Wireline and Perforating Products and Services Catalog - Halliburton

Knowledge and Data Transfer 

Reservoir Evaluation Services 

Open-Hole Wireline Services 

Cased-Hole Wireline Services 

Perforating Solutions 

Downhole Video 

Slic Slickline Service Equipment and Services 

Mobilization 

Mnemonics

Table of Contents 

Knowledge and Data Transfer . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .1-1 

Real-Time Operations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .1-1 

Real-Time Data/Solution Delivery. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .1-1 

HalLink ® Satellite Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .1-2 

InSite Anywhere ® Service . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .1-3 

Reservoir Evaluation Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-1 

Petrophysics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-1 

MRI Petrophysics. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-1 

MRIL ® Simultaneous T 1 and T 2 Measurements . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-1 

MRIAN Magnetic Resonance Imaging Analysis. . . . . . . . . . . . . . . . . . . . . . . . . .2-2 

Time Domain Analysis (TDA). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-4 

Diffusion Analysis (DIFAN) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-5 

Enhanced Diffusion Method (EDM) Technique . . . . . . . . . . . . . . . . . . . . . . . .2-6 

Heavy Oil MRIAN SM Service . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-7 

StiMRIL Process . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-8 

Volumetric Petrophysics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-10 

Chi Modeling ® Computation Service . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-10 

ULTRA Module Suite . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-12 

SASHA Shaly Sand Analysis. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-14 

CORAL Complex Lithology Analysis. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-15 

LARA Laminated Reservoir Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-16 

Reservoir Characterization. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-17 

Borehole Image Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-17 

AutoDip and TrendSetter Services. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-17 

AutoDip Service. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-18 

TrendSetter Service . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-18 

ReadyView Open-Hole Imaging System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-20 

Facies Profile . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-22 

Net2Gross Sand Count . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-24 

ImagePerm . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-25 

Borehole Geophysics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-26 

Wellbore Seismic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-26 

High Resolution Seismic Imaging—(Near Offset VSP, Fixed Offset VSP, 

Walkaways, 3D VSP, Salt Proximity Surveys, Microseismic Surveys) . . . . . . . . .2-26 

Reservoir Geophysics. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-27 

Long Array Multi-Component Acquisition Tools . . . . . . . . . . . . . . . . . . . . . . . . . .2-27 

GeoChain VSP Downhole Receiver Array . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-27 

Synthetic Seismic and Sonic Log Calibration . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-27 

Vertical Incidence Vertical Seismic Profiling (VIVSP) Analysis . . . . . . . . . . . . . .2-28 

ExactFrac ® Services. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-29 

Acoustics and Rock Properties. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-30 

Table of Contents i

Anisotropy Analysis. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-30 

RockXpert2 Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-32 

FracXpert Analysis. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-34 

AcidXpert Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-36 

Reservoir and Production Engineering . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-38 

Reservoir Testing Studio . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-38 

RTS Reservoir Testing Studio . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-38 

Pressure Time Plot . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-38 

Exact Buildup Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-39 

Exact Anisotropy Analysis Plot . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-39 

FasTest ® Buildup Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-40 

Horner Time Plots . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-40 

Log-Log Derivative Analysis Plot . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-41 

PVT Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-42 

Formation Test Summary Program (FTS) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-42 

Well Testing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-44 

Well Test Design . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-44 

Well Test Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-46 

Multi-Layered Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-47 

Reservoir Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-48 

SigmaSat Model . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-48 

CarbOxSat Model. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-49 

TripleSat Model . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-50 

Production Logging Analysis. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-51 

Production Logging Analysis. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-51 

FloImager ® Analysis Service . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-54 

FloImager ® 3D Software Analysis. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2-54 

Open-Hole Wireline Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-1 

Resistivity. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-1 

ACRt Array Compensated Resistivity Tool System . . . . . . . . . . . . . . . . . . . . . . . . . .3-1 

HRAI High Resolution Array Induction Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-3 

HRI High Resolution Induction Tool. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-4 

HDIL Hostile Dual Induction Log . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-5 

DLL Dual Laterolog Service . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-6 

MSFL Micro-Spherically Focused Log and Microlog (ML) . . . . . . . . . . . . . . . . . . . .3-7 

HFDT High Frequency Dielectric Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-8 

Imaging. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-9 

EMI Electrical Micro Imaging Service . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-9 

XRMI X-Tended Range Micro Imager Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-11 

OMRI Oil-Based Micro-Imager Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-13 

CAST-V Circumferential Acoustic Scanning Tool-Visualization. . . . . . . . . . . . . . .3-15 

SED Six Arm Dipmeter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-16 

Nuclear . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-17 

SDL Spectral Density Log . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-17 

ii Table of Contents

DSN Dual-Spaced Neutron Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-19 

DSEN Dual-Spaced Epithermal Neutron Log Tool . . . . . . . . . . . . . . . . . . . . . . . . . .3-21 

CSNG Compensated Spectral Natural Gamma Ray . . . . . . . . . . . . . . . . . . . . . . . . .3-22 

Acoustics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-24 

BSAT Borehole Compensated Sonic Array Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-24 

WaveSonic ® Tool. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-25 

FWS Full Wave Sonic Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-27 

NMR. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-29 

MRIL-XL and MRIL ® -Prime Magnetic Resonance Image Logging Tools . . . . . . .3-29 

MRILab ® Magnetic Resonance Image Fluid Analyzer . . . . . . . . . . . . . . . . . . . . . . . . .3-31 

Borehole Geophysics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-33 

Wellbore Seismic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-33 

High Resolution Seismic Imaging—(Near Offset VSP, Fixed Offset VSP, 

Walkaways, 3D VSP, Salt Proximity Surveys, Microseismic Surveys) . . . . . . . . .3-33 

Reservoir Geophysics. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-34 

Long Array Multi-Component Acquisition Tools . . . . . . . . . . . . . . . . . . . . . . . . . .3-34 

GeoChain VSP Downhole Receiver Array . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-34 

Synthetic Seismic and Sonic Log Calibration . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-34 

Vertical Incidence Vertical Seismic Profiling (VIVSP) Analysis . . . . . . . . . . . . . .3-35 

ExactFrac ® Services. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-36 

Sampling. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-37 

RDT Reservoir Description Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-37 

DPS Dual Probe Section . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-39 

Oval Pad . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-39 

Straddle Packer. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-39 

FPS Flow-Control Pump-Out Section . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-39 

QGS Quartz Gauge Section . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-39 

MRILab Section . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-40 

MCS Multi Chamber Section. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-40 

CVS Chamber Valve Section. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-40 

SFT-IV Sequential Formation Tester IV Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-41 

SFTT Sequential Formation Test Tool. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-42 

RSCT Rotary Sidewall Coring Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-43 

SWC Side Wall Coring Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-45 

HRSCT Hostile Rotary Side Wall Coring Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-46 

Hydraulic Valve Section . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-46 

Motor Drive Section. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-46 

Mandrel Section . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-46 

Hostile—Slimhole Formation Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-47 

HEAT Hostile Environment Applications Tool Suite . . . . . . . . . . . . . . . . . . . . . . . .3-47 

HEDL Hostile Environment Dual Laterolog Tool . . . . . . . . . . . . . . . . . . . . . . . .3-48 

HFWS Hostile Full Wave Sonic Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-49 

HSDL Hostile Spectral Density Log . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-51 

HDSN Hostile Dual-Spaced Neutron Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-53 

Table of Contents iii

HNGR Hostile Natural Gamma Ray Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-55 

HSFT Hostile Sequential Formation Tester Tool. . . . . . . . . . . . . . . . . . . . . . . . .3-56 

Auxiliary Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-57 

Multi-Conductor LockJar ®* System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-57 

Borehole Conditions. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-58 

RWCH Releaseable Wireline Cable Head . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-59 

Toolpusher Logging (TPL) Service . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-60 

CTL Coiled Tubing Logging . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-62 

BHPT Borehole Properties Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-63 

FIAC Four Independent Arm Caliper Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-65 

SDDT Stand-Alone DITS Directional Tool. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3-67 

Cased-Hole Wireline Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4-1 

Formation Evaluation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4-1 

TMD-L Thermal Multigate Decay-Lithology Logging Tool. . . . . . . . . . . . . . . . . . . .4-1 

RMT Elite Reservoir Monitor Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4-3 

Spectra Flow Logging Service (SpFl) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4-5 

DSN Dual-Spaced Neutron Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4-7 

FCMT Formation Compaction Monitoring Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4-9 

CASE Casing Evaluation and Inspection Software . . . . . . . . . . . . . . . . . . . . . . . . . .4-10 

Through Casing Acoustic Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4-12 

WaveSonic ® Tool. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4-12 

FWS Full Wave Sonic Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4-14 

HFWS Hostile Full Wave Sonic Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4-16 

Production Logging . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4-18 

Production Logging Tools . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4-18 

Memory Production Logging . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4-18 

Electric Line Production Logging . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4-18 

FloImager ® Service . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4-21 

GHT Gas Holdup Tool. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4-23 

MPL Memory Production Logging Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4-24 

Quartz Pressure Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4-27 

Casing and Tubing Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4-28 

MAC Multi-Arm Caliper Tool. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4-28 

CAST-V Circumferential Acoustic Scanning Tool-Visualization. . . . . . . . . . . . . . .4-29 

The FASTCAST Fast Circumferential Acoustic Scanning Tool . . . . . . . . . . . . . . . .4-31 

Cement Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4-33 

Cement Bond Log (CBL). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4-33 

Radial Cement Bond Tools . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4-35 

ACE Advanced Cement Evaluation Process . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4-37 

Mechanical Services. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4-39 

Pipe Recovery . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4-39 

Chemical Cutter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4-39 

Tubing Cutters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4-42 

*LockJar is a registered trademark of Evans Engineering, Inc. 

iv Table of Contents

Super Tubing Cutters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4-44 

Coiled Tubing Cutters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4-46 

Casing and Drillpipe Cutters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4-48 

C-4 Casing Cutters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4-50 

Drill Collar Severing Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4-51 

Junk Shot . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4-53 

Plug Setting Equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4-54 

EZ Drill ® Bridge Plugs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4-54 

Fas Drill ® Bridge Plugs . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4-55 

Perforating Solutions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-1 

Shaped Charges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-1 

MaxForce Shaped Charges. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-1 

Dominator ® Shaped Charges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-2 

Mirage ® Shaped Charges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-3 

Maxim Shaped Charges . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-5 

KISS Low-Damage Perforating Charge. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-6 

Gun Systems. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-10 

VannGun ® Assemblies. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-10 

1 9/16 in. to 7 in. and 4 SPF to 21 SPF . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-10 

VannGun Phasing and Shot Patterns . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-11 

0° Phasing 4 and 5 SPF . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-11 

60° Phasing 4, 5, and 6 SPF . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-11 

90° Phasing 4 SPF . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-12 

180° Phasing 4 and 8 SPF . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-12 

60° Phasing 6 SPF Two Planes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-13 

45°/135° Phasing 5, 6, 8, 12, and 18 SPF . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-13 

140°/160° Phasing 11 SPF . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-14 

51.4°/154.3° Phasing 12 SPF . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-14 

30°/150° Phasing 12 SPF . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-14 

25.7°/128.5° Phasing 14 SPF . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-15 

60°/120° Phasing 18 and 21 SPF . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-15 

138° Phasing 14 SPF . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-15 

Tensile Ratings. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-16 

1 9/16-in. Premium VannGun Assemblies. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-16 

2-in. Premium VannGun Assemblies. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-17 

2 1/2-in. Premium VannGun Assemblies. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-18 









Table of Contents v

5 1/8-in. Premium VannGun ® Assemblies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-31 




6 1/2-in. High-Pressure Premium VannGun Assemblies. . . . . . . . . . . . . . . . . . . . .5-35 


Capsule Gun Systems. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-41 

Dyna-Star ® Capsule Gun . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-41 

Deep Star Capsule Gun . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-42 

1.6875-in. and 2.125-in. Deep Star Debris Fill Data . . . . . . . . . . . . . . . . . . . . . . . .5-43 

Ported Gun Perforating System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-44 

Firing Heads . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-45 

Detonation Interruption Device . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-45 

Mechanical Firing Head . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-46 

Model II-D Mechanical Firing Head . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-47 

Model III-D Mechanical Firing Head . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-48 

Pressure-Actuated Firing Head . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-49 

Model K and K-II Firing Heads . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-50 

Model KV-II Firing Head . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-51 

Time-Delay Firer . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-52 

Multiaction-Delay Firing Head . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-53 

Annulus Pressure Firer-Control Line . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-54 

Annulus Pressure Transfer Reservoir. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-55 

Slimhole Annulus Pressure Firer—Internal Control . . . . . . . . . . . . . . . . . . . . . . . . . . .5-56 

5-in. Annulus Pressure Transfer Reservoir . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-56 

3 1/8-in. Internal Control . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-56 

3 1/8-in. Annulus Pressure Transfer Reservoir—Internal Control . . . . . . . . . . . . . . . .5-56 

Differential Firing Head . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-57 

Hydraulic Actuator Firing Head and Swivel-Type Hydraulic Actuator 

Firing Head. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-58 

Mechanical Metering Hydraulic-Delay Firing Head . . . . . . . . . . . . . . . . . . . . . . . . . . .5-59 

Slickline-Retrievable Mechanical Firing Head . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-60 

Slickline-Retrievable Time-Delay Firer Firing Head. . . . . . . . . . . . . . . . . . . . . . . . . . .5-62 

Extended Delay Fuses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-63 

Modular Mechanical Firing Head . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-64 

Side-Pocket Mandrel Firing Head . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-66 

Annulus Pressure Crossover Assembly . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-67 

EZ Cycle Multi-Pressure Cycle Firing Head . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-68 

Pump-Through Firing Head . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-70 

Ancillary Equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-71 

Fill Disk Assembly. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-71 

Balanced Isolation Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-72 

Ratchet Gun Connector . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-74 

AutoLatch Release Gun Connector . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-75 

vi Table of Contents

Isolation Sub-Assembly . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-76 

Quick Torque Connector . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-77 

Detach Separating Gun Connector. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-79 

Rathole Length Restriction. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-79 

Rigless Completion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-79 

EZ Pass Gun Hanger . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-80 

Automatic-Release Gun Hanger—Rotational Set . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-82 

Automatic-Release Gun Hanger—Automatic-J Mandrel . . . . . . . . . . . . . . . . . . . . . . .5-84 

Explosive Transfer Swivel Sub . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-86 

Shearable Safety Sub . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-87 

Roller Tandem Assembly. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-88 

Centralizer Tandem . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-89 

Emergency Release Assembly . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-90 

Annular Pressure-Control Line Vent . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-91 

Annular Pressure-Control Line Swivel Sub . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-92 

Annular Pressure-Control Line Tubing Release . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-93 

Bar Pressure Vent. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-94 

Below-Packer Vent Device . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-95 

Maximum Differential Bar Vent . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-96 

Pressure-Operated Vent . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-97 

Vann Circulating Valve . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-98 

Automatic Release . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-99 

Mechanical Tubing Release . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-101 

Pressure-Actuated Tubing Release. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-103 

DPU ® Downhole Power Unit. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-104 

SmartETD ® Advanced Electronic Triggering Device . . . . . . . . . . . . . . . . . . . . . . . . .5-105 

Y-Block Assembly . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-106 

Non-Ported . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-106 

Ported . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-106 

Gun Guides. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-107 

Hydraulic Metering Release Tool for the Single Trip System 

(STPP-GH) Tool. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-108 

Fast Gauge Recorder . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-110 

Gamma Perforator Logging Tool. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-112 

Detonators . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-113 

Capsule RED ® Detonators . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-113 

RED GO-Style Thermal Igniter . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-114 

Block RED Detonators. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-115 

Top Fire RED Detonators . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-116 

Dynamic Modeling. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-117 

PerfPro ® Process . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-117 

PerfPro Process–Predicting In-Situ Charge Performance . . . . . . . . . . . . . . . . . . .5-117 

Near-Wellbore Stimulation and PulsFrac Software . . . . . . . . . . . . . . . . . . . . . . . . .5-120 

EOB - Energized Fluid Stimulation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-120 

Table of Contents vii

Propellant Stimulation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-121 

ShockPro SM Shockload Evaluation Service . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-125 

Near-Wellbore Stimulation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-127 

StimGun* Assembly. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-127 

Propellent Stimulation Tool Assembly . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-130 

POWR*PERF SM Perforation/Stimulation Process. . . . . . . . . . . . . . . . . . . . . . . . . . . .5-132 

PerfStim Process. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-133 

Oriented Perforating. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-134 

G-Force ® Precision Oriented Perforating System . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-134 

Oriented Perforating with Modular Guns. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-136 

Finned Orienting Tandem . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-137 

Eccentric Orienting Tandem . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-138 

Special Applications. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-139 

Modular Gun System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-139 

The Modular Gun System Process . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-140 

Rathole Length Restriction. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-140 

Rigless Completion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-140 

Select Fire Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-141 

Coiled Tubing Conveyed Perforating . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-142 

DrillGun Perforating Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-143 

Setting Tools for the Auto-Release Gun Hanger . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-145 

Running and Retrieving Tools . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5-145 

Downhole Video . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .6-1 

Downhole Video Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .6-1 

Hawkeye Camera System. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .6-2 

Fiber-Optic Camera System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .6-3 

EyeDeal Camera System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .6-4 

Slickline Service Equipment and Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-1 

Subsurface Service Tools . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-2 

Slickline Service Tools. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-2 

Slickline Toolstring . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-2 

Otis ® Accelerators . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-3 

Slickline Detent Jars. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-4 

Otis Quick Connect Toolstring Connection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-5 

Auxiliary Tools For Use with Slickline Toolstring . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-6 

Otis Gauge Cutter and Swaging Tools. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-6 

Otis Impression Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-6 

Otis Tubing Broach . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-6 

Otis M Magnetic Fishing Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-6 

Otis G Fishing Socket . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-7 

Otis P Wireline Grab . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-7 

*StimGun is a trademark of Marathon Oil Company. 

viii Table of Contents

Otis ® Go-Devil. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-7 

Expandable Wirefinder . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-7 

Running Tools . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-8 

Otis X ® and R ® Running Tools . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-8 

Otis RXN Running Tools. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-8 

Otis UP Running Tool . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-8 

Otis MR Running Tools . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-8 

Pulling Tools . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-9 

Internal Fishing Necks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-9 

External Fishing Necks . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-9 

Test Tools. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-11 

Otis Non-Selective Test Tools . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-11 

Positioning Tools . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-12 

Tubing Perforators and Bailers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-13 

Slickline Skid Units and Trucks. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-14 

Surface Service Equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-15 

Advanced ® Slickline Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-16 

Advanced Slickline Service System. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-18 

DPU ® Tubing Punch . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-22 

CollarTrak ® Slickline Collar Locator . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-23 

Advanced Measurement System (AMS) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-25 

Electronic Advanced Measurement System (Portable) . . . . . . . . . . . . . . . . . . . . . . . . .7-26 

SmartETD ® System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-27 

JobTrak ® Data Job Logger. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-28 

Standard Mounted Equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-28 

Memory Production Logging (MPL) Service . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-29 

LineTrak ® Slickline Inspection Device and Wire Management Program . . . . . . . . . . .7-31 

Wire Management Program . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .7-31 

Deepwater Riserless Subsea Light Well Intervention System . . . . . . . . . . . . . . . . . . . .7-33 

Mobilization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .8-1 

LOGIQ Logging Truck . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .8-1 

LOGIQ Modular Skid Unit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .8-3 

Cabin Module. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .8-4 

Winch Module . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .8-5 

Power Pack. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .8-6 

Mnemonics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .9-1 

Wireline and Perforating Services Mnemonics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .9-2 

Log Header Mnemonics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .9-44 

Table of Contents ix

x Table of Contents

Knowledge and Data Transfer 

Real-Time Operations 

Real-Time Data/Solution Delivery 

Various methods are used to deliver data in real time from 

wellsites to offsite locations. The three main methods are: 

• InSite Anywhere® service 

Collaborative formation evaluation and reservoir 

monitoring 

Real-time monitor and control (RTMC) 

InSite Anywhere® service moves data from the logging tools 

onto a secured website, where it can be viewed in real time as 

it is acquired. InSite Anywhere service is also a drop box for 

data files and viewing DHV images in real time. 

With collaborative formation evaluation and reservoir 

monitoring, it is possible to deliver data to environments 

where experts can discuss any issues dealing with geology, 

operations, or the reservoir, thereby influencing the ongoing 

services at the wellsite immediately. 

Real-time monitor and control (RTMC) is an internal tool 

that provides both operational and technical support along 

with ability to control remote wellsite locations. 

Features 

Scalable, from simple operations to the most 

sophisticated 

Halliburton expertise available 

Provides instant access and support from non-wellsite 

locations 

Personnel can participate in multiple operations 

Expand personnel capabilities 

Knowledge and Data Transfer 1-1 

Knowledge and Data Transfer

HalLink ® Satellite Systems 

Three systems are available: land (tripod), skid 

(compensating), and vessel (permanent). HalLink® systems 

allow transmission of data and video at high speeds through 

a secure network supporting all Halliburton real-time 

operations. With “last mile” connectivity to the location, 

real-time support and decisions can be made more easily. 

Features 

Fully scalable to client needs, simple point-to-point 

network through full mesh (point-to-many) 

Deployment can be expanded per client needs 

System is flexible, which enables the system to be part of 

the Halliburton or client network 

Two phone lines for operational support 

Improved reliability for wellsite connectivity 

Bandwidth scalable to local/client needs 

Services Enabled by HalLink Systems 

Immediate data transfer for: 

– QuikLook® reservoir fluid management services 

– Applied formation evaluation processing 

InSite Anywhere® service 

–Downhole video 

– MRILab® downhole measurement service 

– RDT reservoir description tool 

– Standard logging suite 

Collaborative formation evaluation and reservoir 

monitoring 

Real-time monitor and control 

Video conferencing Connectivity Anywhere 

1-2 Knowledge and Data Transfer

InSite Anywhere ® Service 

InSite Anywhere® service is a next-generation, web-based 

data delivery system that gives you the flexibility of the 

industry’s most robust database structure—without the need 

to install special software. Using our advanced satellite 

communications technology or any other network, InSite 

Anywhere service moves data from the logging tools onto a 

secured web site, where you can view it in real time as it is 

acquired. 

When an unplanned event arises, the InSite Anywhere web 

delivery system provides needed facts to command the 

situation. Whatever solution directed will be based on 

complete up-to-the-minute information. The system allows 

you to participate in multiple wellsite operations from one 

location. With all the travel time saved, capabilities are 

stretched further—and make the most of company resources. 

Features 

View and print logging and tester data in real time from 

any PC 

Access offset well data from nearby wells 

Download logging data, answer products, and more 

Configure display to individual preference by 

manipulating logging or test data 

View and print numerous display types: 

–Log plots 

– Pressure tests and samples 

– Streaming downhole video (view only or save/ 

print to screen capture) 

– Cross-plots 

– MRILab® service results (view only or save/print 

as screen capture) 

– Efficient gauges, LEDs, and other indicators 

Expand personnel capabilities 

Speed decision-making 

Participate in multiple operations 

Optimize logging passes 

Deploy expertise and resources more efficiently 

Save travel expenses 

Avoid travel risk 

No special hardware or software required 

Requirements for Service 

Internet or intranet access 

Uses standard web browsers 

User name, password, and URL 

Uses the security protections of the HalLink® 

commuciations network or any other secure network 

Knowledge and Data Transfer 1-3

1-4 Knowledge and Data Transfer

Reservoir Evaluation Services 

Petrophysics 

MRI Petrophysics 

MRIL ® Simultaneous T 1 and T 2 Measurements 

Both the MRIL-XL and MRIL®-Prime tools acquire NMR 

data in several modes of operation. Simultaneous T 1 and T 2 

log acquisition is a robust technique to acquire NMR 

reservoir information faster and simpler. T 1 has made its 

wireline debut to join MRIL-WD (MRI while drilling) and 

MRILab® service (MRI fluid analysis during wireline 

formation sampling). In both the MRIL-WD and MRILab 

applications, the preference of T 1 over T 2 has been its 

insensitivity to motion as T 1 measurements eliminate the 

detrimental effects from tool motion or fluid flow. 

Simultaneous T 1 and T 2 wireline acquisition is now done in a 

single log pass. Micro-porosity, capillary bound water, free 

fluid index, effective porosity, and total NMR porosity 

acquired during T 1 logging may be used in MRIAN 

analysis as described on page 2-2. 

T 1 logging offers a simplified NMR measurement composed 

of only two of the three decay mechanisms associated with 

NMR. Only surface and bulk relaxation mechanisms 

contribute to the T 1 response. There is no diffusion effect in 

T 1 data, so many fluid identification applications are 

simplified as in tight gas identification in water-based mud 

systems. For simple and faster NMR reservoir information, 

T 1 offers a reliable alternative to T 2 . 

Features 

Robust reservoir quality measurements of NMR 

Total and effective porosity and bound fluid volumes 

Light hydrocarbon identification 

Faster logging speeds 

Simplified NMR interpretation (no diffusion effects) 

Simultaneous T1 and T2 acquisition (single log pass) 

Real-time permeability calculations 

This T 1 MRIAN analysis example depicts the long T 1 gas signal in the 

upper zone, green waveforms on far right in Track 4. The free water T 1 

values are much shorter as can be seen in Track 4 in the lower zone. 

Reservoir Evaluation Services 2-1 

Reservoir Evaluation Services

MRIAN Magnetic Resonance Imaging Analysis 

MRIAN analysis is a technique that combines MRIL® and 

conventional data to identify potential hydrocarbon zones. 

MRIAN analysis uses the dual-water model technique to 

estimate the volume of formation fluids in a virgin zone. 

Using the dual-water model within the MRIAN program 

allows identification of free water volume. When the 

computed effective volume of water equals the MRIL data 

irreducible volume of water, then production is water free. 

Both T 1 and T 2 distributions and permeability calculations 

are provided to indicate reservoir quality. 

MRIL stand-alone analyses, such as time domain analysis 

(TDA), diffusion analysis (DIFAN), and Enhanced Diffusion 

Method (EDM) technique provide hydrocarbon typing 

interpretation within the depth of investigation of the MRIL 

measurements. When MRIL data is combined with other 

logs, analysis can furnish even more information about the 

reservoir. MRIAN analysis is one of the interpretation 

models that use this data combination. 

Features 

MRIAN analysis combines MRIL analysis and deepresistivity 

data from any induction tool. MRIL data is used to 

provide two important parameters needed in the dual-water 

model: the clay-bound water porosity (MCBW) and total 

porosity (MPHIT). 

Additional features include the following: 

Provides enhanced permeability calculations 

Indicates zones of potential water production 

Identifies hydrocarbon-water contacts 

Calculates water saturation in the uninvaded zone 

Provides a solution for low-resistivity pay reservoirs 

Confirms dual-water Rw by reconstructing spontaneous 

potential (SP) 

Uses a robust implementation of the dual-water 

resistivity model to provide improved water saturation 

(Sw) calculations, especially in shaly reservoirs 

This MRIAN analysis indicates an oil/water contact at X940. The MRI 

T 2 distribution in Track 3 demonstrates a change in relaxation times 

verifying the MRIAN analysis. 

2-2 Reservoir Evaluation Services 

HAL9111

Inputs 

HAL9112 

This MRIAN analysis example demonstrates the effectiveness of 

this model to identify oil/water contact as well as zones of potential 

water production (Track 4). Enhanced permeability calculations are 

presented in Track 2 (red curve). 

MRIL ® porosity data. The main data requirements for MRIAN processing are true formation resistivity (R t), total porosity 

(φ t ), and clay-bound-water saturation (S wb ). Density, neutron, and/or sonic porosity are optional inputs. MRIL activation 

planning is critical for successful interpretation. 

Outputs Permeability, effective porosity, total porosity, water saturation, free water volume, irreducible water volume 

Reservoir Evaluation Services 2-3

Time Domain Analysis (TDA) 

MRIL® data can be analyzed independently or in 

combination with conventional logs. When MRIL data is 

processed independently, it can provide formation porosity 

and permeability information as well as complete 

information on fluid types and fluid saturation within the 

depth of investigation of the MRIL tool. Time domain 

analysis (TDA) is an interpretation technique that utilizes 

only MRIL data. 

Time domain analysis operates on the principle that different 

fluids have different rates of polarization or different T 1 

relaxation times. The T 1 of both gas and light oil (viscosity 

less than 5 cp) is normally much higher than that of water. 

TDA is very effective in evaluating gas and light oil reservoirs. 

TDA is very different from other techniques available 

because it uses only MRIL data in the interpretation process; 

no conventional data is needed in the processing. 

Features 

TDA analysis provides an alternative to the differential 

spectrum method for processing dual-Tw echo trains data. 

Interpretation is performed in the time domain rather than 

in the T2 spectra domain. Key features of TDA analysis 

include: 

Subtraction of the two echo trains from one another 

Processing echo differences in the time domain using 

predicted or measured oil, gas, and water relaxation 

times and hydrogen-index values 

Additional TDA features include the following: 

Provides accurate formation porosity in gas and light oil 

reservoirs 

Allows complete fluid volume analysis within the depth 

of investigation of the MRIL tool using only MRIL tool 

data 

Provides hydrocarbon typing 

Recognizes direct pay 

Improves permeability calculations in light hydrocarbon 

environment 

Clearly identifies pay zones vs. tight zones 

Inputs 

Estimates free fluid volume and type in thinly laminated 

reservoirs 

Indicates the best possible producing zones in carbonate 

formation 

This MRIAN analysis example demonstrates the effectiveness of this 

model to identify oil/water contact as well as zones of potential water 

production (Track 4). Enhanced permeability calculations are 

presented in Track 2 (red curve). 

MRIL ® data only from dual-wait time acquisition which can be acquired using MRIL-XL, MRIL ® -Prime and/or 

MRIL-WD tools 

Outputs Volumetric calculation of gas, oil, and water; formation total and effective porosity; permeability estimation 


HAL9113

Diffusion Analysis (DIFAN) 

Diffusion analysis (DIFAN) is a stand-alone NMR technique 

for quantitative diffusion analysis of intermediate oil 

viscosity range of 2 to 30 cp and has been applied successfully 

in many fields. DIFAN was developed specifically for 

situations where TDA cannot be applied because of 

insufficient T 1 contrast. Variations in molecular diffusion 

will manifest themselves as variations in the observed T 2 

distributions. These can be used to quantify water-filled and 

oil-filled porosity, respectively. 

Features 

Diffusion analysis is an interpretation technique utilizing 

dual-T E measurements. DIFAN relies on the diffusion 

contrast between water and medium viscosity oil to quantify 

oil volume within the depth of investigation of the tool. The 

data for DIFAN is acquired through single-T W (wait time), 

dual-T E (echo spacing) logging. 

Other features of diffusion analysis include: 

Calculates hydrocarbon and water saturation in 

freshwater environments 

Stand-alone analysis does not need resistivity logs 

Works in low to moderate viscosity oils (typically 2 to 

30 cp at reservoir conditions) 

Works in areas of unknown or variable Rw Inputs MRIL ® data (dual-T E activation) from MRIL-XL or MRIL ® -Prime tools 

Outputs Porosity, S w , diffusion ratios, permeability, watercut (if relative permeabilities are known) 

This log contains results from the application DIFAN to MRIL® data 

from an Indonesian well. Track 1 includes conventional gamma ray, 

spontaneous potential, and caliper curves. Track 2 presents deep, 

medium, and shallow resistivity data and MRIL permeability. Track 3 

contains the long-T E T 2 distribution. Track 4 contains the short-T E T 2 

distribution. Track 5 displays answer products from DIFAN 

calculations. 


HAL9114

Enhanced Diffusion Method (EDM) Technique 

Enhanced Diffusion Method (EDM) NMR technique 

utilizes the contrast in molecular diffusion between water 

and oil to identify and potentially quantify oil 

accumulations. The diffusion properties of water, combined 

with tool parameters (T E, magnetic field gradient) and the 

temperature of the logging environment, define the slowest 

relaxation time possible for water to be observed: T 2DW. 

Consequently, any NMR signal observed beyond this value 

can only be associated with oil. This offers a simple way to 

interpret the presence of oil and to differentiate pay from 

non-pay zones. 

The EDM technique can also be used to quantify residual oil. 

The advantage it has over conventional techniques such as 

pressure-coring and/or sponge-coring is that oil is measured 

at in-situ conditions. Hence, gas expansion or fluid expulsion 

need not be taken into account. As with any residual oil 

determination technique, controlling fluid loss from the mud 

system to the formation is critical to the overall success of the 

EDM technique. 

Features 

EDM interpretation methodology is based on the contrasts 

in molecular diffusion between different fluids. 

Enhancement of the diffusion effect, by increasing the interecho 

spacing T E during data acquisition, separates water and 

oil in the T 2 domain. 

HAL9115 

For typing medium-viscosity oils with this method, standard 

CPMG T 2 data recorded with a long T E is sufficient. 

Quantitative application of the EDM technique requires 

either dual-T W data recorded with a long T E , or dual-T E data 

recorded with a long T W. 

Additional features include: 

Independent confirmation of oil-bearing zones and 

identification of oil/water contacts 

Stand-alone determination of (residual) oil saturation 

with no need to dope drilling fluids 

Sensitive to oil in the viscosity range from 1 cp to 50 cp 

Works in areas of unknown or variable Rw Enhanced Diffusion Method technique can differentiate pay from non-pay zones. Track 5 indicates an oil/water contact near the bottom and the 

oil column continues to the top of the zone. This finding is supported by the resistivity curves in Track 2. 

Inputs MRIL ® data (dual-T E activation) from MRIL-XL, MRIL ® -Prime, or MRIL-WD tools 

Outputs Residual oil saturation, porosity, permeability, viscosity, flushed zone S w 

2-6 Reservoir Evaluation Services

Heavy Oil MRIANSM Service 

The heavy oil MRIANSM service improves reservoir 

evaluation in areas where oil viscosity exceeds 100 cp at 

formation conditions, and the oil gravity is less than 20° API. 

The heavy oil MRIAN service combines dual-echo spacing 

MRIL® logs with conventional porosity and resistivity logs to 

provide improved: 

Determination of bulk volume irreducible (BVI) 

Measurement of movable water 

Quantification of viscous oil reserves 

Estimation of permeability in water-wet reservoirs 

By themselves, NMR responses to viscous oils are not readily 

distinguishable from those of capillary-bound and claybound 

water. The heavy oil model is able to differentiate 

these fluids by using MRIL® data to quantify movable water 

in the formation. This volume, when subtracted from the 

effective water volume derived from conventional logs, gives 

the irreducible water volume. In addition, this comparison is 

useful for recognizing mixed or oil-wet reservoir conditions, 

which can often occur in viscous-oil reservoirs. 

Good candidates for application of the heavy oil MRIAN 

service are heavy oil producing areas in Venezuela, Canada, 

Alaska, Russia, and smaller heavy oil provinces throughout 

the world. This service has been successfully applied in both 

sandstone and carbonate reservoirs. 

Features 

An integrated NMR and conventional log heavy oil 

interpretation model 

Movable water determination in heavy oil-bearing 

formations using the Enhanced Diffusion Method 

(EDM) 

Comparison of NMR and conventional porosity 

responses to estimate in-situ oil viscosity 

Improved BVI determination compared to traditional 

interpretation of NMR measurements in heavy-oil 

reservoirs 

Can provide a complete analysis of pore fluids, including 

clay-bound and capillary-bound pore fluids, movable 

water volume, and hydrocarbon volumes 

Direct measurement of movable water 

Inputs MRIL ® data acquired with dual-T E and conventional data 

Aid improved water saturation evaluation 

Indication of moved hydrocarbons in the near-wellbore 

region 

Determination of in-situ oil viscosity from MRIL signalloss 

in heavy oil-bearing formations 

Indication of formation wettability conditions 

The log above shows results from a heavy oil MRIAN analysis of data 

collected from an area of the United Kingdom continental shelf. These 

results show the reservoir is mostly water-wet through the transition 

zone. The absence of capillary bound water above the transition zone 

indicates an oil-wet condition. 

Outputs Corrected BVI, clay porosity, total porosity, improved permeability estimates, effective porosity, water saturations, viscosity 


HAL9116

StiMRIL Process 

The StiMRIL process is an integrated stimulation process 

built upon a reservoir performance model created from a 

combination of MRIL® magnetic resonance imaging logging 

analyses and reservoir simulations. This model allows the 

stimulation design engineer to develop optimum 

completion/stimulation plans and accurately predict the 

outcome of production enhancement efforts. Identification 

of hydrocarbon type and accurate determinations of 

porosity, free fluid, and bound fluid volumes from MRIL 

logging measurements provide operators with answers to 

critical questions by providing: 

The location of oil, gas, or water in the zone 

The potential for water production 

The net present value (NPV) of the zone 

The rate at which the well will produce oil, gas, or water can 

then be predicted by carrying this information forward in the 

reservoir simulation step of the StiMRIL process. 

The MRIL® tool is used to perform high-quality 

measurements and collect the data required to make a 

thorough reservoir evaluation in a single logging pass. In 

addition to saving rig time, the resulting calculations of 

permeability, water saturation, and effective porosity are 

better than those derived from other lithology-dependent 

methods. 

Features 

The reservoir modeling capabilities included in the StiMRIL 

process use the results of the MRIL analysis to provide a 

relatively complete representation of the reservoir's 

production characteristics. An integrated stimulation design 

process allows operators to accurately predict reservoir 

performance and to optimize their financial investment 

based on the economics of the fracturing treatment for the 

reservoir. For example, in a tight-gas sand (low permeability 

formation), the completion design usually centers around a 

hydraulic treatment. 

Other features include: 

Increased focus on the reservoir through the integration 

of well logging, reservoir performance, and stimulation 

design 

Logging data and reservoir simulations used in 

combination to increase reservoir understanding 

Built-in stimulation design capabilities to help operators 

develop the best completion strategies 

Here is an example of a layered sandstone reservoir which indicates a 

high clay, low porosity interval in the lower section of the well, cleaner 

zones with higher movable hydrocarbons in the middle, and an 

extremely high perm zone in the top, which contains a large amount 

of oil. 


HAL9117

MRIL® logging has revolutionized the logging industry 

through its ability to directly and accurately measure the 

fluids in the reservoir. This results in the accurate 

determination of: 

Porosity and permeability 

Fluid type and viscosity changes 

Irreducible water volume and free fluid volume 

In other words, MRIL logs indicate not only whether there is 

oil or gas in a zone but also where it is located within the 

zone. These logs also show how much water is present in the 

zone, how it is distributed throughout the zone, and whether 

it is free to move to the wellbore and interfere with 

hydrocarbon production. Before the StiMRIL process was 

developed, fracturing designs relied on lithological volumes 

from quad-combo logging data to provide the information 

to qualitatively evaluate zones and calculate fracture 

geometry. With the StiMRIL process, engineers are able to 

incorporate MRIL logging data into the design to predict 

productivity results. Quad-combo logs still provide the 

lithology information, while MRIL logs provide the fluid 

dynamics information. 

The result is optimized treatment designs for maximum, 

predictable well productivity and improved profitability for 

the operator. 

Inputs Pore-size distribution, permeability, effective porosity, total porosity, water saturation, gas indicator 

Outputs Initial production rate, time of recovery, porosity, permeability, Young's modulus, Poisson's ratio optimum NPV for the well 


Volumetric Petrophysics 

Chi Modeling ® Computation Service 

Some open-hole wells have difficult logging conditions that 

may result in missed zones of open-hole information, or in 

extreme conditions, even the loss of the entire open-hole 

logging run. Halliburton now provides Chi Modeling® 

computation post-processing service will help the user to 

better evaluate their reservoir when they have missing data 

due to borehole conditions, missing LWD sections, old wells, 

etc. Chi Modeling computation service is able to predict 

triple-combo or even quad-combo open-hole data with a 

very high degree of accuracy by using the input data obtained 

from a capture pass of a pulsed neutron tool and a known 

triple-combo or quad-combo data set from a neighboring 

well. Under some conditions, missing or incorrect data 

caused by tool pulls or intermittent sensor failure can be 

correctly generated using only the triple-combo data. Chi 

Modeling computation is also able to: 

Fill in data gaps where the original data is missing from 

either wireline or LWD data 

Replace poor quality data that occurred due to poor 

borehole conditions 

Generate reliable open-hole logs when none are available 

Chi Modeling computation service uses associations made in 

one well between an existing open-hole triple-combo and a 

cased-hole pulsed neutron tool. It does this by looking at 

data from a reference well and assigning a processing weight 

to each input variable. 

If the predicted values do not match the actual value in the 

reference well adequately, the weights are changed, and the 

model is re-computed. These associations are then used, 

along with pulsed neutron data from an offset well, to model 

a triple-combo or quad-combo response in an offset well. 

These associations may be confidently used as long as: 

The formation geology remains similar 

The formations geology is adequately sampled and 

represented in the reference well 

When the formation geology from the reference well 

changes, a new set of open-hole data is required to create a 

new set of associations. This method retains the variability of 

the original data and does not over predict mean statistical 

values. 

A root mean square (RMS) statistical analysis is performed 

on each curve generated in the base well to confirm the 

reliability of the data associations that will be used to project 

and predict the offset triple-combo or quad-combo data. 

Normal accuracy results are as follows: 

Density ± .034 gm/cc = ±2PU 

Neutron ±2PU 

Resistivity ± .1 decade 

50% 

25% 

25% 

Train 

Validate 

Test 

Figure 1 indicates that Chi Modeling software uses training data 

from the reference well in conjunction with weights for each input 

variable to generate predictions. The weights are then applied to the 

entire reference well to generate predictions. The values obtained are 

validated and tested against the original open-hole data. If they do 

not match, new weights are used until a match is obtained. 


HAL12892

HAL12893 

Figure 2 shows the normal input data going into the Chi Modeling software. The weights used for data prediction are 

refined until a reasonable match is obtained with the open-hole data from the reference well. These relationships are used to 

predict and construct triple-combo data on offset wells that have only pulsed neutron data available. 

HAL12894 

Figure 3 shows a comparison between the original neutron/density porosity data (Track 3) and the predicted neutron/ 

density porosity data for a reference well (Track 4) as well as the original (black) and predicted (red) 90-in. resistivity 

data (Track 2). Track 1 is the open-hole gamma ray. 


Chi 

®

ULTRA Module Suite 

ULTRA products are a suite of interactive and noninteractive 

modules which process well log data to make 

comprehensive formation evaluation computations 

determining mineral volumes and fluid saturations. The 

ULTRA tool uses a weighted least-squares error optimization 

technique to determine fractional lithology constituents 

(clay, sandstone, limestone, and other minerals) and the 

percent of saturation of individual fluid components which 

occupy total pore space. 

PREPARE is a query-based module that leads the user 

through the basic parameter entries necessary for later use in 

other modules of ULTRA data. It is obligatory to use either 

PREPARE or JOBVAR before proceeding with the processing 

of modules in the ULTRA suite. 

LOGQUAL calculates the uncertainty or quality of each log 

using all levels. These log uncertainties are used as weighting 

factors in the minimization process in CORINV, ULFE, and 

AUTOMOD. The log curve names in the CLS file must be 

properly mapped into generic curve names used in the 

ULTRA suite via the group NAMLOG under JOBVAR. 

LOGQUAL must be run prior to any quantitative evaluation 

done under the routines CORINV, ULFE, and AUTOMOD. 

DATRED is used to square or block the logs. It provides nine 

different levels of squaring, ranging from coarse to fine, any 

of which may be selected during interactive processing to 

reduce the processing time. This routine must be run before 

CORINV, ULFE, or AUTOMOD. 

CORINV is designed to compute R t, R xo, and D i using any 

combination of resistivity logs. It has distinct advantages 

over the chart book approach when more than three 

resistivity logs are available and one or more logs in the suite 

have different degrees of reliability. The technique is based on 

a constrained weighted least squares error optimization 

using the inverse approach, wherein maximum likelihood 

values of R t, R xo, and D i are computed. Graphical 

comparisons of theoretical and measured log curves are used 

to determine the reliability of measurements. 

An interactive part of CORINV allows the log analyst to test 

hypotheses and to try various options to use weight 

multipliers and constraints. When the analyst is satisfied with 

the results, noninteractive option is used during which all 

data points in the zone selected are processed and computed 

results are written into the CLS file. 

HAL986 

This ULTRA log presents a light hydrocarbon indicator and water 

saturation in Track 1; volumes of residual hydrocarbons, movable 

hydrocarbons, and water in Track 2; and lithology analysis in Track 3. 

ULFE is used to perform log analysis involving the evaluation 

of constituent volume fractions of the rock and estimation of 

fluid saturations in the pore. A weighted least squares error 

optimization technique, using the inverse approach is 

employed. The analyst inputs the lithology, selects the 

response equations, enters the clay and mineral parameters, 

and geological constraints, etc. via the alpha-numeric edit 

screen. The data is then processed to obtain the statistically 

most probable results. 

The output is presented as graphical display of computed 

results, including formation bulk volume analysis and pore 

volume analysis, and a display of measured logs overlain by 

the theoretical or reconstructed logs. Theoretical logs are 

obtained by back computing the log values from the 

computed results. The degree of fit between the two sets of 

logs is a measure of the validity of the assumptions implicit 

in the model used. 


Output can also be presented as a statistical display on an 

alphanumeric screen. The arithmetic average and the 

variance of the difference between each of the measured and 

theoretical logs over the zone processed is individually 

displayed. Also the total error, which represents the 

summation of the errors for each of the constituent logs over 

the zone, is displayed. If the fit between the measured and the 

theoretical logs is poor, the analyst can modify the lithology, 

vary the clay and mineral parameters and try out the 

different response equations until a satisfactory fit is 

obtained, and results correspond to geological expectations. 

Results are computed and displayed on the screen but are not 

written to the disk in the interactive ULFE. Non-interactive 

processing is the next step where all data points are 

processed, and all computed results are written to the disk. 

The AUTOMOD primary objective is to provide optimized 

values for parameters or constants. In addition to the 

weighted least squares error optimization in ULFE for 

computing the variables like S w , V cl , Phi etc., the AUTOMOD 

routine also performs a zone wide optimization on a set of 

constants or parameters to provide optimized values for the 

constants. The constants that can be optimized include all 

parameters associated with sand, lime, dolomite, minerals 1 

through 9, clay, formation water resistivity, hydrocarbon 

density, cementation factor, and saturation exponent. The 

parameters to be optimized are set to the variable status. The 

log analyst furnishes an initial value and minimum and 

maximum values within which parameters are to be 

optimized. Computations are then made over the entire 

interval selected for analysis using various values of the 

parameters to be optimized. The incoherence between the 

measured logs and the logs reconstructed from computed 

variables is then analyzed. The parameters' values that yield 

Inputs 

the least incoherence between the measured and 

reconstructed logs over the interval selected for analysis are 

considered to be the optimized values of the parameters. 

AUTOMOD is the automatic modeling to optimize 

unknown parameters—an especially useful feature in 

exploration wells where data is scarce. 

Features 

Provides the analyst with statistically optimum 

computations of: 

–Porosity 

–Water saturation 

–Multi-mineral volumes 

–Hydrocarbon density 

Uses all available log data simultaneously 

– Provides powerful quality control features 

– Cross-checks final interpretation results 

– Validates tool calibration and performance 

– Validates interpretive model and zone constants 

Interactive testing and refinement of interpretation 

parameters and models 

Allows combination of core analysis information with 

log measurements to help ensure accurate results 

Allows the analyst to use zoned constants and 

interpretive model selection in multiple wells to facilitate 

field study applications 

Minimum: at least one porosity measurement, resistivity, and GR or SP for shale volume ideal: all minimum inputs, plus 

caliper, Rxo-resistivity device, additional porosity sensors, MRIL ® , Spectral GR, and Sonic 

Outputs S w, S xo, V sh, φ eff, lithology, hydrocarbon weight, permeability, plus volumetric percent of selected minerals 


SASHA Shaly Sand Analysis 

SASHA analysis provides volumetric evaluation of gas, oil, 

and water in shaly sands and uses traditional density/neutron 

crossplot as the basis of its volumetric analysis. A variety of 

water saturation and permeability models are available to 

optimize the petrophysical analysis to the reservoir. 

The oil and gas company can use conventional wireline or 

LWD log data to evaluate potential hydrocarbon production 

from predominately shaly/sand depositional environments 

by using the results of this analysis. SASHA analysis produces 

a summary of the lithology in terms of percent volume shale, 

sandstone silt, dispersed clay, coal, and salt. It includes logic 

for detection and correction for salt, rugosity, and gas. It also 

computes water saturation (S w), lithology, effective porosity 

(φ eff), hydrocarbon density, and relative permeabilities in 

shaly/sand reservoirs. 

A number of different water saturation models may be 

chosen. Input from the client as to previous analysis or 

model preferences could avoid unnecessary guessing. 

SASHA analysis can also produce a summary table of net pay, 

porosity feet, and hydrocarbon feet for each potential zone of 

interest. 

Environmental corrections for the resistivity and porosity 

devices should be done prior to running SASHA analysis. 

Applications 

Formation lithology analysis 

Porosity, saturation, and hydrocarbon flags 

Overview of potential pay zones over the well 

Inputs 

Features 

Robust, traditional cross-plot approach 

Multiple saturation and permeability models 

Calculation of hydrocarbon density 

Summary table of each pay interval 

Minimum: at least one porosity measurement, resistivity, and GR or SP for shale volume 

Ideal: All minimum inputs, plus caliper, additional porosity, Spectral GR, and Sonic 

Outputs S w, S xo, V sh, φ eff, lithology, hydrocarbon weight, permeability 

Example SASHA analysis showing (l-r) shale/sand volumetric analysis; 

hydrocarbon weight analysis with oil (red) and gas (pink) volumes and 

pay flag (black); saturation analysis; relative permeability analysis 


HAL9120

CORAL Complex Lithology Analysis 

CORAL complex lithology analysis helps evaluate the 

potential production from complex or mixed lithology 

reservoirs using wireline or LWD log data. 

CORAL analysis computes water saturation (S w), lithology, 

effective porosity (φ eff) and relative permeabilities in 

carbonates and complex lithology reservoirs. 

CORAL analysis produces an analysis of the lithology in 

terms of percent volume shale, limestone, dolomite, 

sandstone, coal, and salt. It includes logic for detection and 

correction for salt, rugosity, and gas. 

CORAL analysis uses a traditional crossplot-based formation 

evaluation approach to determine shale volume, effective 

porosity, and water saturation. CORAL analysis also 

estimates relative permeabilities from several different 

models. 

A number of different water saturation models may be 

chosen. Input from the client as to previous analysis or 

model preferences could avoid unnecessary guessing. 

CORAL analysis also can produce a summary table of net 

pay, porosity feet, and hydrocarbon-feet for each potential 

zone of interest. 

Environmental corrections for the resistivity and porosity 

devices should be done prior to running CORAL analysis. 

Applications 

Formation lithology analysis 

Porosity, saturation, and gas flags 

Pay zone evaluation summary 

Overview of potential pay zones over the well 

Features 

Robust, traditional crossplot-based approach 

Flexibility for almost all lithology mixtures 

Multiple saturation and permeability models 

Summary table of each pay interval 

Inputs 

Minimum: Neutron, Density, Resistivity, and GR or SP. 

Ideal: All minimum inputs, plus Caliper, Spectral GR, Sonic, and Pe. 

Outputs S w , S xo , V sh , φ eff , Lithology volume percent, permeability 

Example of CORAL log analysis in late Pennsylvanian carbonates and 

sands. 


HAL9121

LARA Laminated Reservoir Analysis 

Many highly-laminated reservoirs have been missed in 

existing wells due to the coarse vertical resolution of older 

logging tools and the inadequate analysis techniques of 

traditional interpretation programs. To better detect and 

study thin-bed reservoirs, it has been necessary to develop 

new logging tools, post-processing techniques, and data 

analysis methods. 

High-resolution shale indicators allow separation of the sand 

and shale components but still require thin bed resolution of 

true formation resistivity and porosity. The measurements 

produced by high resolution shale indicators are used with 

those from conventional or resolution-enhanced porosity 

logging tools to improve the saturation analysis of the 

laminated reservoir. This is the basis of LARA laminated 

reservoir analysis. 

To determine shale volume, the high-resolution shale device 

data is first integrated to the vertical resolution of the 

porosity device. Then two medium-resolution shale volumes 

are calculated—one from the integrated high-resolution data 

and one from the porosity data. Device-specific shale 

parameters are automatically adjusted until the two volumes 

are equal. Then LARA analysis calculates the conventional 

total and effective porosities. It also determines the mode of 

clay distribution, i.e., dispersed or laminated. 

The high-resolution shale volumes are then used with the 

known shale resistivity to generate high resolution resistivity 

expressions that involve shale and non-shale volumes and 

resistivities. These expressions are integrated to the vertical 

resolution of the resistivity device. The integrated resistivity 

is equated to the measured resistivity, and the resulting 

equation solved to give the non-shale resistivity, which is 

essentially a shale-corrected true formation resistivity (R t). 

Finally, the calculated effective porosity and true formation 

resistivity are used in a modified Waxman-Smits equation to 

calculate S w . 

Applications 

Resolving gross shale volume percent to high resolution 

laminated and dispersed clay content 

Detection of thin-bed reservoirs 

Improve saturation analysis of the laminated reservoir 

Inputs 

Features 

High-resolution shale indicator generally yields 

significantly more accurate analysis in laminated 

reservoirs than standard shaly sand models 

Helps with the reliable quantitative interpretation of 

thinly laminated reservoirs 

Helps identify potential hydrocarbon production often 

missed by conventional analysis 

Thinly laminated hydrocarbon bearing zones above the main clean sand 

pay zones would have been overlooked with conventional log analysis. 

In this case, high resolution data from the EMI image tool was 

integrated into the LARA analysis. Note the gas effect density-neutron 

crossover in the clean sands and lack of crossover in the thinly 

laminated zone above the clean sand zone. 


HAL9123 

In addition to the minimum of a GR, resistivity and porosity measurement, one or more of the following thin-bed shale indicator inputs 

is required for LARA analysis: SED, Pe (unfiltered), Microresistivity (ML, MSFL), CAST, EMI, XRMI, OMRI, EVR-GR. 

The best high-resolution shale indicators are six-arm dipmeter or EMI, XRMI, OMRI, but alternatives include all of the above. LARA 

program requires only a single porosity device but yields better results when more than one is used. 

Outputs S w, S xo, V SH, φ eff, lithology hydrocarbon weight (oil, gas), permeability

Reservoir Characterization 

Borehole Image Analysis 

AutoDip and TrendSetter Services 

AutoDip and TrendSetter services automate dip and dip 

trend analysis of EMI, XRMI, and OMRI borehole 

data. These services save time and provide high-quality data 

that can help spot “hidden features” in sedimentary beds and 

laminates. 

AutoDip service automates high-resolution dip detection—a 

vast improvement on tedious manual dip picking. Unlike 

traditional dip computation methods, AutoDip service does 

not simply correlate raw resistivity data. This method 

operates independently of often inappropriate correlation 

parameters, such as correlation length, step length, and 

search angle. 

TrendSetter service augments AutoDip functionality by 

taking dip data and automatically sorting it into categories: 

Constant dip with depth 

Increasing dip with depth 

Decreasing dip with depth 

TrendSetter service helps characterize geologic features based 

on dip trends. AutoDip and Trendsetter services provide a 

continuous plot with a break out of dip trends and constant 

dips. These dips and trends can be easily recognized and 

incorporated into a geological model. 

AutoDip and TrendSetter services differentiate themselves by 

selecting bedding features more quickly and consistently 

than hand picking. This provides more time to view the 

results and interpret the data. 

Slumping and soft sediment deformation are evident in this section of 

log. The AutoDip program does a good job of capturing the 

changing dips. 


HAL7635

AutoDip Service 

AutoDip service uses data from all resistivity buttons—not 

just 4, 6, or 8—to more accurately determine dips. By using 

more data, more accurate dip readings are possible. 

AutoDip service translates the human visual experience of 

event correlation into an equation that quantifies visual 

recognition to obtain the optimal dip. The self optimizing 

algorithmic process¹ operates without the need to adjust 

correlation parameters, which can introduce bias into dips or 

even hide dips when using traditional methods. 

The AutoDip program works equally well in simple bedding 

or in more complex bedding environments. 

Applications 

High-resolution dip detection of EMI, XRMI, and 

OMRI borehole data to help spot “hidden features” in 

sedimentary beds and laminates 

Features 

Uses all buttons to compute dips 

Uses quality curves to optimize dip selection 

Removes user bias in selecting dips 

Consistent picks independent of interpreter bias 

Output curves that indicate degree of laminations 

Output curves that indicate degree of bed contrast 

Independence from search angle, correlation length, and 

step length 

¹Shin-Ju Ye, et al., Automatic High Resolution Sedimentary 

Dip Detection on Borehole Imagery (SPWLA 38th Annual 

Logging Symposium, 1997) 

Inputs EMI, XRMI, and OMRI data set 

Outputs Computed dips and dip trends 

TrendSetter Service 

The AutoDip program can generate many dips. The number 

of dips is partially determined by dip quality filters. During 

the analysis process, it is prudent to look for patterns to help 

recognize trends that can impact mapping, offset wells, and 

describe depositional environments and structural changes. 

TrendSetter service automatically separates dips into 

constant, increasing, and decreasing categories, making it 

easier to visualize changes and trends. 

TrendSetter service separates the dips from stratigraphic 

events such as current bedding, slumps, and drapes from the 

more constant structural dips, which allows better estimates 

of local structural dip. 

Applications 

Dip trend analysis of EMI, XRMI, and OMRI borehole 

data to help spot “hidden features” in sedimentary beds 

and laminates 

Features 

Automates the selection of dip trends 

Provides quality curves used to control grade of trend 

Removes scatter from structural dip trend 

Identification of other stratigraphic or structural events 

when used with other geologic data 

A user interface that provides flexibility and quality 

control 


HAL7642 

Trendsetter service eliminates need for hand-selecting dip trends. 


ReadyView Open-Hole Imaging System 

The ReadyView system provides easy-to-use interactive 

software for the analysis of acoustic and electrical wellbore 

image data. The ReadyView system consists of three 

separate applications that provide image and dip 

interpretation and 3D visualization of the wellbore. The 

ReadyView system can be used to determine both true and 

apparent bedding dip and can also be used to determine the 

distribution, orientation, and apparent aperture of natural 

and drilling-induced fractures. 

This innovative system uses a customized USB flash drive to 

store and launch the applications. Performance on the flash 

drive is comparable to running on a local hard drive. 

It provides unique accessibility to all types of wellbore image 

data, along with measurement and classification tools 

required for borehole breakout, structural, stratigraphic, and 

formation evaluation applications of image analysis. 

The software can be modified or augmented to meet the 

specific requirements of individual clients. 

Features 

Runs on Microsoft® Windows® 2000 and Microsoft 

Windows XP platforms 

Works with a wide range of wellbore image data 

including third party imaging tools, allowing full 32-bit 

RGB color resolution of acoustic and electrical image 

data 

User interface provides a comprehensive set of 

sophisticated, interactive measurement tools and the 

ability to more easily classify and describe features 

observed in these logs. In particular, the ReadyView 

system offers a series of 2D data filters (i.e. Sobel, 

Gaussian, Sharpen, Horizontal edge detection) to 

enhance the image 

Planar features can be displayed in stereographic 

projections or rose diagrams; tadpole profiles can be 

used to display planar data or wellbore trajectory 

Standard log profiles, including gamma and resistivity 

logs, can be imported and displayed as reference logs for 

formation interpretation 

Menus and dialog boxes allow quick scrolling, resizing, 

and selection of intervals of the data, making image 

analysis easy and straightforward 

Customers can pick and interpret their own dips, save 

and restore their own dip results, and export them in a 

variety of formats for transfer to other systems including 

OpenWorks and Microsoft Excel® applications 

All image projections and data analysis views may be 

saved in a variety of raster and vector formats for report 

generation 

Allows wellbore image data to be easily viewed in full 

color unwrapped views, polar cross-sections, 3D 

cylindrical displays, log profile views, and many others 

The ReadyView system is also an excellent archival 

system for use of the digital image data at a future date 

ReadyView System USB Flash Drive 


This example shows a 2D view of image data when launching ReadyView software. From left to right, the first tract 

is a compressed image, second tract static image, third tract is depth, fourth tract is a dynamically enhanced image 

and the right side is a Schmidt plot, image histogram, and a dip-azimuth plot. 


Facies Profile 

Facies profile is a multi-dimensional, dot-pattern 

recognition, clustering method based on nonparametric K— 

nearest neighbor and graph data representation. The 

underlying structure of the data is analyzed, and natural data 

groups are formed that may have very different densities, 

sizes, shapes, and relative separations. Facies profile 

automatically determines the optimal number of clusters, yet 

allows the analyst to control the level of detail actually 

needed to define the electro-facies. 

Facies profile partitions the reservoir into discrete electrofacies 

or flow units. Producing electro-facies is a common 

and valuable operation performed by oil companies to 

discriminate discrete reservoir components. These 

components are used to populate reservoir models, flow 

simulators, determine porosity/permeability relationships, 

and describe the reservoir. 

The facies profile model can be run with conventional log 

data (such as GR, RHOB, or ΔT), NMR data, and possibly 

other data (not yet tested). A texture profile model based on 

the same clustering method has been developed to extract 

texture from electric (EMI, XRMI, and OMRI data) 

image data. 

The facies profile analysis shows similarities to a core 

description that might be done on a whole core or outcrop. 

Grain size, cleanliness, or porosity increase toward the right 

and changes in facies correspond to different colors and 

patterns. The Facies profile analysis contains automatic 

ordering that performs the grain size or porosity function 

automatically. The lowest numbered electro-facies has the 

smallest grain size or porosity and the highest number 

electro-facies has the largest grain size or porosity. The 

smaller numbered facies would plot farthest to the left, and 

the larger numbered facies would plot farthest to the right. 

Applications 

Log interpretation that helps define 3D reservoir facies 

models describing the distribution of porosity, 

permeability, and capillary pressure in more detail than 

is possible with reflection seismology 

Determination of the optimal number of clusters, while 

still allowing the analyst to control the level of detail 

actually needed to define the electro-facies 

Track 4 shows nine electro-facies computed from the GR (Track 1 

black) RHOB (Track 3 red) NPHI (Track 3 green) and PE (Track 3 

magenta). Using these four inputs, facies profile is able to discriminate 

differences in the lithology (but not actual lithology) and automatically 

order them according to increasing grain size or porosity. The EMI 

image in Track 1 is provided to show the correlation between the image 

and electro-facies. 


HAL9129

Features 

Helps define layering and select the best options for 

production test interpretation 

Integrates geological insight into conventional log 

analysis 

Automatically clusters and orders log data for generating 

electro-facies. It processes conventional log data, array 

data, such as NMR T2 distribution, image texture 

parameters, (texture profile), or any combination of a 

wide range of data 

Partitions the natural pattern of the data without 

requiring the user to give the number of clusters 

Inputs 

Outputs 

Automatically proposes optimal number of clusters. 

Clusters are organized in a hierarchical way which can 

ease the interpretation 

Automatically orders the clusters in log space which uses 

coarse-to-fine self-organizing map (CFSOM). This 

ordering usually corresponds to the geological facies 

evolution order which is particularly important for 

assessing geological meaning of each of the facies and 

their vertical sedimentary sequences 

All the input curves must have the same step. Halliburton recommends placing the input curves to be used in a separate 

CLS file because numerous new curves may be generated. The output will have the step of the CLS file. 

ALPHA–The higher ALPHA the greater the smoothing. ALPHA can vary from 1 to 500. This parameter has been 

optimized and it is highly recommended that the user leave it at the default of 10. 

K–Another smoothing parameter that can vary from 4 to 20. The higher the number the greater the smoothing. K has also 

been optimized and it is recommended that the user leave it at the default of 5. The minimum number of electro-facies to 

compute. The maximum number of electro-facies to compute. The number of optimal electro-facies models generated by 

the program. 

EFAC_1, EFAC_2, and EFAC_3EFAC—stands for electro-facies. EFAC_1, EFAC_2, etc. are generated electro-facies 

model 1, 2, etc. Also see PARAMETER OM. 

Gives cluster kernels in log space order (after automatic ordering). 

The Kernel Representative Index of each data point. 

The Neighboring Index of each data point. It is unique for each data point for a given ALPHA. It measures the local data 

density around each point. Higher its value, higher its local density. 

The normalized Neighboring Index of each data point within the cluster. Because the cluster member configuration 

change with different electrofacies models, NNI is different with different electro-facies models. 


Net2Gross Sand Count 

The preferred approach for determining net pay in laminated 

sediments of fluvial and turbidite formations is to delineate 

sand layers from borehole image data. New image 

interpretation software, Net2Gross, has been developed to 

estimate the sand and pay counts within the subsurface 

sedimentary sequence logged by XRMI X-tended range 

imager tool or OMRI oil mud imager tool. The software 

exploits the XRMI and OMRI tool’s ability to resolve thin 

laminations and sedimentary structures. It applies threshold 

techniques to the pre-processed high resolution XRMI/ 

OMRI image and constructs secondary images for sand and 

pay. The analyst retains the flexibility to calibrate these 

images to the gamma ray and porosity logs using the 

cumulative distributions from all the logs to determine valid 

threshold values for the images. The software also generates 

cumulative sand and pay counts versus depth. An R-sand 

interpretation is also available by combining image data with 

triple combo data. This provides quantitative water 

saturation in laminated and dispersed shale environments. 

The sand image is constructed by applying an upper and 

lower threshold to the conductivity amplitude image, after 

calibration of this image to the neutron, density and gamma 

ray logs using the cumulative distributions from the logs and 

image data to determine valid threshold values. Pixels lying 

between the lower and upper threshold values, and greater 

than an analyst-specified cutoff are classified as sand. Sand 

pixels are then upgraded to pay if all of the following 

conditions are satisfied: the pixel's image conductivity is 

below a specified threshold, porosity greater than a threshold 

depth proximal to the pixel exists, and deep resistivity greater 

than a threshold depth proximal to the pixel exists. Finally, 

cumulative sand and pay counts versus depth are constructed 

by simply counting the sand and pay pixels. 

In Track 1, the sand image is presented as a binary image, 

black for shale and white for sand. Track 2 presents the pay 

image in which sands interpreted to be pay are assigned the 

color red. 

Features 

High-resolution net sand and net pay images and curves 

Cumulative net sand and net pay curve 

Logic to prevent interpretation of tight streaks as pay 

Interactive histogram based calibration of logging curves 

Accurate sand and net pay counts in laminated 

sediments of fluvial and turbidite formations 

Better agreement between core and log, net sand, 

and pay 

Combines image data and triple combo for an R-sand 

interpretation which provides water saturation for both 

laminated and dispersed shales 


ImagePerm 

ImagePerm is an image based approach providing a highresolution 

porosity and permeability curve as well as a highresolution 

porosity image and histograms. In addition, it 

provides a high resolution secondary porosity curve, which is 

useful for interpretation in the presence of vugs and 

fractures. 

The basic approach is to calibrate the image data to image 

porosity using filtering techniques. The image data is 

averaged over a moving window, and a transform is 

constructed which calibrates the average image data to 

porosity. This transform is then applied to the “pixel-bypixel” 

image data and a moving adjustment for bias is made. 

The final result is shown in Track 5, which shows the EMIP 

(or XRMI X-tended range micro-imager tool) porosity 

image scaled 0 to .3. Track 4 compares the total porosity 

PHIT from the neutron density logs (lazy black curve) with 

the image porosity averaged around the borehole (red curve) 

at each depth. It can be seen the calibration is correct and the 

resolution is improved for all the tight, low porosity streaks. 

A porosity histogram of the image data as shown in Track 6 is 

used to aid in the interpretation and detection of vuggy 

porosity. Secondary porosity should manifest itself in the 

histogram being bimodal with the highest porosity mode 

corresponding to secondary porosity. Given each image 

porosity histogram, the cumulative distribution can be 

computed and displayed. In particular, the cumulative 

distribution in Track 3 shows in red the variation in porosity 

of those 20% of the samples having the highest porosity. 

Without any sonic or core data, for illustrative purposes, 

these samples were assumed to be secondary porosity. This 

constant fraction is converted to a volume and displayed in 

Track 4 as the gray shaded portion of the display. 

This implementation is intended to support a highresolution 

prediction of permeability for carbonates. The 

Jennings-Lucia model which relates the porosity 

permeability transform to rock type has been implemented. 

One obtains rock type from looking at core data, or by 

calibration to core permeability. Track 2 shows the 

permeability from primary porosity as cyan, and from 

secondary porosity as shaded. The predicted permeability 

can either decrease or increase with secondary porosity, 

dependent upon the model selected. 

Features 

High resolution image porosity curve and image 

High resolution image secondary porosity curve 

High resolution micro porosity from MRIL® tool 

calibration 

Image depth based histograms for rock facies 

interpretation 

High resolution intergranular permeability 

Permeabilty correction for secondary porosity 

Rock type based high-resolution permeability 

Describes porosity and permeability in vuggy carbonate 

facies 

Helps identify thief zones in vuggy formations, thus 

aiding in well completion 

Helps identify productive zones in carbonates 

Better agreement between core and log, permeability, 

and porosity 


Borehole Geophysics 

Wellbore Seismic 

High Resolution Seismic Imaging—(Near Offset VSP, 

Fixed Offset VSP, Walkaways, 3D VSP, Salt Proximity 

Surveys, Microseismic Surveys) 

Halliburton provides high-resolution images in the vicinity 

of the borehole using a number of different techniques 

depending on the objectives and the geologic environment. 

The techniques include vertical incidence vertical seismic 

profiles (VIVSP) in deviated wells, salt proximity surveys, 

tomographic velocity analysis, fixed offset VSP surveys 

(FOVSP), 2D walkaway surveys, 3D VSP, and ExactFrac® or 

microseismic surveys. 

Halliburton is an industry leader in providing advanced 

source and downhole array technologies for borehole 

seismic. Halliburton’s expertise serves to benefit operators 

with reduced rig time and improved data quality. Advanced 

source and receiver technology is crucial towards obtaining a 

more accurate and comprehensive geological picture of your 

well, field, or reservoir. 

Halliburton can offer custom built solutions for client’s 

seismic imaging field needs. For survey planning, we use the 

most advanced 3D wavefront modeling software available, 

GeoTomo’s VECON software. 

Multi-component arrays can be mobilized downhole to more 

accurately record true amplitude information of both 

compressional and shear waves. 

Compressional and shear images can be used in conjunction 

for lithology and fluid identification. Surveys can be repeated 

for time-lapse 4D views of fluid movements. 

Downhole seismic tools can also be used to passively listen to 

the reservoir and to map fluid movements, fault reactivation, 

or active fracture monitoring. 

A full array of tools is available for analyzing high resolution 

seismic data for reservoir imaging. Halliburton offers 

advanced pre-processing, including multi-component 

wavefield separation and final imaging using pre-stack depth 

migration (PSDM). 

High Resolution Seismic Imaging Features 

Generation of high-resolution multiple free images 

Mapping of steep structures (such as salt flanks) 

Detailed velocity cubes in areas of laterally changing 

velocity (shallow gas, permafrost, salt, etc.) 

Map structure, stratigraphy, lithology, and fluids with 

higher resolution and confidence than can be obtained 

with surface seismic 

Improve a poor data quality area or overcome no-data 

areas 

High Resolution Seismic Imaging Applications 

Profiling salt dome flanks 

Detecting natural fractures 

Enhanced seismic velocity analysis 

Primary seismic reflector identification 

Porosity and permeability estimation 

Anisotropy determination 

AVO analysis 

Determine height, length, and width of well frac or 

stimulation process 

Associated Answer Products 

Vertical incidence VSP 

Synthetic seismogram 

FWS full wave sonic processing 

ExactFrac® services 


Reservoir Geophysics 

Long Array Multi-Component Acquisition Tools 

Halliburton offers survey planning, data acquisition, and 

data processing using multi-component long seismic arrays. 

Each tool combines advanced-source technology with 

industry leading multi-component and anisotropic 

migration software for a complete package of advanced 

custom designed reservoir imaging systems. Systems include 

the GeoChain VSP downhole receiver array. 

GeoChain VSP Downhole Receiver Array 

The GeoChain vertical seismic profile (VSP) array is 

designed for large borehole imaging surveys and can be used 

in open and cased holes with standard seven-conductor cable 

even in deep and hostile environments. 

GeoChain VSP Receiver Array Features 

Based on the proven ASR-1 downhole geophone 

Can be used in wells up to 25,000 psi and with hole sizes 

from 3.5-in. to 22-in. 

Unique ACS active cooling system allows continuous 

operation up to 356°F (180°C) 

Up to 42 satellites can be used in the array with a 

maximum tool spacing of 200 ft 

All satellite locking arms open and close simultaneously, 

and the entire string can lock into a 9.625-in. well in only 

30 seconds 

Can be run in the following configurations: 

No. of Tools Sample Rate 

5 1/2 ms 

10 1 ms 

21 2 ms 

26 2.5 ms 

32 3 ms 

42 4 ms 


3D VSP imaging 


Interwell imaging 

ExactFrac® (microseismic) services 

Synthetic Seismic and Sonic Log Calibration 

The synthetic seismogram obtains an accurate tie between 

well logs measured in depth and the surface seismic image 

measured in two-way time. Correlation between logs and 

seismic is important to verify interpreted horizons and to 

help determine the true phase of the surface seismic 

(important for advanced lithologic and fluid interpretations 

from seismic data). 

An accurate synthetic depends on sonic log calibration using 

data from a vertical seismic profile (VSP) or check shot 

survey. This calibration is necessary for a number of reasons 

such as: 

Sonic log and surface seismic are measured at different 

frequencies (dispersion) 

Sonic log and surface seismic can measure different rock 

and fluid volumes (fluid differences, invaded zones, 

damaged borehole, non-vertical ray paths, etc.) 

Calibration of the sonic log includes an analysis of the data to 

determine the cause of the differences (drift) between the 

sonic and the check shots. 

Depending on the cause of the drift, different methods of 

correction are used. The corrected sonic log is converted to 

interval velocity. Acoustic impedance is calculated using the 

corrected velocity log and the bulk density. Changes in 

acoustic impedance are used to create a reflection coefficient 

log, which is subsequently convolved with a desired wavelet 

to create a synthetic seismic trace. 

Recording of a shear sonic log or calculation of a synthetic 

shear log allows calculation of a 2D synthetic to analyze or 

predict AVO effects on the surface seismic. Perturbation of 

the rock parameters also allows study of the effects of fluid 

and lithology changes on the seismic character. 

Synthetic Seismic Features 

Helps promote accurate tie between well logs and surface 

seismic including phase determination 

Allows identification of multiples on the surface seismic 

Allows study of fluid and lithology effects on the seismic 

character 



High resolution seismic imaging (walkaway, fixed offset, 

3D VSP, salt proximity, AVO Studies) 



Vertical Incidence Vertical Seismic Profiling (VIVSP) Analysis 

The VIVSP analysis is a downhole seismic survey with the 

surface source positioned vertically above the geophones 

anchored in the well. In a vertical well, it is known as a zero 

offset VSP (ZOVSP) with the source positioned in a single 

location near the wellhead. In highly deviated wells, the 

source is moved along with the downhole geophone tool to 

keep the source vertically positioned above the geophone 

tool at each level. 

VIVSP analysis is useful for facilitating more accurate timedepth 

correlation between your well logs and your surface 

seismic. It is also useful for determining the phase of your 

surface seismic and for identifying multiples. 

VIVSP data provides an indispensable bridge between sonic 

log data and surface seismic data. In areas where it is difficult 

to obtain a good tie between the synthetic and the surface 

seismic, the VIVSP can be helpful to identify and resolve the 

differences. 

VIVSP is also very useful for predicting lithology, fluids, and 

pore pressure ahead of the bit. Velocity trends that are useful 

for predicting pore pressure are calibrated at the well. 

VIVSP data is typically higher frequency than the surface 

seismic and can be used to better understand the reflectivity 

seen in the surface seismic. 

VIVSP data can be useful for computing the dip of the 

reflecting horizons in the vicinity of the borehole. 

This can be used to confirm dips seen on dipmeter tools and 

help project these dips away from the well. 

In deviated wells, the VIVSP also delivers a high resolution 

2D image beneath the wellbore. This image is typically 

higher frequency than the surface seismic, multiple free, and 

tied directly to the wellbore in depth. 

Halliburton uses advanced proprietary software to handle 

VSPs in the most demanding geologic environments 

(advanced editing, multi-component wavefield separation, 

interpolation, deconvolution, and migration tools). 

VSP software and processing can be used in the field, in a 

computing center linked to the wellsite, or in the client 

offices for special projects. 

VSP acquisition teams utilize customized energy sources and 

the most advanced seismic tools available to record high- 

quality seismic data. The rugged, computerized logging 

systems precisely position the geophone tool in the well, 

properly synchronize the energy sources, and accurately 

transfer the measured data to the surface. The data obtained 

from VSPs provide extremely important information for 

enhancing and supplementing surface seismic data. 

VIVSP Features 

Allows detailed analysis of the downgoing and upgoing 

wavefield 

Real seismic trace rather than synthetic for log seismic 

correlation 

Provides detailed velocity analysis 

VSP Applications 

Direct correlation between surface seismic data and logs 

recorded in depth 

Calibrate wireline sonic data for correlating synthetic 

seismograms with conventional seismograms 

Mapping geologic structure in the vicinity of the wellbore 

Predict stratigraphy, lithology, and structure ahead of the 

drill bit to help save drilling time and costs 

Improve poor data-quality area or overcome no-data area 

Helps profile salt dome flanks 

Helps detect natural fractures 

Aids seismic identification of lithology 

Prospect delineation 



Analyze multiple patterns 

Deconvolution operator for surface seismic data 

processing 


2D and 3D stratigraphic and structural imaging 

Helps locate overthrust granite/sediment interface 

AVO analysis 




ocean bottom cable, salt proximity, AVO studies) 



ExactFrac ® Services 

Halliburton eases frac modeling concerns by taking a fullservice 

approach to logging, offering both dipole sonic and 

borehole seismic services. To give engineers the answers they 

require, our microseismic techniques provide real-time 

assessments of fracturing processes using two wells: 

A stimulation well where actual frac jobs are under way 

A monitor well equipped with a downhole geophone 

tool array with multiple sensors 

These microseismic techniques provide accurate information 

on the length, height, and distance of the frac being 

generated in the formation and can dramatically optimize 

the placement of future wells. 

ExactFrac Services Features 

Allows operators to optimize drilling program in field 

Improves later frac jobs (only zone you need to frac) 

Minimizes uncertainty in your fracturing program 


Acoustics and Rock Properties 

Anisotropy Analysis 

Sonic anisotropy data—the directional sound attenuating 

characteristics of the reservoir—is used to improve the timeto-depth 

correlation since both fast and slow shear waves 

may be present. It also helps to develop synthetic 

seismograms using both the fast and slow shear wave and 

their orientation to improve 3D seismic analysis and future 

seismic acquisition. 

The waveform data from the WaveSonic® crossed dipole 

sonic tool is analyzed with the anisotropy waveform 

processing model to obtain the fast and slow shear wave 

travel times and their orientation in the formation. The 

anisotropy analysis processing engine is a simultaneous 

inversion technique which uses all 64 dipole waveforms, 

from the in-line and crossed-line transmitter-receiver arrays. 

The objective function includes all combinations of all 

waveforms, so it maximizes the redundancy which improves 

the robustness of the processing method. 

The minimum and maximum principal stresses and stress 

field orientation are calculated by combining oriented 

slowness data with overburden and pore pressure data. This 

information is vital for geomechanical analysis, wellbore 

stability, and production enhancement treatment design. 

Sonic anisotropy and the orientation of the anisotropy can be 

used to determine the orientation of natural fractures. Sonic 

attributes such as P-wave slowness, fast, and slow shear wave 

travel time, can be used for identification of compressive 

fluids in the pore space. This allows planning of the best 

completion method and builds reservoir understanding to be 

applied to the next well. 

Applications 

Analyze WaveSonic tool waveform data to identify fast 

and slow shear wave travel times and their orientation in 

the formation 

Develop synthetic seismograms to improve 3D seismic 

analysis and future seismic acquisition 

Identification of compressive fluids in the pore space to 

maximize completion planning 

This is an example of fracture anisotropy. The fast and slow shear wave 

travel times are presented in Track 3. The azimuth of the fast shear wave 

is presented in Track 2 along with its uncertainty. The percent 

anisotropy is presented in Track 4, and shaded when the anisotropy is 

greater than 5%. The anisotropy is also presented in an image on the far 

right-hand track. North is on the right and left-hand edges of the plot 

and South is in the middle. The color intensity is proportional with the 

magnitude of the anisotropy. The rose plots in Track 4 shows the change 

in azimuth of the anisotropy. The energy ratio curves shaded in Track 1 

identify the anisotropy as being a result of natural fractures. 


HAL9130

Features 

WaveSonic® tool provides simultaneous monopole and 

crossed dipole sonic information 

The low frequency flexural wave travels at the true shear 

slowness of the formation—dispersion corrections for 

shear wave slowness are not required 

A low frequency monopole source is utilized, so the 

P-wave and flexural wave data have similar depths of 

investigations well beyond any near-wellbore alteration 

The wellsite products from the WaveSonic tool are the 

X-X and Y-Y flexural (shear) wave slowness (time travel) 

and the monopole P-wave slowness 

Depth shifting of the waveform data is not required since 

the X-X and Y-Y depth dipole transmitters are on a 

common depth 

Inputs 

Outputs 


RockXpert analysis–sand production and fracture 

strength analysis 

FracXpert analysis–fracture stimulation zoning 

analysis 

Navigation data, all in-line and cross-line dipole waveforms, processing window starting time and processing window 

width 

Fast and slow shear wave travel time and their corresponding orientations, anisotropy (as curve and image), rose plots of 

azimuth of the fast shear 


RockXpert2 Analysis 

Knowledge of rock properties and borehole stresses as 

provided by Halliburton’s RockXpert2 analysis allow 

drilling, completion, and stimulation optimization. It has 

been estimated that borehole stability problems cost the oil 

industry more than $2 billion annually. 

Sloughing or collapsed wellbores can stick downhole tools 

and tubulars, which lead to lost rig time, expensive fishing 

jobs, side-tracking, or even well abandonment. Inadvertent 

fracturing of weak formations can result in lost circulation, 

and improperly planned hydraulic fracturing operations can 

give disappointing production results. 

RockXpert2 analysis provides critical information for 

designing fracturing programs, planning drilling operations, 

and evaluating sanding potential. The RockXpert2 program 

uses well log data to calculate rock mechanical properties and 

borehole stresses. 

These rock mechanical properties include Poisson’s Ratio, 

Young’s Modulus, shear modulus, and bulk modulus. The 

stresses include axial, tangential, radial, maximum 

horizontal, and minimum horizontal. 

The use of RockXpert2 analysis allows the customer to drill, 

complete, stimulate, and produce the well at the most 

economical cost. Wells can be drilled to avoid geomechanical 

problems including lost circulation zones, sanding potential, 

and borehole collapse, but the well can be completed, 

stimulated, and produced without causing tensile, shear, or 

cohesive failure, and pore collapse. 

Applications 

Reduce the risk of losses from borehole instability 

Determines optimum mud weights required to prevent 

sanding and fracturing during drilling operations 

Evaluate a well's sanding potential to determine whether 

gravel packs or frac packs are necessary 

7 9 11 13 15 17 19 21 23 25 

Mud Weight - Pounds per Gallon 

At any specified point along a proposed or existing well path, 

RockXpert2 analysis can identify stable borehole conditions as a 

function of mud weight and borehole deviation. 

RockXpert2 logs indicate the safe mud weight range to provide sanding 

and formation breakdown, as shown in Track 2. The logs also include 

gamma and caliper curves in Track 1, predicted maximum borehole 

deviation in Track 3, and lithology information in Track 4. 


HAL951 

HAL157 

Borehole Deviation 

90 

80 

70 

60 

50 

40 

30 

20 

10 

0 

5 

Shear 

Failure 

Stable 

Borehole 

Tensile 

Failure

Features 

Provides valuable input to fracture-design programs that 

predict fracture geometry and that help select fracturing 

fluids, proppants, and pumping schedules 

Determines the mud weights required to prevent sanding 

and fracturing during drilling 

Provides optimal direction in which to drill deviated, 

horizontal, and extended-reach wells to maximize 

borehole stability and increase the effectiveness of 

subsequent hydraulic fracturing 

Assists in evaluating a well’s sanding potential to 

determine whether a gravel pack or frac pack may be 

necessary to help maintain production at optimal levels 

Helps assist in determining the maximum amount of 

drawdown to eliminate both sanding potential and 

borehole collapse 

Computations use data from continuous well logs rather 

than from core or microfrac measurements made at 

discrete points 

Computes stress magnitude and takes into account 

borehole orientation relative to stress-field orientation 

Results can be input directly into Halliburton’s 

FracXpert program 

Results can be normalized to core-analysis results. 

Halliburton maintains an advanced rock mechanics 

laboratory that provides comprehensive core analysis 

Inputs Compressional wave travel time, ΔT C, shear wave travel time, ΔT S, bulk density, VSH, pressure gradients 

Outputs Poisson’s Ratio, Young’s Modulus, shear modulus, bulk modulus, fracture pressure, collapse pressure 


FracXpert Analysis 

FracXpert analysis provides total data integration for 3Dfracture 

modeling. The FracXpert log provides automatic 

zoning based upon stress contrasts and averages the design 

parameters for each zone. It includes a presentation of log 

data that includes lithology, porosity, saturations, 

permeability index, and borehole stress information. 

FracXpert analysis provides linkages between the actual well 

properties and the fracturing design models. The automatic 

zoning removes possible design errors based on incorrect 

observations by the stimulation design engineer. This 

extremely fast process allows different scenarios to be 

analyzed and processed in both FracXpert analysis and the 

fracture modeling programs. After the stimulation is 

performed, modifications can be made to both models to 

accurately account for the stimulation response. 

Early frac design models did not include important design 

criteria such as pumping rates, fluid efficiencies, or treatment 

volumes. The FracPro program incorporates all these 

additional job parameters to accurately model, optimize, and 

execute frac operations. 

The rock mechanical data is taken from the results of 

formation strength-borehole stability analysis programs such 

as RockXpert2 analysis. The analyst needs to run a 

volumetric log analysis model to find both the shale volume 

needed for the rock mechanical programs and to compute 

the permeability. 

FracXpert analysis differentiates itself from other zoning type 

logs which usually do not have adequate log processing 

capabilities. In that case, the log analysis or the picking of the 

relevant logging parameters is still done by hand, and the 

quality depends heavily on the experience of the stimulation 

design engineer. Several consultants have a similar approach 

to hydraulic fracture design. 

The depth track provides zonal numbering, pay and bad hole flags, 

perforations, and perforation numbering. The zonal numbers are 

assigned to the selected zones as determined by the zoning process based 

on fracture tensile pressure. Track 1 contains CORAL lithology track 

consisting of shale, dolomite, limestone, sand, and porosity. Track 2 

presents that calculated water saturation. Track 3 displays CORAL 

analysis results that include effective porosity, water, and hydrocarbons. 

Track 4 presents the fracture tensile pressure and gradient from 

RockXpert2 analysis. Track 5 provides five different flow calculations to 

help determine the economic potential of each zone. Track 5 also displays 

two normalized curves that help interpret zones of interest: permeability 

feet (NKH) and porosity feet (NPORH). Both are normalized from 0 to 1 

over the entire well. 


HAL9131

Applications 

Total data integration for 3D fracture modeling 

Log processing using automatic zoning 

Features 

Automatic zoning helps define different layers within the 

formation for more accurate and consistent results 

without bias of the user 

Outputs include a well log plot, tabular listings, and an 

ASCII data file for input to 3D models 

Economic models and reservoir simulation reports are 

generated for accurate comparisons 

Stress information is gathered from FWS full wave 

sonic or dipole sonic logs 

Software can use permeability from conventional 

saturation/effective porosity relationships or from 

nuclear magnetic resonance logs 

Inputs Poisson's Ratio, Young's Modulus, minimum horizontal stress, permeability, pore pressure, and shale volume 

Outputs 

Automatic zoned averaging of the rock mechanical properties and volumetric data. Text files for simulators and 

stimulation programs. 


AcidXpert Analysis 

AcidXpert analysis aids in the design of stimulation 

treatments on carbonate rocks. The AcidXpert process 

provides a standard log presentation and associated text files 

that allow importation into other analysis packages. 

The success of matrix acidizing treatments depends on the 

placement of acid for efficiently removing near-wellbore 

formation damage. The type and composition of the acid is 

selected due to the rock matrix involved. The acid should be 

placed so that all potentially productive intervals accept a 

sufficient quantity of the total acid volume. If significant 

permeability or formation damage variations are present in 

the interval to be treated, acid will enter the zones with the 

highest permeability or least formation damage, leaving little 

acid to treat what may be the most productive zones. 

AcidXpert analysis is a process to collect and interpret the 

available data to maximize the stimulation effort. AcidXpert 

analysis provides answers for the following questions: 

With a complex lithology, how detrimental are the 

carbonate mineralogies to production enhancement? 

Is there a wide variance in the rock mineralogies? 

Is there sufficient permeability for the well to flow? 

Are natural fractures present, and do they intersect the 

wellbore? 

What is a reasonable expectation for production? 

How should the stimulation treatment be modified for 

specific scenarios? 

What factors require attention? Is the right information 

available to make this judgement? 

AcidXpert analysis automatic zoning provides a superior 

method for stimulation evaluation. Additionally, generated 

text files allow easy input into several analysis models 

including reservoir stimulation, economic, and stimulation 

design. 

There might be different stimulation scenarios depending 

upon the log data, and AcidXpert analysis allows these 

scenarios to be modeled efficiently and effectively. The 

minimal data required by AcidXpert analysis includes 

resistivity, density, and neutron log data along with 

volumetrics. Additional processing can be used if FWS full 

wave sonic logs, MRIL®, and imaging logs are available. 

Matrix acidizing requires basic triple combo data and 

volumetrics 

Acid fracturing requires the components necessary for 

Matrix acidizing plus FWS full wave sonic tool data 

StiMRIL process requires the components of acid 

fracturing plus MRIL® data 

Within the depth track on the left side of the log are perforations, 

perforation number, a bad-hole indicator, pay flag, and the numbering 

assigned to the selected zones as determined by the zoning process. The 

red lines across all the tracks delineate the zones that were chosen based 

upon solubility. Track 1 contains gamma ray and temperature. Track 2 is 

the solubility curve, a sum of the limestone and dolomite minerals on a 

depth-by-depth basis. The pink shading indicates zones that could 

effectively be treated by acid stimulation. Track 3 provides lithology data 

that was generated by CORAL analysis. Track 4 presents that 

calculated water saturation. Track 5 displays analysis results that include 

effective porosity, water, and hydrocarbons. Track 6 presents a calculated 

permeability and effective water permeability. 


HAL9132

Applications 

Design of stimulation treatments on carbonate rocks 

Import standard log presentation and associated text 

files into other analysis packages 

Collect and interpret available data for stimulation 

treatments 

Inputs 

Features 

Automatic zoning based on the rock matrix, fracture 

initiation pressures, or permeability 

Part of a comprehensive approach to acidization that 

improves well performance 

The use of the automatically generated text files allows 

easy linkages to reservoir stimulation, reservoir 

performance, and economic models 

Standard processed volumetric data including porosity, matrix lithology, permeability, and water saturation. Additional 

inputs can include sonic and MRIL ® data. 

Outputs Standard zoned log presentation along with automatically generated text reports. 


Reservoir and Production Engineering 

Reservoir Testing Studio 

RTS Reservoir Testing Studio 

RTS reservoir testing studio provides real-time analysis of 

data while it is being acquired to improve test quality and 

shorten rig time. RTS analysis features Halliburton's 

proprietary Exact and FasTest® analysis service techniques 

as well as conventional Horner (radial) and spherical time 

plot well test routines. RTS studio is designed to work with 

Halliburton's InSite® real-time data management and 

distribution system. The InSite Anywhere® option provides 

real-time access to RTS analysis plots, from anywhere and at 

anytime, with a standard internet connection. A report 

generator compiles the pressure transient analysis into 

reports that contain summary tables, gradient plots, and all 

the analysis plots. The summary tables can be exported to 

Microsoft® Excel® spreadsheets or Microsoft Word® tables. 

Applications 

Analysis of drawdowns and buildup pressure transients 

Determine pressure transient flow regime (spherical or 

radial) 

Summary tables of test results 

Pressure gradient analysis plots 

Sample PVT closed chamber testing 

Features 

QC pressure transient data 

Makes data selections for gradient analysis 

Provides project formation pressure (P*) 

Estimates mobility (1,000 - 0.001 md/cp) 

Estimates of anisotropy (kv/kh) Documents results in a final report 

The following plots and analysis techniques are available 

with RTS analysis. 

Pressure Time Plot 

The pressure time plot is the primary display that documents 

the data to be analyzed. The data selections made are later 

summarized in tabular form. From these data selections, an 

initial estimate of the formation mobility is made using the 

raw data (M raw drawdown mobility). The pressure time plot 

also includes a pressure stability plot with a wrapping scale 

from 0 to 10 or 0 to 1 psi so that the pressure can be observed 

on an expanded scale. 

RTS analysis pressure time plot is used to make data selections, which 

are documented in summary tables. Additionally, the results are used to 

create gradient plots and calculate the drawdown mobility (md/cp). 


Exact Buildup Analysis 

The Exact buildup analysis can be used to estimate 

spherical mobility (M s Ex) and formation pressure (P* Ex) 

over a wide range of mobilities (i.e., 0.001 to more than 

1000 md/cp). Conventional methods of analysis use late time 

data which requires pressures to stabilize after storage effects 

have dissipated. For low mobility zones (less than 

1 mDarcy/cp), this can require long buildup times, but Exact 

analysis can match the early time data thus shortening the 

test time required. In higher mobility, Exact analysis can also 

be used to provide accurate estimates of mobility and 

formation pressure. 

Exact Anisotropy Analysis Plot 

The Exact anisotropy plot is a buildup analysis method used 

for a vertical interference testing (VIT). The pressure 

recorded at a vertical monitoring probe is combined with the 

source (either probe or straddle packer) buildup analysis to 

determine the horizontal mobility (M hrz ex ) and the ration of 

vertical to horizontal mobility, Aniso (k v /k h ) ex . 

The RTS Exact analysis plot is a priority analysis technique designed 

to be used over the entire range of operation for formation testers. In 

addition to estimating the mobility from the buildup, the formation 

pressure can be estimated before the shut-in pressure is established, 

saving rig time. 

Example of an Exact Anisotropy Analysis Plot 


FasTest ® Buildup Analysis 

FasTest® buildup analysis can be used when mobility is above 

1 mDarcy/cp. Originally developed for well test surge or 

impulse testing analysis, it is also well suited for SFT and 

RDT tool buildup analysis. FasTest analysis is considered 

more reliable than traditional methods because it does not 

depend on an accurate estimate of the drawdown period or 

rate. Therefore, it is ideal for buildups where the sample 

chamber is used to create the pressure impulse. FasTest 

analysis can: 

Save rig time by terminating tests as soon as a sufficient 

amount of data is obtained 

Analyze sample chamber pressure pulse to determine 

permeabilities up to at least 1 Darcy (Mfast ) for both 

spherical or radial flow regimes 

Determine flowline storage effects on measured pressure 

Provide accurate calculated sandface pressure estimates 

(P* Fast) 

Horner Time Plots 

Horner time plots are the traditional technique for analyzing 

pressure transient analysis data. Both spherical and radial 

time domains are available with the projected formation 

pressure (P*), Horner mobility being determined from the 

slope of a line formed from a regression of the data on a 

radial or spherical time plot. Horner interpretation for 

wireline testers is generally used for zones with mobilities 

above 1md/cp. 

RTS FasTest® analysis service plot is used for buildup analysis in more 

permeable zones (i.e., > 1md/cp). The FasTest analysis is very flexible and 

can be used for pretests as well as sample chamber surge tests. Either 

spherical or radial flow regimes can be used. 

RTS analysis Horner plot offers a traditional method of analyzing 

pretest buildups. Either spherical or radial flow regimes can be used. 


Log-Log Derivative Analysis Plot 

This plot verifies the flow regime and data quality of the 

pressure transient. The FasTest® analysis service derivative 

and pressure differential of the buildup data is presented in 

this plot. Either a spherical time or conventional radial time 

derivative can be chosen so that a stable horizontal line 

represents infinitely acting flow for either regime. 

RTS analysis log-log derivative plot is based on the FasTest® analysis service derivative and is used to verify 

the flow regime of buildups and evaluate the quality of the pressure transient. 


M 

spher 

M 

1 

1. 

5 

⎛ 

⎞ 

⎜ 

1. 

5 

⎟ 

⎛1013 

⎞⎜ 

Vo 

φ c f 

= ⎜ ⎟ 

⎟ 

⎝ 4π 

⎠⎜ 

⎟ 

2. 

5⎛ 

dp ⎞ 

⎜ t ⎜ ⎟ ⎟ 

⎝ ⎝ dt ⎠ ⎠ 

radial 

⎛ ⎞ 

⎜ ⎟ 

⎛1013 

⎞⎜ 

Vo 

= ⎜ ⎟ 

⎟ 

⎝ 4π 

⎠⎜ 

⎛ ⎞ ⎟ 

2 dp 

⎜ ht 

⎜ ⎟ ⎟ 

⎝ ⎝ dt ⎠ ⎠

PVT Analysis 

A PVT plot is available for the RDT reservoir description 

tool service. This is a closed chamber in-situ sample analysis 

test that is performed automatically during the pumping 

process and after a sample is taken. The bubblepoint and 

fluid compressibility is determined. 

Formation Test Summary Program (FTS) 

The FTS program compiles RTS pressure test analysis data 

and creates gradient plots and summary tables. When 

selections are made from real-time data, they are 

automatically added to the gradient analysis. This allows 

multiple zones, gradients, and contacts to be identified. A 

manual input mode is also available. 

Applications 

A true vertical depth survey log for correcting depth 

measurements 

Identify multiple zones, gradients, and contacts 

Features 

Multiple gradient plots for each zone 

An unlimited number of gradient lines that can be 

generated from RTS analysis data 

Fluid contacts can be identified and annotated on plots 

Minimizes errors because data is automatically imported 

from the RTS analysis program 

Verifies the quality of pressure data by automatically 

producing the hydrostatic gradient 

+ + 

+ 

0.10 

0.09 

0.08 

0.07 

0.06 

0.05 

0.04 

0.03 

0.02 

0.01 

0 

+ +++++++++++++++++++++++++++++ 

+++ 

+++ 

+ 

++ 

++++++ 

+ + 

+ + ++++++ 

+ 

+ 

7 

6 

5 

4 

3 

2 

1 

0 

0 500 1000 1500 2000 2500 3000 3500 4000 

Pressure (QPRS, psi) 


Pretest Volume Fraction (^Volume/Total Volume) 

PVT plots the volume fraction against the pressure. The linear 

portion of the plot determines the compressibility and when the 

curve deviates from this linear trend, the bubblepoint is detected. 

Tvd (ft) 

3200 

3300 

3400 

3500 

3600 

HAL9249 

PRESSURE GRADIENT PLOT 

Legend 

Unassigned Pform 

Group 1: 0.377 

Group 2: 0.261 

Group 3: 0.275 

Group 4: 0.957 

Group 5: 0.268 

3,613.351 ft 

3700 

400 600 800 1000 1200 1400 1600 1800 

Pressure (psi) 

Pressure gradient plots allow multiple zones, gradients, and contacts to 

be identified. Plots are derived from RTS analysis data and are 

automatically added to the gradient analysis when data selections are 

made from real-time data. A manual input mode is also available. 

Pretest Volume Change (cc)

Test 

No. 

Test Identification 

MD 

(m) 

TVD 

(m) 

Hydrostatic 

Pressure 

Phyds1 

(psi) 

Phyds2 

(psi) 

Example of Pressure Test Summary 

Equivalent Mud 

Weight 

EqFmM 

w 

#/Gal 

EqBhMw 

#/Gal 

Test Pressures Test Times 

1.1 2892.90 2755.23 4219.07 4217.79 6.5 8.98 4301.96 3002.60 3053.43 286 342 395 

1.2 2892.90 2755.23 4219.07 4217.79 6.5 8.98 3050.07 2996.47 3053.41 470 487 627 

2.1 2899.98 2761.96 4220.33 4224.27 6.49 8.96 4328.67 2985.81 3058.43 353 381 492 

2.2 2899.98 2761.96 4220.33 4224.27 6.49 8.96 3058.30 3036.94 3058.19 505 564 574 


Pdd 

(psi) 

Tfu 

(sec) 

Tstop 

(sec) 

Tdd 

(sec) 

Pfu 

(psi) 

Pstop 

(psi) 

Remarks 

10 cc 

Effective 

Pre Test 

10 cc 

Effective 

Pre Test 

Good 

Test 

10 cc 

Effective 

Pre Test 

3.1 2909.48 2770.97 4234.52 4232.36 6.48 8.96 3074.09 1682.64 3064.64 437 512 1119 Tight Test 

4.1 2984.55 2842.19 4312.47 4313.45 6.69 8.89 4396.87 3141.33 3242.76 308 381 506 

Good 

Test 

4.2 2984.55 2842.19 4312.47 4313.45 6.69 8.89 3242.76 3134.49 3242.66 506 580 708 

Good 

Test 

Legend: 

Phyds1 Initial Hydrostatic Pressure 

Phyds1 Final Hydrostatic Pressure 

Pdd Initial Drawdown Pressure 

Pfu Final Drawdown or Fillup Pressure 

Pstop Final Buildup Pressure 

EqFmMw Equiv. Formation Mud Weight (PStop / (TVD*Constant)) 

EqBhMw Equivalent Borehole Mud Weight (Phyds1 / (TVD*Constant)) 

Tdd Initial Drawdown Time 

Tfu Final Drawdown or Fillup Time 

Tstop Final Buildup Time 

The Pressure Test Summary table compiles all pressure selections from the RTS program. Pressure tests are documented 

in a single table that is plotted on the log. This data is also available in ASCII form that can be easily imported into a spreadsheet for analysis. 

Test 

No. 

Example of Pressure Transient Analysis Summary 

Test Identification PTA Pressure PTA Mobilities Dual Probe Anistropy 

MD 

(m) 

TVD 

(m) 

Psphere 

(psi) 

Pfast 

(psi) 

Ptight 

(psi) 

Msphere 

(md/cp) 

Mfast 

(md/cp) 

Mtight 

(md/cp) 

Msdd 

(md/cp) 

Mh 

(md/cp) 

ANISO 

(Kv/Kh) 

Remarks 

1.1 2892.90 2755.23 3053.73 0.00 3052.98 2.10 0.00 5.30 11.69 Good Perm 

1.2 2892.90 2755.23 3053.57 3053.59 0.00 3.52 3.96 3.96 34.81 Good Perm 

2.1 2899.98 2761.96 3058.57 0.00 0.00 1.75 0.00 0.00 16.46 Good Perm 

2.2 2899.98 2761.96 3063.21 0.00 0.00 1.79 0.00 0.00 26.41 Good Perm 

3.1 2909.48 2770.97 0.00 0.00 3057.06 0.00 0.00 0.04 0.32 Low Perm 

4.1 2984.55 2842.19 3243.07 0.00 0.00 1.27 0.00 0.00 4.48 

Test performed 

at engineers 

request, Good 

Perm 

4.2 2984.55 2842.19 3242.78 0.00 0.00 1.53 0.00 0.00 4.17 Good Perm 

Legend: 

Psphere* Spherical Analysis Formation Pressure 

Pfast* FasTest Analysis Formation Pressure 

Ptight Tight Zone Analysis Formation Pressure 

Msphere Spherical Mobility 

Mfast FasTest Mobility 

Mtight Tight Zone Mobility 

Msdd Spherical Drawdown Mobility Mh Horizontal Mobility ANISO Anisotropy (Kv/Kh) 

The Pressure Transient Analysis Summary table is a tabular listing of pressure buildup analysis data, including mobility estimates and formation pressure 

projections (P*). Data is also available in real time and as a document on the log.

Well Testing 

Well testing is performed to determine formation 

productivity/deliverability, permeability, reservoir pressure, 

presence of skin damage, flow profile inside a formation and 

wellbore, reservoir geometry/size/drainage area, inter-well 

communication, and perforation efficiency. 

Well testing is usually performed right after a well is 

completed and when the productivity does not follow the 

expected trends. Well testing is also done periodically 

through the life of a well and field to assess well performance 

and to establish pressure and rate decline patterns. 

In pressure transient testing, the changes in pressure, 

temperature, and fluid properties caused by sudden changes 

in production rates of oil, gas, and water from a well (or 

wells) are measured and analyzed during a given time span. 

The most widespread type of pressure transient testing is a 

pressure buildup test in which a producing well is shut-in, 

and the pressure values are recorded with time. In a pressure 

drawdown test, a shut-in well is opened, and the pressure 

values are recorded with time. 

The basic requirements of a well test are: 

Measuring the flow rate of the gas and the liquids 

produced or injected 

Controlling and adjusting the flow from the reservoir 

Measuring the pressures and temperatures using 

sensitive and accurate downhole instruments 

Obtaining samples of the reservoir fluids 

Safely disposing of or storing the well effluent produced 

during the test 

Well Test Design 

In a well test design, all the production history and the 

available reservoir and wellbore properties of a well are 

included in a pressure transient testing design model. A given 

reservoir flow geometry based on the completion and 

production history is selected to simulate pressure and time 

data as close as the actual data which would be obtained from 

an ensuing well testing. For the unknown parameters, 

sensitivity runs should be conducted to cover the entire range 

of the expected values. Test duration and types should then 

be modified to provide a sufficient amount of data to be 

recommended for the ensuing pressure transient testing. 

Types of well tests include closed chamber or surge test with 

the zero-emission FasTest® system, shoot and pull test, 

drillstem test, cleanup test, slug test, early production test, 

multi-rate production/ injection well tests, reservoir limit 

test, permanent gauge test, and interference/pulse tests. 

For these tests to be reliable and effective, a well test design is 

critical to assuring the test objectives are feasible by selecting: 

Proper completion equipment 

Pressure gauges with the required sensitivity and 

accuracy 

Type of well test 

Flow rate and choke sizes 

Duration of flow and shut-in periods 

The following well and reservoir models are considered when 

designing or analyzing well test data: 

Analytic and numeric models 

Homogeneous or dual porosity formations 

Horizontal, vertical, or deviated wellbores 

Hydraulic fracture wellbores 

Any boundary configuration 

Radial and linear composite reservoirs 

Layered reservoirs 

Wellbore with limited entry (partial completions) 

Changing wellbore storage and/or skin 

Turbulent flow and tidal effects 

Well interference effects 

Simultaneous analysis of a changing reservoir model 

before and after a stimulation or a workover application 

Material balance effects 

The accuracy and the value obtained from a well test design 

depends on the following: 

Experienced engineers performing the service 

Availability of advanced well/reservoir models 

Comprehensive well test design report 

Comparisons with prior tests to establish trend 

Parameter sensitivity evaluation to signify the 

importance of the values obtained 


Features 

The following features are included in a well test design 

report: 

–Optimum test times 

–Optimum flow rates 

– The right equipment suited for the job 

– Models with sensitivities to reservoir, fluid, and 

wellbore parameters 

– Well test procedure 

Inputs 

A well test design is a planned activity that uses the prewell 

test well and reservoir information to optimize the 

test type, procedure, and time 

Success of a well test is greatly enhanced by coupling the 

well testing with the real- time operations (RTO) 

Wellbore data, reservoir data, fluid properties, stimulation treatment, information geology, seismic and environmental 

controls, surface facilities, previous production/injection problems 

Outputs Well test design report 


Well Test Analysis 

A well test analysis report provides information about well 

productivity/deliverability, formation permeability, reservoir 

pressure, amount and type of damage, perforation efficiency, 

and flow type /profile inside a formation and wellbore. If the 

test was designed and conducted for a longer period, then 

reservoir geometry/size/drainage area and inter-well 

communication would also be evaluated and provided in the 

report. Well test and completion data can be deployed to get 

a more accurate reservoir description. 

In a well test report, Halliburton engineers identify 

opportunities to improve well performance, which often 

includes reservoir and well production projection with 

recommendations to enhance productivity. If a well test 

identifies wellbore damage, then productivity improvement 

projections will be simulated to compare acidizing with 

hydraulic fracturing and frac pack to evaluate if stimulation 

will improve production. If the cause of the problem stems 

from partial completion and perforation plugging, then reperforation, 

acidizing, and fracturing cases will be compared. 

The optimum production scenario based on the evaluated 

reservoir and wellbore parameters can also be included in the 

report. 

Well test analysis can provide initial reservoir pressure (p i), 

permeability thickness (k h), and skin (S). Additionally, the 

perforated wellbore length (h w), distance of horizontal 

wellbore to bottom of formation (Z w), and ratio of vertical to 

radial permeability (k Z/k r) are calculated for horizontal 

wells. The dual-porosity flow model provides values for λ 

and ω. Stimulated wells are characterized by the fracture 

half-length (X f), conductivity (C FD), and fracture skin. 

Distances to boundaries and the boundary type (no-flow, 

constant pressure, or leaky) can be provided for any of the 

models. In a composite reservoir, the size and the properties 

inside and outside of the composite zone will be provided. In 

a limited entry well, the effective interval producing into the 

wellbore and the plugged perforations are identified. In 

layered reservoirs, permeability, skin, pressure, and flow rate 

for each layer can be calculated. 

A well test analysis technique may include one or a 

combination of the following methods: 

Conventional linear regression analysis 

Type curve analysis 

Non-linear regression 

Closed-chamber DST analysis 

Production analysis 

Halliburton well test analysis service differentiating factors 

include: 

Experienced reservoir engineers performing the service 

Customized and easy to use report 

Advanced well/reservoir models 

Analytic and/or numeric analysis techniques 

Real-time analysis capabilities using a secured website 

that can be accessed using your computer anytime or 

anywhere 

Features 

Enhanced reservoir and completion description with 

advanced and sophisticated reservoir models 

Evaluation and/or analysis performed in batch or real 

time 

Recommendations for well improvement based on 

reservoir, wellbore, completion, and the surface 

equipment 

Fast turnaround at a reasonable cost to free up valuable 

engineering time 

Experienced reservoir engineers available for any 

questions 

Evaluation of the entire job 

Follow-up briefing on analyses results and 

recommendations for future tests 

A complete analysis report with: 

– Well test description 

– System evaluation 

– Discussion of each event 

– Gauge comparison 

– Analysis results 

– Well test data summary 

– Historical comparisons (when applicable) 

– Production improvement recommendations 

(when applicable) 

– Conclusions 


Multi-Layered Analysis 

In multi-layered reservoirs, hydrocarbon fluids exist in 

different layers. These layers could be located close or far 

from each other, in hydraulic communication or totally 

isolated from each other, and with similar or completely 

different properties. The pressure values in the layers could 

differ by just the hydrostatic head pressure difference or be 

totally different from each other. Multi-layer formations are 

divided into two main categories of: 

Commingled layered reservoirs – The layers in a 

commingled formation are isolated from each other and 

do not communicate in the reservoir. They are 

hydraulically connected with each other through the 

wellbore 

Cross-flow layered reservoirs – The layers in a cross-flow 

reservoir communicate with each other through both the 

formation and the wellbore. At any point in the reservoir, 

the interlayer cross flow is proportional to the pressure 

difference between the layers 

At high flow rates, the high permeability layers produce at 

higher flow rates than the low permeability layers, and thus, 

they get depleted at a faster rate. At low flow rates or when 

the well is shut-in at surface, fluids from the low permeability 

layers invade the high permeability layers which were 

depleted more. 

Halliburton provides a multi-rate, multi-layer test in 

conjunction with the production logging service. Layer 

pressure and flow rates are evaluated by the production 

logging service. This information is fed into the multi-layer 

well test analysis program to evaluate permeability, skin, and 

pressure for each layer. 

5500Analysis Results 

Gas Rate 

[Mscf/D] BHP [psia] 

4500 

3500 

4000 

Skin vs. Rate 

0 20 40 60 80 100 120 140 

History plot (Pressure [psia], Gas Rate [Mscf/D] vs Time [hr]) 

Multi-rate test showing analysis results accounting for 

turbulent flow effects. 

Inputs 

14 

12 

10 

8 

6 

4 

2 

Skin 

-1000 0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 

Rate [Mscf/D] 

Prod Index = 4.95 Mscf/D - psi 

Storage Constant = 0.00509 STB/psi 

True Skin = 1.96 

True Delta P Skin = 71 psi 

Turb Skin = 4.58 

Turb Delta P Skin = 165 psi 

Turb Factor = 0.00131 1/Mscf/D 

Initial Pressure = 6000 psia 

kh = 141 md-ft 

k = 4.7 md 

HAL7687 

Permanent Gauge Analysis: History plot of pressure and rate showing 

analysis model match 

Reservoir shape: Analysis results showing geologic boundary configuration 

Inflow and outflow pressure—rate responses for various reservoir 

parameters showing production match point. 


BHP [psia] 

Gas Rate 

[Mscf/D] 

HAL7755 

FLOWING BTM PRES psig 

9000 

8000 

7000 

6000 

5000 

4000 

3000 

5000 

4900 

4800 

4700 

9000 

HAL7688 

FORM PERM 

(md ) 

50 

50 

100 

100 

250 

250 

Constraints: 

Erosion:C=100.00 

2000 

0 2000 

Pressure vs Time 

Gas Rate vs Time 

0 1000 2000 3000 4000 5000 6000 

Inflow Parameter 

Pressure [psia], Gas Rate [Mscf/D] vs Time [hr]) 

3,000 ft 

Production Data Matching Theoretical Model 

SKIN 

( ) 

0 

5 

0 

5 

0 

5 

Match 

Point 

Pbar 

3,000 ft 

2,500 ft 

2,000 ft 

Outflow Parameter 

FLNCHOK ID 

(1/64 ) 

12 

16 

20 

26 

36 

64 

HAL7689 

4000 6000 8000 10000 

FLOW RATE bbl/d 

Test objectives, geologic information, prior production data, completion schematic, fluid property data, prior treatment 

data, well test downhole pressure gauge files, well test surface data report files 

Outputs Well test analysis report including recommendations for well performance improvement (when needed)

Reservoir Evaluation 

SigmaSat Model 

This cased-hole interpretation model is designed for 

saturation analysis of a single well based on sigma logs from 

any supplier. Oil saturation can be determined in the 

presence of saline formation waters. Gas saturation can be 

determined under almost any conditions. 

