Establishing tertiary EOR operations in unconventional plays
In an effort to improve recovery efficiency from unconventional plays and accelerate their development, the National Energy Technology Laboratory (NETL), part of the U.S. Department of Energy (DOE), has established a group of field laboratories across several basins across the U.S. These field laboratories have been developed in conjunction with operators, service companies, and academic institutions. This article, the third in a series on NETL’s field laboratories, discusses two projects that are focused on evaluating and optimizing enhanced oil recovery (EOR) operations in the Bakken and Eagle Ford shale plays. The primary goal of both projects is to better characterize existing fracture networks, stimulated reservoir volume, and fluid flow dynamics, to improve tertiary EOR opportunities in both plays.
BAKKEN RICH GAS EOR FIELD LABORATORY
North Dakota is well-situated to demonstrate the implementation of rich, gas-based EOR for tight oil formations. While flaring associated with Bakken oil production has been reduced significantly in recent years, as of May 2019, approximately 18% 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 Bakken field laboratory project, a collaboration between DOE/NETL and the University of North Dakota’s Energy & Environmental Research Center (UND-EERC), and Liberty Resources, began in September 2017 and is focused in the Leon Gohrick drill spacing unit within the Stomping Horse complex, Fig. 1. The results of recent preliminary laboratory investigations suggest that pure ethane and mixtures of methane and ethane may be used to mobilize oil from the Bakken reservoir, and thus could be viable injectate for tertiary EOR operations. The EERC is working with Liberty Resources and the North Dakota Industrial Commission (NDIC), through the Bakken Production Optimization Program (BPOP), to design and conduct an EOR pilot test using rich gas.
A pilot injection test and associated monitoring activities are currently ongoing and are continuing through the summer of 2019, Fig. 2. Shale permeability and shale sorption studies, using a flow-through testing approach, have been initiated and are ongoing. A Rubotherm Series IsoSORP SA magnetic balance, for multigram determination of isotherms under reservoir temperatures and pressures, is being used to quantitatively measure the absorption capacity of Bakken shales for methane, ethane, propane, and relevant rich gas mixtures under relevant pressure and temperature conditions.
The effects of rich gas exposure on the properties of Bakken shale and nonshale tight rocks, including clays and mineralogy, wettability, and relative permeability, will be examined using a variety of laboratory techniques, such as nuclear magnetic resonance (NMR) and field emission scanning electron microscopy (FESEM). The potential for preferential sorption of different rich gas components in Bakken rocks is also being examined using flow-through experiments under reservoir pressure and temperature conditions.
While estimates for original oil-in-place (OOIP) in the Bakken petroleum system range from 300 Bbbl to 600 Bbbl 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 plays, 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 hopes to demonstrate the viability of utilizing rich gas for EOR in the Bakken, which would result in reduced flaring and improved recovery factors. This project’s primary impacts will be reductions in greenhouse gas emissions associated with Bakken activities, and the potential production of billions of barrels of incremental oil.
Specific accomplishments include the following:
- A baseline reservoir characterization data collection has been 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.
- Minimum miscibility pressure (MMP) studies have been 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 non-shale 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 predict that rich gas EOR will not adversely affect surface facility operations.
- Reservoir modeling of selected injection/production scenarios predicts that 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 Sept. 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.
- Large-scale pilot tests were initiated in a well in the Stomping Horse complex on Nov. 20, 2018. A tracer was introduced to the injection well on Nov. 21, 2018. Multiple sampling events from multiple wells were conducted in the Stomping Horse complex as a means of identifying fast flow pathways between the injector and various offset wells. The maximum injection rate for the large-scale test is 2.0 MMscfd. In general, each cycle injection is conducted 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.
EAGLE FORD SHALE LABORATORY: A FIELD STUDY OF VOLUME, FRACTURES AND EOR
Multi-stage hydraulic fracturing of unconventional reservoirs, implemented in tens of thousands of wells, has been the enabling technology for the tremendous growth in U.S. oil and gas production during the past decade. This approach continues today, even as the technology evolves rapidly. As stimulation methods continue to improve rapidly, allowing significant improvements in stimulated volume, a very large percentage of the recoverable oil remains in the ground after initial production.
Therefore, operators have recently started to explore options for enhancing recovery from existing wells, via two methods: 1) the “re-fracturing” of wells that have been hydraulically fractured during the past decades, based on “old” less-than-optimal stimulation technology; and 2) the injection of natural gas or other gases to significantly enhance oil recovery after initial production. In each of these areas, it is crucial for effective and sustained production that there is better understanding of field diagnostic experiments, fracture characteristics created from state-of-the-art stimulation, optimized re-fracturing of legacy wells, and improving sweep efficiency of shale EOR.
The objective of this project, conducted by Texas A&M University, teamed with Lawrence Berkeley National Laboratory and Stanford University on Chesapeake Energy Corporation’s Eagle Ford properties (Fig. 3), is to improve efficiency of oil and gas recovery from hydraulically fractured horizontal wells. The project is funded by DOE/NETL, with matching funding from Chesapeake Energy and contributions by other operators and service companies in a supporting joint industry project.
