4 
Carbon Storage and Utilization

What to do with the CO₂—that is the question. Should we put it back into the Earth from whence it came? Should we sell it as a feedstock to make useful products, thereby recouping at least some of the cost of capture? Should we turn it into rocks, stabilizing it for millions of years? Researchers are exploring all of these options.

To be effective in fighting climate change, we need to keep the CO₂ out of the atmosphere for thousands of years or more. The most promising option today is injecting the CO₂ deep into the Earth in porous geologic formations—the primary focus of this chapter. I will briefly review other storage options, specifically the ocean, mineralization, basalts, and coal seams, and conclude with a discussion of CO₂ utilization: a hot-button topic in the world of carbon capture. In theory, it is so much better to sell the CO₂ for useful purposes rather than deep-six it in the Earth. However, as will be shown, the opportunities for effective utilization are quite limited. Nevertheless, we must first transport the CO₂ from the capture facility to where it will be stored or used.

CO₂ Transport

Commercial technologies for CO₂ transport are readily available from vendors. Tanker trucks transport tens of tonnes of CO₂ for distances up to 200–300 km. For the millions of tonnes of CO₂ per year associated with carbon capture, pipelines are the preferred mode, with ship transport a possible alternative under certain circumstances.

There are over 6,000 km of CO₂ pipelines installed in the United States to support enhanced oil recovery operations (see next section).¹ To ensure single-phase flow and to maintain high densities in the pipeline, the pressure is kept above the CO₂ critical pressure of 73.9 bar. To protect against corrosion, water is removed to keep its concentration less than 50 ppm. Pipeline transport scales well; doubling the pipe diameter increases the pipeline capacity by a factor of four. A 45 cm diameter pipe can transport 10 MtCO₂/year for a cost of about $1/tCO₂/100 km.² By comparison, transport of small quantities in tanker trucks will cost about $7/tCO₂/100 km.³

Ships, like tanker trucks, transport CO₂ as a refrigerated liquid under pressure. As discussed in chapter 3, this is because CO₂ does not exist as a liquid at atmospheric pressure. Typical conditions for the small quantities of CO₂ transported today are −20°C and 20 bar. For the larger quantities that will need to be transported for CCS, transport conditions will be closer to −50°C and 7 bar.⁴ For shipping large quantities of CO₂ over distances of hundreds of kilometers or less, ship transport will be more expensive than pipelines; however, at longer distances, ship transport can become competitive. Situations that require flexibility may also favor ship transport. For example, Norway is considering developing a storage facility in the North Sea that would accept CO₂ from numerous sites in several countries. They are planning to use ship transport, not pipelines, because it gives them more flexibility in the development of this project.

Geologic Storage

The Permian Basin in West Texas is the major oil-producing region in the United States. Oil fields that have been producing crude oil for decades slow down and produce less oil each year, but a large fraction of the original oil remains trapped in the pores of the rock. To continue extracting more oil from these existing reservoirs, the oil industry is always trying to develop Enhanced Oil Recovery (EOR) technologies. One such EOR technology, CO₂ flooding, was first used in 1972 in Scurry County, Texas. CO₂ injected into the oil reservoir helps mobilize the trapped oil so it can flow to a production well. Eventually the CO₂ will break through and flow up a production well, where it will be separated from the oil for reinjection into the reservoir. Today, the Permian Basin has over 70 CO₂ EOR projects and is crisscrossed by over 4000 km of CO₂ pipelines. Oil field operators purchase and inject tens of millions of tons of CO₂ a year.⁵

The Permian Basin is by far the world’s largest collection of CO₂ EOR operations because they have access to cheap CO₂ from natural reservoirs. Most gas reservoirs are primarily methane, with varying amounts of other gases, including CO₂. In the western United States, there are a number of large gas reservoirs that contain nearly pure CO₂, including Bravo Dome in New Mexico, and McElmo Dome and Sheep Mountain in Colorado. Pipelines bring the CO₂ to the oil producing fields of the Permian Basin. It is this cheap CO₂, generally delivered for under $20/tCO₂, which makes these EOR operations successful.⁶ Additionally, as will be discussed in the next chapter, some anthropogenic CO₂ sources using carbon capture feed their CO₂ into this pipeline network to help meet the growing demand for CO₂ EOR.

