The Wara reservoir is one of the four main reservoirs in the Greater Burgan field, the world's largest sandstone oil field. It has experienced significant pressure decline after 60 years of primary production. In 2005, design for a pressure maintenance project (PMP) via a peripheral waterflood was initiated to arrest pressure decline and improve oil recovery. A key building block of the Wara PMP is a stand-alone, full-field Wara simulation model. The 23-million cells geological model was scaled-up to 4 million cells for flow simulation. Four pseudo layers were added to the simulation model to allow fluid migration via faults from the lower reservoirs. The new model has 100 m x 100 m areal cells and individual layers with an average thickness of 6 ft. Overall, this new model has 18 times refinement compared to the previous model for the Wara reservoir. Thus, this model is suitable for evaluating PMP, infill drilling and pattern waterflood. This paper, however, focuses on PMP evaluation only carried out over the last four years. The final history-match has been carried out at three levels: Field, Gathering Centers (GC) and Key Wells. Detailed study of interactions among field permeability distribution, edge aquifer representation, and fault transmissibility specifications on simulation results was key in developing a meaningful history-match. PNC data for many wells around the periphery of the field provided useful insights for edge aquifer representation. Water cut match was less than satisfactory for wells located in the center due to modeling deficiency of pseudo layers as discussed in the body of the paper. Prediction runs have been set up to investigate various PMP designs. These runs include sensitivity with respect to number of injectors, number of producers, target injection rate per well, maximum bottom-hole injection pressure, voidage replacement ratio, injector-producer distances, and injector-producer rows along with various scenarios for dealing with production from existing Wara producers throughout the field. This flow simulation model will be used as an operating model to optimize process design and well location. Introduction Greater Burgan, which is located in southeastern Kuwait, covers a surface area of about 320 square miles and has been ranked as the largest clastic oil field in the world. The four main reservoir units comprising the Greater Burgan Field complex are the Wara, Mauddud, Burgan Third Sand and Burgan Fourth Sand. The Greater Burgan Field is separated into three producing areas, Burgan, Magwa and Ahmadi. No structural, geologic or reservoir features distinguish these areas, although PVT differences are assigned for areas north and south of the Graben fault. The Wara and Mauddud reservoirs are separated vertically from the remaining reservoirs by extensive carbonate and shale intervals. However, extensive faulting does allow communication between the Wara sand and the Burgan Sands. Wara reservoir has an average thickness of 160 ft and historically, 336 wells have produced from the Wara reservoir at one time or another.

The Mauddud reservoir in the Greater Burgan field is a thin, carbonate reservoir containing light oil in a 10 to 20-feet (ft) target zone with "good" porosity. Matrix permeability is low, and natural fracture density can be variable in this reservoir. Thus, this reservoir must be exploited using horizontal wells. In the early 1990s, 16 horizontal wells were drilled in this reservoir. Five more horizontal wells have been drilled in 2005 and 2006 in an effort to scope out the long-term potential of this reservoir. However, only three of these five new wells had a production history of a few months that could be used in our history-matching effort. Thus, the history-matching effort concentrated on 19 wells (16 old plus 3 new wells).In conjunction with the drilling of recent horizontal wells, a comprehensive reservoir characterization program culminating into a full-field reservoir simulation model has been completed. The 24-million cell geological model was scaled up to a 9-million cell model at a 164-ft by 164-ft areal grid level to properly incorporate flow characteristics of horizontal wells into the simulation model. Matrix permeability of the scaled-up model was enhanced by using a unique process based on analytical solutions for short fractures and fracture density/orientation mapping for the entire field. This reservoir simulation model has been historymatched for the 13-year production history of 16 1990s horizontal wells along with a production history of a few months for 3 new wells using only a global-permeability multiplier and water relativepermeability curve shape modification. This model has been used in the forecast mode to assess long-term field development opportunity for the Mauddud reservoir. Primary depletion results show that horizontal wells drilled in an intelligent manner in this difficult reservoir hold the key to economic development of this reservoir.

