A policy, legal, and regulatory evaluation of the feasibility of a national pipeline infrastructure for the transport and storage of carbon dioxide

              A Policy, Legal, and Regulatory Evaluation of the Feasibility
of a National Pipeline Infrastructure
for the Transport and Storage
of Carbon Dioxide
Topical Report
Reporting Period Beginning April 1, 2009, and Ending December 31, 2010
Principal Authors:
Kevin Bliss, Esq., Interstate Oil and Gas Compact Commission, Washington, D.C.
Darrick Eugene, Esq., Consultant, Austin, Texas
Robert W. Harms, Esq., The Harms Group, Bismarck, North Dakota
Victor G. Carrillo, Esq., Texas Railroad Commission, Austin, Texas
Kipp Coddington, Esq., Mowrey, Meezan, Coddington, Cloud, LLP, Washington, D.C.
Mike Moore, VP External Affairs, Blue Source LLC, Houston, Texas
John Harju, Associate Director for Research at the University of North Dakota Energy & Environmental Research Center, Grand Forks, North Dakota
Melanie Jensen, University of North Dakota Energy & Environmental Research Center, Grand Forks, North Dakota
Lisa Botnen, University of North Dakota Energy & Environmental Research Center, Grand Forks, North Dakota
Philip M. Marston, Esq., Marston Law, Alexandria, Virginia
Doug Louis, Director, Conservation Division, Kansas Corporation Commission, Wichita, Kansas
Steve Melzer, Melzer Consulting, Midland, Texas
Colby Drechsel, Wyoming Pipeline Authority, Cheyenne, Wyoming
Jack Moody, Director, State Mineral Lease Program, Jackson, Mississippi
Lon Whitman, Enhanced Oil Recovery Institute, University of Wyoming
IOGCC-SSEB CO2 Pipeline Task Force members
Submitted to:
Southern States Energy Board
6325 Amherst Court
Norcross, Georgia 30092
Submitted by:
Rachel Amann, Federal Projects Director
Interstate Oil and Gas Compact Commission
PO Box 53127
Oklahoma City, OK 73152-3127
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DISCLAIMER
This report was prepared as an account of work sponsored by an agency of the United States Government. Neither the United States Government nor any agency thereof, nor any of their employees, makes any warranty, expressed or implied, or assumes any legal liability or responsibility for the accuracy, completeness, or usefulness of any information, apparatus, product, or process disclosed, or represents that its use would not infringe privately owned rights. Reference herein to any specific commercial product, process, or service by trade name, trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement, recommendation, or favoring by the United States Government or any agency thereof. The views and opinions of authors expressed herein do not necessarily state or reflect those of the United States Government or any agency hereof.
ABSTRACT
The report focuses on the transportation of carbon dioxide (CO2) through pipelines from a “source” to a geologic ”sink,” the possibility of a federal mandate requiring capture and storage of CO2. An overview of carbon capture drivers and the geologic means of storing CO2 is provided. The Report also describes the nature, size, and location of the significant CO2 pipeline system that currently exists in the United States, and the state and federal regulatory regime, under which it operates. An analysis of the regulatory status of CO2 pipeline systems under the Interstate Commerce Act and the Natural Gas Act is included as well as a discussion of other prospective regulatory models. Potential business models and economic issues for future CO2 pipeline build-out are also discussed. Conclusions and recommendations suggest that the market is responding to current CO2 pipeline construction demand and that future build-out of CO2 pipelines should occur with limited federal regulatory intervention.
