CO2 Capture and Sequestration
- Carbon capture and storage (CCS) sometimes referred to as carbon capture and sequestration
The long-term isolation of carbon dioxide from the atmosphere through physical, chemical, biological, or engineered processes.
- CO2 capture
The separation and concentration of CO2 from multicomponent gas streams.
- CO2-enhanced oil recovery (EOR)
Injection of CO2 into depleted oil fields for the purpose of increasing oil production. Depending on geologic formations, this can result in long-term storage of CO2.
- Geologic storage
The long-term physical or chemical storage of CO2 in deep geological formations to isolate it indefinitely from the atmosphere.
- Oxyfired combustion
The burning of a hydrocarbon fuel (coal, oil, gas, biofuel) in an oxygen-rich or pure oxygen environment for generating high-concentration CO2 in flue gas.
- Precombustion capture
Separation of CO2 from multicomponent gas streams that are the products of fuel conversion (e.g., gasification, methanation, or fermentation) before combustion, commonly through physical solvents.
- Post-combustion capture
Separation of CO2 from multicomponent gas streams that are the products of hydrocarbon combustion, commonly through chemical solvents, sorbents, or selective membranes.
Definition of Subject
Carbon capture and storage (CCS) sometimes called carbon capture and sequestration is the long-term isolation of carbon dioxide from the atmosphere through physical, chemical, biological, or engineered processes. The purpose is to reduce anthropogenic CO2 emissions, primarily from fossil fuel usage. CCS can be a cost-effective partial solution to climate change, accounting for 10–15% of the needed abatement to limit global warming to less than 2 °C above pre-industrial levels . CCS should be considered as part of a portfolio of solutions which include efficiency, conservation, renewable energy, nuclear power, and other options.
In the broadest sense, CCS includes a range of approaches including soil carbon sequestration (e.g., through no-till farming), terrestrial biomass sequestration (e.g., through planting forests), direct ocean injection of CO2 either onto the deep seafloor or into the intermediate depths, injection into deep geological formations, or even direct conversion of CO2 to carbonate minerals. Some of these approaches are considered geoengineering (see the appropriate entry herein). All are considered in the 2005 special report by the Intergovernmental Panel on Climate Change .
There is no obvious immediate technical barrier to deployment. Systems to capture and concentrate CO2 are well-understood and widely used commercially [3, 5], and the oil and gas industry has injected CO2 for enhanced oil recovery for over 45 years.
Most countries across the globe with high CO2 emissions have published GCS storage estimates much higher than what is needed to store expected future emissions .
Testing of large-scale GCS is feasible and has begun. In many industrialized countries, large CO2 sources like power plants and refineries lie near prospective storage sites. These plants could be retrofit today, and injection begun (while bearing in mind scientific uncertainties and unknowns).
Part of this interest comes from several key documents written in the last few years that provide information on the status, economics, technology, and impact of CCS.
When coupled with improvements in energy efficiency, renewable energy supplies, fuel switching, and nuclear power, CCS helps dramatically reduce current and future emissions [5, 6, 7]. If CCS is not available as a carbon management option, it will be much more difficult and much more expensive to stabilize atmospheric CO2 emissions. Estimates of the cost of carbon abatement to 450 ppm CO2-eq without CCS are 138% higher than if CCS were to be available .
CCS is a series of sequential steps. While each step may be considered separately, they are serially coupled. The first step, commonly called “carbon capture,” is the separation of carbon dioxide from industrial flue streams, including power plants. The second step is compression of the separated CO2 to a pressure required to transport, use, or otherwise store the CO2. In practice, capture and compression are often discussed together since both processes are needed in order to render the CO2 in the state it’s ultimately needed. The third step is the transport of the CO2 via pipelines, ships, or other means to the final site. In some cases, transport may not be needed if the final site is the same location as the carbon capture process. The fourth and final step is the utilization or storage of CO2. For CO2 storage in deep geological formations, CO2 is injected as a dense, supercritical (liquid-like) phase. This step is commonly called geological carbon sequestration or GCS. If CO2 is utilized in another process, instead of stored, the CCS chain is sometimes written as CCU or CCUS. Utilization options, however, are small relative to anthropogenic CO2 emissions , though it could provide an important market opportunity for the first deployment of carbon capture technologies. Enhanced oil recovery (EOR) is one of the larger utilization options that has been key to deploying some of largest carbon capture plants thus far .
