A major numerical modelling project was performed with the objectives of develop a more robust model for development planning studies. The second was to gain a better understanding of "reservoir dynamics", in particular aquifer influx, the lateral pressure distribution and gross fluid movement within the major reservoirs of the Wara–Burgan sequence and the flow between them. The challenges and implemented solutions of history matching a reservoir model of a huge, complex field with multiple production zones, many wells and large volumes of production and surveillance data are described in the context of a recently completed study of Wara–Burgan reservoir in the giant Greater Burgan field. Additional challenges due to possible mechanical problems in wells and uncertainties in production and injection data, as usually experienced in mature fields, are also discussed. The work started with reviews of basic engineering data, previous simulation studies and the regional geology. It was the first project for this field in which modern assisted history matching (AHM) techniques were applied. The main enablers for this were increased computational resources and the availability of new generation high-performance reservoir simulators. AHM techniques were used to help better define "high level" features of aquifer properties, pressure communication and gross fluid movement within and between the main reservoir units. A large emphasis was given to matching the pressure data from RFTs and cased-hole saturation estimates. A combination of AHM and more traditional calibration methods have enabled improved models of the Wara-Burgan reservoir to be developed. These models account for the gross aspects of pressure and fluid movements in and between major reservoir units and provide a reasonable match of the performance at field, reservoir unit and gathering center (GC) levels. The use of AHM techniques and special plots to assess the quality of the pressure match have enabled better characterization on permeability levels and allowed lateral pressure gradients to be better represented. As the match was refined, issues with well histories become more apparent and the approach to dealing with these problems is discussed. Matching the apparent remaining oil distribution was facilitated by extensive tools that allowed easy comparison of simulation with both saturation estimates at wells from cased-hole logs and to interpreted saturation maps. The available workflows, simulation tools and computing environment also allowed models with different levels of refinement (4 to 28 million cells) to be used to address concerns about numerical resolution and upscaling. Base "Do-Nothing" prediction cases were also performed. These gave some insight into how sensitive prediction results would be to model calibration assumptions. Development of the current representative numerical model for the main (Wara – Burgan) reservoir of the giant Greater Burgan field has allowed the major features of pressure communication, fluid movement and current pressure and fluid distributions all to be captured in a geologically plausible setting. The approach to using very large volumes of data, including log data, in the AHM work and the novel tools used to assist visualization of match quality will be discussed.

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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.

Executive Summary Fluid characterization and mapping in the Greater Burgan field was performed using an extensive database of PVT analysis reports. This enabled an enhanced understanding of the distribution of fluids, in which a lateral compositional gradient was discovered. Summary information of 381 samples that had been acquired from 1938 to 2017 was gathered and plotted against both true vertical depth subsea (TVDSS) and spatial directions (northing and easting). Correlations of average fluid characteristics of all these samples against TVDSS and the direction in 15° north-east was determined. The API gravity, oil viscosity and solution gas to oil ratio were parameterised as a function of horizontal direction and depth. The saturation pressure was modelled using a correlation, being a function of the other variables modelled in space. Over 30 correlations published in the literature were ranked, and the best-fitting correlation was selected to predict the saturation pressure distribution spatially. All these properties were mapped by formation. This is the first study in which the existence of this lateral gradient is fully described. This work is being used as a reservoir management tool to predict zones close to or below the saturation pressure and reduce the production offtake from those zones and to develop an appropriate sampling plan. This work has also help manage access to the heavy oil zones.