A STUDY OF PETROPHYSICAL PARAMETERS FOR QUICK-LOOK ...

A STUDY OF PETROPHYSICAL PARAMETERS 

FOR QUICK-LOOK PETROPHYSICAL EVALUATION, 

SIRIKIT EAST FIELD, S1 PROJECT, 

PHITSANULOK BASIN 

Miss Weenawadee Bahae 

A REPORT IN PARTIAL FULFILLMENT OF THE REQUIREMENT 

FOR THE DEGREE OF THE BACHELOR SCIENCE 

DEPARTMENT OF GEOLOGY FACULTY OF SCIENCE 

CHULALONGKORN UNIVERSITY 

2008

การศึกษาคาตัวแปรที่เหมาะสมสําหรับการประเมินคุณสมบัติทางกายภาพเบื้องตน 

ของหินจากการหยั่งธรณีหลุมเจาะ 

ในบริเวณพื้นที่สิริกิติ์ตะวันออก 

โครงการเอส-1 แองพิษณุโลก 

วีณาวดี บาเหะ 

ภาควิชาธรณีวิทยา คณะวิทยาศาสตร จุฬาลงกรณมหาวิทยาลัย 

โทร: 0-8154-08932, e-mail: mew_35@hotmail.com 

บทคัดยอ: ในการประเมินศักยภาพของชั้นหินกักเก็บปโตรเลียมนั้น 

สามารถประเมินไดจากขอมูลคุณสมบัติทาง 

กายภาพ (Petrophysics) ของชั้นหิน 

ซึ่งในแหลงน้ํามันสิริกิตติ์นั้นปจจุบันไดนําขอมูลคุณสมบัติทางกายภาพของชั้นหิน 

มาแปลความโดยใชโปรแกมที่เรียกวา 

Geolog6 ซึ่งในการดําเนินการนั้นมีวิธีการที่ซับซอนและใชเวลามาก 

ดังนั้น 

จึงไดมี 

การศึกษาเพื่อหาคาตัวแปรตางๆ 

ที่จะนํามาใชในการแปลขอมูลคุณสมบัติทางกายภาพของชั้นหิน 

โดยอาศัยโปรแกรม 

Microsoft Excel ซึ่งสามารถใชงานไดงาย 

และใชไดทันทีที่หลุมเจาะหลังจากที่ไดรับขอมูลคุณสมบัติทางกายภาพของชั้น 

หินแลว ซึ่งวิธีการนี้เรียกวา 

การประเมินคุณสมบัติทางกายภาพเบื้องตนของหินจากการหยั่งธรณีหลุมเจาะ 

(Quick Look 

Petrophysical Evaluation) 

การวิจัยครั้งนี้เปนการศึกษาจากขอมูลหยั่งธรณีหลุมเจาะจํานวน 

10 หลุม ของพื้นที่บริเวณสิริกิตติ์ตะวันออก 

โครงการเอส1 แองพิษณุโลก โดยทําการศึกษาจากชั้นหินกักเก็บปโตรเลียมที่สําคัญของพื้นที่ซึ่งไดแก 

ชั้นหิน 

K และ L 

จากการศึกษาทฤษฎีพื้นฐานของการแปลขอมูลจากการหยั่งธรณีหลุมเจาะและการประเมินคุณสมบัติทางกายภาพ- 

เบื้องตนของหินสามารถนํามาใชในการวิเคราะหขอมูลหยั่งธรณีจํานวน 

10 หลุมของพื้นที่ที่ทําการศึกษาและเลือกคาตัว 

แปรที่เหมาะสมที่ไดจากการเฉลี่ยของผลการศึกษาทั้งหมด 

ดังนี้ 

คาเฉลี่ยจากการอานขอมูลหยั่งรังสีแกมมาในหินทราย 

และหินดินดาน นําไปสูการคํานวณคาปริมาณหินดินดาน(Vsh) 

คาความตานทานไฟฟาปรากฏของน้ําในหินทราย(Rwa) 

และในหินดินดาน(Rwb) ซึ่งเปนคาคงที่ที่ใชตลอดสําหรับการศึกษาครั้งนี้ 

นําไปสูการหาคาความอิ่มตัวดวยน้ํา(Sw) 

ขั้นตอมาเปนการอานขอมูลหยั่งความหนาแนนและขอมูลหยั่งนิวตรอน 

นําไปสูการคํานวณเพื่อนหาคาความพรุน 

จากนั้น 

เปนการประมวลผลดวยวิธีการ Quick Look Petrophysical Evaluation และไดทําการเปรียบเทียบผลการแปลความโดย 

วิธี Quick Look Petrophysical Evaluation กับวิธีการแปลความโดยใชโปรแกรม Geolog6 

ผลการศึกษาที่ไดพบวา 

การประเมินคุณสมบัติทางกายภาพของชั้นหินดวยวิธี 

Quick Look ที่เดิมใชกับแหลง 

กักเก็บกาซนั้นสามารถนํามาใชกับพื้นที่สิริกิตติ์ซึ่งเปนแหลงกักเก็บทั้งกาซและน้ํามันได 

โดยใชไดดีสําหรับการหาคา 

ปริมาณหินดินดาน และ คาความพรุน สวนคาความอิ่มตัวดวยน้ํานั้นยังใชไมไดผลเนื่องจากไดคาความแตกตาง 

(deviation) คอนขางสูง นั่นคือ 

อยูที่ประมาณ 

22% ซึ่งอาจเนื่องมาจากการเลือกคาของตัวแปรที่ไมเหมาะสมและการใช 

สมการที่ตางกัน 

จึงอาจตองมีการปรับคาของตัวแปรบางตัวเพื่อใหคาความแตกตางออกมานอยที่สุด 

Keywords: Quick Look, Petrophysical evaluation, Sirikit east 

I

A STUDY OF PETROPHYSICAL PARAMETERS FOR QUICK LOOK PETROPHYSICAL 

EVALUATION, SIRIKIT EAST FIELD, S1 PROJECT, PHITSANULOK BASIN 

Weenawadee Bahae 

Department of Geology, Faculty of Science, Chulalongkorn University; 

Tel: 0-8154-08932, e-mail: mew_35@hotmail.com 

Abstract: The common practice for petrophysical log analysis in PTTEP is employing Geolog 6 

software. The software requires more complicated procedures and hence time. At the rig site, where 

immediate impression on the well result is needed, the simply MS excel worksheet was in-house developed 

for a quick-look petrophysical analysis. Quick-look petrophysical evaluations are used by oil companies to 

allow well site geologists to quickly make an approximate evaluation of the wireline log data at the well site. 

This allows the geologist to quickly identify any potential hydrocarbon bearing intervals and helps in the 

selection of intervals for pressure testing. The accuracy of the results depends on accuracy of the input 

parameters. 

This project analyzed wire line log and mud log data from 10 wells in the Sirikit East area, S1 Project, 

Phitsanulok basin, North of Thailand, which study from the main reservoir such as formation K and L. After 

learning the basic principles of petrophysical logging tools and interpretation, the Quick-look evaluation 

technique was studied. The 10 wells were analyzed and a set of input parameters were chosen by taking 

averages from the results. The inputs were mostly average values of gamma readings in sand and shale, 

used to compute shale volumes (Vsh), and apparent formation water resistivity in sand and shale, Rwa and 

Rwb respectively. These values were seen to be fairly constant for the wells being studied. An additional 

step was added to the standard quick-look method. The normal method of computing porosity does not 

include any correction for gas effect on the density and neutron tools. An option was added where gas 

corrections could be applied if required. 

The final step of the project was to compare the results of the quick-look evaluations with those 

produced by the petrophysical evaluation carried out by the S1 Asset. The results agreed very well in 

volume of shale and porosity, which is shown the deviation value is approximate 2-3% and 4% respectively. 

The result have some different values of water saturation which depend on some parameters such as matrix 

and shale parameters and use different equation to calculate water saturation because the deviation value is 

shown rather high approximate 22%. This quick-look method is shown to work rather well in this field and 

probably to adjust in some parameter for next study. 

Keywords: Quick Look, Petrophysical evaluation, Sirikit east 

II

Acknowledgement 

This report has been accomplished with the help, suggestion and encouragement of 

many people. Firstly, I would like to sincerely thank PTT Exploration & Production Public 

Company Limited, especially to Khun Kiatisak Kuntawang, Khun Wanida Srithongtae, Mr.Terry 

Higgins, Khun Suphawich Thanudamrong and Khun Parinya Pholbud for giving me a great 

chance to do this project and also provide me with the company’s data needed for this project. 

I appreciate help and support from Dr. Vichai Chutakositkanon, Khun Wanida Srithongtae and , 

Mr.Terry Higgins who are my advisors and always give me excellent suggestion and 

encouragement. Acknowledgement is also expressed to Khun Parinya Pholbud, Khun 

Kriangkrai Varejaroenchai, Khun Sutasinee Kittisupalauk, Khun Nattapong Tanapuntanurak, 

Khun Sudarat Chareonsrisomboon, Khun Pinyada Taweepornpratomkul, Khun Tanaporn 

Chareonpan and Khun Kannika Preecha for their kind support, help and useful advice. 

I would like to deeply express thank to all lecturers in the Department of 

Geology, Faculty of Science, Chulalongkorn University, Assoc. Prof. Dr. Punya Charusiri, 

Assist. Prof. Virote Daorerk, Assoc. Prof. Dr. Visut Pisutha–Arnond, Assoc. Prof. Dr. 

