The document summarizes the petroleum play of the Lower Indus Basin in Pakistan. It describes the tectonic evolution and stratigraphy of the basin, including the source rocks like the Sembar Formation. It details the production history from fields like Sui producing from Eocene reservoirs. Key reservoirs included sandstones in the Jurassic to Eocene formations. Traps are structural like anticlines. Source rock evaluation of wells like Sann #1 showed good hydrocarbon generation potential from source rocks like the Sembar Formation and upper Goru Formation.

2. Petroleum Play Of Lower
Indus Basin
Presented By
Maryam Nazeer 2013-MS-GS-1
Rizwan Sarwar Awan 2013-MS-GS-2

3. Contents
• Lower Indus Basin
Introduction
Tectonics
Stratigraphy
Production History
Source Rocks
Reservoirs
Traps
Seals
• Source rock
Evaluation
Study Area
Samples and Methods
Instrumentation
Results and Discussion
Conclusion

4. Trap

5. Lower Indus Basin

6. Introduction
• The Greater Indus Basin extends over most of eastern
Pakistan and the westernmost parts of India, covering
an area of about 873,000 square kilometers (km2).
• Given its geological and tectonic evolution, the Indus
basin can be divided into three parts: from North to
South, the Upper Indus basin, the Middle Indus basin
and the Southern Indus basin.
• These sub-basins are separated by topographic
elevations of the Precambrian Indian shield: the
Sargodha high between the Upper and Middle Indus
basins, and the Khairpur-Jacobabad high between the
Middle and Southern Indus basins.

7. Generalized geology of the Sembar-Goru/Ghazij Composite Total Petroleum System
area modifid from (Oil and Natural Gas Development Company, 1997; Wandrey and
Law, 1997; Wandrey and others, 2000; and Petroconsultants, 1996).

9. Location of Indus Basin, Sulaiman-Kirthar, and Kohat-Potwar geologic provinces shown
in green (8042 and 8026); other assessed provinces within region 8 shown in yellow

10. Tectonics
• The Indian subcontinent drifted north during
the late Mesozoic from a paleolatitude of near
30ᵒS to about the equator. Marine marls,
turbidites, and shales, along with shelf
carbonates and clastics, were deposited in the
Southern Indus basin (Shuaib, 1982; Quadri
and Shuaib, 1986, 1987).

11. Middle Jurassic (approximately 166 Ma).
Perspective lat 20°S., long 68°E. (modifid
from Scotese and others, 1988).
Early Cretaceous (approximately 130 Ma).
Perspective lat 20°S., long 68°E. (modifid from
Scotese and others, 1988).

12. Late Cretaceous (approximately 94 Ma).
Perspective lat 20°S., long 68°E. (modifid
from Scotese and others, 1988).
Latest Cretaceous (approximately 69 Ma).
Perspective lat 20°S., long 68°E. (modified
from Scotese and others, 1988).

13. Middle Eocene (approximately 50 Ma).
Perspective lat 20°S., long 68°E. (modifid
from Scotese and others, 1988).
Late Oligocene Epoch (approximately 27
Ma). Perspective lat 20°S., long 68°E.
(modifid from Scotese and others, 1988).

14. Stratigraphy
of Lower
Indus Basin

15. Generalized cross sections showing structure across the Lower Indus Basin (modifid from
Quadri and Shuaib, 1986; Malik and others, 1988; Khadri, 1995; and OGDC, 1996).
Legend

16. Production History
• Recoverable gas reserves from 14 fields total about 22 tcf, but more than 90% of
Pakistan’s gas production and 57% of the gas reserves are from the giant Sui and Mari
fields both of which were discovered in the 1950s and produce from Eocene carbonate
reservoirs in the central basin Quadri and Quadri, 1996 . Oil was discovered in the
Cretaceous upper and lower Goru Formation at Khaskeli in 1981.
• several small fields with estimated reserves of about 50 million barrels of oil were
developed in the next few years.
• Oil fields southeast of the location of the Sann 1 well produce from the upper Goru
Formation.

17. Source Rocks
Sember Formation
Other Source rocks of Indus Basin:
Salt Range Formation
Permian Dandot and Tredian Formations,
Triassic Wulgai Formation,
Jurassic Datta Formation
Paleocene Patala Formation,
Eocene Ghazij Formation,
lower Miocene shales
Age: Lower Cretaceous
Lithology: shale with subordinate amounts of siltstone and sandstone.
Environment Of Deposition: Marine
Thickness: 0 to more than 260 m (Iqbal and Shah, 1980).