Features 

Saturation interpretation of any formation sigma data 

Standard volumetric analysis or an adaptation of the 

Chevron variable matrix model 

Inclusion of open-hole porosity and clay volume 

analyses 

Stand-alone analysis using porosity and clay indicators 

from cased-hole monitoring tools or any available source 

Determines volume of hydrocarbons produced from the 

reservoir and allows estimates of remaining reserves 

Enhances reservoir production knowledge 

Allows better understanding of hydrocarbon drainage 

efficiency from the reservoir 

Identifies potential hydrocarbon production zones that 

have not been drained or were bypassed or previously 

undiscovered 

Pinpoints changing oil/water and gas/oil contacts 

through time lapse monitoring 

Finds flooded or swept zones 

Associated Answer Products and Pre-Processing 

Software 

Pulse-height spectral gain stabilization and processing, 

plus environmental corrections (TMDLRL) 

CarbOxSat model – similar model for saturation 

analysis of neutron decay logs 

TripleSat model – similar family of models utilizing 

both carbon/oxygen and neutron decay logs for use 

where three fluids are present in the reservoir 

Inputs Clay volume, total porosity, effective porosity, environmentally corrected intrinsic sigma 

Outputs 

Track 1 indicates the amount of sand and shale by volume, along with 

the effective porosity. Track 2 is a porosity overlay track indicating 

hydrocarbon crossover. Track 3 shows sigma water apparent and sigma 

solids apparent. Track 4 shows an envelope of sigma wet and sigma 

hydrocarbon with sigma intrinsic in between, indicating the 

hydrocarbon. Track 5 indicates the total hydrocarbon saturation, and 

Track 6 shows total porosity, effective porosity, the effective volume of 

water, and the volume of hydrocarbon. 


HAL11409 

Individual and combined clay volume, total porosity, effective porosity, capture-ratio porosity, inelastic ratio porosity, 

hydrocarbon volume, total and effective hydrocarbon saturation, water volume

CarbOxSat Model 

This interpretive model is specifically designed for saturation 

analysis of a single well based on Halliburton carbon/oxygen 

(C/O) logs. The CarbOxSat model is used for interpreting 

oil saturation in reservoirs where formation water salinity is 

fresh, mixed, or unknown. 

Features 

Saturation interpretation of all Halliburton formation 

carbon/oxygen data 

Halliburton’s lithology compensated Delta-C/O or 

traditional overlay method 

Inclusion of open-hole porosity and clay volume 

analyses 

Stand-alone analysis using porosity and clay indicators 

from cased-hole monitoring tools or any available source 

Determines volume of hydrocarbons produced from the 

reservoir and allows estimates of remaining reserves 

Enhances reservoir production knowledge 

Allows better understanding of hydrocarbon drainage 

efficiency from the reservoir 

Identifies potential hydrocarbon production zones that 

have not been drained or were bypassed or previously 

undiscovered 

Pinpoints changing oil/water and gas/oil contacts 

through time lapse monitoring 

Finds flooded or swept zones 


Software 

Pulse-height spectral gain stabilization and processing 

(RMTERL) 

Multi-pass stacking (RMTEAVG) 

Environmental corrections (RMTECOR) 

SigmaSat model – similar model for saturation analysis 

of neutron decay logs 

TripleSat model – similar family of models utilizing 

both carbon/oxygen and neutron decay logs for use 

where three fluids are present in the reservoir 

Track 1 contains the open-hole neutron and density porosity curves, as 

well as the gamma ray curve. Track 2 contains the cased-hole porosity 

indicators of a pseudo-density curve from the inelastic ratio, and a 

pseudo-neutron porosity from the capture ratio. Track 3 contains the 

delta-C/O envelope indicating the C/O interpretation. Track 5 shows the 

total hydrocarbon saturation, and Track 6 is a volumetrics track 

containing the volume of shale, effective porosity, and the bulk volume 

of water to provide water and hydrocarbon saturation. 

Inputs Clay volume, total porosity, effective porosity, environmentally corrected carbon/oxygen and calcium/silica ratios 

Outputs 


volume of oil, total and effective oil saturations, water volumes 


HAL11768

TripleSat Model 

This unique interpretation model is specifically designed for 

use with Halliburton’s reservoir monitoring tools. The 

TripleSat model employs a combination of C/O and sigma 

measurements and is used to calculate saturation when three 

fluids are present in the reservoir. 

Features 

Utilizes simultaneously-recorded sigma and C/O 

measurements 

Provides more accurate interpretation in oil producing 

reserves where steam or gas is present 

Contains selectable sets of equations that can be 

optimized for one of the following: 

–Steamflood 

– Oil drainage from gas cap 

– Gasflood 

–Sea waterflood 

Allows additional optimizations to be readily 

constructed, some using a Halliburton adaptation of the 

Chevron gas correction to carbon/oxygen logs 

Permits inclusion of open-hole porosity and clay volume 

analyses 

Allows stand-alone analysis using porosity and clay 

indicators from cased-hole monitoring tools or any 

available source 

Allows accurate interpretation in reservoirs that have gas 

cap development or are under steamflood or gasflood 

Permits interpretation in reservoirs with retrograde 

condensate production 


Software 

SigmaSat model – neutron decay time saturation 

analysis 

CarbOxSat model – carbon/oxygen saturation analysis 

Inputs 

Outputs 

KernSat Interpretation Example. This well located in Kern County, 

California in the Kern River Field, is in an active steamflood 

hydrocarbon recovery project. This log is an example of our customized 

interpretation model KernSat. Track 4 of the example displays the 

computed oil saturation (shaded in green) and the gas saturation 

(shaded in red). These saturations were computed using a combination 

of carbon-oxygen ratio and formation sigma. Track 3 displays the 

carbon-oxygen and the calcium-silicon ratio curves. The green shading 

between the two curves indicates hydrocarbons in the formation. Also 

displayed in the track are the natural gamma ray measurement and the 

simultaneous recorded formation sigma. Tracks 1 and 2 display a 

comparison of the open-hole density and neutron porosities and the 

porosity ratio indicators measured by the RMT Elite analysis. Track 1 

is the open-hole density neutron porosity. Steam measured in the 

formation at the time of the log is indicated by the gray shading between 

the curves. Tracks 2 displays the inelastic and capture ratios measured 

from the RMT Elite analysis. The red shading indicates the current 

location of steam in the reservoir. This example indicates that the steam 

chest has expanded when compared to the original formation contacts. 

The depth track recorded at the far left side of the log displays water flow 

measured by the RMT Elite analysis outside the casing. 

Clay volume, total porosity, effective porosity, environmentally corrected carbon-oxygen and calcium-silica ratios, 

environmentally corrected sigma 


volume of oil, total and effective oil saturations, water volumes, corrected three-phase saturations 


HAL9180

Production Logging Analysis 

Production Logging Analysis 

Halliburton has several programs that are used to interpret 

production logs. The basic production logging interpretation 

is provided using Kappa Engineering's Emeraude software. 

The industry standard in production logging is Emeraude 

which allows for a common platform for communication 

and evaluation between service companies and operators. 

From vertical injectors to horizontal or highly deviated 

multiphase producers, Emeraude provides a comprehensive 

and intuitive set of tools to produce results from the log data 

from simple through to the most sophisticated toolstrings. 

The basic interpretation uses raw PL data from the spinner, 

fluid density, pressure, and temperature tools to determine 

flow rates of the well. The log at the right consists of seven 

passes logged at different multiple logging speeds as shown 

by the different colors for each pass. The basic interpretation 

process is explained as follows: 

Spinner calibration and apparent velocity 

The user defines the spinner calibration zones to 

determine the spinner calibration with or without 

thresholds values. After each calibration, an apparent 

velocity curve is generated 

Single and zoned PVT 

The next step is to use the PVT model to provide the 

properties of any phase at any temperature and pressure. 

Several different correlations may be used for each and 

every inflow zone 

Flow rates 

Using a nonlinear regression method, the rate 

calculations for each inflow zone is determined. This 

allows the user full flexibility in the number and type of 

input measurements. The basic calculation scheme 

successively solves the cumulative rates at selected depths 

inside the wellbore. The contributions of the user 

selected inflow zones are then obtained from successive 

differences above and below each zone. To further 

enhance the product, a global regression allows 

comparisons between zones 

Interpretation models 

Emeraude offers a full range of flow models from single 

to three-phase flow. Specific models are provided to 

handle flow re-circulation as well as flow through 

standing water columns. Emeraude can be tightly 

controlled by the user to provide a solution to complex 

flow situations including fallback, three-phase, and 

deviated wellbores 

Basic raw data showing two sets of perforations (red), two sets of spinner 

calibration zones (yellow), and three rate calculation zones (grey). From 

the fluid density data, it is possible to see where there are major fluid 

composition changes (4480), with minor changes from 4480 to 4550. The 

spinner information also indicates fluid entry around 4480. 


This screen capture shows the spinner calibration in the sump. The positive and negative thresholds are applied to 

the other zones to correct for spinner friction. 

This zone is above the top set of perforations, so the velocity at this zone should be the velocity of the total fluid 

flow. The calculated velocity will be corrected for tool position in later sections of the software. 


Several programs were developed in-house for specialized 

tools but are linked to Kappa Engineering's Emeraude 

program. These specialized analysis programs are used to 

process specific logging tool data to determine fluid velocities 

and holdups. 

GHTA gas holdup tool analysis 

FloImager® analysis service for CAT capacitance array 

tool data 

SatImager analysis for spinner array tool (SAT) data 

The GHTA model is an analysis program used to process the 

data from the GHT gas holdup tool and create a gas holdup 

for further processing in Emeraude. 

The FloImager model uses data from the CAT tool to provide 

an accurate holdup calculation. Like the GHTA model, the 

output from the FloImager model is used seamlessly in the 

Emeraude software to further quantify the production rates. 

The SatImager model uses data from the SAT tool to provide 

an accurate image of the velocity profile in the wellbore. The 

SAT tool with six spinners allows interpretation of complex 

flow regimes including downflow and liquid fallback. 

Combining the FloImager and SatImager models in 

Emeraude provides an efficient method to evaluate 

complicated downhole flow regimes including deviated, 

horizontal, and three-phase. 

Features 

Delivers a complete interpretation of production logs 

Detailed analysis of downhole and surface production 

rates, both continuous and averaged, over the desired 

interval 

Handles a multiple array of production logging sensors 

including the new generation fullbore holdup tools 

Allows customized analysis using customer PVT inputs 

and slip velocities 

Various presentations and stringent quality control 

promotes more accurate PL analysis of production and 

injection wells including the difficult three-phase flow in 

horizontal wells 

Continuous logs provide more accurate determination 

of fluid entry points which allow for improved 

conformance treatments 

Averaged and zonal production rates provide valuable 

information in determination of treatments and/or 

remedial work 

Log presentations can be customized to meet the specific 

requests or needs 

Text files provide linkages to reservoir models and other 

analysis packages 

Final Emeraude product showing two-phase flow showing the lower 

perforations taking fluid. Track 1 provides information about the 

holdups, or the cross-sectional area of the pipe that the phase is 

occupying. Track 2 is the continuous flow rate measurement in STB/day. 

Track 3 is the zonal average of the two phases while Track 4 shows the 

production of each zone. In this case the lower zone is taking a large 

amount of water that is being produced by the upper zone. 


FloImager ® Analysis Service 

The FloImager® analysis service is a logging service product 

that uses the data from the CAT capacitance array tool to 

provide accurate three-phase holdup calculations. This 

application is extremely useful in highly deviated and 

horizontal wells having multiphase flow. Applications for 

detecting three-phase fluid entry can be done at any angle. 

There are a multitude of applications for the FloImager 

analysis service. In addition to measuring fluid holdup, the 

FloImager analysis service can be used to detect water entry 

and its orientation relative to high side of pipe at any well 

deviation. The FloImager analysis service can successfully 

show three-phase fluid segregation since each fluid has its 

own log response. The FloImager analysis service provides an 

accurate visualization of the undulating horizontal wellbore 

when TVD data is combined with CAT tool data. Combining 

the calculated fluid holdup with additional PL sensors allow 

a more accurate and complete three-phase analysis. 

The FloImager analysis service improves interpretation of the 

flow patterns in all wells due to the increased number of 

sensors at the same depth. More accurate holdups can be 

determined because the relative position of the CAT tool is 

monitored, correcting the images and logs to the high side of 

the hole. 

FloImager 3D Software Analysis 

The FloImager 3D software provides a 3D method of viewing 

data from the FloImager service. The FloImager 3D software 

allows the customer to view, rotate, and manipulate CAT 

capacitance array tool data to understand the flow patterns 

and character of the well. Both the FloImager 3D and 

FloImager service use data from the CAT tool to provide 

accurate three-phase holdup calculations. 

FloImager 3D software allows a complete picture or profile of 

the downhole holdup pattern. This allows the viewer to 

approach the wellbore from any direction to allow multidimensional 

understanding of the flow characteristics. Since 

the sensors are normalized in the CAT tool, the same color 

pallet can be used for each sensor providing a precise image. 

The FloImager 3D software provides a superior technique for 

displaying multiphase holdup. However, since this 

segregation is dependent upon total fluid flow, each sensor 

has the ability to measure phase holdups of gas, oil, and 

water. Both the FloImager 3D and the FloImager service have 

several options to calculate total holdup of the wellbore, 

allowing the user to determine the best possible solution to 

this complicated issue. 

Track 1 consists of a gamma ray (GR), relative bearing (RB), 

temperature (TEMP), pressure (PRES), and continuous spinner 

(FCON). RB is the relative bearing for arm 1 of the CAT tool and 

allows arm position relative to the high side of the hole to be 

determined. Track 2 provides the image of the flow as measured by the 

CAT tool. The image is positioned so that the high sides are on the left 

and right side of the track while the middle is on the low side. Since this 

is a horizontal well, it should be apparent that the heavier fluids should 

be on the bottom and lighter fluids should be on the top of the well. 

Track 3 shows the average of the 12 sensors (AVCAPN) along with two 

center sample holdup measurements fluid density (FDEN) and hydro 

tool (HYDR). Track 4 provides a cross-sectional view of the data in 

Track 2. The right side of the image is high side while the left is on the 

bottom. The holdups are also presented in the last track, water (YWE) 

and gas (YGE). This presentation allows quick method of determined 

fluid contacts and provides accurate calculation of fluid compositions. 

Lines A and B correspond to the Flo3D section. 


XX50 

XY00 

XY50 

A 

B

Features 

Multi-directional images available 

Continuous display of the flowing fluids 

More accurate three-phase holdup calculations 

Images in all types of stratified and mixed flow 

Designed for more accurate responses in both deviated 

and horizontal wells 

Excellent wellbore coverage with array of 12 sensors 

allows superior data and improved flow characterization 

A 

High Side View 

Low Side View 

Continuous holdup curves, fluid distribution mapping, 

and a view of the fluid distribution in cross-section 

allows clear-cut understanding of the flow profiles and 

characteristics 

Ability to obtain more reliable holdup measurements 

and high-resolution fluid entry detection, location, and 

orientation in deviated and horizontal wells 

XX90 XY00 

This output is from FloImager® 3D software analysis and shows 10 ft of the log from above. It is possible to see the changes in the holdup due either 

to wellbore trajectories or possible fluid inflow. 

XY00 

XX92 

Gas Holdup = .223 

Oil Holdup = .516 

Water Holdup = .261 

XX90 

This presentation is a composite from FloImager® 3D software analysis. The first display is over the same zone as above looking downhole. The last 

two images are from the cross-section display that shows both the tool arm position and the calculated holdups for the three phases. The white dot is 

arm #1 which determines the relative bearing so that the data can be oriented to the high side of the wellbore. 


B 

XX96 

Gas Holdup = .221 

Oil Holdup = .651 

Water Holdup =.128


Open-Hole Wireline Services 

Resistivity 

ACRt Array Compensated Resistivity Tool 

System 

The ACRt array compensated resistivity tool system 

represents the latest thinking in conventional array induction 

technology. Every aspect of mechanical, electrical, software, 

and signal processing design has been optimized to yield 

array induction measurements with unparalleled accuracy, 

stability, and dynamic range. 

The ACRt system is an asymmetric design that consists of a 

single transmitter operating at three frequencies and six 

receiver antennas with spacings from 6 to 80 in. A simple and 

robust skin effect method utilizes only the in-phase 

components of the received signals at all three frequencies. 

Each tool is individually characterized for thermal drift 

during manufacture. This characterization, in concert with 

sonde-mounted temperature sensors, provides the basis of a 

proprietary and highly accurate temperature compensation 

method. Real-time borehole corrections are usually derived 

from a caliper source and a sonde-mounted mud cell. When 

the caliper input is absent (e.g. downlogging), borehole 

corrections are derived from the short-spaced induction 

receiver data alone. The final step in the processing chain, 

2D software focusing, produces five radial curves with 

matched vertical resolution and with radial focal depths of 

10, 20, 30, 60, and 90 in. The ACRt sonde includes an 

integrated SP sensor. 

Applications 

Accurate measures of formation resistivity at varying 

depths of investigation for enhanced estimates of Rt , Rxo , 

and Di 

Quantitative assessment of Sw , Sxo , and moveable water 

volumes 

Qualitative assessment of permeability and rock quality 

Array induction measurements are available in 

formations with resistivities from 0.2 to 2000 ohm-m 

and in water, air, or oil-filled boreholes 

Analysis of finely-bedded formations 

Real-time 10-20-30-60-90 in. radial curves from the ACRt system are 

displayed in track 2. Good sensitivity to shallow invasion is in evidence 

in the zones 10290 and 10385. RT, RXO, DI and the graphical invasion 

map are available in real time. 

Open-Hole Wireline Services 3-1 

Open-Hole Wireline Services

Features 

State of the art processing scheme features: 

– 2D software focusing produce five resolutionmatched 

radial curves with radial focal depths of 

10, 20, 30, 60 and 90 in. 

– Real-time inversion for Rt , Rxo , Di, and invasion 

“map” 

– Proprietary thermal correction scheme 

– Three frequency skin effect correction 

– Real-time borehole corrections with or without 

caliper inputs 

– Resolution-match filters of 1, 2 and 4 ft 

Length 

ft (m) 

19.5 

(5.9) 

Minimum Borehole 

Diameter 

in. (mm) 

4.75 

(121) 

Optimized receiver antenna spacings provide improved 

sensitivity to shallow and mid-range mud filtrate 

invasion depths along with excellent deep response for Rt Receiver coil spacings closely approximate computed 

radial curve depths, which results in fundamentally 

stable processing 

Short array length reduces dependency on “speed 

correction” when encountering moderate overpulls 

Environmental ratings of 350°F and 20,000 psi 

Logging speeds up to 6,000 ft/hr 

ACRt Array Compensated Resistivity Tool Specifications 

Maximum Borehole 

Diameter 

in. (mm) 

12.25 

(311) 

Operating Pressure 

Rating 

psi (bar) 

20,000 

(1400) 

Operating 

Temperature Rating 

°F (°C) 

Weight 

lb (kg) 

Maximum Logging 

Speed 

ft/hr (m/hr) 

3-2 Open-Hole Wireline Services 

350 

(177) 

308 

(140) 

6,000 

(1830)

HRAI High Resolution Array Induction Tool 

The HRAI high resolution array induction tool represents 

a significant engineering advance over the HRI high 

resolution induction tool. The HRAI tool leverages the 

proven features of the HRI tool “three-coil” receiver 

configuration while providing induction measurements with 

six radial focal depths. The sonde is a symmetrical design, 

with five upper and five lower receivers positioned around a 

center-mounted transmitter. Raw conductivity data is 

collected at two frequencies, 8 and 32 kHz, and the receiver 

antennas are spaced from 17 to 78 in. 

A new speed correction algorithm implemented in the 

logging software enhances the accuracy of HRAI tool coil 

array data even during large overpulls in sticky boreholes. 

Long transmitter-receiver spacing and optimized array 

processing help to significantly reduce the effects of 

washouts, rugosity, and tool eccentricity. 

Applications 

Accurate measures of formation resistivity at varying 

depths of investigation for enhanced estimates of Rt , Rxo , 

and Di 

Quantitative assessment of Sw , Sxo , and moveable water 

volumes 

Qualitative assessment of permeability and rock quality 

Array induction measurements are available in 

formations with resistivities from 0.2 to 2,000 ohm-m 

and in water, air, or oil-filled boreholes 

Analysis of finely-bedded formations 

Features 

Real-time 2D software focusing achieves an optimum 

balance of vertical resolution, radial focusing, and 

symmetry of response 

Resolution-matched radial curves are computed with 

radial focal depths of 10, 20, 30, 60, 90 and 120 in. 

Description 

LOGIQ 

DIT 

Logging Speed 

ft//hr (m) 

6,000 

(1830) 

6,000 

(1830) 

Each resistivity comes with a 1-ft, 2-ft, and 4-ft vertical 

resolution 

Real-time Rt , Rxo , and Di curves and an invasion “map” 

are available 

Real-time borehole corrections facilitated by a sondemounted 

mud resistivity sensor 

Advanced “speed correction” algorithm for correcting 

array data for over-pulls in sticky boreholes 

Vertical resolution-matched elemental measurements 

High logging speeds up to 6,000 ft/hour are possible 

Real-time answer products of HRAI tool: an invasion map in Track 4, R t 

and R xo in Track 3, and Track 2 shows the 2-ft resolution radial resistivity 

curves. 

HRAI High Resolution Array Induction Tool Specifications 

Length 

ft (m) 

25.43 

(7.75) 

35 

(10.67) 


HAL3960 

Minimum Borehole 

Diameter 

in. (cm) 

4.5 

(11.43) 

4.5 

(11.43) 


psi (bar) 

20,000 

(1400) 

20,000 

(1400) 

Operating 

Temperature 

°F (°C) 

350 

(177) 

300 

(150) 

Weight 

lb (kg) 

400 

(181) 

586 

(266.5)

HRI High Resolution Induction Tool 

The HRI high resolution induction tool is an electrical 

wireline tool that belongs to the induction logging family of 

tools. It records apparent conductivity of the subsurface 

formations. Data processing converts the measured 

conductivity into resistivity. The HRI tool works well in 

boreholes drilled with water, air, or oil. Standard HRI tool 

presentation includes deep and medium resistivities derived 

from the raw conductivities. In conductive muds, a digitally 

focused resistivity log (DFL) and SP measurements are 

available. 

Applications 

Reliable Rt in resistivity environments from 0.2 to 

2,000 ohm-m provides improved estimates of water 

saturation 

Quantitative moveable hydrocarbon volumetric analysis 

and radial fluid distribution around the borehole when 

DFL is available 

High vertical resolution deep, medium conductivities 

and DFL logs enhance analysis in finely laminated 

reservoirs 

Distinguishes between conductive water-bearing and 

hydrocarbon-bearing formations 

Provides estimate of invasion diameter and Rxo Features 

Sonde architecture consists of four transmitters and one 

receiver. The transmitter operates at 20 kHz 

The single receiver is a “three-coil” configuration for 

enhanced vertical resolution 

The tool measures both R and X components of the 

conductivities. X signals are used for skin effect 

correction 

The signal processing chain includes corrections for 

formation skin and shoulder bed effects to produce the 

deep (HDRS) and medium (HMRS) resistivities 

Length 

ft (m) 

33.3 

(10.2) 

The DFL provides a shallow focused resistivity 

measurement with a radial investigation of 15 in. The 

vertical resolution of the DFL closely matches that of the 

HRI tool induction curves 

A 1-ft vertical resolution improves estimates of Sw and 

the hydrocarbon reserves in thinly laminated pays 

Standard HRI log example showing deep and medium resistivities 

(Track 2) computed by correcting the raw conductivity data for skin, 

shoulder bed, and borehole effects. 

HRI High Resolution Induction Tool Specifications 

Diameter 

in. (mm) 

3.63 

(92.2) 


psi (bar) 

20,000 

(137.9) 

Operating Temperature 

°F (°C) 

350 

(176.7) 

Weight 

lb (kg) 

455 

(206.4) 

3-4 Open-Hole Wireline Services

HDIL Hostile Dual Induction Log 

The HDIL hostile dual induction log tool is an open-hole 

electric wireline tool used to measure formation resistivity in 

high temperature, high pressure wells. The tool provides 

three resistivity measurements: short normal, medium 

induction, and deep induction. Also, SP electrodes are built 

into the sonde and provide an SP measurement in 

conductive mud systems. Flushed zone resistivity (R xo) is 

computed from the short normal measurement. 

The medium and deep induction array is hardware focused, 

and the measurements are derived from, respectively, 64440 

and 8ff34 coil configurations. The short normal has a spacing 

of 16 in. 

Applications 

The HDIL tool is specifically designed to provide reliable 

basic induction and resistivity measurements in 

extremely high temperature and/or high pressure wells 

The HDIL tool provides induction measurements in 

slimhole applications down to 4.75 in. 

Features 

Optimized for accurate induction and resistivity 

measurements in hostile conditions. Like the other 

HEAT suite tools, the HDIL tool is rated to operate in 

500°F and 25,000 psi environments 

Slim 2.75 in. tool diameter and relatively light tool 

weight facilitate safe operations in ultra deep, slim, or 

short-radius boreholes 

Fully combinable with other 500°F and 25,000 psi 

HEAT suite tools 

Post-processed environmental corrections are available 

An inversion for Rt , Rxo , and Di is available when the 

short normal is available (conductive muds) 

Length* 

ft (m) 

31.7 

(9.7) 

HDIL Hostile Dual Induction Log Specifications 

Diameter 

in. (mm) 

2.75 

(69.9) 

Maximum Pressure 

psi (Mpa) 

25,000 

(172.4) 

An HDIL log from a shaley sand sequence. The standard HDIL curves are 

presented and include a deep and medium induction as well as a short normal log. 

An SP log is supplied by an HDIL sonde-mounted electrode and is presented if the 

mud is sufficiently conductive. 

Maximum 

Temperature** 

°F (°C) 

Weight 

lb (kg) 


500 

(260) 

260 

(117.9) 

*The HDIL tool must be run with the isolation sub-assembly. The isolation sub-assembly is 1.9 ft (0.6 m) long and 

is located between the cablehead and the telemetry section. 

**6 hour

DLL Dual Laterolog Service 

Halliburton's proven DLL dual laterolog service provides a 

reliable means of measuring formation resistivity in 

conductive borehole fluids and/or where large contrasts exist 

between the formation and mud resistivities. The DLL 

service operates by focusing currents into the formation to 

produce a deep resistivity measurement (LLd) and a shallow 

resistivity measurement (LLs). The MSFL micro- 

spherically focused log is usually run in combination to 

provide a third shallow resistivity measurement. Together, 

these three measurements provide the resistivity profile 

around the borehole and permit the computation of R t in 

presence of invasion. 

Applications 

Provides accurate, high resolution shallow (LLs) and deep 

(LLd) resistivity measurements in high Rt /Rm conditions 

(>100) or when formation resistivity exceeds the limits 

for conventional induction tools (> 2,000 ohm-m) 

Quantitative assessment of Sw When run with the MSFL log, provides estimates of Rt, Rxo, and diameter of invasion 

Quantitative assessment of moveable water saturations 

(Sxo ) and moveable hydrocarbon volumes 

Acquires improved formation resistivity measurements in 

saline borehole fluids and in high Rt /Rm (>100) contrast 

logging conditions or when formation resistivity exceeds 

the limits of induction tools (>2000 ohm-m) 

Provides MSFL measurements to help delineate thin 

beds and provide estimates of Rxo Offers qualitative indication of permeable zones and 

estimating invasion diameters (when run with the 

MSFL tool) 

Length 

ft (m) 

33.9 

(10.3) 

DLL Dual Laterolog Service Specifications 

Diameter 

in. (mm) 

3.63 

(92.2) 

Features 

Rugged sonde construction and state-of-the-art 

electronics provide for accurate measurements of 

formation resistivity up to 40,000 ohm-m 

Dual electrode arrays and an automatic current-focusing 

technique 

The fundamental vertical resolution is 24 in. for both 

measurements which facilitates reservoir description of 

thinly bedded formations 

DLL log example from a carbonate-evaporite sequence showing deep and 

medium laterolog curves presented along with the shallow MSFL log. 


HAL9154 


psi (Mpa) 

20,000 

(137.9) 

Maximum 

Temperature 

°F (°C) 

350 

(176.7) 

Weight 

lb (kg) 

460 

(208.7)

MSFL Micro-Spherically Focused Log and Microlog (ML) 

The MSFL micro-spherically focused log and microlog 

(ML) tool is a pad-type version of the spherically focused log 

(SFL) that was developed to eliminate borehole effects and 

achieve superior shallow resistivity measurements with high 

vertical resolution. Included with the MSFL tool is a ML 

sensor. The ML recorded 2-in. normal and 1.5-in. lateral 

resistivity measurements. The MSFL and ML tools are 

combined into one tool which can be run as a standalone 

service or in combination. The pads are arranged on 

opposing, powered caliper arms which provide accurate 

measures of borehole size. 

Applications 

The MSFL tool provides measurements of Rxo in all types 

of conductive mud systems. Rxo is used quantitatively in 

computing Sxo and moveable water volumes 

The ML tool is sensitive to the presence of mudcake and 

provides a qualitative indication of formation 

permeability 

Evaluation of thinly bedded sand/shale sequences 

Two powered caliper arms provide reliable estimates of 

borehole size 

Features 

The MSFL tool records resistivity with a vertical 

resolution of 8 in. and a depth of investigation of 3 in. 

The ML tool records resistivity with a vertical resolution 

of 2 in. and a depth of investigation of 1 in. 

Both the MSFL and ML tools, by virtue of being padtype 

devices, offer measurements relatively free of 

environmental effects. This makes them particularly well 

suited for operations in highly conductive (saltsaturated) 

mud systems 

Tool 

MSFL Tool 

ML with HFDT 

Assembly 1 

ML with SDLT 

Assembly 2 

Non-rubber versions of the MSFL and ML tools are 

available that provide superior resistance to gas 

absorption and better durability and run life over older 

rubber pad versions 

The tool can be run independently or in combination 

with other logging tools. When run in combination, the 

MSFL/ML tool can be placed anywhere in the toolstring 

MSFL Micro-Spherically Focused Log and Microlog (ML) Specifications 

Length 

ft (m) 

10.2 

(3.1) 

27.5 

(8.4) 

18.6 

(5.7) 

Diameter 

in. (mm) 

5 

(127) 

5 

(127) 

4.5 

(114.3) 

1 Weight, length, and diameter apply to the HFDT/Microlog assembly. 

2 Weight, length, and diameter apply to the SDLT/Microlog assembly. 


psi (Mpa) 

20,000 

(137.9) 

20,000 

(137.9) 

20,000 

(137.9) 

Maximum Temperature 

°F (°C) 

350 

(176.7) 

350 

(176.7) 

350 

(176.7) 

Weight 

lb (kg) 


214 

(96.4) 

720 

(326.6) 

475 

(215.5)

HFDT High Frequency Dielectric Tool 

The HFDT high frequency dielectric tool is a pad-type 

electric logging tool used primarily in the determination of 

flushed-zone water saturation (S xo). The HFDT tool 

transmits a continuous 1,000 MHz electromagnetic wave 

into the formation and measures the propagated wave 

amplitude and phase with respect to the transmitted signal. 

The principle measurement objectives are to determine the 

complex dielectric constant of the formation. Depth of 

investigation ranges from 1 cm to about 10 cm. 

Applications 

Provides reliable Rxo measurements for determining 

flushed-zone water saturation (Sxo ) and moveable 

hydrocarbon volumes 

Determining irreducible water saturation (Swirr ) in oilbased 

muds 

Evaluation of thinly bedded sand/shale sequences 

Determination of the cementation exponent (m) when 

combined with other micro-resistivity logs 

Features 

Absolute and differential dielectric measurements are 

recorded, resulting in less sensitivity to borehole rugosity 

Uniquely measures both the incident and reflected phase 

and amplitude signal 

Phase-shift and attenuation measurements from three 

receivers for increased accuracy 

Automatic gain control permits good log quality across a 

wide range of formation resistivity 

Extendable pad sensor reduces borehole rugosity effects. 

An accelerometer curve and composite profiles of 

resistivity and dielectric curves give indications of 

irregular tool motion, mudcake buildup, and pad lift-off 

Length 

ft (m) 

27.5 

(8.4) 

Independent deployment of the pad and backup arm 

permit optimal alignment with other tools in the 

toolstring for more effective combination logging 

Works in fresh, salt-saturated, and oil-based mud 

systems, freshwater and most saltwater formations, and 

in formations where water salinity is highly variable or 

unknown 

HFDT log computed on a sandstone matrix. Hydrocarbons are 

indicated when dielectric porosity FPHI falls below density/neutron 

porosity. In the above example, the high frequency dielectric clearly shows 

that the zones from 46 ft to 83 ft and 91 ft to 99 ft are hydrocarbon bearing 

while the zone from 132 ft to 142 ft is water filled. 

HFDT High Frequency Dielectric Tool Specifications 

Diameter 

in. (mm) 

4.75 

(120.7) 


psi (Mpa) 

20,000 

(137.9) 


°F (°C) 

Weight 

lb (kg) 


320 

(160) 

720 

(326.6)

Imaging 

EMI Electrical Micro Imaging Service 

The EMI Electrical Micro Imaging service provides highly 

detailed, core-like images of the formations encountered by 

the borehole. These images are produced by measuring and 

mapping formation micro-resistivity with each of the 150 

pad-mounted button electrodes on six independent arms. 

The current of each button is recorded as a curve and 

sampled every 0.1-in. (120 samples/ft). These current 

variations are then converted to color or gray-scaled images. 

Conventional dipmeter information is embedded into the 

image data and is available for standard SED tool answer 

products. A navigation package is included in the EMI tool to 

provide accurate information on tool position and 

orientation within the borehole. 

Consistent, direct pad contact with the borehole wall is 

essential to obtaining high quality borehole image data. By 

virtue of independent arm linkages and pad articulation, 

optimum pad contact can be maintained with a minimum of 

pad pressure even in rugose, washed-out, or non-circular 

boreholes. This results in accurate, sharp images, more 

complete borehole coverage, and a reduced dependence on 

corrections for irregular tool motion effects (speed 

corrections). In addition, the EMI service uses six 

independent arms, making it possible to acquire quality 

image data in non-optimal hole conditions. 

Applications 

Provides a variety of real-time and post-processing 2D 

and 3D image products to evaluate geological, 

petrophysical, and borehole properties 

Offers detailed structural, stratigraphic, and 

sedimentological analysis for optimized offset well 

placement, completion tactics, and hydrocarbon 

depletion efficiency 

Allows thin bed delineation and improved net pay 

estimations 

Quantifies rock textures and electro-facies 

Permits 2D and 3D borehole geometry and breakout 

presentations from 6 caliper measurements as well as 

characterization and evaluation of secondary porosity 

Identifies orientation and connectivity of fracture 

systems 

Features 

Electric borehole technology has the capability of resolving 

features impossible to resolve using conventional logging 

tools. Small fractures, vugs, bedding planes, depositional 

features, thin beds, and rock texture changes provide 

significant insights that can impact reservoir exploration and 

development. 


SHIVA program 

AutoDip service 

TrendSetter service 

Texture-profile 

Manual dip picking 

Image interpretation 

Static (Track 2) and dynamic (Track 5) enhancement of an EMI 

borehole image showing a sand-shale sequence and the computed dips 

(Track 4) of the sedimentary strata. Vertical fractures (drilling artifacts) 

are also seen in the enhanced images. High resolution data can provide 

insight into the texture of the formation and reveal details conventional 

logs cannot. 


HAL9155

Equipment 

HAL9156 

Soft sediment deformation and slumping are captured on the 

electric image. The AutoDip program does a good job of 

capturing the dip reversals and handling the high angle dips. 

HAL9158 

EMI Tool Only 

EMI Toolstring 

Structural and stratigraphic dips are well represented in this 

example. Slumping above the base of the sand (3295) is 

evident and current bedding above give evidence of the 

depositional environment. 

EMI Electrical Micro Imaging Service Specifications 

Length 

ft (m) 

24 

(7.3) 

41 

(12.5) 

Diameter (minimum) 

in. (mm) 

5 

(127.0) 

5 

(127.0) 


psi (Mpa) 

20,000 

(137.9) 

20,000 

(137.9) 

Fine structural and stratigraphic details of a thinly bedded 

reservoir are captured in this borehole image. The 

automatically picked dips do an excellent job of capturing 

dip trend details. There are over 100 dips selected in this 

13-ft interval. Hand picking would be tedious, time 

consuming, and perhaps discretionary. 


HAL9157 


°F (°C) 

350 

(176.7) 

Weight 

lb (kg) 

496 

(225) 

350 

(176.7) N/A

XRMI X-Tended Range Micro Imager Tool 

This new electrical wireline borehole imaging tool is 

designed to obtain superior quality images even in high 

R t:R m environments. The expanded operating range of the 

XRMI X-tended range micro imager tool over 

conventional electrical imaging tools is achieved through its 

new, state-of-the-art 32 bit digital signal acquisition 

architecture combined with a large increase in available 

power for the excitation current (EMEX). 

As a result, the signal to noise ratio of the raw measurements 

is improved by a factor of up to five, and the dynamic range 

is expanded by a factor of up to three. The resulting images 

offer superior fidelity even in highly resistive formations 

(R t > 2000 ohm �m) or relatively salty borehole fluids 

(R m < 0.1 ohm �m). 

Besides the new electronics, the mandrel architecture derived 

from Halliburton’s highly successful EMI imaging tool 

greatly helps the XRMI tool generate superior quality 

borehole images. Pads mounted on six independently 

articulated arms help maintain pad contact in rugose, 

washed-out, elliptical, or highly deviated boreholes. Further, 

high sampling rate (120 samples/ft) and adequate borehole 

coverage (67% in 8.5 in. holes) help obtain high resolution 

pictures of the borehole walls. 

Applications 

Shows bedding dips that help rationalize the choice of 

next drilling location 

Chooses the sidewall core zones, formation testing zones, 

and perforation intervals accurately by integrating 

images with other open-hole logs 

Computes accurate high resolution net-to-gross 

Optimizes offset well placement by evaluating structural 

and stratigraphic features and bedding orientation 

Provides more accurate net-to-gross estimations in 

laminated shaly sands and carbonates by delineating thin 

beds and laminations 

Rationalizes well stimulation and formation testing 

decisions by characterizing the secondary porosity (e.g. 

fractures and vugs) in reservoirs 

Optimizes drilling efficiency by evaluating and orienting 

borehole breakout 

Optimizes the completion tactics and reservoir 

management by providing characterization of rock 

texture and electro-facies 

a b c 

High resolution XRMI images showing the micro-textural geological 

details in the fabric of a limestone section in a test well from Permian 

Basin, West Texas: (a) vugular open porosity; (b) open natural fractures; 

and (c) stylolites. The R t:R m ratio exceeds 100,000 in this borehole. 


HAL13883 

HAL13882

Length 

ft (m) 

24.18 

(7.37) 

Maximum OD 

in. (cm) 

5 

(12.7) 

HAL13884 

Borehole coverage is 67% in 8.5 in. hole. 

An XRMI formation evaluation answer product generated by Halliburton’s 

proprietary software WXforecast. The first image track shows the static 

equalized image and the second image track exhibits the texture-enhanced high 

resolution image produced by the application texture-pro. Central dip-track 

shows the results of Auto-Dip service. The sharp change in the dip azimuths 

from west to east is interpreted to be due to slump faulting. The base of the 

channel sand is also a scoured surface. 

XRMI X-Tended Range Micro Imager Tool Specifications 

Minimum Hole Size 

in. (cm) 

6 

(15.240) 

Maximum Hole Size 

in. (cm) 

21 

(53.34) 


psi (Kpa) 

20,000 

(137 895) 

Maximum 

Temperature 

°F (°C) 

350 

(176.7) 

Weight 

lb (kg) 


496 

(225)

OMRI Oil-Based Micro-Imager Tool 

The latest addition to Halliburton’s borehole imaging 

solutions is the OMRI tool for use in oil-based muds. The 

OMRI tool generates crisp, high-resolution digital images of 

the wellbore down to 1 in. of vertical resolution, instead of 

1 ft of vertical resolution that is available with conventional 

logging tools. The extra resolution makes thin bed pay and 

other important features clearly visible. 

An advanced pad sensor generates six resistivity 

measurements per pad, each with a vertical resolution of 1 in. 

and a depth of investigation of about 3 in. Data is collected at 

120 samples per foot with a proprietary signal acquisition 

scheme optimized for rugose hole conditions. The pads are 

mounted on six independent caliper arms which yield true 

assessments of borehole shape and stress, useful in frac jobs 

and completion designs. The sensor pads are mounted on the 

caliper arms with unique two-axis of articulation. This 

facilitates improved pad contact, and thus improved images, 

in less than ideal borehole conditions. This combination of 

features provides unparalleled image fidelity over the widest 

possible range of logging conditions. 

HAL18834 

Applications 

High vertical resolution pay zone volumetrics (both 

fluids and minerals) 

Pay zone detection (in extreme thin bed / “low contrast” 

pay zones) 

Structural and stratigraphic dips 

Sedimentary features and textures 

Net-to-gross sand counts 

Identification of faults and unconformities 

Evaluation of sedimentary sequences and flow units 

Lithologic unit thickness 

Secondary porosity evaluation 

Sequence stratigraphy analysis 

Borehole stresses analysis 

Open-Hole Wireline Services 3-13

Features 

Identifies important reservoir characteristics, such as 

structural and stratigraphic dips, sedimentary geometry 

and texture, borehole stresses, and lithologic unit 

thickness 

Recognizes features beyond resolution of conventional 

logs, including permeability barriers, sand attributes, 

clasts, vugs, and more 

Quantifies important reservoir characteristics such as 

lithology, porosity, water saturation, permeability, fluid 

profile, and flow potential when integrated with other 

logs and well information 

Provides detailed, accurate pictures of the reservoir that 

answer key geological and petrophysical questions 

Identifies thin bed pay that cannot be seen with 

conventional logs, particularly in geologically younger, 

unconsolidated formations 

Helps increase success rate in multi-well developments 

by answering questions about sedimentology and 

structural and stratigraphic analysis, which serve to 

enhance reservoir management decision making 

Optimizes design of completion programs in order to be 

more efficient and cost effective 

Length 

ft (m) 

27.54 

(8.39) 

Maximum OD 

in. (cm) 

5.5 

(13.97) 

Range of Mudcake 

Thickness Mudcake Resistivity 

OMRI Oil-Based Micro-Imager Tool Specifications 


psi (Kpa) 

20,000 

(137 895) 

Maximum 

Temperature 

°F (°C) 

350 

(176.7) 

Borehole Conditions 

Recommended Logging Speed* 

Minimum Hole 

in. (cm) 


6.5 

(16.5) 

HAL18835 

Maximum Hole 

in. (cm) 

24 

(60.96) 

Borehole Fluids 

Weight 

lb (kg) 

760 

(344.73) 

High Data Rate Low Data Rate Tool Positioning Salt Fresh Oil Air 

0 - 0.25 in. > 10,000 ohm-m 30 ft/min (9.1 m/min) 20 ft/min (6.1 m/min) Centralized X 

*Slower logging speed may be required for low resistivity environments or poor borehole conditions.

CAST-V Circumferential Acoustic Scanning Tool-Visualization 

The CAST-V circumferential acoustic scanning toolvisualization 

is an ultrasonic tool that provides highresolution 

images in both fresh and oil-based drilling fluids. 

The tool’s interchangeable head rotates a full 360° and 

contains a high-frequency acoustic transducer to provide a 

full 360° profile of the borehole. A second acoustic 

transducer is mounted in the scanner housing and is used to 

measure characteristics of the borehole fluid. A directional 

sub is provided to orient images to either the high side of the 

hole or to north. The image mode, run primarily in open 

hole, consists of 200 points horizontally by 40 samples/ft 

vertically. The CAST-V tool is designed to operate in 

conjunction with other DITS tools but must be run 

centralized in fluid filled boreholes. 

Applications 

Provides complete borehole imaging for accurate, precise 

formation evaluation 

Detailed structural, stratigraphic, and sedimentological 

analyses for optimized offset well placement, completion 

design, and hydrocarbon depletion efficiency 

Thin bed delineation and improved net pay estimations 

2D and 3D borehole geometry and breakout 

presentations from acoustic caliper measurements 

Features 

Resolves features impossible to resolve using 

conventional logging tools. Small fractures, vugs, 

bedding planes, depositional features, thin beds, and 

rock texture changes provide significant insights that can 

impact reservoir exploration and development 

Real-time fluid cell measures both borehole fluid transit 

time and fluid impedance. The fluid transit time is used 

to correct the internal radius measurements made from 

the scanner head while the acoustic impedance 

measurement is used as a quality control monitor 


Manual dip-picking 

Image interpretation 

CAST-V tool open-hole fractures example—3D projection with 

perspective view. Borehole breakout (in direction of minimum stress) 

normal to strike of fractures. 

CAST-V Circumferential Acoustic Scanning Tool-Visualization Specifications 

Length 

ft (m) 

17.9 

(5.5) 

Diameter 

in. (mm) 

3.63 

(92.2) 


HAL9159 


psi (Mpa) 

20,000 

(137.9) 

Maximum 

Temperature 

°F (°C) 

350 

(176.7) 

Weight 

lb (kg) 

316 

(143.3)

SED Six Arm Dipmeter 

The SED six arm dipmeter is an electric logging tool that 

provides data used to compute formation dip. It provides six 

formation micro-resistivity measurements, tool orientation 

data, and six caliper curves. The six micro-resistivity 

measurements are taken at 60° increments around the 

borehole. This data is then correlated to identify bedding and 

other features in the formation. 

Applications 

Evaluate magnitude and direction of structural and 

stratigraphic dip events for offset well placement, 

reservoir modeling, and reservoir management decisions 

Improved evaluation of thinly laminated sand/shale 

sequences 

Fracture detection 

Directional data to provide TVD, drift surveys, and 

bottomhole location 

Caliper data as input to 2D and 3D borehole profile plots 

as well as integrated borehole volumetrics 

Features 

High resolution micro-resistivity measurements sampled 

at 0.1-in. 

Independent arm linkage and swiveled pads provide 

optimum pad contact with a minimum of pad force 

Tri-axial accelerometers and three magnetometers are 

employed to compute borehole drift, azimuth, and 

corrections for tool rotation and irregular motion 

Available oil-based mud pads for acquiring dip logs in 

non-conductive drilling fluids 

Six independent caliper measurements describe borehole 

washout and breakout in precise detail 

Length 

ft (m) 

22.3 

(6.8) 

SED Six Arm Dipmeter Specifications 

Diameter 

in. (mm) 

4.5 

(114.3) 


SHIVA program – standard analysis package to 

correlate raw micro-resistivity data and evaluate it for 

planar structural or sedimentological features. Results 

presented as vector (tadpole) plots. Available at the 

wellsite as well as in the computing centers 

Omnidip – module of SHIVA program uses the tool’s 

high sampling density to identify nonplanar surfaces and 

describe current bedding characteristics and other 

nonplanar sedimentary structures 

Resmapa – borehole imaging program that interpolates 

between the six micro-resistivity curves to produce a 

color oriented image of structural and sedimentological 

features 

Standard processed SED log showing the raw resistivity data and 

results of dip analysis. 


HAL9160 


psi (Mpa) 

20,000 

(137.9) 

Maximum 

Temperature 

°F (°C) 

350 

(176.7) 

Weight 

lb (kg) 

470 

(213.2)

Nuclear 

SDL Spectral Density Log 

The SDL spectral density log provides superior formation 

bulk density and borehole compensated photoelectric factor 

(Pe) measurements. 

Applications 

Determination of formation porosity 

Identification of formation lithology regardless of 

formation fluid type 

Indication of gas when used in combination with a 

neutron log 

Features 

Delineation of thinly bedded formations using the 

unfiltered Pe curve 

Field engineers perform precise calibration and wellsite 

checks 

Curves indicating data quality are displayed on a 

computer screen in real-time and are recorded on the log 

Advanced correction algorithm is applied to density data 

Rigid tungsten pad incorporates a 1.5-curie cesium-137 

source and two high-efficiency scintillation detectors 

designed to maintain high gamma counts 

Rugged construction and advanced gain stabilization 

help maintain measurement integrity under varying 

temperature conditions 

Combinable with a complete family of tools that 

operates under the DITS digital interactive telemetry 

system 

CALIPER 

INCHES 

GAMMA 

API 

Typical Field Output of the SDL Tool 

Mineral Identification Plot 


HAL9374 

6 

0 

-4.5 

4.5 

Quartz 

QS 

QL 

16 

200 

0.5 

-0.5 

X250 

X300 

X350 

X400 

X450 

Dolomite 

2.0 

Pe c 

rb 

0 10 -0.25 

HAL323 

Dr 

3.0 

0.25 

Calcite


The wellsite answer product is apparent bulk density of 

the formation and borehole compensated photoelectric 

factor 

Bulk density or density porosity data is used with other 

open-hole sensors as input to Halliburton’s mineralogy, 

open-hole, and cased-hole saturation analysis to provide 

a complete formation evaluation product. These include: 

Length 

ft (m) 

19.3 

(5.9) 

SDL Spectral Density Log Specifications 

Diameter 

in. (mm) 

4.5 

(114.3) 


psi (Mpa) 

20,000 

(137.9) 

– ULTRA multi-mineral evaluation program 

– CORAL complex lithology analysis 

–LARA laminated reservoir analysis 

– SASHA shaly sand analysis 

Maximum 

Temperature 

°F (°C) 

350 

(176.7) 

Weight 

lb (kg) 

420 

(190.5) 


DSN Dual-Spaced Neutron Tool 

The DSN dual-spaced neutron tool is a thermal neutron 

tool designed to measure formation porosity from neutronnuclei 

interactions. Neutron porosity logs provide total fluid 

information for use with resistivity logs and/or pulsed 

neutron logs in determining formation water saturation. 

They can be combined with density logs to provide an 

indication of formation gas saturation and also with density 

and/or sonic logs to provide indications of formation 

lithology. In open holes, the DSN tool is usually combined 

with the SDLT spectral density logging tool and the 

NGRT natural gamma ray tool. In cased holes, the 

DSN tool is usually combined with the NGRT tool and 

DITS casing collar locator. 

The DSN tool consists of an instrument section housing the 

electronics, two He3 detectors, and a source sub housing an 

americium-beryllium source which generates fast neutrons 

that penetrate the formation at an initial energy of 4.6 MeV. 

Thermal neutron tools are not as limited by the spacing and 

depth of investigation problems associated with epithermal 

neutron tools. Since thermal neutrons are detected, count 

rates are much higher than for epithermal neutrons. 

However, thermal neutron detectors are more sensitive to 

lithology and are affected by borehole and formation salinity. 

The dual detector method is used to compensate for these 

environmental effects. 

Applications 

Gas detection 

Porosity 

Lithology 

Features 

Detector array contains two helium proportional 

counters 

Optimized detector spacing, advanced calibration 

methods, and greater counting rates 

Faster log runs 

Delineation of thin-bed formations with enhanced 

vertical resolution (EVR) available in real-time or in 

post-processing 

A combination of logging tools can be run to identify 

lithology, reveal gas zones, and calculate shale volumes 

In this DSN log example, the subject well was logged twice. The 

resulting near/far ratio curves and the calculated porosity curves are 

overlaid to illustrate the high repeatability of DSN tool 

porosity measurements. 


HAL1664


Wellsite answer product is the neutron porosity NPHI 

Neutron porosity data is also used with other open-hole 

sensors as input to Halliburton’s mineralogy, open-hole, 

and cased-hole saturation analysis to provide a complete 

formation evaluation product. These include: 

Length 

ft (m) 

10.25 

(3.1) 





DSN Dual-Spaced Neutron Tool Specifications 

Diameter 

in. (mm) 

3.63 

(92.2) 


psi (Mpa) 

20,000 

(137.9) 


°F (°C) 

350 

(176.7) 

Weight 

lb (kg) 

196 

(88.9) 


DSEN Dual-Spaced Epithermal Neutron Log Tool 

The DSEN dual-spaced epithermal neutron log tool is a 

subsurface logging tool that provides a measurement of 

epithermal neutron porosity. It is used primarily in air-filled 

wells or in fluid-filled wells where shales and/or formation 

salinity adversely affect thermal neutron measurements. In 

open boreholes, the DSEN tool is usually combined with the 

SDLT spectral density logging tool and the NGRT 

natural gamma ray tool. 

Applications 

Neutron porosity measurements in water or gas filled 

boreholes 

Gas detection in the formation or in filled wellbores 

when combined with density measurements 

Porosity curve measurements that are less affected by 

thermal neutron absorbers in shale, such as boron and 

gadolinium 

Features 

Less affected by formation water salinity 

Combinable with other tools 

Optimized dual neutron detector design combines twodetector 

responses for enhanced accuracy 

Uses a steady-state neutron generating source 

(radioactive americium-beryllium, AmBe) and two 

epithermal neutron detectors to investigate formation 

porosity 

Provides reliable porosity measurements even in air, gas, 

and foam-filled boreholes 

Provides consistent, repeatable data over entire porosity 

range 

Requires minimum corrections in high-temperature 

environments, such as steamfloods and high-porosity 

formations 


Epithermal neutron porosity (wellsite) 









DSEN log computed assuming a limestone matrix. The bottom of the 

well is liquid filled. From x534 to the top, the well is air filled. Formation 

gas is indicated when the density porosity becomes greater than the 

neutron porosity. This log reveals good gas zones from x586 to x427. 

DSEN Dual-Spaced Epithermal Neutron Log Tool Specifications 

Length 

ft (m) 

7.25 

(2.2) 

Diameter 

in. (mm) 

3.63 

(92.2) 


HAL1663 


psi (Mpa) 

20,000 

(137.9) 

Maximum 

Temperature 

°F (°C) 

350 

(176.7) 

Weight 

lb (kg) 

170 

(77.1)

CSNG Compensated Spectral Natural Gamma Ray 

The CSNG compensated spectral natural gamma ray tool 

measures the gamma ray spectrum from 0 to 3,000 keV. The 

tool uses full-spectrum processing to provide precise and 

accurate logs of potassium, uranium, and thorium 

concentrations. Measurement precision curves and tool 

diagnostics help validate logging data quality. 

The CNSG tool's unique stabilizer system differentiates it 

from the competition by compensating for temperature 

related drift in the gamma ray energy gain and offset 

conversion. The full-spectrum processing performs 

additional refinement of the energy calibration and 

compensates for variations in detector resolution. 

Another unique feature of the CSNG tool is its ability to 

provide real-time outputs corrected for the borehole 

environment and converted to standard conditions 

(8.625-in. borehole, freshwater in borehole, no casing, and 

tool eccentered). 

Estimates of borehole potassium concentration and 

photoelectric absorption made during the log are helpful to 

confirm real-time corrections or to apply corrections in a recomputation 

mode. Also, removal of borehole potassium 

signal produces accurate total gamma ray and elemental 

yields in potassium muds. 

Applications 

Detection of producible zones 

Determine clay types, volumes, and cation exchange 

capacity using elemental concentration data and CLAMS 

clay and matrix analysis post-processing analysis 

Features 

Measures and records energy of individual gamma rays 

Elemental yield calculations are insensitive to 

photoelectric absorption in barite muds or other high-Z 

materials 

Filtering technique improves the statistical precision of 

the elemental yields 

Forms a spectrum of gamma energies indicating the 

number of gamma rays recorded at each energy level 

0 to 3 MeV spectrum facilitates determination of 

potassium, uranium, and thorium weight concentrations 

in the formation 

Reduced cross-correlation among elemental yields 


Output from the CSNG spectral processing includes 

total gamma ray and elemental concentrations of 

potassium, uranium, and thorium 

Clay typing, volumes, and cation exchange capacity can 

be compared using CLAMS analysis software 

CSNG log with gamma ray contributions from thorium, potassium, and 

uranium 


Housing 

Titanium 

Low Z 

LOGIQ ® CSNG Compensated Spectral Natural Gamma Ray Specifications 

Makeup Length 

ft (m) 

14.9 

(4.5) 

12.9 

(3.9) 

Diameter 

in. (mm) 

3.625 

(92.1) 

3.625 

(92.1) 

*Please refer to the CSNG Pressure Rating Chart below. 

HAL23446 

Maximum Pressure* 

psi (Mpa) 


°F (°C) 

Weight 

lb (kg) 


14,000 

(96.5) 

8,000 

(55.2) 

350 

(176.7) 

275 

(135) 

271 

(122.9) 

260 

(117.9)

Acoustics 

BSAT Borehole Compensated Sonic Array Tool 

Halliburton's BSAT service integrates two monopole 

transmitters with an array of five receivers. This tool 

configuration provides borehole compensation of the P-wave 

measurement. The full waveform data is digitally recorded 

for each receiver, thus permitting advanced data analysis and 

quality control for waveform amplitude, slowness, and 

arrival time in both open-hole and cased-hole applications. 

The BSAT tool is over 12 ft shorter than many other acoustic 

logging tools. While not compromising data quality, the 

reduction in tool length helps speed up rig-up and rig-down 

times, especially when lubricator and pressure control 

equipment are required. 

The P-wave slowness is obtained using a robust waveform 

cross correlation coherency process which utilizes the 

waveform data from the entire receiver array. The process 

evaluates many attributes of the waveform data before 

selecting, in real time, the acoustic velocities of the 

formation. 

The BSAT tool can also be used for 3-ft to 5-ft CBL-VDL 

measurements and can be run in combination with any IQ 

tool services. 

Applications 

P-wave slowness used for sonic porosity determination 

Time-to-depth correlation 

Synthetic seismograms 

Identification of pore pressure changes 

3-ft to 5-ft CBL-VDL measurement 

Instantaneous waveform attributes 

Features 

Waveforms can be recorded at high logging speeds 

The P-wave slowness is obtained using a robust 

waveform cross correlation semblance process 

Downhole digitization helps eliminate the transmission 

noise and improve signal-to-noise ratio. Compression 

technique allows high uplink data transfer rate 

Length 

ft (m) 

15.83 

(4.82) 

Can be used as CBL tool in combination with any 

LOGIQ® cased-hole services 

Gamma ray, VpVs, and caliper presented in Track 1. 

Compressional and refracted shear are presented in Track 2. 

Semblance with compressive and shear slowness overlaid on 

the semblance image are presented in Track 3. 

BSAT Borehole Compensated Sonic Array Tool Specifications 

Diameter 

in. (mm) 

3.63 

(92.2) 


psi (Mpa) 

20,000 

(137.9) 


°F (°C) 

350 

(176.7) 

Weight 

lb (kg) 

318 

(144.4) 


WaveSonic ® Tool 

The WaveSonic® crossed dipole sonic tool provides 

simultaneous monopole, XX dipole, and YY dipole sonic 

measurements. The dipole flexural wave propagation allows 

for the measurement of shear wave slowness in virtually all 

formation conditions. The compressional P-wave slowness, 

refracted shear wave slowness, and Stoneley wave properties 

are obtained from the monopole data. The shear wave 

slowness in two orthogonal directions can be obtained in 

real- time from the XX and YY dipole data. The WaveSonic 

tool is combinable with all standard open and cased-hole 

tool services. The WaveSonic tool requires a liquid filled 

borehole and can be used in freshwater, saltwater, or oilbased 

mud systems. The robust mechanical design of this 

tool allows for drillpipe conveyed logging, and it is not 

limited to the bottom of the toolstring. A hostile WaveSonic 

version is available for high-temperature and high-pressure 

applications. 

The shear wave slowness in the XX and YY directions and the 

monopole P-wave slowness are the basic well site 

deliverables. The tool has 32 broadband receivers, arranged 

in eight rings of four receivers, to provide high-quality 

waveform data. The tool provides 96 waveforms (32 

monopole, 32 YY dipole, and 32 XX dipole) for each firing 

cycle, which are recorded by the surface system. The fast and 

slow shear wave travel times are obtained with advanced 

waveform processing methods in Halliburton's reservoir 

evaluation services centers, strategically located throughout 

the world. 

From the fast and slow shear wave travel times, and their 

orientation in the formation, the minimum and maximum 

principal stresses and stress field orientation can be obtained 

by combining oriented slowness data with overburden and 

analysis, wellbore stability, and production enhancement 

treatment design. 

Natural gamma ray and caliper are presented in Track 1. Semblance 

quality data is presented in the depth track. The dipole X travel time, 

dipole Y travel time, and monopole P-wave travel time are presented 

in Track 2. Monopole semblance with the compressive wave slowness 

overlaid on the semblance image are presented in Track 3. The dipole 

X semblance with the XX shear wave slowness overlaid on the 

semblance image are presented in Track 4. The dipole Y semblance 

with the YY shear wave slowness overlaid on the semblance image are 

presented in Track 5. 


Sonic anisotropy analysis provides the fast and slow shear 

wave travel times as a simultaneous solution of 64 waveforms 

(32 XX and 32 YY). Anisotropy and its orientation can be 

used to determine the minimum horizontal stress and the 

orientation of natural fractures. The sonic attributes of 

slowness, amplitude, and frequency content can be used for 

identification of fractures and compressive fluids and to 

measure various geomechanical properties. The fast and slow 

shear wave travel times and their orientation, combined with 

P-wave slowness, allows for better 3D seismic analysis. 

Applications 

Determine fast and slow wave travel times and 

orientation in the formation 

Calculate minimum and maximum principal stresses 

and stress field orientation 

Porosity estimation 

Fracture identification 

Permeability (mobility) estimation 

AVO calibration 


Features 

Programmable-frequency sources to minimize effects of 

near-wellbore alteration 

Length 

ft (m) 

Tool 

Version 

20 kpsi 

Tool 

30 kpsi 

Tool 

34.0 

(10.3) 

Length 

ft (m) 

40.9 

(12.4) 

40.9 

(12.4) 

Diameter 

in. (mm) 

3.63 

(92.2) 

WaveSonic ® Tool Specification 


psi (Mpa) 

20,000 

(137.9) 

Broadband eight-level, quad receiver array for highquality 

waveform data 

All 96 waveforms for each set of transmitter firings are 

recorded at the surface for advanced waveform 

processing techniques 

Combinable with all open-hole tools, including MRIL® 

and RDT tools and services 


Shear slowness anisotropy analysis 

RockXpert2 sand production and fracture strength 

analysis 

FracXpert fracture stimulation zoning analysis pore 

pressure data information is vital for geo-mechanical 


Stoneley derived permeability 

Stoneley reflection analysis 

Formation stress, borehole stability, and sanding 

potential 

Maximum 

Temperature 

°F (°C) 

350 

(176.7) 

Hostile WaveSonic ® Tool Specification 

Diameter 

in. (mm) 

3.13 

(79.4) 

3.13 

(79.4) 


psi (Mpa) 

20,000 

(137.9) 

30,000 

(206.8) 

Maximum 

Temperature 

°F (°C) 

500 

(260.0) 

500 

(260.0) 

Weight 

lb (kg) 

520 

(236.3) 

Weight 

lb (kg) 

595 

(269.9) 

720 

(326.6) 


FWS Full Wave Sonic Tool 

The FWS tool provides compressional wave, refracted 

shear wave, and Stoneley wave properties of downhole 

formations for a wide range of petrophysical, geological, and 

geophysical applications. To minimize the number of logging 

trips required for complete formation evaluation, the FWS 

tool is compatible with all DITS logging tool strings. A 

liquid-filled borehole is required for sonic logging and can be 

used in fresh, salt, or oil-based mud systems. 

The long transmitter-to-receiver offset allows for the 

acquisition of borehole sonic data beyond the effects of any 

near-wellbore altered region. This long offset also allows for 

the acquisition of high-quality sonic data in enlarged 

boreholes where critical angle effects would affect sonic tools 

with short transmitter-to-receiver offsets. 

The information obtained from the FWS tool is plotted in 

three separate log presentations: 

Slowness presentation – compressional slowness and 

refracted shear slowness, velocity ratio, and time-depth 

integration of the compressional and shear travel times, 

and other logging data such as gamma ray and caliper 

Quality presentation – indicators which establish 

confidence levels for the slowness processing, including 

compressional slowness and semblance coherency and 

refracted shear and semblance quality gain curves for 

each receiver 

Waveform presentation – waveforms from all four 

receivers can be presented. Gain curves reflecting the 

gain applied to the waveform by the automatic gain 

control (AGC) circuit, and correlation curves, including 

gamma ray and caliper information 

The FWS tool can be run in the cased-hole environment to 

obtain sonic properties through casing. Acoustic coupling of 

the pipe-to-formation is required for cased-hole 

applications. 

Applications 

Identify wave properties of downhole formations 

Acquisition of borehole sonic data 

The natural gamma ray, X-X caliper, Y-Y caliper, P-wave travel time and 

P-wave semblance quality are presented in Track 1. The monopole 

waveform data is presented in Track 2 in the MicroSeismogram format 

(X-Z) and in an X-Y waveform presentation in Track 3. 


HAL9170

Features 

Long transmitter-to-receiver offsets and 1 ft 

receiver-to-receiver spacings 

Detection of signals at all receivers for each transmitter 

pulse ensures constant source characteristics 

Automatic gain control of each receiver preserves signal 

amplitude 

Downhole digitizing helps eliminate transmission noise 

and allows broadband frequency response 

Low-frequency response allows detection of low 

frequency Stoneley waves and multiple Δt measurements 

per depth interval 

Continuous uninterrupted recording of full waveform 

signals 

Records various types of information including tool 

data, quality curves, and final results 

Operator-selectable multiple modes of tool operation, 

digitally recorded waveform data, and improved porosity 

estimates using both Δtc and Δts Length 

ft (m) 

28.6 

(8.7) 

FWS Full Wave Sonic Tool Specifications 

Diameter 

in. (mm) 

3.625 

(92.1) 


psi (Mpa) 

20,000 

(137.9) 

Lithology identification by means of velocity ratio, Δts/ Δtc, and location of gas zones, even in poor hole 

conditions and cased holes 

Indication of permeability variations with depth from 

Stoneley wave attenuation and slowness 

Detection of naturally fractured zones, determination of 

rock elastic constants, and estimation of formation 

strength and least horizontal stress 

Prediction of vertical extent of hydraulic fractures 

Improved vertical resolution for detection of thinner 

beds (Beds as thin as 3 in. can be identified with the t 

curves) 

Calculates sonic porosity from P-wave slowness and can 

determine secondary porosity by combining sonic 

porosity with neutron and density porosity data 

Time-to-depth correlation for seismic correlation 

Combining sonic slowness data with formation density 

data is the required input information needed for 

synthetic seismograms 

Maximum 

Temperature 

°F (°C) 

350 

(176.7) 

Weight 

lb (kg) 

460 

(208.7) 


NMR 

MRIL-XL and MRIL ® -Prime Magnetic 

Resonance Image Logging Tools 

The MRIL-XL tool is the latest family member of 

Halliburton's wireline NMR logging tools. Both the MRIL- 

XL and MRIL®-Prime should be considered the first choices 

for primary formation evaluation in open holes. 

NMR logging answers the four basic, critical questions all 

well operators must answer to understand the economics of a 

newly drilled prospect: 

Has the well penetrated reservoir rock? (What is the total 

and effective porosity in a complex lithology 

environment?) 

What types of fluids (hydrocarbons) are present in the 

reservoir and how are they distributed? 

What is the ability of the reservoir to produce these 

hydrocarbons, i.e. will they flow in this type of 

formation? (What is the permeability?) 

Will there be associated water production (BVI/FFI)? 

The MRIL-XL and MRIL-Prime tools utilize the very same 

principles as medical MRI by directly measuring the 

magnetic resonance of hydrogen atoms in fluids. Amplitude 

of the measured signals gives porosity, whereas the actual 

signature carries information on rock properties and fluid 

characteristics. 

Applications 

The MRIL® tools are used in open-hole logging programs to: 

Obtain minerology-independent measurements of 

porosity. The MRIL tools truly measure the amount of 

fluid in the pore space and do not measure rock matrix. 

Unlike density, neutron, or sonic porosity devices, which 

require accurate matrix and fluid-density or Δt-matrix 

and Δt fluid to compute porosity, the MRIL tools are 

uniquely a minerology-independent porosity tool(s), 

yielding clay-bound water porosity, irreducible porosity 

(i.e. volume of bound fluid), free-fluid porosity, and total 

porosity 

Provide a permeability profile along the well. (Note that 

standard perm values are not calibrated; this requires 

integration with core data.) 

Provide fluid-typing (gas-oil-water), find fluid contacts, 

identify changes in oil viscosity 

Identify low-resistivity and/or low-contrast pay zones 

MRIL®-Prime Service 


HAL18923 

HAL1716 

MRIL-XL Service

Features 

As an eccentered NMR tool, the MRIL-XL signal 

penetration into the formation is effectively increased in 

large boreholes, and the effects of drilling mud are 

eliminated. MRIL-XL service is available with a standard 

6-in. sonde to accommodate holes sizes from 7.875-in. to 

>12.25-in. and is especially effective in large deviated 

boreholes. MRIL®-Prime is available in two sizes (slim sonde 

has 4.875-in. OD and standard sonde has 6-in. OD) to 

accommodate hole sizes from 5.875-in. to 12.25-in. Both 

MRIL services may be operated at up to 9 RF-frequencies— 

allowing data acquisition to be fast and efficient. 

Each frequency creates an independent volume of fluids 

in the formation, which allows the tool to log 

considerably faster than any single frequency NMR tool 

Both MRIL services can acquire simultaneous T1 and T2 logs and all MRIL services have maximum temperature 

ratings of 350°F 

Through-wire and switching sub adapters offer ultimate 

combinability with other Halliburton tools and 

competitor tools 

Compatible with drillpipe or tubing conveyed type 

logging systems in highly deviated wells 

Accurately measures porosity in mixed mineralogy 

reservoirs 

Improves completion success in low-permeability 

reservoirs 

Identifies pay zones in laminated, fine-grained sand, and 

shale formations 

Increases access to reserves by providing complete and 

accurate analyses of low resistivity/low-contrast intervals 

Identifies zones of water-free production 

Sonde 

in. 

6.0 

Sonde 

in. 

6 

4.875 

Multi-frequency capability allows operators to acquire 

much more accurate data by combining the 

measurements made in each volume (at each different 

frequency) 

Only product to allow combining of different 

measurements probing different NMR properties of the 

fluids and formation in one single pass—a major step 

forward in fluid identification and quantification 

Has successfully pioneered the discovery of oil in zones 

which triple-combo has traditionally bypassed, leading 

to increased production of reserves and some spectacular 

discoveries in even mature production areas 

These huge amounts of reservoir information from a single 

device are extremely valuable for optimizing stimulation and 

completion programs, thereby optimizing the productivity 

of each well drilled. 


MRIAN MRI analysis – an integrated analysis which 

incorporates MRIL porosity from T1 and/or T2 plus 

resistivity data in the dual-water model 

TDA time domain analysis – a MRIL only fluids and 

porosity analysis derived from analysis of the raw NMR 

echo train data only 

DTW dual wait time analysis – an analysis of 

hydrocarbon type or types found within each reservoir. 

Obtained by operating the MRIL service using a short 

and long Tw (wait time, such as 1s and 12s) in a single 

logging pass 

DTE dual echo time analysis – an analysis of 

hydrocarbon or other fluids within each reservoir. 

Obtained by operating the MRIL service using two 

different Te (inter-echo spacing, such as a short Te of 

1.2ms and a longer Te of 6ms or longer) 

MRIL ® -Prime Magnetic Resonance Image Logging Tool Specifications 

Length 

ft (m) 

52.9 

(16.1) 

50.4 

(15.4) 

Length 

ft (m) 

45.7 

(13.49) 

Diameter 

in. (mm) 

6.00 

(152.4) 

4.875 

(123.8) 


psi (Mpa) 

20,000 

(137.9) 

20,000 

(137.9) 

MRIL-XL Service Specifications 

Diameter 

in. (mm) 

6.00 

(152.4) 


psi (MPa) 

20,000 

(137.9) 

Maximum 

Temperature 

°F (°C) 

350 

(176.7) 

350 

(176.7) 


°F (°C) 

350 

(176.7) 

Weight 

lb (kg) 

1,475 

(669.1) 

1,275 

(578.3) 

Weight 

lb (kg) 


1,600 

(726)

MRILab ® Magnetic Resonance Image Fluid Analyzer 

Halliburton's patented MRILab® service is another 

breakthrough development of nuclear magnetic resonance 

imaging technology for oil and gas operators. The service 

provides laboratory-quality fluids measurements at reservoir 

conditions in real time by directly measuring the magnetic 

resonance parameter T 1. Because contaminates mixed with 

crude oil modulate the T 1 response, these measurements can 

be interpreted to determine when a clean sample can be 

taken and saved in Halliburton's RDT reservoir description 

tool sample chambers. This ability to provide downhole 

laboratory-quality fluid measurements makes the MRILab 

service an integral component of the RDT tool. 

The MRILab service allows operators to measure relaxation 

times on reservoir fluids in-situ at true reservoir 

conditions—an important industry first. The measured T 1, 

T 2, and the self-diffusion coefficient (D) of the reservoir 

fluids tie directly into important fluid characteristics such as 

viscosity and apparent Hydrogen Index. This makes the 

MRILab service approach superior to traditional reservoir 

fluid sample processing that involves transferring samples 

uphole at the wellsite for conventional laboratory analysis. 

These measurements are significant for completion and 

reservoir engineering as well as for reservoir understanding, 

and they are available at the wellsite immediately where they 

will have the most value. 

Features 

Identifies connate oil vs. oil-based mud filtrate 

differentiation 

Provides accurate fluid data for MRIL® log 

interpretation either wireline or LWD 

Measures hydrocarbon viscosity in-situ 

Complements MRIL logging service and extends the 

application of MRI technology in reservoir fluids 

determination 

Can be conveyed on wireline or drillpipe 

Measures the magnetic resonance properties of reservoir 

fluids as the RDT pumps from the reservoir into the 

borehole or sample chamber 

Measures T1 of fluid in the flowline while pumping with 

the RDT 

Measures T2 and diffusivity of stagnant fluid in the 

flowline 

MRILab® service is a modular component to the RDT reservoir 

description tool, providing real-time fluid analysis while pumping 

out to determine optimal time to obtain the cleanest samples 

possible. 


Available immediately at vastly reduced cost compared to 

conventional laboratory measurement. Surface 

laboratory PVT analysis is both expensive and can take 

weeks or months to produce results. The actual task of 

collecting a reasonably uncontaminated reservoir fluid 

sample can require significant rig time. And during that 

time the clock is running on the well operators' and 

other contractors' time, rental equipment, and personnel 

costs. It is not uncommon for physical drillstem tests for 

viscosity and other key fluid properties to cost the 

operator hundreds of thousands of dollars when all the 

expenses are calculated 

More accurate measurements of native oil than other 

methods. Since the MRILab® measurements occur 

downhole on in-place and unaltered reservoir fluids, 

there is no direct human manipulation and no 

opportunity for the errors that can occur in surface lab 

work. The well operator can have confidence in the 

viscosity oil characterization measurement results on the 

native oil in place in the reservoir 

Results are available in real-time at the rigsite or by 

remote viewing. Viscosity and oil characterization are 

important attributes usable for making completion 

decisions 

Producing this information right away at the rigsite 

makes MRILab data infinitely more valuable than surface 

lab data that may be delayed for over a month. Similarly, 

the MRILab tool is equipped with real-time telemetry 

capability that makes the results of the measurements 

viewable remotely over a secure connection between 

client and the tool 

Health, Safety, and Environmental 

The ability to analyze the filtrate contamination level of 

reservoir fluids in real-time allows one to minimize the 

volume of fluid that is pumped from the formation into the 

wellbore before securing the fluid into the sample chamber. 

Further, real-time analysis of the reservoir fluids may reduce 

the number of samples that are required, thus eliminating 

the need for transfer and transport of hazardous fluid 

samples. 

Length 

ft (m) 

14 

(4.3) 

MRILab ® Service Specifications 

Diameter 

in. (mm) 

4.75 

(120.7) 


psi (Mpa) 

20,000 

(137.9) 

FluidXpert fluid analysis service – Real-time NMR fluid analysis from 

the MRILab® service while pumping out to determine optimal time to 

obtain sample. Available while pumping: real-time contamination 

estimation, fluid type probability, T 1 spectra, Hydrogen Index, 

capacitance, pressures, temperature, and pump rate. Available in 

real time at the wellsite and in a customer's office via InSite Anywhere® 

service. 

Maximum 

Temperature 

°F (°C) 

350 

(176.7) 

Weight 

lb (kg) 

400 

(181.4) 


Borehole Geophysics 

Wellbore Seismic 

High Resolution Seismic Imaging—(Near Offset VSP, 

Fixed Offset VSP, Walkaways, 3D VSP, Salt Proximity 

Surveys, Microseismic Surveys) 

Halliburton provides high-resolution images in the vicinity 

of the borehole using a number of different techniques 

depending on the objectives and the geologic environment. 

The techniques include vertical incidence vertical seismic 

profiles (VIVSP) in deviated wells, salt proximity surveys, 

tomographic velocity analysis, fixed offset VSP surveys 

(FOVSP), 2D walkaway surveys, 3D VSP, and ExactFrac® or 

microseismic surveys. 

Halliburton is an industry leader in providing advanced 

source and downhole array technologies for borehole 

seismic. Halliburton’s expertise serves to benefit operators 

with reduced rig time and improved data quality. Advanced 

source and receiver technology is crucial towards obtaining a 

more accurate and comprehensive geological picture of your 

well, field, or reservoir. 

Halliburton can offer custom built solutions for client’s 

seismic imaging field needs. For survey planning, we use the 

most advanced 3D wavefront modeling software available, 

GeoTomo’s VECON software. 

Multi-component arrays can be mobilized downhole to more 

accurately record true amplitude information of both 

compressional and shear waves. 

Compressional and shear images can be used in conjunction 

for lithology and fluid identification. Surveys can be repeated 

for time-lapse 4D views of fluid movements. 

Downhole seismic tools can also be used to passively listen to 

the reservoir and to map fluid movements, fault reactivation, 

or active fracture monitoring. 

A full array of tools is available for analyzing high resolution 

seismic data for reservoir imaging. Halliburton offers 

advanced pre-processing, including multi-component 

wavefield separation and final imaging using pre-stack depth 

migration (PSDM). 

High Resolution Seismic Imaging Features 

Generation of high-resolution multiple free images 

Mapping of steep structures (such as salt flanks) 

Detailed velocity cubes in areas of laterally changing 

velocity (shallow gas, permafrost, salt, etc.) 

Map structure, stratigraphy, lithology, and fluids with 

higher resolution and confidence than can be obtained 

with surface seismic 

Improve a poor data quality area or overcome no-data 

areas 

High Resolution Seismic Imaging Applications 

Profiling salt dome flanks 

Detecting natural fractures 




Anisotropy determination 

AVO analysis 

Determine height, length, and width of well frac or 

stimulation process 





ExactFrac® services 


Reservoir Geophysics 

Long Array Multi-Component Acquisition Tools 

Halliburton offers survey planning, data acquisition, and 

data processing using multi-component long seismic arrays. 

Each tool combines advanced-source technology with 

industry leading multi-component and anisotropic 

migration software for a complete package of advanced 

custom designed reservoir imaging systems. Systems include 

the GeoChain VSP downhole receiver array. 

GeoChain VSP Downhole Receiver Array 

The GeoChain vertical seismic profile (VSP) array is 

designed for large borehole imaging surveys and can be used 

in open and cased holes with standard seven-conductor cable 

even in deep and hostile environments. 

GeoChain VSP Receiver Array Features 

Based on the proven ASR-1 downhole geophone 

Can be used in wells up to 25,000 psi and with hole sizes 

from 3.5-in. to 22-in. 

Unique ACS active cooling system allows continuous 

operation up to 356°F (180°C) 

Up to 42 satellites can be used in the array with a 

maximum tool spacing of 200 ft 

All satellite locking arms open and close simultaneously, 

and the entire string can lock into a 9.625-in. well in only 

30 seconds 

Can be run in the following configurations: 

No. of Tools Sample Rate 

5 1/2 ms 

10 1 ms 

21 2 ms 

26 2.5 ms 

32 3 ms 

42 4 ms 




Interwell imaging 

ExactFrac® (microseismic) services 

Synthetic Seismic and Sonic Log Calibration 

The synthetic seismogram obtains an accurate tie between 

well logs measured in depth and the surface seismic image 

measured in two-way time. Correlation between logs and 

seismic is important to verify interpreted horizons and to 

help determine the true phase of the surface seismic 

(important for advanced lithologic and fluid interpretations 

from seismic data). 

An accurate synthetic depends on sonic log calibration using 

data from a vertical seismic profile (VSP) or check shot 

survey. This calibration is necessary for a number of reasons 

such as: 

Sonic log and surface seismic are measured at different 

frequencies (dispersion) 

Sonic log and surface seismic can measure different rock 

and fluid volumes (fluid differences, invaded zones, 

damaged borehole, non-vertical ray paths, etc.) 

Calibration of the sonic log includes an analysis of the data to 

determine the cause of the differences (drift) between the 

sonic and the check shots. 

Depending on the cause of the drift, different methods of 

correction are used. The corrected sonic log is converted to 

interval velocity. Acoustic impedance is calculated using the 

corrected velocity log and the bulk density. Changes in 

acoustic impedance are used to create a reflection coefficient 

log, which is subsequently convolved with a desired wavelet 

to create a synthetic seismic trace. 

Recording of a shear sonic log or calculation of a synthetic 

shear log allows calculation of a 2D synthetic to analyze or 

predict AVO effects on the surface seismic. Perturbation of 

the rock parameters also allows study of the effects of fluid 

and lithology changes on the seismic character. 

Synthetic Seismic Features 

Helps promote accurate tie between well logs and surface 

seismic including phase determination 

Allows identification of multiples on the surface seismic 

Allows study of fluid and lithology effects on the seismic 

character 




3D VSP, salt proximity, AVO Studies) 



Vertical Incidence Vertical Seismic Profiling (VIVSP) Analysis 

The VIVSP analysis is a downhole seismic survey with the 

surface source positioned vertically above the geophones 

anchored in the well. In a vertical well, it is known as a zero 

offset VSP (ZOVSP) with the source positioned in a single 

location near the wellhead. In highly deviated wells, the 

source is moved along with the downhole geophone tool to 

keep the source vertically positioned above the geophone 

tool at each level. 

VIVSP analysis is useful for facilitating more accurate timedepth 

correlation between your well logs and your surface 

seismic. It is also useful for determining the phase of your 

surface seismic and for identifying multiples. 

VIVSP data provides an indispensable bridge between sonic 

log data and surface seismic data. In areas where it is difficult 

to obtain a good tie between the synthetic and the surface 

seismic, the VIVSP can be helpful to identify and resolve the 

differences. 

VIVSP is also very useful for predicting lithology, fluids, and 

pore pressure ahead of the bit. Velocity trends that are useful 

for predicting pore pressure are calibrated at the well. 

VIVSP data is typically higher frequency than the surface 

seismic and can be used to better understand the reflectivity 

seen in the surface seismic. 

VIVSP data can be useful for computing the dip of the 

reflecting horizons in the vicinity of the borehole. 

This can be used to confirm dips seen on dipmeter tools and 

help project these dips away from the well. 

In deviated wells, the VIVSP also delivers a high resolution 

2D image beneath the wellbore. This image is typically 

higher frequency than the surface seismic, multiple free, and 

tied directly to the wellbore in depth. 

Halliburton uses advanced proprietary software to handle 

VSPs in the most demanding geologic environments 

(advanced editing, multi-component wavefield separation, 

interpolation, deconvolution, and migration tools). 

VSP software and processing can be used in the field, in a 

computing center linked to the wellsite, or in the client 

offices for special projects. 

VSP acquisition teams utilize customized energy sources and 

the most advanced seismic tools available to record high- 

quality seismic data. The rugged, computerized logging 

systems precisely position the geophone tool in the well, 

properly synchronize the energy sources, and accurately 

transfer the measured data to the surface. The data obtained 

from VSPs provide extremely important information for 

enhancing and supplementing surface seismic data. 

VIVSP Features 

Allows detailed analysis of the downgoing and upgoing 

wavefield 

Real seismic trace rather than synthetic for log seismic 

correlation 

Provides detailed velocity analysis 

VSP Applications 

Direct correlation between surface seismic data and logs 

recorded in depth 

Calibrate wireline sonic data for correlating synthetic 

seismograms with conventional seismograms 

Mapping geologic structure in the vicinity of the wellbore 

Predict stratigraphy, lithology, and structure ahead of the 

drill bit to help save drilling time and costs 

Improve poor data-quality area or overcome no-data area 

Helps profile salt dome flanks 

Helps detect natural fractures 

Aids seismic identification of lithology 

Prospect delineation 



Analyze multiple patterns 

Deconvolution operator for surface seismic data 

processing 


2D and 3D stratigraphic and structural imaging 

Helps locate overthrust granite/sediment interface 

AVO analysis 




ocean bottom cable, salt proximity, AVO studies) 



ExactFrac ® Services 

Halliburton eases frac modeling concerns by taking a fullservice 

approach to logging, offering both dipole sonic and 

borehole seismic services. To give engineers the answers they 

require, our microseismic techniques provide real-time 

assessments of fracturing processes using two wells: 

A stimulation well where actual frac jobs are under way 

A monitor well equipped with a downhole geophone 

tool array with multiple sensors 

These microseismic techniques provide accurate information 

on the length, height, and distance of the frac being 

generated in the formation and can dramatically optimize 

the placement of future wells. 

ExactFrac Services Features 

Allows operators to optimize drilling program in field 

Improves later frac jobs (only zone you need to frac) 

Minimizes uncertainty in your fracturing program 


Sampling 

RDT Reservoir Description Tool 

RDT reservoir description tool is a modular, combinable 

formation tester and fluid-sampling tool. The RDT tool 

provides accurate pressure measurements. High-quality 

clean and representative formation fluid samples are 

collected, along with a broad range of valuable reservoir data. 

This is accomplished through: 

Pressure-gradient testing 

Permeability anisotropy testing 

Formation fluid properties monitoring 

Zero Shock pressure/volume/temperature (PVT) 

sampling 

The RDT Zero Shock PVT sampling method eliminates 

unanticipated fluid expansion and pressure shocks during 

pumping and sampling through its advanced digital control 

feedback system, which maintains a constant flowrate 

throughout the sampling process. Two closely spaced probes 

are standard, providing redundant packer seals and probes. 

In-situ PVT bubblepoint testing is performed while pumping 

to determine the ideal sampling pressure for oil-bearing 

reservoirs. Sample chambers are filled against hydrostatic 

pressure and additional pump pressure can be applied to 

maintain the sample in the single-phase condition while 

retrieving reservoir fluid to surface. 

Bubblepoint, compressibility, density, and resistivity are fluid 

properties which are monitored while pumping. In addition, 

spherical mobility, horizontal mobility, and anisotropy are 

monitored. When the MRILab® section is added, additional 

fluid properties including Hydrogen Index (HI), T 1 and T 2 

distributions, log mean T 1 , viscosity index, and capacitance 

are also monitored. Because these properties are monitored 

real-time, operators are able to identify the optimum point at 

which to divert fluid flow and collect samples. 

Applications 

Identify depleted and overpressured zones 

Assess reservoir fluid types and contacts 

Collect uncontaminated, representative, PVT-quality 

reservoir fluid samples 

Determine reservoir fluid PVT behavior 

Determine formation permeability and anisotropy 

Assess reservoir compartmentalization 

Verify reservoir isolation 

Detect interwell communication 

Quantify field-wide pressure trends 

Features 

The 100 cc pre-test chamber allows for rate- or pressurecontrolled 

fluid entry to ensure accurate bubblepoint 

and PVT analyses. The large volume chamber also allows 

multiple pretests per pad set without releasing the pad 

from the borehole wall 

Dual probe configuration provides improved horizontal 

and vertical permeability estimates due to probe 

proximity 

Determine real-time horizontal and vertical mobilities 

while sampling or pre-testing 

Dual probe configuration provides high reliability and 

redundancy with multiple quartz and strain gauge 

pressure measurements 

Fluid type identification and contamination monitoring 

is used to discriminate between filtrate and formation 

fluid and to determine the optimal time to collect a fluid 

sample. Each multichamber section includes three 

1,000 cc PVT sample chambers 

Multiple fluid property sensor outputs are combined to 

yield reliable hydrocarbon/fluid typing even in oil- or 

synthetic-based mud 

Powerful pump reduces cleanup time, contamination 

level, and saves rig time 

Three flow control pump-out sections, configured for 

4,000; 6,000; and 8,000 psi pump pressure provide 

extended range pressure sampling capabilities in highly 

depleted or overbalanced conditions 

Zero Shock flowrate control ensures sample integrity 


Pressure Testing and 

Zero Shock Sampling 

DPS 

QGS 

FPS 

MCS 

MRILab 

MCS 

Low Mobility and Laminated 



OPS 

QGS 

FPS 

MCS 

MRILab 

MCS 

Mini-DST and VIT 




OPS 

DPS 

QGS 

QGS 

FPS 

MCS 

MRILab 

MCS 

Mini-DST and VIT 


Zero Shock Sampling with 

Straddle Packer 

DPS 

QGS 

SPS 

FPS 

MCS 

MRILab 

MCS

DPS Dual Probe Section 

The DPS section deploys two independent probe/pad 

assemblies against the borehole wall for pressure drawdown/ 

buildup analysis and pumping formation fluid. The DPS is 

designed to detect horizontal mobility (k h/μ), permeability 

(k h), and anisotropy (k v/k h) over an extended range of 

operation. The DPS pressure testing flowrate is precisely 

controlled with the advanced digital control feedback system, 

thus achieving steady-state pressure quickly and reducing 

required testing time. By running two dual probe sections in 

tandem, the RDT tool is used determine the pressure 

between the probes and profile permeability and anisotropy. 

This further enables an extended depth of investigation and 

detection of permeability barriers. 

Features 

Design redundancy – two flow paths 

Operational efficiency 

Different pad configurations 

Closely spaced – enhanced permeability 

Probe shut-in valve – reduced flowline storage volume 

Faster buildup times – tight zones 

Resistivity fluid ID sensor 

Drawdown rate control 0.1 to 15 cc/sec 

Drawdown volume control 0.1 to100 cc 

Oval Pad 

Carbonate rocks, thinly bedded sands, and naturally 

fractured reservoirs can exhibit a very challenging logging 

environment when pressure testing and fluid sampling are 

required. The challenge is due to, at least, reservoir 

heterogeneity and the difficulty of sealing the probes in these 

reservoirs. The RDT utilizes a proprietary oval pad section 

(OPS) to help overcome all of these challenges. The oval pad 

spans a 9-in. vertical section of the borehole, giving it the 

sealing advantages of a straddle packer but still maintaining 

the operational flexibility of a probe. In particular, the oval 

pad design ensures an effective seal for the probe during 

formation testing and fluid sampling in the presence of 

vuggy and/or fractured carbonate rocks. In addition to the 

increased vertical sealing area, the oval shape can reduce the 

sampling time due to a focusing effect the pad has on near- 

wellbore flow. Simulations show that when the complete 

testing system performance is considered, the oval pad 

reduces pumping times compared to a standard probe and in 

some cases a straddle packer. 

Straddle Packer 

The straddle packer section (SPS) offers advantages over 

probes in low permeability applications as well as 

heterogeneous environments. SPS incorporates a dual port 

design which offers unique benefits in non-horizontal wells 

when a density contrast exists between the drilling mud 

contaminant and reservoir fluids. The lighter fluid segregates 

towards the top of the packed-off interval. After initially 

pumping through both inlet ports and detecting reservoir 

fluid, one available option is to close the bottom port to flow 

only the lighter fluid through the top probe. Proper 

manipulation of the dual ports and taking advantage of 

naturally occurring fluid segregation of the fluids contained 

in the packed-off interval provides cleaner samples faster 

than samples attainable with only a single port tool. In 

carbonates, thinly bedded sands, and naturally fractured 

reservoirs, most of the production occurs from small 

features. Such features make sampling and reservoir 

characterization difficult with a probe. The probe is more 

likely to be placed in a location that is characteristic of the 

rock matrix, which usually results in a tight test. The SPS 

isolates a 1 m interval, which is normally ample to 

characterize heterogeneous rock. The primary advantage of 

an SPS is its ability to cover a vertical interval where a probe 

is a pinpoint evaluation by comparison. 

FPS Flow-Control Pump-Out Section Features 

High pump rates-less contamination 

Faster pump-out times-reduced rig time 

Pump up or down (four-way valve) 

Multiple pump capability and flexible location in string 

Sampling flowrate – real-time control 

Outlet gauge controls sample filling 

Interchangeable pump pistons enable 4,000; 6,000; or 

8,000 psi pumps 

Instantaneous control (0.004 to 1.1 gpm) 

Flowrate feedback control 

Single phase samples 

QGS Quartz Gauge Section 

The quartz pressure transducer features 14.7 - 20,000 psi 

calibration at 350°F. Resolution is 0.02 psi with accuracy to 

± [1 psi + 0.01% reading]. 

This sensor is just 0.75-in. OD × 2.25-in. long. Other 

properties include a low mass, which means shorter time to 

thermal stability and fast temperature compensation. 


MRILab ® Section 

The MRILab® section measures in-situ reservoir fluid 

relaxation time at true reservoir conditions. The measured 

T 1, T 2, and the self-diffusion coefficient (D) of the reservoir 

fluids tie directly into important fluid characteristics such as 

viscosity index, fluid type, and contamination cleanup 

during pump-out. 

MCS Multi Chamber Section 

The MCS contains motorized chamber valves with three 

1,000 cc sample chambers. The chambers are detachable, 

transportable, and approved by the US department of 

transportation (DOT) and national association of corrosion 

engineers (NACE). Single phase nitrogen-charged sample 

chambers are available. Nitrogen-charged sample chambers 

maintain the fluid sample at higher pressure than standard 

chambers while the fluid is cooled and retrieved to the 

surface. Nitrogen charged sample volume is approximately 

550 cc at surface conditions. 

Module 

CVS 

QGS 

DPS 

OPS 

HPS 

FPS 

MCS 

PTS 

MRILab ® 

SPS 

Length 

ft (m) 

2.3 

(0.7) 

4.2 

(1.3) 

10.6 

(3.2) 

Slim Probe 

10.6 

6-in. Pad 

8.8 

(2.7) 

12.0 

(3.7) 

8.9 

(2.7) 

7.0 

(2.1) 

14.0 

(4.3) 

18.6 

(5.7) 

Diameter 

in. (mm) 

4.75 

(120.7) 

4.75 

(120.7) 

Sampling Tools Specifications 

Minimum 

Hole Size 

in. (mm) 

6 

(152.4) 

6 

(152.4) 

4.75 

(120.7) 6 

5.0 @ Probe (152.4) 

(127) 

4.75 

(120.7) 6 

5.6 @ Pad (152.4) 

(142.2) 

4.75 

(120.7) 

4.75 

(120.7) 

4.75 

(120.7) 

4.75 

(120.7) 

4.75 

(120.7) 

4.75 

(120.7) 

6 

(152.4) 

6 

(152.4) 

6 

(152.4) 

6 

(152.4) 

6 

(152.4) 

6 

(152.4) 

CVS Chamber Valve Section 

The CVS contains motorized sample chamber shut-in valves, 

an expulsion valve, and a check valve which prevents 

backflush. The MCS carries up to two standard 2-3/4 gallon 

SFTT sample chambers typically used for large volume, 

non-PVT, water sampling. 


PTA pressure transient analysis 

In-situ real-time bubble point 

Advanced analysis from Applied Formation Evaluation 

Centers 

Maximum 

Hole Size 

in. (mm) 

18 

(457.2) 

18 

(457.2) 

18 

(457.2) 

17.5 

(444.5) 

18 

(457.2) 

18 

(457.2) 

18 

(457.2) 

18 

(457.2) 

18 

(457.2) 

12.25 

(311.1) 

Maximum 

Pressure 

psi (Mpa) 

20,000 

(137.9) 

17,000 

(117.2) 

20,000 

(137.9) 

20,000 

(137.9) 

20,000 

(137.9) 

20,000 

(137.9) 

20,000 

(137.9) 

20,000 

(137.9) 

20,000 

(137.9) 

20,000 

(137.9) 

20,000 

(137.9) 

Maximum 

Temperature 

°F (°C) 

350 

(176.7) 

Weight 

lb (kg) 


75 

(34.0) 

350 

(176.7) 102 

400 

(46.3) 

(204.4) 

350 

(176.7) 

350 

(176.7) 

350 

(176.7) 

350 

(176.7) 

350 

(176.7) 

350 

(176.7) 

350 

(176.7 

350 

(176.7) 

385 

(174.6) 

385 

(174.6) 

296 

(134.3) 

450 

(204.1) 

290 

(131.5) 

211 

(95.7) 

450 

(204.1) 

858 

(389.2)

SFT-IV Sequential Formation Tester IV Tool 

The SFT-IV sequential formation tester IV tool is used for 

gathering the quality formation data required to evaluate 

reservoir potential and plan well completions and is part of 

our comprehensive line of wireline formation testing 

services. This service includes a full suite of open-hole test 

tools designed to allow the best possible test in any formation 

under any condition. 

Features 

Surface controlled pre-test volumes (0 to 20 cc) 

Multiple drawdown without pad resetting 

Variable rate drawdown (0.1 to 0.33 cc/sec) 

Backflushing of pre-test volume (0 to 20 cc) 

Variable hydraulic pad seating pressure 

Optional precision quartz gauge (14.7 to 12,000 ±1.0 psi 

accuracy) 

All parameters necessary for a successful test—accuracy, 

adaptability, speed, and reliability—are designed into the 

test tool 

Pre-test does not start until the operator gives the 

command, allowing: 

– Verification of padset before starting pre-test 

– Evaluation of mudcake properties from padset 

data 

Proprietary quartz transducer technology allows better 

response to pressure changes 

Length 1 

ft (m) 

17.8 

(5.4) 

Temperature compensation crystal, attached to the 

pressure crystal, provides improved temperature 

compensation and pressure measurement accuracy 

Crystal size and special construction features permit 

reliable transducer operation—even under harsh 

borehole conditions 

The SFT-IV probe section is articulated to ensure that pad seals in 

deviated holes or washed out sections. It features surface selectable 

pretest volumes and up to three sample chambers. 

SFT-IV Sequential Formation Tester IV Tool Specifications 

Diameter 2 

in. (mm) 

5.5 

(139.7) 


psi (Mpa) 

12,000 

(82.7) 


HAL9152 

Maximum 

Temperature 

°F (°C) 

350 

(176.7) 

Weight 

lb (kg) 

Varies 

1 Without sample chambers. 

2 Standard configuration. 

Various chamber configurations are available for specific applications or formation conditions. Check with your local 

Halliburton representative for further information. The 2.75 gal (10.4 L) chambers are H 2 S compatible.

SFTT Sequential Formation Test Tool 

The SFTT sequential formation test tool measures wellbore 

and formation fluid pressure at any point in the well with a 

petroquartz pressure transducer. The SFTT tool can also 

collect representative formation fluid samples for up to two 

test depths in one trip into the well. 

The following measurements are available for monitoring 

and recording at the surface system: 

Hydrostatic (mud column) and formation pressures 

Continuous recording of time so significant events 

during the test can be timed for computations 

Pre-test volumes 

Petroquartz pressures 

Petroquartz pressure sample rate 

Petroquartz transducer temperature 

Features 

Variable pre-test volumes (5 to 10 cc) 

Drawdown rates (0.5 to 2 cc/sec) 

Drawdown after padset established 

Adaptable to H2S Standard precision quartz gauge 

Determine reservoir pressure 

Identify gas and oil reservoir boundaries 

Monitor reservoir intercommunication 

Indicate areas of pressure depletion 

Estimate formation permeability by pressure/time curve 

correlation 

Determine chemical concentrations and reservoir fluid 

properties through laboratory analysis of retrieved 

formation samples 

Measure flow and shut-in pressures vs. time 

Tool Length 

ft (m) 

SFTT-B 

SFTT-C 

The SFTT tool features ruggedized construction for measuring precise 

formation and wellbore-hydrostatic pressure readings. The SFTT tool can 

also collect reservoir fluid samples in two separate chambers for analysis 

of fluid properties with standard 2.75-gal chambers and optional 1.0, 5.0, 

and 8.0 gal chambers. 

The advanced Halliburton quartz gauge is standard and can measure 

pressures with an accuracy of ± (1.0 psi + 0.01% of the reading); 

resolution is 0.01 psi and a repeatability of 1.0 psi 

SFTT Sequential Formation Test Tool Specifications 

22.1 

(6.7) 

18.9 

(5.8) 

Diameter 

in. (mm) 

6.5 

(165.1) 

6.5 

(165.1) 


HAL703 


psi (Mpa) 

20,000 

(137.9) 

20,000 

(137.9) 

Maximum 

Temperature 

°F (°C) 

350 

(176.7) 

350 

(176.7) 

HAL9252 

Weight 

lb (kg) 

675 

(306.2) 

525 

(238.1) 

The sequential formation test tool is also available for hostile environments. For more information, reference 

the HSFT hostile sequential formation tester tool on page 55.

RSCT Rotary Sidewall Coring Tool 

The RSCT tool diamond-drills cores perpendicular to the 

borehole wall with continuous monitoring of the coring 

process. After gamma ray depth positioning, a backup shoe is 

extended to decentralize and hold the tool securely against 

the formation. A diamond bit rotating at 2,000 rpm cuts a 

0.9375-in. OD, 1.75-in. long sample from the formation. 

Surface control of weight-on-bit optimizes drilling. 

After the sample has been cut, a slight vertical movement of 

the bit breaks the core sample from the formation. The bit 

containing the sample is then withdrawn into the tool and 

the core is punched into a receiver tube. An indicator reveals 

both the existence and length of the sample. The tool is then 

ready for the next selected core point. 

The RSCT tool is used to obtain core samples in consolidated 

formations. A tubular shaped drill bit with diamond cutting 

edges is used to drill the core. The core is recovered as a 

cylindrical shaped plug of the formation. 

The system operates independently from other systems on 

the logging truck or skid. The only input required is a source 

of AC voltage. A recording device is necessary for recording 

gamma ray correlation data. 

The downhole tool is controlled from the surface by use of 

the control panel. 

Applications 

Rotary core samples collected by the RSCT tool can be used 

to provide: 

More accurate readings of porosity and permeability that 

reduce reservoir analysis variables. Microfractures in 

core samples taken with percussion tools cause false 

readings of porosity and permeability 

Information useful in fine-tuning MRIL® data 

Reliable data for rock mechanical analysis necessary for 

hydraulic fracturing design, wellbore stability analysis, 

and sand potential prediction 


HAL9184 

HAL9183

Features 

Allows 30 or more cores to be taken in one run 

Can be run on Toolpusher service or coiled tubing to 

acquire cores in deviated, extended reach, and horizontal 

wells 

A core length indicator takes the guesswork out of core 

recovery 

Stand-alone tools can be run on third-party logging 

units 

Originally designed to recover cores in hard rock 

formations inaccessible with percussion tools, the 

RSCT tool can be used with equal success in soft 

rock formations 

Length 

ft (m) 

18.1 

(5.5) 

RSCT Rotary Sidewall Coring Tool Specifications 

Diameter 

in. (mm) 

4.87 

(123.7) 


psi (Mpa) 

20,000 

(137.9) 

Gamma ray tool positioning provides accurate core 

point location 

Core samples are undistorted with consistent cylindrical 

geometry which allows a wide range of petrophysical 

testing and analysis 

Allows for evaluation of pre-existing formation damage 

by providing core samples free of distortions caused by 

percussion tools 

HRSCT hostile rotary sidewall coring tool available for 

use in hostile environments 

Maximum 

Temperature 

°F (°C) 

350 

(176.7) 

Weight 

lb (kg) 

275 

(124.7) 


SWC Side Wall Coring Tool 

The SWC side wall coring tool allows geologists to take a 

sample of a prospective formation traversed by the borehole. 

These sidewall core samples can improve log analysis, help to 

identify a rock's type and origin, and can be used to 

determine the exact location of gas and oil, gas and water, or 

oil and water contacts within a reservoir. In some cases, 

sidewall cores can even discover productive reservoirs not 

evident on logs. 

The SWC tool consists of a propelling explosive material and 

hollow core barrels housed in the body of the gun. The tool is 

lowered to a predetermined depth and fired, one shot at a 

time. The barrels containing the core samples are then 

retrieved by means of a cable attaching the barrels to the gun. 

The SWC tool utilizes a single cable running through and in- 

between the barrel back and barrel. The two ends of the cable 

are secured to the side rails of the gun, helping to reduce the 

number of broken cables. In addition, release rings adapted 

to the top of the barrel control entry depth and velocity and 

provide flexibility during the coring process. 

Applications 

Clay typing 

Fluid saturation estimation 

Length 

ft (m) 

7.7 

(2.4) 

SWC Side Wall Coring Tool Specifications 

Diameter 

in. (mm) 

4.5 

(114.3) 


psi (Mpa) 

20,000 

(137.9) 

Matrix makeup 

Grain size and cementing agents 

Paleonthological data 

API oil gravity 

Gas and oil presence 

Porosity and permeability estimations can also be made 

using sidewall core analysis. However, these estimates should 

never be used to extensively evaluate porosity or permeability 

since there is a high probability that the core structure has 

been altered by the impact of the core barrel into the 

formation. 

Features 

Area specific – can shoot 24 to 144 cores on a single trip 

into the well 

Depth correlation via gamma ray or SP application 

Sampling can be done at any time before casing is run 

Allows sampling of very soft formations 

Permits positive verification of formation type indicated 

by the other open-hole logs 

Maximum 

Temperature 

°F (°C) 

400 

(204.4) 

Weight 

lb (kg) 


215 

(97.5)

HRSCT Hostile Rotary Side Wall Coring Tool 

The HRSCT hostile rotary sidewall coring tool provides a 

new approach for acquiring multiple sidewall core samples 

from an earth formation and special means for storing and 

identifying individual samples in multiple tubes for wireline 

operation. This apparatus is specifically designed with high 

efficiency to provide high-speed bit rotation combined with 

high torque for best drilling performance. 

The coring tool apparatus consist of control/power 

electronics and includes a hydraulic valve section, motor 

drive section, and the mandrel section. The descriptions of 

each section are as follows. 

Hydraulic Valve Section 

This section incorporates multiple solenoid valves for 

independent control of the tool functions such as, setting 

tool, tilting bit box, bit rotation, drilling/bit advance control, 

and core storage. The main feature of this section is the bit 

advance control mechanism which is based on applying bit 

weight and receiving positive feedback from the bit torque 

for the active control system. Small incremental increase and 

decrease in bit weight are possible to provide for smooth 

drilling without the risk of bit stalling. 

Motor Drive Section 

This section consists of an electric motor with a small pump 

at one end, for providing hydraulic pressure for all the 

auxiliary functions. The other end of the motor is connected 

to a clutch mechanism used for engaging and disengaging the 

bit on demand. The output of the clutch is directly coupled 

to the bit box through a flexible steel drive shaft. The main 

feature of this drive system is that by eliminating the 

hydraulic pumps and motors, high drive train efficiencies of 

as much as 80% is possible without sacrificing performance. 

The clutch mechanism can also be adjusted to slip at the 

torque rating of the electric motor to eliminate motor/bit 

stalling while drilling. 

Maximum 

Temperature °F 

Mandrel Section 

This section incorporates a bit box movable by actuators for 

tilting, advance/retract, bit break, and storage functions. The 

bit box incorporates several sets of bevel and spur gears to 

translate the direction of the rotation of the flexible shaft into 

normal direction to the axis of the wellbore. Finally, multiple 

core separator tubes are positioned in a carousel manner. The 

carousel rotates on demand from the hydraulic power section 

after depositing a core to place a washer for positive 

identification. The carousel stores up to sixty 2.12-in. cores 

that would otherwise be length prohibitive if a single tube is 

used. During the coring operation, the mandrel is secured to 

the borehole using two powerful backup pistons instead of a 

single backup arm. The backup pistons are sized so that 

minor slippage that could cause mandrel movement can be 

eliminated. This reduces the possibility of lodging and 

sticking the bit in the formation. 

Features 

High temperature AC motor drives the bit for: 

– Full power across entire temperature range 

– Minimum post-job re-fit time 

Software control offers “cruise control” option 

Surplus power: 

– 1500 rpm with 22-in.-lb torque for fast drill times 

Excellent coring capacity: 

– 60 cores 2.12-in. L × 1.0 diameter 

Fail-safe retract includes bit-box and backup pistons 

Combinable 

Sensor coring record includes: 

– ROP, bit torque, and RPMs 

–Drilled core length 

–Recovered core length 

Pressure 

HRSCT Hostile Rotary Side Wall Coring Tool Specifications 

Maximum 

Pressure 

psi 

Push Pull 

Tension 

lb 

Push Pull 

Compression lb 

40 20,000 100,000 50,000 

Maximum OD 

in. 

4.75 nominal 5.125 

at standoffs 


Length 

ft 

Minimum / Maximum 

Hole 

in. 

30 6.25 - 12

Hostile—Slimhole Formation Evaluation 

HEAT Hostile Environment Applications Tool Suite 

The HEAT hostile environment applications tools suite 

comprises six logging instruments—a cablehead-tension 

load cell and associated centralizer, decentralizer, flex-joint, 

and telemetry assemblies. Each HEAT tool contains an 

internal temperature sensor that provides quality control 

data related to operational characteristics and tool 

electronics. Such information is usually critical only in very 

hot well conditions—in particular, when temperatures over a 

prolonged period are near the 500°F limit of the toolstring. 

The following are tools in the HEAT suite: 

HDIL Hostile Dual Induction Log (see page 5) 

HEDL Hostile Environment Dual Laterolog 

HFWS Hostile Full Wave Sonic Tool 

HSDL Hostile Spectral Density Tool 

HDSN Hostile Dual-Spaced Neutron Tool 

HNGR Hostile Natural Gamma Ray Tool 

HSFT Hostile Slim Formation Tester Tool 

Features 

HEAT suite tools are digital and smaller than standard 

logging tools—2.75-in. to 3.5-in. OD for HEAT suite 

versus 3.625-in. to 4.5-in. OD for standard tools 

The HEAT sonic, neutron, and gamma ray tools can all 

operate in open and cased holes 

Built to handle the severe conditions encountered in 

deep and hot hydrocarbon-bearing formations 

Can be combined in almost any configuration to suit the 

borehole geometry and formation evaluation 

requirements of each job 


HEDL Hostile Environment Dual Laterolog Tool 

The HEDL hostile environment dual laterolog tool is a 

wireline-deployed formation resistivity device designed for 

extreme borehole temperatures and pressures. It is the tool of 

choice when those resistivities routinely exceed 100 ohm m, 

especially in highly conductive muds. 

The HEDL tool is combinable with other hostile 

environment tools, e.g. the density and neutron tools to 

permit simultaneous resistivity/porosity measurements in 

the reservoirs. The tool is designed to be run with the 

HETS hostile environment telemetry sub and must be 

located immediately below the HETS sub and a 2.75-in. 

diameter isolation sub. From top to bottom, the HEDL tool 

assembly consists of: 

A flasked electronic assembly 

An upper toroid sub 

An alpha sub 

A lower toroid sub 

Features 

2.75-in. diameter permits slimhole and through drillpipe 

logging of high-temperature/high-pressure wells 

Performs two resistivity/porosity measurements: a deep 

laterolog (LLd) and a shallow laterolog (LLs) resistivity 

measurement 

Calibrated using three external resistor networks that 

simulate relatively low, medium, and high resistivities 

Under conditions of high Rt and low Rm and at 

temperatures higher than 350°F, the HEDL tool provides 

the basic formation resistivity data to aid formation 

evaluation 

Typical HEDL log recorded in highly resistive carbonate formations 

HEDL Hostile Environment Dual Laterolog Tool Specifications 

Length 

ft (m) 

21 

(6.4) 

Diameter 

in. (mm) 

2.75 

(69.9) 


HAL9137 


psi (Mpa) 

25,000 

(172.4) 

Maximum 

Temperature 

°F (°C) 

450 

(232.2) 

Weight 

lb (kg) 

300 

(136.1)


The HFWS hostile full wave sonic tool is a 2.75-in. acoustic 

velocity logging tool that is a part of the HEAT suite hostile 

environment applications tool toolstring. The HFWS tool, 

along with all of the HEAT suite sensors, have a pressure 

rating of 25,000 psi (172 400 kPa). The HEAT suite logging 

tools are designed for continuous operation of six hours at 

500°F (260°C). 

The HFWS tool, like the larger in diameter (3.625-in.) 

FWS full wave sonic tool, provides compressional wave, 

refracted shear wave, and Stoneley wave properties of 

downhole formations for a wide range of petrophysical, 

geological, and geophysical applications. To minimize the 

number of logging trips required for complete formation 

evaluation, the HFWS tool is compatible with all HEAT suite 

logging toolstrings. A liquid filled borehole is required for 

sonic logging, and can be used in fresh, salt, or oil-based 

mud systems. 

The HFWS tool can be compared to having two sonic tools 

within the same toolstring—a long-spaced sonic tool for 

traditional full waveform open-hole sonic logging, and 

located within the transmitter-to-receiver offset, a cement 

bond tool that utilizes the second transmitter and two 

receivers. The upper transmitter and the lower four receivers 

array are utilized for FWS full wave sonic logging. The lower 

(second) transmitter and the upper two receivers are utilized 

for cement bond logging and short, offset compressional 

wave travel time. The long transmitter to-receiver offset 

allows for the acquisition of borehole sonic data beyond the 

effects of any near-wellbore altered region. The long offset 

also allows for the acquisition of high-quality sonic data in 

enlarged boreholes where critical angle effects would affect 

sonic tools with short transmitter-to-receiver offsets. 

