Structural architecture of fault zones, their distribution across the field and impact on migration pathways & reservoir permeability play an important part in field development. Inspiration for this study was limited understanding of role that faults play in brittle carbonate reservoirs. Extensive fault interpretation study was planned for quantification of orientations, segmentation, offset magnitudes and fault zones spacing to define their implications on fluid flow in terms of sealing capabilities within reservoirs. A systematic structural interpretation approach was established by exhausting the combination of regional tectonic history, 3D seismic interpretation techniques, advanced 3D visualization, BHIs, drilling data, production data, pressure data and MDT data. This resulted in better and more thorough definition of structures and hydrocarbon distribution in reservoirs. Structural history of the field was analyzed to tie fault related observations with known tectonic events affecting reservoirs. A simple structural restoration with available data indicated that structures & fault zones probably resulted from regional WNW-ESE compression during late Cretaceous period. 3D seismic interpretation techniques & 3D visualization were exploited to interpret faulted zones present in the field. Geometrical attributes were extracted from conditioned seismic data to enhance discontinuities & edges. Interpreted faults were later tied with wells crossing faulted zones using BHIs & drilling data. Thorough analysis reveals that major faults are actually assemblage of numerous segments. Furthermore, lateral and vertical displacement gradients are observed near tip lines of the fault planes. Relay-ramp behavior between fault segments are variable, mainly dependent on their orientation relative to prevailing maximum horizontal stress direction. Accordingly, positive (popups) and negative (sinkhole) structures can be found along the major faults. Two major faults having larger throws, as compared to other faults, divided the field into three parts, namely, northern, central & southern. Fault transmissibility varies as function of slip magnitude, diagenesis history leading to minerals filling, and their orientations relative to current maximum horizontal stress direction. Field dynamic data unveils that magnitude of slip is one of the most significant factors in explaining sealing capabilities of faults in reservoirs. Numerous wells have been drilled in central & southern parts of field with continuous production from wells in central part since 2005. Pressure records have shown no pressure change in southern part till date. Additionally, MDT results showed different FWLs and GOCs in both parts of field which also point to complete isolation. Northern part of field is yet to be appraised. Possibility of faults, with significant throw separating the northern from the central part of the field, acting as a seal may not be ruled out. An appraisal well with extensive acquisition program has been proposed to uncover hydrocarbon potential in northern part of field.
The purpose this study is to use geophysical technology, analyze the characteristics of typical sedimentary facies in the study area, extract sensitive seismic attributes, compile sedimentary facies distributions, establish a sedimentary model, and improve the understanding of the distribution law of complex carbonate reservoir in oil and gas exploration and development. The Cretaceous Arabian Basin is a typical gentle slope carbonate basin with rich oil and gas resources. The main reservoirs in the study area have complex lithology, including bioclastic grainstone, bioclastic packstone and rudstone. However, the heterogeneity of carbonate rocks is strong and the sedimentary facies change rapidly, which increases the difficulty of understanding the distribution law of reservoirs. Based on core data, well logs, seismic data and well-to-seismic integration, the sedimetary facies study of the Cretaceous Thamama Group has been completed. Typical lithology and logging facies were identified. The logging facies were established, multi-well facies were carried out; and sedimentary characteristics were analyzed. Multi-attributes have been analyzed including amplitude, frequency, continuity and phase attributes to extract sedimentary facies maps by combining lithofacies and logging facies. Based on the above analysis results, a sedimentary model has been summarized. According to this study, the target strata are mainly carbonate deposits of gentle slope with shoal, inner shoal and grain flat facies deposits. Four typical logging facies were identified consisting of low energy shoal, margin shoal, grain shoal and grain flat microfacies. The favorable reservoirs are mainly bioclastic grainstone and packstone formed in a medium-strong hydrodynamic environment. The sedimentary model of the study area is established to analyze the distribution of target reservoirs and guide the analysis of favorable reservoirs in the area. The Thamama Formation has stable thickness in general, the depositional environments changed from subtidal to inner shoal of restricted platform, to grain shoal and grain flat. It is concluded that the Shuaiba Formation and the Kharaib Formation of the Lower Cretaceous Thamama Group in the middle of the study area are the most favorable reservoir development formations, and the central and northern areas are the most favorable oil and gas accumulation areas. Through this study, a more complete and instructive carbonate slope sedimentary model has been established. In addition, through the multi-attribute analysis technology and optimization method, we have completed and deepened the understanding of the distribution of the target layer sedimentary facies, and provided a new geophysical comprehensive research method. However, due to the complexity of carbonate rocks, further research is needed.