Post-combustion capture: This involves separation of CO2 from nitrogen and other gases in air, commonly with chemical sorbents (e.g., aqueous monoethanolamine (MEA)).
Pre-combustion capture: This involves conversion of fuel feedstocks (e.g., coal) into syngas via gasification, steam reformation, or partial oxidation, then shifting the syngas chemically to hydrogen and CO2, and then separating the H2 from CO2. Currently, this last step is commonly done with solvents.
Oxy-combustion: This involves combustion of fuels in a pure oxygen or O2-CO2-rich environment such that almost no nitrogen is present in the flue gas. Separation of O2 from air (N2) is required and is the main cost element.
Chemical looping combustion. This involves oxidizing a metal in air in one reactor, transporting it to another reactor and reducing it with a hydrocarbon fuel to release CO2 and water. The reduced metal is then sent back to the first reactor. Both reactors are operated as fluidized bed reactors, and the exothermic air reactor provides high temperature heat that can be converted to work .
Direct capture of high-purity streams: In these cases, CO2 is produced or generated in a chemical or industrial process and already at or above 95% purity. This requires only compression and transportation before sequestration.
Direct air capture: This involves separation of CO2 directly from the atmosphere. The very low concentrations of CO2 in air (∼400 ppm) make this approach highly energy intensive.
Industry has experience with each of these technology pathways, chiefly from operation of hydrogen plants, fertilizer plants, refineries, and natural gas processing facilities. CO2 has been separated from industrial flue streams at scales much greater than 1 Mt. CO2/year (270,000 t C/year). Similarly, CO2 has been separated from small-scale power plants for decades, and some of these have been scaled to 100–150 MWe . Large pipelines transport millions of tons of CO2 across hundreds of kilometers, and millions of tons of CO2 and other acid gases are compressed and injected into geological formations every year. Thus, a great deal is known about carbon capture, separation, and transportation, and many countries have regulatory frameworks in place to accommodate the permitting of separation facilities and pipelines.
While small-scale carbon capture processes are commercial for utilization, the scale of anthropogenic emissions is orders of magnitude larger. Hence, the lack of a market or regulatory driver remains an important barrier to wider commercial deployment for CCS [5, 14]. However, as the concepts for geological carbon sequestration are proven to be reliable for current power plant technology, improved power plant designs are expected to be able to bring down CCS costs dramatically. Several large pilot projects are testing pre-, post-, and oxyfired combustion tests at the 2–30 MW scale, a necessary precursor to broad commercial deployment. These are expected to bring CCS costs down from a current estimate of ~$70/t to ~$40/t and lower. Further R&D is needed to pursue such pathways and possibly reduce costs even further.
As the name suggests, post-combustion capture (PCC) involves capture and separation of CO2 from flue gas streams after combustion [5, 12]. It can also apply to capture from high- or low-concentration streams from industrial sources (e.g., cement manufacturing). Most PCC studies have focused on coal and gas power plants, both because of their central role in global power production and power sector is one of the largest CO2 emitters. Typically, coal-fired power plants have ~12–15% CO2, while gas-fired power plants have ~3–4% CO2. The balance of the gas mixture is typically nitrogen, oxygen, argon, and other minor components.
Chemical solvents: This process operates when flue gas contacts liquid solvents and CO2 selectively absorbs into the liquid. The CO2-rich solvent is typically heated to release the CO2 and reconstitute the solvent, which is then recirculated.
Membranes: This process separates CO2 from mixed gases as CO2 preferentially transports across a selective membrane which rejects other gases. Membranes can be made of polymers , ceramics , or more exotic materials (e.g., ). Costs and viability are a function of gas selectivity, permeance, and membrane lifetime, among other factors.
Solid sorbents: In this process, selective solid materials adsorb CO2 from mixed gas streams. These are released under different physical or chemical conditions, typically through heating the adsorbent or altering the pressure of the gas surrounding it.
Phase separation: At sufficiently low temperatures, CO2 can condense from a gas mixture and can thus be physically separated from the gas mixture. Examples include cryogenic methods and supersonic gas expansion .