Using CO₂ to help produce CO₂-emitting oil will not solve the climate change problem by itself, but it has made significant contributions to CCS. Most of the injected CO₂ will remain in the reservoir after oil production ceases, significantly lowering the net carbon intensity of the oil produced. More important though, EOR has developed the operational methods and history to show that large amounts of CO₂ can be injected safely into geologic formations. These EOR projects have financed a CO₂ pipeline network and helped develop CO₂ handling technology. This knowledge and infrastructure were instrumental to many CCS projects that followed. As such, CO₂ EOR has become an important stepping-stone for the development and deployment of CCS.

Target Formations

A good geologic storage formation for CO₂ must meet four main criteria. First, the target formation must be porous with good permeability. A bucket of sand meets this criterion. If you add water to the bucket, the water easily flows through the sand because of its high permeability, its pores the spaces between the grains that the water fills. Deep in the Earth, sandstone formations, found around the world in sedimentary basins, exhibit similar characteristics to our bucket of sand. Second, the target formation must be below 800 m depth. To ensure that the CO₂ remains in a dense liquid-like phase, it needs to be stored at pressures greater than its critical pressure of 73.9 bar. The average hydrostatic pressure at 800 m depth is 80 bar, so anything deeper will safely satisfy this criterion. For CO₂ storage reservoirs, typical depths are 2–3 km, with pressures of 200–300 bar and temperatures of 60–100°C. This results in a range of specific gravities for the CO_2, from 0.5 to 0.8. Compare this to a CO₂ gas with a specific gravity of about 0.001 or to liquid water with a specific gravity of one: being much denser than a gas, much more CO₂ can be stored in the pore space of the formation. Being less dense than water means that the CO₂ is buoyant and will want to rise up in the formation. This leads to the next criteria: the target formation must have an impermeable caprock. Since the CO₂ is buoyant, an impermeable caprock will keep it trapped in the target formation. Thick shale layers, consisting primarily of clay, make an excellent caprock. Finally, it is desirable for a good storage formation to be thick and continuous over large areas in order to be able to store large volumes of CO₂.

The geological formations that meet the above criteria fall into two categories: oil and gas reservoirs, or deep saline formations. Oil and gas reservoirs have proved that they can hold hydrocarbons for millions of years. This bolsters confidence that they can store CO₂ for a long time. Because they have been producing hydrocarbons, their flow characteristics are well known. Questions do arise about whether the wells drilled into the reservoirs and the removal of the hydrocarbons have compromised their integrity. Most capacity lies with depleted oil and gas reservoirs, but active oil reservoirs have become a high-priority target for CCS because of the income generated by EOR. Deep saline formations are filled with salty water (i.e., saline) and are much deeper in the Earth than drinking water aquifers. Because they have little or no economic value, very few wells have been drilled into them, making the data regarding their physical characteristics sparse. Ultimately, these deep saline formations will store the most CO₂ because they are widespread and have much larger volumes than oil and gas reservoirs.

Trapping Mechanisms

Geologic storage of CO₂ is the mirror image of oil and gas production. Instead of drilling wells into the Earth to extract oil and gas, wells are drilled to inject CO₂. Injection requires the CO₂ to be pressurized, typically in the range of 100–150 bar. As it moves down the well, the pressure will rise due to weight of the CO₂ in the pipe. For injection, the pressure in the pipe must be higher than the formation pressure, so that at the perforated interval at the bottom of the well, the pressure pushes the CO₂ into the formation, where it displaces water and moves into the pores of the rock, forming a plume.

