Utilizing carbon dioxide (CO2) as an energized fracturing fluid is a common practice in Canada. In the United States, however, introducing new methods of enhanced oil recovery and well stimulation usually requires a global oil player to lead the charge.
As reported by Hart Energy’s E&P Magazine, Statoil has a reputation for being open to embracing new and innovative technologies to tackle the big challenges facing the industry. Later this year, Statoil will pursue expanding such innovations and begin stimulation tests on its Bakken acreage using a CO2 enhanced oil recovery method to determine if the process is as promising as its modeling indicates.
According to a Statoil-issued release, the test will be conducted at a well site approximately 15 miles outside of Williston, North Dakota. The trial will evaluate the possible production uplift while reducing the amount of water used in a large, multistage hydraulic fracturing operation. The test will be a step toward the company’s overall goal of increasing the efficiency and sustainability of its unconventional drilling operations in the Bakken, Eagle Ford and Marcellus regions.
As a means to increase the chances of success, Statoil has sought out a partner company for its well stimulation program. The CO2 test is one of several projects being pursued under its Powering Collaboration initiative, the technology partnership between Statoil and GE that seeks to accelerate the development of sustainable energy solutions.
Explaining how the process is different from other methods, Statoil Head of Shale Oil and Gas Research Dr. Bruce Tocher said, “We will use liquid CO2 as the initial fracturing medium because we believe that it will create a more complex fracture network, giving increased surface area, which should increase the ultimate oil recovery.”
In a press release, Statoil noted that the use of CO2 for well stimulation is common practice in the Western Canadian Sedimentary Basin. However, the upcoming testing will be the first significant application of the process to displace slickwater during the hydraulic fracturing process in the Bakken region. Tocher explained that the modeling and laboratory experiments indicate that by using this method in the Bakken, recovery rates could increase by 20 to 25 percent.
Further explaining the process, he said that after using CO2 in the initial fracturing stages, the stimulation will be completed by using a more standard mixture of water and proppant. “By using CO2 for the initial stimulation, we project that we will use 20 to 40 percent less water than normal in the test phase. Ultimately, as the technology matures, we hope to be able to further reduce water usage in the stimulation process,” Tocher said.
If the tests are successful and show promising results, the program will move on to its next stage of developing cost-effective a system to capture the CO2 in the flowback to be used later on other well stimulations. Tocher commented, “This is where the collaboration with GE comes in. Its main part of the project is to use its world-leading engineering and technical expertise to develop this capture and reuse system. We are very excited about this upcoming test phase and subsequent progress of this project, which is one of several exciting new technologies we are developing with GE as part of our Powering Collaboration Initiative.”