The objective of this paper is to show the integrated subsurface reservoir models created for high challengeable HPHT North Kuwait Jurassic (NKJ) Gas Asset. The successful story focuses on the study and modelling achievements that involved applying the appropriate method of upscaling the fine grid static model, calibrating & initializing, history matching with field observation data and finally performing a long-term production forecast. The IPSM (Integrated Production System Modelling) tool has been used to integrate all (six) fields to fill planned facilities and optimize each field forecast to get facilities production target The new history matched models and base forecast scenarios built by an integrated multi-disciplinary subsurface team of Schlumberger, Shell and KOC staff members. KOC is the focal point and the owner of these models and the asset. The new Middle Marrat static model is supported as a tool for dynamic simulation, volumetric calculation and other static model applications. Overall the model presents a number of significant improvements over previous models such as the following list of updates: Updated non-horizontal tilted hydrocarbon contact. Refined zonation and layering to capture vertical heterogeneities observed on porosity / permeability logs Modify the log upscaling method for porosity by removing the bias by facies Update the porosity using the kriging method constrained to IPSOM Correct the log upscaling method for water saturation by using the bulk volume of water Include recent well data Updated fault distribution Discrete fracture network (DFN) model was built for Middle Marrat reservoirs. The ultimate objective of the fracture modelling work is to provide full field heterogeneous fracture properties to be used in the dynamic simulation as input for history matching and forecasting. The full field DFN which has been calibrated by PTA database. The models were upscaled and initialized with different approaches such as up-gridding method (SLB workflow) and Reduce ++ application (Shell workflow) on a field by field bases. After the history match and individual development well number and location optimization by reservoir/field, the models were coupled with IPSM tool to predict the production potential of the assets at the per field and reservoir level This tool is the key enabler for asset development planning in order to achieve KOC's gas production target of 1 Bscf/d. The integrated development planning tool allows KOC to determine the number of wells and drilling rigs required to achieve this target. As there are new coming facilities for NJK fields. The integrated development tool was also used to test the gas production plateau length after start-up of the new production facilities and the gas supply of the underlying fields/reservoirs and wells.

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.