By Lana Cunningham
The Permian Basin was the proving ground for Enhanced Oil Recovery using CO2. Now the rest of the country, and even other nations, are hopeful of tapping into the technology. But supply poses a potential limiting factor—and regulatory oversight issues as well.
Carnegie Mellon University. Department of Energy and Climate Change. Hanyang University. Los Alamos National Laboratory. Nippon Steel and Sumikin Engineering Co., Ltd. Norwegian Petroleum Directorate. Lawrence Berkeley National Laboratory.
And Melzer Consulting of Midland, Texas.
Almost 300 people representing the global view of CO2 capture and storage attended the 13th annual Carbon Capture, Utilization, and Storage (CCUS) Conference that convened in late April in Pittsburgh, PA. Among them was Steve Melzer, a leading authority on the use of CO2 in Enhanced Oil Recovery (EOR) projects in the Permian Basin.
“We’re trying to make the pitch that CO2 is the best way to go with an EOR project,” he said. “They don’t do much CO2 east of the Mississippi River. There are opportunities in Illinois and Kentucky but there isn’t a good source of CO2” in those areas.
Finding sources of CO2 for EOR projects is the roadblock halting plans for more usage in developing these wells. Meanwhile, the Environmental Protection Agency is stepping into this arena with possible additional regulations, Melzer noted, and that development was one of the topics at the Pittsburgh gathering.
“We’ve always been a smaller niche in the marketplace,” Melzer said of the CO2 process. “All the assets and almost all the capital seems to be going to the unconventionals, such as the Wolfberry and Bone Springs. Our biggest detriment in enhanced oil recovery is development of a source of CO2. It’s hard to start a new project because you can’t get a longterm commitment for the CO2 that you need.”
The Permian Basin was the first area to recognize the benefits of CO2 injection when it was tried in Scurry County in 1972 and today reigns as the leader of CO2 projects. Melzer helps run a CO2 school in Midland twice a year and meets with people from around the globe throughout the year.
“Some Chinese were here recently and we have some Indonesians coming in mid-May. We’re doing a lot of work on Residual Oil Zones (ROZ) and we will have a seminar on that topic in August in Colorado.
“The Permian Basin is the world leader in this technology. Everyone wants to figure out how we’ve done it. People are still fine-tuning it. We have 14 projects that are injecting into the ROZ. You couldn’t take any oil out of those zones in primary or secondary recovery. But we calculate about 12,000 barrels/day coming from this process.”
Despite the amount of oil that horizontal wells are producing, there is still a need for more CO2 wells. Jim Wuerth, president for CO2 operations of Kinder Morgan Energy Partners, explained that wells which have reached a point where they are producing little oil and mostly water will still have 50 to 60 percent of oil in place. “With CO2, you can go in and produce another 10 to 20 percent of the oil in place,” he said in early April while appearing on Platt’s Energy Week, an independent all-energy news and talk show program. Kinder Morgan is the largest transporter and marketer of CO2 in the U.S.
With elevated crude oil prices, Wuerth sees the need for more enhanced oil recovery operations that would expand opportunities in these older oil-producing basins.
On the Platt’s show, Wuerth explained, “If you’re painting your house with an oil brush and try to wash the paint out with water, it doesn’t work well. If you use paint thinner, it comes out real well. CO2 is like the paint thinner. You put it down under pressure and it mixes in with the oil, swells, and makes it move a little easier from the rock.”
Energy writer Tim Maverick explained it this way in his April 24, 2014, post: “Oil production from oil reservoirs is a three-phase process: primary, secondary, and tertiary [or enhanced] recovery. But after the first two phases 30 percent to 60 percent of the oil is still left in the reservoir. Thus the need for enhanced recovery methods. The latest method is called CO2-EOR, which involves injecting carbon dioxide into the reservoir. The carbon dioxide mixes with the water, making the oil lighter. At that point, the oil can detach from the rock surfaces and flow more freely within the reservoir and up through the well.”
Companies that can find supplies of CO2 use it for enhanced recovery. Petrotech Oil and Gas, for example, announced in late January plans for an 18-well drilling program in Oklahoma. That program also includes “five of the existing wells to be converted to injection wells. The company will inject water as well as gas and CO2 back into the zone to enhance production. It is estimated there are 40,000 barrels of recoverable oil under the lease,” as was noted in a news release from the firm.
“Throughout the United States there are primary depleted oil reservoirs representing billions of barrels of oil that lend themselves to the use and exploitation of Enhanced Oil Recovery and PetroTech Oil and Gas, Inc.’s, proven patented technology. Without EOR technology, these reservoirs will produce only about 20 percent of their original oil in place,” according to the news release.
Maverick quoted General Electric’s Michael Ming, general manager of the Oil and Gas Technology Center, who said that carbon dioxide presented a huge opportunity for the oil and natural gas industry. “Ming believes that the new technologies have the potential to triple domestic oil production from enhanced recovery operations if the supply of available carbon dioxide is double. There’s also the vast potential of using a chilled form of CO2, known as a ‘super critical fluid’ (it’s neither solid nor liquid), to replace water as the new industry standard in frac’ing.”
“The number of CO2 projects is up,” said Midland’s Melzer. “The number of projects in the United States and worldwide has gone up. There is still a lot of momentum for CO2-EOR. And there could be more if we weren’t running behind on developing new sources of CO2.”
Melzer said the CO2 projects are capital intensive and take three to five years to complete. “It’s a similar story all around the United States. Projects are limited by an available supply of CO2.”
With more possible uses for CO2, where are the sources to supply the increasing demand?
