Full-Field Parallel Simulation Model: A Unique Tool for Reservoir Management
of the Greater Burgan Oil Field

Ambastha, A.K.; Al-Matar, Dawood; Ma, Eddie; Kasischke, William

doi:10.2523/102281-ms

Cited by 3 publications

(3 citation statements)

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“…• An improved full field Burgan simulation model with 2 times the overall grid density compared to the previous model of Ambastha et al [3] has been developed. The result was a sound full-field reservoir simulation model that demonstrated a good match of the production, pressure and saturation histories, and allowed reliable forecasting of oil recovery under different development scenarios.…”

Section: General Observations and Conclusionmentioning

confidence: 99%

Reservoir Simulation Modeling of the World

Ryzhov

Gheorghiu

et al. 2014

All Days

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The Greater Burgan field in Kuwait is the largest clastic oil field in the world. Its sheer size, complex geology, intricate surface facility network, over 2,200 well completions and 65-years of production history associated with uncertainty present formidable challenges in reservoir simulation. In the last two decades, many flow simulation models, part-field and fullfield, were developed as reservoir management tools to study depletion plan strategies and reservoir recovery options. The new 2011 Burgan reservoir simulation effort was not just another simulation project. Indeed, it was a major undertaking in terms of technical and human resource. The model size, innovative technology, supporting resources, integrated workflows and meticulous planning applied to this project were unprecedented in the history of the Greater Burgan field development.The quest began in 2009 with the construction of a Structural and Stratigraphic model, followed by Static modeling in 2010 and Dynamic modeling in 2011. Early dynamic model startup allowed integration between the static and dynamic modeling teams which resulted in a geological model suitable for reservoir simulation.This paper describes work done to prepare a representative numerical model which could be utilized to optimize the remaining life of the reservoir complex. Right from the onset, representative numerical modeling concerns were identified. These led to a systematic collaboration framework being built in place between the static and dynamic modeling teams. Calibration of the model to the historical observations was executed at three levels, Global, Regional and Wells -the Cascade Approach. The cascade approach was designed to enable a concerted model calibration effort in accordance with the recurrent data quality. For instance, while the total field production history attains a high degree of accuracy, the data at the regional Gathering Center (GC) is of a lower level of certainty, but far more reliable than the data at an individual well. Commercial modeling software have been utilized extensively to produce several utilities such as water encroachment maps, Repeat Formation Tester (RFT) matching tools and aquifer definition and adjustment workflows. Subsequently, synergy in the integrated use of these tools produced a robust model calibration process on all three levels in the cascade approach.The second part of the project was to develop a predictive simulation model to be used as a reservoir management tool to forecast and evaluate reservoir development options for ultimate recovery. Check-point prediction models were defined and constructed at regular intervals during the model calibration phase. This approach allowed qualitative assessment on the evolution towards a representative numerical model. Furthermore, it allowed synchronizing simulation workflows and expedited project deliverables. The overall result was a sound full-field reservoir simulation model that achieved a good match of production, pressure and saturation histories, leading to reliable f...

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Section: General Observations and Conclusionmentioning

confidence: 99%

Reservoir Simulation Modeling of the World

Ryzhov

Gheorghiu

et al. 2014

All Days

Self Cite

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show abstract

“…The result was a sound full-field reservoir simulation model that demonstrated a good match of the production, pressure and saturation histories, and allowed reliable forecasting of oil recovery under different development scenarios.  An improved full field Burgan simulation model with 2 times the overall grid density compared to the previous model of Ambastha et al [3] has been developed. This prediction model is suitable for KOC Asset Action Plan work, which generates various reservoir development options to meet Burgan field target production rate.…”

Section: General Observations and Conclusionmentioning

confidence: 99%

Meeting the Challenge of Reservoir Simulation in the World's Largest Clastic Oil Field - The Greater Burgan Field Complex, Kuwait

