The Burgan field, the second largest in the world and the largest clastic reservoir, has been in production for 66 years under primary production from natural water drive. The first phase of water injection has just begun in a small part of Burgan as a precursor to peripheral step-in water injection in the topmost Wara reservoir. Tertiary recovery schemes are being evaluated early in the life of this field with the foresight of reaping maximum benefits through early application before waterflood approaches maturity. Low salinity water (LSW) injection has been identified as a forerunner and apart from being very promising in itself; it will form an important base for the application of polymers and/or Alkaline/polymer/surfactant EOR schemes. Burgan is large enough to have a diversity that will require distinctive solutions for different areas of the field and different reservoir zones. Produced water injection started in Wara formation in 2010 at 60mbwpd with next phase of 670mbwd injection arriving in 2014 to implement peripheral injection in the flanks. This is targeting just 5% of the reserves that will need future water injection. Confidence in the LSW trial will therefore change the course of our future water injection schemes in the remaining zones. Replacing secondary with tertiary recovery schemes early will benefit not just the operating costs of the volume of water handling and disposal/injection; the overall recoveries will be higher. The eyes of the world are constantly on the health of the 2 super giants, Burgan and Ghawar. Potential benefits from EOR will have a huge impact on the extension to the life of Burgan and its strategic importance worldwide. This is the first time that KOC has taken a bold step into the field without extensive laboratory screening. As a result of taking this carefully calculated risk, KOC have soared ahead in experience on EOR in the Greater Burgan Field, within a small timeframe. The presentation will discuss the results of the LSW trial injection into 2 producers and comparisons on Sorw are made of LSW versus High Salinity produced water injection. Key learnings are shared from operating the pilot and modeling of the results. Single well tracers were used to measure the Sorw and its interpretations can be quite challenging. The tests have been analysed using five different methods. From this work, it was concluded that Low salinity water injection reduced Sorw by at least 3 s.u. (23.7% of remaining oil after effluent waterflood) in the best quality rock with the least clay content in Burgan, which would still be sufficient to make it economically attractive. Additional tests are planned for the remaining rock types in Burgan, having higher clay content and the potential for a larger change in oil saturation. Multiple models for evaluating the tracers response provide better insights to the interpretation of the Sorw. Good surveillance during the test and careful control on injection/production volumes are essential when a small response in Sorw is expected. To reduce uncertainty in the results, it is preferable to use downhole pumps rather than gas lift, control the temperature of injected water and invest in lengthy overfishing back to base brine after LSW injection.

Asphaltene deposition in the reservoir, wellbore and facilities has long been recognized as a problem in the Marrat reservoir in the Magwa field, Kuwait. One option of avoiding asphaltene problems in the reservoir, including the near wellbore region, is to maintain reservoir pressure and flowing BHPs above the asphaltene onset pressure (AOP). Given that there is a large pressure difference between AOP and the bubble point pressure and that natural flow is possible at pressure well below AOP, there may be economic benefits in operating the reservoir at pressures below AOP. Benefits relate the reduced and delayed costs of water injection facilities. There may also be some additional recovery related to fluid expansion. Potential problems relate to possible adverse changes to relative permeability due to asphaltene related wettability changes, productivity impairment due to near well-bore asphaltene deposition and increased asphaltene problems in the wellbore. The second and third of these potential problems have been assessed by a field trial. This paper describes the selection of a candidate well and the design of a field trial to assess these problems. The selected well was produced first with FBHP well above the AOP. Asphaltene deposition in the tubing was monitored, fluid samples were taken and pressure transient tests were performed to diagnose well inflow performance. No decline in well productivity was seen in this period. Asphaltene deposition in the tubing was a problem and the well required cleaning during this period. The well was then produced at high rate, with flowing BHP well below AOP and a similar surveillance program was carried out. Finally the well was returned to low rate production. Analysis of the data from the high rate and subsequent low rate production periods indicated that there had been a limited decrease in well productivity. These data also showed that asphaltene deposition in the tubing was less of a problem during the high rate test than during the preceding low rate test.