Thanawat Jarupongsakul, Assist. Prof. Dr. Somchai Nakapadungrat, Assist. Prof. Dr. 

Sombat Yumuang, Assist. Prof. Dr. Chakrapan Sutthirat, Assist. Prof. Dr. Thasinee 

Charoentitirat, Assist. Prof. Montri Choowong, Dr. Vichai Chutakositkanon, Dr. Kruawun 

Jankaew, Dr. Thanop Thitimakorn, Dr. Yoshio Sato, Archan Pitsanupong Kanjanapayont, 

Archan Akaneewut Chabangbon, Archan Malatee Taiyaqupt, Archan Bussarasiri Thana for 

giving me their knowledge, experiences and suggestions. 

My thanks are also to my seniors and colleagues especially Khun Muchimaporn 

Khamphutorn and Khun Ladda Sunthong for giving me encouragement, support and advice 

through the past time. 

Thanks are extended to my family, all geology classmates and juniors for their 

helpfulness and cheerfulness in the last three years. Finally, I appreciate all supports 

from the others that have not been mentioned. 

III

Contents 

Abstract (Thai) I 

Abstract (English) II 

Acknowledgements III 

Contents IV 

List of Figures V 

List of Tables IX 

Chapter 1: INTRODUCTION 

1.1 Rationale 1 

1.2 Study Area 5 

1.3 Objective 5 

1.4 Scope of study 6 

1.5 Methodology 6 

1.6 Previous works 9 

Chapter 2: REGIONAL GEOLOGY OF PHITSANULOK BASIN 13 

2.1 Regional Geology 13 

2.2 Structural Evolution 15 

2.3 Stratigraphic and Depositional Environment 21 

2.4 Petroleum System 23 

IV 

Page

Chapter 3: WELL LOG INTERPRETATION THEORY 31 

3.1 Introduction to Well Log Interpretation 31 

3.2 Well Logging Tools 31 

3.3 Log Interpretation Derived Parameters 32 

Chapter 4: METHODOLOGY 34 

4.1 Data Used 34 

4.2 Log Evaluation Workflow 34 

4.3 Quick Look Analysis 41 

Chapter 5: RESULT OF WORKS 46 

5.1 Result of the computation from Quick Look Excel Software. 46 

5.2 The computed result of parameter of 10 wells compare with 47 

S1 petrophysical Method. 

5.3 To compare the results of the quick-look evaluations with those 48 

produced by the petrophysical evaluation carried out by 

the S1Asset. 

Chapter 6: DISCUSSION, CONCLUSION AND RECOMMENDATION 49 

6.1 Discussion 49 

6.2 Conclusion 54 

6.3 Recommendations 54 

Reference 56 

APPENDIX 57 

V

List of Figures 

Figure 1.1: Picture showing the S1 Concession in Phitsanulok Basin (Thai Shell,1997) 3 

Figure 1.2: Picture showing the Location of study area in north eastern of 4 

Sirikit Field (Thai Shell,1997) 

Figure 1.3: The flow chart of this study. 8 

Figure 2.1: Depositional history of the Phitsanulok Basin. (Modified from TanapornC, 14 

2008) 

Figure 2.2: Structural frame work of the Phitsanulok basin, Thailand (Thai Shell,1997) 18 

Figure 2.3: Structural model of phase I & II of Phitsanulok Basin (Thai Shell,1997) 20 

Figure 2.4: Structural model of phase III & IV of Phitsanulok Basin (Thai Shell,1997) 21 

Figure 2.5: Schematic stratigraphy of Phitsanulok basin (Bal et al., 1988) 22 

Figure 2.6: Picture shows the stratigraphic chart in Phitsanulok basin (Bal et al., 1988) 23 

Figure 2.7: Source rock distribution of Phitsanulok Basin (PTTEP,2008) 24 

Figure 2.8: Reservoir properties distribution of Phitsanulok Basin (PTTEP,2008) 25 

Figure 2.9: Hydrocarbon migration distribution of Phitsanulok Basin (PTTEP,2008) 26 

Figure 2.10: Seal distribution of Phitsanulok Basin (PTTEP,2008) 27 

Figure 4.1: The Quick Look Formula for Petrophysical Analysis (applied from 39 

Arthit Field) 

Figure 4.2: The example of Quick Look Excel Program of Sirikit East well. 39 

Figure 4.3: The example of log reading in Sirikit East well. 40 

VI 

Page

List of Figures 

Figure 4.4: The Example of cross plot between Resistivity of free water (Rwf) and 40 

bound water (Rwb) 

Figure 5.1: The example of summary computing data sheet of Quick-Look for 46 

Formation Evaluation of LKU-X07 well. 

Figure 5.2: The computed result of Volume of Shale of 10 wells compare with 47 

S1 Asset. 

Figure 5.3: The computed result of Porosity of 10 wells compare with S1 Asset. 47 

Figure 5.4: The computed result of Water Saturation of 10 wells compare with 54 

S1Asset. 

Figure 5.5: Comparison results of the quick-look evaluations with S1 Asset. 48 

VII 

Page

List of Tables 

Table1: Greater Sirikit East reservoir information summary (updated from 29 

Sirikit East Field Development,1996) 

Table 2: The matrix density, fluid density and PEF(Photo Electrical Factor) for 35 

some common compounds. 

Table 3: The average of Rwa and Rwb from 10 wells. 44 

VIII 

Page

Chapter 1 

INTRODUCTION 

1.1 Rationale 

Nowadays, there are many kinds of energy resource such as coal, wind, solar 

cell and petroleum which are very important for human. However the most important 

energy resource is petroleum. Since human have known the petroleum, it have been 

used for many advantages such as the fuel for vehicle, producing electricity and used 

polymer industry. Because of its advantages, the petroleum is needed to develop 

economic of countries, so one of the important key to success in the exploration and 

production for new potential area is the study of the sand reservoir. 

The S1 Concession is located in the Phitsanulok Basin in northern Thailand 

(Figure 1.1) near Lan Krabu district, Kamphaeng Phet province, approximately 400 km 

north of Bangkok. The concession contains Sirikit Field which is Thailand’s largest 

onshore producing oil field. 

The Sirikit field is located in the south western part of the S1 concession close to 

the village of Lan Krabu, some 50 km from the nearest major town of Phitsanulok. This is 

the main producing field of the Phitsanulok Basin, a major extensional structure of 

Oligocene age, overlying folded partly metamorphosed, and block faulted, Mesozoic 

basement, is high potential petroleum reservoir. The basin is a half graben with up to 8 

km of Tertiary sediment infill situated at the triangular intersection of two regional strikeslip 

fault zones, the Mae Ping Fault Zone and the Uttaradit Fault Zone. The basin fill has 

been subdivided into 8 formations namely in ascending order: Khom, Nong Bua, 

Sarabop, Lan Krabu, Chum Saeng, Pratu Tao, Yom and Ping Formation. However, the 

Tertiary Basins in Thailand are mostly covered by Quaternary sediments therefore, the 

petroleum exploration have to use the subsurface exploration technique. 

The study area is located in the northeastern part of Sirikit Field, (Figure1.2) is 

situated in S1 concession of PTTEP Public Company Limited is the first commercial and 

the largest onshore oil field in Thailand, which covers five provinces: Phichit, 

Phitsanulok, Sukhothai, Kamphaeng Phet and Uttaradit. 

1

I am interested in the petrophysical evaluation and to know working of geologist 

at the rig site in this particular oil field. Therefore, I would like to study the fundamental of 

petrophysical evaluation for formation namely should be to start to learn a quick-look 

petrophysical analysis. In addition, to evaluate the Volume of shale, Porosity and Water 

saturation and classify the fluid type bearing in reservoirs. The fundamental 

petrophysical principles will be provided me to understand the petrophysical 

parameters for Quick-Look petrophysical evaluation . This study comprises of 

interpretation of wire-line logs and Quick-Look analysis. The results will be used to 

define petrophysical parameters and perform petrophysical evaluation. The presence of 

shale strongly affects the physical properties of the reservoir rock and induces a 

significant effect on the respond of the most open-hole logging tools especially 

resistivity logs in hydrocarbon zone. 

Now, Sirikit East Field use Geolog6 program for petrophysical evaluation, which 

is the complex method and dawdle over the time . So that, to have this study for 

petrophysical evaluation by using Microsoft Excel, which is easy to use and do it at the 

rig site suddenly after you got the wure line log data. So this method known as Quicklook 

petrophysical evaluations. 

Quick-Look Excel Program is use in Sirikit East Field is apply the method which 

will get from Arthit and Bong Kot Field, the gas zone area. Because of Quick-look 

petrophysical evaluations are used by oil companies to allow well site geologists to 

quickly make an approximate evaluation of the wireline log data at the well site. This 

allows the geologist to quickly identify any potential hydrocarbon bearing intervals and 

helps in the selection of intervals for pressure testing. 

2

Figure1.1 Picture showing the S1 Concession in Phitsanulok Basin (Thai Shell,1997) 

3

Figure 1.2 Picture showing the Location of study area in north eastern of Sirikit Field 

(Thai Shell,1997). 

