The current work is intended to show the application of a multiple realization approach to produce a strategic development plan for one of the mines in Karaganda coal basin. The presented workflow suggests using a comprehensive reservoir simulator for a history matching process of a coal pillars on a detailed 3D grid and application of sensitivity and uncertainty analyses to produce probabilistic forecast. The suggested workflow significantly differs from the standard approaches previously implemented in the Karaganda Basin. First, a dynamic model has been constructed based on integrated algorithm of petrophysical interpretation and full cycle of geological modeling. Secondly, for the first time in the region, dynamic modeling has been performed via a combination of history matching to the observed degassing data and multiple realization uncertainty analysis. Thirdly, the described model parameters with defined range of uncertainty has been incorporated into the forecasting of degassing efficiency in the mine using different well completion technology. From the hydrodynamic modeling point of view, the coal seam gas (CSG) reservoir is presented as a dual porosity medium: a coal matrix containing adsorbed gas and a network of natural fractures (cleats), which are initially saturated with water. This approach has allowed the proper description of dynamic processes occurring in CSG reservoirs. The gas production from a coal is subject to gas diffusion in coal micropores, the degree of fracture intensity and fracture permeability. By tuning these parameters within reasonable ranges, we have been able to history match our model to the observed data. Moreover, application of an uncertainty analysis has resulted in a range of output parameters (P10, P50, and P90) that were historically observed. Performed full cycle of CSG dynamic modelling including history matching, sensitivity, and uncertainty analyses has been performed to create a robust model with the predictive power. Based on the obtained results, different optimization technologies have been simulated for fast and efficient degassing through a multiple realization probabilistic approach. The coal reservoir presented in this work is characterized by very low effective permeability and final degassing efficiency depends on well-reservoir contact surface. The decrease of the well spacing led to a proportional increase of gas recovery which is very similar to unconventional reservoirs. Therefore, vertical and horizontal wells with hydraulic fractures have been concluded the most efficient way to develop coal seams with low effective permeability in a secondary medium.

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The Greater Burgan Field is located in southeastern Kuwait, covers a surface area of about 800 square kilometers and is ranked as the largest clastic oil field in the world. The field comprises six main reservoir units, namely Wara Sand, Mauddud Limestone, Burgan Sand Upper, Burgan Sand Middle, Burgan Sand Lower and Burgan Fourth Sand, stacking on top of each other. The Wara Shale acts as a barrier separating Wara from the massive sands of the underlaying Burgan formation. However, extensive faulting does allow communication between the Wara and the Burgan Sands. Production was initiated from the Greater Burgan Field in early 1946. As the field has matured over time, the reservoir pressure has declined in certain areas, with associated reduced productivity. The reduction of wells’ productivity, combined with the increasing water production, has necessitated improved oil recovery (IOR) initiative in order to support the Kuwait Oil Company (KOC) 2030 strategy, sustaining a corporate target oil rate and ensuring high recovery from Burgan reservoirs. This paper describes the modeling effort in designing the Wara Pressure Maintenance Project (WPMP). The WPMP is the first major full-scale waterflood project implemented in the Greater Burgan field. The management decision was based on the fact that Wara has experienced significant pressure decline after 68 years of primary production. Weak edge water drive, combined with poor reservoir connectivity, has resulted in deteriorating productivity along with creating secondary gas caps in some areas. In 2005, design for a pressure maintenance project (PMP) 2 via a peripheral waterflood was initiated to arrest pressure decline and improve oil recovery. Indeed, it became a major component of the Greater Burgan Field Development Plan (FDP) and is now entering the operation stage after 10 years of planning and facility construction. The Greater Burgan FDP is supported by a massive sub-surface modeling project. It started in 2009 with the sequence stratigraphy model (Phase-1) followed by geological model (Phase-2) 6 and dynamic model (Phase-3) 9. All modeling projects were conducted by reputable consulting firms with significant KOC hands-on participation and project management. The three modeling phases were concluded in 2013 and a simulation prediction model has been developed as a premium FDP reservoir management tool. In this paper, we focused on the modeling of the WPMP which was built meticulously and comprehensively to produce an optimal development and operation strategy. This includes project phasing, waterflood pattern design, producer/injector locations, drilling sequence, polygon setup for voidage replacement ratio (VRR) control, and constraints for good reservoir management practice. Sensitivity on constrained and unconstrained cases was included to evaluate future facility requirement. All in all, a robust simulation model to optimize Wara waterflood performance and ultimate recovery.

The case study describes a modeling and simulation study of an inverted ESP completion to address three fundamental objectives. A) Increasing the ultimate oil recovery in the massive sands of Cretaceous age in Greater Burgan field by managing water production B) Mitigating the rapid water coning conditions in this high permeable water drive reservoir and C) Designing an optimal operating strategy with Downhole Water Sink (DWS) to control water production and manage well performance. A 2×2km sector was carved out from the full field geological model with 12 wells including the study well. The study well was producing at high water cut at the time of the study. All static properties were updated, and the model was history matched for production, pressure and saturation. Several sensitivity runs were performed, and prediction scenarios were run for 5 years to observe well production behavior in time. The well model was setup with an inverted ESP between straddle packers to produce water from below OWC and inject into bottom reservoir with a production string above to produce from the oil zone. This setting ensured a reverse oil cone being generated from below OWC in the reservoir under production. The aquifer model was finite in size enabling bottom water influx. Simulation results showed that implementation of DWS technology made the water production reduced by 18% during five years with an increase in oil production of nearly 25% in the study well. To maintain continuous well offtake rate, a range of water rates to be produced and injected to bottom reservoir have been studied. Several iterative runs were made to investigate the best completion interval and injection & production rates. The profiles of oil water interface near well bore indicated good reduction in the cone height as compared to normal completion. The results also showed significant improvement in oil recovery within the drainage radius of the well from the simulations. Simulation results provided good understanding of the saturation change near well bore area under different production rates. Prediction runs were made for sustainable oil production under natural flowing condition and the conditions to switch over to production under artificial lift. Production of thin layers of remaining oil from within high permeable massive Burgan middle sands has been a high concern due to very high water cuts because of coning. The study results have provided encouraging option with DWS technique to improve recovery from the reservoir.