Interference testing is the oldest but still the most effective way of establishing communication between wells and determining the reservoir transmissibility. However, data can be difficult to interpret and the results can be misleading. Fortunately, simple steps can be performed to validate the data and obtain first estimates of the formation parameters. We demonstrate this methodology for an interference test performed in the Greater Burgan field in Kuwait.A pilot project was started to understand how to successfully inject water in the Wara reservoir. Seven wells were drilled in an area away from the existing wells: one injector at the center of a 250 m-radius hexagon formed by six producers. An interference test was performed between the injector and the producers. The main objective of the study was to evaluate the transmissibility between wells and the permeability anisotropy in the formation. In five of the producers, the target sands were oil bearing, whereas surprisingly, the same sands were water bearing in the sixth well. Consequently, a second objective was added to the study: to check whether the sixth well was in communication with the other wells and to determine the origin of the water.The tests showed that all wells responded to the pressure pulse, including the sixth well, thus refuting the assumption that a fault was isolating it. The fall-off analysis of all the wells highlighted the presence of boundaries, a finding that was consistent with the fluvial depositional environment. Moreover, the analysis showed that the channel was narrowing near the sixth well. Therefore, we could hypothesize that the sixth well had been drilled in a zone with perched water trapped by the channel boundaries. A few weeks after the test, the oil cut started to increase in that well, confirming our hypothesis.The findings from this pilot project proved the efficiency of waterflooding as secondary recovery method and were used to design the pressure maintenance program.

Greater Burgan is the second largest oil field and the largest clastic reservoir in the world. There are over 1000 wells on production in this field. There is a robust plan to drill more wells in the coming years to cater for world demand in production. It is therefore necessary to track and report the production and field performance from this giant field in a timely and effective manner. This paper describes the approach taken towards the development of an integrated tracking and reporting metrics tool which displays operational data to key decision makers to monitor field performance and make practical decisions.The metrics report provides a comprehensive view of the performance of an asset using key performance indicators (KPIs) in the form of a dashboard. Information is captured from corporate databases, in house tools and data sources tracking daily operations. The report is displayed graphically for quick overview of categories such as daily production, subsurface and shutin well potential, facility capacity and constraints, well work, production tests, surveillance activities, wet and dry completions, production allowables, and other pertinent highlights through a single visual interface.Designed as a scorecard the tool provides a platform for increased collaboration and knowledge capture between assets. It reduces time spent looking for data thereby allowing more time for higher priority issues. The impact is directly on the reservoir management strategies, production management, prioritization of well work and surveillance activity.The metrics report is a best practice implemented by KOC Field Development South East Kuwait Asset Group to monitor the Greater Burgan oil field performance and optimize its production. Value added decision making is made easy wherein plans are properly implemented and targets are met. The designing, completing, and operating aspects of this successful reporting tool are highlighted together with the challenges and accomplishments.

The Greater Burgan field is the largest sandstone reservoir system in the world, and its complexity requires the state of art technology for a sound reservoir management practice. This paper will discuss our methodology to maximize the production plateau length of Burgan field using parallel reservoir simulation, waterflood efficiency algorithm, streamline visualization, and ensemble-based optimization method. With a reservoir dimension longer than 48 km, parallel reservoir simulation becomes necessary for an integrated Burgan field study. Through history matching of 60-year production data, we quantified billions of barrels vertical fluid migration between major reservoir units, and fluid migration is a major concern in making reservoir management decisions. To optimize future development plans, an economic analysis package was developed to evaluate various operating scenarios, and Net Present Value (NPV) is used as an objective function. The scalability data of parallel reservoir simulation are discussed. The waterflood efficiency algorithm was based in injection efficiency or remaining oil recovery, and the input could come from finite-difference simulation, streamline simulation, and field surveillance data. The algorithm utilized the injector-producer connectivity relationship realized from streamline analysis, and it calculated the amount of water injection for each injector in order to achieve maximum sweep efficiency. The alternative method to optimize the waterflood is based on the ensemble method in which hundreds of simulation models with different operating settings are automatically submitted to run. Results of all models are gathered and analyzed by co-variance. A better setting will be proposed for each model and the next batch of simulation is then launched. At the end, all models will converge to an optimized operating setting.