Petroleum Geology Of Pakistan.ppt

PETROLEUM GEOLOGY of Pakistan

Plate Tectonic Development History 1. Development of thick shelf margin reefal limestones, in the Permo Triassic time (Searle et al.,1983), suggest the first rifting event of the Gongwanaland and development of the Atlantic type passive continental margin. 2. The early rifting of micro-continents, away from the northern margin of the Gondwanaland, resulted in the development

of Paleo-Neotethys with a spreading ridge in between (Stocklin, 1977). 1. These microplates gradually drifted towards north and welded to the Eurasian Plate during Cretaceous to Paleogene times. 2. Prior to Triassic times, Indo-Pakistani plate was a part of the Gondwana continental mass. 3. Evidense from wells and outcrops, along its northwestern leading edge, the Punjab Platform, shows deposition progressing in continental and shallow marginal marine settings from Precambrian times.

1. Similar Precambrian and early Cambrian carbonates dominate the shelf areas, preserved in modern Arabia and Iran. 2. The southern margin of Eurasia was the site of northward subduction of late Paleozoic “Paleotethys” oceanic crust. 3. The rifting of India from Africa and Madagascar probably started in the Cretaceous. 4. The initial northward drift of the Indian Plate, from Early Companion to Middle Eocene, was rapid at a rate of 130-150 mm/y.

1. The counter clockwise rotation of the Indian Plate, relative to Eurasia around a close pole, during Early Eocene (Powell, 1979) was coincident with reduction of its velocity to 40 -60 mm/y, was finally settled down to 2 mm/y from Early Oligocene to the present (Patriat & Achache, 1984). 2. The continental underthrusting of the Indian Plate, since Cretaceous, produced the mountain ranges of the Himalayas and a chain of foreland foldthrust belts, as thick sheets of sediments, thrusted over the indian craton (Quittmeyer et al., Valdiya, 1984).

1. In the present plate tectonic setting Pakistan lies on the north western corner of the Indian Lithospheric Plate, which represents part of the Tertiary convergence between the Indian Eurasian plates. 2. The collision zone, in the northern Pakistan has been subdivided as the Main Karakoram thrust (MKT), Main Mantle thrust (MMT), Main Boundary Thrust (MBT) and Salt Range thrust (SRT).

1. Precambrian Basement rocks are exposed along the Sargodha High. Its east southeast trend parallel to the main Himalian, correspond to the Lithospheric flextural bulge developed due to norhtward underthrusting of the Indian Plate and leading of south verging thrust sheets (Molnar et al., 1975, Duray et al., 1989). 2. The collision in the west is oblique along a transpressional fault zone. The discontinous belt of ophiolites, which runs through the Bela and Zhob valleys, represent the suture. 3. Presently the Chaman/Onarch-Nal Transform Fault Zone (COTFZ) marks the western plate boundary.

• The triple junction, located northwest of karachi (Figure-1), which is the eastern limit of the Makran Subduction Complex. • Indian Plate is separated from the African Plate along Carlsberg Ridge, while the Owen fracture Zone marks the boundary between the Indian and Arabian plated. • The mid Tertiary collision zone, east of the COTFZ, can be subdivided into, stratigraphically and tectonically, distinct regions, i.e., northern montane area, axial belt and Indus Basin.

1. Indus Basin is further subdivide into Upper, Middle and Lower indus subbasins. 2. The area west and northwest of the axial belt represents the Baluchistan and Pishin basins. Baluchistan basin includes the Makran Subduction Complex and Kharan Fore Arc Basin.

Basin Development and Depositional response • The geologic history of a basin can be traced by three basic criteria: 1) basin forming tectonics; 2) depositional sequences, and 3) basin modifying tectonics ( Kingstan et al., 1983). INDUS BASIN • The Indus Basin development started during the Precambrian, as the deposition of red beds started in a sag of the eastward inclined, intensely peneplained, igneous and

metamorphic basement of the Gondwana Continental Mass (Arif Kemal, 1991). • With the increasing amount of sag, the marine conditioned prevailed at the center of the basin. • Stromatolitic dolomites followed by thick evaporite beds of the Salt Range Formation, which were deposited in the intertidal-supratidal envirionments over a large area of the subsiding basin.