Once the CO₂ enters into the formation, the laws of nature take over and determine its fate. The better we can characterize a formation in terms of its structure, dimensions, and physical properties, the better we can model how the CO₂ will move through the formation and what will happen to the plume over time. The formation will experience a pressure rise associated with the injected CO₂. The magnitude of the pressure rise will depend on the formation properties, both in the area of the plume and far away, where the formation is compressed to accommodate water displaced by the CO₂. The section below, on induced seismicity, will explore the implications of this pressure rise.

Four main mechanisms, working together, trap the CO₂ in the formation: structural trapping, capillary trapping, solubility trapping, and mineral trapping.⁷ Structural trapping refers to the CO₂ being beneath the formation’s impermeable caprock. As the CO₂ plume rises, it will eventually run into the caprock, which will stop its rise and keep the plume in the formation. The geometry of the caprock can form a trap, like an inverted bowl or hat, which then fills with CO₂ and limits the lateral extent of the plume.

Capillary trapping, sometimes referred to as residual trapping, refers to the CO₂ being immobilized in the pore space as the plume moves through the formation. It is a function of water and CO₂ competing to move though the small pores between sand grains. A capillary trapping situation that most of us can relate to is dripping oil on our shirt while eating. You can try to rub out the stain using water, but that will not work. The oil is trapped in the holes between cloth fibers. In this sense, capillary trapping is a very secure storage mechanism.

Solubility trapping refers to the dissolution of CO₂ into the formation water. Some CO₂ dissolves rapidly at first contact with water at the plume edge, saturating the water. Behind the plume front, no more CO₂ can dissolve unless new unsaturated water encounters the CO₂. The CO₂-saturated water is denser than unsaturated water, meaning it will sink, which is one way of bringing more unsaturated water in contact with the CO₂. Increasing the amount of dissolved CO₂ increases storage security.

Mineral trapping refers to the reaction of formation minerals with dissolved CO₂ to incorporate the CO₂ into new minerals, most commonly calcite. The rate and ultimate amount of mineral trapping depends on the rate of dissolution of CO_2, and the availability of reactive minerals in the formation. Most sandstones meet both needs only to a limited extent. Mineral trapping removes CO₂ from the plume very slowly. However, as discussed in following sections, some rock types such as basalt contain reactive minerals, and dissolving CO₂ prior to injection can accelerate reactions.

The trapping mechanisms discussed above create storage security. The multiple barriers relying on different physics are additive, so that even if one system is flawed (e.g., the caprock), most of the CO₂ will be retained in the formation.

Storage Security and Monitoring

The number one question people ask about geologic CO₂ storage is: “Will it leak?” The IPCC, in typical bureaucratic language, answers as follows: “Observations from engineered and natural analogues as well as models suggest that the fraction retained in appropriately selected and managed geological reservoirs is very likely to exceed 99% over 100 years and is likely to exceed 99% over 1000 years.”⁸ The IPCC defines very likely as 90–99 percent and likely as 66–90 percent. Allow me to translate: if done properly, there will be no significant leakage. So why the longwinded statement? First, as seen for all types of projects, not all of them are “appropriately managed.” Second, the selection of an appropriate reservoir for geologic storage is crucial to success. Finally, since geologists think on geological timescales, they will not guarantee that a fluid injected in the ground will never come out; there are simply too many changes in Earth systems on geologic time­scales for that. However, if an appropriate reservoir is selected, and if the project is appropriately managed, we should expect little or no leakage over human timescales of interest.

It is important to understand the nature of any potential leakage. The CO₂ is being injected into a porous medium, as opposed to a big cavity in the Earth. Therefore, if leakage occurs, it is more like squeezing a wet sponge rather than popping a water balloon. This means the chances of a large and sustained rapid release of CO₂ are small. Leakage would only happen if the CO₂ found a pathway from the formation to the surface. Based on decades of injection and EOR experience, wells drilled into or through the storage formation are the most likely failure points. While wells are designed to isolate fluids (such as oil, gas and brine) in one zone from fluids (such as freshwater) in other zones, engineering failures have occurred. That is why the US EPA requires a survey and, if needed, remediation of all wells before it will issue a permit for any injection, including geologic storage of CO₂. A second potential pathway is a geologic flaw in the caprock. Certain types of faults can provide these, and a good characterization of a reservoir should be able to detect the existence of faults. Fracturing the caprock could also open up pathways for CO₂ to escape, but this will only happen if the pressure rise from the injection gets too large. Properly managed projects will monitor formation pressure and adjust operations to keep the formation pressure within safe limits.

