# An Assessment of the Commercial Availability of Carbon Dioxide Capture and Storage Technologies
as of June 2009

JJ Dooley
CL Davidson

RT Dahowski

PNNL-18250

June 2009

1DISCLAIMER

This report was prepared as an account of work sponsored by an agency

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1Abstract: Currently, there is considerable confusion within parts of the carbon dioxide capture and storage (CCS) technical and regulatory communities re garding the maturity and commercial readiness of the technologies needed to capture, transport, inject , monitor and verify the efficacy of carbon dioxide (CO 2 ) storage in deep, geologic formations. The purpo se of this technical report is to address this confusion by discussing the state of CCS technological readiness in terms of existing commercial deployments of CO 2 capture systems, CO 2 transportation pipelines, CO 2 injection systems and measurement, monitoring and verification (MMV) systems for CO 2 injected into deep geologic structures. To date, CO 2 has been captured from both natural gas a nd coal fired commercial power generating facilities, gasification facilities and other industrial pr ocesses. Transportation via pipelines and injection

of CO 2 into the deep subsurface are well established co mmercial practices with more than 35 years of industrial experience. There are also a wide variet y of MMV technologies that have been employed to

understand the fate of CO 2 injected into the deep subsurface. The four existing end-to-end commercial CCS projects – Sleipner, Snøhvit, In Salah and Weyb urn – are using a broad range of these technologies, and prove that, at a high level, geologic CO 2 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 anthropogen ic 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, tr ansport, injection, monitoring, management and verification for most large CO 2 source types and in most CO 2 storage formation types, exist.

Key Words : carbon dioxide capture and storage; technological readiness; climate change; CO 2 pipelines; measurement, monitoring and verification.

2

## 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, No rth Dakota) and the Weyburn Enhanced Oil Recovery Project (Weyburn, Saskatchewan, Canada) ....................................................... 6

3.3 In Salah Natural Gas Production Facilit y (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 CO 2 Capture, Compression, Dehydration, and Handling Technologies ..................................... 8

4.1 Post Combustion CO 2 Capture from Pulverized Coal-fired Electric Power Plants ........... 8

4.2 CO 2 Capture from Coal Gasification .................................................................................. 9

4.3 CO 2 Capture from Oxygen-fired Coal Combustion ........................................................... 9

4.4 Post-Combustion CO 2 Capture from Natural Gas-fired Facilities ................................... 10

4.5 CO 2 Capture from Natural Gas Reforming ...................................................................... 10

4.6 CO 2 Capture from Natural Gas Production ...................................................................... 11

5.0 CO 2 Transportation Technologies ............................................................................................ 14

6.0 CO 2 Injection Technologies ...................................................................................................... 15

34 7.0 CO 2 Measurement, Monitoring and Verification Technologies ............................................... 17

7.1 CO 2 SINK – ....................................................................................................................... 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 CO 2 Capture System Configurations that Could Be Applied to Large

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

Appendix D: Brief Summary of Commer cially Available Absorption-based CO 2 Capture Systems ........ 31

Appendix E: CO 2 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:

• CO 2 capture systems that have been mated to coal and natural gas fired electricity plants, coal gasification facilities and various industrial facilities. Some of these CO 2 capture systems have been in operation since the late 1970s.

• There are currently more than 3,900 miles of dedicated CO 2 pipelines in the United States and there is more than 35 years of commercial experience associated with transporting large volumes

of CO 2 via dedicated pipelines. Some of the earliest CO 2 pipelines were constructed in the early 1970s and are still in operation today. Available data suggests that these CO 2 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 CO 2 into the deep subsurface for the purpose of

CO 2 -driven enhanced oil recovery. There are over 6,000 deep CO 2 injection wells currently in operation across parts of 10 states of the U.S. Since 1972, more than 8,800 CO 2 injector wells

have been used in Texas alone.

• There is a wide variety of measurement, mon itoring and verification (MMV) technologies which have been employed to understand the fate of CO 2 injected into the deep subsurface at large

commercial CO 2 storage facilities.

• There are currently four complete, end-to-end co mmercial CCS facilities on the planet. Each of these facilities captures anthropogenic CO 2 from a process stream/flue gas that would otherwise be vented to the atmosphere. The captured CO 2 is dehydrated, compressed and otherwise prepared for transport via pipeline and/or for injection into nearby suitable deep geologic CO 2 storage formations. Each facility injects between 0.7 MtCO 2 and 2 MtCO 2 into these deep geologic formations annually and then applies a suite of MMV technologies to monitor and verify the fate of the injected CO 2 . These four sites represent 25 years of cumulative experiential knowledge on safely and effectively storing anthropogenic CO 2 in appropriate deep geologic

formations.

It is also important to acknowledge that key compone nt 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 tec hnologies to the scale of deployment needed for a hypothetical 500 MW coal power plant that employed CCS to reduce its CO 2 emissions to the atmosphere.

• The largest CO 2 capture system commercially delivered to date that would be applicable to electric power production facilities can capture 450 tCO 2 /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 pa rallel capture units. This would represent a

1significant 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 CO 2 capture units that are as large as 3000tCO 2 /day which would reduce the number of parallel CO 2 capture trains required for this hypothetical 500MW coal plant to only three units.

