Back to Top
Skip to main content
Subtask 3.1 - Bakken Rich Gas Enhanced Oil Recovery
Project Number
Last Reviewed Dated

The project goal is to determine the feasibility of reinjecting captured rich gas into a Bakken reservoir to enhance oil recovery. Specific research objectives related to this goal are as follows:

  • Determine the ability of various rich gas mixtures to mobilize oil in Bakken petroleum system reservoir rocks and shales.
  • Determine the changes in gas and fluid compositions over time in both the tight oil reservoir and surface infrastructure environments, and assess how those changes affect reservoir and process facility performance.
  • Optimize future commercial-scale tight oil EOR design and operations through the use of iterative modeling of surface infrastructure and reservoir performance using data generated by the field- and laboratory-based activities.
  • Establish the effectiveness of selected monitoring techniques as a means of reservoir surveillance and injection conformance monitoring in the Bakken petroleum system.
  • Determine the sorptive capacity of Bakken shales for rich gas components and the effects of sorption in the shales on gas utilization rates in samples representing areas of low, medium, and high thermal maturity. 
  • Use laboratory-based rock characterization activities to evaluate fluid flow pathways by determining wettability and relative permeability of rich gas components in Bakken rocks from different thermal maturity areas, and investigate the use of an emerging technique to predict fracture occurrence across a horizontal wellbore by correlating cuttings’ mineralogy to brittleness.
  • Model alternative commercial-scale injection scenarios based on models developed with the embedded discrete fracture model (EDFM) technique.
  • Apply machine learning (ML) and big data analytics (BDA) to develop virtual learning methods for Bakken rich gas EOR. Develop a methodology to integrate ML and BDA with advanced modeling (including coupled geomechanics and fluid flow) to examine the potential impact that multiple operational scenarios may have on conformance and sweep efficiency (i.e., a multiwell huff ‘n’ puff operation conducted over a township scale as opposed to a drill spacing unit [DSU] scale). Additionally, in these ML and BDA activities, include where to place or space infill wells to increase total recovery within multiple DSUs, when to start the injection of fluids, and which type of fluids to manage reservoir pressure to improve total recovery.

Energy & Environmental Research Center (EERC) – University of North Dakota, Grand Forks, ND 58202-9018


North Dakota is well-situated to demonstrate the implementation of rich gas-based EOR for tight oil formations. Although flaring associated with Bakken oil production has been reduced significantly in recent years, as of March 2019, approximately 19 percent of the rich gas produced in association with Bakken oil production continues to be flared. The associated gas from Bakken oil production operations is typically a mixture dominated by methane with a significant amount of ethane and other hydrocarbons. The results of recent preliminary laboratory investigations at the EERC suggest that pure ethane and mixtures of methane and ethane may be used to mobilize oil from Bakken rocks and thus could be viable injection fluids for EOR operations. The EERC is working with Liberty Resources (LR) to design and conduct an EOR pilot test using rich gas. The project is a joint initiative between the EERC, North Dakota Industrial Commission (NDIC) through the Bakken Production Optimization Program (BPOP), LR, and the U.S. Department of Energy (DOE). Project activities will be coordinated, managed, and evaluated by the EERC. LR will be responsible for providing the wells and rich gas necessary for the test and will operate the injection, production, and monitoring activities. An improved understanding of wettability, relative permeability, and fracture network distribution across the Bakken will be developed using advanced reservoir characterization techniques. Alternative injection strategies to optimize EOR strategies at scales larger than a DSU will be investigated using advanced reservoir-modeling methods. ML and BDA will be used to streamline pilot performance assessments. 