Since maintaining proper formation pressure is critical and CO₂ injection can increase formation pressure, the greatest risk for problems to occur is near the injection wells while active injection is taking place. Once the injection stops, the pressure will start to drop back down as the pressure equalizes throughout the formation. Models can help design systems to stay within safe pressure limits. However, there will still be uncertainty in understanding the formation properties, so monitoring the pressure is not only crucial, but also required by EPA, to adjust operations if necessary.

Both during and after injection, numerous monitoring techniques are available to ensure sites are both appropriately selected and managed. Making direct measurements of pressure and temperature involves putting instruments at or down the injection well. Projects may also drill observation wells to take measurements at other locations in the formation. A number of seismic techniques allows one to image the CO₂ in the formation. Seismic techniques involve sending sound waves into the Earth; the waves will travel at different speeds, depending of the density of the medium through which they are traveling. Since the density of CO₂-filled rock is different from brine-filled rock, it allows one to locate the CO₂ plume. Numerous other monitoring techniques, including surface monitoring to detect any CO₂ that migrates to the surface, are also available. In putting together a monitoring program for a project, there are trade-offs between the level of monitoring versus its cost. Initial demonstration projects usually have extensive monitoring programs in order to gather as much information as possible to improve the knowledge on how CO₂ behaves in the subsurface. Commercial projects are developing more targeted monitoring packages to comply with regulatory requirements for safely injecting the CO₂.

There is a debate about how long to monitor a formation after injection stops. The US EPA regulations for CO₂ storage wells have set a default time of fifty years post-injection monitoring, with possibilities to reduce the time based on site-specific data and modeling. Many in industry and elsewhere feel that this requirement is excessive and shorter post-injection monitoring periods are adequate. Impacts of elevated CO₂ levels are described below:

At low concentrations (less than 1% by volume), CO₂ causes no ill effects on humans, fauna or flora. In fact, CO₂ is essential for life, being a critical component in photosynthesis. Some greenhouses purposely elevate CO₂ levels in order to “fertilize” the plants. At concentrations of about 6% by volume, CO₂ can cause nausea, vomiting, diarrhea, and irritation to mucous membranes, skin lesions and sweating. At about 10% by volume, it will cause asphyxiation.⁹

Can CO₂ escaping from geologic storage reservoirs reach the elevated concentrations that cause harmful impacts? Under most cases, the answer is no. Even at high leakage rates, CO₂ leaking from the reservoir will disperse into the atmosphere and not reach harmful concentrations. However, there are two major exceptions. CO₂ is heavier than air, so it can gather in low-lying areas on still days. If a big enough leak occurs in a topography that will gather the CO₂, it does present a risk. The second exception is enclosed structures, such as the basement of a house. This scenario is analogous to the way radon can build up in basements that are not adequately ventilated. In both of these cases, monitoring can help detect the presence of CO₂. In general, the biggest impact of CO₂ leaking from geologic storage will be the ineffectiveness of the money spent to keep that CO₂ out of the atmosphere. To date, there has been no significant leakage reported from any operating CCS projects.

Induced Seismicity

Induced seismicity refers to human-made triggering of seismic energy. Injection or withdrawals of any fluid that changes pressure within the Earth can trigger audible adjustment of rock grains and layers. Instruments can locate and measure these noises, known as microseismic events. These are small and of no concern. In fact, they are helpful in providing data about the subsurface response to injection. What is concerning is when pressure changes work to augment the stresses already in the Earth, triggering larger adjustments of rocks and large movements that are felt by people as earthquakes and that can cause damage. Large events are associated with only a very small percentage of injections, but they are unacceptable.