Applications 

Full waveform open-hole sonic logging 

Cement bond logging 


The natural gamma ray, X-X caliper, Y-Y caliper, P-wave travel time 

and P-wave semblance quality are presented in Track 1. The monopole 

waveform data is presented in Track 2 in the MicroSeismogram 

format (X-Z) and in an X-Y waveform presentation in Track 3. 


HAL9171

Features 

Advanced system design and software processing with 

long transmitter-to-receiver offsets and 1/2 ft receiver-toreceiver 

spacings 


pulse to promote constant source characteristics 

Automatic gain control of each receiver helps preserve 

signal amplitude 






Facilitates continuous uninterrupted recording of full 

waveform signals 

Ability to record various types of information including 

tool data, quality curves, and final results 



estimates using both Δtc and Δts Facilitates lithology identification by means of velocity 

ratio, Δts /Δtc , and location of gas zones, even in poor 

hole conditions and cased holes 


Stoneley wave attenuation and Δt 




Prediction of vertical extent of hydraulic fractures using 

the RockXpert2 analysis package 


beds (Beds as thin as 3-in. can be identified with the 

t curves) 



data are the required input information for synthetic 

seismograms 

Length* 

ft (m) 

30.2 

(9.2) 

Gamma ray and caliper are presented in Track 1, compressional 

wave travel time (DTC) is presented in Track 4, and the P-wave 

semblance quality is presented in Track 3. 

HFWS Hostile Full Wave Sonic Tool Specifications 

Diameter 

in. (mm) 

2.75 

(69.9) 

*Add 3.50 ft (1.1 m) for each in-line centralizer (usually two). 

** 6 hour 


psi (Mpa) 

25,000 

(172.4) 

This is a hard rock example. Natural gamma ray, caliper, and 

VpVs are presented in Track 1. The P-wave travel time and the 

refracted shear wave travel time are presented in Track 2. The 

semblance quality is presented in an image format in Track 3 for 

the P-wave and refracted shear wave. 


HAL9172 

HAL9173 

Maximum Temperature** 

°F (°C) 

500 

(260) 

Weight 

lb (kg) 

340 

(154.2)

HSDL Hostile Spectral Density Log 

The HSDL hostile spectral density log is a section of the 

HEAT suite system. It is available with the source-detector 

pad either as a bottom-only in-line configuration (2.75-in. 

tool OD) or as a powered, extendable configuration (3.5-in. 

tool OD). It is fully combinable with all other HEAT suite 

tools. 

The HSDL log measures formation density, photoelectric 

factor (a lithology indicator), and borehole diameter. It 

measures formation density by emitting gamma rays into the 

formation and recording the energy of gamma rays reflected 

by the formation to the two detectors in the tool. The HSDL 

log measures borehole diameter with a spring-loaded caliper 

arm that opens and closes as the tool is pulled through 

changes in hole diameter. 

Additionally, as for all Halliburton’s HEAT suite services, the 

HSDL log provides reliable data in temperatures up to 500°F 

and pressures as high as 25,000 psi that are encountered in 

hot hydrocarbon bearing formations. 

Applications 

Determination of formation porosity 

Identification of formation lithology regardless of 

formation fluid type 

Indication of gas when used in combination with a 

neutron log 

Features 

More precise delineation of thinly bedded formations 

using the unfiltered Pe curve 


computer screen in real-time and recorded on the log 

Advanced correction algorithm is applied to density data 

in real-time 

Rigid tungsten pad incorporates a 1.5-curie cesium-137 

source and two high-efficiency scintillation detectors 

designed to maintain high gamma counts 

Rugged construction and advanced gain stabilization 

help maintain measurement integrity under varying 

temperature conditions 

Combinable with a complete family of tools that 

operates under the DITS digital interface telemetry 

system 

Extensively characterized in test pits with a full set of 

correction charts available 

2.75-in. OD for use in slimholes makes it possible to 

design a through-formation evaluation program for 

holes as small as 3.5-in. 

Uses a new 4D technique to account for the density and 

photoelectric absorption of the formation and mudcake 

without assuming any correlation between these 

variables. Besides yielding a superior density, these 

calculations provide information for compensating the 

Pe measurement and computing useful quality indicators 

such as the two component density correction 

Typical Field Output of the HSDL Log 


HAL846


The wellsite answer product is formation density and Pe 

Density data is also used with open-hole sensors as input 

to Halliburton’s mineralogy, open-hole, and cased-hole 

saturation analysis to provide a complete formation 

evaluation product. These include: 

Equipment Length 

ft (m) 

In-Line Pad 

Extendable Pad 





HSDL Hostile Spectral Density Log Specifications 

13.8* 

(4.2) 

23.8 

(7.3) 

*Usually run with the HPDC-A—if so add 3.8 ft (1.2 m) 

**6 hour 

Diameter (minimum) 

in. (mm) 

2.75 

(69.9) 

3.50 

(89.9) 


psi (Mpa) 

25,000 

(172.4) 

25,000 

(172.4) 

Maximum 

Temperature** 

°F (°C) 

500 

(260) 

500 

(260) 

Weight 

lb (kg) 

176 

(79.8) 

456 

(206.8) 


HDSN Hostile Dual-Spaced Neutron Tool 

The HDSN hostile dual-spaced neutron tool is a section of 

the HEAT suite system. The HDSN tool consists of 

combinable, high-quality, small-diameter tools capable of 

comprehensive formation evaluation in harsh environments. 

Applications 

Provides a neutron porosity log, i.e. the porosity of the 

formation as indicated by the detection of neutron 

radiation induced in the formation by the tool 

Investigates formation lithology, using a steady state, 

neutron-generating source of radioactive americiumberyllium 

(AmBe) and two thermal neutron detectors. 

Neutrons emitted from the source are slowed and 

scattered by the surrounding media, and the resulting 

neutron field is sampled at two locations. The neutron 

flux is converted to electrical signals for logging 

Features 

Can be deployed in both open and cased-hole wells 

Commonly run with the powered decentralizer to 

provide HDSN tool eccentering and to furnish a 

continuous standoff measurement that helps improve 

porosity calculations, especially over rugose intervals 

Uses caliper data from the decentralizer to correct 

porosity for hole size 

Extensively characterized in test pits with a full set of 

correction charts available 

Temperature and pressure ratings of 500°F (for 6 hours) 

and 25,000 psi, respectively to handle severe conditions 

encountered in deep and hot hydrocarbon-bearing 

formations 

Specially designed He3 detectors minimize the effects of 

elevated temperature on observed count rates and 

computed porosity 

2.75-in. OD for use in slimholes 

Small OD to design a through formation evaluation 

program for holes as small as 3.5 in. 

Combinable in almost any configuration to suit borehole 

geometry and provide appropriate formation evaluation 

information 

Typical Field Output of the HDSN Tool 


HAL846


The wellsite answer product is the neutron porosity 

NPHI 





Length* 

ft (m) 

15.3 

(4.6) 





HDSN Hostile Dual-Spaced Neutron Tool Specifications 

Diameter 

in. (mm) 

2.75 

(69.9) 


psi (Mpa) 

25,000 

(172.4) 

Maximum 

Temperature** 

°F (°C) 

Weight 

lb (kg) 


500 

(260) 

*The length and weight include the HGNI instrument section, which is required to run the HDSN tool. Add 7.04 ft 

(2.1 m) when run with the in-line, bowspring decentralizer. 

**6 hour 

179 

(81)

HNGR Hostile Natural Gamma Ray Tool 

The HNGR hostile natural gamma ray tool is a section of 

the HEAT suite system. Along with the HGNI tool, the 

HNGR tool can be run alone or with any other hostile service 

in either an open or cased-hole. 

The HNGR tool is used to record naturally occurring gamma 

radiation. Gamma ray measurements are used for geologic 

correlation, depth control, and computing shale and clay 

volumes. Shale volume data can then be applied to correct 

the apparent porosities indicated by the acoustic, neutron, 

and density logs. 

When wellbore conditions are not favorable for a definitive 

SP response, a gamma ray curve is recorded in its place. 

Applications 

Record natural gamma radiation 

Features 

Commonly run with the powered decentralizer to press 

the toolstring along the borehole wall and to furnish a 

continuous standoff measurement 

Temperature and pressure ratings of 500°F (for 6 hours) 

and 25,000 psi, respectively to handle severe conditions 

encountered in deep and hot hydrocarbon-bearing 

formations 

2.75-in. OD for use in slimholes makes it possible to 

design through-formation evaluation programs for holes 

as small as 3.5-in. 

Combinable in almost any configuration to suit borehole 

geometry and provide appropriate formation evaluation 

information calibration and wellsite checks 


computer screen in real-time and recorded on the log 

Length* 

ft (m) 

11.6 

(3.5) 

Typical Field Output of the HNGR Tool 

HNGR Hostile Natural Gamma Ray Tool Specifications 

Diameter 

in. (mm) 

2.75 

(69.9) 


HAL846 


psi (Mpa) 

25,000 

(172.4) 


°F (°C) 

500 

(260) 

*The length and weight include the HGNI instrument section, which is required to run the HNGR tool. 

**6 hour 

Weight* 

lb (kg) 

146 

(66.2)

HSFT Hostile Sequential Formation Tester Tool 

The 3.125-in. OD HSFT tool is capable of formation 

testing in conditions where conventional tools cannot. The 

HSFT tool can be run in holes as slim as 4-in. and at 

temperatures and pressures up to 400°F and 25,000 psi. 

The HSFT tool can take an unlimited number of pressure 

tests and up to two fluid samples per trip in the well. 

Formation pressures are determined using a high resolution, 

high temperature quartz gauge. 

The HSFT tool is fully combinable with the HEAT suite 

toolstring, allowing open-hole data acquisition and 

formation testing in the same trip in the well. 

Features 

Maximum tool OD 3-1/8 in. tool design includes selfcontained 

standoffs, reducing the contact area between 

the tool and the borehole wall and minimizing the 

chance of differential sticking, especially in difficult hole 

conditions and depleted reservoirs 

Designed for wellbore diameters as small as 4 in. 

With optional backup shoe, pad can extend to 12.25 in. 

Sampling flowrate controlled by air or fluid cushions 

Two 1-gal sample chambers available 

Tool, reinforced pad design, and quartz gauge proven 

reliable to 400°F 

Backup strain gauge provides redundancy 

Low flowline volume reduces storage resulting in faster 

pressure tests in low mobility reservoirs, often 

encountered in high-pressure, high-temperature 

(HPHT) wells 

Self-cleaning sand screen design prevents snorkel 

plugging 

Extends pressure and temperature range over 

conventional testers 

Combinable with HEAT suite resistivity, sonic, and 

porosity logs to increase rig time savings 

Low power consumption electronics reduces internal 

heat generation and extends tool operating time 

Length* 

ft (m) 

28.0 

(8.5) 

4000 

Legend 

3000 

Pressure Used 

Pressure Data 

2000 

Hydro Static 1 

Draw Down 

Fill Up 

1000 

Stop 

Hydro Static 2 

0 HAL9144 

ETIM (sec) 

Real-time plot of HSFT tool data provides test monitoring and a 

drawdown mobility estimate. 

Real-time HSFT tool analysis plot identifies flow regime and aids 

operator in determining when to terminate test, resulting in saved rig 

time. 

Time (sec): T(-1.5) 

Buildup analysis performed on HSFT tool data 



Pressure (psi) and Derivative 


6000 

5000 

1e+07 

1e+06 

1e+05 

10000 

0 

100 

Pressure/Time Depth: XX879 ft 

200 

300 

400 

HAL9139 

1000 

Legend 

Derivative Plot 

100 

Delta Pressure 

Match 

10 

1 

10 

100 

1000 

Buildup Time (sec) 

5000 

4980 

4960 

4940 

4920 

4900 

4880 

0 

500 

600 

700 

Spherical LogLog Depth: XX879 ft 

Spherical FasTest Depth: XX879 ft 

Legend 

Pressure Used 

Pressure Data 

P*Fast Curve Fit 

800 

5e-5 10e-5 15e-5 20e-5 25e-5 30e-5 35e-5 40e-5 45e-5 50e-5 

HSFT Hostile Sequential Formation Tester Tool Specifications 

Diameter 

in. (mm) 

3.125 

(79.4) 


psi (Mpa) 

25,000 

(172.4) 


°F (°C) 

400 

(204.4) 

Weight 

lb (kg) 

525 

(231.8) 

*HSFT tool only; does not include HPSU or sample chambers. Minimum toolstring length for pressures only, including gamma 

and telemetry sub 55 ft (16.8 m) HPSU length: 8.33 ft (2.5 m); weight 120 lb (54.4 kg); OD: 2.75 in. (69.9 mm). 

HAL11253

Auxiliary Services 

Multi-Conductor LockJar ®* System 

The multi-conductor LockJar® system minimizes the risk of 

unproductive rig time in logging operations. 

The benefits of using wireline instruments to log oil and gas 

wells can diminish quickly if the logging string becomes 

stuck in the wellbore while tripping. Now, with multiconductor 

LockJar wireline technology available from 

Halliburton, that risk can be dramatically reduced. 

Unlike previous jars, the LockJar system arrives at the 

wellsite ready to run. Logging crews can be trained to use the 

tool in minutes, so a jar service technician is not required on 

location. There is even a hydraulic time delay that allows the 

crew to pull the toolstring through a tight spot without 

activating the tool. 

The new LockJar system can be adjusted right at the wellsite 

to begin metering the jar with a pull from the surface of 1,700 

to 4,000 lb. It can function reliably in reservoir temperatures 

up to 400°F and at pressures as high as 22,500 psi. However, 

those specifications can be easily increased because the tool is 

pressure balanced. 

Features 

Mechanical lock helps prevent inadvertent triggering 

during logging operations 

Hydraulic time delay allows actuation at any load above 

the mechanical lock setting and is not sensitive to 

pressure or temperature 

Balanced pressure increases the hydrostatic pressure 

rating by providing compensation to prevent collapsing 

Protected seal and impact surfaces enhance downhole 

reliability by minimizing friction from borehole fluids 

and problems associated with debris 

All internal parts, including the jar mechanism and 

conductive path, are sealed and segregated from the 

wellbore 

Permits operators to free-fall wireline in regions where 

persistent sticking problems have dictated the need for 

drillpipe-conveyed logging operations 

System ready to run upon arrival 

*LockJar is a registered trademark of Evans Engineering, Inc. 


HAL14045

Operation 

In a typical open-hole logging string, the LockJar® system is 

placed immediately above the logging or formation testing 

tools. To augment the force with which the weight is thrown 

up hole after the jar is activated, it is mated with an enhancer. 

It has been demonstrated in the lab that the LockJar tool’s 

impulse is more than twice as powerful with up to five times 

more duration when the enhancer is added to the jar. 

The LockJar tool is usually run in the string in the following 

order from the cable head down: enhancer, cable mode and 

telemetry sub-assemblies, and the jar. In combination, they 

Length 

ft (m) 

11.4 

(3.49**) 

Maximum OD 

in. (cm) 

3.625 

(9.20) 

create as large a mass as possible to help the jar release stuck 

logging tools. The enhancer stores energy in Belleville springs 

which propel the hammer into an anvil upon activation of 

the jar which generates the impact and impulse that are 

directed down towards the stuck point. 

Borehole Conditions 

Borehole fluids: salt, fresh, oil, and air 

Tool positioning: centralized eccentralized 

Multi-Conductor LockJar ® System Specifications 

Minimum Hole Size 

in. (cm) 

4.0 

(10.16) 

Maximum Hole Size 

in. (cm) 

N/A* 

*Tool not restricted on maximum hole size 

**Length of enhancer is 10.1 ft (3.07 m); combination jar and enhancer is 21.5 ft. (6.56 m). 

***Weight of the enhancer is 290 lb (131.5 kg). 


psi (Kpa) 

20,000 

(137 895) 

Maximum 

Temperature 

°F (°C) 

400 

(204) 

Weight 

lb (kg) 

365 

(165***) 


RWCH Releaseable Wireline Cable Head 

The RWCH tool has an electrically activated wireline 

release system as opposed to the tension activated release 

system of conventional cable heads. Tension activated heads 

require a safety factor to avoid premature release of the 

wireline. This safety factor keeps you from utilizing the full 

safe load on the wireline when trying to free stuck tools from 

the borehole. The RWCH tool allows you to utilize this extra 

tension to free stuck tools. This additional tension has proven 

very successful at freeing stuck tools and avoiding fishing 

operations. This extra pull also allows you to safely run heavy 

toolstrings in deep wells. 

The RWCH tool can reduce the costs of obtaining wireline 

logs in areas that are prone to tool sticking. It has reduced the 

incidence of fishing for stuck tools in problem areas, saving 

customers expensive and risky fishing jobs. 

Features 

Allows for greater pulling of stuck tools at any depth and 

in any conditions 

Able to support heavy toolstrings by utilizing the full 

strength of the wireline, regardless of depth 

Electrically controlled release from the surface 

Contains a conventional 2.3125-in. fishing neck 

Includes a special sub designed to allow easy rigup and 

rig-down 

Allows the maximum pull to be applied at any depth in 

the well regardless of the total depth if the backup weak 

point is not used 

Allows the release to be aborted as long as the fusible 

alloy has not reached melting temperature 

Length 

ft (m) 

6.3 

(1.9) 

RWCH Operation 

RWCH Releaseable Wireline Cable Head Specifications 

Diameter 

in. (mm) 

3.63 

(92.2) 


psi (Mpa) 

20,000 

(137.9) 


°F (°C) 

350 

(176.7) 

Weight 

lb (kg) 


135 

(61.2) 

HAL9188

Toolpusher Logging (TPL) Service 

Today’s search for oil and gas is heavily influenced by the 

rapid growth of technology. New tools and equipment are 

being built, new production and recovery methods are being 

tested, and new exploration techniques are being developed. 

Drilling programs are becoming increasingly complex and 

many wells now commonly include highly deviated or 

horizontal sections. In these cases, obtaining quality 

formation evaluation data with conventional wireline 

methods may be impossible or impractical at best—severely 

restricting the options available to the operator. 

The Toolpusher logging (TPL) service provides an 

innovative solution to this significant problem. TPL service 

utilizes drillpipe to effectively transport conventional electric 

wireline logging tools to the zone of interest. This method 

eliminates many of the problems associated with conveying 

tools through highly deviated or horizontal sections of the 

well. It also helps eliminate problems caused by: 

Wireline key seating 

Differential sticking of tools or wireline 

Swelling formations 

HAL607 

Toolpusher Drillpipe Conveyed Logging System 

Heavy muds 

Doglegs 

Cuttings bridging off the wellbore 

The TPL service has successfully logged thousands of highly 

deviated and horizontal wells, including: 

Wells with temperatures over 400°F (204°C) 

Depths exceeding 24,000 ft (7315 m) 

Logged intervals over 10,000 ft (3048 m) 

The Toolpusher latch assembly has been deployed and 

latched at angles of up to 97° with a maximum logged angle 

of over 104°. Average job time at 12,000 ft is 16 to 18 hours. 

Toolpusher service is designed to run both standard and 

modified wireline logging tools. The quick change, attached 

to the top of the logging toolstring, is attached to the bottom 

of a connector sub. Then the connector sub is attached to the 

drillpipe. The connector sub, available in three diameters, 

has slots cut through it so circulation can be accomplished at 

any time during a logging operation. 


Toolpusher service requires a variety of specialty subs and 

hardware. Among the subs are the downhole tension device, 

multiconductor swivel adapter, and offset, alignment, flex, 

knuckle, and pad locator subs. Some of the specialty 

hardware includes the rig floor display, spinning stand-offs, 

stiffening collars, hole finders, bullnoses, protective sleeves, 

and standoffs. The lists of equipment can get quite extensive. 

Each piece is utilized for special situations and the variety 

makes Toolpusher service a very versatile and adaptable 

system. Many toolstrings have unique hardware to assist in 

getting the best possible data. 

Toolpusher service was the first drillpipe conveyed logging 

system introduced in the field. It has a very long track record 

and has proven to be very reliable. Unlike our competitors, 

Toolpusher allows the customer to circulate at any time 

during the operation. The side-entry sub (SES) has a larger 

through-bore than the competition, which allows fishing 

operations to proceed as normal without restriction. 

Applications 

Conventional open-hole and cased-hole logging 

Formation testing and coring 

Vertical seismic profiling 

Ultrasonic and electrical imaging 

Cement and casing evaluation 

Features 

Control of pull off tension allows the operator to pull test 

to check the mechanical latch 

Tool Section 

Toolpusher Logging (TPL) Service Specifications 

Length 

ft (m) 

Diameter 

in. (mm) 

Side-Entry Sub SES * * 

Positive Latch/Unlatch Quick Change 

Assembly 

7-Conductor Pump Down Head ** 

Multi Conductor Swivel Assembly 

DITS Downhole Tension Device 

DITS Single Knuckle Joint 

DITS Flex Joint 

DITS Double Knuckle Joint 

* 

3.02 

(0.9) 

3.78 

(1.2) 

3 

(0.9) 

5.64 

(1.7) 

5 

(1.5) 

3.625 

(92.1) 

2.0 or 2.25 

(50 or 57.1) 

3.625 

(92.1) 

3.625 

(92.1) 

3.625 

(92.1) 

3.625 

(92.1) 

3.625 

(92.1) 

*Size selection is based on casing size and drillpipe size and type. 

**Length and weight are variable depending upon the latching conditions. 

No metal around female electrical connection reduces 

the possibility of shorting 

Female wet connect is floating and spring loaded, 

eliminating the movement of the connection and 

reducing noise 

New wiper glands to clean the male probe removes 

conductive films from the pin 

Multiple o-ring seal after the connection is made to 

effectively seal the connection 

Spring loaded sleeve protects downhole parts before 

latching 

Male probe completely covered after latching to help seal 

out invading fluids 

Employs conventional high-resolution wireline tools to 

provide formation data with quality equal to that of 

wireline-conveyed logs. Conventional rig tripping 

procedures are used to mechanically position logging 

tools in the zone of interest 

Formation data is available in real-time at the wellsite. 

Also, zones of interest can be relogged by lowering the 

blocks 

Rig up on the drillpipe rather than multiple runs with 

conventional wireline can save time. Prior planning with 

your Halliburton representative can determine which 

method is more economical 

Provides mud circulation throughout the operation. 

This reduces the risk of tools getting stuck and 

minimizes further hole deterioration 


psi (Mpa) 

20,000 

(137.9) 

20,000 

(137.9) 

20,000 

(137.9) 

20,000 

(137.9) 

20,000 

(137.9) 

20,000 

(137.9) 

20,000 

(137.9) 

20,000 

(137.9) 


°F (°C) 

400 

(204) 

400 

(204) 

400 

(204) 

400 

(204) 

350 

(176.7) 

400 

(204) 

400 

(204) 

400 

(204) 

Weight 

lb (kg) 


* 

* 

** 

70 

(31.8) 

96 

(43.5) 

50 

(22.7) 

140 

(63.5) 

75 

(34)

CTL Coiled Tubing Logging 

As the only major service company that designs, 

manufactures, and operates its own coiled tubing equipment, 

Halliburton incorporates important input from field 

personnel and customers into designing features that are 

strategically directed toward the most effective possible job 

performance. Deploying logging tools on coiled tubing is one 

of the more innovative uses of Halliburton coiled tubing. 

Installing logging cable inside the coiled tubing allows tools 

to be deployed into highly deviated wells and permits a 

variety of remedial functions. 

CTL logging differentiates itself from drillpipe conveyed 

logging by offering: 

Continuous circulation capabilities 

Pressure control while moving pipe 

Electrical connections made at the surface to eliminate 

wet latches 

Tolerance for high mud solids content 

Relogging of any interval, eliminating multiple latch 

runs 

Constant speed logging capability 

Applications 

Cement bond logging in highly deviated wells 

Production logging to determine water entry points in 

highly deviated wells 

Open-hole logging in deviated air-drilled wells that need 

pressure control 

Tool OD 

Coiled Tubing Size 

Top Connection 

Bottom Connection 

Coiled Tubing Cablehead Specifications 

1.50 in. 

(38.1 mm) 

1.00 to 1.50-in. 

(25.4 to 38.1 mm) 

Roll-on or 

OECO “A” Box 

1-3/16-in. (30.2 mm) 12 UN 

Type “A” Pin 

Single-trip underbalanced perforating with long 

gunstrings 

Setting plugs and packers in deviated wells with pinpoint 

depth control 

Features 

Purpose-built coiled tubing cableheads 

– Shear pin release 

– Flow-release 

High pressure surface termination assemblies 

– Standard integral plumbing 

–DNV certified 

Self-contained unit, requires no rig 

Can continuously pump fluids into well while moving 

pipe 

Land or offshore system designs 

No workover rig required when using coiled tubing 

Reduced potential damage to formation 

Can be and is typically used on live wells (no kill fluids 

introduced into well) 

Acts as tool transport medium for deviated and 


Advanced data acquisition system to monitor key job 

parameters on tubing management 

2.00 in. 

(50.8 mm) 

1.50-in. and above 

(38.1 mm and above) 

Roll-on or 

OECO “A” Box 

1-3/16-in. (30.2 mm) 12 UN 

Type “A” Pin or 

3-5/8-in. (92.1 mm) DITS Tool 

2.50 in. 

(63.5 mm) 

1.50-in. and above 

(38.1 mm and above) 

OECO “A” Box or 

AMMT Box 

1-3/16-in. (30.2 mm) 12 UN 

Type “A” Pin 

Fishing Neck Size 1.0-in. (25.4 mm) External 1.375-in. (34.9 mm) External 1.812-in. (46.0 mm) Internal 

Emergency Release Force Range 

Logging Cable 

3,200 to 10,000 lb 

(1,451.5 to 4,536 kg) 

7/32-in (5.6 mm) or 

5/16-in. (7.9 mm) 

monoconductor 

5,000 to 30,000 lb 

(2,268 to 13,608 kg) 

5/16-in. (7.9 mm) 

monoconductor or 

3/8-in. (9.5 mm), 

7/16-in. (11.1 mm), 

0.457-in. (11.6 mm), or 

15/32-in. (11.9 mm) multiconductor 

Flow-release in 

conjunction with shear pins 

7/32-in (5.6 mm) or 

5/16-in. (7.9 mm) 

monoconductor or 

3/8-in. (9.5 mm), 

7/16-in. (11.1 mm), 

0.457-in. (11.6 mm), or 

15/32-in. (11.9 mm) multiconductor 


BHPT Borehole Properties Tool 

The BHPT borehole properties tool is a DITS tools 

compatible electric logging tool, which provides signals used 

to determine characteristics of wellbore fluids. The primary 

outputs of a BHPT log are pressure, temperature, and 

borehole fluid resistivity. This information has long been 

requested by our clients and now is available during the first 

logging pass in a newly drilled well. 

The BHPT tool is normally run in conjunction with other 

logging services but may also be used as a stand-alone 

logging tool requiring the use of a telemetry sub. Open-hole, 

cased-hole, and drillpipe conveyed logging environments 

will accommodate the BHPT tool and two external diameters 

are available. The open-hole version is standard 3.625-in. 

and a smaller 3.375-in. version may be necessary in heavy 

4.5-in. casing and slimhole applications. 

Downhole pressure and temperature readings can assist 

clients in blowout prevention, mud weight corrections, 

determining formation fracture pressures, thief-zone 

identification, determining wellbore fluid pressure gradients 

in deviated holes, thermal gradient calculation, bottomhole 

temperature, and detection of dynamic fluid environments 

within the wellbore, including location of gas entry points in 

air-drilled wells. 

The resistivity sensor provides accurate, real-time 

information about mud resistivity at any depth and 

temperature in the wellbore. This information is required 

during water saturation calculations. The R m data may be 

used in invasion diameter calculations and also to identify 

abnormal induction and laterolog readings caused by 

borehole fluid effects. In cased-hole environments, the 

resistivity sensor can locate fluid levels and contact depth of 

static oil and water. 

Pre- and post-job maintenance requires flushing the pressure 

entry port to remove mud debris and create a pressure buffer 

to the sensor. Calibrations involve coefficient entry and 

internal resistor network readings. 

The BHPT tool can be used at any location in the logging 

stack depending on the data acquisition depth priorities with 

the exception that it must be run below the telemetry sub. 

The BHPT tool is available in two diameter sizes: a 3.375-in. 

tool and a 3.625-in. tool. The 3.625-in. BHPT tool is used 

specifically in open-hole applications. The smaller diameter 

3.375-in. tool is used in cased-hole wells (with heavy 4.25-in. 

casing), and in slimhole applications. 

Typical Field Output of the BHPT Tool 


HAL9394

Features 

Outputs real-time pressure, temperature, and mud 

resistivity data in the case that no similar measurements 

are taken in the toolstring configuration 

Aids in blowout prevention 

Makes mud-weight corrections 

Determines formation fracture pressures 

Identifies thief zone 

Determines wellbore fluid-pressure gradients in deviated 

holes 

Determines thermal-gradient calculation 

Determines bottomhole temperature 

Detects dynamic fluid environments within the wellbore, 

which also includes locating gas entry points in airdrilled 

wells 

Length 

ft (m) 

5.02 

(1.5) 

5.02 

(1.5) 

The resistivity sensor provides accurate, real-time 

downhole temperature and mud resistivity information at 

any depth. This resistivity measurement can be used to: 

Make water saturation calculations 

Make invasion diameter calculations 

Identify abnormal induction and laterolog 

measurements (caused by borehole fluid effects) 

Locate fluid levels and contact depth of static oil and 

water in cased-hole wells 


Absolute pressure and differential pressure 

Absolute temperature and differential temperature 

Mud resistivity 

BHPT Borehole Properties Tool Specifications 

Diameter 

in. (mm) 

3.375 

(85.7) 

3.625 

(92.1) 


psi (Mpa) 

20,000 

(137.9) 

20,000 

(137.9) 


°F (°C) 

350 

(176.7) 

350 

(176.7) 

Weight 

lb (kg) 

95 

(43.1) 

Cased-Hole 

107 

(48.5) 

Open-Hole 


FIAC Four Independent Arm Caliper Tool 

The FIAC four independent arm caliper tool is a four-arm 

caliper which provides information on the borehole 

geometry of the wellbore. Unlike other X-Y caliper services, 

the FIAC tool has four independent caliper measurements. 

The FIAC tool, run as a separate or combined service, 

provides an accurate measurement of the borehole diameter 

in four orthogonal directions with respect to the tool body. 

This survey is useful in calculating cement volume, selecting 

packer seats for formation sampling, and identifying and 

locating washouts and bridges in the borehole, as well as 

identify borehole ovality. 

Borehole size may range from 3.625-in. diameter to 22-in. 

diameter. The caliper arms are mounted at 90° angles to each 

other and provide a continuous X-Y (borehole axis is Z) 

borehole measurement. This tool is combinable with any 

other DITS standard tools. 

When the FIAC tool is combined with the SDDT 

navigation package, the borehole geometry information is 

oriented with respect to both magnetic north and the highside 

of the wellbore. The borehole azimuth, borehole 

deviation, and relative bearing of the X and Y caliper data are 

presented in a continuous log presentation. This allows the 

correlation of the borehole geometry with the drilling 

process, such as correlation of the long axis of the borehole to 

the high-side/low-side of the well. The FIAC tool differs from 

the competition by providing four independent caliper 

measurements, whereas with types of other four arm 

calipers, the X-X and Y-Y arms are paired together to provide 

only two diameter measurements. 

A borehole geometry presentation is created by combining the FIAC 

and SDDT data. Orientation data from the SDDT navigation tool is 

presented in Track 1, the deviation and hole azimuth are presented as 

text values every 50 ft and as continuous curves. The averaged X and Y 

calipers are presented in the depth track. The two independent X-X 

calipers are presented in Track 2 along with a bit size data. The two 

independent Y-Y calipers are presented in Track 3 along with the bit size 

data. This presentation illustrates an oval borehole with the long axis of 

the borehole aligned with the high-side/low-side of the deviated well. 

The short axis of the borehole is smaller than bit size, indicating the 

presence of mudcake. 


HAL9189

Features 

Four independent caliper measurements to provide 

needed borehole geometry data 

Combined with a navigation package the borehole 

geometry profile can be oriented with respect to 

magnetic north as well as to the high side of deviated or 


Borehole geometry information can be used to monitor 

hole size and shape with wellbore deviation and azimuth 

for basic geo-mechanical analysis 

Length 

ft (m) 

13.9 

(4.2) 

Helps optimize drilling and mud systems by the 

evaluation of borehole geometry along with mud weight 

and type, bit type, and ROP 

More accurate borehole volume and annular volume 

determinations for the required cement volume 

Identification of packer seats for sampling and testing 

FIAC Four Independent Arm Caliper Tool Specifications 

Diameter 

in. (mm) 

3.63 

(92.2) 


psi (Mpa) 

20,000 

(137.9) 


°F (°C) 

400 

(204.4) 

Weight 

lb (kg) 

310 

(140.6) 


SDDT Stand-Alone DITS Directional Tool 

The SDDT stand-alone DITS directional tool is a full 

navigational package that consists of three orthogonal 

fluxgate accelerometers and three orthogonal 

magnetometers. 

Features 

An enormous amount of data is acquired while logging. The 

SDDT tool transmits this data to the surface unit via 

Length 

ft (m) 

12.5 

(3.8) 

Halliburton’s proven DITS digital interactive telemetry 

system. 

The SDDT tool provides accurate information to help 

determine tool position, motion, direction, and orientation 

within the borehole. 

SDDT Stand-Alone DITS Directional Tool Specifications 

Diameter 

in. (mm) 

3.63 

(92.9) 


psi (Mpa) 

20,000 

(137.9) 


°F (°C) 

350 

(176.7) 

Weight 

lb (kg) 

240 

(108.9) 



Cased-Hole Wireline Services 

Formation Evaluation 

TMD-L Thermal Multigate Decay-Lithology 

Logging Tool 

The TMD-L tool is a new-generation pulsed-neutron 

logging tool which measures the thermal neutron capture 

cross-sections (sigma) of both the formation and the 

borehole. The sigma parameter is a measure of the ability of 

the formation to absorb thermal neutrons. Because of the 

strong correlation between the open-hole resistivity log and 

the sigma log, the sigma log is considered to be the casedhole 

equivalent of the conductivity log. 

Using induced gamma spectroscopy and decay time 

measurement, the TMD-L tool determines oil saturation in 

reservoirs with high salinity. Reservoir monitoring includes 

measurement of initial and current fluid contacts and 

predicts how the fluids will move in the future. Accurate 

monitoring of fluid movement in a producing hydrocarbon 

reservoir can also yield major economic benefits through 

improved recovery (such as better reservoir management, 

better placement of infill wells, and break-through deferral) 

as well as lower costs from fewer wells and reduced water and 

gas handling. 

The TMD-L tool differs from the competition by applying 

alpha-processing which optimally combines near and far 

detector responses to provide a sigma curve with the 

accuracy of the far detector and the vertical resolution and 

precision of the near detector. 

This leading-edge detector technology results in full 

spectrum monitoring for greater amounts of information, 

faster logging speeds, and higher accuracy. 

Applications 

Cased-hole formation evaluation 

Lithology determination 

Enhanced oil recovery monitoring 

Gas vs. tight determination 

Water-flow detection 

Cased-Hole Wireline Services 4-1 

HAL9138 

Example of Gravel Pack Evaluation with Silicon Activation 

Cased-Hole Wireline Services

Features 

Larger diameter detectors to produce higher count rates 

Recording of each detector's decay curve with 61 time 

gates; time gates span the entire burst cycle—from build 

up through decay 

A different background measurement scheme to sample 

the background more frequently 

Recording of gamma ray spectra for the far-spaced or 

near-spaced detectors during several time windows 

Ability to mount gamma ray detector below the 

generator and running the tool inverted to facilitate 

water-flow measurements 

Simultaneous inelastic and capture spectral 

measurements 

Modular hardware design allows custom configurations 

Accurate water saturation interpretation over a broad 

range of borehole conditions and porosities 

Improved interpretation to help distinguish between gas 

reservoirs and low-porosity formations 

Improved repeatability, lithology determination, 

enhanced oil recovery monitoring, and spectral waterflow 

determination 

Quality indicators for monitoring tool operation and 

algorithm performance 

Combinable with standard PL sensors to provide 

extensive interpretation support, save time at the rig site, 

and provide special tool configurations for special 

challenges 

Identifies problems earlier to reduce production 

downtime 

Optimizes and verifies completions for improved 

production 

Can help recommend remedial activities, such as further 

stimulation or conformance operations to: 

– Optimize production 

– Estimate reserves for better financial planning 

– Explore old wells for additional reserves 

– Help maximize customer return on investment 


SigmaSat sigma saturation analysis 

Chi Modeling® computation service 

TMD-L Thermal Multigate Decay-Lithology Logging Tool Specifications 

Length 

ft (m) 

18 

(5.5) 

Diameter 

in. (mm) 

1.6875 

(42.86) 


psi (Mpa) 

15,000 

(103.4) 

Maximum 

Temperature 

°F (°C) 

325 

(162.7) 

Weight 

lb (kg) 

70 

(31.75) 

4-2 Cased-Hole Wireline Services

RMT Elite Reservoir Monitor Tool 

The RMT Elite reservoir monitor tool is a unique throughtubing 

carbon/oxygen (C/O) system, offering two to three 

times higher measurement resolution than other throughtubing 

C/O logging systems. Its high-density Bismuth 

germanium oxide (BGO) detectors allow the RMT Elite tool 

to achieve resolutions previously available only with larger 

diameter C/O systems. As a result, the RMT Elite tool can be 

used to run continuous passes in low porosity formations 

where other systems can only be run in a stationary mode. 

The RMT Elite tool can also be conveyed into a well with 

tubing completions unlike larger C/O systems that can only 

log through casing. 

Utilizing induced gamma spectroscopy and decay time 

measurements, this pulsed-neutron device is primarily used 

to determine oil saturation in reservoirs. For reservoirs 

having low, mixed, or unknown salinity-formation water, the 

inelastic or C/O mode is used. For higher salinities, the 

capture mode is used, producing a TMD-L thermal 

multigate decay-lithology-type log. In addition, the RMT 

Elite tool can be used in either operating mode to perform 

elemental analyses from the measured spectra to identify 

lithology in all types of reservoirs. 

Because the RMT Elite tool is so accurate and precise, it 

allows operators to achieve logging speeds two to five times 

faster than competing systems. 

Applications 

Discriminate formation fluid contacts 

Evaluate hydrocarbon zone saturations in fresh, mixed, 

or unknown water salinity environments 

Locate water and oil zones in waterfloods where mixed 

salinities exist between formation and flood waters 

Evaluate saturations in formations behind casings when 

open-hole logs are not available 

Monitor steam and CO2 flood/breakthrough 

Inside/outside casing water detection 

Verify gravel pack integrity via silicon activation 

Accurately determine oil and gas saturations in high 

salinity or fresh water formations 

Identify bypassed reserves 

Pinpoint formation fluid contacts 

Identify lithologies and mineralogies 

HAL5680 

RMT Elite Primary Log Presentation—Track 1 of the display is used for 

plotting basic correlation curves. In this example the simultaneously 

recorded formation sigma and the potassium yield curve (YK) are plotted. 

Also plotted in the track is the oxygen activation curve (OAI), which is 

used to detect water flow. Track 2 of the log is used to display the raw 

carbon to oxygen ratio (COIR) and the calcium to silicon ratio (LIRI). 

The green shading between the curves is a quick look representation of 

hydrocarbons. Track 3 of the log displays yield curves computed from the 

capture spectra for silicon (YSi), calcium (YCa) and hydrogen (YH). 

Track 4 displays inelastic and capture near to far detector ratio curves. 

These curves are used to identify gas in the formation (shaded in red). 

Cased-Hole Wireline Services 4-3

Features 

Below-tubing and in-tubing logging capability without 

sacrificing quality and accuracy 

2.125-in. tool size allows use of a large detector and 

passage through 2.875-in. tubing 

Two detectors provide a near-to-far inelastic ratio, 

capture ratio, and two C/O measurements. 

Dual operating modes 

– Inelastic mode—(optimized for C/O formation 

measurements) C/O, elemental yields, ΣFM , 

porosity from ratios, and oxygen activation 

– Capture mode—(optimized for Sigma formation 

measurements) ΣFM , elemental yields, porosity 

from ratios, and oxygen activation 

Accurately evaluates the time-lapse performance of 

hydrocarbon-producing reservoirs 

No well-kill fluids are necessary 


RMT Elite tool data can be used alone in postlogging 

analysis, however, the addition of open-hole and cased-hole 

logging data often serves to enhance analysis results. For 

example, analysis options allow total and effective porosity to 

be computed from open-hole or cased-hole porosity data, 

TMD-L data, or external inputs. Also, a simple twoporosity 

log cross plot option is available to improve effective 

porosity estimates. Formation saturation analysis using the 

RMT Elite tool and porosity data can be provided via 

Halliburton’s cased-hole formation evaluation interpretation 

in the following software models. 

CarbOxSat model oil saturation analysis using C/O 

measurements 

SigmaSat model water saturation analysis using 

capture cross section measurements (Σ) 

TripleSat model three-phase oil, gas, and water 

saturations using both C/O and Σ measurements 

Chi Modeling® computation service 

Additionally, complex lithology and mineralogy answers can 

be provided by integrating RMT Elite tool elemental yield 

data in Halliburton’s ULTRA multi-mineral evaluation 

program software. 

Length 

ft (m) 

14.22 

(4.33) 

RMT Elite Quality Log Presentation—Track 1 of the presentation are 

curves that represent the accuracy of spectral gain stabilization measured 

from ratios of the iron edge (FERC) and the hydrogen peak (HPLI). 

Track 2 is a plot of the COIR and LIRI from the near space detector. 

Track 3 is used to plot additional yield curves computed from the capture 

spectra. Plotted on this example are the Iron yield (YFe) and the chlorine 

yield (YCl). Tracks 4 and 5 are used to plot the total inelastic and capture 

count rates for the near and far detectors. Track 6 is used to plot the 

simultaneous measured near formation sigma (SGFN) and the far 

formation sigma (SGFF). 

RMT Elite Reservoir Monitor Tool Specifications 

Diameter 

in. (mm) 

2.125 

(53.975) 

4-4 Cased-Hole Wireline Services 

HAL5681 


psi (Mpa) 

15,000 

(103.4) 


°F (°C) 

325 

(163) 

Weight 

lb (kg) 

77 

(34.9)

Spectra Flow Logging Service (SpFl) 

The Spectra Flow logging service directly detects and 

evaluates water movement behind and inside the casing of 

both production and injection wells. The service is capable of 

measuring water-flow direction up and down, linear flow 

velocity, and volume flow rate of water moving vertically. 

Water velocity measurements using spectral data are 

provided with continuous logs and stationary impulse stepdown 

tests. Water-flow greater than 3 ft/min can be detected 

and, depending on the flow volume and location, 

quantitative velocities as low as 5 ft/min can be measured. 

For velocities over 50 ft/min, improved accuracy is obtained 

by using the more distant natural gamma ray detector. A 

modular tool design allows the Spectra Flow service to be run 

in combination with production logging tools. Multiple 

configuration options allow the service to be tailored to the 

types of flows encountered downhole. 

The Spectra Flow tool is a uniquely reconfigured pulseneutron 

capture/spectral through-tubing device with a 

source to detect spacing to make quantitative water-flow 

measurements. The tool has two logging methods— 

continuous logging and stationary impulse testing. 

This combination of high-resolution water detection plus 

unique pulsed-neutron timing allows the use of the 

continuous logging method. In this method, the linear 

velocity of water-flow is determined from the ratio of oxygen 

activation measured with the near and far detectors. 

The stationary impulse method is a travel time measurement 

that automatically switches the neutron generator on/off and 

measures the fluid velocity with respect to time. Independent 

velocities are measured for each detector. Since calibration of 

the detectors is not required for measurement accuracy, this 

method has better results than any other system. 

Other logging techniques used to discover fluid movement 

behind the casing involve measuring acoustical noise, 

temperature, and radioactive tracers. Running one or a 

combination of these services can be done successfully, but 

the interpretation of the data is frequently not easy. 

Spectra Flow logs eliminate the need to inject tracer 

materials, have sufficient resolution, a deeper depth of 

investigation, and appear to be more practical for detecting 

low flow rates than traditional methods. 

The above Spectra Flow impulse velocity test calculates accurate velocity 

by measuring the time of activated water compared to nonactivated water 

passing by Spectra Flow detectors. Velocities are calculated for the two 

spectral measurements, the total activation measurement, and the natural 

gamma ray detector. Both simultaneous up and down flow can be 

measured. Track 3 displays the spectral measurements of activated oxygen. 

Track 2 contains the gamma ray, near and far oxygen activation (OAIN 

and OAIF), generator voltage, and near and far total activation 

measurement (TNA and TFA) curves. Track 1 shows the water-flow 

velocity curves from each of the measurements in Track 2 (VSN for OAIN, 

VSF for OAIF, VTN for TNA, VTF for TFA, and VGR for GR). 


HAL1031

Applications 

The detection and quantification of water flowing in 

cement channels (in producing or injection wells) 

Identification of water-flow between tubing and casing 

Detecting water entries 

Detecting thief zones 

Discovering cross flow between zones 

Detecting leaking plugs and packers 

CO2 flow measurements 

Features 

Specially designed for quantitative water-flow 

measurements 

Modified detector section for the pulsed neutron capture 

tool includes source-to-detector spacing to eliminate 

effects of stationary water in the borehole and/or the 

formation 

Fully combinable with a complete string of production 

log sensors 

Length 

ft (m) 

18 

(5.5) 

Modular design allows tool to be configured for 

detecting water sources from above or below; can also be 

configured to measure both up and down water sources 

simultaneously 

Pure spectral measurement isolates only gamma rays 

produced for oxygen recording 

Gamma rays produced as a result of oxygen activation 

are recorded spectrally, allowing elimination of all other 

sources of gamma rays 

Because it measures spectrally, it can determine 

Compton downscattering, allowing qualitative 

determination of whether flow is inside or outside the 

pipe 


QW (Calculates water-flow rate and velocity) 

Spectra Flow Logging Service (SpFl) Specifications 

Diameter 

in. (mm) 

1.6875 

(42.8625) 


psi (Mpa) 

15,000 

(103.4) 

Maximum 

Temperature 

°F (°C) 

325 

(162.8) 

Weight 

lb (kg) 


70 

(31.8)

DSN Dual-Spaced Neutron Tool 

The DSN dual spaced neutron tool is a thermal neutron 

tool designed to measure formation porosity from neutronnuclei 

interactions. Neutron porosity logs provide total fluid 

information for use with resistivity logs and/or pulsed 

neutron logs in determining formation water saturation. 

They can be combined with density logs to provide an 

indication of formation gas saturation and also with density 

and/or sonic logs to provide indications of formation 

lithology. In open holes, the DSN tool is usually combined 

with the SDLT spectral density logging tool and the 

NGRT natural gamma ray tool. In cased holes, the 

DSN tool is usually combined with the NGRT tool and 

DITS casing collar locator. 

The DSN tool consists of an instrument section housing the 

electronics, two He3 detectors, and a source sub housing an 

americium-beryllium source which generates fast neutrons 

that penetrate the formation at an initial energy of 4.6 MeV. 

Thermal neutron tools are not as limited by the spacing and 

depth of investigation problems associated with epithermal 

neutron tools. Since thermal neutrons are detected, count 

rates are much higher than for epithermal neutrons. 

However, thermal neutron detectors are more sensitive to 

lithology and are affected by borehole and formation salinity. 

The dual detector method is used to compensate for these 

environmental effects. 

Applications 

Gas detection 

Porosity 

Lithology 

Features 

Detector array contains two helium proportional 

counters 

Optimized detector spacing, advanced calibration 

methods, and greater counting rates 

Faster log runs 

Delineation of thin-bed formations with enhanced 

vertical resolution (EVR) available in real-time or in 

post-processing 

A combination of logging tools can be run to identify 

lithology, reveal gas zones, and calculate shale volumes 

In this DSN log example, the subject well was logged twice. The 

resulting near/far ratio curves and the calculated porosity curves are 

overlaid to illustrate high repeatability of DSN porosity measurements. 


HAL1664


The wellsite answer product is the neutron porosity 

NPHI 





Length 

ft (m) 

10.25 

(3.1) 





DSN Dual-Spaced Neutron Tool Specifications 

Diameter 

in. (mm) 

3.63 

(92.2) 


psi (Mpa) 

20,000 

(137.9) 

Maximum 

Temperature 

°F (°C) 

350 

(176.7) 

Weight 

lb (kg) 


196 

(88.9)

FCMT Formation Compaction Monitoring Tool 

The FCMT formation compaction monitoring tool is a 

through-tubing instrument that can be run in production 

wells. The tool uses multiple gamma ray detectors to 

determine the location of and precise distance between 

radioactive markers planted in the formation or casing. 

Compaction of the formation can be measured by changes in 

the distance between the markers. Vertical compaction and 

the lateral displacement of markers can also be monitored 

using the FCMT tool. 

Applications 

Determine the location of and precise distance between 

radioactive markers planted in the formation or casing 

Monitor vertical compaction and lateral displacement of 

markers 

Features 

Unique construction allows spacing between detectors to 

be easily altered to fit the application 

Available in three-detector or four-detector arrays to 

help make necessary configuration changes easy to 

implement 

Measures tool temperature to correct for thermal 

expansion 

Depth measurements are corrected for irregular tool 

motions using a uni-axial accelerometer 

A pair of induction-type casing collar locators (CCLs) 

provides additional compaction/depth measurements 

Length* 

ft (m) 

– 

* Specified by customer 

** Depends on configuration 

Track 1 consists of the processed gamma ray reading from detector 1. It 

shows the high spikes of the radioactive tags with the upper three tags 

being placed in the formation while the lower three tags were placed in 

the casing. Three different methods are used to determine spacing 

between radioactive tags. The next track shows the depth of each tag 

plus the distance between tags as calculated by special processing. This 

processing can be extremely accurate as long as the tag placement is 

close to the spacing between gamma ray detectors. The red numbers in 

Track 3 indicate the average of all the different methods to calculate 

distance between the tags. Track 4 is the average of all the methods less 

the HES method. The last track is raw gamma ray data from the three 

detectors. The tool configuration in this case consisted of three gamma 

ray detectors with 1 ft spacing between the first two detectors and 30 ft 

between the second and third. Distance between each detector is 

corrected for temperature affects and is used in the post-processing 

software. 

FCMT Formation Compaction Monitoring Tool Specifications 

Diameter 

in. (mm) 

1.68 

(42.7) 


HAL9762 


psi (Mpa) 

15,000 

(103.4) 


°F (°C) 

350 

(176.7) 

Weight** 

lb (kg) 

–

CASE Casing Evaluation and Inspection Software 

CASE casing evaluation and inspection software is a series 

of programs that will use data from either the rotating 

ultrasonic tools (FASTCAST or CAST-V tools) or the 

multi-finger caliper tools to provide accurate casing 

evaluation. When the ultrasonic data is recorded in the 

casing mode, CASE software provides precise casing ID and 

thickness presentations that allow easy interpretation of 

casing damage. When the ultrasonic data is acquired in the 

image mode or with multi-finger caliper tools, CASE 

software provides a detailed interpretation of the interior 

casing damage. 

With both the FASTCAST and CAST-V tools in the image 

mode, they can be used to monitor wear on the inner surface 

of the casing string. Its high vertical and horizontal 

resolutions nearly eliminate the chance of missing flaws in a 

string of pipe, thus preventing possible long-term problems. 

In the cased-hole mode, the ultrasonic tools provide accurate 

casing ID and casing thickness measurements. With these 

two measurements, it is possible to determine the total 

damage to the casing and proportionate it to either inside 

casing wear, outside casing corrosion, or a combination of 

the two. 

The CASE software family provides detailed information on 

the condition of the casing, preventing minor problems from 

becoming major problems. The software consists of several 

different programs to provide the best possible interpretation 

of casing damage. 

With both ultrasonic and caliper data, slight tool eccentering 

problems will lead to an inaccurate analysis. Spiral or 

patterns similar to a barbershop pole are indications of 

eccentricity problems, not necessarily casing wear. The 

program HoleShape corrects the travel time data for tool 

eccentering. The correction increases the detail of the travel 

time image leading to an improved visual interpretation of 

casing defects. 

The CASE program will use the corrected travel time, the 

pipe thickness, and fluid travel time to evaluate the casing 

condition and determine the percent of casing wear. With 

this program, the results are presented both calculated and 

normalized for each size and weight of the casing present. If 

the casing is perfect (no damage in radius or thickness), then 

the normalized radius and thickness measurements will be 

zero. If the casing has internal corrosion, the radius 

measurement will be larger than the known, and the 

thickness will be smaller. Therefore, the normalized data will 

show the loss of casing wall as an increase in the pipe radius 

and a decrease in pipe thickness. This information allows us 

to grade the pipe based on the total loss of metal, and can 

determine if the damage is inside/outside or a combination 

of both for the casing in question. These grades are based on 

industry standards or can be adjusted based on customer 

requirements. 

The final program in this family is the CASE_JOINT 

program that finds, counts, and displays data based on each 

joint. For casing evaluation, collars provide problems with 

the standard casing analysis logs. There are usually gaps 

between adjacent joints, additional metal in the collars, and 

possible damage near the collars from when the joints were 

made up. This program will determine the joint makeup 

point, and allow determination of both joint and collar 

damage based on the grading used in CASE software. 

The CHIME program combines all these programs and also 

has the ability to provide graphical displays of damage from 

both the ultrasonic and caliper tools. In addition, the CASE 

programs generate both spreadsheets and text files that list 

minimum, maximum, and average values of both the 

internal radius and the thickness of the casing not only on a 

joint-by-joint listing but also as a depth-by-depth listing. 

These files will allow continuous monitoring and 

comparisons of casing wear throughout the life of the well. 

Features 

Delivers a more reliable indication of casing condition 

Works with existing logging procedures for FASTCAST, 

CAST-V, and MIT tool data 

Improves casing evaluation for both inner and outer 

defects 

Corrects for tool eccentricity thus helping to distinguish 

even minute casing problems 

Log presentations can be customized to meet the specific 

requests or needs. Presentations include raw data, 

segmented curves, and images, including 3D displays 

Joint and depth listings of defects allow easy input into 

other programs or a simple method to monitor known 

casing deformities 

Health, Safety, and Environmental 

Helps customers to monitor and prevent catastrophic 

casing problems 

Proper CASE software usage allows monitoring of casing 

erosion / corrosion / rectification 


Y000 

Y030 

Y050 

This CASE processed log effortlessly shows where a packer was set and did not release properly. The metal was peeled up when the packer was pulled, 

which is highlighted by the green stripe box in the depth track. This zone is expanded on the log on the left. Track 1 provides gamma ray for correlation 

along with eccentricity and ovality. Eccentricity consists of tool and casing eccentricity, while ovality measures casing ovality. INTDAMG is the percent 

of pipe wear on a scale from 0 to 50 percent. The AVRAD is the average radius calculated from the 200 radius measurements from the CAST-V tool. 

Track 2 is the amplitude of the first arrival and can be used to visually indicate casing damage. Track 3 is an eccentricity corrected travel time for the first 

arrival. This will be used in determining casing ID or radius. Track 4 shows the minimum, maximum, and average of the normalized pipe radius 

PRADN. The normalized pipe radius is shown in Track 5 where red is showing the packer damage and blue is showing metal buildup from the packer 

damage. The last track shows the pipe grading where the damage is color coded with the following percentages: white< 20%

Through Casing Acoustic Services 

WaveSonic ® Tool 

The WaveSonic® crossed dipole sonic tool provides 

simultaneous monopole, XX dipole, and YY dipole sonic 

measurements. The dipole flexural wave propagation allows 

for the measurement of shear wave slowness in virtually all 

formation conditions. The compressional P-wave slowness, 

refracted shear wave slowness, and Stoneley wave properties 

are obtained from the monopole data. The shear wave 

slowness in two orthogonal directions can be obtained in 

real- time from the XX and YY dipole data. The WaveSonic 

tool is combinable with all standard open and cased-hole 

tool services. The WaveSonic tool requires a liquid filled 

borehole and can be used in fresh water, salt water, or oil 

based mud systems. The robust mechanical design of this 

tool allows for drillpipe conveyed logging, and it is not 

limited to the bottom of the toolstring. A hostile WaveSonic® 

version is available for high temperature and high pressures 

applications. 

The shear wave slowness in the XX and YY directions and the 

monopole P-wave slowness are the basic well site 

deliverables. The tool has 32 broadband receivers, arranged 

in eight rings of four receivers, to provide high-quality 

waveform data. The tool provides 96 waveforms (32 

monopole, 32 YY dipole, and 32 XX dipole) for each firing 

cycle, which are recorded by the surface system. The fast and 

slow shear wave travel times are obtained with advanced 

waveform processing methods in Halliburton's Reservoir 

Evaluation Services centers, strategically located throughout 

the world. 

From the fast and slow shear wave travel times, and their 

orientation in the formation, the minimum and maximum 

principal stresses and stress field orientation can be obtained 

by combining oriented slowness data with overburden and 

analysis, wellbore stability, and production enhancement 

treatment design. 

Natural gamma ray and caliper are presented in Track 1. Semblance 

quality data is presented in the depth track. The dipole X travel time, 

dipole Y travel time, and monopole P-wave travel time are presented in 

Track 2. Monopole semblance with the compressive wave slowness 

overlaid on the semblance image are presented in Track 3. The dipole X 

semblance with the XX shear wave slowness overlaid on the semblance 

image are presented in Track 4. The dipole Y semblance with the YY 

shear wave slowness overlaid on the semblance image are presented in 

Track 5. 


Sonic anisotropy analysis provides the fast and slow shear 

wave travel times as a simultaneous solution of 64 

waveforms(32 XX and 32 YY). Anisotropy and its orientation 

can be used to determine the minimum horizontal stress and 

the orientation of natural fractures. The sonic attributes of 

slowness, amplitude and frequency content can be used for 

identification of fractures and compressive fluids and to 

measure various geomechanical properties. The fast and slow 

shear wave travel times and their orientation, combined with 

P-wave slowness, allows for better 3D seismic analysis. 

Applications 

Determine fast and slow wave travel times and 

orientation in the formation 

Calculate minimum and maximum principal stresses 

and stress field orientation 

Porosity estimation 

Fracture identification 

Permeability (mobility) estimation 

AVO calibration 


Features 

Programmable-frequency sources to minimize effects of 

near-wellbore alteration 

Length 

ft (m) 

Tool 

Version 

34.0 

(10.3) 

20 KPSI 

Tool 

30 KPSI 

Tool 

Length 

ft (m) 

40.9 

(12.4) 

40.9 

(12.4) 

Diameter 

in. (mm) 

3.63 

(92.2) 

WaveSonic ® Tool Specifications 


psi (mpa) 

20,000 

(137.9) 

Broadband eight-level, quad receiver array for highquality 

waveform data 

All 96 waveforms for each set of transmitter firings are 

recorded at the surface for advanced waveform 

processing techniques 

Combinable with all open-hole tools, including MRIL® 

and RDT tools and services 


Shear slowness anisotropy analysis 

RockXpert2 sand production and fracture strength 

analysis 

FracXpert fracture stimulation zoning analysis pore 

pressure data information is vital for geo-mechanical 


Stoneley derived permeability 

Stoneley reflection analysis 

Formation stress, borehole stability and sanding 

potential 

Maximum 

Temperature 

°F (°C) 

350 

(176.7) 

Hostile WaveSonic ® Tool Specifications 

Diameter 

in. (mm) 

3.13 

(79.4) 

3.13 

(79.4) 


psi (Mpa) 

20,000 

(137.9) 

30,000 

(206.8) 

Maximum 

Temperature 

°F (°C) 

500 

(260.0) 

500 

(260.0) 

Weight 

lb (kg) 

520 

(236.3) 

Weight 

lb (kg) 

595 

(269.9) 

720 

(326.6) 


FWS Full Wave Sonic Tool 

The FWS tool provides compressional wave, refracted 

shear wave, and Stoneley wave properties of downhole 

formations for a wide range of petrophysical, geological, and 

geophysical applications. To minimize the number of logging 

trips required for complete formation evaluation, the FWS 

tool is compatible with all DITS logging tool strings. A 

liquid-filled borehole is required for sonic logging and can be 

used in fresh water, salt water, or oil-based mud systems. 

The long transmitter-to-receiver offset allows for the 

acquisition of borehole sonic data beyond the effects of any 

near-wellbore altered region. This long offset also allows for 

the acquisition of high-quality sonic data in enlarged 

boreholes where critical angle effects would affect sonic tools 

with short transmitter-to-receiver offsets. 

The information obtained from the FWS tool is plotted in 

three separate log presentations: 

Slowness presentation – compressional slowness and 

refracted shear slowness, velocity ratio, and time-depth 

integration of the compressional and shear travel times, 

and other logging data such as gamma ray and caliper 

Quality presentation – indicators which establish 

confidence levels for the slowness processing, including 

compressional slowness and semblance coherency and 

refracted shear and semblance quality gain curves for 

each receiver 

Waveform presentation – waveforms from all four 

receivers can be presented. Gain curves reflecting the 

gain applied to the waveform by the automatic gain 

control (AGC) circuit, and correlation curves, including 

gamma ray and caliper information 

The FWS tool can be run in the cased-hole environment to 

obtain sonic properties through casing. Acoustic coupling of 

the pipe-to-formation is required for cased-hole 

applications. 

Applications 

Identify wave properties of downhole formations 







HAL9170

Features 

Long transmitter-to-receiver offsets and 1 ft 

receiver-to-receiver spacings 


pulse ensures constant source characteristics 

Automatic gain control of each receiver preserves signal 

amplitude 






Continuous uninterrupted recording of full waveform 

signals 

Records various types of information including tool 

data, quality curves, and final results 



estimates using both Δtc and Δts Length 

ft (m) 

28.6 

(8.7) 

FWS Full Wave Sonic Tool Specifications 

Diameter 

in. (mm) 

3.625 

(92.1) 


psi (Mpa) 

20,000 

(137.9) 

Lithology identification by means of velocity ratio, Δts/ Δtc, and location of gas zones, even in poor hole 

conditions and cased holes 


Stoneley wave attenuation and slowness 




Prediction of vertical extent of hydraulic fractures 


beds (Beds as thin as 3 in. can be identified with the t 

curves) 

Calculates sonic porosity from P-wave slowness and can 

determine secondary porosity by combining sonic 

porosity with neutron and density porosity data 



data is the required input information needed for 

synthetic seismograms 


°F (°C) 

350 

(176.7) 

Weight 

lb (kg) 

460 

(208.7) 



The HFWS tool is a 2.75-in. acoustic velocity logging tool 

that is a part of the HEAT suite hostile environment 

applications tool toolstring. The HFWS tool, along with all of 

the HEAT suite sensors, have a pressure rating of 25,000 psi 

(172 400 kPa). The HEAT suite logging tools are designed for 

continuous operation of six hours at 500°F (260°C). 

The HFWS tool, like the larger in diameter (3.625-in.) 

FWS full wave sonic tool, provides compressional wave, 

refracted shear wave, and Stoneley wave properties of 

downhole formations for a wide range of petrophysical, 

geological, and geophysical applications. To minimize the 

number of logging trips required for complete formation 

evaluation, the HFWS tool is compatible with all HEAT suite 

logging toolstrings. A liquid filled borehole is required for 

sonic logging, and can be used in fresh water, salt water, or 

oil-based mud systems. 

The HFWS tool can be compared to having two sonic tools 

within the same toolstring—a long-spaced sonic tool for 

traditional full waveform open-hole sonic logging, and 

located within the transmitter-to-receiver offset, a cement 

bond tool that utilizes the second transmitter and two 

receivers. The upper transmitter and the lower four receivers 

array are utilized for full wave sonic logging. The lower 

(second) transmitter and the upper two receivers are utilized 

for cement bond logging and short, offset compressional 

wave travel time. The long transmitter-to-receiver offset 

allows for the acquisition of borehole sonic data beyond the 

effects of any near-wellbore altered region. The long offset 

also allows for the acquisition of high-quality sonic data in 

enlarged boreholes where critical angle effects would affect 

sonic tools with short transmitter-to-receiver offsets. 

Applications 

Full waveform open-hole sonic logging 

Cement bond logging 







HAL9171

Features 

Advanced system design and software processing with 

long transmitter-to-receiver offsets and 1/2 ft receiver-toreceiver 

spacings 


pulse to promote constant source characteristics 

Automatic gain control of each receiver helps preserve 

signal amplitude 






Facilitates continuous uninterrupted recording of full 

waveform signals 

Ability to record various types of information including 

tool data, quality curves, and final results 



estimates using both Δtc and Δts Facilitates lithology identification by means of velocity 

ratio, Δts /Δtc , and location of gas zones, even in poor 

hole conditions and cased holes 


Stoneley wave attenuation and Δt 




Prediction of vertical extent of hydraulic fractures using 

the RockXpert2 analysis package 


beds (Beds as thin as 3-in. can be identified with the 

t curves) 



data are the required input information for synthetic 

seismograms 

Length* 

ft (m) 

30.2 

(9.2) 

HFWS Hostile Full Wave Sonic Specifications 

Diameter 

in. (mm) 

2.75 

(69.9) 


psi (Mpa) 

25,000 

(172.4) 

* Add 3.50 ft (1.1 m) for each in-line centralizer (usually two). 

**6 hour 

Gamma ray and caliper are presented in Track 1, compressional wave 

travel time (DTC) is presented in Track 4, and the P-wave semblance 

quality is presented in Track 3. 

This is a hard rock example. Natural gamma ray, caliper, and VpVs 

are presented in Track 1. The P-wave travel time and the refracted 

shear wave travel time are presented in Track 2. The semblance 

quality is presented in an image format in Track 3 for the P-wave 

and refracted shear wave. 


HAL9172 

HAL9173 


°F (°C) 

500 

(260) 

Weight 

lb (kg) 

340 

(154.2)

Production Logging 

Production Logging Tools 

A wide range of production logging tools for use in all type of 

downhole environments are available: 

Production logging tools for vertical, deviated, and 


Full range of sensors and running hardware for memory 

and electric line PL logging 

Applications 

Flow rate measurements – continuous flowmeters, 

basket flowmeters, fullbore flowmeters, spinner array 

tool (SAT) 

Fluid identification / flow composition tools – gas 

holdup, capacitance water holdup, radioactive fluid 

density, differential pressure density, capacitance array 

Flow condition / well diagnostic tools – pressure, 

temperature, X-Y caliper, inclinometer 

Correlation tools – gamma ray, casing collar locator 

Memory Production Logging 

The memory production logging string is normally deployed 

on slickline or coiled tubing. Simultaneous telemetry 

transmits the signals from standard sensors to a battery 

powered memory tool at the top of the toolstring. The 

memory tool is programmed using a computer and 

interfaces to record log values with intervals as short as 0.1 

seconds or as long as many hours between readings. 

Once the logging operation is complete, the procedure for 

merging the log-time and depth-time data is rapid. 

Electric Line Production Logging 

Using a computerized LOGIQ-CH system, calibration, 

recording, and printing of well logs can be done in real time. 

When operating in this mode, the downhole telemetry 

transfers data from the toolstring to the surface system via 

electric line. 

This example provides a display of typical production logging tool data. 

For a complete interpretation temperature, pressure, holdup, and fluid 

velocity readings are necessary. Track 1 consists of the gamma ray (GR1), 

pressure (PR1), and temperature (TEMP1). The pressure data shows that 

this well has not achieved a steady production rate at this time. Tracks 2 

through 4 provide data concerning the fluid holdup as measured by the 

CAT tool, radioactive fluid density, and fluid capacitance tool. Tracks 5 

and 6 provide information about the fluid movement and cable speed. 

Track 2 consists of the average capacitance reading from four different 

passes of the CAT tool. Higher readings indicate hydrocarbons while water 

is around 450 counts or the right side of the track. Track 3 is the fluid 

density from four passes of the radioactive fluid density tool. Likewise, 

Track 4 consists of four passes of the fluid capacitance tool where low 

counts indicate water while the higher counts indicate hydrocarbons. 

Track 5 consists of four passes of the continuous spinner with pass 1 and 2 

showing a nonsteady state. Track 6 shows the speed of the tool, and since 

the well was logged with a coiled tubing the two speeds are about 30 fpm 

down and 20 fpm up. 


HAL9253

Features 

Great selection of flowmeter types and sizes, including 

the SAT tool for deviated or horizontal wells 

High sensitivity and low threshold velocity flowmeters 

Standard and compact tool sizes 

Multiple logging sensors in one string. All PL sensors can 

run simultaneously except the bottom only tools 

Advanced sensors such as the GHT gas holdup tool, 

CAT capacitance array tool, and spinner array tool 

(SAT) for horizontal and undulating wells 

Conveyance flexibility – toolstring can be deployed on 

electric line, slickline, coiled tubing, or drillpipe 

PL Tool 

Category Tool Type 

Casing Collar 

Locator 

Correlation 

Flow 

Condition / 

Well 

Diagnostic 

Fluid 

Identification 

Production Gamma 

Ray 

Dual Caliper 

Quartz Pressure 

Gauge 

Fast Response 

Platinum Resistance 

Thermometer 

Inclinometer 

Accelerometer 

Enhanced 

Capacitance Water 

Holdup Tool 

Radioactive Fluid 

Density Tool 

Differential Pressure 

Fluid Density Tool 

Capacitance Array 

Tool 

Gas Holdup Tool 

Greater consistency of data sets as a result of using the 

same sensors for electric line and memory operations 

Faster telemetry, accurate, safe, reliable operations 

The same telemetry platform is used to run production 

logging tools with casing inspection and/or pulse 

neutron tools, either sequentially in one trip in the hole 

or simultaneously if required 


Hard copy log of multiple sensor measurements 

Wellsite production log analysis 

Advanced production log analysis at Applied Formation 

Evaluation Centers 

Production Logging Tools Specifications Summary 

Tool 

Length 

in. (mm) 

18.5 

(470) 

Range of Measurement Resolution Accuracy 

23.1 

(586) 

37.5 

(953) 

19.01 

(483) 

12.5 

(318) 

10.7 

(272) 

26.2 

(665) 

22.9 

(582) 

51.9 

(1318) 

51.43 

(1306) 

24 

(610) 

Sensitivity 

Threshold 

20 keV approx. 

2 to 9 in. 0.015 in. 

0 to 15,000 psi 

50 to 350°F (10 to 177°C) 

0.008 psi and 

PL Tool 


Flowmeter 

Combination 

Tool 

Deployment 

Tools 

Inline Spinner 

Flowmeter 

Continuous Spinner 

Flowmeter (Bearing) 


Flowmeter (Jeweled) 

Caged Full Bore 

Flowmeter 

3 Arm 


Flowmeter 

6 Arm 

Diverter Flowmeter 

Spinner Array Tool 


CCL 

Capacitance / 

Temperature / Flow 

Head Tension Unit 

Roller Centralizer 

Spring Centralizer 

Swivel 

Knuckle Joints 

Production Logging Tools Specifications Summary 

Tool 

Length 

in. (mm) Range of Measurement Resolution Accuracy 

21 

(533) 

9 

(229) 

34.9 

(886) 

34.9 

(886) 

70.7 

(1796) 

46 

(1168) 

19.01 

(483) 

Approx. 

18.5 

(470) 

w/o flow 

mech 

section 

22.8 

(580) 

Max fluid velocity 3,450 ft/min 



500 ft/min (2.54 m/s), 28,250 BPD 

in 7-in. casing; with solid shaft tool 

can work up to 1,200 ft/min 

500 ft/min (2.54 m/s), 28,250 BPD 



Minimum 6-8 m 3 per day. Maximum 

approx. 400 m 3 /d (6 psi drop 

~120 lb uplift in 5 1/2-in. casing) 

3 1/2 to 7-in. casing 

Threshold 

approx 8 ft/min 

in water 

Threshold 


in water 

Threshold 


in water 

1.7 ft/min approx 

(0.01m/s), 

100 BPD in 7-in. 

casing 


(0.01m/s), 

100 BPD in 

7-in. casing 

Threshold 


in water 

12 ft/min in 

water 

Same as quartz pressure gauge and CCL individual tools 

10 pulses/rev 

10 pulses/rev 

10 pulses/rev 

10 pulses/rev 

10 pulses/rev 

10 pulses/rev 

3/8-in. spinner 

3 pulses/rev 

Same as capacitance / temperature flow individual tool. Flowmeter 

mechanical section can be any type of continuous or full bore flowmeter. 

-400 kg (compr.) to +1000 kg 

Hysteresis 

5% FS 

Temperature 

Drift 5% FS 


10.6 

(4.8) 

3.5 

(1.6) 

mechanical 

section only 

3.5 

(1.6) 

mechanical 

section only 

10 

(4.5) 

10 

(4.5) 

Approx 15 

(6.8) 

8.8 

(4.0) 

Approx 5.4 

(2.5) 

w/o flow 

mech section 

10 

(4.5) 

Spinner shroud 

OD 1 11/16, 

2 1/8, 3 1/8 in. 


OD 1 11/16, 

2 1/8, 3 1/8 in. 


OD 1 11/16, 

2 1/8, 3 1/8 in. 

Available for 

different casing 

size 

4 1/2 to 9 5/8 in. 

(114 to 244 mm) 

Available for 


size 

4 1/2 to 9 5/8 in. 

(114 to 244 mm) 

3 1/2 to 9 5/8 in. 

(90 to 244 mm) 

6 miniature 

spinner equispaced 

around 

circumference 

Repeatability 

±2% FS 

Different roller centralizers are available with 3 or 4 arms with single or double rollers in each arm. Also have different 

centralization force as per operational requirement. Approx Length - 33.25 in. (845 mm) and weight around 12 lb. 

Different compact spring bows are available with 3 to 6 springs. Also have different centralization force as per 

operational requirement. Approx Length - 28 in. (711 mm) and weight around 10 lb. 

This is a monoconductor swivel joint which allows free rotation between the upper and lower heads while maintaining 

electrical continuity through the tool. Different sizes available, Approx Length - 11 in. (280 mm) and weight 4 lb. 

7 

(178) 

Ball type knuckle for deployment in 

deviated well 

Weight 

lb (kg) Others 

1. Tools specified have nominal OD of 1 1//16 in. Tools with OD of 1 3/8 in. are also available. 

2. All tools have maximum pressure rating of 15,000 psi and maximum temperature rating of 350°F or 177°C. For higher pressure or higher temperature tools 

contact your local Halliburton representative. 

3. Telemetry is very high speed capable of running 62 tools in combination (virtually no limit on tool combination for telemetry). 

3.5 

(1.6)

FloImager ® Service 

The FloImager® service provides three-phase holdup 

calculations using data from the CAT capacitance array 

tool. This service is extremely useful in highly deviated and 

horizontal wells having multiphase flow. Applications for 

detecting three-phase fluid entry can be done at any angle. 

The CAT tool is an electric line, tractor, or coiled tubing 

conveyed production logging instrument developed in 

partnership with Sondex. It consists of an array of 12 microcapacitance 

sensors which are radially distributed in the 

wellbore to accurately measure fluid holdup. This holdup 

measurement is fullbore. Consequently, tool position does 

not affect the readings in horizontal wells as would be the 

case with a center sample device. 

The CAT tool is uniquely versatile in that sensors are 

distributed across 12 bow springs, allowing cross-sectional 

measurements in tubing and in casing, logging up or logging 

down. This process can be repeated as often as necessary. 

Readings can also be taken with the tool stationary at any 

depth. The CAT tool can be run in combination with the 

spinner array tool (SAT), reservoir monitoring tools, and 

other conventional production logging sensors. 

Applications 

Detect water entry and its orientation relative to the high 

side of the pipe in any well deviation 

Successfully show three-phase fluid segregation since 

each fluid has its own log response 

Provide an accurate visualization of the undulating 

horizontal wellbore when TVD data is combined with 

CAT tool data 

Allows a complete three-phase analysis by combining the 

calculated fluid holdup with additional PL sensors 

Improve interpretation of flow patterns in all wells due to 

the increased number of sensors at the same depth. Since 

the relative position of the CAT tool is known at all 

times, the images and logs are corrected to the high side 

of the hole, allowing accurate holdups to be determined 

Track 1 consists of a gamma ray (GR), relative bearing (RB), temperature 

(TEMP), pressure (PRES), and continuous spinner (FCON). RB is the 

relative bearing for arm 1 of the CAT tool and allows arm position 

relative to the high side of the hole to be determined. Track 2 provides the 

image of the flow as measured by the CAT tool. The image is positioned so 

that the high sides are on the left and right side of the track while the 

middle is on the low side. Since this is a horizontal well, it should be 

apparent that the heavier fluids should be on the bottom and lighter fluids 

should be on the top of the well. Track 3 shows the average of the 12 

sensors (AVCAPN) along with the two center sample holdup 

measurements fluid density (FDEN) and Hydro tool (HYDR). Track 4 

provides a cross-sectional view of the data in Track 2. The right side of the 

image is high side while the left is on the bottom. Additionally two holdup 

curves are shown, water (YWE) and gas (YGE). These holdups are also 

presented in the last track. This presentation allows quick method of 

determine fluid contacts and provide an accurate calculation of the fluid 

compositions. 


HAL9135

Features 

Makes both vertical and cross-sectional images available 

Valuable data can be obtained in deviated or horizontal 

wells when run in combination with traditional PL 

sensors. Running the SAT tool in combination allows a 

complete analysis regardless of well geometry 

Permits more accurate three-phase holdups 

Shows images in all types of stratified flow 

Has unsurpassed responses in both deviated and 

horizontal wellbores 

Can produce video-like images of the fluid distribution 

across the borehole with further processing 

Length 

ft (m) 

4.63 

(1.4) 

FloImager ® Service Specifications 

Diameter 

in. (mm) 

1.69 

(42.9) 


psi (Mpa) 

15,000 

(103.4) 


Production logging analysis (PLA) 

FloImager® 3D imaging product, CD-based 3D viewer 

Reliable water holdup measurements in highly deviated 

and horizontal wellbores 

Maximum 

Temperature 

°F (°C) 

350 

(176.7) 

Weight 

lb (kg) 

17.3 

(7.8) 


GHT Gas Holdup Tool 

Representing a major improvement over center sample 

production logging tools for horizontal and highly deviated 

wells, the GHT gas holdup tool is a unique tool that 

directly and accurately determines the volumetric fraction of 

gas over a cross-sectional volume element of the wellbore. 

This instrument operates in horizontal, highly deviated, and 

vertical cased wells in any flow regime. It measures gas 

holdup directly and with greater accuracy using real-time 

downhole pressure and temperature, casing ID, and gas 

gravity measurements to generate a 0% to 100% gas holdup 

log in stratified or homogenized flows. 

The superior information provided by the GHT tool 

mitigates against the ambiguities that an interpreter of 

conventional production logs sometimes encounters. 

Applications 

Fast, accurate flow analysis 

Highly deviated horizontal and vertical cased wells 

Reservoir evaluation 

Features 

Determines gas holdup, independent of flow patterns or 

wellbore angles 

Provides an improved true fullbore measurement 

Helps identify water entry in gas wells 

Converts a complex three-phase flow analysis into a 

simple dual-phase analysis 

Improve understanding of actual downhole flow 

conditions in wells producing gas 

Real-time gas holdup measurements expedite the 

evaluation of well production 

Helps avoid costly errors in judgment based on 

inaccurate flow analysis 

Length 

ft (m) 

2 

(0.6) 

GHT Gas Holdup Tool Specifications 

Diameter 

in. (mm) 

1.687 

(42.8) 

GHT tool and data in a vertical low-velocity well with multiple flow 

patterns. Track 1 consists of gamma ray, temperature, and pressure. Since 

GHT data is corrected for PVT relationships, it is extremely important to 

have these temperature and pressure sensors run in combination with 

GHT tool. Tracks 2 and 3 show the wellbore diagram consisting of 

formation, cement, casing, and perforations. Track 4 highlights the 

comparison of calculated gas holdups between the fluid density tool and 

the GHT tool. Track 5 shows the raw fluid density data. The raw GHT tool 

count rates are presented in Track 6. The last track provides the spinner 

data indicating fluid movement. 


HAL9226 


psi (Mpa) 

15,000 

(103.4) 


°F (°C) 

350 

(176.7) 

Weight 

lb (kg) 

10.8 

(4.9)

MPL Memory Production Logging Tool 

MPL memory production logging is a system where 

slickline, conventional coiled tubing, or drillpipe conveyed 

tools acquire data without the need for electric line. 

The MPL system is comprised of the downhole data 

acquisition system, which includes memory production 

logging tools recording time-based data to the memory 

section. The standard memory section has 128 MB of 

memory and can be extended up to 1 GB of memory. It can 

run 62 tools at the same time. This new memory system can 

log production logging tools with casing or cement 

evaluation tools if required. It also includes the surface data 

acquisition system, comprising a depth and time recorder 

which records both time (from an internal clock) and depth 

pulses from a low current optical encoder. The unit can also 

be configured to record weight, tension, and other surface 

inputs. The Advanced Measurement System (AMS) can be 

included, comprising depth, time, weight, tension, and 

casing collar locator recording and a job log. Some sample 

capacities are shown below. 

Time Interval 

sec/sample 8.0 MB 4.0 MB 

0.1 15 hours 7.5 hours 

0.5 70 hours 35 hours 

1.0 120 hours 60 hours 

Times given assume 6 PL tools and quartz pressure. 

Times are calculated to the nearest whole hour. 

Sample capacities might be limited by battery type. 

4 MB tool all 12 ch sampling at 1sec = 49.5 hours. 

Applications 

Downhole well problem diagnostics 

Production/injection profiles 

Treatment (stimulation) evaluation 

Multiple rate production logs 

Fall off tests 

Reservoir information 

Data for reservoir simulation 

This memory production log was obtained for an operator looking to cut 

high water production in a formation with a three-phase downhole flow 

regime. The MPL service captures logging data on a memory recorder. 

The data is equal in quality to data obtained with electric line services. 

Computing center analysis of the MPL data reveals that the bottom set 

of perforations is producing mostly water and only 2% of the total oil 

production and 6% of the gas. Remedial work to plug off the bottom zone 

should decrease water production and reduce water disposal costs without 

greatly affecting hydrocarbon production. 


HAL964 

HAL965

Features 

Highly portable and easily deployed and can also be 

deployed on electric line if slickline is not available 

Utilizes the same conventional sensors as the standard 

electric line toolstring providing data of the same 

accuracy and resolution 

Can be deployed with coiled tubing in highly deviated or 

horizontal wells. Suitable for offshore locations where 

there are limitations in space, weight-lifting capacity, and 

height restrictions 

PL Tool 


Casing Collar 

Locator 

Correlation 

Flow 

Condition / 

Well 

Diagnostic 

Fluid 

Identification 

Production Gamma 

Ray 

Dual Caliper 


Gauge 

Fast Response 

Platinum Resistance 

Thermometer 

Inclinometer 

Accelerometer 

Enhanced 

Capacitance Water 

Holdup Tool 

Radioactive Fluid 

Density Tool 

Differential Pressure 

Fluid Density Tool 

Capacitance Array 

Tool 

Gas Holdup Tool 

Utilization of slickline simplifies the pressure control 

equipment 

Very high memory enabling combination of production 

logging tools with casing or cement evaluation tools like 

MIT/MTT or CBL/RCBL tools 


Raw data hard copy log 

Production log analysis, an AFE analyzed hardcopy log 

MPL Memory Production Logging Tools Specifications Summary 

Tool 

Length 

in. (mm) 

18.5 

(470) 

Range of Measurement Resolution Accuracy 

23.1 

(586) 

37.5 

(953) 

19.01 

(483) 

12.5 

(318) 

10.7 

(272) 

26.2 

(665) 

22.9 

(582) 

51.9 

(1318) 

51.43 

(1306) 

24 

(610) 

Sensitivity 

Threshold 

20 keV approx. 

2 to 9 in. 0.015 in. 

0 to 15,000 psi 

50 to 350°F (10 to 177°C) 

0.008 psi and 

PL Tool 


Flowmeter 

Combination 

Tool 

Deployment 

Tools 

Inline Spinner 

Flowmeter 


Flowmeter (Bearing) 


Flowmeter (Jeweled) 


Flowmeter 

3 Arm 


Flowmeter 

6 Arm 

Diverter Flowmeter 

Spinner Array Tool 


CCL 

Capacitance / 

Temperature / Flow 

Head Tension Unit 


Spring Centralizer 

Swivel 

Knuckle Joints 

MPL Memory Production Logging Tools Specifications Summary 

Tool 

Length 

in. (mm) Range of Measurement Resolution Accuracy 

21 

(533) 

9 

(229) 

34.9 

(886) 

34.9 

(886) 

70.7 

(1796) 

46 

(1168) 

19.01 

(483) 

Approx. 

18.5 

(470) 

w/o flow 

mech 

section 

22.8 

(580) 




500 ft/min (2.54 m/s), 28,250 BPD 



500 ft/min (2.54 m/s), 28,250 BPD 



Minimum 6-8 m 3 per day. Maximum 

approx. 400 m 3 /d (6 psi drop 

~120 lb uplift in 5 1/2-in. casing) 

3 1/2 to 7-in. casing 

Threshold 


in water 

Threshold 


in water 

Threshold 


in water 


(0.01m/s), 

100 BPD in 7-in. 

casing 


(0.01m/s), 

100 BPD in 

7-in. casing 

Threshold 


in water 

12 ft/min in 

water 

Same as quartz pressure gauge and CCL individual tools 

10 pulses/rev 

10 pulses/rev 

10 pulses/rev 

10 pulses/rev 

10 pulses/rev 

10 pulses/rev 

3/8-in. spinner 

3 pulses/rev 

Same as capacitance / temperature flow individual tool. Flowmeter 

mechanical section can be any type of continuous or full bore flowmeter. 

-400 kg (compr.) to +1000 kg 

Hysteresis 

5% FS 

Temperature 

Drift 5% FS 


10.6 

(4.8) 

3.5 

(1.6) 

mechanical 

section only 

3.5 

(1.6) 

mechanical 

section only 

10 

(4.5) 

10 

(4.5) 

Approx 15 

(6.8) 

8.8 

(4.0) 

Approx 5.4 

(2.5) 

w/o flow 

mech section 

10 

(4.5) 


OD 1 11/16, 

2 1/8, 3 1/8 in. 


OD 1 11/16, 

2 1/8, 3 1/8 in. 


OD 1 11/16, 

2 1/8, 3 1/8 in. 

Available for 


size 

4 1/2 to 9 5/8 in. 

(114 to 244 mm) 

Available for 


size 

4 1/2 to 9 5/8 in. 

(114 to 244 mm) 

3 1/2 to 9 5/8 in. 

(90 to 244 mm) 

6 miniature 

spinner equispaced 

around 

circumference 

Repeatability 

±2% FS 

Different roller centralizers are available with 3 or 4 arms with single or double rollers in each arm. Also have different 

centralization force as per operational requirement. Approx Length - 33.25 in. (845 mm) and weight around 12 lb. 

Different compact spring bows are available with 3 to 6 springs. Also have different centralization force as per 

operational requirement. Approx Length - 28 in. (711 mm) and weight around 10 lb. 

This is a monoconductor swivel joint which allows free rotation between the upper and lower heads while maintaining 

electrical continuity through the tool. Different sizes available, Approx Length - 11 in. (280 mm) and weight 4 lb. 

7 

(178) 

Ball type knuckle for deployment in 

deviated well 

Weight 

lb (kg) Others 

1. Tools specified have nominal OD of 1 1//16 in. Tools with OD of 1 3/8 in. are also available. 

2. All tools have maximum pressure rating of 15,000 psi and maximum temperature rating of 350°F or 177°C. For higher pressure or higher temperature tools 

contact your local Halliburton representative. 

3. Telemetry is very high speed capable of running 62 tools in combination (virtually no limit on tool combination for telemetry). 

3.5 

(1.6)

Quartz Pressure Tool 

For high-precision downhole pressure measurement, 

Halliburton offers a quartz gauge tool that employs 

quartzdyne transducers, an industry standard quartz crystal 

pressure sensor. The tool provides both pressure and gauge 

temperature outputs. 

Fluid pressure applied to the quartz tension member changes 

the resonant frequency of the quartz crystal. Thermal 

compensation of the sensor and measurement of its 

temperature allows the calculation of very accurate, highresolution 

downhole pressures. 

Applications 

Measuring shut-in and flowing pressures at prescribed 

depth levels 

Diagnosing well problems 

Features 

Detects minimum pressure changes and temperature 

variations 

Conveyance flexibility with the following methods: 

slickline, wireline, coiled tubing, and drillpipe 

Resistance to corrosion 


Plots that are available at the wellsite include flowing 

pressure surveys, static pressure gradient surveys, log-log 

pressure buildup, and derivative pressure plots 

Advanced pressure transient analysis can also be done 

utilizing Sapphire software 

Section 

Memory 

SRO 

Length 

ft (m) 

1.0 

(0.3) 

1.9 

(0.59) 

Quartz Pressure Tool Specifications 

Diameter 

in. (mm) 

1.65 

(42) 

1.65 

(42) 

This log example shows how the quartz pressure tool can help determine 

flowing conditions. Track 1 shows the gamma ray (GR1) and four collar 

locator logs (CCL1-4) showing depth correlation. Track 2 provides four 

quartz pressure readings from continuous passes in this horizontal well. 

Normally in a stabilized well, the pressures have a common gradient as 

shown in Pass 4. Pass 1 and 2 indicate that this well has not been stabilized 

after shut-in. Track 3 has the four temperature passes with both fluid 

entry (higher temperatures) and gas entry (lower temperatures) in Pass 1. 

Track 4 includes some of the results from the CAT tool that can be used 

to determine fluid holdups. 


HAL9250 


psi (Mpa) 

15,000 

(103.4) 

15,000 

(103.4) 


°F (°C) 

350 

(176.7) 

350 

(176.7) 

Weight 

lb (kg) 

6.5 

(2.95) 

9.6 

(4.35)

Casing and Tubing Evaluation 

MAC Multi-Arm Caliper Tool 

Halliburton offers a wide variety of multi-arm calipers that 

provide high-resolution details about the condition of the 

casing or tubing, including accurate measurements of its 

internal radius. The MAC tool is available for most casing 

and tubing sizes. The tool can operate 24 to 80 arms and is 

deployed on wireline, slickline, or coiled tubing. All data 

collected is used to generate 3D images of the casing or 

tubing. 

Applications 

Detail the condition of casing or tubing with accurate 

internal radius measurements 

3D images of casing or tubing 

Features 

Comes in several sizes to work in a wide range of casing 

Can be deployed on wireline, slickline, or coiled tubing 

Can obtain data in horizontal wells 

Can be combined with production logging or cement 

bond tool 

Accurately identifies casing damage such as holes, splits, 

or cracks and their depth in the wellbore 

Can be used for scale evaluation 

Provides a method for mapping perforations 


MITview (multifinger imaging tool presentation 

package) 

MITpro (multifinger imaging tool software) 

Number 

of Arms 

24 

40 

60 

80 

Length 

ft (m) 

3.75 

(1.1) 

5.5 

(1.7) 

5.75 

(1.8) 

3.33 

(1.0) 

MAC Multi-Arm Caliper Specifications 

Diameter 

in. (mm) 

1.69 

(42.9) 

2.75 

(69.9) 

4.00 

(101.6) 

8.00 

(203.2) 

This 3D view shows an enlarged OD caused by perforating the well. 

This 3D image shows general deep corrosion with light deposits in the 

body possibly caused from cable movement. 


HAL10363 

HAL10364 


psi (Mpa) 

15,000 

(103.4) 

15,000 

(103.4) 

15,000 

(103.4) 

15,000 

(103.4) 


°F (°C) 

150 

(65.6) 

150 

(65.6) 

150 

(65.6) 

150 

(65.6) 

Weight 

lb (kg) 

20 

(9.1) 

62 

(28.1) 

100 

(45.4) 

93 

(42.2)

CAST-V Circumferential Acoustic Scanning Tool-Visualization 

The CAST-V tool is an ultrasonic tool that provides highresolution 

images in both open and cased holes. The tool’s 

interchangeable head rotates a full 360° and contains a highfrequency 

acoustic transducer to provide a full 360° profile of 

the borehole or cement. A second acoustic transducer is 

mounted in the tool housing and is used to measure 

characteristics of the borehole fluid. A directional sub is 

provided to orient images to either the high side of the hole 

or to north. The image mode, run primarily in open hole, 

consists of 200 points horizontally by 40 samples per foot 

vertically while the cased-hole mode measures 100 points by 

4 samples/ft. The CAST-V tool is designed to operate in 

conjunction with other DITS tools. 

The system provides high-resolution images indicating 

texture changes in the borehole wall or on the interior 

portion of the casing. These images can be used to identify 

fractures in the formation or slight internal defects in casing. 

The CAST-V tool in the cased-hole mode also determines the 

casing thickness for pipe inspection. Simultaneously the 

CAST-V tool determines the type of material in the annular 

space between the casing and borehole wall. 

The CAST-V tool must be run centralized in fluid filled 

boreholes. It must be the bottom tool in any combination. Its 

operation is limited by factors such as high mud density and 

dissolved gases that increase the attenuation of the tool’s 

acoustic pulses as they travel through the borehole fluid. 

CAST-V tool differs from other ultrasonic type tools in the 

cased-hole mode by several different ways. It has 100 shots 

per depth frame versus 72 (maximum) and includes a realtime 

fluid travel time (FTT) measurement. The competition 

down logs FTT and then plugs the results into the uplog. All 

measurements are made real-time with no mode selection to 

determine what is or what is not being processed. It is fully 

combinable with all DITS tools, especially the M305 FWS 

tool for the CBL portion. The complete navigation package is 

standard with service. The competitor’s standard service does 

not include a navigation package—they additionally charge 

for running the service. 

Applications 

Simultaneous ultrasonic pipe inspection and cement 

evaluation 

2D and 3D borehole imaging 

Process images, histograms, and curve-type data 

HAL9227 

The casing-evaluation presentation includes casing ovality, eccentricity, 

hole deviation, and gamma ray in Track 1. In this instance, the eccentricity 

is composed of both tool and casing eccentricity due to formation 

movement. Track 2 shows a cross-sectional presentation of the pipe shape. 

A cross-sectional of the pipe wall is presented in Track 3. Track 4 provides 

the average, minimum, and maximum value of the pipe radius that is 

shown in Track 5. Track 6 provides the average, minimum, and maximum 

value of the pipe thickness that is the image plotted in last Track 7. On the 

image logs red shows pipe thinning while blue indicates pipe thickening. 


Features 

Allows 100 shots per depth frame measurement, 

providing complete circumferential coverage in casedhole 

cement evaluation and pipe inspection 

Near real-time evaluation of complex and lightweight 

cements is accomplished through ACE processing 

Combinable with all DITS tools. This can reduce 

rigtime when run with the M305 FWS tool for the 

cement bond log 

Simultaneous cement evaluation and casing inspection 

capability 

Real-time fluid cell measures both borehole fluid transit 

time and fluid impedance for measured data correction 

Real-time casing thickness, casing OD, and ID 


ACE processing for cement evaluation 

CASE evaluation for casing inspection 

The CAST-V tool is also useful in cement evaluation. See 

page 33 for more information on Cement Evaluation tools. 

The cement-evaluation presentation includes casing ovality and tool 

eccentricity in Track 1 along with the gamma ray. Conventional CBL 

amplitude and amplified amplitude data is presented in Track 2. Track 3 

provides the typical CBL waveform showing both pipe to cement bond 

along with cement to formation bond. Data from the CAST-V scanner 

is displayed in Tracks 4 and 5. Track 4 provides information regarding the 

average impedance of the ZP image in Track 5. Likewise a CBI is a bond 

index from the same image and provides a quick indication of the percent 

of bond. The image in Track 5 is the Z map from 0 to 360° (left to right) 

with 0° representing the high side of the hole. The center of the track is 

scaled at 180°, which represents the low side of the hole. 

CAST-V Circumferential Acoustic Scanning Tool-Visualization Specifications 

Length 

ft (m) 

17.9 

(5.5) 

Diameter 

in. (mm) 

3.63 

(92.2) 


HAL9230 


psi (Mpa) 

20,000 

(137.9) 


°F (°C) 

350 

(176.7) 

Weight 

lb (kg) 

316 

(143.3)

The FASTCAST Fast Circumferential Acoustic Scanning Tool 

The FASTCAST tool provides the same industry leading 

measurements and products for cement evaluation or pipe 

inspection as the CAST-V tool but at speeds up to five 

times faster. 

The FASTCAST tool data acquisition system is versatile and 

programmable at the wellsite, fully optimized for speed, 

based on the customer’s requirements and on the 

characteristics of the borehole. 

With a resolution improved by at the most a factor of 12 in 

pipe inspection mode, the FASTCAST tool can provide 100% 

coverage of casings up to 20-in. in diameter. 

The FASTCAST tool provides true measured full coverage 

unavailable by most other acoustic, electric, or mechanical 

devices. 

The factors that influence the logging speed are: 

Horizontal coverage 

Borehole size – smaller holes are logged faster because 

they require less shots / scan for the same amount of 

horizontal coverage 

Vertical resolutions – lower resolution implying higher 

speed 

In open hole, the FASTCAST tool provides complete 

borehole imaging for accurate, precise, formation evaluation. 

In cased-hole, ultrasonic pipe inspection and cement 

evaluation can be obtained simultaneously. 

The FASTCAST tool in cement evaluation mode is used 

primarily to determine cement bonding and image channels 

in cement directly behind casing, but it can also be used to 

measure casing characteristics such as thickness and internal 

and external diameters. Images can be oriented to either tool 

body or the high side of the hole in any operating mode. 

When combined with a CBL tool, the cement evaluation log 

can be acquired at 60 ft/min or twice as fast as previous 

generation tools, yet providing the same quality product as 

the CAST-V tool for all cement types, including foam, 

through the Halliburton proprietary ACE processing. This 

increased logging speed results in a significant reduction in 

operating cost to the operator through minimized 

unproductive rig time. 

The FASTCAST tool in pipe inspection mode is optimized to 

provide the hole coverage suited to the application. The 

vertical resolution can be the traditional 3 in. but can be 

refined down to 0.1 in. Similarly, the number of waveforms 

per scan can be adjusted to provide full horizontal coverage 

down to the beam footprint of 0.25 in. The optimum 

coverage being identified, the job planner allows the engineer 

to acquire the data at the maximum logging speed suited for 

the application. 

Other features that open a wide range of new possibilities for 

looking at details further away from the casing / cement 

interface are the user-configurable waveform length and 

sampling interval. 


HAL17810

Casing 

OD in. 

The FASTCAST Tool Specifications 

Casing Data CAST-V The FASTCAST Tool Logging Speed (ft/min) 

Casing Weight 

lb / ft 

With or Without 

CBL, 

100 shots / scan, 

4 spf 

Standalone, Full 

Horizontal Coverage 

(4 spf) 

With CBL and Full 

Horizontal 

Coverage (4 spf) 

Standalone, Full 

Horizontal and Vertical 

Coverage (12 spf) 

5.500 17 32 123 60 41 

6.000 20 32 123 60 41 

7.000 29 30 103 60 34 

9.625 43 24 82 60 27 

13.375 68 15 55 43 18 

18.625 106 9 45 45 15 

Temperature 

°F (°C) 

350 

(175) 

Pressure 

psi (kPa) 

20,000 

(137 900) 

*With interchangeable transducer head 

Tool OD 

in. (mm) 

3.625 

(92) 

Length 

in. (m) 

215 

(5.46) 

Weight 

lb (kg) 

316 

(143) 

Min Hole ID 

in. (mm) 

Max Hole ID* 

in. (mm) 

Vertical 

sampling 

in. 

Logging 

speed 

ft/min 


4.25 

(108) 

22.00 

(559) 0.1 to 3.0 60 typical

Cement Evaluation 

Cement Bond Log (CBL) 

Cement bond tools (CBT) are sonic logging tools that have 

one omni-directional transmitter and two omni-directional 

receivers. Cement bond log tools are used to evaluate the 

effectiveness of cementing operations. 

The transit time measurement of the acoustic signal at the 

3-ft receiver is used for two purposes: verification of the 

centralization of the CBL in free, non-bonded casing; and to 

identify fast formations in acoustically bonded intervals. In 

other than fast formations or free pipe, the transit time 

measurement is undefined. 

Correlation of the waveform data with other petrophysical 

measurements, such as gamma ray, porosity, or resistivity 

data, are used to identify the acoustic coupling of the cement 

to both the casing and formation. ACE advanced waveform 

processing methods can be used for concentric casing string 

evaluation. 

Cement bond logging tools come in a number of different 

tool diameters, pressure, and temperature ratings. Small 

diameter CBL tools are available for both through-tubing 

logging operations and small diameter casing completions. 

Applications 

Measuring the attenuation of the acoustic energy in the 

casing-to-cement interface 

Evaluating the cement-to-formation coupling by the 

correlation of the waveform data to other petrophysical 

measurements 

Indicating channels or intervals with only a partial bond 

Locating free pipe and top of cement 

Evaluating the mud displacement processes 

This log example illustrates nearly free pipe, an apparent top of cement 

around X80, and below Y26 it is well bonded. Track 1 consists of the 

gamma ray for correlation and travel time which is used for quality 

control. Track 2 consists of the amplitude curve and amplified amplitude 

which indicates cement to casing bond. Track 3 consists of the CBL 

waveform which indicates both casing to cement bond along with 

cement to formation bond. Straight lines in the CBL waveform along 

with high amplitude readings indicate poor cement to casing bond. 


HAL9231

Features 

Runs in combination with a gamma ray and a collar 

locator for depth correlation purposes 

Optional neutron correlation logs can be used in 

formations where there is minimal gamma ray contrast 

Digital telemetry versions are combinable with the 

CAST-V tool for simultaneous ultrasonic cement and 

casing evaluation 

CBL tools are available that can be run on all types of 

wireline from large diameter 0.9375-in. slammer heptacables 

to 0.22-in. sour gas service monoconductor cables 

Sonde 

FWST-A 

Full Wave Sonic Tool 

HFWS-A Hostile Full 

Wave Sonic Tool 

*6 hour 

Length 

ft (m) 

20.4 

(6.2) 

30.2 

(9.2) 

Cement Bond Log (CBL) Specifications 

Diameter 

in. (mm) 

3.63 

(92.2) 

2.75 

(69.9) 

Cement sheath evaluation in a wide range of casing sizes 

from small diameter tubing to over 20-in. casing 

Accurate correlation to open-hole measurements 

Digital recording of the waveform data for real-time data 

transmission and advanced interpretational methods 


psi (Mpa) 

20,000 

(137.9) 

25,000 

(172.4) 


°F (°C) 

350 

(176.7) 

500* 

(260.0) 

Weight 

lb (kg) 

365 

(165.6) 

340 

(154.2) 


Radial Cement Bond Tools 

Cement bond tools (CBT) are sonic logging tools that have 

one omni-directional transmitter and two omni-directional 

receivers. In addition, the radial cement bond log (RCBL) 

tool has eight radial receivers and the RCBS tool has six. 

Radial cement bond tools are used to evaluate the 

effectiveness of cementing operations. 

The transit time measurement of the acoustic signal at the 

3-ft receiver is used for two purposes—to verify the 

centralization of the radial cement bond tool in free, nonbonded 

casing, and to identify fast formations in acoustically 

bonded intervals. In other than fast formations or free pipe, 

the transit time measurement is undefined. 

Correlation of the waveform data with other petrophysical 

measurements, such as gamma ray, porosity, or resistivity 

data is used to identify the acoustic coupling of the cement to 

both the casing and formation. ACE advanced waveform 

processing methods can be used for concentric casing string 

evaluation. 

Applications 

Indicating channels or intervals using radial receivers 

Measuring the attenuation of the acoustic energy in the 

casing to cement interface 

Evaluating the cement to formation coupling by the 

correlation of the waveform data to other petrophysical 

measurements 

Locating free pipe and top of cement 

Evaluating the mud displacement processes 

Results from a specially designed test well for the RCBL and RCBS tools. 


HAL9232

Features 

It runs in combination with a gamma ray and a collar 

locator for depth correlation purposes 

Optional neutron correlation logs or DSN dual-spaced 

neutron tool logs can be used in formations where there 

is minimal gamma ray contrast 

DSN tool can be run for formation evaluation 

It can be run on all types of wireline from large diameter 

0.9375-in. slammer hepta-cables to 0.22-in. sour gas 

service monoconductor cables 

Sonde 

RCBS 

RCBS-P1 

RCBS-P2 

RCBL 

HTHP* 

Length 

ft (m) 

15 

(4.57) 

13.12 

(4) 

8.75 

(2.68) 

13.83 

(4.23) 

13.175 

(4.2) 

With 

Centralizers 

ft (m) 

21.6 

(6.58) 

17.72 

(5.4) 

13.15 

(4) 

20.43 

(6.23) 

Radial Cement Bond Tool Specifications 

OD 

in. (cm) 

1.69 

(4.29) 

1.69 

(4.29) 

2.75 

(6.98) 

3.125 

(7.94) 

3.125 

(7.94) 

Maximum 

Pressure 

psi (Mpa) 

20,000 

(137.9) 

20,000 

(137.9) 

20,000 

(137.9) 

20,000 

(137.9) 

30,000 

(206.8X) 

Maximum 

Temperature 

°F (°C) 

350 

(176.68) 

450 

(232) 

350 

(176.68) 

375 

(190) 

400 

(204.4) 

Cement sheath evaluation in a wide range of tubing or 

casing sizes from small diameter tubing to 13.38-in. 

casing, including channel identification 

Accurate correlation to open-hole measurements 

Digital recording of the waveform data for real-time data 

transmission and advanced interpretational methods 

Weight 

lb (kg) 

75 

(34) 

78 

(35.38) 

106.5 

(48.31) 

215 

(97.5) 

151.65 

(68.79) 

*Supplies are limited. Please contact your local Halliburton representative for more information. 

Maximum 

Casing 

in. (cm) 

7.5 

(19) 

7 

(17.78) 

9.625 

(24.45) 

13.38 

(33.98) 

13.4 

(34) 

Minimum 

Casing 

in. (cm) 

2 

(5.1) 

2.875 

(7.3) 

4 

(10.16) 

3.75 

(9.53) 

3.75 

(9.53) 

Borehole Fluids 

Salt Fresh Oil Air 

X X X 

X X X 

X X X 

X X X 

X X X 


ACE Advanced Cement Evaluation Process 

The ACE advanced cement evaluation process helps 

provide quick, accurate information concerning cement 

bond for all standard logging tools and procedures for any 

type of cement mixtures, including foam, latex, and other 

complex slurries. 

Traditional cement sheath interpretation, using the standard 

cement bond log (CBL) or any other cement evaluation tool 

has severe limitations when used to evaluate complex 

cements. Lightweight, foamed, or complex cements affect the 

traditional methods of determining zonal isolation, which 

may create the misleading impression that the cement bond 

is inadequate. This can lead to the ordering of expensive and 

completely unnecessary remedial cementing. 

The ACE process is a new way of interpreting the cement 

evaluation tool data that is already being recorded during the 

logging runs. Although the ACE process was originally 

developed for lightweight cements, experience and 

experiments have shown that it provides a superior method 

for interpreting any type of cement. Above all it gives clear 

answers to the most urgent questions: 

How good is my zonal isolation? 

Do I need a squeeze job? 

The ACE process yields its greatest benefit when evaluating 

both the cement to pipe bond and the cement to formation 

bond. To properly evaluate the cement to casing bond, the 

FASTCAST and CAST-V ultrasonic tools along with the 

ACE process provide the best solution. However, both 

segmented and radial bond tools can be evaluated with the 

ACE process and still provide excellent information 

regarding the cement to pipe bond. 

The CBL and other sonic tools are used to determine the 

cement to formation bond along with the cement to casing 

bond. The ACE process uses the sonic waveforms to 

highlight the differences between bonded, partially bonded, 

micro-annulus, and free pipe. The ACE process can help 

determine the presence of cement between two casing 

strings, which was extremely difficult to quantify with 

previous logs and/or interpretation procedures. 

These extraordinary results are the product of a new 

technique based on a statistical-variation process to 

distinguish cement from fluid, even when both have the same 

raw value. This process actually will use two different 

methods to determine zonal isolation—the original tool data 

and the activity level of the data. Through this process, the 

activity level is determined and will allow easy differentiation 

between solids and fluids. In addition, new bond-index 

curves and special log presentations have been developed to 

make interpretation quick and unambiguous. 

The ACE process works on every cement evaluation tool that 

Halliburton offers as well as effectively evaluating data from 

other service companies. Not only does this method work on 

data from both the rotating (FASTCAST, CAST-V tools), 

and/or stationary ultrasonic logs (PET tool), it also provides 

detailed information using standard CBL logs, sonic logs, 

dipole sonics, segmented bond logs, and the newer 

generation of radial bond logs (RBT). 

ACE analysis has been proven effective on cementing jobs in 

all parts of the world and on every type of cement now in use. 

It saves time and money by eliminating countless 

unnecessary squeeze jobs and associated expenses. Reducing 

the amount of unnecessary remedial cement operations will 

allow the customer to reduce operational expenses and 

contribute to the bottom line. 

Features 

Uses every cement evaluation tool to provide detailed 

information about cement bond 

Works with existing logging procedures 

Enhances current logs to achieve a better understanding 

of zonal isolation 

Delivers a reliable cement bond index 

Works for any cement—conventional, complex, 

lightweight, or foam 

Helps improve cement interpretation for multiple casing 

strings 

Delivers answers in minutes on location, using your log 

or data tape 

Helps provide accurate and dependable cement bond 

interpretation regardless of the service company 

Saves time and money by helping eliminate countless 

unnecessary squeeze jobs and associated expenses 

Reduces the customer’s operational expenses and 

contributes to the bottom line by helping to eliminate 

unnecessary remedial cement operations 


Track 1 presents correlation data (GR), quality control (ECTY), and the average impedance (ZAVG) which provides a 

quick interpretation of the cement placement. Track 2 presents the amplitude (AMP), amplified amplitude (AAMP), 

filtered cement bond index (FCBI), as well as the computed cement bond index (FCEMBI). Track 3 contains a standard 

CBL waveform display (WMSG). Track 4 is the total CBL waveform (WMSGT) which is the ACE processing which 

highlights the collar response. The ultrasonic impedance map (ZP) is presented in Track 5, which indicates the impedance 

of the material behind pipe. Track 6 (DZ) is the variance of the impedance map which highlights the differences between 

solids (cement) and liquids. Track 7 (CEMT) shows the result of both the impedance and variance in determination of 

solids vs. fluids. Fluids are designated as blue, while cement is indicated by the brown color. Tracks 8 to 16 provide 5 

segmented curves from the impedance image broken into 9 segments around the wellbore. High activity indicates solids, 

and low activity indicates fluid. In the zone F notice how the curves have both low impedance and low activity compared 

to the data immediately above it in zone C. 


Mechanical Services 

Pipe Recovery 

Chemical Cutter 

Chemical cutters eject a circular stream 

of bromine trifluoride (BrF 3) to 

dissolve pipe with a clean cut that leaves 

no debris and does not require milling 

prior to pipe retrieval. Built-in 

flexibility allows the tool to be adapted 

for many special cutting applications 

where other cutting methods may be 

ineffective or undesirable. 

Chemical cutters provide a clean pipe 

cut. Chemical cutters can also shorten 

operating time and reduce rig costs by 

eliminating the flare associated with 

explosive cutters and the related need to 

dress flares with a mill run before 

fishing operations can start. 

Additionally, chemical cutters can be 

used to release specially designed 

permanent packers such as 

Halliburton’s AHR cut-to-release 

packer. They can be used to cut pipe 

and casing during plug and 

abandonment operations, sever duplex- 

22 nickel/chromium tubing or other 

high-grade tubulars for salvage or 

reuse, and replace or retrieve old or 

deteriorating pipe in environmentally 

sensitive areas. 

Applications 

Re-establishing circulation during 

drilling operations by chemically 

punching drill collars or heavy 

weight pipe 

Removing metal restrictions 

blocking the well in open or cased 

holes with downward chemical junk 

shot 

Cutting drillpipe after freepoint and 

backoff operations when sensitive 

washover and fishing operations are 

anticipated 

Cutting large pipe (7-in. or larger 

OD) utilizing a special wagon wheel 

configuration 

Using chemical cutter/tubing 

hanger combination in high 

pressure situations when normal 

operations may cause pipe to drop 

after being cut 

Cutting standard-diameter pipe 

through normal restrictions 

Shooting large holes in tubulars for 

gravel pack production 

Chemical cutters require the following 

inputs or samples to perform properly: 

Well sketch 

Type of pipe to be cut (ID, OD, 

metal composition, any plastic 

coatings) 

Any other restrictions or problems 

Temperature and pressure at cutting 

depth 

Type of fluid in the well, including 

any solvents or paraffins in the well 

Any other ID restrictions above the 

depth to be cut 

Features 

Standard cutting head sizes from 

0.75-in. to 5.5-in. OD 

Unique holddown system to 

centralize the tool for even cuts 

without damaging pipe 

Deployment via electric wireline, 

coiled tubing, rigid tubing, or 

slickline 

Can pass through normal 

restrictions and still make a clean 

cut on standard size tubulars below 

the restriction 

Performs under a wide range of 

temperatures, pressures, and depths 

Produces no debris or drillpipe 

deformation which might require 

milling 

Does not damage adjacent string 

during cutting 

Severs pipe flare-free for retrieval 

through a packer or other 

restriction 

Does not change ID or OD of the 

cut 

Capable of cutting high-grade 

tubulars 

Specially designed slip assembly 

maintains mechanical tool stability 

and helps ensure that pieces of 

metal are not ejected from the tool 

in case of accidental firing 

Manufacture from high-grade, heat 

treated steel that will not rupture 

even if tool is accidentally fired at 

the surface 

Unique safety sleeve that virtually 

eliminates possibility of exposing 

the cutting head to operators and 

equipment 

Guiding rope system that helps 

ensure personnel are always at a safe 

distance from the tool when it is 

being placed into or removed from 

the well 

Safety features based on worst-case 

scenarios and tested under actual 

conditions to help provide quick 

responses to any situation 


Caution: Prior to every chemical cutter job, Halliburton 

strongly recommends checking for restrictions in the well by 

performing a gauge run and string shot. 

