Burgan Minagish (BGMN) reservoir in the Greater Burgan field, is one of the reservoirs among others that has been producing from Minagish formation. It has been in production intermittently since 1960's though full development was delayed due to high H2S content and the need to construct sour processing surface facilities. The analysis of reservoir pressure over time indicated that the main reason of reservoir pressure decline in BGMN was production from three neighboring reservoirs producing from the same formation. This was clear as pressure decline continued for the period of 2005-2009 while Burgan-Minagish was not in production. Reservoir pressure dropped below bubble point in 2011 and made it necessary to design and implement a pressure maintenance program. This included a water injection scheme which has been implemented since 2018. In 2012, using a novel approach (Al-Faresi et al, 2012), two Fast and Slow Loop simulation models were built to model a regional aquifer and quantify flux exchange between Burgan-Minagish, regional aquifer and surrounding reservoirs. While the Fast Loop coarse model was used to match field level production and pressure data, the detailed BGMN Slow Loop model would solely focus on modeling of BGMN having incorporated the impact of neighboring reservoirs via calculated flux derived from Fast Loop model. The drawback, however, is that every time the model needs updating, a tedious and manual process must be performed to calculate flux rate across the BGMN boundaries from the Fast Loop and then incorporate it explicitly into the Slow Loop model. 10 years after the previous study, a new approach for regional aquifer modeling has been utilized to integrate two existing simulation models in a combined one that serves for both purpose of modeling the regional aquifer and surrounding reservoirs as well as history matching of high resolution BGMN model. The history matched combined model has been used to extensively evaluate BGMN reservoir production performance under different development scenarios. We have compared the results with existing two-model solution, and it is clear from the analysis that the impact of neighboring reservoirs as well as the regional aquifer is captured in the new approach. The novelty of the new approach is that it allows a seamless interaction between three surrounding reservoirs with BGMN. The unified simulation model is more convenient to use and eliminates the manual work of influx calculations. It is also more flexible and repeatable as systematic updates on both static and dynamic modeling sides for any reservoir in the area of interest could be easily implemented.
The Tayarat formation extends over a large area; this formation has a diverse and complex geology and has heavy oil fluid system. A previous review of the analogous technologies that apply to the Tayarat heavy oil formation shows that it would be economically impossible to deploy a single reservoir development technology in all the areas of the field. In this project, we evaluated cyclic steam stimulation strategies focusing on applying different well completions. We have applied a compositional numerical simulation model using CMG Stars to investigate the application of different cyclic steam stimulation strategies. This includes using a traditional vertical well with a single steam injection point in the entire zone of the reservoir. We also investigated the use of vertical wells with dual string completion, where the short string injected into the upper parts of the formation while the long string injected into the lower part of the reservoir. With the horizontal well injection, we investigated open-hole completion and the case of using a horizontal well with multi-stage hydraulic fracturing. The potential of injecting steam at a higher rate with horizontal wells is attractive and requires more investigation. Apart from reducing the well count, we could overcome the surface constraints challenge in the field by stepping out of the congested areas and placing the horizontal section in the targeted part of the formation. With the advances in horizontal wells with multi-stage hydraulic fracturing in the industry, carbonate reservoirs such as Tayarat with low permeability could benefit from more reservoirs contact and possibly better steam distribution if we introduce adequate hydraulic fracture stimulation in the formation. The results of this study show that we could reduce our drilling footprint substantially by implementing a horizontal well with multi-stage hydraulic fracture stimulation in developing parts of the Tayarat carbonate heavy oil reservoir. Cyclic steam injection with vertical wells completed with dual strings shows a production advantage over a similar vertical well completed with a single string in similar zones. At the same time, horizontal wells with multi-stage hydraulic fracturing stimulation offer marginal benefits. The risk of increased hydraulic stimulation costs could undermine the value created by horizontal drilling and completion.