In 1966 at the Rocky Mountain Arsenal in Denver, Colorado, one of the first recorded instances of induced seismicity occurred as a result of disposal of contaminated fluids.¹⁰ Around this time there was a whole series of earthquakes in the Denver area, with the largest being a magnitude of 5.3. While not all the seismic activity could be connected to the fluid injections, this incident was the first to raise the issue of induced seismicity.

More recently, the injection of wastewater from oil and gas production operations has raised the induced seismicity concern:

Between the years 1973–2008, there was an average of 21 earthquakes of magnitude three and larger in the central and eastern United States. This rate jumped to an average of 99 [magnitude] 3+ earthquakes per year in 2009–2013, and the rate continues to rise. In 2014, alone, there were 659 [magnitude] 3 and larger earthquakes. Most of these earthquakes are in the magnitude 3–4 range, large enough to have been felt by many people, yet small enough to rarely cause damage. There were reports of damage from some of the larger events, including the [magnitude] 5.6 Prague, Oklahoma earthquake and the [magnitude] 5.3 Trinidad, Colorado earthquake.¹¹

Risks of triggering large seismic events can be managed by selecting and properly characterizing appropriate formations and controlling pressure changes. Techniques for controlling pressure are primarily selecting formations that can accept large injection rates and limiting the injection rate in each well. Removing saline water from the formation can limit pressure rise. The biggest problem with this technique is figuring out what to do with the saline water, which can be a very nasty fluid. However, it is quite likely that new technologies will make some form of active reservoir management practical in the future.

Storage Capacity

There are many estimates for CO₂ storage capacity in the literature. The methodology employed by researchers varies considerably, so the estimates are not always directly comparable. The availability and quality of data inputs are also variable; this results in large ranges given for the estimates. For example, for US storage capacity, the DOE estimates 1877–14737 GtCO₂, while the US Geological Survey (USGS) estimates 1637–4102 GtCO₂.¹² Even at the low end of the range, these numbers are large, representing hundreds of years of US emissions.

One way used to estimate storage capacity—termed the “volumetric method”—first estimates the total water-filled pore volume in a formation. Then, an empirical efficiency factor, generally a few percent, is applied to estimate the usable volume. The efficiency factor represents the facts that the CO₂ plume will only contact a small proportion of the reservoir, and that certain parts of the reservoir may have unsuitable geologic characteristics. Multiplying the usable volume by the CO₂ density in the formation yields the storage capacity.

The volumetric method assumes that storage capacity is migration limited. The migration refers to how the CO₂ plume migrates through the pore space in the reservoir. However, since maintaining a safe reservoir pressure is essential, storage capacity can also be pressure limited. Many capacity estimates in the literature ignore the pressure limitations. When pressure limitations are included, they yield lower estimates than the volumetric method.¹³

Detailed capacity estimates have only been conducted in a few regions, such as the United States and the North Sea in Europe. Kearns et al. developed a methodology to extrapolate from these relatively known regions to give estimates for all regions worldwide.¹⁴ The basis for the extrapolation is the worldwide distribution of sedimentary basins (see figure 4). Kearns et al. estimate worldwide capacity to range from 8,000–55,000 GtCO₂. Even at the lower estimate, which does take into consideration pressure limitations, there are over two hundred years of storage at current worldwide emissions rates that are approaching 40 GtCO₂/year. The estimates are also comparable to the estimated 15,000 GtCO₂ contained in the recoverable fossil fuels (see figure 2). While the total amount of storage space appears more than adequate, its distribution across the globe is somewhat problematic (see figure 4). North America has plentiful and well-distributed storage options, but Japan and Korea have very little. China appears to have reasonable capacities, but India has significant limitations.

Figure 4 Geographical distribution of sedimentary basins and their thicknesses (courtesy of Jordan Kearns).

Source: Jordan Kearns et al., “Developing a Consistent Database for Regional Geologic CO₂ Storage Capacity Worldwide,” Energy Procedia 114 (July 2017): 4705.

