A variety of distinct salt tectonic features are present in the Sab’atayn Basin of western Yemen. Based on the interpretation of 2D/3D seismic data and exploration wells in the central part of the basin, an Upper Jurassic evaporite unit produced numerous salt rollers, salt pillows, reactive, flip-flop, and falling diapirs. Halokinetics began as soon as the early Cretaceous, within just a few million years after the deposition of the Tithonian Sab’atayn evaporite sequence. The significant proportions of nonevaporite lithologies within the “salt” made the seismic interpretation of the salt features challenging. The evaporite sequence had been described by most as a syn-rift unit and therefore a strong correlation was assumed between the subsalt syn-rift basement architecture and the overlying diapirs and other salt-related features. However, seismic reflection and well data revealed a nonsystematic relationship between the salt diapirs and the subsalt basement highs. This observation has very important implications for the subsalt fractured basement play in the Sab’atayn Basin.
One of the most challenging part of managing a Gas-Condensate reservoir is to reduce Condensate Banking and its damaging impacts on the overall recovery. Several techniques have been applied in the past to overcome this problem such as pressure maintenance by Gas Injection (i.e. Lean gas, CO2 or N2), Water-Alternating-Gas (WAG) or chemical injection etc. However, none of these techniques could easily be initiated on a mature Gas-Condensate Field owing to the large upfront CAPEX and technical limitations. This study presents a strategy on such a mature Gas condensate reservoir, to target the Condensate banks and improve the overall condensate recovery. This study has been based on a field currently producing from the Potwar basin of Pakistan. The current pressure of the field is around 2500 psi - significantly lower than the Initial Reservoir Pressure (5200 psi) and Dew point (4950 psi). The PVT reports are showing that the reservoir has already passed the region of Maximum Liquid Drop out (MLDO). Thus, there was a risk of losing a good amount of Condensate if proper measures were not taken. This study focuses on the strategy to target these Condensate banks being accumulated at different locations of the Field, which has given an increment of around 30% already in the condensate production rates. Since the reservoir pressure has already dropped considerably below the dew point pressures - conventional CO2 or Lean gas injections cannot be utilized as they require significant re-pressurization which is technically and economically impossible at this stage of field's life. In this study, an alternative approach taken, is presented which increases the overall condensate recovery by almost 90%. This includes drilling smartly placed production wells (at locations which were not very attractive in the start of field development) and the overall impact of placing the injectors for Selective Water Flood using comprehensive reservoir simulation and water flood algorithms. This paper illustrates the approach that can be utilized in a mature gas condensate field where no pressure maintenance has been performed since the start - to improve the overall condensate recovery. This paper presents a clinical analysis of targeting the Condensate banks and possible usage of selective water flood strategy to sweep these banks along with the optimum placement of wells and injectors. This offers an innovative approach towards such gas condensate fields which are facing the problems of condensate drop out and re-pressurizing the field to a higher Reservoir pressures, at current stage, is next to impossible.
X field is producing water along with hydrocarbon from Tobra, Khewra & Sakesar reservoirs. Hence, it is imperative to understand the source of this water and its entry into the wells to optimize the field's production and limit the water production within the available water handling and disposal constraints. Even though multiple wells have been drilled in the field to-date, depth of the free water level is still unknown in the Tobra and Khewra formations. Large uncertainty lies with the thickness of the transition zone across the reservoirs with permeabilities ranging from 4 to 10 md. Besides, capillary forces are likely to have some effect in the rise of water in the pore space leading to some water production. In context of the uncertainties associated with the water breakthrough time and predicting the trend of water cut, it is considered useful to investigate the source of water via the information on the salinities and ion analyses. Four types of water have been produced from four types of reservoir rocks. Water ranges from fresh to brackish, and brackish to brine. Murree Formation is producing freshwater on surface; and hydrocarbon (HC) shows during drilling. Water production in Sakesar is high with relatively less salinity and high pressures. Surface Well Testing (SWT) data confirmed the water salinity of brine origin with varying composition. Sakesar formation's water salinity in X field ranges between 10,000 - 20,000 ppm is because of fresh water mixing with marine origin. However, nearby regional produced water salinity is 50,000 - 60,000 ppm from Sakesar. SWT data showed the production of high saline water in Tobra and Khewra reservoirs. However, salinity greater than 80,000 ppm is not associated with depositional environment of glacial sands (Tobra), and deltaic sands (Khewra); nor present in present day oceans and seas. Probably high saline water (brine) encroached in the formation from somewhere else. Our research is based on the chemical testing of water samples collected during well testing campaigns. Data was analyzed to understand the origin of water in Potwar Plateau, X field and probable ranges of salinity in different depositional environment. This case study is focused on the source of water from underlying formations or through deep seated faults. Same will be confirmed by detailed evaluation of SWT data and water analyses. In this paper, water breakthrough will be discussed with varying salinities in different wells depending upon the faults in the vicinity.
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