Petroleum and Middle Indus Basin Essay Example

Petroleum and Middle Indus Basin Essay Example Petroleum and Middle Indus Basin Essay Petroleum and Middle Indus Basin Essay Kohat-Potwar Oil and Gas Exploration and Production The first oil well drilled in present-day Pakistan was at Kundal on the Potwar Plateau in 1866. The first commercial oil discovery was made in the Greater Indus Basin in 1914 when the Attock Oil Company completed a 214 ft well on a thrust-faulted anticline near Khaur on the Potwar Plateau (Khan and others, 1986). Early success in the Kohat-Potwar geologic province served to focus much of the early exploration activity in that area. The Sui field in the Sulaiman-Kirthar Foreland geologic province was the first discovery outside of the Kohat-Potwar geologic province and is the largest gas discovery in Pakistan, with more than 5 trillion cubic feet (TCF) of gas reserves. Discovered in 1952, the Sui field is a dome-shaped reef structure with an anticlinal surface expression. The largest reserves were found in the 625 m thick Eocene Sui Formation Sui Main Limestone Member. The Sui Upper Limestone Member and upper Eocene Habib Rahi Limestone were also productive. In 1999, Upper Cretaceous Pab Sandstone Formation gas production began at Sui field. Although exploratory wells had been previously drilled in the Middle and Lower Indus Basins, the discovery of the Sui field accelerated exploration efforts in the 1950s. More discoveries followed in that area with the Zin gas field in 1954, the Uch gas field in 1955, and the Mari gas field in 1957. Exploration activity increased again in the 1980s, when identification of a tilted fault block in the Lower Indus Basin led to the discovery of a series of oil fields. Although there have been significant oil discoveries in the Lower Indus Basin, it remains a gas-prone province. Gas discoveries that are attributed to the Sembar-Goru/Ghazij TPS have been made in Eocene, Paleocene, and Lower Cretaceous rocks on the Mari-Kandhot High in the Rajasthan Province of India. The Cambrian oil discoveries in Rajasthan, however, are beyond the extent of Sembar deposition and are either sourced by updip hydrocarbon migration from the Sembar or more likely by proximal older Mesozoic and early Paleozoic rocks. Sembar-Goru/Ghazij Composite Total Petroleum System The Sembar-Goru/Ghazij Composite Total Petroleum System (TPS) as defined for this assessment, is a north-south elongated area extending from the Potwar-Kohat geologic province in the north to the 2,000 m bathymetric contour in the Arabian Sea . The west boundary coincides with the axial belt and western edge of the Indian plate and the eastern boundary extends into India on the Indian Shield . Geochemical analyses of potential source rocks and produced oil and gas have demonstrated that the Lower Cretaceous Sembar Formation is the most likely source of oil and gas for most of the producing fields in the Indus Basin. Source Rocks While the Sembar has been identified as the primary source rock for much of the Greater Indus Basin, there are other known and potential source rocks. Rock units containing known or potential source rocks include the Salt Range Formation Eocambrian shales, Permian Dandot and Tredian Formations, Triassic Wulgai Formation, Jurassic Datta Formation, Paleocene Patala Formation, Eocene Ghazij Formation, and lower Miocene shales. Of all the possible source rocks in the Indus Basin, however, the Sembar is the most likely source for the largest portion of the produced oil and gas in the Indus foreland. In the Kohat-Potwar geologic province the Paleocene Patala Shale is the primary source rock for most, if not all of the province. In the offshore areas of the Indus geologic province, Miocene rocks are postulated to be good hydrocarbon sources, with the Sembar contributing in the shelf area. The Lower Cretaceous Sembar Formation consists mainly of shale with subordinate amounts of siltstone and sandstone. The Sembar was deposited over most of the Greater Indus Basin in marine environments and ranges in thickness from 0 to more than 260 m (Iqbal and Shah, 1980). Rock-eval pyrolysis analyses of 10 samples from the Jandran-1 well in the Sulaiman Range of the foldbelt, indicate an   most likely prove to be gas prone. verage total organic carbon content (TOC) of 1. 10 percent. The TOC values from the Sembar in two Badin area wells in the foreland portion of the Lower Indus Basin have TOC’s ranging from 0. 5 to 3. 5 percent and averaging about 1. 4 percent. A cross-plot of pyrolysis data on a modified van-Kreveln diagram study indicates that the organic matter in the Sembar is mainly type-III kerogen, capabl e of generating gas; however, additional proprietary data indicate the presence of type-II kerogen as well as type-III kerogen. With respect to the oil window (0. 