• Organic rich, dark laminated shales (oil shale), associated with the evaporites, were deposited in intertidal to sabkha flat environment. • Deposition of red beds started again at the start of the Cambrian, representing the transgressive siltstone, galauconitic sandstones and dolomites of Khewra Formation. • Kussak Formation represent the marginal marine environments while the Jutana Dolomites were deposited in the peak marine environments in the Cambrian.

• Towards the end of this phase, evaporitic conditions appeared again and became increasingly widespread. • The red/brown claystones, with salt pseodomorphs of the Baghanwala Formation, were deposited in such environments, followed by a long period of erosion and non-deposition till the Early Permian. • Cambrian rocks are widespread in the Upper and Middle Indus sub-basins.

• The top of the Baghanwala Formation is erosional in the Upper Indus , while both, Jutana and Baghanwala formations are absent in the Middle Indus. Interior Fracture Phase • After a long hiatus of about 230 M.y., sedimentation restarted over the continental landmass of the Gondwanaland. • The Tobra, Dondot, Warcha and Sardai formations (Nilawahan Group) were deposited in the first phase of this period.

• Tobra Formation represents tillites and glacial wash deposits, which consists of sandstones, clay and polimictic conglomerates. • This formation gradually grades into the marginal marine and estuarine clastics of the Dandot formation in the Eastern Salt Range. • The res brown claystones of the Warcha Formation were deposited in the fluviatile environments.

• The variegated clastics of the Sardhai Formation mark the end to the continental conditions of the Early Permian. • The second phase of deposition represents the start of marine conditions during the Late Permian. • Marginal sagging initiated as the platform gently tilted westward. The Amb, Wargal and Chhidru formations of the Zaluch Group were deposited during this period.

• The dull yellow sandstones and limestones of Amb Formation represent marginal marine environment. • Amb Formation gradually grades into thick, dull brown, highly fossiliferous limestone of the Wargal Formation. • The Chhidru Formation consist of sandstones and shales with occasional limestone beds, deposited in marginal marine, estuarine or lagoonal environments.

MARGINAL SAG PHASE • With the further expansion of the rift system, margins subsided and marine transgression renewed deposition in the coastal basins. • The thick Mesozoic sedimentary sequence represents the gradual evolution of the typical passive continental margin.

• The clastics of the Sembar and Lower Goru formations represent a complete pattern of sea-level rise deltaics and sealevel fall turbidites. • The thick interbedded quartzose sandstones and shales of the Pab Formation represent deltaic plain/shallow water environments. • The fault bounded jacobabad High, developed in the Lower Indus sub-basin. In the Early Upper Cretaceous and begain

to control the depositional patterns of the younger formations. • Fort Munro Carbonates were deposited along this high in the Norhtern Lower Indus. • During Maastrichtian time the Indian Plate was positioned over the Reunion Hot spot, which produced the Deccan Trap volcanics.

COLLISION PHASE • Sedimentation resumed after the late Cretaceous uplift and erosion in the Upper Indus sub-basin (Hangu Formation mark the unconformily in the Salt range and Potwar sub-basin). • Lockhart Formation marks the marine transgression during the Paleocene.

• Organic rich lagoonal to restricted marine shales of Patala Formation represents the late regressive episode during the Paleocene. • Marine conditions persisted during the early Eocene time throughout the Indus Basin. • Restricted marine, evaporitic environments prevailed in the Kohat basin, where Panoba shales, Bahadur Khel Salt and Jatta Gypsum were deposited.

• Mudstones with thin turbidites of Ghazij formation are widespread in the Middle and Lower Indus sub-basins. • The shelf and reefal carbonates of the Sui Main limestone are developed in the southern Middle indus. • The red-brown fluvial/alluvial claystones and shales of kuldana Formation were deposited in coastal plains or in a tidal brakish water environment in the Upper Indus sub-basin.

• The overlying Kohat Limestone represent transitional marine conditions. In the Middle and Lower Indus, the Kirthar Formation indicates the restricted marine, shallow shelf deposits. • The continuous continent-continent collision, since Middle to Late Eocene produced uplift and corresponding erosion in the north and northeast. • The Nari and Gaj formations, comprising shallow marine glauconitic, crossbedded and ripple marked sandstones, overlain by variegated fluvial clastics, were deposited in the Lower Indus and southern parts of the Middle Indus during the Oligocene and Early Miocene.

