An Assessment of the Commercial 

Availability of Carbon Dioxide 

Capture and Storage Technologies 

as of June 2009 

JJ Dooley 

CL Davidson 

RT Dahowski 

June 2009 

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Abstract: Currently, there is considerable confusion within parts of the carbon dioxide capture and 

storage (CCS) technical and regulatory communities regarding the maturity and commercial readiness of 

the technologies needed to capture, transport, inject, monitor and verify the efficacy of carbon dioxide 

(CO2) storage in deep, geologic formations. The purpose of this technical report is to address this 

confusion by discussing the state of CCS technological readiness in terms of existing commercial 

deployments of CO2 capture systems, CO2 transportation pipelines, CO2 injection systems and 

measurement, monitoring and verification (MMV) systems for CO2 injected into deep geologic structures. 

To date, CO2 has been captured from both natural gas and coal fired commercial power generating 

facilities, gasification facilities and other industrial processes. Transportation via pipelines and injection 

of CO2 into the deep subsurface are well established commercial practices with more than 35 years of 

industrial experience. There are also a wide variety of MMV technologies that have been employed to 

understand the fate of CO2 injected into the deep subsurface. The four existing end-to-end commercial 

CCS projects – Sleipner, Snøhvit, In Salah and Weyburn – are using a broad range of these technologies, 

and prove that, at a high level, geologic CO2 storage technologies are mature and capable of deploying at 

commercial scales. Whether wide scale deployment of CCS is currently or will soon be a cost-effective 

means of reducing greenhouse gas emissions is largely a function of climate policies which have yet to be 

enacted and the public’s willingness to incur costs to avoid dangerous anthropogenic interference with the 

Earth’s climate. There are significant benefits to be had by continuing to improve through research, 

development, and demonstration suite of existing CCS technologies. Nonetheless, it is clear that most of 

the core technologies required to address capture, transport, injection, monitoring, management and 

verification for most large CO2 source types and in most CO2 storage formation types, exist.

Key Words: carbon dioxide capture and storage; technological readiness; climate change; CO2 pipelines; 

measurement, monitoring and verification. 

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Table of Contents 

1.0 Summary ..................................................................................................................................... 1

2.0 Introduction: The Role of CCS in Addressing Climate Change ................................................. 4

3.0 Overview of Four Operational Commercial CCS Facilities ....................................................... 5

3.1 Sleipner West Field (250km off the Norwegian coast in the North Sea) ........................... 5

3.2 Great Plains Synfuels Plant (Beulah, North Dakota) and the Weyburn Enhanced Oil 

Recovery Project (Weyburn, Saskatchewan, Canada) ....................................................... 6

3.3 In Salah Natural Gas Production Facility (Central Saharan Region, Algeria) ................... 7

3.4 Snøhvit LNG Project (located in the Barents Sea 150 km off the northern coast of 

Norway) .............................................................................................................................. 7

4.0 CO2 Capture, Compression, Dehydration, and Handling Technologies ..................................... 8

4.1 Post Combustion CO2 Capture from Pulverized Coal-fired Electric Power Plants ........... 8

4.2 CO2 Capture from Coal Gasification .................................................................................. 9

4.3 CO2 Capture from Oxygen-fired Coal Combustion ........................................................... 9

4.4 Post-Combustion CO2 Capture from Natural Gas-fired Facilities ................................... 10

4.5 CO2 Capture from Natural Gas Reforming ...................................................................... 10

4.6 CO2 Capture from Natural Gas Production ...................................................................... 11

5.0 CO2 Transportation Technologies ............................................................................................ 14

6.0 CO2 Injection Technologies ...................................................................................................... 15

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4 

7.0 CO2 Measurement, Monitoring and Verification Technologies ............................................... 17

7.1 CO2SINK – ....................................................................................................................... 20

7.2 In Salah – .......................................................................................................................... 20

7.3 Nagaoka – ......................................................................................................................... 20

7.4 Sleipner – ......................................................................................................................... 21

7.5 Snøhvit – .......................................................................................................................... 21

7.6 Weyburn – ........................................................................................................................ 21

7.7 Frio – ................................................................................................................................ 21

Appendix A: References ............................................................................................................................. 24

Appendix B: Online Resources Tracking CCS Demonstration Projects and Planned Commercial CCS 

Facilities ...................................................................................................................................................... 29

Appendix C: Overview of Principal CO2 Capture System Configurations that Could Be Applied to Large 

Commercial Power Plants ........................................................................................................................... 30

Appendix D: Brief Summary of Commercially Available Absorption-based CO2 Capture Systems ........ 31

Appendix E: CO2 Purity Specifications for Various Classes of Use .......................................................... 33
1.0 Summary 

Carbon dioxide capture and storage (CCS) technologies are commercially available today. Specifically, 

there exists the following deployment experience with CCS component systems: 

• CO2 capture systems that have been mated to coal and natural gas fired electricity plants, coal 

gasification facilities and various industrial facilities. Some of these CO2 capture systems have 

been in operation since the late 1970s. 

• There are currently more than 3,900 miles of dedicated CO2 pipelines in the United States and 

there is more than 35 years of commercial experience associated with transporting large volumes 

of CO2 via dedicated pipelines. Some of the earliest CO2 pipelines were constructed in the early 

1970s and are still in operation today. Available data suggests that these CO2 pipelines have 

safety records that are on par with or better than the closest industrial analogue which would be 

large interstate natural gas pipelines. 

• More than 35 years of injecting anthropogenic CO2 into the deep subsurface for the purpose of 

CO2-driven enhanced oil recovery. There are over 6,000 deep CO2 injection wells currently in 

operation across parts of 10 states of the U.S. Since 1972, more than 8,800 CO2 injector wells 

have been used in Texas alone. 

• There is a wide variety of measurement, monitoring and verification (MMV) technologies which 

have been employed to understand the fate of CO2 injected into the deep subsurface at large 

commercial CO2 storage facilities. 

• There are currently four complete, end-to-end commercial CCS facilities on the planet. Each of 

these facilities captures anthropogenic CO2 from a process stream/flue gas that would otherwise 

be vented to the atmosphere. The captured CO2 is dehydrated, compressed and otherwise 

prepared for transport via pipeline and/or for injection into nearby suitable deep geologic CO2

storage formations. Each facility injects between 0.7 MtCO2 and 2 MtCO2 into these deep 

geologic formations annually and then applies a suite of MMV technologies to monitor and verify 

the fate of the injected CO2. These four sites represent 25 years of cumulative experiential 

knowledge on safely and effectively storing anthropogenic CO2 in appropriate deep geologic 

formations. 

It is also important to acknowledge that key component technologies of complete CCS systems have been 

deployed at scales large enough to meaningfully inform discussions about CCS deployment on large 

commercial fossil-fired power plants, which are almost certainly going to represent the largest market for 

CCS technologies in a greenhouse gas constrained world. To illustrate this point, the following bullets 

compare the current state of key CCS component technologies to the scale of deployment needed for a 

hypothetical 500 MW coal power plant that employed CCS to reduce its CO2 emissions to the 

atmosphere. 

• The largest CO2 capture system commercially delivered to date that would be applicable to 

electric power production facilities can capture 450 tCO2/day in a single unit. If there were no 

technological progress beyond this point, the application of this unit to a nominal 500MW coal 

power plant would require approximately 20 parallel capture units. This would represent a 

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significant capital expenditure and would require significant land at the power plant. However, 

there is no reason to assume that there will not be technological progress in this regard. 

Mitsubishi Heavy Industries has stated that they are ready to deliver CO2 capture units that are as 

large as 3000tCO2/day which would reduce the number of parallel CO2 capture trains required for 

this hypothetical 500MW coal plant to only three units. 

• There are operational CO2 pipelines in the U.S. that routinely transport 10-20 MtCO2 / year 

through a single pipeline. A large 500 MW coal fired power plant that was capturing its CO2

would generate approximately 3 MtCO2/year. Thus mankind’s ability to transport large volumes 

of CO2 over long distances via pipeline at a scale that would be germane to CCS deployment with 

large power generation facilities has been demonstrated. Not only do these large pipelines exist 

but the pumps, compressors, valves, automated safety and shut off devices exist that allow for 

their safe operation are also common technologies available off the shelf today. 

• Over the past 35 years approximately 150 MtCO2 has been injected into the Canyon Reef 

formation at the 90mi2

 SACROC unit in Texas for the purpose of stimulating additional oil 

recovery. This volume of CO2 is roughly equivalent to what a 500 MW coal power plant would 

produce over a 40 year period. Assuming that the CO2 from this hypothetical 500 MW power 

plant was injected into a deep saline formation, the foot-print of the injection field would likely 

be smaller than the 90mi2

 of the SACROC unit, and perhaps significantly so. It is important to 

note that the CO2 injected at SACROC was not monitored in terms of whether the CO2 was being 

permanently isolated from the atmosphere and most of the CO2 injected into the Canyon Reef 

was purposefully withdrawn so that it could be reused to stimulate oil production in other areas. 

Notwithstanding these two important caveats, one can conclude that the knowledge to inject CO2

into the deep subsurface over many decades and over a large area exists. 