• There are operational CO 2 pipelines in the U.S. that routinely transport 10-20 MtCO 2 / year through a single pipeline. A large 500 MW coal fired power plant that was capturing its CO 2 would generate approximately 3 MtCO 2 /year. Thus mankind’s ability to transport large volumes

of CO 2 over long distances via pipeline at a scale that would be germane to CCS deployment with large power generation facilities has been demons trated. Not only do these large pipelines exist but the pumps, compressors, valves, automated saf ety 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 MtCO 2 has been injected into the Canyon Reef

formation at the 90mi 2 SACROC unit in Texas for the purpose of stimulating additional oil recovery. This volume of CO 2 is roughly equivalent to what a 500 MW coal power plant would produce over a 40 year period. Assuming that the CO 2 from this hypothetical 500 MW power plant was injected into a deep saline formation, th e foot-print of the injection field would likely

be smaller than the 90mi 2 of the SACROC unit, and perhaps significantly so. It is important to

note that the CO 2 injected at SACROC was not monitored in terms of whether the CO 2 was being permanently isolated from the atmosphere and most of the CO 2 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 CO 2 into the deep subsurface over many decades and over a large area exists.

• For ten years, approximately 1 MtCO 2 /year as been injected into th e 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 co re analysis, wireline logging, geochemical monitoring, pressure / temperature / injection rate monitoring, as well as microseismic and gravitational techniques. The data derived fro m this MMV program is evaluated by national regulators who use these data to determine the envi ronmental efficacy of CCS in terms of climate protection and to determine whether the storag e activities are successful in isolating the CO 2 from the atmosphere and to hence avoid Norway’s exis ting carbon tax. Again, if one compares this to activity to a nominal 500MW coal power plant that would generate approximately 3 MtCO 2 /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 CO 2 point sources (e.g., fossil fired power plants, refineries, cement kilns, chemical plants) that c ould conceivably adopt CCS technologies as a means of reducing their CO 2 emissions have not adopted CCS systems. Moreover, the vast majority of the new power plants and other large industrial CO 2 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 signific antly 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 pr ogram focused on improving CCS technologies and demonstrating them in various combinations of t echnological, geographical, and geologic applications and settings.

23 The fact that CCS technologies are commercially available today is also not sufficient to suggest that they provide cost effective means for significantly reducing CO 2 emissions to the atmosphere absent a climate policy that would create a significant disincentive on the free venting of CO 2 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 CO 2 as well as other key regulatory issues. Howe ver, this again does little to diminish the commercial availability of the technologies, only in crease 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 chal lenge 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 advan cements in energy efficiency, nuclear power, renewable energy, and other energy technologies to not only reduce carbon dioxide (CO 2 ) emissions but to also help to improve economic efficiency, competitiveness, and local environmental quality.

Carbon dioxide capture and storage (CCS) technologies ha ve 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 an d other research groups has shown that CCS systems are capable of reducing the costs of climate stabili zation 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 productio n (IPCC, 2005, Dooley, et. al., 2006, McFarland et. al. 2003). The costs of CCS systems should be compe titive with – and in some cases significantly less costly than – other potential large-scale CO 2 emissions reduction and abatement technologies (Edmonds, et. al., 2008).

Globally, there are currently more than 8,100 large CO 2 point sources (accounting for more than 60% of all anthropogenic CO 2 emissions) that could conceivably adopt CCS technologies as a means for delivering deep and sustained CO 2 emissions reductions. These 8,100 large CO 2 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 CO 2 , suggesting that in certain niche applications it is already profitable to deploy so me 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 CO 2 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 CO 2 point sources.

There is widespread agreement on the potentia l value of CCS technologies in a greenhouse gas constrained world (e.g., Dooley et. al., 2006, IPCC 2005, Bennaceur and Gielen, 2009, MIT 2007).

4However, there is considerable confusion as to whet her CCS technologies exist today or whether these are technologies that have yet to be invented and therefor e will not be ready for use for many years, perhaps decades, to come.

The purpose of this short paper is to id entify and describe commercially deployed CO 2 capture systems,
CO 2 transportation pipelines, CO 2 injection systems and measurement, monitoring and verification (MMV) systems for CO 2 injected into deep geologic structures. That is, this paper seeks to help establish the current commercial availability of CCS technologi es. This paper will not attempt to speak to the rapidly changing status of currently operational or pl anned CCS facilities. Readers interested in learning more about these facilities and demonstration projects wh ich are working to advan ce 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. CO 2 is currently being captured from both natural gas and coal fired commercial pow er generating facilities, gasification facilities and other industrial processes. Transportation via pipelines and injection of CO 2 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 b een employed to understand the fate of CO 2 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 anthropogen ic interference with the

Earth’s climate.

Before examining the commercial deployment of indi vidual 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 CO 2 from process streams/flue gases that would otherwise be vented to the atmosphere. The captured CO 2 is dehydrated, compressed and otherwise prepared for transport via pipeline and injection into nearby suitable deep geologic CO 2 storage formations. Each facility injects CO 2 into these deep geologic formations and then employs a suite of MMV technologies to monitor the injected CO 2 . These four facilities represent 25 years of cumulative knowledge on safely and effectively storing anthropogenic CO 2 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 co mmercial CCS facility. The Sleipner natural gas field has a high – approximately 9% – concentration of CO 2 which must be removed prior to shipping the natural gas on-shore and selling it to various markets. Approximately 1 MtCO 2 /year is removed from the produced natural gas via an amine-based CO 2 separation unit. The captured CO 2 is injected via a single injection into the Utsira deep saline formation 800-1000 meters below the seabed (IPCC 2005 and IEA GHG, 2009). CO 2 capture and storage has been ongoing at Sleipner since 1996 and to date more that 10

MtCO 2 has been safely stored at this site (Statoil Press Release, 2008). The Sleipner project has utilized

5an MMV program focused on time-lapse seismic survey s, and drawing on core analysis, wireline logging, geochemical monitoring, pressure / temperature / inj ection rate monitoring, as well as microseismic and gravitational techniques (Chadwick, et al. 2006, Chadwick, et al. 2007).