This field-based research began in April 2018 and is being conducted in the Eagle Ford shale formation, with the purpose of addressing fundamental questions, such as the extent of the true stimulated reservoir volume and the complexity of the resulting fracture system. Utilizing newly-developed and comprehensive monitoring solutions, the team will deliver unprecedented and comprehensive high-quality field data, to improve scientific knowledge of the hydraulic fracturing process, re-fracturing, and subsequent Huff-and-Puff gas injection as an EOR method. This knowledge will allow optimized production from fewer new wells, with less material and energy use.
This project’s ultimate objective is to improve the effectiveness of shale oil production by providing new scientific knowledge and new monitoring technology for both initial stimulation and production, as well as enhanced recovery via re-fracturing and EOR. This project will provide key insights into the fracture stimulation and EOR processes, and develop new methodologies and operational experience for optimized production of oil from fractured shale. While aspects of the proposed project are site-specific to the Eagle Ford formation, there will be many realistic and practical learnings that apply to other unconventional plays, or even apply to other subsurface applications, such as unconventional oil and gas recovery and tight gas sand reservoirs.
The project has three major phases, all of which will be monitored more comprehensively than any previous field tests, Fig. 4. The first phase is the re-fracturing of a multi-stage fractured horizontal well, the second phase consists of the drilling and fracturing of two new producers, and the third phase is a huff- and-puff gas injection EOR pilot test.
A unique feature of the project will be the presence of a highly instrumented horizontal observation well alongside an existing horizontal producing well that will be re-fractured. This well will be equipped with fiber optic cables for measuring distributed temperature, acoustics, and strain (DTS, DAS, and DSS), an array of geophones to receive seismic signals, and an array of quartz pressure gauges. The observation well also will provide access for running well logs at any time throughout the project’s life. This observation well will provide an unprecedented level of monitoring of the fracturing processes applied during the project, of the distribution of injected gas during the EOR phase of the project, and of reservoir performance throughout the life of the project.
Another unique feature of the project will be the testing of the use of an array of surface orbital vibrators (Fig. 5) over the test site for active seismic interrogation of the subsurface region being fractured. The seismic signals generated will be received by the DAS cable and the geophones in the observation well. Developed at the Lawrence Berkeley National Laboratory, this novel means of creating seismic sources that can be activated throughout the life of the project to generate 4D seismic information has never been tested at a multi-stage hydraulic fracturing site.
The field test site for the project has been selected, and existing data have been evaluated and used in the development of a reservoir model for simulation and history-matching efforts. Design of integrated and comprehensive monitoring schemes is completed. This includes active seismic monitoring, using the surface orbital vibrators (SOV), distributed acoustic, temperature and strain (DAS, DTS and DSS) sensing and interpretation, drill cutting evaluation, well logs to be run before and after the re-fracture treatment, and a proppant/fluid tracing program. Experimental factorial design for pumping strategy, proppant/fluid loading and completion design is being carried out to examine the interactive impacts of key parameters on stimulation optimization. The experimental apparatus used for field core testing, experimental procedure, and data analysis methods are established and ready for use.
The observation well is scheduled to be drilled and completed during fall 2019, with the re-fracture treatment to be conducted shortly thereafter. After monitoring the production performance for some period of time, the project will move on to the drilling and completion of the new producers, followed by the EOR pilot. Monitoring equipment and methods have been confirmed or procured by the team, and all programs have been designed or are being evaluated.
Utilizing newly-developed monitoring technologies and a unique, highly instrumented horizontal observation well, the Eagle Ford Shale Laboratory (EFSL) site will deliver unprecedented and comprehensive high-quality field data to improve the scientific knowledge of multi-stage hydraulic fracturing of unconventional shales by implementing three field research stages: 1) a Refracturing Stage, where a previously fractured legacy well will be characterized in detail and then re-stimulated for improved production;, 2) a new Stimulation Stage, where the most advanced new hydraulic fracturing and geosteering technology will be applied in new production wells, and 3) a Gas-EOR Phase, where the refractured well will be tested later for the efficiency of Huff-and-Puff gas injection as an EOR method. Advanced field monitoring will be complemented by laboratory testing on cores and drill cuttings and coupled modeling for design, prediction, calibration, and code validation. WO
"This report was prepared as an account of work sponsored by an agency of the United States Government. Neither the United States Government, nor any agency thereof, nor any of their employees, makes any warranty, express or implied, or assumes any legal liability or responsibility for the accuracy, completeness, or usefulness of any information, apparatus, product, or process disclosed, or represents that its use would not infringe privately owned rights. Reference, herein, to any specific commercial product, process or service by trade name, trademark, manufacturer or otherwise does not necessarily constitute or imply its endorsement, recommendation, or favoring by the United States Government or any agency thereof. The views and opinions of authors expressed herein do not necessarily state or reflect those of the United States Government or any agency thereof."
KeyLogic Systems, Inc.’s contributions to this work were funded by the National Energy Technology Laboratory under the Mission Execution and Strategic Analysis contract (DE-FE0025912) for support services.
- U.S. upstream muddles along, with an eye toward 2024 (September 2023)
- Canada's upstream soldiers on despite governmental interference (September 2023)
- Regional report: Newfoundland and Labrador: Despite some setbacks, NL’s offshore sector continues to ride its large potential to greater progress (September 2023)
- Machine learning-assisted induced seismicity characterization of the Ellenburger formation, Midland basin (August 2023)
- Executive viewpoint (July 2023)
- Utilizing electronic data captured at the bit improves PDC design and drilling performance (July 2023)