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TABLE OF CONTENTS
DISCLAIMER ................................................................................................................................... iii
ABSTRACT ...................................................................................................................................... iii
TABLE OF CONTENTS ...................................................................................................................... iv
EXECUTIVE SUMMARY .....................................................................................................................1
EXPERIMENTAL METHODS ..............................................................................................................4
RESULTS AND DISCUSSIONS ............................................................................................................5
PART 1: OVERVIEW ............................................................................................................... 5
PART 2: BACKGROUND .......................................................................................................... 6
I. Carbon Capture ........................................................................................................... 7
II. Geologic Storage .......................................................................................................... 8
A. Depleted Oil and Gas Fields ...................................................................................... 9
B. Deep Saline Formations ..........................................................................................10
C. Coal-beds ...............................................................................................................11
III. Transportation ...........................................................................................................14
PART 3: ANALYSIS ................................................................................................................14
I. Existing Physical and Regulatory Infrastructure in the U.S. ...........................................14
A. Existing CO2 Pipeline Infrastructure in the U.S. .........................................................14
1. CO2 Pipeline Basics ..........................................................................................14
2. Costs of CO2 Pipeline Construction ..................................................................16
3. CO2 Quality Specifications for Pipeline Transportation ..................................18
4. Pricing for CO2 .................................................................................................22
5. Safety Regulation of Carbon Dioxide Pipelines in the U.S. ..............................24
B. Existing Regulatory Infrastructure for CO2 Pipelines in the U.S. .................................26
1. Regulatory Status under the ICA and the NGA. ................................................27
2. Jurisdiction under Mineral Leasing Act of 1920. .............................................28
3. CO2 Pipeline Regulation under State Law........................................................29
C. CO2: Commodity or Pollutant – Resource Management – A New Paradigm ................32
D. Future Pipeline Build-out Scenarios .........................................................................34
II. Prospective Business Models and State and Federal Regulatory Options .......................37
A. Leading Potential Business Models for CO2 Pipeline Build-out in the U.S. ...................37
1. Intrastate Dedicated Pipeline Model Description and Examples ...................38
2. Intrastate Open Access Model .........................................................................38
3. Interstate Dedicated Pipeline Model ..............................................................39
4. Interstate Open Access Model .........................................................................40
5. Government/Public Option Model ..................................................................41
C. The Potential Regulatory Systems State and Federal .................................................43 Interstate Oil & Gas Compact Commission: A Policy, Legal, and Regulatory Evaluat ion of the
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1. Status Quo .......................................................................................................43
2. Possible Future Regulatory Scenarios ............................................................44
3. The Impact of Possible Regulatory Scenarios on Possible Business Models ................52
III. Economic Issues .........................................................................................................54
A. Financing ...............................................................................................................54
B. Infrastructure Costs ................................................................................................56
C. Cost Forecasting of CO2 Pipelines .............................................................................59
D. Cost Factors ............................................................................................................60
2. Regulatory Compliance Cost Issues .............................................................61
E. Commercial Transactions ........................................................................................65
1. Purchase and Off-take Agreements .................................................................65
PART 4: CONCLUSIONS AND RECOMMENDATIONS ........................................................................ 67
I. The Market .................................................................................................................67
II. Climate Change - a Federal Response ...........................................................................68
III. Recommendations ......................................................................................................68
A. General...................................................................................................................68
B. State Recommendations ..........................................................................................69
C. Federal Recommendations ......................................................................................69
GLOSSARY ..................................................................................................................................... 71
GRAPHICAL MATERIALS LIST......................................................................................................... 74
REFERENCES ................................................................................................................................. 74
BIBLIOGRAPHY .............................................................................................................................. 82
LIST OF ACRONYMS AND ABBREVIATIONS .................................................................................... 82
APPENDICES .................................................................................................................................. 84
Appendix I: Table of United States High Pressure CO2 Pipelines by State .................................... 85
Appendix II: Inventory of IOGCC Member State Statutory and Regulatory Laws ......................... 89
Appendix III: Regulatory Infrastructure and Physical Requirements for Canadian CO2 Pipelines....................................................................................................................................................... 94
Appendix IV: Participants in IOGCC/SSEB Pipeline Transportation Task Force .......................... 97
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EXECUTIVE SUMMARY
Carbon capture and storage (CCS) is receiving considerable attention in government, academia, and the media. However, the economic reality of the capital commitments necessary to move from research and development to large-scale deployment is a challenge of enormous proportions.
