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Geologic Storage is Permanent: An FAQ with Bruce Hill

March 9, 2021 Work Area: Carbon Capture

Carbon capture technologies are essential tools to reduce today’s industrial CO₂ emissions, providing a transition pathway from fossil fuels to zero-carbon energy alternatives being developed today as well as to remove CO₂ directly from the atmosphere.

In order for carbon capture to be effective, storage of those captured emissions must be permanent. Carbon capture is picking up momentum now with more than thirty proposed carbon capture projects that have been kindled by the 45Q tax credits. This has spurred inquiries about geologic options for storing captured carbon dioxide (CO₂) as well as questions about whether CO₂ stored in geologic formations will remain there permanently.

In this blog I will answer frequently asked questions to illustrate how geologic CO₂ storage does indeed provide long-term, low-risk, and permanent reduction of CO₂ emissions. A key takeaway from this FAQ is the fact is that it is extremely unlikely that well-regulated injections of CO₂ into deep geologic formations at properly sited projects, will ever reach the atmosphere in significant quantities. Multiple lines of evidence for permanence begin with what we know about rocks and geologic formations. “Permanent” here, means that CO₂ injected for storage will remain in the subsurface and will never reach the atmosphere.

Jump to FAQ:


How does Geologic Storage of CO₂ work?

Geologic storage in its simplest form takes place in a porous rock capped by an impermeable rock. To find subsurface options for storing large volumes of CO₂, we must look hard to seek out very deep—no less than one-half mile deep – formations of sedimentary rocks, such as sandstones and limestone and dolomites or that are porous enough to hold CO₂. Such storage formations are not right underfoot, they are not caves, instead, they are deep porous rocks, tightly bound by impermeable formations above, and vertically separated from the surface. In geology we also talk about traps within these formations that keep fluids and gases from migrating; there are several different kinds of geologic structures that trap CO₂, including the well-known upside-down bowl type formation that geologists call anticlines or domes (illustrated below).

Some of the thickest and best potential storage formations are in the Gulf of Mexico region (onshore and offshore) where the Mississippi River, and its ancestral predecessor, for millions of years has laid down marine sedimentary sequences where the river dumps its sediments in seawater forming the Mississippi Delta. The Delta is a staggering several miles in thickness as a result of the underlining crust sagging and therefore accommodating more deposits as the Mississippi drops its load of sand. Storage formations such as these are highly permeable, have adequate spaces between grains, filled in part by salty water, such that they can serve as geologic sponges. We call sequestration of CO₂ in these rocks saline storage. These formations ensure permanent storage because they are characterized by repetitive sequences of overlying impermeable rock such as shale, or other tight, well cemented-together rock layers that fluids and gases may not pass through, known as caprock. This association of porous reservoir rock and impermeable shale is a product of millions of years of repetitive tectonic and sea level processes resulting in shallower and deeper water environments. With these spectacular storage formations, this region could be a destination for much of the mid-continent’s captured CO₂. Reservoir and caprock sequences can also be formed in non-marine continental environments by streams and lakes and by wind in desert environments. All of these geologic settings are represented in the stupendous geology of the Grand Canyon. Such alternating sandstone and shale layers are commonly repeated and stacked in such a way that they can even accept CO₂ at multiple depths creating the opportunity for what is called stacked storage.

Grand Canyon rock layers
 

This Grand Canyon vista illustrates the one-mile depth of typical CO₂ injections, and the thick overburden of strata—repeated stacks of sandstones, limestones and shale, much of it impermeable–that buoyant CO₂ would need to pass through to reach the surface. Storage of captured supercritical CO₂ must occur at a depth of at least a half mile.

How is CO₂ trapped?

CO₂ becomes trapped or locked into the formation, as it travels through porous rock. In geologic storage, captured CO₂ is injected into porous rock, not as a gas, but as a very compressed liquid-like form called supercritical CO₂. Carbon dioxide in this state is extremely fluid and easily can pass through the pore spaces in rock as it approaches a physical trap. Yet, as it does so, some of the CO₂ “snaps off,” as geophysicists say, and remains locked into the rock pores. We call this capillary or residual trapping because capillary action holds the CO₂ behind in the rock pores. As the plume of CO₂ that’s been injected travels into and through the rock into the reservoir, the plume becomes diminished in size and force, such that it can only go so far. The CO₂ therefore does not maintain enough momentum to travel buoyantly up through such a vertically thick sequence of rocks. As a result, this residual trapping provides some help in reducing the likelihood that CO₂ would migrate unexpectedly through a half mile of porous rock and to the atmosphere. In addition to capillary trapping, injected CO₂ also is dissolved in the saline formation brine water. Solubility trapping is important because it dissolves the free-phase CO₂ into the brine, reducing the potential for vertical migration in the gas phase. In fact, under some conditions, if the CO₂ -bearing brine is dense, it may actually sink lower in the formation. Finally, over time, in the presence of adequate calcium, CO₂ may be used up in forming calcium carbonate minerals in the formation, depending on the local geochemical makeup of the rocks and surrounding brine.