• For ten years, approximately 1 MtCO2/year as been injected into the Utsira deep saline formation 

below the Sleipner CCS facility. The Sleipner project has utilized a MMV program focused on 

time-lapse seismic surveys, and drawing on core analysis, wireline logging, geochemical 

monitoring, pressure / temperature / injection rate monitoring, as well as microseismic and 

gravitational techniques. The data derived from this MMV program is evaluated by national 

regulators who use these data to determine the environmental efficacy of CCS in terms of climate 

protection and to determine whether the storage activities are successful in isolating the CO2 from 

the atmosphere and to hence avoid Norway’s existing carbon tax. Again, if one compares this to 

activity to a nominal 500MW coal power plant that would generate approximately 3 MtCO2/year 

the scale of the activity might be multiples of this size not orders of magnitude more complex. 

The vast majority of the 8,100 large stationary CO2 point sources (e.g., fossil fired power plants, 

refineries, cement kilns, chemical plants) that could conceivably adopt CCS technologies as a means of 

reducing their CO2 emissions have not adopted CCS systems. Moreover, the vast majority of the new 

power plants and other large industrial CO2 point sources that are now being built or that are in various 

stages of planning in the United States and throughout the rest of world are also not planning on adopting 

CCS systems. This reveals an important point: the deployment of CCS technologies is almost exclusively 

motivated by the need to significantly reduce greenhouse gas emissions and therefore, their large-scale 

adoption depends upon explicit efforts to control such emissions. 

The fact that complete, end-to-end commercial CCS systems exist and that the needed system 

components of a CCS system are commercially available does not undercut the rationale for a vigorous 

ongoing research, development and demonstration program focused on improving CCS technologies and 

demonstrating them in various combinations of technological, geographical, and geologic applications 

and settings. 

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The fact that CCS technologies are commercially available today is also not sufficient to suggest that they 

provide cost effective means for significantly reducing CO2 emissions to the atmosphere absent a climate 

policy that would create a significant disincentive on the free venting of CO2 to the atmosphere thereby 

creating a market for the services CCS technologies provide. 

It is also critical to acknowledge that in addition to a sufficiently stringent climate policy, the deployment 

of CCS as a part of society’s response to climate change will need a more clearly defined regulatory 

framework. Progress is being made on creating and implementing an appropriate regulatory framework 

covering each aspect of CCS deployment and that ensures appropriate protection for human and 

environmental health, property and mineral rights, and settlement of liability concerns related to the longterm storage of CO2 as well as other key regulatory issues. However, this again does little to diminish the 

commercial availability of the technologies, only increase the uncertainty and potential risks for those 

seeking to deploy them.
2.0 Introduction: The Role of CCS in Addressing Climate 

Change 

Addressing climate change is a large-scale, global challenge to reduce and avoid the release of enormous 

quantities of greenhouse gases over the course of this century while global populations, economies, and 

standards of living are expected to continue to grow. There is an extensive body of technical literature that 

conclusively demonstrates the value of developing an enhanced and diversified portfolio of energy 

technologies in meeting this challenge (Edmonds, et. al., 2008, IPCC, 2008). “Addressing climate 

change” will require continued advancements in energy efficiency, nuclear power, renewable energy, and 

other energy technologies to not only reduce carbon dioxide (CO2) emissions but to also help to improve 

economic efficiency, competitiveness, and local environmental quality. 

Carbon dioxide capture and storage (CCS) technologies have the potential to be central elements of this 

needed advanced energy technology portfolio. CCS technologies are capable of deploying widely across 

the globe in many different economic sectors and are capable of delivering deep, cost effective and 

sustained emissions reductions. Research by this and other research groups has shown that CCS systems 

are capable of reducing the costs of climate stabilization by trillions of dollars because these technologies 

allow for the continued use of fossil fuels and enable the deployment of other key mitigation technologies 

such as large-scale, low-emissions hydrogen production (IPCC, 2005, Dooley, et. al., 2006, McFarland et. 

al. 2003). The costs of CCS systems should be competitive with – and in some cases significantly less 

costly than – other potential large-scale CO2 emissions reduction and abatement technologies (Edmonds, 

et. al., 2008). 

Globally, there are currently more than 8,100 large CO2 point sources (accounting for more than 60% of 

all anthropogenic CO2 emissions) that could conceivably adopt CCS technologies as a means for 

delivering deep and sustained CO2 emissions reductions. These 8,100 large CO2 point sources are 

predominantly fossil-fuel-fired electric power plants, but there are also hundreds of steel mills, cement 

kilns, chemical plants, and oil and gas production and refining facilities (Dooley, et. al., 2006). A very 

small number of these facilities are already capturing and selling CO2, suggesting that in certain niche 

applications it is already profitable to deploy some CCS component technologies. However, the vast 

majority of these existing facilities have not adopted CCS systems. Moreover, the vast majority of the 

new power plants and other large industrial CO2 point sources that are now being built in the United 

States or anywhere else in the world or that are in various stages of planning are also not planning on 

adopting CCS systems. This reveals an important point: the deployment of CCS technologies is almost 

exclusively motivated by the need to significantly reduce greenhouse gas emissions and therefore, their 

large-scale adoption depends upon explicit efforts to control such emissions. 

The limited, early large scale commercial adoption of complete, end-to-end CCS systems which has taken 

place to date has occurred outside the electric power sector. However, if there were an explicit climate 

policy in place that called for substantial and sustained emissions reductions, the fossil-fired electric 

power plants would almost certainly represent the largest market for CCS systems. CCS systems will be 

most economic when deployed with large baseload power plants (Dooley et. al., 2006 Kamel and Dolf, 

2009, MIT 2007 and IPCC 2005). One explicit goal of this paper is to examine -- in a disaggregated 

manner -- the status of CCS technologies and their component systems to shed light on the degree to 

which current systems are of a scale that is relevant to future CCS deployment with large fossil fired 

power plants and other large anthropogenic CO2 point sources. 

There is widespread agreement on the potential value of CCS technologies in a greenhouse gas 

constrained world (e.g., Dooley et. al., 2006, IPCC 2005, Bennaceur and Gielen, 2009, MIT 2007). 

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However, there is considerable confusion as to whether CCS technologies exist today or whether these are 

technologies that have yet to be invented and therefore will not be ready for use for many years, perhaps 

decades, to come. 

The purpose of this short paper is to identify and describe commercially deployed CO2 capture systems, 

CO2 transportation pipelines, CO2 injection systems and measurement, monitoring and verification 

(MMV) systems for CO2 injected into deep geologic structures. That is, this paper seeks to help establish 

the current commercial availability of CCS technologies. This paper will not attempt to speak to the 

rapidly changing status of currently operational or planned CCS facilities. Readers interested in learning 

more about these facilities and demonstration projects which are working to advance the current state of 

the art can consult the on-line resources listed in Appendix B. 

There is no reason for confusion as to whether CCS technologies exist. CO2 is currently being captured 

from both natural gas and coal fired commercial power generating facilities, gasification facilities and 

other industrial processes. Transportation via pipelines and injection of CO2 into the deep subsurface are 

well established commercial practices with more than 35 years of industrial experience. There are a wide 

variety of MMV technologies which have been employed to understand the fate of CO2 injected into the 

deep subsurface. Whether wide scale deployment of CCS is currently or will soon be a cost-effective 

means of reducing greenhouse gas emissions is largely a function of climate policies which have yet to be 

enacted and the public’s willingness to incur costs to avoid dangerous anthropogenic interference with the 

Earth’s climate. 

Before examining the commercial deployment of individual system components of CCS in more detail, 

this paper will begin with a brief overview of the four currently operational large commercial complete 

end-to-end CCS facilities. 

3.0 Overview of Four Operational Commercial CCS Facilities 

As of early summer 2009, there are four complete, end-to-end commercial carbon dioxide capture and 

storage facilities on the planet (See Figure 1). Each of these facilities captures anthropogenic CO2 from 

process streams/flue gases that would otherwise be vented to the atmosphere. The captured CO2 is 

dehydrated, compressed and otherwise prepared for transport via pipeline and injection into nearby 

suitable deep geologic CO2 storage formations. Each facility injects CO2 into these deep geologic 

formations and then employs a suite of MMV technologies to monitor the injected CO2. These four 

facilities represent 25 years of cumulative knowledge on safely and effectively storing anthropogenic CO2

in appropriate deep geologic formations. 

3.1 Sleipner West Field (250km off the Norwegian coast in the North 

Sea) 

The Sleipner project represents the world’s first commercial CCS facility. The Sleipner natural gas field 

has a high – approximately 9% – concentration of CO2 which must be removed prior to shipping the 

natural gas on-shore and selling it to various markets. Approximately 1 MtCO2/year is removed from the 

produced natural gas via an amine-based CO2 separation unit. The captured CO2 is injected via a single 

injection into the Utsira deep saline formation 800-1000 meters below the seabed (IPCC 2005 and IEA 

GHG, 2009). CO2 capture and storage has been ongoing at Sleipner since 1996 and to date more that 10 

MtCO2 has been safely stored at this site (Statoil Press Release, 2008). The Sleipner project has utilized 

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an MMV program focused on time-lapse seismic surveys, and drawing on core analysis, wireline logging, 

geochemical monitoring, pressure / temperature / injection rate monitoring, as well as microseismic and 

gravitational techniques (Chadwick, et al. 2006, Chadwick, et al. 2007). 