Use of carbon dioxide (CO2) for enhanced oil recovery (EOR) remains the primary driver for CCS deployment. However, national carbon control policies on the horizon could lead to expanded deployment of CCS in the near future. If CCS continues to evolve, a national CO2 pipeline infrastructure of sufficient scope and capacity will be needed to handle the expected volumes. Accordingly, the Pipeline Transportation Task Force (PTTF) of the Interstate Oil and Gas Compact Commission-Southern States Energy Board (IOGCC-SSEB) evaluated the regulatory status and current level of development of CO2 pipelines, as well as the policies that would encourage rational build-out of a future CO2 pipeline system in the U.S.
The U.S. has developed a model for geologic storage in the Permian Basin area that effectively stores CO2 while producing additional domestic oil through CO2-driven EOR. While CO2-driven EOR is not focused on carbon storage, the result is large volumetric storage of CO2 at a regionally significant scale (currently up to 35 million tons per year).
The potential for oil recovery from large reservoirs in the southwest drove the industry to find a way to connect sources of CO2 with sinks or reservoirs that could benefit from CO2-driven EOR. This was accomplished using a private capital model with relatively small incentives from federal and state governments. Oil revenues provided the cash flow and debt collateral. This private sector response has been replicated throughout much of the U.S. with minimal oversight from the federal government, leaving most of the regulatory responsibility to the states. Natural CO2 fields were expensive to develop, but less expensive than the investment required for CO2 captured from coal-fired power plants or industrial sources. If federal carbon reductions are imposed the scale of CO2 infrastructure in the southwestern United States, although large, will pale in comparison with envisioned U.S. CCS infrastructure.
One problem with deploying many large carbon capture projects is the proximity of storage capacity. Many plants are not located near low-risk, high-volume sinks, and not all capture technologies can be moved to areas with large storage capacities. Thus, a national CO2 pipeline transportation network is necessary.
This report contains an evaluation of several models showing that the private sector model has responded well to market demands. Approximately 4,000 miles of CO2 pipelines have been constructed in the U.S. These pipelines have been built through a variety of business models (open access, dedicated access, interstate, and intrastate) but each follows a private sector model, with limited government involvement from either a regulatory or financial standpoint. States have dominated the regulatory model, by providing siting, construction, and operating regulations and some economic regulation on a state-by-state basis. The Federal Government regulates safety parameters of CO2 pipelines and right of way provisions where the pipelines traverse federal lands. The IOGCC / SSEB Pipeline Transportation Task Force believes the model that will most likely result in a robust CO2 pipeline system in the U.S. is a Interstate Oil & Gas Compact Commission: A Policy, Legal, and Regulatory Evaluat ion of the
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private sector model, with a state-based regulatory framework, rather than a federally dominated or expanded regulatory role. While the PTTF believes that the current level of federal regulatory oversight is sufficient, members recommend a federal role that includes incentives to encourage the private construction of CO2 pipelines.
The economics of CO2 pipeline construction have been driven by the private sector market demand primarily in response to EOR activities. EOR sinks can serve as significant anchors for future CO2 pipeline construction to mitigate the costs of transporting CO2 long distances from sources that would not otherwise have an available sink because of distance and cost of transportation. A federal mandate that requires carbon capture will not change CO2 pipeline distances, the costs of transportation, location of sinks, CO2 sources, and the potential adverse reactions from population centers. These factors must be considered when evaluating carbon capture mandates, their efficacy and the significant challenges of capturing and transporting enormous quantities of CO2 across the U.S.
In the report’s final section, the economic factors underpinning CO2 pipelines are examined. The report outlines the tools used to finance CO2 pipelines but questions whether the financial markets are interested in or capable of financing a national CO2 pipeline network.
All aspects of the physical infrastructure costs of developing a CO2 pipeline network are examined. Categories include capital and material costs, land acquisition costs, and operational and maintenance costs. The PTTF members also examine cost saving options such as cost recovery for pipeline infrastructure in regulated utility markets and various state and federal economic incentives (e.g., income and property tax incentives, grants, loans, etc.) that offset the costs of pipeline infrastructure.