4

1.2 Study area 

The Sirikit East was discovered by LKU-X01 since 1995. The 3D seismic 

acquisition was done in 1998 and followed up by field development plan. The 

comprehensive geology of the Sirikit East area has been studied since 1998. During 

2000 – 2004, there was very limited activities happen in Sirikit East Area due to constrain 

of resources. In 2005, it was Pre-Depth Stacked Migration processing on 3D seismic 

data. It leaded to the success of LKU-X11 to LKU-Z04 wells. 

The Sirikit East Field is located to the northeastern of the Sirikit Main Field, is 

situated in S1 concession of PTTEP Public Company Limited is the first commercial and 

the largest onshore oil field in Thailand. Sirikit Oil Field which lies in the Phitsanulok 

Basin (Figure 1.2) covers five provinces: Phichit, Phitsanulok, Sukhothai, Kamphaeng 

Phet and Uttaradit. It is far from Bangkok about 400 kilometers. The license area of Sirikit 

East area is about 1.98 square kilometers which was presented in Figure …… 

The Phitsanulok Basin, one of a series of Tertiary rift-related structures in central 

and northern Thailand, is high potential petroleum reservoir. The tectonic history of the 

area is complex: the original, extensional, half graben was deformed during deposition 

of the upper reservoir sequence by left-lateral strike-slip faulting (Knox & Wakefield, 

1983).The basin fill has been subdivided into 8 formations namely in ascending order: 

Khom, Nong Bua, Sarabop, Lan Krabu, Chum Saeng, Pratu Tao, Yom and Ping 

Formation. However, the Tertiary Basins in Thailand are mostly covered by Quaternary 

sediments therefore, the petroleum exploration have to use the subsurface exploration 

technique. 

1.3 Objective 

This study concentrates on well log approaches to study the petrophysical 

parameters for Quick-Look petrophysical evaluation in Sirikit East area. 

The main objective is to identify the reservoir properties. To define petrophysical 

parameter for formation evaluation and to determine Volumn of Shale, Porosity and 

Water Saturation by using wireline logging data, core data, cuttings and pressure data 

of well. 

5

1.4 Scope of Study 

The whole data for use based on the main reservoir such as formation K and L of 

Sirikit East Area. All data in this senior project is supported by PTT Exploration & 

Production Public Company Limited. The database is composed of: 

- Wire line log data of LKU-X07, LKU-X08, LKU-X09, LKU-X10, LKU-X11, LKU- 

X12, LKU-Y04, LKU-Y05, LKU-Z04 and LKU-Z06 consisted of gamma ray log, resistivity 

log, density log and neutron log. 

- Mud log data of LKU-X07, LKU-X08, LKU-X09, LKU-X10, LKU-X11, LKU-X12, 

LKU-Y04, LKU-Y05, LKU-Z04 and LKU-Z06. 

1.5 Methodology 

1. Study previous works that are related to this project including (Figure 1.3); 

1.1 Research and publications relating to Quick-Look petrophysical 

evaluation. 

1.2 Study regional geology, structural evolution, stratigraphy, 

depositional environment and petroleum system of Phitsanulok Basin and study area. 

1.3 Collect preliminary studies including well log digital data, well 

formation, deviation data and well report. 

2. Learning methods of basic petrophysical evaluation including;- 

2.1 Basic Log Interpretation in Shaly Sands. 

2.2 Basic Petrophysical evaluation by using Geolog6 program and 

Microsoft Excel Software, applied from Arthit and Bongkot gas field. 

3. Interpret wireline logging data of 10 wells in the study area by hand and using 

Geolog6 software. 

4. Define petrophysical parameters for petrophysical evaluation such as GRmin, 

GRmax, Rt, RHOB and NPHI. 

5. To measure and find the proper parameter for petrophysical evaluation by 

Quick Look method. 

6. Compare petrophysical results (Volume of Shale, Porosity, Water Saturation) 

between Quick Look methodology and full interpretation from S1 asset. 

6

7. Discussion and conclusion which conduce to writing report of the 

petrophysical analysis results. 

8. Presentation. 

7

Literature review 

Learning Petrophysical Evaluation 

(Basic Log Interpretation and Basic Quick Look Interpretation) 

Logging interpretation (10 Wells) 

Define Petrophysical parameters for petrophysical evaluation 

(GRmin, GRmax, Rt, RHOB, NPHI). 

To measure and find the proper parameter for petrophysical 

evaluation by Quick Look method. 

Compare parameter results (Volume of Shale, Porosity, Water 

Saturation) between Quick Look method and S1 method. 

Discussion and conclusion 

Report and presentation 

Figure 1.3 The flow chart of this study. 

8

1.6 Previous work 

R. B. Ainsworth and H. Sanikosik (1998) studied 3-D reservoir modelling of the 

Sirikit West Field, Phitsanulok Basin, Thailand, reported that the Sirikit West Oil Field lies 

within the Phitsanulok Basin of Central Thailand. It is a satellite of the main Sirikit 

accumulation. Within the field, the Lan Krabu Formation represents the main reservoir 

interval. It is interpreted as fluvio-lacustrine in origin. The three major reservoir submembers 

(D, K1 and K2) are subdivided into 10 to 15 m thick parasequences bounded 

vertically by minor flooding surfaces. Each parasequence represents a progradational 

phase of mouthbar development which is terminated by a flooding event. A typical 

parasequence consists of facies progressing from open lacustrine claystone to delta 

front including mouthbars and channel sands, to floodplain sands and shales. 

Compared to the Main Sirikit Field, the same stratigraphic intervals in Sirikit West 

are up to three times thicker. This indicates a strong element of differential subsidence 

across the major bounding fault between the two fields. The depositional and sequence 

stratigraphic models for the area were used as a basis for generating 3-D geological 

and property models. 3-D modelling was undertaken to determine reservoir architecture 

and reservoir property trends prior to a new phase of field development. The Shell 

proprietary correlation software package GEOLOGIX and 3-D modelling package 

MONARCH were utilised to enable rapid evaluation of a a range of geological and 

petrophysical scenarios. For example. differing correlation scenarios reflecting 

geological uncertainties such as reservoir continuity were generated using GEOLOGIX 

and rapidly screened in MONARCH. The 3-D models were used for volumetric 

calculations, well planning, static connectivity analyses of proposed wells and as the 

input for dynamic flow modelling. Upscaling of the 3-D geological models was 

undertaken using REDUCE and dynamic reservoir simulation was performed using the 

MoReS simulator. History matching of the two geological models carried forward to the 

simulator suggested that the high reservoir continuity scenario is the most readily 

matched. The dynamic model is being used as a general reservoir management tool for 

forecasting, well planning, and for analysing further development options. Results 

indicate potential for further development and appraisal drilling of up to ten new wells to 

fully develop the field and achieve optimal oil recovery. 

9

Sombat et al. (2006) used data from Gamma Ray (GR), Resistivity (AT90), 

Density (RHOB) and Neutron (NPHI) logs of existing wells in AWP1, AWP2, and AWP3. 

They studied the Rwf and Rwb determination for Quick Look formation evaluation of 

Arthit Field. They present that to determine water saturation (Sw) through use of by Dual 

Water Equations, Ro (Resistivity of water filled rock) is a major uncertainty parameter 

needed to calculate precise levels of water saturation. Initially, values for Rwf (Resistivity 

of free water) and Rwb (Resistivity of bound water) are required in order to calculate Ro. 

In the wellsite, Rwf and Rwb values of each formation are obtained by using the Rwa-GR 

crossplots method. It should be noted that previous Rwf and Rwb determinations of 

formations FM0, FM1, 2A, 2B, 2C, and 2D/2E were derived from a very small number of 

plotted values, which, therefore, might not have resulted the most accurate Rwf and 

Rwb determinations. Consequently, they study aims to determine more accurate Rwf 

and Rwb values from the crossplots by use of an increased amount of data from all wells 

in AWP1, AWP2, and AWP3. They can describe the result of Rwf and Rwb from the 

study of each formation as below: 

- FM0, Rwf is equal to 0.25 while Rwb is equal to 0.05 

- FM1, Rwf is equal to 0.28 while Rwb is equal to 0.03 

- FM2A, Rwf is equal to 0.20 while Rwb is equal to 0.04 

- FM2B, Rwf is equal to 0.30 while Rwb is equal to 0.05 

- FM2C, Rwf is equal to 0.28 while Rwb is equal to 0.03 

- FM2D/2E, Rwf is equal to 0.19while Rwb is equal to 0.09 

Pullarp (2007) studied the petrophysical re-evaluation log analysis of reservoir 

rocks in the B6/27 concession, Chumphon basin, Gulf of Thailand. Her studied was 

performed to determine reservoir and fluid properties which are composed of lithology, 

porosity and water saturation. Furthermore, she set up the methodology and parameters 

of reservoir rocks by GEOLOG6 software and applied for next drilling campaign. She 

studied two wells such as Well NNN-A04ST and NNN-B01ST. 

10

Well NNN-A04ST is located in the center part of the study area and well NNN- 

B01ST is lies 6 km north of well A04ST. The results show that there are significant oil 

reserves in the karstified Permian carbonate reservoirs. Average reservoir porosity of 

NNN-A04ST and NNN-B01ST is 27% and 32% respectively. Average reservoir water 

saturation of NNN-A04ST and NNN-B01ST is approximate 26% and 20% respectively. 