• CO 2 storage began in 2000

• 2 MtCO 2 /year being injected via approximately 85 injection wells over a 40 km 2 area

• Projected 30 MtCO 2 lifetime storage Weyburn

• CO 2 storage began in 2004

• Three 1.5 km horizontal CO 2 injector wells are used to inject 1.2 MtCO 2 /year

• Projected 17 MtCO 2 lifetime storage In Salah Snøhvit

• CO 2 storage began April 2008

• 0.7 MtCO 2 /year injected into DSF

• 23 MtCO 2 injected over 30 years

• 150 km of the Norwegian coast

• Started injection in 1996

• More than 10 MtCO 2 have been injected via 1 injection well with a plume approximately 5 km 2 with

• Projected 20 MtCO 2 lifetime storage

• 150 km of the Norwegian coast Sleipner • CO 2 storage began in 2000

• 2 MtCO 2 /year being injected via approximately 85 injection wells over a 40 km 2 area

• Projected 30 MtCO 2 lifetime storage Weyburn

• CO 2 storage began in 2004

• Three 1.5 km horizontal CO 2 injector wells are used to inject 1.2 MtCO 2 /year

• Projected 17 MtCO 2 lifetime storage In Salah Snøhvit

• CO 2 storage began April 2008

• 0.7 MtCO 2 /year injected into DSF

• 23 MtCO 2 injected over 30 years

• 150 km of the Norwegian coast

• Started injection in 1996

• More than 10 MtCO 2 have been injected via 1 injection well with a plume approximately 5 km 2 with

• Projected 20 MtCO 2 lifetime storage

• 150 km of the Norwegian coast Sleipner

Figure 1: Overview of Four La rge Commercial CCS Facilities



## 3.2 Great Plains Synfuels Plant (Beulah, North Dakota) and the Weyburn Enhanced Oil R ecovery 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 CO 2 from a coal energy production facility. CO 2 is captured at a coal gasification plant in North Dakota and shipped to Saskatchewan via a dedicated 320 km pipeline. CO 2 is captured from this synfuels plant with a Rectisol capture unit. More than 3 MtCO 2 /year is captured at this plant with approximately 2 MtCO 2 / year being sent to Weyburn with the remainder vented to the atmosphere (IPCC, 2005). In 2000, equi pment needed to recover, compress, and transport via pipeline a portion of this coal gasification plant’s CO 2 was installed so that the CO 2 could be pipelined to an enhanced oil recovery project known as the We yburn Unit in southeast Saskatchewan, Canada. The Weyburn oil field lies at a depth of approximately 15 00 meters and is less than 50 meters thick. The Weyburn EOR project injects both water and CO 2 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 anal ysis, 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 CO 2 (White 2007).

6

## 3.3 In Salah Natural Gas Producti on Facility (Central Saharan Region, Algeria)

CO 2 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 MtCO 2 /year is removed from the natural gas using and MEA-based CO 2 capture unit. The CO 2 is injected into a deep saline geologic formation 1800 meters below the surface via three CO 2 injector wells with long horizontal legs running up to a 1.5 km to increase the efficiency of CO 2 injection in this tight formation (IPCC, 2005). CO 2 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 subsu rface 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 fi rst commercial liquefied natural gas production facility. The fields that are producing the natural gas also contain a significant quantity of CO 2 (5-8% CO 2 by volume) which must be separated before the natural gas can be li quefied prior to transport. Approximately 0.7 MtCO 2 / 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 th e 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 na tional regulators who use these data to determine the environmental efficacy of CCS in terms of cl imate protection. Norwegian regulators rely on these

data as evidence that the CO 2 is staying in the target injection formations, to determine whether the storage projects are successfully trapping CO 2 away from the atmosphere and therefore whether the projects qualify as a mean to avoid the national carbon tax on CO 2 emissions. The Weyburn and InSalah projects utilize their MMV data to demonstrate to relevant regulators that CO 2 is remaining in the injection formation and is therefore not negativel y 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 CO 2 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 CO 2 storage at these two sites.

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

MtCO 2 /year into suitable deep geologic formations, a typical large fossil fired power plant would generate perhaps 2-4 times as much CO 2 /year and perhaps an order of magnitude more cumulative CO 2 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 su ch as pipelines that can handle up to 2 MtCO 2 / 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

CO 2 from a large commercial power plant. These four facilities also demonstrate that MMV technologies

7can be deployed in a range of different settings a nd conditions to understand the movement and behavior

of CO 2 that has been injected into the deep subsurface.



## 4.0 CO 2 

## Capture, Compression, Dehydration, and Handling Technologies

CO 2 has been captured from operational coal power pl ants 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 CO 2 capture is a secondary task. As such, these facilities tend to capture CO 2 from a small fraction of the total flue gas stream as these CO 2 capture units are sized to meet niche

commercial markets for CO 2 (such as carbonated beverage pr oduction and food processing).

As noted above, CO 2 is also being captured at the Dakota Gasification Facility which gasifies coal to produce synthetic natural gas as well as a number of ch emical 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 CO 2 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 CO 2 is not precisely the

same as CO 2 capture from a coal-fired IGCC power plant.

Anthropogenic CO 2 is also “captured” from natural gas processing plants and from ammonia plants, which produce a high purity CO 2 stream that requires little effort to capture beyond diverting and compressing it. Similar to the situation for th e Dakota Gasification Facility, the capture of CO 2 at these facilities is an inherent part of the process of producing the end product (e.g., natural gas). The technologies used to separate CO 2 at these facilities are well established. CO 2 capture from natural gas processing plants is at the heart of three of the f our large commercial end-to-end CCS facilities currently in operation worldwide. The volumes of CO 2 captured from these facilities ar e 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 CO 2 capture system. Systems to compress, dehydr ate and move gaseous and supercritical CO 2 including materials and seals, fittings, meters, etc. are all co mmercially available and well established technologies.