• CO2 storage began in 2000

•2 MtCO2/year being injected via 

approximately 85 injection wells over a 40 

km2 area

•Projected 30 MtCO2 lifetime storage 

Weyburn

• CO2 storage began in 2004

• Three 1.5 km horizontal CO2

injector wells are used to inject 1.2 

MtCO2/year

• Projected 17 MtCO2 lifetime storage

In Salah

Snøhvit

• CO2 storage began April 2008

• 0.7 MtCO2/year injected into DSF

• 23 MtCO2 injected over 30 years

• 150 km of the Norwegian coast

•Started injection in 1996 

•More than 10 MtCO2 have been 

injected via 1 injection well with a 

plume approximately 5 km2 with 

•Projected 20 MtCO2 lifetime storage

•150 km of the Norwegian coast

Sleipner

• CO2 storage began in 2000

•2 MtCO2/year being injected via 

approximately 85 injection wells over a 40 

km2 area

•Projected 30 MtCO2 lifetime storage 

Weyburn

• CO2 storage began in 2004

• Three 1.5 km horizontal CO2

injector wells are used to inject 1.2 

MtCO2/year

• Projected 17 MtCO2 lifetime storage

In Salah

Snøhvit

• CO2 storage began April 2008

• 0.7 MtCO2/year injected into DSF

• 23 MtCO2 injected over 30 years

• 150 km of the Norwegian coast

•Started injection in 1996 

•More than 10 MtCO2 have been 

injected via 1 injection well with a 

plume approximately 5 km2 with 

•Projected 20 MtCO2 lifetime storage

•150 km of the Norwegian coast

Sleipner

Figure 1: Overview of Four Large Commercial CCS Facilities 

3.2 Great Plains Synfuels Plant (Beulah, North Dakota) and the 

Weyburn Enhanced Oil Recovery Project (Weyburn, 

Saskatchewan, Canada) 

 This is the only large scale commercial CCS project in North America and the only one of the four large 

complete end-to-end CCS facilities that captures CO2 from a coal energy production facility. CO2 is 

captured at a coal gasification plant in North Dakota and shipped to Saskatchewan via a dedicated 320 km 

pipeline. CO2 is captured from this synfuels plant with a Rectisol capture unit. More than 3 MtCO2/year is 

captured at this plant with approximately 2 MtCO2 / year being sent to Weyburn with the remainder 

vented to the atmosphere (IPCC, 2005). In 2000, equipment needed to recover, compress, and transport 

via pipeline a portion of this coal gasification plant’s CO2 was installed so that the CO2 could be pipelined 

to an enhanced oil recovery project known as the Weyburn Unit in southeast Saskatchewan, Canada. The 

Weyburn oil field lies at a depth of approximately 1500 meters and is less than 50 meters thick. The 

Weyburn EOR project injects both water and CO2 to enhance oil production via 197 vertical and 15 

horizontal injector wells (Wilson and Monea, 2004) The Weyburn project uses a broad range of MMV 

technologies including time-lapse seismic, core analysis, wireline logging, geochemical sampling and 

analysis, electrical resistance tomography, crosswell seismic, microseismic monitoring, and sampling of 

the soil, shallow subsurface and atmosphere to ensure retention of injected CO2 (White 2007). 

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3.3 In Salah Natural Gas Production Facility (Central Saharan 

Region, Algeria) 

CO2 concentrations in this natural gas field range from 1-10% which is far in excess of allowable 

concentrations for exporting natural gas to markets in Europe. Approximately 1.2 MtCO2/year is 

removed from the natural gas using and MEA-based CO2 capture unit. The CO2 is injected into a deep 

saline geologic formation 1800 meters below the surface via three CO2 injector wells with long horizontal 

legs running up to a 1.5 km to increase the efficiency of CO2 injection in this tight formation (IPCC, 

2005). CO2 capture and storage began in April 2004. (IEA GHG, 2009). The In Salah project uses 

seismic, core, wireline logging, geochemical sampling / analysis, pressure / temperature / injection rate 

monitoring, electrical resistance tomography, passive / microseismic monitoring, gravitational surveys, 

tiltmeters, differential InSAR, soil / shallow subsurface and atmospheric monitoring techniques as well as 

tracer-based monitoring (Wright, et al. 2005, Ebrom, et al. 2007, Onuma & Ohkawa 2009). 

3.4 Snøhvit LNG Project (located in the Barents Sea 150 km off the 

northern coast of Norway) 

The Snøhvit facility is Europe’s first commercial liquefied natural gas production facility. The fields that 

are producing the natural gas also contain a significant quantity of CO2 (5-8% CO2 by volume) which 

must be separated before the natural gas can be liquefied prior to transport. Approximately 0.7 MtCO2/ 

year is captured from this facility using an amine-based capture system and is injected into a nearby deep 

saline formation that lies 2,600 meters below the seafloor. (IEA GHG, 2009, Statoil, 2009, Benson, 

2009). The Snøhvit project, also operated by Statoil, has also employed a monitoring and verification 

program that focuses heavily on time-lapse seismic surveys and pressure monitoring, along with timelapse gravimetric surveys (Late, 2008). 

Sleipner and its sister project Snøhvit are unique among these four commercial CCS projects in that data 

derived from their MMV programs are submitted to national regulators who use these data to determine 

the environmental efficacy of CCS in terms of climate protection. Norwegian regulators rely on these 

data as evidence that the CO2 is staying in the target injection formations, to determine whether the 

storage projects are successfully trapping CO2 away from the atmosphere and therefore whether the 

projects qualify as a mean to avoid the national carbon tax on CO2 emissions. The Weyburn and InSalah 

projects utilize their MMV data to demonstrate to relevant regulators that CO2 is remaining in the 

injection formation and is therefore not negatively impacting underground sources of drinking water or 

other natural resources. However, because there is no climate policy in place in Algeria or Canada there is 

no explicit dialogue with a regulator about the efficacy of CO2 storage in terms of mitigating greenhouse 

gas emissions. If climate policies are put in place in Algeria and Canada, the types of MMV data 

collected would most likely form the core if not the totality of data presented to regulators to establish the 

climate benefits of CO2 storage at these two sites. 

While each of these four commercial CCS facilities captures, injects, and monitors between 0.7 and 2 

MtCO2/year into suitable deep geologic formations, a typical large fossil fired power plant would 

generate perhaps 2-4 times as much CO2/year and perhaps an order of magnitude more cumulative CO2

stored over a typical 40-50 year lifetime. And therefore, there is truth to the often heard assertion that 

CCS has never been demonstrated at the scale of a large commercial power plant. On the other hand, 

these four facilities demonstrate that many of the underlying technologies such as pipelines that can 

handle up to 2 MtCO2 / year (along with all of the seals, pumps, automated flow and safety controls for 

such a pipeline) do currently exist and would only need to be scaled up modestly to handle the mass of 

CO2 from a large commercial power plant. These four facilities also demonstrate that MMV technologies 

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can be deployed in a range of different settings and conditions to understand the movement and behavior 

of CO2 that has been injected into the deep subsurface. 

4.0 CO2 Capture, Compression, Dehydration, and Handling 

Technologies 

CO2 has been captured from operational coal power plants since the late 1970s and from natural gas 

power plants since the early 1990s. The primary task of these facilities is producing electricity or steam 

for industrial processes, and CO2 capture is a secondary task. As such, these facilities tend to capture CO2

from a small fraction of the total flue gas stream as these CO2 capture units are sized to meet niche 

commercial markets for CO2 (such as carbonated beverage production and food processing). 

As noted above, CO2 is also being captured at the Dakota Gasification Facility which gasifies coal to 

produce synthetic natural gas as well as a number of chemical feedstocks. While similar to IGCC power 

plants in a number of key respects, it is important to note that this facility does not generate electricity. 

Industrial coal gasification systems must separate CO2 from the syngas stream as an inherent part of their 

process unlike an electricity generating IGCC, a point which will be explained in more detail below. 

However, it is important to note that Dakota Gasification Facility’s capture of CO2 is not precisely the 

same as CO2 capture from a coal-fired IGCC power plant. 

Anthropogenic CO2 is also “captured” from natural gas processing plants and from ammonia plants, 

which produce a high purity CO2 stream that requires little effort to capture beyond diverting and 

compressing it. Similar to the situation for the Dakota Gasification Facility, the capture of CO2 at these 

facilities is an inherent part of the process of producing the end product (e.g., natural gas). The 

technologies used to separate CO2 at these facilities are well established. CO2 capture from natural gas 

processing plants is at the heart of three of the four large commercial end-to-end CCS facilities currently 

in operation worldwide. The volumes of CO2 captured from these facilities are significantly larger than 

what is currently captured from power plants, due in large part to the low costs of capture. 

It is also important to note that there is more than 35 years of experience related to many of the 

underlying system components that are often overlooked but are vital aspects of a functioning CO2

capture system. Systems to compress, dehydrate and move gaseous and supercritical CO2 including 

materials and seals, fittings, meters, etc. are all commercially available and well established technologies. 

