This document summarizes the analysis of a hydrocarbon reservoir from a base map, cross-sections, well log data, and formation pressure measurements. Key findings include an anticlinal structural trap occupying an area of 53.15 km2, average gross reservoir thickness between 51-94m among three wells, average porosity of 26.6%, and an estimated 516 million hydrocarbon volumes initially in place with 206 million recoverable through primary and EOR recovery. Calculations determine production from 19 wells over 15 years is needed to recover the volumes.

1. Spotlight
Akhil Prabhakar (Int. Mtech 4th yr GPT)
Swapnil Pal (Int. Mtech 4th yr GT)
Ojaswita Singh (Mtech 1st yr GPT)
IIT Roorkee

2. Base map
A B
C
D

3. 0
200
400
600
800
1000
1200
1400
1600
Depth(m)
Cross-section across A-B
A B
S N

4. 0
500
1000
1500
2000
2500
Cross-section across C-D
C
D
SE NW

5. 0
500
1000
1500
2000
2500
0 20 40 60 80 100 120 140 160 180 200
Depth
Distance
Cross-section across C-D
SE NW

6. Traps
Anticlinal trap Fault trap

8. Following conclusions can be drawn from
the base map:
Primary structural element: antiformal fold and fault
Trap: anticlinal trap
Area of Hydrocarbon accumulation: 53.15 Km2

9. Well log templates (GR)
Well 1 Well 2 Well 3
Well no. Top
reservoir
Base
reservoir
mTVD mTVD
Well 1 765 859
Well 2 909 960
Well 3 878 956
Marker Data

10. Well log templates (GR)
Well 1
Average gross reservoir thickness = 94m
Net-sand thickness = 27.5m
Net to gross (NTG) = 0.293
Average porosity = 27%
Average water saturation = 0.1

11. Well log templates (GR)
Well 2
Average gross reservoir thickness = 51m
Net-sand thickness = 21m
Net to gross (NTG) = 0.411
Average porosity = 27.17%
Average water saturation = 0.08

12. Well log templates (GR)
Well 3
Average gross reservoir thickness = 78m
Net-sand thickness = 19m
Net to gross (NTG) = 0.244
Average porosity = 25.7%
Average water saturation = 0.09

13. Comparison of different wells
Well 1 Well 2 Well 3 Field
Average gross reservoir
thickness
94m 51m 78m 74.3m
Net sand thickness 27.5m 21m 19m 22.5m
Net to Gross 0.293 0.411 0.244 0.316
Average porosity 27% 27.17% 25.7% 26.6
Average water saturation 0.1 0.08 0.09 0.09

14. Depositional environment
Fluvial/detaic environment.
• Alternating sand and shale.
• Clastic sediments deposition in passive margin.
Recovery factor: Primary 40%
EOR 50-60%

15. Formation Pressure Data (Well 2)
Depth (mTVD) Formation pressure (psi)
946 1614
952 1619
956 1622
969.5 1639
977 1650
980.5 1655

16. Formation Pressure Data (Well 2)

17. Formation pressure
1610
1615
1620
1625
1630
1635
1640
1645
1650
1655
1660
944 946 948 950 952 954 956 958 960 962 964 966 968 970 972 974 976 978 980
Formationpressure(psi)
Depth (mTVDSS)
Fluid contact depth
formation pressure
Slope = 0.45 psi/feet
Slope = 0.25 psi/feet
Slope = 0.22 psi/feet
Slope = 0.38 psi/feet
Slope = 0.44 psi/feet
Oil filled
reservoir
Water filled
reservoir
Oil-water contact

18. Calculations:
Total in-place hydrocarbon = 516.3319986 million hydrocarbon volumes
Recoverable reserves = 206.5327994 million hydrocarbon volumes
Volume produced per day by a well = 5000 hydrocarbon volumes
Production at this rate from 1 well for 15 yrs. = 27.375 million hydrocarbon volumes
Number of wells needed = 18 or 19 wells

19. Thank you