Appendices C and D provide more detail on the three basic CO 2 capture system configurations and terms like “food grade CO 2 ” and “amine” that are used throughout the remainder of this section.



## 4.1 Post Combustion CO 2 

## Capture from Pulverized Coal-fired Electric

Power Plants

CO 2 is currently being captured from three coal fired el ectric power plants in the U.S. Each of these are conventional coal power plants. A small fraction of the power plant’s overall CO 2 is captured to serve

niche markets for CO 2 . The vast majority of the CO 2 produced at these power plants through the combustion of coal to generate electr icity 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 tCO 2 /day of food grade CO 2 (Holt, 2008). The CO 2 is captured using an ABB Lummus unit that uses monoethanolamine (MEA) as its solvent. This pl ant has been in operation since 2000. (IEA GHG, 2009)

• Shady Point Power Plant (Panama, Oklahoma) . The 320MW

e 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 tCO 2 /d of food grade CO 2 via an ABB Lummus scrubber system that uses MEA as it s solvent. The extracted CO 2 is used for food processing, freezing, beverage production and ch illing purposes. (IEA GHG, 2009).

• Searles Valley Minerals Soda Ash Plant (Trona, California). Approximately 800tCO 2 /d of CO 2 is captured from the flue gas of a coal power plant (st eam 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 CO 2 capture facility. The captured CO 2 is used for the carbonation of brine in the process of producin g soda ash. (IEA GHG, 2009, SourceWatch, 2009).



## 4.2 CO 2 

## Capture from Coal Gasification

As noted above, the capture of CO 2 from a coal gasification plant like the Dakota Gasification Facility which makes synthetic natural gas and various chemic als 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 CO 2 is removed by plant’s gas treatment units upstream of the methanation units in an already concentrated and pressurized form. This

CO 2 stream is in a form that requires little extra pr ocessing 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 CO 2 prior to combustion of the syngas stre am, 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 CO 2 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 CO 2 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 th at synthesizes natural gas from coal. CO 2 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 CO 2 was installed so that the CO 2 could be pipelined to an enhanced oil recovery project known as the Weyburn Unit in southeast Saskat chewan, Canada. More than 3 MtCO 2 /year is separated at this plant with approximately 2 MtCO 2 / year being sent to Weyburn with the remainder vented to the atmosphere (IPCC, 2005, Perry and Eliason, 2004).



## 4.3 CO 2 

## 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 n on-reactive constituent gases is seen as one promising

9technology for increasing the concentration of CO 2 in the flue gas stream and thereby simplifying and hopefully reducing the cost of CO 2 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 220tCO 2 /day can be captured from this pilot plant via compression and liquefaction of the resulting high purity CO 2 exhaust stream as opposed to a chemical absorption process like MEA. The captured CO 2 is stored in a liquefied state on-site in two 180m 3 tanks which are used to temporarily store the CO 2 before it is sent to various markets via tanker trucks. (Strömberg, 2009)



## 4.4 Post-Combustion CO 2 

## Capture from Natural Gas-fired Facilities

While the CO 2 concentration in the flue gas of conventiona l coal-fired power plants is approximately 15% and oxy-fired technology aims at significantly higher c oncentrations, the combustion of natural gas results in very low CO 2 concentrations (approx. 3%-5%). Capturing CO 2 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 tCO 2 /day of food-grade CO 2 . A Fluor

Econamine CO 2 scrubber system is used to remove CO 2 from flue gases. The plant has been operational since 1994. (IEA GHG, 2009).

• Prosint Methanol Production Plan t (Rio de Janeiro, Brazil) . Approximately 90 tCO 2 /day of foodgrade CO 2 is captured from the flue gases of a natura l gas-fired boiler using a Fluor Econamine

MEA CO 2 capture unit. This facility has been in operation since 1997. The captured CO 2 is used to carbonate beverages (IEA GHG, 2009).



## 4.5 CO 2 

## Capture from Natural Gas Reforming

Natural gas is commonly used as a fe edstock in the production of hydr ogen, 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 separa ting out large commercial quantities of high purity CO2 (IPCC, 2005).

• Indian Farmers Fertilizer Company (Aonla and Phulpur, India) . CO 2 is recovered from steam reformer flue gases via a CO 2 capture unit that uses Mitsubi shi Heavy Industry’s (MHI) proprietary KS-1 amine. The plant captures approximately 900 tCO 2 /day utilizing two 450

tonCO 2 /day capture trains) for use in manufacturing (MHI, 2009).

• Petronas Fertilizer (Kedah Darul Aman, Malaysia). Approximately 160 tCO 2 /day is captured from a steam reformer flue gases. The recovered CO 2 is used for urea production. The Petronas flue gas CO 2 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 tCO 2 /day is captured from steam reformer flue gases using a capture unit based on MH I’s KS-1 solvent. CO 2 capture began at this facility in 2008 (MHI, 2009).