Tool Size in. 

(Anchor And Sev Head) 

Halliburton’s chemical cutter supplier is Pipe Recovery 

Systems Inc. (PRS). 

Selection Guide for Coiled Tubing Chemical Cutter 

Tool Specifications Coiled Tubing Specifications 

Max. Extension 

of Wedges/Slips in. 


OD 

in. 

ID 

in. 

Weight 

lb/ft 

*11/16 0.92 1 0.782 - 0.810 0.918 - 1.037 

*3/4 1.05 1 0.826 - 0.866 0.688 - 0.848 

*13/16 1.09 1 1/4 0.938 - 1.076 1.081 - 1.823 

*7/8 1.11 1 1/4 1.032 - 1.076 1.081 - 1.328 

*15/16 1.15 1 1/4 1.100 - 1.116 0.840 - 0.941 

*1 1.33 1 1/2 1.188 - 1.282 1.619 - 2.239 

*1 1/16 1.35 1 1/2 1.188 - 1.282 1.619 - 2.239 

*1 1/8 1.42 1 1/2 1.282 - 1.334 1.256 - 1.619 

*1 3/16 1.51 1 3/4 1.374 - 1.500 2.169 - 3.136 

*1 1/4 1.61 1-3/4 1.400 - 1.532 1.910 - 2.944 

1 3/8 1.80 2 1.594 - 1.688 3.072 - 3.896 

1 1/2 2.04 2 1.732 - 1.782 2.201 - 2.671 

1 11/16 2.20 2 3/8 1.969 - 2.025 4.112 - 4.709 

1 7/8 2.55 2 3/8 2.063 - 2.157 2.638 - 4.709 

2 1/8 2.60 2 7/8 2.469 - 2.563 4.530 - 5.793 

2 5/8 

* Denotes wedge type anchor 

3.35 3 1/2 3.094 - 3.150 6.215 - 7.148 

Tool Size 


Selection Guide for CS Hydril Tubing 1.050 - 1.660 OD 

Tool Specifications 

in. Tubing Specifications 


of Wedges/Slips 

OD 

in. 

ID 

in. 

Weight 

lb/ft 

*11/16 0.92 1.05 0.824 1.200 

*3/4 1.05 1.315 0.957 2.250 

*13/16 1.09 1.315 1.049 1.800 

*1 1/16 1.35 1.660 1.278 3.020 

*1 3/16 

* Denotes wedge type anchor 

1.51 1.660 1.380 - 1.410 2.100 - 2.400

Tool Size 


in. 

* 6-slip anchor only 

Selection Guide — Tubing for D/A Chemical Cutter 

Tool Specifications Tubing Specifications 


of Wedges/Slips 

in. 


OD 

in. 

ID 

in. 

Weight 

lb/ft 

1 3/8 1.80 1.90 1.500 - 1.650 2.40 - 3.64 

1 1/2 2.04 

2 1/16 1.670 - 1.751 3.25 - 3.40 

2 3/8 1.703 - 1.995 4.70 - 7.70 

1 9/16 2.10 2 3/8 1.853 - 1.995 4.70 - 6.20 

1 11/16 2.20 2 3/8 1.939 - 1.995 4.70 - 5.30 

1 3/4 2.50 2 7/8 2.059 - 2.441 6.50 - 10.70 

1 7/8 2.55 2 7/8 2.059 - 2.441 6.50 - 10.70 

2 2.58 2 7/8 2.195 - 2.441 6.50 - 9.50 

2 1/8 2.60 2 7/8 2.323 - 2.441 6.50 - 7.90 

2 E.R. 2.85 3 1/2 2.480 - 2.750 12.95 - 16.70 

2 1/8 E.R. 3.10 3 1/2 2.480 - 2.992 9.30 - 16.70 

2 3/16 3.10 3 1/2 2.480 - 2.992 9.30 - 16.70 

2 1/4 3.15 3 1/2 2.602 - 2.992 9.30 - 15.50 

2 3/8 3.25 3 1/2 2.602 - 3.068 7.70 - 15.50 

*2 5/8 3.35 3 1/2 2.922 - 3.068 7.70 - 10.30 

*2 7/8 3.65 4 3.240 - 3.476 11.00 - 15.70 

*3 1/8 3.92 4 3.340 - 3.548 9.50 - 14.00 

*3 1/4 4.04 4 1/2 3.640 - 3.958 12.60 - 20.00 

*3 3/8 4.16 4 1/2 3.697 - 4.000 11.60 - 17.70 

*3 1/2 4.28 4 1/2 3.826 - 4.090 9.50 - 15.50 

*3 5/8 4.40 4 1/2 3.920 - 4.090 9.50 - 13.50 

*3 7/8 4.68 5 4.154 - 4.408 15.00 - 21.00 

*4 4.80 5 4.276 - 4.560 11.50 - 19.50 

*4 3/16 4.92 5 1/2 4.548 - 4.778 20.00 - 26.00 

*4 7/16 5.14 5 1/2 4.670 - 4.950 15.50 - 23.00 

*4 9/16 5.14 5 1/2 4.892 - 5.044 13.00 - 17.00 

5 1/2 6.50 7 6.004 - 6.214 28.00 - 35.00 

5 3/4 6.50 7 6.276 - 6.456 20.00 - 26.00 

6 3/8 7.37 7 5/8 6.765 - 7.125 20.00 - 33.70

Tubing Cutters 

Jet Research Center’s tubing cutters are designed to cleanly 

sever a wide range of tubing quickly and efficiently. These 

proven design cutters are the world’s most widely used and 

have a performance record that is unsurpassed. The tubing 

cutter range includes industry-leading ceramic cap designs 

for minimum debris to economic cast iron versions for costeffective 

solutions. JRC tubing cutters offer high reliability in 

field applications with a minimum amount of set-up or 

configuration based on well parameters. JRC tubing cutters 

and method of assembly are patented technology (US Patent 

5,129,322). Tubing cutters can be used with JRC’s 

proprietary RED® rig environment detonator, offering a high 

level of protection against stray voltage or inadvertent RFinitiation. 

Features 

High strength ceramic cap provides 20,000 psi pressure 

rating 

Breakup characteristic of the ceramic design leaves 

minimal debris in the well 

Cutter design features minimum flare characteristic for 

ease of recovery 

Extensive cutter range offers selection based on well 

conditions 

Cutters available for high strength and chrome material 

Special designs available to match unique well conditions 

Detonator options available to satisfy all applications 



HAL11763

Tubing 

OD in. 

2 1/16 

2 3/8 

2 3/8 

2 3/8 

2 3/8 

2 3/8 

2 7/8 

2 7/8 

2 7/8 

2 7/8 

2 7/8 

2 7/8 

3 1/2 

3 1/2 

3 1/2 

3 1/2 

Description Part No. 

1 9/16-in. 

Tubing Cutter 

1 11/16-in. 

Tubing Cutter 

1 11/16-in. 

Tubing Cutter 

(Cast Iron) 

1 23/32-in. 

Tubing Cutter 

1 13/16-in. 

Tubing Cutter 

1 13/16-in. 

Tubing Cutter 

(Cast Iron) 

2 1/32-in. 

Tubing Cutter 

2 1/8-in. 

Tubing Cutter 

2 1/8-in. 

Tubing Cutter 

(Cast Iron) 

2 1/8-in. 

Hastelloy 

Tubing Cutter 

2 1/4-in. 

Tubing Cutter 

2 1/4-in. 

Tubing Cutter 

(Cast Iron) 

2 1/2-in. 

Tubing Cutter 

(Cast Iron) 

2 19/32-in. 

Tubing Cutter 

2.70-in. 

Tubing Cutter 

2.70-in. 

Hastelloy 

Tubing Cutter 

Cutter OD 

in. 

Rating 

psi / °F 


Explosive 

weight g 

Housing 

Material 

100083086 1.563 15,000/400 4 Ceramic 

100000352 1.688 20,000/400 8.5 Ceramic 

101288527 1.688 12,500/400 8.5 Cast Iron 

100000570 1.719 20,000/400 8.5 Ceramic 

100000353 1.813 20,000/400 8.5 Ceramic 

101290400 1.813 12,500/400 8.5 Cast Iron 

100000354 2.031 20,000/400 15.4 Ceramic 

100000355 2.125 20,000/400 15.4 Ceramic 

101290402 2.125 12,500/400 15.4 Cast Iron 

100000430 2.125 20,000/400 33 Ceramic 

100000356 2.250 20,000/400 13 Ceramic 

101290405 2.250 12,500/400 13 Cast Iron 

101290406 2.500 12,500/400 22.5 Cast Iron 

100116367 2.594 20,000/400 22.5 Ceramic 

100011034 2.700 20,000/400 22.5 Ceramic 

100000431 2.700 20,000/400 46 Ceramic 

Shipping 

Class 

1.4S 

UN0441 

1.4S 

UN0441 

1.4S 

UN0441 

1.4S 

UN0441 

1.4S 

UN0441 

1.4S 

UN0441 

1.4S 

UN0441 

1.4S 

UN0441 

1.4S 

UN0441 

1.1D 

UN0059 

1.4S 

UN0441 

1.4S 

UN0441 

1.4S 

UN0441 

1.4S 

UN0441 

1.4S 

UN0441 

1.1D 

UN0059 

Recommended Target Tubing 

Grade Wall Th 

(Incl 

Coupl.) lb/ft 

P105 0.216 3.25 


P105 

P105 

P105 

P105 

P105 

0.190 - 

0.254 

0.190 - 

0.254 

0.190 - 

0.254 

0.190 - 

0.254 

0.190 - 

0.254 

4.70 - 5.95 

4.70 - 5.95 

4.70 - 5.95 

4.70 - 5.95 

4.70 - 5.95 

P105 0.308 6.50 - 8.70 

P105 0.217 6.50 

P105 0.217 6.50 

Chrome 0.276 7.90 

P105 0.217 6.50 

P105 0.217 6.50 

P105 

P105 

P105 

Chrome 

0.254 - 

0.449 

0.254 - 

0.289 

0.254 - 

0.289 

0.254 - 

0.289 

9.3 - 15.50 

9.30 - 10.30 

9.30 - 10.30 

9.30 - 10.30

Super Tubing Cutters 

Jet Research Center’s super tubing cutters are designed where 

well conditions prevent the use of a conventional tubing 

cutter based on unexpected or severe restrictions. In this 

situation, a specially designed cutting charge is used. The 

cutter is based on a conventionally shaped charge assembly 

but has additional explosive in the form of a pelletized charge 

in the base of the cutter. It is a smaller diameter than a 

conventional charge for the pipe to be cut. The cutter can 

easily pass through tight restrictions and still achieve 

severance. Based on the design constraints, some tubing 

deformation at the cut point is likely with this cutter. Super 

tubing cutters can be used with JRC’s proprietary RED® rig 

environment detonator, offering a high level of protection 

against stray voltage or inadvertent RF initiation. 

Features 

High strength steel cap provides 20,000 psi pressure 

rating 

Reduced diameter easily passes wellbore restrictions 


Two cutter sizes for common tubing sizes 




HAL11763

Tubing 

OD in. 

2 3/8 

2 7/8 


1 9/16-in. Super 

Cutter 

1 13/16-in. 

Super Cutter 

100005493 

+100158162 

100008057 

+100158161 

Cutter OD 

in. 


Rating 

psi / °F 

Explosive 

weight g 

Housing 

Material 

(S-Steel) 

1.563 20,000/400 40 S 

1.813 20,000/400 40 S 

Accessories 

Shipping 

Class 

1.4S 

UN0441 

1.4S 

UN0441 


Grade Wall Th 

(Incl 

Coupl.) lb/ft 


N80 

N80 

0.190 - 

0.254 

0.217 - 

0.308 

Tubing Cutter Accessories HP Accessories Safety Accessories 

Detonator - Resistorized 100000432 Extension Mandrel - Steel 101293227 Shunt Plug 100010861 

Firing Head, 1 1/2-in. OD 100000434 Adapter for RED - Steel 101293230 Safety Tube 100010862 

Extension Mandrel 100008258 

Detonator - RED ® 

101272595 

Adapter for RED Detonator 101293676 

Notes: 

1. Undersized cutters may not make a full cut. 

2. Always run effective centralization for optimum results. 

3. Field assembly required due to shipping features. 

4. CAUTION: Not recommended for casing sizes less than 7 in. 

4.70 - 5.95 

6.50 - 8.70

Coiled Tubing Cutters 

Jet Research Center’s coiled tubing cutters are designed to 

cleanly sever common sizes of tubing quickly and 

economically. These proven design cutters are widely used 

and have an unsurpassed performance record. 

Features 

High strength steel components allow successful trip 

inside the coiled tubing 

Corrosion resistant components 

Cutters sizes available for 1, 1.25, 1.5 and 1.75-in. coiled 

tubing 

13.75-in. cutter suitable for cutting 1.5-in. (1.900) NU 

API tubing 

Compatible with industry standard wireline accessories 

Can be designed with high temperature explosives for 

special applications 



HAL11764

Tubing 

OD in. 

1.00 

1.25 

1.50 

1.75 

1.90 


0.718-in. Coiled 

Tubing Cutter 

0.948-in. 

Coiled Tubing 

Cutter 

1 3/16-in. 

Coiled Tubing 

Cutter 

1 3/8-in. 

Tubing Cutter 

1 3/8-in. 

Tubing Cutter 

Cutter OD 

in. 


Rating 

psi / °F 

Explosive 

weight g 

Housing 

Material 

(S-Steel) 

100118388 0.718 10,000/325 1 S 

100118389 0.948 10,000/325 2.9 S 

100000429 1.188 10,000/325 4.7 S 

100000569 1.375 15,000/400 4 S 

100000569 1.375 15,000/400 4 S 

Accessories 

Shipping 

Class 

1.4S 

UN0441 

1.4S 

UN0441 

1.4S 

UN0441 

1.4S 

UN0441 

1.4S 

UN0441 

Accessories Safety Accessories 


Grade Wall Th 

Weight 

(Incl 

Coupl.) lb/ft 

N80 0.081 0.786 

N80 0.095 1.172 

N80 0.109 1.619 

N80 0.134 2.313 

P105 0.145 2.900 

Detonator - Resistorized 100010855 Safety Tube for Detonator 100158234 

5/8-in. OD Cont Sub (1.59 cm) 100005498 0.5-20 UNF-2A (thread) 5/8-in. Shunt Plug 100158235 

3/4-in. OD Cont Sub (1.91 cm) 100158243 0.555-28P-36-SA (thread) 3/4-in. Shunt Plug 120042542 

1-in. OD Cont Sub (2.54 cm) 100014497 0.812-16 UN-2A (thread) 1-in. Shunt Plug 120042541 

Notes: 



3. When more than one cutter is available for the specification, always select the largest diameter cutter. 


Casing and Drillpipe Cutters 

Jet Research Center’s casing and drillpipe cutters feature the 

same level of engineering detail and design as the industryleading 

JRC tubing cutters. They are designed to cleanly sever 

a wide range of casing efficiently, using a minimum amount 

of explosive. The designs feature high specification 

aluminum alloy case material that breaks up substantially 

upon detonation. JRC casing and drillpipe cutters offer high 

levels of safety and reliability in field applications with a 

minimum amount of set-up or configuration based on well 

parameters. JRC developed the industry standard shock 

attenuating mandrel for use with the range of casing and 

drillpipe cutters and patented this technology (US patent 

5,117,911). Casing and drillpipe cutters can be used with 

JRC’s proprietary RED® rig environment detonator, offering 

a high level of protection against stray voltage or inadvertent 

RF-initiation. 

Features 

Shock attenuating mandrel helps protect associated 

wireline tools 

Cutter designed for minimum pipe flare 

Extensive cutter range offers selection based on well 

conditions 

Cutters available for high-strength and chrome pipes 



Casing and Drillpipe Cutters 


HAL11765

Tubing 

OD 

in. 

3 1/2 DP 

4 

4 1/2 DP 

4 1/2 DP 

5 DP 

4 1/2 

5 

5 DP 

5 1/2 

5 1/2 

5 3/4 

6 

6 5/8 

6 5/8 

7 

7 

7 5/8 

8 5/8 

9 5/8 


2 3/8-in. Drill 

Pipe Cutter 

2 15/16-in. Drill 

Pipe Cutter 

2 5/16-in. Drill 

Pipe Cutter 

3 15/16- in. 

Drill Pipe Cutter 

3 5/16-in. 

Drill Pipe Cutter 

3 5/8-in. 

Casing Cutter 

4-in. 

Casing Cutter 

4-in. 

Casing Cutter 

4 1/2-in. 

Casing Cutter 

4 3/4-in. 

Casing Cutter 

4 3/4-in. 

Casing Cutter 

5 3/8-in. 

Casing Cutter 

5 3/8-in. 

Casing Cutter 

5 1/2-in. 

Casing Cutter 

5 1/2-in. 

Casing Cutter 

6- in. 

Casing Cutter 

6 1/8-in. 

Casing Cutter 

7 1/4-in. 

Casing Cutter 

8 3/16-in. 

Casing Cutter 

Cutter OD 

in. 

Wafer Casing Cutters (1.1D) 

Rating 

psi / °F 

Explosive 

Weight g 

Housing 

Material 

(S-Steel, 

A-Aluminum) 

100116368 2.375 12,500/400 22 S/A 

100127821 2.938 7,500/400 47.4 A 

100127821 2.938 7,500/400 47.4 A 

100000140 3.313 7,500/400 61 A 

100000140 3.313 7,500/400 61 A 

101293449 3.625 7,500/400 54 A 

101293457 4.000 9,000/400 110 S/A 

101293457 4.000 9,000/400 110 S/A 

100014494 4.500 9,000/400 104 S/A 

101293484 4.750 9,000/400 100 S/A 

101293484 4.750 9,000/400 100 S/A 

101293491 5.375 9,000/400 240 S/A 

101293491 5.375 9,000/400 240 S/A 

101293515 5.500 9,000/400 253 A 

101293515 5.500 9,000/400 253 A 

101293536 6.000 9,000/400 280 A 

101293544 6.125 9,700/400 253 A 

101293553 7.250 8,000/400 373 A 

101293555 8.188 8,000/400 407 A 

Accessories 

Shipping 

Class 

1.4S 

UN0441 

1.1D 

UN0059 

1.1D 

UN0059 

1.1D 

UN0059 

1.1D 

UN0059 

1.1D 

UN0059 

1.1D 

UN0059 

1.1D 

UN0059 

1.1D 

UN0059 

1.1D 

UN0059 

1.1D 

UN0059 

1.1D 

UN0059 

1.1D 

UN0059 

1.1D 

UN0059 

1.1D 

UN0059 

1.1D 

UN0059 

1.1D 

UN0059 

1.1D 

UN0059 

1.1D 

UN0059 


Grade Wall Th 

Weight (Incl 

Coupl.) lb/ft 


G105 

L80 

G105 

0.254 - 

0.449 

0.262 - 

0.380 

0.271 - 

0.430 

9.5 - 15.5 

11.85 - 

15.7 

13.75 - 

20.00 

G105 0.430 20.00 

G105 

L80 

L80 

G105 

L80 

L80 

L80 

L80 

0.296 - 

0.500 

0.205 - 

0.337 

0.253- 

0.437 

0.296 - 

0.362 

0.304 - 

0.415 

0.244 - 

0.304 

0.330 - 

0.430 

0.224 - 

0.275 

16.25 - 

25.60 

9.50 - 

15.10 

11.50 - 

21.40 

16.25 - 

19.50 

17.00 - 

23.00 

14.00 - 

17.00 

19.50 - 

25.20 

14.00 - 

17.00 

L80 0.475 32.00 

L80 

L80 

L80 

L80 

L80 

L80 

0.228 - 

0.417 

0.408 - 

0.540 

0.317 - 

0.408 

0.375 - 

0.500 

0.400 - 

0.595 

0.435 - 

0.545 

Tubing Cutter Accessories HP Accessories Safety Accessories 

Detonator - Resistorized 100000432 Extension Mandrel - Steel 101293227 Shunt Plug 100010861 

Adapter for Resistorized Detonator 100014468 

Adapter for Resistorized 

Detonator - Steel 

Firing Head, 1 1/2-in. OD 100000434 Adapter for RED - Steel 101295134 

Extension Mandrel 100008258 

Detonator - RED ® 

101272595 

Adapter for RED Detonator 101295128 

Notes: 



3. When more than one cutter is available for the specified target, always select the largest diameter cutter. 

20.00 - 

28.00 

29.00 - 

38.00 

23.00 - 

29.00 

29.70 - 

39.00 

36.00 - 

52.00 

43.50 - 

53.50 

101293240 Safety Tube 100010862

C-4 Casing Cutters 

Jet Research Center’s C-4 casing cutters are designed to allow 

air transportation (via commercial aircraft) of the explosives 

in individual packages. Air freight allows for rapid shipment 

of urgently needed cutters and is considerably less expensive 

than transportation by sea. Upon arrival at the location, the 

explosive can then be placed in the cutter body and run in 

the well. 

The C-4 cutters then function as traditional cutters, except 

for their reduced temperature limitation. This product line 

uses the same safe-arming procedures as the popular tubing, 

drillpipe, and normal casing cutters. It allows the detonator 

to be electronically connected safely before the detonator is 

placed in proximity to the cutting charge. 

Applications 

Emergency situation where cutter must be flown 

to wellsite 

Temperature limitation of 225°F 

Pressure limitations depend on the size of the cutter 

Features 

Patented shock absorber mandrel helps protect CCLs 

and other associated hardware 

Aluminum case components allow easy breakup of 

components into debris 

Detonation options available to satisfy all applications 

Available in sizes to cut 4.5-in. to 9.625-in. casing 

Upon request, test shots can be made in special pipe to 

verify performance 

C-4 Casing Cutters 


HAL11765

Drill Collar Severing Tool 

Jet Research Center developed the dual end severing tool for 

severing thick wall tubulars over 20 years ago. The technique 

is based on the colliding shock wave principle. Since its 

inception, the drill collar severing tool has been continuously 

refined, resulting in the industry-leading severance device for 

cutting drill collars and drillpipe in a wide variety of stuck 

pipe scenarios. The latest refinement to the tool has resulted 

in a standard explosive column length with superior 

performance. The secret to the success of the tool lies in the 

precisely-timed detonation of two equal and opposing shock 

fronts. The colliding shock is matched to a cartridge 

assembly at the mid-point of the assembly, designed to help 

focus the energy transmitted to the target. JRC developed the 

industry standard shock attenuating mandrel for use with 

drill collar severing tools and patented this technology (US 

patent 5,117,911). Drill collar severing tools can be used with 

JRC’s proprietary RED® rig environment detonator, offering 

a high level of protection against stray voltage or inadvertent 

RF initiation. 

Applications 

Cutting drill collars and drillpipe in situations involving 

stuck pipe 

Features 

Redesigned in 2002 for maximum performance 

Full range of sizes for virtually any severing requirement 

Suitable for hostile environment up to 400°F, 20,000 psi 

Higher temperature tools available for extreme 

temperature application 

Shock attenuating mandrel helps protect wireline tools. 

Quick assembly and deployment 

Industry standard connections can be run on any 

wireline unit 

Air freight classification (1.4s) provides rapid 

mobilization 

Drill Collar Severing Tool 


HAL11766

Tool OD 

in. (cm) Temperature and Pressure Rating 

1 3/8 

(3.5) 

1 3/4 

(4.4) 

2 

(5.1) 

2 5/8 

(6.7) 

HMX - 400°F (204°C) 

20,000 psi (138 Mpa) for 1 hour* 

HNS - 475°F (246°C) 


HMX - 400°F (204°C) 


HNS - 475°F (246°C) 


HMX - 400°F (204°C) 


HNS - 475°F (246°C) 


HMX - 400°F (204°C) 


HNS - 475°F (246°C) 


Drill Collar Capability Chart 

Length 

in. 

Designed to 

Sever up to 

in. 

Explosive Pellet 

Weight 

g 

Cartridge 

Assembly 

Explosive 

Weight 

g 

Loaded Tool 

Weight 

g 

36 3 1/2 OD DCs 20.7 × 28 pellets 4.8 × 2 589.2 

36 6 1/2 OD DCs 22.7 × 44 pellets 12.7 × 2 1024.2 

36 8 OD DCs 22.7 × 64 pellets 17.4 × 2 1487.8 

36 11 OD DCs 21.5 × 110 pellets 28.5 × 2 2422.1 

* For high pressure application, in excess of 15,000 psi, JRC recommends the use of high pressure steel rated accessories. 


Junk Shot 

Jet Research Center’s junk shots have been field proven time 

after time in a wide variety of applications all over the world. 

The junk shot charge has been used to overcome some of the 

most challenging fishing operations encountered, ranging 

from breaking up complete drilling bits to underreamer 

arms. The junk shot is a large downward shooting shaped 

charge secured inside a pressure housing.When placed on top 

of the junk, it functions in a similar manner as a perforating 

charge, but the explosive effect is substantially greater with 

the ability to destroy large targets. In almost any situation, 

the use of the junk shot charge to break up obstacles 

downhole reduces costly fishing time, returning the rig to full 

operation. 

Applications 

Break up obstacles downhole and return rig to full operation 

Features 

Main charge run on wireline, drillstring, or tubing with a 

secondary wireline initiator for maximum effect 

Two sizes of charge available: 5.25-in. OD and 7.75-in. OD 

Tools may be clustered for special applications 

Can be transported via air charter or standard ground 

services 

Pressure rated to 18,000 psi 

Temperature rated to 400°F for one hour 

Offers a high degree of safety due to its two-stage 

deployment 

Offers a safe assembly method through the use of JRC’s 

safe arming equipment 

Can be run on wireline or tubing 

Can be fired electronically or hydraulically 

Junk Shot 


HAL11767

Plug Setting Equipment 

EZ Drill ® Bridge Plugs 

EZ Drill® bridge plugs consist of an EZ Drill SV packer from 

which the sliding valve has been removed and a bridging plug 

has been added. This combination offers excellent downhole 

pressure control and drillability. 

Applications 

Downhole pressure control and drillability 

Features 

Built from cast iron, brass, aluminum, and rubber 

Ability to be set on: 

– Electric wireline 

– Slickline 

–Coiled tubing 

– Jointed pipe with a mechanical or hydraulic 

setting tool 

Can be used with conventional tricone bits or junk-style 

mills 

EZ Drill® Bridge Plug 


HAL9254

Fas Drill ® Bridge Plugs 

The Fas Drill® bridge plug allows oil and gas operators to run 

multiple drillable bridge plugs in a well for stimulation and 

workover operations, then drill out in one fast, easy 

operation. 

Fas Drill bridge plugs are used in a manner similar to 

conventional, drillable bridge plugs and can be set on tubing, 

on drillpipe, or with conventional tools, such as electric 

wireline. An adaptor kit is required for setting tools. Setting 

equipment and operation are identical for both versions. 

Standard Fas Drill bridge plugs have operational limits of 

250°F with 5,000 psi differential from either direction. HPHT 

models have operating limits of 350°F with an 8,000 or 

10,000 psi differential. 

Applications 

Run multiple drillable bridge plugs for stimulation and 

workover operations 

Features 

Consists of composites and a packer set, giving it 

minimal ferrous metal content 

Can be set with electric wireline setting tools, slickline 

setting tools, coiled tubing setting tools, or mechanical 

setting tools 

Isolates lower zones during squeeze cementing 

operations on land-based or offshore rigs in vertical or 

deviated wells 

Functions as a bridge plug in multizone stimulation 

treatments 

Fas Drill® Bridge Plug 


HAL12041


Perforating Solutions 

Perforating Solutions maintains an unequalled success and 

safety record while continuously developing and introducing 

new and innovative products for tubing conveyed and 

wireline perforating. 

Shaped Charges 

Halliburton shaped charges lead the way in quality, reliability 

and performance. Halliburton ballistic engineers at Jet 

Research Center continue to develop and manufacture 

perforating systems for virtually any reservoir environment 

or intervention technique. Halliburton also has the capability 

and expertise to develop custom charges to maximize 

effective penetration into specific reservoirs. 

MaxForce Shaped Charges 

The new MaxForce line of super-deep penetrating charges 

is Jet Research Center's latest advancement in shaped charge 

evolution. The MaxForce line of charges is manufactured 

with the highest level of quality assurance that results in a 

lower standard deviation to provide consistent charge 

performance. 

Features 

MaxForce deeper penetration charges: 

Increase productivity 

Penetrate past any near wellbore damage with deeper 

penetration 

Potentially intersect more natural fractures with deeper 

penetration 

Reduce pressure drop at perforations, which can 

potentially delay scale, paraffin, or asphaltene deposits 

Perforating Solutions 5-1 

2007 

2000 

1995 

1990 

DP (HNS) 

Super DP 

HAL16785 

MaxForce 

Millennium 

Perforating Solutions

Dominator ® Shaped Charges 

The Dominator® shaped charges are designed to optimize 

perforating performance in reservoir rock and increase 

hydrocarbon production. To achieve that goal, Dominator 

charges were evaluated in terms of geometry and flow 

performance in sandstone targets at simulated downhole 

conditions instead of by their ability to penetrate API 19B 

Section I unstressed concrete. As a result, these new shaped 

charges far exceed the performance of current, comparable 

charges. 

A Revolutionary Approach to Charge Development 

To maximize well inflow performance for a specific reservoir, 

it is necessary to engineer the shaped-charge explosive jet-tip 

velocity profile with consideration to the target properties 

(compressive strength, particle grain size, pore fluid type, 

etc.). Optimized shaped charge design combined with 

perforating best practices per Halliburton’s PerfPro® process 

ensure that all perforations are surged at the optimum 

underbalance pressure to minimize perforation skin effects. 

Naturally, shaped charges engineered for a given reservoir 

should be validated with API 19B Section IV testing (i.e. 

Perforation Flow Laboratory) at as close to in-situ properties 

as possible. 

Dominator shaped charges were developed at Halliburton’s 

Jet Research Center (JRC) Perforation Flow Laboratory by 

firing perforating charges into real rock under simulated 

downhole conditions that included rock effective stress, 

wellbore underbalance, and rock pore pressure. By analyzing 

post-shot results from the testing program, it was possible to 

rapidly develop a design with favorable jet characteristics. 

Using the perforation flow laboratory in the design process 

also avoided the pitfalls associated with translating data from 

surface shot concrete targets to productivity estimations in 

downhole reservoirs. 

The improvement in penetration performance is evident 

from the results. In one example, penetration increased by an 

average of 52% in the gas-filled samples and by an average of 

37% in liquid-filled samples. These penetration results, along 

with improvement in core flow efficiency, contribute to 

increased flow performance. 

Expanding case 

fragments 

Rearmost 

portion of jet 

Stretching jet 

Jet tip 

Flash X-ray of a charge during detonation sequence 

5-2 Perforating Solutions 

HAL15999 

HAL15956 

Actual charge performance in formation core samples comparing 

standard charge on left vs the Dominator® charge on the right. 

HAL15957

Mirage ® Shaped Charges 

The Mirage® line of BH shaped charges was introduced as an 

improved low debris system. The Mirage line provides more 

of a total perforating system debris reduction solution. With 

the Mirage line, gun debris associated with all components of 

the perforating assembly is reduced. 

Previous BH guns systems required that the shaped charges 

be positioned and retained in the charge tube holder using 

bend tabs. The bend tab is a significant source of gun debris 

because of the metal slivers generated during gun detonation. 

The improved Mirage system incorporates a new twist lock 

feature in the charge tube holder, eliminating the debris 

associated with the bend tabs. 

In addition to metallurgical considerations, the geometry of 

the Mirage shaped charge liner is carefully controlled during 

the manufacturing process such that those portions of the 

liner that might contribute to slug creation are removed. This 

process results in a charge liner with a controlled geometry 

liner (CGL). 

“Thick” region 

controlled to 

reduce debris 

“Thinned” region 

after forming 

HAL16270 

Mirage® Super Hole Perforator 

Initial (Copper) 7-in. BH Liner Technology 

Current (Brass) 7-in. BH Liner Technology 

Latest (Mirage®) 7-in. BH Liner Technology 


HAL16361 

HAL16360 

HAL16366

The LD zinc charge cases with the Mirage® system have been optimized to reduce the particle size distribution as shown below. 

Mass Retained (g) 

HAL16267 

70.0 

60.0 

50.0 

40.0 

30.0 

20.0 

10.0 

Case Debris Comparison (One Charge) 

Mirage Case Debris 

LD Zinc Case Debris 

Steel Case Debris 

0.0 

> 0.500 > 0.375 > 0.250 > 0.187 > 0.094 > 0.066 > 0.033 > 0.011

Maxim Shaped Charges 

The completion of wells in unconsolidated formations 

generally requires some form of sand control or gravel 

packing for flow assurance. For a cased and perforated sand 

control completion, the perforating strategy typically calls 

for perforations with the largest possible exit hole in the 

casing with as high a shot density (spf) as possible. The large 

casing exit hole improves the likelihood of placing sand or 

gravel into the perforation tunnel and the higher spf 

increases the effective flow area resulting in lower pressure 

drop across the completion during production. 

As completion targets in deep water environments go deeper, 

drilling challenges are compounded forcing operators in 

many cases to set the casing shoe point higher than planned 

in order to safely reach deeper primary targets. 

Unfortunately, this scenario results in secondary pay zones 

that have multiple strings of casing across portions or the 

entire length of the pay zone. This situation presents a 

serious technical challenge because the typical big-hole (BH) 

perforating system cannot efficiently penetrate multiple 

casing strings and still produce an adequate casing exit hole. 

The results utilizing conventional BH perforating systems in 

the past yielded a large exit hole in the first casing string and 

a very small exit hole in the second casing string with 

minimal formation penetration. 

Revolutionary Shaped Charge Liner Design Meets the 

Challenge 

Shaped charge design engineers at Halliburton's Jet Research 

Center (JRC) have unleashed the power of Maxim shaped 

charges by utilizing hydro-code modeling software and flash 

X-ray imaging to develop a proprietary shaped charge liner 

that optimizes the casing exit-hole size when penetrating 

multiple casing strings. 

The effectiveness of the new Maxim shaped charge concept 

was demonstrated with the development of a 5-in. 8 spf 

47 gram charge for a completion scenario with 7-5/8-in. 

47.1 lb/ft P-110 and 9-5/8-in. 47 lb/ft P-110 casing. 

A standard 5-in. 12 spf 28 gram BH gun system was tested 

under the completion configuration described resulting in a 

casing exit-hole of 0.28-in. 

Charge Part 

No. 

Gun OD SPF 

The newly developed Maxim perforating system resulted in a 

casing exit-hole size of 0.66-in. with an impressive formation 

penetration of 6.0-in. These results show a significant 136% 

improvement in casing exit-hole size and 270% 

improvement in flow area on a per foot basis. 

HAL15955 Maxim Dual String Technology 

Maxim Charge Performance Data 

Explosive 

Load 

Existing Dual String 

Technology 

Expanding 

Case Fragments 

Stretching Jet 

Jet Tip 

Rearmost Portion 

of Jet 


HAL16359 

Flash X-ray and hydro-code simulation of a shaped charge during 

detonation sequence. 

Inner Casing Exit Hole Outer Casing Exit Hole Penetration* 

101350449 5.00 8 47 7 5/8 47.1# P-110 0.75 9 5/8 47 P-110 0.66 6.00 

101357518 5.75 10 56.5 8 5/8 60.8# P-110 0.78 11 3/4 65# P-110 0.63 7.50 

101357518 7.00 14 56.5 9 5/8 473 lL-80 0.61 13 3/8 72# P-110 0.68 8.77 

*Penetration is in cement measured from the OD of the outer casing. 

HAL16362

KISS Low-Damage Perforating Charge 

The KISS charge provides all the benefits expected from 

big-hole charges—yet produces significantly less damage in 

unconsolidated formations. 

KISS charges limit perforating damage with minimal 

penetrator design charges, reducing damaged material eightfold. 

Damaged material is near the casing with 200% of the 

cross-sectional area a possibility. Penetration past the cement 

is not a problem, and lower explosive weight charges are less 

susceptible to carrier failure. 

In an extensive series of lab tests comparing KISS lowdamage 

charges with conventional big-hole perforating 

charges under simulated downhole conditions, the KISS 

charge more than proved its superiority. In these tests: 

KISS charges created holes in the casing that were equal 

to or larger in diameter than those created by 

conventional big-hole perforating charges. 

Perforation depth was appropriately reduced, so there 

was far less damage to the formation as well as a 

significantly reduced crushed zone (less than 1/3 of a 

conventional big-hole charge). 

KISS charges easily penetrated 2-in. thick cement 

sheaths, proving they can be effective even in wellbores 

where washouts have occurred. 

Less damage occurred to the cement surrounding the 

entrance hole, and the cement damage area was smaller. 

Features 

Can be run in standard VannGun® perforating guns and 

conveyed on tubing or wireline 

Complements Halliburton’s StimGun service by 

producing an instantaneous, high-pressure surge into 

the formation to enhance perforating and stimulation 

results 

Specialists help determine if the KISS low damage 

perforating charge would be a productive choice for a 

specific well 

Low impact on unconsolidated formations for a positive 

impact on completions 

Better gravel packs due to greatly improved fluid 

injectivity—whether running a conventional gravel pack, 

a FracPac system, or a high-rate water pack 

Reduced fines movement 

Reduced sand production 

HAL5945 

The unique KISS perforating charge is designed to just penetrate the 

formation while the high pressure gas breaks through the crushed zone in 

the tunnel and creates fractures in the formation. 

5-6 Perforating Solutions

Gun Size Phasing JRC P/N Charge Name 

Charge Performance Data 

CAPSULE GUNS 

Explosive 

Load 

(Grams) 

Casing 

Size (in.) 

Target 

Strength 

(psi) 

EHD (in.) 

Total Target 

Penetration 

(in.) 

Penetration 

Normalized 

to 5000 psi 

(5% per 

1000) 

1-11/16” 0 100005450 1-11/16” Dyna-Star ® 4 SPF RDX DP 13.4 4-1/2” 5149 0.39 10.50 19B 

1-11/16” 0 100005450 1-11/16” Dyna-Star 4 SPF RDX DP 13.4 4-1/2” 5909 0.40 12.46 13.03 QC 

1-11/16” 0 100005449 1-11/16” Dyna-Star 6 SPF HMX DP 13.5 4-1/2” 6384 0.41 11.97 12.80 QC 

1-11/16” 0 101398891 1-11/16” MILLENNIUM Dyna-Star 6 SPF HMX 8 4-1/2” 5426 0.29 24.00 24.51 QC 

1-11/16” 0 101521848 1-11/16” MaxForce Deep Star 8 SPF HMX 8 4-1/2” 7170 0.27 19.90 19B 

2-1/8” 0 101210198 2-1/8” MILLENNIUM Deep Star HMX 15.9 5-1/2” 5435 0.40 30.60 31.27 QC 

2-1/8” 0 101383082 2-1/8” MILLENNIUM Dyna-Star 6 SPF HMX 15.9 5-1/2” 5633 0.39 29.07 29.99 QC 

2-1/8” 0 100008259 2-1/8” Dyna-Star 6 SPF HMX DP 15.5 5-1/2” 5326 0.38 14.84 15.08 QC 

2-1/8” 0 100005448 2-1/8” Dyna-Star 6 SPF RDX DP 15.5 5-1/2” 5538 0.42 16.61 17.06 RP43 

2-1/8” 0 100005448 2-1/8” Dyna-Star 4 SPF RDX DP 15.5 5-1/2” 5292 0.35 15.50 19B 

2-1/8” 90 101210198 2-1/8” MILLENNIUM Deep Star 4 SPF HMX DP 15.9 5-1/2” 5820 0.31 20.60 19B 

2-1/8” 0/45/90 101210198 

2-1/8” MILLENNIUM Deep Star 5.8 SPF HMX - 

PENTAPHASE Oscillating Spiral 

PORTED GUNS 


* Unofficial 

Data 

15.9 5-1/2” 6740 0.30 20.60 19B 

3-1/8” 90 101410556 3-1/8” GSC 4 SPF RDX DP 12 4-1/2” 5500 0.34 20.90 21.42 QC 

4” 90 101288857 4" MILLENNIUM EXPRESS GSC 19.5 5-1/2” 5600 0.51 27.18 27.95 QC 

SLICKWALL GUNS 

3-1/8” 60 / 90 101366678 3-1/8” MILLENNIUM IS 4 SPF HMX 21 4-1/2” 6200 0.40 38.30 40.60 QC 

3-1/8” 90 101204537 4” Basic MILLENNIUM EXPRESS 4 SPF RDX 19.5 5-1/2” 6277 0.50 16.65 17.71 QC 

4” 90 101204537 4” Basic MILLENNIUM EXPRESS 4 SPF RDX 19.5 5-1/2” 6277 0.50 24.94 26.53 QC 

3-1/8” 60 / 90 101310802 

4” 60 / 90 101310802 

4” Twisted Strip MILLENNIUM EXPRESS 4 SPF 

RDX W/ TWIST LOCK 1/2 RUBBER JACKET 

4” Twisted Strip MILLENNIUM EXPRESS 4 SPF 

RDX W/ TWIST LOCK 1/2 RUBBER JACKET 

SCALLOPED GUNS 

19.5 5-1/2” 6277 0.50 16.65 17.71 QC 

19.5 5-1/2” 6277 0.50 24.94 26.53 QC 

1-9/16” 0 100157028 1-9/16” MILLENNIUM IS 4 SPF HMX 3.4 4-1/2” 5967 0.21 11.34 11.89 RP43 

1-9/16” 60 100157028 1-9/16” MILLENNIUM IS 6 SPF HMX 3.4 2-7/8” 6949 0.23 8.30 19B 

1-9/16” 60 384465 1-9/16” 4 SPF HMX BH 3.2 2-7/8” 7533 0.34 2.50 19B 

2” 60 101208224 2” MILLENNIUM IS HMX 6.8 2-7/8” 6019 0.22 18.30 19B 

2” 60 101603801 2" MaxForce IS HMX 7 2-7/8” 5697 0.24 20.30 19B 

2” 60 101206246 2” IS 6 SPF-HMX BH 6.8 3-1/2” 7332 0.48 3.00 19B 

2-3/8” 60 101590845 2-3/8” MaxForce IS 6 SPF HMX 10 3-1/2” 5663 0.28 19.90 19B 

2-3/8” 60 101591373 2-3/8” 6 SPF HMX BH 10 3-1/2” 5663 0.48 5.80 19B 

2-1/2” 60 101418095 2 1/2” MILLENNIUM II IS 6 SPF HMX 11.1 3-1/2” 5996 0.32 24.50 19B 

2-1/2” 60 101244923 2-1/2” 6 SPF HNS DP 11.1 3-1/2' 7128 0.26 12.60 19B 

2-1/2” 60 384466 2-1/2” 6 SPF HMX BH 11 3-1/2' 7469 0.58 2.40 19B 

2-3/4” 60 101233817 2-3/4” MILLENNIUM 6 SPF HMX 15 4-1/2” 6394 0.30 26.00 19B 

2-3/4” 60 101318485 2-3/4” 6 SPF MILLENNIUM HNS 15.1 4-1/2” 5694 0.30 27.55 28.51 QC 

2-3/4” 60 101206793 2-3/4” 6 SPF RDX BH 14.7 4-1/2” 6109 0.67 5.50 5.80 RP43 

2-3/4” 60 101270158 2-3/4” 6 SPF HMX BH 15 4-1/2” 7381 0.65 4.20 19B 

2-7/8” 60 101233817 2-3/4” MILLENNIUM 6 SPF HMX (Hvy Wall Gun) 15 4-1/2” 6388 0.31 27.30 19B 

2-7/8” 60 101233817 2-3/4” MILLENNIUM 6 SPF HMX (Hvy Wall Gun) 15 4-1/2” 5124 0.35 30.00 19B 3 

2-7/8” 60 101388407 2-7/8” MILLENNIUM 6 SPF HNS 18.5 4-1/2” 6859 0.28 22.80 19B 

3-1/8” 60 101366678 3-1/8” MILLENNIUM IS 6 SPF HMX 21 4-1/2” 6200 0.40 38.30 40.60 QC



Explosive 

Load 

(Grams) 

Casing 

Size (in.) 

3-1/8” 60 101618998 3-1/8” MILLENNIUM Express IS DP 6 SPF RDX 21 4-1/2” 

3-1/8” 60 101618994 3-1/8” MILLENNIUM Express IS SDP 6 SPF RDX 21 4-1/2” 

Target 

Strength 

(psi) 

3-1/8” 135/45 101351605 3-1/8” Mirage ® 10 SPF HMX BH/LD 14 5” 6100 0.64 3.80 4.01 QC 

3-3/8” 60 101233819 3-3/8” MILLENNIUM 6 SPF HMX 25 4-1/2” 6215 0.48 40.40 42.85 RP43 

3-3/8” 60 101233819 3-3/8” MILLENNIUM 6 SPF HMX 25 4-1/2” 5754 0.45 37.50 19B 

3-3/8” 60 101600039 3-3/8” MILLENNIUM Express IS 6 SPF RDX DP 23 4-1/2” 5704 0.42 25.60 26.5 QC 

3-3/8” 60 101589595 3-3/8” MILLENNIUM Express IS 6 SPF RDX SDP 23 4-1/2” 5219 0.39 43.00 43.5 QC 

3-3/8” 60 101365876 3-3/8” MILLENNIUM 6 SPF HNS 25 4-1/2” 6578 0.31 22.10 19B 

3-3/8” 60 101320459 3-3/8” 6 SPF RDX DP 22 4-1/2” 7538 0.34 17.60 19B 

3-3/8” 60 100005333 3-3/8” 6 SPF RDX DP 22 4-1/2” 6138 0.41 20.30 21.46 RP43 

3-3/8” 60 100005332 3-3/8” 6 SPF HMX DP 26 5-1/2” 9846 0.38 18.28 22.71 RP43 

3-3/8” 60 100008014 3-3/8” 6 SPF RDX SUPER DP 24 4-1/2” 5251 0.39 28.45 28.81 RP43 

3-3/8” 60 100008249 3-3/8” 6 SPF HMX SUPER DP 25 4-1/2” 5967 0.40 26.20 19B 

3-3/8” 60 100008249 3-3/8” 6 SPF HMX SUPER DP 25 5” 6097 0.40 28.70 30.27 RP43 

3-3/8” 135/45 101351605 3-3/8” Mirage 12 SPF HMX BH/LD 14 5-1/2” 6100 0.63 4.15 4.38 QC 

3-3/8” 60 100005321 3-3/8” 6 SPF RDX BH 24 4-1/2” 6101 0.86 4.66 4.92 QC 

3-3/8” 60 100157017 3-3/8” 6 SPF HMX BH 24 4-1/2” 6490 0.88 4.76 5.11 QC 

3-3/8” 150/30 100008251 3-3/8” Omni 12 SPF RDX BH 14 5-1/2” 7802 0.62 5.33 6.08 RP43 

3-3/8” 150/30 100005312 3-3/8” Omni 12 SPF HMX BH 14 5-1/2” 6300 0.64 5.24 5.58 QC 

3-1/2” 135/45 101542642 3-1/2” Mirage 12 SPF HMX BH/LD 15 5-1/2” 6100 0.65 4.20 4.43 QC 

4” 90 101210636 4” MILLENNIUM HMX (4 SPF) 39 5-1/2” 5490 0.39 44.60 45.69 RP43 

4” 90 101210636 4” MILLENNIUM HMX (4 SPF) 39 5-1/2” 6365 0.38 43.40 19B 

4” 60 100005322 4-5/8” 6 SPF RDX DP 32 7” 5277 0.6 40.50 41.06 QC 

4” 60 100005327 4-5/8” 6 SPF HMX DP 32 5-1/2” 5568 0.45 37.00 19B 4 

4-1/2” 60 101210636 4” MILLENNIUM HMX (5 SPF) 39 7” 6775 0.37 39.60 19B 

4-1/2” 150/30 101210674 4-1/2” MILLENNIUM 12 SPF HMX 22.7 7” 8484 0.38 26.80 31.47 RP43 

4-5/8” 180 101446899 4-5/8” KleenZone ® G-FORCE ® HMX 39 7" 5208 0.36 42.80 19B 

4-5/8” 350/10 101446899 4-5/8” KleenZone G-FORCE HMX 39 7" 5412 0.35 41.70 19B 

4-5/8” 60 101210636 4” MILLENNIUM HMX (5 SPF) 39 7” 5502 0.37 52.00 53.31 RP43 

4-5/8” 60 101210636 4” MILLENNIUM HMX (5 SPF) 39 7” 5518 0.35 43.60 19B 

4-5/8” 60 101287306 4” 5 SPF HNS DP 39 7” 7559 0.33 31.20 19B 

4-5/8” 60 100005322 4-5/8” 6 SPF RDX DP 32 7” 5325 0.43 30.46 30.95 RP43 

4-5/8” 60 100005327 4-5/8” 6 SPF HMX DP 32 7” 5809 0.46 39.50 41.10 QC 

4-5/8” 60 101332806 4-5/8” 6 SPF HNS DP 32 7” 5814 0.45 30.30 31.53 QC 

4-5/8” 150/30 101210674 4-1/2” MILLENNIUM 12 SPF HMX 22.7 7” 8484 0.38 26.80 31.47 RP43 

4-5/8” 150/30 101210674 4-1/2” MILLENNIUM 12 SPF HMX 22.7 7” 6322 0.38 24.40 19B 

4-5/8” 150/30 100005324 4-5/8” Omni 12 SPF RDX DP 22.7 7” 9080 0.36 16.25 19.57 RP43 

4-5/8” 150/30 100005325 4-5/8” Omni 12 SPF RDX DP/LD 22.7 7” 5685 0.32 17.41 18.01 RP43 

4-5/8” 150/30 100014352 4-5/8” Omni 12 SPF HMX DP 22.7 7” 9080 0.37 16.09 19.37 RP43 

4-5/8” 150/30 101343830 4-5/8” Omni 12 SPF HNS DP 7” 5020 0.35 28.00 28.03 QC 

4-5/8” 150/30 100005340 4-5/8” Omni 12 SPF HMX DP/LD 22.7 7” 5685 0.30 18.37 19.00 RP43 

4-5/8” 150/30 100005319 4-5/8” Omni 12 SPF RDX BH 25 7” 6840 0.74 6.41 7.00 RP43 

4-5/8” 150/30 100005326 4-5/8” Omni 12 SPF RDX BH/LD 22.7 7” 7346 0.65 5.51 6.16 RP43 

4-5/8” 150/30 100157006 4-5/8” 12 SPF HMX BH 25 7” 5723 0.75 7.02 7.27 QC 

4-5/8” 150/30 100005311 4-5/8” Omni 12 SPF RDX SH 28 7” 6982 0.93 6.30 6.92 RP43 

4-5/8” 150/30 100156995 4-5/8” Omni 12 SPF HMX SH 28 7” 5016 0.96 5.10 5.10 RP43 

EHD (in.) 

Total Target 

Penetration 

(in.) 

Penetration 

Normalized 

to 5000 psi 

(5% per 

1000) 


* Unofficial 

Data


4-5/8” 150/30 101228756 4-5/8” 12 SPF RDX SUPER HOLE/LD 28 7” 5124 0.81 5.40 5.43 QC 

4-5/8” 150/30 101233690 4-5/8” 12 SPF HMX SUPER HOLE/LD 28 7” 5622 0.85 5.30 5.46 RP43 

4-5/8” 135/45 100156990 4-5/8” 18 SPF RDX BH 20 7” 5553 0.73 6.18 6.35 RP43 

4-5/8” 180 101287306 4-5/8” 4 SPF HNS DP 39 7-5/8” 6349 0.29 30.20 19B 

5” 150/30 100005311 4-5/8” Omni 12 SPF RDX SUPER HOLE 28 7” 5192 0.91 6.90 6.97 RP43 

5” 150/30 100005319 4-5/8” Omni 12 SPF RDX BH 25 7” 6508 0.84 8.80 9.46 QC 

5” 150/30 100156995 4-5/8” Omni 12 SPF HMX SUPER HOLE 28 7” 6487 1.00 6.00 6.45 QC 

5” 150/30 100005311 4-5/8” Omni 12 SPF RDX SUPER HOLE 28 7-5/8” 7877 0.83 6.65 7.61 RP43 

5” 135 101307494 5" Mirage ® 12 SPF RDX SUPER HOLE/LD 32 7-5/8” 6345 0.90 6.00 19B 

5” 

120 

Cluster 

101292616 5" 21 SPF RDX BH 21 7-5/8” 5411 0.72 5.30 19B 1 

5-1/8” 135 101307494 5" Mirage 12 SPF RDX SUPER HOLE/LD 32 7-5/8” 5576 0.88 6.60 19B 

5-1/8” 231.4 100157007 5-1/8” 14 SPF RDX SUPER HOLE 32 7-5/8” 5138 0.93 5.11 5.15 RP43 

5-1/8” 231.4 100157011 5-1/8” 14 SPF HMX SUPER HOLE 32 7-5/8” 5250 0.94 5.83 5.90 RP43 

5-1/8” 

120 

Cluster 

101292616 5-1/8” 21 SPF RDX BH 21 7-5/8” 6246 0.74 5.65 5.99 QC 

5-3/4” 150/30 100157007 5-1/8” 14 SPF RDX SUPER HOLE 32 8-5/8” 6498 0.75 5.87 6.31 QC 

6-1/2” 

6-1/2” 

135/45 

138 

135/45 

138 

101304878 6-1/2” Mirage 12 or 14 SPF RDX BH/LD 47 8-5/8” 7043 1.07 5.60 19B 

101304878 6-1/2” Mirage 12 or 14 SPF RDX BH/LD 47 9-5/8” 5088 0.91 6.80 19B 2 

7” 135/45 101207997 7” MILLENNIUM 12 SPF HMX 39 9-5/8” 7006 0.36 43.30 47.63 RP43 

7” 135/45 101207997 7” MILLENNIUM 12 SPF HMX 39 9-5/8” 6397 0.42 38.70 19B 

7” 

7” 

7” 

135/45 

138 

135/45 

138 

135/45 

138 

101304878 6-1/2” Mirage 12 or 14 SPF RDX BH/LD 47 9-5/8” 6178 1.07 6.10 19B 

101213474 7” 12 or 14 SPF RDX SUPER HOLE 56.5 9-5/8” 5975 1.29 5.80 19B 

101484232 7” Mirage 14 SPF RDX BH/LD 39 9-5/8” 6270 1.04 6.30 19B 

7” 138 101212693 7” 12 SPF RDX SUPER HOLE/LD 56.5 9-5/8” 6040 1.16 5.00 19B 

7” 60/120 101414821 7” Mirage 18 SPF HMX/LD 45 9-7/8” 5893 1.02 6.50 19B 

Registered 19B data except fired in 7-5/8” 47# P110 casing 

Registered 19B data except fired in 9-5/8” 71# N-80 casing 

Registered 19B data except fired in air 

Registered third party 19B data 

MaxForce, G-Force ® ,and KleenZone ® are proprietary to Halliburton 

Charge performance will vary due to well conditions. 

For realistic data, contact JRC “Perforation Flow Lab” testing services. 

Penetration normalization is not certified by API for 19B. 

RP43 Test are not endorsed by API and will not be available on new or improved JRC Charges. 


Explosive 

Load 

(Grams) 

Casing 

Size (in.) 

Target 

Strength 

(psi) 

EHD (in.) 

Total Target 

Penetration 

(in.) 

Penetration 

Normalized 

to 5000 psi 

(5% per 

1000) 


* Unofficial 

Data

Gun Systems 

VannGun ® Assemblies 

1 9/16 in. to 7 in. and 4 SPF to 21 SPF 


7.00" 

6.50" 

6.00" 

5.75" 

5.125" 

5.00" 

4.75" 

4.625" 

4.50" 

4.25" 

4.00" 

3.375" 

3.125" 

2.875" 

2.75" 

2.50" 

2.00" 

1.563”

VannGun ® Phasing and Shot Patterns* 

0° Phasing 4 and 5 SPF 

HAL10590 

60° Phasing 4, 5, and 6 SPF 

HAL15978 

*Other shot densities and phasings are available upon request. 

6" 

6" 

12" 

0º 180º 360º 

6" 

6" 

12" 

4 SPF 

4 SPF 

0º 60º 120º 180º 240° 300º 360º 


6" 

6" 

12" 

6" 

6" 

12" 

5 SPF 

0º 180º 360º 

6" 

6" 

12" 

6 SPF 

0º 60º 120º 180º 240° 300º 360º 

5 SPF 

0º 60º 120º 180º 240° 300º 360º

90° Phasing 4 SPF 

180° Phasing 4 and 8 SPF 

HAL15982 

HAL15981 

6" 

6" 

12" 

4 SPF 


6" 

6" 

12" 

0º 180º 360º 

4 SPF 

0º 90º 180º 270° 360º 

6" 

6" 

12" 

8 SPF 

0º 180º 360º

60° Phasing 6 SPF Two Planes 

45°/135° Phasing 5, 6, 8, 12, and 18 SPF 

6" 

6" 

12" 

HAL15355 

8 SPF 

HAL15356 

0º 45º 90º 135º 180º 225° 270º 315º 360º 

6" 

6" 

12" 

6" 

6" 

12" 

6" 

6" 

12" 

5 SPF 

0º 45º 90º 135º 180º 225° 270º 315º 360º 

12 SPF 

0º 102.9° 205.7° 308.6° 

51.4° 154.3° 257.1° 360º 

0º 45º 90º 135º 180º 225° 270º 315º 360º 


6 SPF 

6" 

6" 

12" 

6" 

6" 

12" 

6 SPF 

0º 45º 90º 135º 180º 225° 270º 315º 360º 

18 SPF 

0º 45º 90º 135º 180º 225° 270º 315º 360º

140°/160° Phasing 11 SPF 

HAL15983 

51.4°/154.3° Phasing 12 SPF 

30°/150° Phasing 12 SPF 

HAL15354 

HAL15357 


6" 

6" 

12" 

6" 

6" 

12" 

6" 

6" 

12" 

0º 

100º 

11 SPF 

180° 260° 360° 

110º 250° 

12 SPF 

0º 102.9° 205.7° 308.6° 

51.4° 154.3° 257.1° 360º 

12 SPF 

0º 60° 120º 180º 240° 300º 360° 

30º 90º 150° 210° 270º 330°

25.7°/128.5° Phasing 14 SPF 

60°/120° Phasing 18 and 21 SPF 

HAL15984 

138° Phasing 14 SPF 

HAL15993 

HAL15985 

6" 

6" 

12" 

6" 

6" 

12" 

18 SPF 

0º 60º 120º 180º 240° 300º 360º 

6" 

6" 

12" 

14 SPF 

0º 51º 103º 154º 206º 257° 309º 360º 

26º 77º 129º 180º 231º 283° 334º 


6" 

6" 

12" 

14 SPF 

0º 45º 90º 135º 180º 225° 270º 315º 360º 

21 SPF 

0º 60º 120º 180º 240° 300º 360º

Charge 

Part No. 

Explosive 

Type 

Tensile ratings on the following tables are based on the box x pin connection. 

Charge 

Type 

1 9/16-in. Premium VannGun ® Assemblies 

SPF Phasing 

Gun 

Material 

Type 

Gun Thread 

Pressure 

Rating 

psi (bar) 

100157028 HMX Millennium 4 0° Premium Vann 20,000 

(1379) 

101210199 HMX BH 60° 

90° 

180° 

0° Premium Industry 

Standard 

20,000 

(1379) 

100157028 HMX Millennium 6 60° Premium Vann 20,000 

(1379) 

60° 

90° 

180° 

101210199 HMX BH 60° Premium Industry 


20,000 

(1379) 

Tensile 

Strength 

lb (kg) 

70,000 

(31 746) 

70,000 

(31 746) 

70,000 

(31 746) 

70,000 

(31 746) 

Weights 


Length 

ft (m) 

Loaded 

lb (kg) 

4 spf Millennium 

Spacer 

lb (kg) 

4 (1.22) 21 (9) 17 (8) 

7 (2.13) 31 (14) 24 (11) 

11 (3.35) 46 (21) 34 (15) 

15 (4.57) 60 (27) 44 (20) 

21 (6.40) 81 (37) 59 (27) 


4 (1.22) 21 (10) 17 (8) 

7 (2.13) 32 (14) 24 (11) 

11 (3.35) 48 (22) 34 (15) 

15 (4.57) 63 (28) 44 (20) 

21 (6.40) 85 (39) 59 (27)

Charge 

Part No. 

Explosive 

Type 

Charge 

Type 

2-in. Premium VannGun ® Assemblies 

SPF Phasing 

Gun 

Material 

Type 

Gun Thread 

101208224 HMX Millennium 4 0° Premium Vann 

101603801 HMX MaxForce 

100008017 HMX SDP 

100157018 HNS DP 

60° 

90° 

180° 

101206246 HMX BH 0° Premium 

60° 

90° 

180° 

Industry 



101603801 HMX MaxForce 60° Premium 

Industry 


Pressure 

Rating 

psi (bar) 

20,000 

(1379) 

20,000 

(1379) 

20,000 

(1379) 

20,000 

(1379) 

Tensile 

Strength 

lb (kg) 

70,000 

(31 746) 

70,000 

(31 746) 

70,000 

(31 746) 

70,000 

(31 746) 

Weights 


Length 

ft (m) 

Loaded 

lb (kg) 


Spacer 

lb (kg) 

4 (1.22) 28 (13) 23 (10) 

7 (2.13) 44 (20) 35 (16) 

11 (3.35) 66 (30) 51 (23) 

15 (4.57) 87 (39) 63 (29) 

21 (6.40) 120 (54) 92 (42) 


4 (1.22) 28 (13) 23 (10) 

100008017 HMX SDP 7 (2.13) 44 (20) 35 (16) 

100157018 HNS DP 11 (3.35) 66 (30) 51 (23) 

101206246 HMX BH 15 (4.57) 87 (39) 63 (29) 


101603801 HMX MaxForce 60° Premium 

Industry 


20,000 

(1379) 

20,000 

(1379) 

70,000 

(31 746) 

70,000 

(31 746) 

21 (6.40) 120 (54) 92 (42) 

6 spf Reduced Swell Gas Gun 

2 (.61) 14 (6.3) 11 (4.9) 

100008017 HMX SDP 4 (1.22) 25 (11.3) 20 (9.1) 

100157018 HNS DP 5 (1.52) 31 (14) 24 (10.9) 

101206246 HMX BH 6 (1.83) 36 (16.3) 28 (12.7) 

7 (2.13) 42 (19) 32 (14.5) 

8 (2.44) 48 (21.7) 36 (16.3) 

9 (2.74) 53 (24) 40 (18.2) 

11 (3.35) 65 (29.5) 48 (21.8)

Charge 

Part No. 

Explosive 

Type 

Charge Type SPF Phasing 


Gun 

Material 

Type 

Gun Thread 


101332418 HMX SDP 

101244923 HNS DP 

60° 

90° 

180° 

0° Premium 

60° 

90° 

180° 

Industry 


101418095 HMX Millennium II 6 60° Premium Vann 

60° Premium 

Industry 



Pressure 

Rating 

psi (bar) 

20,000 

(1379) 

20,000 

(1379) 

20,000 

(1379) 

20,000 

(1379) 

20,000 

(1379) 

Tensile 

Strength 

lb (kg) 

121,000 

(54 875) 

121,000 

(54 875) 

121,000 

(54 875) 

121,000 

(54 875) 

121,000 

(54 875) 

Weights 


Length 

ft (m) 

Loaded 

lb (kg) 


Spacer 

lb (kg) 

4 (1.22) 43 (20) 34 (15) 

7 (2.13) 67 (30) 52 (24) 

11 (3.35) 98 (44) 75 (34) 

15 (4.57) 129 (59) 98 (44) 

21 (6.40) 176 (80) 133 (60) 

6 spf Millennium II 

4 (1.22) 43 (20) 34 (15) 

7 (2.13) 67 (30) 52 (24) 

11 (3.35) 98 (44) 75 (34) 

15 (4.57) 129 (59) 98 (44) 

21 (6.40) 176 (80) 133 (60) 


101332418 HMX SDP 4 (1.22) 45 (20) 34 (15) 

101244923 HNS DP 60° Premium 

101418095 HMX Millennium II 6 60° Premium 

Industry 


Industry 


20,000 

(1379) 

20,000 

(1379) 

121,000 

(54 875) 

121,000 

(54 875) 

7 (2.13) 70 (32) 52 (24) 

11 (3.35) 104 (47) 75 (34) 

15 (4.57) 133 (60) 98 (44) 

21 (6.4) 189 (86) 133 (60) 

6 spf Reduced Swell Gas Gun 

4 (1.22) 43 (20) 34 (15) 

7 (2.13) 67 (30) 52 (24) 

11 (3.35) 98 (44) 75 (34) 

15 (4.57) 129 (59) 98 (44)

Charge 

Part No. 

Explosive 

Type 

Charge 

Type 


SPF Phasing 

Gun 

Material 

Type 

101233817 HMX Millennium 4 60° Standard 

101318485 HNS Millennium 120° Standard 

100157026 RDX SDP 6 

60° Two 

Row 

Gun Thread 

Industry 


Industry 


Premium Vann 

Pressure 

Rating 

psi (bar) 

18,000 

(1241) 

18,000 

(1241) 

20,000 

(1379) 

Tensile 

Strength 

lb (kg) 

116,700 

(52 934) 

116,700 

(52 934) 

134,000 

(60 771) 

Weights 


Length 

ft (m) 

Loaded 

lb (kg) 


Spacer 

lb (kg) 

4 (1.22) 59 (27) 50 (23) 

5 (1.53) 74 (34) 63 (29) 

6 (1.83) 88 (40) 75 (34) 

7 (2.13) 95 (43) 79 (35) 

8 (2.44) 102 (46) 82 (37) 

9 (2.74) 115 (52) 93 (42) 

10 (3.05) 125 (57) 99 (45) 

11 (3.35) 134 (61) 105 (48) 

15 (4.57) 172 (83) 145 (66) 

21 (6.71) 241 (114) 193 (88) 

6 spf SDP 

100010399 HMX SDP 4 (1.22) 59 (27) 50 (23) 

101251723 HNS SDP 

60° Two 

Row 

Standard Vann 

18,000 

(1241) 

116,700 

(52 934) 

8 (2.44) 102 (46) 82 (37) 

101206793 RDX BH 11 (3.35) 134 (61) 105 (48) 

101270158 HMX BH 16 (4.88) 183 (83) 145 (66) 


101318485 HNS Millennium 60° Standard Vann 

60° Standard 

Industry 


22,000 

(1517) 

18,000 

(1241) 

18,000 

(1241) 

134,000 

(60 771) 

116,700 

(52 934) 

116,700 

(52 934) 

22 (6.71) 252 (114) 193 (88) 


4 (1.22) 59 (27) 50 (23) 

7 (2.13) 95 (43) 79 (35) 

8 (2.44) 102 (46) 82 (37) 

11 (3.35) 134 (61) 105 (48) 

15 (4.57) 172 (83) 145 (66) 

16 (4.88) 183 (83) 145 (66) 

22 (6.71) 252 (114) 193 (88)

Charge 

Part No. 

Explosive 

Type 

Charge 

Type 


SPF Phasing 

Gun 

Material 

Type 

Gun Thread 


101318485 HNS Millennium 60° Premium 

Industry 




101414743 HMX Dominator ® 

Industry 




Industry 


Pressure 

Rating 

psi (bar) 

22,000 

(1517) 

22,000 

(1517) 

25,000 

(1724) 

25,000 

(1724) 

25,000 

(1724) 

25,000 

(1724) 

Tensile 

Strength 

lb (kg) 

142,000 

(64 399) 

142,000 

(64 399) 

142,000 

(64 399) 

142,000 

(64 399) 

142,000 

(64 399) 

142,000 

(64 399) 

Weights 


Length 

ft (m) 

Loaded 

lb (kg) 


Spacer 

lb (kg) 

4 (1.22) 62 (28) 54 (24) 

8 (2.44) 106 (48) 86 (39) 

11 (3.35) 138 (63) 110 (50) 

16 (4.88) 186 (84) 150 (68) 

22 (6.71) 258 (117) 198 (90) 

6 spf Millennium II 

4 (1.22) 62 (28) 54 (24) 

8 (2.44) 106 (48) 86 (39) 

11 (3.35) 138 (63) 110 (50) 

16 (4.88) 186 (84) 150 (68) 

22 (6.71) 258 (117) 198 (90) 

6 spf Millennium Gas Gun 

4 (1.22) 64 (29) 55 (25) 

101414743 HMX Dominator 8 (2.44) 112 (51) 92 (42) 

11 (3.35) 148 (67) 120 (54) 

16 (4.88) 204 (93) 166 (75) 

22 (6.71) 281 (127) 221 (100)

Charge 

Part No. 

Explosive 

Type 

Charge 

Type 


SPF Phasing 

Gun 

Material 

Type 

Gun Thread 

101320459 RDX DP 4 60° Premium Vann 

Pressure 

Rating 

psi (bar) 

25,000 

(1724) 

Tensile 

Strength 

lb (kg) 

238,000 

(107 937) 

Weights 


Length 

ft (m) 

Loaded 

lb (kg) 

4 spf DP 

Spacer 

lb (kg) 

90° 4 (1.22) 86 (39) 77 (35) 

180° 7 (2.44) 126 (57) 109 (50) 

60° Standard Vann 

20,000 

(1379) 

218,000 

(98 883) 

8 (2.44) 144 (65) 125 (57) 

90° 11 (3.35) 187 (85) 160 (73) 

180° 15 (4.88) 240 (109) 205 (93) 


Industry 


100008014 RDX SDP 4 60° Premium Vann 

20,000 

(1379) 

218,000 

(98 883) 

16 (4.88) 256 (116) 219 (99) 

90° 21 (6.41) 329 (150) 277 (126) 

20,000 

(1379) 

218,000 

(98 883) 

22 (6.71) 361 (164) 290 (132) 

4 spf SDP and Millennium 

101293450 RDX SDP/LD 90° 4 (1.22) 86 (39) 77 (35) 

101233819 HMX Millennium 180° 7 (2.44) 126 (57) 109 (50) 


101600039 RDX 

101589595 RDX 

Millennium 

Express 

Millennium 

Express 

20,000 

(1379) 

218,000 

(98 883) 

8 (2.44) 144 (65) 125 (57) 

90° 11 (3.35) 187 (85) 160 (73) 

180° 15 (4.88) 240 (109) 205 (93) 


Industry 


20,000 

(1379) 

218,000 

(98 883) 

16 (4.88) 256 (116) 219 (99) 

90° 21 (6.41) 329 (150) 277 (126) 

4 60° Standard 

Industry 


20,000 

(1379) 

218,000 

(98 883) 

22 (6.71) 361 (164) 290 (132) 

6 spf DP 

4 (1.22) 86 (39) 77 (35) 

7 (2.44) 126 (57) 109 (50) 

8 (2.44) 144 (65) 125 (57) 

11 (3.35) 187 (85) 160 (73) 

15 (4.88) 240 (109) 205 (93) 

16 (4.88) 256 (116) 219 (99) 

21 (6.41) 329 (150) 277 (126) 

22 (6.71) 361 (164) 290 (132)

Charge 

Part No. 

Explosive 

Type 

Charge 

Type 


100008014 RDX SDP 60° Standard Vann 

101293450 RDX SDP/LD 60° Standard 

101233819 HMX Millennium 

60° Two 

Row 

101309223 HMX Dominator ® 60° Two 

Row 

Industry 


Premium Vann 


25,000 

(1724) 

20,000 

(1379) 

20,000 

(1379) 

25,000 

(1724) 

20,000 

(1379) 

238,000 

(107 955) 

218,000 

(98 883) 

218,000 

(98 883) 

238,000 

(107 955) 

218,000 

(98 883) 

6 spf SDP and Millennium 

4 (1.22) 86 (39) 77 (35) 

7 (2.44) 126 (57) 109 (50) 

8 (2.44) 144 (65) 125 (57) 

11 (3.35) 187 (85) 160 (73) 

101365876 HNS Millennium 15 (4.88) 240 (109) 205 (93) 

100005321 RDX BH 16 (4.88) 256 (116) 219 (99) 

100157017 HMX BH 21 (6.41) 329 (150) 277 (126) 

100008251 RDX BH 12 

100005312 HMX BH 


SPF Phasing 

30°/150° 

OMNI 

30°/150° 

OMNI 

Gun 

Material 

Type 

Gun Thread 

Premium Vann 


Pressure 

Rating 

psi (bar) 

23,000 

(1586) 

20,000 

(1379) 

Tensile 

Strength 

lb (kg) 

238,000 

(107 955) 

218,000 

(98 883) 

Weights 

22 (6.71) 365 (166) 290 (132) 

12 spf BH 

4 (1.22) 89 (40) 77 (35) 

101351605 HMX BH/LD 8 (2.44) 150 (68) 125 (57) 

11 (3.35) 197 (88) 160 (73) 

16 (4.88) 271 (123) 219 (99) 

22 (6.71) 365 (166) 290 (132) 


Length 

ft (m) 

Loaded 

lb (kg) 

Spacer 

lb (kg)

Charge 

Part No. 

Explosive 

Type 

Charge 

Type 

100005322 RDX DP 


SPF Phasing 

4 60° 

Gun 

Material 

Type 

Gun Thread 

Premium Vann 

100005327 HMX DP 60° Standard Vann 

90° 

Pressure 

Rating 

psi (bar) 

20,000 

(1379) 

18,000 

(1241) 

Tensile 

Strength 

lb (kg) 

278,000 

(126 077) 

240,387 

(109 038) 

Weights 


Length 

ft (m) 

Loaded 

lb (kg) 

4 spf DP 

Spacer 

lb (kg) 

4 (1.22) 107 (49) 99 (45) 

101332806 HNS DP 90° 8 (2.44) 173 (78) 155 (70) 

100008014 RDX SDP 90° Standard 

Industry 


18,000 

(1241) 

240,387 

(109 038) 

11 (3.35) 223 (101) 197 (89) 

101293450 RDX SDP/LD 16 (4.88) 297 (135) 267 (121) 

100008249 HMX SDP 22 (6.71) 404 (183) 351 (159) 



101332806 HNS DP 60° Standard 

Industry 


20,000 

(1379) 

18,000 

(1241) 

18,000 

(1241) 

278,000 

(126 077) 

240,387 

(109 038) 

240,387 

(109 038) 

4 spf SDP 

4 (1.22) 110 (50) 99 (45) 

8 (2.44) 179 (81) 155 (70) 

11 (3.35) 230 (104) 197 (89) 

16 (4.88) 309 (140) 267 (121) 

22 (6.71) 420 (191) 351 (159) 

6 spf DP 

4 (1.22) 111 (50) 99 (45) 

8 (2.44) 189 (86) 155 (70) 

100008014 RDX SDP 11 (3.35) 233 (106) 197 (89) 

101293450 RDX SDP/LD 16 (4.88) 319 (144) 267 (121) 

100008249 HMX SDP 22 (6.71) 424 (192) 351 (159) 

6 spf SDP 

4 (1.22) 114 (52) 99 (45) 

8 (2.44) 189 (86) 155 (70) 

11 (3.35) 244 (111) 197 (89) 

16 (4.88) 336 (152) 267 (121) 

22 (6.71) 448 (203) 351 (159)

Charge 

Part No. 

Explosive 

Type 

Charge Type SPF Phasing 


Gun 

Material 

Type 

Gun Thread 

101355271 RDX DP 5 60° Standard Vann 

101210636 HMX Millennium 60° Standard 

Industry 


Pressure 

Rating 

psi (bar) 

18,000 

(1241) 

18,000 

(1241) 

Tensile 

Strength 

lb (kg) 

240,387 

(109 038) 

240,387 

(109 038) 

Weights 


Length 

ft (m) 

Loaded 

lb (kg) 

5 spf SDP 

Spacer 

lb (kg) 

4 (1.22) 107 (49) 99 (45) 

101287306 HNS DP 8 (2.44) 173 (78) 155 (70) 

101356077 HNS Dominator ® 11 (3.35) 223 (101) 197 (89) 

101293450 RDX SDP/LD 6 60° Standard Vann 

100008249 HMX SDP 60° Standard 

Industry 


18,000 

(1241) 

18,000 

(1241) 

240,387 

(109 038) 

240,387 

(109 038) 

16 (4.88) 297 (135) 267 (121) 

22 (6.71) 404 (183) 351 (159) 

6 spf DP 

4 (1.22) 111 (50) 99 (45) 

100005322 RDX DP 7 (2.44) 126 (57) 109 (50) 

100005327 HMX DP 11 (3.35) 233 (106) 197 (89) 

101332806 HNS DP 15 (4.88) 240 (109) 205 (93) 

100008014 RDX SDP 21 (6.41) 329 (150) 277 (126) 


101293450 RDX SDP/LD 

101262511 HNS SDP 

100008249 HMX SDP 

100005319 RDX BH 12 45°/135° Standard Vann 

100005324 RDX DP 45°/135° Standard 

Industry 


18,000 

(1241) 

18,000 

(1241) 

240,387 

(109 038) 

240,387 

(109 038) 

12 spf SDP 

4 (1.22) 111 (50) 99 (45) 

100005325 RDX DP/LD 7 (2.44) 126 (57) 109 (50) 

100005340 HMX DP/LD 11 (3.35) 233 (106) 197 (89) 

100014352 HMX DP 15 (4.88) 240 (109) 205 (93) 

100157006 HMX BH 21 (6.41) 329 (150) 277 (126) 

101210674 HMX Millennium

Charge 

Part No. 

Explosive 

Type 

Charge 

Type 


SPF Phasing 

Gun 

Material 

Type 

Gun Thread 





Pressure 

Rating 

psi (bar) 

20,000 

(1379) 

19,000 

(1310) 

20,000 

(1379) 

19,000 

(1310) 

Tensile 

Strength 

lb (kg) 

414,000 

(187 755) 

385,000 

(174 633) 

414,000 

(187 755) 

385,000 

(174 633) 

Weights 


Length 

ft (m) 

Loaded 

lb (kg) 

5 spf 39 g Millennium 

Spacer 

lb (kg) 

4 (1.22) 156 (71) 135 (61) 

8 (2.44) 257 (117) 208 (94) 

11 (3.35) 333 (151) 265 (120) 

16 (4.88) 447 (203) 357 (162) 

22 (6.71) 611 (277) 469 (213) 

6 spf 32 g DP 

4 (1.22) 147 (67) 134 (61) 

101332806 HNS DP 8 (2.44) 235 (107) 207 (94) 

100008014 RDX SDP 11 (3.35) 301 (137) 262 (119) 

101293450 RDX SDP/LD 16 (4.88) 405 (184) 354 (161) 

100008249 HMX SDP 22 (6.71) 544 (247) 464 (210) 

100005311 RDX SH 8 45°/135° Premium Vann 

101228756 RDX SH/LD 45°/135° Standard Vann 

20,000 

(1379) 

19,000 

(1310) 

414,000 

(187 755) 

385,000 

(174 633) 

8 spf SH 

4 (1.22) 151 (69) 134 (61) 

100156995 HMX SH 8 (2.44) 245 (111) 207 (94) 

101233690 HMX SH/LD 11 (3.35) 316 (143) 262 (119) 

16 (4.88) 420 (191) 353 (160) 

22 (6.71) 574 (260) 462 (210)

Charge 

Part No. 

Explosive 

Type 

Charge 

Type 


SPF Phasing 

Gun 

Material 

Type 

Gun Thread 

100005319 RDX BH 11 140°/160° Premium Vann 

100005326 RDX BH/LD 140°/160° Standard Vann 

Pressure 

Rating 

psi (bar) 

16,000 

(1103) 

Tensile 

Strength 

lb (kg) 

Weights 


14,000 

(965) 

414,000 

(187 755) 

385,000 

(174 633) 

Length 

ft (m) 

Loaded 

lb (kg) 

11 spf BH 

Spacer 

lb (kg) 

4 (1.22) 153 (69) 129 (59) 

100157006 HMX BH 8 (2.44) 252 (114) 197 (89) 

120038060 HMX BH/LD 11 (3.35) 326 (148) 248 (112) 

100005324 RDX DP 16 (4.88) 438 (199) 334 (151) 

100014352 HMX DP 22 (6.71) 600 (272) 436 (198) 


101343830 HNS DP 

100005324 RDX DP 12 

100005325 RDX DP/LD 

30°/150° 

OMNI 

30°/150° 

OMNI 

Premium Vann 


20,000 

(1379) 

19,000 

(1310) 

414,000 

(187 755) 

385,000 

(174 633) 


4 (1.22) 158 (72) 127 (58) 

100014352 HMX DP 8 (2.44) 262 (119) 194 (88) 

100005340 HMX DP/LD 11 (3.35) 340 (154) 244 (111) 

101210674 HMX Millennium 16 (4.88) 459 (208) 327 (148) 

101343830 HNS DP 22 (6.71) 626 (284) 427 (194) 

100005319 RDX BH 12 spf BH 

100005326 RDX BH/LD 4 (1.22) 154 (70) 127 (58) 

100157006 HMX BH 8 (2.44) 254 (115) 194 (88) 

120038060 HMX BH/LD 11 (3.35) 328 (149) 244 (111) 

100005311 RDX SH 16 (4.88) 442 (200) 327 (148) 

101228756 RDX SH/LD 22 (6.71) 602 (273) 427 (194) 

100156995 HMX SH 12 spf SH 

101233690 HMX SH/LD 4 (1.22) 150 (68) 127 (58) 

8 (2.44) 245 (111) 194 (88) 

11 (3.35) 315 (143) 244 (111) 

16 (4.88) 422 (191) 327 (148) 

22 (6.71) 575 (261) 427 (194)

Charge 

Part No. 

Explosive 

Type 

Charge 

Type 

100005311 RDX SH 14 

100156995 HMX SH 


SPF Phasing 

25.7°/ 

128.5° 

25.7°/ 

128.5° 

Gun 

Material 

Type 

Gun Thread 

Premium Vann 



100157005 HMX DP 45°/135° Standard Vann 

Pressure 

Rating 

psi (bar) 

20,000 

(1379) 

19,000 

(1310) 

20,000 

(1379) 

19,000 

(1310) 

Tensile 

Strength 

lb (kg) 

414,000 

(187 755) 

385,000 

(174 633) 

414,000 

(187 755) 

385,000 

(174 633) 

14 spf SH 

4 (1.22) 150 (68) 124 (56) 

8 (2.44) 244 (111) 188 (85) 

11 (3.35) 315 (143) 235 (107) 

16 (4.88) 422 (192) 314 (142) 

22 (6.71) 575 (261) 410 (186) 


Length 

ft (m) 

Weights 

Loaded 

lb (kg) 

18 spf 

Spacer 

lb (kg) 

4 (1.22) 139 (63) 118 (54) 

8 (2.44) 222 (101) 176 (80) 

11 (3.35) 285 (129) 219 (99) 

16 (4.88) 379 (172) 291 (132) 

22 (6.71) 513 (233) 378 (171)

Charge 

Part No. 

Explosive 

Type 

Charge 

Type 

100005324 RDX DP 12 

100005325 RDX DP/LD 


SPF Phasing 

30°/150° 

OMNI 

30°/150° 

OMNI 

Gun 

Material 

Type 

Gun Thread 

Premium Vann 


Pressure 

Rating 

psi (bar) 

21,000 

(1447) 

19,000 

(1310) 

Tensile 

Strength 

lb (kg) 

516,000 

(234 014) 

480,000 

(217 724) 

Weights 


Length 

ft (m) 

Loaded 

lb (kg) 

12 spf BH 

Spacer 

lb (kg) 

4 (1.22) 169 (77) 144 (65) 

100014352 HMX DP 8 (2.44) 284 (129) 228 (103) 

100005340 HMX DP/LD 11 (3.35) 370 (168) 291 (132) 


101343830 HNS DP 22 (6.71) 685 (311) 521 (236) 

100005319 RDX BH 12 spf DP 

100005326 RDX BH/LD 4 (1.22) 166 (75) 144 (65) 

100157006 HMX BH 8 (2.44) 277 (126) 228 (103) 

120038060 HMX BH/LD 11 (3.35) 361 (164) 291 (132) 

100005311 RDX SH 16 (4.88) 491 (223) 395 (179) 

101228756 RDX SH/LD 22 (6.71) 666 (302) 521 (236) 

100156995 HMX SH 12 spf Millennium 

101233690 HMX SH/LD 4 (1.22) 173 (78) 144 (65) 

8 (2.44) 292 (132) 228 (103) 

11 (3.35) 381 (173) 291 (132) 

16 (4.88) 522 (237) 395 (179) 

22 (6.71) 709 (321) 521 (236) 

12 spf SH 

4 (1.22) 165 (75) 144 (65) 

8 (2.44) 275 (125) 228 (103) 

11 (3.35) 357 (162) 291 (132) 

16 (4.88) 485 (220) 395 (179) 

22 (6.71) 657 (298) 521 (236)

Charge 

Part No. 

Explosive 

Type 

Charge 

Type 


SPF Phasing 

Gun 

Material 

Type 

Gun Thread 

Pressure 

Rating 

psi (bar) 

Tensile 

Strength 

lb (kg) 

Weights 


Length 

ft (m) 

Loaded 

lb (kg) 

101321963 RDX Maxim 6 45°/135° Premium Vann 6 spf SH 

101350449 RDX Maxim 8 45°/135° Premium Vann 

100005311 RDX SH 12 

30°/150° 

OMNI 

Premium Vann 

20,000 

(1379) 

18,000 

(1241) 

427,000 

(193 651) 

427,000 

(193 651) 

Spacer 

lb (kg) 

4 (1.22) 175 (79) 152 (69) 

8 (2.44) 280 (127) 230 (104) 

11 (3.35) 359 (163) 288 (131) 

16 (4.88) 490 (222) 385 (175) 

22 (6.71) 648 (294) 502 (228) 

12 spf SH 

4 (1.22) 175 (79) 152 (69) 

8 (2.44) 280 (127) 230 (104) 

101228756 RDX SH/LD 11 (3.35) 359 (163) 288 (131) 

100156995 HMX SH 16 (4.88) 490 (222) 385 (175) 

101233690 HMX SH/LD 22 (6.71) 648 (294) 502 (228) 

101307494 RDX Mirage ® 

100005311 RDX SH 14 

25.7°/ 

128.5° 

Premium Vann 

17,000 

(1172) 

427,000 

(193 651) 

14 spf SH 

101228756 RDX SH/LD 4 (1.22) 177 (80) 152 (69) 

100156995 HMX SH 8 (2.44) 286 (130) 230 (104) 

101233690 HMX SH/LD 11 (3.35) 368 (167) 288 (131) 

16 (4.88) 504 (228) 386 (175) 

22 (6.71) 667 (302) 503 (228)

Charge 

Part No. 

Explosive 

Type 

Charge 

Type 


SPF Phasing 

Gun 

Material 

Type 

Gun Thread 

101268719 RDX SH 18 60°/120° Premium Vann 


Pressure 

Rating 

psi (bar) 

17,000 

(1172) 

427,000 

(193 651) 

18 spf SH 

3/Plane 4 (1.22) 181 (82) 152 (69) 

16,000 

(1103) 

Tensile 

Strength 

lb (kg) 

427,000 

(193 651) 

Weights 

8 (2.44) 296 (134) 229 (104) 

11 (3.35) 383 (174) 288 (130) 

16 (4.88) 527 (239) 385 (174) 

22 (6.71) 701 (318) 501 (227) 

21 spf BH 

3/Plane 4 (1.22) 185 (84) 152 (69) 

8 (2.44) 304 (138) 229 (104) 

11 (3.35) 393 (178) 287 (130) 

16 (4.88) 540 (245) 384 (174) 

22 (6.71) 717 (325) 500 (227) 


Length 

ft (m) 

Loaded 

lb (kg) 

Spacer 

lb (kg)

Charge 

Part No. 

Explosive 

Type 

Charge 

Type 


SPF Phasing 

Gun 

Material 

Type 

Gun Thread 

101240223 RDX SH 6 135° Premium Vann 

100005319 RDX BH 12 OMNI Premium Vann 

100005326 RDX BH/LD OMNI Premium 

Industry 


Pressure 

Rating 

psi (bar) 

18,000 

(1241) 

16,000 

(1103) 

16,000 

(1103) 

Tensile 

Strength 

lb (kg) 

520,000 

(235 868) 

520,000 

(239 929) 

520,000 

(239 929) 

Weights 


Length 

ft (m) 

Loaded 

lb (kg) 

6 spf SH 

Spacer 

lb (kg) 

4 (1.22) 185 (84) 152 (69) 

8 (2.44) 304 (138) 229 (104) 

11 (3.35) 393 (178) 287 (130) 

16 (4.88) 540 (245) 384 (174) 

22 (6.71) 717 (325) 500 (227) 

12 spf 22.7 g 

4 (1.22) 181 (82) 157 (71) 

100157006 HMX BH 8 (2.44) 290 (132) 239 (108) 

120038060 HMX BH/LD 11 (3.35) 372 (169) 300 (136) 

100005324 RDX DP 16 (4.88) 505 (229) 401 (182) 

100005325 RDX DP/LD 22 (6.71) 672 (305) 523 (237) 

100014352 HMX DP 12 spf 28 g SH 

100005340 HMX DP/LD 4 (1.22) 180 (81) 157 (71) 


101343830 HNS DP 11 (3.35) 368 (167) 300 (136) 

100005311 RDX SH 16 (4.88) 499 (226) 401 (182) 

101228756 RDX SH/LD 22 (6.71) 663 (301) 523 (237) 

100156995 HMX SH 

101233690 HMX SH/LD 

101307494 RDX Mirage ®

Charge 

Part No. 

Explosive 

Type 

Charge 

Type 

100157007 RDX SH 14 


SPF Phasing 

25.7°/ 

128.5° 

Gun 

Material 

Type 

Gun Thread 

Premium Vann 

16,000 

(1103) 

520,000 

(239 929) 

14 spf 28 g SH 

100157011 HMX SH 4 (1.22) 182 (82) 157 (71) 


Pressure 

Rating 

psi (bar) 

16,000 

(1103) 

Tensile 

Strength 

lb (kg) 

520,000 

(239 929) 

8 (2.44) 292 (133) 238 (108) 

11 (3.35) 375 (170) 298 (135) 

16 (4.88) 511 (232) 399 (181) 

22 (6.71) 679 (308) 520 (236) 

14 spf 32 g SH 

4 (1.22) 186 (84) 157 (71) 

8 (2.44) 302 (137) 238 (108) 

11 (3.35) 389 (176) 298 (135) 

16 (4.88) 531 (241) 399 (181) 

22 (6.71) 708 (321) 520 (236) 


Length 

ft (m) 

Weights 

Loaded 

lb (kg) 

21 spf 

Spacer 

lb (kg) 

3/Plane 4 (1.22) 190 (86) 156 (71) 

8 (2.44) 311 (141) 236 (107) 

11 (3.35) 402 (182) 296 (134) 

16 (4.88) 553 (251) 395 (179) 

22 (6.71) 734 (333) 515 (234)

Charge 

Part No. 

Explosive 

Type 

Charge 

Type 

100157007 RDX SH 14 

101307494 RDX Mirage ® 


SPF Phasing 

25.7°/ 

128.5° 

Gun 

Material 

Type 

Gun Thread 

Premium Vann 

10 45°/135° Premium Vann 

Pressure 

Rating 

psi (bar) 

17,000 

(1172) 

17,000 

(1172) 

Tensile 

Strength 

lb (kg) 

512,000 

(232 200) 

512,000 

(232 200) 

Weights 


Length 

ft (m) 

Loaded 

lb (kg) 

14 spf SH 

Spacer 

lb (kg) 

4 (1.22) 216 (98) 192 (87) 

101357518 RDX Maxim 8 (2.44) 344 (156) 293 (133) 


Charge 

Part No. 

Explosive 

Type 

Charge 

Type 

100156993 RDX DP 12 

16,000 

(1103) 


SPF Phasing 

51.4°/ 

154.2° 

Gun 

Material 

Type 

Gun Thread 

Premium Vann 

Pressure 

Rating 

psi (bar) 

15,000 

(1034) 

512,000 

(232 200) 

Tensile 

Strength 

lb (kg) 

672,000 

(304 762) 

11 (3.35) 442 (200) 369 (167) 

16 (4.88) 647 (294) 496 (225) 

22 (6.71) 859 (389) 648 (294) 

21 spf SH 

4 (1.22) 216 (98) 192 (87) 

8 (2.44) 344 (156) 293 (133) 

11 (3.35) 442 (200) 369 (167) 

16 (4.88) 647 (294) 496 (225) 

22 (6.71) 859 (389) 648 (294) 

Length 

ft (m) 

Weights 

Loaded 

lb (kg) 

12 spf DP 

Spacer 

lb (kg) 

100156994 HMX DP 4 (1.22) 272 (123) 216 (98) 

100156992 HMX BH 8 (2.44) 447 (203) 318 (144) 

100156991 RDX BH 15 (4.57) 706 (320) 497 (225) 

12 spf BH 

4 (1.22) 251 (114) 216 (98) 

8 (2.44) 398 (181) 318 (144) 

15 (4.57) 608 (276) 497 (225)

Charge 

Part No. 

Explosive 

Type 

Charge 

Type 


SPF Phasing 

Gun 

Material 

Type 

Gun Thread 

101228037 RDX Mirage ® 12 45°/135° Premium Vann 

Pressure 

Rating 

psi (bar) 

15,000 

(1034) 

Tensile 

Strength 

lb (kg) 

480,000 

(217 687) 

Weights 


Length 

ft (m) 

Loaded 

lb (kg) 

12 spf BH Mirage 

Spacer 

lb (kg) 

101304878 RDX Mirage 4 (1.22) 275 (125) 240 (109) 

101213474 RDX SH 8 (2.44) 431 (195) 354 (160) 

101212693 RDX SH/LD 16 (4.88) 733 (333) 582 (264) 

101357518 RDX Maxim 12 spf SH/LD 

101228037 RDX Mirage 14 138° Premium Vann 

15,000 

(1034) 

480,000 

(217 687) 

4 (1.22) 277 (126) 240 (109) 

8 (2.44) 435 (197) 354 (160) 

16 (4.88) 743 (337) 582 (264) 

14 spf SH Mirage 

101304878 RDX Mirage SH 4 (1.22) 277 (124) 240 (109) 

101213474 RDX SH 8 (2.44) 437 (198) 354 (160) 

101357518 RDX Maxim 16 (4.88) 754 (342) 582 (264) 

14 spf SH 

4 (1.22) 283 (128) 240 (109) 

8 (2.44) 451 (205) 354 (160) 

16 (4.88) 784 (355) 582 (264)

Charge 

Part No. 

Explosive 

Type 

Charge 

Type 

6 1/2-in. High-Pressure Premium VannGun ® Assemblies 

SPF Phasing 

Gun 

Material 

Type 

Gun Thread 

101228037 RDX Mirage ® 12 45°/135° Premium Vann 

Pressure 

Rating 

psi (bar) 

20,000 

(1379) 

Tensile 

Strength 

lb (kg) 

719,000 

(326 132) 

Weights 


Length 

ft (m) 

Loaded 

lb (kg) 


Spacer 

lb (kg) 

101304878 RDX Mirage SH 4 (1.22) 298 (135) 268 (121) 

101213474 RDX SH 8 (2.44) 476 (216) 410 (186) 

101212693 RDX SH/LD 16 (4.88) 824 (370) 684 (310) 

101357518 RDX Maxim 12 spf SH/LD 


20,000 

(1379) 

480,000 

(217 687) 

4 (1.22) 300 (136) 268 (121) 

8 (2.44) 481 (218) 410 (186) 

16 (4.88) 834 (378) 684 (310) 


101304878 RDX Mirage SH 4 (1.22) 300 (136) 268 (121) 

101213474 RDX SH 8 (2.44) 482 (219) 410 (186) 

101357518 RDX Maxim 16 (4.88) 841 (382) 684 (310) 

14 spf SH 

4 (1.22) 305 (138) 268 (121) 

8 (2.44) 496 (225) 410 (186) 

16 (4.88) 871 (395) 684 (310)

Charge 

Part No. 

Explosive 

Type 

Charge 

Type 


SPF Phasing 

Gun 

Material 

Type 

Gun Thread 

100005325 RDX DP/LD 12 45°/135° Premium Vann 

100005340 HMX DP/LD 45°/135° Premium 

Industry 


Pressure 

Rating 

psi (bar) 

Tensile 

Strength 

lb (kg) 

Weights 


13,000 

(897) 

13,000 

(897) 

802,000 

(363 719) 

802,000 

(363 719) 

Length 

ft (m) 

Loaded 

lb (kg) 


Spacer 

lb (kg) 

4 (1.22) 326 (148) 292 (132) 

101228037 RDX Mirage ® 8 (2.44) 494 (224) 421 (191) 

101304878 RDX Mirage 16 (4.88) 831 (377) 679 (308) 

101213474 RDX SH 12 spf SH/LD 

101212693 RDX SH/LD 4 (1.22) 328 (149) 292 (132) 


101357518 RDX Maxim 16 (4.88) 841 (381) 679 (308) 


13,000 

(897) 

802,000 

(363 719) 


4 (1.22) 356 (161) 292 (132) 

8 (2.44) 565 (256) 421 (191) 

16 (4.88) 984 (446) 679 (308) 


101304878 RDX Mirage SH 4 (1.22) 328 (149) 291 (132) 

101213474 RDX SH 8 (2.44) 501 (227) 420 (190) 

101357518 RDX Maxim 16 (4.88) 847 (384) 677 (307) 

14 spf SH 

4 (1.22) 334 (151) 291 (132) 

8 (2.44) 515 (234) 420 (190) 

16 (4.88) 877 (398) 677 (307)

Charge 

Part No. 

Explosive 

Type 

Charge 

Type 


SPF Phasing 

Gun 

Material 

Type 

Gun Thread 

101414821 HMX Mirage ® 18 60°/120° Premium Vann 

101414821 HMX Mirage 18 60°/120° Premium Vann 

Pressure 

Rating 

psi (bar) 


13,000 

(897) 

20,000 

(1379) 

Tensile 

Strength 

lb (kg) 

802,000 

(363 719) 

802,000 

(363 719) 

Length 

ft (m) 

Weights 

Loaded 

lb (kg) 


4 (1.22) 334 (151) 291 (132) 

8 (2.44) 515 (234) 420 (190) 

16 (4.88) 877 (398) 677 (307) 

18 spf SH Mirage XHP 

Spacer 

lb (kg) 

4 (1.22) 334 (151) 291 (132) 

8 (2.44) 515 (234) 420 (190) 

16 (4.88) 877 (398) 677 (307)

Gun Size 

in. 

1.563 

2 

2.5 

2.75 

Gun Washover/Fishing Specifications 

Gun OD 

in.* 

(Gun OD after 

shooting) 

Maximum Shot 

(Density) per foot 

SPF 

1.745 4 

1.76 6 

2.166 4 

2.203 6 

TBD* 4 

2.67 6 

2.97 4 

2.79 5 

3.09 6 

Minimum Casing 

Size 

(for washing over 

w/o 

milling guns) 


4 in. 

4 in. 

4.5 in. 13.5 #/ft 

4.5 in. 9.5 #/ft 

3.125 3.25 9 5 in. 15 #/ft 

3.375 

3.68 4 

3.68 6 

3.53 12 

5.5 in. 23 #/ft 

4 4.26 6 6 5/8 in. 35 #/ft 

4.625 

5 

5.125 

4.87 5 

4.88 6 

4.86 8 

4.87 11 

4.96 12 

4.79 14 

5.2 12 

5.3 14 

5.23 18 

5.41 6 

5.21 12 

5.38 14 

5.36 21 

7 in. 35 #/ft 

7 in. 26 #/ft/** 

7 5/8 in. 39 #/ft 

6 6.79 12 9 5/8 in. 

6.5 6.76 14 9 5/8 in. 71.8 #/ft 

7 

7.14 12 

7.15 14 

9 5/8 in. 58.4 #/ft 

*Worst Case-Atmospheric pressure, submerged in water. 

**It is possible to washover 5 in. guns in 7 in. 29-lb casing, but washover pipe to be used is 

not a common size and is difficult to find.

OD SPF 

1 9/16 6 

2 

Gun Swell Information 

Gun Charge Test Results 

Shot Phase 

deg 

Charge 

Part No. 

Type 

Explosive Weight 

gm 

Tested In 

Air/Water 

Maximum Swell 

in. 

60 100157028 

1.760 

Millennium 3.4 water 

0 100157028 1.705 

4 0 100008017 

air 2.246 

SDP 

60 100008017 

2.221 

6.8 

0 101208224 

water 

2.177 

6 

Millennium 

101208224 2.225 

60 

101603801* MaxForce ® 7 air 2.193 

2.38 6 60 101590845 MaxForce 10 water 2.529 

2 1/2 6 60 

101206251 DP 11 water 2.680 

101418095* Millennium II 11.1 air 2.705 

4 

5 

22 LS 

180 

100158220 

100158220 

100157026 

DP LD 

SDP 

13 

13 

14.7 

water 

2.781 

2.810 

2.971 

2 3/4 

6 

60 

100005329 

100005329 

100158220 

101206793 

DP 

DP LD 

BH 

12.5 

12.5 

13 

14.7 

air 

2.853 

2.898 

2.893 

2.850 

100010399 SDP 14.7 water 

2.954 

60 LS 

101233817 

101233817 

Millennium 

15 

15 

2.892 

2.915 

2 7/8 6 60 101233817 Millennium 15 water 3.047 

2 7/8 HW 6 60 101233817 Millennium 15 air 3.044 

2.88 6 60 101388407 Millennium HNS 18.5 water 3.060 

3 1/8 6 60 101388406 Millennium 17.5 HMX 3.333 

3.38 5 60 101320075 Dominator ® 25 water 3.497 

G-Force 

3 3/8 

® 

180 101233817 Millennium 15 water 3.42 

4 

60 

90 

100005322 

100005327 

100005327 

DP 

32 

32 

32 

air 

water 

3.676 

3.592 

3.555 

180 100008249 SDP 25 3.546 

100005333 DP 22 air 3.610 

6 

60 

60 LS 

100008249 

101207640 

100008249 

SDP 

SDP LD 

SDP 

25 

24 

25 

3.600 

3.615 

3.600 

60 

101233819 

101309223 

Millennium 

Dominator 

25 

25 

water 

3.645 

3.695 

8 180 100008251 

14 3.458 

12 

12 

30/150 

100008251 

100005312 

BH 

14 

14 

3.520 

3.568 

3 1/2 6 60 101309223 Dominator 25 air 3.845 

4 

4 

7 

90 

150 

101210636 

101228756 

Millennium 

SH LD 

39 

28 

water 

water 

4.260 

4.280 

Perforating Solutions 5-39

OD SPF 

4.25 8 150 101228756 SH LD 28 water 4.487 

4 5/8 

5 

G-Force ® 

180 100005327 DP 32 water 4.696 

4 10/350 101466192 KleenZone 39 water 4.705 

5 

6 60 

8 180 

60 101210636 Millennium 39 air 4.944 

45/135 101321963 SH 56.5 water 4.904 

100005327 

32 air 4.876 

DP 

100005327 32 water 4.806 

100005326 

23 air 4.860 

DP LD 

100005326 23 

4.780 

100005311 SH 28 4.770 

11 140/160 100005324 

22.7 4.868 

DP 

100014352 23 4.834 

12 30/150 

Gun Swell Information 

Gun Charge Test Results 

Shot Phase 

deg 

Charge 

Part No. 

Type 

100005340 DP LD 22.7 4.925 

water 

100005326 BH LD 22.7 4.840 

100005311 SH 

Explosive Weight 

gm 

101228756 SH LD 28 

4.895 


4.813 

14 25.7/128.5 100005311 SH 4.790 

18 45/135 100156990 BH 20 4.730 

8 135 101350449 Maxim 47 water 5.202 

12 30/150 100005311 

5.196 

SH 

100005311 5.207 

14 25.7/128.5 

28 

101228756 SH LD water 

5.304 

18 

101269719 SH 5.229 

60/120 

21 101292616 BH 21 5.198 

6 45/135 101240223 SH 56.5 

Tested In 

Air/Water 

Maximum Swell 

in. 

5 1/8 

12 

14 

30/150 

25.7/128.5 

100005326 

100157007 

BH LD 

SH 

22.7 

32 

water 

5.210 

5.332 

21 60/120 101292616 BH 20 5.268 

5 3/4 

14 

21 

25.7/128.5 

3/plane 60 

101272769 

101292616 

SH LD 

BH 

34 

21 

water 

water 

5.945 

6.065 

6 1/2 

14 138 101304878 Mirage ® BH 47 

water 

6.685 

12 45/135 101212693 SH LD 56.5 6.715 

6 1/2 HP 12 45/135 101212693 SH LD 56.5 water 6.762 

7 

12 

14 

45/135 

138 

101210063 

101213474 

SH LD 

SH 

56.5 water 

7.125 

7.143 

18 3/plane 60 101498239 BH LD 45 water 7.130 

*Special gun length requirements 

The above chart was taken from actual tests conducted by Halliburton Technology on RDX and HMX charges. It can be used as a 

general guideline for all explosives. If you have questions regarding these systems, or systems that are not listed, please contact your 

local Halliburton representative. 

All tests were conducted at ambient temperature and pressure. 

5.413

Capsule Gun Systems 

Dyna-Star ® Capsule Gun 

Jet Research Center’s Dyna-Star® capsule gun is an 

economical, second-generation capsule perforating system. 

This system is partially expendable and uses a stainless steel 

strip in its through-tubing technology. 

Applications 

2.125-in. and 1.6875-in. gun systems at 4-spf and 6-spf 

1.6875-in. system rated at 14,000 psi and up to 370°F 

(HMX version) in dry gas or fluid 

2.125-in. system rated at 15,000 psi and up to 370°F 

(HMX version) in dry gas or fluid 

Rated up to 370°F (HMX version) in dry gas or fluid— 

may be used in hostile environments only if special 

precautions are taken. Contact JRC for more 

information 

Features 

Deep penetrating charges 

Uses same charges as the Dyna-Cap® four-wire strip gun 

to minimize inventory 

Available in 0° phasing 

Rollover sleeves to keep the gun in its optimum 

orientation 

Can cut guns to required length in the field 

Economical operation 

Can use 18-ft long strips without tandem 

Ease of gun retrieval after shooting 

Dyna-Star® Capsule Gun 


HAL11757

Deep Star Capsule Gun 

Jet Research Center's Deep Star perforating system is a 

third-generation, state-of-the-art, through-tubing capsule 

perforating system with improved charge performance and 

running characteristics. 

Applications 

2.125-in. and 1.6875-in. OD gun systems 

Rated at 15,000 psi and 350°F in dry gas, fluid, or hostile 

environments 

Higher ratings available upon request 

Designed for deep, high temperature, high pressure wells 

Features 

Extremely deep penetrating charges 

Higher shot densities without charge interference (up to 

8-spf with the 1.6875-in. system-patent pending) 

attained using hydrodynamic modeling techniques 

Most available in seven phasings: 0°, 90° downside, 90° 

spiral, triphase (patented), pentaphase, heptaphase, and 

octaphase 

Compatible interval coverage with the innovative “gullwing” 

tandem (patented), which minimizes strip 

deformation, allowing easier retrieval 

Hardware offset in conjunction with charge center 

gravity to optimize gun stability and orientation 

Corrosion-resistant steel alloy charge cases and carrier 

strips permit the use of the Deep Star system in hostile 

environments 

No gaps in shot pattern at joints in strips 

Ease of gun removal after shooting 

2.125-in. 90° Spiral Phase Deep Star Capsule Gun 


HAL11758

1.6875-in. and 2.125-in. Deep Star Debris Fill Data 

Inches of Fill Per Charge 

1.2 

1.0 

0.8 

0.6 

0.4 

0.2 

HAL11759 

0 

2.125-in. 

1.6875-in. 

1 2 3 4 5 6 7 8 9 10 

Pipe ID (inches) 

Pipe OD 

in. 

Deep Star Fill Data (Shot in Water) 

Pipe Weight 

lb/ft 

Pipe ID 

in. 

2 3/8 4.7 1.995 

2 7/8 6.5 2.441 

3 1/2 9.3 2.992 

4 11.0 3.476 

4 1/2 11.6 4.000 

5 15.0 4.408 

5 1/2 17.0 4.892 

7 32.0 6.094 

7 5/8 33.7 6.765 

9 5/8 47.0 8.681 

Notes: 

1. Fill data is approximate. 

2. When shot in gas, the debris is smaller and will occupy less volume. 

Fill per 1 11/16-in. 

Charge 

in. (mm) 

Fill per 2 1/8-in. 

Charge 

in. (mm) 


0.322 

(8.17) 

0.215 

(5.45) 

0.143 

(3.63) 

0.106 

(2.69) 

0.080 

(2.03) 

0.066 

(1.67) 

0.053 

(1.36) 

0.034 

(0.88) 

0.028 

(0.71) 

0.017 

(0.43) 

0.920 

(23.37) 

0.615 

(15.61) 

0.409 

(10.39) 

0.303 

(7.70) 

0.229 

(5.81) 

0.188 

(4.79) 

0.153 

(3.89) 

0.099 

(2.50) 

0.080 

(2.03) 

0.049 

(1.23) 

11

Ported Gun Perforating System 

Jet Research Center’s ported gun perforating systems provide 

users with economical, reusable guns for multi-purpose 

applications. 

Applications 

Multi-zone shooting on a single run with select fire subs 

Hostile environment 

Short guns available for squeeze applications 

Features 

Charges are protected from well fluids, formation 

pressure, and abrasion 

Debris retained in hollow carrier 

Carrier protects casing from detonation shock 

Charges for high-temperature environments are 

available upon request 

Charges are tested to API standards 

Charges are designed to minimize internal damage to the 

gun body, prolonging life 

The gun design has minimized charge interference 

Options 

3.125-in. to 5-in. gun sizes 

Big-hole and deep penetrating charges 

90° and 120° phasing (other phase angles available upon 

request) 

3.125-in. Ported Gun 


HAL11760

Firing Heads 

Detonation Interruption Device 

The detonation interruption device (DID) provides added 

safety for the VannSystem® service by helping to prevent 

firing at surface conditions. This device contains a eutectic 

metal that has a very low melting point. When the metal is 

in a solid state, the firing head could detonate, but the 

explosive train will not transmit through the interrupt 

device to the guns. 

Features 

Compatible with other firing heads 

Disables transmission of explosive train at the surface 

Used with redundant firing heads 

Operation 

The eutectic metal will remain solid as the assembly lowers 

into the hole (assuming the tool temperature is below 117°F). 

When exposed to the bottomhole temperature (minimum 

135°F for operational purposes), the metal becomes liquid, 

allowing the transfer of the explosive train from the firing 

head to the gun. 

To help prevent accidental gun detonation when lowering or 

retrieving unfired guns, the metal returns to a solid state 

upon reaching a cooler surface temperature. 

Note: The eutectic material utilized actually melts at 117°F. 

At 117°F or above, the DID assembly will not prevent 

detonation. For safe operation, it should be assumed that 

detonation transfer will occur if the tool is at or above 110°F. 

SAP No. 

100155745 

101204860 

100155746 

Thread Size 

and Type 

in. (mm) 

2 (50.8) 6 

Acme 2G 

2 3/8 (60.33) 6P 

Acme Box × Pin 

2 7/8 (73.03) 6P 


Detonation Interruption Device 

Detonation Interruption Device (DID) Specifications 

Maximum OD 

in. (mm) 

2.50 

(63.5) 

2.75 

(69.85) 

3.375 

(85.73) 

Makeup Length 

ft (m) 

1.58 

(0.48) 

3.70 

(1.13) 

3.04 

(0.93) 


HAL10519 

Maximum Operating 

Pressure 

psi (bar) 

N/A 

20,000 

(1380) 

25,000 

(1725) 

Maximum temperature is determined by explosives. 

These ratings are guidelines only. For more information, consult your local Halliburton representative. 

Minimum Required 


°F (°C) 

135 

(57) 

135 

(57) 

135 

(57) 

Tensile Strength 

lb (kg) 

121,000 

(54 885) 

140,000 

(63 400) 

246,000 

(111 500)

Mechanical Firing Head 

The extended mechanical firing head (MFH) is a special 

application tool. It should be used only when well conditions 

preclude the use of an alternate firing device. Whenever it is 

used on a job, the MFH must be used according to 

Halliburton standard operating procedures. 

Operation 

The operation of the MFH depends on the amount of force 

delivered to the firing pin by the detonating bar. This firing 

pin must be hit with enough force to shear the spiral pin, 

which holds the firing pin in place, and to detonate the 

initiator. The firing pin is driven into a percussion detonator, 

which fires the guns. 

The detonation interruption device (DID) and a minimum 

of 10 ft of safety spacer must always be used with the MFH. 

SAP No. 

100155741 

100005223 

100005228 

Thread Size 


in. (mm) 

1 7/16 (36.51) 8 UN 2 B Box × 

1.90 (48.26) NU 10 Rd Pin 

1.90 (48.26) NU 10 Rd Pin × 

2 3/8 (60.33) 6P Acme Box 

2 3/8 (60.33) EUE 8 Rd Pin × 

2 7/8 (73.03) 6P Acme Box 

Mechanical Firing Head (MFH) Specifications 

Maximum OD 

in. (mm) 

2.0 

(50.8) 

2.75 

(69.85) 

3.375 

(85.73) 


HAL15358 

Makeup Length 

(w/Tubing Sub) 

ft (m) 

1.48 

(.45) 

4.92 

(1.50) 

4.92 

(1.50) 

Mechanical Firing 

Head (MFH) 

Burst and collapse pressures are determined by handling sub. 

Temperature rating is determined by explosives. 



Pressure 

psi (bar) 

20,000 

(1380) 

20,000 

(1380) 

20,000 

(1380) 

HAL15376 

Firing Head 

Sub-Assembly 

Minimum ID 

(No-Go) 

in. (mm) 

1.53 

(38.86) 

1.56 

(39.62) 

1.56 

(39.62) 


(FH Body) 

lb (kg) 

60,000 

(27 200) 

140,000 

(63 400) 

238,000 

(107 900)

Model II-D Mechanical Firing Head 

The model II-D mechanical firing head is a pressure-assisted 

mechanical firing head. The detonating bar strikes the firing 

pin, releasing the firing piston. Hydrostatic pressure then 

forces the firing piston into the initiator. 