Appendices C and D provide more detail on the three basic CO2 capture system configurations and terms 

like “food grade CO2” and “amine” that are used throughout the remainder of this section. 

4.1 Post Combustion CO2 Capture from Pulverized Coal-fired Electric 

Power Plants 

CO2 is currently being captured from three coal fired electric power plants in the U.S. Each of these are 

conventional coal power plants. A small fraction of the power plant’s overall CO2 is captured to serve 

niche markets for CO2. The vast majority of the CO2 produced at these power plants through the 

combustion of coal to generate electricity is vented to the atmosphere. 

8 
• Warrior Run Power Plant (Cumberland, Maryland). This 180 MW pulverized coal power plant 

captures a small slip stream of the facility’s flue gases to produce approximately 330 tCO2/day of 

food grade CO2 (Holt, 2008). The CO2 is captured using an ABB Lummus unit that uses 

monoethanolamine (MEA) as its solvent. This plant has been in operation since 2000. (IEA GHG, 

2009) 

• Shady Point Power Plant (Panama, Oklahoma). The 320MWe Shady Point power plant is a 

circulating fluidised bed coal-fired power plant. A small slip stream of the facility’s emissions are 

treated to produce approximately 200 tCO2/d of food grade CO2 via an ABB Lummus scrubber 

system that uses MEA as its solvent. The extracted CO2 is used for food processing, freezing, 

beverage production and chilling purposes. (IEA GHG, 2009). 

• Searles Valley Minerals Soda Ash Plant (Trona, California). Approximately 800tCO2/d of CO2 is 

captured from the flue gas of a coal power plant (steam and electricity are generated at this plant) 

using ABB Lummus MEA capture unit (Herzog, 1999). This facility has been in operation since 1978 

thus making it the world’s longest operating CO2 capture facility. The captured CO2 is used for the 

carbonation of brine in the process of producing soda ash. (IEA GHG, 2009, SourceWatch, 2009). 

4.2 CO2 Capture from Coal Gasification 

As noted above, the capture of CO2 from a coal gasification plant like the Dakota Gasification Facility 

which makes synthetic natural gas and various chemicals is similar yet markedly different than what 

would need to occur within a coal fired integrated gasification combined cycle (IGCC) electricity plant. 

For a gasification plant like the Dakota facility, the vast majority of the CO2 is removed by plant’s gas 

treatment units upstream of the methanation units in an already concentrated and pressurized form. This 

CO2 stream is in a form that requires little extra processing other than some additional compression for 

pipeline transport. While similar acid gas removal processes would be used in an IGCC power plant 

wishing to capture CO2 prior to combustion of the syngas stream, this process is not necessary for the 

production of electricity in an IGCC plant. Therefore, the key difference between a coal gasification 

facility and an IGCC power plant is that the CO2 must be separated in syngas production while it is a 

choice (that also brings additional costs and design considerations into play) for the IGCC plant. 

However, the technologies employed for CO2 separation in each case would be very similar. 

• Great Plains Synfuels Plant (Beulah, North Dakota). This facility is the only large coal 

gasification plant in the United States that synthesizes natural gas from coal. CO2 is captured 

from this synfuels plant with a Rectisol capture unit. In 2000, equipment needed to recover, 

compress, and transport via a 205 mile pipeline a portion of this coal gasification plant’s CO2 was 

installed so that the CO2 could be pipelined to an enhanced oil recovery project known as the 

Weyburn Unit in southeast Saskatchewan, Canada. More than 3 MtCO2/year is separated at this 

plant with approximately 2 MtCO2 / year being sent to Weyburn with the remainder vented to the 

atmosphere (IPCC, 2005, Perry and Eliason, 2004). 

4.3 CO2 Capture from Oxygen-fired Coal Combustion 

The combustion of coal using purified oxygen as opposed to combustion in air which contains a 

significant fraction of nitrogen and many other non-reactive constituent gases is seen as one promising 

9 
technology for increasing the concentration of CO2 in the flue gas stream and thereby simplifying and 

hopefully reducing the cost of CO2 capture from coal power plants. Currently, there is one rather small 

“oxy-fired” coal power plant in operation. 

• Schwarze Pumpe Pilot Plant (Spremberg in Brandenburg, Germany). Vattenfall has been 

operating a 30 MW pilot scale, oxygen fired coal power plant since the middle of 2008. 

Approximately 220tCO2/day can be captured from this pilot plant via compression and 

liquefaction of the resulting high purity CO2 exhaust stream as opposed to a chemical absorption 

process like MEA. The captured CO2 is stored in a liquefied state on-site in two 180m3

 tanks 

which are used to temporarily store the CO2 before it is sent to various markets via tanker trucks. 

(Strömberg, 2009) 

4.4 Post-Combustion CO2 Capture from Natural Gas-fired Facilities 

While the CO2 concentration in the flue gas of conventional coal-fired power plants is approximately 15% 

and oxy-fired technology aims at significantly higher concentrations, the combustion of natural gas results 

in very low CO2 concentrations (approx. 3%-5%). Capturing CO2 from such dilute streams can present 

unique challenges. 

• Sumitomo Chemicals Plant (Chiba Prefecture, Japan). This natural gas fired power plant 

generates electricity and approximately 150-165 tCO2/day of food-grade CO2. A Fluor 

Econamine CO2 scrubber system is used to remove CO2 from flue gases. The plant has been 

operational since 1994. (IEA GHG, 2009). 

• Prosint Methanol Production Plant (Rio de Janeiro, Brazil). Approximately 90 tCO2/day of foodgrade CO2 is captured from the flue gases of a natural gas-fired boiler using a Fluor Econamine 

MEA CO2 capture unit. This facility has been in operation since 1997. The captured CO2 is used 

to carbonate beverages (IEA GHG, 2009). 

4.5 CO2 Capture from Natural Gas Reforming 

Natural gas is commonly used as a feedstock in the production of hydrogen, ammonia, urea, and related 

products, via steam reforming processes. Approximately 85% of ammonia is made by steam reforming 

natural gas, a process that is well suited to separating out large commercial quantities of high purity CO2 

(IPCC, 2005). 

• Indian Farmers Fertilizer Company (Aonla and Phulpur, India). CO2 is recovered from steam 

reformer flue gases via a CO2 capture unit that uses Mitsubishi Heavy Industry’s (MHI) 

proprietary KS-1 amine. The plant captures approximately 900 tCO2 /day utilizing two 450 

tonCO2/day capture trains) for use in manufacturing (MHI, 2009). 

• Petronas Fertilizer (Kedah Darul Aman, Malaysia). Approximately 160 tCO2/day is captured 

from a steam reformer flue gases. The recovered CO2 is used for urea production. The Petronas 

flue gas CO2 recovery plant started up in October 1999 and has been operated continuously since. 

(MHI, 2009). 

10 
• Ruwais Fertilizer Industries (Abu Dhabi, United Arab Emirates). At this facility 400 tCO2/day is 

captured from steam reformer flue gases using a capture unit based on MHI’s KS-1 solvent. CO2

capture began at this facility in 2008 (MHI, 2009). 

Luzhou Natural Gas Chemicals (Luzhou City, China). CO2 is removed from the exhaust gases of 

a natural gas reformer unit using Fluor's Econamine MEA CO2 removal process. The facility 

captures approximately 160 tCO2/d of CO2 which is used for manufacturing urea. (IEA GHG, 

2009) 

4.6 CO2 Capture from Natural Gas Production 

Natural gas fields around the world contain various levels of CO2 that is intermixed with the methane and 

other light hydrocarbons which are being produced from these fields. Natural gas pipeline specifications 

vary around the world, though natural gas markets and pipeline operators generally limit CO2

concentrations to no more than 2% by volume. This is done to prevent pipeline corrosion, to avoid using 

energy to compress the CO2 for transport and to increase the heating value of the gas (IPCC, 2005). For 

the vast majority of these facilities, current commercial practice is to vent this pure CO2 into the 

atmosphere 

• Snøhvit LNG Project (located in the Barents Sea 150 km off the northern coast of Norway). The 

Snøhvit facility is Europe’s first commercial liquefied natural gas production facility. The fields 

that are producing the natural gas also contain a significant quantity of CO2 (5-8%), which must 

be separated before the natural gas can be liquefied prior to transport (Carbon Capture Journal 

2008). Approximately 0.7 MtCO2/ year is captured from this facility and is injected into a nearby 

deep saline formation. (IEA GHG, 2009 and Statoil, 2009) 

• In Salah Natural Gas Production Facility (Algeria). CO2 concentrations in this natural gas field 

range from 1-10% which is far in excess of allowable concentrations for exporting natural gas to 

markets in Europe. Approximately 1.2 MtCO2 / year is removed from the natural gas using and 

MEA-based CO2 capture unit and is injected into a nearby deep geologic formation. CO2 capture 

and storage began in 2004. (IEA GHG, 2009). 

• Sleipner West Field (150km off the Norwegian coast in the North Sea). The Sleipner natural gas 

field has high – approximately 9% -- concentration of CO2 which must be removed prior to 

shipping the CO2 on shore and selling it to various markets. Approximately 1 MtCO2/year is 

removed from the produced natural gas via an amine-based CO2 separation unit. The captured 

CO2 is stored in a nearby deep saline formation (IEA GHG, 2009). CO2 capture and storage has 

been ongoing at Sleipner since 1996 and to date more that 10 MtCO2 has been stored at this site 

(Statoil Press Release, 2008). 