One other consideration when discussing storage capacity relates to public acceptance. NIMBY (“Not In My Backyard”) sentiments can be strong. While the world shares the benefits of CO₂ storage, the abutters assume the risks. As an analogue, look at hydraulic fracturing for oil and gas production. States like Pennsylvania and North Dakota have embraced it, while states like New York have put a moratorium on it. In Europe, for the moment, offshore geologic storage projects within porous and permeable sedimentary rocks under the sea floor are operating, but onshore projects have run into resistance. Like all emerging technologies, public outreach and acceptance will be critical to its future.¹⁵

Other Storage Options

Ocean Storage

Some of the first CCS projects I worked on in the 1990s considered storing CO₂ in the oceans. Japan had great interest in this option because they lacked geologic storage options, but had relatively easy access to the deep ocean. The main concept for ocean storage is to inject the CO₂ below 800 m, where it would dissolve into the seawater. An alternate concept is to form a “CO₂ lake” on the bottom of the ocean. The 2005 IPCC Special Report on CCS contains an entire chapter on ocean storage.¹⁶

Today, ocean storage is not being actively pursued. One problem is the issue of permanence. Unlike geologic reservoirs, which are totally isolated from the atmosphere, the ocean and atmosphere exchange CO₂ as part of the carbon cycle. So, injecting CO₂ in the ocean can keep it out of the atmosphere initially, but after a number of centuries, it would equilibrate with the atmosphere. In other words, the end state would be the same whether the CO₂ was released into the ocean or atmosphere. There may be some benefits with century-scale storage, but today those benefits look small compared to permanent storage.¹⁷

Another problem is environmental. Even though local environmental impacts near the injection point can be minimized, the bigger issue is ocean acidification.¹⁸ While much of the focus on climate change is on having too much CO₂ in the atmosphere, too much CO₂ in the ocean is also associated with having a significant impact.

The bottom line on ocean storage of CO₂ is that it is a concept that has been studied and rejected. Today, there are no ongoing research programs, nor any vocal advocates, for this option.

Mineral Carbonation

Mineral trapping—one of the four mechanisms discussed above for CO₂ geologic storage—refers to CO₂ reacting with minerals in situ in a geologic formation. Mineral carbonation, sometimes referred to as mineralization, is the ex situ version of this mechanism. The process starts with mining ores, such as serpentine or olivine. Next, reacting the ore with the captured CO₂ forms carbonate rocks. This mimics the natural process of rock weathering, in which CO₂ in the air or water reacts with rocks over hundreds of thousands of years. The challenge for mineral carbonization is to speed up this process. If successful, it will provide permanent storage as well as eliminate leakage and induced seismic risks associated with geologic storage. Theoretically, this concept looks very good, because it is thermodynamically favorable, meaning that carbonates are in a lower energy state than CO₂. Practically, there are several significant barriers.

Pathways to increase reaction rates include crushing the ore to provide more surface area for reaction, increasing temperatures and increasing pressures. While laboratory experiments have shown reaction rates to improve dramatically, the costs to implement these processes will be high. One reason is the large amount of energy needed to mine and crush rocks, and to apply high temperatures and pressures. Another reason is the large amount of ore needed to react with the CO₂. For example, reacting all the carbon contained in one ton of coal requires over eight tons of serpentine ore.¹⁹ The US Department of Energy (DOE) ran a major research program on mineral carbonation at their Albany Research Center in Oregon in the early 2000s. One conclusion from that program was “the scale of ex-situ operations, requiring ~55 kt mineral/day to carbonate 100% of the CO₂ emissions from a 1 GW coal-fired power plant, may favor an in-situ methodology. Laboratory studies of in-situ mineral carbonation show promise.”²⁰

One proposed method of in situ mineral carbonization involves basalt, an igneous rock associated with volcanic activity. Basalts are highly reactive and found throughout the world. For example, India, which has limited onshore geologic storage reservoirs, has large deposits of basalts.