The cost and performance of different systems vary as a function of loading, energy costs, capital costs, vapor pressure, process efficiency, and other issues. While some processes appear to be highly efficient, they may have cost or volumetric issues which limit deployment. Many prospective processes remain at the bench scale and have not been tested in large-scale pilots or commercial plants.
Today, most post-combustion capture is performed by liquid solvents, chiefly aqueous amines. This is in large part due to the familiarity of the technology patented in 1930  and the conventional equipment set used, such as gas stripper towers and thermal regeneration. In addition, improvements in both amine chemistry and process development have led to lowering of costs over the past few decades .
Aqueous amines have thus become the de facto standard against which other newer capture technologies are judged. Two large-scale amine capture systems have been deployed at commercial power plants , and a host of other capture technologies is currently under development at various scales.
Precombustion capture involves the removal of CO2 after a hydrocarbon fuel such as coal or natural gas is converted into syngas but before combustion in a turbine or boiler. Typically, the first step is to oxidize the carbon and make syngas and some CO2. This CO2 may be separated at this stage for partial capture (typically around 20% of carbon content). To achieve higher fractional capture, a water-gas shift reactor converts carbon monoxide and steam to CO2 and hydrogen. This increases the concentration of CO2 which is then removed using either a chemical or a physical solvent, such as Selexol™ or Rectisol™, and is compressed. This approach is used widely where coal is used for chemical feedstock.
For power production applications, the remnant hydrogen burns in a turbine to generate electricity . The likeliest configuration for these systems is an integrated gasification combined cycle (IGCC) power plant. While both IGCC and precombustion CO2 capture technologies are available today, the costs of the power generation block limit commercial deployment. About 10,000 MWth of syngas, derived predominantly from coal, are being used for power production at the end of 2016 [21, 22].
Overall, because CO2 is generated at higher pressure in the power plant, CCS on IGCC plants have lower energy penalties than other kinds of plants with carbon capture . The commercial availability of gasifiers, water-gas shift reactors, solvent towers, and gas turbines also provides some commercial advantages. However, the total capital costs for IGCC systems with CCS remain higher than conventional plants with post-combustion carbon capture.
Other precombustion plant designs show promise. For example, hydrogen and syngas from gasification can also be used to make chemicals such as ammonia, urea, or olefins. Coal-to-chemical plants can use some hydrogen like an IGCC plant and generate power as well. These polygeneration plants show some advantages in terms of economic return (e.g., ). Several US projects, including the Texas Clean Energy Project  and HECA project , are attempts to manage costs and create economic return for precombustion plants through polygeneration.
Given the high efficiency of physical solvents for precombustion, little research has focused on solvent-based precombustion technology improvement. Much research has focused on improving efficiency or reducing costs of gasification or on better plant integration to improve overall efficiency and cost. Additional research has focused on alternative separation technologies, including hydrate formation, ceramic membranes, or exotic materials. Alternative gasification technologies such as molten metal gasifiers  or underground coal gasification  remain potential avenues to large cost reductions for precombustion capture-based plant designs.
The burning of a hydrocarbon fuel (coal, oil, gas, biofuel) in an oxygen-rich or pure oxygen environment for the purpose of CO2 concentration or capture is called oxy-combustion.
One of the potential challenges with oxy-combustion is that many hydrocarbon fuels will burn extremely hot in a pure oxygen environment, making retrofits difficult and new reactors expensive. One common approach to this problem is to mix oxygen with CO2 at near atmospheric oxygen concentrations (e.g., 25% oxygen and 75% CO2) creating a “synthetic air.” The CO2 is recirculated after separation and acts to moderate the temperature and kinetics of the fuel combustion in the reactor. This approach is considered promising for retrofits, both in the power sector (subcritical and supercritical pulverized coal boilers) and in the industrial sector (e.g., in catalytic crackers common in hydrocarbon refining).
An alternative approach is to reduce the amount of fuel in the oxygen by staging the combustion. In this process, the fuel is introduced in stages, such that the temperature is controlled at each stage. Each stage is also operated at elevated pressure which partially offsets the amount of CO2 compression after the last stage.
The primary cost of oxyfired combustion is the cost of oxygen separation from air. The air separation unit (ASU) requires substantial capital and operating costs. There are also some specific technical considerations associated with the operating pressure of the combustion unit. If the reactor burns its fuel at lower than atmospheric pressure (a common configuration for boilers), then there is a risk of air leaking into the reactor and contaminating the stream with nitrogen.