• Shute Creek Natural Gas Processing Plant (La Barge, Wyoming). Produced gas streams from 

fields in this area contain approximately 65% CO2 and only 22% natural gas. The plant has been 

separating, compressing, and selling approximately 4 MtCO2/yr to various enhanced oil recovery 

projects in the region and venting another 3.5 MtCO2/yr. Selexol process is used to remove CO2

and H2S from natural gas (Kubek, 2009). ExxonMobil is currently planning to increase the 

capture of CO2 by another 100 MMCFD (1.9 MtCO2/yr) and is testing a new controlled freeze 

zone capture technology that may make additional capture more affordable (Environmental 

Leader, 2008). 

11 
12 

• Val Verde Natural Gas Plants (Terrell and Pecos Counties, Texas). The Terrell, Grey Ranch, 

Mitchell, and Puckett plants, process natural gas and transport their collected CO2 to oil fields in 

west Texas via the Petro Source Canyon Reef Carriers CO2 pipeline (the oldest large CO2

transport pipeline in the U.S., constructed in 1972). Current estimates suggest that 75 MMCFD 

of CO2 are delivered to the SACROC and other oil fields (Moritis, 2008) while total pipeline 

capacity is estimated at 275 MMCFD (Bradley 2005). 

• DTE Turtle Lake Gas Processing Plant (Otsego County, Michigan). One of several gas 

processing plants in northern Michigan’s Antrim Shale fields. Gas produced from Antrim Shales 

contain between 5-30% CO2 which is removed by an amine based separation process. The 

resulting high purity (99%) CO2 stream is used periodically for EOR flooding of Niagaran Reef 

oil fields (transported via existing 8 mile pipeline) and also for the ongoing demonstration of CO2

storage in the Silurian-age Bass Island dolomite deep saline formation by the Midwest Regional 

Carbon Sequestration Partnership. A total of 60,000 tons is scheduled to be injected (at rates of 

250-600 tons/d) by the end of this demonstration project, at a depth of 3,500 feet (Battelle 2007 

and Global Energy Network Institute, 2009). Excess CO2 is vented to the atmosphere. 

Table 1 summarizes the individual CO2 capture facilities discussed above. The volume of CO2 captured 

from each facility is shown in three different sets of units as these are common units for discussing the 

scale of these operations in different engineering and technical communities. The first three rows in 

Table 1 also show the volume of CO2 that could be captured from hypothetical 500 MW natural gas and 

coal fired power plants. These hypothetical reference plants are included here to provide a basis of 

comparison from today’s CO2 capture deployments to the scale that might be needed for future facilities. 

As can be seen, many of the existing CO2 capture facilities – and in particular those capture facilities that 

are mated to fossil fired electricity generating plants – is considerably smaller than the volumes of CO2

that would have to be processed from these reference 500 MW facilities. However, the observation that 

CO2 capture facilities mated to existing power plants is small compared to a large power plant’s total CO2

emissions should be seen as being driven by the niche market circumstances that existed which led to the 

investment in these CO2 capture systems. That is, these facilities were built to serve a specific 

commercial market for CO2; at the time they were built there was no incentive to build a CO2 capture unit 

larger than what was required to serve that market and in fact there would have been strong disincentives 

that would have prevented the construction of a larger than needed CO2 capture unit. 

Because these CO2 capture units were sized to serve specific market demands for CO2, it would be 

incorrect to assume that the size of these units represents some inherent technical or economic threshold 

for CO2 capture units. The last two columns in Table 1 are intended to speak to this point. The data in 

these last two columns represent a back of the envelope calculation of how many CO2 capture trains 

would be needed to handle this volume of CO2 based upon a 450 tCO2/day system (the largest advanced 

CO2 capture system commercially installed to date) and a 3000 tCO2/day system (which represents the 

largest advanced CO2 capture system that Mitsubishi Heavy Industries says they can deliver today for 

commercial applications (Hirata, et. al., 2008 and Ijima et. al., 2009)). Assuming that the largest currently 

installed CO2 capture system that is applicable to electric power production was deployed on a nominal 

500 MW coal-fired power plant, it would require approximately 20 parallel 450 tCO2/day capture units. 

This would represent a significant capital expenditure and significant land at the power plant. However, 

there is no reason to assume that there will not be technological progress in this regard and considering 

the application of the 3000 tCO2/day capture technology that is reported to be available would reduce the 

number of parallel CO2 capture trains required for this hypothetical 500MW coal plant to only three units. 

With additional experience and development, it is not unreasonable to believe that the number of required 

trains may be further decreased. 
Table 1: Summarizing Existing Anthropogenic CO2 Capture Facilities 

CO2 Source Type Use MMCFD tCO2/d MtCO2/yr 

500 MW NGCC Power Plant Reference Power Plant 67 3,550 1.3 500 MW Pulverized Coal Power Plant Reference Power Plant 154 8,160 3.0 500 MW IGCC Power Plant Reference Power Plant 145 7,680 2.8 IMC Global Soda Ash Plant (USA) Coal-fired power plant Soda ash production 15 800 0.3 Warrior Run Power Plant (USA) Coal-fired power plant Food/beverage 6 330 0.1 Schwarze Pumpe Pilot Plant (Germany) Coal-fired oxyfuel combustion Various 4 202 0.1 Shady Point Power Plant (USA) Coal-fired power plant Food/beverage 4 200 0.1 Great Plains Synfuels Plant (USA) Coal gasification EOR 104 5,480 2.0 Sumitomo Chemicals Plant (Japan) Natural Gas-fired power plant Various 4 200 0.1 Prosint Methanol Production Plant (Brazil) Methanol Beverage/food 2 90 0.0 Enid Fertilizer Plant (USA) Fertilizer Urea, EOR 35 1,850 0.7 Indian Farmers Fertilizer Company (India) Fertilizer Manufacturing 17 900 0.3 Ruwais Fertilizer Industries (India) Fertilizer 8 400 0.1 Luzhou Natural Gas Chemicals (China) Fertilizer Urea 3 160 0.1 Petronas Fertilizer (Malaysia) Fertilizer Urea 3 160 0.1 Shute Creek Natural Gas Processing Plant (USA) Natural gas processing EOR 300 15,870 5.8 Val Verde Natural Gas Plants (USA) Natural gas processing EOR 75 3,970 1.4 In Salah Natural Gas Production Facility (Algeria) Natural gas processing Geologic storage 62 3,290 1.2 Sleipner West Field (North Sea, Norway) Natural gas processing Geologic storage 52 2,740 1.0 Snohvit LNG Project (Barents Sea, Norway) Natural gas processing Geologic storage 36 1,920 0.7 DTE Turtle Lake Gas Processing Plant (USA) Natural gas processing EOR/Geologic storage 11 600 0.2 

13 
5.0 CO2 Transportation Technologies 

The technologies needed to safely move CO2 by pipeline are well established. CO2 transport via pipeline 

has been practiced in the U.S. since the early 1970s and should be seen as an established technology. 

The U.S. has by far the largest existing dedicated CO2 pipeline infrastructure in the world. There are 

currently more than 3900 miles of dedicated CO2 pipelines in the United States—of varying lengths and 

diameters—built primarily to serve CO2-driven enhanced oil recovery (EOR) projects. Figure 2 shows 

the existing CO2 pipeline infrastructure in the US and Saskatchewan, Canada. 

Figure 2: Existing CO2 Pipelines in the U.S. 

Many of the largest CO2 pipelines in terms of length and capacity take CO2 from natural CO2 domes and 

transport the CO2 to aging oil fields for enhanced oil recovery. Table 2 lists selected major CO2 pipelines 

in North America. As Table 2 illustrates the volumes of CO2 that can be moved though these pipelines 

are very large and are certainly on the order of (if not larger than) the volume of CO2 that would need to 

be transported from a large yet-to-be-built power plant that might employ CCS to reduce its greenhouse 

gas emissions. Large-scale transport of CO2 via pipeline is not a technology that needs to be created nor 

are new laws or regulatory policies prerequisites for any potential expansion of the nation’s CO2 pipeline 

infrastructure. 

Gale and Davison (2007) and Forbes et. al. (2008) report that CO2 pipelines in the US have a safety 

record which is better than that of comparable natural gas lines and the IPCC (2005) cites a number of 

studies showing that pipeline safety has improved in many parts of the world with the development and 

dissemination of operational best practices and improved remotely controlled safety valves and sensors. 

14 
Table 2. Selected Major Operational CO2 Pipelines in North America (IPCC, 2005) 

Pipeline Name (year completed) Length Estimated Design 

Capacity 

Bravo (1984) 217 7 MtCO2/year 

Canyon Reef Carriers (1972) 140 miles 5.2 MtCO2/year 

Cortez Pipeline (1984) 502 miles 24 MtCO2/year 

Sheep Mountain (1984) 410 miles 9.5 MtCO2/year 

LaBarge (2003) 285 miles 8 MtCO2/year 

Val Verde (1998) 81 miles 2.5 MtCO2/year 

Weyburn (2000) 205 miles 2 MtCO2/year 

These existing CO2 pipelines are regulated under an established body of regulations under the authority of 

the U.S. Department of Transportation’s Office of Pipeline Safety as applicable state-specific regulations. 

