Unconventional oil production has had a far-reaching impact on the worldwide oil and gas industry. The surge of domestic shale oil production, particularly from the Permian Basin, has played a large role in keeping the price of oil low while also pushing North America to be a leading oil producer.

Still, hydraulic fracturing only recovers about 7% of oil in a reservoir, according to the Energy and Environmental Research Center (EERC). And even with longer lateral lengths, tight reservoirs present steeper decline curves than conventional reservoirs because of low permeability. That leaves vast amounts of oil— about 400 Bbbl in known U.S. reserves, according to the National Energy Technology Laboratory (NETL)—left to be recovered in tight rocks.

Various studies and industry experts claim the density of tight rock reservoirs isn’t conducive to waterflood, and steam injection is likely to prove too costly. For those reasons, CO2 EOR methods could very well be the next frontier in unconventional oil production.

Although widespread EOR efforts in unconventional plays are still mostly uncharted territory, at least one company has cracked the code in the Eagle Ford and is seeing positive results in tight rock CO2 EOR. Meanwhile, several companies and government agencies are making significant investments in research for EOR in unconventional plays, particularly in the Bakken.

But the challenges for implementing CO2 EOR across unconventional resources are the same that are familiar to the industry when facing just about any other challenge: economics and know-how. Unconventional resources will likely require an unconventional approach to EOR. Among those looking into such recovery efforts is the Research Partnership to Secure Energy for America (RPSEA).

“It’s going to be one of those things where [EOR in unconventional reserves is] going to take a while to crack the safe, and it’s best to work on that collaboratively,” said Jack Belcher, business program director for RPSEA. “There’s a will to do it, but there is no will for companies at $50 oil to spend much money on it. [EOR] is a completely different animal with low permeability. It could take a government program to get it going.”

EERC studies the Bakken

Among the organizations exploring the possibilities of CO2 EOR in unconventional resources is the EERC in Grand Forks, N.D. Specifically, the EERC, which is funded by state and government agencies as well as several oil companies, is researching the potential utilization of CO2 EOR in the Bakken.

In 2012 the EERC initiated a study of CO2 storage and EOR in the Bakken, with Phase 1 using reservoir characterization and laboratory data such as core analyses, well logs and oil analyses. The study’s Phase 1 results revealed CO2 could potentially recover more than 90% of hydrocarbons from Bakken reservoir rocks and more than 60% from Bakken shales. However, Jim Sorensen, EERC principal geologist, said those numbers were “crazy high” and likely would not be realistic in real-world applications.

“When we talk about 90% removal, that is on very small core plugs under lab conditions where the whole point is to extract as much oil as we can,” he said. “We don’t believe everyone can get 90% from the Middle Bakken or 60% from shales.”

Phase 1 of the study was completed in 2014, and Phase 2 was only recently initiated by the EERC. Sorensen said Phase 2 involves applying the information and data the EERC learned in its Phase 1 laboratory work to perform field tests in the Bakken.

“We think we understand what’s going on at smaller scales at the mechanism standpoint and how to update that on the reservoir scale,” he said. “The biggest part of Phase 2 is to take things we saw in the lab and in modeling and go to the field to try to do a scientifically robust field test.”

In late June the EERC, in partnership with XTO Energy, initiated a field injection test on an unstimulated vertical well in the Bakken. Sorensen said the CO2 injection field test was conducted over a period of about two weeks, with the results potentially being made public by the end of the year.

“This particular test will not give us a direct number like [the ones seen in Phase 1], but we think the data we generate will help us predict a model and predict what final recovery might be,” he said.

An injection pipe is used for EOR at a facility in Gaylord, Mich. (Source: National Energy Technology Laboratory)

 

Sorensen said one of the biggest barriers to widespread implementation of CO2 EOR in unconventional reservoirs is overcoming the problem of conformance. According to Halliburton, conformance technology is “the application process to reservoirs and boreholes to help reduce production of unwanted water and/or gas to efficiently enhance hydrocarbon recovery.”

“Fractures make conformance difficult but not impossible,” Sorensen said. “One of the things that needs to be understood through additional engineering is that we need to figure out how to control conformance. My personal belief is we’re a couple of years away from figuring out conformance. Those guys at EOG [Resources] may have figured out the solution to conformance. If they can figure it out, someone else can figure it out too.”

EOG in the Eagle Ford

EOG Resources has, it appears, figured it out. The Houston- based independent oil and gas company appears to have cracked the code of CO2 EOR in unconventional reservoirs. According to EOG, the company began working on EOR three years ago and achieved production and economic success on four pilots involving 15 wells at its Eagle Ford site. In 2016 EOG completed a 32-well pilot at Eagle Ford that was also successful. The company said in an emailed statement that it was implementing EOR on another 100 wells.

“EOR will become a regular part of our Eagle Ford development going forward, and once we have more datapoints and production history, we hope to provide a total resource estimate attributable to EOR,” said John Wagner, engineer investor relations for EOG Resources.

Lloyd Helms Jr., executive vice president of E&P for EOG Resources, said during the company’s fourth-quarter 2016 conference call that its 32-well project’s economics included a finding cost of less than $6/bbl, and between 2011 and 2016 the company saw favorable results with well spacing ranging from 61 m to 152 m (200 ft to 500 ft). Helms said EOG Resources produced 300 Mbbl of net oil production from its EOR efforts in 2016.

“This data supports our previous estimates that the incremental recovery due to EOR is adding 30% to 70% more oil to our primary recovery estimates,” Helms said.

EOG has traditionally been reserved when pressed on its specific methods and technologies, saying such information is proprietary. But it has revealed that two key components exist when implementing CO2 EOR at an unconventional resource: the importance of understanding the geology and developing a successful drilling plan. What works in the Eagle Ford may not necessarily work somewhere else, said EOG CEO William Thomas during the company’s first-quarter 2016 conference call.

“The Eagle Ford is unique,” Thomas said. “The same geologic characteristics that make the Eagle Ford prolific in primary development also make it unique for enhanced oil recovery. The EOR process we are using to produce incremental oil out of the Eagle Ford is not necessarily applicable to other horizontal basins. No. 2, how you initially drill the field matters. Secondary recovery works best on leased units that were developed using the best completions with optimal spacing.”

And perhaps most importantly, EOG figured how to make EOR in shale economically feasible. The company’s premium drilling program has turned into what Helms calls a “game changer” in terms of low-cost production, and its EOR program in the Eagle Ford rivals those returns.

“We figured out how to execute EOR economically,” Thomas said. “The process can be implemented at rates of return that rival our premium drilling and significantly lower finding costs over time.”

A tempting target

Outside of the successes seen by EOG, widespread implementation of CO2 EOR methods in unconventional reservoirs is still in the early developmental stages. Several efforts by institutions such as the EERC and also Texas Tech University, RPSEA and the University of Wyoming have yielded inconclusive but encouraging results. Other institutions such as NETL and the U.S. Department of Energy are funding efforts to study EOR in unconventional reservoirs.

According to a study published by Elsevier, a research publishing company, “Little EOR research has been done on these deposits, in part because their exploitation has been so recent. But the potential is huge—and so is the major challenge: extremely low permeability.

“Low prices have kept investors and companies focused on drilling new shales in the most economical areas of shale plays,” the report stated. “Until these sweet spots are exhausted and prices head higher, any progress on EOR in shale is likely to be stalled. But with 95% or more of the oil left behind, shale will remain a tempting target.”

 

Contact the author at bwalzel@hartenergy.com.