Features 

Cannot be detonated accidentally at surface 

Ideal for use in mud environments where spudding may be 

necessary 

Used in deviated wells 

Operation 

The model II-D firing head requires a minimum of 1,500 psi 

hydrostatic pressure in the tubing to actuate the firing head 

properly. 

Adding more pressure to the tubing after the detonating bar 

has struck the firing pin will not actuate the firing head. 

SAP No. 

100014156 

100005227 

Thread Size and Type 

in. (mm) 

1.90 (48.26) EUE 10 Rd 

Pin × 2 3/8 (60.33) 

6P Acme Box 

2 3/8 (60.33) EUE 8 Rd Pin 

× 2 7/8 (73.03) 6P Acme 


HAL15377 

Model II-D Mechanical 

Firing Head 

Model II-D Mechanical Firing Head Specifications 

Maximum 

OD 

in. (mm) 

2.75 

(69.85) 

3.375 

(85.73) 

Minimum ID 

(No-Go) 

in. (mm) 

1.56 

(39.62) 

1.56 

(39.62) 

Makeup Length 

(w/tubing sub) 

ft (m) 

4.92 

(1.50) 

4.92 

(1.50) 




Maximum 

Operating 

Pressure 

psi (bar) 

20,000 

(1380) 

20,000 

(1380) 

HAL15378 

Model II-D Mechanical 

Firing Head Assembly 

Minimum 

Operating 

Pressure 

psi (bar) 

1,500 

(103) 

1,500 

(103) 

Tensile 

Strength 

(FH body) 

lb (kg) 

140,000 

(63 400) 

238,000 

(107 900)

Model III-D Mechanical Firing Head 

The model III-D mechanical firing head is a pressure-assisted 

mechanical firing head. The detonating bar strikes the firing 

pin, releasing the firing piston. Hydrostatic pressure then 

forces the firing piston into the initiator. 

The model III-D firing head requires a minimal amount of 

hydrostatic pressure to actuate the firing head. 

Features 

Cannot be detonated accidentally at surface 

Requires minimal hydrostatic pressure to actuate the firing 

head 

Operation 

The model III-D firing head requires a minimum of 250 psi 

hydrostatic pressure in the tubing to actuate the firing head 

properly. This minimal actuating pressure is ideal for 

applications that require maximum differential pressures. 

If a detonating bar is dropped on the model III-D firing head 

with less than 250 psi hydrostatic pressure in the tubing, and 

the head does not fire, increasing the hydrostatic pressure in 

the tubing may cause it to fire. 

SAP No. 

100155742 

100005191 


in. (mm) 

1.90 (48.26) EUE 10 Rd Pin × 

2 3/8 (60.33) 6P Acme Box 

2 3/8 (60.33) EUE 8 Rd Pin × 

2 7/8 (73.03) 6P Acme Box 


HAL15379 

Model III-D Mechanical 

Firing Head 

Model III-D Mechanical Firing Head Specifications 

Maximum 

OD 

in. (mm) 

2.75 

(69.85) 

3.375 

(85.73) 

Minimum ID 

(No-Go) 

in. (mm) 

1.56 

(39.62) 

1.56 

(39.62) 

Makeup 

Length 

(w/Tubing Sub) 

ft (m) 

4.92 

(1.50) 

4.92 

(1.50) 




Maximum 

Operating 

Pressure 

psi (bar) 

8,000 

(550) 

8,000 

(550) 

HAL15380 

Model III-D Mechanical 


Minimum 

Operating 

Pressure 

psi (bar) 

250 

(17) 

250 

(17) 


(FH Body) 

lb (kg) 

140,000 

(63 400) 

238,000 

(107 900)

Pressure-Actuated Firing Head 

The 1 11/16-in. pressure-actuated firing head (PAF) can run 

with small-OD tubing or coiled tubing to detonate small-OD 

perforating guns. The PAF is detonated by applied pressure. 

Features 

Can be run on the top and bottom of the gun assembly 

Initiates a bridge-plug setting tool 

Initiates tubing cutters 

Detonates tubing punch charges for squeeze or 

circulating jobs 

Can be run to remain closed after detonation 

Can be modified to be run as a slickline-retrievable firing 

head and a time-delay firing head (TDF) 

Operation 

The 1 11/16-in. PAF consists of an upper housing with 

circulating ports, a firing piston that is shear-pinned in place 

across the circulating ports, and an initiator contained in a 

lower housing. 

Pressure applied to the tubing string shears the shear set, 

which forces the firing piston into the initiator to detonate 

the explosive component attached to the PAF. The downward 

movement of the firing piston opens the circulating ports. 

SAP No. 

100005224 

Thread Size 


in. (mm) 

1.315 (33.40) NU-10 Rd 

Pin × 17/16 (36.51) 

8 UN-2 B Box 

Pressure-Actuated 

Firing Head (PAF) 

Pressure-Actuated Firing Head (PAF) Specifications 

Maximum 

OD 

in. (mm) 

1.688 

(42.88) 

No. and ID 

of Ports 

in. (mm) 

2 @ 0.75 

(19.05) 

Flow Area 

of Ports 

in. 2 (cm 2 ) 

0.88 

(5.68) 

Makeup 

Length 

ft (m) 


0.73 

(0.22) 



HAL10561 

Maximum 

Operating 

Pressure 

psi (bar) 

17,000 

(1170) 

Minimum 

Operating 

Pressure 

psi (bar) 

2,200 

(150) 

Tensile 

Strength 

lb (kg) 

65,000 

(29 400) 

Collapse 

Pressure 

psi (bar) 

27,000 

(1860)

Model K and K-II Firing Heads 

The model K and K-II firing heads were 

developed for conditions that are 

unfavorable for dropping a detonating 

bar in a horizontal well. The model K 

and K-II firing heads are pressuresensitive 

tools designed to hydraulically 

detonate at a prescribed pressure. These 

firing heads use tubing pressure applied 

to a piston-type firing pin. 

Features 

Allows the operator to determine the 

exact time of firing the guns since the 

firing heads require a predetermined 

pressure before the guns can fire 

Works with full-opening or non-fullopening 

downhole tools 

Ideal for balanced or overbalanced 

perforating 

Can be used for dual completions, 

drillstem testing, or production 

perforating 

Well-suited for highly deviated well 

completions 

SAP No. 

100014211 

SAP No. 

100005190 

100014215 


in. (mm) 

2 7/8 (73.03) EUE 8 Rd Box × 

2 7/8 (73.03) 6P Acme Box 


in. (mm) 

1.90 (48.26) EUE 10 Rd Pin × 

2 3/8 (60.33) 6P Acme Box 

2 7/8 (73.03) EUE 8 Rd Box × 

2 7/8 (73.03) 6P Acme Box 

Can be run on the top or bottom of 

the perforating assembly 

Can be easily redressed 

Operation 

The model K and K-II firing heads are 

designed to provide a reliable and costeffective 

method for firing guns using 

hydrostatic pressure. Each firing head 

contains a firing piston that is shearpinned 

in place above an initiator. The 

number of shear pins used varies for 

each well situation. 

When enough hydrostatic pressure is 

applied to the piston, the shear pins 

shear, thereby allowing the firing pin on 

the lower end of the piston to be driven 

into the initiator. This action detonates 

the guns. These firing heads do not 

have a built-in delay. 

Model K Firing Head Specifications 

Maximum OD 

in. (mm) 

3.375 

(85.73) 

Makeup 

Length 

ft (m) 

1.25 

(0.38) 

Maximum 

Operating 

Pressure 

psi (bar) 

Minimum 

Operating 

Pressure 

psi (bar) 

Model K-II Firing Head 


13,000 

(895) 

Model K-II Firing Head Specifications 

Maximum 

OD 

in. (mm) 

2.75 

(69.85) 

3.375 

(85.73) 

Makeup 

Length 

ft (m) 

1.24 

(0.38) 

1.64 

(0.50) 

Maximum 

Operating 

Pressure 

psi (bar) 

19,500 

(1345) 

19,500 

(1345) 



Minimum 

Operating 

Pressure 

psi (bar) 

4,000 

(275) 

4,000 

(275) 

4,000 

(275) 

HAL15381 

Tensile 

Strength 

lb (kg) 

220,000 

(99 700) 


lb (kg) 

187,000 

(84 800) 

220,000 

(99 700) 

Collapse 

Pressure 

psi (bar) 

30,000 

(2070) 

Collapse 

Pressure 

psi (bar) 

25,000 

(1725) 

30,000 

(2070)

Model KV-II Firing Head 

The model KV-II firing head makes the 

firing of the guns and the opening of 

the vent one operation rather than two. 

This tool allows the operator more 

accurate control of when the vent opens 

in relation to when the guns fire. 

Features 

Useful in wells with open 

perforations where it is not possible 

to pressure up on the wellbore to 

actuate a firing head 

Useful in perforating and stimulation 

jobs where the tubing pressure 

exceeds the limitations of the casing 

Useful because the firing head and 

vent operate at one pressure 

Ideal for deviated wells 

Piston mechanically locked after 

firing 

SAP No. 

100014153 

100014155 

Thread Size 


in. (mm) 

2 3/8 (60.33) EUE 8 Rd Pin × 

2 3/8 (60.33) 6P Acme Box 

2 7/8 (72.88) EUE 8 Rd Pin × 

2 7/8 (72.88) 6P Acme Box 

Operation 

In many tubing conveyed perforating 

applications, it is either desirable or 

necessary to keep the tubing closed 

until the guns have been detonated. In 

the past, the tubing was kept closed by a 

firing head with some type of vent 

assembly. Coordination between the 

two tools was sometimes hard to 

achieve, and the vent often opened 

either too soon or too late. The model 

KV-II firing head combines a firing 

head and a vent assembly. 

In the model KV-II firing head, a piston 

is sheared to cause the guns to detonate 

and the ports to open and equalize (or 

vent) pressure. This venting feature 

allows operators to run the tubing in 

the hole dry if needed. In the standard 

KV-II firing head, the ports in the tool 

open the instant the firing head is 

actuated and the guns detonate. To 

delay the gun detonation, one or more 

delay devices may be added to the 

assembly. 

Model KV-II Firing Head Specifications 

Maximum 

OD 

in. (mm) 

2.75 

(69.85) 

3.375 

(85.73) 

Flow Area 

in. 2 (cm 2 ) 

2.79 

(18.0) 

3.14 

(20.27) 

Minimum Makeup 

Length 

ft (m) 

Maximum 

Operating 

Pressure 

psi (bar) 

Model KV-II 

Firing Head 


1.33 

(0.41) 

1.43 

(0.44) 



25,000 

(1725) 

25,000 

(1725) 

HAL15459 

Minimum 

Operating 

Pressure 

psi (bar) 

3,000 

(206) 

4,000 

(275) 

Maximum 

Differential 

Pressure 

psi (bar) 

15,000 

(1035) 

15,000 

(1035) 

Tensile 

Strength 

lb (kg) 

145,000 

(65 700) 

235,000 

(106 600)

Time-Delay Firer 

The time-delay firer (TDF) allows 

under- or overbalanced perforating 

through the use of a pressure-actuated 

firing head with a time-delay fuse. The 

delay fuse allows 4 to 6 minutes for 

adjusting the actuating pressure in the 

tubing to achieve the desired pressure 

before firing the guns. 

Features 

Allows independent perforating of 

selected zones 

Allows maximum use of under- or 

overbalanced pressure 

Can be run in heavy mud systems 

Can be used with full-opening or 

non-full-opening tools 

Reduces cost by allowing the running 

of multiple guns without gun spacers 

Ideal for production completions, 

drillstem testing, and dual 

completions 

Recommended for running on the 

top and bottom of gun assemblies 

Allows additional time-delay 

elements as needed for increasing 

delay time 

SAP No. 

100014157 

100005231 

100005230 

Thread Size 


in. (mm) 

1 7/16 (36.51) 8 UN-2 B Box × 

1.315 (33.4) NU-10 Rd Pin 

1.90 (48.26) EUE 10 Rd Pin × 

2 (50.8) 6P Acme Box 

2 7/8 (73.03) EUE 8 Rd Pin × 

2 7/8 (73.03) 6P Acme Box 

Operation 

The TDF is run with a predetermined 

number of shear pins for specific well 

conditions. The tubing is pressured to 

the maximum actuating pressure 

slowly. The maximum pressure shears 

the pins in the shear set and forces the 

firing piston into the primer. The 

primer ignites the pyrotechnic delay 

fuse. The delay fuse burns for a 

predetermined time (between 4 and 6 

minutes) depending on the bottomhole 

temperature and detonates the 

perforating assembly. 

Time-Delay Firer (TDF) Specifications 

Maximum 

OD 

in. (mm) 

1.688 

(42.88) 

2.50 

(63.5) 

3.375 

(85.73) 

Makeup 

Length 

ft (m) 

2.16 

(0.65) 

1.69 

(0.52) 

1.81 

(0.55) 

Maximum 

Operating 

Pressure 

psi (bar) 

21,500 

(1482) 

25,000 

(1723) 

Minimum 

Operating 

Pressure 

psi (bar) 

Time-Delay 

Firer (TDF) 


13,000 

(895) 

Temperature rating is determined by explosives or elastomers. 


2,200 

(150) 

4,000 

(275) 

4,000 

(275) 

HAL15382 

Temperature 

Rating 

°F (°C) 

425 (218) for 

200 hours 

425 (218) for 

200 hours 

350 (176) for 

500 hours 

Tensile 

Strength 

lb (kg) 

56,000 

(25 400) 

120,000 

(54 432) 

220,000 

(99 700) 

Collapse 

Pressure 

psi (bar) 

26,300 

(1813) 

30,000 

(2070) 

30,000 

(2070)

Multiaction-Delay Firing Head 

The multiaction-delay firing head is a pressure-actuated 

redundant firing system that can be run with any one of 

several other firing heads. 

Features 

Allows the use of a redundant firing head without having a 

firing head on the bottom of the gun string 

Allows multiple redundancy when a multiaction firing 

head is placed on both the top and bottom of the gun 

string 

Allows operators to postpone the decision of whether to 

use the bar drop or pressure side of the firing head as the 

primary firing mechanism 

Allows use of additional delay elements 

Operation 

One side of the multiaction firing head will always be 

pressure-actuated. The other side of the firing head may be a 

bar drop-type head or another pressure-actuated firing head. 

Either side of the firing head may be used as the primary or 

backup firing system. 

SAP No. 

100155753 

100155750 

Thread Size and 

Type 

in. (mm) 

2 3/8 (60.33) 6P 


2 7/8 (73.03) 6P 


Multiaction-Delay Firing Head Specifications 

Maximum OD 

in. (mm) 

3.10 

(78.74) 

3.375 

(85.73) 

Makeup 

Length 

ft (m) 

3.41 

(1.04) 

3.41 

(1.04) 


Pressure 

psi (bar) 

18,000 

(1240) 

25,000 

(1725) 



Multiaction-Delay 

Firing Head 


HAL10511 

Minimum Operating 

Pressure 

psi (bar) 

4,000 

(275) 

4,000 

(275) 

Tensile 

Strength 

lb (kg) 

170,000 

(77 100) 

201,000 

(91 100) 

Collapse 

Pressure 

psi (bar) 

22,000 

(1515) 

29,000 

(2000)

Annulus Pressure Firer-Control Line 

The annulus pressure firer-control line 

(APF-C) was developed as a dual-firing 

system that allows the perforating guns 

to be detonated by annular pressure, a 

drop bar, or tubing pressure. The 

APF-C system consists of a pressure 

transfer reservoir, a sleeve through the 

packer mandrel, an adapter below the 

packer, and a control line to transmit 

pressure from the annulus above the 

packer to the APF-C firing head 

assembly on top of the guns. Any of the 

mechanical or pressure-firing heads can 

be attached to the top of the APF-C 

firing head. 

Features 

Can be used with non-full-opening 

test tools and partially filled tubing 

strings 

Can be used for drillstem testing or 

shoot-and-pull for gravel packs 

Can be used wherever a pressureactuated 

tool is desirable 

Ideal for deviated wells 

Provides a system of two firing heads 

on top of the guns 

SAP No. 

100156138 

Thread Size 


in. (mm) 

2 7/8 (73.03) 6P 


Can be run with a mechanical or 

pressure-actuated firing head as a 

secondary firing mechanism 

Enhances safety because the annulusoperated 

portion is pressure balanced 

before the packer is set and the tester 

valve is opened 

Operation 

The APF-C system depends on the 

transfer of annular pressure through 

the packer down to the APF-C firing 

head. This pressure creates a differential 

pressure across the mandrel where the 

firing piston is housed. When the 

predetermined differential pressure is 

reached, the pins shear and the mandrel 

moves up and releases the firing piston, 

which is driven down by rathole 

pressure. The piston strikes the firing 

pin which detonates the initiator. 

The operation of the drop bar or 

pressure-actuated firing head depends 

on which firing head system is used. 

Annulus Pressure Firer-Control Line (APF-C) Specifications 

Maximum 

OD 

in. (mm) 

3.68 

(93.47) 

Makeup 

Length 

ft (m) 

3.70 

(1.13) 


Pressure 

psi (bar) 

20,000 

(1380) 




Pressure 

psi (bar) 

Annulus Pressure 

Firer-Control Line (APF-C) 

Firing Head 


250 

(17) 

HAL10515 

Tensile 

Strength 

lb (kg) 

174,000 

(78 900) 

Collapse 

Pressure 

psi (bar) 

17,000 

(1170)

Annulus Pressure Transfer Reservoir 

The annulus pressure transfer reservoir (APTR) is an integral 

component of the annulus pressure firer-control line 

(APF-C). The APTR is the mechanism that transmits pressure 

from above the packer to a differential pressure or pressureactuated 

firing (PAF) head on top of the perforating assembly. 

Features 

Features a full-opening ID 

Compatible with mud environments 

Adapted for RTTS and CHAMP® IV packers 

Ideal for applications that require a partial fluid column in 

the tubing string 

Eliminates the need for nitrogen 

Operation 

The APTR transmits annulus pressure into a microannulus 

created by the packer mandrel and the APTR 

mandrel. The pressure is ported to a control-line sub on 

the lower end of the packer. A stainless steel control line 

connects the APTR to the pressure-responsive firing head 

on the perforating assembly. 

SAP No. 

100156028 

101016453 

Maximum 

OD 

in. (mm) 

5.00 

(127.00) 

6.12 

(155.45) 

Packer Top 

Connection 


Transfer Reservoir 


Transfer Reservoir (APTR) 

Annulus Pressure Transfer Reservoir (APTR) Specifications 

Minimum 

ID 

in. (mm) 

2.00 

(50.8) 

2.37 

(60.20) 

Top 

Assembly 

3 1/2 

4 IF Box x 

3 7/8 

6 Stub Acme Pin 

4 1/2 4 IF 

Box x Pin 

Lower 

Assembly 

2 7/8 (73.03) 

EUE 8 Rd 

Box x Pin 

4 1/2 (114.3) 

4-IF Box x 

3 1/2 (88.90) 

EUE 8 Rd Pin 

Length Above 

Packer 

ft (m) 

Packer 

Bottom 

Connection 

Lower 

Control-Line 

Housing 


5.09 

(1.55) 

4.34 

(1.32) 

Temperature rating is determined by o-rings. 


HAL15439 

Length Below 

Packer 

ft (m) 

1.02 

(0.31) 

1.33 

(0.41) 

HAL15440 

Tensile 

Strength 

lb (kg) 

328,000 

(148 700) 

587,000 

(266 200) 

Burst 

Pressure 

psi (bar) 

18,000 

(1240) 

22,000 

(1515) 

Collapse 

Pressure 

psi (bar) 

15,000 

(1035) 

19,000 

(1310)

Slimhole Annulus Pressure Firer—Internal Control 

5-in. Annulus Pressure Transfer Reservoir 

The slimhole annulus pressure transfer reservoir (APTR) 

system assembles in a similar manner to the 7-in. and 

9 5/8-in. APTR systems. Only two design changes have been 

implemented in the new 5-in. APTR system. First, a series of 

concentric tubes below the packer replaces the control line 

from larger APTR systems. Second, a single tube mandrel 

runs through the packer, replacing the series of threaded tube 

mandrels from the larger APTR systems. 

3 1/8-in. Internal Control 

Concentric tubes eliminate the need for an external control 

line in slimhole casing. 

3 1/8-in. Annulus Pressure Transfer Reservoir— 

Internal Control 

The slimhole 3 1/8-in. (APF-IC) firing head is designed for 

use with the 5-in. APTR system with internal control. The 

firing head design remains the same as the 3 3/8-in. APF-C 

with diameter reductions in many of the component parts to 

achieve a true 3.13-in. OD. 

SAP No. 

101301541 

Ball Valve 

Annular Pressure 

Transfer Sub 

Safety Joint 

Retrievable Packer 

Flow Ports 

Firing Head 

VannGun ® 

Assembly 


HAL15403 

Slimhole Annulus Pressure Firer— 

Internal Control (APF-IC) 

Installation 

Slimhole Annulus Pressure Firer—Internal Control (APF-IC) Specifications 

Thread Size 


2 3/4-in. 6P 


Max OD 

in. (mm) 

3.13 

(79.5) 

Min ID 

in. (mm) 

1.25 

(31.75) 

No. of 

Ports 

2 

Makeup 

Length 

ft (m) 

56.41 

(17.2) 

Maximum 

Operating 

Pressure 

psi (bar) 

20,000 

(1378) 

Minimum 

Operating 

Pressure 

psi (bar) 

Temperature Rating 325°F (20K psi) with Extreme Environment Kit (162°C 1.406 kg/cm 2 with Extreme Environment Kit) 

Call Technology for temperatures above 325°F (162°C). 

250 

(17) 

Tensile 

Strength 

lb (kg) 

87,000 

(39 463) 

Burst 

Pressure 

psi (bar) 

N/A 

Collapse 

Pressure 

psi (bar) 

10,000 

(689)

Differential Firing Head 

The differential firing head (DFH) was 

designed to allow underbalanced 

perforating with a differential pressureactuated 

firing system. The DFH works 

by requiring the internal pressure to be 

greater than the external pressure. This 

condition can be created when pressure 

is applied to the ID or when the OD 

pressure is reduced. 

The pressure required to actuate the DFH 

may be lower than that used for other 

pressure-operated firing heads because it 

is operated by differential pressure. 

Features 

Allows underbalanced perforating in 

horizontal wells without a packer 

Ideal for perforating with a sucker 

rod or submersible pump in place 

Offers added safety because it is 

pressure-balanced when being run 

into the well 

Helps allow maximum 

underbalanced pressure in lowpressure 

wells when mechanical 

firing is not desirable 

SAP No. 

120002262 

100014232 


in. (mm) 

2 3/8 (60.33) EUE 

8 Rd Box × 2 3/8 (60.33) 

6P Acme Box 

2 7/8 (73.03) EUE 

8 Rd Box × 

2 7/8 (73.03) 6P Acme Box 

Can be used when equipment or well 

conditions will not permit the use of 

high pressures 

Allows the use of time-delay elements 

as needed 

Operation 

The DFH is actuated after a 

predetermined differential pressure is 

created in the firing head ID. This 

differential pressure can be created 

when surface pressure is applied to the 

tubing or by reducing the hydrostatic 

pressure in the annulus. 

When the predetermined differential 

pressure is reached, the shear pins 

holding the dog retainer piston will 

shear, allowing the dog retainer to 

move up. The upward movement 

releases the dogs holding the firing 

piston in place, and the internal 

pressure drives the firing piston into 

the initiator. 

Differential Firing Head (DFH) Specifications 

Maximum OD 

in. (mm) 

3.0 

(76.20) 

3.38 

(85.73) 

Makeup 

Length 

ft (m) 

1.94 

(0.59) 

1.98 

(0.60) 

Maximum 

Operating 

Pressure 

(Differential) 

psi (bar) 

Minimum 

Operating 

Pressure 


psi (bar) 

Differential Firing Head (DFH) 


10,000 

(690) 

5,000 

(345) 

Temperature rating is determined by explosives or o-rings. 


1,000 

(69) 

1,000 

(69) 

HAL10518 

Tensile 

Strength 

lb (kg) 

130,000 

(58 900) 

220,000 

(99 700) 

Burst 

Pressure 

psi (bar) 

20,000 

(1380) 

20,000 

(1380) 

Collapse 

Pressure 

psi (bar) 

20,000 

(1380) 

20,000 

(1380)

Hydraulic Actuator Firing Head and 

Swivel-Type Hydraulic Actuator Firing Head 

The hydraulic actuator firing head 

(HAF) is a pressure-balanced tool that 

automatically fills the tubing string 

while it is running in the well. A 

stainless steel or ceramic ball is dropped 

from the surface or circulated into 

position. Pressure applied to the tubing 

string actuates the HAF. 

The smaller swivel-type hydraulic 

actuator firing head (SHAF) has a 

swivel incorporated into the firing 

head assembly. The added swivel 

feature allows the lower portion of the 

firing head and the attached explosive 

assembly to rotate independently from 

the tubing string. 

Features 

Allows packerless completions 

Makes actuation easily observable 

SAP No. 

100156011 

(Swivel Type) 

100156025 

101007031 

100156150 

101313489 

Thread Size 


in. (mm) 

1.315 (33.40) 

NU-10 Rd Pin × 

17/16 (36.51) 

8UN-2B Box 

1.315 (33.40) 

NU-10 Rd Pin × 

17/16 (36.51) 

8UN-2B Box 

1.90 (48.26) EUE-10 Rd 

3/4 TPF Pin 

2 3/8 (60.33) 6P Acme 

Box 

2 3/8 (60.33) EUE 

8 Rd Pin × 

2 7/8 (73.03) 

6P Acme Box 

2 7/8 (73.03) EUE 8 Rd 

Pin × 2 7/8 (73.03) 6P 

Acme Box 

Useful in coiled tubing conveyed 

completions, deviated wells, and 

through-tubing perforating 

Reusable 

Rotation of explosive assembly from 

tubing string possible with 

swivel type 

Operation 

A stainless steel or ceramic ball is 

dropped from the surface or is 

circulated downhole into the hammer 

piston. Pressure applied to the tubing 

string shears the retaining pins and 

forces the hammer piston into the 

firing pin. The firing pin detonates the 

initiator, which starts the detonation of 

the perforating assembly. Circulation is 

regained as soon as the firing pin has 

been sheared. 


HAL15384 

Hydraulic Actuator 

Firing Head (HAF) 

Hydraulic Actuator Firing Head (HAF) Specifications 

Maximum 

OD 

in. (mm) 

1.69 

(42.88) 

1.69 

(42.88) 

2.75 

(69.85) 

3.38 

(85.85) 

3.38 

(85.85) 

Ball OD 

in. (mm) 

0.625 

(15.875) 

0.625 

(15.875) 

0.625 

(15.875) 

1.375 

(34.925) 

1.375 

(34.925) 


of Ports 

in. (mm) 

2 @ 0.5 

(12.70) 

2 @ 0.5 

(12.70) 

2 @ 0.5 

(12.70) 

4 @ 1.0 

(25.40) 

4 @ 1.0 

(25.40) 

Flow Area of 

Ports 

in. 2 (cm 2 ) 

0.39 

(2.52) 

0.39 

(2.52) 

0.39 

(2.52) 

3.14 

(20.26) 

3.14 

(20.26) 

Makeup 

Length 

ft (m) 

2.84 

(0.87) 

2.18 

(0.66) 

2.28 

(0.691) 

2.40 

(0.73) 

2.40 

(0.73) 




Pressure (differential) 

psi (bar) 

20,000 

(1379) 

20,000 

(1379) 

20,000 

(1379) 

20,000 

(1379) 

20,000 

(1379) 

HAL10563 

Swivel-Type Hydraulic 

Actuator Firing Head (SHAF) 

Actuating 

Pressure 

psi (bar) 

3,200 

(221) 

3,200 

(221) 

3,200 

(221) 

2,000 

(138) 

2,000 

(138) 

Tensile 

Rating 

lb (kg) 

50,000 

(22 680) 

50,000 

(22 680) 

113,000 

(51 256) 

135,600 

(61 507) 

216,000 

(97 976)

Mechanical Metering Hydraulic-Delay Firing Head 

The mechanical metering hydraulic-delay (MMHD) firing 

head provides a retrievable firing system with an adjustable 

delay for situations where longer delay times are needed. 

Delay time can be adjusted from 1 to 6 hours. The tool is 

designed with a 1/2 gallon fluid chamber below a weighted 

piston. The piston meters downward until it travels into a 

larger bore which allows it to free-fall and initiate a 

mechanical firing head. 

Delay time is affected by temperature, tool weight above the 

piston, and the number of jets used (maximum of two), and 

the adjustments can be made by running one or two fluid 

metering jets or by changing the amount of fluid. 

Features 

Adjustable time-delay—May vary from 1 up to 6 hours 

Retrievability—Firing head can be pulled and another one 

run without affecting the rest of the bottomhole assembly 

Safety—With the ability to run the firing head and the 

guns separately, this system greatly reduces the chance of 

accidental or premature firing of guns 

Operation 

The MMHD assembly is run into the well using normal 

monobore completion techniques. The mechanical metering 

hydraulic-delay firing head is conveyed on a slickline or 

electric line. For safety and flexibility, the tool will not start 

metering until it is landed on the top gun. Once in place and 

released, the firing head starts to meter. The running tools 

can either be pulled into the lubricator, pulled completely 

out of the hole, or simply pulled up the hole to a safe distance 

and secured to await detonation. After the guns have fired, 

the firing head can be quickly relatched and retrieved using 

the same conveyance methods as during deployment. 

SAP No. 

101201927 


HAL6559 

Mechanical Metering Hydraulic- 

Delay (MMHD) Firing Head 

Mechanical Metering Hydraulic-Delay (MMHD) Firing Head Assembly Specifications 

Maximum 

OD 

in. (cm) 

Dependent on 

centralizers 

Stinger 

Fishing 

Neck 

in. (cm) 

1.75 

(4.45) 

Maximum 

Stroke 

Length 

in. (cm) 

54.86 

(139.34) 

Maximum Metering 

Stroke* Length 

(Available for Delay) 

in. (cm) 

46.50 

(118.11) 

Overall 

Length* 

(Extended) 

ft (m) 

12.44 

(3.79) 

Maximum 

Operating 

Pressure 


psi (bar) 

13,000 

(896.6) 

*Length from top sub to firing head body (does not include weight bars and/or skirt) 

Delay time of 1 hour minimum is recommended for safe operation of system. 

Delay time of 6 maximum hours is dependent on temperature, silicon fluid, and number of jets. 


Temp 

Rating 

°F (°C) 

350 

(176.67) 

Tensile 

Strength 

lb (kg) 

51,100 

(23 100) 

Total 

Volume 

(Silicon) 

gal (liter) 

1/2 

(1.89) 

Assembly 

Weight 

lb (kg) 

152 

(68.95)

Slickline-Retrievable Mechanical Firing Head 

The slickline-retrievable mechanical 

firing head (SLRMFH) is designed to 

give customers flexibility in 

completing a well. It can be run 

attached to the guns, separately from 

the guns, or using an auto-release 

firing mechanism. The firing head 

latches onto the guns and provides a 

positive indication that it is attached. 

The SLRMFH can be retrieved if the 

firing head needs to be replaced. 

The system can be run with either a 

mechanically operated firing head or a 

pressure-operated firing head. It is 

designed so that 80% of the parts are 

used in all three applications allowing 

for more flexibility with less inventory. 

Features 

Saves rig time—If for any reason the 

firing head needs replacement, the 

guns remain in the hole and the 

firing head can be retrieved 

Positive engagement—When the 

firing head is run separately, the 

operator can tell when the firing head 

is latched onto the guns 

Safety—Guns can be run separately 

from the firing head adding a safety 

feature for the guns at the surface 

Flexibility—Guns can be run 

separately or attached. Unlimited 

number of runs can be made to 

replace firing head if needed 

Operation 

The SLRMFH was designed for 3 1/2- 

and 2 7/8-in. tubing strings. It can be 

run with either a mechanical drop 

firing head, or a pressure-operated 

firing head such as the 1 11/16 timedelay 

firer (TDF). 

The top gun is assembled with the J-slot 

stinger. The guns are run into the well 

on tubing and then correlated on 

depth. The running tool is latched to 

the firing head at surface and run in on 

wireline/slickline. 

As the firing head is lowered, it comes 

in contact with the J-slot stinger. The 

skirt on the firing head then 

automatically latches into position 

connecting the firing head with the 

J-slot stinger. An overpull is applied to 

give a positive latch indication. The 

running tool is released by jarring 

down and the slickline is pulled out of 

the well. The guns are fired by pressure 

or mechanical means. 

The firing head can be retrieved by 

relatching to the firing head and jarring 

up. The jarring action shears the brass 

screws freeing the firing head from the 

J-slot stinger. If the firing head does not 

actuate, another firing head may be run 

as many times as required. 

Slickline-Retrievable Mechanical 

Firing Head (SLRMFH) 


HAL6560

w/ Model 

III-D 

Mechanical 

FH 

SAP No. 

101226902 

w/ Pressure 

Actuated FH 101227170 

w/ Model 

III-D 

Mechanical 

FH and Auto 

Release 

101227212 

Slickline-Retrievable Mechanical Firing Head (SLRMFH) Specifications 

Maximum 

OD 

in. (cm) 

2.31 

(5.87) 

2.31 

(5.87) 

2.31 

(5.87) 

Minimum 

ID 

(No-Go) 

in. (cm) 

1.56 

(3.96) 

1.56 

(3.96) 

1.56 

(3.96) 

Overall 

Length 

(Max) 

ft (m) 

20.05 

(6.11) 

20.05 

(6.11) 

20.05 

(6.11) 

Maximum 

Operating 

Pressure 

psi (bar) 

8,000 

(550) 

17,000 

(1170) 

8,000 

(550) 

Minimum 

Operating 

Pressure 

psi (bar) 

250 

(17.2) 

2,200 

(150) 

250 

(17.2) 

Minimum 

Operating 

Pressure 

Auto Release 

psi (bar) 

Maximum 

Differential 

Pressure 

Auto 

Release 

psi (bar) 

N/A N/A 

N/A N/A 

Tensile 

Strength 

of FH 

Body 

lb (kg) 

30,000 

(13 600) 

30,000 

(13 600) 

Maximum 

Sustained 

Force 

Required to 

Shear Two 

Lugs 

lb (kg) 

4,000 

(1800) 

4,000 

(1800) 


1,500 

(100) 

Burst and collapse pressures are determined by tubing. 



10,000 

(690) 

30,000 

(13 600) 

4,000 

(1800) 

Weight 

lb (kg) 

120 

(54.4) 

100 

(45.4) 

120 

(54.4)

Slickline-Retrievable Time-Delay Firer Firing Head 

The slickline-retrievable time-delay firer (TDF) firing head 

is a combination of two assemblies: the slickline-retrievable 

firing head and a 1 11/16-in. TDF firing head. It is a 

pressure-actuated firing head with a built-in pyrotechnic 

time-delay assembly. 

Features 

Allows the guns to be run in the hole without any type of 

firing mechanism installed 

Allows the retrieval and reinstallation of a malfunctioning 

firing head without pulling the guns 

Allows greatly reduced actuating pressures of the firing 

head because the firing head does not have to be in place 

when the guns are run 

Operation 

This firing head does not have to be run until after all 

pressure testing has been done and the heavy fluids have been 

displaced, which allows a reduced actuating pressure for the 

firing head. 

This assembly allows the operator to run guns in the hole on 

the end of tubing without a firing head. This assembly can be 

run in on slickline and attached to the firing head after the 

tubing is in the hole. It can also be retrieved on slickline. 

SAP No. 

100155739 


HAL15385 

Slickline Retrievable Time-Delay Firer 

(TDF) Firing Head 

HAL15434 

Stinger Assembly 

1 11/16-in. Slickline-Retrievable Time-Delay Firer (TDF) Firing Head Specifications 

Maximum OD 

in. (mm) 

1.688 

(42.88) 

Overall Length 

(1 fuse) 

ft (m) 

3.83 

(1.17) 

Additional Length 

per Fuse 

ft (m) 

0.87 

(0.27) 

Temperature 

Rating 

°F (°C) 

425 for 200 hours 

(218 for 200 hours) 

Maximum 

Operating 

Pressure 

psi (bar) 

17,000 

(1170) 

The assembly certification sheet which specifies the batch number and pin values is supplied with each assembly. 

SAP No. 

100155952 

Thread Size 


in. (mm) 

2 3/8 (60.33) EUE 8 Rd Box × 

2 7/8 (73.03) 6P Acme Box 

3 3/8-in. Vann Jet Stinger Specifications 

Maximum 

OD 

in. (mm) 

3.38 

(85.85) 



Minimum ID 

(No-Go) 

in. (mm) 

1.37 

(34.80) 

Makeup Length 

with 

2-ft Sub 

ft (m) 

5.37 

(1.64) 

Maximum 

Operating 

Pressure 

psi (bar) 

20,000 

(1380) 

Minimum 

Operating 

Pressure 

psi (bar) 

None 

Minimum 

Operating 

Pressure 

psi (bar) 

2,200 

(150) 

Tensile 

Strength 

(FH Body) 

lb (kg) 

238,000 

(107 900) 

Collapse 

Pressure 

psi (bar) 

23,000 

(1590) 

Weight with 

2-ft Sub 

lb (kg) 

73 

(33)

Extended Delay Fuses 

A delay fuse is an explosive device with a slow-burning fuse. 

Extended and modular delay fuses add time between the 

actuation of the firing head and the actual detonation of the 

guns. Each delay fuse lasts six minutes at 70°F. 

Features 

Increases delay time when nitrogen is used to actuate the 

firing head to give additional time to bleed the nitrogen 

pressure down to the desired level 

Allows time for necessary actions to take place downhole 

such as increasing pressure to open a pressure-actuated 

vent assembly 

Operation 

The extended delay assemblies contain one delay fuse and 

can be run with any other firing assembly. They are installed 

between the firing head and the guns. 

The modular delays are assembled with the firing head in one 

housing and become an integral part of the firing system. 

The modular delays are used primarily with the multiactiondelay 

firing head, the 1 11/16-in. time-delay firer (TDF) 

firing head, and the slickline-retrievable TDF firing head. 

SAP No. 


in. (mm) 

100005229 2 (50.8) 6P Acme Box × Pin 

100009426 2 7/8 (73.03) 6P Acme Box × Pin 

Extended Delay Fuses Specifications 

Maximum 

OD 

in. (mm) 

2.5 

(62.5) 

3.375 

(85.73) 

Makeup 

Length 

ft (m) 

1.10 

(0.34) 

1.10 

(0.34) 

Maximum 


psi (bar) 

25,000 

(1725) 

25,000 

(1725) 


Extended Delay Fuses 

Assembly 


HAL15383 


Delay Fuse 

°F (°C) 

425 (218) for 200 hours 

425 (218) for 200 hours 

Tensile 

Strength 

lb (kg) 

197,000 

(89 300) 

270,000 

(122 400) 

Collapse 

Pressure 

psi (bar) 

30,000 

(2070) 

30,000 

(2070)

Modular Mechanical Firing Head 

The modular mechanical firing head is designed to be a 

retrievable firing system utilizing a standard mechanical 

firing head with a specialized drop bar for detonation. This 

system will allow the operator the flexibility to run the gun 

assemblies independently of the firing system. Once the guns 

are in place, the firing head is set on the top module and 

released. The perforation assembly is detonated by use of a 

special fluted bar dropped from surface. 

The most common application for this system is to be run 

with the modular guns in a monobore completion. Special 

consideration must be given to job set-up and execution to 

ensure that this tool functions properly. 

Features 

Safety—With the ability to run the firing head and the 

guns separately, this system helps to greatly reduce the 

chance of accidental or premature firing of the guns 

Retrievability—In the event of a mechanical malfunction, 

the firing head can be pulled, and another one run without 

interfering with the rest of the bottomhole assembly 

Applications 

The modular mechanical firing head is designed to be run on 

slickline and set on the top gun in a monobore completion 

by use of a JDC hydraulic running tool. The system is 

designed with the hammer held above the firing pin with 

brass shear screws. The two shear screws are rated at 

875 lb each. The tool is actuated by dropping a specifically 

designed drop bar fitted for the proper casing. (Do not use a 

standard 1 1/4-in. drop bar.) The bar strikes the stinger with 

sufficient force to shear the brass screws and drive it into the 

firing pin. 

The firing pin and hammer are pressure balanced; and 

therefore, are not limited to any specific depth and/or 

hydrostatic pressure beyond the tool specifications. 

Modular Mechanical 

Firing Head 


HAL8325

SAP No. 

120021629 

Stinger Fishing 

Neck 2-in. 

Stinger 

in. (mm) 

1.38 

(35.05) 

Modular Mechanical Firing Head Specifications 

Stinger Fishing 

Neck 2 1/2-in. 

Stinger 

in. (mm) 

1.75 

(44.45) 

*Will vary with skirt 

Maximum OD dependent on centralizers used. 


Weight dependent on centralizers and skirts. 

SAP No. 

N/A 

101227709 

120125486 

101227719 

101227720 

Drop Bar Options 

Casing and Tubing 

Size and Weight 

in./lb (cm/kg) 

2 7/8 / 6.4 

(7.30 / 2.9) 

3 1/2 / 9.2 

(8.89 / 4.17) 

4 1/2 / 9.5-13.5 

(11.43 / 4.3-6.12) 

5 / 15-18 

(12.7 / 6.80-8.16) 

5 1/2 / 15.5-23 

(13.97 / 7.03-10.43) 

Casing ID 

in. (mm) 

2.441 

(62.0) 

2.992 

(76.0) 

4.090 

(103.9) 

4.408 

(111.9) 

4.950 

(125.7) 

Maximum 


psi (bar) 

13,000 

(896.6) 

Total Bar 

OD 

in. (mm) 

N/A 

2.50 

(63.5) 

3.75 

(95.3) 

4.125 

(104.8) 

4.50 

(114.3) 


lb (kg) 

59,000 

(26 762) 

Overall Length* 

in. (mm) 

72.30 

(1836.42) 

Maximum Stroke 

Length 

in. (mm) 

7.88 

(200.15) 

Skirt-Centralizer Selection Chart 

SAP No. 

101207195 

101201882 

101228625 

101201884 

101226987 

101205671 

Skirt OD 

in. (mm) 

Centralizer OD 

in. (mm) 

Shear Rating 

For Brass 

lb (kg) 


2 

(50.8) 

2.5 

(63.5) 

2 3/4 

(69.9) 

3 1/8 

(79.4) 

3 3/8 

(85.7) 

4 5/8 

(117.4) 

N/A 

3.00 

(76.2) 

101207187 

3.50 

(88.9) 

101207198 

3.75 

(95.3) 

100014297 

3.25 

(82.6) 

101213087 

3.50 

(88.9) 

100014299 

3.875 

(98.4) 

101207193 

3.75 

(95.3) 

100009581 

4.00 

(10.16) 

100156785 

4.40 

(111.8) 

100010177 

5.61 

(142.5) 

100156224 

5.75 

(146.1) 

100156225 

1,700 

(771)

Side-Pocket Mandrel Firing Head 

The side-pocket mandrel firing head (SPMFH) is designed 

for well conditions that preclude the use of a pressureactuated 

firing head run with a Y-block. The side-pocket 

mandrel firing system is used on single-string, multizone 

completions and standard dual completions. A modified 

model III-D mechanical firing head is attached to the short 

string side of a side-pocket mandrel. The firing head is 

detonated with a kickover tool run on slickline. 

Features 

Selectively fires multiple intervals 

Eliminates the need for nitrogen 

Allows maximum underbalance for low-pressure 

formations 

Offers economical value 

Operation 

The model III-D mechanical firing head is made up on the 

short string side of the side-pocket mandrel. When the 

perforating assembly is ready to be detonated, the operator 

runs a kickover tool down the long string on slickline. After 

the kickover tool is located in the side-pocket mandrel, the 

slickline operator jars down. The kickover tool hits the 

releasing pin on the model III-D. The firing piston is forced 

into the initiator by the hydrostatic pressure in the tubing 

string to detonate the VannGun® assembly. 


HAL15453 

Side-Pocket Mandrel 

Firing Head (SPMFH) 

Side-Pocket Mandrel Firing Head (SPMFH) Specifications 

SAP No. 

100155737 

(Firing Head) 

221.00284 

(7-in. Side-Pocket Mandrel) 

221.00285 

(9.625-in. Side-Pocket Mandrel) 


(Long String Side) 

in. (mm) 

1.90 (48.26) EUE 10 Rd Pin 

× 2 3/8 (60.33) 6P Acme Box 

2 3/8 (60.33) 4.7 lb 

OECO-B Box × Box 

2 3/8 (60.33) 4.7 lb 

OECO-B Box × Box 

101306060 3 1/2 CJ Hydril 

Maximum OD 

in. (mm) 

2.75 

(69.85) 

5.54 

(140.72) 

6.62 

(168.15) 

8.00 

(203.20) 

Minimum ID 

in. (mm) 

N/A 

1.926 

(48.92) 

1.926 

(48.92) 

Overall 

Length 

ft (m) 

2.36 

(0.72) 

5.79 

(1.76) 

5.79 

(1.76) 

N/A N/A 

These ratings are guidelines only. For more information, consult your local Halliburton representative.

Annulus Pressure Crossover Assembly 

The annulus pressure crossover assembly (APCA) allows the 

use of annulus pressure to actuate any one of several firing 

heads. This assembly is compatible with retrievable packers 

of all types and sizes. 

Features 

May be used as the annulus firing system on wells with 

non-full-opening test tools and a partially filled drillstring 

May be used as the annulus firing system on horizontal 

wells 

Allows the use of below-packer venting devices along with 

this assembly 

Note: Not recommended for mud environment 

Operation 

The APCA creates a pressure chamber above the firing head 

that is equalized with the pressure in the casing annulus. 

Once the packer has been set, the pressure on the annulus 

can be increased to actuate a pressure-actuated firing head. 

The pressures in the annulus and the tubing can also be 

manipulated to create the differential pressure necessary to 

actuate a differential-type firing head. 

SAP No. 

100014175 

100155786 

101241465 

Thread Size 


in. (mm) 

2 3/8 (60.33) 

EUE 8 Rd 

2 7/8 (73.03) 

EUE 8 Rd 

3 1/2 (88.9) API 

IF Tool Joint 


Crossover Assembly 

Packer 

Ported Sealing Sub 

Tubing 


® 

VannGun 

Assembly 

Annulus Pressure Crossover Assembly (APCA) 

Annulus Pressure Crossover Assembly (APCA) Specifications 

Maximum 

OD 

in. (mm) 

3.56 

(90.42) 

5.0 

(127) 

5.015 

(127.381) 

Minimum 

ID 

Non-fullbore 

Non-fullbore 

Non-fullbore 

Flow Area 

in.² (cm²) 

2.25 

(14.52) 

4.75 

(30.65) 

4.75 

(30.65) 


HAL15448 

Minimum 

Makeup 

Length 

ft (m) 

9.15 

(2.79) 

9.40 

(2.87) 

9.40 

(2.87) 

Overall 

Length 

ft (m) 

12.35 

(3.76) 

12.60 

(3.84) 

12.60 

(3.84) 

Maximum operating pressure is determined by tubulars. 



Maximum 

Differential 

Pressure 

psi (bar) 

10,000 

(689) 

9,500 

(655) 

10,500 

(723) 

Tensile 

Strength 

lb (kg) 

104,000 

(47 173) 

145,000 

(65 770) 

145,000 

(65 770) 

HAL15449 

Burst 

Pressure 

psi (bar) 

11,200 

(772) 

10,500 

(723) 

13,210 

(910) 

Collapse 

Pressure 

psi (bar) 

11,700 

(806) 

11,100 

(765) 

22,500 

(1551)

EZ Cycle Multi-Pressure Cycle Firing Head 

The EZ Cycle firing head is a pressure-operated tool that 

can be cycled several times prior to firing the perforating 

guns. Several pressure operations can also be performed on 

the well including tubing testing, packer setting, and packer 

testing prior to firing the perforating guns. Even if pressure 

operations are higher than the operating pressure of the 

firing head, the EZ Cycle firing head should not fire until it 

has completed all of the preset cycles. The firing head is 

cycled by applying pressure at the tool to overcome a 

nitrogen-charged chamber which operates the cycling piston 

back and forth until the entire release rod has been pulled 

from the piston collet. 

Each EZ Cycle firing head assembly includes a nitrogen 

chamber, cycling grapple piston, and firing piston with firing 

pin initiator assembly. 

Features 

Ideal for completions and drillstem testing 

Time-delay elements can be used as needed for delay time 

Can be used in underbalanced or overbalanced perforating 

jobs 

It is a surface-safe firing head because it requires pressure 

to energize the firing piston 

Operates at low pressure 

Can be deployed connected to the gun assembly or run 

separate on slickline or coiled tubing 

Allows the retrieval and reinstallation of a malfunctioning 

firing head without pulling the guns 

Can be used when equipment or well conditions will not 

permit the use of high pressures 

EZ Cycle Firing Head Assembly 


HAL14095

Operating the EZ Cycle Firing Head 

The tool is run in hole with a pre-charged nitrogen chamber, 

which is set according to the maximum bottomhole pressure. 

After positioning gun on depth and all operations prior to 

firing guns have been completed, the firing head is cycled to 

detonate the perforating guns. Pressure applied at the tool 

will move the cycle piston and traveling grapple up 0.375 in. 

pulling the release rod up 0.375 in. Releasing the applied 

pressure will allow the nitrogen charge to move the cycle 

Upper 

Connection 

(External 

Fishneck) 

in. (cm) 

2.313 

(5.875) 

Lower 

Thread Size 


in. (cm) 

2 3/8 

(6.0325) 6P 

Acme Box 

piston and traveling grapple down engaging another 

0.375 in. of the release rod. These steps are continued until 

the release rod is completely retrieved from the firing piston 

collet. At this point, the bottomhole pressure will drive the 

firing piston into the firing pin detonating the initiator and 

the guns. 

3.00 in. Multi-Pressure Cycle Firing Head Assembly Specifications 

Makeup 

Length 

in. (cm) 

77.32 

(196.393) 

Maximum 

OD 

in. (cm) 

3.00 

(7.62) 

Minimum 

ID 

in. (cm) 

N/A 

*Call your local Halliburton representative if conditions exceed this value. 

Temperature 

Rating 

°F (°C) 

400 

(204.4) 

Operating Pressure Range 

psi (bar) 

Low 

Pressure 

Assembly 

1,000-5,000 

(68.95- 

344.74) 

High 

Pressure 

Assembly 

5.000- 

20,000 

(344.74- 

1378.95) 

Tensile 

Rating* 

lb (kg) 

100,000 

(18 143) 

Burst 

Pressure* 

psi (bar) 

40,000 

(1379) 

Collapse 

Rating* 

psi (bar) 


40,000 

(1379)

Pump-Through Firing Head 

The 1 11/16-in. pump-through firing head is designed to be 

run on coiled tubing and is used for breaking the ceramic 

flapper valve disk on a one-trip coiled tubing operation. The 

firing head originates from proven technology in the 

1 11/16-in. pressure actuated pressure firing head. The 

components were hardened to withstand pumping erosion, 

and an outer tube is incorporated to allow fluid circulation to 

the bottom of the tool. A miniature shaped charge is set in 

the bottom of the firing head to shoot into the ceramic disk. 

The assembly is actuated by dropping a ball through the 

coiled tubing, which seats in the assembly to allow a pressure 

differential to actuate the firing head and shape charge. 

Application 

The pump-through firing head can be used to circulate 

debris off of a barrier, such as a ceramic disk, and then shoot 

into the barrier to break it up. This function is primarily 

developed toward circulating sand and other debris off of a 

ceramic disk in a production well, and then shooting into the 

disk to allow access below. 


Type 

in. (mm) 

1.315 (33.40) 

NU-10RD Pin 

Maximum OD 

in. (mm) 

2.3 

(58.42) 

Minimum ID* 

in. (mm) 

0. 44 

(11.18) 

*Through ball seat 

Minimum Operating Pressure is not applicable. 

Burst Pressure is not applicable. 

Pump-Through Firing Head Specifications 

Maximum 

Operating 

Pressure 

psi (bar) 

3,000 (207) 

± 10% at 70°F 

Flow Area 

(before firing) 

in. 2 (mm 2 ) 

0.15 

(96.77) 

Temperature 

Rating 

As per 

explosives 

Axial Load 

Rating 

lb (kg) 

54,400 

(24 700) 


1 11/16-in. Pump Through 


HAL15777 

Collapse 

Pressure 

psi (bar) 

23,200 

(1600) 

Overall 

Length 

in. (mm) 

22.69 

(576.32) 

Mass 

lb (kg) 

16.9 

(7.68) 

Maximum Flow 

Rate 

bbl/min (m 3 /min) 

2.5 

(0.397)

Ancillary Equipment 

Fill Disk Assembly 

The fill disk assembly (FDA) is used 

where either packer selection or well 

conditions preclude the use of a venting 

device. The FDA is used in place of a 

perforated sub and replaces the 

balanced isolation tool (BIT) in wells 

with reasonably clean fluids. The glass 

disk prevents debris from settling on 

the firing head. Pressure is equalized 

across the glass disk. 

The FDA is run between the firing head 

and packer. The recommended 

minimum distance from the FDA to the 

firing head is 30 ft (9.14 m). 

Features 

Allows debris to be circulated off the 

glass disk through the flow ports 

above the glass disk 

Acts as a perforated sub for 

circulating fluid displacement with 

nitrogen and swabbing 

Can be run with either a mechanical 

or pressure-actuated firing head 

SAP No. 

100005295 

100005297 

100005299 

Thread Size 


in. (mm) 

2 3/8 (60.33) EUE 

8 Rd Box × Pin 

2 7/8 (73.03) EUE 


3 1/2 (88.90) EUE 


Operation 

The FDA consists of a ported housing 

with a glass disk installed in the ID 

across the lower set of ports. The disk is 

not sealed, so pressure can equalize 

across the glass. Any debris falling out 

of the tubing or fluid above the glass 

should land on the glass disk. This 

debris can be circulated off the disk, or 

if it is not a large amount, it will be 

displaced out the ports by the 

detonating bar falling through it. 

Once the bar breaks through the disk, it 

should fall in clean fluid all the way to 

the firing head. In mud systems or wells 

with a known debris problem, the 

balanced isolation tool is recommended 

in place of the FDA. 

Fill Disk Assembly (FDA) Specifications 

Maximum OD 

in. (mm) 

3.01 

(76.45) 

3.51 

(89.15) 

4.20 

(106.68) 

Minimum ID 

in. (mm) 

1.98 

(50.29) 

2.44 

(61.98) 

3.0 

(76.20) 

Flow Area 

in.² (cm²) 

6.28 

(40.54) 

Number of 

Ports 

Fill Disk Assembly 

(FDA) 


7.88 

(50.8) 

14.13 

(91.20) 

8 

8 

8 

HAL8352 


lb (kg) 

120,000 

(54 431) 

150,000 

(68 039) 

200,000 

(90 718) 

Makeup Length 

ft (m) 

0.76 

(0.23) 

0.71 

(0.22) 

0.69 

(0.21)

Balanced Isolation Tool 

The balanced isolation tool (BIT) 

assembly is used where either packer 

selection or well conditions preclude the 

use of a venting device. The BIT 

assembly replaces the fill disk assembly 

and is used in place of a perforated sub. 

The BIT helps prevent contamination of 

the fluid below it from the fluid above it. 

Debris or solids in the fluid above 

should not pass through the glass disk 

that is in the floating piston. The glass 

disk helps prevent debris from setting on 

the firing head. Pressure is balanced 

across the glass barrier through 

equalizing ports in the piston. 

The BIT assembly is run between the 

firing head and packer. The 

recommended minimum distance 

from the BIT to the firing head is 

30 ft (9.14 m). 

Features 

Allows mud and debris to be 

circulated off the glass barrier 

through the flow ports above the 

glass barrier 

Allows displacement of the tubing 

with a lighter fluid or nitrogen before 

firing the guns 

Allows swabbing of the tubing to 

achieve differential pressure 

Allows stopping and circulating at 

any depth since flow ports are 

always open 

Can be run with either a mechanical 

or pressure-actuated firing head 

Operation 

The basic components of the BIT are a 

floating piston with a glass disk, a 

ported lower housing, and a top 

housing. The BIT is run with clean fluid 

below it. 

The upward travel of the floating piston 

is limited by the bottom of the top sub. 

A pressure increase above the glass 

barrier causes the piston to move down 

and forces fluid below the glass barrier 

out of the bleeder ports. A pressure 

increase below the glass barrier forces 

the piston to move up or forces fluid 

out of the bleeder ports. 

The piston moves up or down within its 

limits to help prevent the glass barrier 

from breaking. The glass barrier 

remains intact until the bar passes 

through it. As fluid enters or leaves the 

tubing through the ports, debris on the 

glass barrier is washed off. 

Balanced Isolation Tool 

(BIT) 


HAL15460

SAP No. 

120022203 

101318220 

100014322 

100014323 

100156936 

Thread Size 


in. (mm) 

1.90 (48.26) EUE 


2 3/8 (60.33) EUE 


2 3/8 (60.33) EUE 


2 7/8 (73.03) EUE 


3 1/2 (88.90) EUE 


Balanced Isolation Tool (BIT) Specifications 

Maximum OD 

in. (mm) 

2.50 

(63.50) 

2.895 

(73.4) 

3.10 

(78.74) 

3.75 

(95.25) 

4.25 

(107.95) 

Minimum ID 

in. (mm) 

1.61 

(40.89) 

1.99 

(50.54) 

1.99 

(50.54) 

2.44 

(61.98) 

3.0 

(76.20) 


No. of 

Ports 


4 

4 

4 

4 

4 

Total Flow 

Area 

in. 2 (cm 2 ) 

2.03 

(13.10) 

3.09 

(19.96) 

3.14 

(20.27) 

4.68 

(30.19) 

7.07 

(45.60) 

Overall 

Length 

ft (m) 

2.09 

(0.64) 

2.02 

(0.62) 

2.15 

(0.65) 

2.41 

(0.73) 

2.41 

(0.73) 

Tensile 

Strength 

lb (kg) 

110,000 

(49 800) 

100,000 

(45 300) 

155,000 

(70 200) 

200,000 

(90 700) 

280,000 

(126 000)

Ratchet Gun Connector 

In addition to perforating new wells, Halliburton’s ratchet 

gun connector system is ideal for reperforating producing 

wells since the well does not have to be killed and can be left 

on production. It also allows perforating with all production 

equipment in place. Connections are made inside the 

lubricator using a left-hand quick connect 

locking mechanism. 

Features 

Can be snubbed into and retrieved from a live well 

Utilizes standard blowout preventers 

Can perforate long and multiple intervals in a single trip 

Does not have to kill producing zone to run or 

retrieve guns 

Perforates new wells 

Reperforates producing wells with all production 

equipment in place 

Perforates underbalanced or overbalanced assemblies 

VannGun® sections are quickly connected together 

Can be used with hydraulic workover (HWO) 

SAP No. 

101000794 

101000793 


Type 

in. (mm) 

2 3/8 (60.33) 

6P Acme Box × Pin 

2 7/8 (73.03) 



Assembly Using Sealed 

Imitation Assembly 

Ratchet Gun Connector Specifications 

Maximum OD 

in. (mm) 

2.35 

(59.69) 

3.375 

(85.73) 

Makeup Length 

ft (m) 

2.11 

(0.64) 

2.11 

(0.64) 


Assembly Using Non- 

Sealed Insert Assembly 


HAL22573 


Pressure 

psi (bar) 

13,000 

(896) 

13,000 

(896) 

Temperature rating is determined by explosive. 


HAL22574 


lb (kg) 

100,000 

(45 360) 

220,000 

(100 000)

AutoLatch Release Gun Connector 

The AutoLatch release gun 

connector is designed to join 

VannGun® assemblies and enables 

VannGun sections to be run in and 

out of new or producing wells. 

Using the AutoLatch system, VannGun 

assemblies are connected without 

rotation and can be operated with 

standard blowout preventer (BOP) 

rams, making this connector ideal for 

snubbing guns into and out of the 

wellbore with coiled tubing or a 

hydraulic workover (HWO) unit. 

The AutoLatch connector can also be 

used to run VannGun assemblies on 

wireline when the length of the 

perforating assembly is limited by the 

lubricator length. The VannGun 

assemblies can be run in sections 

(limited by the weight rating of the 

wireline) and then, retrieved in 

sections. This system reduces the 

number of wireline runs to perforate 

longer intervals. 

SAP No. 

Features 

Can be used to perforate new or 

existing wells 

Can snub VannGun assemblies into 

and out of the well 

Utilizes standard BOPs 

Can be used with coiled tubing, 

HWO, or wireline 

Can retrieve VannGun assemblies 

without killing a producing zone 

Can perforate in underbalanced or 

overbalanced conditions 

May be used for monobore 

completions 

Can be used when oriented 

perforations are required 

Sections are quickly connected for 

time savings 

Can be designed to accommodate 

different BOP configuration 

AutoLatch Release Gun Connector Specifications 


Type 

in. (mm) 

Upper 

Assembly: 

101205866 2 3/8 (60.33) 

Lower 

Assembly: 

101205878 


Upper 

Assembly: 

100155775 2 7/8 (73.03) 

Lower 

Assembly: 

101207115 


Maximum 

OD 

in. (mm) 

2.88 

(73.15) 

3.625 

(92.00) 

Makeup 

Length 

ft (m) 

4.46 

(1.36) 

3.47 

(1.06) 

Maximum 

Operating 

Pressure 

psi (bar) 

20,000 

(1380) 

20,000 

(1380) 

Tensile 

Strength 

lb (kg) 

80,000 

(35 000) 

125,000 

(56 800) 



Stop/Release 

Pads 

Spring Housing 

Operating Spring 

Shear Screws 


Collet Fingers 

Collet Retainer 

Housing 

OD Seal Area 

Pressure Isolation 

Configuration 


HAL8662 

AutoLatch Release 

Gun Connector

Isolation Sub-Assembly 

The isolation sub-assembly (ISA) is live 

well intervention technology designed 

to provide extreme flexibility in well 

completions. The ISA allows 

completion or recompletion of the well 

without killing it. The well can be 

producing before, during, and after the 

guns are deployed in or out of the well. 

The ISA is a lower cost alternative to 

other live well intervention assemblies. 

The ISA incorporates a threaded 

connection that is manually connected 

and disconnected. 

SAP No. 

101228396 

101222274 

101226330 

Features 

Can run VannGun® assemblies on 

hydraulic workovers, coiled tubing, 

or wireline 

Can run VannGun sections to 

perforate a new well or add 

perforations to existing zones 

Can run or retrieve guns without 

killing the well 

Can perforate underbalanced or 

overbalanced 

Low cost 

Provides extreme flexibility in well 

completions 

Isolation Sub-Assembly Specifications 

Thread Size 


in. (mm) 

1 11/16-in. 

(42.86) 

8P Stub Acme 

2G 

2 3/8 (60.33) 

6P Acme 2G 

2 7/8 (73.03) 

6P Acme 2G 

OD Isolation 

Sub-Assembly 

with OD Ram 

Lock 

in. (mm) 

2 with 1 1/2 

(50.8 with 38.1) 

2 3/4 with 2 

(69.85 with 50.8) 

3 3/8 with 2 

(85.73 with 50.8) 

Maximum 

OD 

in. (mm) 

2.015 

(51.18) 

2.765 

(70.23) 

3.395 

(86.23) 

Overall 

Length 

ft (m) 

2.42 

(0.74) 

2.28 

(0.69) 

2.22 

(0.68) 

Maximum 

Operating 

Pressure 

psi (bar) 

10,000 

(689) 

10,000 

(689) 

10,000 

(689) 

Tensile 

Strength 

lb (kg) 

64,500 

(29 250) 

108,000 

(49 000) 

191,400 

(86 800) 




Gun 

Isolation 

Sub-Assembly 

HAL6151 

Isolation Sub-Assembly 

Sealing 

Initiator 

Sealing 

Area 

Sealing 

Initiator 

Gun

Quick Torque Connector 

The Quick Torque connector consists of connectors that 

cover both ends of each gun section to enclose the assembly. 

The connectors have a common, self-aligning drillpipe 

thread that allows automatic or manual makeup. Explosive 

transfer occurs through a web, making the system 

self-contained for added safety. With these connectors, TCP 

gun assemblies can now be picked up by the rig equipment 

and properly made up using iron roughneck equipment 

without the need for human intervention. It simplifies the 

process and saves time by eliminating assembly of the 

components on the rig. 

Features 

Standard NC38 thread makeup procedure 

Redressable 

Self-contained system increases personnel safety on the rig 

floor—no human intervention is needed 

Once the thread protectors are removed, all subsequent 

steps can be automated 

Efficient, automated system saves rig time 

Allows venting of any built-up pressure during shipping 

No exposed explosives 

Q125 material, sour service > 175° F 

Operation 

This system can be used on any rig with automatic or manual 

pipe handling equipment. It can be used with 4 5/8-in. 

standard or 4 5/8-in. self-orienting TCP gun systems, and a 

3 3/8-in.-OD or smaller firing head. 


HAL14398 

Firing Head 

Sub-Assembly 

HAL14399 

Gun 

Sub-Assembly

SAP No. 

101635158 

101634159 

Thread 

Connection 

Box Modified 

API-NC26 

Pin Modified 

API-NC26 

Tool Maximum 

OD 

in. (mm) 

3.14 

(79.95) 

3.14 

(79.95) 

Quick Torque Connector - 2 7/8-in. Guns 


Pressure* 

psi (bar) 

22,000 

(1516) 

22,000 

(1516) 

Temperature 

Rating* 

°F (°C) 

Determined by 

explosives and 

elastomers 

Determined by 


elastomers 

*Maximum Operating Pressure and Temperature Rating based on the elastomers. 

SAP No. 

101351984 

101352042 

101351885 

101354907 

101381170 

Thread 

Connection 

Pin Connector 

Assy, NC38 Pin 

x Acme Pin 

Firing Head 

Connector Assy, 

NC38 Pin x 

Double Acme 

Pin 

Box Connector 

Assy, NC38 Box 

x Acme Pin 

Crossover, 

Standard NC38 

Box x Modified 

NC38 Pin 

Firing Head 

Connector Assy, 

Firing Head on 

Bottom, NC38 

Box x Double 

Acme Pin 

Tool Max. OD 

in. (mm) 

4.75 

(120.65) 

4.75 

(120.65) 

4.75 

(120.65) 

4.75 

(120.65) 

4.75 

(120.65) 

Makeup 

Length 

in. (mm) 

End Connections 

Tensile Rating 

lb (kg) 


12.5 

(317) 

9.3 

(236) 

Quick Torque Connector - 4 5/8-in. Guns 


Pressure* 

psi (bar) 

20,000 

(1379) 

20,000 

(1379) 

20,000 

(1379) 

20,000 

(1379) 

20,000 

(1379) 

Temperature 

Rating* 

°F (°C) 

Determined by 


elastomers 

Determined by 


elastomers 

Determined by 


elastomers 

Determined by 


elastomers 

Determined by 


elastomers 


SAP No. 

101514211 

101535542 

101514214 

Thread 

Connection 

Box Modified 

API-NC38 

Box for 

Centralizer 

Modified API- 

NC38 

Pin Modified 

API-NC38 

Tool Maximum 

OD 

in. (mm) 

5.0 

(127) 

5.0 

(127) 

5.0 

(127) 

Makeup 

Length 

in. (mm) 

6.75 

(171) 

7.61 

(193) 

23.08 

(586) 

13.56 

(344) 

23.08 

(586) 

Quick Torque Connector - 5-in. Guns 


Pressure* 

psi (bar) 

20,000 

(1379) 

20,000 

(1379) 

20,000 

(1379) 

Temperature 

Rating* 

°F (°C) 

Determined by 


elastomers 

Determined by 


elastomers 

Determined by 


elastomers 


Makeup 

Length 

in. (mm) 

22.8 

(579) 

25.2 

(640) 

14.4 

(365) 

2 7/8-in. Gun Pin 

2 7/8-in. Gun Pin 


4-6 Acme Pin x 

Modified NC38 Pin 

2 7/8-6 Acme and 

Pin x 4-6 Acme Pin x 


Modified NC38 Box x 

4-6 Acme Pin 

NC38 Box x 


Modified NC38 Box x 

4-6 Acme Pin x 

2 7/8-6 Acme Pin 


5-in. Gun Pin 

5-in. Gun Pin 

5-in. Gun Pin 

280,500 

(127 232) 

247,000 

(112 354) 


lb (kg) 

493,500 

(223,848) 

Limited by 4-6 Acme 

Pin Thd 

493,500 

(223,848) 


Pin Thd 

493,500 

(223,848) 


Pin Thd 

398,000 

(180,530) 

Limited by NC38 Box 

493,500 

(223,848) 


Pin Thd 


lb (kg) 

540,600 

(245 212) 

540,600 

(245 212) 

540,600 

(245 212)

Detach Separating Gun Connector 

The Detach separating gun connector 

allows operators to deploy long gun 

sections into the well. The guns are 

deployed downhole in a single trip and 

placed across the perforating zone 

supported by a gun hanger or plug. The 

guns are fired when desired and then, 

will automatically separate, which 

allows them to be retrieved in 

manageable sections or left in the hole. 

The Detach separating gun connector is 

ideal for use in monobore wells with 

rathole length restrictions and in 

rigless completions. 

Rathole Length Restriction 

In this application, insufficient rathole 

length causes the uppermost gun 

modules to remain adjacent to the 

perforated interval after they are fired 

where they may interfere with 

production from the well. With the 

Detach separating gun connector, gun 

sections can be removed from the 

perforated interval without having to 

kill the well. 

Rigless Completion 

On wells where the completions are 

installed with wireline or coiled tubing, 

the Detach separating gun connector or 

modular gun system is the preferred 

method for perforating. No rig is 

required—saving both time and 

money. 

SAP No. 

101363724 

101286871 

Upper Thread Size 


in. (mm) 

2 3/8 (60.450) 

6P Acme Pin 

2 7/8 (73.03) 


Operation 

When the firing head detonates the 

detonating cord initiator, the explosives 

train continues through the tool and 

detonates two shaped charges that 

punch holes in the vent sub. At this 

point, wellbore pressure is allowed to 

enter the assembly and move the 

mandrel lock piston upward, allowing 

the retaining dogs to move inward, 

releasing the stinger, and allowing the 

gun sections to separate. 

Advantages 

Can deploy entire gun assembly to 

cover the zone of interest in a single 

trip and retrieve in manageable gun 

sections without killing the well 

Guns can be retrieved or left at 

bottom of the hole 

Allows perforating in either 

underbalanced or overbalanced 

conditions over the entire interval 

Detach Separating Gun Connector Specifications 

Lower Thread 

Size and Type 

in. (mm) 

2 3/8 (60.450) 

6P Acme Box 

2 7/8 (73.03) 

6P Acme Box 


*Verification testing 

Maximum 

OD 

in. (mm) 

2.75 

(69.850) 

3.38 

(85.85) 

Minimum 

ID 

N/A 

N/A 

Makeup 

Length 

ft (m) 

Minimum 

Operating 

Pressure 

psi (bar) 

Detach Separating 

Gun Connector 


2.86 

(0.87) 

2.74 

(0.83) 

1,000 

(69) 

1,000 

(69) 

HAL12070 

Tensile 

Rating 

lb (kg) 

80,000 

(36 300)* 

110,000 

(49 800) 

HAL11525 

Burst 

Pressure 

N/A 

N/A 

Collapse 

Pressure 

psi (bar) 

20,000 

(1379) 

20,000 

(1379)

EZ Pass Gun Hanger 

The EZ Pass gun hanger is designed 

to be run in conjunction with 

Halliburton’s Modular Gun System. 

This advanced design includes slips that 

stay retracted within the slip housing 

until the tool is set. After the 

perforating event, the slips will return 

to the running position and the tool 

auto releases. 

If desired, the hanger can be fished with 

a standard pulling tool and retrieved 

from the well. 

Features 

Running and setting procedures are 

similar to common bridge plugs and 

sump packers—uses standard setting 

equipment 

Can be set in larger ID after running 

through restrictions 

Retrievable and redressable 

May be configured to auto-release or 

stay set after gun detonation 

Can be deployed on wireline, tubing, 

or coiled tubing 

One size sets in multiple casing 

ranges 

Operation 

The EZ Pass gun hanger can be run 

independently or attached to the gun 

system. 

If the gun hanger is run attached to the 

perforating assembly, it must be 

actuated using pressure. The assembly 

would be run in, positioned, and then 

pressure would be applied to the 

wellbore to set the tool. No explosive 

components would be necessary for 

this operation. 

If the gun hanger is deployed and 

positioned similar to a wireline-set 

permanent or sump packer, the same 

power charge-type setting tools are 

used to set the hanger. After the setting 

tool is removed from the wellbore, the 

guns may be deployed as individual 

modules or as a complete assembly and 

are stacked on top of the hanger. 

A releasing tool is needed to release the 

hanger and may be run on the bottom 

of the perforating assembly. When 

activated, the releasing tool fires a 

shaped charge and breaches the top of 

the hanger. This process allows the gun 

weight to be transferred to the inner 

mandrel, placing the hanger in the 

releasing position and forcing the slips 

away from the casing. 

The EZ Pass gun hanger is designed 

with a 2.75 fishing neck and can be 

fished with a standard pulling tool. The 

slips will retract into the ID of the tool 

and helps allow it to be retrieved 

through a wellbore restriction. 

EZ Pass Gun Hanger 


HAL12794

Casing Size 

and 

SAP No. 

4 1/2 

101320360 

5 1/2 

101315538 

7 

101321131 

Casing 

Weights* 

lb 

9.5 - 15.1 

20 / 23 / 26 

29 / 32 / 35 

Range of 

Casing IDs* 

in. (cm) 

4.09 - 3.826 

(10.4 - 9.72) 

4.778 - 4.548 

(12.14 - 11.55) 

6.184 - 6.004 

(15.70 - 15.25) 

Tool 

Maximum 

OD 

(With Slips 

Retracted) 

in. (cm) 

3.50 

(8.89) 

4.125 

(10.5) 

5.375 

(13.65) 

EZ Pass Gun Hanger Specifications 

Maximum 

Operating 

Pressure 

psi (bar) 

18,000** 

(1241) 

20,000** 

(1450) 

20,000** 

(1450) 

Minimum 

Operating 

Pressure 

psi (bar) 

500 

(34.5) 

500 

(34.5) 

500 

(34.5) 

Temperature 

Rating 

°F (°C) 

400 

(204.4) 

400 

(204.4) 

400 

(204.4) 

Tensile 

Rating 

lb (kg) 

74,000 

(33 600) 

74,000 

(33 600) 

74,000 

(33 600) 

Collapse 

Pressure 

psi (bar) 

18,000 

(1241) 

20,000 

(1450) 

20,000 

(1450) 

Overall 

Length 

(Maximum) 

ft (mm) 

Maximum 

Gun Weight 

lb (kg) 


5.1 

(1.55) 

5.1 

(1.55) 

5.1 

(1.55) 

30,000 

(13 600) 

30,000 

(13 600) 

30,000 

(13 600) 

*Recommended 

**Maximum Operating Pressure based on hydrostatic pressure and applied gun weight. 

The EZ Pass hanger does not have minimum ID or Burst Pressure requirements. 

NOTE: The EZ Pass gun hanger is designed with specific features to enhance its retrievability; however, due to the uncertainty of the wellbore conditions created by the 

perforating event, the retrieval of this tool cannot be assured. 

Weight 

lb (kg) 

116 

(52.6) 

165 

(74.8) 

180 

(81.7)

Automatic-Release Gun Hanger—Rotational Set 

For high volume testing and 

production, the automatic-release gun 

hanger (ARGH) allows perforating 

and testing of a zone without 

imposing downhole restrictions. The 

perforating assembly can be 

positioned and retained adjacent to 

the desired interval. The drillpipe or 

tubing is then removed. After all 

surface equipment is installed, the 

guns are detonated and then released 

automatically into the bottom of the 

well. 

Features 

With the ARGH: 

No tubing is required between the 

guns and packer 

No wireline work is required to drop 

the assembly 

No restrictions are left in the casing 

below the packer 

The maximum desired 

underbalanced pressure can be used 

Production tubing can be run and 

tested independently from other 

tools 

The ARGH and guns are run on the 

workstring 

The risk of presetting the packer is 

reduced 

In BigBore monobore completions, 

the production tubing and 

permanent packer are installed 

before running the ARGH 

perforating assembly 

Remedial work can be performed 

without pulling production 

equipment (such as setting bridge 

plugs, adding perforations, running 

coiled tubing, etc.) 

Lower gun-firing pressures can be 

used since all production equipment 

is pressure-tested before the guns are 

installed in the well (no need to 

exceed previous test pressures) 

Operation 

The ARGH is made up on the bottom 

of the perforating assembly. A righthand 

release on/off tool is made up on 

the top of the bottomhole assembly 

(BHA). After the BHA is correlated on 

depth, the operator picks up the string, 

turns it to the right, and slacks off 

weight on the ARGH. The ARGH 

should be set at this point. 

With weight still on the BHA, the 

operator continues to turn the 

workstring to the right to release the 

on/off tool. 

As the guns are detonated, the explosive 

train is continued to the ARGH. Two 

shaped charges are detonated into a 

sealed fluid chamber. This action 

eliminates the support to the slip 

assembly. The ARGH and perforating 

assembly are then released 

automatically and fall to the bottom. 

Primacord 

Shaped 

Charges 

Silicone 

Fluid 

Chamber 

Slip 

Assembly 


HAL10516 

Auto-Release Gun Hanger 

Rotational Set

Casing OD 

in. (mm) 

3 1/2 

(88.9) 

4 1/2 

(114.3) 

5 

(127) 

5 1/2 

(139.7) 

7 

(177.8) 

7 5/8 

(193.7) 

9 5/8 

(244.5) 

Casing Range 

lb/ft (kg/m) 

5.7-10.2 

(8.48-15.18) 

9.5-13.5 

(14.14-20.09) 

11.5-18 

(17.11-26.78) 

13-26 

(19.34-38.69) 

17-38 

(25.3-56.54) 

20-39 

(29.76-58.03) 

29.3-53.5 

(43.6-79.61) 

Automatic-Release Gun Hanger—Rotational Set Specifications 

Maximum OD 

in. (mm) 

2.75 

(69.85) 

3.75 

(95.25) 

3.75 

(95.25) 

4.5 

(114.3) 

5.5 

(123.2) 

5.5 

(123.2) 

8.0 

(203.2) 

Length 

ft (m) 

3.33 

(1.02) 

4.88 

(1.49) 

4.88 

(1.49) 

5.92 

(1.80) 

6.04 

(1.84) 

6.04 

(1.84) 

7.08 

(2.16) 

Minimum Tensile Rating 

lb (kg) 

25,000 

(11 300) 

85,000 

(38 500) 

85,000 

(38 500) 

120,000 

(54 400) 

120,000 

(54 400) 

120,000 

(54 400) 

120,000 

(54 400) 

Minimum BHA Weight 

lb (kg) 

Maximum Gun Weight 

lb (kg) 


150 

(68) 

300 

(136) 

300 

(136) 

500 

(227) 

600 

(272) 

600 

(272) 

600 

(272) 

12,300 

(5580) 

40,000 

(18 140) 

40,000 

(18 140) 

40,000 

(18 140) 

40,000 

(18 140) 

40,000 

(18 140) 

40,000 

(18 140)

Automatic-Release Gun Hanger—Automatic-J Mandrel 

For high volume testing and 

production, the automatic-release gun 

hanger (ARGH) allows perforating 

and testing of a zone without 

imposing downhole restrictions. The 

perforating assembly can be 

positioned and retained adjacent to 

the desired interval. The drillpipe or 

tubing is then removed. After all 

surface equipment is installed, the 

guns are detonated and then released 

automatically into the bottom of the 

well. 

Features 

With the ARGH: 

No tubing is required between the 

guns and packer 

No wireline work is required to drop 

the assembly 

No restrictions are left in the casing 

below the packer 

The maximum desired 

underbalanced pressure can be used 

Production tubing can be run 

and tested independently from 

other tools 

The automatic-J ARGH and guns are 

run on wireline, slickline, coiled 

tubing, or the workstring 

In BigBore monobore completions, 

the production tubing and 

permanent packer are installed 

before running the ARGH 

perforating assembly 

Remedial work can be performed 

without pulling production 

equipment (such as setting bridge 

plugs, adding perforations, running 

coiled tubing, etc.) 

Lower gun-firing pressures can be 

used since all production equipment 

is pressure-tested before the guns are 

installed in the well (no need to 

exceed previous test pressures) 

Operation 

The automatic-J mandrel can be run 

on wireline, slickline, coiled tubing, or 

the workstring. Rotation is not 

required to set the automatic-J gun 

hanger. Upward and downward 

manipulation either sets or un-sets the 

hanger. As the guns are detonated, the 

explosive train is continued to the 

ARGH. Two shaped charges are 

detonated into a sealed fluid chamber. 

This action eliminates the support to 

the slip assembly. The ARGH and 

perforating assembly are then released 

automatically and fall to the bottom. 

Silicone Fluid 

Chamber 

Slip Cone 

Automatic-J 

Mandrel 

Primacord 

Slip Assembly 


Crossover 


HAL10542 

Automatic-Release 

Gun Hanger (ARGH) 

Automatic-J Mandrel

Casing OD 

in. (mm) 

2 7/8 

(73.1) 

3 1/2 

(88.9) 

4 

(101.6) 

3 1/2 

(88.9) 

Slimhole 

4 1/2 

(114.3) 

5 

(127) 

4 1/2 

(114.3) 

Slimhole 

5 1/2 

(139.7) 

7 

(177.8) 

7 5/8 

(193.7) 

9 5/8 

(244.5) 

10 3/4 

(273.05) 

Casing Range 

lb/ft (kg/m) 

2 7/8 

6.4-6.50 

(9.52-9.67) 

3 1/2 

5.75-10.2 

(8.56-15.18) 

4 

14.40 

(21.43) 

3 1/2 

9.2-12.95 

(13.69-19.27) 

4 1/2 

9.5-13.5 

(14.14-20.09) 

5 

15.0-18.0 

(22.32-26.78) 

4 1/2 

15.1-16.9 

(22.46-25.15) 

5 1/2 

15.50-23 

(23.06-34.22) 

7 

20-38 

(29.76-56.54) 

7 5/8 

24-39 

(35.71-58.03) 

9 5/8 

29.3-53.5 

(43.6-79.61) 

10 3/4 

60.7 - 71.10 

(90.31 - 105.78) 

Maximum 

OD 

in. (mm) 

Automatic-J Mandrel Specifications 

2.25 

(57.2) 

2.75 

(73.0) 

2.75 

(73.0) 

2.50 

(63.5) 

3.75 

(95.25) 

3.75 

(95.25) 

3.50 

(88.9) 

4.50 

(114.3) 

5.5 

(123.2) 

5.5 

(123.2) 

8.0 

(203.2) 

9.17 

(233) 

Length 

ft (m) 

4.49-4.87 

(1.349-1.47) 

4.87-5.28 

(1.47-1.59) 

4.87-5.28 

(1.47-1.59) 

53.79-58.47 

(16.40-17.82) 

7.95-9.28 

(2.40-2.80) 

7.95-9.28 

(2.40-2.80) 

58.34-67.29 

(17.78-20.51) 

9.31-10.29 

(2.80-3.10) 

9.26-10.44 

(2.79-3.14) 

9.26-10.44 

(2.79-3.14) 

7.08 

(2.16) 

9.8 

(299) 


Pressure* 

psi (bar) 

20,000 

(1379) 


lb (kg) 

25,000 

(11 300) 

Minimum 

BHA Weight 

lb (kg) 

Maximum 

Gun Weight 

lb (kg) 


N/A 

N/A 

20,000 

(1379) 

20,000 

(1379) 

20,000 

(1379) 

N/A 

N/A 

N/A 

N/A 

N/A 

N/A 

25,000 

(11 300) 

25,000 

(11 300) 

25,000 

(11 340) 

85,000 

(38 500) 

85,000 

(38 500) 

25,000 

(11 340) 

120,000 

(54 400) 

120,000 

(54 400) 

120,000 

(54 400) 

120,000 

(54 400) 

160,300 

(72 700) 

*As total gun weight increases, the maximum operating pressure decreases. 



150 

(68) 

150 

(68) 

150 

(68) 

150 

(68) 

300 

(136) 

300 

(136) 

200 

(91) 

500 

(227) 

600 

(272) 

600 

(272) 

600 

(272) 

600 

(272) 

9,000 

(4050) 

12,300 

(5580) 

12,300 

(5580) 

20,000 

(9072) 

40,000 

(18 140) 

40,000 

(18 140) 

20,000 

(9072) 

40,000 

(18 140) 

40,000 

(18 140) 

40,000 

(18 140) 

40,000 

(18 140) 

250,000 

(113 400)

Explosive Transfer Swivel Sub 

The explosive transfer swivel sub allows two sections of guns 

to rotate independently of one another. This independent 

rotation is important on long strings of guns in horizontal 

wells when they must be oriented in a specific direction. It is 

easier to orient several short sections of guns, rather than one 

long section. 

Features 

Useful in horizontal wells when shots need to be oriented 

in a specific direction to the wellbore 

Bi-directional, allowing firing from either direction 

Operation 

This swivel sub can be run as a connector between two guns 

to allow them to rotate independently without breaking the 

explosive train. In other words, this sub passes on the 

explosive transfer to the next gun. 

SAP No. 

101271529 

101271553 

101271546 

101284187 

101278821 


Type 

in. (mm) 

2 3/8 (60.33) 


2 7/8 (73.03) 


4.00 (101.60) 


4.420 (112.27) 


5 1/8 (130.18) 


Explosive Transfer Swivel Sub Specifications 

Maximum 

OD 

in. (mm) 

2.75 

(69.85) 

3.375 

(85.73) 

4.625 

(117.47) 

5.125 

(130.18) 

5.750 

(146.05) 

Makeup 

Length 

ft (m) 

1.13 

(0.344) 

1.13 

(0.344) 

1.16 

(0.353) 

1.13 

(0.344) 

1.16 

(0.353) 


Pressure 

psi (bar) 

20,000 

(1379) 

20,000 

(1379) 

20,000 

(1379) 

20,000 

(1379) 

20,000 

(1379) 

Explosive Transfer 

Swivel Sub Assembly 


HAL10513 


lb (kg) 

108,000 

(48 988) 

190,000 

(86 183) 

332,000 

(150 593) 

416,000 

(188 694) 

410,000 

(185 973) 


Tensile Load* 

lb (kg) 

32,000 

(14 515) 

40,000 

(18 144) 

60,000 

(27 216) 

60,000 

(27 216) 

60,000 

(27 216) 

*Maximum operating tensile load is the point at which the ball bearing race will start to deform, and the tool will not function as designed. 

Temperature rating is determined by explosive.

Shearable Safety Sub 

The shearable safety sub is designed to 

provide a gap in the explosive train, 

which could be severed at surface with 

the shear rams. The most common 

application is in the use of live 

well intervention. 

The shearable safety sub provides two 

levels of defense against wellbore 

pressures. First, it provides a sub with a 

smooth profile that is utilized by 

closing the sealing rams to control 

pressure when the gun connection is 

made up or broken out. Secondly, if the 

well conditions become dangerous and 

the shear rams need to be activated, it 

provides an area in the gun assembly 

that does not contain explosives and 

can be safely severed by the shear rams. 

Features 

Continues the explosive train 

without use of continuous explosives 

Isolates pressure from below 

Allows a smooth sealing area for the 

pipe rams to seal against 

SAP No. 

101245799 


Type 

2 7/8-in. Acme 

Box x Pin 

Maximum OD 

in. (mm) 

3.375 

(85.73) 


Uses standard explosives 

Contains standard 3 3/8-in. gun 

connections above and below 

Can be run with tubing, coiled 

tubing, wireline, and modular 

applications 

Can be sheared independently of the 

guns firing 

Can be redressed at minimal cost 

This tool has been successfully sheared 

during testing using the following: 

Shaffer shear 7 1/16-in. 10k safety 

head 

Piston diameter of 14 in. (153 in.²) 

Sheared at 2,000 psi 

Force required to shear tool = 

(153 in.²) (2,000 psi) = 306,000 lb 

Shearable Safety Sub Specifications 

Minimum ID 

N/A 

Makeup 

Length 

ft (m) 

2.50 

(0.76) 


Pressure 

psi (bar) 

20,000 

(1380) 


Pressure 

psi (bar) 

Shearable Safety Sub 


N/A 

HAL15454 

Tensile 

Strength 

lb (kg) 

200,000 

(90 700) 

Weight 

lb (kg) 

54.4 

(24.6)

Roller Tandem Assembly 

Roller tandem assemblies are used to reduce the friction 

between the perforating guns and the casing. In some cases, 

the frictional drag can be reduced by as much as 90%. 

Applications 

Running guns on coiled tubing in horizontal and highly 

deviated wells 

Dropping the guns into the rathole in highly deviated wells 

Can be deployed in conjunction with the modular gun 

system 

SAP No. 

120021632 

100155770 

100155771 

101313551 

Size 

in. (mm) 

2 3/4 

(69.85) 

3 3/8 

(85.72) 

4 5/8 

(117.47) 

7 

(177.80) 

Roller Tandem Assembly 


HAL10567 

Roller Tandem Assembly Specifications 

Effective OD 

in. (mm) 

3.06 

(77.72) 

3.76 

(95.50) 

5.63 

(143.00) 

8.20 

(208.28) 

No. of Rollers 

6 

(2 rows of 3) 

8 

(2 rows of 4) 

8 

(2 rows of 4) 

8 

(2 rows of 4) 

Roller 

Phasing 

60° 

45° 

45° 

45° 


lb (kg) 

140,000 

(63 503) 

246,000 

(111 584) 

414,000 

(187 787) 

444,000 

(201 395) 

Makeup Length 

in. (mm) 

6.97 

(177.04) 

7.70 

(195.58) 

9.25 

(234.95) 

15.52 

(394.21)

Centralizer Tandem 

In certain types of TCP operations, it is desirable to 

centralize the guns and other tools in the casing. Halliburton 

has designed a full range of centralizers to meet this 

requirement for all gun sizes. The centralizers are designed to 

minimize the possibility of “hanging up” while running or 

pulling the guns and to maximize the flow area around the 

centralizers. 

Application 

Two of the primary applications for the centralizers are: 

1. When perforating with big hole charges, it is 

recommended to centralize the guns to ensure that the 

exit holes in the casing will all be of a consistent size. If 

the guns are not centralized, the size of the exit holes 

will vary according to the clearance from the gun to 

the casing. This can cause problems with sand control 

operations. 

2. In modular gun completions, it is necessary to 

centralize the gun modules to obtain a reliable 

explosive transfer between modules. 

Contact your Halliburton representative for a list of available 

centralizers. 

Centralizer 


Guns 

Centralizer 

HAL15986 

Centralizer Tandem

Emergency Release Assembly 

The emergency release assembly was designed to run in 

conjunction with the automatic-release gun hanger 

assembly. When deploying the gun hanger on tubing or drill 

pipe, the emergency release is run between the gun hanger 

and guns to serve as a weak point in case the hanger gets 

stuck while running in the hole. Pulling or jarring on the 

pipe will cause the emergency release assembly to shear, 

allowing the retrieval of the guns and tubing from the well. 

When deploying the gun hanger on wireline, the rope socket 

typically acts as the weak point. 

SAP No. 

101201127 

Emergency Release Assembly Specifications 

OD Size 

in. (mm) 

3 3/8 

(85.73) 

Emergency Release Assembly 


HAL15987 

No. Shear Screws Temperature Rating 

8 steel shear screws rated at 

5,600 lb per screw 

Determined by explosives 

Pressure Rating 

psi (bar) 

25,000 

(1724)

Annular Pressure-Control Line Vent 

The annular pressure-control line (APF-C) vent is a device 

that isolates the tubing from annulus fluid or pressure. The 

vent is actuated by rathole pressure after the perforating 

assembly has been detonated. It then provides a flowpath for 

the formation fluid into the tubing string. 

Features 

Ideal for highly deviated or horizontal wells 

Requires minimal pressure to operate 

Eliminates nitrogen displacement or swabbing the tubing 

string to achieve desired underbalance 

Operation 

The APF-C vent is run directly on top of the APF-C firing 

head. When the perforating assembly is detonated, gun 

pressure shifts an actuating piston into a power piston. This 

shift opens the flow ports to the tubing. 

SAP No. 

120038049 

101016565 


Type 

in. (mm) 

2 3/8 (60.33) EUE 

8 Rd Box × 

2 7/8 (73.03) 6P 

Acme Box 

2 7/8 (73.03) 

EUE 8 Rd Box × 

2 7/8 (73.03) 6P 

Acme Box 

Annular Pressure-Control Line 

(APF-C) Vent 

Annular Pressure-Control Line (APF-C) Vent Specifications 

Maximum 

OD 

in. (mm) 

3.38 

(85.85) 

3.88 

(98.55) 

Minimum 

ID 

in. (mm) 

Nonfull-bore 

Nonfull-bore 


of Ports 

in. (mm) 

4@1.0 

(25.4) 

5@1.0 

(25.4) 

Flow 

Area 

in. 2 (cm 2 ) 

2.63 

(16.97) 

3.93 

(25.34) 

Makeup 

Length 

ft (m) 


2.37 

(0.72) 

2.43 

(0.74) 


HAL15441 

Maximum 

Operating 

Pressure 

psi (bar) 

20,000 

(1380) 

20,000 

(1380) 

Tensile 

Strength 

lb (kg) 

150,000 

(68 000) 

170,000 

(77 000) 

Burst 

Pressure 

psi (bar) 

22,000 

(1515) 

15,000 

(1035) 

Collapse 

Pressure 

psi (bar) 

22,000 

(1515) 

15,000 

(1035)

Annular Pressure-Control Line Swivel Sub 

When run in conjunction with the annular pressure-control 

line (APF-C) firing head, the APF-C swivel sub provides a 

swivel point between the guns and packer when it is desired 

to have the guns rotate freely as when orienting shots in a 

deviated well. 

Features 

Compatible with APF-C firing head and control line 

Can be run anywhere between the packer and the 

firing head 

Transmits pressure through the control line while rotating 

Operation 

The APF-C swivel is made up in the string between the 

packer and the firing head. A section of control line is made 

up from the packer to the top of the swivel. A second section 

of control line is made up from the bottom of the swivel to 

the APF-C firing head. Annulus pressure is transmitted from 

the packer, through the swivel to the firing head. 

SAP No. 

101230619 

Thread Size 


in. (mm) 

2 7/8 EU 8rd 

Box × Pin 

APF-C Swivel Sub 

Annular Pressure-Control Line (APF-C) Swivel Sub Specifications 

Maximum OD 

in. (mm) 

5.13 

(130.30) 

Minimum ID 

in. (mm) 

2.0 

(50.8) 

*The APF-C swivel sub is not designed to operate with differential pressure. 


lb (kg) 

200,000 

(90 718) 

Operating Load 

Limit Rating 

lb (kg) 

36,000 

(16 329) 


HAL10539 

Burst 

Pressure 

psi (bar) 

Collapse 

Pressure 

psi (bar) 

NA* NA* 

Makeup 

Length 

ft (m) 

1.3 

(0.39)

Annular Pressure-Control Line Tubing Release 

The 2 7/8-in. annular pressure-control line tubing release 

assembly (APF-C TR) provides a mechanical method of 

releasing the APF-C firing head and VannGun® assembly 

from the tubing string. 

Features 

Releasing the gun assembly opens the tubing for other 

tools such as production logging, testing, and treating 

Low cost method to release gun assembly 

Utilizes off-the-shelf shifting tools 

No time limit on dropping the gun assembly 

Leaves perforations uncovered and helps eliminate 

flow restriction 

Operation 

The APF-C TR is run between the APF-C firing head and the 

7- or 9 5/8-in. annulus pressure transfer reservoir (APTR). 

The control line for the APF-C is attached to the control line 

housing, which transfers the pressure through the APF-C TR 

and out the finger sub to a second control line. The second 

control line transfers the pressure down to the APF-C firing 

head. Releasing can be accomplished by the use of a standard 

Halliburton or Garret shifting tool. 

SAP No. 

87921 

APF-C Tubing Release (APF-C TR) 

Annular Pressure Control Line Tubing Release (APF-C TR) Specifications 

Upper Thread Size 


2 7/8 (73.03) 

EUE 8 Rd Box 

Lower Thread Size 


2 7/8 (73.03) 

EUE 8 Rd Pin 

Makeup 

Length 

ft (m) 

2.24 

(0.68) 

Maximum OD 

in. (mm) 

4.62 

(117.35) 

Minimum ID 

in. (mm) 


HAL10589 

Latch Sizes – 1.88 

(47.75), 2.125 (53.98), 

or 2.25 (57.15) 

Tensile 

Strength 

lb (kg) 

120,000 

(54 431) 

Burst 

Pressure 

psi (bar) 

12,000 

(827) 

Collapse 

Pressure 

psi (bar) 

11,000 

(758)

Bar Pressure Vent 

The bar pressure vent (BPV) is 

designed to achieve a differential 

pressure between the formation and 

tubing string. This tool helps to safely 

allow a differential pressure in wells 

with existing open perforations or in 

unperforated wells. The BPV is an 

internal sliding-sleeve tool actuated by 

pressure in the tubing. It is run between 

the packer and the guns. 

Features 

Offers an inexpensive way to create 

the necessary underbalance 

Allows the hole to be totally 

contained at the wellhead before 

the surge 

Allows the sleeve to lock in place 

once the port is opened 

Can be run with any packer 

Does not rely on tubing 

manipulation (Hydrostatic 

pressure in the tubing is the only 

force required) 

SAP No. 

101201951 

100155788 

100010328 

100155789 

Thread Size 


in. (mm) 

2 3/8 (60.33) 

EUE 8 Rd 

Box × Pin 

2 3/8 (60.33) 

EUE 8 Rd 

Box × Pin 

2 7/8 (73.03) 

EUE 8 Rd 

Box × Pin 

3 1/2 (88.90) 

EUE 8 Rd 

Box × Pin 

Maximum 

OD 

in. (mm) 

3.06 

(77.72) 

3.63 

(92.20) 

3.88 

(98.55) 

5.0 

(127.0) 

Minimum 

ID 

in. (mm) 

1.50 

(38.10) 

1.90 

(48.26) 

2.25 

(57.15) 

2.75 

(69.85) 

Operation 

The BPV consists of a ported housing 

and a sliding sleeve. The sliding sleeve is 

isolated from the tubing pressure by a 

break plug with a hollow center. 

The BPV is activated when the 

detonating bar is dropped through the 

tubing and shears the hollow break 

plug. This action allows the pressure 

in the tubing to force the sleeve 

upward, uncovering the ports. A lock 

ring locks the sleeve open. The 

detonating bar continues downward 

to strike the firing head. 

If the vent must be opened before 

dropping the detonating bar, dropping 

a special tube will open the vent and 

not fire the guns. When the bar is 

dropped, it will pass through the tube 

and fire the guns. 

Bar Pressure Vent (BPV) Specifications 


of Ports 

in. (mm) 

4 @ 1.0 

(25.40) 

4 @ 1.0 

(25.40) 

4 @ 1.13 

(28.70) 

4 @ 1.75 

(44.45) 

Flow 

Area 

in. 2 (cm 2 ) 

1.77 

(11.40) 

3.14 

(20.27) 

3.98 

(25.65) 

5.94 

(38.32) 

Makeup 

Length 

ft (m) 

1.30 

(0.40) 

1.30 

(0.40) 

1.40 

(0.43) 

1.57 

(0.48) 

Maximum 

Operating 

Pressure 

psi (bar) 

20,000 

(1380) 

15,000 

(1035) 

15,000 

(1035) 

15,000 

(1035) 


Minimum 

Operating 

Pressure 

psi (bar) 

Maximum 

Differential 

Pressure 

psi (bar) 

Bar Pressure Vent (BPV) 


1,000 

(69) 

1,000 

(69) 

1,000 

(69) 

1,000 

(69) 

8,000 

(550) 

8,000 

(550) 

8,000 

(550) 

8,000 

(550) 

HAL10565 

Tensile 

Strength 

lb (kg) 

140,000 

(63 400) 

146,000 

(66 200) 

160,000 

(72 500) 

400,000 

(181 400) 

Burst 

Pressure 

psi (bar) 

24,000 

(1655) 

18,000 

(1240) 

19,000 

(1310) 

22,000 

(1515) 

Collapse 

Pressure 

psi (bar) 

20,000 

(1380) 

22,000 

(1515) 

17,000 

(1170) 

18,000 

(1240)

Below-Packer Vent Device 

The below-packer vent device (BPVD) was developed for 

use with the annulus-pressure crossover assembly (APCA). 

Surface pressure applied to the annulus is transmitted 

through the APCA to a closed chamber below the BPVD 

and above a pressure-responsive firing head. The BPVD 

can be set to work before or after the perforating assembly 

is detonated. 

Features 

Does not require tubing hydrostatic pressure to operate 

Can operate in highly deviated wells 

Can be used in wells with low formation pressure 

Eliminates nitrogen requirements 

Helps allow maximum underbalance 

Is compatible with several types of firing heads 

Can provide reliable and accurate pressure response 

Operation 

To open the BPVD, a predetermined annulus pressure is 

transmitted through the APCA to below the BPVD. This 

pressure then ruptures a disk in the lower housing of the 

BPVD. An actuating piston then forces the venting sleeve 

away from the production ports. This action establishes 

communication with the tubing string. 

SAP No. 

100155787 

100014176 

Thread Size 


in. (mm) 

2 3/8 (60.33) 

EUE 8 Rd 

Box × Pin 

2 7/8 (73.03) 

EUE 8 Rd 

Box × Pin 

Maximum OD 

in. (mm) 

3.38 

(85.85) 

3.88 

(98.55) 

Below-Packer Vent 

Below-Packer Vent Device (BPVD) Specifications 

Minimum ID 

in. (mm) 

Nonfull-bore 

Non- 

full-bore 

Makeup 

Length 

ft (m) 

2.32 

(0.71) 

2.26 

(0.69) 


of Ports 

in. (mm) 

4 @ 1.0 

(25.4) 

5 @ 1.0 

(25.4) 


HAL15450 

Maximum 

Operating 

Pressure 

psi (bar) 

15,000 

(1035) 

15,000 

(1035) 


Minimum 

Operating 

Pressure 

psi (bar) 

1,000 

(69) 

1,000 

(69) 

Tensile 

Strength 

lb (kg) 

150,000 

(68 000) 

170,000 

(77 000) 

HAL15451 

Below-Packer Vent 

Device (BPVD) 

Burst 

Pressure 

psi (bar) 

25,000 

(1725) 

25,000 

(1725) 

Collapse 

Pressure 

psi (bar) 

22,000 

(1515) 

25,000 

(1725)

Maximum Differential Bar Vent 

The maximum differential bar vent 

(MDBV) assembly is run between the 

perforating guns and the packer. After 

the packer is set, the opening of the 

vent creates communication between 

the tubing and the rathole. The vent is 

opened by breaking the plug inside the 

tool and allowing the sleeve to 

uncover the ports. Running the 

MDBV allows the operator to run the 

tubing in the well with no hydrostatic 

pressure in the tubing. 

Features 

Operates with a minimum amount 

of fluid in the tubing 

Helps allow maximum differential 

pressure when perforating in lowpressure 

formations 

Does not depend on tubing 

hydrostatic pressure to operate 

Assisted mechanically by an 

operating spring to help ensure full 

and complete opening 

Can be used in wells with open 

perforations to achieve an 

underbalance when guns are fired to 

add new perforations 

SAP No. 

100005291 

100005294 

100156853 

Thread Size 


in. (mm) 

2 3/8 (60.33) 

EUE 8 Rd 

Box × Pin 

2 7/8 (73.03) 

EUE 8 Rd 

Box × Pin 

3 1/2 (88.9) 

EUE 8 Rd 

Box × Pin 

Operation 

The maximum differential bar vent is 

held closed by a chamber of silicone 

fluid, which keeps a spring compressed. 

When the silicone fluid is released from 

the chamber, the spring extends and 

opens the vent. Once the break plug is 

broken, the silicone fluid drains into 

the tubing. 

The MDBV will open with up to 

1,000 psi (68.95 bar) in the tubing 

regardless of rathole pressure. If there is 

more than 1,000 psi (68.95 bar) in the 

tubing, and there is uncertainty about 

the rathole pressure, consider the bar 

pressure vent instead of the MDBV. 

If the vent must be opened before 

dropping the detonating bar, dropping 

a special tube will open the vent and 

not fire the guns. When the bar is 

dropped, it will pass through the tube 

and fire the guns. 

Maximum Differential Bar Vent (MDBV) Specifications 

Maximum 

OD 

in. (mm) 

3.36 

(92.20) 

3.88 

(98.55) 

4.50 

(114.30) 

Minimum 

ID 

in. (mm) 

2.0 

(50.80) 

2.2 

(57.15) 

2.7 

(69.85) 


of Ports 

in. (mm) 

5 @ 1.0 

(25.40) 

4 @ 1.13 

(28.70) 

4 @ 1.75 

(44.45) 

Flow Area 

of Ports 

in. 2 (cm 2 ) 

3.92 

(25.29) 

4.01 

(27.87) 

9.58 

(61.81) 

Makeup 

Length 

ft (m) 

Temperature 

Rating 

(Limited by 

Silicone Fluid) 

°F (°C) 

Maximum Differential Bar Vent 


2.29 

(0.70) 

2.39 

(0.73) 

2.75 

(0.84) 


350 

(176) 

350 

(176) 

350 

(176) 

HAL15445 

Tensile 

Strength 

lb (kg) 

221,000 

(100 200) 

231,000 

(104 700) 

245,000 

(111 000) 

Burst 

Pressure 

psi (bar) 

19,500 

(1345) 

19,000 

(1310) 

14,000 

(965) 

Collapse 

Pressure 

psi (bar) 

16,500 

(1135) 

13,000 

(895) 

14,000 

(965)

Pressure-Operated Vent 

The pressure-operated vent (POV) is 

designed to achieve a differential 

pressure between the formation and 

tubing string and to provide a way to 

open the vent and test the packer before 

the guns are fired. 

When the guns have been positioned 

and the packer has been set, the 

predetermined amount of fluid is 

added to the tubing. Adding the fluid 

into the tubing causes the POV to open 

and creates the proper pressure 

differential before firing. Nitrogen may 

also be used with or in place of the 

fluids to obtain the necessary 

hydrostatic pressure in the tubing. 

Features 

Allows the vent to be opened without 

the guns being fired 

Allows the packer to be tested before 

the guns are fired 

Fills tubing automatically when run 

with Vann circulating valve 

SAP No. 

101297298 

100014177 

100014178 

100014179 

Thread Size 


in. (mm) 

2 3/8 (60.33) 

EUE 8 Rd 

Box × Pin 

2 3/8 (60.33) 

EUE 8 Rd 

Box × Pin 

2 7/8 (73.03) 

EUE 8 Rd 

Box × Pin 

3 1/2 (88.90) 

EUE 8 Rd 

Box × Pin 

Maximum 

OD 

in. (mm) 

3.06 

(77.72) 

3.63 

(92.20) 

3.88 

(98.55) 

5.0 

(127.0) 

Minimum 

ID 

in. (mm) 

1.50 

(38.10) 

1.90 

(48.26) 

2.25 

(57.15) 

2.75 

(69.85) 

Can be run with mechanical or 

pressure-actuated firing heads 

Useful in highly deviated wells 

Compatible with other packers 

Operation 

The POV consists of a ported housing, 

a sliding sleeve, and a set of shear pins. 

The sleeve is held in the closed 

position by a variable number of shear 

pins. The pins are isolated from 

annular pressure and are only exposed 

to the tubing hydrostatic. The POV 

will open when the proper amount of 

hydrostatic pressure is applied to the 

shear pins. The amount of hydrostatic 

it takes to open the POV depends on 

how many shear pins are installed in 

the tool. When the pins shear, the 

hydrostatic pressure forces the sleeve 

upward, which uncovers the flow 

ports. The sleeve is then locked into 

the open position. 

Pressure-Operated Vent (POV) Specifications 


of Ports 

in. (mm) 

4 @ 1.0 

(25.40) 

4 @ 1.0 

(25.40) 

4 @ 1.13 

(28.70) 

4 @ 1.75 

(44.45) 

Total 

Flow Area 

in. 2 (cm 2 ) 

1.77 

(11.40) 

3.14 

(20.27) 

3.98 

(25.65) 

5.94 

(38.32) 

Makeup 

Length 

ft (m) 

1.30 

(0.40) 

1.30 

(0.40) 

1.40 

(0.43) 

1.57 

(0.48) 

Maximum 

Operating 

Pressure 

psi (bar) 

20,000 

(1380) 

15,000 

(1035) 

15,000 

(1035) 

15,000 

(1035) 


Minimum 

Operating 

Pressure 

psi (bar) 

Pressure-Operated Vent (POV) 


1,000 

(69) 

1,000 

(69) 

1,000 

(69) 

1,000 

(69) 

HAL10538 

Maximum 

Differential 

Pressure 

psi (bar) 

8,000 

(550) 

8,000 

(550) 

8,000 

(550) 

8,000 

(550) 

Tensile 

Strength 

lb (kg) 

140,000 

(63 400) 

146,000 

(66 200) 

160,000 

(72 500) 

400,000 

(181 400) 

Burst 

Pressure 

psi (bar) 

24,000 

(1655) 

18,000 

(1240) 

19,000 

(1310) 

22,000 

(1515) 

Collapse 

Pressure 

psi (bar) 

20,000 

(1380) 

22,000 

(1515) 

17,000 

(1170) 

18,000 

(1240)

Vann Circulating Valve 

The Vann circulating valve (VCV) is 

designed to be used as a fill-up valve or 

as a circulating valve for displacing well 

fluids before setting a packer. After the 

fluid is displaced, the operator applies 

pressure to the tubing or annulus to 

rupture a disk and close the VCV. 

Features 

Can be used as a circulating and 

shutoff valve 

Often run with other venting or 

production devices 

Economical and reusable 

Operation 

The VCV consists of a ported housing, 

a sliding sleeve, and a rupture disk, 

which must be ordered separately. The 

sliding sleeve, which has two air 

chambers, is open while the tool is run 

in the hole. 

SAP No. 

101015372 

120038456 

Thread Size 


in. (mm) 

2 3/8 (60.33) 

EUE 8 Rd 

Box × Pin 

2 7/8 (73.03) 

EUE 8 Rd 

Box × Pin* 

Maximum 

OD 

in. (mm) 

3.38 

(85.85) 

4.65 

(188.11) 

The rupture disk is available for 

different pressure ratings as needed. 

The amount of hydrostatic pressure 

required to actuate the VCV depends 

on the rating of the rupture disk. 

Once the disk ruptures, the hydrostatic 

pressure enters the lower air chamber 

through the ruptured disk, forcing the 

sliding sleeve upward to cover the flow 

ports. Operating pressure can be 

pump-pressure applied after the VCV is 

at the bottom of the well or applied by 

hydrostatic pressure when the tool is 

run in the hole. 

Vann Circulating Valve (VCV) Specifications 

Minimum ID 

in. (mm) 

1.875 

(47.62) 

2.12 

(53.85) 


of Ports 

in. (mm) 

4 @ 1.0 

(25.4) 

6 @ 1.0 

(25.4) 

Flow Area 

of Ports 

in. 2 (cm 2 ) 

3.14 

(20.26) 

4.71 

(30.39) 

Makeup 

Length 

ft (m) 

Maximum 

Operating 

Pressure 

psi (bar) 

Minimum 

Operating 

Pressure 

psi (bar) 

Vann Circulating 

Valve (VCV) 


1.96 

(0.60) 

3.25 

(0.99) 

15,000 

(1035) 

15,000 

(1035) 

*Optional connections are 2 7/8-IF and 3 1/2-IF. 


1,000 

(69) 

1,000 

(69) 

HAL15447 

Tensile 

Strength 

lb (kg) 

225,000 

(102 000) 

392,000 

(177 700) 

Burst 

Pressure 

psi (bar) 

22,000 

(1515) 

20,000 

(1380) 

Collapse 

Pressure 

psi (bar) 

18,000 

(1250) 

18,000 

(1250)

Automatic Release 

The automatic release (AR) allows the perforating guns to 

drop immediately after firing. 

Features 

Can be used with most mechanical and pressure-actuated 

firing heads 

Allows for immediate release of the guns 

Leaves the tubing fully open after the guns are released 

Eliminates the need to run wireline to shift the guns 

Reduces the chance of the gun’s sticking because of debris 

Operation 

The AR allows for dropping the perforating guns after they 

are fired. The guns may be fired either mechanically or by 

pressure. The releasing device is actuated by the pressure 

generated outside the perforating guns upon detonation, so 

the guns are released as soon as they fire. 

Automatic Release (AR) Assemblies List 

SAP No. Description 

Automatic Release (AR) 

100005225 2 3/4-in. Auto Release with Mechanical Firing Head 

100005226 2 3/4-in. Auto Release with Mechanical Firing Head Model II-D 



100155754 3 3/8-in. Auto Release with Mechanical Firing Head Model III-D 

100005235 3 3/8 in. Auto Release with 2 1/2-in. TDF 

100014158 3 3/8-in. Auto Release-High Pressure with 2 1/2-in. TDF 

100010045 3 3/8-in. Auto Release-High Pressure with Mechanical Firing Head 

101313281 3 3/8-in. Auto Release Firer with 2 1/2 in. TDF (3 1/2 NK3SB) 



101205564 3 1/2-in. Auto Release Firer, Low Pressure with Model II-D 

101294470 3 1/2-in. Auto Release Firer with 2 1/2 in. TDF 

101313282 3 1/2-in. Auto Release Firer with Model II-D 



101213155 4 1/2-in. Auto Release Firer Low Pressure with Model II-D 



HAL10512

SAP No. 

