The distribution of reservoir quality in tight carbonates depends primarily upon how diagenetic processes have modified the rock microstructure, leading to significant heterogeneity and anisotropy. The size and connectivity of the pore network may be enhanced by dissolution or reduced by cementation and compaction. Consequently, a clear understanding of the diagenetic process that responsible for the reservoir tightness would offer vital assurance on the spatial property distribution and future field development plan. In this paper, we have examined the factors which affect the distribution of porosity, permeability and reservoir quality in the Thamama Group, which is a prospective low permeability carbonate reservoir rock in Onshore Abu Dhabi. The dataset includes regional stratigraphy, well logs and core material from a number of wells, a suite of laboratory petrophysical measurements, seismic attributes, geomechanics, fracture study, and production history. Dataset analysis and interpretation suggested that the reservoir was deposited in shallow to deep marine low energy environment which led to deposition of fine to very fine grains (lime-mud supported) types of sediments. This, in turn, would produce poor reservoirs during compaction and finally leads to tightness. Because of the low permeability nature of this tight reservoir, it is quite challenging to obtain their complete reservoir properties and dynamic behavior. As in many other tight reservoir projects, a considerable area of the reservoir must be effectively stimulated during the hydraulic fracturing process to achieve economic productivity. In addition, development of tight reservoirs often faces challenges, for example, low initial production rates and high declining rate. This paper aims to frame all possible optimum development practices for tight reservoir in the studied field that should be considered for future development plan. We also investigated the application of new technology to enhance the poor oil recovery within the pool including horizontal drilling and multi-stage fracture completion technology. Furthermore, this paper also discusses well orientation relative to the far field principal stresses, hydraulic fractures treatment, fracture fluid selection, and nano-technology application. This, in turn, would provide valuable information on how to optimally develop this previously considered marginal and uneconomic reservoir.

The paper is continuation of SPE-175682 and SPE-182963. This work illustrates horizontal well placement optimization studies conducted on a Cretaceous complex carbonate reservoir with thin oil column and strong water drive reservoir. A further complication for the well placement is the presence of some thin high permeability streaks intervals with permeability value of up to 1 Darcy. Early water breakthrough encountered in the existing oil producers is a serious problem which results in lower oil production rates, lower oil recovery, and increased lifting cost. In addition, premature water breakthrough would leave behind bypassed oil zones. Hence determining the optimum location of the wells is a critical and crucial decision to be made during a field development plan. In this study, we apply integrated geosciences, geostatistical, and flow simulations to assess options for well placement. Base case porosity, permeability, and water saturation realization was selected from multi-realizations performed in the static model which was then used for sensitivity in fluid flow simulations. Flow simulation was used to analyze the performance of the well considering horizontal wells length, well azimuth, well inclination, wells position relative to the reservoir top as well as its position relative to the water contact. In addition, multi-scenarios of well placement relative to the high permeability intervals were created to see the impact on the oil rate, plateau, and water breakthrough time. The flow simulation results show that the 4000 feet horizontal well that penetrating the upper high permeability streak gives the best performance in most of the cases. In contrast, the performance of the horizontal wells deteriorated rapidly once the well hit the lower high permeability streaks. Some producers in the studied reservoirs have been drilled using the multidiscipline study recommendation. Actual property derived from the newly drilled wells displayed a very reasonable match to the expected property from model. In addition, production test and well commissioning result also showed comparable match with what was expected from dynamic simulation.

The carbonate reservoirs lithofacies discussed in this paper contain heterogeneous pore types and properties. The challenge in predicting the distribution of the pores properties is through the technique used to construct a representative model to effectively describe the lithofacies distribution in 3D. The studied reservoirs are part of the Lekhwair and Kharaib Formations that were deposited in carbonate platform environment varied from lagoon, shoal, to ramp settings during Valanginian-Barremian age. Core and well-log data from an onshore oil field of Abu Dhabi were used to establish lithofacies distribution schemes and high resolution sequence stratigraphy (HRSS) frameworks. Twenty four lithofacies were identified based on faunal content, texture, sedimentary structures, and lithologic composition. HRSS interpretation indicated twenty one fourth-order parasequences that displayed aggradational, progradational, and retrogradational stacking cycles. A novel stochastic multirealizations modeling of lithofacies and their property distribution has been developed to characterize the subsurface complexity. The method combined depositional environment, HRSS, and diagenesis trend, and then integrated them with dynamic data to generate a holistic reservoirs characterization and representative simulation model. The workflow is as follows: Detailed core, thin section and lithofacies description;Paleoenvironmental interpretation;HRSS interpretation;Field scale stochastic modeling;Flow simulation and history match validation. Field wide reservoirs lithofacies and property distributions were modeled and constrained by the identified HRSS framework. Hybrid combination of Truncated Gaussian Simulation (TGS) and Sequential Indicator Simulation (SIS) algorithms were used. This allows generating equiprobable multirealizations of realistic lithofacies cycles and properties trend in the area. The use of lithofacies distribution provided flexibility in the modeling workflow as it offers the outline for rock properties distribution such as rock types, porosity, permeability, and water saturation. The resulting multirealizations demonstrated consistency with the conceptual scheme, outcrop analogs, and geostatistical trend. This innovative approach has recently been implemented successfully in the studied field reservoirs. The resulting dynamic model depicted a good production history match; hence it will provide reliable production forecast and reservoirs development plan.