A recent experiment in Iceland demonstrated that basalts could mineralize CO₂ in less than 2 years.²¹ The CO₂ is dissolved in water before it is injected into the rock formation. This requirement will add costs and the issue of water availability could be problematic. Seismic and leakage risk evaluation are in early stages and outcomes are uncertain. While interesting, there is still a long way to go before basalts can be considered a viable storage option.

Coal Seams

Abandoned or uneconomic coal seams are another potential type of CO₂ storage. The CO₂ diffuses through the pore structure of coal and is physically adsorbed to it. This process is similar to removing impurities from air or water using activated carbon.

There is very little experience in injecting CO₂ into coal seams. One problem in doing so is that the coal will swell, decreasing its permeability. Like basalt, research is lacking on potential leakage or environmental impacts. Though some study continues on coal seam storage, its feasibility is a question mark.

CO₂ Utilization

One of the mantras of the sustainability movement is the 3 r’s: reduce, reuse, and recycle. In the context of carbon capture, CO₂ utilization represents the reuse/recycle option. So, aesthetically, the carbon capture and utilization option (CCU) should be preferable to the carbon capture and storage (CCS) option. Unfortunately, reality rears its ugly head, imposing significant barriers that limit the effectiveness of CCU.

Compared to the almost 40 Gt of CO₂ emitted from worldwide energy use each year, the amount used commercially is less than 1 percent of this total. Besides EOR, there is a variety of commercial uses for CO₂, such as carbonating beverages, flash freezing of foods, and as an expellant in fire extinguishers. Since CO₂ is expensive to ship in small quantities, commercial CO₂ production plants are small and widely distributed. For feedstocks, they generally take advantage of high-purity CO₂ by-products of processes like ammonia production, ethanol fermentation, and hydrogen production. In the United States, there are about 100 production plants with an average capacity of a little over 300 tCO₂/day.²² For CCU to have an impact in climate mitigation, it must expand beyond EOR and today’s limited commercial markets. The two applications getting the most attention are the use of CO₂ as a chemical feedstock to produce carbon-containing products and the conversion of CO₂ back to a fuel.

Excepting fuels, the markets for carbon-containing products are small, on the orders of 100s of MtCO₂ (0.1s of GtCO₂), compared to the 10s of GtCO₂ from energy use. While there may be some profitable niche opportunities, they do not have the scale required to be an important mitigation pathway. As the IPCC concluded, “Industrial uses [excluding EOR] of captured CO₂ … are not expected to contribute to significant abatement of CO₂ emissions.”²³ As a result, many CCU projects have focused converting CO₂ to fuels.

Fuels release their chemical energy during combustion, producing primarily H₂O and CO₂. These combustion products represent spent energy, meaning that they contain no useful chemical energy. In order to recycle the CO₂ back into fuels, you will need an energy source. Since the whole idea of CCU is to reduce CO₂ emissions, this energy source must be carbon free. All conversion processes have energy losses associated with them, typically in the range of 25 to 35 percent. For example, to convert CO₂ into one unit of energy, one must typically provide 1.3–1.5 units of energy. The requirement for carbon-free energy and the unavoidability of losses during conversion makes recycling CO₂ back to a fuel an expensive proposition. Using that carbon-free energy directly almost always turns out to be a much more cost-effective approach to reducing carbon emissions than recycling CO₂ to fuels.

Upon use, almost all the products that result from non-EOR CCU will quickly release their CO₂ to the atmosphere. There are some exceptions, such as building materials, but they are a small fraction of potential CCU applications. This has the effect of using the carbon twice: once in the original fuel and once in the CCU product. While this may have some benefit, the CO₂ in the original fuel will still end up in the atmosphere.

