Lower indus basinPetroleum Play Of Lower Indus Basin

Petroleum Play Of Lower

Indus Basin

Presented ByMaryam Nazeer 2013-MS-GS-1Rizwan Sarwar Awan 2013-MS-GS-2

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

Trap

Lower Indus Basin

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.

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).

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

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; Quadriand Shuaib, 1986, 1987).

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).

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).

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).

Stratigraphy

of Lower

Indus Basin

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

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 GoruFormation.

Source RocksSember 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).

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

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)

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).

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

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.

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 .

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.

Source Rock Evaluation

A Case Study

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

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

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

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

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

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.

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.

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.

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

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.

Conclusion

• Thermal maturity determinations for the Sann a1 section from meanvitrinite reflectance and TAI data show the top of the ‘oil window’ R of0.60%. occurs at a depth of 2000 m and the base of the ‘oil window’ o R of1.30%. occurs at an extrapolated depth of about 4000 m.

• The Rock-Eval pyrolysis data for the upper Goru Formation support theorganic petrographic observations on thermal alteration, source quality andtype, 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 of0.04 to 0.30. This jump in KTR values corresponds to the start of peak oiland gas generation, and it appears to represent the onset of indigenoushydrocarbon generation.

• Additionally, the Tmax for the upper Goru also increases slightly between1963 and 2013 m Table 2., corresponding to entry into the ‘oil window’ atthis point. Tmax values in the deeper stratigraphic units have beensuppressed, probably by some inevitable drilling-fluid contamination, andare no longer a reliable indicator of thermal maturation.

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,Pakistanand 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.

• Soulsby, A., Kemal, A., 1988b. A review of exploration activity in Pakistan. Oil and Gas J. 86 48 , 81–83.Ž .