CO2 trapping diagram

Following injection, several trapping mechanisms ensure that CO₂ prevents migration to the surface. Stratigraphic trapping is the physical trapping of CO₂ under impermeable layers like shales. Residual trapping is the progressive immobilization of CO₂ trapped in pores by capillary pressure as the plume passes through the rock. Solubility trapping is CO₂ trapped by dissolving in the saline formation water. Mineral trapping is the formation of minerals over the long term in certain formations, such as limestones or calcite cemented sandstones. Source: IPCC, 2005.

 

Can faults and fractures allow injected CO₂ to migrate to the surface?

Faulting and fracturing may pose a risk to stored CO₂ if they provide a route around traps to the surface. In older rocks, however, existing faults and fractures can be filled in with minerals, or mineralized, such that they actually provide excellent traps where impermeable formations have been tectonically juxtaposed against permeable ones. So, where a fault crops up in a geologic review in preparation for a storage project, it is important to determine what type of a fault it is. Robust regulations requiring such detailed geologic study is essential to identify any such features, and to determine whether they are transmissive or impermeable under expected injection conditions.

If permeability is likely, or if there is nearby earthquake risk, a site may not – and should not – qualify for a storage permit. U.S. Underground Injection Control regulations provide these protections, requiring identification and monitoring of any potentially transmissive faults and fractures.

 

Can sudden loss of CO₂ occur in geologic storage, for example as in the tragic loss of life at the Lake Nios disaster in Cameroon in 1986?

Carbon dioxide, unlike its sibling carbon monoxide (CO), is not directly toxic to humans when released to the ambient air unless the release is catastrophic – very rapid and in extremely high quantities. As discussed briefly above, and in more detail in my blog post, the Lake Nios catastrophic release was under very different conditions than would be the case for sequestered CO₂. That was caused by very large volumes of vented volcanic CO₂ which were concentrated and trapped in the cold water on the bottom of the young lake and released likely as the result of an earthquake.

Geysers are a tangible example of rapid releases of CO₂ far greater than would ever be released from a storage site; if you have been to Yellowstone National Park, you can stand by as CO₂ and water from Old Faithful periodically gush skyward from the earth without risk of asphyxia.

 

How long will CO₂ stored in geologic traps remain out of the atmosphere at well-sited storage projects?

Oil and gas deposits a valid analog for demonstrating the permanence of geologic trapping having been trapped in geologic formations for millions of years. The oil and gas that we produce from geologic formations has been trapped for millions, tens of millions, and in some cases several hundreds of millions of years. And, they would remain there for tens or hundreds of millions of years longer, if we weren’t tapping into them. Like CO₂, these hydrocarbons are buoyant relative to water, and as they form from decomposition of shale over exceedingly long periods of geologic time, they travel buoyantly through rock until such time as they are trapped by an overlying caprock sequence and form the pools, from which we now produce them.

Rock layering diagram

Highly buoyant natural gas and oil is trapped for millions of years in geologic structures such as this anticline. Other traps include faults and stratigraphic traps, juxtaposing porous rock beneath impermeable rock. Illustration: San Joachin Valley Geology.

As summarized in my 2013 paper Geologic Carbon Storage Though Enhanced Oil Recovery, penned with colleagues Susan Hovorka at the University of Texas Bureau of Economic Geology and Steve Melzer, well known EOR consultant, the U.S. has a half-century of experience in subsurface CO₂ injections and plume management. CO₂ has been utilized by the oil industry to produce more oil for half a century because of its properties in mobilizing and liberating stubborn oil from fields that have been depleted by conventional methods. We call this enhanced oil recovery or EOR. The 50-plus-year track record of the EOR industry provides additional strong evidence of the low probability of significant losses of CO₂ from leakage events. Approximately 65 million tons of CO₂ are currently transported to EOR projects through over 5,000 miles of pipelines in the U.S. and with decades of safe operations. EOR operators pay for CO₂ and treat it as a valuable commodity working to minimize and eliminate its loss through recapture and recycle processes, leak prevention, by tracking the CO₂ in the subsurface. Such tracking can include equipping wells with pressure sensors that immediately alert central operations of injection and production problems so that they can be immediately remedied. In EOR, CO₂ is managed in a pattern where an injector well may be typically surrounded by 4 producer wells, resulting in a low-pressure zone to which the injected CO₂ flows, thereby keeping the CO₂ in the field, drawn to the production wells. Recycle systems recapture any CO₂ in the oil, and reinject it, thereby progressively storing virtually all of the initially injected CO₂. When injection ceases, the formation pressure is relaxed, and the injected fluids eventually reach equilibrium with the surrounding rock.

