The Material Balance method is a good analytical tool for assessing and understanding energy balance and connectivity of reservoirs. This method was used to investigate the effect of water injection in a target reservoir and pressure response in the target reservoir and an adjacent reservoir in Okan field.Water injection was initiated in two adjacent reservoirs (Reservoir "A" and Reservoir "B") in Okan Field in year 2002 with wells A1_Inj and B1_Inj respectively. Another water injector (Well A2_Inj) was completed in Reservoir "A" in year 2008 to provide further pressure support for the reservoir. Analysis showed that the water injection in Well A2_Inj was not providing pressure support to Reservoir "A" as expected. In addition an unexpected reservoir pressure increase was observed in Reservoir "B" from year 2008. It was suspected that Well A2_Inj was injecting out of zone and there was contemplation to cut-back water injection in the well and allocate the water injection to other injectors in the field.
The classical Material Balance equation (F = N*Et + We) is a zero-dimensional reservoir modeling methodology that is used to estimate original oil-in-place volume (N), gas cap size, and aquifer influx (We). The material balance equation is a single equation with many unknowns (e.g. N, m, We); thus the solution to the equation is inherently non-unique. In other words a range of original oil in place (STOOIP) gives good match of the material balance equation. The range of STOOIP solutions of the material balance equation is often too high. In this paper a methodology is suggested for reducing the uncertainty in the material balance derived STOOIP values. In the proposed methodology, the material balance equation is further constrained by history matching the average fluid contacts in the reservoir. Three case studies were used to illustrate the application of material balance and fluid contact match in STOOIP estimation. The first case study is a synthetic reservoir with a STOOIP of 100 MMBO, initial gas cap and aquifer influx. The result shows that solving only the material balance equation gives a very wide range of STOOIP of 80 - 300 MMBO, while including the fluid contact match reduced the STOOIP range to 80 – 125 MMBO. The second case study is a real reservoir with initial gas cap and aquifer influx. Using material balance alone the STOOIP range was 80 – 800 MMBO whereas including the fluid contact match gave a lower STOOIP range of 100 – 120 MMBO. The last case study also shows a reduction in the range of STOOIP estimation from 50 - 500 MMBO for solving the material balance equation alone to 90 - 120 MMBO when the fluid contacts are history matched. These case studies show that uncertainty in the material balance STOOIP estimates are greatly reduced by matching fluid contacts.
This paper summarizes the strategy adopted in the development of two thin oil rim reservoirs in Okan Field, Offshore Niger Delta, Nigeria. Its objective is to elucidate the strategy, engineering analyses, subsurface assessment and production procedures set in place to optimally develop the reservoirs. Both reservoirs have oil thickness of <30 ft with gas thickness of >100 ft. The adopted development strategy for the two reservoirs involves the drilling of 4 wells, 2 in each reservoir, to drain the remaining oil reserves, prior to gas development. Because of structural and fluid contact uncertainties, soft landing was incorporated into the well designs. Shale-to-shale correlation was used for accurate horizon depth prediction and detailed simulation models with local grid refinements were employed to determine optimum well orientation, landing depth, lateral length and aquifer properties. Details on their use to maximize value are shared. While drilling, Azithrak™, a Baker Hughes tool, was used in geosteering the lateral well section to determine distance of well to nearest conductive zone as part of the oil-water contact tracking. All available data - logs, cuttings, reservoir pressures and production data - was incorporated and used to validate fluid contacts data because of the impact of landing depth relative to the fluid contacts on oil recovery. Simulation results and operational constraints were used to set acceptable production limits to ensure delivery of target reserves. All the four wells have been successfully drilled and completed, with the wells landed successfully within the thin oil column, at the optimized distance from the fluid contacts, with the wells producing at <0.55 percent water cut. Initial production performances of the four wells are in line with static and dynamic assessment forecasts. Lessons learned and challenges encountered during this development are also captured in this paper.
Reservoir simulation history match was recently carried out for the A7 reservoir located in the Niger Delta. The A7 reservoir is divided into two compartments ("Main" and "West") by a fault ("Center Fault") such that at initial conditions, the compartments have common Original Oil Water Contact (OOWC), but different Original Gas Oil Contact (OGOC). The difference between the OGOC of the two fault block is 24ftss. One well ("Well-A7") has produced from the reservoir in the West compartment. Well-A7 has been on production for nine years with three distinct produced GOR periods: Low-GOR, Mid-GOR and High-GOR periods. Initial attempt to history match the performance of Well-A7 by assuming that the Center Fault was completely sealing resulted in the inability to match the Mid-GOR and High-GOR production periods. Consequently, the sealing potential of the Center Fault was further analyzed in detail. Examination of the Center Fault shows that the Main and West compartments have sand-to-sand juxtaposition in part of the gas zone; with the pressure difference between the gas zones of the two compartments at initial condition estimated at about 8 psi. This implies that the threshold pressure of the Center Fault was greater than 8 psi. Thus, it was presumed that the Center Fault was sealing at initial condition, but became non-sealing at dynamic condition when the pressure difference between the two compartments exceeded the capillary threshold pressure of the Center Fault. Results/Conclusion The GOR, water cut, shut-in-bottom-hole-pressure and flowing-well-pressure were history matched for Well-A7. Several history-match parameters were identified prior to history matching, but the parameters that had the most significant impact on history matching were the transmissibility and threshold pressure of the Center Fault. Good quality history-match was obtained with a fault threshold pressure of 25 psi. Some forecast results using this history-matched model are also presented.
A comprehensive reservoir simulation study was recently carried out for the A4 reservoir located in the Niger Delta. The A4 reservoir is divided into two fault blocks (Main and West) that are connected in the down-dip part of the reservoir both in the oil leg and aquifer. Original Oil-Water Contact (OOWC) was logged in the reservoir, but no Original Gas-Oil Contact (OGOC) was logged by the wells that penetrated the reservoir. Thus, there existed uncertainty in the OGOC from the Highest Known Oil (HKO) to the crest of the reservoir. During the period of the simulation project, two oil producers (A4-1p and A4-2p) were producing from the Main Block, while one water injector (A4-1i) was providing pressure support. Two additional oil producers were then being planned to increase the recovery from the reservoir. One of the wells was planned to be drilled up-dip of the existing two producers in the Main Block, while the other well was planned to drain the West Block. Base model deterministic history-match and sensitivity studies were conducted to gain insight into the reservoir performance and parameters that affect history match, especially the OGOC. Then, probabilistic history-matching was carried out to assess the full range of uncertainties of the different history-match parameters with special consideration to the OGOC. Probabilistic history-matching shows that the P10 OGOC for the Main Block is about 24ft shallower than the HKO, which was also supported by the base deterministic model. The simulation models were then used to forecast the performance of the two additional planned development wells to validate the planned landing depth of the completions. The two additional development wells were drilled and brought online. Initial test results from the new development wells were consistent with the pre-drill base deterministic simulation predictions.
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