• Thick terrigenous clastics of the Murree and Kamlial formations, were laid down in the Potwar region, north of the Sargodha High during the Miocene. • The Siwalik group of Middle/Upper Miocene to Pleistocene age, represents an overall coarsening upward sequence of fluviatile sedimentation. • In the Middle and Lower Indus area, the axis of the Siwalik depocenter, although remained aligned north-south, but shifted eastward along the mountain.

• The shallow marine facies gradually moved further south across the Lower Indus sub-basin. • The development of foreland fold-andthrust belts, along the northern and western margins of the Indian Plate, resulted in the development of lacustrine and fluvial environments. • The coarse grained, variegated siltstone and interbedded shales of Dada and Lei conglomerates, were depositd in local

Fluvial, lacustrine and valley fill environments during the late pliocene and pleistocene. Balochistan Basin • The evolution of Balochistan and Makran areas followed a different pattern from that of the indus basin. • The northward drift of the Central Iran, Lut and Afghan microcontinents from the Gondwanaland, most probably started as early as Permain.

• The presence of arc associated volcanics, in the Chagi and Raskoh Magmatic Belts of the Companion age suggest that a subduction complex had developed along the southern margin of these microplates, probably during the Cenomanian. • The accreted Paleogene Flysch gradually gets younger from north to south. • The pelagic conditions, which prevailed during the Jurassic and Cretaceous, were interrupted in the Late Cretaceous due to local uplift.

• The rapid erosion, from the uplifted landmass to the north, provided the sediments for the development of thick turbidites in the south. • In the coastal zone and offshore areas, the prograding shelf related sandstones with interbedded turbidites and mudstones of Panjgur and Parkini formations were deposited. • The continuous subduction of the Arabian Plate along Makran, during Middle Miocene, uplifted large area in the north.

• The rapid erosion of Oligocene and the Early Miocene rocks, in the north, accelerated the development of the accretionary prism to the south. • Fan gravels of the Kamerod Formation were deposited in the lacustrine and loessic environments, on the back of the rising mountain belts in the post Miocene time.

SOURSE ROCKS INDUS BASIN Upper Indus Basin Post-Eocene

• No samples were collected and analyzed from the post-Eocene molasse sequence (Rawalpindi and Siwalik groups) which due to its predominantly fluviatile character, does not contain any potential source rocks.

Eocene • In the Eocene, the best potential oil source rocks, in the Kohat area, are Early Eocene Jatta Gypsum which contains layers and lenses of high-grade oil shales. TOC of Jatta Gynsum ranges from 22.9% to 26.9 9 (Porth & Raza, 1990). • The dark, slightly bituminous limestones and intercalated shales of the Margala Hill Limestone of Hazara and Margala Hill have to be considered as potential oil-source rocks, if present in an adequate thermal-maturity range in the subsurfaces of the adjacent northern Potwar.

Late Paleocene to Eocene • A large number of samples from the Late Paleocene to Early Eocene Patala Formation were analyzed ((Porth & Raza, 1990). • Kohat Area (Panoba, Tarkhobi) Patala shales, in these localities, have the appearance of oil shales (dark-grey to black colour, light-grey to white weathering surfaces.

• The composition of the organic matter (Kerogen type I/II) is well in accordance with the interpretation as former oil shales from which most of the hydrocarbons have already escaped due to the advanced stage of thermal maturity, resulting in a reduced percentage of remaining organic material (Maximum TOC 1.56%). • Western Salt Range Only from Khairabad locality, Patala shales gave good data (predominantly Keogen type I/II).

• In the rest of the western salt Range (Nammal Gorge, Patala Nala) as well as in Surghar Range, the prevailing organic matter (OM) in the Patala shales is inertinite and vitrinite. • In the eastern and central Salt Range the coals of Patala Formation, which are partly highly resinuous, contain major percentage of liptinitic OM and could theoretically play a role as potential oilsource rocks.

• It is, however, disputed whether the high absorption of the coal would allow the expulsion of liquid hydrocarbons if generated within the coal. • In central and northern Potwar depression where the Patala Formation is mainly constituted of marlstone and limestone, the few analyzed core samples have yielded favourable results. • In Dhurnal-3 (TOC 1.21%) and Dhulian-41 (TOC 0.75%), liptinite and kerogegen-I/II, respectively, are the predominant organic components.