Net pay thickness of NNN-A04ST and NNN-B01ST is 7.91 mTVT (True Vertical 

Thickness) and 24.53 mTVT respectively. 

The results of re-petrophysics evaluation compared with the previous 

petrophysics evaluation have some different values of porosity and saturation which 

depend on some parameters such as matrix and shale parameters and use different 

equation to calculate water saturation. 

Tanapuntanurak (2007) studied geoscience of Mahidol University, studied the 

re-petrophysical evaluation of shaly sand reservoir in Muda field, Malay basin. He was 

undertaken to determine reservoirs and fluid properties which compose of volumn of 

shale, porosity and water saturation. He reported that five wells in Muda field are used in 

this study (Well A, Well B, Well c, Well D, Well E) and the results of this Re-evalation as 

following : shaly sand reservoir which has petroleum potential in Muda field have 

average volumn of shale 13.45%-30.07%, porosity 10.24%-20.49% and water saturation 

35.83%-57.20%, which is the highest potential reservoir. 

Mezzatesta (2006) studied the reconciling formation porosity and fluid 

distribution estimations in carbonate and shaly-sand systems represents a problem that 

log analysts and petrophysicists face in dealing with well log interpretation. The problem 

becomes especially challenging when data from conventional (e.g., density, neutron, 

gamma ray) and non-conventional (e.g., Nuclear Magnetic Resonance (NMR), multicomponent 

induction) instruments are available and need to be combined in a 

consistent interpretation. Also, the use of effective and/or total porosity petrophysical 

models may lead to confusion and improper use and interpretation of those quantities. 

His paper proposes petrophysical interpretation models for use in the evaluation of 

11

carbonate and shaly sand reservoirs. They allow for effectively and consistently 

combining the various measurements under the framework of either effective or total 

porosity. Simultaneous and sequential solutions of the petrophysical models are 

proposed leading to consistent data integration and reconciliation of porosity and fluid 

distribution across the various available log measurements. 

The proposed interpretation method focuses on the integration of NMR with 

conventional log measurements in carbonate and shaly-sand environments. With 

sufficient log data, rocks having complex mineralogy can be interpreted in terms of 

mineral volumes, irreducible and moveable water saturation, and hydrocarbon 

saturation. In a shaly-sand environment, results are expressed in terms of sand, shale 

and fluid saturation distributions. 

His paper describes the mathematical formulation of the petrophysical model as 

well as the applied numerical techniques. Optimal interpretation results are achieved 

using forward modeling and a constrained, quality-weighted error minimization 

technique. Field data examples are presented that show the ability of the interpretation 

models to reconcile porosity, fluid type, and fluid distribution in the pore space. 

12

Chapter 2 

REGIONAL GEOLOGY OF PHITSANULOK BASIN 

2.1 Regional Geology 

The Sirikit field is located in the south western part of the S1 concession close to 

the village of Lan Krabu, some 50 km from the nearest major town of Phitsanulok. This is 

the main producing field of the Phitsanulok Basin, a major extensional structure of 

Oligocene age, overlying folded partly metamorphosed, and block faulted, Mesozoic 

basement. The basin is a half graben with up to 8 km of Tertiary sediment infill situated 

at the triangular intersection of two regional strike-slip fault zones, the Mae Ping Fault 

Zone and the Uttaradit Fault Zone. 

The depositional history of the Phitsanulok Basin is intimately linked to the 

structural evolution of the area. The sediments can be subdivided into 3 main divisions 

that have been observed in other Thai extensional basins ( Figure 2.1); 

Sarabop Formation (Oligocene) : Predominantly clastic deposits (P member) 

composed of fluvial to alluvial fan & fan delta sediments deposited in a predominantly 

extensional structural environment. 

Chum Saeng & Lan Krabu Formations (Lower-Middle Miocene) : Deposition of 

interdigitating shales (Chum Saeng) and fluvio-deltaic (Lan Krabu D, K, L & M members) 

sediments in central & eastern parts of Phitsanulok Basin. Widespread transgressions 

alternating with extensive delta progradations resulted in thin (but areally extensive) 

transgressive-regressive (sand-shale) cycles characteristic of the Phitsanulok Basin. 

Pratu Tao, Yom & Ping Formations (Miocene-Recent) : Abrupt reduction in 

subsidence as structural environment became more transtensional. Deposition of 

clastic braided & meandering fluvial sediments (PTO & Yom) and alluvial fan/braid plain 

deposits of the Ping Formation. This latter depositional environment change may be 

associated with a structural environment shift from transtensional to transcompressional. 

13

Rock Formation Member Sub Member 

Ping 

Gas Yom Upper Yom (UYOM) 

Oil 

Oil 

Gas 

Oil 

Shale 

Pratu Tao (PTO) 

Chum Saeng (CS) 

Oil Lan Krabu (LKU) D 

Gas 

Oil 

Lower Yom (LYOM) 

Upper PTO (UPTO) 

Lower PTO (LPTO) 

Main Seal (MS) 

Lan Krabu (LKU) K K1 

Shale Chum Saeng (CS) Upper Intermediate Seal (UIS) 

Oil 

K2 

K3 

K4 

Lan Krabu L L1 

Shale Chum Saeng (CS) Lower Intermediate Shale (LIS) 

Oil Lan Krabu M 

Shale Chum Saeng (CS) Basal Shale (BS) 

Sarabop 

P 

Oil 

Oil Pre Tertiary (PTT) - Basement 

L2 

L3 

L4 

800m 

1400m 

2400m 

Figure 2.1 Depositional history of the Phitsanulok Basin. (Modified from TanapornC, 

2008) 

14

2.2 Structural Evolution 

2.2.1 Regional Structure 

The Phitsanulok Basin is the largest of the string of tertiary intracratonic 

extensional basins of onshore Thailand. Their formation is related to the relative 

movement of continental blocks which presently form the Malayan peninsula and 

Indochina. The rift basins occur in a roughly N-S oriented zone which coincides with the 

suture zone of the western Shan-Thai Block and the Indosinian Block (Helmcke, 1984; 

Barr & MacDonald,1991) which were joined in a continent to continent collision in the 

Late Triassic during the Indosinian Orogeny (Bunopas&Vella,1992). The Indosinian 

Block (in the literature also referred to as the Indochina Block or Craton) incorporates 

present day Cambodia, Laos and Vietnam as well as the Khorat Plateau in the eastern 

part of Thailand. The Shan Thai Block incorporates the rest of Thailand and the eastern 

parts of Burma (Bunopas & Vella,1992). 

The Late Mesozoic and Tertiary history of these continental blocks is primarily 

influenced by the collision of the Indian subcontinent with Eurasia. This collision was a 

diachronous event which caused a fundamental change in the tectonic regime in SE 

Asia. In Thailand it caused a tensional regime in which rift basins were formed (Bunopas 

& Vella,1992). The rifting is related to the clockwise rotation of the Shan-tai Block relative 

to the Indosinian Block. This reactivated the suture between the blocks which became 

the focus of the east – west spreading motion (Bonopas & Vella, 1992; McCabe, 1988). 

A system of N – S trending normal faults developed, starting in the south with the 

opening of the gulf of Thailand and gradually migrating to the north. 

2.2.2 Structural Framework 

The Phitsanulok Basin has been generated by the eastward displacement of this 

province, governed in turn by the movements along four major fault systems (Trump, 

1983)as below (Figure 2.2); 

1. The Western Boundary Fault System 

This fault is a zone of NNW-SSE running faults which have taken up the 

basement and basin extension as normal faults. The faults dip around 45o. Extension at 

basement level is in the order of 10 km. The fault system is not continuous. Separate 

15

segments are connected by NNE-SSW striking faults which locally show minor sinistral 

oblique slip. 

2. The Uttaradit Fault 

This fault is an ENE-WSW running sinistral wrench fault which accommodated the 

eastward movement of the basement. This fault turns into the Western Boundary Fault 

System just west of the S1 Concession and does not extend, to the west, beyond the 

Phitsanulok Basin. The Uttaradit Fault separates the Sukhothai depression (the northern 

part of the Phitsanulok 

Basin) from the Phichai Graben to the north. The Sukhothai depression has been 

downthrown to the South. 

3. The Mae Ping Fault 

This fault is a NW-SE sinistral wrench fault which primarily accommodated 

movement towards the SE of the Shan Thai block on the western side of the fault. This 

fault is a pre-existing basement fault as shown by the offset of up to 100 km of 

Palaeozoic rocks. (Trumpy, 1983). In the Tertiary the fault formed the relative passive 

southern boundary of the Phitsanulok Basin. 

4. The Petchabun Fault Zone 

This fault is a N-S running dextral wrench fault system. This zone separates the 

structurally complex Shan Thai Block from the lesser deformed Indosinian Block. The 

zone consists of several parallel dextral wrench faults with a total displacement of at 

least 50 km. (Trumpy, 1983). 

The overall framework of the major faults in the sirikit Area is show in (Figure.2.2). 

The pattern is dominated by N-S and NW-SE trending faults, rooted in the basement. 

The major faults subdivided the Sirikit Area as follow: 

- The Sirikit Field 

The Sirikit Field delineated to the W and NW by the faults systems composed of 

W70, W87 & W60). This fault system collectively forms the Sirikit Boundary Fault. To the 

east the field is delineated by the W10, W15 fault system also know as the Ket Kason 

Fault System. The Sirikit Field is a fault-dip closure overlying a pre-Tertiary basement 

high. It is fault closed in the W and E essentially dip closed in the north and in the south. 