Chemical looping  is considered an oxyfiring variant, although in most ways the technology is radically different from synthetic air combustion. Instead, a metal is oxidized, creating heat which can be used to run a steam cycle. Most commonly, the process is configured with two interconnected fluidized bed reactors: an air reactor and a fuel reactor. The solid oxygen carrier is circulated between the air and fuel reactors, and the metal oxide is reduced in the second stage. This process remains promising, in large part due to the very high theoretical conversion efficiencies (as high as 80%). However, no reactors larger than benchtop have proven viable yet, and questions remain about the operation, longevity, and stability of the metal oxide carriers.
Direct Air Capture (DAC)
DAC is not an economically viable approach.
Generally, low-carbon power and energy are best used directly to minimize losses rather than used for DAC.
Eventually, DAC could play a role in capture and storage from decentralized sources of CO2, such as vehicles, ships, or planes.
While the situation may change with CO2 demand and price, the consensus today is that the economics and engineering of DAC remain formidable and difficult to overcome relative to removing CO2 from more concentrated streams.
Saline formations contain brine in their pore volumes, commonly with salinities greater than 10,000 ppm. Because CO2 is buoyant in most geological settings, target saline formations require a cap rock or sealing unit above the main injection zone.
Depleted oil and gas fields have some combination of water and hydrocarbons in their pore volumes. In some cases, economic gains can be achieved through enhanced oil recovery or enhanced gas recovery [8, 30, 31]. Substantial CO2-enhanced oil recovery already occurs in the United States with both natural and anthropogenic CO2. These fields provide much of the knowledge base available about the potential issues related to CO2 sequestration.
Deep coal seams, often called unmineable coal seams, are composed of organic minerals with brines and gases in their pore and fracture volumes that can preferentially adsorb and bind CO2 as well as store it in pores and minor fractures. These targets present some challenges in that coals are relatively low permeability units, presenting challenges to injection.
Because of their large storage potential and broad distribution, it is likely that most geological sequestration will occur in saline formations. However, initial projects have been proposed for depleted oil and gas fields, accompanying enhanced oil recovery, due to the high density and quality of subsurface data and the potential for economic return. Although there remains some economic potential for enhanced coal bed methane recovery, much less is known about this style of sequestration [2, 32, 33, 34]. Even less is known about sequestration in basalts. As such, many are not convinced of the economic viability of sequestration projects in coal, basalts, or oil shales given today’s technology and understanding .
Storage of large CO2 volumes in geological formations requires that the CO2 be relatively dense, so that storage capacity is efficiently used. Given typical geothermal gradients and hydrostatic loads, CO2 is likely to be in a supercritical state at most target sites greater than 800 m depth (e.g., ). At the likely range of injection pressures and temperatures for most projects, CO2 would be buoyant relative to the in situ brine.
Consequently, trapping mechanisms are needed to store CO2 effectively. For depleted oil and gas fields or for saline formations, CO2 storage mechanisms are reasonably well defined and understood. CO2 sequestration targets will require physical barriers to CO2 migration out of the crust to the surface. These barriers will commonly take the form of impermeable layers (e.g., shales, evaporites) overlying the sequestration target. This storage mechanism is highly or directly analogous to that of hydrocarbon trapping, natural gas storage, and natural CO2 accumulations. At the pore scale, capillary forces can immobilize a substantial fraction of a dispersed CO2 bubble, commonly measured to be between 5% and 25% of the CO2-bearing pore volume. The volume of CO2 trapped as a residual phase is highly sensitive to pore geometry and consequently is difficult to predict; however, standard techniques can measure residual phase trapping directly in the laboratory with rock samples.
Once in the pore volume, the CO2 will dissolve into other pore fluids, including hydrocarbon species (oil and gas) or brines. Depending on the fluid composition and reservoir condition, this may occur rapidly (seconds to minutes) or over a period of tens to hundreds of years. Once dissolved, the CO2-bearing brines are denser than the original brines, and so the strong buoyant forces of free phase gas are replaced by small downward forces. Over longer time scales (hundreds to thousands of years), the dissolved CO2 may react with minerals in the rock volume to dissolve or precipitate new carbonate minerals. For the majority of the rock volume and major minerals, this process is slow and may take hundreds to thousands of years to achieve substantial storage volumes. Precipitation of carbonate minerals permanently binds CO2 in the subsurface; dissolution of minerals generally traps CO2 as an ionic species (usually bicarbonate) in the pore fluid.