• Hazara area including Margala Hills, the Patala shales have no oil-sourcing potential. Besides a very low TOC, the prevailing OM type is inertinite or vitrinite. Paleocene • If originally sufficiently rich, parts of the Paleocene Lockhart Limestone can be considered as potential oil-source rocks. • The three analyzed samples from western Salt Range, Surghar Range and Hazara area (current TOC from Khairagali is 0.34%), contain liptinite, Kerogen type I/II and kerogen type I), respectively.

• The coal samples, collected from the Paleocene Hangu formation of Surghar Range, contain major percentages of liptinite, besides vitrinite, as the main organic component. • Regarding the oil-expulsion capability of the hangu coals, however, the same reservations have to be made as for the Patala coals. • They may, however, be considered as potential gas-source rocks at higher maturity levels.

• The same holds true for the Hangu coals of Kohat area. • Late Jurassic to Early Cretaceous • Late Jurassic to Early Cretaceous Chichali Formation, show rather low TOC (Max 0.66%) and the OM type as inertinite and partly vitrinite, in the Salt Range and Surghar Range. • In Hazara area and Kala Chitta Range, however, the Chichali shales and siltstones are partly very rich in organic carbon (TOC upto 27.78% at the locality of Changla Gali, Safdar thesis, 2007), despite

their advanced thermal maturity (overcooked for oil in Hazara). • The main OM component is vitrinite, thus Chichali Formation has to be taken considered as a good potential gas source rock along the northern rim of Potwar Depression. • Early Jurassic • Most of the samples, collected from the carbonaceous shales of Early Jurassic Datta Formation, exposed in the Salt Range, Trans-Indus ranges as well as core

samples from Potwar Depression, contain inertinite and vitrinite and only subordinate liptinite as the main organic components. • The vitrinite-rich carbonaceous shales and thin coal layers might act as gas-source rocks at adequate thermal-maturity levels. Paleozoic • The coal of Warchha and Tobra formations have to be rated as potential source rocks as the Paleocene coals, with the same reservations.

• The shales of Dandot Formation are organically very rich, but the predominant OM component of all samples is inertinite and the percentage of liptinite is <20%, thus the formation is interpreted as mainly non-source. • The cambrian exposed in the Salt Range and Khisor Range does not contain any potential oil or gas-source roks. Precambriam • Besides the Eocene oil shales of Kohat area, the best potential oil-source rocks

were encountered in the Precambrian Salt Range Formation which contains highgrade oil shales near the top and lessergrade oil shales and slightly bituminous shales and siltstones in the middle part. • The OM consists predominantly of kerogen type I/II partly contains major proportions of liptinite. • The oil yeild of the Precambrian oul shales is partly more than 20% of the rock weight. • Oil shales from Dulmial-1 well shows TOC as 23.4%, at the depth of 585 m.

• Middle Indus Basin • The oil shales and shales, marlstone and limestones of Pirkoh Limestone and Habib Rahi Limestone (Middle Eocene) are excelent potential oil-source rocks. • The predominant OM component of both the formations consist of Kerogen type I/II. • The liptinite content of the OM is generally higher in Pirkoh Limestone than in Habib Rahi Limestone. • Vitninite is practically absent in all the samples anylyzed, while the inertinite content is generally less than 5%.

• Ghazij Formation (Early Eocene: The coal smples, from Ghazij Formation, collected from Sor range, Duki and Much, consists of mainly vitrinite, with liptinite only 1 to 4% of the organic material. • Apart from the coals which might constitute suitable gas source rocks at higher maturity levels, no potential petroleum-source rocks have been recognized in Ghazij Formation. • Dungan Formation (Paleocene): Only a few surface and subsurface samples show significant proporion of bituminous OM (kerogen type I/II) and thus can considered as fair potential oil-source rocks.

• Mughal Kot Formation (Late Cretaceous):The TOC from the samples of Mughal Kot Formation, collected from Rakhi Nala ranges from 0.19% to 0.34%, in Mughal Kot from 0.34% to 0.56%. • The TOC values are rather low, but the original TOC of the rocks was probably considerable higher, before the present high stage of thermal maturity was reached. • Sembar Formation (Early Cretaceous): Inertinite and vitrinite, generally, prevails in the analyzed surface samples.