6 1. 3 percent vitrinite reflectance), the Sembar ranges from thermally immature to over mature . The Sembar is more 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   Conclusive geochemical data supporting a Sembar source for most of the produced oil and gas in the Indus Basin are lacking; however, limited available geochemical and thermal data favor a Sembar source. To date, the only oil-productive regions in the Greater Indus Basin are the Potwar Plateau in the north and the Badin area in the Lower Indus Basin. Cross-plots of the carbon isotope ratios and the isoprenoid ratios of produced oils in these two regions are distinctly different , indicating two different source rocks. Gas content varies throughout the basin with CO2 ranging from lt; 1 percent to gt;70 percent, nitrogen lt; 1 percent to gt; 80 percent, and H2S lt; 0. percent to gt; 13 percent (IHS Energy Group, 2001). Reservoirs Productive reservoirs in the Sembar-Goru/Ghazij Composite TPS include the Cambrian Jodhpur Formation; Jurassic Chiltan, Samana Suk, and Shinawari Formations; Cretaceous Sembar, Goru, Lumshiwal, Moghal Kot, Parh, and Pab Formations; Paleocene Dungan Formation and Ranikot Group; and the Eocene Sui, Kirthar, Sakesar, Bandah, Khuiala, Nammal, and Ghazij Formations . The principal reservoirs are deltaic and shallow-marine sandstones in the lower part of the Goru in the Lower Indus Basin and the Lumshiwal Formation in the Middle Indus Basin and limestones in the Eocene Ghazij and equivalent stratigraphic units . Potential reservoirs are as thick as 400 m. 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 gt; 2,000 milidarcies (md). Reservoir quality generally diminishes in a westward direction but reservoir thickness increases. Because of the progressive eastward erosion and truncation of Cretaceous rocks, the Cretaceous reservoirs all have erosional updip limits, whereas Tertiary reservoirs extend farther east overlying progressively older rocks. Traps All production in the Indus Basin is from structural traps. No stratigraphic accumulations have been identified, although the giant Sui gas field is a dome-shaped reef structure (possibly an algal mound) expressed on the surface as an anticline. 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. The tilted fault traps in the Lower Indus Basin are a product of extension related to rifting and the formation of horst and graben structures. The temporal relationships among trap formation and hydrocarbon generation, expulsion, migration, and entrapment are variable throughout the Greater Indus Basin. In the foreland portion, formation of structural traps pre-date hydrocarbon generation, especially in the Lower Indus Basin. In the Middle and Upper Indus Basins, traps may also have formed prior to hydrocarbon generation, although the temporal relationships between trap formation and hydrocarbon generation are not as distinct as in the Lower Indus Basin. The structural deformation in the foldbelt region is generally contemporaneous with hydrocarbon generation, suggesting that some of the hydrocarbons generated from the Sembar probably leaked to the surface prior to trap formation. Burial history reconstructions based on data from the Sakhi-Sarwar no. 1 well , located in the foreland part of the Middle Indus Basin, and the Shahdapur no. 1 well, located in the foreland part of Lower Indus Basin, indicate that hydrocarbon generation began 40 and 65 Ma, respectively . The main differences in the hydrocarbon generation times between these wells are due to large differences in the thermal gradients; the present-day thermal gradient in the Sakhi-Sarwar well is 2. 6 °C/km as opposed to 3. 3 °C/km in the Shahdapur well. We interpret the critical moments for these wells at about 15 and 50 Ma, respectively. Based on these reconstructions, trap formation may have postdated the start of hydrocarbon generation in the foreland portion of the Indus Basin. Seals The known seals in the system are composed of shales that are interbedded with and overlying the reservoirs. In producing fields, 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. Overburden Rock The rocks overlying the Sembar are composed of sandstone, siltstone, shale, limestone, and conglomerate. The maximum thickness of these overlying rocks is estimated to be as much as 8,500 m in the Sulaiman foredeep area . In the foredeep areas immediately adjacent to the front of the foldbelt parts of the Indus Basin, the overburden thickness ranges from 2,500 m to 6,000 m. East of the foredeep, overburden rocks thin as Cretaceous and Paleocene rocks are progressively truncated.