Operational pipelines are monitored continuously by pressure and flow management systems to detect 

and respond to leakage instantaneously, and are periodically evaluated internally by automated inspection 

devices and externally by visual inspection (on foot or by aircraft). Long-distance pipelines are divided 

into smaller segments with each segment instrumented to measure pressure and flow, and capable of 

isolating individual segments for maintenance, repair, or to minimize loss of CO2 in the event of a 

pipeline breach (IPCC 2005). 

6.0 CO2 Injection Technologies 

The technologies needed to safely inject CO2 into these deep geologic formations largely exist today and 

are drawn from technologies, techniques and industrial best practices that are routinely used in the oil and 

natural gas production industries. CO2 injection should be seen as established technology. 

The injection of anthropogenic CO2 into the deep subsurface dates to at least 1972 when CO2-driven 

enhanced oil recovery began at the Scurry Area Canyon Reef Operators Committee (SACROC) unit in 

west Texas (Ambrose et. al., 2008). Over the past 35 years, approximately 150 MtCO2 has been injected 

into the Canyon Reef formation for the purpose of stimulating additional oil recovery. 75 MtCO2 were 

intentional produced from these fields for reinjection into other parts of the SACROC or in other oil fields 

employing CO2-driven EOR. Thus, an estimated 55 MtCO2 has become trapped in these deep geologic 

formations from the injection of CO2 (Smyth et. al. 2006). Meyer (2007) reports that 440 injection wells 

have been completed in the SACROC unit itself which covers approximately 90mi2

. 

In their 2008 Enhanced Oil Recovery Survey, the Oil and Gas Journal (2008) indicates that there are 100 

CO2-driven enhanced oil recovery projects operational in the Untied States. The CO2 flooding across 

these 100 projects encompasses nearly 420,000 acres and utilizes more than 6200 injection wells (as well 

as more than 9100 production wells). Meyer (2007) estimates that since the start of the SACROC project 

in 1972 more than 8,800 CO2 injector wells have been completed in Texas alone. 

15 
A Real World 205 mile CO2 pipeline. 

The CO2 pipeline from the Dakota Gasification Company’s (DGC) Great Plains Synfuels Plant 

runs for 205 miles from North Dakota to Saskatchewan. This pipeline transports 2 MtCO2/year 

for use in enhanced oil recovery operations at the Weyburn oil field. 

• Rights of way were negotiated with various land owners to acquire the needed continuous 

corridor for the pipeline. All parties eventually agreed to allow the pipeline to cross their 

land. There was no need to resort to condemnation proceedings. 

• The pipeline diameter runs from 12 to 14 inches. The pipe is made from carbon steel as 

there was no need to use exotic alloys given the very low water content entrained in the 

CO2 coming from the DGC Great Plains Synfuels Plant. The thickness of the pipeline’s 

walls is increased significantly at water crossings, road and railroad crossings. The 

maximum operating pressure is 2700 psig over the first half of the pipeline and 2964 psig 

over the remainder of the pipeline. A booster pump operates at Tioga, ND which is 

approximately half way along the pipeline. 

• The pipeline is buried at a minimum depth of 4 feet. At road crossings, a minimum depth 

of 5 feet is used and at railroad crossings the pipeline is buried to a depth of 10 feet. 

• In total there are 12 remotely controlled main line valves, which are designed to allow for 

individual sections of the pipeline to be isolated in case of damage to the pipeline. These 

remotely controlled main line valves are no more than 20 miles apart along the pipeline. 

• The pipeline crosses three waterways along its path; the Little Missouri River as well as 

Lake Sakakawea both of which are in North Dakota and Jewel Creek in Canada. The 

crossing at Lake Sakakawea is three miles long. At the two more significant water 

crossings, the Little Missouri River and Lake Sakakawea, there are remotely controlled 

main line valves on both shores for both of these water crossings. 

• The pipeline undergoes periodic inspections and tests to ensure its continued integrity and 

safety including: aerial and foot patrols of the right of way 26 times per year, maintenance 

and inspection of all valves twice per year, internal inspection of the pipeline using 

electronic tools at least once every 5 years, and testing of all emergency systems including 

over pressurizing safety devices once per. 

Sources: Perry and Eliason, 2004 and Dakota Gasification Company 2009. 

16
The injection of CO2 into the deep subsurface is not a new practice and has been regulated for decades 

under the Safe Drinking Water Act. The draft Class VI Underground Injection Control rule clearly states 

“CO2 is currently injected in the U.S. under two well classifications: Class II and Class V experimental 

technology wells” (Federal Register, 2008). There is a small but growing body of literature that indicates 

that past CO2 injection has managed in a safe and effective manner. These research studies are built upon 

an examination of the historical record of CO2 injection and highly analogous deep subsurface injection 

techniques. Here we briefly mention three of these studies. 

• In a study of well blowouts in California oil fields undergoing thermal enhanced oil recovery 

during the period 1991-2005, Jordan and Benson (2008) demonstrate that well blowouts were rare 

and the rate of blowouts declined significantly over this 15 year period. The authors attribute this 

to “increased experience, improved technology, and/or changes in the safety culture in the oil and 

gas industry.” They go on to note, “Any of these explanations suggests that blowout risks can 

also be minimized in CO2 storage fields.” 

• Preliminary analysis of research still underway looking at the effects of more than 35 years of 

CO2 injection at the SACROC field by Smyth (2009) suggests that no leakage of injected CO2

into shallower underground sources of drinking water has occurred notwithstanding the large 

volumes of CO2 that have been injected at this site. There has also been significant improvement 

in well construction and operations over the last three decades. 

• Carey et. al., (2007) report that while cement cores retrieved from 30 year old CO2 injector wells 

in the SACROC formation clearly show that the injected CO2 reacted with the cement that the 

cement appears to have “retained its capacity to prevent significant flow of CO2” which is the 

primary purpose of this cement casing around the CO2 injection well. 

7.0 CO2 Measurement, Monitoring and Verification 

Technologies 

Because CCS technologies will only deploy in the presence of a societal mandate to avoid CO2 emissions 

to the atmosphere, and since these policies are likely to carry with them either incentives for long-term 

storage or penalties for venting, it is necessary to create a framework that provides for the safe, secure, 

long-term storage of CO2 in the subsurface, and certifies that a given ton of CO2 stored qualifies for 

monetization as a credit, offset or avoided emission. This is the motivation for a robust program to 

measure, monitor and verify the quantity of CO2 stored. 

Measurement, monitoring and verification (MMV) technologies for CO2 injected into the deep subsurface 

represent a large set of potential technological options for monitoring CO2 injection and other critical in 

situ behaviors that help determine the fate of the stored CO2 and the ultimate efficacy of CO2 storage as a 

means of isolating CO2 from the atmosphere and underground sources of drinking water. Wellhead 

monitoring of the volume and rate of CO2 injected into the formation provides the first critical data stream 

used in the MMV toolkit. This step quantifies the amount of CO2 injected in the subsurface, while other 

methods are used to verify this storage volume, and/or look for evidence that the injectate is migrating out 

of the storage formation. As shown in Figure 3 below, some technologies are best used for detecting the 

presence of CO2 at the surface and in the shallow subsurface – including atmospheric and soil monitoring 

methods that involve sampling and analysis to detect CO2 in the air, soil and water table – while other 

17 
technologies are only used to examine the very deep subsurface, all the way down to the storage 

formation itself, or even deeper. 

There are also sampling-based techniques for monitoring the very deep subsurface, including formation 

fluid chemistry monitoring, and monitoring of overlying water-bearing formations to determine if CO2

from the target formation has migrated away from the intended zone. They also can include technologies 

such as seismic imaging, a technology that uses energy imparted into the earth’s crust, collects 

information on how that energy is reflected and refracted through the layers of rock, and uses that 

information to create an image of the CO2 plume at depth like those shown in Figure 4 (IPCC 2005). 