Automatic Release (AR) Assemblies List 

SAP No. Description 

101313025 5 1/2-in. Auto Release Firer with Model II-D 

101310170 5 1/2-in. Auto Release Firer with Model II-D or III-D 




in. (mm) 

100005225 2 3/8 (60.33) EUE 8 Rd 

100005226 2 3/8 (60.33) EUE 8 Rd 

100005233 2 7/8 (73.03) EUE 8 Rd 

100005234 2 7/8 (73.03) EUE 8 Rd 

100005235 2 7/8 (73.03) EUE 8 Rd 

100155754 2 7/8 (73.03) EUE 8 Rd 

100014158 2 7/8 (73.03) EUE 8 Rd 

100010045 2 7/8 (73.03) EUE 8 Rd 

100005236 3 1/2 (88.90) EUE 8 Rd 

100156106 3 1/2 (88.90) EUE 8 Rd 

100155752 4 1/2 (114.30) OD Box 

101357916 4 1/2 (114.30) OD Box 

101294470 3 1/2 (88.90) EUE 8 Rd 

101313059 5 1/2 (139.7) TS-3SB Pin 

101357918 5 1/2 (139.7) VAM Box 

101313281 3 1/2 (88.90) NK3SB Box 

101205564 3 1/2 (88.90) EUE 8 Rd 

101313282 3 1/2 (88.90) NK3SB Box 

100155752 4 1/2 (114.30) OD Blank 

101294471 4 1/2 (114.30) OD Blank 

101213155 

4 1/2 (114.30) 

CS Hydril Box 

101313025 5 1/2 (139.7) OD Blank 

Automatic Release (AR) Specifications 

Maximum 

OD 

in. (mm) 

2.88 

(73.15) 

2.88 

(73.15) 

3.38 

(85.85) 

3.38 

(85.85) 

3.38 

(85.85) 

3.38 

(85.85) 

3.38 

(85.85) 

3.38 

(85.85) 

3.78 

(96.01) 

3.78 

(96.01) 

4.5 

(114.30) 

4.92 

(126) 

3.78 

(96.01) 

5.81 

(148) 

5.957 

(151) 

ID After 

Release 

in. (mm) 

2.125 

(53.98) 

2.125 

(53.98) 

2.72 

(69.09) 

2.72 

(69.09) 

2.72 

(69.09) 

2.72 

(69.09) 

2.52 

(64.186) 

2.52 

(64.186) 

2.99 

(75.95) 

2.99 

(75.95) 

3.67 

(93.22) 

3.76 

(96) 

3.00 

(76.2) 

4.703 

(119) 

4.70 

(119) 

Makeup 

Length 

ft (m) 

Maximum 

Operating 

Pressure 

psi (bar) 

Minimum 

Operating 

Pressure 

psi (bar) 

Maximum 

Differential 

Pressure 

psi (bar) 

Tensile 

Strength 

lb (kg) 


2.06 

(0.63) 

2.06 

(0.63) 

2.23 

(0.68) 

2.23 

(0.68) 

2.23 

(0.68) 

2.23 

(0.68) 

2.23 

(0.68) 

2.23 

(0.68) 

2.23 

(0.68) 

2.23 

(0.68) 

2.23 

(0.68) 

2.39 

(.728) 

1.74 

(0.53) 

1.83 

(0.56) 

2.39 

(0.73) 

20,000 

(1380) 

20,000 

(1380) 

20,000 

(1380) 

20,000 

(1380) 

20,000 

(1380) 

20,000 

(1380) 

20,000 

(1380) 

20,000 

(1380) 

20,000 

(1380) 

20,000 

(1380) 

20,000 

(1380) 

13,000 

(896) 

20,000 

(1380) 

17,800 

(1227) 

13,000 

(896) 

1,500 

(103) 

1,500 

(103) 

1,500 

(103) 

1,500 

(103) 

1,500 

(103) 

1,500 

(103) 

500 

(34) 

500 

(34) 

1,500 

(103) 

1,500 

(103) 

1,500 

(103) 

7000 

(483) 

7000 

(483) 

4000 

(276) 

7000 

(483) 

Contact Halliburton TCP Representative 

15,000 

(1035) 

15,000 

(1035) 

10,000 

(690) 

10,000 

(690) 

10,000 

(690) 

10,000 

(690) 

17,000 

(1170) 

17,000 

(1170) 

10,000 

(690) 

10,000 

(690) 

9,500 

(655) 

6000 

(414) 

7500 

(517) 

4700 

(324) 

4000 

(276) 

49,500 

(22 400) 

49,500 

(22 400) 

68,000 

(30 800) 

68,000 

(30 800) 

68,000 

(30 800) 

68,000 

(30 800) 

68,000 

(30 800) 

68,000 

(30 800) 

68,000 

(30 800) 

68,000 

(30 800) 

115,000 

(52 100) 

87,200 

(39 553) 

53,300 

(24 100) 

106,100 

(48 100) 

106,100 

(48 100)

Mechanical Tubing Release 

The mechanical tubing release (MTR) provides operators 

with the option of keeping or releasing the VannGun® 

assembly from the tubing string. The MTR is usually run 

above the firing head and below the production ports below 

the packer. A standard shifting tool is used to operate the 

release mechanism in the MTR. 

Features 

Frees the tubing for other tools and operations such as 

logging, production testing, and treating 

Provides a low-cost way to release the gun assembly 

Uses standard off-the-shelf shifting tools 

Does not have a time limit on dropping the gun assembly 

Leaves perforations uncovered to eliminate flow 

restrictions 

Operation 

The MTR consists of three main components: the upper 

housing, a lower finger release sub, and a latch. The latch 

retains the finger release sub in the housing. To operate the 

MTR, the user must do the following: 

1. Select the proper shifting tool and run it into the hole 

on slickline through the MTR. 

2. Pick back up to engage the latch and lightly jar the 

latch four or five times. 

3. Go back down to verify the release of the VannGun 

assembly. 

SAP No. 

(w/o Latch) 

100005286 


Type 

in. (mm) 

2 3/8 (60.33) EUE 


Mechanical Tubing Release (MTR) Specifications 

Maximum OD 

in. (mm) 

3.06 

(77.22) 

Minimum ID 

(Latch Size) 

in. (mm) 

1.50 

(38.10) 

1.63 

(41.40) 

1.81 

(45.97) 

1.88 

(760) 

Tensile 

Strength 

lb (kg) 

111,500 

(50 576) 

Mechanical Tubing Release (MTR) 


HAL15435 

Burst 

Pressure 

psi (bar) 

12,000 

(825) 

Collapse 

Pressure 

psi (bar) 

10,000 

(690) 

Makeup 

Length 

ft (m) 

1.50 

(0.46)

SAP No. 

(w/o Latch) 

100005281 

100005284 

101236790 

101435633 

101398862 

101399826 

101327124 

Latch Size 

in. (mm) 

1.50 

(38.10) 

1.625 

(41.28) 

1.81 

(45.97) 

1.88 

(47.75) 

2.25 

(57.15) 

2.125 

(53.98) 

2.75 

(69.85) 

3.69 

(93.73) 

3.562 

(90) 

4.313 

(110) 


Type 

in. (mm) 

2 7/8 (73.03) EUE 


3 1/2 (88.9) EUE 


5 (127) 15 lb (6.8 kg) 

New Vam Box × Pin 

5 1/2-17.00 Vam Top 

HC Box X Pin 

Threads, 13 Chrome 

4 1/2-12.6 Vam Top 


5 1/2-15.5 Vam Top 


4 1/2-12.6 Vamace 

Box X Pin, 

13 Chrome 

Mechanical Tubing Release (MTR) Specifications 

3.38 

(85.85) 

3.95 

(100.33) 

5.59 

(142.01) 

6.50 

(165) 

5.50 

(140) 

6.50 

(165) 

5.50 

(140) 

1.88 

(47.75) 

2.13 

(53.98) 

2.25 

(57.15) 

111,500 

(50 576) 

2.25 

(57.15) 111,500 

2.75 

(69.85) 

3.69 

(93.68) 

4.313 

(110) 

3.562 

(90) 

4.313 

(110) 

3.562 

(90) 

(50 576) 

111,500 

(50 576) 

168,000 

(76 200) 

107,000 

(48,500) 

168,000 

(76,200) 

107,000 

(48,500) 


12,000 

(825) 

11,000 

(760) 

12,000 

(825) 

6,800 

(469) 

6,300 

(434) 

6,400 

(441) 

6,300 

(434) 

Mechanical Tubing Release (MTR) Shifting Tool and Key Number 

Tool No. 

SAP No. 

42 BO 245 

101059081 

42 BO 121 

12005796 

42 BO 117 

101059064 

42 BO 237 

101059079 

42 BO 116 

100008775 

42 BO 117 

101059064 

42 BO 237 

101059079 

42 BO 118 

100008776 

42 BO 159 

101015719 

42 BO 146 

100009659 

42 BO 238 

101010057 

Maximum OD 

in. (mm) 

Key No. 

SAP No. 

42 B 818 

101282505 

42 B 80 

101059269 

42 B 37 

101059122 

42 B 681 

101059193 

42 B 153 

101059090 

42 B 37 

101059122 

42 B 681 

101059193 

42 B 287 

101059109 

42 B 387 

101059133 

42 B 349 

101059118 

42 B 707 

101059204 

101399752 101399753 

101399109 101399113 

Minimum ID 

(Latch Size) 

in. (mm) 

Tensile 

Strength 

lb (kg) 

Key Maximum Exp. OD 

in. (mm) 

1.64 

(41.65) 

1.89 

(48.006) 

2.076 

(52.73) 

2.156 

(54.76) 

2.108 

(53.569) 

2.076 

(52.73) 

2.156 

(54.76) 

2.592 

(65.837) 

2.49 

(63.25) 

3.156 

(80.16) 

4.15 

(105.41) 

Burst 

Pressure 

psi (bar) 


Collapse 

Pressure 

psi (bar) 

11,000 

(760) 

10,000 

(690) 

11,000 

(760) 

5,000 

(345) 

6,000 

(414) 

4,000 

(276) 

6,000 

(414) 

Key Minimum OD 

in. (mm) 

1.49 

(37.85) 

1.62 

(41.148) 

1.75 

(44.45) 

1.69 

(42.93) 

1.84 

(46.74) 

1.750 

(44.45) 

1.69 

(42.93) 

2.156 

(54.762) 

1.97 

(50.04) 

2.718 

(69.037) 

3.67 

(93.218) 

Makeup 

Length 

ft (m) 

1.63 

(0.50) 

1.88 

(0.57) 

3.60 

(1.10) 

4.7 

(1.4) 

4.1 

(1.25) 

4.8 

(1.46) 

4.1 

(1.25)

Pressure-Actuated Tubing Release 

The pressure-actuated tubing release (PATR) is used to 

separate the guns from the toolstring when mechanical or 

slickline devices are not desirable. When separated, the guns 

drop off of the production tubing. Once the guns drop away, 

other tools and operations have no restrictions through the 

end of the tubing. In fact, the housing attached to the string 

has a greater ID than the tubing. 

Features 

Leaves the tubing string fully open 

Ideal for use in remote areas where wireline is expensive 

or unavailable 

Ideal for situations where wireline can cause a safety 

hazard 

Provides access to the wellbore for production logging 

tools 

Especially suited for releasing guns prior to stimulation 

treatments 

Operation 

The PATR consists of four main components: an upper 

housing, lower finger release sub, inner sleeve, and retaining 

latch. The PATR is pressure-balanced until the standing valve 

is dropped into the inner sleeve. 

Tubing pressure is applied to shear the retaining pins in the 

latch. Once the latch has been shifted, the finger release sub 

with the sleeve releases from the housing and drops the 

perforating assembly into the rathole. 

SAP No. 

100156751 

100156744 

101015385 

Thread Size 


in. (mm) 

2 3/8 (60.33) EUE 


2 7/8 (73.03) EUE 


3 1/2 (88.9) EUE 


Pressure-Actuated Tubing 

Release (PATR) 

Pressure-Actuated Tubing Release (PATR) Specifications 

Maximum OD 

in. (mm) 

3.38 

(85.85) 

3.75 

(95.25) 

4.19 

(106.43) 

Minimum ID 

Before 

Release 

in. (mm) 

1.63 

(41.40) 

1.812 

(46.02) 

1.812 

(46.02) 

Minimum ID 

After 

Release 

in. (mm) 

2.31 

(58.67) 

2.828 

(71.83) 

3.5 

(88.90) 


HAL15442 

Standing 

Valve OD 

in. (mm) 

1.76 

(44.70) 

1.86 

(47.24) 

1.86 

(47.24) 


Makeup 

Length 

ft (m) 

1.73 

(0.53) 

1.72 

(0.52) 

1.71 

(0.52) 

Tensile 

Strength 

lb (kg) 

90,000 

(40 800) 

120,000 

(54 400) 

130,000 

(58 900) 

HAL10531 

Standing Valve 

Burst 

Pressure 

psi (bar) 

10,000 

(670) 

10,000 

(670) 

10,000 

(670) 

Collapse 

Pressure 

psi (bar) 

9,000 

(620) 

10,000 

(670) 

10,000 

(670)

DPU ® Downhole Power Unit 

The DPU® downhole power unit firing head is an 

electromechanical device that is designed to produce a linear 

force that activates a pressure-assisted firing device. The 

pressure-assisted device fires the perforating guns. Before the 

DPU firing head was used to activate the pressure-assisted 

firing device, this type of perforating gun activation was run 

on tubing. The pressure-assisted firing device was previously 

activated by dropping a device from the surface. The DPU 

firing head is run on slickline. 

For the DPU firing head to begin activation, several 

parameters must be present. 

Pressure setting: The DPU firing head has a surfaceselected 

downhole pressure setting that must be met. Any 

time the well pressure at the DPU firing head drops below 

the selected pressure setting, the DPU firing head 

activation sequence is stopped 

Downhole Temperature: The DPU firing head requires a 

precise surface-selected downhole temperature. Any time 

the well temperature drops below the selected temperature 

setting, the DPU firing head activation sequence is stopped 

Tool Movement: The DPU firing head has an 

accelerometer that detects tool movement. If the 

accelerometer detects motion, the other operating 

parameters are inactive 

Surface-Selected Timer: The DPU firing head has a 

surface-selected timer that is activated if the three previous 

parameters are present 

If these four parameters are present, the DPU firing head is 

activated and the rod begins to stroke out. Rod travel takes 

approximately 20 minutes before contracting the pressureassisted 

firing device. When the DPU firing head rod 

contacts the pressure-assisted firing device, a pin is sheared 

and perforating is activated. After initial activation, the DPU 

runs for 25 minutes and then turns off. 

The 3.66 OD DPU and 2.50-in. DPU firing head can be 

converted to run either the Model II-D or the Model III-D 

pressure-assisted firing heads. 

Fish Neck 

Pressure 

Temperature 

Switch 

Firing Head 

PC Board 

® 

DPU 

Downhole 

Power Unit 

DPU Power 

Rod 

Push Guide 

Model III 

Firing Head 

Adapter 

to Guns 

Conversion Kits for DPU ® Downhole Power Unit 

Assembly No. SAP No. 

146DFH20 00050531 

146DFH11 00050462 

Maximum OD 

in. (mm) 

3.66 

(93.96) 

2.50 

(64.50) 


HAL15990 

HAL15988 

DPU® Downhole Power 

Unit 

® 

DPU Power 

Rod 

Push Guide 

Model III 

Firing Head 

Adapter 

to Guns

SmartETD ® Advanced Electronic Triggering Device 

The SmartETD® tool is an advanced 

electronic triggering device that 

provides an accurate, safe, and reliable 

method to run and fire downhole 

explosive tools using slickline. With its 

built-in sensor and memory 

capabilities, it can record and store 

downhole temperature and pressure 

data that can be used by the slickline 

specialists to program firing 

parameters. 

The SmartETD tool requires four 

parameters to be met prior to firing. 

These are motion, time (preset), 

pressure (preset), and temperature 

(preset). The timing sequence begins 

when the tool is exposed to pressure. 

After the tool stops, any motion resets 

the electronic timer. After the 

SmartETD timer has remained 

motionless for a specific period of 

time and has simultaneously 

encountered the preset temperature 

and pressure windows, it initiates the 

firing sequence. The SmartETD tool 

can log memory settings for pressure 

and temperature readings up to 12k 

data sets. 

The SmartETD tool will fire the 

Halliburton rig environment RED® 

detonator, as well as 

API RP-67-compliant devices. It is 

also capable of resisting detonation. 

SmartETD ® Specifications 

SAP No. 

Diameter 

in. (mm) 

Length 

in. (mm) 

Max. Temperature 

°F (°C) 

Max. Pressure 

psi (bar) 

Features 

Control Parameters 

101038328 

146ETD14 

Optional No-Blow 

No-Drop Assembly 

1.690 

(42.93) 

60 

(1524) 


300 

(149) 

15,000 

(103.42) 

Pressure yes (programmable) 

Temperature yes (programmable) 

Time yes (programmable) 

Motion yes 

Tension no 

Resist Detonation 

Capability 

yes 

HES RED ® Capability yes 

Memory Logging 

Pressure yes 

Temperature yes 

No. of Points (reading) 12k data sets 

HAL15398 

SmartETD® Tool 

No-Blow, No Drop 

Assembly 

Top Shock/Centralizer 

Quick Lock Assembly 

® 

Smart ETD Tool 

HV Shooting Module 

Adapter 

Selectable Mechanical 

Pressure Switch 

Shock Absorber 

Detonator 

Sub/Explosives 

as required with 

STD 13/8-in. GO 

Connection 

® 

VannGun Assembly

Y-Block Assembly 

The Y-block assembly is used in dual completions and 

single selective completions to attach or hang guns from 

the long string. 

In single selective completions, this installation is run either 

for selectively shooting and testing two zones or for 

production when the application requires the option of 

producing two zones separately through one tubing string. 

In dual completions, the assembly allows for the elimination 

of the tail pipe between the dual packer and the gun. 

The Y-block assembly is available as a ported or non-ported 

assembly. The ported Y-block allows guns to be fired upon 

applying pressure to the long string. In the non-ported 

assembly, there is no communication between the long string 

and the short string. 

HAL10578 

Non-Ported Ported 

Y-block assemblies are custom-made according to the casing ID, the 

tubing size and type, and the gun size. Consult your local 

Halliburton representative for ordering information. 

Retrievable 

Packer 

Sliding-Side Door ® 

Y-Block 

® 

VannGun 

Assembly 


Hydraulic 

Packer 

Nipple 


HAL8139 

Y-Block Assembly 

Vent 

Tubing Release 

Mechanical Firing 

Head 

VannGun 

Assembly 

Time-Delay Firer

Gun Guides 

Gun guides were developed by Halliburton to maintain the 

proper orientation of guns attached to the short string in a 

dual completion. The gun orientation must be maintained 

so that the charges shoot away from the long string. Gun 

guides are also used with Y-blocks in dual-string and 

single-string completions. 

There are two types of gun guides. The delta-shaped or dual 

gun guide can be used when the casing ID is the same from 

top to bottom. If the casing at the top of the well is larger, 

then the wraparound guide must be used. The wraparound 

type may also be used in the wellbores with the same ID top 

to bottom. 

Guides are available for most of the smaller size guns 

(3 3/8 in. or 85.73 mm and smaller) that are typically run on 

the short string side of a dual completion. 

HAL6190 

HAL10577 

Dual Completion with Wraparound 

Gun Guide 

Dual Completion with 

Dual Gun Guide 

Dual Completion 

with Gun Guides 

® 

VannGun 

Assemblies 

Gun Guide 

VannGun 

Assemblies 

Gun Guide 

VannGun 

Assemblies 

Time-Delay 

Firing Head 

Permanent or 

Retrievable Packer 

Tubing Release 

Mechanical 

Firing Head 

VannGun 

Assemblies 


HAL15395 

Dual Hydraulic 

Set Packer 

Balanced 

Isolation Tool 

Time-Delay 

Firing Head

Hydraulic Metering Release Tool for the Single Trip System (STPP-GH) Tool 

The hydraulic metering release tool is one component of the 

single trip system that allows us to perforate and frac-pack a 

zone of interest in a single trip. 

Numerous safety and economic benefits accompany this 

capability. These benefits become even more profound as 

well parameters become more severe. The ever-present goal 

is to reduce completion CAPEX and maximize net present 

value. 

Features 

Save rig time with reduced pipe trips for faster 

completions 

Minimize fluid loss and formation damage 

Minimize associated well control risks 

Perforate under- or overbalanced 

Perform the sand control option most suitable for your 

well (FP, HRWF, GP) 

Complete deep, hot zones where fluid loss pills are not 

effective 


HAL15780 

Plug 

Hydraulic Metering 

Release Tool 

Floating Piston 

Metering Section 

Silicone Fluid 

Finger Release 

Stinger/Fishneck 

Shear Screws

Upper 

Thread 

Size and 

Type 

2 7/8 

EU-RD 

Lower 

Thread 


Type 

N/A 

Hydraulic Metering Release Assembly (Low Temperature) 

Overall 

Length 

in. (cm) 

45.47 

(115.49) 

Maximum 

OD 

in. (cm) 

4.5 

(11.43) 

Effective 

OD* 

in. (cm) 

4.5 

(11.43) 

5.5 

(13.97) 

7.5 

(19.05) 

Temperature 

Rating 

°F (°C) 

200 

(93.33) 

*Effective OD of the tool is dictated by the OD of the skirt to be used. 

**Maximum weight on gun hanger = gun weight + slackoff weight on hydraulic release tool. 

***The tool is assembled with four shear screws of 3,400 lb each. 

Upper 

Thread 


Type 

2 7/8 

EU-RD 

Lower 

Thread 


Type 

N/A 

Tensile 

Rating 

lb (kg) 

97,700 

(44 315) 

Maximum 

Slack Off 

Weight on 

Tool 

lb (kg) 

30,000 

(13 607) 

Minimum 

Slack Off 

Weight on 

Tool 

lb (kg) 

13,600 

(6168) 

Hydraulic Metering Release Assembly (High Temperature) 

Overall 

Length 

in. (cm) 

45.47 

(115.49) 

Maximum 

OD 

in. (cm) 

4.5 

(11.43) 

Effective 

OD* 

in. (cm) 

4.5 

(11.43) 

5.5 

(13.97) 

7.5 

(19.05) 

Temperature 

Rating 

°F (°C) 

200-350 

(93.33-148.88) 

*Effective OD of the tool is dictated by the OD of the skirt to be used. 

**Maximum weight on gun hanger = gun weight + slackoff weight on hydraulic release tool. 

***The tool is assembled with four shear screws of 3,400 lb each. 

Tensile 

Rating 

lb (kg) 

97,700 

(44 315) 

Maximum 

Slack off 

Weight on 

Tool 

lb (kg) 

30,000 

(13 607) 

Minimum 

Slackoff 

Weight on 

Tool 

lb (kg) 

13,600 

(6168) 

Redressable 


Yes 

Redressable 

Yes 

Weight 

lb (kg) 

156.46 

(70.96) 

Weight 

lb (kg) 

156.46 

(70.96)

Fast Gauge Recorder 

The fast gauge recorder is a downhole 

gauge that records important pressure 

and temperature data in high-pressure, 

severe shock/vibration environments. 

This gauge is typically used with 

StimGun* assemblies or 

StimTube* tools. The pressure 

profile collected is used to verify 

proper propellant burn as well as 

determine the fracturing response of 

the formation by analyzing post-job 

data with PulsFrac** software. 

The data the fast gauge recorder collects 

can be used to determine whether or 

not the job was executed properly, to 

validate computer models, and to make 

initial determinations of rock 

properties. The data can also be used to 

estimate fracture gradients. 

The fast gauge recorder can perform 

within the rigors of perforating 

applications by withstanding shock 

loads of 100,000 g. The tool collects and 

records 115,000 data points per second 

to give exceptionally accurate and 

reliable information. 

The programmable multi-speed feature 

allows flexibility in collecting pressure, 

acceleration, and vibration data at 

various sampling speeds and time 

intervals. The gauge starts sampling at a 

slow speed and when a pressure pulse 

or acceleration/vibration event occurs, 

the gauge automatically switches to a 

high sampling speed, then back to an 

intermediate speed, and finally back to 

a slow sampling speed. The process can 

be repeated until the memory is full. 

Each gauge includes a shock mitigator 

which isolates the gauge from the tool, 

reducing shock and vibration (up to a 

factor of 10) that occurs when the gun 

ignites. Use of the shock mitigator 

lengthens the life of the recorder, 

battery, and sensors. 

A special application of the 1 11/16-in. 

(42.86 mm) OD gauge is its use as a 

“drop bar” to fire a propellant or 

perforating gun. The gauge can be used 

with firing pin and fishneck 

attachments as the drop bar to trigger a 

gun firing head. It can be left there as 

long as necessary to collect pressure 

flow data. With this feature, the 

customer can retrieve pressure data 

from the gun and also determine if the 

gun actually fired. 

Fast Gauge 

Recorder 

*StimTube and StimGun are trademarks of 

Marathon Oil Company. 

**PulsFrac is a trademark of John F. Schatz 

Research and Consulting, Inc. 


HAL15464

Features 

Shock-hardened design 

High sampling speed 

Records pressure, acceleration, vibration, and 

temperature 

Programmable low, intermediate, and high speeds and 

time intervals 

Can be used as drop bar pressure gauge 

Computer programming and data readout 

Internal microprocessor control 

Automatic sensor testing and balancing 

Selectable pressure, temperature, and acceleration/ 

vibration ranges 

Gauge Dimensions 

Maximum 

Acceleration 

and Vibration 

1 11/16 in. OD × 50 in. 

± 50,000 g 

(22 lb) 

*Windows 2000 or NT is recommended. 

Sampling Rate 

115,000 points/second 

down to one sample every 

10 seconds 

Fast Gauge Recorder Specifications 

Current Drain 

500 uA sleeping 

100 mA sampling 

Temperature Range 

°F (°C) 

-40 to 248 

(-40 to 120) 

Computer/ 

Communications 

750 MHz or greater PC, 

with standard RS-232 

Pressure Range 

psi (bar) 

35,000 (2413) peak 

15,000 (1034) continuous 

Measures tool movement and acceleration/vibration up 

to ±50,000 g 

Current and internal/battery voltage readouts to verify 

proper gauge operation 

Internal temperature and battery data 

Selectable sampling rates up to 115,000 data points 

per second 

Auto stop/start recording modes 

Includes shock mitigator 

Up to 1,048,756 data points of memory 

Uses low-cost standard AA alkaline or lithium batteries 

Software 

Sensor 

Frequency 

Response 

Windows 98* 0 to 10,000 Hz 

Data Resolution Memory Capacity 

12 bits @ 115,000 

data points/second 

Power Requirements 

6 to 12 volts, AA 

alkaline or lithium cells 

1,048,576 data points 

Perforating Solutions 5-111

Gamma Perforator Logging Tool 

The gamma perforator is a ruggedized depth correlation tool 

designed specifically for operation with explosive equipment, 

such as perforating guns, packers and plugs, and coring guns. 

The tool can operate in liquid or gas-filled, openhole or cased 

hole wells. The gamma perforator is available in two sizes: 

3.375-in. and 1.687-in. version. 

The gamma perforator is not intended to provide a 

calibrated gamma measurement. No borehole corrections are 

performed in the algorithms, and calibration procedures are 

only used to ensure that the tool is working properly before 

and after jobs. 

The tool has a built-in shock absorber system and does not 

require an external shock sub. In addition, the electronic 

components are covered with silicon potting to help dampen 

the shock wave that impacts components. All sub-assemblies 

required for perforating with different connections must be 

ordered individually. 

Tool Length 

GPLT 

GPST 

Length 

ft (m) 

5.03 

(1.5) 

6.23 

(1.9) 

Gamma Perforator Logging Tool Specifications 

Diameter 

in. (mm) 

3.375 

(85.7) 

1.69 

(42.9) 

Features 

Offers three configurations: 

– Normal perforating and plug setting 

– Stand-alone gamma/CCL-correlation 

– Side wall coring 

High resistance minimizes accidental firing risks 

Slimhole version allows perforating operations to be 

performed without the need to pull tubing from the well 


psi (Mpa) 

20,000 

(137.9) 

18,000 

(124.1) 


°F (°C) 

350 

(176.7) 

350 

(176.7) 

Weight 

lb (kg) 

82 

(37.2) 

35 

(15.9) 


Detonators 

Capsule RED ® Detonators 

The capsule RED® detonator is an 

advanced electro-explosive device 

designed for use with capsule 

perforating guns and other explosive 

devices where a pressure-resistant 

detonator is required. The design 

features of the capsule RED detonator 

provides significantly improved safety 

characteristics over conventional 

resistorized devices and allows wellsite 

activities to continue uninterrupted 

while perforating. 

Features 

Does not use primary explosives 

Redundant electrical components 

for enhanced safety 

Ceramic firing capacitors for 

enhanced reliability 

Surface-mount circuit technology 

for ruggedness 

Metal housing for radio frequency 

shielding 

High-output explosive load and 

flyer plate for enhanced reliable 

detonation transfer 

Dual sealing methods at top of 

detonator 

Patented sealing for detonating cord 

interface 

Specifications 

No-fire voltage level: 120 VDC 

Firing voltage: 155 to 190 VDC 

(nominal 175 VDC) 

Recommended firing method: 

“Dump firing.” Deliver 250 VDC to 

the firing head 

Recommended firing polarity: 

positive or negative DC 

Requirements for radio silence 

waivers: 

– Transmitters with power less 

than 1 watt = no exclusion 

area 

– Handheld RF transmitters 

(cell phones and walkietalkies) 

operation— 

minimum distance radius 

from explosive workplace = 

no minimum distance 

restriction 

– All other RF sources (land or 

offshore, mobile or fixed) 

operation—minimum 

distance radius from 

explosive workplace = no 

minimum distance 

restriction 

– Offshore workboats (or other 

1-MHz, 1,000 watt or above 

transmitters) operation— 




restriction 

– Stray voltage measurement, 

electric welding operation, or 

electrical cathodic protection 

systems = operation 

acceptable if stray voltage is 

less than 2 V 

Bleed-off time with power removed: 

5 sec 

Semi-conductor bridge (SCB) 

resistance: 2 ohms 

No-fire DC power dissipation 

(stand-alone SCB without circuit): 

5 watts minimum 

Energetic materials: 

– Ignition pyrotechnic mix = 

50 mg THKP 

– Transition column = 400 mg 

HMX 

– Output pellet = 500 mg 

HMX 

Environmental rating: 375°F at 

15,000 psi for one hour 

UN shipping classification: 1.4S 

Capsule RED® Detonator 


HAL9251

RED ® GO-Style Thermal Igniter 

The RED® igniter is an advanced 

electro-explosive device used to initiate 

gas-generating power charges inside 

oilfield setting tools. The design 

features of the RED igniter provide 

significantly improved safety 

characteristics over conventional 

resistorized devices and allow many 

wellsite activities to continue 

uninterrupted while using power 

setting tools. 

Features 

Mates with top subs and adapters 

for industry standard setting tools 

Redundant electrical components 

for enhanced safety 

Multiple ceramic firing capacitors 

for reliability 

Surface-mount circuit technology 

for ruggedness 

Thermally conductive semiconductor 

bridge for stray power 

dissipation 

Metal housing for radio frequency 

shielding 

Thin aluminum end-closure for low 

debris characteristics 



Firing voltage: 155 to 190 VDC 

(nominal 175 VDC) 

Recommended firing method: 

“Dump firing.” Deliver 250 VDC to 

the firing head 

Recommended firing polarity: 

positive or negative DC 

Requirements for radio silence 

waivers: 

– Transmitters with power less 

than 1 watt = no exclusion 

area 

– Handheld RF transmitters 

(cell phones and walkietalkies) 

operation— 




restriction 

– All other RF sources (land or 

offshore, mobile or fixed) 

operation—minimum 

distance radius from 

explosive workplace = no 

minimum distance 

restriction 

– Offshore workboats (or other 

1-MHz, 1,000 watt or above 

transmitters) operation— 




restriction 

– Stray voltage measurement, 

electric welding operation, or 

electrical cathodic protection 

systems = operation 

acceptable if stray voltage is 

less than 2 V 

Bleed-off time with power removed: 

5 sec 

SCB resistance: 2 ohms 

SCB no-fire power dissipation: 

5 watts minimum 


– Ignition pyrotechnic mix = 

150 mg THKP pressed in 

SCB header 

– Main load = .15 gm FFFG 

black powder and .75 gm 

THKP loose powders 

Temperature rating: 375°F for one 

hour 

UN shipping classification: 1.4G 

RED® GO-Style Thermal Igniter 


HAL11756

Block RED ® Detonators 

The block RED® detonator is an advanced electro-explosive 

device used to initiate perforating guns. The design features 

of the block RED detonator provide significantly improved 

safety characteristics over conventional resistorized devices 

and allow wellsite activities to continue uninterrupted while 

perforating. 

Features 


Redundant electrical components for enhanced safety 

Ceramic firing capacitors for enhanced reliability 

Surface-mount circuit technology for ruggedness 

Metal housing for radio frequency shielding 

High-output explosive load and flyer plate for enhanced 

reliable detonation transfer 

Fluid-disabled to prevent gun damage in the event of a 

seal failure 



Firing voltage: 155 to 190 VDC (nominal 175 VDC) 

Recommended firing method: “Dump firing.” Deliver 

250 VDC to the firing head 

Recommended firing polarity: positive or negative DC 

Requirements for radio silence waivers: 

– Handheld RF transmitters (cell phones and 

walkie-talkies) operation—minimum distance 

radius from explosive workplace = no minimum 

distance restriction 

– All other RF sources (land or offshore, mobile or 

fixed) operation—minimum distance radius from 

explosive workplace = no minimum distance 

restriction 

– Offshore workboats (or other 1-MHz, 1,000 watt 

or above transmitters) operation—minimum 

distance radius from explosive workplace = no 

minimum distance restriction 

– Stray voltage measurement, electric welding 

operation, or electrical cathodic protection 

systems = operation acceptable if stray voltage is 

less than 2 V 

Bleed-off time with power removed: 5 sec 


SCB no-fire power dissipation: 5 watts minimum 


– Ignition pyrotechnic mix = 50 mg THKP 

– Transition column = 400 mg HMX 

– Output pellet = 500 mg HMX 

Temperature rating: 375°F for one hour 


Block RED® Detonator 


HAL11412

Top Fire RED ® Detonators 

The top fire RED® detonator is an advanced electroexplosive 

device used to initiate perforating guns, jet cutters, 

and severing tools. The design features of the top fire RED 

detonator provide significantly improved safety 

characteristics over conventional resistorized devices and 

allow wellsite activities to continue uninterrupted while 

perforating. 

Features 


Redundant electrical components for enhanced safety 

Ceramic firing capacitors for reliability 

Surface-mount circuit technology for ruggedness 

Thermally conductive semi-conductor bridge for stray 

power dissipation 

Metal housing for radio frequency shielding 

High-output explosive load and flyer plate assure reliable 

detonation transfer 



Firing voltage: 155 to 190 VDC (nominal 175 VDC) 

Recommended firing method: “Dump firing.” Deliver 

250 VDC to the firing head 

Recommended firing polarity: positive or negative DC 

Requirements for radio silence waivers: 

– Handheld RF transmitters (cell phones and 

walkie-talkies) operation—minimum distance 

radius from explosive workplace = no minimum 

distance restriction 

– All other RF sources (land or offshore, mobile or 

fixed) operation—minimum distance radius from 

explosive workplace = no minimum distance 

restriction 

– Offshore workboats (or other 1-MHz, 1,000 watt 

or above transmitters) operation—minimum 

distance radius from explosive workplace = no 

minimum distance restriction 

– Stray voltage measurement, electric welding 

operation, or electrical cathodic protection 

systems = operation acceptable if stray voltage is 

less than 2 V 

Bleed-off time with power removed: 5 sec 


SCB no-fire power dissipation: 5 watts minimum 


– Ignition pyrotechnic mix = 50 mg THKP 

– Transition column = 400 mg HMX 

– Output pellet = 500 mg HMX 

Temperature rating: 375°F for one hour 


Top Fire RED® Style Detonator 


HAL11413

Dynamic Modeling 

Dynamic modeling is used to understand perforation 

performance, tubing movement, shock loading, and wellbore 

pressure response during well intervention. 

PerfPro ® Process 

PerfPro ® Process– Predicting In-Situ Charge Performance 

Halliburton's PerfPro® charge performance calculations for 

penetration are based on proprietary models derived from 

theoretical and experimental studies carried out at Jet 

Research Center (JRC), a Halliburton Company. 

API RP-19B defines the procedure for evaluating gun system 

performance at surface conditions in unstressed concrete 

targets. A fully loaded gun system is perforated in actual 

casing surrounded by concrete, and the target penetration, 

casing entrance hole, and burr height are recorded. 

Halliburton's PerfPro program transforms 

API RP-19B Section I surface test data to downhole 

conditions by correcting for the formation compressive 

strength and effective stress. The associated downhole charge 

performance takes into account the gun positioning, casing 

grade, wellbore fluid density, and well condition. 

HAL15393 

PerfPro® Charge Performance Calculations 

The ability to understand dynamic behavior is critical for 

Halliburton to deliver world-class solutions to its customers. 

Test 

Specimen 

Casing 

Gun 

Water 

Steel Form 

28-Day 

Concrete 


HAL15333 

API Section 1 

Concrete Target

The primary objective of the Halliburton PerfPro® process is 

to optimize gun selection and job execution to deliver the 

highest productivity index or lowest skin factor. Therefore, 

after charge performance values are calculated, the PerfPro 

program makes a productivity index and skin factor 

assessment. The PerfPro process accounts for skin factors due 

to perforation, drilling damage, partial penetration, non- 

Darcy flow, and well deviation. A fully three-dimensional 

CHARGE PERFORMANCE REPORT 

General Data 

Reservoir fluid type Oil Mid-Perforation Depth 3250.0 ft - TVD 

Borehole Diameter 12.25 in Reservoir Pressure 1464.0 psi 

Porosity 24.0 % Reservoir Temperature 112.0 °F 

Permeability 1191.0 md Completion Fluid Type Diesel 

Formation Compressive 

Strength 

3891.0 psi Completion Fluid Density 6.83 lb/gal 

Drilling Damage Radius 3.0 in Lithology Sandstone 

Completion Data 

Casing Description 1 

Outer Diameter 9.63 in 

Inner Diameter 8.68 in 

Grade N-80 

Weight 47.0 lb/ft 

Perforator Information 

Charge Name 7" 

MILLENNIU 

M 

Gun 1 Gun 2 Gun 3 

4" 

MILLENNIU 

M 

4-1/2" 

MILLENNIU 

M 

Charge Type DP SDP SDP 

Charge Loading, gm 39.0 39.0 22.7 

Phasing, deg 45.0 60.0 30.0 

Shot Density, spg 12 5 12 

Gun Position Eccentered Eccentered Eccentered 

Avg Formation Penetration, in 40.68 43.22 23.78 

Avg Entrance Hole Dia*, in 0.36 0.29 0.28 

API 5th Edition Section I 

Data 

Total Target Penetration, in 43.3 52.0 26.8 

Entrance Hole Diameter, in 0.36 0.37 0.38 

PRODUCTIVITY REPORT 

(3D) flow model is utilized, as described by Ansah et al. 2001, 

to characterize the skin component due to perforation 

geometry. Input well parameters and calculated charge 

performance values are linked to an artificial neural network, 

trained by the 3D finite element model, to generate the 

perforation skin component. The productivity index and 

total skin factor are corrected, utilizing analytical 

calculations for well inclination, partial penetration effect, 

non-Darcy flow, and drilling damage effects. 

Completion Data 

Reservoir Fluid Type Oil Well Deviation @ Perfs 56.2 deg 

Drainage Radius 1500.0 ft Net Sand Thickness 27.0 ft 

Pseudo-Skin duetoWell 

Deviation 

-0.697 Perforated Total Length 27.0 ft 

Distance To Top Perf Interval 0.0 ft 

Skin due to Partial Penetration 0.0 

Reservoir Data 

Permeability 1191.0 md Reservoir Pressure 1464.0 psi 

Anisotropic Ratio, kV/kH 0.2 Reservoir Temperature 112.0 °F 

Formation Volume Factor 1.1 bbl/stb Porosity 24.0 % 

Formation Fluid Viscosity 4.36 cp API Gravity 32.6 °API 

Perforator Information 

Charge Name 7" 

MILLENNIU 

M 

Gun 1 Gun 2 Gun 3 

4" 

MILLENNIU 

M 

4-1/2" 

MILLENNIU 

M 

Gun Position Eccentered Eccentered Eccentered 

Shot Phasing, deg 45.0 60.0 30.0 

Shot Density, spf 12 5 12 

Avg Formation Penetration, in 40.68 43.22 23.78 

Avg Entrance Hole Dia, in 0.36 0.29 0.28 

Underbalance Condition, psi -350.0 -350.0 -500.0 

Productivity Analysis 

Total Skin Perforation Skin Productivity Index, STB/day/psi 

Gun No. 1 -0.666 0.031 7.2 

Gun No. 2 -0.158 0.539 6.682 

Gun No. 3 0.319 1.016 6.261 


HAL15390 

HAL15389 

Total Pressure Drop (psi) 

1600 

1400 

1200 

1000 

800 

600 

400 

200 

7.2 

6.2 

Total Pressure Drop Vs Flow Rate 

0 0 2000 4000 6000 8000 10000 

Gun No.1 Gun No.2 Gun No.3 

PerfPro® Graph Example 

Pl and Total Skin Vs Gun 

Gun1 Gun 2 

Gun Number 

PI 

Total Skin 

Gun3 

PerfPro® Graph Example 


1.0 

0.0 

-1.0 

Total Skin

Near-Wellbore Stimulation and PulsFrac Software 

In many formations, the remaining 

reservoir pressure or underbalance is 

insufficient to effectively clean the 

perforations as suggested by King et al. 

(1985) and others. In other cases, where 

formation competence is questionable 

and the risk of sticking perforating 

assemblies is greater, sufficient 

underbalance pressure is not possible, 

aid in lowering treating pressures is 

needed, or bypassing near-wellbore 

damage is needed, then near-wellbore 

stimulation could be a possible 

perforating solution. To address the 

perforation damage in these cases, 

some (Handren et al. 1993, Pettijohn 

and Couet, 1994; Snider and Oriold, 

1996) have suggested near-wellbore 

stimulation using extreme 

overbalanced (EOB) perforating and 

propellant assisted perforating. Nearwellbore 

stimulation provides 

perforation breakdown in preparation 

for other stimulation methods, and 

therefore, eliminates the need for 

conventional perforation breakdown 

methods. 

Near-wellbore stimulation can be 

achieved using energized fluids, 

propellants, or a combination of both, 

and all can be properly designed using 

the PulsFrac* dynamic pressure 

modeling software. The PulsFrac 

software allows a job simulation to be 

performed to determine anticipated 

peak pressures, injection rates, 

injection volumes, and theoretical 

fracture lengths. 

EOB - Energized Fluid Stimulation 

EOB techniques involve pressuring the 

wellbore with compressible gases above 

relatively small volumes of fluid. The 

gases have a high level of stored energy. 

Upon expansion at the instant of gun 

detonation, the gases are used to 

fracture the formation and divert fluids 

to all intervals. The high flow rate 

through relatively narrow fractures in 

the formation is believed to enhance 

near-well conductivity by extending the 

fractures past any drilling formation 

damage. 

Wellhead 

Isolation Tool 

Nitrogen 

300 ft of Fluid 

Radioactive 

Collar 

Packer 

Tubing 

Pressure-Operated 

Venture Firing Head 

Bauxite 

Proppant 

Carrier 

VannGun ® 

Assembly 


HAL15314 

Typical Extreme 

Overbalanced (EOB) 

Perforating Assembly

Building upon the success of EOB 

perforating, Marathon Oil Company 

incorporated proppant carriers into the 

perforation assembly to introduce 

proppants into the flow path as the gun 

detonates. The POWR*PERF process, 

patented by Marathon Oil Company, 

further enhances productivity by 

scouring the perforations to leave some 

residual conductivity on the fracture 

plane. Most EOB perforating jobs are 

designed with a minimum pressure 

level of 1.4 psi/ft of true vertical depth. 

For optimum results, it is suggested to 

utilize the highest possible pressure 

level without compromising wellbore 

integrity or operation safety. 

Propellant Stimulation 

Propellant stimulation can be provided 

during the perforating event with 

propellant-assisted perforating. 

Propellant-assisted perforating using 

the StimGun assembly, patented by 

Marathon Oil Company, combines 

solid propellant technology with 

conventional perforating. The StimGun 

assembly may be utilized for either EOB 

or conventional underbalanced 

perforating. The hardware utilized for 

either system remains the same aside 

from added protection by using 

centralizer rings to protect the brittle 

propellant material. The propellant 

sleeve in the StimGun assembly simply 

slides over the perforation scalloped 

carrier and is held in position on the 

gun with the centralizer rings. 

The propellant material is potassium 

perchlorate, an oxidizer that burns 

rapidly, creating carbon dioxide gas. As 

the shaped charges detonate, the 

propellant is ignited by extreme heat 

from the gun system. As it burns, the 

propellant generates carbon dioxide gas 

at high peak pressures typically well 

above the formation fracture gradient. 

The StimGun assembly is an effective 

method for mild stimulation (fractures 

on order of 2 to 9 ft) for treating nearwellbore 

problems. 

Propellant stimulation can also occur 

using solid propellant conveyed in 

protective carriers. This type of 

propellant can virtually be unlimited in 

length by simply interconnecting the 

carriers to place across existing 

perforations, slotted liner, or in 

openhole. The propellant is ignited 

using a sealed ignition system, and 

similar to the StimGun assembly once 

the propellant is ignited it will generate 

carbon dioxide at high peak pressure, 

allowing for adequate stimulation of 

the desired formation interval. As with 

all near-wellbore stimulation 

techniques, PulsFrac software aids in 

proper job design and provides 

estimated peak pressures, injection 

rates, and volumes to ensure successful 

propellant stimulation. 

RA Marker 

Safety Joint 

Retrievable 

Packer 

Fill Disk 

Firing Head 

Centralizer 

Fast Gauge 

Recorder 


HAL15977 

StimGun Assembly

Near-Wellbore Stimulation 

Increasing conductivity past near-wellbore damage is critical 

in maximizing a well’s producibility. Halliburton provides 

multiple solutions suitable for various stimulation scenarios 

depending upon the well's restriction, completion methods, 

and reservoir characteristics. 

StimGun* Assembly 

The StimGun assembly is a process that combines 

perforating and perforation breakdown with propellant in 

a single tool and operation. The StimGun assembly has a 

propellant sleeve over a conventional Halliburton 

VannGun® perforating gun assembly. When the guns are 

detonated, the propellant sleeve is ignited, instantly 

producing a burst of high-pressure CO 2 gas. This gas enters 

the perforations, breaks through any damage around the 

perforation tunnel, and creates short fractures near the 

wellbore. As the gas pressure in the wellbore dissipates, the 

gas in the formation surges back into the wellbore carrying 

with it damaging fines. The StimGun assembly has been 

used with great success in conventional underbalanced 

perforating to obtain the benefits of both extreme 

overbalance from propellants and the surging effect from 

maximum underbalance. 

Features 

Improved production or injectivity with greater 

uniformity in the perforation breakdown 

Improved connectivity to the undamaged reservoir matrix 

by extending fractures past damage induced by either 

drilling or completion practices 

Improved conventional underbalanced perforating by 

combining benefits of extreme overbalance in one 

operation 

Stimulation of near-wellbore on zones that cannot be 

treated conventionally with acid or hydraulic fracturing 

due to undesirable production from nearby gas cap or 

water contact 

Excellent pre-hydraulic fracture treatment assists in 

keeping perforations open and minimizes tortuosity 

effects, resulting in lower breakdown pressures and 

horsepower requirements on location 

*StimGun is a trademark of Marathon Oil Company and is licensed to 

Halliburton by Marathon. StimGun Assembly 

Radioactive 

Marker 

Safety Joint 

Retrievable 

Packer 

Fill Disk 

Firing Head 

Centralizer 

Fast Gauge 

Recorder 


HAL15417

Operation 

The StimGun assembly consists of a cylindrical sleeve of 

gas-generating propellant-potassium perchlorate that slides 

in place over the outside of a conventional hollow steel 

carrier perforating gun. The StimGun assembly can be 

conveyed on either wireline, coiled tubing, or in a 

conventional perforation configuration. StimGun sleeves are 

similar to PVC pipe and must be protected and positioned on 

the gun with an oversized retaining collar that is secured to 

the gun scallop. Additional sleeve protection is achieved 

through centralization of the gun sections at the tandems. 

The StimGun tool can be run on Halliburton tubingconveyed 

or wireline equipment. 


HAL5941

Gun Size 

in. 

Sleeve SAP No. 

2 1/2 58179 

2 3/4 58190 

3 1/8 58193 

3 3/8 58195 

4 58196 

4 5/8 57514 

5 1/8 101240496 

5 3/4 215347 

7 58159 

StimGun Assembly Specifications 

Sleeve OD 

in. (mm) 

3.11 

(78.99) 

3.36 

(85.34) 

3.72 

(94.48) 

4.02 

(102.10) 

4.71 

(119.63) 

5.21 

(132.33) 

5.81 

(147.63) 

6.45 

(163.83) 

7.88 

(200.15) 

Sleeve ID 

in. (mm) 

2.50 

(63.50) 

2.75 

(69.85) 

3.21 

(81.53) 

3.38 

(85.85) 

4.05 

(102.87) 

4.72 

(119.88) 

5.175 

(131.44) 

5.75 

(146.05) 

7.09 

(180.08) 

Minimum 

Centralizer OD* 

in. (mm) 

3.50 

(88.90) 

3.76 

(95.50) 

4.13 

(104.90) 

4.40 

(111.76) 

5.09 

(129.28) 

5.63 

(143.00) 

6.18 

(156.97) 

6.95 

(176.53) 

8.25 

(209.55) 

Propellant Mass** 

lb/ft (kg/m) 


2.01 

(2.99) 

2.01 

(2.99) 

2.33 

(3.46) 

2.67 

(3.98) 

3.68 

(5.47) 

3.33 

(4.96) 

3.99 

(5.94) 

4.68 

(6.97) 

7.01 

(10.43) 

StimGun sleeves are manufactured in standard 3 ft (0.91 m) lengths and are rated for a service temperature of 350°F (177°C). The 

sleeves are non-reactive to most commonly used oilfield fluids, including acids. 

*The StimGun sleeve is an oxidizer that is bonded with a resin or plastic, making it quite brittle; therefore, it is required that the perforating 

gun be centralized to this minimum OD to provide protection when the assembly is in the wellbore. 

**CO 2 gas generated from a propellant burn is estimated at 7.06 scf per kg of material at standard conditions. 

SAP No. 

Gun Size 

in. 

101233588 2 1/2 

101233598 2 3/4 

101233215 3 1/8 

101240387 3 3/8 12 spf 

101222271 3 3/8 

101233163 4 

101227396 4 5/8 

101239368 5 1/8 

101303748 5 3/4 

101292913 7 

Retaining Collar Assembly Specifications 

OD 

in. (mm) 

3.38 

(85.85) 

3.63 

(92.20) 

4.02 

(102.10) 

4.27 

(108.45) 

4.27 

(108.45) 

4.96 

(125.98) 

5.50 

(139.70) 

6.05 

(153.67) 

6.70 

(170.18) 

8.15 

(207.01) 

ID 

in. (mm) 

2.56 

(65.02) 

2.81 

(71.37) 

3.18 

(80.77) 

3.43 

(87.12) 

3.43 

(87.12) 

4.06 

(103.12) 

4.69 

(119.12) 

5.19 

(131.82) 

5.82 

(147.82) 

7.07 

(179.57) 

Sleeve OD 

in. (mm) 

3.11 

(78.99) 

3.36 

(85.34) 

3.72 

(94.48) 

4.02 

(102.10) 

4.02 

(102.10) 

4.71 

(119.63) 

5.21 

(132.33) 

5.81 

(147.32) 

6.45 

(163.83) 

7.88 

(200.15) 

Minimum 

Centralizer OD 

in. (mm) 

3.51 

(89.15) 

3.76 

(95.50) 

4.13 

(104.90) 

4.40 

(111.76) 

4.40 

(111.76) 

5.09 

(129.28) 

5.63 

(143.00) 


6.18 

(156.97) 

6.95 

(176.53) 

8.25 

(209.55) 

Flow Area through Collar 

in. 2 (mm 2 ) 

1.10 

(709.67) 

1.15 

(741.93) 

1.21 

(780.64) 

1.71 

(1103.22) 

1.71 

(1103.22) 

2.00 

(1290.32) 

2.00 

(1290.32) 

2.21 

(1425.80) 

2.70 

(1741.93) 

3.75 

(2419.35)

Propellent Stimulation Tool Assembly 

The stimulation tool assembly is a process that uses the same 

solid propellant technology employed by the StimGun 

assembly to stimulate existing perforations, slotted liners, or 

openhole sections when it is not desirable to add 

perforations. The stimulation assembly is assembled with 

propellant and standard detonating cord to provide the 

ignition system. When the detonating cord is ignited, the 

solid propellant breaks up into many smaller pieces, allowing 

it to burn very rapidly and producing CO 2 gas. This gas 

enters the perforations, breaking through any damage 

around the perforation tunnel, creating short fractures near 

the wellbore. As the gas pressure in the wellbore dissipates, 

the gas in the formation surges back into the wellbore, 

carrying with it damaging fines. Stimulation assembly jobs 

are designed using Halliburton’s PulsFrac simulator, which 

assists in achieving consistent results without compromising 

safety or wellbore integrity. 

Operation 

The stimulation assembly consists of a solid stick of gasgenerating 

propellant-potassium perchlorate with 

detonating cord run through it. The assembly can be 

conveyed on either wireline, coiled tubing, or threaded pipe. 

Standard perforating safety, arming, and firing procedures 

are used. The industry standard detonating cord provides 

consistent, reliable, and instantaneous ignition over the 

entire length of the stimulation assembly. 

When deployed on coiled tubing or threaded pipe, the 

stimulation assembly is run inside a vented hollow steel 

carrier. 

Stimulation Assembly 


HAL22575

Features 

Improved production or injectivity with greater 

uniformity in the perforation breakdown 

Improved connectivity to the undamaged reservoir 

matrix by extending fractures past damage induced by 

either drilling or completion practices 

Stimulation of near-wellbore on zones that cannot be 

treated conventionally with acid or hydraulic fracturing 

due to undesirable production from nearby gas cap or 

water contact 

SAP No. 

Tool Size 

in. 

Upper 

Thread 


Type 

2 7/8 Gun 

101566827 2 7/8 

Pin 

1 

Based on control line collapse rating 

2 

2 7/8 gun box at top sub 

Lower 

Thread 


Type 

2 7/8 Gun 

Box 

Stimulation Tool Assembly Specifications 

Overall 

Length 

ft (m) 

26.25 

(8.0) 

Makeup 

Length 

ft (m) 

25.98 

(7.92) 

Excellent pre-hydraulic fracture treatment assists in 

keeping perforations open and minimizes tortuosity 

effects resulting in lower breakdown pressures and 

horsepower requirements on location 

Selective stimulation of long openhole horizontal 

sections 

This assembly is currently available in 2 7/8 OD ported 

carriers. Contact TCP technology for more information. 

Maximum 

OD 

in. (mm) 

Temperature 

Rating 1 

°F (°C) 

Pressure 

Rating 1 

psi (bar) 

Tensile 

Rating 2 

lb (kg) 

Redressable 


2.88 

(73.2) 

300 

(149) 

8500 

(578) 

110,800 

(50 250) 

Yes 

Weight 

(No 

Explosives) 

lb (kg) 

249 

(113)

POWR*PERF SM* Perforation/Stimulation Process 

POWR*PERF SM perforation/ 

stimulation process is a completion 

process that uses proven extreme 

overbalance perforating techniques. 

This method is coupled with the 

release of an erosive agent at the 

moment of VannGun® detonation to 

clean and scour near-wellbore damage 

and enhance conductivity of fractures 

created by extreme overbalance 

perforating. 

Features 

Overcomes skin damage in low 

pressure, high permeability wells 

Can be a useful pre-frac 

evaluation tool 

Applicable to both new wells and 

wells with nearby water or gas 

Compatible with all casing sizes 

and tubulars 

Operation 

The POWR*PERF tool is run as a 

normal part of the completion 

assembly. A non-damaging fluid is 

added to the tubing to serve as a 

medium for carrying the bauxite 

into the formation. After the assembly 

has been positioned across the 

producing zone, the tubing is 

energized with nitrogen gas to create a 

pressure gradient of no less than 

1.4 psi/ft (31 bar/m). A model KV-II 

firing head, which has been pre-set to 

function at the desired bottomhole 

pressure, detonates the VannGun 

assembly and opens flow ports to 

allow the fluid and nitrogen to rush 

toward the formation. 

The fluid “spear” is driven ahead of 

the expanding nitrogen gas into the 

formation at velocities that can exceed 

140 bbl/min. The bauxite material is 

ejected into the fluid stream at the 

moment of detonation by specially 

designed shaped charges. The 

combination of fluid and bauxite 

serves to fracture, erode, and scour all 

of the perforations, and to further 

enhance the fractures created by 

extreme overbalance perforating. 

*POWR*PERF is a service mark/trademark of 

Marathon Oil Company and licensed by 

Halliburton. 

Retrievable 

Packer 

KV-II Firing 

Head 

Proppant 

Carrier 

® 

VannGun 

Assembly 

POWR*PERF SM 

Perforation/Stimulation Process 


HAL15314

PerfStim* Process 

The PerfStim process uses an extreme overbalanced 

condition to simultaneously perforate and stimulate a well. 

The process not only produces cleaner perforations in lowpressure 

formations, it also initiates fractures in the 

formation, reducing stimulation costs. 

Features 

Gets production flowing quickly 

Saves rig time 

Helps develop negative skin factors 

Gives an early evaluation of a well’s potential 

Uses less horsepower than full scale stimulations 

Operation 

In the PerfStim process, an extreme overbalanced 

condition is created—pressure gradients of at least 

1.4 psi/ft (31 bar/m). 

When the perforating gun fires, the pressure drives a fluid 

“spear” into the perforation at velocities exceeding 

3,000 ft/sec (900 m/sec) and at rates that can exceed 

140 bbl/min. Crushed zone damage is removed and small 

fractures are created—improving initial production and 

treatment results. 

*The PerfStim process is licensed to Halliburton by Oryx Energy Company. 

PerfStim is a trademark of Oryx Energy Company. 

Packer 

Firing Head 

® 

VannGun 

Assembly 


HAL15387 

Halliburton’s VannSystem® toolstring is used in typical 

PerfStim procedures. The tubing conveyed system helps to 

allow for the highest possible bottomhole pressures. A small 

volume (usually no more than a 300-ft column) of nondamaging 

fluid is placed above the gun, then pressured with 

nitrogen. If needed, a liquid can be bullheaded on top of the 

nitrogen column. The VannGun® perforating assembly can 

remain attached to the toolstring or dropped into the rathole 

after the guns have been fired.

Oriented Perforating 

The benefits of sand prevention or 

improved stimulation performance can 

be enjoyed using any of Halliburton's 

leading oriented perforation 

technologies. Halliburton oriented 

perforating solutions can be deployed 

using a wide range of conveyance 

methods providing reliable world-class 

results. 

G-Force ® Precision Oriented 

Perforating System 

Historically, oriented perforating was 

attempted via external orienting 

devices and weights (external to the 

gun and exposed to the casing 

environment). In the externally 

oriented systems, there is added 

friction created by the guns moving 

axially down the casing wall, which 

can significantly work against the 

orienting mechanism. In addition, 

doglegs and other discontinuities 

during the deployment can cause loss 

of orientation. 

It was conceived that if the rotating 

device could be taken inside the 

protective environment of the carrier, 

adverse factors that can significantly 

decrease the ability to orient the guns in 

a desired direction could be overcome, 

if not completely eliminated. 

Halliburton's G-Force® system is 

comprised of an internal orienting 

charge tube assembly and gun carrier, 

which allows perforating in any 

direction irrespective of the gun's 

position relative to the casing. 

Features 

Able to go through restrictions not 

possible with older systems 

Since the orienting mechanism of the 

internal orienting system is 

contained within the gun carrier, the 

fundamental orienting design is 

unaffected by potential restrictions in 

the completion string 

Able to run through tubing and 

orient in casing 

No need for fin tandems, eccentric 

tandems, and swivel subs 

Increased orientation accuracy: the 

operating range will be for wells of 25° 

deviation and greater. For deviated 

wells, the accuracy range is ± 5° 

Compatible with live well 

intervention systems such as the 

AutoLatch connector, ratchet 

connector, and the modular gun 

system 

Gun assemblies can be centralized in 

the casing 

Can be deployed on coiled tubing, 

wireline, slickline, or jointed pipe 

No external weight bars required 

means no gaps between loaded 

sections and no lost shots 

G-Force® System 


HAL12019

SAP No. 

101300078 

SAP No. 

101305067 

SAP No. 


Type 

in. (mm) 

2 7/8 (73.03) 

6P Acme 


Type 

in. (mm) 

4.00 6P Acme 

(101.60 Acme) 

Gun OD 

in. 

Gun OD 

in. (mm) 

3.375 

(85.73) 

SAP No. 

101300078 

Gun OD 

in. (mm) 

4.625 

(117.48) 

SAP No. 

101305067 

Length ft 

3.375-in. G-Force ® System Specifications 

Length 

ft (m) 

22 

(6.7) 

Tensile Load 

lb (kg) 

238,000 

(107 954) 

Maximum 

Shot 

Density 

4 spf 

(13 spm) 

Collapse 

Pressure 

psi (bar) 

25,000 

(1725) 

Shot 

Phasing 

Perforation 

Planes 

180° 2 

Tandem Tensile Load 

lb (kg) 

355,000 

(161 025) 

Vertical 

Shot 

Spacing 

in. (mm) 

2.8 

(71.12) 

4.625-in. G-Force ® System Specifications 

Length 

ft (m) 

22 

(6.7) 

Tensile Load 

lb (kg) 

403,000 

(182 783) 

Maximum 

Shot 

Density 

4 spf 

(13 spm) 

Collapse 

Pressure 

psi (bar) 

20,000 

(1378.95) 

Shot 

Phasing 

Perforation 

Planes 

180° 2 

Tandem Tensile Load 

lb (kg) 

563,000 

(255 372) 

G-Force ® System Specifications 

Maximum 

Shot Density 

Shot 

Phasing 

Perforation 

Planes 

Maximum 

Shots per 

Gun 

Vertical 

Shot 

Spacing 

in. (mm) 

2.8 

(71.12) 

Survival Test 

Medium 

Maximum Diameter 

after Detonation 

in. (mm) 

3.42 

(86.87) 

Distance from Top 

End of Gun to 

First Shot 

in. (mm) 

8.50 

(215.90) 


Fluid 

Survival Test 

Medium 

Fluid 

Distance 

to First 

Shot in. 

Maximum Diameter 

after Detonation 

in. (mm) 

4.69 

(118.87) 

Charge 

Distance from Top 

End of Gun to 

First Shot 

in. (mm) 

8.50 

(215.90) 

101450833 4 5/8 16.00 4 spf 10°-350° 2 52 7.94 101466192 - 39g DP HMX 

101498446 4 5/8 22.00 4 spf 0°-180° 2 76 9.94 101210636 - 39g Millennium 

101435773 4 5/8 22.00 4 spf 0° 1 75 8.60 101210636 - 39g Millennium 





101515354 3 3/8 22.00 4 spf 0°-180° 2 72 9.25 101371884 - 25g Super DP 



101295030 3 3/8 2.00 4 spf 0° OR 180° 1 or 2 2 10.00 101366678 - 21g Millennium 

101630791 2 7/8 16.00 4 spf 10°-350° 2 56 7.74 101571815 - 11.1g G-Force ® HMX 

101621606 2 7/8 4.00 4 spf 0° OR 180° 1 or 2 12 7.62 101571815 - 11.1g G-Force HMX 

101600677 2 7/8 22.00 4 spf 10°-350° 2 78 7.62 101571815 - 11.1g G-Force HMX 

101563379 2 7/8 22.00 4 spf 0° OR 180° 1 or 2 78 7.62 101571815 - 11.1g G-Force HMX

Oriented Perforating with Modular Guns 

There are several methods available for orienting perforating 

guns in horizontal and highly deviated wells, such as the 

G-Force® system. In vertical wells it can be more difficult to 

orient perforations in a particular direction. One proven 

method is the oriented Modular Gun System. 

To accomplish this, a standard auto-J gun hanger is used in 

conjunction with specially modified skirts and stingers for 

the modular guns. The stingers are made with locating lugs, 

and the skirts are modified to locate on the lugs. 

The gun hanger is run in the well and set on wireline using 

normal procedures. A gyro steering tool is then run to 

determine the direction of the locating lug on the gun hanger 

stinger. The skirts and stingers on the remaining gun 

modules are then adjusted accordingly so that when they are 

landed, the shots will be oriented to the desired direction. 

This system has been used successfully in standard 

applications when perforating for production, and in special 

applications such as shooting from a relief well into a well 

that is blowing out. 

Stinger 

Gun Hanger 

with Modifications 

Modular Gun 

with Modifications 

Modified Skirt 

Modified Stinger 

Modified Skirt 

and Stinger 

Assembly 


HAL24404 

Lug 

HAL24407 

HAL24406 

HAL24405 

HAL24403

Finned Orienting Tandem 

As perforating guns are run into the well, and transition from 

a vertical to deviated position occurs, the fin will orient to 

the high side of the wellbore. The finned tandem works on 

the principle of gravity whereby the weight of the perforating 

guns rotates towards the lowest side of the wellbore and is 

aided by the additional standoff from the casing wall created 

by the connected fin. 

Features 

Built with an adjustable ring, which makes it possible to 

orient the shots in the casing to a predetermined 

direction 

Tensile strength of finned tandem equivalent to the 

standard gun connectors 

Available for most gun sizes 

Cost effective perforation orientation solution 

Finned Orienting Tandem 


HAL24409

Eccentric Orienting Tandem 

For several years, Halliburton successfully ran oriented 

perforating jobs using a fin welded to a gun connection every 

30 ft in conjunction with swivel assemblies. 

Now, a second method for orienting perforations referred 

to as eccentric subs has been developed. The eccentric sub 

is run in place of the finned tandem still in conjunction 

with a swivel assembly. 

The eccentric tandem works on the same principle as the 

fins. As the guns are run into the well, and transition from a 

vertical to deviated position occurs, the natural tendency is 

for the fin to orient to the high side of the wellbore. The 

eccentric tandem works on the same principle. The eccentric 

tandems allows for a greater degree of accuracy with an 

overall smaller profile. 

Features 

Eccentric subs allow perforating guns to be oriented in 

situations where the fin system is not ideal due to restrictions 

in the casing, fishing concerns, welding concerns, etc. Several 

tests and wells have been perforated using this new technique 

in the North Sea area and the Gulf of Mexico. 

Built with an adjustable ring, which makes it possible to 

orient the shots in the casing to a predetermined direction 

Tensile strength of the eccentric sub equivalent to the 

standard gun connectors 

Available for most gun sizes 

Eliminates the use of welded fins on the connectors 

Eccentric Orienting Tandem 


HAL15456

Special Applications 

Modular Gun System 

Through a special arrangement of perforating equipment, 

Halliburton’s modular gun system permits the optimum 

number of guns to be removed via slickline or 

electric line so larger intervals can be perforated 

simultaneously. In fact, the modular gun system is so 

innovative, Halliburton has patented* this unique system, 

proving once again our commitment to bring the latest 

technology to the wellsite. 

The modular gun system is run by Halliburton perforating 

specialists who know the equipment, know your well, and 

know the best techniques to fit your particular application. 

And of course, the modular gun system is backed by 

Halliburton’s worldwide network of technical support, 

reliable equipment, and innovative performance—all of 

which are ready to go wherever and whenever needed. 

Features 

Ideal for monobore completions 

With the modular gun system, you are able to stack an 

optimum number of guns downhole for perforating the 

maximum interval 

Several features make the modular gun system your best 

choice for perforating under a wide range of conditions 

– The guns are retrievable or can be left at 

the bottom of the hole 

– The system allows perforating in either 

underbalanced or overbalanced 

conditions over the entire interval 

– Wide range of gun sizes (2- to 7-in. OD) 

permits deployment over a wide range of 

casing, from 3 1/2 to 9 5/8 in. 

No rig is required—the system is ideal for rigless 

completions 

The modular gun system can be deployed via coiled 

tubing, electric wireline, or slickline, as well as with 

conventional tubing or drillstring 

The modular gun system allows a zone to be perforated 

and tested with no downhole restrictions below or above 

the packer 

Proven VannSystem® guns and firing heads are used in the 

modular gun system 

Wireline 

Running Tool 

Stinger Skirt 

Stinger 

Modular Gun System Configuration 

*US Patent Number 5,366,014 

Retrievable 

Firing Head 

(Wireline 

Conveyed) 

Centralizer 

Auto-Release 

Gun Hanger 


HAL6093

The Modular Gun System Process 

The modular gun system allows operators to deploy multiple 

gun sections to perforate long intervals. The gun modules are 

deployed downhole individually and stacked on each other at 

the perforating zone until the appropriate length is achieved 

with the lowermost gun module being supported by the gun 

hanger. This method avoids any gun length restrictions 

caused by the lubricator. The auto-release gun hanger 

positions the perforating assembly and allows it to remain 

adjacent to the desired interval. The guns are fired, via a 

pressure-actuated firing head, and are then, automatically 

released to the bottom of the hole where they can later be 

retrieved or left in the hole. 

The modular gun system is ideal for use in wells with rathole 

length restrictions and rigless completions. 

Rathole Length Restriction 

In this application, insufficient rathole length causes the 

uppermost gun modules to remain adjacent to the 

perforated interval after they are fired—where they may 

interfere with production from the well. The modular gun 

system allows the guns to be retrieved in sections without 

having to kill the well. 

Rigless Completion 

On wells where the completions are installed with wireline or 

coiled tubing, the modular gun system is the preferred 

method for perforating. No rig is required, saving both time 

and money. 


HAL15458 

HAL15457 


Skirt Assembly

Select Fire Systems 

The Select Fire system offers flexibility in perforating, 

testing, and evaluating multiple zones in one trip. The 

Select Fire system saves rig time and tool charges to help 

multiply profits. 

Features 

Perforating and testing several individual zones — one 

at a time 

Selecting the order zones are perforated 

Customizing gun configurations for various applications 

Available for all VannGun® assemblies 2-in. and larger 

Helps develop essential information about the reservoir — 

potentially saving hundreds of thousands of dollars 

Saves rig time and tool charges to help multiply profits 

HAL10537 

A 

I 

R 

C 

H 

A 

M 

B 

E 

R 

P 

R 

E 

S 

S 

U 

R 

E 

Before Firing 

Select Fire Sub Operation 

When gun #1 fires, the 

explosives train is continued 

to the Select Fire Sub, which fires 

a shaped charge downward. 

Pressure may now enter into 

the air chamber. (Note: the 

isolation sub is used to 

prevent pressure from going 

upward from the Select Fire Sub). 

Air 

Chamber 

TDF Firing 

Head 

® 

VannGun 

Assembly 

Select Fire Tubing Conveyed 

Perforating System 

® 

VannGun 

Assembly 

Pressure 

Isolation 

Sub 

Sealed Initiator 

Select Fire 

Sub 

Air Chamber 


HAL10586

Coiled Tubing Conveyed Perforating 

Conveying perforating guns to the zone 

of interest with coiled tubing has been 

effectively used for many years in a 

variety of applications. Benefits include 

faster run-in times when compared to 

conventional methods. And the guns 

can be detonated either with wireline or 

a pressure-activated firing head. Some 

of the applications include: 

Perforating in Underbalanced 

Conditions 

Underbalanced conditions occur 

when hydrostatic pressure in the well 

is lower than formation pressure. 

Perforation under these conditions 

allows increased flow from the 

formation, which helps clean the 

perforations and helps reduce nearwellbore 

damage 

Horizontal Well Perforating 

Coiled tubing conveyed perforating 

could be deployed in horizontal 

portions of the well where 

conventional methods of perforating 

are impractical or impossible 

Coiled Tubing Used as the 

Production String 

The coiled tubing that conveys the 

perforating guns can also be used as 

the production tubing after well 

completion 

Special features include an automaticrelease 

gun hanger, which allows the 

coiled tubing to detach from the 

perforating guns before they are fired, 

avoiding damage to the coiled tubing. A 

modular gun system is also available in 

which the perforating guns are loaded 

at the surface, deployed downhole 

individually, and stacked at the 

perforating zone. This method helps 

eliminate any gun length restrictions 

caused by the lubricator. 

HAL15399 

Correlation Tool Stack 

Coiled Tubing 

Connector 

Swivel 

Back Pressure 

Valve 

Hydraulic 

Disconnect 

Circulating 

Valve 

Crossover 

Centralizer 

Battery 

Housing 

Memory 

Controller 

Pressure 

Casing Collar 

Locator (CCL) 

Gamma/Ray 

Temperature 

Roller 

Centralizer 

Perforating Gun String 

Coiled Tubing 

Connector 

Swivel 

Back Pressure 

Valve 

Hydraulic 

Disconnect 

Pressure Relief 

Ports* 

Coiled Tubing 

and Firing Head 

Crossover 

Firing Head 

with Circulating 

Ports 

3 3/8-in.-6TTP 

Scalloped Guns 

*Pressure relief ports are added to the BHA for 

coiled tubing perforating jobs to help eliminate 

the possibility of a pressure increase due to 

thermal expansion in a closed chamber. 


HAL15400

DrillGun Perforating Systems 

Halliburton has developed the 

DrillGun assembly to be a drillable 

perforating system that provides 

reliable, quality performance while 

lowering overall wellsite costs by: 

Eliminating the high costs associated 

with wireline services 

Eliminating the need to switch to a 

mud system for workovers 

The DrillGun perforating system is a 

new method that combines rugged, 

reliable Halliburton perforating 

components with the versatility of 

drillable materials. It is this type of 

innovative design that has made 

Halliburton the leader in perforating 

charge performance and delivery 

systems. Now, with the DrillGun 

perforating system, you have a drillable, 

disposable system that helps save you 

two of the most valuable commodities 

at the wellsite—time and money. 

Components of the drillable 

perforating system are the drillpipe 

conveyed to the zone of interest; 

thereby eliminating mobilization or 

demobilization charges normally 

associated with wireline units. And, 

since no mud system is needed, clear 

fluids can remain in place for workover 

operations. Once in place, the firing 

head is actuated by pressure applied 

through the tubing. After perforating, 

the gun can be drilled out with 

conventional drilling methods. 

The drillable perforating system is ideal 

for: 

Single-trip perforating, packer 

placement, and cementing on tubing 

Cementing and perforating in 

underbalanced conditions 

Plug-to-abandon operations 

Workover cementing with clear fluids 

Plugback set on wireline 

Limited entry drill stem testing 

Components of the drillable 

perforating system include: 

Aluminum perforating gun 

High-performance, perforating 

charges 

Halliburton’s industry-proven 

EZ Drill® SVB packer 

DrillGun Assembly 


HAL12056

DrillGun Perforating System - Quick, Economical Solution For 

Perforating In Unusual Conditions. 

Savings on Rig Time 

Operator's challenge—Carrizo Oil & 

Gas, Inc. needed to perform a squeeze 

job on a South Texas well. The 

customer had already switched to a 

lighter drilling fluid and did not want 

the high cost of changing to a mud 

system. As a result, the well would have 

to be perforated underbalanced. 

Halliburton's solution—To meet this 

challenge, Halliburton recommended 

its DrillGun system. 

Economic value created—As a result, 

Carrizo was able to perform the squeeze 

job without having to replace the 

lighter drilling fluid with an expensive 

mud system. This procedure saved rig 

time and the expense of a fluid change 

for a total economic value to the 

customer of $20,000. 

SAP No. 

101288693 

Aluminum 

101288692 

Aluminum 

101292015 

Composite 

Thread Size 


in. (mm) 

2 7/8 (73.03) 

EUE 8 Rd 

2 7/8 (73.03) 

EUE 8 Rd 

2 7/8 (73.03) 

EUE 8 Rd 

Block Squeeze Application 

Operator's challenge—An operator 

working in the Permian Basin had to 

perform three block squeezes in a 

7 5/8 in. liner from 14,400 ft to 

14,800 ft. A primary cement job had 

not been possible, so instead of cement 

behind the casing, there was 15.5 ppg 

drilling mud. The well fluid was 10 ppg 

brine water. However, it would not be 

necessary to change the well fluid to 

15.5 ppg drilling mud to cement. 

Halliburton's solution— Halliburton 

logged the first DrillGun system on 

depth, perforated and performed the 

cement job at 4,230 psi underbalanced. 

For the next two DrillGun system runs, 

we tagged the first retainer and located 

it on depth to perform the squeeze. 

Economic value created—The three 

aluminum perforating guns added only 

one hour each to the drill-out time. The 

customer estimates that this procedure 

saved $52,000. 

DrillGun Assembly Specifications 

Maximum OD 

in. (mm) 

4.00 

(101.6) 

7.00 

(177.8) 

3.625 

(92.1) 

*For use in wells above 300°F (148.89°C), consult a Halliburton representative. 


Pressure 

psi (bar) 

15,000 

(1020) 

12,000 

(816) 

15,000 

(1020) 

Plug-to-Abandon 

Operator's challenge—To plug a well 

before abandoning it, an operator in 

Chambers County, Texas needed to 

perforate six zones. 

Halliburton's solution—Halliburton 

recommended using its DrillGun rather 

than employing electric-line 

perforators which would normally be 

selected for the project. The first 

DrillGun system was started in the well 

on Sunday evening and was set the next 

day at a depth of 13,050 ft. The bottom 

zone was then squeezed. After the 

procedure was completed, the setting 

assembly was pulled out of the hole. It 

went back in with the second stage, and 

the job was performed at 8,590 ft. The 

next day, the final four jobs were run at 

5,500 ft, 2,615 ft, 500 ft, and 350 ft, 

respectively. 

Economic value created—All six stages 

were completed in 2 1/2 days. If 

electric-line perforators had been used, 

the total job would have taken up to six 

days. By using the Halliburton 

DrillGun system, the operator saved 

four days of rig-associated costs, 

consultants, and fluid standby time. An 

additional savings was realized by using 

the perforating DrillGun system instead 

of more expensive electric-line charges. 

The resulting estimated economic value 

to the customer is $24,200. 


Pressure 

psi (bar) 

3,500 

(241) 

3,500 

(241) 

3,500 

(241) 

Temperature 

Rating 

°F (°C) 

300 

(148.9)* 

300 

(148.9)* 

300 

(148.9)* 

Maximum 

Overall Length 

ft (m) 

4.40 

(1.341) 

4.40 

(1.341) 

3.95 

(1.204) 


Setting Tools for the Auto-Release Gun Hanger 

Running and Retrieving Tools 

The running and retrieving tools for the modular gun system 

and the auto-release gun hanger gives customers flexibility in 

the conveyance of these tools in the well. There are four basic 

running tools that have been run with these systems: 

explosive set, jar down, hydraulic, and rotational set. Most of 

the tools are for wireline and slickline deployment of the 

systems. The on/off tool requires rotation to operate and is 

limited to tubing conveyed applications. All of these tools are 

reusable with a minimal amount of redressing. 

Application 

The running and retrieving tools are used for setting gun 

hangers in position, running modules, and retrieving 

modules. The tools break down into four categories: 

explosive set, jar down and jar up, hydraulic, and rotational 

set. There are many tools that can be used with the modular 

system. This manual has been written for the tools specially 

designed for the modular gun system or those recognized as a 

usable tool. 

Explosive set 

–Adapter kit for Baker #10 setting tool 

–Adapter kit for Baker #20 setting tool 

Jar down 

–Otis® SB and RB shear release and running tool 

–Camco JDC and JUC 

Hydraulic 

–Hydraulic JDC running and retrieving tool 

Rotational set 

–Right hand release on/off tool 

Running Tool Assembly Modular 

3.12 in. OD for Baker #20 Setting Tool 


HAL15778


Downhole Video 

Downhole Video Services 

Equipment providing real-time videos of actual oil 

production into wellbores through perforations, and the 

resulting flow up production tubulars, enhance the ability to 

characterize fluid inflow on a perforation-specific basis. 

The visually intuitive nature of downhole video data results 

in greatly increased effectiveness of conformance technology 

treatments, leading to increased oil and gas production and 

decreased water production. Greater knowledge of the type 

of fluid being produced from each perforation substantially 

reduces the risk of inadvertently shutting off oil or gas 

production with misplaced treatments. 

Features 

A downhole video survey allows observation of the integrity 

of the casing or tubing to find holes, cracks, or corroded 

areas and fluid entry or exit points. Also, it can detect scale or 

bacteria buildup, which can impede the flow of 

hydrocarbons out of the wellbore and reduce the ID of the 

wellbore tubulars and plug slotted liners, gravel pack screens, 

or perforations. 

Downhole video can help the operator detect and identify 

phase entry, fluid flow, and sand or particulate matter entry 

into the wellbore. 

The video survey can detect the entry of sand and particulate 

matter from individual perforations. Conventional flowmeasurement 

tools often cannot detect such subtle changes 

in fluid activity. Oil bubbling into the wellbore does not 

disrupt the surrounding well fluids. The oil remains in 

bubbles and migrates to the high side of the well, causing 

Max Deployment Depth 

ft (m) 

14,000 

(4267) 

Camera Assembly OD 

in. (mm) 

1.687 

(42.8) 

Downhole Video Services Specifications 


psi (Mpa) 

10,000 

(69) 

some of the oil to bypass conventional logging tools. Video 

surveying clearly identifies the oil-producing perforations. 

A downhole video survey documents the amount of gas and 

oil being produced at each point in a producing interval. 

Conventional flowmeters directly measure the average flow 

rate of a column of fluid. The downhole video survey does 

not directly measure absolute flow rates but is used to 

quantify relative flow rates along the production intervals. 

Downhole video surveys can visually confirm the initial 

analysis of conformance problems and determine if the 

prescribed treatment can solve the problem. If the initial 

analysis was incorrect, the visual information can be used to 

modify the treatment schedule to prevent costly but 

ineffective treatment procedures. 

Downhole video can monitor well and reservoir treatments 

in real-time during the treatment process. For example, 

downhole video surveys run during a frac job can verify 

that the frac proppant entered the intended fracture areas. 

The downhole video is limited by fluid clarity, the 

operational limits of the camera and system, and extremely 

high flow rates. 

After the completion of a treatment, a downhole video 

survey can show whether the treatment successfully treated 

the problem area. Video confirmation of the job results also 

allows operators to learn more about the effectiveness of the 

treatment to continually improve the treatment process. 


°F (°C) 

Cable Tension Limits 

lb (kg) 

at Camera Cable Head at Surface 

Downhole Video 6-1 

225 

(107) 

500 

(226.8) 

1,200 

(544.3) 

Downhole Video

Hawkeye Camera System 

The Hawkeye camera system allows operators to view 

conditions inside oil and gas wells without the need for a 

special coaxial or fiber-optic cable. Video images (frames) are 

transmitted to the surface every 1.7 seconds over standard 

electric line logging cable. Complete redundancy for all 

mission critical components is provided along with rugged 

shipping containers for complete transportability. The 

camera requires a transparent medium in the area to be 

filmed for meaningful results. Obtaining the correct clarity of 

fluid at the viewing zone is often the most challenging aspect 

of performing this service. 

The camera is used as a diagnostic tool to detect all types of 

fluid and solids entry into the borehole, to inspect pipe for 

corrosion, mechanical integrity, and correct production/ 

perforation verification. Additionally it may be used to aid 

fishing operations. 

Features 

The Hawkeye system can be run from any logging cable 

with less than 250 ohms total loop resistance and up to 

1.5 micro farads of total capacitance. This allows 

downhole video service to be offered as the system is 

completely transportable to any location without the 

need for special cable or logging units 

The ability to measure depth and superimpose it on the 

video image along with time, date, and internal tool 

temperature is provided. In addition, the ability to 

Length 

ft (m) 

8.5 

(2.6) 

Hawkeye Camera System Specifications 

Diameter 

in. (mm) 

1.69 

(42.9) 

annotate the recorded tape with text entered from an 

optional laptop computer or video typewriter is 

provided 

The system comes equipped with two downhole tools, 

two surface power supply/receivers, and two video 

monitors. This provides complete backup for the image 

producing and display equipment 

The system is provided in three rugged shipping 

containers with internal padding designed for the 

standard components plus some additional room for 

cables and miscellaneous equipment 

This image shows cut up casing that has fallen onto a trash cap for a 

casing shoe. 

6-2 Downhole Video 

HAL11281 


psi (Mpa) 

10,000 

(69.0) 


°F (°C) 

250 

(121.1) 

Weight 

lb (kg) 

31 

(14.1)

Fiber-Optic Camera System 

The fiber-optic system allows operators to view conditions 

inside oil and gas wells. Video images (frames) are 

transmitted to the surface at a rate of 30 frames every second 

over a specialty 0.25-in. diameter logging cable with a fiberoptic 

cable at its center. Complete redundancy for all mission 

critical components is provided along with rugged shipping 

containers for complete transportability. The camera 

requires a transparent medium in the area to be filmed for 

meaningful results. Obtaining the correct clarity of fluid at 

the viewing zone is often the most challenging aspect of 

performing this service. 

The camera is used as a diagnostic tool to detect all types of 

fluid and solids entry into the borehole, and to inspect pipe 

for corrosion, mechanical integrity, and correct production/ 

perforation verification. Additionally, it may be used to aid 

fishing operations. 

The fiber-optic system differentiates itself from other video 

camera tools by having the highest video data rate and is 

better than any other products available for detecting flow 

due to gas entry. 

Length 

ft (m) 

9.5 

(2.9) 

Fiber-Optic Camera System Specifications 

Diameter 

in. (mm) 

1.69 

(42.9) 


psi (Mpa) 

10,000 

(69.0) 

Features 

A 1.6875-in. backlight camera is used to provide 

unobstructed, wide viewing angle, and clearly defined 

images. A 10,000 psi pressure rating and operation at 

temperatures up to 250°F are standard 

The ability to measure depth and superimpose it on the 

video image along with time, date, and internal tool 

temperature is provided. In addition, the system has the 

ability to annotate the recorded tape with text entered 

from an optional laptop computer or video typewriter 

The system comes equipped with two downhole tools, 

two surface power supply/receivers, and two video 

monitors. This provides complete backup for the image 

producing and display equipment 

The system is provided in three rugged shipping 

containers with internal padding designed for the 

standard components plus some additional room for 

cables and miscellaneous equipment 

The fiber optic system’s resolution is 550 × 350 lines vs. 

the 317 × 262 lines of the Hawkeye system. As a result, 

the fiber-optic system has better picture resolution and 

provides pictures virtually in real time. By comparison, 

the Hawkeye system is more akin to a slo-scan security 

camera 


°F (°C) 

250 

(121.1) 

Weight 

lb (kg) 


35 

(15.9)

EyeDeal Camera System 

Pictures are said to be worth a thousand words—and they 

become even more powerful when they are transmitted from 

wellbores miles beneath the Earth’s surface. Halliburton’s 

EyeDeal camera system opens new windows to the 

downhole world with high-resolution images that eliminate 

the guesswork from a range of diagnostic tests and 

troubleshooting operations. 

HAL18524 

HAL18523 

Downhole 

Camera View 

HAL18525 

Sideview camera with 

view angle that is closer 

and almost dead-on to 

the camera lens 

The EyeDeal camera system can be deployed in two ways: 

Fiber-optic configuration – When attached to the fiberoptic 

system, the EyeDeal camera system can operate to a 

depth of 14,000 ft and can sustain pressures of 10,000 psi 

and temperatures of 250°F. In this configuration, the 

EyeDeal camera system offers a continuous-feed image 

with an excellent screen resolution of 550 × 350 

Hawkeye system configuration – When attached to the 

Hawkeye system, the EyeDeal camera system uses 

existing logging cables to transmit high-quality images 

(screen resolution: 317 × 262) at the rate of one frame 

every 1.7 seconds. The Hawkeye system provides full 

remote camera operation and control, and its advantages 

include deeper operation and the ability to perform 

flawlessly in corrosive fluids 

Fiber Optic Configuration: 

Down View, Real Time 

Hawkeye Configuration: 

Snapshots, Every 1.7 Seconds 

Fiber Optic Configuration: 

Side View, Real Time 

Applications of the EyeDeal camera system include quality 

assurance inspection, gas entry, water entry, fishing 

operations, casing and perforation inspection, and general 

problem identification. 

The technology incorporated in the fiber-optic and Hawkeye 

systems allows operators to toggle between downview and 

sideview images. The sideview lens records images 

perpendicular to the borehole wall and gives a true 360° view. 

This is especially useful in large-diameter wellbores (from 16 

to 30 in.) where traditional downview cameras offer only a 

limited field of vision. The EyeDeal camera system can be 

toggled between downview and sideview images, giving 

operators the valuable advantage of being able to isolate and 

study an area of interest. 

6-4 Downhole Video 

HAL18526 

HAL18528 

HAL18527

EyeDeal Camera System Examples 

HAL18526 

HAL18529 

HAL18532 

Suspect Latch Found OK, DV Latch Issues Due to Debris, SV Damaged Flow Tube, DV 

Fishing Operation 1 of 3 Fishing Operation 2 of 3 Fishing Operation 3 of 3 

5.5-in. Lubricator 

HAL18527 

HAL18530 

HAL18533 

Perfs Before Cleanout, DV 

Perfs After Cleanout, DV 

EyeDeal Camera System Specifications: Sideview and Downview Combination 

Length 

ft (in.) 

9.75 

(117) 

Length 

ft (mm) 

8.5 

(2.6) 

Diameter 

in. (mm) 

1.937 

(49.2) 

Diameter 

in. (mm) 

1.687 

(42.9) 


psi (Mpa) 

10,000 

(69) 


HAL18528 

HAL18531 

HAL18534 


°F (°C) 

250 

(121.1) 

Downview Camera Specifications 


psi (Mpa) 

10,000 

(69) 


°F (°C) 

250 

(121.1) 

Weight 

lb (kg) 

36 

(16.3) 

Weight 

lb (kg) 

31 

(14.1)

6-6 Downhole Video

Slickline Service Equipment and Services 

The high quality of Halliburton’s slickline services depends 

upon the capabilities of its service tools and equipment; 

therefore, we are committed to designing and manufacturing 

the most sophisticated tools in the industry. Our success in 

this endeavor, along with highly trained and experienced 

personnel, has allowed us to remain the leader of the slickline 

service industry. 

Through our decades of experience and global presence, 

Halliburton has continued to offer the industry the most 

complete line of slickline service equipment, tools, and 

services. 

Slickline Service Equipment 7-1 

Slickline Service Equipment

Subsurface Service Tools 

Slickline Service Tools 

Otis® designed and manufactured slickline service tools have 

been the benchmark for the industry and are a requirement 

for all toolboxes worldwide. Known for dependable 

performance and low maintenance costs, these service tools 

can help reduce your total operating costs. As the original 

equipment manufacturer (OEM), Halliburton continues to 

provide high-quality slickline service tools. 

Slickline Toolstring 

Wireline Toolstring 

A wireline toolstring is attached to the wireline to furnish the 

mechanical force necessary for setting, pulling, or servicing 

subsurface equipment under pressure without killing the 

well. Toolstrings are available in various ODs and 

component lengths designed to be compatible with various 

tubing sizes. 

Otis Rope Sockets 

Otis rope sockets provide a means for connecting the 

wireline to the toolstring. The wireline is tied around a disc 

or dart in the socket to achieve a firm connection. 

Otis Stems 

Otis stems are used as weight to overcome stuffing-box 

packing friction and well pressure on the cross-sectional area 

of the wireline. The stem can also transmit force either 

upward or downward to set or retrieve subsurface controls. 

Size and weight of the stem are determined by the impact 

force required and the size of the subsurface control to be run 

or pulled. For normal conditions, 5 ft of 1 1/2-in. OD stem is 

made up by combining 2-, 3-, or 5-ft (0.61, 0.91, 1.22 m) 

lengths of standard stem. For high-pressure applications 

when additional weight is needed, lead or mallory-filled 

stems are available. 

7-2 Slickline Service Equipment 

HAL8500 

Wireline Socket 

Stem 

Jars 

Typical String of 

Wireline Tools 

Knuckle Joint 

Running or 

Pulling Tool 

HAL8501 

Otis® Rope Socket 

HAL8502 

Otis® Stem

Otis ® Accelerators 

Otis® accelerators are used with and just above hydraulic jars 

for shallow, weighty jarring. Accelerators help maintain 

constant pull as the hydraulic jars begin to open. The 

accelerator inhibits pulling the wireline out of the wireline 

socket at these shallow depths. 

Otis Knuckle Joints 

Otis knuckle joints have a special ball and socket design, 

allowing angular movement between the jars and the 

running or pulling tool to help align them with the tubing. 

Knuckle joints are important if the tubing is corkscrewed and 

when wireline work is done in a directional hole. In these 

conditions, joints are used at every connection in the 

toolstring. Where stem and jars will not align or move freely, 

tool operation may be impossible; however, the knuckle joint 

inhibits the wireline tools from hanging up. 

Otis Jars 

Otis jars are available in mechanical and hydraulic types. 

With a set of mechanical jars below the stem, the weight of 

the jars and stem can be used to jar up or down by pulling 

and releasing the wireline. A Halliburton wireline specialist 

can easily feel the jars and manipulate the wireline. Hydraulic 

jars are designed to provide jarring action in wells in which it 

is difficult to obtain good jarring action with mechanical jars. 

Hydraulic jars, which allow an upward impact only, are 

usually run just above the regular mechanical jars. They 

require careful maintenance for maximum use in the 

toolstring. Jar operation is monitored by a weight indicator. 

Otis B Blind Box 

Otis B blind box serves as the impact point when downward 

jarring operations are required. 

Standard Wireline Toolstring 

Normal Tool OD 

in. (mm) Thread Connection* 

3/4 

(19.05) 

5/8 in. - 11 UNC 

1 

(25.40) 

5/8 in. - 11 UNC 

1 1/4 

(31.75) 

15/16 in. - 10 UNS 

1 1/2 

(38.10) 

15/16 in. - 10 UNS 

1 7/8 

(47.63) 

1 1/16 in. - 10 UNS 

2 

(50.80) 

1 1/16 in. - 10 UNS 

2 1/2 

(63.50) 

1 1/16 in. - 10 UNS 

*Other thread connections available 

Fishneck OD 

in. (mm) 

0.750 

(19.05) 

1.000 

(25.40) 

1.188 

(30.18) 

1.375 

(34.93) 

1.750 

(44.45) 

1.750 

(44.45) 

2.313 

(58.75) 


HAL8503 

Otis® Knuckle Joint 

HAL8505 

Otis® 

Mechanical Jar 

HAL8504 

HAL8506 Otis® Blind Box 

Otis® 

Hydraulic Jar 

HAL8507 

Otis® 

Accelerator

Slickline Detent Jars 

The Halliburton detent jar is a mechanically operated jar that 

is run on slickline or wireline to deliver an impact through 

the toolstring when the release setting is overcome by 

tension. This jar has adjustable stroke and release settings 

that are predetermined on the surface prior to running the 

jar. The detent jar can be run with accelerator, weight bar, 

and link-type or Spang jars for delivering an optimum 

impact load for releasing a stuck object or operating a 

downhole tool. The detent jar is re-settable downhole by 

slacking weight at the jar to a collapsed mode. The jar can be 

tripped and reset rapidly and multiple times downhole. 

There are no seals in the detent jar, so bottomhole 

temperature or pressure has minimal effect on the jar 

operation. 

Sometimes in deep and deviated wells, the line tension on the 

weight indicator at the surface is not the same line tension at 

the rope socket. Modeling the slickline job with Cerberus 

will provide calculated rope socket line tensions. 

Size 

in. (mm) 

1.500 

(38.10) 

1.875 

(47.63) 

2.250 

(57.15) 

Standard Release 

lb (kg) 

up to 900 

(up to 408) 

up to 1,400 

(up to 635) 

up to 3,100 

(up to 1406) 

High Release 

lb (kg) 

750 to 2,100 

(340 to 953) 

1,300 to 3,500 

(590 to 1588) 

1,250 to 5,000 

(567 to 2268) 

Detent Jars 

Stroke 

in. (mm) 

8 to 14 

(203.2 to 355.6) 

8 to 14 

(203.2 to 355.6) 

8 to 14 

(203.2 to 355.6) 

Length 

in. (mm) 

52 

(1320.8) 

53 

(1346.2) 

50 

(1270) 

Tensile 

lb (kg) 

37,500 

(17 010) 

62,000 

(28 123) 

76,000 lb 

(34 473) 

Slickline Detent Jar 

7-4 Slickline Service Equipment

Otis ® Quick Connect Toolstring Connection 

Before its extensive field history, the Otis® quick connect was 

thoroughly tested in both the engineering laboratory and the 

Halliburton test well in Carrollton, Texas. During the design 

proving phase, a 1 1/2-in. (38.1 cm) Otis quick connect was 

jarred through 50,000 cycles at impact loads of 9,000 to 

10,000 lb (4082.33 to 4535.92 kg) in both directions. Tensile 

testing on the tool after jarring revealed the Otis quick 

connect had retained full strength throughout the operation. 

Now Halliburton toolstring components and wireline service 

tools are available with integral Otis quick connects. 

Features 

Spacing of load-bearing shoulders will not allow 

coupling to connect until full engagement of all 

shoulders are in place 

Self-washing feature minimizes sand buildup in the 

locking mechanism 

Designed for manual operation; no special tools required 

Otis quick connect design ensures proper toolstring 

makeup 

Reliable disconnect, even in sandy environment 

Safe assembly/disassembly on location 

Faster turnaround on location minimizes job time 


HAL11442 

Mechanical 

Wireline Jar 

HAL11443 

Wireline Quick 

Connect Stem 

HAL11444 

Knuckle Joint 

Quick Connect

Auxiliary Tools For Use with Slickline Toolstring 

Otis ® Gauge Cutter and Swaging Tools 

It is important to run a gauge cutter before running 

subsurface controls to: (1) determine if the flow control will 

pass freely through the tubing and (2) to locate the top of the 

landing nipple or restriction if any are in the tubing. The 

gauge cutter knife (larger than OD of the control) is designed 

to cut away paraffin, scale, and other debris in the tubing. 

Mashed spots in the tubing and large obstructions may be 

removed with the swaging tool. These tools are available in 

sizes for all tubing IDs. 

Otis Impression Tool 

Otis® impression tool is a lead-filled cylinder with a pin 

through the leaded section to secure it to the body of the tool. 

It is used during a fishing operation to ascertain the shape or 

size of the top of the fish and to indicate the type of tool 

necessary for the next operation. 

Otis Tubing Broach 

Otis tubing broach is made up of three major parts: (1) 

mandrel, (2) nut, and (3) a set of three spools. Spools are 

tapered and used to cut burrs in the tubing ID caused by 

perforation, rust, bent tubing, etc. A small OD spool is run 

first followed by the next larger size, followed by a spool 

corresponding to the original ID of the tubing. Broach 

assemblies are run on wireline. 

Otis M Magnetic Fishing Tool 

Otis M magnetic fishing tool is designed to remove small 

particles of ferrous metals from the top of tools in the well. 


HAL8510 

HAL8508 

Otis® Swaging Tool Otis® Gauge Cutter 

Otis® Impression 

Tool 

HAL8511 

Otis® Tubing Broach 

HAL8509 

HAL8512 

Otis® M Magnetic 

Fishing Tool

Otis ® G Fishing Socket 

Otis® G fishing socket was designed primarily to extract 

prongs with fishing necks from Halliburton subsurface 

equipment, such as the Otis PS plug choke. 

Otis P Wireline Grab 

Otis P wireline grab is a fishing tool designed to extract 

broken wireline or cable from the tubing or casing. 

Otis Go-Devil 

Otis go-devil is a slotted stem with a fishing neck. Should the 

tool become stuck, the go-devil can be attached to the 

slickline via a small strip of metal pinned in the slot to keep 

the wireline from coming out. The go-devil is dropped from 

surface and will slide down the wire until it hits a restriction 

or the top of the rope socket. The go-devil will cut the 

slickline at that point, allowing the slickline to be retrieved. 

Its use is usually limited to fishing operations where the 

wireline socket is inaccessible and the line must be cut. Otis 

go-devils designed to cut the wireline at the wireline socket 

are also available. 

Expandable Wirefinder 

The expandable wirefinder is designed to locate wireline lost 

below a tubing restriction (such as a TRSV). The expandable 

wirefinder is held retracted in a sleeve which is run, located, 

and preferably latched in the restriction in the tubing. The 

wirefinder is then sheared out of the sleeve allowing it to 

expand to the ID of the tubing. Once the lost wireline is 

found and deformed, the wirefinder can be returned to its 

running sleeve and retracted for retrieval. A wireline grab is 

then run to latch and retrieve the lost wireline. 


HAL8515 

HAL8513 

Otis® G Fishing Socket 

Otis® Go-Devil 

HAL14025 

Run-in 

Position 

HAL8514 

Otis® P Wireline Grab 

Otis® Expandable Wirefinder 

Wirefinder 

Position

Running Tools 

Otis ® X ® and R ® Running Tools 

Otis® X® and R® running tools are used 

to set Otis X, XN®, R, RN®, and RQ 

lock mandrels in their respective Otis 

landing nipples. These tools are 

designed with locator dogs, serving to 

locate the proper landing nipple and 

positioning the lock mandrel before 

locating and locking. By selecting the 

position of the running tool, the lock 

mandrel keys may be placed in the 

locating or retracted position. 

Otis RXN Running Tools 

Otis RXN running tools set Otis X, XN, 

R, RN, RPT®, and RQ lock mandrels in 

their respective landing nipples. This 

tool is generally used for installing 

wireline-retrievable subsurface valves 

in the uppermost landing nipple in 

staggered bore nipples such as RPT. 

With this tool, the lock mandrel may be 

run with the keys in the control or 

locating positions. The lock mandrel 

keys or no-go serve to locate the nipple 

rather than the dogs on the running 

tool. When a non-no-go lock is being 

run, the keys must be run in the 

locating position and the lock must be 

set in the first nipple in the bore of that 

lock size. The tool gives a positive 

indication when the lock is fully set. 

Otis SAFETYSET ® Running Tools 

Otis SAFETYSET® running tools are 

used to set Halliburton surfacecontrolled, 

wireline-retrievable safety 

valves on Otis RP and RQ lock 

mandrels. Two independent conditions 

must exist in sequence before the 

running tool will release the valve and 

lock. First, the SCSSV must be 

pressured open to activate the running 

tool. Second, only when the locking 

sleeve is moved upward into its locked 

position will the running tool release. 

A running tool retrieved to the surface 

without the lock and valve indicates a 

functional valve securely locked in the 

landing nipple. 

Otis UP Running Tool 

An Otis UP running tool is also 

available for running SAFETYSET lock 

mandrels and subsurface safety valves, 

which utilize staggered sealbores. The 

UP running tool is entirely mechanical 

and does not require control line 

pressure to activate. 

Otis MR Running Tools 

Otis MR running tools are used to run 

Otis XNS and RNS soft set bomb 

hangers. This running tool is designed 

to carry weight exceeding the 140-lb 

(63.50 kg) weight limit of hydraulic 

running tools because no preset force 

needs to be overcome. 

The lugs of the running tool hold the 

fish neck of the bomb hanger during 

the running of the bombs. The lugs are 

held in the expanded position by the 

core in the fully down position. When 

the bomb hanger locks into the nipple 

profile, the lock moves upward, 

pushing the core up by means of the 

core extension. Once the core is pushed 

up, the lock-out lug can then be pushed 

into the core recess by the leaf spring, 

thus locking the core in the up position. 

In the up position, the core no longer 

holds the lugs out and the running tool 

is disengaged from the hanger. The 

bomb hanger and pressure gauges are 

left suspended in the well. 


HAL8516 

Otis® RXN 

Running Tool 

HAL8518 

Otis® 

SAFETYSET® 

Running Tool 

HAL14029 

HAL8517 

Otis® UP 

Running Tool 

Otis® X® or R® 

Running Tool 

HAL8519 

Otis® MR 

Running Tool

Pulling Tools 

Internal Fishing Necks 

Otis® GS pulling tools are used during wireline operations to 

unlock and pull a variety of subsurface controls with internal 

fishing necks, such as an Otis G pack-off assembly. Designed 

to shear with a jarring down action, this pulling tool is used 

where excessive jarring upward is necessary to retrieve 

subsurface flow controls. In the running position, the dogs 

are designed to seat and lock in the internal recess of the 

mandrel being retrieved. If the device cannot be retrieved by 

upward jarring, the GS pulling tool can be released by jarring 

down which shears the pin to allow the pulling tool and 

toolstring to be removed from the well. With this tool being a 

shear-down-to-release, it can be used in many cases as a 

running tool for certain devices. 

Otis GR pulling tools are used during wireline operations to 

unlock and pull a variety of subsurface controls with internal 

fishing necks, including: Otis D bridge plugs, Otis X® and R® 

lock mandrels, Otis D mandrels, and Otis D collar stops. 

Designed to shear with a jarring up action, this pulling tool is 

used during routine wireline operations on controls when 

shear-down is not possible. The Otis GR pulling tool is 

assembled by incorporating an Otis GS pulling tool with an 

Otis GU shear-up adapter. 

External Fishing Necks 

Otis S pulling tools are designed for jobs 

in which extensive upward jarring is 

required to pull a bottomhole control. 

This tool is designed to pull any 

subsurface equipment with an external 

fishing neck. The core is manufactured in 

various lengths and may be changed in 

the field to accommodate the fishing 

necks of various controls. These are 

referred to as SS, SB, or SJ. The tool is 

designed to shear and release by 

downward jarring. With this feature, the 

tool may also be used as a running tool to 

run collar stops, pack-off anchor stops, 

and various other Halliburton tools. 

Note: When used as a running tool, the 

core must be long enough to allow for 

upward travel after shearing the pin 

before the skirt is stopped by the 

equipment being run. It is this action 

that permits complete release of the running tool. 

HAL8523 

Otis® S Pulling Tool 

Fishing Neck 

Shear Pin 

Dowel Pin 

Core Nut 

Otis R pulling tools are designed for jobs 

in which extensive downward jarring is 

required. Tools use upward jarring to 

release when necessary. Dogs in the R 

pulling tool engage the fishing neck of the 

device to allow it to shear with upward 

jarring. The R pulling tool can be 

modified as follows: 

Otis RB pulling tool (R body with a 

B core) pulls Otis B, C, and W lock 

mandrel assemblies and mandrel 

assemblies with full relative motion 

Otis RS pulling tool (R body with 

S core) pulls Halliburton S mandrel 

assemblies 

Otis RJ pulling tool (R body with J 

core) pulls all controls that do not 

have full relative motion 

Shear Pin 

Fishing 

Neck 

Shear Pin 

Cylinder 

Spring 

Spring 

Retainer 

Dog Spring 

Dog Retainer 

Cylinder 


HAL8520 

Otis® GU Shear 

Up Adapter 

HAL8521 

Otis® GS Pulling 

Tool Shear Down 

Dogs 

Core 

HAL8544 

HAL8522 

Otis® GR 

Pulling Tool 

Shear Up 

Otis® R® Wireline 

Pulling Tool

Plugs For Wells Without Landing Nipples 

Monolock ® Plug 

The Halliburton Monolock® plug is 

designed to be set anywhere in a given 

size of tubing, casing, or liner. The 

Monolock plug differs from a 

conventional lock mandrel because it 

does not require either a profile or 

sealbore in the tubing string and is 

retained in its set position by slips 

rather than keys. The Monolock plug 

may be used in association with the 

Halliburton full bore nipple system 

or any other selective or nipple and 

lock system. 

The plug is set and retrieved with 

Halliburton’s DPU® running and 

retrieving tools, which can be run on 

slickline, braided line, or coiled tubing. 

When used for plugging applications, 

the plug is designed to withstand 

differential pressure of up to 10,000 psi 

(690 bar) from either direction. 

Applications 

As a retrievable bridge plug placed 

anywhere in the tubing string 

Can be adapted to install BHP 

gauges and other flow control 

devices 

Plug tubing below hanger for well 

repairs 

Features 

Pressure ratings up to 10,000 psi 

(690 bar) 

Requires no landing receptacle 

Seals against pipe ID 

Slip-type anchor system 

Element is retracted during retrieval 

Belleville spring energy storage 

system provides positive sealing 

during pressure reversals 

Can be installed and retrieved 

through restrictions 

Run and retrieved on same DPU 

unit 

Run on slickline, braided line, or 

coiled tubing 

Element located above slips, 

preventing any debris accumulation 

around slip area 

Equalizing feature provided in 

standard assembly 

Barrel-slip design provides 

maximum slip engagement while 

minimizing tubing deformation 

Benefits 

Can be set anywhere in tubing, 

casing, or liner 

Quick running and retrieval 

Use of slickline rather than 

conductor line lowers installation 

and retrieval costs 

Redressable in field, reducing 

downtime 

Because element returns to original 

shape, assembly can be recovered 

back through restrictions 

Slip configuration ensures 

centralized setting of the lock even 

in high-angle or horizontal wells 

Provides same reliability as 

production packers 

Slip design minimizes tubing 

deformation 


HAL10466 

Monolock® Plug

Test Tools 

Otis® selective test tools are used to test tubing, locate leaks, 

or set hydraulic-set packers. Designed to hold pressure from 

above, selective test tools may be set in compatible Otis X®, 

XN®, R®, or RN® landing nipples in the tubing string. With 

the keys retracted, the tool is run to a point below the desired 

nipple. Pulling up through the nipple releases the locking 

keys to set the tool with downward motion. Pressure from 

above may then be applied. 

Features 

Designed for high working pressure 

Located in the lowest nipples first, these tools are then 

moved up the tubing and set in sequential nipples until a 

leak is not detected, thus reducing wireline trips 

Otis Non-Selective Test Tools 

Otis non-selective test tools are designed to test the tubing 

string, set hydraulic packers, and protect lower zones when 

circulating through a Sliding Side-Door® circulating device 

or producing a zone above the lowermost zone. Designed to 

hold pressure from above only by employing the use of a 

drop valve equalizing assembly, the non-selective test tools 

land in no-go landing nipples with compatible packing 

bores. When landed in the landing nipple, pressure from 

above is sealed by the drop, seal ring, and v-packing. In order 

to retrieve by wireline, the drop is moved off seat with a 

pulling tool. This equalizes the pressure across the test tool, 

allowing it to be retrieved. 

Features 

Ease of running, setting, and retrieving 

No-go OD on bottom of tool for positive location in 

landing nipple 

May be pumped into the well 

Designed for high-pressure ratings 


HAL8524 

Otis® Non-Selective 

Test Tool 

HAL8525 

Otis® Selective 

Test Tool

Positioning Tools 

Otis ® BO Selective Positioning Tools 

Otis® BO selective positioning tools are used to move the 

inner sleeve to its open or closed position in Sliding 

Side-Door® circulating devices. 

Note: The Otis B selective positioning tool is not to be used 

for shifting Otis XXO or RRO surface-controlled safety valve 

nipples. For these nipples, use the Otis XL or RL shifting tool. 

The positioning tool engages the recess in the upper 

(or lower) end of the inner sleeve to permit the sleeve to be 

shifted by a jarring action. The tool is designed to release 

itself only after the sleeve reaches its fully open or closed 

position. This automatic-releasing feature incorporates a 

releasing profile on the key itself that acts to compress the key 

spring and release the positioning tool. A shear pin is an 

added feature designed to release the tool in the event well 

conditions make it impossible to shift the sleeve. 

A set of positive keys is available for this tool to permit 

upward movement of the inner sleeve of one among several 

Sliding Side-Door circulating devices in one wellbore. These 

keys do not have a releasing profile. The positioning tool pin 

must be sheared to release. 

Note: The Otis BO selective positioning tool will not pass 

through position number 1 of Otis S landing nipples. 

Otis BO selective positioning tools are designed to selectively 

position Sliding Side-Door inner sleeves only to the down 

position. These tools are designed so that one sleeve can be 

shifted to the down position at any level in the tubing string 

without shifting any other sleeve. 

This positioning tool is designed with dogs that serve to 

locate the proper Sliding Side-Door circulating device and 

release the spring-loaded keys to engage the profile in the 

inner sleeve. The tool is designed to release itself only after 

the sleeve reaches the full-down position. This automaticrelease 

feature incorporates a releasing profile on the key 

that acts to compress the key spring and release the 

positioning tool. The tool can then be raised to the next 

Sliding Side-Door circulating device to position its sleeve 

down or return to the surface. 


HAL8526 

Otis® BO Selective 

Positioning Tool 

HAL8527 

Otis® BP Selective 

Positioning Tool

Tubing Perforators and Bailers 

Otis® A tubing perforators are mechanically operated and 

can be used with slickline (under pressure) to perforate both 

standard and heavyweight tubing. 

Applications 

To provide access to casing annulus to circulate or kill a 

well 

To bring in additional productive zones 

To permit production through tail pipe that has been 

plugged and cannot be opened by regular methods 

Features 

No explosives used, minimizing the possibility of 

perforating the casing 

Safety-release mechanism designed to permit removing 

perforator without perforating 

Greater tubing penetration 

Perforator designed to retract the punch and release 

automatically after perforating 

Service performed by Halliburton-trained personnel 

Otis M sand pump bailers may be used to remove a sand 

bridge if one is encountered during normal wireline 

operations. The sand bailer consists of a piston encased in an 

outer cylinder. By working the wireline in the same manner 

as used to set certain subsurface controls (lightly jarring up 

and down), the bailer acts to pull sand into the cylinder to 

remove the sand bridge. An assortment of bailer bottoms is 

available: 

Flat bottom for soft, easy-to-bail sand 

Chisel bottom for hard-packed sand 

Flapper bottom for bailing metal particles that are too 

large to pass the ball and seat 

Otis B hydrostatic bailers are designed for use when the 

substance to be bailed cannot be removed by a pump-type 

bailer. This is sometimes the case when small metallic 

particles become lodged on top of the locking mandrel dogs 

of a subsurface flow control. 