18. Rock-Eval pyrolysis analyses
10 samples from the Jandran-1 well in the Sulaiman Range.
TOC: 1.10 %
TOC values from the Sembar in two Badin area wells
ranging from 0.5 to 3.5 % and averaging about 1.4%
Cross-plot of pyrolysis
• Van Kreveln diagram indicates that the organic matter in the Sembar
is mainly type-III kerogen, capable of generating gas
• additional proprietary data indicate the presence of type-II kerogen as
well as type-III kerogen.
• The oil window 0.6–1.3 percent vitrinite reflectance.
• Sembar ranges from thermally immature to overmature
• Thermally mature in the western, more deeply buried part of the shelf
and becomes shallower and less mature toward the eastern edge of the
Indus Basin

19. Reservoirs
Productive reservoirs in the Sembar-Goru/Ghazij Composite TPS
include the
• Jurassic Chiltan, Samana Suk, and Shinawari Formations;
• Cretaceous Sembar, Goru, Lumshiwal, Moghal Kot, Parh, and
Pab Formations;
• Paleocene Dungan Formation and Ranikot Group
• Eocene Sui, Kirthar, Sakesar, Bandah, Khuiala, Nammal, and
Ghazij Formations.
• Sandstone porosities are as high as 30 percent, but more commonly
range from about 12 to 16 percent; and limestone porosities range
from 9 to 16 percent. The permeability of these reservoirs ranges
from 1 to > 2,000 millidarcies (mD)

20. Plot showing lithologic and temporal numeric distribution of productive reservoir in
the Sembar-Goru/Gazij Composite Total Petroleum System, based on the 2001
IHS Energy Probe Database (IHS Energy Group, 2001).

21. Burial history plots for the Shahdapur-1 and the Sakhi-Sarwar-1 wells

22. Traps
• All production in the Indus Basin is from structural traps.
• No stratigraphic accumulations have been identified.
• The variety of structural traps includes anticlines, thrust-faulted
anticlines, and tilted fault blocks.
• The anticlines and thrusted anticlines occur in the foreland portions of
the Greater Indus Basin as a consequence of compression related to
collision of the Indian and Eurasian plates.

23. West to east cross-section through the center of the southern Indus basin; line of section
shown on Fig adapted from Quadri and Shuaib, 1986 .

24. Seals
• The known seals in the system are composed of shales that are
interbedded with and overlying the reservoirs.
• In producing filds, thin shale beds of variable thickness are
effective seals.
• Additional seals that may be effective include impermeable seals
above truncation traps, faults, and updip facies changes.
• Regional Seal is Ghazij formation.

25. Source Rock Evaluation
A Case Study

26. Study Area
• Study Well
Sann # 1 well, located along the west-central edge of Kirthar Trough, Southern
Indus basin, Sindh Province, Pakistan
• Objective
To define the hydrocarbon potential of petroleum source rocks in the area of
the Sann # 1 well

27. Southern Indus basin and Sann a1 well location map after Quadri and Shuaib, 1986..

28. Samples and Methods
• Samples
 Unwashed Cuttings=76
 Cores=3(interval 3677-3686m)
• Methods Used:
 Total organic carbon (TOC)-to evaluate organic richness.
 Rock-Eval pyrolysis-hydrocarbon generation potential.
 Kerogen Microscopy-Vitrinite Reflectance

29. Sample Preparation
• For organic richness and hydrocarbon generation potential;
 ground to a 200 mesh powder mechanically,
 treated with hydrochloric acid to dissolve carbonate minerals,
 dried and then combusted

30.  demineralized first with dilute hydrochloric acid (dissolution of carbonate
minerals), washed, and then treated with concentrated hydrofluoric acid
(dissolution of silicate minerals).
 Kerogen macerals were separated from residual mineral matter by heavy
liquid separation using zinc bromide (specific gravity 1.85–1.90).
 Kerogen slides were prepared from concentrated kerogen.
For Kerogen Microscopy

31. Instrumentation
• LECO Carbon/Sulfur Analyzer for total organic carbon and total sulfur
contents.
• Rock-Eval Pyrolyzer for rock pyrolysis.
• Nikon Microphot-FXA Microscope for kerogen microscopy.
• Zeiss Universal microscope and photometer for vitrinite reflectance
measurement.