Luzhou Natural Gas Chemicals (Luzhou City, China) . CO 2 is removed from the exhaust gases of a natural gas reformer unit using Fluor's Econamine MEA CO 2 removal process. The facility captures approximately 160 tCO 2 /d of CO 2 which is used for manufacturing urea. (IEA GHG, 2009)



## 4.6 CO 2 

## Capture from Natural Gas Production

Natural gas fields around the worl d contain various levels of CO 2 that is intermixed with the methane and other light hydrocarbons which are being produced fro m these fields. Natural g as pipeline specifications vary around the world, though natural gas markets and pipeline operators generally limit CO 2 concentrations to no more than 2% by volume. This is done to prevent pipeline corrosion, to avoid using energy to compress the CO 2 for transport and to increase the hea ting value of the gas (IPCC, 2005). For the vast majority of these facilities, current commercial practice is to vent this pure CO 2 into the atmosphere

• Snøhvit LNG Project (located in the Barents Se a 150 km off the northern coast of Norway). The Snøhvit facility is Europe’s first commercial lique fied natural gas production facility. The fields that are producing the natural gas also contain a significant quantity of CO 2 (5-8%), which must be separated before the natural gas can be lique fied prior to transport (Carbon Capture Journal 2008). Approximately 0.7 MtCO 2 / 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) . CO 2 concentrations in this natural gas field range from 1-10% which is far in excess of allowa ble concentrations for exporting natural gas to markets in Europe. Approximately 1.2 MtCO 2 / year is removed from the natural gas using and

MEA-based CO 2 capture unit and is injected into a nearby deep geologic formation. CO 2 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 CO 2 which must be removed prior to shipping the CO 2 on shore and selling it to various mark ets. Approximately 1 MtCO2/year is removed from the produced natural gas via an amine-based CO 2 separation unit. The captured

CO 2 is stored in a nearby deep saline formation (IEA GHG, 2009). CO 2 capture and storage has been ongoing at Sleipner since 1996 and to date more that 10 MtCO 2 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% CO 2 and only 22% natural gas. The plant has been separating, compressing, and selling approximately 4 MtCO 2 /yr to various enhanced oil recovery projects in the region and venting another 3.5 MtCO 2 /yr. Selexol process is used to remove CO 2 and H 2 S from natural gas (Kubek, 2009). ExxonMobil is currently planning to increase the capture of CO 2 by another 100 MMCFD (1.9 MtCO 2 /yr) and is testing a new controlled freeze zone capture technology that may make additional capture more affordable (Environmental Leader, 2008).

1112 • Val Verde Natural Gas Plants (T errell and Pecos Counties, Texas) . The Terrell, Grey Ranch, Mitchell, and Puckett plants, process natural gas and transport their collected CO 2 to oil fields in west Texas via the Petro Source Canyon Reef Carriers CO 2 pipeline (the oldest large CO 2 transport pipeline in the U.S., constructed in 1972). Current estimates suggest that 75 MMCFD

of CO 2 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% CO 2 which is removed by an amine based separation process. The resulting high purity (99%) CO 2 stream is used periodically for EOR flooding of Niagaran Reef oil fields (transported via existing 8 mile pipe line) and also for the ongoing demonstration of CO 2 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 CO 2 is vented to the atmosphere.

Table 1 summarizes the individual CO 2 capture facilities discussed above. The volume of CO 2 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 a nd technical communities. The first three rows in

Table 1 also show the volume of CO 2 that could be captured from hypothetical 500 MW natural gas and coal fired power plants. These hypothetical referenc e plants are included here to provide a basis of comparison from today’s CO 2 capture deployments to the scale that mi ght be needed for future facilities. As can be seen, many of the existing CO 2 capture facilities – and in particular those capture facilities that are mated to fossil fired electricity generating plants – is considerably smaller than the volumes of CO 2 that would have to be processed from these reference 500 MW facilities. However, the observation that

CO 2 capture facilities mated to existing power plants is small compared to a large power plant’s total CO 2 emissions should be seen as being driven by the niche market circumstances that existed which led to the

investment in these CO 2 capture systems. That is, these facilities were built to serve a specific

commercial market for CO 2 ; at the time they were built there was no incentive to build a CO 2 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 CO 2 capture unit.

Because these CO 2 capture units were sized to serve specific market demands for CO 2 , it would be incorrect to assume that the size of these units repr esents some inherent technical or economic threshold

for CO 2 capture units. The last two columns in Table 1 ar e intended to speak to this point. The data in these last two columns represent a back of the envelope calculation of how many CO 2 capture trains

would be needed to handle this volume of CO 2 based upon a 450 tCO 2 /day system (the largest advanced

CO 2 capture system commercially installed to date) and a 3000 tCO 2 /day system (which represents the largest advanced CO 2 capture system that Mitsubishi Heavy In dustries says they can deliver today for commercial applications (Hirata, et. al., 2008 and Ijim a et. al., 2009)). Assuming that the largest currently

installed CO 2 capture system that is applicable to elect ric power production was deployed on a nominal 500 MW coal-fired power plant, it would re quire approximately 20 parallel 450 tCO 2 /day capture units. This would represent a significant capital expenditure a nd 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 tCO 2 /day capture technology that is reported to be available would reduce the number of parallel CO 2 capture trains required for this hypothetical 500MW coal plant to only three units. With additional experience and development, it is not unreasonable to believe th at the number of required trains may be further decreased.Table 1: Summarizing Existing Anthropogenic CO2Capture FacilitiesCO2SourceTypeUseMMCFDtCO2/dMtCO2/yrNumberof450tCO2/dCaptureTrainsNumberof3000tCO2/dCaptureTrains500 MW NGCC Power PlantReference Power Plant673,5501.382500 MW Pulverized Coal Power PlantReference Power Plant1548,1603.0193500 MW IGCC Power PlantReference Power Plant1457,6802.8183IMC Global Soda Ash Plant (USA)Coal-fired power plantSoda ash production158000.321Warrior Run Power Plant (USA)Coal-fired power plantFood/beverage63300.111Schwarze Pumpe Pilot Plant (Germany)Coal-fired oxyfuel combustionVarious42020.111Shady Point Power Plant (USA)Coal-fired power plantFood/beverage42000.111Great Plains Synfuels Plant (USA)Coal gasificationEOR1045,4802.0132Sumitomo Chemicals Plant (Japan)Natural Gas-fired power plantVarious42000.111Prosint Methanol Production Plant (Brazil)MethanolBeverage/food2900.011Enid Fertilizer Plant (USA)FertilizerUrea, EOR351,8500.751Indian Farmers Fertilizer Company (India)FertilizerManufacturing179000.321Ruwais Fertilizer Industries (India)Fertilizer84000.111Luzhou Natural Gas Chemicals (China)FertilizerUrea31600.111Petronas Fertilizer (Malaysia)FertilizerUrea31600.111Shute Creek Natural Gas Processing Plant (USA)Natural gas processingEOR30015,8705.8366Val Verde Natural Gas Plants (USA)Natural gas processingEOR753,9701.492In Salah Natural Gas Production Facility (Algeria)Natural gas processingGeologic storage623,2901.282Sleipner West Field (North Sea, Norway)Natural gas processingGeologic storage522,7401.071Snohvit LNG Project (Barents Sea, Norway)Natural gas processingGeologic storage361,9200.751DTE Turtle Lake Gas Processing Plant (USA)Natural gas processingEOR/Geologic storage116000.22113