• Some samples from Mughal Kot, Loralai area and Mazar Drik, however, contain a significant percentage of kerogen type I/II. • The TOC is combatively high (0.52% to 1.86% in Moghal Kot area, upto 2.14% in Loralai area and 1.08% to 1.79% in Mazar Drik), despite the partly very high degree of thermal maturity. • It is assumes that a considerable percentage of the organic matter has escaped during maturation process and that the original TOC was distinctly higher than

the measured TOC. • The Sembar Formation is, therefore, considered as a very good potential oil and gas-source rock in areas with an adequate thermal maturity. • In Giandari-1 well, all samples from Sembar Formation contains a major percentage of bitumen (kerogen type I/II). • The TOC reaches 4.33% despite the very highMaturation of more than 3% VR.

• The Sembar facies of Giandari-1 well, is considered as holding very good oil prospects if present in neighbouring areas with moderate thermal maturity (i.e., within oil window). • Saman Suk Formation (Early Jurassic): A core sample from Panjpir-1 has a TOC of 1.59% with a liptinite proportion of 20% to 50%. This sample has to be ranked as a fair potential oil-source rock.

• Spingwar (Alozai) Formation ( Middle Jurassic): The analyzed surface samples of Spigwar Formation have no apparent source potential (low TOC of 0.11% to 0.46%, predominant of inertinite, low vitrinite and liptinite percentages). • Two core samples, from the Alozai Formation of Zindapir-1 well, however, are organically rich (TOC more than 1%), with a predominance of vitrinite. • The Alozai Formation of Zindapir area, therefore, has to be consodered as a potential gas-source fromation.

• Wulgai Formation (Triassic): One of the samples, collected from the type locatily, contains keogen type I/II as the predominant OM component. • In its original state, before reaching to its present stage of high maturation, the Wulgai Formation might have contained OM for oil generation.

Lower Indus Basin • Alozai Formation: Three mudstone samples of Alozai Formation, from Jhatpat-1 well were analyzed. They show no rock potential for oil but may have (according to AMOCO) a potential for gaseous hydrocarbons. No surface samples were analyzed. • Sembar Formation (Cretacous): Extensive geochemical investigations by exploration oil companies, in Sind, have proved good source rock parameters, specially for oil.

• Surface samples from the northern Kirthar Mountain Ranges (north of Khuzdar and between Sibi and Quetta) proved poor hydrocarbon potential. • According to BP’s investigations, in the Sanni area southwest of Sibbi, there is no hydrocarbon potential in that area. • Source rock quality, however, improves towards the south and southeast. • Goru Formation: TOC values of about 85% of the surface samples are less than 1%, most of then even below 0.5%.

• However, a former potential of Goru Formation, either for gas or for gas and oil, for some of the subsurface samples, should not be ruled out. • Quadri & Shuaib (1986) report, from the oil province of the Lower Indus Basin, that “ the lower part of the lower Goru sandstone, has moderately organic-rich sediments. • Therefore, it is likely that also for the Goru Formation, the southern part of the Lower Indus Indus Basin is richer and generally better source rock.

• Mughal Kot Formation: None of the surface and subsurface samples, of Mughal Kot Formation, qualifies as a hydrocarbon source rock. • However, it should be kept in mind that most of the samples are highly nature or even super mature, and contain besides the main component inertinite also oilprone alginite.

Moro Formation: Moro Formation is time equivalent of Pab and partly of Mughal Kot Formation, has been investigated by BP in the Sanni area. • According to BP the dark grey shales intercalation, within the sandstone sequence, might have some source rock potential. Dungan and Ranikot formations (Paleocene) • These two formations are widely distrubuted in the eastern Kirthat Mountain Ranges and Kirthar Depression, but missing on the Jacobabad-Khairpur High.

• Based on the studies, carried out until now by different agencies, there is every possibility of limited source rock potential in Paleocene sediments. Ghazij Formation (Eocene): Some of the samples, collected from different localities, indicate good to excellent source potential within the Ghazij Formation. Kirthar Formation ( Middle Eocene): Like Sulaiman Range, oil shales have been found with the Kirthat Formation at different places

• Within the Kirthar Formation in this region too. Thus Kirthar Formation is considered as excellent source potential for oil and gas.