Estimates for original oil in place  (OOIP) in the Bakken petroleum system range from 300 billion to 900 billion  barrels. Current resource recovery factors for Bakken wells are typically 10% or  less. If this trend continues, billions of barrels of oil will be left stranded  in the reservoir. Analysis conducted by the North Dakota Pipeline Authority  indicates that the current gas-gathering infrastructure in North Dakota  (including pipelines, compressor stations, and gas processing facilities) is  insufficient to accommodate all of the associated gas that is produced as part  of oil production from the Bakken. The geographically isolated location of the  Bakken oil play relative to large natural gas markets, combined with continued  low natural gas prices, has made it economically challenging for industry to invest  capital in expanding gas-gathering infrastructure in North Dakota. Therefore,  management of rich gas production from the Bakken is still a high priority for  government and industry stakeholders in North Dakota. This project will  demonstrate the viability of utilizing rich gas for EOR in the Bakken, which  will result in reduced flaring and an improvement in recovery factors. The  primary impacts of this project will be reductions in greenhouse gas emissions  associated with Bakken activities, and potentially the production of billions  of barrels of incremental oil.

Accomplishments (most recent listed first)

The project was initiated on September 1, 2017. A hearing of the NDIC Oil and Gas Division was held September 21, 2017, for the purpose of LR providing testimony for its application to obtain the necessary permits for the pilot injection test. Permits for injection activities in six wells have been granted to LR. LR has purchased a compression unit that is necessary for the operation of the pilot injection test. Specific accomplishments include the following:


  • Large-scale pilot tests were conducted in two wells in the Stomping Horse complex beginning on November 20, 2018, and continuing through May 2019.
  • A gas tracer was introduced to the injection well on November 21, 2018. A second tracer study — which included the injection of gas, oil, and water tracers — was initiated on January 27, 2019. Multiple sampling and analysis events for multiple wells were conducted to look for tracers as a means of identifying fast flow pathways for gas, oil, and water between the injector and various offset wells.
  • The maximum injection rate for the large-scale test is 2.0 MMscfd. For each injection cycle the pilot testing plan called for injection into each well  until one of three criteria are achieved: 1) total injection of 60 MMscf, 2) 30 days of injection, or 3) clear evidence of substantial breakthrough at an offset well.
  • As of May 1, 2019, over 130 MMscf of rich gas had been injected into four wells during six different injection periods.
  • Key observations from the pilot testing included:
    • The ability to effectively inject rich gas into Bakken and Three Forks reservoirs has been demonstrated.
    • Injectivity was readily established and was not a constraint on operations.
    • Reservoir surveillance and monitoring demonstrated that the injected gas could be controlled and was contained within the drill spacing unit.
    • Pressure buildup occurred and showed a positive trend towards achieving minimum miscibility pressure (MMP).
    • The conceptual approach of using laboratory-based testing to inform modeling, which in turn guides injection scheme design and operations, was effective.
  • Baseline reservoir characterization data collection was completed for all wells within the Leon-Gohrick drill spacing units in the Stomping Horse complex. Parameters measured included analysis of produced oil, water, and gas as well as bottomhole pressure and temperature for wells permitted for injection and offset wells. 
  • MMP studies were conducted to determine the MMP of rich gas components and different rich gas mixtures in oil from the Stomping Horse complex. MMP data for methane, ethane, propane, and different relevant mixtures have shown that “richer” gas mixtures will result in lower MMP values (e.g. methane MMP > ethane MMP > propane MMP)..
  • Rock extraction studies of the rich gas components on Bakken shale and nonshale samples have shown that when it comes to mobilizing hydrocarbons from Bakken rocks, methane is the least effective, propane is the most effective, and ethane has an intermediate effect. The rock extraction studies also showed that propane is effective at all pressures, ethane is effective at higher pressures, and methane is the least effective at any pressure.
  • Modeling-based studies of the potential effects of rich gas EOR operations on the surface infrastructure of the Stomping Horse complex predicted that rich gas EOR would not adversely affect surface facility operations. 
  •  Reservoir modeling of selected injection/production scenarios predicted incremental oil recovery may exceed 25%.
  • Small-scale injectivity tests were conducted in two wells in the Stomping Horse complex during the summer of 2018. A total of 24.6 MMscf of rich gas was injected during three tests conducted in two wells between July 17 and September 10, 2018. The maximum injection rate achieved was 1.14 MMscfd. Downhole pressure and temperature data were collected before, during, and after the injection tests from six wells in the drill spacing wells, including the injection wells and the immediately adjacent offset wells. Data obtained from the small-scale injection tests were used to refine the design of the subsequent larger pilot tests.
  • Sorption isotherms for methane, ethane, propane, and a rich gas mixture were successfully measured on three shales representing areas of low, medium, and high thermal maturity in the Bakken Formation using the high-pressure magnetic balance.
  • Large-scale injection testing was conducted into the Gohrick 4-MBH well, which began on January 17, 2019. Multiple severe weather events in February 2019 caused interruptions to the injection activities. Consistent injection was reestablished in early March 2019 and continued until May 9, 2019. A total of 74.5 MMscf was injected into the Gohrick 4-MBH well. Injection into the Gohrick 6-TFH well was initiated May 15, 2019, and ceased in early June 2019, with a total of 17.4 MMscf injected. Injection was ceased because of a constraint on rich gas availability.
  • Reservoir surveillance data from the 2018–2019 pilot injection testing in the Leon and Gohrick wells in the Stomping Horse area were used to revise the reservoir model. The revised reservoir model also incorporated a new EDFM, which more accurately accounts for the complexity and heterogeneity of the fractured reservoir. The use of the reservoir surveillance data and revised model resulted in improved history matching of oil, gas, and water production.
  • Rich gas flow-through experiments were conducted by injecting a 70% methane, 20% ethane, and 10% propane mixture into two samples of Upper Bakken Shale from different wells. Samples were characterized using a suite of tests to investigate properties responsible for observed methane retention. The samples show different levels of porosity/permeability and organic matter content, with the tightest sample showing a capacity to capture and retain a significant quantity of injected hydrocarbon gas. In both experiments, methane appeared to be preferentially retained, while the rate and capture exhibited by each sample differed greatly. Nanoscale porosity associated with abundant organic matter in rock samples was suggested to cause the observed phenomena.
  • A tensiometer was used to determine the IFT (interfacial tension) and contact angle of fluid–fluid and fluid–rock pairs. These measurements and mercury injection capillary pressure (MICP) analysis provided an understanding of wettability and aid in the determination of relative permeability.