## 5.0 CO 2 

## Transportation Technologies

The technologies needed to safely move CO 2 by pipeline are well established. CO 2 transport via pipeline has been practiced in the U.S. si nce the early 1970s and should be seen as an established technology.

The U.S. has by far the largest existing dedicated CO 2 pipeline infrastructure in the world. There are currently more than 3900 miles of dedicated CO 2 pipelines in the United States—of varying lengths and diameters—built primarily to serve CO 2 -driven enhanced oil recovery (EOR) projects. Figure 2 shows the existing CO 2 pipeline infrastructure in the US and Saskatchewan, Canada.

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

Many of the largest CO 2 pipelines in terms of length and capacity take CO 2 from natural CO 2 domes and transport the CO 2 to aging oil fields for enhanced oil recovery. Table 2 lists selected major CO 2 pipelines

in North America. As Table 2 illustrates the volumes of CO 2 that can be moved though these pipelines are very large and are certainly on the orde r of (if not larger than) the volume of CO 2 that would need to be transported from a large yet-to-be-built power pl ant that might employ CCS to reduce its greenhouse gas emissions. Large-scale transport of CO 2 via pipeline is not a technology that needs to be created nor are new laws or regulatory policies prerequisit es for any potential expansion of the nation’s CO 2 pipeline

infrastructure.

Gale and Davison (2007) and Forbes et. al. (2008) report that CO 2 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 impr oved remotely controlled safety valves and sensors.

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

Pipeline Name (year completed) Length Estimated Design Capacity
Bravo (1984) 217 7 MtCO 2 /year

Canyon Reef Carriers (1972) 140 miles 5.2 MtCO 2 /year

Cortez Pipeline (1984) 502 miles 24 MtCO 2 /year

Sheep Mountain (1984) 410 miles 9.5 MtCO 2 /year
LaBarge (2003) 285 miles 8 MtCO 2 /year
Val Verde (1998) 81 miles 2.5 MtCO 2 /year
Weyburn (2000) 205 miles 2 MtCO 2 /year

These existing CO 2 pipelines are regulated under an established body of regulations under the authority of the U.S. Department of Transportation’s Office of Pipe line 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 periodi cally 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 instrument ed to measure pressure and flow, and capable of isolating individual segments for maintena nce, repair, or to minimize loss of CO 2 in the event of a pipeline breach (IPCC 2005).



## 6.0 CO 2 

## Injection Technologies

The technologies needed to safely inject CO 2 into these deep geologic forma tions 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. CO 2 injection should be seen as established technology.

The injection of anthropogenic CO 2 into the deep subsurface dates to at least 1972 when CO 2 -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 MtCO 2 has been injected into the Canyon Reef formation for the purpose of stimulating additional oil recovery. 75 MtCO 2 were intentional produced from these fields fo r reinjection into other parts of the SACROC or in other oil fields employing CO 2 -driven EOR. Thus, an estimated 55 MtCO 2 has become trapped in these deep geologic formations from the injection of CO 2 (Smyth et. al. 2006). Meyer (2007) reports that 440 injection wells have been completed in the SACROC unit itself which covers approximately 90mi 2

.

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

CO 2 -driven enhanced oil recovery projects operational in the Untied States. The CO 2 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) es timates that since the start of the SACROC project in 1972 more than 8,800 CO 2 injector wells have been completed in Texas alone.

15A Real World 205 m ile CO 2 pipeline.

The CO 2 pipe line from the Dakota Gasifi cation Com p a n y’ s (DGC) Great Plains Synfuels Plant

runs for 205 miles fro m N o rth Dakota to Saskatchew an. This pipe line transports 2 MtCO 2 /y ear for use in enh a nced oil recover y operati ons at the Weyburn oil fiel d.

• Rights of way were negotiated with various la nd own e rs to acquire the needed continu ous corridor for the pipeline. All parties ev entually agreed to allow the pipeline to cross their

land. There was no need to resort to condem n ation proceedings.

• The pipeline dia m eter runs from 12 to 14 inches. The pipe is made fro m carbo n steel as there was no need to use exotic alloy s given the ver y low water co ntent entrained in the

CO 2 com i ng from the DGC Great Plains Synfuels Plan t. The thickne ss of the pipel i ne’s

walls is incre ased significa ntly at water crossings, road and railroad crossings. The

maxi m u m op erating pressure is 2700 psi g over th e firs t half of the pipeline and 2964 psig over the remainder of the p i peline. A bo oster pum p operates at Tio g a, ND which is approxim a tely half way al ong t h e pipeli ne.

