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.
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.
Reservoir simulation is one subject with different "schools of thought" for its ability to predict the future performance of a reservoir. An important topic in reservoir simulation workflow is the parameters used to achieve history-match. The non-uniqueness of history-match parameters creates an opportunity for reservoir simulation engineers and geologists to engage in collaborations that ensure geological and engineering interpretations are incorporated in history-match parameters. Simple history-match parameters are often times preferred by practitioners to complex history-match parameters. This paper will discuss Delta reservoir history-match parameters used in a 2014 reservoir simulation study which was later updated in 2016 with simplified history-match parameters. The parameters that were simplified are permeability multipliers, oil/water relative permeability and the use of Land's constant. Also, vertical grid refinement was implemented to reduce it from 8ft to 2ft to enable the simulation model reproduce the reservoir fluid distributions in the two lobes of the reservoir. With all these modifications, there were no significant differences with the wells’ static reservoir pressure and fluid saturation matches between the 2014 simulation study and the 2016 simulation update. This paper demonstrates the non-uniqueness of reservoir simulation history match parameters and the value to consider simple grid and fluid parameters’ modification before considering complex approach. With the simplified history-match parameters, the Asset Team had more confidence in the simulation result. The updated Delta reservoir simulation model was used to assess future development opportunities and identified two oil-well producers and one water injector well with EUR of 13.3 MMSTBO.
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