RESEARCHERS TEST ‘PROMISING’ OPTION FOR CO2 STORAGE, METHANE PRODUCTION

But Industry Unlikely to Get on Board Without Carbon Price

Tamar Hallerman
GHG Monitor
06/15/12

A carbon sequestration option being tested by the Department of Energy could have the added benefit of simultaneously producing natural gas as a revenue source, but experts say that industry is unlikely to get on board with enhanced gas recovery (EGR) until gas prices spike or government sets a price on carbon. Depleted natural gas reservoirs and unmineable coal seams have the potential to permanently trap carbon dioxide emissions while also boosting methane production in the process, researchers said. But while RD&D work moves forward in earnest, experts interviewed by GHG Monitor said that unlike enhanced oil recovery—which involves the injection of CO2 to boost oil production in depleted wells—industry has been slow to adopt the technology for either production or emissions mitigation purposes. Many said they do not expect gas companies to utilize CO2 injection to boost methane recovery until gas prices dramatically increase above current levels or governments levy a price on carbon that incentivizes CCS.

In addition to depleted gas reservoirs, methane is found naturally in coal seams. Beginning with early tests in the 1990s, researchers found that when they injected CO2 into those geologic formations once they were largely depleted of their natural gas, the greenhouse gas would displace much of the remaining methane, sending the gas up to the surface where it could later be collected. Subsequently, that injected CO2 would stay trapped within the formation. The promise of both permanent CO2 storage and enhanced production prompted DOE and others to move forward on EGR lab and field tests. “We have a lot of research and demonstrations ahead before we can really feel like we’ve got it. But even though we haven’t gotten there yet, the promise is intriguing,” Advanced Resources International Vice President Michael Godec told GHG Monitor.

Depleted Gas Reservoirs

Geologists have long touted depleted natural gas reservoirs as promising host sites for CO2 storage projects. Early sequestration tests at Sleipner in the North Sea and In Salah in Algeria proved that natural gas reservoirs were ideal storage sites for CO2 given their generally well-characterized geologies and natural propensity for storage given that they naturally held hydrocarbons for thousands to millions of years. “Natural gas reservoirs are proven containers for gas, so whenever people are ready to actually do carbon sequestration, these reservoirs are there and there is no real research needed to prove that CO2 sequestration will work in [those formations],” said Curtis Oldenburg, head of the Geologic Carbon Sequestration Program at Lawrence Berkeley National Laboratory. In order to extract the methane and store the CO2, researchers inject CO2 into the reservoir, raising the pressure and temporarily increasing the rate at which methane can be extracted.  

Companies in Europe and the Middle East have done much of the early work in the field, and research in the U.S. continues to be in its early stages. Oldenburg said that research on the subject at Lawrence Berkeley National Lab has lain “dormant” in recent years. Godec said that much of the interest in gas reservoirs seems to be for CO2 storage and not as much for production. “People seem to be more intrigued by the storage side of things, because shale in many cases—and coal to a lesser extent—exists near where the power plants are. So if we can begin to figure out how to make this work, maybe we won’t have to ship CO2 halfway across the country to store it in the future,” said Godec.

Enhanced Coalbed Methane Recovery

Much of the initial EGR research sponsored by DOE’s National Energy Technology Laboratory has instead focused on the potential for CO2 storage in unmineable coal seams that are too deep, thin or otherwise ill-suited for coal extraction. Researchers inject the CO2 into those formations, which readily adsorbs to the coal while also displacing the methane, which can then be recovered. “When NETL started flooding the coals with CO2, they had a phenomenon where the CO2 was actually displacing methane off the coal. So it kind of evolved into the potential that maybe we could enhance gas recovery as well as store CO2,” said John Litynski, a carbon storage technology manager in NETL’s Office of Coal & Power R&D, in an interview with GHG Monitor.