To date, the states have enabled a market-based, robust system to transport CO2 for use in EOR. Build-out of an extensive pipeline system to accommodate CO2 transport from several hundred coal plants most likely will occur over an extended period of time. State solutions and interstate compacts are expected to offer the support necessary for those installations. However, there may be scenarios in which federal agencies could play a more significant role in the development of the pipeline infrastructure. An aggressive, short lead-time program that requires CO2 to be disposed of also could require further federal participation. If a large number of power plants and other sources are required to sequester CO2, adequate storage sites might require long distance pipelines that cross state lines, which could necessitate a mix of state and federal activity to address those challenges.
The conclusions and recommendations at the end of the report serve to reinforce the finding that the current level of regulatory oversight is appropriate and no additional federal regulation is required. To the degree there is a place for expanded regulation of CO2 pipelines, such regulation must preserve the contractual basis of CO2 transport and avoid marginalizing states and their involvement. Specifically, the report finds and recommends the following:
General Conclusions
 The current pipeline infrastructure was sited, constructed, and regulated by the states in which they operate with federal oversight limited to safety regulations or instances where federal lands are traversed. Today, no federal involvement is required to facilitate the development of CO2 pipelines. Interstate Oil & Gas Compact Commission: A Policy, Legal, and Regulatory Evaluat ion of the
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 Growth is occurring in CO2 -driven EOR through the use of anthropogenic, or man-made, CO2 along with the pipeline infrastructure necessary to meet that demand.
 Non-EOR CO2 storage and transportation opportunities can be delayed until they are economically or politically mandated. Should such a mandate occur, sufficient public resources must be allocated to build the infrastructure necessary and mitigate the economic disconnects and impacts that are likely to occur.
 Care must be taken to ensure that a pipeline transporting CO2 for storage only purposes is not viewed less favorably by the public than pipelines transporting CO2 for EOR.
State Recommendations
 State-based regulatory solutions for CO2 pipelines should be carefully considered before pursuit of additional federal regulation. Any policy decision should avoid a one-size-fits-all approach and promote flexibility and innovation in response to market conditions.
 States should implement statutes and regulations to approve, site, construct, and manage CO2 pipelines to meet EOR demands or in response to a federal mandate.
 States should consider creating separate pipeline authorities to foster pipeline build-out. In lieu of additional federal regulation, states should consider multi-state agreements as a way to regulate a national CO2 pipeline network.
 Because of their existing experience with CO2 -driven EOR, states should quantify and distribute information relating to jobs and public revenue resulting from CO2 pipelines.
Federal Recommendations
 Federal policy should retain the status quo and allow the private sector to respond to market demands as currently demonstrated.
 If the federal role is expanded (in approval, siting, or economic regulation), the federal model should closely follow the natural gas model.
 Federal policy should encourage private sector build-out for CO2 –driven EOR through incentives and other forms of non-regulatory support.
The PTTF hopes these recommendations will facilitate development of a national pipeline infrastructure with rational regulatory oversight that is responsive to both market forces and national carbon management policies.
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EXPERIMENTAL METHODS
The data for this study were gathered through informal surveys, letters, personal interviews, site visits, and published reports. Sources include government officials, regulatory agency employees, private oil and gas company owners and employees, oil and gas service-industry owners and employees, academics, trade publications, and government documents. Necessarily, much of the information is anecdotal and somewhat subjective. Statistics cited are identified by source. Estimates are based on published statistical evidence with the methodology and source identified.
In many instances, the actions of a particular state, or several states, are cited as examples of approaches to challenges faced by oil and gas development. It should be noted that in most of these cases, other oil- and gas-producing states are using similar approaches; the cited examples are deemed to be the most representative or inclusive.
The Interstate Oil and Gas Compact Commission (IOGCC) / Southern States Energy Board (SSEB) Pipeline Transportation Task Force (PTTF) was formed in April 2009 for the purposes of examining the legal and regulatory environment surrounding CO2 pipelines and transport. This working group led and directed the research, analysis, and conclusions contained in this report utilizing IOGCC’s collaborative work group model.
Task force members represent diverse interests and regions --- from state oil and gas lawyers, to regulatory authorities, scientists, and industry representatives --- and are charged with creating comprehensive guidance documents that encompass all management aspects involving the transport of CO2, including regulatory, legal, economic, environmental, and educational issues. The task force includes the member states of both the IOGCC and the SSEB, thus facilitating broad-based input to the study. A full roster of task force participants can be found in Appendix IV.