  • Elastic properties from minerals were used to model predictions for geomechanical properties. Four geomechanical properties, including Young’s modulus, Poisson’s ratio, bulk modulus, and shear modulus, were predicted from rock physics modeling. These were combined with x-ray diffraction (XRD) and x-ray fluorescence (XRF) analyses. Various ML algorithms (K-nearest neighbor regressor, random forest regressor) were applied to the prediction of mineral composition and brittleness index. The purpose is to optimize the prediction performance and avoid the nonunique algorithm effect.
  • A ten-component equation-of-state (EOS) was developed for a typical Bakken oil sample based on a detailed analysis of multiple pressure, volume, temperature (PVT) data sets. The EOS enables engineers to consider different gas-flooding scenarios flexibly since all gas components can be adjusted individually to mimic the field observations.
  • Two reservoir simulation models with different natural fracture and induced fracture settings have been developed using the EDFM approach. Test runs showed the models developed with the EDFM approach run faster than the traditional fracture models with the same reservoir size and number of fractures.
  • An initial Bakken–Three Forks geologic model (geomodel) was created for a DSU-sized area (approximately 2 miles × 1 mile) in northwestern North Dakota on the western flank of the Nesson Anticline. The reservoir database will provide the virtual learning environment for the ML activity.
  • A series of data acquisition/analysis and geologic modeling activities have been conducted to develop a large-scale geologic model for conformance control and EOR studies. Data of 77 wells in the Dunn–McKenzie area were collected from the NDIC database. The geologic model encompasses a 3-mile by 4-mile (12-square-mile) area. The formations of interest in the modeling effort included the Lodgepole, Bakken, and Three Forks Formations.
  • Based on the large-scale geologic model built, a simulation model with seven wells was developed to simulate the reservoir dynamics in the Bakken. Included in the model were 25% of the fractures in each well to make the simulation run efficiently while keeping the well interference effects considered. The distribution of wells and fractures in the model not only enables the project team to consider the pressure and flow interference between wells/fractures in the production/injection processes but also allows the project team to study conformance control strategies in the EOR operations. The nonintrusive EDFM technique was employed to generate fractures in the simulation model. This recently developed technique enables modeling of complex fracture geometry using structured grids, which significantly improves computational efficiency while maintaining the simulation accuracy.
  • Over 300 rich gas injection EOR cases were set up utilizing the seven-well simulation model. Key EOR design and operational parameters including injector location, gas injection rate and time, soaking time, and production time, were considered in the simulation cases. The results will be used as input data for the ML study.
  • Gas breakthrough behavior was studied using pure gas injection. Methane, ethane, and propane were used as the sole injection solvent in different simulation cases to identify the interference between the injector and neighboring producers. Premature gas breakthrough can be detected by observing the concentration change of the injected solvent in the produced gas from neighboring producers.
  • Based on the gas breakthrough results observed in the pure gas injection cases, conformance control using water injection was studied. Oil–water interfacial tension measurements indicated that the capillary pressure between oil and water does not change significantly with reservoir pressure in the rich gas injection EOR process. Therefore, water injection could confine the injected gas around the huff ‘n’ puff well for EOR purposes, but it may not improve the oil production in the wells that are used for water injection.
  • The virtual learning work is using two simulation case matrices to quantify the effect of DSU development and operational parameters on DSU production (oil, gas, and water production). The Set 1 cases were completed and evaluated 18 realizations that explored the effects of DSU well count, EOR development timeline, and EOR injectate on DSU production. Based on the results from Set 1, an additional case matrix of 274 realizations (Set 2) was designed to explore the parameter space more broadly for a seven-well DSU, early EOR development timeline, gas-only injectate, and the following operational variables: injection rate, injection time, soak time, and production time.
  • Different visualization techniques were used to assess pilot test field data acquired from propane gas injection targeting the Middle Bakken in Mountrail County, North Dakota; a pilot-scale field test of CO2 injection into a tight oil reservoir in northern Dunn County, North Dakota; and a rich gas EOR pilot in Williams County, North Dakota.
  • The well interference effect on the production of a parent well during the hydraulic fracturing of an offset well was analyzed for two sites. Results showed that water cut is an effective indicator to identify the interference between wells since a high volume of water needs to be injected when fracturing a new well. Water injection tests were designed to mimic the fluid communication process in the two sites. Simulation results showed that the models can capture well interference and water cut behavior in the two sites, i.e., water cut increases rapidly in parent wells after breakthrough when the fractures are set up properly. Fundamental gas and water flow mechanisms were analyzed to understand their transporting behavior in fractures between wells so that reasonable conformance treatment strategies can be applied to control their flow in the EOR process. Compared to gas, water has much lower mobility under reservoir conditions. Therefore, injection of water in the offset wells can effectively slow down the movement of gas through the fractures and thus achieve conformance control purposes. Shutting in the offset wells is also helpful to slow down the crossflow by decreasing the pressure differential between wells.