The Otis B hydrostatic bailer is sealed at the surface and run 

into the tubing bore with the internal bailer chamber at 

atmospheric pressure. When the bailer reaches the object to 

be bailed, a few downward strokes of the wireline jars act to 

shear a small sealing disc and admit the well pressure and/or 

hydrostatic head (as well as the junk) into the bailer cylinder. 

A ball check valve acts to contain the junk in addition to the 

well pressure until the bailer is retrieved. For large pieces of 

junk, a flapper bottom and junk basket are available. 

Note: The internal chamber pressure should always be bled 

off through the bailer release valve before the bailer bottom is 

broken off at surface. 


HAL8530 

Otis® A Tubing 

Perforator 

HAL8531 

Otis® M 

Sand Pump Bailer 

HAL8532 

Otis® B 

Hydrostatic Bailer

Slickline Skid Units and Trucks 

Halliburton designs and manufactures top quality skid-base 

units for offshore operations and trucks for land operations. 

The units are known worldwide for their user-focused 

design, providing the right mix of operator-friendly 

HAL22812 

HAL22811 

Offshore Three-Piece 

Skid Unit 

T800 Slickline Crane Truck 

HAL22808 

HAL22810 

components to make both specialized and standard 

operations more productive. For more detailed information, 

please contact your local Halliburton representative. 

Slickline Container Unit 

Stainless Steel Skid Unit 


HAL22809

Surface Service Equipment 

Halliburton’s wellhead pressure control equipment 

provides for a safe and highly productive service operation. 

Unmatched equipment quality backed by available 

extensive training and maintenance instruction has made 

HAL22757 

Options: 

Lubricator 

Safety Valve 

Pin End Assembly 

Options: 

• Slickline Grease 

Head 

Liquid Chamber 

Lubricator Control 

(Purge) Valve 

Hydraulic Stuffing Box 

(16-in. Sheave) 

Quick Union 

Upper Lubricator 

Section 

Quick Union 

Middle Lubricator 

Section 

Lubricator Pick 

Up Clamp 

Quick Union 

Lower Lubricator 

Section 

Option: 

Pump-In Sub 

Quick Union 

Wireline Valve 

Single 

(Manual or Hydraulic) 

Flanged Tree 

Connection 

Halliburton the industry’s premier provider of this type of 

equipment and services. For more detailed information, 

please contact your local Halliburton representative. 

Options: 


Dual (Manual or Hydraulic) 


Triple (Manual or Hydraulic) 

Slickline Grease Head 

Liquid Chamber 

Dual Wireline Valve 


Triple Wireline Valve 



HAL22755 

HAL22756 

HAL22754 

HAL22753

Advanced ® Slickline Services 

Highly developed measurement and innovative downhole 

tools provide low-cost slickline solutions for well 

interventions. 

Halliburton Advanced® slickline services let you set and 

retrieve packers, plugs, and monobore flow controls, and 

perforate, cut casing, and tubing–all with depth accuracy 

comparable to electric line with the efficiency of slickline. 

Halliburton’s innovative slickline technology produces depth 

measurements so accurate you can now use slickline 

procedures for many services traditionally reserved for 

electric line operations. Procedure for procedure, when 

compared to electric line, Halliburton's new slickline 

technology substantially lowers your total cost. 

Key developments make this revolutionary advance in 

slickline utility possible: 

An advanced measurement system that makes slickline 

depth readings comparable to electric line depth 

readings 

A slickline collar locator that pinpoints tubing or casing 

collars 

A downhole power unit that eliminates the need for 

explosives to set packers and plugs 

An electronic triggering device that fires perforating and 

cutting charges 

A data/job logger that produces real-time slickline collar 

logs or customer job summary 

A wire inspection device that detects abnormalities in 

slickline to facilitate wire management and reduce 

premature failures 

Unprecedented Slickline Accuracy 

Halliburton's Advanced Measurement System (AMS) uses 

microprocessor technology to take the guesswork out of 

slickline depth measurements. Yes, we still count wheel turns. 

But, the processor not only counts wheel turns, it also 

instantly and continuously adjusts for the effect of ambient 

temperature on counter wheel size and for tension-caused 

line stretch measured with an electronic load sensor. Depth, 

tension, and line speed are logged and a hard copy printed in 

real time, guiding the operator and providing a permanent 

job record. 

Correlate to the Original Log to Identify Collar Locations 

Halliburton's exclusive slickline collar locator further 

enhances data accuracy. As it passes a tubing or casing collar, 

it increases line tension. The tension spikes are recorded in 

real time on the permanent job log so the operator always 

knows the precise tool location in relation to the tubing or 

casing collars. 

Set Packers and Plugs Without Explosives 

The remarkable Halliburton DPU® downhole power unit 

eliminates the need to use explosive charges to set packers 

and plugs. The slow controlled force provided by an 

electromechanical powertrain improves setting 

performance for downhole equipment, such as packers, 

where improved element compression and a more uniform 

slip set are obtained. 


CollarTrak ® 

Slickline Collar 

Locator 

DPU ® 

Downhole 

Power Unit 

LineTrak ® Inspection Device 

Bridge Plug 

SmartETD ® 

System 

JobTrak ® 

Data Logger 

Advanced ® 

Slickline 

Service Unit 

Perforating Gun 

Advanced® Slickline Service Tools 

Advanced Measuring System (AMS) 

Memory Production Logging 

CCL/Gamma Ray 

Pressure 

Temperature 

Capacitance Water Holdup 

Filled Density (Differential Pressure) 

Fullbore Spinner and Continuous 

Monolock ® Plug Packer Perforator 

Slickline Service Equipment 7-17

Perforating and Cutting Services Performed with Slickline 

The Halliburton electronic triggering device employs 

slickline to run and fire perforating and cutting charges when 

explosives are a requirement. The triggering device also can 

be used to fire explosive-activated tools used to set plugs and 

packers. The device's redundant safety system prevents 

premature firing. 

Produce a Permanent Job Record 

Data recorded through the job logger can either be a printed 

hardcopy or stored to floppy disc as a permanent well file. 

The data can also be merged with data from downhole 

memory tool surveys to produce API quality production well 

logs for diagnostic or flow analysis. 

Even More Built in Reliability 

Halliburton's new wire inspection device and wire 

management software has prevented fishing trips and has 

greatly reduced lost production time caused by slickline 

failure. The device can be used for periodic electronic 

inspection to detect line abnormalities. 

The wire management software tracks wire usage and 

provides a permanent record of each line's job history, when 

utilizing AMS. The software provides a basis for predicting 

wire failures due to normal, job-related stresses, and 

exposure to hostile well environments. 

The state-of-the-art Advanced® slickline service system 

offered by Halliburton provides the most efficient means for 

precise depth correlation, setting plugs and packers, 

perforating, and producing high quality memory production 

logs. 

Advanced ® Slickline Service System 

This system provides services traditionally performed by 

e-line services, but with slickline. 

Save With Halliburton Advanced Slickline Services 

You can substantially save on your electric line costs for 

comparable services with Halliburton's Advanced slickline 

technology. And the Halliburton wire inspection device in 

conjunction with wire management software can cut the 

costs of traditional slickline services by significantly reducing 

the potential for line breaks. 


DPU ® Downhole Power Unit 

Halliburton’s DPU® downhole power unit is an electromechanical 

downhole electric power supply device that 

produces a linear force for setting packers using downhole 

electric power. The tool is self-contained with a battery unit 

and an electrical timer to start the setting operation. The unit 

consists of three functioning sections: the pressure sensing 

actuator, the power source, and the linear drive section. 

The slickline version of the DPU unit uses batteries to 

provide the energy to the motor and timing circuits. An 

electric line version without the timer, circuits, and batteries 

is also available. 

Note: Both slickline and e-line DPU units include conversion 

kits to allow the use of existing Baker setting adapter kits. 

The DPU unit and attached subsurface device are run into 

the well on slickline or braided line. The timer initiates the 

operation. The setting motion is gradual and controlled 

(about 0.7 in./min) allowing the sealing element to conform 

against the casing/tubing wall and the slips to fully engage. 

The controlled setting motion allows the sealing element to 

be fully compressed. Once the setting force is reached, the 

DPU unit shears loose from the subsurface device and is free 

for removal from the well. The DPU unit is designed to help 

set and allow for dependable operation of downhole flow 

control devices, reduce well completion costs, and improve 

safety at the wellsite. 

Applications 

Sets and Retrieves: 

Packers 

Bridge plugs 

Whipstocks 

Monolock® devices 

Subsea tree plugs 

Sets: 

Cement retainers 

Sump packers 

HE3® retrievable bridge plugs 

BB wireline-retrievable packers 

Perforates: 

Tubing 

Casing 

Shifts: 

Sliding Side-Door® circulation/production devices 

Internal control valves 

Releasing mechanisms/sleeves 


HAL14000 

DPU® Downhole 

Power Unit

Features 

Equipped with a timer/accelerometer/pressure actuation 

system to ensure tool setting at the proper time and 

depth 

Batteries for self-contained operation 

Slickline, e-line, or coiled tubing operation 

Sets and retrieves tools with optimal setting force 

Reduced cost for setting packers and bridge plugs using 

traditional electric line 

Non-explosive operation improves safety 

Eliminates need for electric wireline 

Dependable operation 

Positive setting of slips and elements 

Optimized operating speed 


Max OD 

in. (mm) 

1.70 

(43.2) 

2.51 

(63.75) 

3.59 

(91.19) 

Max OD 

in. (mm) 

1.70 

(43.2) 

2.51 

(63.75) 

3.81 

(96.77) 

Max Shear 

Force 

lbf (N) 

15,000 

(66 720) 

30,000 

(133 440) 

50,000 

(222 400) 

60,000 

(266 880) 

Max Shear 

Force 

lbf (N) 

15,000 

(66 720) 

30,000 

(133 440) 

60,000 

(266 880) 

Slickline DPU ® System Specifications 

Voltage Amps 

27 2 

36 4 

30 5 

48 2 

Max 

Temperature 

°F (°C) 

300 

(148) 

300 

(148) 

250 

(121) 

329 

(165) 

E-Line DPU System Specifications 

Voltage Amps 

50 0.6 

115 0.6 

200 0.75 

Max 

Temperature 

°F (°C) 

400 

(204) 

400 

(204) 

400 

(204) 

Max Pressure 

psi (bar) 

15,000 

(1034.5) 

15,000 

(1034.5) 

10,000 

(689.4) 

10,000 

(689.4) 

Max Pressure 

psi (bar) 

15,000 

(1034.5) 

15,000 

(1034.5) 

20,000 

(1378) 

Max Effective 

Stroke 

in. (mm) 

9 

(229) 

8.5 

(216) 

36 

(914) 

8.75 

(222) 

Max Effective 

Stroke 

in. (mm) 

9 

(229) 

8.5 

(216) 

8.75 

(222) 


DPU ® Tubing Punch 

The DPU® tubing punch can help cut your costs for 

perforating the tubing. Coupled with the Monolock® 

plugging device, the DPU tubing punch provides an effective 

and dependable solution for well (kill) workover operations. 

Features 

Can reduce the cost for perforating tubing 

Reduces rig time by minimizing misruns with other 

mechanical perforators 

No extensive jarring to achieve a hole 

Eliminates the need for electric wireline and an explosive 

soft shot perforating service. The DPU tubing punch can 

be run on slickline, braided line, or coiled tubing. This 

means it offers the economy of slickline and the 

versatility to meet operational requirements 

Improves safety with its non-explosive operation by 

eliminating transportation and handling of explosives 

and by not requiring explosive-trained personnel 

Offers proven, dependable operation of the punch 

Equipped with a timer/accelerometer/pressure actuation 

system for precise control 

HAL23160 


HAL23161

Size 

in. (mm) 

2.50 

(64) 

3.66 

(93) 

1.69 

(43) 

CollarTrak ® Slickline Collar Locator 

The Halliburton CollarTrak® slickline collar locator consists 

of a standard electric line collar locator, an electronic subassembly, 

and a magnet/drag sub-assembly. When the collar 

locator senses a tubing or casing collar, it signals the 

electronic sub-assembly, which instantaneously activates 

magnets in the magnet/drag assembly. The magnets increase 

frictional engagement to the pipe wall, creating a brief but 

significant increase in line tension. 

Halliburton's advanced measurement system detects the 

tension increase and sends the data signals to the data/job 

logger, which records it as a well-defined spike on the log. 

The advanced measurement system automatically and 

continuously compensates for line stretch, assuring 

log accuracy. 

The tool, which is powered by alkaline batteries, locates 

collars in up to 13 chrome pipe and in flush-joint tubing. 

Tubing 

or 

Casing 

Size in. 

3 1/2- 

41/2 

5 1/2- 

7 5/8 

2 3/8- 

2 7/8 

Max OD 

Magnets 

Collapsed 

in. (mm) 

2.50 

(64) 

3.66 

(93) 

1.69 

(43) 

CollarTrak® Slickline Collar Locator 

Slickline Collar Locator (SLCL) (with Power Pack) Specifications 

Max OD 

Magnets 

Expanded 

in. (mm) 

3.85 

(98) 

5.50 

(140) 

3.06 

(77) 

All sizes are alloy material and have three magnets. 

Optional 

Larger 

Magnet 

Housing 

Max OD Larger 

Magnet Housing 

Collapsed 

in. (mm) 


HAL8887 

Max OD Larger 

Magnet Housing 

Expanded 

in. (mm) 

Max 

Operating 

Pressure 

psi 

Max 

Operating 

Temp. 

°F 

No N/A N/A 15,000 300 

Yes 

5.70 

(145) 

7.50 

(191) 

10,000 250 

No N/A N/A 15,000 300 

Overall 

Length 

in. (mm) 

95.3 

(2.421) 

69.8 

(1.773) 

34.12 

(.86) 

Power 

Source 

“AA” size 

Batteries 

“C” size 

Batteries 

“AA” size 

Batteries 

Top 

Connection 

1 5/16-in. - 

10UNS pin 

1 1/16 in. - 

10UNS pin 

1 5/16 in. - 

10UNS pin 

Bottom Tool 

Connection 

1 5/16-in. - 

10UNS box 

1 1/16 - 

10UNS box 

15/16 in. - 

10UNS box

HAL8356 

Electronic Depth 

Measurement System 

Combination Depth Counter 

and Line Tension Sensors 

(Input to Electronic Depth 

Measurement System) 

Slickline 

Collar 

Locator 

Downhole 

Power Unit 

Slickline Collar 

Log 

Bridge 

Plug or 

packer 

Slickline Service Unit 

Data/Job Logger 

(Portable) 


Halliburton Job Logger 

JOB ENDED ( DATE: May, 02 1995 TIME: 15:04:39 ) 

MAXIMUM ( DEPTH: 1352.5 m TENSION : 123 DNs LINE SPEED : 238.8 m/min 

) 

COMMENTS : TOOL BOX SAFETY MEETING 

RIH FLOWING DUMMY AT 1353M. 

RIH FLOWING SURVEY MAKE 5 MIN STOP 250M 423M 453M 746M 

766M 984M 1104M 1152M 1172M 1282M 1302 1343M 15MIN STOP 

CASSING PRESS 4000KPA 

6100 

6200 

6000 

Line Speed 

Casing 

Collar 

Location

Advanced Measurement System (AMS) 

The electronic advanced measurement system (AMS) 

measures tension and depth, compensates for wire stretch 

and temperature effects on the measuring wheel, and reports 

a corrected depth reading. This model of the AMS system is 

designed to be mounted inside a wireline operator cabin. 

Other features also help improve the quality of a service job. 

A differential load indicator indicates small changes in 

pickup weight. Digital displays can be switched between 

English and metric measurements at any time. The 

approaching surface alarm warns the operator as the tools 

near the surface. The excessive tension function works with 

the hydraulic system to limit the maximum line tension to an 

adjustable preset value. The system allows the operator to 

input a “rig-up angle” for accurate line tension readings. 

When used with a Halliburton two-wheel counter with a 

“universal” measuring wheel, the AMS gives accurate depth 

readings for any size wire, in English or metric, without 

changing wheels. 

This model has digital and analog displays with switch input 

controls and RS-232 output for data acquisition with a 

laptop computer. 

Panel AMS will not work with IS (Class 1 Division 2) 

counter. This system requires an electronic strain gauge load 

sensor and an optical encoder. 

Standard Mounted Equipment 

Automatic depth adjustment 

Line tension adjustment 

Depth offset adjustment 

Ambient temperature correction 

Analog line tension display 

Analog differential line tension display 

Digital line tension display 

Digital line depth display 

Digital line speed display 

RS-232 serial port output for corrected depth, line speed, 

line tension, units of measurement, and time 

Advanced Measurement System 


HAL8890

Electronic Advanced Measurement System (Portable) 

This portable model has a flat screen display, keypad 

functional inputs, and extended RAM for data storage. 

A RS-232 serial port is provided for real-time data retrieval. 

This system requires an electronic strain gauge, load sensor, 

and an optical encoder. The portable unit is available for 

standard and hazardous Class I Division 2 operation. 

Standard Portable Model Equipment 

Automatic depth adjustment 

Line tension adjustment 

Integrated AMS Advanced Measurement System 

Depth offset adjustment 

Ambient temperature correction for counter wheel 

Analog line tension display 

Analog differential analog line tension display 

Digital line tension display 

Digital line depth display 

Digital line speed display 

RS-232 serial port output for corrected depth, line speed, 

line tension, units of measurement, and time 


SmartETD ® System 

The Halliburton SmartETD® system is an advanced 

electronic triggering device that provides an accurate, safe, 

and reliable method to run and fire downhole explosive tools 

using slickline. With its built-in sensor and memory 

capabilities, it can record and store downhole temperature 

and pressure data that can be used by the slickline specialists 

to program firing parameters. 

The SmartETD tool requires four parameters to be met prior 

to firing. These are time, motion, pressure, and temperature. 

The timing sequence begins when the tool is exposed to 

pressure. After the tool stops, any motion resets the 

electronic timer. After the SmartETD timer has remained 

motionless for a specific period of time and has 

simultaneously encountered the preset temperature and 

pressure windows, it initiates the firing sequence. 

The SmartETD tool will fire the Halliburton RED® 

rig environment detonator, as well as API RP-67-compliant 

devices. 

No-Blow, No Drop 

Assembly 

Top Shock/Centralizer 

Quick Lock Assembly 

® 

SmartETD Tool 

HV Shooting Module 

Adapter 

Selectable Mechanical 

Pressure Switch 

Shock Absorber 

Detonator 

Sub/Explosives 

as required with 

STD 1 3/8-in. GO 

Connection 

® 

VannGun Assembly 


HAL15398 

SmartETD® System

JobTrak ® Data Job Logger 

The JobTrak® data job logger is used with the Halliburton 

advanced measurement system to produce summary logs 

that provide a real-time plot of depth, line speed, and line 

tension. The data logger consists of a portable computer and 

thermal printer packaged in a heavy-duty carrying case. It is 

connected to the AMS system through a RS-232 port, and the 

computer is programmed to convert the AMS data to 

graphical form. The data logger can be powered using 12 to 

30 volts DC or 110 to 240 volts AC. 

HAL8322 

JobTrak® Data Job Logger 

Standard Mounted Equipment 

Temperature rating: -10° to 110°F 

Power supply: 12-30 VDC or 110-240 VAC 

Maximum line speed: 3,000 ft/min (914 m/min) 

Maximum line tension: 5,000 lb (2267 kg) 

Plot units per hour settings: 4 in./hr or 8 in./hr 

(10 cm/hr or 20 cm/hr) 


Memory Production Logging (MPL) Service 

Halliburton’s memory production logging service provides 

solutions to production problems with accurate flow profiles 

and downhole diagnostics. Logging data is stored in 

downhole memory and played back on location after the 

tools are retrieved from the well. MPL can be used in 

producing and injecting wells with single- or multi-phase 

flow regimes. 

Features 

Economical in hostile environments – Using slickline 

minimizes the risk in CO2 , H2S, or high-pressure 

environments. Slickline wellhead pressure control 

equipment simplifies rig up and operates safely and 

efficiently in demanding conditions 

Proven in horizontal applications – MPL is deployable 

on coiled tubing for highly deviated or horizontal wells 

Reduced rig space requirements – Small footprint and 

low weight make MPL ideal for small production 

platforms and mono-pod completions. MPL also 

requires less surface equipment and crane height than 

electric line services 

HAL964 

This memory production log was obtained for an operator looking to 

cut high water production in a formation with a three-phase downhole 

flow regime. The MPL service captures logging data on a memory 

recorder. The data is equal to data obtained with electric line services. 

HAL965 

Helicopter portable – MPL can be run with existing 

slickline equipment, avoiding the cost of mobilizing a 

logging unit 

Proven reliability and resolution of electric line tools – 

MPL string uses the same sensors as the standard electric 

line tools to deliver the same accuracy and highresolution 

data 

Exclusive depth indicators ensure depth accuracy – AMS 

advanced slickline depth measurement system or 

slickline collar locator provides accurate depth control 

for the MPL string, eliminating misruns and saving 

valuable rig time 

Tool strings customized to meet well requirements – All 

services can be run with a 1 second sample rate, allowing 

approximately 18 hours of logging time. Sample rates as 

high as 0.2 seconds can be selected for increased data 

density and higher resolution 

Computing center analysis of the MPL data reveals that the bottom set 

of perforations is producing mostly water and only 2% of the total oil 

production and 6% of the gas. Remedial work to plug off the bottom 

zone should decrease water production and reduce water disposal costs 

without greatly affecting hydrocarbon production. 


Battery and 

Memory Recorder 


Casing Collar 

Locator 

Gamma Ray 


Fluid Density 

Differential 

Pressure 

Capacitance 

Water Holdup 


Temperature 

Caged Fullbore 

Spinner 

HAL966 

Memory Production Logging Service 

Tool Description 

Battery Housing 

Memory Tool 


Casing Collar Locator 

Gamma Ray 

Capacitance Water Holdup 

Temperature 

Fluid Density Differential Pressure 

Caged Fullbore 

Continuous 


Knuckle Joint 

Services 

Spinners 

Accessories 

Max. Tool OD 

in. (mm) Tool Length in. (m) 


1.687 

(43) 

1.68 

(43) 

1.68 

(43) 

1.687 

(43) 

1.687 

(43) 

1.687 

(43) 

1.687 

(43) 

1.687 

(43) 

1.687 

(43) 

1.687 

(43) 

1.687 

(43) 

1.687 

(43) 

All tools are rated to 350°F (177°C) and 15,000 psi (103 400 kPa) 

18 

(0.46) 

19.5 

(0.50) 

12.1 

(0.31) 

18.5 

(0.47) 

26.6 

(0.68) 

26.2 

(0.67) 

11.5 

(0.29) 

47 

(1.19) 

34.1 

(0.87) 

24 

(0.61) 

23 

(0.58) 

6.1 

(0.15)

LineTrak ® Slickline Inspection Device and Wire Management Program 

The Halliburton LineTrak® slickline 

inspection device spots problems that 

simply would be impossible for even a 

veteran slickline technician to detect. 

The device is used to provide 

continuous inspection of the entire line 

—not just selected areas and provides 

inspection of both in-service lines as 

well as new lines as it is spooled. 

Wire Management Program 

In addition to periodic inspections for 

line abnormalities, a permanent record 

of each line’s job history, when utilizing 

Halliburton’s AMS advanced 

measurement system and the JobTrak® 

data logger, provide a basis for 

predicting line failures due to normal 

job-related stresses and exposure to 

hostile well environments. 

Wire inspections have become an 

integral component of Halliburton’s 

extensive Wire Management 

Program—a program designed to 

prevent on-the-job failures. 

The LineTrak slickline inspection 

device spots problems before they cause 

downhole line failure. The following 

are examples of problems detected by 

the LineTrak device. 

This 0.021-in. deep crack (100x magnification) 

was detected in a nickel alloy wire with 

1,850 cycles. 

Damage on left was detected at 462 ft and on 

right at 368 ft (arrow points to pit on wire) on a 

nickel alloy wire. 

Abrasion damage on this cobalt alloy wire was 

detected before it could cause wire separation. 


During inspection, the slickline travels through a coil 

matched to its size. A high-frequency, low-power alternating 

current running through the coil produces an alternating 

magnetic field which generates an electric current, or eddy 

current, in the slickline. Any changes or discontinuities in the 

slickline’s conductivity affects the eddy current, changing the 

coil’s impedance. The inspection device detects the 

impedance change. 

Pass-fail criteria are based on notched reference wires. 

Impedance changes that exceed the established limits identify 

line sections that require more detailed inspection or cause a 

line to be taken out of service. 

Although the LineTrak® inspection device cannot guarantee 

you will never have another parted line, it can minimize the 

chances of a line failure causing a fishing job in your well. 

Wire Management Program Features 

Proprietary software developed from extensive empirical 

cycle fatigue test data and field testing 

Utility application in AMS system 

Extends wireline life 

Minimizes premature line failure 

User friendly interface 

Tracks wire usage and length 

Provides graph of used life of line 

Discontinuities 


Coil 

AC 

Generator/Indicator 

Magnetic 

Field 

Slickline 

Direction 

of Movement 

Inspection System Using Self-Comparison Differential Coils 

Wire Management Program

Deepwater Riserless Subsea Light Well 

Intervention System 

The Halliburton deepwater riserless subsea light well 

intervention system offers complete well intervention 

solutions. 

Features 

Reduced well intervention costs on subsea wells 

No workover riser during operation 

Deepwater Riserless Intervention System 

System can be operated from a more cost-effective 

intervention DP vessel 

Ideal intervention method on deepwater wells 

Increases subsea well availability 

Reduced chance of damage resident pipelines and 

structures 



Mobilization 

LOGIQ Logging Truck 

LOGIQ logging trucks are an evolution in onshore logging 

technology. The trucks are designed to operate all of the new 

evolution tools at well depths of up to 27,000 ft in single 

drum (open-hole) or dual drum (open and cased-hole) 

configuration. The latest state-of-the-art technology and 

engineering design make the truck and computer system a 

platform that can be upgraded as technology evolves. 

Logging Cabin Features 

Exterior 

– Material – 1/8-in. aluminum 

– Construction – welded aluminum 

– Insulation – 2-in. urethane foam 

– Entrance(s) – single door 

Interior 

– Material – brushed anodized aluminum skin 

– Console – winch operator console for depth 

panel, engine, and generator panel 

– Window – one large sliding window facing reel 

and frame assembly 

LOGIQ Logging Truck 

Truck Chassis and Engine Specifications 

Power Distribution Panel 

– Power type – 110V and 220V sockets 

– Direct Lights – 110V and 12V direct lights 

– Floodlights – 110V, 500W quartz 

– Air Conditioners – four DuoTherm; 13,500 BTU/ 

5,600 BTU heating for each 

– Intercom – 3M Model D-15 

Curbside Tool Racks (with airbags) 

– Top – four, 2-in. diameter tools, maximum length 

92 in. (233.7 cm) 

– Middle, Lower – holds two, 4-in. diameter tools, 

maximum length 98 in. (249 cm) 

Roadside Tool Racks (with airbags) 

– Top – four, 2-in. diameter tools, maximum length 

88 in. (223.5 cm) 

– Middle, Lower – holds two, 4-in. diameter tools, 

maximum length 136 in. (345.4 cm) 

Underbelly Tool Rack 

– Holds four, 5-in. diameter tools and two, 4-in. 

diameter tools; maximum length 22 ft (6.7 m) 

with pneumatic tool retainers 

Make/Model Height Width Length Wheel Base Cab to Axle Engine Model Horsepower Fuel Tanks 

Kenworth 

T-800 6X4 

13 ft, 2 in. 

(4.01 m) 

7 ft, 11 in. 

(2.41 m) 

38 ft, 4 in. 

(11.68 m) 

24 ft, 6 in. 

(8.86 m) 

16 ft 

(4.87 m) 

Caterpillar 

Cat-13 

380 hp at 

2100 RPM 

Two 24.5-in. 

diameter aluminum, 

cap: 110 and 50 USG 

Mobilization 8-1 

Mobilization

Winch Specifications 

Two-speed transmission, speeds from 55,000 ft/hour 

down to 360 ft/hour with an enhanced low speed option 

down to 50 ft per hour. 

Single speed transmission cased-hole drum with speeds 

up to 52,000 ft/hour and down to 360 ft/hour with an 

enhanced slow speed option down to 50 ft/hour 

Rexroth AA4VG pumps and AA6V motors with 

electronic controls 

Large drum capable of holding 25,500 of 0.490-in. 

heptacable slammer cable or 28,500 ft of 0.472-in. 

heptacable slammer. Small drum capable of holding 

22,500 ft of 5/16 single conductor cable or 28,500 ft of 

7/32 single conductor cable. 

Satellite dish and communications optional 

8-2 Mobilization

LOGIQ Modular Skid Unit 

The LOGIQ DNV 2.7.1 certified logging skids are an 

evolution in offshore logging technology. The three-piece 

modular skids are designed to operate the most complex 

logging jobs in the harshest offshore and land environments. 

The three-module design allows for the three modules to 

operate together or separate changing the footprint of the 

skid to better match the space available. 

LOGIQ Modular Skid Unit 

Setup times are greatly reduced because of the slewing 

mechanism of the winch module and service multiple wells 

as well. It will run all of the new evolution tools at well depths 

of up to 27,000 ft, in single drum (open-hole) or dual drum 

(open and cased-hole) configuration. The latest state-of-theart 

technology and engineering design make the skid and 

computer system a platform that can be upgraded as 

technology evolves. 

Mobilization 8-3

Cabin Module 

The cabin module unit can be transported as a single DNV 

2.7.1 certified lift. The unit has entry doors on both sides, 

and cooling and heating is provided by four units. The 

exterior material is 3/16-in. aluminum with 2.0-in. urethane 

foam walls. The cabin is ergonomically designed and holds a 

single or double LOGIQ logging system. The control panel 

includes all functions, such as: gauges for power pack, winch 

controls, generator controls, start/stop, pump controls, and 

an integrated touch screen depth panel. 

Length 

in. (m) 

136 

(3.45) 

Cabin Module Specifications 

Height 

in. (m) 

113 

(2.87) 

Width 

in. (m) 

96 

(2.44) 

Cabin Module 

Weight 

lb (kg) 

11,350 

(5148) 

8-4 Mobilization

Winch Module 

The winch module unit can be transported as a single DNV 

2.7.1 certified lift. It has interchangeable reels for open-hole 

and cased-hole purposes. Both have maximum slew rate 

angles of up to ± 12°. The open-hole reel has a two-speed 

direct drive transmission. Speeds vary from 55,000 ft/hour 

down to 360 ft/hour with an enhanced low speed option 

down to 50 ft/hour. 

The cased-hole reel has a single speed direct drive 

transmission with speeds up to 52,000 ft/hour and down to 

360 ft/hour with an enhanced slow speed option down to 

50 ft/hour. 

It also features a Rexroth 90 cc pump and 80 cc motors with 

electronic controls. 

The unit includes a large drum capable of holding 25,500 ft 

of 0.490-in. heptacable slammer cable or 28,500 ft of 

0.472-in. heptacable slammer. The small drum is capable of 

holding 22,500 ft of 5/16 single conductor cable or 28,500 ft 

of 7/32 single conductor cable. 

Satellite dish and communications optional 

Length 

in. (m) 

72 

(1.83) 

Height 

in. (m) 

113 

(2.87) 

Winch Module Specifications 

Width 

in. (m) 

96 

(2.44) 

Winch Module 

Weight 

lb (kg) Certification 

25,200 

(11 455) 

DNV 2.7.1 / 

EN12079 certified 

Mobilization 8-5

Power Pack 

The power pack unit can be transported as a single DNV 

2.7.1 certified lift. Its main component is the Caterpillar 3126 

EURO-3 engine with 230 hp. It runs the hydraulic pumps for 

the winch and 30 kW hydraulic generator and other auxiliary 

hydraulic controls. All electrical and hydraulic connections 

are quick change so set up time is minimal. All service access 

points are easy to reach. The power pack unit has an enclosed 

pollution drip pan with easy access drain plugs. It also 

includes air-start with standard rig air connections. 

Length 

in. (m) 

60 

(1.52) 

Power Pack Module Specifications 

Height 

in. (m) 

113 

(2.87) 

Width 

in. (m) 

Power Pack Module 

Weight 

lb (kg) 

8-6 Mobilization 

96 

(2.44) 

7,150 

(3250)

Mnemonics 

Mnemonic: Refers to the Curve Mnemonic - LIS / DLIS 

Unit: Refers to the Engineering Units—LIS Eng / Metric; DLIS Eng / Metric 

Tool: Refers to the logging tool for the curve. 

Description: 

Described the recorded Curve 

Serv_Name: Refers to the General Service (combined tools) 

Refers to the Data format classification and processing status 

Type_Data: 

RES = Result curve 

INP = Processed Input data 

TEL = Telemetry with some processing applied 

This is a generalized listing of current supported tools and is not intended to include older tools, 

software versions or data systems. Dual detector tools may utilize either N or 1 to distinguish 

Near detector and F or 2 to distinguish Far detector. 