• The pipeline i s buried at a minim u m depth of 4 feet. At road crossings, a m i nimum depth of 5 feet is used and at railroad crossings the pipeline i s buried to a depth of 10 fe et.

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

individual sections of the pipelin e to be is olated in case of dam a ge to the pipeline. These

rem o tely cont rolled m a in line valves are no m o re than 20 m iles apart along t h e pi peline.

• The pipeline crosses three water w ay s along its pat h ; t h e Little Missouri River as well as

Lake Sakakawea both of which are in Nort h Dakota and Jewel Cr eek in Canada. The crossing at Lake Sakakawea is three m i les long. At t h e two m o re significant water crossings, the Little Missouri River and Lake Sakakawea, there are rem o tely controlled

main line valves on both s hores for both of these water crossings.

• The pipeline undergoes pe riodic inspections and t ests to ensure its continued i n t e grity and safety includi ng: aerial and foot patrols o f the right of way 26 tim es per y ear, m a intenance and inspection of all valve s twice per y ear , internal inspection of the pipeline using

electronic tools at least onc e every 5 y e a r s, and testing of all emerge ncy s y stem s i n cluding over pressurizing safety de vices once per.

Sources: Perr y and Eliason, 2004 a nd D a kota Gasification Com p any 2009.

16The injection of CO 2 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

“CO 2 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 CO 2 injection has managed in a safe and effectiv e manner. These research studies are built upon

an examination of the historical record of CO 2 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 (20 08) 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 CO 2 storage fields.”

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

CO 2 injection at the SACROC field by Smyth (200 9) suggests that no leakage of injected CO 2 into shallower underground sources of drinking water has occurred notwithstanding the large

volumes of CO 2 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 CO 2 injector wells in the SACROC formation clearly show that the injected CO 2 reacted with the cement that the cement appears to have “retained its capacity to prevent significant flow of CO 2 ” which is the primary purpose of this cement casing around the CO 2 injection well.



## 7.0 CO 2 

## Measurement, Monitoring and Verification Technologies

Because CCS technologies will only deploy in the presence of a societal mandate to avoid CO 2 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 CO 2 in the subsurface, and certifies that a given ton of CO 2 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 CO 2 stored.

Measurement, monitoring and verification (MMV) technologies for CO 2 injected into the deep subsurface represent a large set of potential technological options for monitoring CO 2 injection and other critical in

situ behaviors that help determine the fate of the stored CO 2 and the ultimate efficacy of CO 2 storage as a means of isolating CO 2 from the atmosphere and underground so urces of drinking water. Wellhead monitoring of the volume and rate of CO 2 injected into the formation provides the first critical data stream used in the MMV toolkit. This step quantifies the amount of CO 2 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 belo w, some technologies are best used for detecting the presence of CO 2 at the surface and in the shallow subsurf ace – including atmospheric and soil monitoring methods that involve sampling and analysis to detect CO 2 in the air, soil and water table – while other

17technologies 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 monito ring the very deep subsurface, including formation fluid chemistry monitoring, and monitoring of overl ying water-bearing formations to determine if CO 2 from the target formation has migrated away from th e intended zone. They also can include technologies such as seismic imaging, a technology that uses en ergy imparted into the earth’s crust, collects information on how that energy is reflected and re fracted through the layers of rock, and uses that information to create an image of the CO 2 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

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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 140Temperature (*F)

Deep Monitoring

Well

Not Shown:

• Wellhead Monitoring

• Acoustic Emissions Borehole

Tiltmeters

Brine Chemistry

and
Fl id S li

Na

Ca K 9 0 1

0

90 8 0 2 0

80 7

0 3 0

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Soil Gas Probes

Multi-level Monitoring

50 4 0 6 0

40 3 0 7 0

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20 1 0 9 0

10 1460 1480 1500 1520 1540 1560 1580 1600 1620

0 10 20 30 40 50 60 70

DaysPressure (PSI) Pressure1

Pressure2

Pressure3

Pressure4

60 65 70 75 80 85 90 95

0 10 20 30 40 50 60 70

DaysTemperature (F)

Temp1

Temp2

Temp3

Temp4

Figure 3. Examples of MMV techniques applicable at various depths. (Graphic credit: Midwest Regional Carbon Sequestration Partnership)

18Figure 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 CO 2 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 ma gnetic surveys that are flown over the projected

maximum CO 2 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 valida ting and updating models used to si mulate 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 geoche mical 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 CO 2 already exists, having been developed for other industries interested in exploring the deep subsu rface. 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 su rveys – is routinely used all over the world by the oil and gas industry to identify new resources a nd 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 ex ample, in order to resolve the movement of a body of injected CO 2 , seismic surveys are taken at various time intervals in order to see the progress of the CO 2 plume. This kind of survey was less routine a decad e ago when the Sleipner project began injection CO 2 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.

19Figure 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 di scussion is based on a preliminary literature review, and should not be considered comprehensive.



## 7.1 CO 2 

## SINK –

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, tiltmet ers, differential InSAR, soil / shallow subsurface and atmospheric monitoring techniques as well as trace r-based monitoring (Wright, et al. 2005, Ebrom, et al. 2007, Onuma & Ohkawa 2009).



## 7.3 Nagaoka –

The Japanese Nagaoka project has em ployed core analysis, wireline logging, geochemical sampling and analysis, injection operations monitoring (wellhead a nd in situ), crosswell seismic and microseismic

detection to monitor CO 2 injection operations (Yoshimura 2007).