35. Results and Discussion
• Source rock quality and generation potential
• Average TOC values for the Cretaceous formations are 2.70% in the upper
Goru (n=43), 2.35% in the lower Goru (n=18), and 4.15% in the Sembar
(n=7).
• Total hydrocarbon generation potentials average 14.31 mg HCrg rock for
the upper Goru Formation between 1318 and 2573 m, 5.72 mg HC/g rock
for the lower Goru, 18.69 mg HC/g rock for the Sembar, and 9.12 mg HC/g
rock for cuttings from the Chiltan Formation.

36. Therefore, it appears from
the pyrolysis data that the
Sann # 1 well has excellent
source-rock potential
below 1318 m. On Fig. 5,
the hydrocarbon yield for
most samples is seen to be
high relative to their TOC;
i.e., they plot above the
best-fit line. This indicates
that these source rocks are
oil-prone and contain little
coal or other gas-prone
organic matter.

37.  A mean vitrinite reflectance measurement of 1.09% for a sample from the
Sembar Formation at 3530 m places the base of the main phase of
hydrocarbon generation and expulsion (the ‘oil-window’) near this depth.
Thermal Maturation

41. The van Krevelen diagram
in Fig. 6 also indicates the
relative level of thermal
maturation of the organic
matter as the HI and OI
values decrease along fixed
pathways relating to burial
and time–temperature
alteration.

42. Conclusion
• Thermal maturity determinations for the Sann a1 section from mean
vitrinite reflectance and TAI data show the top of the ‘oil window’ R of
0.60%. occurs at a depth of 2000 m and the base of the ‘oil window’ o R of
1.30%. occurs at an extrapolated depth of about 4000 m.
• The Rock-Eval pyrolysis data for the upper Goru Formation support the
organic petrographic observations on thermal alteration, source quality and
type, and organic facies.
• There is a pronounced increase in the kerogen transformation ratios KTR;
(S1/ S1 +S2) of the upper Goru at a depth of 2300 m from an average of
0.04 to 0.30. This jump in KTR values corresponds to the start of peak oil
and gas generation, and it appears to represent the onset of indigenous
hydrocarbon generation.
• Additionally, the Tmax for the upper Goru also increases slightly between
1963 and 2013 m Table 2., corresponding to entry into the ‘oil window’ at
this point. Tmax values in the deeper stratigraphic units have been
suppressed, probably by some inevitable drilling-fluid contamination, and
are no longer a reliable indicator of thermal maturation.

43. Refrences
• Wandrey.J.C., Law.E.B., and Shah.A.H., May 2004 Sembar Goru/Ghazij Composite
Total Petroleum System,Indus and Sulaiman-Kirthar Geologic Provinces,Pakistan
and India, U.S. Geological Survey Bulletin 2208-C.
• C.R. Robison ) , M.A. Smith 1, R.A. Royle., 1999 Organic facies in Cretaceous and
Jurassic hydrocarbon source rocks, Southern Indus basin, Pakistan International
Journal of Coal Geology 39 205–225
• Ahmad, S., Alam, Z., and Khan, A.R., 1996, Petroleum exploration and
production activities in Pakistan: Pakistan Petroleum Information Service, 72 p.
• Biswas, S.K., and Deshpande, S.V., 1983, Geology and hydrocarbon prospects of
Kutch, Saurashtra, and Narmada basins: Petroleum Asia Journal, v. 6, no. 4, p.
111–126.
• Drewes, Harald,1995, tectonics of the Potwar Plateau Region and the development
of syntaxes, Punjab, Pakistan: U.S. Geological Survey Bulletin 2126, 25 p.
• Quadri, Viqar-un-Nisa, and Quadri, S.M.G.J., 1997, Indus basin off Pakistan
contains few wells: Oil and Gas Journal, v. 95, i. 24.
• Wandrey, C.J., 2002, Kohat-Potwar Geologic Province Patala-Namal Composite
Total Petroleum System: U.S. Geological Survey Bulletin 2208-B.
• Waples, D.W., and Hegarty, Kerry, 1999, Seychelles thermal history hydrocarbon
generation traced: Oil and Gas Journal, v. 97, no. 21, p. 78–82.
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