DOE’s Regional Carbon Sequestration Partnerships conducted many of the initial field tests for CO2 injection into coal seams and other formations, helping compile DOE’s North American Carbon Storage Atlas released last month. The atlas estimates that the CO2 storage potential in unmineable seams in the United States ranges from 61 to 119 gigatonnes, with the largest potential in the Gulf Coast, West Virginia, Illinois and Wyoming. In addition to the regional partnerships, lab work and some smaller injection tests are also planned nationwide, most notably a project that intends to inject roughly 20,000 tons of CO2 into a coal seam in southwest Virginia to be overseen by Virginia Tech. Advanced Resources International has also been conducting a multi-phase EGR research project through a consortium called Coal-Seq.

Overall, Litynski said that research into coalbed methane recovery is still in its early phases. “There’s been a history over the last decade of looking at coal seams and other secondary gas or novel gas plays. I think we’re kind of in the early stages of getting out in the field, and once we get these field tests done in the next four to five years we’ll have a much better sense of how fast we can use and develop these fields and how much of the resource we’re going to get,” Litynski said. “We’ve kind of moved from the lab-scale to the field-scale, so we’re just at the beginning of this much larger field-scale work that will hopefully help us understand the benefit for storage and production.”

Industry Interest Limited

Despite NETL’s interest in EGR operations, industry has been slower in its involvement, especially compared to EOR. Oldenburg said that disparity is due to several factors. For one, he said, the price of oil has remained high for decades, and given that much of the country’s oil wells are older, EOR is considered economic in many cases. EGR, however, is disadvantaged because natural gas prices are currently at an all-time low. With the advent of unconventional extraction techniques like hydraulic fracturing, there is even less of incentive now for gas companies to pursue EGR, especially when acquiring new wells is in many cases cheaper, Oldenburg said. “Looking at the big picture here, the price of natural gas is down to the lowest it’s ever been due to hydraulic fracking. So there isn’t really a lot of incentive to go and try to enhance the production of natural gas. In fact, there’s zero incentive,” Oldenburg said. “There’s already too much of it. Contrast that with oil. The price stays really high and it’s a really valuable resource and there’s a huge incentive for people to go back to old reservoirs and increase the production from declining reservoirs, so CO2-EOR is really attractive. And we just don’t have that kind of driver with natural gas.”

The natural gas industry is also currently hesitant to pursue EGR because the methane that is produced is not very high grade, rendering it non-ideal for most uses, Oldenburg said. That is because the methane mixes with the CO2 during the EGR process, which helps dilute the product. A company must then pay to have the CO2 separated, which can be costly. “[Gas companies] want more methane, but they certainly don’t want to risk contaminating it. To them, they’re putting something that they consider a waste product into their resource,” he said. On the other hand, the oil extracted from EOR has its full economic value intact. Also at issue is the lack of captured CO2 that could be purchased for EGR, a reality that the EOR also faces on a daily basis.

Litynski said that industry interest is not as low as people think. NETL is seeing industry interest continue as it moves forward on field-scale tests, he said. “Industry takes a much longer view of these things. Gas may be cheap today, but 10 years ago it was cheap also. We’ve seen volatility in prices before, and I think industry is always looking for the next thing,” he said.

Incentives Needed

Godec and Oldenburg said that natural gas prices will have to significantly increase from its current $2 per MMBtu level in order for gas companies to look seriously at EGR as a source for production. Or at the very least, current wells will have to mature until they are near depletion levels, Godec said. “Shale development is in its initial stages of development in most of these plays. It’s really not at the point yet where they’re at the end of the regular life and now they need to figure out a way to go in and get a little more [gas production],” Godec said. He added: “If companies are going out and buying new acreage, why would they want to spend all their time squeezing a few more percentages of recovery out of when they’ve got lots of untapped potential remaining. It’s a timing issue, I think. We’re just not at the same state of maturity for shale that we are for oil.” 

Oldenburg said that perhaps the best short term incentive for companies to look to EGR in depleted reservoirs and coal seams is a high price on carbon that incentivizes technologies like CCS. “Talking about it just as enhanced gas recovery really doesn’t get you very far with industry because they don’t see that as having any upside,” Oldenburg said. “But if there is a carbon sequestration industry at some time, then you can get that conversation going because you’re going to be having an upside to storing CO2, and whether it’s credits or tax breaks there’s benefit to be made, and maybe you could get a greater benefit by enhancing gas recovery.”