Washington, D.C. — Exploration and field development in the largest continuous oil play in the lower 48 states, located in North Dakota and eastern Montana, will be guided by new geo-models developed with funding from the Department of Energy’s (DOE) Office of Fossil Energy (FE).
The three-year project to develop exploration and reservoir models for the Bakken Shale resource play was conducted by the Colorado School of Mines (CSM), through research funded by FE’s Oil and Natural Gas Program.
A "play" is a shale formation containing significant accumulations of natural gas or oil. The U.S. Geological Survey estimates the Bakken Shale play contains 3.65 billion barrels of oil and 1.85 trillion cubic feet of natural gas that can be recovered using current technologies. The development of new fields, combined with advances in horizontal drilling and other production technologies, continues to increase these estimates.
Hydrocarbon traps in the Bakken petroleum system appear to be controlled by pinch-outs, where the formation tapers out against a nonporous sealing rock, and high areas in the geologic structure, where hydrocarbons tend to accumulate. Natural fractures and fracture concentrations are key elements for establishing Bakken Shale production "sweet spots," locations with the best production potential.
CSM determined that previously undetected oil accumulation areas could be outlined by mapping the distribution of shale within the reservoir, the impermeable rocksthat form the reservoir’s top and base seals, pinch-out zones, and fracture distribution in areas of subtle structure. With this in mind, CSM integrated information about rock physics, the formation’s rock strata, and seismic, fracture and thermal maturity data—all compiled during the course of the project—into a series of reports that can be used as an exploration model to predict high-potential fairways and traps for the Bakken hydrocarbon system.
CSM also developed a second model, a 3-D reservoir geo-model, that includes detailed subsurface mapping of depositional and fracture trends along with core-calibrated porosity from well logs. The reservoir model was built using data from the Elm Coulee Field, where there is an extensive geological and production database to validate the model. Located in Richland County, Mont., the western portion of the Williston Basin, the Elm Coulee is the largest producing oilfield in the basin. More than 350 horizontal wells have been drilled in the Elm Coulee Field since the initial horizontal well was drilled in 2000. Several major and independent operators work the field.
In Elm Coulee wells, primary oil recovery, in which natural mechanisms drive oil from the reservoir, is only 5–10 percent of the estimated oil-in-place because of the shale reservoir’s low porosity and low permeability. This poor primary recovery makes Elm Coulee an excellent candidate for secondary oil recovery, in which pressure is applied to force the oil from the reservoir. The poor quality of the reservoir essentially eliminates water injection as a secondary recovery method, but CO2 flooding could be a preferred enhanced recovery method.
A consortium of 29 companies consisting mainly of independents, and initiated in conjunction with this DOE project, has been using the results of the study to further develop the Bakken. Information in the reports can be used to identify high potential yield areas by mapping critical elements such as fracture distribution, hydrocarbon maturity, and reservoir quality that were obtained during field studies and subregional mapping.