Well-sited and carefully managed EOR-storage projects conducted with monitoring, reporting, and verification such as Core Energy in Michigan and Occidental Petroleum in Texas (and several others) are contributing to the storage of CO₂ while, at the same time producing oil. One advantage of EOR-based CO₂ sequestration is that the subsurface is well-known, as are the trapping mechanisms and capacity of the field. The risk of leakage lies in fields where there are old, unknown, poorly plugged wells. However, legacy well risk must, under the U.S. rules described below, be examined during the process of establishing the monitoring, reporting and verification (MRV) plan required for geologic storage under the Greenhouse Gas Reporting Program. Several significant abandoned (legacy) well failures have been reported in the press over the past decade, e.g., Mississippi (2007, 2011), and Texas (2015). Although some environmental damage did result from the flow of CO₂-carrying oil brines to the earth’s surface, large volumetric losses of CO₂ were not publicly reported. Moreover, these leakages were quickly discovered, remedied, and hefty fines were paid. A California study suggested that these kinds of legacy well failures were most likely early in CO₂ flooding process as the plume edge reached the insufficiently abandoned wells. As a result, any leakage from abandoned legacy wells is likely to be detected—and resolved early. In a poorly managed EOR project, risk of out-of-pattern/off-lease CO₂ migration could result in CO₂ loss from the project, in many cases to other company’s leases. While loss of oil and CO₂ out of a project could pose a problem for operators, it can be managed by keeping track of pattern balance – injected fluids must equal produced fluids – and by water curtains (injected water around the margins of an EOR site to block flow of CO₂ out of the field) while the project continues. For carbon accounting purposes, off-lease migration is counted as leaked CO₂, though, the CO₂ may never migrate all the way to the atmosphere if the migration is below the trapping sequence.

CO2 injection diagram

CO₂ that is injected a mile deep and recycled during oil production is stored in enhanced oil recovery systems such as in this illustration provided by the Core Energy project in Michigan, an EPA-approved monitoring and storage project. Taking into account lifecycle analysis, net CO₂ is stored even when the CO₂ from the fossil fuel is considered.

 

Is natural gas storage an analog for geologic CO₂ storage?

Natural gas storage indeed provides another useful analog demonstrating how CO₂ remains trapped after injection. In fact, three trillion cubic feet of natural gas are currently stored in geologic formations as part of the U.S. natural gas storage program. Natural gas is stored by injecting it into geologic storage formations (a combination of deep salt caverns, saline reservoirs and depleted oil fields). Natural gas remains secure until it is accessed as demand requires unlike the permanent storage intended in CCS projects. The first underground natural gas storage facility was established in 1915. The United States maintains 415 natural gas geologic storage facilities and 17,500 wells. These strategic reserves contain over 3 trillion cubic feet of natural gas, routinely managed over the past 25 years. The National Energy Technology Laboratory released a report in 2019 entitled Underground Natural Gas Storage – Analog Studies to Geologic Storage of CO₂ which concludes: “…experience has demonstrated that large volumes of gas can be stored safely underground and over long timeframes when the appropriate best-practices are implemented. Storing CO₂ in subsurface geologic formations at commercial scales should also be feasible if comparable best practices are demonstrated.” The report identifies antiquated well construction as the root of the uncommon, but well-known leakage events which include Aliso Canyon in 2015, illustrating the importance of identification and remedying of abandoned wells, and today’s robust well construction requirements for storage of CO₂.

Total NG Storage Field Capacity

Exhibit 2-7 taken from the 2019 NETL report showing natural gas storage facilities throughout the U.S. by type and storage size.

 

What regulations ensure safe storage?

Drinking water and air pollution regulations in the U.S. ensure that CO₂ storage is permanent. More specifically, two regulations are key to CO₂ security, once it has been injected for sequestration. The first one is the Underground Injection Control (UIC) program, part of the Safe Drinking Water Act (SDWA), that is administered by the EPA’s office of water in cooperation with states. A specific well class was established under that program in 2010 for the purposes of geologic sequestration of CO₂. UIC Class VI includes requirements to identify, via thorough geologic study and injection testing, high-quality, low-risk geologic formations, rigorous construction and mechanical integrity of injection wells, requirements for CO₂ injection (such as limiting injection pressure to 90 percent of the pressure that would fracture the formation and caprock), operational and post injection monitoring and reporting, and site closure requirements. Complementing UIC Class VI is the Clean Air Act’s Greenhouse Gas Reporting program, subpart RR which requires geologic analysis identifying and monitoring any potential leakage pathways to the atmosphere, and annual reporting and accounting. In geologic storage, integrity of the confining or trapping system in the area of elevated pressure or buoyant CO₂ must be proven by assessment of any potential leakage paths, such as flawed existing legacy wells (where storage is in depleted oil fields) or natural conduits such as transmissive fractures or faults.

In sum, the inherent characteristics of rock formation and carbon storage analogs, accompanied by regulatory requirements for planning, injecting, storing and monitoring injected CO₂, strongly suggest that well-sited geologic storage is low risk for the long-term, and is permanent. Project leakage will be a rare exception and limited in magnitude due to what we know about the physics of geologic trapping of injected CO₂, decades of experience with injection of CO₂ and other analogs, and existing regulatory requirements for selecting and operating CO₂ injection and storage sites, including requirements for injection well construction and mechanical integrity. This is the permanence needed to meet CO₂ reduction goals that geologic storage provides offers for captured CO₂ emissions.

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