RESERVOIR ROCKS

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INDUS BASIN Upper Indus Basin Potwar Depression contains a large number of actual and potential reservoir formations, ranging in age from Cambrian to Miocene. Among the producing formations, the Chorgali Limestone and Sakesar Limestone (Early Eocene) are the most important reservoir rocks.

• Both limestones are genarally considered as tight (average primary porosity 2 to 3%, permeability 2 to 5 md), but fracturing in the crests of the acutely folded and faulted structures provides a sufficient secondary porosity (15 to 25%). • Fracturing seems to be more prominent in the dolomitic portion of the two limestone formations. • Contrary to the prevailing assumption that effective porosity, in the Chorgali and Sakesar limestones, is only provided by

fracturing, a good moldic and vuggy porosity was observed in dolomitic horizons of the two formations, both in surface samples and core samples (Jurgan, Abbas and Mujtaba, 1988). • Apart from the Chorgali and Sakesar limestones, oil was also found in limestones of the Paleocene (Lockhart Limestone) and the Late permian (Wargal Limestone). In both cases, effective porosity is provided by fracturing.

• Most important clastic reservoir rocks are sandstones of the Early Jurassic Datta Formation in the western part of Potwar basinand eastern part of Kohat basin. • Sufficient porosities were also found in the sandstones of the Early Permian Tobra Formation (10% to 13%) and the Early Cambrian Khewra Formation (9% to 13%) in southeastern Potwar. • As potential reservoir rocks the Cambrian Jutana Dolomite and Triassic Kingriali Dolokite, as well as sandstones of the Early Cretaceous Lumshiwal Formation

(in northwestern Potwar and in Kohat) have also to be taken into consideration. • In Kohat area, clean, porous quartz sandstones were observed in the Paleocene Hangu Formation.

CAP ROCKS • Main cap rock of the Potwar oil fields are the Molasse sediments of the Rawalpindi group. • Claystones and siltstones of the Early Miocene Murree Formation genarally provide an excellent, effective sealing for the Early Eocene carbonate reservoirs. • In northwestern Potwar, sealing is provided by the claystones of Kuldana Formation.

• The oil bearing sandstones of Datta Formation are thought to be sealed by intraformational shale layers, the Tobra reservoirs by shales of Dandot Formation, and the Khewra sandstone by the predominantly shaly/silty Kussak Formation. • In Kohat area, the thick Early Eocene salt (Bahadur Khel Salt and Jatta gypsum) constitutes an excellent caprock for oil accumulations in the pre-saline reservoirs.

• Numerous oil and gas seeps, present in and around Upper Indus basin, are not due to ineffective sealing of the oil and gas bearing formations, but due escape to the surface along faults or thust planes, particularly along the margins of the basin.

HYDROCARBON PLAYS • The present structural pattern of Kohat-Potwar area is the result of south-vergent compressional tectonics and the decollement of the Phanerozoic sedimentary sequence above the salt of the Late Precambrial Salt Range Formation. • Main types of structural traps are elongated W-E or SW- NE trending, fault or thrust bounded anticlines or tilted fault blocks. • All wells, drilled in Kohat-Potwar area, have been located on structural traps.

Time of Trap Formation and Migration

• In Potwar Depression, the source formation (Patala Formation) reached the onset of maturity for the generation of oil in Late Miocene (11 to 5 my ago) in the northern part and in the Pliocene (5 to 2 my ago) in the southern part (Z. MALIK et al., 1988). • Patala Formation reached its deepest burial (and the final stage of Maturity) by the end of the Pliocene (2 mya).

• The structural deformation, of the sedimentary basin fill prograded steadily from north to south.

Middle Indus Basin Reservoir Rocks and Sealing Sulaiman Foldbelt • In Sulaiman Foldbelt, Eocene carbonates and Cretaceous sandstones are the main gas-producing horizons. • The Sui Main Limestone is an excellent reservoir rock. Its thickness reaches 665 m, the porosity (mainly primary) partly exceeds 40% (average 14%), and the permeability can be as high as 100 md.