Although work remains to characterize and quantify these mechanisms, the current level of understanding can be used today to develop estimates of the percentage of CO2 that can be stored over some period of time. Confidence in these estimates is bolstered by studies of hydrocarbon systems, natural gas storage operations, hazardous waste injection, and CO2-enhanced oil recovery (CO2-EOR). Current evaluations of CCS effectiveness based on the current understanding of trapping mechanisms estimate that more than 99.9% of injected CO2 can be reliably stored over 100 years, and it is likely that 99% of CO2 can be reliably stored for 1,000 years . These estimates assume careful siting, due diligence before injection, and appropriate management of injection and reflect the view that the crust contains many sites that are generally well configured to store CO2 effectively.
Large-Scale Commercial Deployment
Projects must be large in scale, roughly in the order of 1 Mt/year CO2 or more.
There must be minimal leakage from the underground storage reservoirs back to the atmosphere.
There must be minimal impact on other uses of the subsurface environment and the resources it contains.
The issue of scale dominates deployment of GCS [5, 39]. These volumes would have geological carbon sequestration, providing 25–75 Gt C over 50 years or 15–43% of emissions reduction needed to stabilize atmospheric CO2 levels at 550 ppm .
Below are summaries of three large-scale injection projects, some of which have an ambitious scientific program that includes monitoring and verification.
Petra Nova Parish Holdings, LLC
The Petra Nova Parish Holdings project offers the potential to significantly reduce CO2 emissions from existing coal-fueled electric power generation by demonstrating a combined commercial-scale post-combustion carbon capture technology and EOR from the WA Parish Generating Station’s coal-fired plant to the West Ranch oil field. The project’s specific objectives include (1) remove CO2 from treated flue gas from an existing coal-fired electrical generating station and (2) compress and transport pipeline-quality CO2 to a storage site for use in EOR .
The proposed benefits include the capture and storage of up to 1.4 million metric tons of CO2 per year from a flue gas stream, increased oil production from CO2-enhanced oil recovery, and the incorporation of CO2 capture technologies within existing coal-fueled power generation plants, which allows them to continue producing energy while meeting environmental sustainability goals . The project has been operating since January 2017 .
Archer Daniels Midland Company
The Archer Daniels Midland Company is testing large-scale industrial CCS technologies through the development and demonstration of an integrated system in the processing and transportation of CO2 from an ethanol plant to saline reservoir within the Mt. Simon Sandstone formation. Part of the Illinois Industrial Carbon Capture and Storage (Illinois ICCS) project, the effort offers an opportunity to collect scientific and engineering data of large-scale CO2 storage in saline formations, including the injection of approximately one million tons of CO2 annually .
In 2014 SaskPower’s Boundary Dam Carbon Capture Project became the first power station in the world to effectively use CCS technology at scale. Located in Canada, the coal-burning Boundary Dam Unit #3 CCS project captures up to 1.3 million tons of CO2 per year, reducing SO2 emissions by up to 100% and CO2 by 90% . The captured carbon dioxide is injected both in oil fields in the region and a saline-filled sandstone aquifer through the Petroleum Technology Research Centre’s Aquistore Project .
Worldwide Large-Scale CO2 Sequestration Projects
Some current and pending large CO2 injection projects
Amount of CO2 stored
Project start date
PEMEX CCS Project
SECARB Development Phase – Cranfield Project
Bent County IGCC Plant
Big Sky Development Phase – Kevin Dome Project
MRCSP Development Phase – Michigan Basin Project
SWP Development Phase – Farnsworth Unit Ochiltree Project
MGSC Development Phase – Illinois Basin Decatur Project
Purdy, Sho-Vel-Tum EOR Project
SECARB Validation Phase – Stacked Storage Test
Salt Creek, Monell, Sussex Unit EOR
In Salah Gas Storage Project
Boundary Dam Integrated CCS Project
Today there are over a dozen large-scale injection projects, some of which have an ambitious scientific program that includes monitoring and verification. Each project has injected CO2 at the rate of ∼1 Mt CO2/year (∼280,000 t C/year). Each project has had a substantial supporting science program or anticipates one.
