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.
The United States Geologic Survey (USGS) reported in 2008 that undiscovered technically recoverable oil in the Bakken was about 3.6 billion barrels across the U.S. portion of the basin, considering recent successful application of horizontal wells and multistage hydraulic fracturing technologies. As the development of the unconventional resources in the Williston Basin continues beyond the phases of exploration and lease evaluation, optimum well spacing and recovery factor will become forefront considerations in the formulation of asset development strategies. Based on our studies the reservoir producing mechanism is primarily solution gas drive and primary oil recovery factor is lower than 15% of the original oil in-place. This low recovery or very high oil volume remaining in place is a strong motivation to investigate the application of enhanced oil recovery methods in this basin.
This paper describes the construction of numerical simulation models using typical fluid and rock properties for the Bakken and Three Forks, assuming both naturally fractured and single porosity systems and their combinations. Multistage hydraulic fracture properties are determined from well completion engineering and coupled with the flow models. The flow models are constrained by well operating practices implemented by operators across the basin during primary oil production.
The results of pressure maintenance methods to arrest the rapid reservoir pressure decline due to large pressure drawdown necessary to produce oil and water, as well as gas (including carbon dioxide) and water injection methods to improve oil recovery are presented.
Cherian, Bilu Verghis (Schlumberger) | Stacey, Edwin S. (Petro-Hunt LLC) | Lewis, Ray (Petro-Hunt LLC) | Iwere, Fabian Oritsebemigho (Schlumberger) | Heim, Robin Noel (Schlumberger) | Higgins, Shannon Marie (Schlumberger)
This paper presents a closed-loop reservoir study in tight gas fluvial sands of the giant Jonah gas field located in the northwestern part of the Greater Green River Basin, Wyoming. It produces gas from the micro-darcy fluvial channel sandstones of the Upper Cretaceous Lance Formation after multistage hydraulic fracturing. Single sand body pay zones would not be commercially attractive.
Rigorous reservoir modeling and simulation workflows were employed to build a 3D flow model from geology, geophysics, petrophysics and engineering data and interpretation. The stacked, multi-pay, tight gas sandstone reservoirs and their overpressured conditions were modeled and the hydraulic fractures properties were derived from matching initial well performance. The model was calibrated with well and field performance data through 2006. The calibrated model was used to forecast well performance, estimate reserves; investigate optimal well spacing and infill-well patterns.
Production for old wells and infill wells completed during 2007 and 2008 which was not included in the model calibration is compared with our previously forecasted results. The comparison shows that the actual well production of most of the wells is close to our forecasted results. The production-validated results of this closed-loop study clearly demonstrate that well production and field performance can be forecasted using reservoir modeling and simulation in a highly heterogeneous reservoir. Rigorously-constructed reservoir model(s) help us test and determine optimal production techniques to maximize field production goals. It can be confidently used to reduce field development risk and maximize profits.
Conceptual models are used to solve specific problems in selected sectors of reservoirs; study production mechanisms; understand behavior of a particular process in a reservoir system, and assess impacts of changing input parameters during reservoir modeling. They are tools of choice for assessing risks, evaluating "worst-case" scenarios, validating analyst's intuition, and to support informed decision making. Our objective is to demonstrate via two case studies how conceptual numerical models were used to shorten the time required to make reservoir management decisions. The first case study involves making a decision, either to develop or sell an oil property. Target formation is sandstone saturated with heavy oil (12°API gravity) which is overlain by a gas cap. Conceptual numerical simulation models provided answers to two questions:
• What is the impact of gas production from the gas cap on the underlying heavy oil zone?
• Can gas production from up-structure wells meet field deliverability requirements?
Second case study uses conceptual models to optimize well placement and support infill drilling. Infill well placement posed a challenge because thickness of target formation is not well known, and oil zone is bounded on top by a massive impermeable shale boundary, and by oil-water contact (OWC) located about 20-40 feet below.
Conceptual models answered the following questions:
• What type of well to drill--vertical or horizontal?
• What is the impact of horizontal well's vertical placement (offset distance from OWC) on oil recovery and water breakthrough times?
• What is the optimum horizontal well lateral length and its impact on oil recovery?
This paper describes modeling methodology, major observations and conclusions. We discuss the benefits and lessons learned from the case studies and demonstrate that successful application of conceptual models requires identifying key well/reservoir performance drivers and assessing their impacts on the reservoir management decisions.
Modeling naturally fractured reservoirs is difficult because of the need to characterize the fractures, matrix and the matrix-fracture interaction. It becomes more challenging if the naturally fractured reservoir produces wet gas, condensates and water. Three different three dimensional, compositional models--single-porosity (SP), single-porosity with alpha factor (SPWAF), and dual-porosity single permeability (DPSP) of the study area, were studied.
The models were calibrated against measured pressure, historical oil production, layer contributions and gas-oil ratios. The calibrated models were then used to forecast the performance of wells in the study area. The impacts of the methodology of describing the natural fractures on fluid flow behavior and recovery mechanisms, as well as on the ultimate hydrocarbon recovery were evaluated. The results also were used to ascertain the risks of selecting the optimum methodology for the field development plan.
The forecasted results show little variations in oil recovery, pressure and oil saturation distributions under identical operating strategy for the three models. This is attributed to the absence of some critical properties required to model the oil recovery mechanisms in dual porosity system. For example, imbibition capillary and relative permeability functions were not input in the dual porosity (DPSP) model. However, the DPSP model is considered more efficient than the single porosity (SP and SPWAF) models because it took less time and modifications to obtain reasonable history match of the field performance. It was also more difficult to obtain a reasonable and acceptable history match using the SP and SPWAF models compared to the DPSP model, and the reservoir properties in the single porosity models had to be modified extensively and unrealistically to obtain history match.
Huffman, Clark (Montana Tech.) | Apaydin, Osman Gonul (Schlumberger) | Ma, Yuan Z. (Exxon Corp.) | Dubois, Dean P. (EnCana Oil & Gas (USA) Inc.) | Iwere, Fabian Oritsebemigho (Schlumberger) | Luneau, Barbara A. (Schlumberger)
Model face is cut parallel to depositional strike. Channel bodies are depicted as elliptical shapes. Connectivity is reduced in both dip and strike orientations. Lateral connectivity does not differ greatly from the SIS distributions.