3d Seismic Interpretation and Petro physical Evaluation of Stroh field Onshore Niger Delta

ABSTRACT Petrophysical evaluation and 3D seismic interpretation were carried out on the hydrocarbon bearing reservoirs of Stroh field with the aim of maximizing the benefits of petrophysical evaluation and structural interpretation in the production and development of hydrocarbon in the reservoir of the ‘Stroh field’ in Niger Delta. Eight hydrocarbon bearing reservoirs – sands ST1, ST3, ST6, ST7, ST8, ST11, ST13 and ST14 were identified from well logs and correlated across six Stroh wells. Sand ST11 was missing in Stroh-5 which crossed a normal fault. Fluid types were determined from the well log signatures; neutron density crossplot was used to check for the presence of gas. All the hydrocarbon bearing reservoirs were inferred to be oil with sand ST11 having a gas cap. Stroh-1 well saw 134.5 ft of oil in 7 sands and 26 ft of gas in 1 sand. Stroh-3st has 25.6ft of oil in one sand. Stroh-4 encountered 113ft of oil in 3 sands and 18ft of gas in one sand. Stroh-5 has 100ft of oil in 2 sands and 19ft of oil in Stroh-6. Result from petrophysical analysis shows that porosity ranges from 15.8% to 28.3%, volume of shale from 2.5% to 38.9% and permeability which increases with porosity ranges from 10000md. Bulk volume of water shows possible variation of grain size. Top depth structure maps were produced from seismic interpretation for Sands ST6, ST11 and ST13having total (47.23mmbo & 32,319.05mmscf) of oil and gas respectively. One prospects – NE (7.9mmbo low case, 10.81mmbo mid case and 12.03mmbo high case) was also identified for future drilling considerations. The result of seismic data interpretation shows that ten faults were identified F1 to F10 with two main regional bounding faults; F1 synthetic& F2 antithetic faults trending E-W. Trapping mechanisms are fault assisted and fault dependent. Time maps generated and depth converted to show structural variation and fluid contacts. The results of petrophysical analysis of the reservoir properties (NTG,Porosity,Sw) and seismic data interpretation (GRV) showed a perforation interval for ST13 as having the most profilic reservoir with a reserve of 25.28 mmbo, while ST6 has least prolific reservoir with reserve of 8.68 mmbo which serves as a guide for robust future development strategy for the Stroh field.

TABLE OF CONTENTS

TITLE PAGE i

CERTIFICATION ii

DEDICATION iii

ACKNOWLEDGEMENT iv

ABSTRACT v

TABLE OF CONTENT vi

LIST OF FIGURES ix

LIST OF TABLES x

1.0INTRODUCTION 1

1.1 Statement of Research Problem 2

1.2 Location of Study Area 6

1.3 Climate and vegetation 5

1.4 Drainage6

1.5 Scope of Study 6

6.1 Aim and Objectives of the Study 6

CHAPTER TWO

2.0GEOLOGY OF NIGER DELTA AND LITERATURE REVIEW 8

2.1 Basin Formation 8

2.2 Megatectonic Setting 9

2.3 Stratigraphy 9

2.3.1Outcrops (of the tertiary niger deltaic deposition) 10

2.3.2Subsurface formations 12

2.4Depobelts 14

2.5Delta Tectonics: 15

3.5.1 Clay substratum: 15

3.5.2 Growth faults:- 15

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CHAPTER THREE

3.0 METHODS AND AVAILABLE DATA

3.1 Checkshot Loading 25

3.2 Petrophysical Evaluation 28

3.2.1 Gamma ray log 28

3.2.2 Resistivity log 28

3.2.3 Density log 28

3.2.4 Neutron log 29

3.3 Workflow Adopted 30

3.3.1 Data loading and basemap display of wells 30

3.3.2 Log quality control 30

3.3.3 Lithology determination and zoning of reservoirs 31

3.3.4 Lithostratigraphic correlation 31

3.3.5 Determination of formation temperature 31

3.3.6 Fluid determination and contacts 32

3.3.7 Computation of shale volume (vsh) 32

3.3.8 Volume of shale from gamma ray 32

3.3.9 Calculation of total porosity 33

3.3.10 Estimation of formation water resistivity from pickett plot 37

3.3.11 Shaly sand analysis 38

3.3.12 Bulk volume of water calculation 40

3.3.13 Net to gross 40

3.3.14 Permeability calculation 40

3.3.15 Irreducible water saturation 42

3.3.16 Well log pattern and shapes 43

3.4 Seismic Interpretation 45

3.4.1 Fault picking 45

3.4.2 Well to seismic tie 45

3.4.3 Well Correlation 45

3.4.4 Horizon interpretation 46

3.4.5Time to depth conversion 46

3.4.6 Map generation 46

3.5 Volumetrics 45

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3.5.1 Gross rock volume 47

3.5.2 Petrophysical parameters input 48

4.0 RESULTS AND DISCUSSION

4.1 Hydrocarbon Bearing Zones 49

4.2 Sand to Sand Correalation 49

4.3 Structural Interpretation 52

4.4 Horizon Interpretation 52

4.5 Generated Maps 59

4.6 Identified Prospects 59

4.7 Petrophysical Analysis 65

4.7.1 Porosity and water saturation determination 65

4.7.2 Fluid Typing 72

4.7.3 Shale Volume 73

4.8 Volumetric Analysis 74

4.8.1 Contingent resource volumetrics 74

4.8.2 Prospect volume estimation 74

CHAPTER FIVE

5.0 CONCLUSIONS AND RECOMMENDATIONS

5.1 Conclusions 78

5.2 Recommendations 79