These projects have sampled a wide array of geology with varying trapping mechanisms, injection depths, reservoir types, and injectivity. Each of these projects appears to have ample injectivity and capacity for success, and none has detected CO2 leakage of any significance. In addition to the sequestration projects, many industrial applications have injected large volumes of CO2 into the subsurface. EOR operations in West Texas, New Mexico, Colorado, Wyoming, Oklahoma, Mississippi, Trinidad, Canada, and Turkey have individual injection programs as large as 3 Mt CO2/year (∼820,000 t C/year) and cumulative anthropogenic emission injections of ∼10 Mt CO2/year (2.7 Mt C/t) . It should be said that the monitoring and verification program at each site varies substantially . In the United States, EOR projects are typically monitored consistent with long-established Class II regulations, while saline projects operate under the recent and more stringent monitoring requirements for Class VI wells .
It is worth noting that many of these projects have come online recently in China, which has the potential to ramp up projects very rapidly [45, 46, 47]. It should also be noted that all of the first projects do not involve capture from a power plant but rather from industrial facilities where CO2 is available at a relatively low cost.
Science and Technology Status
As discussed above, the knowledge of trapping mechanisms and large projects provides substantial information. These are augmented by studies of naturally occurring CO2 systems, , natural gas storage facilities, hazardous waste disposal, acid gas injection, and CO2-EOR . This knowledge provides a firm foundation for commercial action and a nascent foundation for the development of regulation, standards , and legal frameworks for sequestration. GCS itself, however, drives study into specific technical and scientific challenges associated with the central elements of site characterization, selection, operation, and monitoring . Forward investigation around these topics will enhance the technical and operational understanding of commercial GCS.
Monitoring and Verification (M&V)
Monitoring and verification must detect and track CO2 in the deep subsurface near injection targets, in the shallow subsurface, and above ground. Monitoring and verification studies are a chief focus of many applied research efforts. The US Department of Energy has defined M&V technology development, testing, and deployment as a key element to their technology roadmap ). The National Energy Technology Laboratory has published several versions of a best practice manual on Monitoring, Verification, and Accounting (MVA) for Geologic Storage Projects, which discussed tools, approaches, regulatory regimes, and lessons learned from application in the field .
The European Union CO2ReMoVe effort was dedicated to monitoring and verification, and the industry-led CO2 Capture Project continues to study monitoring in commercial settings . Some form of M&V will be required at commercial sites, but the extent of monitoring required by regulators, operators, or financiers remains uncertain. Many geophysical and geochemical methods are sufficiently well understood for them to be used to make reasonable performance predictions at candidate storage sites [50, 52].
Characterize a site.
Design and operate the project.
Monitor the CO2 injection.
Mitigate problems that might arise.
Close and abandon the project.
Although this knowledge is currently being brought to bear on specific injection projects around the world, greater work is needed to codify and develop tools, regulations, and standards for deployment of multiple million ton injections in thousands of wells nationwide and worldwide across a range of geological settings. This affects both sides of the deployment rubric over the project life cycle. Potential operators must execute a set of tasks to prepare for and implement permitting and injection operations. Similarly, potential regulators, investors, insurers, and public stakeholders require information to make decisions. Part of the challenge is to provide a technical basis for each set of actors to make decisions concerning the minimal amount of information needed to serve all stakeholders.
While many possible goals and terms may be pursued in site characterization, it is difficult to imagine the success of a large-scale injection project without knowledge of three parameters. These are injectivity, capacity, and effectiveness . In general terms, injectivity and capacity may be estimated by conventional means, such as core analysis, regional and local structural and stratigraphic mapping, and simple multiphase fluid flow simulations. However, there are explicit standard measures of effectiveness. Ultimately, characterizations must rely on estimates of geomechanical integrity, hydrodynamic stability, and seal continuity for the rock system, fault system, and well system [55, 56, 57, 58, 59].