16

- Sirikit East Field 

From the Sirikit East Field (including the Nong Khaem appraisal area). This field 

has developed over another N-S trending pre-Tertiary high. These structures are 

essentially fault/dip closed with the dip closure being in the north. The geology of this 

part of the sirikit Area and the developed/appraisal options have been described 

separately (Makel et al., 1996) 

- The Thap Raet Field 

Thap Raet Field is delineated by the W80 fault to the west and the W60 fault to 

the south-east and is dip-closed to the nirth. 

- The Nong Makhaam/Sirikit West 

The structuctural of Sirikit West are delineated by the W90 fault in the west, the 

W88 fault in the southwest and the W60 fault system to the east. The structure is dip 

closed to the north. 

- The Western Apprisal Region 

The Western Apprisal Region is closed by the Sirikit Boundary Fault in the east, 

the W99 to the west and the W88 Fault to the north and dip closed to the south. 

In this report the focus will be on the Sirikit east Field. Where appropriate the 

other fields or areas will be mentioned. It is the intension, however, that comprehensive 

descriptions for the other fields and areas will be compiled in the future. 

17

Figure 2.2 Structural frame work of the Phitsanulok basin, Thailand (Thai Shell,1997) 

18

2.2.3 Structural History 

The structural history of the Phitsanulok Basin and adjacent areas enclosed by 

the four major faults can be subdivided into four phase. The Tertiary to recent fill of the 

basin was subjected to extensional tectonics in Phase I, extensional to transtensional 

tectonics during Phase II and gradually increasing to transpressional tectonics through 

Phases III and IV.The evolution of Phitsanulok Basin can be subdivided into four phase 

as follow: 

1. Phase I: Extension in the basin occurs along NNW-SSE oriented faults. The 

extensional direction is WSW-ENE. The main extension occurs along the Western 

Boundary Fault System. 

2. Phase II: After extensional movement along the Mae Ping Fault is blocked, the 

Petchabun Fault had continued movement in the southern area. The divergence which 

during Phase I compensated for the compression in the northeast disappears and 

consequently the compression in the Soi Dao area increases. The start of this phase 

marks the onset of the deposition of the Pratu Tao Formation. 

3. Phase III: The extension in the northern part of the Phitsanulok Basin stops. 

Compression here continued and overthrusts develop in the Soi Dao area. Uttaradit and 

northern part of the Petchabun Fault in the northeast leads to the development of a 

hinge zone on the eastern flank upthrowing the Nakhon Thai area and increasing the 

downthrow along the Western Boundary Fault System. To the north of the Uttaradit Fault 

the Phichai Graben develops and maximum downthrow occurs in the Sukhothai 

depression which already started to form in Phase II 

4. Phase IV: The extension in the southern part of the area is blocked. As a result 

the basin is subjected to increasing compressional stresses and inversion features and 

dextral wrench faulting, parallel to the Petchabun Fault, affect pre-existing structures. 

Basaltic and rhyolitic volcanism is associated with this phase. 

19

Figure 2.3 Structural model of phase I & II of Phitsanulok Basin (Thai Shell,1997) 

20

Upper PTO – Yom Ping 

Figure 2.4 Structural model of phase III & IV of Phitsanulok Basin (Thai Shell,1997) 

2.3 Stratigraphic and Depositional Environment 

The depositional history of the Phitsanulok Basin is linked to the structural 

evolution of the area. The Tertiary basin fill has been subdivided into 8 lithostratigraphic 

formations, that together constitute the Phitsanulok Group. The lateral variations in the 

lithostratigraphy are shown in (Figure 2.5) in N-S and E-W schematic chronostratigraphic 

cross-sections. In the lowest section, alluvial fan and alluvial plain were deposited during 

Phase I of the structural history of the basin which occurred in the age Oligocene. In this 

section consists of Sarabop, Nong Bua and Khom Formaton. In the middle section, the 

depositional environment changed to that of the interdigitating, open lacustrine Chum 

Saeng Formation and the fluvio-deltaic Lan Krabu Formation in the central and eastern 

parts of the basin during the Miocene. Lan Krabu is sand and shale while Chumsang is 

shale. Widespread transgressions alternated with extensive delta progradations 

resulting in the thin but aerialy extensive transgressive-regressive cycles characteristic 

21

of the Phitsanulok Basin deltaic deposits. In the upper part of the fill, the Middle 

Miocene, the depositional environment changed abruptly when pure extension in the 

basin decreased and a transtensional tectonic component (Phase II) gained in 

importance. In this changing tectonic regime the sediments of the Pratu Tao and Yom 

Formations were deposited. The change from transtenstional to transpressional (Phase 

III) may be reflected by the Yom to Ping Formation transition where the dominant 

depositional environment switched from meandering fluvial deposition (Yom) to alluvial 

fan/braidplain deposition (Ping). 

Figure 2.5 Schematic stratigraphy of Phitsanulok basin (Bal et al., 1988) 

22

Figure 2.6 Picture shows the stratigraphic chart in Phitsanulok basin (Bal et al., 1988) 

2.4 Petroleum System 

The Phitsanulok Basin is the largest of the many Tertiary (non-marine) basins onshore 

Thailand has the country’s only commercial oil production (~20,000 bopd). The basin 

was formed by extension, with minor strike-slip movement. The up to 8 km thick Tertiary 

basin fill is almost entirely alluvial and lacustrine clastic. The underlying pre-Tertiary 

contains a wide range of rock types and formations except for Mesozoic sandstone and 

Permain limestone which occur only locally 

23

2.4.1 Source Rock 

The lacustrine contain very rich oil source rock (type I/II) in a cumulative 

thickness of up to 1000m. Small kitchen areas can supply large HC volumes and oil 

generation started 16 million years ago to the last main tectonic event (10 million years). 

The present-day kitchen area comprised 770 sq.km. The source rock produces a waxy, 

low-sulphur, high pour point crude which is light (40˚API) but heavy (14-23˚API) in the 

shallow reservoir due to transformation and bacterial degradation. The geochemical 

parameter and the carbon isotope indicating a source from mainly mature, lacustrine 

algae/SOM source rock, often with a distinct land plant contribution (Figure2.7); 

50 

150 

100 

Lower Clay, 

Chum Saeng Fm. 

20 

40 

Intermediate Clay, 


VR 0.62 VR 1.20 

Lateral Facies Change 

Truncation/Onlap Boundary Est.. Source Rock Thickness 

20 

100 

200 

50 

Upper Clay, 


Figure 2.7 Source rock distribution of Phitsanulok Basin (PTTEP,2008) 

50 

24 

*VR = Vitrinite Reflectance

2.4.2 Reservoir Distribution 

The alluvial and deltaic-lacustrine parts of the clastic basin fill contain numerous 

reservoir/seal interval sand discontinuous. The Lan Lrabu Formation fluviolacustrine 

sandstone constitute one of the main reservoir targets for this basin. They are fine, 

sorted, lithic sandstone with minor carbonate cement. They form the main reservoirs in 

the Sirikit Field where porosity range from 20-30% and individual sand bodies are 

usually thin (1-7m). Reservoir continuity has proven to be variable depending of the 

original of the sand body. Good lateral continuity exists in distributary channel or 

composite sand units whereas mouth bar and delta front sand area limited in extent. 

Only two potential reservoirs are identified in the pre-Tertiary basement; karstified 

Permian limestone and Mesozoic sandstone (Figure 2.8); 

Possible below Por. cutoff 

Pre-Tertiary 

N/G < 0.1 

< 0.1< N/G< 0.2 

LKU 

0.2 < N/G < 0.3 

0.3 < N/G < 0.5 

Figure 2.8 Reservoir properties distribution of Phitsanulok Basin (PTTEP,2008) 

25 

N/G > 0.5 

Eroded 

Pratu Tao

2.4.3 Hydrocarbon maturation and migration 

It is estimated that the total hydrocarbon generation is at the Sukhothai 

Depression at the north of Sirikit Field. In 2000, the comprehensive study of basin 

modeling suggested the maturation and migration as below (Figure 2.9); 

SBP-A 

HYI-A 

KDN-A 

MNN-C 

NOH-A 

KKN-A 

MDG-A 

MNN-B 

CYO-A 

BKO-A 

Figure 2.9 Hydrocarbon migration distribution of Phitsanulok Basin (PTTEP,2008) 

26

2.4.4 Trap and seal 

Both structural and stratigraphic trapping mechanisms are present in Sirikit 

Field. The lower and upper claystone formed as vertical seal nd thickest just to the 

north-west of Sirikit field. The lateral seal formed completely by juxtaposition of reservoir 

sands with claystone unit. Retention depends heavily on clay smear, combination with 

the amount of throw of the faults (Figure 2.10); 

Lower Clay 

100 

200 

50 

400 

500 

Upper Clay 

60 

200 

100 

50 

40 

20 

Alluvial 

Floodplain 

Figure 2.10 Seal distribution of Phitsanulok Basin (PTTEP,2008) 

27

Reservoir stratigraphy and depositional environment 

As mentioned above, the main reservoirs are located in the Pratu Tao, Lan Krabu 

and Sarabop formations. Only the Lan Krabu reservoirs are of interest in the context of 

this Greater Sirikit East Production License Application as they are exclusively holding 

hydrocarbons, so they only will be the object of this section. 

