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.
Gomez, Ernest (Schlumberger) | Al-Faresi, Fahad A. Rahman (Kuwait Oil Company) | Belobraydic, Matthew Louis (Schlumberger) | Yaser, Muhammad (Schlumberger) | Gurpinar, Omer M. (Schlumberger) | Wang, James Tak Ming (Schlumberger) | Husain, Riyasat (Kuwait Oil Company) | Clark, William (Schlumberger) | Al-Sahlan, Ghaida Abdullah (Kuwait Oil Company) | Datta, Kalyanbrata (KOC) | Mudavakkat, Anandan (KOC) | Bond, Deryck John (Kuwait Oil Company) | Crittenden, Stephen J. (KOC) | Iwere, Fabian Oritsebemigho (Schlumberger) | Hayat, Laila (KOC) | Prakash, Anand (KOC)
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.
Brown, Alan Lee (Schlumberger Carbon Services) | Berlin, Eric Hamilton (Schlumberger) | Butsch, Robert John (Schlumberger) | Senel, Ozgur (Schlumberger) | Mills, Joseph | Harichandran, Arutchelvi | Wang, James Tak Ming
The onshore area of the Northeastern United States is lacking in reservoir intervals appropriate for storing large volumes of carbon dioxide (CO2). It is proposed that the geologic conditions found offshore of the Eastern Seaboard are conducive to the safe storage of large volumes of CO2 generated from anthropogenic activities in the region (Schrag, 2009). Little subsurface investigation has occurred in this area since it was initially explored for hydrocarbons in the mid-1970s. Can newer data evaluation techniques be applied to older data to ascertain the CO2 storage potential of the Atlantic Outer Continental Shelf?
Schlumberger Carbon Services recently performed an initial site evaluation of storage potential for CO2 within the Cretaceous intervals near the Baltimore Canyon Trough utilizing vintage wireline, core, and 2D seismic data to develop a geocellular model to simulate CO2 injection and storage. The evaluation site is centered approximately on the COST B-2 well, located about 70 miles offshore of New Jersey and drilled as a stratigraphic test in 1976. The COST B-2 well and others drilled in the late 1970s and 80s penetrated a Lower Cretaceous interval abundant in channel and mouth-bar sands deposited in a wave-dominated delta-front to nearshore depositional environment. Petrophysical analysis of available wireline data indicates these sands exhibit porosity and permeability ranges adequate for the potential injection of CO2. Additonally, log analysis indicates laterally extensive and vertically thick marine shales overly these potential reservoir intervals and provide an appropriate seal across the region. This petrophysical analysis was integrated with interpretations from available two dimensional seismic lines to investigate the spatial potential of the targeted sediments to store large volumes of injected CO2.