EOS Modeling and Reservoir Simulation Study of Bakken Gas Injection Improved Oil Recovery in the Elm Coulee Field, Montana

Abstract

The Bakken Formation in the Williston Basin is one of the most productive liquidrich unconventional plays. The Bakken Formation is divided into three members, and the Middle Bakken Member is the primary target for horizontal wellbore landing and hydraulic fracturing because of its better rock properties. Even with this new technology, the primary recovery factor is believed to be only around 10%. This study is to evaluate various gas injection EOR methods to try to improve on that low recovery factor of 10%. In this study, the Elm Coulee Oil Field in the Williston Basin was selected as the area of interest.Static reservoir models featuring the rock property heterogeneity of the Middle Bakken Member were built, and fluid property models were built based on Bakken reservoir fluid sample PVT data. By employing both compositional model simulation and Todd-Longstaff solvent model simulation methods, miscible gas injections were simulated and the simulations speculated that oil recovery increased by 10% to 20% of OOIP in 30 years.The compositional simulations yielded lower oil recovery compared to the solvent model simulations. Compared to the homogeneous model, the reservoir model featuring rock property heterogeneity in the vertical direction resulted in slightly better oil recovery, but with earlier CO 2 break-through and larger CO 2 production, suggesting that rock property heterogeneity is an important property for modeling because it has a big effect on the simulation results. Long hydraulic fractures shortened CO 2 break-through time greatly and increased CO 2 production. Water-alternating-gas injection schemes and injection-alternating-shut-in schemes can provide more options for gas injection EOR projects, especially for gas production management. Compared to CO 2 injection, separator gas injection yielded slightly better oil recovery, meaning separator gas could be a good candidate for gas injection EOR; lean gas generated the worst results. Reservoir simulations also indicate that original rock properties are the dominant factor for the ultimate oil recovery for both primary recovery iii and gas injection EOR.Because reservoir simulations provide critical inputs for project planning and management, more effort needs to be invested into reservoir modeling and simulation, including building enhanced geologic models, fracture characterization and modeling, and history matching with field data. Gas injection EOR projects are integrated projects, and the viability of a project also depends on different economic conditions.

A numerical simulation study of CO2 injection for enhancing hydrocarbon recovery and sequestration in liquid-rich shales

“…Total CO 2 injected was 113% hydrocarbon pore volume (HCPV). Oil recovery increases by injecting CO 2 are also noted in other studies, as Pu and Hoffman (2014) reported an incremental oil recovery of 35% in the Middle Bakken with a 15 stage injection well and a nearby production well. As CO 2 is injected through hydraulically fractured well perforations, it will rapidly flow through these fractures without permeating the rock matrix.…”

Huff-n-Puff Technology for Enhanced Oil Recovery in Shale/Tight Oil Reservoirs: Progress, Gaps, and Perspectives

“…However, injectivity was found to be very positive in some CO 2 pilot tests in the shale reservoir. Pu and Hoffman summarized these surprising results by stating that all of the wells in the pilot tests were stimulated wells with hydraulic fracturing. Song et al stated a few years later that another explanation is that the Bakken permeability and porosity in the United States are not as poor as that in Canada.…”

“…197 The application of CO 2 EOR in tight formations, especially in ultralow permeability reservoirs, is complicated, because of the complex structure and technical challenges in field implementation. Pu and Hoffman 198 evaluated the performance of both WAG and continuous gas injection in shale oil (Bakken Formation), using well-paired systems. They confirmed that permeability is the central key factor that determines the success of the two projects.…”

A Literature Review of CO2, Natural Gas, and Water-Based Fluids for Enhanced Oil Recovery in Unconventional Reservoirs

“…Due to both pressure maintenance and solvent strength, the miscible injection scenarios of CO 2 and hydrocarbon gas yielded more oil recovery than immiscible scenarios. An equation-of-state compositional model was used to test CO 2 , natural gas, and lean gas (pure methane) using continuous and WAG injection schemes (Table , entry 33) . CO 2 WAG utilized less CO 2 but yielded much less incremental oil than continuous CO 2 injection.…”