As said before, the Lan Krabu Formation is composed of 4 sub-units, the D, K, L 

and M members that coincide with episodes of deltaic progradations in the Lake 

Phitsanulok. The K and L members are the most extensive and the largest intervals as 

they span over the full Sirikit Area whereas the D and M are more restricted to the North 

of Sirikit where stratigraphic closure have occurred. The K and L are decomposed into 4 

parasequence sets, K1, ..., K4 and L1, ..., L4. K1, K2, K4, L1, L2 and L4 are delta 

dominated sequences whereas K3 and L3 show more fluvial dominated lithotypes and 

coincide with major Sequence Boundaries (Table 1) 

The main LKU members are vertically isolated by 3 major shale layers, Main 

Seal, Upper Intermediate Seal and Lower Intermediate Seal. Those 3 transgressive 

events are the result of maximum flooding events, they are thus laterally very extensive 

and offer integral vertical sealing as well as lateral sealing capacity through fault 

smearing. 

28

Member Sub Depositional Dominant lithotype 

member environment fractions 

Main Seal (MS) 

Chum Saeng 

Open lacustrine Shale 

Lan Krabu D (LKU D) 

D2 

D 

Lower deltaic 

Lower deltaic 

Mouthbar 

Mouthbar 

K1 Lower deltaic Mouthbar 

K2 

Upper to Lower 

deltaic 

Mouthbar (80%) 

Channel (20%) 

Lan Krabu K (LKU K) 

K3 Floodplain 

Channel (70%) 

Crevasse (30%) 

Upper Intermediate 

K4 


deltaic 


Channel (40%) 

Seal (UIS) 

Chum Saeng 


L1 Lower deltaic Mouthbar 

L2 


deltaic 

Mouthbar (80 %) 

Channel (20%) 

Lan Krabu L (LKU L) 

L3 Floodplain 

Channel (80%) 

Crevasse (20%) 

Lower Intermediate 

L4 


deltaic 


Channel (30%) 

Seal (LIS) 

Chum Saeng 


Lan Krabu M (LKU M) M 


deltaic 


Channel (20%) 

Table1 Greater Sirikit East reservoir information summary (updated from Sirikit East 

Field Development,1996) 

29 

Age 

Middle 

Miocene 

Lower 

Miocene

The table above is summarizing the reservoir stratigraphic information together 

with interpreted depositional environment and lithotype fraction. The lithotype fractions 

were derived from the wireline log interpretation and reservoir correlation and are given 

as notional average only. 

30

CHAPTER 3 

WELL LOG INTERPRETATION THEORY 

3.1 Introduction to Well Log Interpretation 

As logging tools and interpretation methods are developing in accuracy and 

sophistication, they are playing an expanded role in the geological decision-making 

process. Petrophysical log interpretation is one of the most useful and important tools 

available to a petroleum geologist. Logging data are used to identify productive zones, 

to determine depth and thickness of zones, to distinguish between oil, gas, or water in a 

reservoir, and to estimate hydrocarbon reserves. Also, geologic maps developed from 

log interpretation with determining facies relationships and drilling locations. 

3.2 Well Logging Tools 

Characteristics of wire-line log 

Wire-line logging is one of the necessary methods for earth scientists to 

understand the subsurface formations. Wire-line logs used in this study include gamma 

ray, resistivity, density and neutron logs. 

3.2.1 Gamma Ray Logs 

This log record the radioactivity of a formation. Shale (or clay-minerals) 

commonly has a relatively high gamma ray radioactive response, and consequently 

gamma ray logs are taken as good measures for grain size ( and subsequently inferred 

depositional energy). Thus coarse-grain sand, which contains little mud, will have low 

gamma ray value, while a fine mud will have a high gamma ray value. The values range 

of gamma ray is measured in API (American Petroleum Institute) units and range of very 

few units (in anhydrite) to over 200 API in shale. 

3.2.2 Resistivity Logs 

This log measures the bulk resistivity (the reciprocal of conductivity) of the 

formation. Resistivity is defined as the degree to which a substance resists the flow of 

the electric current. Resistivity is a function of porosity and pore fluid in the rock. Porous 

31

ock containing conductive fluid (such as saline water) will have low Resistivity. A nonporous 

rock or hydrocarbon bearing formation has high resistivity. This log very useful 

for the type of fluids in formations and is frequently used as an indicator of formation 

lithology. 

3.2.3 Neutron Logs 

This log measures the porosity of a formation, indicating in its response the 

quantity of hydrogen present in the formation. The log is calibrated to limestone. The 

linear limestone porosity units are calibrated using the AOI Neutron pit in 19% porosity, 

water-filled limestone a defined as 1000 AOI units. Thais useful in measuring lithology 

(usually in combination with Density Log) 

3.2.4 Density Logs 

This Log is a measure of the formation’s bulk density and is mostly used as a 

porosity measure. Different lithology can also be determined using Density log based on 

return density value. For example, pure quartz will have bulk density (g/cm3) up to 2.65, 

coal 1.2-1.8, halite 2.05, limestone up to 2.75, dolomite up to 2.87, anhydrite 2.98. 

Density is mostly commonly used in conjunction with Neutron logs to determine lithology 

of formation. 

3.3 Log Interpretation Derived Parameters 

Rock characteristics which affect logging measurements are porosity, 

permeability, and water saturation. It is essential that the reader understand these 

properties and the concepts they represent before proceeding with a study of log 

interpretation. 

3.3.1 Volume of shale 

Shale contains higher amount of potassium atoms than sand or carbonate, 

gamma ray logs can be used to calculate volume of shale in porous reservoir. The 

volume of shale can then be applied as cutoff parameter. The volume of shale can be 

calculated by use Vsh equation see in Chapter 4. 

32

3.3.2 Porosity 

Porosity can be defined as the percentage of voids to the total volume of rock. It 

is measured as the percent and has the symbol phi, Ф. (Asquith, G., 2004) 

Porosity = 

The amount of internal space or voids in a given volume of rock is a measure of 

the amount of fluids a rock will hold. This is illustrated by this equation and is called the 

total porosity. The amount of void space that is interconnected, and so able to transmit 

fluids, is called effective porosity. 

3.3.3 Water Saturation 

Water saturation is the percentage of pore volume in a rock which is occupied 

by formation water. Water saturation is measured in percent and has the symbol Sw. 

(Asquith, G., 2004) 

Water saturation, Sw = 

Volume of pores 

Total volume of rock 

Hydrocarbon saturation is usually determined by the difference between unity 

and water saturation: 

Sh = 1- Sw 

Where : Sh : Hydrocarbon saturation 

Sw : Water saturation 

Formation water occupying pores 

Total pore space in the rock 

33

CHAPTER 4 

METHODOLOGY 

4.1 Data Used 

Petrophysical Interpretation require these data. 

4.1.1 General well data 

4.1.2 Wireline log data both digital file and hard copy 

4.1.3 Deviation data of well 

4.1.4 Surface temperature and temperature gradient 

4.1.5 Formation Resistivity of formation water 

4.2 Log Evaluation Workflow 

The petrophysical evaluation of Sirikit East field in this study were carried out by Geolog6 

software. The method of evaluation is described by the following step and log evaluation 

workflow is shown before in Figure 1.3 

4.2.1 Before petrophysics calculation 

1. Data loading by connect module in Geolog6, such as Main Log, LWD Total 

Gas and Deviation Data 

2. Create Standard SET, such as temperature, Working Zone and Marker. 

3. Create Crossplot by Neutron Log, Density Log and Gamma Ray Log. 

4 . Log Editing: All data need to be quality checked and edited. 

5. Defining the petrophysical parameters for each stratigraphic unit. 

4.2.2 Petrophysics Calculation 

1. Lithology of the formation is determined by using log data. 

2. Volume of shale (Vsh) is compute from GR log which is calculated by linear 

equation and GR is read from corrected GR log. 

34

3. Porosity will be computed from RHOB-NPHI logs by using Density Neutron 

equation. In this study to mention the Total porosity(PHIT), is The total pore volume per unit 

volume of rock. and Effective porosity (PHIE), is The interconnected pore volume or void 

space in a rock that contributes to fluid flow or permeability in a reservoir. Effective porosity 

excludes isolated pores and pore volume occupied by water adsorbed on clay minerals or 

other grains. Effective porosity is typically less than total porosity. For the Dual Water model, 

the porosity is determined from equation. 

Where; 

RHOb = Bulk density (g/cc), reading from RHOB log. 

RHOma = Matrix density (g/cc) (Table2) 

RHOfl = The density of the fluid filling the pore which the tool 

is investigating: in open-hole, the fluid is mainly mud filtrate (1g/cc) 

Table 2 The matrix density, fluid density and PEF(Photo Electrical Factor) for 

some common compounds. 

35

Total porosity (PHIT) 

The density-neutron logs calculation are used to calculate the total 

porosity (PHIT) and effective porosity. For Quick-Look interpretation, porosity is often taken 

as the average of density porosity and neutron porosity in the same matrix. On a standard 

display in limestone compatible scales, this is the midpoint between the density and neutron 

porosity logs. The equation is shown below; 

In case of gas effect , is much larger on neutron porosity than on the density log. 