Carbonate reservoirs are notoriously complex and difficult to characterise, due to their inherit homogeneity. The ability to understand and model such homogeneity accurately, leads to better reservoir management and improved field development strategy in terms of well placement and optimised well patterns. Dynamic reservoir model was built from the static geological model i.e. using MDT, pressure volume temperature (PVT), routine core analysis (RCA) and special core analysis (SCAL) etc. As part of the reservoir model validation process, history matching of the model was conducted to match the observed data. After history matching was completed, tracers injection analysis and streamlines modelling was conducted in other validate the reservoir model, the well patterns and improved the full field development strategy. The full field development scheme includes water alternating gas (WAG) miscible hydrocarbon gas injection, with 5 observers covering both the flank and crestal locations. The tracer analysis included the injection of 11 different tracers in 11 different injectors, and the monthly monitoring of the producers within the well pattern. Streamline model was built simultaneously from the convention compositional model, in order to analysis and predict the different tracers break through times i.e. both observed from the field and simulated. In addition to this, streamline time of flight (TOF) analysis, the effect of tracking of different tracer components, geological and geophysical impact was evaluated, in order to improve the breakthrough time match between observed and simulated time. As a result of this analysis reservoir management improved, as the source of increasing higher GOR in specific wells were discovered. Remedial actions were recommended to help reduced the increasing high GOR in the respective wells. Also the field development strategy improved, as injector's contribution per well pattern well was quantified. As a result injection could be redistributed. In producer wells with little or no support from their respective injectors, a plan was made to ensure that such patterns could be close appropriately. This improved and maintains the viodage replacement ratio (VRR) in the field, according to reservoir guidelines. This paper describes how by using gas tracer injection and streamline modelling reservoir management and field development can be improved. In addition to the improvements in reservoir management and field development strategy, several lessons learnt and best practice were suggested from the tracer and streamline study conducted. They include but are not limited to; Different tracers can show different concentration level at breakthrough wells.Wells further away from injectors can show earlier breakthrough than well close to injectors, as it is dependent on reservoir connectivity.In analysing model breakthrough times, the measurable tracer in the field needs to be used, as opposed to the actually first breakthrough seen in the simulator. As below such concentration cannot be measured.Operational changes in wells need to be captured properly in the simulator, in order ensure improve prediction of tracer breakthrough times.
Reliable sonic and density logs are key inputs for seismic driven reservoir characterization. Anisotropic surface vertical velocities are essential for seismic well ties, estimation of wavelets and low frequency modeling. These help us to understand the relationship between reservoir and acoustic properties. In this study, sonic logs were acquired in highly deviated wells penetrating highly anisotropic shale formations. These logs needed corrections before integrating in the reservoir characterization workflows. In allusion to problem existed in traditional methods, an iterative inversion method based on multi-well models composed of adjacent vertical and deviated wells was proposed. Well data was optimized after matching depth of vertical and deviated wells. Thomson approximation formula was re-derived based on multivariate linear fitting and least square coefficient matrix was constructed to obtain delta and epsilon respectively. Best Thomsen parameters were obtained to address shale anisotropy. The results show that the Nahr-Umr shale formation have strong anisotropy for highly deviated wells in the field of study. The correction was not required for deviation less than 20 degrees. The correction gradually increases and reaches as much as 20% to 30% at 60 degrees. It was observed that there is a huge difference between the measured velocity of highly deviated wells and the true vertical velocity in the shale formation. This anisotropy can affect seismic imaging, time-depth conversion, AVO, well-seismic calibration. Therefore, sonic log correction is necessary for highly deviated wells in the shale formations. Corrected sonic logs in deviated wells provide accurate acoustic velocities for further reservoir characterization & seismic inversion studies. The real acoustic data of deviated wells can be obtained from shale formations with strong anisotropy such as Nahr-Umr and Laffan formations.
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