(475b) The Potential for Enhanced OIL Recovery in the Bakken Petroleum System

The Williston Basin’s Bakken petroleum system, which includes the Bakken and Three Forks Formations, is a world-class unconventional tight oil play with original oil-in-place (OOIP) estimates ranging from 300 billion to 600 billion barrels. Matrix permeability in the Bakken is typically on the order of micro- to nano-Darcies, and hydraulic fracturing techniques are necessary to produce oil from the reservoir. Despite the enormous resource, the U.S. Geological Survey estimates the technically recoverable reserves for the Bakken are only 7.4 billion barrels, with primary recovery factors for individual wells typically ranging from 4% to 10%. The massive size of the resource combined with low recovery factors means business as usual will leave an enormous amount of oil behind, and even small improvements in productivity would yield billions of barrels of incremental oil. The Williston Basin also holds world-class lignite coal reserves. Several large lignite coal-fired power plants in North Dakota and Saskatchewan operate within 100 km of the most oil-productive areas of the Bakken Formation. The juxtaposition of a need to improve the productivity of a world-class oil resource with a desire to manage carbon dioxide (CO₂) emissions from nearby power plants has led to an interest in the potential to use CO₂ for enhanced oil recovery (EOR) and associated storage in the Bakken Formation. There is also an interest in using hydrocarbon gases (e.g., methane, ethane, and propane, also referred to as “rich gas”), the coproduction of which may inhibit oil production because of inadequate gathering and processing infrastructure and tight regulations on flaring. Although flaring associated with Bakken oil production has been reduced significantly in recent years, as of January 2019, approximately 507 million cubic feet per day (MMcfd) of rich gas was being flared, accounting for 18% of the rich gas produced in association with Bakken oil production. The North Dakota Industrial Commission, which regulates the oil and gas industry in North Dakota, has a stated goal of reducing the amount of flared rich gas to 10% or less of the total associated gas produced in the state by November 2020. Therefore, reduction of emissions due to flaring from the Bakken is a high priority for government and industry stakeholders in North Dakota.

From 2012 to 2018, the Energy & Environmental Research Center (EERC) conducted a series of consortium-driven research programs focused on potential approaches to EOR in the Bakken petroleum system. The U.S. Department of Energy (DOE) and industry consortium-funded projects used new and existing reservoir characterization, laboratory experimental data, state-of-the-art modeling, and two field-based injection tests to examine the viability of EOR using CO₂ or rich gas. The lab- and modeling-based studies demonstrate that CO₂ and rich gas can permeate the Bakken and Three Forks matrix, largely through diffusion, to mobilize oil. Those studies also showed that CO₂ will preferentially mobilize lower-molecular-weight hydrocarbons. The modeling studies indicated that huff ‘n’ puff EOR schemes may be the most effective approach to EOR in the Bakken petroleum system. The laboratory and modeling activities were used to inform the design and execution of two pilot EOR tests, one using CO₂ and the other using rich gas as the injection fluid.

In 2017, XTO Energy in partnership with the EERC conducted a CO₂ injection test in a vertical well completed in a nonshale, but still unconventionally tight and productive, zone of the Bakken Formation referred to as the Middle Bakken. The objectives of the test were to determine the injectivity of an unstimulated Middle Bakken reservoir (i.e., a reservoir that had not been hydraulically fractured) and the ability of injected CO₂ to permeate the matrix and mobilize oil. The well completion program did not include the use of hydraulic fracturing and proppant. Upon perforation, the well did not flow to surface, but oil samples were collected from the well before injection. Approximately 99 tons of CO₂ was injected over 4 days. The CO₂ was allowed to soak for 15 days. Reservoir pressure and temperature were monitored during all stages of the test using downhole gauges. During the flowback period, gas composition was monitored, and fluid samples were collected. Preinjection and postinjection oil samples were analyzed for oil composition to determine the molecular weight distribution of the hydrocarbons. Pulsed-neutron logs were also run before and after injection to evaluate the vertical distribution of the CO₂ in the near-wellbore environment.

Injectivity of the unstimulated Middle Bakken was found to be low, with stable CO₂ injection rates between 6 and 12 gallons per minute and bottomhole pressure during continuous injection from 9400 to 9470 psi. The CO₂ penetration radius was calculated to be 50 to 70 ft. However, numerical simulation indicated it may be as much as 140 ft. During flowback, oil flowed to the surface briefly, during which time fluid and gas samples were collected. Analyses of the preinjection and postinjection oil showed that the composition of the postinjection oil samples had greater amounts of lower-molecular-weight hydrocarbons than the pretest oils. Interpretation of the results from the field test suggest that although matrix injectivity is low, injected CO₂ can penetrate the Middle Bakken and mobilize oil from the matrix.

The data from the CO₂ field test were used in simulation modeling exercises to gain further understanding of the flow characteristics of CO₂ in unconventional tight oil formations using a variety of EOR schemes. The simulations indicated that the cyclic multiwell huff ‘n’ puff (CMWHP) approach showed the best performance in terms of EOR. In the best cases, the CMWHP scheme was predicted to more than double the oil recovery factor of a well. The CMWHP scheme would include a sequence of alternating injection, shut-in (soak), and production using three or more wells. In 2018 Liberty Resources, in partnership with the EERC, initiated a pilot-scale EOR test using rich gas as the injection fluid and a CMWHP scheme for injection and production. The hypothesis being tested by the rich gas pilot testing activities is that CHWHP can be used to maintain conformance of injected fluids within the target reservoir, improve oil recovery response, and utilize rich gas components that might otherwise be flared. Rich gas injection started in the summer of 2018, and as of the end of March 2019, over 76 MMscf of gas had been injected sequentially into four wells during six different injection periods. Operation of the pilot is expected to continue into the summer of 2019.

The results from the laboratory-, modeling-, and field-based studies indicate there is a tremendous potential to conduct EOR operations in the Bakken petroleum system. The results of the CO₂ lab studies and field test were integrated into simulations of various EOR scenarios. Those simulations showed incremental oil recovery from the injection of CO₂ into a Bakken or Three Forks reservoir as high as 5.4% of OOIP. With OOIP estimates ranging from 300 billion to 600 billion barrels, the modeling results, therefore, suggest that the use of CO₂ for EOR in the Bakken petroleum system may yield between 16 billion and 49 billion barrels of incremental oil. The laboratory-based studies show that CO₂ and rich gas behave similarly in terms of their ability to permeate tight Bakken rocks and mobilize oil. While the rich gas EOR studies and pilot test are still ongoing and results from those activities will not be available until 2020, it is anticipated that the potential impacts of using rich gas for EOR in the Bakken will be of a similar magnitude.