In agas-bearing reservoir, neutron-density porosity average underestimates true porosity. We 

must give more weight to density porosity than to neutron porosity. In case of study, there is 

a small amount of gas by using equation: 

Effective porosity (PHIE) 

Effective porosity was derived from the Neutron-Density computation 

using the equation as shown below: 

Where: 

PHIT = Total porosity 

PHIE = Effective porosity 

PHIE = PHIT*(1-Vsh) 

36

4. True Resistivity of the Formation (RT) 

True Resistivity the formation (RT) is derived from the Laterolog resistivity 

(DLL,MDFL). DLL and MSFL have been corrected to estimate the true formation resistivity 

(RT). For well S1-East where induction log were run, AT90 has been assumed as true 

formation resistivity (RT). 

5. The water saturation is calculated from Archie’s equation. 

So compute Water Resistivity (Rw) and Water Saturation (Sw) were derived from step 

as below: 

- Locate a clean zone, water-bearing interval. 

- Compute porosity as described before. 

- Read value of resitivity (Rt), take deepest resistivity log (AT90) 

- Compute Rw by using Archie equation as below: 

a * Rw 

n 

Sw m 

* Rt 

If assumed that all zones are water-bearing, Sw=1, resistivity of rock is Ro, a=1, m 

and n exponent used as equal to 2. We know as Archie I equation as below; 

m 

F = Ro/Rw = * Rt \ 

Where: F = Formation factor 

Ro = Resistivity of rock 

Rw = Resistivity of water 

To determine apparent water resistivity (Rw) by applying equation as shown below: 

m 

aRw= * Rt 

If that zone are hydrocarbon-bearing, resistivity of rock is Rt, Sw ≠1. We know as 

Archie II equation, were derived from step as below: 

37

- Compute porosity from the density log or from density-neutron cross-plot. 

- Read value of resitivity (Rt), take deepest resistivity log (AT90) 

- Compute for Sw by using equation: 

a * Rw 

n 

Sw m 

* Rt 

Where: Sw = Water saturation 

a,m,n = Constant value 

Rt = Resistivity of Formation 

Rw = Resistivity of water 

Ø = Porosity 

Note: In S1 area, always take a=1, m=1.95, n=1.85 

To determine water saturation, Dual water equation as below: 

Ro 

Sw ( ) 

Rt 

In this part all logging interpretation are prepared for the Quick-Look Excel 

Program, applied from Arthit and Bong Kot Field. 

From the definition quick-look petrophysical evaluation is to identify the 

reservoir properties. Therefore the steps will be consisted of several calculations ie. 

thickness, volume of shale (Vsh), total porosity (PHIT), effective porosity (PHIE) and 

water saturation (Sw). The formulas which use to identify these reservoir properties are 

summarized in the (Figure 4.1) and the example data sheet for Quick Look Excel 

Program for formation evaluation is shown in (Figure 4.2). Furthermore, is also consisted 

of the example of Log reading in Sirikit east well (Figure 4.3) and Cross plot between 

Resistivity of free water (Rwf) and bound water (Rwb) in (Figure 4.4) 

1 

n 

38

Figure 4.1 The Quick Look Formula for Petrophysical Analysis (applied from Arthit Field) 

Figure 4.2 The example of Quick Look Excel Program of Sirikit East well. 

39

Figure 4.3 The example of log reading in Sirikit East well. 

Figure 4.4 The Example of cross plot between Resistivity of free water (Rwf) and 

bound water (Rwb). 

40

4.3 Quick Look analysis 

The concepts of Quick-Look analysis for formation evaluation are as follows: 

A. Calculation of TVD and TVDSS from MD and Inclination . 

1. Record log values for GR, AT90, RHOB and NPHI from sand and shale in waterbearing 

zones in each formation. 

2. Calculate total porosity by using equations 

 

 

N D 

b ma 

t 

and D 

2 

f ma 

2 D N 

 

3 

3. Determine Rwa by using equation Rt* 

4. Plot Rwa versus GR of sand to determine Rwf. 

Rwa 

D or 

Rwf is the point at the lowest Rwa value and the lowest GR value. 

5. Plot Rwa versus GR of shale to determine Rwb. 

m 

t 

Rwb is the point in the middle of shale cloud. 

Where: Sw = Water saturation 

Ro = Resistivity of water filled rock (ohm.m) 

Rwa = Apparent Formation water resistivity (ohm.m) 

Rwb = Resistivity of bound water (ohm.m) 

Rwf = Resistivity of free water (ohm.m) 

Rt = Formation resistivity (ohm.m), reading from AT90 

GR = Gamma Ray (GAPI) 

Vcl = Volume of clay (m 3 /m 3 ) 

Ø t = Total porosity 

Ø N = Neutron porosity, reading from NPHI 

Ø D = Density Porosity 

ρb = Bulk density (g/cc), reading from RHOB 

ρma = Matrix density (2.67 g/cc) 

ρf = Fluid density (1 g/cc) 

a = Tortuosity factor (a=1) 

m = Cementation exponent (m=1.95 for S1) 

n = Saturation exponent (n=1.85 for S1) 

41

B. Estimate of Shale (Clay) Content (Vsh) 

The magnitude of the gamma ray in the zone of interest (relative to that of 

nearby clean and shale zones) is used to calculate the shale content of the formation. 

The linear equation is applied to evaluate shale volume with out any corrections as 

below: 

(1) 

The steps to estimate shale content are as below; 

1. Define GR value of clean sand zone (GRss) and GR value of clean shale zone 

(GRsh), then input GRss and GRsh into the quick-look data sheet in Figure 4.2. 

2. Record the GR value at zone of interest (GRlog). 

3. The program will generate the shale volume (Vsh) automatically by using 

Equation (1). 

C. Total Porosity (PHIT) and Effective Porosity (PHIE) 

Porosity is derived from the density log by using equation: 

Where; RHOB = Bulk density (g/cc), reading from RHOB log. 

RHOma = Matrix density (g/cc) (See Table2) 

RHOfl = The density of the fluid filling the pore which the tool 

is investigating: in open-hole, the fluid is mainly mud 

filtrate (1g/cc) 

The density log and neutron log calculation are used to calculate the total 

porosity (PHIT) and effective porosity as the below equation; 

- Total porosity equation in water-bearing zone: 

(3) 

(2) 

42

- Total porosity equation in small amount of gas-bearing zone (Gas corrected): 

- Effective porosity as equation: 

PHIE PHIT * ( 1 Vsh) 

(4) 

(5) 

1. After defined PHIN and PHID of each reservoir and then input PHID and PHIE 

into the worksheet, the next step is to calculate the total porosity (PHIT) in waterbearing 

zone by using Equation 3. If the reservoir is gas-bearing zone, Equation 

4 (for gas correction). 

2. The program will automatically generate effective porosity (PHIE) by using 

Equation 5. 

3. To check the density logging quality, Equation 6 can be applied to calculate 

grain density. It should be in between 2.66-2.69 g/cc. If bad hole the RHOB will 

be more than 0.2 g/cc. 

RHOB PHIT 

RHOG 

1 PHIT 

D. Water Saturation (Sw) Determination 

The Dual Water Equation is used for water saturation determination. 

The procedures to determine water saturation (Sw) are below; 

1. To determine apparent water resistivity (Rwa) by applying the Archie 

Equation as below: 

* Rt 

(6) 

a * Rw 

(7) 

n 

Sw m 

43

This method assumed that all zones are water-bearing zone, Sw = 1, 

cementation factor (a) = 1 , cementation exponent (m) and saturation exponent (n) exponent 

= 2, then determines the apparent formation water salinity (Rwa) as below: 

m 

Rwa * Rt (8) 

In S1 field, the cementation exponent (m) is equal to 1.95 and n is equal to 1.85. Then, input 

the Rwa values into the quick-look data sheet. This part use to compute for Quick-Look 

analysis step for formation evaluation. Rwa and Rwb is shown in part of index value derived 

from the average of Rwa and Rwb from 10 wells as shown in Table 3 

TVDSS 

WELL TOP BOTTOM Rwa Rwb 

X07 1800 2310 0.15 0.23 

X08 1940 2500 0.25 0.23 

X09 1960 2686 0.18 0.24 

X10 1980 2587 0.16 0.24 

X11 2120 2490 0.18 0.2 

X12 2050 2800 0.17 0.22 

Y04 2050 2820 0.18 0.23 

Y05 2120 2870 0.15 0.28 

Z04 1840 2643 0.19 0.28 

Z06 2400 2887 0.20 0.26 

average 0.18 0.24 

Table 3 The average of Rwa and Rwb from 10 wells. 

2. Plot Rwa versus GR in sandstone to determine resistivity of free water (Rwf). 

Rwf value of sandstone is the point at the lowest Rwa with the lowest GR 

values (Figure 4.4) 

44

3. Plot Rwa versus GR in shale to determine resistivity of bound water (Rwb). 

4. Rwb value of the shale is the point in the middle of shale cloud (Figure 4.4). 

In Sirikit East Field, Rwa and Rwb values of each formation are determined. 

