BAKER HUGHES - Drilling Fluids Reference Manual

RESERVOIR APPLICATION FLUIDS
by volume while barite would be about 65% by volume. Balling and lost circulation are
frequent problems while drilling conductor, surface or any large diameter hole. Generally,
this is a function of the concentration of drilled cuttings in the annulus. High
concentrations of active clay (gumbo) cuttings in the annulus result in cuttings adhering
together on the bit and pipe. In addition, cuttings increase fluid density and hydrostatic
pressure. Factors affecting the cuttings concentration are penetration rate, circulating rate,
and cuttings transport efficiency. The following equation provides the maximum
penetration rate for a given circulation rate and desired cuttings concentration.
PERFFLOW Systems: General Engineering Guidelines
The potentially severe borehole problems intrinsic with horizontal drilling can be minimized
dramatically with the selection of a non-damaging drilling fluid system possessing optimum holecleaning
and lubrication capabilities.
Drilling fluids for vertical wells are often chosen primarily for their ability to control the formation
surrounding the reservoir. By modifying the fluid properties and dynamics, these same fluids, in
many cases, have been used to drill horizontally.
In this regard, it is important to devote particular attention to the cleaning, lubrication, and
maximum pay zone protection capabilities of the fluid system. For gravel packed completion, pay
zone protection is extremely important. Damage to the formation will inhibit perforation filling,
open hole performance, and reduce well productivity. It is extremely important to obtain a clean
interface between the gravel pack sand and the formation sand.
As with vertical wells, deciding which fluid system, or combination of systems, to use in a
horizontal application depends upon the geology of the prospect, historical successes and failures,
environmental constraints, and the experience of the fluid company and operator.
When planning a drilling fluids program for a horizontal well, it is often advantageous to view the
prospect in the same manner as the production engineer – from the downhole objective up. For
gravel pack purposes, this usually requires the use of drill-in fluids.
The drill-in fluid should be designed to minimize damage to the reservoir. If the proposed drill-in
fluid design conflicts with fluid designs up-hole, then a change in the fluid program may be
warranted. The carrying capacity, inhibition, and lubricity of the fluid should suit the formations
drilled and the prospective well profile.
PERFFLOW DIF fluids were designed to be used as drill-in fluid systems. A drill-in fluid
possesses the desirable properties of a good drilling fluid and provides the necessary attributes of a
completion fluid. In this respect, PERFFLOW DIF should be the only fluid the producing
formation sees during the final drilling operation. This point, however, brings up the question as to
when the fluid should be introduced into the drilling operation.
Even though a PERFFLOW DIF fluid can be formulated to handle most hole conditions during
the drilling operation, it may be more economical and effective to use conventional fluids such as
oil-base fluids, PHPA systems, or simple bentonite-base fluids for most of the drilling operation.
When to introduce the PERFFLOW DIF becomes a judgment call on the part of the drilling and
production engineers. The following guidelines and comments are provided to assist in making this
decision.
BAKER HUGHES DRILLING FLUIDS
REFERENCE MANUAL
REVISION 2006 6-25