• The foraminiferal limestone, which was deposited on a shallow platform near the shelf edge, forms a buildup in Sui area as documented by the increase of its thickness towards Sui structure. • Some authors even interpret Sui as a reef. • An effective sealing oh the Sui limestone is provided by the shales of Ghazij Formation. • The Late paleocene Dungan Limestone is gas-bearing in Loti and Rodho.

• Chiltan Limestone of Jurassic age, has produced gas on commercial scale from Zarghoon and Dewan fields. • Among the clastic reservoirs, the Late Cretaceous Pab Sandstone, which is gas bearing in Pirkoh, Rodho and Dhodak plays, is the most important reservoir. • Its gross thickness ranges from 250 to 350 m, the average porosity is 7% to 12%. • The Pab Sandstone, which normally forms one reservoir unit together with the overlying “ Lower Ranikot” sandstone, is

Efficiently sealed by the Upper Ranikot shales. • Other potential clastic reservoir rocks are the Lumshiwal Formation and sandstone horizons within the mainly shaly Mughal Kot Formation (Late Cretaceous). Punjab Platform • In Punjab Platform gas is prodused from Jurassic and Cretaceous clastic reservoirs (Nandpur and Punjpir fields). • Main gas producer is the Early Cretaceous Lumshiwal Sandstone, which constitutes time-equivalent of the Lower Goro

sandstones, the main oil and gasproducing formation in Lower Indus Basin. • The gas-bearing calcareous sandstones of the Middle Jurassic Samana Suk Formation have an average porosity of 12% to 17%. • The above gas reservoirs are sealed by shale portions within the Jurassic (Samana Suk Formation, Chichali Formation) and by the Paleocene Ranikot shales, respectively.

• Good quality porosities have been also reported from sand intervals in the deeper Mesozoic and Paleozoic part of the sedimentary succession in the Punjab Platform. • 14% porosity in the Early Jurassic Datta Formation,, upto 22% in the Early Permian Nilawahan Group, and upto 21% in the Early Cambrian Khewra Sandtone have been reported in various wells from the Punjab Platform.

Hydrocarbon Plays • The present structural pattern of Sulaiman Foldbelt and its margins is the result of the collision of the South-Asian Plate with the Eurasian Plate (Afghan Block). • The structures of the Punjab Platform are, however, of different origin. They formed on the more or less undisturbed, stable northwestern flank of the Indian Shield. • In the central part of the Sulaiman Foldbelt, numerous, partly larger, but more complex structures exist.

• A strong young uplift, has, however, brought the potential reservoir rocks and the (partly overmature) source rocks locally upto the erosional level. • The intensity of structural deformation decrease towards the south and east. • In Marri-Bugti area (southern Sulaiman lobe), the structures are E-W trending, elongated, partly arcuate surface anticlines whose northern flanks are normally steeper and more complex than the (mostly thrust-controlled) southern flanks.

• The gas fields of Pirkoh and Loti, as well as the gas discoveries of Zin and Uch are associated with this type of structures. • Sui anticline is less complex and combined with an Early Eocene carbonate buildup. • A similar structural type occurs in zindapir anticlinorium, along the eastern margin of Sulaiman Foldbelt. • Here, the eastern flanks of thje elongated, N-S trending anticlines are bounded by reverse faults or overthrusts.

• Two gas (and condensate) deposits (Dhodak and Rodho) have been found so far in separate structural culminations within the Zindapir anticlinal trend. • The large Sulaiman Depression shows very little signs of structural deformation. • Some structural leads are, however, present on some seismic lines, particularly in the northern part of the depression. • The E-W lines show a successive truncation of the older formations underneath the Paleocene and Miocene

unconfirmities, indicating the possible existence of stratigraphic traps. • Punjab Platform is also structurally very little disturbed. Some low-amplitude structures were probably induced by salt movements (partly salt solution). • Some of the tested structures (e.g. Nandpur and Panjpir) are located near the truncation line of the Mesozoic formations and might, therefore, constitute combines structural/stratigraphic traps.