Wireline, Coring and 

Mechanical Integrity 

Cross-well or 

3D Seismic 

Depth 

(ft bgs)

0

1,000

2,000

3,000

4,000

Storage 

Formation

Injection Test

Well

Depth 

(ft bgs)

0

1,000

2,000

3,000

4,000

Storage 

Formation

Depth 

(ft bgs)

0

1,000

2,000

3,000

4,000

Storage 

Formation

Injection Test

Well

System Monitoring 

3650

3700

3750

3800

3850

3900

3950

0 20 40 60 80 100

Time (Days)

Pressure (PSI)

0

20

40

60

80

100

120

140

Temperature (*F)

Deep Monitoring 

 Well 

Not Shown: 

• Wellhead Monitoring 

• Acoustic Emissions 

Borehole 

Tiltmeters

Brine Chemistry 

and 

Fl id S li Na

Ca K

90

10

90

80

20

80

70

30

70

60

40

60

50

50

Surface Flux and 

Soil Gas Probes 

Multi-level Monitoring 

50

40

60

40

30

70

30

20

80

20

10

90

10

1460

1480

1500

1520

1540

1560

1580

1600

1620

0 10 20 30 40 50 60 70

Days

Pressure (PSI)

Pressure1

Pressure2

Pressure3

Pressure4

60

65

70

75

80

85

90

95

0 10 20 30 40 50 60 70

Days

Temperature (F)

Temp1

Temp2

Temp3

Temp4

Figure 3. Examples of MMV techniques applicable at various depths. (Graphic credit: Midwest 

Regional Carbon Sequestration Partnership) 

18 
Figure 4. Seismic images from the Sleipner injection project (IPCC 2005). 

Likewise, while some methods such as these require that a baseline survey be conducted prior to injection 

but are also useful for long-term monitoring once CO2 injection has begun, some technologies are better 

suited to pre-injection site characterization activities – such as geophysical tests of the formation that can 

only be run before the well is cased, or aerial magnetic surveys that are flown over the projected 

maximum CO2 plume footprint to find any undocumented wells that may need to be remediated prior to 

injection (Figure 5, USGS 2005) It is also important to note the interdependence of baseline and 

continuing data acquisition in validating and updating models used to simulate future reservoir behavior 

under expected conditions. By updating the models with new data, they become more robust over time, 

increasing certainty in the results for a given geochemical code – and therefore all subsequent projects 

that use that model – as well as for the specific field and project. 

A large, varied suite of tools for monitoring injected CO2 already exists, having been developed for other 

industries interested in exploring the deep subsurface. A large number of these technologies are mature, 

and are used commercially in the oil and gas fields (Spangler 2008). For example, seismic imaging of the 

subsurface – particularly two- and three-dimensional surveys – is routinely used all over the world by the 

oil and gas industry to identify new resources and manage hydrocarbon production. However, the 

application of these technologies to CCS, though expected to be very similar and in some cases already 

tested, may require knowledge gaps to be filled. For example, in order to resolve the movement of a body 

of injected CO2, seismic surveys are taken at various time intervals in order to see the progress of the CO2

plume. This kind of survey was less routine a decade ago when the Sleipner project began injection CO2

into the subsea Utsira formation, but Sleipner and other CCS projects have used it successfully, and the 

knowledge gained in these applications has increased the confidence in these “4D” seismic methods. 

19 
Figure 5. Example of data acquired during an aerial magnetic survey showing the locations of wells, 

differentiated from the surrounding ground by their magnetic signatures (USGS 2005). 

Table 3 summarizes the major components of the MMV suite discussed within the CCS technical 

community, including the phase(s) where each technology is applicable and whether it was used for one 

of the major CCS projects listed. Note that this discussion is based on a preliminary literature review, and 

should not be considered comprehensive. 

7.1 CO2SINK – 

The CO2SINK injection project at Ketzin, Germany was designed to utilize surface seismic, core 

analysis, wireline logging, geochemical monitoring of formation fluids in and above the storage zone, 

injection rate / in situ pressure and temperature monitoring, electrical resistance tomography, crosswell 

seismic, and surface / shallow subsurface monitoring techniques (Giese, et al. 2009). 

7.2 In Salah – 

BP’s Algerian In Salah project uses seismic, core, wireline logging, geochemical sampling / analysis, 

pressure / temperature / injection rate monitoring, electrical resistance tomography, passive / 

microseismic monitoring, gravitational surveys, tiltmeters, differential InSAR, soil / shallow subsurface 

and atmospheric monitoring techniques as well as tracer-based monitoring (Wright, et al. 2005, Ebrom, et 

al. 2007, Onuma & Ohkawa 2009). 

7.3 Nagaoka – 

The Japanese Nagaoka project has employed core analysis, wireline logging, geochemical sampling and 

analysis, injection operations monitoring (wellhead and in situ), crosswell seismic and microseismic 

detection to monitor CO2 injection operations (Yoshimura 2007). 

20 
7.4 Sleipner – 

The Sleipner project, under which Statoil injects CO2 into the Utsira formation, deep beneath the North 

Sea, has utilized a program focused on timelapse seismic surveys, and drawing on core analysis, wireline 

logging, geochemical monitoring, pressure / temperature / injection rate monitoring, as well as 

microseismic and gravitational techniques (Chadwick, et al. 2006, Chadwick, et al. 2007). 

7.5 Snøhvit – 

The Snøhvit project, also operated by Statoil, has also employed a monitoring and verification program 

that focuses heavily on timelapse seismic surveys and pressure monitoring, along with timelapse 

gravimetric surveys (Late 2008). 

7.6 Weyburn – 

The Weyburn project, which takes CO2 from the Dakota Synfuels plant in the United States and injects it 

into the Weyburn-Midale EOR field in Saskatchewan, Canada, uses a broad range of MMV technologies 

including timelapse seismic, core analysis, wireline logging, geochemical sampling and analysis, 

electrical resistance tomography, crosswell seismic, microseismic monitoring, and sampling of the soil, 

shallow subsurface and atmosphere to ensure retention of injected CO2 (White 2007). 

7.7 Frio – 

The GEOSEQ’s Frio project, a pilot injection project into the Frio formation in Texas, utilized seismic 

surveys for site characterization as well as monitoring plume movement. Core and wireline logging were 

used in characterization, in addition to monitoring techniques that included pressure / injection rate 

monitoring, electromagnetic surveys, crosswell seismic, geochemical sampling of the deep subsurface, 

and sampling of the atmosphere, surface and shallow surface for CO2 and tracers (Hovorka & Knox 2003, 

Hovorka 2005). 

In some instances, as is the case for the In Salah and Weyburn projects for example, the geology of the 

storage formation is analogous to the oil and gas formations where many of these technologies were 

pioneered and perfected. However, in other cases where non-standard storage formations (e.g., basalt 

formations, coal seams, shales, and others) may be used as the primary storage reservoir, it is likely that 

the gaps between existing technologies and their reliable use in these novel formation types will be 

greater than when they are used on sandstones and carbonates like the ones where oil and gas are typically 

found. Thus, while the various MMV component technologies may be commercially mature, they may 

not necessarily be able to deploy everywhere and always, and the same technologies may prove to be 

technologically immature or unusable in these novel formation types. 

Similarly, technologies that have been used in the oil and gas industry for decades and have been 

constantly improved upon to increase their effectiveness for finding and producing hydrocarbon resources 

are not capable of imaging a very small volume of oil, nor would they be capable of imaging a very small 

volume of CO2. Indeed, the biggest gun in the MMV arsenal, 3D seismic surveys, typically expect 

resolutions in the meters to tens of meters when imaging the edge of the CO2 plume. For the range of CO2

densities present at depth at the Sleipner project, this corresponds to hundreds or thousands of tons of 

CO2. While being able to define the boundary of a CO2 plume that is 5000 feet deep and be accurate to 

within 10-20 feet and verify millions of tons of CO2 injected to within a matter of a few hundred tons is a 

technological marvel, if CO2 regulations require that MMV methods be capable of verifying that 100% of 

the CO2 is present and accounted for, there is no suite of technologies that currently exists that will meet 

this requirement. In no way does this suggest that regulations will be expected to forgive some quantity of 

21 
leakage, but the resolution of the monitoring tools is such that knowing where literally all of the CO2 is at 

any time is not possible, nor is it likely to be any time in the next 10-20 year timeframe expected to be 

crucial for CCS deployment and climate change mitigation in general. As discussed earlier, some tools 

are best suited for surface or near-subsurface monitoring tasks, while others are ideal for the very deep 

subsurface; similarly, some tools have very high lateral resolutions, others very high vertical resolutions, 

and still others achieve a well balanced combination of the two. Certain tools complement each other well 

and are often used in conjunction with each other (e.g., surface seismic with vertical seismic profile), and 

other tools can be combined to address the unique needs – reservoir geometry, formation fluids, matrix 

rock, etc. – of the individual storage site. However, while the individual resolutions of each tool in the 

MMV suite employed by a given project may vary by technology and site, it is the cumulative set of data 

produced by the combination of MMV tools, iterative reservoir modeling and careful injection rate 

monitoring that provides the needed level of detail to detect and address issues before they threaten from 

multiple tools corroborating and improving modeling results and verifying the initial flowmeter 

measurements of CO2 introduced into the storage formation that resolves enough detail to say with a very 

high degree of certainty that the CO2 is effectively stored, and that groundwater and surface resources and 

environmental health are being protected. 

Lastly, it is important to note that there are often multiple technologies that can be used to obtain values 

for the same parameter. One technology may be better for a certain situation, while another would be 

preferable elsewhere. This suggests that, instead of a single standardized MMV suite for all sites, 

operators and their wellfield support contractors should choose that suite of technologies, based on sitespecific needs, that satisfy the data requirements necessary to verify the volume and location of injected 

CO2 at the levels of resolution and certainly required by the entity responsible for certifying the emissions 

credit or offset. If verification requirements are crafted to be appropriate to the resolution of the tools used 

to quantify the volume and location of injected CO2, and if project operators are allowed to use a flexible 

approach to selecting the MMV technologies employed, for a large majority of the potential CO2 storage 

projects likely to deploy in the next 10-20 years, the existing technologies available for MMV are likely 

to be sufficient. As CCS deploys and demand for storage in non-standard settings grows, the need for 

effective novel MMV applications is likely to push the research and industrial communities up the 

learning curve as well. 

