The Thamama group of reservoirs consist of porous carbonates laminated with tight carbonates, with pronounced lateral heterogeneities in porosity, permeability, and reservoir thickness. The main objective of our study was mapping variations and reservoir quality prediction away from well control. As the reservoirs were thin and beyond seismic resolution, it was vital that the facies and porosity be mapped in high resolution, with a high predictability, for successful placement of horizontal wells for future development of the field. We established a unified workflow of geostatistical inversion and rock physics to characterize the reservoirs. Geostatistical inversion was run in static models that were converted from depth to time domain. A robust two-way velocity model was built to map the depth grid and its zones on the time seismic data. This ensured correct placement of the predicted high-resolution elastic attributes in the depth static model. Rock physics modeling and Bayesian classification were used to convert the elastic properties into porosity and lithology (static rock-type (SRT)), which were validated in blind wells and used to rank the multiple realizations. In the geostatistical pre-stack inversion, the elastic property prediction was constrained by the seismic data and controlled by variograms, probability distributions and a guide model. The deterministic inversion was used as a guide or prior model and served as a laterally varying mean. Initially, unconstrained inversion was tested by keeping all wells as blind and the predictions were optimized by updating the input parameters. The stochastic inversion results were also frequency filtered in several frequency bands, to understand the impact of seismic data and variograms on the prediction. Finally, 30 wells were used as input, to generate 80 realizations of P-impedance, S-impedance, Vp/Vs, and density. After converting back to depth, 30 additional blind wells were used to validate the predicted porosity, with a high correlation of more than 0.8. The realizations were ranked based on the porosity predictability in blind wells combined with the pore volume histograms. Realizations with high predictability and close to the P10, P50 and P90 cases (of pore volume) were selected for further use. Based on the rock physics analysis, the predicted lithology classes were associated with the geological rock-types (SRT) for incorporation in the static model. The study presents an innovative approach to successfully integrate geostatistical inversion and rock physics with static modeling. This workflow will generate seismically constrained high-resolution reservoir properties for thin reservoirs, such as porosity and lithology, which are seamlessly mapped in the depth domain for optimized development of the field. It will also account for the uncertainties in the reservoir model through the generation of multiple equiprobable realizations or scenarios.

Reservoir compartmentalization, either structural, stratigraphic, or combination, is one of key parameters for accurately characterizing the hydrocarbons distribution in the subsurface and it is an important component for optimizing hydrocarbon recovery. In order to accurately characterize its compartmentalization, structural synthesis has been applied for generating a representative structural configuration of the complex and highly faulted reservoirs of the studied field. This paper demonstrates detail structural synthesis of a Cretaceous Middle-Eastern carbonate reservoir. The studied field exhibits multiple fault blocks with different fluid composition and contacts variation. Log analysis and test results from a number of wells suggested oil rim with significant gas cap and water leg. Exploiting the oil and gas in highly faulted reservoir possesses a major challenge hence the optimum strategy of development plan was created. Multi-tectonics history of the Arabia in the region is demonstrated by both folding and brittle deformation represented by fault system comprising en echelon faults and joint sets. The most dominant faults are N75W and N45W trending strike slip fault systems. Kinematic analysis, outcrop analogue, and nearby field analogue revealed that the two fault systems have been developed by different tectonic events. The N75W trending faults have been developed as tensile fracture shortly prior to folding when SHmax azimuth was approximately oriented 120o azimuth. The N45W trending faults have been developed at a later stage possible as splay faults by branching from the pre-existing N75W when the SHmax trend was oriented approximately 90°. The N45W fault arrays show partitioning of displacement between the various splays, with relatively abrupt changes in the displacement at branchlines. Long ‘single faults’ are frequently shown to be segmented into en-echelon arrays. This expression defines a model of fault growth by radial propagation and linkage from a single seed fault as indicated from geometrical and kinematic evidence. Antithetic N45W fault exhibit a downward decrease in displacement towards a tip line near the N75W master fault. This suggests that the N45W faults were initially developed as Riedel shears which then propagated and linked to the pre-existing N75W system as splay faults. This has occurred by a continuous counterclockwise rotation of the causative SHmax stress from Cretaceous to present. Quantification of the orientations, segmentation, and offset magnitudes provided a foundation for defining their implications for fluid charging, fluid flow, and pressure development within the reservoir. Thus several development scenarios were constructed in order to maintain the pressure and production rate, considering various combinations of horizontal producers and injectors, number of wells, well orientation, horizontal length, and depletion schemes.