Seismic as well as structural techniques were exploited to elucidate the subsurface structure of the Zamzama area that directly led to petroleum system. Zamzama gas field is located in the Kirthar Foredeep, southern Indus Basin, Pakistan. The current research is based on data scrutinized systematically through eight seismic lines (796-JH-01, 02, 03, 07, 10, GHPK-98A-32, 34 and 40) and three wells (Zamzama-02, 03 and 05) drilled in the Zamzama field. Seismic interpretation reveals that Tertiary and Cretaceous sequence is deformed by transpressive tectonics, and a reverse fault is located from 400 to 3400 ms deep on the vertical seismic section. The hanging wall moves up along the fault plane under the action of eastward directed stress as a result an extensive North–South oriented and eastward verging thrusted anticline is formed. Stratigraphically, area encompasses well-developed Mesozoic–Cenozoic sequence. The Late Cretaceous Pab Formation is well-known primary hydrocarbon reservoir capped by the shale of the Paleocene Ranikot Formation that acts as a regional seal rock. The Jurassic and Cretaceous shales of the Sember and Goru formations are substantiated as main source rocks. The execution and portrayal of seismic and subsurface geological data provide the clues that area contains appropriate petroleum play potential. Present study suggests a worthwhile regional geo-seismic model that might be significant for future exploration in the Kirther Foredeep and adjacent areas.
Lower Goru sand intervals of Early Cretaceous age are proven reservoirs in the Lower Indus Platform area. The delineation of reservoir geometries is of utmost importance while searching for stratigraphic and combination traps in clastic reservoirs. The data of ten wells and two 2D seismic lines from the northern part of the Lower Indus Basin are incorporated in this study. These reservoir intervals of the Lower Goru Formation are correlated in a third-order sequence stratigraphic framework to understand the depositional architecture and reservoir geometries. The Lower Goru Formation was deposited in westerly prograding river-dominated deltas developed by river system drained through the Indian Shield from east and south-east during Cretaceous time. Due to auto-cyclic switching of river distributaries, different lobes might have formed which if identified can point out the possible locations and configurations of stratigraphic and combination traps in this highly prospective area of Lower Indus Basin. The Lower Goru Formation (Barremian to Cenomanian) consists of one full second-order sequence of 20 Ma duration, having all the three fundamental system tracts in which eleven sequences of the third order, i.e. LG-1 to LG-11, were interpreted. Proven reservoir intervals of the Lower Goru Formation are concentrated in various third-order lowstand system tracts. The net sand and porosity maps of lowstand system tracts, gross depositional map and depositional cross section of the Lower Goru Formation point out the potential sites of good sandstone reservoirs and hint at the possible sand-body geometries.
The North Tapti field is located in Arabian Sea WNW of Mumbai city. The bathymetry of the area is very shallow between 8-35 m depending on the tide condition and therefore poses adverse logistic conditions due to strong bottom currents. In North Tapti field shallow gas sands of Oligo-Miocene age occurring at depth of 550- 900 m are layered reservoir with several pays. Exploratory wells produced dry gas with sand. The lithology of the reservoir sand is mainly medium to fine grained and at places coarse sandstone with fair inter-granular porosity. Initial development plan envisaged exploitation of gas through six development wells. All the six wells were envisaged as horizontal wells of about 300m drain hole with sand control completions through pre- drilled liner supported open hole gravel packs with a view to achieve higher gas productivity. The rig positioning activity in North Tapti area experienced great difficulties due to severe sand-scouring of seabed. Therefore, the first well had to be drilled as vertical well and completed with premium screen as a standalone screen completion with a view to make up lost time prior to impending monsoon. Studies based on the drilling data obtained from first development well revealed sub- surface surprises like reduction in pay thickness and occurrence of multi layered pays in Mahim and Daman formations at shallow depth. This posed considerable challenges in achieving desired high drift at shallow vertical depth of about 400m while maintaining high angle trajectory during drilling and subsequent completion programme. Hence, innovative drilling and completion approaches were adopted to tackle sub-subsurface complixities and to achieve maximum planned gas production. In this backdrop of accomplishing the onerous task to produce sand free gas in all the six wells in platforms of North Tapti which were planned to be completed with suitable sand control methode using in-house expertise was a real challenge. The methodology adopted in two wells viz. A and B of 80° and 85° inclination were single frac pack and stacked completion of both. Stand alone in the lower barefoot section and a frac pack in the upper sands which was cased cemented and perforated. The wells of P1 platform are accessible with difficulty due to severity of water depth and short tide periods. Therefore wells were completed as stand-alone screen completions through Expandable Sand Screen (ESS) in 6″ drain hole section and 7″ liner sections. This highly innovative drilling and completion approach facilitated exposure and completion of thin pay sands in multi-layered reservoirs in a deviated well. The result is stable and uninterrupted gas production for over a period of more than two and half years and continuing at a consistent rate of about 1.3 MMm3/d.
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