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The Third Sand Upper (3SU) is one of the three sub-reservoirs in the Third Sand of the Greater Burgan field, the world's largest sandstone oil field. Initial oil production begun in 1948 and 3SU field development has not been aggressive due to its poor reservoir quality and productivity. After 60 years of primary production, only 7.5% recovery has been achieved. Infill drilling was identified as a key development strategy in 3SU. In 2008, a simulation study was initiated to investigate infill drilling potential and its impact on production and recovery. We opted for a sector model mainly due to practicality and time constraint. The 780,800 cells sector geological model was scaled-up to 421,632 cells for flow simulation. Due to the sand-to-sand contact with the lower Burgan sands, it is imperative to include these reservoirs in the model to achieve proper energy balance. Accordingly, four pseudo layers were added to the simulation model to allow fluid migration from the lower reservoirs. The 3SU sector simulation model has 100m × 100m areal cells and individual layers with 4–6 feet thickness. Overall, the sector model has 30 times refinement compared to previous 3SU models (Ambastha et al, 2006). The history match has been carried out for 37 3SU historical wells with 60 years of production history. Detailed study of interactions among field permeability distribution, aquifer strength, fluid migration and fault transmissibility specifications on simulation results was key in developing meaningful history match. Water cut match was less than satisfactory for wells located in the dome area due to modeling deficiency introduced by the pseudo layers. Three infill drilling spacing scenarios were set up to evaluate prediction performance of 800-meter, 400-meter and 200-meter well spacing. Results of the 50-year prediction runs indicated that an incremental recovery of 11% can be achieved by reducing the current well spacing of 800-meter to 400-meter. Introduction Greater Burgan field, which is located in southeastern Kuwait, covers a surface area of about 320 square miles and has been ranked as the largest clastic oil field in the world. The four main reservoir units comprising the Greater Burgan Field complex are Wara, Mauddud, Burgan Third Sand (3S) and Burgan Fourth Sand (4S). The massive 3S is further subdivided into Third Sand Upper (3SU), Third Sand Middle (3SM) and Third Sand Lower (3SL). The 3SU reservoir is sandwiched by a tight Mauddud formation above and a permeable 3SM sand below. Figure 1 shows the corss-section of the major reservoir-horizons in the Greater Burgan field. 3SU reservoir communication occurs mainly through sand-to-sand contact with 3SM but extensive faulting also allows communication between Wara, Mauddud, 3S and 4S reservoirs. The Greater Burgan Field is separated into three producing areas, Burgan, Magwa and Ahmadi. No structural, geologic or reservoir features distinguish these areas, although PVT differences are assigned for areas north and south of the Graben fault. Figure 2 shows the areal view delineating these 3 areas. Initial 3SU production begun in early 1948. Despite of its significant STOOIP, 3SU has not been a dominant producer due to its inferior productivity. Overshadowed by the prolific 3SM reservoir, 3SU development has not been the priority and its potential was not fully assessed. In 2007, Kuwait Oil Company (KOC) has started revitalization of several low priority reservoirs in order to achieve the corporate production growth by 2020. In 3SU reservoir, two new wells were drilled in 2008 and 2009 to evaluate the performance of infill drilling. At the same time, a 3SU sector model was built to investigate the incremental recovery of infill drilling. This simulation effort was carried out by the KOC Greater Burgan Studies team with consulting assistance from Schlumberger.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractNine multi-million cell geostatistical earth models of Marrat reservoir in Magwa field of Kuwait were upscaled for streamline screening in FRONTSIM and flow simulation using ECLIPSE.The scale-up strategy consisted of (1) maintaining square areal blocks over the oil column, (2) upscaling to the largest areal block size (200m x 200m) compatible with 125 acre well spacing, (3) upscaling to less than a million grid blocks for FRONTSIM streamline screening, and (4) upscaling to less than 250,000 grid blocks for ECLIPSE flow simulation. GOCAD-SCP program was utilized for scale-up. SCP employs a single-phase flow-based process for upscaling nonuniform 3D grids. Several iterations of scale-up were made to optimize the result.Sensitivity tests suggest that a uniform scaled-up grid overestimates breakthrough time compared to the fine model and the post-breakthrough fractional flow also remains higher than the fine model. However, preserving high flow rate layers in a non-uniform scaled-up model was key to match the front tracking behavior of the fine model. The scaled-up model was coarsened in areas of low average layer flow since less refinement is needed in these areas to still match the flow behavior of the fine model. The final ratio of pre-to postscaleup grid sizes was 6:1 for FRONTSIM, and 21:1 for ECLIPSE.Several checks were made to verify the accuracy of scaleup. These include comparison of pre-and post-scaleup fractional flow curves in terms of break through time and postbreak through curve shape, cross-sectional permeabilities, global porosity histograms, porosity-permeability clouds, visual comparison of heterogeneity, and finally earth model and scaled-up volumetrics.The scaled-up models were screened using FRONTSIM 3D streamline technique. The results helped in bracketing the flow behavior of different earth models and evaluating the model that better tracks the historical performance data. By initiating the full-field history matching process with the geologic model that most closely matched the field performance in the screening stage, the amount of history matching was minimized and the time and effort required reduced. The application of unrealistic changes to the geologic model in order to match production history was also avoided.The study suggests that single realizations of "best guess" geostatistical models are not guaranteed to always offer the best history match and performance prediction. Multiple earth models must be built to capture the range of heterogeneity and assess their impact on reservoir flow behavior.