On a small scale, General Electric is working with Norway’s privately owned Sargas SA to capture CO2 emissions from power plants, and it will be injected later into oil fields. Author Tim Maverick noted, “Now, it’s impressive enough that the company has taken notice of the trend’s emerging importance—since many others in the industry are ignoring its potential.”
The CO2 industry leader, Kinder Morgan, announced it would invest $1 billion in a CO2 enhanced oil recovery project in New Mexico and Arizona. “The project includes construction of a 213-mile pipeline to send CO2 from the company’s St. Johns field in Apache County, Arizona, to the Kinder Morgan-operated Cortez Pipeline in Torrance County, New Mexico.
Wuerth, with Kinder Morgan, said, “In today’s market, CO2 runs about $2 per thousand cubic feet (/Mcf) or a little higher. It takes 6 Mcfs of CO2 to produce a barrel of oil,” a rate which suggests operating costs of around $30 to $35/barrel.
Even so, with oil prices around $100/barrel, EORs are still economic despite high operating costs. Also, oil yields increase after enhanced oil recovery, which can extend a field’s productive life to years, Wuerth noted.
Although the CO2 process is capital intensive and the infrastructure paid for up front, Wuerth contends the CO2 flooding is a “very life-long process.” He cited the example of a Shell CO2 project started decades ago at a Denver Unit.
“They thought when it started they’d inject CO2 for about 10 years and that would justify putting in the pipeline and the infrastructure,” Wuerth said. “But it’s 40 years later and [the company is] still one of our largest customers. Production just keeps coming.”
Maverick talked of Denbury Resources in an April 28, 2014, article in Wall Street Daily. “Denbury owns the largest reserves of naturally occurring underground carbon dioxide used for oil recovery east of the Mississippi River. Its primary focus is using CO2 to increase oil output from past-producing fields of stranded oil.”
Denbury is involved in America’s largest carbon capture project with Air Products & Chemicals and Valero Energy. The project received a $284-million investment from the U.S. Department of Energy because it cuts carbon emissions. Maverick explained that Denbury then uses the captured CO2 for its EOR operations across the Gulf Coast.
Meanwhile, GE is working with the Norwegian energy company, Statoil ASA, on a $10 billion research program that’s aimed at using captured CO2 instead of water in fracking. The two companies are trying to find the perfect viscosity for the chilled CO2, which then could carry proppant sand, which is a key factor in the fracking process, according to Maverick. “They also need to figure out how to re-capture the carbon dioxide at the wellhead so that it can be re-used to frac additional wells.”
Melzer added that Kinder-Morgan “is doing a lot right now.” According to its website, two pipelines serve the McElmo Dome source field. The 502-mile 30-inch Cortez Pipeline carries CO2 to the Denver City hub in West Texas while the 40-mile, 8-inch McElmo Creek Pipeline supplies a unit in Utah.
“Due to increasing demands for CO2, production capacities have been increased by the installation of larger gathering lines to several wells and by increasing compression capacity at McElmo Dome. With this expansion, the production capacity of McElmo Dome has increased to 1.2 BCFD,” the website noted.
Another future source is expected to come from the Texas Clean Energy Project at Penwell. This “NowGen” Integrated Gasification Combined Cycle (IGCC) facility will incorporate carbon capture and storage technology in a commercial clean coal power plant. According to the TECP website, this plant is being developed by Seattle-based Summit Power Group and is expected to capture 90 percent of its carbon dioxide, or about 3 million tons per year. This CO2 will be used for enhanced oil recovery in the Permian Basin. This project is expected to be the first U.S.-based power plant that combines both Integrated Gasification Combined Cycle and carbon capture and storage technologies.
Melzer noted, though, that the plant is having start-up issues. “We should have had the groundbreaking by now. It’s not dead, just set back another six months or so.”
As more projects are being done, the more CO2 is needed. That’s why Melzer was at the Pittsburgh CCUS conference. Conference literature explained the issue: “The development and deployment of commercially-viable carbon capture and storage technology is now at a critical juncture given the Environmental Protection Agency’s issuance of a proposed CO2 emissions standard requiring the deployment of carbon capture and storage technology for any new coal-fired power plants.”
“Another problem we have is that we anticipated the supply growth of CO2 to come from industrial sources, which create it as a by-product. The EPA has confounded that. That’s why I’m here in Pittsburgh… to get them out of the way.”
In Texas, the Railroad Commission has complete authority over those plants and the EPA is trying to acquire some of that authority. “The EOR companies want to keep it business-as-usual with the Railroad Commission. They don’t want to get embroiled in this storage regulatory world. If you claim storage while doing EOR, which we’ve called CO2 retention, the EPA wants you to go to them to get credit for that. It’s like having two regulators instead of one,” Melzer said.
“We are trying to get it so the EPA doesn’t take over that aspect. We want the state oil and gas regulators to certify the storage that occurs during EOR. However, I don’t expect anything will happen this year to clarify it… probably next year.
Melzer is optimistic the issue will be resolved next year but in the meantime the EPA is wanting to shut down coal plants and require the next generation style coal plants.
“They need enhanced oil recovery to give them value for capturing the CO2 to do the shutdowns. In an ironic fashion, one side is needing the EOR and the other side is making it impossible for us to do it. The Clean Air Act side of EPA is trying to shut down the coal plant. The Safe Drinking Water side is saying we have to make the regulatory world complicated. It’s weird. Even the environmental people are saying this needs to get straightened out at the EPA.”
Until this election year is over, though, not much is expected to be resolved on the federal government level.
Lana Cunningham is a freelance writer who has lived in Midland since it was a pleasant city of 60,000 people.