The Burgan Minagish reservoir in the Greater Burgan Field is one of several reservoirs producing from the Minagish formation in Kuwait and the Divided Zone. The reservoir has been produced intermittently since the 1960s under natural depletion. A powered water-flood is currently being planned. The pressure performance of the reservoir has proved hard to explain without invoking communication with other reservoirs. Such communication could be either with other reservoirs through the regional aquifer of through faults to other reservoirs in the Greater Burgan field. Recent pressures are close to the bubble point. A coarse simulation model of the nearby fields and the regional aquifer was constructed based on data from the fields and regional geological understanding. This model could be history matched to allow all regional pressure data to be broadly matched, a result which supports the view that communication is through the regional aquifer. Using this model to predict future pressure performance suggested that injecting at rates that exceeded voidage replacement by about 50 Mbd could keep reservoir pressure above bubble point. It was recognized that the process of history matching performance was non-unique. This is a particular concern in the context of this study because the model inputs that were varied in the history matching process included aquifer data that was very poorly constrained. To address this problem multiple history matched models were created using an assisted history matching tool. Using prediction results from the range of models has increased our confidence that a modest degree of over-injection can help maintain reservoir pressure. This paper demonstrates the utility of computer assisted history match tools in allowing an assessment of uncertainty in a case where non-uniqueness was a particular problem. It also emphasizes the importance of understanding aquifer communication when relatively closely spaced fields are being developed.
The Minagish reservoir in the Burgan Field has been produced intermittently at relatively low rates since the 1960's. Full development has been delayed because of the relatively high H2S content of the reservoir fluid. A sour service production facility is now being planned. Reservoir pressure has declined over time and it has been recognized that a component of this decline is due to offset production from several other reservoirs in the area sharing an extensive common aquifer. Reservoir simulation has been used in two phases for the reservoir to assess development options as follows: The first phase of this work, the "fast loop", involved building models of the regional aquifer and producing reservoirs, developing multiple history matched models and using these models to assess the required volume of injection needed to prevent further reservoir decline. The field level history match was highly non-unique. This work identified the need to have water injection available prior to a new sour service production facility being available and to inject at above voidage rates. A more detailed "slow loop" simulation model has been developed for the Burgan Minagish reservoir following further geological, geophysical and petrophysical studies. This model has been used to perform development planning studies and, in particular, to plan water injection in the period up to the new production facilities being available. The simulation model has been used as one of the inputs to planning for reservoir management and data acquisition in this period. The integration between these two models uses a novel methodology. This paper describes how the "fast loop" and "slow loop" studies are linked so as to include the effect of the regional aquifer in conditioning the "slow loop" model to historical data, and using it for predicting future development scenarios performances.
Every field development plan should go through a ‘quantitative’ option ranking process in order to select the optimum scenario for developing that field. Doing so efficiently will help in identifying the optimum project concept for the delivery of value to Kuwait Oil Company. An example of where such a ranking process was essential was in the development plan for the Minagish Reservoir in the Greater Burgan Field. Within South-East Kuwait asset, this reservoir has to be treated ‘unconventionally’ since its Hydrogen Sulfide (H2S) concentration is high, in relation to the ability of the existing facilities to handle sour crude production. This has contributed to the low recovery factor from this reservoir which has been on production for over 50 years. Therefore, a new surface development plan for this reservoir had to be generated to assist KOC in meeting/sustaining its production targets for the year 2020 onward. The choice for optimum surface production scenario came through a ‘quantitative’ ranking process. This can be broken down into a number of separate steps: Agree to the objectives of the project and the value added to KOC.Capture production options and development concepts to meet the objectives of the project. This was done through a number of brainstorming sessions. The team involved came from several areas of the company with different backgrounds.These options were screened for viability for implementation.Agree to the ranking criteria for the project to determine appropriateness in terms of delivering value and meeting objectives.Rank each of the chosen options against the selection criteria agreed. This will provide the most appropriate concept(s) to be considered for detailed engineering. Such a ranking process was particularly useful in this case because of the number of options available and broad range of project objectives. It is recommended to consider this method for ranking options in future projects. This paper describes the facility selection process implemented for the Minagish reservoir development plan.
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