(See Appendix 2) 

5. Determination resistivity of water filled rock (Ro) can be used the Equation 9 

as below: 

Ro 

Rwb * Rwf 

(9) 2 

Rwb Vcl 

Rwf Rwb* 

t 

6. To determine water saturation, Dual Water Equation as Equation 10 below is 

used; 

Sw 

Ro 

( ) 

Rt 

1 

n 

(10) 

E. Reporting of the Petrophysical Analysis Results 

The result of Vsh, PHIT and Sw will be displayed into Individual Formation report 

sheet in Chapter 5 result of this study (Figure 5.1) but the details of computing data sheet of 

Quick-Look for Formation Evaluation of 10 wells are shown in (Appendix 1). 

45

CHAPTER 5 

RESULT OF WORKS 

In this session, from the logging interpretation and the Quick-Look petrophysical 

evaluation method can be divided into three parts; 

5.1 Result of the computation from Quick Look Excel Software. 

Result of the computation from Quick Look Excel data sheet of 10 wells, that 

shown in Appendix1 but in this part shown the example of summary computing data 

sheet of Quick-Look for Formation Evaluation of Sirikit East well. (Figure 5.1) 

Figure 5.1 The example of summary computing data sheet of Quick-Look for Formation 

Evaluation of LKU-X07 well. 

46

5.2 The computed result of parameter of 10 wells compare with S1 petrophysical 

Method. 

From the summary of computed data sheet of Quick-Look Excel Program from 

10 wells can be compare the parameter, which is most important for Quick-Look 

petrophysical for formation evaluation of 10 wells as below. The compare parameter 

value can be classify for 3 parameters such as Volume of Shale, Porosity and Water 

Saturation repectively. (Figure 5.2- Figure 5.4) 

Figure 5.2 The computed result of Volume of Shale of 10 wells compare with 

S1 Asset. 

Figure 5.3 The computed result of Porosity of 10 wells compare with 

S1 Asset. 

Figure 5.4 The computed result of Water Saturation of 10 wells compare with 

S1 Asset. 

47

5.3 To compare the results of the quick-look evaluations with those produced by the 

petrophysical evaluation carried out by the S1 Asset. 

This part based on a comparison of 3 parameters result, which concerning the 

main reservoir such as formation K and L. (Figure 5.5) 

Figure 5.5 Comparison results of the quick-look evaluations with S1 Asset. 

48

Chapter 6 

DISCUSSION, CONCLUSION AND RECOMMENDATION 

6.1 Discussion 

The comparisons of results both previous study and this study are following; 

6.1.1 Formation K1 

Volume of shale 

The S1 petrophysical evaluation of formation K1 shows average volume of shale 

of shaly sand reservoir is 35 % 

The Quick Look petrophysical evaluation from log interpretation calculated 

volume of shale values of formation K1 is 14 % 

Porosity 

The S1 petrophysical evaluation of formation K1 shows average porosities of 

shaly sand reservoir is 31 % 


porosities values of formation K1 is 23 % 

Water Saturation 

The S1 petrophysical evaluation of formation K1 shows water saturation 62 % in 

shaly sand reservoir while the Quick Look petrophysical evaluation from log 

interpretation calculated water saturation values of formation K1 is 30 % 







49

Porosity 















Porosity 









50







Porosity 









6.1.5 Formation L1 


The S1 petrophysical evaluation of formation L1 shows average volume of shale 



volume of shale values of formation L1 is 14 % 

Porosity 

The S1 petrophysical evaluation of formation L1 shows average porosities of 



porosities values of formation L1 is 23 % 

51


The S1 petrophysical evaluation of formation L1 shows water saturation 48 % in 


interpretation calculated water saturation values of formation L1 is 28 % 







Porosity 















Porosity 



52













Porosity 









53

6.2 Conclusion 

This study was to compare the results of the quick-look evaluations with those 

produced by the petrophysical evaluation carried out by the S1 Asset. The results 

agreed very well in volume of shale and porosity, which is shown the deviation value is 

approximate 2-3% and 4% respectively. The result have some different values of water 

saturation which depend on some parameters such as matrix and shale parameters and 

use different equation to calculate water saturation because the deviation value is shown 

rather high approximate 22%. This quick-look method is shown to work rather well in this 

field and probably to adjust in some parameter for next study. 

6.3 Recommendations 

For next study should be used the same series such as the parameter value 

which use in S1 Petrophysical Evaluation derived from whole Sirikit Area, but this study 

only Sirikit East area which have area less than one. Thus, we should be consider about 

quantity and quality of the area for the same qualification. 

Porosity was derived by Quick Look Porosity formula (used density and neutron 

logs) and compare results with S1 Petrophysical Evaluation (only density log). The 

porosity from Quick Look Petrophysical Evaluation is less than S1 Petrophysical 

Evaluation, that is look like accurate value because it is derived from the average value 

of density and neutron logs. 

Water saturation is calculated by Dual Water equation. From the result the Dual 

Water equation is reasonable to use in Sirikit East field. But some uncertainties of Sw 

determination are; 

- The parameters of Rwa and Rwb is derived from reading the pick point 

of chart between Rwa and Gamma ray in clean sand zone and shale zone. Then, we 

could to read and define the pick point again for the least deviation parameter. 

- The parameters of m and n is derived from core data which available 

in the whole Sirikit Area, but this study only Sirikit East area which have area less than 

one. 

54

- Differentiation of gas and oil properties beneath the same condition water also 

affected Sw computation to improve the Sw, formation water should be collected and 

analyse for formation water salinity. 

55

References 

Makel, G.1996-1997. Sirikit Field Review 1997. Carigali-PTTEI Operating Company SDN. BHD. 

Internal report. 

Petrophysical Re-Evaluation of the Sirikit Field, Using Capillary Pressure Curves and Empirically 

Derived Porosity and Bed Thickness Algorithms. Report No. EPP/43-88015 

Tanapuntanurak, N. 2008. Shaly Sand Petrophysical Re-Evaluation of Muda Field, Gulf of 

Thailand . Senior Project (Geoscience Program) Physics, Mahidol University 

Sinhabaedya, P. 2005. Geological study and petroleum volumetric review of the Mae Nam Nan 

wells in sirikit oil field. Senior Project (Geology) Science, Chulalongkorn 

University. 

Supamittra, C and Suryanto, D; Geology and Petroleum Development in the Phitsanulok Basin, 

Central Plains of Thailand; AOGS 2007 – 4th Annual Meeting; 

Bangkok-Thailand 

Sombat,B., Parinya.,P and Wanida,S.2006.Rwf and Rwb Determination for Quick-Look 

Formation Evaluation of Arthit Field. Carigali-PTTEP1 Operating Company SDN 

BHD. Internal report. 

Taweepornpathomgul, P. 2007. Depositional Model of Lan Krabu reservoirs in the Greater Pratu 

Tao Area, Phitsanulok Basin, North-Central Thailand. Senior Project (Geology) 

Science, Chulalongkorn University. 

Sombat,B., Parinya.,P and Wanida,S.2006.Rwf and Rwb Determination for Quick-Look 

Formation Evaluation of Arthit Field. Carigali-PTTEP1 Operating Company SDN 

BHD. Internal report. 

Panthong, A.2007.On the Job training program of operations geology GGG/O. Carigali-PTTEP1 

Operating Company SDN BHD. Internal report. 

Wanida, S.2008. A Comparison of Various Methods of Computing Water Saturation in Shaly - 

Sands. Carigali-PTTEP1 Operating Company SDN BHD. Internal report. 

Kasama, K. 2007. Comparison between Core and E-log for formation in Sirikit Field. Carigali- 

PTTEP1 Operating Company SDN BHD. Internal report. 

56 

1

The computing data sheet of Quick-Look for Formation Evaluation of LKU-X07 well. 

58


60


64


66


67


69

The computing data sheet of Quick-Look for Formation Evaluation of LKU-Y04 well. 

73

The computing data sheet of Quick-Look for Formation Evaluation of LKU-Y05 well. 

76

The computing data sheet of Quick-Look for Formation Evaluation of LKU-Z04 well. 

79

The computing data sheet of Quick-Look for Formation Evaluation of LKU-Z06 well. 

80

Cross plot between Gamma ray and Rwa for picket sand zone represent Rwa and log reading of sand zone of LKU-X07 well. 

81

Cross plot between Gamma ray and Rwa for picket shale zone represent Rwb and log reading of shale zone of LKU-X07 well. 

82


83

Rwb =0.23 


84


85


86


87


88


89


90


91


92

Cross plot between Gamma ray and Rwa for picket sand zone represent Rwa and log reading of sand zone of LKU-Y04 well. 

93

Cross plot between Gamma ray and Rwa for picket shale zone represent Rwb and log reading of shale zone of LKU-Y04 well. 

94

Cross plot between Gamma ray and Rwa for picket sand zone represent Rwa and log reading of sand zone of LKU-Y05 well. 

95

Cross plot between Gamma ray and Rwa for picket shale zone represent Rwb and log reading of shale zone of LKU-Y05 well. 

96

Cross plot between Gamma ray and Rwa for picket sand zone represent Rwa and log reading of sand zone of LKU-Z04 well. 

97

Cross plot between Gamma ray and Rwa for picket shale zone represent Rwb and log reading of shale zone of LKU-Z04 well. 

98

Cross plot between Gamma ray and Rwa for picket sand zone represent Rwa and log reading of sand zone of LKU-Z06 well. 

99

Cross plot between Gamma ray and Rwa for picket shale zone represent Rwb and log reading of shale zone of LKU-Z06 well. 

100

A STUDY OF PETROPHYSICAL PARAMETERS FOR QUICK-LOOK ...

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