Production in the Upper Burgan reservoir began in the Raudhatain and Sabriyah fields in 1959 and 1970, respectively. However, significant quantities of original oil remain in the reservoir; although the Upper Burgan fields have both been in production for more than 56 years, the offtake to date is a relatively small percentage of the potential ultimate recovery. The sandstone of the Upper Burgan is typically fine grained. Porosities average 25% and can reach 30% in the best quality sands. Horizontal permeability values of 200 to 700 md are common, with variation in vertical permeability caused by changes in the texture and structure of the reservoir. In 1995, the operator initiated a strategy to significantly increase production from these North Kuwait fields by integrating a multidisciplinary team from within the operating company. Waterflooding was part of the Upper Burgan development plan, during which the heterogeneous reservoir was expected to encounter early water breakthrough compared to other North Kuwait reservoirs. After 20 years of waterflooding in the Upper Burgan, the water cut reached 50%, and water management became crucial with reduced hydrocarbon recovery from the field. Autonomous inflow control device (AICD) technology with screens was installed in a pilot well in the Upper Burgan reservoir to help reduce the water production and increase the oil recovery from the well. AICD technology uses fluid dynamics technology to differentiate the fluids flowing through the device. When water breaks through, the AICD creates a pressure drop to restrict production flow at that device, favoring the production of the healthy oil-statured zone, thus increasing expected ultimate recovery from the well. The AICD has no moving parts, electronics, or connections to the surface and employs a unique geometry that alters the flow path within the tool upon water and/or gas breakthrough. This technology has helped improve recovery by reducing water cut from the high water-saturation zones, thereby increasing the overall oil recovery from the well. Forecasted well performance with AICD technology is in line with actual production and water cut.

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In the current and future scenario of increasing demand for hydrocarbons, Multi-Disciplinary Integrated Reservoir Management team is the key to achieve maximum production rates and ultimate recovery. In Raudhatain Upper Burgan reservoir production started in 1959 with initial reservoir pressure of 3850 psi. Decline in reservoir pressure with sustained rate of production indicated weak aquifer support and initiated water injection during the year 2001 with three flank injectors. Production rate was sustained at 30 to 35 MBOPD for long time and it was decided that to go the next level of production and to meet KOC's strategic production target. Various alternative pressures – production plans were scrutinized by the multi-disciplinary team consists of Geologists, Reservoir Engineers, Petrophysicists and Petroleum Engineers and identified bottlenecks, constraints and action plan to address the problems and to accelerate the production. Some of the bottlenecks to accelerate the production were decreasing pressure, unavailability of required volume of water for injection, delay in commissioning of effluent water injection facility and low productivity of flank wells with viscous oil. The integrated Reservoir management team initiated number of projects to increase the productivity like Paradigm shift in drilling practice by way of drilling Horizontal, Multilateral wells and completing with ICD's for better production and injection sweep efficiency. Liquidated the sick wells with no potential in any other Reservoirs (Multiple Reservoirs) are identified for Horizontal Sidetracking to sweet spot areas. Decreasing Reservoir pressure and Voidage Replacement Ratio has been addressed by changing the water injection strategy and aligning the injectors in right areas. The results were rewarding as the production rate doubled from a sustained level of 35 MBOPD to more than 70 MBOPD in a span of 3 to 4 years. The initiatives taken to convert the producers to injectors resulted in increased water injection volume and doubled the Voidage Replacement Ratio. This paper presents the details of Integrated Reservoir Management team efforts and what are the initiatives and strategic actions taken by overcoming the current constraints to double its production. It discusses the effective Reservoir Management of a mature oil field to enhance and accelerate production.

Dumpflooding from a strong Aquifer to support pressure to another depletion-drive reservoir is not new to the oil industry, neither to the region. In cases where the natural Aquifer pressure is insufficient to deliver adequate volumes to meet pressure support requirements, or the Injectivity of the target reservoir is relatively low, artificial lift is required. This was the case in the North Kuwait Asset where Injectivity was poor owing to the relatively low natural fracture density of the Carbonate reservoir being flooded.Since the conventional encapsulated (POD) systems required one (1) seal-bore packer, one (1) encapsulated ESP system, and one (1) ESP-packer, it was decided to test an alternate and simpler system that required only two (2) ESP packers that would achieve the same result.Deployment of this new tandem-ESP-packer system proved less complex and required less rig time than the encapsulated ESP system. Both packers were set simultaneously in one operation with the ESP function test to surface-pit giving excellent results. After opening the SSD's, the ESP operating parameters, measured at surface, indicated optimum pump performance at expected injection rates.The Tandem-ESP-Packer Dumpflood completion system provides fewer sealing interfaces than the conventional encapsulated ESP system, and therefore fewer opportunities for leaks. Additionally, it affords a very simple one-trip system for less complex deployment, and retrieval, when necessary. This alternate system also provides easily-deployed, immediate pressure support in areas of the reservoir/field while awaiting the installation and commissioning of major surface Injection facilities.

Raudhatain Mauddud is an oil bearing carbonate reservoir in North Kuwait. Mauddud consists of 10 layers with different fluid properties (API from 30 to 14 Deg). Oil production started in year 1957 till year 2000 when started full filed waterflood project. There was quick and clear positive response to water injection in both reservoir pressure and oil production. However there was early water breakthrough in some wells. Many factors have increased challenges in managing Mauddud waterflood project. These challenges were mainly due to reservoir heterogeneity in all layers, structure, injection of low saline water, difficulty to evaluate remaining potential in flooded wells or to identify thief zone before start the injection. Consequently, the water management strategy has been adapted by implementing methods and tools to tackle these challenges. Interwell tracers have been implemented to study and monitor water movement from the injectors to the producers and evaluate the sealing nature of the faults. Pattern x-section including Tracer, PLT and production data has been used under one page to assist in evaluating and studying water movement within the reservoir. Automated Workflow has been established to calculate VRR for each pattern. Surveillance plan has been implemented including inference tests and PBU/PFO. The injection to production connections and profiles has been modified by isolating top intervals in the injectors and drill horizontal injectors in the bottom of the reservoir. The new horizontal producer has been drilled in the top of the reservoir with advanced completion technology of ICD. Managing Mauddud Waterflood project in that way has resulted in increase of total Mauddud daily oil rate by 20% with drop in water cut from 40 to 33%. This paper is summarizing the methods that have been used to manage Raudhatain Mauddud waterflood project as best practices.