Given this complexity, it has been difficult to get broadly acceptable guidelines on what constitutes effective storage. The World Resources Institute  proposed a set of guidelines to potential operators based on a working group of over 40 experts ranging from geoscientists to lawyers and regulators. More recently, an international group has been brought together to establish standards for carbon storage based on the knowledge from several large and small storage projects to date, including monitoring and verification, risk management, and regulatory guidelines .
Hazards Assessment and Risk Management
Supercritical CO2 is buoyant and will seek the Earth’s surface; therefore, CO2 injection carries the possibility of leakage. Importantly, CO2 leakage risk will not be uniform across all sites; thus CO2 storage sites will have to demonstrate minimal risk potential in their site characterization plans [50, 61]. Based on analogous experience in CO2 injection such as acid gas disposal and enhanced oil recovery, these risks appear to be less than those of current oil and gas operations .
Hazards associated with the release of the carbon dioxide to the Earth surface
Hazards associated with release into groundwater and subsequent degradation
Hazards associated with Earth movement caused by the injection process itself
The hazards themselves in turn are associated with failure mechanisms and triggers. Potential triggering of events associated with these hazards could lead to undesired consequences. As such, it is an important goal to identify and understand these hazards in order to avoid triggering hazard events. Identification and characterization of these hazards are the critical first steps to managing the risks at a site. They also serve as the basis for a quantitative probabilistic risk assessment (PRA). A robust PRA is still challenging due to substantial scientific and technical gaps. However, the hazards associated with a site can be identified, mapped, characterized, and parameterized sufficiently to avoid failure or (alternatively) avoid selecting a poor site.
The management of risks involves analysis and evaluation of risk factors, as well as ranking and prioritizing risks based on the assessment of probability (frequency) and magnitude (severity) . Several risk assessment factors include (1) environment, (2) health and safety, (3) technical, (4) cost, (5) reputation, and (6) schedule . An often-cited approach to help understand and categorize the risks associated with GCS projects is the features, events, and processes, or FEPs, approach [62, 63].
A summary of geologic carbon storage risk assessment tools
Carbon Storage Scenario Identification Framework (CASSIF), TNO
Vulnerability Evaluation Framework (VEF), US EPA
Screening and Ranking Framework (SRF), LBNL
Qualitative, expert-elicited probabilities
CO2QUALSTORE guideline, DNV
Qualitative/semiquantitative, with “panel” inputs
Quintessa FEP database
Semiquantitative, FEPs screened by experts
TNO risk assessment methodology
Semiquantitative, expert-elicited probability and consequence matrices
Risk Identification and Strategy using Quantitative Evaluation (RISQUE), URS
Semiquantitative, expert-elicited probability and consequence matrices
CarbonWorkFlow process for long-term CO2 storage
Semiquantitative, FEPs ranked through expert elicitation using a risk matrix approach
Performance Assessment (PA), Quintessa
Quantitative, evidence-support (three-valued) logic (ESL) Distinguishes cases of poor-quality data from uncertain data
CarbonSCORE software to pre-assess potential CO2 storage sites
Quantitative, all evaluated criteria are weighted, jointly evaluated, and summarized
Oxand Performance & Risk (P&RTM) Methodology
Quantitative, risk matrix evaluation
Quantitative, hybrid system-process model
Quantitative, hybrid system-process model evolved from CO2-PENS
Certification Framework (CF), LBNL
Quantitative, system-level model, probabilities partly calculated using fuzzy logic
A number of issues arise from CCS regarding water use and quality. These include additional water use due to process steam and additional hear requirements in the plants, displacement of in situ brines, and potential risks to groundwater quality from unplanned CO2 leakage . Additional water needs for surface facilities are highly sensitive to capture process and plant type, ranging from 20% to 110% additional water consumption . CO2 injected into saline formations necessarily interacts with water and brines there. This interaction includes displacement of the brines there, local drying of the reservoir, and dissolution of CO2 into brine forming carbon acid. Early research focused on the potential risks and impacts of acid brine formation, ultimately concluding that these risks are small.
Injection also creates a pressure transient in the reservoir which increases through time. In the right context, this pressure can drive water co-production (enhanced water recovery) and even drive surface desalination processes [68, 69]. Based on preliminary calculations, it appears that water co-production can cut the water demands for an integrated CCS plant by 50% or produce freshwater for agricultural or civil use. More work is needed to understand the viability of this technical approach.
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