IOGCC Collaborative Work Groups
In its 75-year history, the IOGCC has perfected a consensus-building model for development and review of statutory and regulatory guidance documents. Collaborative work groups --- comprised of state oil and gas lawyers, regulatory authorities, content-area experts, industry representatives, and other stakeholders --- are facilitated by the IOGCC project management team and contracted content-area experts. This collaborative process leverages the combined experience and expertise of oil and gas community members to create comprehensive guidance documents that encompass all management aspects, including regulatory, legal, economic, environmental, and educational issues.
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RESULTS AND DISCUSSIONS
PART 1: OVERVIEW
This report is produced by the Carbon Dioxide (CO2) PTTF. The PTTF was initiated and administered by the IOGCC and the SSEB.
The PTTF was formed in April with a project kickoff meeting in Anchorage, Alaska, that brought together a diverse group of experts representing states, provinces, industry, and a number of federal government departments and agencies. A list of participants, including observers and industry advisory council members,1 is attached in Appendix IV. In addition to the kickoff meeting in Alaska, the PTTF held a project mid-point meeting in Biloxi, Mississippi, in October 2009 and a project wrap-up meeting in Lexington, Kentucky, in May 2010.
The IOGCC and the SSEB bring to this project more than 14 years of experience working on various aspects of Carbon Capture and Geologic Storage (CCGS). Their focus in this report turns to the subject of the transportation of CO2, linking the product created in the “Carbon Capture” phase with the geologic storage sites necessary for the “Geologic Storage” phase of CCGS.
The IOGCC began its involvement with CCGS, or Carbon Capture and Storage (CCS), as it is more commonly known, in July of 2002 when it convened --- with the support of the U.S. Department of Energy (DOE) and its National Energy Technology Laboratory (NETL) --- a meeting of state oil and natural gas regulators and state geologists in Alta, Utah. As a result of the conclusions reached at that meeting, the IOGCC formed its “Geological CO2 Sequestration Task Force” that in early 2005 produced a report that examined the technical, policy, and regulatory issues related to the safe and effective storage of CO2 in subsurface geological media (oil and natural gas fields, coal seams, and deep saline formations) for both enhanced hydrocarbon recovery and long-term CO2 storage. This report came to be known as the “Phase I” Report2. Following this “scoping” report, the IOGCC set to work with its task force, which it renamed the “Carbon Capture and Geologic Storage Task Force”, to produce A Legal and Regulatory Guide for States and Provinces3. The most significant component of the guide, which was released in September of 2007, was a Model CO2 Storage Statute and Model Rules and Regulations governing the storage of CO2 in geologic media and an explanation of those regulatory components.
1 Participants from the federal government, environmental organizations and from CO2 pipeline companies are “observers” only, and while offering insight and perspective, do not join in final deliberations and should not be associated with any findings or recommendations made by the task force. The CO2 pipeline companies participate through an “Industry Advisory Board” created by the PTTF.
2 Interstate Oil & Gas Compact Commission CCGS Task Force, A Regulatory Framework for Carbon Capture and Geological Storage (2005), available at http://groundwork.iogcc.org/topics-index/carbon-sequestration/executive-white-papers/ccgs-task-force-phase-i-final-report-2005 .
