The Barremian-Aptian, Kharaib Formation is among the main reservoir units in the Middle-East. The Kharaib Formation is broadly divisible into three main zones: the Upper, Middle and Lower Kharaib, which are defined based on their distinct sedimentological characteristics. The Kharaib interval has been extensively studied across the region; however, the inherent heterogeneity associated with sediments always makes it challenging for interpretation of the depositional facies, stratal geometries, and the prediction of their reservoir properties. This study focuses on the Middle and Upper Kharaib by integrating sedimentological, diagenetic, and pore-scale datasets to provide a better understanding of the depositional framework, diagenesis and its effects on the reservoir properties. Dunham/Embry & Klovan classification (1971) scheme is used to describe the sediments, which determines lithofacies. Lithofacies that are genetically relatable are grouped into larger sets of associations. The lithofacies association represent their sedimentary environments of deposition. The grouping/stacking pattern of the sediments reflects a broad third-order sequence. Higher-order variations/sequences are either from localized topographical changes or energy variations or from sea-level changes, which thereby imparts lateral reservoir heterogeneity. X-ray diffraction (XRD) analysis defines the mineralogical composition, whereas pore-scale fabric/textural characteristics have been defined via conventional light microscopy and scanning electron microscopy (SEM). Sedimentological description of the Kharaib Formation showed varying textures ranging from mudstone to grain-rich floatstone, which are interpreted to be deposited in a broad homoclinal ramp setting. Petrographic evaluation of the sediments from the studied section highlighted the effects of diagenesis on reservoir properties with calcite cementation significantly reducing the reservoir quality (i.e., lower porosity and permeability). In contrast considerable micro and macropore enhancement due to secondary dissolution appears to negate the effects of cementation. In the studied sediments, the porosity comprises considerable abundance of primary and secondary macropores. The measured porosity varies from moderate to very good, while permeability is low to moderately high. Interrogation of conventional core analysis data establishes that the primary control on reservoir quality distribution is sediment texture and composition. The genetically distinct characteristics of lithofacies related to allochem assemblage, their abundance and size aid in defining the associations, which thereby provides the former fabric for the subsequent diagenetic alterations. The abundance of detrital clays in the middle Kharaib appears to be the primary cause of relatively poor reservoir quality. This study shows that both the original depositional texture/composition and diagenesis have had an important impact on shaping reservoir properties. This integrated approach sheds light on the sedimentological make-up, depositional setting, and diagenetic overprint of the Kharaib Formation and their effect on the reservoir quality of various lithofacies. This understanding will further develop work related to pattern prediction of the Kharaib Formation, which may be extrapolated to uncored intervals for reservoir quality correlation and assessment.
Tatweer Petroleum completed the first successful Bahrain Field Forced Imbibition Gas Injection Pilot in 2014. This pilot was completed in the Ahmadi formation and demonstrates classical and economic performance. The paper also describes the systematic effective and efficient Tatweer pilot management approach which allowed an impressive results in a time frame less than one year. The Ahmadi formation consists of three, carbonate, highly fractured reservoirs designated as Aa, Ab1, and Ab3. The Ahmadi reservoirs have the greatest areal extent of any of the oil-bearing reservoirs in the Bahrain field. The Aa and Ab productive zones cover over 41,500 acres, and are separated by 40-45 feet thick, shale members. The gas injection (GI) pilot development in the Ahmadi reservoir, along with the waterflood pilot, is considered a secondary recovery process. The objectives of this pilot is to test the concept of forced imbibition (FIMB) in Ahmadi reservoir after it was successfully tested in Rubble reservoir with steam injection. The FIMB GI process is performed by injecting gas within the pattern area for certain period while offset oil producers are kept shut-in. The offset oil producers are opened once the GI cycle is achieved and accordingly the gas injector kept shut-in. This process will enhance the stripping of the oil from the matrix to the fracture system, which are connected to the offset oil producers. The selection criteria to select the optimum FIMB pilot pattern was developed based on an intensive matrix selection criteria. The selected pilot consists of three horizontal wells; one injector and two producers. The wells were completed as open-hole with ~1000m lateral in the Ab3 unit, and the space between the producers and injector is ~180m. The selected pilot was initially a water injection pilot. However, the production after the introduction of this pilot was not promising, and water break-through resulted in a reduction of the base production. Consequently, the pilot injector was suspended. The suspended water flood pilot area was selected since it is located in highly fractured and confined area. A simulation dynamic model was constructed covering a sector area within the vicinity of the pilot. The model was used to run different scenarios for the number of GI cycles at different GI rates, and assess the required soaking time post GI Cycles. So far, 3 GI cycles have been completed with around 60 MMscf being cumulatively injected. The initial results were very encouraging during the FIMB GI execution. The dynamic scenario output predication was calibrated with actual production data from the executed FIMB GI pilot, and the results were in line with the model's predictions. Thus, the FIMB GI seems to be effective and promising enhanced recovery in a highly fractured carbonate reservoirs. The results of the pilot provided confidence on proposing crest GI pilots to enhance the secondary recovery process in the Ahmadi reservoir.
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