Sustaining EOR In Today’s Economy

Once a reservoir’s primary pressure has depleted and its secondary waterflood has run its course, operators often turn to EOR methods to draw the remaining recoverable barrels of oil to the surface. During the past three decades EOR efforts—particularly conventional reservoir tertiary methods that utilize CO₂ injection—have exponentially increased the amount of oil produced in the U.S. According to Advanced Resources International, in 1986 about 25 Mbbl/d of oil was produced via CO₂ injection. By 2012 that amount grew to more than 275 Mbbl/d, an increase of 1,000%.

In the mid-2010s, with oil eclipsing the $100 mark, CO₂ EOR made plenty of economic sense. According to Melzer Consulting, a CO₂ EOR consulting firm, operators were locking in long-term contracts with CO₂ providers at costs of 2% of the price of a barrel. But by 2016 many EOR efforts were put on hold because of low oil prices.

“Those companies that had contracted their CO₂ for [2% of the cost of a barrel of oil] got in a pretty distressed position, sometimes to the point where they had to find a new buyer and get out of that contract,” said Steve Melzer, founder of Melzer Consulting. “We saw several cases of that. Companies that didn’t have onerous contracts are still doing fine—their intent was to weather these storms. That became a big part of our industry.”

Some operators are finding value in CO₂ EOR and likely will continue to do so, particularly those that maintain their own infrastructure and sources of CO₂.

Seeing opportunities in EOR

Following the downturn, some operators began selling off mature fields rather than implementing CO₂ EOR methods to free up cash to do work elsewhere. They often sell to those companies with the technical ingenuity, the financial means or the right infrastructure in place to turn a profit through EOR.

Hess and Occidental Petroleum (Oxy) announced June 19 that Oxy purchased Hess’ EOR assets in the Permian Basin for $600 million, a move that provides Oxy an influx in production of 8,200 boe/d. The transaction included Hess’s working interest in the Seminole-San Andres unit, the Seminole Gas Processing Plant in Texas, the West Bravo Dome CO₂ field and a 9.9% nonoperating interest in the Bravo Dome unit in New Mexico.

Shortly after it emerged from bankruptcy in March, Chaparral Energy announced in April that it was selling off its EOR assets, which comprise eight CO₂ floods in the North Burbank unit and the Panhandle in Oklahoma. The company announced it would instead focus its resources exclusively in developing its STACK play assets.

Fleur de Lis Energy (FDL) purchased EOR assets in the Permian Basin from Devon Energy in August 2016 for $422.5 million and from Summit Energy in September 2016 for $75 million. In 2015 FDL purchased Anadarko Petroleum’s EOR assets in Wyoming for $703 million. The assets FDL acquired in the deal included the Salt Creek Field, Monell Field, Linch Field and Howell Pipeline, with about 14 Mboe/d of net production and CO₂ pipeline capacity of 7.6 MMcm/d (270 MMcf/d).

“In all of these West Texas fields there is still a lot of oil remaining after waterflooding,” said George Hirasaki, professor of chemical and biomolecular engineering at Rice University. “But companies have abandoned [the fields]. Some companies come in with CO₂ , inject it and are now getting a big response. You’ll see a lot more of that happening.”

The story of the 50,000-acre Scurry Area Canyon Reef Operators (SACROC) Field in the Permian Basin is representative of such a dynamic. Discovered in 1948 with an estimated original oil in place of 2.8 Bbbl, SACROC became the first field in the U.S. to undergo CO₂ EOR injection, which began in 1972. Since that time more than 175 million metric tons of CO₂ have been injected into the reservoir. Over time and even under CO₂ injection the field’s output depleted to about 8 Mbbl/d in 2000. That’s when Kinder Morgan purchased the operation.

“We saw some inefficiencies in the flood pattern configuration,” said Jesse Arenivas, CO₂ business unit president for Kinder Morgan. “But we saw a lot of upside. We could see that by changing the pattern configuration, we tripled the production in a couple of years, and we have been able to maintain a rate of 30,000 barrels per day for over a decade.”

Kinder Morgan, with the benefit of leveraging its own CO₂ sourced in Cortez, Colo., optimized the flood pattern by initializing injections in the southern end of the field and working its way up to the northern platform. That plan resulted in peak production of 38 Mbbl/d in 2014. Since then SACROC production has been tapering down to about 30 Mbbl/d, according to Kinder Morgan. A relatively new venture for Kinder Morgan is its Chiquita area, which was activated in the SACROC in 2010 with an initial investment of $15 million. The project underwent an expansion in 2014 and again in 2016. The company said it achieved favorable results from the initial effort and has since invested more than $100 million in the targeted transition zone with similar results.