20

## 7.4 Sleipner –

The Sleipner project, under which Statoil injects CO 2 into the Utsira formation, deep beneath the North Sea, has utilized a program focused on timelapse seism ic surveys, and drawing on core analysis, wireline logging, geochemical monitoring, pressure / temper ature / 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 CO 2 from the Dakota Synfuels plant in the United States and injects it into the Weyburn-Midale EOR field in Saskatchew an, Canada, uses a broad range of MMV technologies including timelapse seismic, core analysis, wire line logging, geochemical sampling and analysis, electrical resistance tomography, crosswell seismic, mi croseismic monitoring, and sampling of the soil, shallow subsurface and atmosphere to ensure retention of injected CO 2 (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 seismi c, geochemical sampling of the deep subsurface, and sampling of the atmosphere, surface and shallow surface for CO 2 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 wh ere non-standard storage formations (e.g., basalt formations, coal seams, shales, and others) may be u sed as the primary storage reservoir, it is likely that the gaps between existing technologies and their re liable 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 t echnologies 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 effectiven ess for finding and produc ing 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 CO 2 . 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 CO 2 plume. For the range of CO 2 densities present at depth at the Sleipner project, this corresponds to hundreds or thousands of tons of

CO 2 . While being able to define the boundary of a CO 2 plume that is 5000 feet deep and be accurate to within 10-20 feet and verify millions of tons of CO 2 injected to within a matter of a few hundred tons is a technological marvel, if CO 2 regulations require that MMV methods be capable of verifying that 100% of

the CO 2 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 regul ations will be expected to forgive some quantity of

21leakage, but the resolution of the monitoring tools is such that knowing where literally all of the CO 2 is at any time is not possible, nor is it likely to be any tim e in the next 10-20 year timeframe expected to be crucial for CCS deployment and climate change miti gation 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 late ral 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 n eeds – 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 CO 2 introduced into the storage formation that resolves enough detail to say with a very high degree of certainty that the CO 2 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 mu ltiple technologies that can be used to obtain values for the same parameter. One technology may be bette r 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 s hould choose that suite of technologies, based on sitespecific needs, that satisfy the data requirements ne cessary to verify the volume and location of injected

CO 2 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 r esolution of the tools used to quantify the volume and location of injected CO 2 , and if project operators are allowed to use a flexible approach to selecting the MMV technologies empl oyed, for a large majority of the potential CO 2 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 st orage in non-standard settings grows, the need for effective novel MMV applications is likely to pus h the research and indu strial communities up the learning curve as well.

22Table 3. Key MMV technologies, their applicab ility by phase, and application at selected major CCS projects around the world.

Technology DescriptionCharacterizationInjectionPost-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 m Monitoring 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 Co mmercial CCS Facilities

• IEA Greenhouse Gas R&D Programme: CO 2 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: Regiona l Carbon Sequestration Partnerships. List general information on the Regi onal Carbon Sequestration Partners hip 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 CO 2 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 CO 2 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 CO 2 

## Capture System Configurations that Could Be Applied to Large Commercial Power

Plants

(IPCC 2005)

30

## Appendix D: Brief Summary of Commercially Available Absorption-based CO 2 

## Capture Systems

While there are many different advanced CO 2 capture technologies under development with some in the field testing stage (see Figueroa, et. al., 2008 for an overview of developments in CO 2 capture), the following are short descriptions of the CO 2 capture technologies in use at the commercial facilities described in the body of this paper. The table on th e next page provides further elaboration on the CO2 capture systems in use today (Inte rnational Energy Agency, 2008).

Post Combustion CO 2 Capture Technologies Monoethanolamine (MEA) and a number of related amines are the most commonly employed CO 2 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 va riety of different circumstances) solvent for removing gases, such as

CO 2 and H 2 S, from produced natural gas before introduci ng the natural gas into pipelines to send to market. The basic MEA process has been modified ove r time to better tune it to the new task of CO 2 capture from combustion flue gas streams. One particul ar innovation in this rega rd was the incorporation of incorporate inhibitors to resist solvent degrad ation and corrosion in the steel components of the CO 2 capture unit (Herzog, 1999).

• The Kerr-McGee/ABB Lu mmus Crest Process is employed to recover CO 2 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 tCO 2 d system utilizing two parallel trains (IPCC, 2005).

• The Fluor Daniel ECONAMINE Process is another MEA-based CO 2 capture process. The Econamine process uses a 30% by weight aque ous solution of MEA in conjunction with inhibitors that are designed to prevent corrosion in the carbon steel components of the CO 2 capture system. The Econamine pro cess was specifically tailored for CO 2 capture from oxygen rich gas streams. It has been used in many plants worldwide recovering up to 320 tCO 2 /d in a single train. (IPCC, 2005).

• The Kansai Electric Power Co., Mitsubishi Hea vy Industries, Ltd., KEPCO/MHI KS-1 Process utilizes a proprietary sterically-hindered amines. The KS-1 amine was specifically designed for

CO 2 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 de gradation 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 tCO 2 /d in a single train (Ijiima, et. al., 2009).

Pre-Combustion CO 2 Capture Technologies For pre-combustion CO 2 capture systems, the CO 2 is typically removed by a physical solvent process. The two most commonly used systems are based ar ound Selexol (a glycol-based solvent marketed by Union Carbide) and Rectisol (a re frigerated methanol-based physical cap ture system marketed by Lurgiand Linde) (IPCC, 2005 and Blomen, et. al., 2009). Physical solvents are typically used for precombustion separation of acid gases including CO 2 and H 2 S from synthesis gas streams such as those found synfuel plants as well as IGCC power plants with CO 2 capture. The Dakota Gasification Great

31Plains Synfuels Plant utilizes the Rectisol process to remove CO 2 and sulfur from the syngas stream prior

to the methanation.

(Table taken from (International Energy Agency, 2008)

3233 

## Appendix E: CO 2 

## 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.