  • A detailed history match was conducted for the 16-well model that was developed to simulate rich gas EOR in one of the sites  with multiple DSUs. Different EOR strategies, including water, rich gas, and surfactant injection, were studied to select a suitable EOR method that can improve the oil production performance in presence of high-permeability fractures between the huff ‘n’ puff well and its offset wells. Results showed that the EOR performance of a well not only relates to the injectate but also relates to the many other factors, including fracture number, stimulated reservoir volume, mobile oil saturation around the well and fractures, pressure level, EOR injectate type, and operational schedule. A low gas injection rate may not improve the oil production performance in the EOR process as the incremental oil of EOR could not offset the production loss during the injection and soaking cycles. Compared to water, surfactant injection could be a more efficient way to improve EOR performance while controlling the conformance issues in the gas EOR process.
  • Reservoir simulation development studies were completed to evaluate 1) DSU development factors: number of wells (5, 6, or 7); development schedule: early (bottomhole pressure [BHP] 500 psi below the minimum miscibility pressure [MMP]), middle (oil rate less than 100 stbd), or late (oil rate less than 50 stbd); and injectate (gas-only or gas + water injection) and 2) DSU operational factors: gas-injection rate, injection time, soak time, and production time (note: the sum of injection time, soak time, and production time yields the cycle time). Machine learning techniques were used to analyze these reservoir simulation outputs and learn the relationships between the different DSU development and operational factors and DSU production of oil, gas, and water. 
  • Public data of improved/enhanced oil recovery (IOR/EOR) pilots in the Bakken were collected and analyzed to identify the most sensitive parameters for gas-breakthrough monitoring in offset wells during the EOR process. Based on these findings, two different scenarios with 112 cases were developed to simulate propane and rich gas injection EOR in the Bakken using a reference seven-well DSU. The scenarios evaluated different gas injection rates from 0.5 to 18 MMscfd and BHP constraints on the injection well from 1500 to 7500 psi. The .sr3 output files from these 112 reservoir simulations have been extracted, compiled, and are continue to be analyzed using different ML-based methods for real-time visualization, forecasting, and control.
  • Alternative EOR and conformance control strategies using water and surfactant injections were developed to improve the oil production performance based on experimental observations. Results showed that water injection can be used for conformance control in the Bakken because of its relatively low mobility compared to gas; however, water could also block oil flow around the conformance control wells because of the high interfacial tension between oil and water. Adding surfactant to the injection water is more effective for improving gas EOR performance since surfactant can reduce the oil–water interfacial tension and contact angle effectively. Up to 9.4% more oil could be produced from the HnP wells in 2 years of EOR operations when rich gas was injected at only 3 MMscf/d with 6000 psi of surfactant injection in the offset wells for conformance control. 
  • EOR operational strategies including single- and multiple-well HnP with different gas injection constraints were investigated based on the multiple-DSU model. The simulation results of single-well HnP without conformance showed that a rich gas injection rate of at least 10 MMscf/d is needed to obtain incremental oil production in the HnP well. The strategy of conformance control via water injection could significantly improve oil production in the HnP well but injecting an excessive amount of water leads to water breakthrough and loss of oil production in the offset wells. The optimized case of using six rich gas HnP wells and two water injection wells with a maximum injection pressure of 6000 psi as the conformance control approach contributes to 8.95% of incremental oil production. Replacing rich gas with propane as the injection gas could result in 15.2% of incremental oil production.
Current Status

Milestones (M) 18 – Conformance Treatment Modeling Studies Complete and M19 – Large-Scale EOR Modeling Studies Complete were completed on October 31, 2021. Two draft journal articles on the conformance control studies were initiated. “Machine Learning Assisting in Estimating Brittleness Index of Middle Bakken Formation from Drilling Cuttings” was presented at the American Geophysical Union Fall Meeting, held December 13–17, 2021, in New Orleans, Louisiana, and online. A draft manuscript entitled “Brittleness Index Estimation of Middle Bakken Formation from Drilling Cuttings” was submitted to the Journal of Petroleum Science and Engineering.

All project activities have been completed and the Final Topical Report was submitted to DOE. A final closeout presentation was provided to DOE reporting the technical accomplishments achieved in the project. 

Project Start
Project End
DOE Contribution


Performer Contribution


Contact Information

NETL – Gary Covatch ( or 304-285-4589)
EERC – Steve Smith ( or 701-777-5108)