Mnemonics 9-1 

Mnemonics

Wireline and Perforating Services Mnemonics 

Serv_Name 

LIS 

Mnem 

LISU_ 

eng 

LISU_ 

met Description Mnem 

DLISU_ 

Eng 

DLISU_ 

Met 

ACRT - ARRAY COMP TRUE RES HRM2 RT RESISTIVITY MAP - TWO FOOT HRM2 RES 

ACRT - ARRAY COMP TRUE RES RMAN RIGHT MANDREL RMAN RES 

ACRT - ARRAY COMP TRUE RES RF90 OHMM OHMM 90 IN RADIAL RESISTIVITY 4FT RF90 ohm.m ohm.m RES 





ACRT - ARRAY COMP TRUE RES RF06 OHMM OHMM 6 IN RADIAL RESISTIVITY 4 FT RF06 ohm.m ohm.m RES 

ACRT - ARRAY COMP TRUE RES LSO LEFT STANDOFF LSO RES 

ACRT - ARRAY COMP TRUE RES LMAN LEFT MANDREL LMAN RES 

ACRT - ARRAY COMP TRUE RES CO60 MMHO MMHO 60 IN RADIAL CONDUCTIVITY 1FT CO60 0.001/ohm 0.001/ohm RES 

ACRT - ARRAY COMP TRUE RES HRM4 RT RESISTIVITY MAP - FOUR FOOT HRM4 RES 

ACRT - ARRAY COMP TRUE RES RO20 OHMM OHMM 20 IN RADIAL RESISTIVITY 1 FT RO20 ohm.m ohm.m RES 

ACRT - ARRAY COMP TRUE RES HRM1 RT RESISTIVITY MAP - ONE FOOT HRM1 RES 

ACRT - ARRAY COMP TRUE RES ECC ECCENTRICITY ECC RES 

ACRT - ARRAY COMP TRUE RES D2 IN IN OUTER RADIAL DEPTH OF INVASION D2 in IN RES 

ACRT - ARRAY COMP TRUE RES D1 IN MM INNER RADIAL DEPTH OF INVASION D1 in mm RES 

ACRT - ARRAY COMP TRUE RES DI IN MM RADIAL DEPTH OF INVASION DI in mm RES 

ACRT - ARRAY COMP TRUE RES CT90 MMHO MMHO 90 IN RADIAL CONDUCTIVITY 2FT CT90 0.001/ohm 0.001/ohm RES 





ACRT - ARRAY COMP TRUE RES INCL INCLINATION INCL RES 

ACRT - ARRAY COMP TRUE RES RT60 OHMM OHMM 60 IN RADIAL RESISTIVITY 2 FT RT60 ohm.m ohm.m RES 

ACRT - ARRAY COMP TRUE RES TMPF TEMPERATURE FEEDPIPE - CALC TMPF RES 

ACRT - ARRAY COMP TRUE RES SED6 MMHO MMHO SKIN EFFECT CORRECTIONS D6 SED6 0.001/ohm 0.001/ohm RES 

ACRT - ARRAY COMP TRUE RES SEU5 MMHO MMHO SKIN EFFECT CORRECTIONS U5 SEU5 0.001/ohm 0.001/ohm RES 





ACRT - ARRAY COMP TRUE RES SMUD OHMM OHMM MUD RESISTIVITY - CALCULATED SMUD ohm.m ohm.m RES 

ACRT - ARRAY COMP TRUE RES RMUD OHMM OHMM MUD RESISTIVITY RMUD ohm.m ohm.m RES 

ACRT - ARRAY COMP TRUE RES RXO/RT OHMM OHMM UNIVADED ZONE RESISTIVITY RXO/RT ohm.m ohm.m RES 








ACRT - ARRAY COMP TRUE RES RT OHMM OHMM TRUE RESISTIVITY UNIVADED ZONE RT ohm.m ohm.m RES 

ACRT - ARRAY COMP TRUE RES RSO RIGHT STANDOFF RSO RES 

9-2 Mnemonics 

Type_ 

Data

Serv_Name 





ACRT - ARRAY COMP TRUE RES RXO OHMM OHMM UNIVADED ZONE RESISTIVITY RXO ohm.m ohm.m RES 

ACRT - ARRAY COMP TRUE RES BCD4 MMHO MMHO BOREHOLE CORRECTIONS D4 BCD4 0.001/ohm 0.001/ohm RES 







ACRT - ARRAY COMP TRUE RES CALU IN IN CAL DIAMETER USED CALU in IN RES 

ACRT - ARRAY COMP TRUE RES CDIA IN IN CALCULATED DIAMETER CDIA in IN RES 

ACRT - ARRAY COMP TRUE RES CF10 MMHO MMHO 10 IN RADIAL CONDUCTIVITY 4FT CF10 0.001/ohm 0.001/ohm RES 







ACRT - ARRAY COMP TRUE RES ACCZ ACCELEROMETER Z ACCZ RES 




BCDT/BSAT/BCS/CBL - BH 

COMP ARRAY SONIC 































LIS 

Mnem 

LISU_ 

eng 

LISU_ 


DLISU_ 

Eng 

DLISU_ 

Met 

TT22 TT_T2R2 TT22 INP 

ALPH ALPHA ALPHA INP 

TT2 US US FAR TRAVEL TIME TT2 uS uS RES 

DT2 US/F US/M DELTA - TIME TRANSMITTER 2 DT2 uS/ft US/M RES 

TT12 UPPER XMTR TRAVEL TIME TT_T1R2 TT12 INP 

TT11 UPPER XMTR TRAVEL TIME TT_T1R1 TT11 INP 

TT21 TT_T2R1 TT21 INP 

AMPL DB DB AMPLITUDE AMPL dB dB RES 

AMP MV MV CBL - PIPE AMPLITUDE AMP mv mv RES 

DT1 US/F US/M DELTA - TIME TRANSMITTER 1 DT1 uS/ft US/M RES 

FRMC TOOL FRAME COUNT FRMC RES 

TT US/F US/M CBL - PIPE TRAVEL TIME TT uS/ft US/M RES 

TT1 US US NEAR TRAVEL TIME TT1 uS uS RES 

WFFW WAVEFORM - ALL WFFW INP 

ITTT INTEGRATED TRAVEL TIME TOTAL ITTT RES 

WMSG WAVEFORM - MSG WMSG INP 

Mnemonics 9-3 

Type_ 

Data

Serv_Name 



































LIS 

Mnem 

LISU_ 

eng 

LISU_ 


DLISU_ 

Eng 

DLISU_ 

Met 

BI CBL - BOND INDEX BI RES 

ITT INTEGRATED TRAVEL TIME MARK ITT RES 

DT US/F US/M DELTA TIME COMPRESSIVE DT uS/ft US/M RES 

DTRC DELTA T AT RECEIVER DT_RCV INP 

DTUN DELTA T UNFILTERED DT_UNF INP 

DTXM DELTA T AT TRANSMITTER DT_XMT INP 

ERR ERROR ERROR INP 

FNOI FAR RECEIVER NOISE FNOISE INP 

GFAR FAR RECEIVER GAIN GAIN_F INP 

MSGR MSG RECEIVER MSGRCV INP 

GNEA NEAR RECEIVER GAIN GAIN_N INP 

SPHI DECP DECP SONIC POROSITY SPHI 100 pu 100 pu RES 

MSGG MSG GAIN MSGGAI INP 

NNOI NEAR RECEIVER NOISE NNOISE INP 

PKCD PICK CODE PKCODE INP 

QDT DELTA TIME QUALITY QDT RES 

SDT2 US/F US/M DELTA T (2 FOOT) SDT2 uS/ft US/M RES 

BHPT - BORE HOLE PROP TOOL FLWT LBS/G K/M3 FLUID WEIGHT FLWT LBS/G Kg/m3 RES 

BHPT - BORE HOLE PROP TOOL DTEM DEGF DEGC DIFFERENTIAL TEMPERATURE DTEM degF degC RES 

BHPT - BORE HOLE PROP TOOL DPRS PSIA KPA DIFFERENTIAL PRESSURE DPRS PSIA Kpa RES 

BHPT - BORE HOLE PROP TOOL PRES PSIA KPA BOREHOLE PRESSURE BHPRES PSIA Kpa RES 

BHPT - BORE HOLE PROP TOOL PXIT DEGF DEGC PRESSURE XDCR INTERNAL TEMP PXIT degF degC RES 

BHPT - BORE HOLE PROP TOOL PTMP DEGF DEGC PROBE INTERNAL TEMP PTMP degF degC RES 

BHPT - BORE HOLE PROP TOOL RES OHM-M OHM-M BOREHOLE RESISTIVITY BHRES OHM-M OHM-M RES 

BHPT - BORE HOLE PROP TOOL TEMP DEGF DEGC BOREHOLE TEMPERATURE BHTEMP degF degC RES 

CALIPER - 2 ARM AHVT FT3 M3 ANNULAR VOLUME TOTAL AHVT ft3 m3 RES 

CALIPER - 2 ARM BHV FT3 M3 BORE HOLE VOLUME MARK BHV ft3 m3 RES 

CALIPER - 2 ARM BHVT FT3 M3 BOREHOLE VOLUME TOTAL BHVT ft3 m3 RES 

CALIPER - 2 ARM CALI IN MM CALIPER CALI in mm RES 

CALIPER - 2 ARM DCAL IN MM DIFFERENTIAL CALIPER DCAL in mm RES 

CALIPER - 2 ARM AHV FT3 M3 ANNULAR VOLUME MARK AHV ft3 m3 RES 

CAST-V - CIRCUM ACOU SCAN AM32 IN MM CALIPER 32 AM32 in mm RES 










9-4 Mnemonics 

Type_ 

Data

Serv_Name 

LIS 

Mnem 

LISU_ 

eng 

LISU_ 


DLISU_ 

Eng 

DLISU_ 

Met 








CAST-V - CIRCUM ACOU SCAN AMMN CAST AMPLITUDE - MINIMUM AMMN RES 

CAST-V - CIRCUM ACOU SCAN AMMX CAST AMPLITUDE - MAXIMUM AMMX RES 

CAST-V - CIRCUM ACOU SCAN AMP CAST AMPLITUDE SCAN AMP RES 

CAST-V - CIRCUM ACOU SCAN AVAM AVERAGE AMPLITUDE AVAM INP 






















CAST-V - CIRCUM ACOU SCAN AVOD AVERAGE CASING OD AVOD RES 



CAST-V - CIRCUM ACOU SCAN THKP THICKNESS PLOT THKP RES 

CAST-V - CIRCUM ACOU SCAN MXID IN MM MAXIMUM INSIDE DIAMETER MXID in mm RES 

CAST-V - CIRCUM ACOU SCAN MXIR IN MM MAXIMUM INSIDE RADIUS MXIR in mm RES 

CAST-V - CIRCUM ACOU SCAN MXTK IN MM MAXIMUM THICKNESS MXTK in mm RES 

CAST-V - CIRCUM ACOU SCAN MXZ MAXIMUM IMPEDENCE MXZ RES 

CAST-V - CIRCUM ACOU SCAN NBS NUMBER OF MISSED SHOTS NBS RES 

CAST-V - CIRCUM ACOU SCAN OVAL OVALITY OVAL RES 

CAST-V - CIRCUM ACOU SCAN PAMP PEAK AMPLITUDE PAMP RES 

CAST-V - CIRCUM ACOU SCAN RADI IN MM CAST RADIUS SCAN RADI in mm RES 

CAST-V - CIRCUM ACOU SCAN RAMN IN MM CAST MINIMUM RADIUS RAMN in mm RES 

CAST-V - CIRCUM ACOU SCAN RAMX INCH INCH CAST MAXIMUM RADIUS RAMX in INCH RES 

CAST-V - CIRCUM ACOU SCAN AVID IN MM AVERAGE INSIDE DIAMETER AVID in mm RES 

CAST-V - CIRCUM ACOU SCAN THET DIRECTION FROM HIGH SIDE THETA RES 

CAST-V - CIRCUM ACOU SCAN MNTK IN MM MINIMUM THICKNESS MNTK in mm RES 

Mnemonics 9-5 

Type_ 

Data

Serv_Name 

LIS 

Mnem 

LISU_ 

eng 

LISU_ 


DLISU_ 

Eng 

DLISU_ 

Met 

CAST-V - CIRCUM ACOU SCAN TT .1 ms .1ms CAST TRANSIT TIME TT .1 ms .1ms RES 

CAST-V - CIRCUM ACOU SCAN VOL1 IMPEDENCE VOLUME 1 VOL1 RES 





CAST-V - CIRCUM ACOU SCAN XO X COORDINATE FROM CENTER XO RES 

CAST-V - CIRCUM ACOU SCAN YO Y COORDINATE FROM CENTER YO RES 

CAST-V - CIRCUM ACOU SCAN ZMUD IMPEDENCE OF BOREHOLE FLUID ZMUD RES 

CAST-V - CIRCUM ACOU SCAN ZP IMPEDENCE PLOT ZP RES 

CAST-V - CIRCUM ACOU SCAN SEQ SCAN SEQUENCE SEQ TEL 

CAST-V - CIRCUM ACOU SCAN GAS GAS FLAG GAS RES 

CAST-V - CIRCUM ACOU SCAN AVIR IN MM AVERAGE INSIDE RADIUS AVIR in mm RES 

CAST-V - CIRCUM ACOU SCAN AVTK IN MM AVERAGE THICKNESS AVTK in mm RES 

CAST-V - CIRCUM ACOU SCAN AVZ AVERAGE IMPEDENCE AVZ RES 

CAST-V - CIRCUM ACOU SCAN BSI BAD SHOT INDEX BSI RES 

CAST-V - CIRCUM ACOU SCAN DIAV IN MM CAST AVERAGE DIAMETER DIAV in mm RES 

CAST-V - CIRCUM ACOU SCAN DIMN IN MM CAST MINIMUM DIAMETER DIMN in mm RES 

CAST-V - CIRCUM ACOU SCAN DIMX IN MM CAST MAXIMUM DIAMETER DIMX in mm RES 

CAST-V - CIRCUM ACOU SCAN DVTH DEVIATION OF THICKNESS DVTK RES 

CAST-V - CIRCUM ACOU SCAN DVZ DEVIATION OF IMPEDENCE DVZ RES 

CAST-V - CIRCUM ACOU SCAN ECTY ECCENTRICITY ECTY RES 

CAST-V - CIRCUM ACOU SCAN MSPD REV XDUCER REVOLUTIONS / SEC MSPD REV INP 

CAST-V - CIRCUM ACOU SCAN FTT US/FT US/M FLUID TRAVEL TIME FTT uS/ft US/M RES 

CAST-V - CIRCUM ACOU SCAN MNZ MINIMUM IMPEDENCE MNZ RES 

CAST-V - CIRCUM ACOU SCAN HIGD IN MM HIGH SCALE FOR DISTANCE HIGHD in mm RES 

CAST-V - CIRCUM ACOU SCAN HIGT IN MM HIGH SCALE FOR THICKNESS HIGHT in mm RES 

CAST-V - CIRCUM ACOU SCAN HRAD IN MM HOLE RADIUS HRAD in mm RES 

CAST-V - CIRCUM ACOU SCAN IDP INNER DIAMETER PLOT IDP RES 

CAST-V - CIRCUM ACOU SCAN IRP INNER RADIUS PLOT IRP RES 

CAST-V - CIRCUM ACOU SCAN LOWD IN MM LOW SCALE FOR DISTANCE LOWD in mm RES 

CAST-V - CIRCUM ACOU SCAN LOWT IN MM LOW SCALE FOR THICKNESS LOWT in mm RES 

CAST-V - CIRCUM ACOU SCAN MDWT GMCC MUD WEIGHT GM/CC MUDWT GMCC RES 

CAST-V - CIRCUM ACOU SCAN MNID IN MM MINIMUM INSIDE DIAMETER MNID in mm RES 

CAST-V - CIRCUM ACOU SCAN MNIR IN MM MINIMUM INSIDE RADIUS MNIR in mm RES 

CAST-V - CIRCUM ACOU SCAN MCNS MUDCELL WAVE NUMB SAMPLES MCNS RES 

CAST-V - CIRCUM ACOU SCAN FREQ KHZ KHZ MEASURED KHZ FREQ 1000 Hz 1000 Hz RES 

CAST-V - CIRCUM ACOU SCAN LWAV LONG WAVEFORM LWAV RES 

CAST-V - CIRCUM ACOU SCAN MZP CALCULTED MUD IMPEDANCE MZP RES 

CAST-V - CIRCUM ACOU SCAN MNCS MINIMUM COMPRESSIVE STRENGTH MNCS RES 

CAST-V - CIRCUM ACOU SCAN MFTT MUDCELL FTT REFLECTION MFTT RES 

CAST-V - CIRCUM ACOU SCAN MDN MUDCELL DENSITY MDN RES 

CAST-V - CIRCUM ACOU SCAN MCSQ MUDCELL SEQUENCE NUMBER MCSQ RES 

CAST-V - CIRCUM ACOU SCAN AVCS AVERAGE COMPRESSIVE STRENGTH AVCS RES 

CAST-V - CIRCUM ACOU SCAN CSP COMPRESSIVE STRENGTH IMAGE CSP RES 

CAST-V - CIRCUM ACOU SCAN AVRA AVERAGE RADIUS AVRA INP 

CAST-V - CIRCUM ACOU SCAN LSTO START TIME LONG WAVEFORM LSTO RES 

CAST-V - CIRCUM ACOU SCAN RB RELATIVE BEARING RB RES 

CAST-V - CIRCUM ACOU SCAN LWNS LONG WAVEFORM NUMB. SAMPLES LWNS RES 

9-6 Mnemonics 

Type_ 

Data

Serv_Name 

CAST-V - CIRCUM ACOU SCAN LWSQ LONG WAVEFORM SEQUENCE NUMBER LWSQ RES 

CAST-V - CIRCUM ACOU SCAN LWNS LONG WAVEFORM NUMB. SAMPLES LWNS RES 

CAST-V - CIRCUM ACOU SCAN MAMP MUDCELL PEAK AMPLITUDE MAMP RES 

CAST-V - CIRCUM ACOU SCAN MATN CALCULATED MUD ATTENUATION MATN RES 

CAST-V - CIRCUM ACOU SCAN MCAL CALIBRATED MUDCELL OFFSET MCAL RES 

CAST-V - CIRCUM ACOU SCAN MCF CALCULATED MUDCELL FREQUENCY MCF RES 

CAST-V - CIRCUM ACOU SCAN FSRA FIRST SHOT RAW AMPLITUDE FSRA RES 

CAST-V - CIRCUM ACOU SCAN RWAV FAST CAST TRANSDUCER WAVEFORM RWAV RES 

CAST-V - CIRCUM ACOU SCAN SMRT SAMPLE RATE SMRT RES 

CAST-V - CIRCUM ACOU SCAN RBRF TOOL REFERENCE ANGLE RBRF RES 

CAST-V - CIRCUM ACOU SCAN MNZD MINIMUM DIFFERENTIAL IMPEDANCE MNZD RES 

CCL - CASING COLLAR 

LOCATOR 

LIS 

Mnem 

LISU_ 

eng 

LISU_ 


DLISU_ 

Eng 

DLISU_ 

Met 

CCL CASING COLLAR LOCATOR CCL RES 

CSNG - COMP SPECT GAMMA HBAR BARITE CORR FACTOR - RUN AVG HBAR RES 

CSNG - COMP SPECT GAMMA MINU URANIUM - MIN ERROR MINU RES 

CSNG - COMP SPECT GAMMA MINT THORIUM - MIN ERROR MINT RES 

CSNG - COMP SPECT GAMMA MINK POTASSIUM - MIN ERROR MINK RES 

CSNG - COMP SPECT GAMMA MAXU URANIUM - MAX ERROR MAXU RES 

CSNG - COMP SPECT GAMMA MAXT THORIUM - MAX ERROR MAXT RES 

CSNG - COMP SPECT GAMMA MAXK POTASSIUM - MAX ERROR MAXK RES 

CSNG - COMP SPECT GAMMA LSPC LOW ENERGY SPECTRUM LSPC RES 

CSNG - COMP SPECT GAMMA HBHK BORHOLE POTASSIUM - RUN AVG HBHK RES 

CSNG - COMP SPECT GAMMA ERTO ERROR GAMMA RAY TOTAL ERTO RES 

CSNG - COMP SPECT GAMMA ERTC ERROR GAMMA RAY KT ERTC RES 

CSNG - COMP SPECT GAMMA EHBK BOREHOLE K CONCENTRATION ERROR EHBK RES 

CSNG - COMP SPECT GAMMA CVBF COMPUTED BARITE FACTOR CVBF RES 

CSNG - COMP SPECT GAMMA CRDF RESOLUTION DEGRADE FACTOR CRDF RES 

CSNG - COMP SPECT GAMMA CGCF SPECTRAL GAIN CORR FACTOR CGCF RES 

CSNG - COMP SPECT GAMMA CASR CSNG CASING RATIO CASR RES 

CSNG - COMP SPECT GAMMA HSPC HIGH ENERGY SPECTRUM HSPC RES 

CSNG - COMP SPECT GAMMA STAB CSNG STABILIZER STAB INP 

CSNG - COMP SPECT GAMMA LITR LITHOLOGY RATIO LITR RES 

CSNG - COMP SPECT GAMMA LSPD LINE SPEED LSPEED INP 

CSNG - COMP SPECT GAMMA NAVG TPU INTERVALS PER DEPTH INTERv NUMAVG RES 

CSNG - COMP SPECT GAMMA NOIS CPS CPS SPECTRAL NOISE NOIS 1.0/S 1.0/S RES 

CSNG - COMP SPECT GAMMA POTA % % POTASSIUM POTA % % RES 

CSNG - COMP SPECT GAMMA SPEH CSNG HIGH ENERGY SPECTRUM SUM SPEH INP 

CSNG - COMP SPECT GAMMA SPEL CSNG LOW ENERGY SPECTRUM SUM SPEL INP 

CSNG - COMP SPECT GAMMA AMER AMERICIUM COUNTS AMER INP 

CSNG - COMP SPECT GAMMA SRCF SOURCE FACTOR SRCF RES 

CSNG - COMP SPECT GAMMA GRTH GAPI GAPI GAMMA THORIUM GRTH gAPI gAPI RES 

CSNG - COMP SPECT GAMMA SWPO SWITCH POSITION SW_POS INP 

CSNG - COMP SPECT GAMMA THOR PPM PPM THORIUM THOR ppm ppm RES 

CSNG - COMP SPECT GAMMA TKRT CSNG RATIO THORIUM POTASSIUM TKRT RES 

CSNG - COMP SPECT GAMMA TOID CSNG TOOL ID TOOLID INP 

CSNG - COMP SPECT GAMMA TOTF CSNG TOTAL SPECTRA COUNTER TOTFRM INP 

CSNG - COMP SPECT GAMMA TURT CSNG RATIO THORIUM URANIUM TURT RES 

CSNG - COMP SPECT GAMMA UKRT CSNG RATIO URANIUM POTASSIUM UKRT RES 

CSNG - COMP SPECT GAMMA URAN PPM PPM URANIUM URAN ppm ppm RES 

CSNG - COMP SPECT GAMMA SRAT SELECTED RATIO SRAT RES 

Mnemonics 9-7 

Type_ 

Data

Serv_Name 

CSNG - COMP SPECT GAMMA FRMI FRAMES PER DEPTH INCRAMENT FRMINC RES 

CSNG - COMP SPECT GAMMA CCL CSNG CCL INPUT CCL INP 

CSNG - COMP SPECT GAMMA CSPC CSNG DISPLAY SPECTRUM CSPC RES 

CSNG - COMP SPECT GAMMA CTIM ACCUMULATION TIME C_TIME TEL 

CSNG - COMP SPECT GAMMA DERR CSNG FRAME DATA ERROR DATERR INP 

CSNG - COMP SPECT GAMMA ERPO % % ERROR POTASSIUM ERPO % % RES 

CSNG - COMP SPECT GAMMA ERTH PPM PPM ERROR THORIUM ERTH ppm ppm RES 

CSNG - COMP SPECT GAMMA ERUR PPM PPM ERROR URANIUM ERUR ppm ppm RES 

CSNG - COMP SPECT GAMMA FAVG AVERAGE FRAME TIME FRMAVG RES 

CSNG - COMP SPECT GAMMA GRUR GAPI GAPI GAMMA URANIUM GRUR gAPI gAPI RES 

CSNG - COMP SPECT GAMMA FRCT CSNG SPECTRAL FRAME COUNTER FRMCNT TEL 

CSNG - COMP SPECT GAMMA GRTO GAPI GAPI TOTAL GAMMA (150 KEV - 3 MEV) GRTO gAPI gAPI RES 

CSNG - COMP SPECT GAMMA FTIM MSEC MSEC FRAME TIME FTIME MSEC MSEC RES 

CSNG - COMP SPECT GAMMA GKCL GAPI GAPI GAMMMA KCL GKCL gAPI gAPI RES 

CSNG - COMP SPECT GAMMA GKUT GAPI GAPI GAMMA KUT GKUT gAPI gAPI RES 

CSNG - COMP SPECT GAMMA GRHI GAPI GAPI OBSERVED GAMMA (500KEV - 3MEV) GRHI gAPI gAPI RES 

CSNG - COMP SPECT GAMMA GRK GAPI GAPI GAMMA POTASSIUM GRK gAPI gAPI RES 

CSNG - COMP SPECT GAMMA GRKC GAPI GAPI GAMMMA KCL CORRECTED GRKC gAPI gAPI RES 

CSNG - COMP SPECT GAMMA GRKT GAPI GAPI GAMMA KT GRKT gAPI gAPI RES 

CSNG - COMP SPECT GAMMA AMCR CPS CPS AMERICIUM COUNTS AMCR 1.0/S 1.0/S RES 

CSNG - COMP SPECT GAMMA FERR FIT ERROR FERR RES 

CSNG - COMP SPECT GAMMA BORQ BORQ BORQ RES 

CSNG - COMP SPECT GAMMA MNGR MIN GAMMA RAY TOTAL ERROR MNGR RES 

CSNG - COMP SPECT GAMMA MNHB MIN BH POTASSIUM RUN AVG MNHB RES 

CSNG - COMP SPECT GAMMA MNKT MIN GAMMA RAY KT ERROR MNKT RES 

CSNG - COMP SPECT GAMMA MXBK MAX BH K CONCENT ERROR MXBK RES 

CSNG - COMP SPECT GAMMA MXGR MAX GAMMA RAY TOTAL MXGR RES 

CSNG - COMP SPECT GAMMA MXHB MAX BH POTASSIUM RUN AVG MXHB RES 

CSNG - COMP SPECT GAMMA MXKT MAX GAMMA RAY KT ERROR MKKT RES 

CSNG - COMP SPECT GAMMA MNBK MIN BH K CONCENT ERROR MNBK RES 

DH TENSION DLOD LB KG DOWNHOLE TENSION (HDTD) DLOD lbm Kg RES 

DH TENSION TEM2 DEGF DEGC BOREHOLE TEMPERATURE TEM2 degF degC RES 

DH TENSION PLOC DEG DEG PAD LOCATOR (HDTD) PLOC deg deg RES 

DLLT- DUAL LATERLOG LLS OHMM OHMM LATEROLOG SHALLOW RESISTIVITY LLS ohm.m ohm.m RES 

DLLT- DUAL LATERLOG CLLD MMHO MS-M LATEROLOG DEEP CONDUCTIVITY CLLD 0.001/ohm mS.m RES 

DLLT- DUAL LATERLOG DI IN IN DIAMETER OF INVASION DI RES 

DLLT- DUAL LATERLOG LLDC OHMM OHMM LLD CORRECTED LLDC RES 

DLLT- DUAL LATERLOG LLSC OHMM OHMM LLS CORRECTED LLSC RES 

DLLT- DUAL LATERLOG RT OHMM OHMM TRUE RESISTIVITY RT RES 

DLLT- DUAL LATERLOG RX0 OHMM OHMM FLUSHED ZONE RESISTIVITY RX0 RES 

DLLT- DUAL LATERLOG LLD OHMM OHMM LATEROLOG DEEP RESISTIVITY LLD ohm.m ohm.m RES 

DSN/DSEN - DUAL SPACE 

NEUTRON 


NEUTRON 


NEUTRON 


NEUTRON 


NEUTRON 

LIS 

Mnem 

LISU_ 

eng 

LISU_ 


DLISU_ 

Eng 

DLISU_ 

Met 

NPRS DECP DECP HDSN PRESSURE POROSITY CORR NPRS 100 pu 100 pu RES 

MCOR DECP DECP DSEN MUD POROSITY CORRECTION MCOR 100 pu 100 pu RES 

NPHS DECP DECP NEUTRON POROSITY SANDSTONE NPHS 100 pu 100 pu RES 

NBHC DECP DECP HDSN BOREHOLE POROSITY CORR NBHC 100 pu 100 pu RES 

NBHL DECP DECP HDSN BAD HOLE POROSITY CORR NBHL 100 pu 100 pu RES 

9-8 Mnemonics 

Type_ 

Data

Serv_Name 


NEUTRON 


NEUTRON 


NEUTRON 


NEUTRON 


NEUTRON 


NEUTRON 


NEUTRON 


NEUTRON 


NEUTRON 


NEUTRON 


NEUTRON 


NEUTRON 


NEUTRON 


NEUTRON 


NEUTRON 


NEUTRON 


NEUTRON 


NEUTRON 


NEUTRON 


NEUTRON 


NEUTRON 


NEUTRON 


NEUTRON 


NEUTRON 


NEUTRON 


NEUTRON 


NEUTRON 


NEUTRON 


NEUTRON 


NEUTRON 


NEUTRON 


NEUTRON 


NEUTRON 

LIS 

Mnem 

LISU_ 

eng 

LISU_ 


DLISU_ 

Eng 

DLISU_ 

Met 

NCSG DECP DECP HDSN CASING POROSITY CORR NCSG 100 pu 100 pu RES 

NDNU CPS CPS HOSTILE DSN NEAR COUNTS UNFILT NDNU 1.0/S 1.0/S RES 

ADPE DECP DECP DSEN AIR DOLO POROSITY EVR ADPE 100 pu 100 pu RES 

NDSE DSNE NEAR SPACED COUNTS NDSE TEL 

NDSN CPS CPS DSN NEAR COUNTS NDSN 1.0/S 1.0/S RES 

RNDS COUNTS COUNTS RAW DSN II NEAR COUNTS NDSN COUNTS COUNTS TEL 

NPSO DECP DECP HDSN STANDOFF POROSITY CORR NPSO 100 pu 100 pu RES 

FDSN CPS CPS DSN FAR COUNTS FDSN 1.0/S 1.0/S RES 

NRAT C/C C/C DSN (NDSN/FDSN) RATIO NRAT C/C C/C RES 

ENPH DECP DECP DSEN LIQUID POROSITY ENPH 100 pu 100 pu RES 

NTMP DECP DECP HDSN TEMPERATURE POROSITY CORR NTMP 100 pu 100 pu RES 

NTOT DECP DECP HDSN TOTAL POROSITY CORR NTOT 100 pu 100 pu RES 

RFDS COUNTS COUNTS RAW DSN II FAR COUNTS FDSN COUNTS COUNTS TEL 

NLIM DECP DECP NEUTRON PHI LIME MATRIX NLIM 100 pu 100 pu RES 

NPHD DECP DECP NEUTRON POROSITY DOLOMITE NPHD 100 pu 100 pu RES 

ENDS CPS CPS DSN NEAR COUNTS - EVR ENDSN 1.0/S 1.0/S RES 

EAPH DECP DECP DSEN AIR POROSITY EAPH 100 pu 100 pu RES 

LDPE DECP DECP DSEN LIQUID DOLO POROSITY EVR LDPE 100 pu 100 pu RES 

LLP DECP DECP DSEN LIQUID LIME POROSITY LLP 100 pu 100 pu RES 

LLPE DECP DECP DSEN LIQUID LIME POROSITY EVR LLPE 100 pu 100 pu RES 

LSP DECP DECP DSEN LIQUID SAND POROSITY LSP 100 pu 100 pu RES 

LSPE DECP DECP DSEN LIQUID SAND POROSITY EVR LSPE 100 pu 100 pu RES 

LPHI DECP DECP DSEN LIQUID POROSITY LPHI 100 pu 100 pu RES 

EMPH DECP DECP MEAN OF NEAR/FAR AIR POROSTIY EMPH 100 pu 100 pu RES 

ELPH DECP DECP DSEN AIR POROSITY LONG ELPH 100 pu 100 pu RES 

ENRA C/C C/C DSN (NDSN/FDSN) RATIO - EVR ENRAT C/C C/C RES 

EFDS CPS CPS DSN FAR COUNTS - EVR EFDSN 1.0/S 1.0/S RES 

FDSE DSEN FAR SPACED COUNTS FDSE TEL 

ASPE DECP DECP DSEN AIR SAND POROSITY EVR ASPE 100 pu 100 pu RES 

NPHI DECP DECP NEUTRON POROSITY NPHI 100 pu 100 pu RES 

ENLI DECP DECP NEUTRON PHI LIME MATRIX - EVR ENLIM 100 pu 100 pu RES 

ALPE DECP DECP DSEN AIR LIME POROSITY EVR ALPE 100 pu 100 pu RES 

ENPD DECP DECP NEUTRON POROSITY DOLOMITE EVR ENPHD 100 pu 100 pu RES 

Mnemonics 9-9 

Type_ 

Data

Serv_Name 


NEUTRON 


NEUTRON 


NEUTRON 


NEUTRON 

LIS 

Mnem 

LISU_ 

eng 

LISU_ 


DLISU_ 

Eng 

DLISU_ 

Met 

LDP DECP DECP DSEN LIQUID DOLO POROSITY LDP 100 pu 100 pu RES 

ENPS DECP DECP NEUTRON POROSITY SAND EVR ENPHS 100 pu 100 pu RES 

ETCO EVR TOTAL CORRECTION ETCOR RES 

FDNU CPS CPS HOSTILE DSN FAR COUNTS UNFILT FDNU 1.0/S 1.0/S RES 

EMI - ELECT MICRO IMAGING ACYU G G ACCELEROMETER Y UNFILTERED ACYU G G INP 

EMI - ELECT MICRO IMAGING EDD2 OHMM OHMM PAD #2 RESISTIVITY (FAST) EDD2 ohm.m ohm.m RES 

EMI - ELECT MICRO IMAGING CALA IN MM EMI AVERAGE CALIPER CALA in mm RES 

EMI - ELECT MICRO IMAGING DCAL IN MM EMI DIFFERENTIAL CALIPER DCAL in mm RES 

EMI - ELECT MICRO IMAGING DEVI DEG DEG DRIFT ANGLE DEVI deg deg RES 

EMI - ELECT MICRO IMAGING DMAX IN MM EMI MAXIMUM CALIPER PAIR DMAX in mm RES 

EMI - ELECT MICRO IMAGING DMIN IN MM EMI MINIMUM CALIPER PAIR DMIN in mm RES 

EMI - ELECT MICRO IMAGING DXT2 08.3MS 08.3MS Z ACCELEROMETER (FAST) TIME DXT2 8.3 mS 8.3 mS RES 

EMI - ELECT MICRO IMAGING ACCZ G G ACCELEROMETER Z-AXIS ACCZ G G RES 


EMI - ELECT MICRO IMAGING CAL4 IN MM EMI CALIPER ARM #4 (DIAMETER) CAL4 in mm RES 





EMI - ELECT MICRO IMAGING EMIM EMI TOOL MODE EMIM INP 

EMI - ELECT MICRO IMAGING EMMR VOLT VOLT REAL PART PHASOR VOLTAGE EMMR V V INP 

EMI - ELECT MICRO IMAGING DXTM 08.3MS 08.3MS Z ACCELEROMETER (FAST) TIME DXTM 8.3 mS 8.3 mS RES 

EMI - ELECT MICRO IMAGING BHVT FT3 M3 BOREHOLE VOLUME TOTAL BHVT ft3 m3 RES 

EMI - ELECT MICRO IMAGING ACCX G G ACCELEROMETER X-AXIS ACCX G G RES 

EMI - ELECT MICRO IMAGING ACCY G G ACCELEROMETER Y-AXIS ACCY G G RES 

EMI - ELECT MICRO IMAGING ACXU G G ACCELEROMETER X UNFILTERED ACXU G G INP 

EMI - ELECT MICRO IMAGING ACZU G G ACCELEROMETER Z UNFILTERED ACZU G G INP 

EMI - ELECT MICRO IMAGING AHV FT3 M3 ANNULAR HOLE VOLUME MARK AHV ft3 m3 RES 

EMI - ELECT MICRO IMAGING AHVT FT3 M3 ANNULAR HOLE VOLUME TOTAL AHVT ft3 m3 RES 


EMI - ELECT MICRO IMAGING BHV FT3 M3 BOREHOLE VOLUME MARK BHV ft3 m3 RES 


EMI - ELECT MICRO IMAGING C14 IN MM EMI CALIPER PAIR 1-4 C14 in mm RES 






EMI - ELECT MICRO IMAGING ACCQ ACCELEROMETER SUM OF SQUARES ACCQ RES 

EMI - ELECT MICRO IMAGING AZI1 DEG DEG PAD #1 AZIMUTH AZI1 deg deg RES 

EMI - ELECT MICRO IMAGING MAGZ MAGNETOMETER Z-AXIS MAGZ RES 

EMI - ELECT MICRO IMAGING P4B1 OHMM OHMM PAD #4 RESISTIVITY P4B1 ohm.m ohm.m RES 

EMI - ELECT MICRO IMAGING ITMP DEGF DEGC INTERNAL TEMPERATURE ITMP degF degC RES 

EMI - ELECT MICRO IMAGING LOWS DEG DEG LOW SIDE OF HOLE LOSIDE deg deg RES 

EMI - ELECT MICRO IMAGING MAGQ MAGNETOMETER SUM OF SQUARES MAGQ RES 

EMI - ELECT MICRO IMAGING MAGX MAGNETOMETER X-AXIS MAGX RES 

EMI - ELECT MICRO IMAGING F6B1 SED PAD #6, PROFILE 1 (FAST) F6B1 RES 

9-10 Mnemonics 

Type_ 

Data

Serv_Name 

LIS 

Mnem 

LISU_ 

eng 

LISU_ 


DLISU_ 

Eng 

DLISU_ 

Met 

EMI - ELECT MICRO IMAGING MAGY MAGNETOMETER Y-AXIS MAGY RES 


EMI - ELECT MICRO IMAGING MGXU MAGNETOMETER X UNFILTERED MGXU INP 

EMI - ELECT MICRO IMAGING MGYU MAGNETOMETER Y UNFILTERED MGYU INP 

EMI - ELECT MICRO IMAGING MGZU MAGNETOMETER Z UNFILTERED MGZU INP 



EMI - ELECT MICRO IMAGING RB DEG DEG PAD #1 ROTATION RB deg deg RES 

EMI - ELECT MICRO IMAGING RAD6 IN MM EMI CALIPER ARM #6 (RADIUS) RAD6 in mm RES 

EMI - ELECT MICRO IMAGING ERD4 OHMM OHMM PAD #4 RESISTIVITY FAST UNDELY ERD4 ohm.m ohm.m RES 

EMI - ELECT MICRO IMAGING BTOT TOAL MAGNETIC FIELD - NAV TOOL BTOT RES 

EMI - ELECT MICRO IMAGING GTOT TOAL GRAVITY FIELD - NAV TOOL GTOT RES 

EMI - ELECT MICRO IMAGING HDIA MEASURED HOLE DIAMETER HDIA RES 

EMI - ELECT MICRO IMAGING TLFC TOOL FACE DIRECTION TLFC RES 


EMI - ELECT MICRO IMAGING HAZI DEG DEG DRIFT AZIMUTH HAZI deg deg RES 











EMI - ELECT MICRO IMAGING RHOC OHMM OHMM BHC CORR. RESISTIVITY RHOC ohm.m ohm.m RES 

EMI - ELECT MICRO IMAGING TEMP DEGC DEGC NAVIGATION TEMPERATURE TEMP degC degC RES 

EMI - ELECT MICRO IMAGING ZAC2 G G Z ACCELEROMETER (FAST) ZAC2 G G RES 

EMI - ELECT MICRO IMAGING ZACC G G Z ACCELEROMETER (FAST) ZACC G G RES 


EMI - ELECT MICRO IMAGING EMMX VOLT VOLT IMAGINARY PART PHASOR VOLTAGE EMMX V V INP 

EMI - ELECT MICRO IMAGING RHOA OHMM OHMM AVERAGE RESISTIVITY RHOA ohm.m ohm.m RES 




EMI - ELECT MICRO IMAGING PRES EMI PAD FORCE PRES RES 

EMI - ELECT MICRO IMAGING PDDV V V EMI RELATIVE PAD VOLTAGE PDDV V V RES 

EMI - ELECT MICRO IMAGING PADS NESW NESW VIEW BUTTONS IMAGE (N-E-S-W-N) PADS NESW NESW RES 

EMI - ELECT MICRO IMAGING PAD6 PAD #6 - FAST DATA ARRAY PAD6 INP 








FCMT - FORM COMP MONITOR RGR1 CPS CPS RAW GAMMA RAY 1 RGR1 1.0/S 1.0/S RES 

FCMT - FORM COMP MONITOR ACCZ ACCELEROMETER ACCZ RES 

Mnemonics 9-11 

Type_ 

Data

Serv_Name 

FCMT - FORM COMP MONITOR CCL CCL FOR CORRELATION CCL RES 

FCMT - FORM COMP MONITOR CCL1 RAW COLLAR LOCATOR 1 CCL1 RES 

FCMT - FORM COMP MONITOR CCL2 RAW COLLAR LOCATOR 2 CCL2 RES 

FCMT - FORM COMP MONITOR TEMP DEGF DEGC INTERNAL TOOL TEMPERATURE TEMP degF degC RES 

FCMT - FORM COMP MONITOR GR API API GAMMA RAY GR gAPI gAPI RES 



FCMT - FORM COMP MONITOR DXTM CPS CPS ACCELEROMETER TIME DXTM 1.0/S 1.0/S RES 


FIAC - FOUR INDEP ARM 

CALIPER 


CALIPER 


CALIPER 


CALIPER 


CALIPER 


CALIPER 


CALIPER 


CALIPER 


CALIPER 


CALIPER 


CALIPER 

LIS 

Mnem 

LISU_ 

eng 

LISU_ 


DLISU_ 

Eng 

DLISU_ 

Met 

SO3 IN MM STAND OFF ARM 3 STAND3 in mm RES 




CALA IN MM AVERAGE CALIPER (C1+C2)/2 CALA in mm RES 

CAL4 IN MM CALIPER 4 CAL4 in mm RES 



C24 IN MM FOUR ARM CALIPER ARMS 2 & 4 C24 in mm RES 

C13 IN MM FOUR ARM CALIPER ARMS 1 & 3 C13 in mm RES 


FWST - FULL WAVE SONIC AMPL DB DB AMPLITUDE AMPL dB dB RES 

FWST - FULL WAVE SONIC ITT INTEGRATED TRAVEL TIME MARK ITT RES 

FWST - FULL WAVE SONIC GFAR FAR RECEIVER GAIN GAIN_F INP 

FWST - FULL WAVE SONIC FNOI FAR RECEIVER NOISE FNOISE INP 

FWST - FULL WAVE SONIC ERR ERROR ERROR INP 

FWST - FULL WAVE SONIC DTXM DELTA T AT TRANSMITTER DT_XMT INP 

FWST - FULL WAVE SONIC DTUN DELTA T UNFILTERED DT_UNF INP 

FWST - FULL WAVE SONIC ALPH ALPHA ALPHA INP 

FWST - FULL WAVE SONIC DT US/F US/M DELTA TIME COMPRESSIVE DT uS/ft US/M RES 

FWST - FULL WAVE SONIC ALPH ALPHA ALPHA INP 

FWST - FULL WAVE SONIC MSGR MSG RECEIVER MSGRCV INP 

FWST - FULL WAVE SONIC ITTT INTEGRATED TRAVEL TIME TOTAL ITTT RES 

FWST - FULL WAVE SONIC DTRC DELTA T AT RECEIVER DT_RCV INP 

FWST - FULL WAVE SONIC TT1 US US NEAR TRAVEL TIME TT1 uS uS RES 

FWST - FULL WAVE SONIC NNOI NEAR RECEIVER NOISE NNOISE INP 

FWST - FULL WAVE SONIC WFMS FWST MSG WAVEFORM WFMSG INP 

FWST - FULL WAVE SONIC WFFW MONOPOLE WF; ONE OF TWO WF'S. WFMT TEL 

FWST - FULL WAVE SONIC GNEA NEAR RECEIVER GAIN GAIN_N INP 

FWST - FULL WAVE SONIC TT2 US US FAR TRAVEL TIME TT2 uS uS RES 

FWST - FULL WAVE SONIC SPHI DECP DECP SONIC POROSITY SPHI 100 pu 100 pu RES 

FWST - FULL WAVE SONIC SDT2 US/F US/M DELTA T (2 FOOT) SDT2 uS/ft US/M RES 

FWST - FULL WAVE SONIC QDT DELTA TIME QUALITY QDT RES 

FWST - FULL WAVE SONIC PKCD PICK CODE PKCODE INP 

FWST - FULL WAVE SONIC WFFW HFWS FULL WAVE WAVEFORMS WFFW INP 


Type_ 

Data

Serv_Name 

GTET-GAMMA TELEMETRY ACCZ G G ACCELEROMETER Z-AXIS ACCZ G G RES 

GTET-GAMMA TELEMETRY EGR GAMMA RAY - EVR EGR RES 

GTET-GAMMA TELEMETRY INCL DEG DEG INCLINATION INCL deg deg RES 

GTET-GAMMA TELEMETRY GR GAMMA RAY GR RES 

HDIL - HOSTILE DUAL IND RES ILM OHMM OHMM INDUCTION MEDIUM RESISTIVITY ILM ohm.m ohm.m RES 

HDIL - HOSTILE DUAL IND RES SP MV MV SP SP mV mV RES 

HDIL - HOSTILE DUAL IND RES ILD OHMM OHMM INDUCTION DEEP RESISTIVITY ILD ohm.m ohm.m RES 

HDIL - HOSTILE DUAL IND RES CILD MMHO MS-M DEEP INDUCTION CONDUCTIVITY CILD 0.001/ohm mS.m RES 

HFDT - HI FREQ DIELECTRIC 

TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 

LIS 

Mnem 

LISU_ 

eng 

LISU_ 


DLISU_ 

Eng 

DLISU_ 

Met 

FE23 DIFF DIELECTRIC CONST 12 17 CM FE23 RES 



FDB3 DB DB AMPLITUDE 17 CM RECEIVER FDB3 dB dB RES 



FD23 DB DB DIFF AMPLITUDE 12 17 CM RCVR FD23 dB dB RES 

FET2 DIELECTRIC CONSTANT 12 CM FET2 RES 


FET3 DIELECTRIC CONST 17 CM FET3 RES 

FET1 DIELECTRIC CONSTANT 8 CM FET1 RES 

MP1V MINUS .1 VOLT MP1V TEL 

FTPL NS/M NS/M HFDT TRAVEL TIME FTPL NS/M NS/M RES 

GR16 GROUND 16 GR16 TEL 

GR64 GROUND 64 GR64 TEL 

GRD1 GROUND 1 GRD1 TEL 

GRD4 GROUND 4 GRD4 TEL 

HSTA HFDT TOOL STATUS HSTA TEL 

IMLA MICROLOG LATERAL IMLA TEL 

IMNO MICROLOG NORMAL IMNO TEL 

ITEM RAW TEMPERATURE ITEM TEL 

ITMP HFDT TEMPERATURE TEMP INP 

FETR TRANS. DIELECTRIC R FETR RES 

M8V MINUS 8. VOLT M8V TEL 

FRPY HFDT REFELECTED POWER Y FRPY TEL 

MP5V MINUS .5 VOLT MP5V TEL 

P2V POSITIVE 2 VOLT P2V TEL 


Type_ 

Data

Serv_Name 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 

LIS 

Mnem 

LISU_ 

eng 

LISU_ 


DLISU_ 

Eng 

DLISU_ 

Met 

P8V POSITIVE 8 VOLT P8V TEL 

PP1V POSITIVE .1 VOLT PP1V TEL 

PP5V POSITIVE .5 VOLT PP5V TEL 

RACZ HFDT Z-ACCELEROMETER RAW RACZ TEL 

RAD1 CALIPER 1 RAD1 TEL 

RAD2 CALIPER 2 RAD2 TEL 

TEM2 DSTU TEMPERATURE (F) DSTEMP TEL 

TPL NS/M NS/M HFDT TRAVEL TIME - LO RES FTPL25 NS/M NS/M RES 

ZACC ACCZ CALIBRATED INPUT FAST ZACC INP 

M2V MINUS 2. VOLT M2V TEL 

FR1Y HFDT REC. #1 Y COMPONENT FR1Y TEL 

FPH1 DEGREE DEGREE PHASE 8 CM RECEIVER FPH1 deg deg RES 

FIPY HFDT INCIDENT POWER Y FIPY TEL 

FP12 DEGREE DEGREE DIFF PHASE 8 12CM RECEIVER FP12 deg deg RES 




FPHX DECP DECP HFDT POROSITY FPHX 100 pu 100 pu RES 

FPHY HFDT QUALITY FPHY RES 

FR1 OHMM OHMM RESISTIVITY 8 CM FR1 ohm.m ohm.m RES 

FR12 OHMM OHMM DIFF RESISTIVITY 8 12 CM FR12 ohm.m ohm.m RES 

FR13 OHMM OHMM DIFF RESISTIVITY 8 17CM FR13 ohm.m ohm.m RES 

FT25 NS/M NS/M HFDT TRAVEL TIME - LO RES FTPL25 NS/M NS/M RES 

FR1X HFDT REC. #1 X COMPONENT FR1X TEL 

FRTR OHMM OHMM TRANS. RESISTIVITY FRTR ohm.m ohm.m RES 


FR23 OHMM OHMM DIFF RESISTIVITY 12 17CM FR23 ohm.m ohm.m RES 

FR2G HFDT REC. #2 GAIN FR2G TEL 







Type_ 

Data

Serv_Name 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 

HRAI/HRI - HIGH RES ARRAY 

IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 

LIS 

Mnem 

LISU_ 

eng 

LISU_ 


DLISU_ 

Eng 

DLISU_ 

Met 


FRPX HFDT REFELECTED POWER X FRPX TEL 

FIPX HFDT INCIDENT POWER X FIPX TEL 


AG1 AUX GROUND 1 AG1 TEL 


AC DB/M DB/M ATTENUATION CORRECTED - LO RES FAC25 DB/M DB/M RES 





DXTM 08.3MS 08.3MS HFDT Z-ACCELEROMETER TIME BASE DXTM 8.3 mS 8.3 mS INP 

FA25 DB/M DB/M ATTENUATION CORRECTED - LO RES FAC25 DB/M DB/M RES 

FAC DB/M DB/M ATTENUATION CORRECTED FAC dB/m dB/m RES 

HF06 OHMM OHMM HRAI 60 IN RAD RESIST 4FT HF06 ohm.m ohm.m RES 

HMR HRI MEDIUM RAW R HMR RES 

HMCN MMHO MS-M HRI MEDIUM CONDUCTIVITY HMCN 0.001/ohm mS.m RES 

HMC1 MMHO MS-M HRI MEDIUM CONDUCTIVITY 1FT HMC1 0.001/ohm mS.m RES 



HMR1 OHMM OHMM HRI MEDIUM RESISTIVITY 1FT HMR1 ohm.m ohm.m RES 




HMRS OHMM OHMM HRI MEDIUM RESISTIVITY HMRS ohm.m ohm.m RES 

HDRS OHMM OHMM HRI DEEP RESISTIVITY HDRS ohm.m ohm.m RES 

HO09 OHMM OHMM HRAI 90 IN RAD RESIST 1FT HO09 ohm.m ohm.m RES 

HDR1 OHMM OHMM HRI DEEP RESISTIVITY 1FT HDR1 ohm.m ohm.m RES 

HDR HRI DEEP RAW R HDR RES 

HDX HRI DEEP RAW X HDX RES 

HO24 OHMM OHMM HRI DEEP RES 1FT 24 INCH I HO24 ohm.m ohm.m RES 

HRM1 HRI MAP - ONE FOOT HRM1 RES 

HRFX XMTR REF 32KHz X SIGNAL X32KRF INP 


Type_ 

Data

Serv_Name 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 

LIS 

Mnem 

LISU_ 

eng 

LISU_ 


DLISU_ 

Eng 

DLISU_ 

Met 

HRFR XMTR REF 32KHz R SIGNAL R32KRF INP 





HMX HRI MEDIUM RAW X HMX RES 


HD3R MMHO MMHO LOWER 54" RCVR 32KHz R SIGNAL HD3R 0.001/ohm 0.001/ohm INP 


HDCN MMHO MS-M HRI DEEP CONDUCTIVITY HDCN 0.001/ohm mS.m RES 




DSE2 MMHO MMHO SKIN EFFECT CORRECTIONS D3 DSE2 0.001/ohm 0.001/ohm RES 

DT18 OHMM OHMM AVG DECON 18" 2FT DT18 ohm.m ohm.m RES 

DSE9 MMHO MMHO SKIN EFFECT CORRECTIONS U1 DSE9 0.001/ohm 0.001/ohm RES 










DRCO MMHO MMHO HRI DEEP R CORRECTION DRCO 0.001/ohm 0.001/ohm RES 

DQZE MMHO MMHO HRI DEEP QUALITY ZERO DQZER 0.001/ohm 0.001/ohm INP 

DQU9 MMHO MMHO QUALITY U1 DQU9 0.001/ohm 0.001/ohm RES 



HD1R MMHO MMHO LOWER 78" RVCR 32KHz R SIGNAL HD1R 0.001/ohm 0.001/ohm INP 

ZM DFL MEASURE Z ZM RES 



Type_ 

Data

Serv_Name 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 

LIS 

Mnem 

LISU_ 

eng 

LISU_ 


DLISU_ 

Eng 

DLISU_ 

Met 

HRM2 HRI MAP - TWO FOOT HRM2 RES 

HD3X MMHO MMHO LOWER 54" RCVR 32KHz X SIGNAL HD3X 0.001/ohm 0.001/ohm INP 

HT12 OHMM OHMM HRAI 120 IN RAD RESIST 2FT HT12 ohm.m ohm.m RES 





ECC ECCENTRICITY ECC RES 

DZM DFL MEASURE DELTA Z DZM RES 

DZB DFL BUCK DELTA Z DZB RES 

DXCO MMHO MMHO HRI DEEP X CORRECTION DXCO 0.001/ohm 0.001/ohm RES 



HDC1 MMHO MS-M HRI DEEP CONDUCTIVITY 1FT HDC1 0.001/ohm mS.m RES 


LSO LEFT STANDOFF LSO RES 

LD4R MMHO MMHO LOWER 42" RCVR 8 KHz R SIGNAL LD4R 0.001/ohm 0.001/ohm INP 

LD4X MMHO MMHO LOWER 42" RCVR 8 KHz X SIGNAL LD4X 0.001/ohm 0.001/ohm INP 



LMAN LEFT MANDREL LMAN RES 


LRFX XMTR REF 8 KHz X SIGNAL X8KREF INP 


LU1R MMHO MMHO UPPER 78" RCVR 8 KHz R SIGNAL LU1R 0.001/ohm 0.001/ohm INP 

LU1X MMHO MMHO UPPER 78" RCVR 8 HKz X SIGNAL LU1X 0.001/ohm 0.001/ohm INP 


LU2X MMHO MMHO UPPER 69" RCVR 8 KHz X SIGNAL LU2X 0.001/ohm 0.001/ohm INP 



LRFR XMTR REF 8 KHz R SIGNAL R8KREF INP 


HU1X MMHO MMHO UPPER 78" RCVR 32KHz X SIGNAL HU1X 0.001/ohm 0.001/ohm INP 


Type_ 

Data

Serv_Name 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 

LIS 

Mnem 

LISU_ 

eng 

LISU_ 


DLISU_ 

Eng 

DLISU_ 

Met 

HU2R MMHO MMHO UPPER 69" RCVR 32KHz R SIGNAL HU2R 0.001/ohm 0.001/ohm INP 















HT60 OHMM OHMM HRI DEEP RES. 2FT RES 60INCH I HT60 ohm.m ohm.m RES 


VRES IN IN HRI VERTICAL RESOLUTION VRES IN IN RES 

VRES FT FT RESOLUTION OF VAR CURVES VRES ft ft RES 

XFRA HRI DEEP X FRACTION XFRAC RES 

XHRF XMTR REF 32KHz X DELAYED XHRF INP 

ZB DFL BUCK Z ZB RES 

STEM DEGF DEGC HRI SONDE TEMPERATURE STEM degF degC RES 


SP MV MV ANALOG SPONTANEOUS POTENTIAL SP mV mV INP 








RMUD OHMM OHMM MUD RESISTIVITY RMUD ohm.m ohm.m RES 


Type_ 

Data

Serv_Name 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 

LIS 

Mnem 

LISU_ 

eng 

LISU_ 


DLISU_ 

Eng 

DLISU_ 

Met 



MQCA MMHO MMHO HRI MEDIUM QUALITY CAL MQCAL 0.001/ohm 0.001/ohm INP 

MQZE MMHO MMHO HRI MEDIUM QUALITY ZERO MQZER 0.001/ohm 0.001/ohm INP 

MRCO MMHO MMHO HRI MEDIUM R CORRECTION MRCO 0.001/ohm 0.001/ohm RES 

MXCO MMHO MMHO HRI MEDIUM X CORRECTION MXCO 0.001/ohm 0.001/ohm RES 

TMPF DEGF DEGC FEEDPIPE TEMP CALCULATED TMPF degF degC RES 

RMAN RIGHT MANDREL RMAN RES 


RSO RIGHT STANDOFF RSO RES 

RT OHMM OHMM UNINVADED ZONE RESISTIVITY RT ohm.m ohm.m RES 

RX0 OHMM OHMM INVADED ZONE RESISTIVITY RX0 ohm.m ohm.m RES 

RXRT RXO OVER RT RXRT RES 

RXRT RXO OVER RT RXRT RES 

SP MV MV SPONTANEOUS POTENTIAL SP mV mV RES 

RHRF XMTR REF 32KHz R DELAYED RHRF INP 

DBH2 MMHO MMHO BOREHOLE CORRECTIONS D3 DBH2 0.001/ohm 0.001/ohm RES 

DDRY HRI DECONVOLED DEEP RY DDRY RES 

CT03 MMHO MMHO HRAI 30 IN RADIAL COND 2FT CT03 0.001/ohm 0.001/ohm RES 




D1 IN MM INNER RADIAL DEPTH OF INVASION D1 in mm RES 

D2 IN IN OUTTER RADIAL DPTH OF INVASION D2 in IN RES 



CO12 MMHO MMHO HRAI 120 IN RADIAL COND 1FT CO12 0.001/ohm 0.001/ohm RES 


DBH4 MMHO MMHO BOREHOLE CORRECTIONS U5 DBH4 0.001/ohm 0.001/ohm RES 






Type_ 

Data

Serv_Name 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 

LIS 

Mnem 

LISU_ 

eng 

LISU_ 


DLISU_ 

Eng 

DLISU_ 

Met 




CF06 MMHO MMHO HRAI 60 IN RADIAL COND 4FT CF06 0.001/ohm 0.001/ohm RES 

BH30 MMHO MMHO BOREHOLE CORRECTIONS 30" BH30 0.001/ohm 0.001/ohm RES 





CALC IN IN CALC DIAMETER CALC in IN RES 




DDX HRI DECONVOLED DEEP X DDX RES 










DO69 OHMM OHMM AVG DECON 69" 1FT DO69 ohm.m ohm.m RES 

DDRX HRI DECONVOLED DEEP RX DDRX RES 

DLS4 OHMM OHMM SYMMETRIZED 8K S42" DLS4 ohm.m ohm.m RES 

DLU5 OHMM OHMM VERT DECON 8K UPPER 30" DLU5 ohm.m ohm.m RES 

DMR HRI DECONVOLED MEDIUM R DMR RES 

DMY HRI DECONVOLED MEDIUM Y DMY RES 






Type_ 

Data

Serv_Name 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 


IND 

LIS 

Mnem 

LISU_ 

eng 

LISU_ 


DLISU_ 

Eng 

DLISU_ 

Met 



DQCA HRI DEEP QUALITY CAL DQCAL INP 

DQU0 MMHO MMHO QUALITY D1 DQU0 0.001/ohm 0.001/ohm RES 







DFLF OHMM OHMM DIGITALLY FOCUSED LATEROLOG FL DFLF ohm.m ohm.m RES 

DDY HRI DECONVOLED DEEP Y DDY RES 

DF18 OHMM OHMM AVG DECON 18" 4FT DF18 ohm.m ohm.m RES 







DFL OHMM OHMM DIGITALLY FOCUSED LATEROLOG DFL ohm.m ohm.m RES 


DHD6 OHMM OHMM VERT DECON 32K LOWER 18" DHD6 ohm.m ohm.m RES 

DHS1 OHMM OHMM SYMMETRIZED 32K S78" DHS1 ohm.m ohm.m RES 




DHU5 OHMM OHMM VERT DECON 32K UPPER 30" DHU5 ohm.m ohm.m RES 

DI IN IN RADIAL DEPTH OF INVASION DI IN IN RES 

DLD6 OHMM OHMM VERT DECON 8K LOWER 18" DLD6 ohm.m ohm.m RES 


HSN - SHORT NORMAL RES SGRU OHMM OHMM UNFILTERED NORMAL RESISTIVITY SGRU ohm.m ohm.m RES 

HSN - SHORT NORMAL RES SGRD OHMM OHMM SHORT NORMAL RESISTIVITY SGRD ohm.m ohm.m RES 

HSN - SHORT NORMAL RES RXRT RXO OVER RT RXRT RES 

ICT - SIX INDEP ARM CALIPER SO1 IN MM STAND OFF ARM 1 STAND1 in mm RES 


Type_ 

Data

Serv_Name 

ICT - SIX INDEP ARM CALIPER RAD6 IN MM RADIUS CALIPER ARM # 6 RAD6 in mm RES 









ICT - SIX INDEP ARM CALIPER HAZI DEG DEG DRIFT AZIMUTH HAZI deg deg RES 


ICT - SIX INDEP ARM CALIPER CAL6 IN MM ICT CALIPER ARM #6 CAL6 in mm RES 

ICT - SIX INDEP ARM CALIPER CALA IN MM ICT AVERAGE CALIPER CALA in mm RES 





ICT - SIX INDEP ARM CALIPER C36 IN MM ICT CALIPER PAIR 3-6 C36 in mm RES 





ICT - SIX INDEP ARM CALIPER HAZI DEG DEG DRIFT AZIMUTH HAZI deg deg RES 

ICT - SIX INDEP ARM CALIPER DEVI DEG DEG DRIFT ANGLE DEVI deg deg RES 

ICT - SIX INDEP ARM CALIPER DEVI DEG DEG DRIFT ANGLE DEVI deg deg RES 

ICT - SIX INDEP ARM CALIPER DCAL IN MM DIFFERENTIAL CLAIPER DCAL in mm RES 

ICT - SIX INDEP ARM CALIPER HDIA IN MM MEASURED HOLE DIAMETER HDIA in mm RES 

ICT - SIX INDEP ARM CALIPER RB DEG DEG RELEATIVE BEARNING RB deg deg RES 

ICT - SIX INDEP ARM CALIPER PRES CALIPER PAD FORCE PRES RES 

ICT - SIX INDEP ARM CALIPER DMIN IN MM MINIMUM CALIPER PAIR DMIN in mm RES 

ICT - SIX INDEP ARM CALIPER DMAX IN MM MAXIMUM CALIPER PAIR DMAX in mm RES 

IDT - INSITE DIRECTIONAL 

TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 

LIS 

Mnem 

LISU_ 

eng 

LISU_ 


DLISU_ 

Eng 

DLISU_ 

Met 

RB DEG DEG RELATIVE BEARING RB deg deg RES 

MAGD MAGNETIC DIP FOR DIRECT TOOL MAGD RES 

MAGZ MAGNETOMETER Z-AXIS MAGZ RES 

MAGY MAGNETOMETER Y-AXIS MAGY RES 

MAGX MAGNETOMETER X-AXIS MAGX RES 

TLFC TOOL FACE DIRECTION TLFC RES 

GTOT TOAL GRAVITY FIELD - NAV TOOL GTOT RES 

BTOT TOAL MAGNETIC FIELD - NAV TOOL BTOT RES 

AZI1 DEG DEG PAD 1 AZIMUTH AZI1 deg deg RES 

ACCZ G G ACCELEROMETER Z-AXIS ACCZ G G RES 

ACCQ G G ACCELEROMETER QUALITY ACCQ G G RES 

ACCX G G ACCELEROMETER X-AXIS ACCX G G RES 


Type_ 

Data

Serv_Name 


TOOL 


TOOL 


TOOL 

MTMP MAGNET TEMPERATURE MTMP RES 

ACCY G G ACCELEROMETER Y-AXIS ACCY G G RES 

MAGQ CALCULATED MAGNETIC FIELD MAGQ RES 

MACT - MULTI-ARM CALIPER CALA IN MM AVERAGE CALIPER CALA in mm RES 

MACT - MULTI-ARM CALIPER MXID IN MM CASING MAXIMUM ID MXID in mm RES 

MACT - MULTI-ARM CALIPER MNID IN MM CASING MINIMUM ID MNID in mm RES 

MACT - MULTI-ARM CALIPER RMWL IN MM REMAINING WALL THICKNESS RMWL in mm RES 

MRIL - MAGNETIC RESONANCE 

IMAGE 


IMAGE 


IMAGE 


IMAGE 


IMAGE 


IMAGE 


IMAGE 


IMAGE 


IMAGE 


IMAGE 


IMAGE 


IMAGE 


IMAGE 


IMAGE 


IMAGE 


IMAGE 


IMAGE 


IMAGE 


IMAGE 


IMAGE 


IMAGE 


IMAGE 


IMAGE 


IMAGE 


IMAGE 


IMAGE 


IMAGE 

LIS 

Mnem 

LISU_ 

eng 

LISU_ 


DLISU_ 

Eng 

DLISU_ 

Met 

PC3 PU PU Bin Sums 1-3 for display PC3 pu pu RES 





P9 PU PU BIN 9 Porosity P9 pu pu INP 



TPW TOTAL POROSITY Distribution TPW RES 



SEQN Sequence Number SEQN INP 









WTME MRIL WAIT TIEM WTME INP 

PERM Computed Permiability PERM INP 

RDSP Raw Echos for Display RDSP INP 

STAT DATA STATUS STAT INP 

T2W MSEC MSEC T2 Distribution Waveform T2W MSEC MSEC RES 

TPHI DECP DECP MRIL FULL POROSITY TPHI 100 pu 100 pu RES 

PHA Corrected Echo Phases PHAS INP 


Type_ 

Data

Serv_Name 


IMAGE 


IMAGE 


IMAGE 


IMAGE 


IMAGE 


IMAGE 


IMAGE 


IMAGE 


IMAGE 


IMAGE 


IMAGE 


IMAGE 


IMAGE 


IMAGE 


IMAGE 


IMAGE 


IMAGE 


IMAGE 


IMAGE 


IMAGE 


IMAGE 


IMAGE 


IMAGE 


IMAGE 


IMAGE 


IMAGE 

LIS 

Mnem 

LISU_ 

eng 

LISU_ 


DLISU_ 

Eng 

DLISU_ 

Met 

FRQ3 MRIL FREQUENCY 3 FRQ3 INP 



ACTN MRIL ACTIVATION NAME ACTN INP 

TE MRIL ECHO SPACING TE INP 




ANT DEG DEG ANTENNA TEMPERATURE ANT deg deg INP 

B1 MG MG B1 SENSOR B1 MG MG INP 

B1MD MG MG B1 ADJUSTED for TEMPERATURE B1MOD MG MG INP 

CHI CHI from analysis CHI INP 

DIH DIAM of INVESTIGATION HYDROGEN DIH RES 

ECHO Corrected Echo Amplitudes ECHO INP 

GAIN MRIL GAIN GAIN INP 

MBVI PU PU MRIL Bound Volume MBVI pu pu INP 

MDPT DATA DEPTH MDPT INP 

MPHI PU PU MRIL EFFECTIVE POROSITY MPHI pu pu INP 








DIS DIAM of INVESTIGATION SODIUM DIS RES 

MSFL/ML - MICRO RES MNOR OHMM OHMM MICROLOG NORMAL MNOR ohm.m ohm.m RES 

MSFL/ML - MICRO RES MSFL OHMM OHMM MSFL (FRXO) MSFL ohm.m ohm.m RES 

MSFL/ML - MICRO RES RXRT RXO OVER RT RXRT RES 

MSFL/ML - MICRO RES MSFU OHMM OHMM MSFL UNFILTERED MSFLUF ohm.m ohm.m RES 

MSFL/ML - MICRO RES MINV OHMM OHMM MICROLOG LATERAL (INVERSE) MINV ohm.m ohm.m RES 

PL TOOLS - PRODUCTION FCCW RPS RPS FLOW (CONTINUOUS) CW FCCW RPS RPS RES 

PL TOOLS - PRODUCTION DPRS PSI KPA DIFFERENTIAL PRESSURE DPRS psi Kpa RES 

PL TOOLS - PRODUCTION DPRS PSI KPA DIFFERENTIAL PRESSURE DPRS psi Kpa RES 

PL TOOLS - PRODUCTION DTEM DEGF DEGC DIFFERENTIAL TEMPERATURE DTEM degF degC RES 

PL TOOLS - PRODUCTION DTEM DEGF DEGC DIFFERENTIAL TEMPERATURE DTMP degF degC RES 


Type_ 

Data

Serv_Name 

LIS 

Mnem 

LISU_ 

eng 

LISU_ 


DLISU_ 

Eng 

DLISU_ 

Met 

PL TOOLS - PRODUCTION FBCC RPS RPS FLOW (FULL BORE) CCW FBCC RPS RPS RES 

PL TOOLS - PRODUCTION FCCC RPS RPS FLOW (CONTINUOUS) CCW FCCC RPS RPS RES 

PL TOOLS - PRODUCTION FCON RPS RPS AVERAGE FLOW (CONTINUOUS) FCON RPS RPS RES 

PL TOOLS - PRODUCTION FDC CPS CPS FLUID DENSITY COUNTS FDC 1.0/S 1.0/S RES 

PL TOOLS - PRODUCTION FDDP DIFFERENTIAL PRESSURE FDDP RES 

PL TOOLS - PRODUCTION FDEN G/CC K/M3 FLUID DENSITY FDEN G/CC Kg/m3 RES 

PL TOOLS - PRODUCTION FICC RPS RPS FLOW (INLINE) CCW FICC RPS RPS RES 

PL TOOLS - PRODUCTION FINL RPS RPS AVERAGE FLOW (INLINE) FLOWI RPS RPS RES 

PL TOOLS - PRODUCTION FICW RPS RPS FLOW (INLINE) CW FICW RPS RPS RES 

PL TOOLS - PRODUCTION FBCW RPS RPS FLOW (FULL BORE) CW FBCW RPS RPS RES 

PL TOOLS - PRODUCTION CP4 INDEX INDEX SENSOR 4 CAPACITANCE INDEX CP4 INDEX INDEX RES 

PL TOOLS - PRODUCTION CALX SQIN CROSS SECTION AREA CALX SQIN RES 

PL TOOLS - PRODUCTION CHMA HORIZONTAL IMAGE MAP CHMAP RES 

PL TOOLS - PRODUCTION TEMP DEGF DEGC TEMPERATURE TEMP degF degC RES 

PL TOOLS - PRODUCTION CP1 SENSOR 1 CAPACITANCE INDEX CP1 RES 

PL TOOLS - PRODUCTION FLFB RPS RPS AVERAGE FLOW (FULL BORE) FLOWFB RPS RPS RES 





PL TOOLS - PRODUCTION DIMV MV MV DIFFERENTIAL MILLIVOLTS DIFFMV mV mV RES 

PL TOOLS - PRODUCTION CP5 SENSOR 5 CAPACITANCE INDEX CP5 RES 





PL TOOLS - PRODUCTION CRMA RADIAL IMAGE MAP CRMAP RES 

PL TOOLS - PRODUCTION CSDL F/M M/M CABLE SPEED - DELAYED CSDL ft/m m/min INP 


PL TOOLS - PRODUCTION YTWA TURB TURB WATER HOLDUP - TURBULENT FLOW YTWAT TURB TURB RES 

PL TOOLS - PRODUCTION RHOG GM/CC KG/M3 GAS DENSITY RHOG GM/CC KG/M3 RES 

PL TOOLS - PRODUCTION YGHT % % GAS HOLDUP YGHT % % RES 

PL TOOLS - PRODUCTION YGHU % % GAS HOLDUP - UNLIMITED YGHU % % RES 

PL TOOLS - PRODUCTION YGHZ % % GAS HOLDUP - PVT UNCORRECTED YGHZ % % RES 

PL TOOLS - PRODUCTION YOD % % OIL HOLDUP FDR TOOL YOD % % RES 

PL TOOLS - PRODUCTION YGAS GAS HOLDUP YGAS RES 

PL TOOLS - PRODUCTION YOIL OIL HOLDUP YOIL RES 

PL TOOLS - PRODUCTION TEMP DEGF DEGC TEMPERATURE TEMP degF degC RES 

PL TOOLS - PRODUCTION YWAT WATER HOLDUP YWAT RES 

PL TOOLS - PRODUCTION YWAT LAMNR LAMNR WATER HOLDUP - LAMINAR FLOW YWAT LAMNR LAMNR RES 

PL TOOLS - PRODUCTION YWD % % WATER HOLDUP FDR TOOL YWD % % RES 

PL TOOLS - PRODUCTION YWH % % WATER HOLDUP YWH % % RES 

PL TOOLS - PRODUCTION CAL1 INCH CALIPER ARM 1 CAL1 in RES 

PL TOOLS - PRODUCTION CAL2 INCH CALIPER ARM 2 CAL2 in RES 

PL TOOLS - PRODUCTION YOH % % OIL HOLDUP YOH % % RES 

PL TOOLS - PRODUCTION HYDR CPS CPS CENTER SAMPLE HYDROMETER CPS HYDR 1.0/S 1.0/S RES 

PL TOOLS - PRODUCTION FTMP FDD SENSOR TEMPERATURE FTMP RES 

PL TOOLS - PRODUCTION GHCC CPS CPS GHT DEAD TIME & DECAY CORR CPS GHTCC 1.0/S 1.0/S RES 

PL TOOLS - PRODUCTION GHTC CPS CPS GHT DEAD TIME ONLY CORR CPS GHTC 1.0/S 1.0/S RES 


Type_ 

Data

Serv_Name 

LIS 

Mnem 

LISU_ 

eng 

LISU_ 


DLISU_ 

Eng 

DLISU_ 

Met 

PL TOOLS - PRODUCTION GR API API GAMMA RAY GR gAPI gAPI RES 

PL TOOLS - PRODUCTION GRCO API API GAMMA RAY CORRECTED GRCO gAPI gAPI RES 

PL TOOLS - PRODUCTION YGD % % GAS HOLDUP FDR TOOL YGD % % RES 

PL TOOLS - PRODUCTION GRS API API GAMMA RAY (SONDEX) GRS gAPI gAPI RES 

PL TOOLS - PRODUCTION FREF FREQUENCY REFERENCE FREF TEL 

PL TOOLS - PRODUCTION IDER ID OUT OF TOLERANCE WARNING IDWARN RES 

PL TOOLS - PRODUCTION ITMP F C INTERNAL TEMPERATURE INTMP ft C RES 

PL TOOLS - PRODUCTION PRBU PSI KG/M3 PRESSURE BUILDUP PRBU psi KG/M3 RES 

PL TOOLS - PRODUCTION PRES PSI KPA PRESSURE PRES psi Kpa RES 

PL TOOLS - PRODUCTION PRES PSIA KPA ABSOLUTE PRESSURE PRES PSIA Kpa RES 

PL TOOLS - PRODUCTION SIT DEGF DEGC SENSOR TEMPERATURE SIT degF degC RES 

PL TOOLS - PRODUCTION TEMP INTERNAL TEMPERATURE TEMP INP 

PL TOOLS - PRODUCTION GRCS API API GAMMA RAY CORRECTED (SONDEX) GRCS gAPI gAPI RES 

PSGT - PULSE SPECT GAMMA STUN CO STATISTICAL UNCERTAINTY STUN RES 

PSGT - PULSE SPECT GAMMA YCA CALCIUM YIELD CAPTURE YCA RES 

PSGT - PULSE SPECT GAMMA SPC2 PSGT CAPTURE 2 SPECTRUM SPC2 INP 

PSGT - PULSE SPECT GAMMA SPBK PSGT BACKGROUND SPECTRUM SPBK INP 

PSGT - PULSE SPECT GAMMA SPC1 PSGT CAPTURE 1 SPECTRUM SPC1 INP 

PSGT - PULSE SPECT GAMMA SPEN PSGT INELASTIC SPECTRUM SPEN INP 

PSGT - PULSE SPECT GAMMA SWPO PSGT TOOL MODE SWPOS INP 

PSGT - PULSE SPECT GAMMA TCCR TOTAL COUNTS CAPTURE TCCR RES 

PSGT - PULSE SPECT GAMMA TMD1 TMD GATE 1 UNFILTERED TMD1 RES 





PSGT - PULSE SPECT GAMMA SIC SULPHUR INDICATOR_C SIC RES 

PSGT - PULSE SPECT GAMMA TMDS CU CU TMD SIGMA TMDS cu CU RES 

PSGT - PULSE SPECT GAMMA SIAI SILICON_ACT_INDICATOR SIAI SIAI RES 

PSGT - PULSE SPECT GAMMA YCL CHLORINE YIELD CAPTURE YCL RES 

PSGT - PULSE SPECT GAMMA YFE IRON YIELD CAPTURE YFE RES 

PSGT - PULSE SPECT GAMMA YH HYDROGEN YIELD CAPTURE YH RES 

PSGT - PULSE SPECT GAMMA YIC CARBON YIELD INELASTIC YIC RES 

PSGT - PULSE SPECT GAMMA YICA CALCIUM YIELD INELASTIC YICA RES 

PSGT - PULSE SPECT GAMMA YIO OXYGEN YIELD CAPTURE YIO RES 

PSGT - PULSE SPECT GAMMA YISI SILICON YIELD INELASTIC YISI RES 

PSGT - PULSE SPECT GAMMA YK POTASSIUM YIELD CAPTURE YK RES 

PSGT - PULSE SPECT GAMMA YS SULPHUR YIELD CAPTURE YS RES 

PSGT - PULSE SPECT GAMMA YSI SILICON YIELD CAPTURE YSI RES 

PSGT - PULSE SPECT GAMMA YTI TITANIUM YIELD CAPTURE YTI RES 

PSGT - PULSE SPECT GAMMA ZOFF ZERO OFFSET PSGT.SHOP CAL S-2 ZOFF RES 


PSGT - PULSE SPECT GAMMA FTR SPECTRAL FIT ERROR FTR RES 

PSGT - PULSE SPECT GAMMA CLIC CHLORINE INDICATOR_C CLIC RES 

PSGT - PULSE SPECT GAMMA COIR INELASTIC CO RATIO COIR RES 

PSGT - PULSE SPECT GAMMA COYR CO YIELD RATIO INELASTIC COYR RES 

PSGT - PULSE SPECT GAMMA CRAT COMPTON RATIO (OAI/OBI) CRAT RES 

PSGT - PULSE SPECT GAMMA CTIM MSEC MSEC ACCUMULATION TIME MILLISECONDS C_TIME MSEC MSEC RES 

PSGT - PULSE SPECT GAMMA DTMP DETECTOR TEMPERATURE DTMP RES 


Type_ 

Data

Serv_Name 

LIS 

Mnem 

LISU_ 

eng 

LISU_ 


DLISU_ 

Eng 

DLISU_ 

Met 

PSGT - PULSE SPECT GAMMA F110 % % PSGT 110 VOLT F110 % % RES 

PSGT - PULSE SPECT GAMMA F17V % % PSGT 17V LOAD F17V % % RES 

PSGT - PULSE SPECT GAMMA F2KV % % PSGT 2K VOLT LOAD F2KV % % RES 

PSGT - PULSE SPECT GAMMA F50V % % PSGT 50 V LOAD F50V % % RES 

PSGT - PULSE SPECT GAMMA FEIC IRON INDICATOR_C FEIC RES 

PSGT - PULSE SPECT GAMMA SIIC SILICON INDICATOR_C SIIC RES 

PSGT - PULSE SPECT GAMMA FREP % % PSGT REPLENISHER FREP % % RES 

PSGT - PULSE SPECT GAMMA LIRI INELASTIC LITHOLOGY INDEX LIRI RES 

PSGT - PULSE SPECT GAMMA RIC INELASTIC CAPTURE RATIO RIC RES 

PSGT - PULSE SPECT GAMMA PSST PSGT TOOL STATE PSGST INP 

PSGT - PULSE SPECT GAMMA PSPC PSGT DISPLAY SPECTRUM PSPC RES 

PSGT - PULSE SPECT GAMMA OBI OXYGEN BACKGROUND INDICATOR OBI RES 

PSGT - PULSE SPECT GAMMA FERC IRON RATIO CAPTURE FERC RES 

PSGT - PULSE SPECT GAMMA LIYR LITH YIELD RATIO INEL LIYR RES 

PSGT - PULSE SPECT GAMMA CAIC CALCIUM INDICATOR_C CAIC RES 

PSGT - PULSE SPECT GAMMA KIC POTASSIUM INDICATOR_C KIC RES 

PSGT - PULSE SPECT GAMMA ITCR INELASTIC TOTAL ITCR RES 

PSGT - PULSE SPECT GAMMA IDER PSGT ID ERROR IDERR INP 

PSGT - PULSE SPECT GAMMA HPLI CAPTURE HYDROGEN PEAK HPLI RES 

PSGT - PULSE SPECT GAMMA HIC HYDROGEN INDICATOR_C HIC RES 

PSGT - PULSE SPECT GAMMA GOUT GENERATOR OUTPUT GOUT RES 

PSGT - PULSE SPECT GAMMA OAI OXYGEN ACTIVATION INDICATOR OAI RES 

RDT - RESERVOIR DESC TOOL C11 CURVE 11 C11 INP 

RDT - RESERVOIR DESC TOOL P1TE DEGF DEGC PROBE 1 TEMPERATURE P1TEMP degF degC INP 

RDT - RESERVOIR DESC TOOL PTHO PSI KPA PRESSURE THOUSANDS PTHO psi Kpa RES 

RDT - RESERVOIR DESC TOOL PTEN PSI KPA PRESSURE TENS PTEN psi Kpa RES 

RDT - RESERVOIR DESC TOOL PRES PSI KPA TOTAL PRESSURE PRES psi Kpa RES 

RDT - RESERVOIR DESC TOOL PRAT CC/S CC/S FPS PUMP MEASURED RATE PRATE 0.1 L/S 0.1 L/S INP 

RDT - RESERVOIR DESC TOOL POTE DEGF DEGC FPS OUTLET TEMPERATURE OUTTMP degF degC INP 

RDT - RESERVOIR DESC TOOL PONE PSI KPA RDT PRESSURE ONES PONE psi Kpa RES 

RDT - RESERVOIR DESC TOOL PITE DEGF DEGC FPS INLET TEMPERATURE INTMP degF degC INP 

RDT - RESERVOIR DESC TOOL PHUN PSI KPA PRESSURE HUNDREDS PHUN psi Kpa RES 

RDT - RESERVOIR DESC TOOL PHST PSI KPA RDT HYDROSTATIC PRESSURE PHST psi Kpa RES 

RDT - RESERVOIR DESC TOOL PHFL PSI KPA RDT HYDRAULIC PRESSURE PHFL psi Kpa RES 

RDT - RESERVOIR DESC TOOL PHDS PSI KPA PRESSURE HUNDREDTHS PHDS psi Kpa RES 

RDT - RESERVOIR DESC TOOL HPRS PSI KPA FPS HYDRALIC PRESSURE SYPRES psi Kpa INP 

RDT - RESERVOIR DESC TOOL P2PS PSI PSI PROBE 2 PRESSURE P2PRES PSI PSI INP 

RDT - RESERVOIR DESC TOOL PTTE DEGF DEGC PRETEST TEMPERATURE PTTEMP degF degC INP 

RDT - RESERVOIR DESC TOOL P1PS PSI PSI PROBE 1 PRESSURE P1PRES PSI PSI INP 

RDT - RESERVOIR DESC TOOL OPTR CC/S CC/S FPS OPTIMUM PUMP RATE OPTR CC/S CC/S INP 

RDT - RESERVOIR DESC TOOL OPTR CC/S CC/S FPS OPTIMUM PUMP RATE OPTR CC/S CC/S INP 

RDT - RESERVOIR DESC TOOL OFFS OFFSET OFFSET TEL 

RDT - RESERVOIR DESC TOOL NOIS NOISE NOISE TEL 

RDT - RESERVOIR DESC TOOL MTEM DEGF DEGC MAGNET TEMPERATURE TEMP2 degF degC TEL 

RDT - RESERVOIR DESC TOOL MSPD RPM RPM Motor Speed MOTSPD RPM RPM INP 

RDT - RESERVOIR DESC TOOL MRAT CC/S CC/S PRETEST MEASURED RATE MRATE 0.1 L/S 0.1 L/S INP 

RDT - RESERVOIR DESC TOOL HTMP DEGF DEGC HPS HYDRAULIC TEMPERATURE HYTEMP degF degC INP 

RDT - RESERVOIR DESC TOOL HTMP HPS HYDRAULIC TEMPERATURE HYTEMP INP 

RDT - RESERVOIR DESC TOOL HSVA SOLENOID VALVE A HPSSVA TEL 


Type_ 

Data

Serv_Name 

LIS 

Mnem 

LISU_ 

eng 

LISU_ 


DLISU_ 

Eng 

DLISU_ 

Met 

RDT - RESERVOIR DESC TOOL HPRS PSI KPA HPS HYDRALIC PRESSURE HYPRES psi Kpa INP 

RDT - RESERVOIR DESC TOOL P2TE DEGF DEGC PROBE 2 TEMPERATURE P2TEMP degF degC INP 

RDT - RESERVOIR DESC TOOL SVB PPS Solenoid Valve B PPSSVB TEL 

RDT - RESERVOIR DESC TOOL RHOG GM/CC GM/CC GAS DENSITY - EST. RHOG gm/cc gm/cc INP 


RDT - RESERVOIR DESC TOOL ANSO KV/KH KV/KH ANISOTROPY ANISO Kv/Kh Kv/Kh INP 

RDT - RESERVOIR DESC TOOL VISC VISCOCITY VISC INP 

RDT - RESERVOIR DESC TOOL V50 50 VOLT DC V50 TEL 



RDT - RESERVOIR DESC TOOL UTLV SURFACE UTILITY VOLTAGE UTLVLT TEL 

RDT - RESERVOIR DESC TOOL UTLC SURFACE UTILITY CURRENT UTLCUR TEL 

RDT - RESERVOIR DESC TOOL SVG PPS Solenoid Valve G PPSSVG TEL 

RDT - RESERVOIR DESC TOOL SVF PPS Solenoid Valve F PPSSVF TEL 

RDT - RESERVOIR DESC TOOL SVE PPS Solenoid Valve E PPSSVE TEL 

RDT - RESERVOIR DESC TOOL PTHS PSI KPA PRESSURE TENTHS PTHS psi Kpa RES 

RDT - RESERVOIR DESC TOOL SVC PPS Solenoid Valve C PPSSVC TEL 

RDT - RESERVOIR DESC TOOL PTPS PSI PSI PRETEST PRESSURE PTPRES PSI PSI INP 

RDT - RESERVOIR DESC TOOL SVA PPS Solenoid Valve A PPSSVA TEL 

RDT - RESERVOIR DESC TOOL SPIK ECHO SPIKING INDICATOR SPIKE INP 

RDT - RESERVOIR DESC TOOL SMOB SHPERICAL MOBILITY MPTHS INP 

RDT - RESERVOIR DESC TOOL SEQ SEQUENCE NUMBER SEQ TEL 

RDT - RESERVOIR DESC TOOL SDEP FT M SFT SET DEPTH SDEP ft m RES 

RDT - RESERVOIR DESC TOOL RING RINGING RING TEL 

RDT - RESERVOIR DESC TOOL RHOF GM/CC GM/CC FLUID DENSITY RHOF gm/cc gm/cc INP 

RDT - RESERVOIR DESC TOOL QTMP DEGF DEGC QUARTZ GAUGE TEMPERATURE QGTEMP degF degC INP 

RDT - RESERVOIR DESC TOOL PWRF HIGH POWER FACTOR PWRFAC TEL 

RDT - RESERVOIR DESC TOOL PVOL CC CC PRETEST VOLUME PTVOL 0.01 L 0.01 L INP 

RDT - RESERVOIR DESC TOOL PTTH PSI KPA PRESSURE TEN THOUSANDS PTTH psi Kpa RES 

RDT - RESERVOIR DESC TOOL QPRS PSI KPA QUARTZ GAUGE PRESSURE QGPRES psi Kpa INP 

RDT - RESERVOIR DESC TOOL SVD PPS Solenoid Valve D PPSSVD TEL 




















Type_ 

Data

Serv_Name 

RDT - RESERVOIR DESC TOOL FPRE PSI PSI FORMATION PRESSURE FPRE PSI PSI INP 


RDT - RESERVOIR DESC TOOL BINS Bins 1-32 BINS INP 

RDT - RESERVOIR DESC TOOL BBLP PSI KPA BUBBLE POINT BBLPNT psi Kpa INP 

RDT - RESERVOIR DESC TOOL B1 B1 SENSOR B1 INP 

RDT - RESERVOIR DESC TOOL AUXV SURFACE AUX VOLTAGE AUXVLT TEL 

RDT - RESERVOIR DESC TOOL AUXC SURFACE AUX CURRENT AUXCUR TEL 

RDT - RESERVOIR DESC TOOL ATIM ASCII ELAPSED TIME A_TIME RES 

RDT - RESERVOIR DESC TOOL HMOB HORIZONTAL MOBILITY MPTHH INP 

RDT - RESERVOIR DESC TOOL RELC Relative Capacitance RELCAP TEL 


RDT - RESERVOIR DESC TOOL FIDV V V FLUID ID VOLTS(Volts) FLVOLT V V INP 

RDT - RESERVOIR DESC TOOL HLOS HPS LOW OIL SWITCH HPSLOS INP 

RDT - RESERVOIR DESC TOOL HI HYDROGEN INDEX HI INP 



RDT - RESERVOIR DESC TOOL GEOM GEOMETRIC MEAN GEOMM INP 

RDT - RESERVOIR DESC TOOL GAIN GAIN GAIN INP 

RDT - RESERVOIR DESC TOOL FTEM DEGF DEGC FLUID TEMPERATURE TEMP1 degF degC TEL 

RDT - RESERVOIR DESC TOOL FREQ FREQUENCY FREQ TEL 

RDT - RESERVOIR DESC TOOL FMSR FPS MOTOR START RELAY FPSMSR TEL 

RDT - RESERVOIR DESC TOOL FLPH DEG DEG FLUID ID PHASE FLPHI DEG deg INP 

RDT - RESERVOIR DESC TOOL FIDI MA MA FLUID ID CURRENT (mA) FLAMP mA mA INP 

RDT - RESERVOIR DESC TOOL EVNT PTA EVENT STRING EVENT INP 

RDT - RESERVOIR DESC TOOL ERES OHMM OHMM ESTIMATED RESISTIVITY ERES ohm.m ohm.m INP 

RDT - RESERVOIR DESC TOOL ECHN Echo Noise ECHONS TEL 





RDT - RESERVOIR DESC TOOL FLTC FAULT CURRENT FLTCUR TEL 

RDT - RESERVOIR DESC TOOL DIEL DIELECTRIC CAPACITANCE DIELCP TEL 





RDT - RESERVOIR DESC TOOL CPRS 1/PSI 1/PSI COMPRESSIBLITY CMPRSS 1/PSI 1/PSI INP 

RDT - RESERVOIR DESC TOOL CPV CVS FLUID PURGE VALVE CVSFPV TEL 

RDT - RESERVOIR DESC TOOL CV1 CVS Chamber Valve 1 CVSCV1 TEL 

RDT - RESERVOIR DESC TOOL CV2 CVS Chamber Valve 2 CVSCV2 TEL 

RMT-ELITE - RESERV MON 

TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 

LIS 

Mnem 

LISU_ 

eng 

LISU_ 


DLISU_ 

Eng 

DLISU_ 

Met 

OAIN OXYGEN ACT INDICATOR NEAR OAI1 RES 

OAIF OXYGEN ACT INDICATOR FAR OAI2 RES 

RCAP RATIO TOTAL CAPTURE RCAP RES 

OBIN OXYGEN BKG INDICATOR NEAR OBI1 RES 

o194 OIN CHANNEL 194 OIN194 RES 

oi68 OIN CHANNEL 68 OIN68 RES 


Type_ 

Data

Serv_Name 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 

LIS 

Mnem 

LISU_ 

eng 

LISU_ 


DLISU_ 

Eng 

DLISU_ 

Met 

o114 OIN CHANNEL 114 OIN114 RES 

OBIF OXYGEN BKG INDICATOR FAR OBI2 RES 

RNFC RATIO NEAR INEL TO NEAR COUNTS RICN RES 

SIAF SILICON ACT INDICATOR FAR SIA2 RES 

SIIN SILICON INDICATOR NEAR SIIC1 RES 

SIIF SILICON INDICATOR FAR SIIC2 RES 

NTIM ACCUMULATION TIME NEAR TIME_N RES 

LMOD LOGGING MODE LMODE PAR 

SICF SULPHUR INDICATOR FAR SIC2 RES 

SICN SULPHUR INDICATOR NEAR SIC1 RES 

SIAN SILICON ACT INDICATOR NEAR SIA1 RES 

NGAI NEAR GAIN NGAIN RES 

LIY1 LITH YIELD RAT INEL NEAR LIYR1 RES 

LIY2 LITH YIELD RAT INEL FAR LIYR2 RES 

YSI1 SILICON YIELD CAPT. NEAR YSI1 RES 

STUF STATISTIC UNCERTAINTY FAR STUN2 RES 

NBAC NEAR BACKGROUND SPECTRUM NBACK INP 

NCAC NEAR CAPTURE SPECTRUM CORR NCAPAC INP 

NBAK NEAR BACKGROUND SPECTRUM NBACK INP 

NFEC NEAR IRON CHANNEL NFECH RES 

NSPT NEAR SPECTRA SUM NSPT RES 

NGAO NEAR GAIN OK NGAOK RES 

NHCH NEAR HYDROGEN CHANNEL NHCH RES 

NINC NEAR INELASTIC SPECTRUM CORR NINELC INP 

NINE NEAR INELASTIC SPECTRUM NINEL INP 

NOFO NEAR OFFSET OK NOFOK RES 

NOFS NEAR OFFSET NOFST RES 

NCAP NEAR CAPTURE SPECTRUM NCAP INP 

YMG2 MAGNESIUM YIELD CAPT. FAR YMG2 RES 

YIC2 CALCIUM YIELD INEL FAR YICA2 RES 

YIO1 OXYGEN YIELD INEL NEAR YIO1 RES 

YIO2 OXYGEN YIELD INEL FAR YIO2 RES 

YIS1 SILICON YIELD INEL NEAR YISI1 RES 


Type_ 

Data

Serv_Name 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 

LIS 

Mnem 

LISU_ 

eng 

LISU_ 


DLISU_ 

Eng 

DLISU_ 

Met 

YIS2 SILICON YIELD INEL FAR YISI2 RES 

YK1 POTASSIUM YIELD CAPT. NEAR YK1 RES 

YS1 SULPHUR YIELD CAPT. NEAR YS1 RES 

YMG1 MAGNESIUM YIELD CAPT. NEAR YMG1 RES 

YH1 HYDROGEN YIELD CAPT. NEAR YH1 RES 

YS2 SULPHUR YIELD CAPT. FAR YS2 RES 

YSI2 SILICON YIELD CAPT. FAR YSI2 RES 

YTI1 TITANIUM YIELD CAPT. NEAR YTI1 RES 

YTI2 TITANIUM YIELD CAPT. FAR YTI2 RES 

LIRN LITH INDEX INEL NEAR LIRI1 RES 

FGAI FAR GAIN FGAIN RES 

YK2 POTASSIUM YIELD CAPT. FAR YK2 RES 

YCA2 CALCIUM YIELD CAPT. FAR YCA2 RES 

TCCF TOTAL COUNTS FAR TCCR2 RES 

TCCN TOTAL COUNTS NEAR TCCR1 RES 

TNGC NEAR SPACED GATES CORR TNGTC INP 

TNGT NEAR SPACED GATES TNGT INP 

TNGT NEAR SPACED GATES TNGT INP 

YC1 CARBON YIELD INEL NEAR YIC1 RES 

YIC1 CALCIUM YIELD INEL NEAR YICA1 RES 

YCA1 CALCIUM YIELD CAPT. NEAR YCA1 RES 

YH2 HYDROGEN YIELD CAPT. FAR YH2 RES 

YCL1 CHLORINE YIELD CAPT. NEAR YCL1 RES 

YCL2 CHLORINE YIELD CAPT. FAR YCL2 RES 

YEX1 EXTRA YIELD CAPT. NEAR YEX1 RES 

YEX2 EXTRA YIELD CAPT. FAR YEX2 RES 

YFE1 IRON YIELD CAPT. NEAR YFE1 RES 

YFE2 IRON YIELD CAPT. FAR YFE2 RES 

STUN STATISTIC UNCERTAINTY NEAR STUN1 RES 

YC2 CARBON YIELD INEL FAR YIC2 RES 

ERIN RATIO NEAR/ FAR INELASTIC EVR ERIN RES 

FEIN IRON INDICATOR NEAR FEIC1 RES 

CRAF COMPTON RATIO FAR CRAT2 RES 


Type_ 

Data

Serv_Name 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 

LIS 

Mnem 

LISU_ 

eng 

LISU_ 


DLISU_ 

Eng 

DLISU_ 

Met 

CRAN COMPTON RATIO NEAR CRAT1 RES 

EFCA FAR COUNTRATE EVR EFCA RES 

EFSI FAR INELASTIC COUNTS EVR EFSI RES 

ENCA NEAR COUNTRATE EVR ENCA RES 

COYF C0 YIELD RAT INEL FAR COYR2 RES 

ERIC RATIO FAR INEL/FAR COUNTS EVR ERIC RES 

COIN CO RATIO INELASTIC NEAR COIR1 RES 

ERNF RATIO NEAR / FAR - EVR ERNF RES 

ESGI CU CU FAR FORMATION SIGMA EVR ESGF RES 

ESGN CU CU NEAR FORMATION SIGMA EVR ESGN RES 

FBAC FAR BACKGROUND SPECTRUM FBACK INP 

FCAP FAR CAPTURE SPECTRUM FCAP INP 

FCPC FAR CAPTURE SPECTRUM CORR FCAPAC INP 

FEIF IRON INDICATOR FAR FEIC2 RES 

ENSI NEAR INELASTIC COUNTS EVR ENSI RES 

AFTN NEAR FORMATION AMPLITUDE AFTN RES 

1780 SILICON CHANNEL E1780 RES 

2220 HYDROGEN CHANNEL E2220 RES 

3730 CALCIUM CHANNEL E3730 RES 

4440 CARBON CHANNEL E4440 RES 

6100 OXYGEN CHANNEL E6100 RES 

7140 OXYGEN FIRST ESCAPE CHANNEL E7140 RES 

COYN C0 YIELD RAT INEL NEAR COYR1 RES 

AFTF FAR FORMATION AMPLITUDE AFTF RES 

CFT1 CAPTURE FIT ERROR NEAR CFTR1 RES 

FHCH FAR HYDROGEN CHANNEL FHCH RES 

CAIN CALCIUM INDICATOR NEAR CAIC1 RES 

LIRF LITH INDEX INEL FAR LIRI2 RES 

CFT2 CAPTURE FIT ERROR FAR CFTR2 RES 

CLIF CHLORINE INDICATOR FAR CLIC2 RES 

CLIN CHLORINE INDICATOR NEAR CLIC1 RES 

COIF CO RATIO INELASTIC FAR COIR2 RES 

7650 IRON CHANNEL E7650 RES 


Type_ 

Data

Serv_Name 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 


TOOL 

LIS 

Mnem 

LISU_ 

eng 

LISU_ 


DLISU_ 

Eng 

DLISU_ 

Met 

IR10 LOG RATIO TOTAL INELASTIC IRIN10 RES 

HPLN HYDROGEN PEAK NEAR HPLI1 RES 

IFT2 INELASTIC FIT ERROR FAR IFTR2 RES 

FERF IRON PEAK FAR FERC2 RES 

INC2 INCA FAR INCA2 RES 

INC2 INCA FAR INCA2 RES 

INX1 INOXY NEAR INOX1 RES 

HPLF HYDROGEN PEAK FAR HPLI2 RES 

IONI MA MA ION CURRENT IONI MA MA INP 

IFT1 INELASTIC FIT ERROR NEAR IFTR1 RES 

IRIN RATIO TOTAL INELASTIC IRIN RES 

ITCF INELASTIC TOTAL COUNTS FAR ITCR2 RES 

ITCN INELASTIC TOTAL COUNTS NEAR ITCR1 RES 

KAT1 KATO NEAR KATO1 RES 

KAT2 KATO FAR KATO2 RES 

CAIF CALCIUM INDICATOR FAR CAIC2 RES 

INX2 INOXY FAR INOX2 RES 

FINC FAR INELASTIC SPECTRUM CORR FINELC INP 

FERN IRON PEAK NEAR FERC1 RES 

FFEC FAR IRON CHANNEL FFECH RES 

KICN POTASSIUM INDICATOR NEAR KIC1 RES 

INC1 INCA NEAR INCA1 RES 

KICF POTASSIUM INDICATOR FAR KIC2 RES 

HICN HYDROGEN INDICATOR NEAR HIC1 RES 

FINE FAR INELASTIC SPECTRUM FINEL INP 

FOFO FAR OFFSET OK FOFOK RES 

FOFS FAR OFFSET FOFST RES 

FSPT FAR SPECTRA SUM FSPT RES 

FTIM ACCUMULATION TIME FAR TIME_F RES 

FTMP DEGF DEGC INTERNAL FLASK TEMPERATURE FTMP degF degC RES 

FTRF SPECTRAL FIT ERROR FAR FTR2 RES 

FTRN SPECTRAL FIT ERROR NEAR FTR1 RES 

HICF HYDROGEN INDICATOR FAR HIC2 RES 


Type_ 

Data

Serv_Name 


TOOL 

LIS 

Mnem 

LISU_ 

eng 

LISU_ 


FGAO FAR GAIN OK FGAOK RES 

SDDT/NAV - DIRECTIONAL AZI1 DEG DEG PAD 1 AZIMUTH AZI1 deg deg RES 

SDDT/NAV - DIRECTIONAL MAGQ MAGNETOMETER SUM OF SQUARES MAGQ RES 

SDDT/NAV - DIRECTIONAL TEMP DEGC DEGC NAVIGATION TEMPERATURE TEMP degC degC RES 

SDDT/NAV - DIRECTIONAL RBX DEG DEG AUXILIARY ROTATION RBX deg deg RES 

SDDT/NAV - DIRECTIONAL RB DEG DEG RELATIVE BEARING RB deg deg RES 

SDDT/NAV - DIRECTIONAL MAGZ MAGNETOMETER Z-AXIS MAGZ RES 

SDDT/NAV - DIRECTIONAL MAGX MAGNETOMETER X-AXIS MAGX RES 

SDDT/NAV - DIRECTIONAL AX G G ACCELEROMETER X-AXIS AX G G RES 

SDDT/NAV - DIRECTIONAL HAZI DEG DEG DRIFT / HOLE AZIMUTH HAZI deg deg RES 

SDDT/NAV - DIRECTIONAL MAGY MAGNETOMETER Y-AXIS MAGY RES 

SDDT/NAV - DIRECTIONAL ACCQ ACCELEROMETER SUM OF SQUARES ACCQ RES 

SDDT/NAV - DIRECTIONAL AY G G ACCELEROMETER Y-AXIS AY G G RES 

SDDT/NAV - DIRECTIONAL AZ G G ACCELEROMETER Z-AXIS AZ G G RES 

SDDT/NAV - DIRECTIONAL AZI1 DEG DEG REFERENCED AZIMUTH AZI1 deg deg RES 

SDDT/NAV - DIRECTIONAL AZIX DEG DEG AUXILIARY AZIMUTH AZIX deg deg RES 

SDDT/NAV - DIRECTIONAL DEVI DEG DEG DRIFT ANGLE DEVI deg deg RES 

SDDT/NAV - DIRECTIONAL DXTM MS MS Z-ACCELEROMETER, TIME BASE DXTM mS mS INP 

SDL - SPECTRAL DENSITY NAB CPS CPS NEAR ABOVE NAB 1.0/S 1.0/S TEL 

SDL - SPECTRAL DENSITY NHV V V NEAR HIGH VOLTAGE NHV V V INP 

SDL - SPECTRAL DENSITY NLU CPS CPS NEAR LITHOLOGY UNFILTERED NLIU 1.0/S 1.0/S TEL 

SDL - SPECTRAL DENSITY NLO CPS CPS NEAR CESIUM LOW NLO 1.0/S 1.0/S TEL 

SDL - SPECTRAL DENSITY NLIU CPS CPS NEAR LITHOLOGY UNFILTERED NLIU 1.0/S 1.0/S INP 

SDL - SPECTRAL DENSITY NLI CPS CPS NEAR LITHOLOGY NLI 1.0/S 1.0/S TEL 

SDL - SPECTRAL DENSITY NPK CPS CPS NEAR PEAK NPK 1.0/S 1.0/S TEL 

SDL - SPECTRAL DENSITY NHI CPS CPS NEAR CESIUM HI NHI 1.0/S 1.0/S TEL 

SDL - SPECTRAL DENSITY NDE CPS CPS NEAR DENSITY NDE 1.0/S 1.0/S TEL 

SDL - SPECTRAL DENSITY NVA CPS CPS NEAR VALLEY NVA 1.0/S 1.0/S TEL 

SDL - SPECTRAL DENSITY NBA CPS CPS NEAR BARITE NBA 1.0/S 1.0/S TEL 

SDL - SPECTRAL DENSITY QF FAR QUALITY QF RES 

SDL - SPECTRAL DENSITY M5AN V V MINUS 5 VOLTS ANALOG MI5AN V V INP 

SDL - SPECTRAL DENSITY M15V V V MINUS 15 VOLTS MI15V V V INP 

SDL - SPECTRAL DENSITY LDWC HSDL LS DENSITY WINDOW COUNTS LDENWD RES 

SDL - SPECTRAL DENSITY NBAU CPS CPS NEAR BARITE UNFILTERED NBAU 1.0/S 1.0/S TEL 

SDL - SPECTRAL DENSITY QS SDL QUALITY SHORT QS RES 

SDL - SPECTRAL DENSITY SPWC HSDL SS PEAK WINDOW COUNTS SPEKWD RES 

SDL - SPECTRAL DENSITY SLWC HSDL SS LITH. WINDOW COUNTS SLITWD RES 

SDL - SPECTRAL DENSITY SDWC HSDL SS DENSITY WINDOW COUNTS 

SDENW 

D 

DLISU_ 

Eng 

DLISU_ 

Met 

SDL - SPECTRAL DENSITY SDSO IN MM SDL STANDOFF SDSO in mm RES 

SDL - SPECTRAL DENSITY SDC1 INCH MM SDL PAD CALIPER CALIP in mm TEL 

SDL - SPECTRAL DENSITY SBWC HSDL SS BARITE WINDOW COUNTS SBARWD RES 

SDL - SPECTRAL DENSITY PRTM C C PRE-REG. TEMPERATURE PRTMP C C INP 

SDL - SPECTRAL DENSITY REF5 V V 5 VOLT REFERENCE REF5 V V INP 

SDL - SPECTRAL DENSITY P15V VOLT VOLT PLUS 15 VOLTS P15 V V TEL 

SDL - SPECTRAL DENSITY QN NEAR QUALITY QN RES 

SDL - SPECTRAL DENSITY QL SDL QUALITY LONG QL RES 

SDL - SPECTRAL DENSITY PTMP PAD TEMPERATURE PTMP TEL 

SDL - SPECTRAL DENSITY LBWC HSDL LS BARITE WINOW COUNTS LBARWD RES 


Type_ 

Data 

RES

Serv_Name 

LIS 

Mnem 

LISU_ 

eng 

LISU_ 


DLISU_ 

Eng 

DLISU_ 

Met 

SDL - SPECTRAL DENSITY PE PHOTO-ELECTRIC FACTOR PE RES 

SDL - SPECTRAL DENSITY P5AN V V Plus 5 Volts Analog PL5AN V V INP 

SDL - SPECTRAL DENSITY RHOB G/C3 K/M3 BULK DENSITY RHOB g/cm3 Kg/m3 RES 

SDL - SPECTRAL DENSITY DLIM DECP DECP DENSITY POROSITY, LIMESTONE DLIM 100 pu 100 pu RES 

SDL - SPECTRAL DENSITY EDLI DECP DECP DENSITY POROSITY LIME, EVR EDLI 100 pu 100 pu RES 

SDL - SPECTRAL DENSITY EDCT G/CC K/M3 EVR DENSITY CORRECTION TOTAL EDCT GM/CC KG/M3 RES 

SDL - SPECTRAL DENSITY EDCP G/CC K/M3 EVR DENSITY CORRECTION POS. EDCP GM/CC KG/M3 RES 

SDL - SPECTRAL DENSITY EDCN G/CC K/M3 EVR DENSITY CORRECTION NEG. EDCN GM/CC KG/M3 RES 

SDL - SPECTRAL DENSITY DRHO G/C3 K/M3 DENSITY CORRECTION DRHO g/cm3 Kg/m3 RES 

SDL - SPECTRAL DENSITY DPHS DECP DECP DENSITY POROSITY, SANDSTONE DPHS 100 pu 100 pu RES 

SDL - SPECTRAL DENSITY EDMF EVR MINIMUM FILTERING EDMF RES 

SDL - SPECTRAL DENSITY DPHD DECP DECP DENSITY POROSITY, DOLOMITE DPHD 100 pu 100 pu RES 

SDL - SPECTRAL DENSITY DPE PE CORRECTION DPE RES 

SDL - SPECTRAL DENSITY DCOM DENSITY CORRECTION MINUS DCOR_M RES 

SDL - SPECTRAL DENSITY DC10 V V DCB 10 Volt Reference DCB10 V V INP 

SDL - SPECTRAL DENSITY CORP DENSITY CORRECTION PLUS CORP RES 

SDL - SPECTRAL DENSITY 5VD V V 5 Volt 5VD V V INP 

SDL - SPECTRAL DENSITY CORM DENSITY CORRECTION MINUS CORM RES 

SDL - SPECTRAL DENSITY ITMP INSTRUMENT TEMPERATURE ITMP TEL 

SDL - SPECTRAL DENSITY PROU V V Pre Reg OUT PROUT V V INP 

SDL - SPECTRAL DENSITY DPHI DECP DECP DENSITY POROSITY DPHI 100 pu 100 pu RES 

SDL - SPECTRAL DENSITY FDE CPS CPS FAR DENSITY FDE 1.0/S 1.0/S TEL 

SDL - SPECTRAL DENSITY DCOP DENSITY CORRECTION PLUS DCOR_P RES 

SDL - SPECTRAL DENSITY EDPD DECP DECP DENSITY POROSITY DOLO, EVR EDPD 100 pu 100 pu RES 

SDL - SPECTRAL DENSITY FPK CPS CPS FAR PEAK FPK 1.0/S 1.0/S TEL 

SDL - SPECTRAL DENSITY FLO CPS CPS FAR CESIUM LOW FLO 1.0/S 1.0/S TEL 

SDL - SPECTRAL DENSITY FLI CPS CPS FAR LITHOLOGY FLI 1.0/S 1.0/S TEL 

SDL - SPECTRAL DENSITY FHI CPS CPS FAR CESIUM HIGH FHI 1.0/S 1.0/S TEL 

SDL - SPECTRAL DENSITY FVA CPS CPS FAR VALLEY FVA 1.0/S 1.0/S TEL 

SDL - SPECTRAL DENSITY FBA CPS CPS FAR BARITE FBA 1.0/S 1.0/S TEL 

SDL - SPECTRAL DENSITY EDPS DECP DECP DENSITY POROSITY SAND, EVR EDPS 100 pu 100 pu RES 

SDL - SPECTRAL DENSITY EDPH DECP DECP DENSITY POROSITY, EVR EDPH 100 pu 100 pu RES 

SDL - SPECTRAL DENSITY FHV V V FAR HIGH VOLTAGE FHV V V INP 

SDL - SPECTRAL DENSITY EDPL DECP DECP EVR DENSITY LIME POROSITY EDPL 100 pu 100 pu RES 

SDL - SPECTRAL DENSITY FAB CPS CPS FAR ABOVE FAB 1.0/S 1.0/S TEL 

SDL - SPECTRAL DENSITY EMPE EVR PE - MIN FILT EMPE RES 

SDL - SPECTRAL DENSITY EMRH G/CC KG/M3 EVR BULK DENSITY - MIN FILT EMRH G/CC KG/M3 RES 

SDL - SPECTRAL DENSITY EPE PE EVR EPE RES 

SDL - SPECTRAL DENSITY EPMF EVR PE MINIMUM FILTERING EPMF RES 

SDL - SPECTRAL DENSITY ERHO G/CC KG/M3 BULK DENSITY - EVR PROCESSED ERHO G/CC KG/M3 RES 

SED - SIX ELECT DIPMETER PDD2 OHMM OHMM SED PAD #2 RESISTIVITY (FAST) PDD2 ohm.m ohm.m RES 

SED - SIX ELECT DIPMETER MAGZ MAGNETOMETER Z-AXIS MAGZ RES 

SED - SIX ELECT DIPMETER MAGY MAGNETOMETER Y-AXIS MAGY RES 

SED - SIX ELECT DIPMETER P2B1 OHMM OHMM SED PAD #2, RESISTIVITY P2B1 ohm.m ohm.m RES 







Type_ 

Data

Serv_Name 

LIS 

Mnem 

LISU_ 

eng 

LISU_ 


DLISU_ 

Eng 

DLISU_ 

Met 

SED - SIX ELECT DIPMETER P1B1 OHMM OHMM SED PAD #1 RESISTIVITY P1B1 ohm.m ohm.m RES 





SED - SIX ELECT DIPMETER PDDV V V SED PAD VOLTAGE PDDV V V RES 

SED - SIX ELECT DIPMETER PRES SED PAD FORCE PRES RES 

SED - SIX ELECT DIPMETER RB DEG DEG PAD #1 ROTATION RB deg deg RES 

SED - SIX ELECT DIPMETER ZACC G G SED Z ACCELEROMETER (FAST) ZACC G G RES 

SED - SIX ELECT DIPMETER MAGX MAGNETOMETER X-AXIS MAGX RES 

SED - SIX ELECT DIPMETER F2B1 SED PAD #2, PROFILE 1 (FAST) F2B1 RES 

SED - SIX ELECT DIPMETER TEMP DEGC DEGC NAVIGATION TEMPERATURE TEMP degC degC RES 

SED - SIX ELECT DIPMETER CAL3 IN MM SED CALIPER ARM #3 (RADIUS X2) CAL3 in mm RES 

SED - SIX ELECT DIPMETER ACCX G G ACCELEROMETER X-AXIS ACCX G G RES 

SED - SIX ELECT DIPMETER ACCY G G ACCELEROMETER Y-AXIS ACCY G G RES 


SED - SIX ELECT DIPMETER MAGQ MAGNETOMETER SUM OF SQUARES MAGQ RES 

SED - SIX ELECT DIPMETER C14 IN MM SED CALIPER PAIR 1-4 C14 in mm RES 








SED - SIX ELECT DIPMETER DEVI DEG DEG DRIFT ANGLE DEVI deg deg RES 

SED - SIX ELECT DIPMETER DMAX IN MM SED MAXIMUM CALIPER PAIR DMAX in mm RES 

SED - SIX ELECT DIPMETER DMIN IN MM SED MINIMUM CALIPER PAIR DMIN in mm RES 

SED - SIX ELECT DIPMETER DXTM 08.3MS 08.3MS SED Z-ACCELEROMETER, TIME BASE DXTM 8.3 mS 8.3 mS INP 



SED - SIX ELECT DIPMETER CALA IN MM SED AVERAGE CALIPER CALA in mm RES 


SED - SIX ELECT DIPMETER HAZI DEG DEG DRIFT AZIMUTH HAZI deg deg RES 


SFT - SEQ FORM TESTER STTF DEGF DEGF SFT TRANSDUCER TEMPERATURE STTF degF degF RES 

SFT - SEQ FORM TESTER STTC DEG C DEG C SFT TRANSDUCER TEMP STTC DEG C DEG C RES 

SFT - SEQ FORM TESTER SSI SAMPLE SHUTIN LOGICAL SSI RES 

SFT - SEQ FORM TESTER SITF DEGF DEGF SFT INSTRUMENT TEMPERATURE SITF degF degF RES 

SFT - SEQ FORM TESTER SITC DEGC DEGC SFT INSTRUMENT TEMPERATURE SITC degC degC RES 

SFT - SEQ FORM TESTER SDEP FT M SFT SET DEPTH SDEP ft m RES 

SFT - SEQ FORM TESTER RPRE PSI KPA STRAIN GAUGE PRESSURE RPRE psi Kpa RES 

SFT - SEQ FORM TESTER SAMP CC CC PRETEST VOLUME SAMP 0.01 L 0.01 L RES 

SFT - SEQ FORM TESTER TENS LB KG LINE TENSION (SURFACE) TENS lbm Kg RES 

SFT - SEQ FORM TESTER HSFE HSFT Event HSFE RES 

SFT - SEQ FORM TESTER SDD PSI KPA SFT SAMPLE DRAWDOWN SDD psi Kpa RES 

SFT - SEQ FORM TESTER TLPS TOOL POSITION TLPS RES 

SFT - SEQ FORM TESTER TMIN MN MN TEST TIME MINUTES TMIN min min RES 

SFT - SEQ FORM TESTER TPT MN MN PRETEST TIME TPT min min RES 


Type_ 

Data

Serv_Name 

SFT - SEQ FORM TESTER TSAM MN MN SFT SAMPLE TIME TSAM min min RES 

SFT - SEQ FORM TESTER TSEC S S SECONDS INTO TEST TSEC S S RES 

SFT - SEQ FORM TESTER TSI MN MN SHUTIN TIME TSI min min RES 

SFT - SEQ FORM TESTER TTMP DEGF DEGF HSFT TRANSDUCER TEMPERATURE TTMP degF degF RES 

SFT - SEQ FORM TESTER STRA PSI KPA STRAIN PRESSURE STRA psi Kpa RES 

SFT - SEQ FORM TESTER HYDP PSI KPA HSFT HYDRAULIC PRESSURE HYDP psi Kpa RES 

SFT - SEQ FORM TESTER HTF PSI KPA HONER BUILD UP DITS HTF psi Kpa RES 

SFT - SEQ FORM TESTER PTTH PSI KPA PRESSURE TEN THOUSANDS PTTH psi Kpa RES 

SFT - SEQ FORM TESTER PROD PSI KPA DRAW DOWN PRESSURE PROD psi Kpa RES 

SFT - SEQ FORM TESTER DMV V V SFT DOWNHOLE MOTOR VOLTAGE DMV V V RES 

SFT - SEQ FORM TESTER KHOR MD MD HORNER PERMEABILITY KHOR mD mD RES 

SFT - SEQ FORM TESTER PTHS PSI KPA PRESSURE TENTHS PTHS psi Kpa RES 

SFT - SEQ FORM TESTER ATXT ASCII ACTION EVENTS A_TEXT RES 

SFT - SEQ FORM TESTER ATIM ASCII ELAPSED TIME A_TIME RES 

SFT - SEQ FORM TESTER DIV V V SFT INSTRUMENT VOLTAGE DIV V V RES 

SFT - SEQ FORM TESTER FTHU PSI KPA STRAIN PRESSURE HUNDREDS FTHU psi Kpa RES 

SFT - SEQ FORM TESTER FTON PSI KPA STRAIN PRESSURE ONES FTON psi Kpa RES 

SFT - SEQ FORM TESTER FTTE PSI KPA STRAIN PRESSURE TENS FTTE psi Kpa RES 

SFT - SEQ FORM TESTER FTTH PSI KPA STRAIN PRESSURE THOUSANDS FTTH psi Kpa RES 

SFT - SEQ FORM TESTER HORT HORNER TIME (DIMENSIONLESS) HORT RES 

SFT - SEQ FORM TESTER KD MD MD DRAWDOWN PERMEABILITY KD mD mD RES 

SFT - SEQ FORM TESTER PBUP PSI KPA SFT PRETEST BUILDUP PBUP psi Kpa RES 

SFT - SEQ FORM TESTER PRDD PSI KPA DRAW DOWN PRESSURE PRDD psi Kpa RES 

SFT - SEQ FORM TESTER PTHO PSI KPA PRESSURE THOUSANDS PTHO psi Kpa RES 

SFT - SEQ FORM TESTER PHDS PSI KPA PRESSURE HUNDREDTHS PHDS psi Kpa RES 

SFT - SEQ FORM TESTER PSBU PSI KPA SAMPLE BUILDUP PSBU psi Kpa RES 

SFT - SEQ FORM TESTER PTEN PSI KPA PRESSURE TENS PTEN psi Kpa RES 

SFT - SEQ FORM TESTER PRES PSI KPA TOTAL PRESSURE PRES psi Kpa RES 

SFT - SEQ FORM TESTER PPSI PSI KPA SFT PREVIOUS SHUT-IN PRESSURE PPSI psi Kpa RES 

SFT - SEQ FORM TESTER PPSI PSI KPA SFT PREVIOUS SHUT-IN PRESSURE PPSI psi Kpa RES 

SFT - SEQ FORM TESTER PONE PSI KPA SFT PRESSURE ONES PONE psi Kpa RES 

SFT - SEQ FORM TESTER PHUN PSI KPA PRESSURE HUNDREDS PHUN psi Kpa RES 

SFT - SEQ FORM TESTER PHST PSI KPA SFT HYDROSTATIC PRESSURE PHST psi Kpa RES 

SFT - SEQ FORM TESTER PHFL PSI KPA SFT HYDRAULIC PRESSURE PHFL psi Kpa RES 

TMD-L - THERMAL MULTIGATE 

DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 

LIS 

Mnem 

LISU_ 

eng 

LISU_ 


DLISU_ 

Eng 

DLISU_ 

Met 

RICL ALOG10(RINC) RINCL RES 

NSG6 NEAR GATE 6 CNTS UNFILTERED NSG6 RES 

QW WATER FLOW RATE QW RES 

RIN RATIO NEAR TO FAR INELASTIC RIN RES 

PHIT POROSITY FROM NEAR/FAR RATIO PHIT RES 

OBI OXYGEN BACKGROUND OBI RES 

OB66 OB66 OB66 RES 

RINC RATIO N NET INEL TO F NET INEL RINC RES 

OAI OXYGEN ACTIVATION OAI RES 

RICF RATIO FAR TO FAR COUNTS RICF RES 


Type_ 

Data

Serv_Name 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 

LIS 

Mnem 

LISU_ 

eng 

LISU_ 


DLISU_ 

Eng 

DLISU_ 

Met 

O194 OA194 OA194 RES 

O114 OA114 OA114 RES 

NTMD NEAR COUNTRATE NTMD RES 


NSGI NEAR GATE I NSGI RES 



RINL Log(RIN) RINL RES 

SGIN CU CU INTRINSIC FORMATION SIGMA SGIN cu CU RES 


NSG1 NEAR GATE 1CNTS UNFILTERED NSG1 RES 

NSIN CU CU NEAR INELASTIC COUNTS NSIN cu CU RES 

SGNU NEAR SIGMA STATISTIC SGNU RES 

NSBU NEAR BACKGROUND UNFILTERED NSBU RES 

INOX OXYGEN VALUE INOX RES 

YSI YIELD SILICATE YSI RES 

YFE YIELD IRON YFE RES 

YCA YIELD CARBONATE YCA RES 

Y4 YIELD EXTRA Y4 RES 

WBUF Work Space Buffer WBUF RES 

TNGT NEAR SPACED UNFILTERED TNGT INP 

TNA TOTAL NEAR ACTIVATION TNA RES 

TFGT FAR SPACED GATES TFGT INP 

SGFN CU CU NEAR FORMATION SIGMA SGFN cu CU RES 

TFA TOTAL FAR ACTIVATION TFA RES 

ROA RATIO OXYGEN ACTIVATION ROA RES 

SGFU FAR SIGMA STATISTIC SGFU RES 

SGFM CU CU CORRECTED FORMATION SIGMA SGFM cu CU RES 

SGFF CU CU FAR FORMATION SIGMA SGFF cu CU RES 

SGBN CU CU NEAR BOREHOLE SIGMA SGBN cu CU RES 

SGBF CU CU FAR BOREHOLE SIGMA SGBF cu CU RES 

RTMD RATIO NEAR TO FAR COUNTRATE RTMD RES 

RTBF RATIO NEAR BORE TO FORM AMP RTBF RES 


Type_ 

Data

Serv_Name 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 

LIS 

Mnem 

LISU_ 

eng 

LISU_ 


DLISU_ 

Eng 

DLISU_ 

Met 

ROAT RATIO OXYGEN ACTIVATION TOTAL ROAT RES 

ROAS RATIO OXY ACTIVATION SPECTRAL ROAS RES 

ROAG RATIO OXYGEN ACTIVATION GAMMA ROAG RES 

TFGT FAR SPACED UNFILTERED TFGT INP 

E510 E510 E510 RES 

FACT FAT ACTIVATION SPECTRUM FACT INP 

ESGN CU CU EVR SIGMA NEAR ESGN cu CU RES 

ESGF CU CU EVR SIGMA FORMATION FAR ESGF cu CU RES 

ESFM CU CU EVR SIGMA FORMATION CORRECTED ESFM cu CU RES 

ERIN EVR RATIO INEL COUNTS ERIN RES 

ERIC EVR RATIO INEL/FS COUNTS ERIC RES 

ENTM EVR NEAR COUNTS ENTM RES 

EGR GAPI GAPI NATURAL GAMMA RAY - EVR EGR gAPI gAPI RES 

EFTM EVR FAR COUNTS EFTM RES 

EFSI EVR FAR INELASTIC COUNTS EFSI RES 

ECRN EVR CORR RATIO COUNT ECRN RES 

FDX FLOW DETECTION INDICATOR FDX RES 

E645 OXYGEN CHANNEL - SECOND ESCAPE E645 RES 

ERAT EVR RATIO NEAR/FAR COUNTRATE ERAT RES 

DSIG DELTA SIGMA FORMATION DSIG RES 

DCSF DIFFUSION CORRECTED SIGMA FORM DCSF RES 

ABTF FAR BOREHOLE AMPLITUDE ABTF RES 

ABTN NEAR BOREHOLE AMPLITUDE ABTN RES 

BACK BACKGROUND SPECTRUM BACK INP 

BKSM SPECTRUM SUMS BKSM RES 

BORE BOREHOLE SPECTRUM BORE INP 

CRAT COMPTON RATIO CRAT RES 

CRNF CORRECTED RATIO CRNF RES 

ITMP DEGF DEGC INTERNAL INSTRUMENT TEMPERATUR ITMP degF degC RES 

NSBF NEAR BACKGROUND FILTERED NSBF RES 

E665 IRON EDGE E665 RES 

INCA CATION VALUE INCA RES 

NNIN NEAR NET INELASTIC COUNT RATE NNIN RES 


Type_ 

Data

Serv_Name 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 


DECAY 

LIS 

Mnem 

LISU_ 

eng 

LISU_ 


DLISU_ 

Eng 

DLISU_ 

Met 

NFTR NEAR FIT ERROR NFTR RES 

NACT NEAR ACTIVATION SPECTRUM NACT INP 

KATO RATIO CATION/OXYGEN VALUE KATO RES 

ENSI EVR NEAR INELASTIC COUNTS ENSI RES 

INEL INELASTIC SPECTRUM INEL INP 

FFTR FAR FIT ERROR FFTR RES 

GRA API API GAMMA RAY TMD FILTERED GRA gAPI gAPI RES 

GENV VOLTS VOLTS GENERATOR VOLTS GENV VOLTS VOLTS INP 

FVT FLOW VELOCITY TOTAL FVT RES 

FVS FLOW VELOCITY SPECTRAL FVS RES 

FVG FLOW VELOCITY GAMMA FVG RES 

FV FLOW VELOCITY FV RES 

FTMD FAR COUNTRATE FTMD RES 

FSG1 FAR GATE 1 CNTS UNFILTERED FSG1 RES 

FNIN FAR NET INELASTIC COUNT RATE FNIN RES 

IONI MA MA ION CURRENT IONI MA MA INP 

FSIN FAR INELASTIC COUNTS FSIN RES 

FORM FORMATION SPECTRUM FORM INP 

FSBU FAR BACKGROUND UNFILTERED FSBU RES 






FSGI FAR GATE I FSGI RES 

FSBF FAR BACKGROUND FILTERED FSBF RES 

WSTT - WAVESONIC SBY Y B-D PRES WAVEFORM SEMBLANCE SBY INP 

WSTT - WAVESONIC YSBP Y SEMBLANCE VALUE OF PEAK YSBP INP 

WSTT - WAVESONIC SBX X A-C PRES WAVEFORM SEMBLANCE SBX INP 

WSTT - WAVESONIC SPHI DECP DECP SONIC POROSITY SPHI 100 pu 100 pu RES 

WSTT - WAVESONIC VPVX VELOCITY RATIO X VPVX INP 

WSTT - WAVESONIC VPVY VELOCITY RATIO Y VPVY INP 

WSTT - WAVESONIC WVST XACT FORMAT DATA STRUCTURE WVST INP 

WSTT - WAVESONIC XDT2 X DIPOLE PEAK SLOWNESS 2 XDT2 INP 

WSTT - WAVESONIC XSBP X SEMBLANCE VALUE OF PEAK XSBP INP 

WSTT - WAVESONIC XSH X DIPOLE UPPER SLOWNESS XSH INP 


Type_ 

Data

Serv_Name 

WSTT - WAVESONIC XSL X DIPOLE LOWER SLOWNESS XSL INP 

WSTT - WAVESONIC YDT Y DIPOLE PEAK SLOWNESS YDT INP 

WSTT - WAVESONIC YMUT Y DIPOLE MUTE YMUT INP 

WSTT - WAVESONIC YSH Y DIPOLE UPPER SLOWNESS YSH INP 

WSTT - WAVESONIC YSL Y DIPOLE LOWER SLOWNESS YSL INP 

WSTT - WAVESONIC XDT X DIPOLE PEAK SLOWNESS XDT INP 

WSTT - WAVESONIC SBM MONO PRES WAVEFORM SEMBLANCE SBM INP 

WSTT - WAVESONIC YDT2 Y DIPOLE PEAK SLOWNESS 2 YDT2 INP 

WSTT - WAVESONIC DXRV DIPOLE X WAVE RIGHT VALUE DXRV INP 

WSTT - WAVESONIC PRY POISSON"S RATIO Y PRY INP 

WSTT - WAVESONIC XMUT X DIPOLE MUTE XMUT INP 

WSTT - WAVESONIC DXLV DIPOLE X WAVE LEFT VALUE DXLV INP 

WSTT - WAVESONIC DPSY DIPOLE SOURCE Y STRUCTURE DPSY INP 

WSTT - WAVESONIC DPSX DIPOLE SOURCE X STRUCTURE DPSX INP 

WSTT - WAVESONIC D2CT DIPOLE 2 COMPRESSED WORD COUNT D2CT INP 

WSTT - WAVESONIC D1CT DIPOLE 1 COMPRESSED WORD COUNT D1CT INP 

WSTT - WAVESONIC ACQN ACQUISITION NUMBER ACQN INP 

WSTT - WAVESONIC DXXW X DIPOLE A-C #1 PRES WAVEFORM DXXW INP 

WSTT - WAVESONIC DYLV DIPOLE Y LEFT VALUE DYLV INP 

WSTT - WAVESONIC DYRV DIPOLE Y RIGHT VALUE DYRV INP 

WSTT - WAVESONIC DYYW Y DIPOLE B-D #1 PRES WAVEFORM DYYW INP 

WSTT - WAVESONIC FAZI DIRECTION OF FAST SHEAR WAVE FAZI INP 

WSTT - WAVESONIC MSH MONOPOLE UPPER SLOWNESS MSH INP 

WSTT - WAVESONIC PNSA % ANISOTROPY PNSA INP 

WSTT - WAVESONIC PRX POISSON"S RATIO X PRX INP 

WSTT - WAVESONIC CONF CONFIDENCE OF THE MEASUREMENT CONF INP 

WSTT - WAVESONIC MCNT MONOPOLE COMPRESSED WORD COUNT MCNT INP 

WSTT - WAVESONIC MWRV MONOPOLE WAVE RIGHT VALUE MWRV INP 

WSTT - WAVESONIC MSL MONOPOLE LOWER SLOWNESS MSL INP 

WSTT - WAVESONIC MWV MONOPOLE REC #1 PRES WAVEFORM MWV INP 

WSTT - WAVESONIC MSBP MONO SEMBLANCE VALUE OF PEAK MSBP INP 

WSTT - WAVESONIC MMUT MONOPOLE MUTE MMUT INP 

WSTT - WAVESONIC MIT MIT mode MITMOD INP 

WSTT - WAVESONIC MDT2 MONOPOLE PEAK SLOWNESS 2 MDT2 INP 

WSTT - WAVESONIC MDT MONOPOLE PEAK SLOWNESS MDT INP 

WSTT - WAVESONIC MWLV MONOPOLE WAVE LEFT VALUE MWLV INP 

XRMI/XROMI - EXT RANGE 

MICRO IMAGING 


MICRO IMAGING 


MICRO IMAGING 


MICRO IMAGING 


MICRO IMAGING 


MICRO IMAGING 


MICRO IMAGING 


MICRO IMAGING 


MICRO IMAGING 

LIS 

Mnem 

LISU_ 

eng 

LISU_ 


DLISU_ 

Eng 

DLISU_ 

Met 

OMIS NESW NESW VIEW BUTTONS IMAGE (N-E-S-W-N) OMIS NESW NESW RES 

OMI4 OHMM OHMM OMI #4 - FAST BUTTON ARRAY OMI4 ohm.m ohm.m RES 

P1B1 OHMM OHMM PAD #1 RESISTIVITY P1B1 ohm.m ohm.m RES 






ITMP DEGF DEGC INTERNAL TEMPERATURE ITMP degF degC RES 


Type_ 

Data

Serv_Name 


MICRO IMAGING 


MICRO IMAGING 


MICRO IMAGING 


MICRO IMAGING 


MICRO IMAGING 


MICRO IMAGING 


MICRO IMAGING 


MICRO IMAGING 


MICRO IMAGING 


MICRO IMAGING 


MICRO IMAGING 


MICRO IMAGING 


MICRO IMAGING 


MICRO IMAGING 


MICRO IMAGING 


MICRO IMAGING 


MICRO IMAGING 


MICRO IMAGING 


MICRO IMAGING 


MICRO IMAGING 


MICRO IMAGING 


MICRO IMAGING 


MICRO IMAGING 


MICRO IMAGING 


MICRO IMAGING 


MICRO IMAGING 


MICRO IMAGING 


MICRO IMAGING 


MICRO IMAGING 


MICRO IMAGING 


MICRO IMAGING 


MICRO IMAGING 


MICRO IMAGING 

LIS 

Mnem 

LISU_ 

eng 

LISU_ 


DLISU_ 

Eng 

DLISU_ 

Met 

F5B1 SED PAD #5, PROFILE 1 (FAST) F5B1 RES 


ZACC G G Z ACCELEROMETER (FAST) ZACC G G RES 






PADS NESW NESW VIEW BUTTONS IMAGE (N-E-S-W-N) XPADS NESW NESW RES 

ROM1 ROMI #1 - FAST RAW VOLTAGE ROMI1 INP 







XRAZ XRMI AZIMUTH EMIAZ INP 

DMIN IN MM XRMI MINIMUM CALIPER PAIR DMIN in mm RES 

XRAZ XRMI AZIMUTH EMIAZ INP 

AHV FT3 M3 ANNULAR HOLE VOLUME MARK AHV ft3 m3 RES 

EDD1 OHMM OHMM PAD #1 RESISTIVITY (FAST) EDD1 ohm.m ohm.m RES 

C36 IN MM XRMI CALIPER PAIR 3-6 C36 in mm RES 



BHVT FT3 M3 BOREHOLE VOLUME TOTAL BHVT ft3 m3 RES 

BHV FT3 M3 BOREHOLE VOLUME MARK BHV ft3 m3 RES 

CAL2 IN MM XRMI CALIPER ARM #2 (DIAMETER) CAL2 in mm RES 

AHVT FT3 M3 ANNULAR HOLE VOLUME TOTAL AHVT ft3 m3 RES 


ACZU G G ACCELEROMETER Z UNFILTERED ACZU G G INP 

ACYU G G ACCELEROMETER Y UNFILTERED ACYU G G INP 

ACXU G G ACCELEROMETER X UNFILTERED ACXU G G INP 

ACCZ G G ACCELEROMETER Z-AXIS ACCZ G G RES 


Type_ 

Data

Serv_Name 


MICRO IMAGING 


MICRO IMAGING 


MICRO IMAGING 


MICRO IMAGING 


MICRO IMAGING 


MICRO IMAGING 


MICRO IMAGING 


MICRO IMAGING 


MICRO IMAGING 


MICRO IMAGING 


MICRO IMAGING 


MICRO IMAGING 


MICRO IMAGING 


MICRO IMAGING 


MICRO IMAGING 


MICRO IMAGING 


MICRO IMAGING 


MICRO IMAGING 


MICRO IMAGING 


MICRO IMAGING 


MICRO IMAGING 


MICRO IMAGING 

LIS 

Mnem 

LISU_ 

eng 

LISU_ 


DLISU_ 

Eng 

DLISU_ 

Met 

ACCY G G ACCELEROMETER Y-AXIS ACCY G G RES 

ACCX G G ACCELEROMETER X-AXIS ACCX G G RES 

ACCQ ACCELEROMETER SUM OF SQUARES ACCQ RES 

AZI1 DEG DEG PAD #1 AZIMUTH AZI1 deg deg RES 

DXTM 08.3MS 08.3MS Z ACCELEROMETER (FAST) TIME-MS DXTM 8.3 mS 8.3 mS RES 



EMIM XRMI LAST TOOL COMMAND EMIM INP 







DMAX IN MM XRMI MAXIMUM CALIPER PAIR DMAX in mm RES 

DEVI DEG DEG DRIFT ANGLE DEVI deg deg RES 

DCAL IN MM XRMI DIFFERENTIAL CALIPER DCAL in mm RES 

CALA IN MM XRMI AVERAGE CALIPER CALA in mm RES 






Type_ 

Data

Log Header Mnemonics 

Tool 

LIS 

Mnem Mnem Description Data_Location 

LOG_HDR LRU5 LOGGING DATA-GENERAL-RUN NO. 5 Character 

LOG_HDR LSC1 LOGGING DATA-ACOUSTIC-SCALE R 1 Character 





LOG_HDR LSL1 LOGGING DATA-NEUTRON-SCALE L 1 Character 





LOG_HDR LSP1 LOGGING DATA-GENERAL-SPEED 1 Character 





LOG_HDR LSR1 LOGGING DATA-NEUTRON-SCALE R 1 Character 





LOG_HDR LSRV LSRV NAME OF SERVICE Character 

LOG_HDR LTO1 LOGGING DATA-GENERAL-DEPTH TO 1 Character 





LOG_HDR LTYP LTYP LOG TYPE Character 

LOG_HDR LUL LUL1 LOGGING UNIT LOCATION Character 

LOG_HDR LUL2 LUL2 LOGGING UNIT LOCATION 2 Character 



LOG_HDR LUN LUN1 LOGGING UNIT NUMBER Character 

LOG_HDR LUN2 LUN2 LOGGING UNIT NUMBER 2 Character 



LOG_HDR MCS2 MCS2 MUD CAKE SAMPLE SOURCE 2 Character 



LOG_HDR MCSS MCSS MUD CAKE SAMPLE SOURCE Character 

LOG_HDR MCST TMC1 MUDCAKE SAMPLE TEMPERATURE Character 

LOG_HDR MCT2 TMC2 MUDCAKE SAMPLE TEMPERATURE 2 Character 



LOG_HDR MFS2 MFSS2 MUD FILTRATE SAMPLE SOURCE 2 Character 


9-44 Mnemonics

Tool 

LIS 



LOG_HDR MFSS MFSS MUD FILTRATE SAMPLE SOURCE Character 

LOG_HDR MFST TMF1 MUD FILTRATE SAMPLE TEMPERATURE Character 

LOG_HDR MFT2 TMF2 MUD FILTRATE SAMPLE TEMPERATURE 2 Character 



LOG_HDR MRT MRT MAXIMUM RECORDED TEMPERATURE Character 

LOG_HDR MRT2 MRT2 MAXIMUM RECORDED TEMPERATURE 2 Character 



LOG_HDR MSS MSS SOURCE OF MUD SAMPLE Character 

LOG_HDR MSS2 MSS2 SOURCE OF MUD SAMPLE 2 Character 



LOG_HDR OS1 OS1 OTHER SERVICES LINE 1 Character 




LOG_HDR OS5 OTHER SERVICES LINE 5 Character 

LOG_HDR OS6 OTHER SERVICES LINE 6 Character 

LOG_HDR OTH1 RES. EQUIP DATA: OTHER 1 (OH) Character 






LOG_HDR PDAT PDAT PERMANENT DATUM Character 

LOG_HDR PGMV PROGRAM VERSION Character 

LOG_HDR PT1 RES. EQUIP DATA: PAD TYPE 1 (OH) Character 






LOG_HDR R1 RMK1 REMARKS LINE 1 Character 

LOG_HDR R10 REMARKS LINE 10 Character 










LOG_HDR ACB ADD. SAMPLES: RMC - BHT 1 (OH) Character 

LOG_HDR ACB2 ADD. SAMPLES: RMC - BHT 2 (OH) Character 

LOG_HDR ACT ADD. SAMPLES: MUDCAKE TEMP. 1 Character 

LOG_HDR ACT2 ADD. SAMPLES: MUDCAKE TEMP. 2 Character 

Mnemonics 9-45

Tool 

LIS 


LOG_HDR ACX ADD. SAMPLES: RMC BOTTOMHOLE TEMP Character 

LOG_HDR ACX2 ADD. SAMPLES: RMC BOTTOMHOLE TEMP Character 

LOG_HDR ADD ADDITIONAL SAMPLES: DEPTH-DRILLER 1 (OH) Character 

LOG_HDR ADD2 ADDITIONAL SAMPLES: DEPTH-DRILLER 2 (OH) Character 

LOG_HDR ADE ADDITIONAL SAMPLES: DENSITY 1 Character 

LOG_HDR ADE2 ADDITIONAL SAMPLES: DENSITY 2 Character 

LOG_HDR ADFT ADDITIONAL SAMPLES: FLUID TYPE IN HOLE 1 (OH) Character 

LOG_HDR ADT ADDITIONAL SAMPLES: DATE 1 (OPEN HOLE ) Character 

LOG_HDR ADT2 ADDITIONAL SAMPLES: DATE 1 (OPEN HOLE ) Character 

LOG_HDR AFB ADD. SAMPLES: RMF - BHT 1 (OH) Character 

LOG_HDR AFB2 ADD. SAMPLES: RMF - BHT 2 (OH) Character 

LOG_HDR AFL ADDITIONAL SAMPLES: FLUID LOSS 1 Character 

LOG_HDR AFL2 ADDITIONAL SAMPLES: FLUID LOSS 2 Character 

LOG_HDR AFT ADD. SAMPLES: MUD FILTRATE TEMP 1 (OH) Character 

LOG_HDR AFT2 ADD. SAMPLES: MUD FILTRATE TEMP 2 (OH) Character 

LOG_HDR AFX ADD. SAMPLES: RMF BOTTOMHOLE TEMP 1 (OH) Character 

LOG_HDR AFX2 ADD. SAMPLES: RMF BOTTOMHOLE TEMP 2 (OH) Character 

LOG_HDR AMS2 ADD. SAMPLES: MUD SAMPLE TEMP 2 (OH) Character 

LOG_HDR AMST ADD. SAMPLES: MUD SAMPLE TEMP 1 (OH) Character 

LOG_HDR APD APD ABOVE PERMANENT DATUM Character 

LOG_HDR APH ADDITIONAL SAMPLES: PH 1 (OH) Character 

LOG_HDR APH2 ADDITIONAL SAMPLES: PH 2 (OH) Character 

LOG_HDR ARB ADD. SAMPLES: RES. OF MUD - BHT 1 (OH) Character 

LOG_HDR ARB2 ADD. SAMPLES: RES. OF MUD - BHT 2 (OH) Character 

LOG_HDR ARC ADD. SAMPLES: RES. OF MUDCAKE 1 (OH) Character 

LOG_HDR ARC2 ADD. SAMPLES: RES. OF MUDCAKE 2 (OH) Character 

LOG_HDR ARF ADD. SAMPLES: RES. MUD FILTRATE 1 (OH) Character 

LOG_HDR ARF2 ADD. SAMPLES: RES. MUD FILTRATE 2 (OH) Character 

LOG_HDR ARM ADD. SAMPLES: RES. OF MUD SAMPLE 1 (OH) Character 

LOG_HDR ARM2 ADD. SAMPLES: RES. OF MUD SAMPLE 2 (OH) Character 

LOG_HDR ARX ADD. SAMPLES: RM BOTTOMHOLE TEMP 1 (OH) Character 

LOG_HDR ARX2 ADD. SAMPLES: RM BOTTOMHOLE TEMP 2 (OH) Character 

LOG_HDR ASC ADD. SAMPLES: SOURCE RMC 1 (OH) Character 

LOG_HDR ASC2 ADD. SAMPLES: SOURCE RMC 2 (OH) Character 

LOG_HDR ASF ADD. SAMPLES: SOURCE RMF 1 (OH) Character 

LOG_HDR ASF2 ADD. SAMPLES: SOURCE RMF 2 (OH) Character 

LOG_HDR ASN ADDITIONAL SAMPLES: SAMPLE NO. 1 (OH) Character 

LOG_HDR ASN2 ADDITIONAL SAMPLES: SAMPLE NO. 2 (OH) Character 

LOG_HDR ASS ADD. SAMPLES: SOURCE OF SAMPLE 1 (OH) Character 

LOG_HDR ASS2 ADD. SAMPLES: SOURCE OF SAMPLE 2 (OH) Character 

LOG_HDR AST2 ADD. SAMPLES: MUD FILTRATE TEMP 2 (OH) Character 

LOG_HDR AV ADDITIONAL SAMPLES: VISCOSITY 1 (OH) Character 

LOG_HDR AV2 ADDITIONAL SAMPLES: VISCOSITY 2 (OH) Character 

LOG_HDR EGL EGL ELEVATION OF GROUND LEVEL Character 

LOG_HDR BARI BARI BARITE CORRECTION Character 


LOG_HDR RIG DRILLING RIG Character 

LOG_HDR RMB RMBH1 RESISTIVITY OF MUD - BHT Character 

LOG_HDR RMB2 RMBH2 RESISTIVITY OF MUD - BHT 2 Character 

9-46 Mnemonics

Tool 

LIS 




LOG_HDR RMC2 RMC2 RESISTIVITY OF MUD CAKE SAMPLE 2 Character 



LOG_HDR RMCS RMCS RESISTIVITY OF MUD CAKE SAMPLE Character 

LOG_HDR RMF2 RMF2 RESISTIVITY OF MUD FILTRATE SAMPLE 2 Character 



LOG_HDR RMFS RMF1 RESISTIVITY OF MUD FILTRATE SAMPLE Character 

LOG_HDR RMS RM1 RESISTIVITY OF MUD SAMPLE Character 

LOG_HDR RMS2 RM2 RESISTIVITY OF MUD SAMPLE 2 Character 



LOG_HDR RRN1 RES. EQUIP DATA: RUN NO 1 (OH) Character 






LOG_HDR RUN RUN NUMBER Character 

LOG_HDR RUN2 RUN NUMBER 2 Character 



LOG_HDR SDC1 RES. SCALE CHANGES: DEPTH 1 (OH) Character 





LOG_HDR SCT1 RES. SCALE CHANGES: TYPE LOG 1 (OH) Character 





LOG_HDR SDAT DATLOG DATE SECTION STARTED Character 

LOG_HDR SDH1 RES. SCALE CHANGES: SCALE DOWN HOLE 1 Character 





LOG_HDR SON SON1 SERVICE/TICKET ORDER NUMBER Character 

LOG_HDR STAT STATE STATE Character 

LOG_HDR STEM STEM SURFACE TEMP Character 

LOG_HDR STIM TIMLOG TIME SECTION STARTED Character 

LOG_HDR SUH1 RES. SCALE CHANGES: SCALE UP HOLE 1 (OH) Character 





Mnemonics 9-47

Tool 

LIS 


LOG_HDR TCS TCS TIME CIRCULATION STOPPED Character 

LOG_HDR TCS2 TCS2 TIME CIRCULATION STOPPED 2 Character 



LOG_HDR TDD1 TDD1 DRILLERS DEPTH 1 Character 




LOG_HDR TDL TDL LOGGERS DEPTH Character 

LOG_HDR TDL2 TDL2 LOGGERS DEPTH 2 Character 



LOG_HDR TLA2 TLAB2 TIME LOGGING ON BOTTOM 2 Character 



LOG_HDR TLAB TLAB TIME LOGGING ON BOTTOM Character 

LOG_HDR TLI TLI TOP LOGGED INTERVAL Character 

LOG_HDR TLI2 TLI2 TOP LOGGED INTERVAL 2 Character 

LOG_HDR TLI3 TLI3 TOP LOGGED INTERVAL 3 Character 

LOG_HDR TLI4 TL4 TOP LOGGED INTERVAL 4 Character 

LOG_HDR TN1 RES. EQUIP DATA: TOOL TYPE & NO. 1 (OH) Character 






LOG_HDR TOOL TOOL TOOL STRING Character 

LOG_HDR TPS1 RES. EQUIP DATA: TOOL POS. 1 (OH) Character 






LOG_HDR TTL1 HEADER TITLE LINE 1 Character 

LOG_HDR TTL4 HEADER TITLE LINE 4 Character 

LOG_HDR WIT2 WITN2 WITNESS 2 NAME Character 


LOG_HDR BASI BASI BASIN Character 

LOG_HDR BHT BHT BOTTOMHOLE TEMPERATURE Character 

LOG_HDR BHT2 BHT2 BOTTOMHOLE TEMPERATURE 2 Character 



LOG_HDR BLI BLI1 BOTTOM LOGGED INTERVAL Character 

LOG_HDR BLI2 BLI2 BOTTOM LOGGED INTERVAL 2 Character 



LOG_HDR BS1 BITDI1 BIT SIZE 1 Character 



9-48 Mnemonics

Tool 

LIS 



LOG_HDR CBD1 DEDRI1 CASING BOTTOM DRILLER 1 Character 




LOG_HDR CBL1 DELOG1 CASING BOTTOM LOGGER 1 Character 




LOG_HDR CN COMPAN COMPANY NAME Character 

LOG_HDR COUN COUNTY COUNTY Character 

LOG_HDR CS1 CASDI1 CASING DIAMETER 1 Character 




LOG_HDR CSW1 CASWE1 CASING WEIGHT 1 Character 




LOG_HDR CTRY COUNTR COUNTRY Character 

LOG_HDR DAT2 HDATE2 LOGGING DATE 2 Character 



LOG_HDR DDEG DIRECTIONAL DEPTH Character 

LOG_HDR DDEV DIRECTIONAL DEVIATION Character 

LOG_HDR DFD DFD DRILLING FLUID DENSITY Character 

LOG_HDR DFD2 DFD2 DRILLING FLUID DENSITY 2 Character 



LOG_HDR DFL DFL DRILLING FLUID LOSS Character 

LOG_HDR DFL2 DFL2 DRILLING FLUID LOSS 2 Character 



LOG_HDR DFP2 DFPH2 DRILLING FLUID PH 2 Character 



LOG_HDR DFPH DFPH DRILLING FLUID PH Character 

LOG_HDR DFS DFS SALINITY Character 

LOG_HDR DFT DFT DRILLING FLUID TYPE Character 

LOG_HDR DFT2 DFT2 DRILLING FLUID TYPE 2 Character 



LOG_HDR DFV DFV DRILLING FLUID VISCOSITY Character 

LOG_HDR DFV2 DFV2 DRILLING FLUID VISCOSITY 2 Character 



LOG_HDR DKOP DIRECTIONAL KOP Character 

LOG_HDR DMF DMF DRILLING MEASURED Character 

LOG_HDR DRMK DIRECTIONAL REMARKS Character 

Mnemonics 9-49

Tool 

LIS 


LOG_HDR EAER EQUIP. DATA-ACOUSTIC-SERIAL NO. Character 

LOG_HDR EAOD EQUIP. DATA-ACOUSTIC-MODEL NO. Character 

LOG_HDR ECNT EQUIP. DATA-ACOUSTIC-NO. OF CENT Character 

LOG_HDR EDF HIGHT3 ELEVATION OF DRILLING FLOOR Character 

LOG_HDR EDIA EQUIP. DATA-DENSITY-DIAMETER Character 

LOG_HDR EDOD EQUIP. DATA-DENSITY-MODEL NO. Character 

LOG_HDR EDS1 EQUIP. DATA-GAMMA-DISTANCE TO SOURCE Character 

LOG_HDR EDSN EQUIP. DATA-DENSITY-SOURCE SERIAL NO. Character 

LOG_HDR ELT EQUIP. DATA-GAMMA-DETECTOR MODEL NO. Character 

LOG_HDR EDTR EQUIP. DATA-DENSITY-STRENGTH Character 

LOG_HDR EDUN EQUIP. DATA-DENSITY-RUN NO. Character 

LOG_HDR EFWD EQUIP. DATA-ACOUSTIC-FWDA Character 

LOG_HDR EGMD EQUIP. DATA-GAMMA-MODEL NO. Character 

LOG_HDR EGRN EQUIP. DATA-GAMMA-RUN NO. Character 

LOG_HDR EGSN EQUIP. DATA-GAMMA-SERIAL NO. Character 

LOG_HDR EKB HIGHT1 ELEVATION OF KELLY BUSHING Character 

LOG_HDR ELGT EQUIP. DATA-DENSITY-LOG TYPE Character 

LOG_HDR ELN1 EQUIP. DATA-GAMMA-LENGTH Character 

LOG_HDR EMIA EQUIP. DATA-GAMMA-DIAMETER Character 

LOG_HDR ENER EQUIP. DATA-DENSITY-SERIAL NO. Character 

LOG_HDR ENG2 ENGI2 ENGINEER 2 NAME Character 



LOG_HDR ENGI ENGI1 ENGINEER 1 NAME Character 

LOG_HDR ENGT EQUIP. DATA-NEUTRON-LOG TYPE Character 

LOG_HDR ENIA EQUIP. DATA-NEUTRON-DIAMETER Character 

LOG_HDR ENOD EQUIP. DATA-NEUTRON-MODEL NO. Character 

LOG_HDR EPD EPD ELEVATATION OF PERMANENT DATUM Character 

LOG_HDR EQLA EQUIP. DATA-ACOUSTIC-LSA Character 

LOG_HDR ERUN EQUIP. DATA-ACOUSTIC-RUN NO. Character 

LOG_HDR ESAT EQUIP. DATA-DENSITY-SOURCE TYPE Character 

LOG_HDR ESER EQUIP. DATA-NEUTRON-SERIAL NO. Character 

LOG_HDR ESPC EQUIP. DATA-ACOUSTIC-SPACING Character 

LOG_HDR ESRT EQUIP. DATA-NEUTRON-SOURCE TYPE Character 

LOG_HDR ESSN EQUIP. DATA-NEUTRON-SOURCE SERIAL NO. Character 

LOG_HDR ESTR EQUIP. DATA-NEUTRON-STRENGTH Character 

LOG_HDR ETP1 EQUIP. DATA-GAMMA-TYPE Character 

LOG_HDR EURN EQUIP. DATA-NEUTRON-RUN NO. Character 

LOG_HDR FL1 LOC1 FIELD LOCATION LINE 1 Character 

LOG_HDR FN FIELD FIELD NAME Character 

LOG_HDR HDAT HDAT DATUM Character 

LOG_HDR HDRT HEADER TYPE Character 

LOG_HDR LAT LAT LATITUDE Character 

LOG_HDR LCC LOGGING COMPANY_CODE Character 

LOG_HDR LCL1 LOGGING DATA-GAMMA-SCALE L 1 Character 





9-50 Mnemonics

Tool 

LIS 


LOG_HDR LCR1 LOGGING DATA-GAMMA-SCALE R 1 Character 





LOG_HDR LDAT LDAT LOGGING DATE Character 

LOG_HDR LDL1 LOGGING DATA-DENSITY-SCALE L 1 Character 





LOG_HDR LDR1 LOGGING DATA-DENSITY-SCALE R 1 Character 





LOG_HDR LDX1 LOGGING DATA-DENSITY-MATRIX 1 Character 





LOG_HDR LFR1 LOGGING DATA-GENERAL-DEPTH FROM 1 Character 





LOG_HDR LGC1 LOGGING DATA-ACOUSTIC-SCALE L 1 Character 





LOG_HDR LMF LMF LOG MEASURED FROM Character 

LOG_HDR LMT1 LOGGING DATA-ACOUSTIC-MATRIX 1 Character 





LOG_HDR LMX1 LOGGING DATA-NEUTRON-MATRIX 1 Character 





LOG_HDR LNAM LNAM Character 

LOG_HDR LONG XLONG LONGITUDE Character 






Mnemonics 9-51

Tool 

LIS 


LOG_HDR WITN WITN1 WITNESS 1 NAME Character 

LOG_HDR WN NAMWEL WELL NAME Character 

LOG_HDR X X X COORDINATE Character 

LOG_HDR XTP MAX. REC TEMP. @ 1 (OPEN HOLE) Character 

LOG_HDR XTP2 MAX. REC TEMP. @ 2 (OPEN HOLE) Character 



LOG_HDR Y Y Y COORDINATE Character 

LOG_HDR SON ORDER-NUMBER String 

LOG_HDR RUN RUN-NUMBER String 

LOG_HDR WN WELL-NAME String 

LOG_HDR FN FIELD-NAME String 

LOG_HDR LCC PRODUCER-CODE String 

LOG_HDR CN COMPANY String 

LOG_HDR ACB ADD. SAMPLES: RMC - BHT 1 (OH) String 

LOG_HDR ACB2 ADD. SAMPLES: RMC - BHT 2 (OH) String 

LOG_HDR ACT ADD. SAMPLES: MUDCAKE TEMP. 1 (OH) String 

LOG_HDR ACT2 ADD. SAMPLES: MUDCAKE TEMP. 2 (OH) String 

LOG_HDR ACX ADD. SAMPLES: RMC OTTOMHOLE TEMP 1 (OH) String 

LOG_HDR ACX2 ADD. SAMPLES: RMC OTTOMHOLE TEMP 2 (OH) String 

LOG_HDR ADD ADDITIONAL SAMPLES: DEPTH-DRILLER 1 (OH) String 

LOG_HDR ADD2 ADDITIONAL SAMPLES: DEPTH-DRILLER 2 (OH) String 

LOG_HDR ADE ADDITIONAL SAMPLES: DENSITY 1 (OH) String 

LOG_HDR ADE2 ADDITIONAL SAMPLES: DENSITY 2 (OH) String 

LOG_HDR ADFT ADDI. SAMPLES: FLUID TYPE IN HOLE 1 (OH) String 

LOG_HDR ADT ADDITIONAL SAMPLES: DATE 1 (OPEN HOLE) String 

LOG_HDR ADT2 ADDITIONAL SAMPLES: DATE 2 (OPEN HOLE) String 

LOG_HDR AFB ADD. SAMPLES: RMF - BHT 1 (OH) String 

LOG_HDR AFB2 ADD. SAMPLES: RMF - BHT 2 (OH) String 

LOG_HDR AFL ADDITIONAL SAMPLES: FLUID LOSS 1 (OH) String 

LOG_HDR AFL2 ADDITIONAL SAMPLES: FLUID LOSS 2 (OH) String 

LOG_HDR AFT ADD. SAMPLES: MUD FILTRATE TEMP. 1 (OH) String 

LOG_HDR AFT2 ADD. SAMPLES: MUD FILTRATE TEMP. 2 (OH) String 

LOG_HDR AFX ADD. SAMPLES: RMF BOTTOMHOLE TEMP 1 (OH) String 

LOG_HDR AFX2 ADD. SAMPLES: RMF BOTTOMHOLE TEMP 2 (OH) String 

LOG_HDR AMS2 ADD. SAMPLES: MUD SAMPLE TEMP 2 (OH) String 

LOG_HDR AMST ADD. SAMPLES: MUD SAMPLE TEMP 1 (OH) String 

LOG_HDR APD ABOVE PERMANENT DATUM String 

LOG_HDR APH ADDITIONAL SAMPLES: PH 1 (OH) String 

LOG_HDR APH2 ADDITIONAL SAMPLES: PH 2 (OH) String 

LOG_HDR ARB ADD. SAMPLES: RES. OF MUD - BHT 1 (OH) String 

LOG_HDR ARB2 ADD. SAMPLES: RES. OF MUD - BHT 2 (OH) String 

LOG_HDR ARC ADD. SAMPLES: RES. OF MUDCAKE 1 (OH) String 

LOG_HDR ARC2 ADD. SAMPLES: RES. OF MUDCAKE 2 (OH) String 

LOG_HDR ARF ADD. SAMPLES: RES. MUD FILTRATE 1 (OH) String 

LOG_HDR ARF2 ADD. SAMPLES: RES. MUD FILTRATE 2 (OH) String 

LOG_HDR AR, ADD. SAMPLES: RES. OF MUD SAMPLE 1 (OH) String 

LOG_HDR ARM2 ADD. SAMPLES: RES. OF MUD SAMPLE 2 (OH) String 

LOG_HDR ARX ADD. SAMPLES: RM BOTTOMHOLE TEMP 1 (OH) String 

9-52 Mnemonics

Tool 

LIS 


LOG_HDR ARX2 ADD. SAMPLES: RM BOTTOMHOLE TEMP 2 (OH) String 

LOG_HDR ASC ADD. SAMPLES: SOURCE RMC 1 (OH) String 

LOG_HDR ASC2 ADD. SAMPLES: SOURCE RMC 2 (OH) String 

LOG_HDR ASF ADD. SAMPLES: SOURCE RMF 1 (OH) String 

LOG_HDR ASF2 ADD. SAMPLES: SOURCE RMF 2 (OH) String 

LOG_HDR ASN ADDITIONAL SAMPLES: SAMPLE NO. 1 (OH) String 

LOG_HDR ASN2 ADDITIONAL SAMPLES: SAMPLE NO. 2 (OH) String 

LOG_HDR ASS ADD. SAMPLES: SOURCE OF SAMPLE 1 (OH) String 

LOG_HDR ASS2 ADD. SAMPLES: SOURCE OF SAMPLE 2 (OH) String 

LOG_HDR AST2 ADD. SAMPLES: MUD FILTRATE TEMP. 2 (OH) String 

LOG_HDR AV ADDITIONAL SAMPLES: VISCOSITY 1 (OH) String 

LOG_HDR AV2 ADDITIONAL SAMPLES: VISCOSITY 2 (OH) String 

LOG_HDR EGL EGL ELEVATION OF GROUND LEVEL String 

LOG_HDR BARI BARITE CORRECTION String 

LOG_HDR BASI BASIN String 

LOG_HDR BHT BOTTOMHOLE TEMPERATURE String 

LOG_HDR BHT2 BOTTOMHOLE TEMPERATURE 2 String 



LOG_HDR BLI BOTTOM LOGGED INTERVAL String 

LOG_HDR BLI2 BOTTOM LOGGED INTERVAL 2 String 



LOG_HDR BS1 BIT SIZE 1 String 




LOG_HDR CBD1 CASING BOTTOM DRILLER 1 String 




LOG_HDR CBL1 CASING BOTTOM LOGGER 1 String 




LOG_HDR CN COMPANY NAME String 

LOG_HDR COUN COUNTY String 

LOG_HDR CS1 CASING DIAMETER 1 String 




LOG_HDR CSW1 CASING WEIGHT 1 String 




LOG_HDR CTRY COUNTRY String 

LOG_HDR DAT2 LOGGING DATE 2 String 



Mnemonics 9-53

Tool 

LIS 


LOG_HDR DDEG DIRECTIONAL DEPTH String 

LOG_HDR DDEV DIRECTIONAL DEVIATION String 

LOG_HDR DFD DRILLING FLUID DENSITY String 

LOG_HDR DFD2 DRILLING FLUID DENSITY 2 String 



LOG_HDR DFL DRILLING FLUID LOSS String 

LOG_HDR DFL2 DRILLING FLUID LOSS 2 String 



LOG_HDR DFP2 DRILLING FLUID PH 2 String 

LOG_HDR DPF3 DRILLING FLUID PH 3 String 

LOG_HDR DFP4 DRILLING FLUID PH 4 String 

LOG_HDR DFPH DRILLING FLUID PH String 

LOG_HDR DFS SALINITY String 

LOG_HDR DFT DRILLING FLUID TYPE String 

LOG_HDR DFT2 DRILLING FLUID TYPE 2 String 



LOG_HDR DFV DRILLING FLUID VISCOSITY String 

LOG_HDR DFV2 DRILLING FLUID VISCOSITY 2 String 



LOG_HDR DKOP DIRECTIONAL KOP String 

LOG_HDR DMF DRILLING MEASURED FROM String 

LOG_HDR DRMK DIRECTIONAL REMARKS String 

LOG_HDR EAER EQUIP. DATA-ACOUSTIC-SERIAL NO. String 

LOG_HDR EAOD EQUIP. DATA-ACOUSTIC-MODEL NO. String 

LOG_HDR ECNT EQUIP. DATA-ACOUSTIC-NO. OF CENT String 

LOG_HDR EDF ELEVATION OF DRILLING FLOOR String 

LOG_HDR EDIA EQUIP. DATA-DENSITY-DIAMETER String 

LOG_HDR EDOD EQUIP. DATA-DENSITY-MODEL NO. String 

LOG_HDR EDSI EQUIP. DATA-GAMMA-DISTANCE TO SOURCE String 

LOG_HDR EDSN EQUIP. DATA-DENSITY-SOURCE SERIAL NO. String 

LOG_HDR EDT EQUIP. DATA-GAMMA-DETECTOR MODEL NO. String 

LOG_HDR EDTR EQUIP. DATA-DENSITY-STRENGTH String 

LOG_HDR EDUN EQUIP. DATA-DENSITY-RUN NO. String 

LOG_HDR EFWD EQUIP. DATA-ACOUSTIC-FWDA String 

LOG_HDR EGMD EQUIP. DATA-GAMMA-MODEL NO. String 

LOG_HDR EGRN EQUIP. DATA-GAMMA-RUN NO. String 

LOG_HDR EGSN EQUIP. DATA-GAMMA-SERIAL NO. String 

LOG_HDR EKB ELEVATION OF KELLY BUSHING String 

LOG_HDR ELGT EQUIP. DATA-DENSITY-LOG TYPE String 

LOG_HDR ELN1 EQUIP. DATA-GAMMA-LENGTH String 

LOG_HDR EMIA EQUIP. DATA-GAMMA-DIAMETER String 

LOG_HDR ENER EQUIP. DATA-DENSITY-SERIAL NO. String 

LOG_HDR ENG2 ENGINEER 2 NAME String 

LOG_HDR ENG3 ENGINEER 3 NAME String 

LOG_HDR RNG4 ENGINEER 4 NAME String 

9-54 Mnemonics

Tool 

LIS 


LOG_HDR ENGI ENGINEER 1 NAME String 

LOG_HDR ENGT EQUIP. DATA-NEUTRON-LOG TYPE String 

LOG_HDR ENIA EQUIP. DATA-NEUTRON-DIAMETER String 

LOG_HDR ENOD EQUIP. DATA-NEUTRON-MODEL NO. String 

LOG_HDR EPD ELEVATATION OF PERMANENT DATUM String 

LOG_HDR EQLA EQUIP. DATA-ACOUSTIC-LSA String 

LOG_HDR ERUN EQUIP. DATA-ACOUSTIC-RUN NO. String 

LOG_HDR ESAT EQUIP. DATA-DENSITY-SOURCE TYPE String 

LOG_HDR ESER EQUIP. DATA-NEUTRON-SERIAL NO. String 

LOG_HDR ESPC EQUIP. DATA-ACOUSTIC-SPACING String 

LOG_HDR ESRT EQUIP. DATA-NEUTRON-SOURCE TYPE String 

LOG_HDR ESSN EQUIP. DATA-NEUTRON-SOURCE SERIAL NO. String 

LOG_HDR ESTR EQUIP. DATA-NEUTRON-STRENGTH String 

LOG_HDR ETP1 EQUIP. DATA-GAMMA-TYPE String 

LOG_HDR EURN EQUIP. DATA-NEUTRON-RUN NO. String 

LOG_HDR FL1 FIELD LOCATION LINE 1 String 

LOG_HDR FN FIELD NAME String 

LOG_HDR HDAT DATUM String 

LOG_HDR HDRT HEADER TYPE String 

LOG_HDR LAT LATITUDE String 

LOG_HDR LCC LOGGING COMPANY_CODE String 

LOG_HDR LCL1 LOGGING DATA-GAMMA-SCALE L 1 String 





LOG_HDR LCR1 LOGGING DATA-GAMMA-SCALE R 1 String 





LOG_HDR LDAT LDAT LOGGING DATE String 

LOG_HDR LDL1 LOGGING DATA-DENSITY-SCALE L 1 String 





LOG_HDR LDR1 LOGGING DATA-DENSITY-SCALE R 1 String 





LOG_HDR LDX1 LOGGING DATA-DENSITY-MATRIX 1 String 





LOG_HDR LFR1 LOGGING DATA-GENERAL-DEPTH FROM 1 String 


Mnemonics 9-55

Tool 

LIS 





LOG_HDR LGC1 LOGGING DATA-ACOUSTIC-SCALE L 1 String 





LOG_HDR LMF LMF LOG MEASURED FROM String 

LOG_HDR LMT1 LOGGING DATA-ACOUSTIC-MATRIX 1 String 





LOG_HDR LMX1 LOGGING DATA-NEUTRON-MATRIX 1 String 





LOG_HDR LNAM LNAM String 

LOG_HDR LONG XLONG LONGITUDE String 

LOG_HDR LRU1 LOGGING DATA-GENERAL-RUN NO. 1 String 





LOG_HDR LSC1 LOGGING DATA-ACOUSTIC-SCALE R 1 String 





LOG_HDR LSL1 LOGGING DATA-NEUTRON-SCALE L 1 String 





LOG_HDR LSP1 LOGGING DATA-GENERAL-SPEED 1 String 





LOG_HDR LSR1 LOGGING DATA-NEUTRON-SCALE R 1 String 





LOG_HDR LSRV LSRV NAME OF SERVICE String 

LOG_HDR LTO1 LOGGING DATA-GENERAL-DEPTH TO 1 String 


9-56 Mnemonics

Tool 

LIS 





LOG_HDR LTYP LTYP LOG TYPE String 

LOG_HDR LUL LUL1 LOGGING UNIT LOCATION String 

LOG_HDR LUL2 LUL2 LOGGING UNIT LOCATION 2 String 



LOG_HDR LUN LUN1 LOGGING UNIT NUMBER String 

LOG_HDR LUN2 LUN2 LOGGING UNIT NUMBER 2 String 



LOG_HDR MCS2 MCS2 MUD CAKE SAMPLE SOURCE 2 String 



LOG_HDR MCSS MCSS MUD CAKE SAMPLE SOURCE String 

LOG_HDR MCST TMC1 MUDCAKE SAMPLE TEMPERATURE String 

LOG_HDR MCT2 TMC2 MUDCAKE SAMPLE TEMPERATURE 2 String 



LOG_HDR MFS2 MFSS2 MUD FILTRATE SAMPLE SOURCE 2 String 



LOG_HDR MFSS MFSS MUD FILTRATE SAMPLE SOURCE String 

LOG_HDR MFST TMF1 MUD FILTRATE SAMPLE TEMPERATURE String 

LOG_HDR MFT2 TMF2 MUD FILTRATE SAMPLE TEMPERATURE 2 String 



LOG_HDR MRT MRT MAXIMUM RECORDED TEMPERATURE String 

LOG_HDR MRT2 MRT2 MAXIMUM RECORDED TEMPERATURE 2 String 



LOG_HDR MSS MSS SOURCE OF MUD SAMPLE String 

LOG_HDR MSS2 MSS2 SOURCE OF MUD SAMPLE 2 String 



LOG_HDR MST TM1 MUD SAMPLE TEMPERATURE String 

LOG_HDR MST2 TM2 MUD SAMPLE TEMPERATURE 2 String 



LOG_HDR MST TM1 MUD SAMPLE TEMPERATURE Character 

LOG_HDR MST2 TM2 MUD SAMPLE TEMPERATURE 2 Character 



LOG_HDR OS1 OS1 OTHER SERVICES LINE 1 String 




LOG_HDR OS5 OTHER SERVICES LINE 5 String 

Mnemonics 9-57

Tool 

LIS 


LOG_HDR OS6 OTHER SERVICES LINE 6 String 

LOG_HDR OTH1 RES. EQUIP DATA: OTHER 1 (OH) String 






LOG_HDR PDAT PDAT PERMANENT DATUM String 

LOG_HDR PGMV PROGRAM VERSION String 

LOG_HDR PT1 RES. EQUIP DATA: PAD TYPE 1 (OH) String 







LOG_HDR R1 RMK1 REMARKS LINE 1 String 

LOG_HDR R10 REMARKS LINE 10 String 











LOG_HDR RIG DRILLING RIG String 

LOG_HDR RMB RMBH1 RESISTIVITY OF MUD - BHT String 

LOG_HDR RMB2 RMBH2 RESISTIVITY OF MUD - BHT 2 String 



LOG_HDR RMC2 RMC2 RESISTIVITY OF MUD CAKE SAMPLE 2 String 



LOG_HDR RMCS RMCS RESISTIVITY OF MUD CAKE SAMPLE String 

LOG_HDR RMF2 RMF2 RESISTIVITY OF MUD FILTRATE SAMPLE 2 String 



LOG_HDR RMFS RMF1 RESISTIVITY OF MUD FILTRATE SAMPLE String 

LOG_HDR RMS RM1 RESISTIVITY OF MUD SAMPLE String 

LOG_HDR RMS2 RM2 RESISTIVITY OF MUD SAMPLE 2 String 



LOG_HDR RRN1 RES. EQUIP DATA: RUN NO 1 (OH) String 




9-58 Mnemonics

Tool 

LIS 




LOG_HDR RUN RUN NUMBER String 

LOG_HDR RUN2 RUN NUMBER 2 String 



LOG_HDR SDC1 RES. SCALE CHANGES: DEPTH 1 (OH) String 





LOG_HDR SCT1 RES. SCALE CHANGES: TYPE LOG 1 (OH) String 





LOG_HDR SDAT DATLOG DATE SECTION STARTED String 

LOG_HDR SDH1 RES. SCALE CHANGES: SCALE DOWN HOLE 1 String 





LOG_HDR SON SON1 SERVICE/TICKET ORDER NUMBER String 

LOG_HDR STAT STATE STATE String 

LOG_HDR STEM STEM SURFACE TEMP String 

LOG_HDR STIM TIMLOG TIME SECTION STARTED String 

LOG_HDR SUH1 RES. SCALE CHANGES: SCALE UP HOLE 1 (OH) String 





LOG_HDR TCS TCS TIME CIRCULATION STOPPED String 

LOG_HDR TCS2 TCS2 TIME CIRCULATION STOPPED 2 String 



LOG_HDR TDD1 TDD1 DRILLERS DEPTH 1 String 




LOG_HDR TDL TDL LOGGERS DEPTH String 

LOG_HDR TDL2 TDL2 LOGGERS DEPTH 2 String 



LOG_HDR TLA2 TLAB2 TIME LOGGING ON BOTTOM 2 String 



LOG_HDR TLAB TLAB TIME LOGGING ON BOTTOM String 

LOG_HDR TLI TLI TOP LOGGED INTERVAL String 

LOG_HDR TLI2 TLI2 TOP LOGGED INTERVAL 2 String 

Mnemonics 9-59

Tool 

LIS 


LOG_HDR TLI3 TLI3 TOP LOGGED INTERVAL 3 String 

LOG_HDR TLI4 TL4 TOP LOGGED INTERVAL 4 String 

LOG_HDR TN1 RES. EQUIP DATA: TOOL TYPE & NO. 1 (OH) String 






LOG_HDR TOOL TOOL TOOL STRING String 

LOG_HDR TPS1 RES. EQUIP DATA: TOOL POS. 1 (OH) String 






LOG_HDR TTL1 HEADER TITLE LINE 1 String 

LOG_HDR TTL4 HEADER TITLE LINE 4 String 

LOG_HDR WIT2 WITN2 WITNESS 2 NAME String 



LOG_HDR WITN WITN1 WITNESS 1 NAME String 

LOG_HDR WN NAMWEL WELL NAME String 

LOG_HDR X X X COORDINATE String 

LOG_HDR XTP MAX. REC TEMP. @ 1 (OPEN HOLE) String 

LOG_HDR XTP2 MAX. REC TEMP. @ 2 (OPEN HOLE) String 



LOG_HDR Y Y Y COORDINATE String 

LOG_HDR BS BITDI BIT SIZE Character 

LOG_HDR CS CASDI CASING DIAMETER Character 

LOG_HDR CBD DEDRI CASING BOTTOM DRILLER Character 

LOG_HDR CBL DELOG CASING BOTTOM LOGGER Character 

LOG_HDR CSW CASWE CASING WEIGHT Character 

LOG_HDR TDD TDD DRILLERS DEPTH Character 

9-60 Mnemonics

Index 

A 

Acoustics 3-24 

BSAT Borehole Compensated Sonic 

Array Tool 3-24 

FWS Full Wave Sonic Tool 3-27 

WaveSonic® Tool 3-25 

Acoustics and Rock Properties 2-30 

AcidXpert Analysis 2-36 

Anisotropy Analysis 2-30 

FracXpert Analysis 2-34 

RockXpert2 Analysis 2-32 

Advanced Measurement System 

Electronic Advanced Measurement System 

(Portable) 7-26 

JobTrak® Data Job Logger 7-28 

SmartETD® System 7-27 

Advanced Measurement System (AMS) 7-25 

Advanced® Slickline Services 7-16 

Deepwater Riserless Subsea Light Well 

Intervention System 7-33 

DPU® Downhole Power Unit 7-19 

DPU Tubing Punch 7-22 

LineTrak® Slickline Inspection Device and Wire 

Management Program 7-31 

Memory Production Logging (MPL) Service 7-29 

Ancillary Equipment 5-71 

Annular Pressure-Control Line Swivel Sub 5-92 

Annular Pressure-Control Line Tubing Release 5-93 

Annular Pressure-Control Line Vent 5-91 

AutoLatch Release Gun Connector 5-75 

Automatic Release 5-99 

Automatic-Release Gun Hanger— 

Automatic-J Mandrel 5-84 

Automatic-Release Gun Hanger— 

Rotational Set 5-82 

Balanced Isolation Tool 5-72 

Bar Pressure Vent 5-94 

Below-Packer Vent Device 5-95 

Centralizer Tandem 5-89 

Detach Separating Gun Connector 5-79 

DPU Downhole Power Unit 5-104 

Emergency Release Assembly 5-90 

Explosive Transfer Swivel Sub 5-86 

EZ Pass Gun Hanger 5-80 

Fast Gauge Recorder 5-110 

Fill Disk Assembly 5-71 

Gamma Perforator Logging Tool 5-112 

Gun Guides 5-107 

Hydraulic Metering Release Tool for the Single 

Trip System (STPP-GH) Tool 5-108 

Isolation Sub-Assembly 5-76 

Maximum Differential Bar Vent 5-96 

Mechanical Tubing Release 5-101 

Pressure-Actuated Tubing Release 5-103 

Pressure-Operated Vent 5-97 

Quick Torque Connector 5-77 

Ratchet Gun Connector 5-74 

Roller Tandem Assembly 5-88 

Shearable Safety Sub 5-87 

SmartETD® Advanced Electronic Triggering 

Device 5-105 

Vann Circulating Valve 5-98 

Y-Block Assembly 5-106 

Auxiliary Services 3-57 

BHPT Borehole Properties Tool 3-63 

CTL Coiled Tubing Logging 3-62 

FIAC Four Independent Arm Caliper Tool 3-65 

Multi-Conductor LockJar®* System 3-57 

RWCH Releaseable Wireline Cable Head 3-59 

SDDT Stand-Alone DITS Directional Tool 3-67 

Toolpusher Logging (TPL) Service 3-60 

Index 10-1 

B 

Borehole Geophysics 2-26, 3-33 

Reservoir Geophysics 2-27, 3-34 

GeoChain VSP Downhole Receiver 

Array 2-27, 3-34 

Long Array Multi-Component Acquisition 

Tools 2-27, 3-34 

Synthetic Seismic and Sonic Log 

Calibration 2-27, 3-34 

ExactFrac® Services 2-29, 3-36 

Vertical Incidence Vertical Seismic 

Profiling (VIVSP) Analysis 2-28, 3-35 

Wellbore Seismic 2-26, 3-33 

High Resolution Seismic Imaging 2-26, 3-33 

C 

Cased-Hole Wireline and Perforating Services 4-1 

Casing and Tubing Evaluation 4-28 

CAST-V Circumferential Acoustic Scanning 

Tool-Visualization 4-29 

MAC Multi-Arm Caliper Tool 4-28 

*LockJar is a registered trademark of Evans Engineering, Inc.

The FASTCAST Fast Circumferential Acoustic 

Scanning Tool 4-31 

Cement Evaluation 4-33 

ACE Advanced Cement Evaluation Process 4-37 

Cement Bond Log (CBL) 4-33 

Radial Cement Bond Tools 4-35 

CollarTrak® Slickline Collar Locator 7-23 

D 

Detonators 5-113 

Block RED® Detonators 5-115 

Capsule RED Detonators 5-113 

RED GO-Style Thermal Igniter 5-114 

Top Fire RED Detonators 5-116 


Downhole Video Services 6-1 

EyeDeal Camera System 6-4 

Fiber-Optic Camera System 6-3 

Hawkeye Camera System 6-2 

Dynamic Modeling 5-117 

Near-Wellbore Stimulation and 

PulsFrac Software 5-120 

PerfPro® Process 5-117 

Predicting In-Situ Charge Performance 5-117 

ShockPro SM Shockload Evaluation Service 5-125 

SurgePro SM Service 5-122 

F 

Firing Heads 5-45 

Annulus Pressure Crossover Assembly 5-67 

Annulus Pressure Firer-Control Line 5-54 

Annulus Pressure Transfer Reservoir 5-55 

Detonation Interruption Device 5-45 

Differential Firing Head 5-57 

Extended Delay Fuses 5-63 

EZ Cycle Multi-Pressure Cycle Firing Head 5-68 

Hydraulic-Actuator Firing Head and Swivel-Type 

Hydraulic-Actuator Firing Head 5-58 

Mechanical Firing Head 5-46 

Mechanical Metering Hydraulic-Delay 

Firing Head 5-59 

Model II-D Mechanical Firing Head 5-47 

Model III-D Mechanical Firing Head 5-48 

Model K and K-II Firing Heads 5-50 

Model KV-II Firing Head 5-51 

Modular Mechanical Firing Head 5-64 

Drop Bar Options 5-65 

Skirt-Centralizer Selection Chart 5-65 

Multiaction-Delay Firing Head 5-53 

Pressure-Actuated Firing Head 5-49 

Pump-Through Firing Head 5-70 

Side-Pocket Mandrel Firing Head 5-66 

Slickline-Retrievable Mechanical Firing Head 5-60 

Slickline-Retrievable Time-Delay Firer 

Firing Head 5-62 

Slimhole Annulus Pressure Firer— 

Internal Control 5-56 

Time-Delay Firer 5-52 

Formation Evaluation 4-1 

CASE Casing Evaluation and Inspection 

Software 4-10 

DSN Dual-Spaced Neutron Tool 4-7 

FCMT Formation Compaction Monitoring Tool 4-9 

RMT Elite Reservoir Monitor Tool 4-3 

Spectra Flow Logging Service (SpFl) 4-5 

TMD-L Thermal Multigate Decay-Lithology 

Logging Tool 4-1 

10-2 Index 

G 

Gun Systems 5-10 

Capsule Gun Systems 5-41 

Deep Star Capsule Gun 5-42 

Dyna-Star® Capsule Gun 5-41 

Ported Gun Perforating System 5-44 

VannGun® Assemblies 

1 9/16 in. to 7 in. and 4 SPF to 21 SPF 5-10 

Gun Swell Information 5-39 

Gun Washover/Fishing Specifications 5-38 

Tensile Ratings 5-16 

1 9/16-in. Premium VannGun 

Assemblies 5-16 

2-in. Premium VannGun 

















Assemblies 5-28

H 

5-in. Premium VannGun® 








6 1/2-in. High-Pressure Premium 

VannGun Assemblies 5-35 





VannGun Phasing and Shot Patterns 5-11 

0° Phasing 4 and 5 SPF 5-11 

138° Phasing 14 SPF 5-15 

140°/160° Phasing 11 SPF 5-14 

180° Phasing 4 and 8 SPF 5-12 

25.7°/128.5° Phasing 14 SPF 5-15 

30°/150° Phasing 12 SPF 5-14 

45°/135° Phasing 5, 6, 8, 12, and 18 SPF 5-13 

51.4°/154.3° Phasing 12 SPF 5-14 

60° Phasing 4, 5, and 6 SPF 5-11 

60° Phasing 6 SPF Two Planes 5-13 

60°/120° Phasing 18 and 21 SPF 5-15 

90° Phasing 4 SPF 5-12 

HalLink® Satellite Systems 1-2 

Hostile—Slimhole Formation Evaluation 3-47 

HEAT Hostile Environment Applications 

Tool Suite 3-47 

HDSN Hostile Dual-Spaced Neutron 

Tool 3-53 

HEDL Hostile Environment Dual Laterolog 

Tool 3-48 

HFWS Hostile Full Wave Sonic Tool 3-49 

HNGR Hostile Natural Gamma Ray 

Tool 3-55 

HSDL Hostile Spectral Density Log 3-51 

HSFT Hostile Sequential Formation Tester 

Tool 3-56 

I 

Imaging 3-9 

CAST-V Circumferential Acoustic Scanning 

Tool-Visualization 3-15 

EMI Electrical Micro Imaging Service 3-9 

OMRI Oil-Based Micro-Imager Tool 3-13 

SED Six Arm Dipmeter 3-16 

XRMI X-Tended Range Micro Imager Tool 3-11 

InSite Anywhere® Service 1-3 

Index 10-3 

K 

Knowledge and Data Transfer 1-1 

L 

LOGIQ Logging Truck 8-1 

LOGIQ Modular Skid Unit 8-3 

M 

Mechanical Services 4-39 

C-4 Casing Cutters 4-50 

Casing and Drillpipe Cutters 4-48 

Chemical Cutter 4-39 

Coiled Tubing Cutters 4-46 

Drill Collar Severing Tool 4-51 

Junk Shot 4-53 

Pipe Recovery 4-39 

Super Tubing Cutters 4-44 

Tubing Cutters 4-42 

Mnemonics 9-1 

Log Header Mnemonics 9-44 

Mobilization 8-1 

N 

Near-Wellbore Stimulation 5-127 

PerfStim Process 5-133 

POWR*PERF SM Perforation/Stimulation 

Process 5-132 

Propellent Stimulation Tool Assembly 5-130 

StimGun* Assembly 5-127 

NMR 3-29 

MRILab® Magnetic Resonance Image Fluid 

Analyzer 3-31 

MRIL-XL and MRIL®-Prime Magnetic Resonance 

Image Logging Tools 3-29 

Nuclear 3-17 

CSNG Compensated Spectral Natural Gamma 

Ray 3-22 

DSEN Dual-Spaced Epithermal Neutron Log 

Tool 3-21 

DSN Dual-Spaced Neutron Tool 3-19 

SDL Spectral Density Log 3-17 

*StimGun is a trademark of Marathon Oil Company.

O 

Open-Hole Wireline and Perforating Services 3-1 

Oriented Perforating 5-134 

Eccentric Orienting Tandem 5-138 

Finned Orienting Tandem 5-137 

G-Force® Precision Oriented Perforating 

System 5-134 

Oriented Perforating with Modular Guns 5-136 

P 


Petrophysics 2-1 

MRI Petrophysics 2-1 

Diffusion Analysis (DIFAN) 2-5 

Enhanced Diffusion Method (EDM) 

Technique 2-6 

Heavy Oil MRIAN SM Service 2-7 

MRIAN Magnetic Resonance Imaging 

Analysis 2-2 

MRIL® Simultaneous T1 and T2 

Measurements 2-1 

StiMRIL Process 2-8 

Time Domain Analysis (TDA) 2-4 

Volumetric Petrophysics 2-10 

Chi Modeling® Computation Service 2-10 

CORAL Complex Lithology Analysis 2-15 

LARA Laminated Reservoir Analysis 2-16 

SASHA Shaly Sand Analysis 2-14 

ULTRA Module Suite 2-12 

Plug Setting Equipment 4-54 

EZ Drill® Bridge Plugs 4-54 

Fas Drill® Bridge Plugs 4-55 

Production Logging 4-18 

FloImager® Service 4-21 

GHT Gas Holdup Tool 4-23 

MPL Memory Production Logging Tool 4-24 

Production Logging Tools 4-18 

Quartz Pressure Tool 4-27 

R 

Real-Time Operations 1-1 

Real-Time Data/Solution Delivery 1-1 

Reservoir and Production Engineering 2-38 

FloImager Analysis Service 2-54 

FloImager® 3D Software Analysis 2-54 

Production Logging Analysis 2-51 

Reservoir Evaluation 2-48 

CarbOxSat Model 2-49 

SigmaSat Model 2-48 

TripleSat Model 2-50 

Reservoir Testing Studio 2-38 

Exact Anisotropy Analysis Plot 2-39 

Exact Buildup Analysis 2-39 

FasTest® Buildup Analysis 2-40 

Formation Test Summary Program (FTS) 2-42 

Horner Time Plots 2-40 

Log-Log Derivative Analysis Plot 2-41 

PVT Analysis 2-42 

Well Testing 2-44 

Reservoir Characterization 2-17 

Borehole Image Analysis 2-17 

AutoDip and TrendSetter Services 2-17 

Facies Profile 2-22 

ReadyView Open-Hole Imaging 2-20 

ImagePerm 2-25 

Net2Gross Sand Count 2-24 


Resistivity 3-1 

ACRt Array Compensated Resistivity Tool 

System 3-1 

DLL Dual Laterolog Service 3-6 

HDIL Hostile Dual Induction Log 3-5 

HFDT High Frequency Dielectric Tool 3-8 

HRAI High Resolution Array Induction Tool 3-3 

HRI High Resolution Induction Tool 3-4 

MSFL Micro-Spherically Focused Log and 

Microlog (ML) 3-7 

10-4 Index 

S 

Sampling 3-37 

HRSCT Hostile Rotary Side Wall Coring Tool 3-46 

Hydraulic Valve Section 3-46 

Mandrel Section 3-46 

Motor Drive Section 3-46 

RDT Reservoir Description Tool 3-37 

CVS Chamber Valve Section 3-40 

DPS Dual Probe Section 3-39 

FPS Flow-Control Pump-Out Section 3-39 

MCS Multi Chamber Section 3-40 

MRILab® Section 3-40 

Oval Pad 3-39 

QGS Quartz Gauge Section 3-39 

Straddle Packer 3-39 

RSCT Rotary Sidewall Coring Tool 3-43 

SFT-IV Sequential Formation Tester IV Tool 3-41 

SFTT Sequential Formation Test Tool 3-42 

SWC Side Wall Coring Tool 3-45 

Shaped Charges 5-1 

Charge Performance Data 5-7 

Dominator® Shaped Charges 5-2

KISS Low-Damage Perforating Charge 5-6 

MaxForce Shaped Charges 5-1 

Maxim Shaped Charges 5-5 

Mirage® Shaped Charges 5-3 

Slickline Service Equipment and Services 7-1 

Slickline Skid Units and Trucks 7-14 

Special Applications 5-139 

Coiled Tubing Conveyed Perforating 5-142 

DrillGun Perforating Systems 5-143 

Modular Gun System 5-139 

Select Fire Systems 5-141 

Setting Tools for the Auto-Release Gun Hanger 5-145 

Subsurface Service Tools 7-2 

Auxiliary Tools For Use with Slickline Toolstring 7-6 

Expandable Wirefinder 7-7 

Otis® Go-Devil 7-7 

Otis M Magnetic Fishing Tool 7-6 

Otis P Wireline Grab 7-7 

Otis Tubing Broach 7-6 

Otis G Fishing Socket 7-7 

Otis Gauge Cutter and Swaging Tools 7-6 

Otis Impression Tool 7-6 

Otis Quick Connect Toolstring Connection 7-5 

Plugs For Wells Without Landing Nipples 7-10 

Monolock® Plug 7-10 

Positioning Tools 7-12 

Otis BO Selective Positioning Tools 7-12 

Pulling Tools 7-9 

External Fishing Necks 7-9 

Internal Fishing Necks 7-9 

Running Tools 7-8 

Otis MR Running Tools 7-8 

Otis RXN Running Tools 7-8 

Otis SAFETYSET® Running Tools 7-8 

Otis UP Running Tool 7-8 

Otis X® and R® Running Tools 7-8 

Slickline Detent Jars 7-4 

Slickline Service Tools 7-2 

Slickline Toolstring 7-2 

Otis Accelerators 7-3 

Otis B Blind Box 7-3 

Otis Jars 7-3 

Otis Knuckle Joints 7-3 

Otis Rope Sockets 7-2 

Otis Stems 7-2 

Wireline Toolstring 7-2 

Test Tools 7-11 

Otis Non-Selective Test Tools 7-11 

Tubing Perforators and Bailers 7-13 

Surface Service Equipment 7-15 

Index 10-5 

T 

Through Casing Acoustic Services 4-12 

FWS Full Wave Sonic Tool 4-14 

HFWS Hostile Full Wave Sonic Tool 4-16 

WaveSonic Tool 4-12

10-6 Index

Wireline and Perforating Products and Services Catalog - Halliburton

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