22 
Table 3. Key MMV technologies, their applicability by phase, and application at selected major 

CCS projects around the world. 

Technology Description

CharacterizationInjectionPost-ClosureCO2SINKIn SalahNagaokaSleipnerSnohvitWeyburnFrio

Surface-based seismic (2D / 3D / 4D) Surface-based sources used to impart energy into thesubsurface. Surface-based 

receivers collect energy waves that have been reflected and refracted through the 

deep subsurface, and these travel time data are processed and analyzed to resolve 

structures at depth. 2D seismic produces a single "slice" image of the subsurface, 

while 3D produces a three-dimensional image. So-called "4D" timelapse seismic data 

are acquired at multiple discrete periods in time to resolve changes in the subsurface 

over time. 

XXXXX XXXX

Lithology logging / core Initially performed for site characterization and project / operational design, these 

tests are crucial to understanding the fine-scale characeristics of the formation at 

depth. In particular, core samples can be analyzed in the laboratory for critical 

storage formation and caprock parameters, including information on the ability of the 

rock to transmit fluids and its ability to withstand injection pressures.

X XXXX X

Wireline logging Performed by introducing a set of tools into the well to measure geophysical and 

electrical properties of the storage formation, caprock and other zones of interest. 

Initial logging is often done in an uncased well, although some logs (e.g., cement 

bond log) are routinely performed through casing. These logs are used for initial 

characterization and project design, and many are useful for ongoing monitoring as 

well. Note that logging of the injection well requires that injection cease in order to 

introduce the logging tool string.

XXXXXXX XX

Geochemical sampling & analysis Collection of fluid samples from the storage zone, as well as overlying and possibly 

underlying aquifers via monitoring wells to screen for changes in chemistry that could 

suggest movement of formation fluids from the storage zone

XXXXXXX XX

Pressure & injection rate monitoring Standard field management tools used to monitor formation and well integrity B

X

X X X X X X X X X

Electromagnetic surveys Introduce EM energy into the subsurface and measure the response. Can be used as 

an accessory to seismic surveys.

XXX X

Electrical resistance tomography Inexpensive but lower resolution that seismic, ERT uses an electrode in the 

subsurface (the wellbore may be used as the electrode) to measure resistitivity. Data 

can be acquired often and via remote, making this a good option for filling in between 

higher-resolution but more expensive discrete seismic surveys.

XXXXX X

Crosswell seismic Uses sources and receivers placed in the wells, which allows for greater resolution in 

the subsurface, but only between the wells. 

XXXX X XX

Microseismic / passive seismic Uses permanent geophones in monitoring wells and/or on the surface to monitor for 

very, very small geomechanical changes in the storage formation as the CO2 moves.

XXX XXX X

Gravitational surveys Measures changes to the gravitational field in order to resolve changes in formaiton 

fluid density as CO2 displaces brine in the formation over time. 

BXX X X

Magnetic surveys Excellent aerial technique for identifying existing (cased) wellbores. Less mature as a 

CO2 monitoring technique. 

X

Tiltmeters Resolves small changes in elevation of the ground surface resulting from CO2 

injection at depth using tiltmeters on the ground.

BX X

InSAR / DInSAR Uses satellite-based radar to measure changes in the elevation of the ground surface 

resulting from CO2 injection at depth.

BXX X

Soil gas / vadose zone / shallow aquifer mMonitoring wells in the shallow subsurface are used to collect samples to check for 

changes in CO2 concentrations, as well as changes in isotope ratios, concentrations 

of tracers, and other markers that might indicate CO2 leakage.

BXXXX X X

Tracers Impurities that are highly detectable at low concentrations and not naturally present in 

the subsurface or the CO2 stream are introduced into the injectate prior to injection. 

Detectors used at the surface and in internediate water-bearing zones can look for 

these trace gases to determine if CO2 is leaking from the storage interval.

XX X X

Atmospheric monitoring Monitoring of the wellhead and other areas above the plume. This can include eddy 

covariance, LIDAR and other forms of CO2 detection.

BXX X X X

B: Baseline needed for future phases. 

23 
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28 
Appendix B: Online Resources Tracking CCS Demonstration 

Projects and Planned Commercial CCS Facilities 

• IEA Greenhouse Gas R&D Programme: CO2 Capture and Storage Info. An extensive searchable 

database of CCS research projects around the world. 

 http://www.co2captureandstorage.info/search.php 

• National Energy Technology Laboratory: Regional Carbon Sequestration Partnerships. List 

general information on the Regional Carbon Sequestration Partnership program sponsored by the 

U.S. Department of Energy and contains links to more detailed information about specific 

research activities being carried out by these public-private CCS research partnerships. 

 http://www.netl.doe.gov/technologies/carbon_seq/partnerships/partnerships.html 

• Scottish Centre for Carbon Storage. “Where is CO2 Storage Taking Place?” An interactive map 

of operational and planned CCS facilities. 

 http://www.geos.ed.ac.uk/sccs/storage/storageSitesFree.html 

• The Australian Cooperative Research Centre for Greenhouse Gas Technologies (CO2CRC) has 

two interactive maps of ongoing and proposed CO2 storage demonstration projects around the 

world. 

http://www.co2crc.com.au/demo/worldprojects.html and 

http://www.co2crc.com.au/demo/worldprojects_pro.html 

29 
Appendix C: Overview of Principal CO2 Capture System 

Configurations that Could Be Applied to Large Commercial Power 

Plants 

(IPCC 2005)

30 
Appendix D: Brief Summary of Commercially Available 

Absorption-based CO2 Capture Systems 

While there are many different advanced CO2 capture technologies under development with some in the 

field testing stage (see Figueroa, et. al., 2008 for an overview of developments in CO2 capture), the 

following are short descriptions of the CO2 capture technologies in use at the commercial facilities 

described in the body of this paper. The table on the next page provides further elaboration on the CO2 

capture systems in use today (International Energy Agency, 2008). 

Post Combustion CO2 Capture Technologies 

Monoethanolamine (MEA) and a number of related amines are the most commonly employed CO2

capture systems today. MEA was developed over 70 years ago as a robust (i.e., relatively low cost and 

capable of being deployed in a variety of different circumstances) solvent for removing gases, such as 

CO2 and H2S, from produced natural gas before introducing the natural gas into pipelines to send to 

market. The basic MEA process has been modified over time to better tune it to the new task of CO2

capture from combustion flue gas streams. One particular innovation in this regard was the incorporation 

of incorporate inhibitors to resist solvent degradation and corrosion in the steel components of the CO2

capture unit (Herzog, 1999). 

• The Kerr-McGee/ABB Lummus Crest Process is employed to recover CO2 from coke and coalfired boilers. This process uses a 15-20% by weight aqueous MEA solution. The largest capacity 

experienced for this process is 800 tCO2 d system utilizing two parallel trains (IPCC, 2005). 

• The Fluor Daniel ECONAMINE Process is another MEA-based CO2 capture process. The 

Econamine process uses a 30% by weight aqueous solution of MEA in conjunction with 

inhibitors that are designed to prevent corrosion in the carbon steel components of the CO2

capture system. The Econamine process was specifically tailored for CO2 capture from oxygen 

rich gas streams. It has been used in many plants worldwide recovering up to 320 tCO2/d in a 

single train. (IPCC, 2005). 

• The Kansai Electric Power Co., Mitsubishi Heavy Industries, Ltd., KEPCO/MHI KS-1 Process

utilizes a proprietary sterically-hindered amines. The KS-1 amine was specifically designed for 

CO2 extraction from natural gas combustion. Other amines are more widely applicable to other 

process streams and other sectors of the economy. Over a decade’s worth of commercial 

experience using the KS-1 process, data have been collected that show that this process 

experiences relatively low amine losses and low degradation of the solvent over time without the 

need to use inhibitors (Yagi, et. al., 2008). The energy required to regenerate the KS-1 solvent 

can be 20% less than a similar MEA based system (Mangalapally, et. al., 2009). It has been used 

in many plants worldwide recovering up to 450 tCO2/d in a single train (Ijiima, et. al., 2009). 

Pre-Combustion CO2 Capture Technologies 

For pre-combustion CO2 capture systems, the CO2 is typically removed by a physical solvent process. 

The two most commonly used systems are based around Selexol (a glycol-based solvent marketed by 

Union Carbide) and Rectisol (a refrigerated methanol-based physical capture system marketed by Lurgi 

and Linde) (IPCC, 2005 and Blomen, et. al., 2009). Physical solvents are typically used for precombustion separation of acid gases including CO2 and H2S from synthesis gas streams such as those 

found synfuel plants as well as IGCC power plants with CO2 capture. The Dakota Gasification Great 

31 
Plains Synfuels Plant utilizes the Rectisol process to remove CO2 and sulfur from the syngas stream prior 

to the methanation. 

(Table taken from (International Energy Agency, 2008)

32 
33 

Appendix E: CO2 Purity Specifications for Various Classes of Use

(Sass, 2005) 

Notes: Table units are in ppm (v/v) unless otherwise noted. A blank indicates no maximum limiting 

characteristic.