The role of CCU is a controversial subject in the carbon capture community. On the one hand, the idea that we can recoup some of the costs of capture and avoid storage costs by CO₂ utilization makes so much sense. For researchers, improving conversion pathways for CO₂ is an interesting topic with many potential pathways to investigate. However, the reality of large energy requirements to drive the conversion, the relatively small market size for the products made, and the fact that the CO₂ will be released to the atmosphere upon use of most products are significant obstacles. As a result, many in the carbon capture community look at CCU as an interesting topic, but more of a sideshow and not the focal point of carbon capture. Some researchers, like a recent paper in Nature Climate Change, go further: “CCU [beyond EOR] may prove to be a costly distraction, financially and politically, from the real task of mitigation.”²⁴ They argue that the narrative that CCU will make carbon capture profitable is too simplistic and may distract from developing storage capability.

I fall into the camp that looks at CCU as a bit of a sideshow. I try to keep an open mind, and realize that there may be some niche markets that can be beneficial. However, scaling up carbon capture to the required gigatonne scale to have a significant impact in climate mitigation will be through CCS, not CCU.

Notes

1. B. Suresh, Carbon Dioxide [Chemical Economics Handbook, SRI Consulting] (March 2010), 136.

2. Gemma Heddle et al., “The Economics of CO₂ Storage,” MIT Laboratory for Energy and the Environment report no. 2003–003 (August 2003): 13–26. http://sequestration.mit.edu/pdf/LFEE_2003-003_RP.pdf.

3. Suresh, Carbon Dioxide, 145.

4. Ragnhild Skagestad, “Ship Transport of CO₂ Status and Technology Gaps,” Tel-Tek report no. 2214090 (September 16, 2014): 8. http://www.gassnova.no/no/Documents/Ship_transport_TelTEK_2014.pdf.

5. J. J. Heinrich et al., “Environmental Assessment of Geologic Storage of CO₂,” MIT Laboratory for Energy and the Environment report no. 2003–002 (March 2004): 17–20. http://sequestration.mit.edu/pdf/LFEE_2003-002_RP.pdf.

6. Suresh, Carbon Dioxide, 146–147.

7. IPCC, Carbon Dioxide Capture and Storage (UK: Cambridge University Press, 2005), 208.

8. Ibid., 14.

9. Heinrich, “Environmental Assessment of Geologic Storage of CO₂,” 6.

10. Ibid., 9–10.

11. https://earthquake.usgs.gov/research/induced/overview.php.

12. Jordan Kearns et al., “Developing a Consistent Database for Regional Geologic CO₂ Storage Capacity Worldwide,” Energy Procedia 114 (July 2017): 4699.

13. M. L. Szulczewski et al., “Lifetime of Carbon Capture and Storage as a Climate-Change Mitigation Technology,” Proceedings of the National Academy of Sciences 109, no. 14 (April 2012): 5185–5189.

14. Kearns et al., “Developing a Consistent Database,” 4697–4709.

15. Josh Wolff and Howard J. Herzog, “What Lessons Can Hydraulic Fracturing Teach CCS about Social Acceptance?,” Energy Procedia 63 (2014): 7024–7042.

16. IPCC, Carbon Dioxide Capture and Storage, 227–317.

17. Howard J. Herzog, Ken Caldeira, and John Reilly, “An Issue of Permanence: Assessing the Effectiveness of Temporary Carbon Storage,” Climatic Change 59, no. 3 (August 2003): 293–310.

18. David I. Auerbach, “Impacts of Ocean CO₂ Disposal on Marine Life,” Environmental Modeling and Assessment, 2 (1997): 333–343.

19. Howard J. Herzog, “Carbon Sequestration via Mineral Carbonation: Overview and Assessment” (March 2002): 11. http://sequestration.mit.edu/pdf/carbonates.pdf.

20. W. K. O’Connor, D. C. Dahlin, G. E. Rush, S. J. Gerdemann, L. R. Penner, and D. N. Nilsen, “Aqueous Mineral Carbonation,” DOE/ARC-TR-04–002 (March 2005): 1.

21. Juerg M. Matter et al., “Rapid Carbon Mineralization for Permanent Disposal of Anthropogenic Carbon Dioxide Emissions,” Science 352, no. 6291 (June 10, 2016): 1312–1324.

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