The Permian Basin’s largest CO₂ EOR operator is Oxy, which operates more than 19,300 wells, and currently has 100 active CO₂ and waterfloods. The company injects more than 56.6 MMcm/d (2 Bcf/d) of CO₂ into reservoirs in the Permian. Oxy’s first-quarter 2017 Permian EOR production was about 145 Mboe/d.

“We are currently recovering hydrocarbons from the Grayburg down to the Devonian formations and realizing recovery factors above 60% in some of our CO₂ floods,” said Jody Elliott, president at Oxy's Oil & Gas Domestic. “At the end of 2015 we began Phase 1 of a CO₂ flood at our South Hobbs Unit in New Mexico. The CO₂ flooding is showing response, with production more than tripling since going online.”

In February Denbury announced that of its $300 million 2017 capital budget $175 million would be allocated for tertiary oilfield expenditures, and $10 million would be spent on CO₂ sources and pipelines. By utilizing CO₂ floods at its Gulf Coast and Rocky Mountain assets, Denbury anticipates producing between 58 Mboe/d and 62 Mboe/d.

“Our capital spending in the current price environment continues to be primarily focused on expanding our existing CO₂ floods and other infill opportunities, and … our planned 2017 capital projects have strong economics at $50 oil,” said Denbury CEO Phil Rykhoek in a release. Kinder Morgan and Denbury are unique in that they own their own CO₂ source fields and infrastructure like pipelines, which cuts down substantially on their costs for tertiary recovery.

“Our portfolio is very robust at lower prices, primarily because we are utilizing existing infrastructure,” Arenivas said. “When you’re looking to develop a new CO₂ project without existing infrastructure, you have to have higher prices than what we are currently experiencing to make them work. But Yates and SACROC are very infrastructure-rich, so we are able to continue to drill wells utilizing those existing facilities.”

Tall Cotton, located in the Permian Basin northwest of Seminole, is a greenfield residual oil zone CO₂ project. Tall Cotton is the first field without a main pay zone to be specifically developed for CO₂ technology, according to Kinder Morgan. The project began in 2014 and has added about 2 Mbbl/d to Kinder Morgan’s production.

Economics of EOR

Previous commodity downturns such as the one the industry currently is experiencing have not necessarily proven to be a roadblock for CO₂ implementation. For example, according to the Energy and Environmental Research Center (EERC) in North Dakota, CO₂ injection was implemented at the Weyburn oil field in Saskatchewan, Canada, in 2000 when West Texas Intermediate was trading for $28/bbl. About seven years later Weyburn was producing more than 30 Mbbl/d, an amount not seen in that field since the early 1970s, according to Cenovus Energy, a Canadian-based oil company operating the field.

Another dynamic impacting the widespread utilization of CO₂ EOR is the trend of private-equity firms making a foray into the Permian shale boom. The Permian Basin shale phenomenon, which is producing oil more rapidly compared to the longer play of EOR, offers a quicker financial return for investors, both public and private, Melzer said.

“The private-equity market is looking for fast returns from horizontal wells in shale—that’s where they want to invest,” he said. “They want to get in and get out. They’re not comfortable doing a long-term project where CO₂ would be utilized. What we’re seeing is that the better market is not very amenable to the CO₂ world. The public market with stocks and the like has almost the same attitude. The opportunity for quick returns for public companies is overwhelming. Very few are investing in CO₂ EOR. Oxy is the only exception.”

Barriers to entry

The most significant challenge operators face when considering implementing EOR methods is a lack of access to enough CO₂.

“A shortage of CO₂ has caused a real issue,” Melzer said. “What we’re seeing is that CO₂ is available, but it’s the suppliers— they can’t go out and sell it. It’s under contract.”

The issue of CO₂ supply shortages is particularly troublesome in the Bakken, where researchers and engineers pretty well know EOR could recover up to 45% of original oil in place—as much as 670 MMbbl of oil, according to the EERC.

“When the Bakken started coming on in 2008, 2009, and as it became clear [operators] were only recovering 3% to 6%, it became a natural question—‘Is CO₂ for the Bakken?’” said Jim Sorensen, EERC principal geologist.

He added that there is a substantial need for CO₂ injection methods in North Dakota, but it could be years before enough product becomes readily available.

“At least for the Williston Basin, I think our lab work demonstrates CO₂ works well, but there really isn’t much CO₂ available right now,” he said. “And it will be at least five to 10 years before more becomes available.”

Contact the author at bwalzel@hartenergy.com.