Time of Trap-Forming and Migration • An optimum timing of trap-forming, sourcerock maturation and hydrocarbon migration is normally considered in those basins, where the structural deformation occur prior to migration, so that the generated hydrocarbons can accumulate in pre-existing structures. • In basins where migration starts prior to the structural deformation, there is always a risk that a major portion of the

hydrocarbons escapes to the surface due to the absence of trap. • In Middle Indus Basin, the gap between the onset of maturation of the main source formation (Sembar) and the majority of structural traps is even bigger than in Upper Indus Basin. • According to the Malik et al. (1988), the Sembar Formation (Early Cretaceous) reached thermalmaturity values of more than 1.0% VR during Early Tertiary and of more than 2.0% VR in MioPliocene in the center of the Sulaiman Depression, before the main phase of structural deformation in the region.

• They have, therefore, concluded that the bulk of the generated hydrocarbons had already escaped before the necessary traps were formed. • The strong young uplift of the Late Pliocene to Pleistocene period, resulted in the folding and faulting and thus forming the present traps of the region. • The above mentioned conclusion is applicable for the areas, such as Mughal Kot and Giandari zone, where the maturity level is high for the Sembar formation due to

the deep burial of the source rock during the geological past. • However, in the other parts of the Middle Indus Basin, thermal maturity of the Sembar Formation is much lower, thus the time gap, between hydrocarbon generation and trap-forming might be smaller. • It even seems possible that active gas (and oil) generation from Sembar Formation is still locally going on.

• For the eastern part of the Sulaiman depression and Punjab Platform The timing of source rock maturation and hydrocarbon migration vs. trap formation is more favourable. • Here, the migrating hydrocarbons, generated from sembar formation, could accumulate in already existing traps (older-structural traps and /or stratigraphic traps).

• For the second important (potential) source formation, the Middle Eocene Kirthar Formation, the timing between hydrocarbon generation and trap-forming, is much more favorable than for Sembar Formation. • According to Malik et al. (1988), the Kirthar Formation reached the onset of thermal maturity for the generation of oil in MioPliocene.

• It can, thus, be anticipated that oil generation, from the Middle Eocene oil shales, is still going on in the center of Sulaiman Depression and that suitable structural traps exist along the faulted and thrust western rim of the depression and stratigraphic traps along its shallow, gently dipping eastern flank.

Reservoir rocks and sealing • Lower Indus Basin • The Early Cretacous Lower Goru sandstones form the main reservoir in the Lower Indus Basin, a time equivalent of Lumshiwal sandstone is gas producing reservoir in the Panjpir (Middle Indus Basin). • The Upper Goru shales and marls act as a good sealing for the Lower Goru sandstone reservoirs.

• Pab Sandstone is the reservoir in the Bhit gas field of Kirthar Forld Belt. • Sediments of the Pab and Lower Ranikot formations are missing on the JacobabadKhairpur High, which had its largest extent during Late creatacous and Early Tertiary. • The Eocene limestones are the most important reservoirs in the gas fields of the Marri-Bugti zones, on the Kandkot-Mari High and in Mazari-1 well in the Kirthar Fold Belt area.

• Habib Rahi and Pirkoh limestones (Kirthar Formation) are lacking on the top of Jacobabad-Khairpur High, due to erosion or non-deposition. • The Ghazij shales proved to be a good vertical and if necessary lateral sealing for the Laki/Sui Main limestone. • Shale interclations and the fine clastic sediments of the overlying Drazinda and Dozkushtak formations, respectively, may act as a sealing for the possible limestone reservoirs of the Kirthar Formation.

Migration and Trapping • Two main elements are responsible for the migration pattern of the hydrocarbons in the northern part of the Lower Indus Basin: • During Cretaceous and the beginning of Tertiary, a steady subsiding shelf of the northwards drifting South Asian Plate was modified by the rising Jacobabad-Khairpur High and after the collision of the South Asian Plate with the Afghan Block, the folding and uplifting of the Kirthar Ranges

and forming of the Kirthar Depression. • Maturity calculation, based on recent geothermal gradients, proved that the Sembar formation had entered the oil window at the end of Cretaceous in the zone of high geothermal gradients, between Giandari-1 and Lakhra-1 wells. • This zone coincides with the area of maximum thickness of Sembar sediments. • Structures were ready when Lower cretaceous and Paleogene potential source rocks became mature. Thus good coincidence was existing.

• Plays and possible Prospects