Ryzhov

Gheorghiu

et al. 2013

Day 1 Mon, September 30, 2013

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The Greater Burgan field in Kuwait is the largest clastic oil field in the world. Its sheer size, complex geology, intricate surface facility network, over 2,200 well completions and 65-years of production history associated with uncertainty present formidable challenges in reservoir simulation. In the last two decades, many flow simulation models, part-field and fullfield, were developed as reservoir management tools to study depletion plan strategies and reservoir recovery options. The new 2011 Burgan reservoir simulation effort was not just another simulation project. Indeed, it was a major undertaking in terms of technical and human resource. The model size, innovative technology, supporting resources, integrated workflows and meticulous planning applied to this project were unprecedented in the history of the Greater Burgan field development. This paper describes work done to prepare a representative numerical model which could be utilized to optimize the remaining life of the reservoir complex. Right from the onset, representative numerical modeling concerns were identified. These led to a systematic collaboration framework being built in place between the static and dynamic modeling teams. Calibration of the model to the historical observations was executed at three levels, Global, Regional and Wells -the Cascade Approach. The cascade approach was designed to enable a concerted model calibration effort in accordance with the recurrent data quality. For instance, while the total field production history attains a high degree of accuracy, the data at the regional Gathering Center (GC) is of a lower level of certainty, but far more reliable than the data at an individual well. Commercial modeling software have been utilized extensively to produce several utilities such as water encroachment maps, Repeat Formation Tester (RFT) matching tools and aquifer definition and adjustment workflows. Subsequently, synergy in the integrated use of these tools produced a robust model calibration process on all three levels in the cascade approach.The main goal of the project -development of a predictive simulation model, always remained at the fore of the project team's mind during the model calibration. Check-point prediction models were defined and constructed at regular intervals during the model calibration phase. This approach allowed qualitative assessment on the evolution towards a representative numerical model. Furthermore, it allowed synchronizing simulation workflows and expedited project deliverables. The overall result was a sound full-field reservoir simulation model that achieved a good match of production, pressure and saturation histories, leading to reliable forecasting of oil recovery under different development scenarios.

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“…Coupled with this is the large data management problem which discourages the practitioner to use this method. For these huge cases (multi-million cell models), there are large number of papers in literature highlighting the various approaches and techniques that can be used to solve the problem such as that by Williams et al 5 , Ambastha et al 6 , etc. to name a few.…”

Section: Introductionmentioning

confidence: 99%

Insights From History Matching and Forecasting Work for a Steeply-Dipping, Faulted Volatile Oil Reservoir

Kaul

Ambastha²,

Eme³

et al. 2013

Day 1 Mon, September 30, 2013

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History matching and subsequent forecasting work becomes a challenging task if limited supporting production data is available and the reservoir is severely depleted. For an offshore, volatile-oil reservoir, added to this challenge was an uncertainty in fluid PVT, where the data clearly suggested presence of condensate, but with black-oil properties. The permeability distribution from logs was counterintuitive to the production data from the wells. The reservoir had a structural relief in excess of 1000 ft., most likely having API gradient, but both the API and the GOR data indicated that there were possible errors in measurement. There was uncertainty associated with original oil-water contact also. The production data showed the reservoir to follow primarily a classical solution gas-drive response, but simple material balance analysis proved a weak aquifer effect as well.The approach followed in simulation was the process of elimination. Pressure match was first achieved, but questions remained about its robustness around the main sealing fault. GOR was targeted next and several different condensates and one full compositional fluid model of a nearby reservoir were unsuccessfully tested. For matching the historical gas production, a new high condensate yield fluid PVT was used. The idea of another oil-water contact (OWC) was tested in the saddle of the reservoir to account for most likely early water breakthrough in a well there. The secondary gas cap formation and its effects were crucial in achieving satisfactory history match.The confidence in the history match, as having captured the physics of the flow, led to forecasting scenarios which were not possible with a black-oil model. Most of the data was found not to be erroneous. What was needed was judicious data interpretation to achieve satisfactory history match. To produce these kinds of depleted, faulted reservoirs further, a strategy to better manage the evolution of secondary gas cap was of utmost importance.

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Full-Field Parallel Simulation Model: A Unique Tool for Reservoir Management of the Greater Burgan Oil Field

Cited by 3 publications

References 0 publications

Reservoir Simulation Modeling of the World

Reservoir Simulation Modeling of the World

Meeting the Challenge of Reservoir Simulation in the World's Largest Clastic Oil Field - The Greater Burgan Field Complex, Kuwait

Insights From History Matching and Forecasting Work for a Steeply-Dipping, Faulted Volatile Oil Reservoir

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