3 Interstate Oil & Gas Compact Commission CCGS Task Force, CO2 Storage: A Legal and Regulatory Guide for States (2007), available at http://groundwork.iogcc.org/topics-index/carbon-sequestration/executive-white-papers/co2-storage-a-legal-and-regulatory-guide-fo. Interstate Oil & Gas Compact Commission: A Policy, Legal, and Regulatory Evaluat ion of the
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The SSEB also began its involvement with CCGS in 2002 with establishment of a Carbon Management Program to help define the role for clean coal in a carbon-constrained world. The following year, SSEB began managing the Southeast Regional Carbon Sequestration Partnership (SECARB), one of seven regional partnerships nationwide co-funded by DOE NETL and partners within each region. Since its inception, the SECARB partnership has grown to encompass 13 states and includes a network of more than 100 stakeholders. In three phases, SECARB has focused on 1) identifying and characterizing the most promising options for technology deployment and geologic CO2 storage in the Southeast; 2) demonstrating, through small-scale field testing, the viability of geologic storage technologies and the options most prominent in the region; and 3) developing large, commercial-scale projects that validate multiple monitoring, verification, and accounting protocols and tools and that integrate CO2 capture from a coal-fired generating facility with CO2 transportation via pipeline and geologic storage in a deep saline formation. In conjunction with this activity, SSEB maintains a productive partnership with the U.S. DOE’s Office of Coal and Power and the Office of Clean Coal and Energy Collaboration through which SSEB provides leadership in international efforts such as in the 24-member Carbon Sequestration Leadership Forum.
The focus of the this report is on the transportation of CO2, with an emphasis on the policy, legal, and regulatory aspects of development of the pipeline infrastructure necessary to move CO2 “captured” from a “source” to a “sink” for storage underground. It is the intention of both organizations and the PTTF that the report serve as a “scoping paper” that informs states and the federal government, as well as CCGS stakeholders, on a broad range of issues likely to be encountered by governments and industry in the building of a transportation infrastructure that enables timely CCGS development. The PTTF considered likely business models for pipeline construction and how they would be affected and influenced by differing potential state and/or federal regulatory frameworks. Included are some tentative conclusions related to which of the various potential scenarios will be most likely to remove barriers and facilitate the timely deployment of CO2 pipelines.
The work of the IOGCC-SSEB Task Force is funded by DOE and NETL through a cooperative agreement with the SSEB in support of the Southeast Carbon Sequestration Partnership Phase II program. The task force gratefully acknowledges the support of DOE and NETL. It also acknowledges the critical support of the states and provinces and other entities that so generously contribute their employees’ time to this project. Deep appreciation is also expressed to task force members. Without their dedicated participation, this effort would not be possible. The assistance of task force Chairman Robert Harms of North Dakota as well as Working/Writing Subgroup Chairs John Harju of North Dakota and Michael Moore of Texas are also gratefully acknowledged.
PART 2: BACKGROUND
Carbon capture and geologic storage is one of the four most commonly discussed and viable means of reducing the emissions of anthropogenic4 greenhouse gases5 to the earth’s atmosphere. Carbon
4 Anthropogenic is defined in this context as “of, relating to, or influenced by the impact of man on nature.” Webster’s New Collegiate Dictionary (1st ed. 1975). Interstate Oil & Gas Compact Commission: A Policy, Legal, and Regulatory Evaluat ion of the
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capture and geological storage is accomplished by first capturing CO2 and then pressurizing and transporting it to where the CO2 can be stored in geologic formations by means of underground injection (instead of being released into the atmosphere). Other means to mitigate carbon emissions include: 1) energy conservation and energy efficiency; 2) the use of technologies involving renewable energy, nuclear power, hydrogen, or fossil fuels containing lower carbon content (e.g., natural gas); and 3) the indirect capture of CO2 after its release into the atmosphere utilizing subseabed or terrestrial sequestration (e.g., reforestation, agricultural practices, etc.).
The focus of this report is the transportation of CO2, that essential link between the product created in the “Carbon Capture” phase and the geologic storage sites necessary for the “Geologic Storage” phase of CCS. Arguably the task force should be talking not about CCS but about CCTS (Carbon Capture, Transportation, and Storage), because transportation is so important to the viability of CCS. Therefore, a useful starting point in a discussion of transportation is a brief explanation of both the “Carbon Capture” and “Geologic Storage” bookends.
I. Carbon Capture
One of many challenges of working with anthropogenic CO2 is its small percentage of the atmosphere and combustion emissions. Total CO2 is less than 4/100 of one percent of the atmosphere by volume6. Of that, naturally occurring CO2 accounts for about 96.7% and man-made about 3.3%. The total is so small that direct removal from the atmosphere is not practical. Even in power plant flue gas emissions, CO2 accounts for only 7% to 15% of the flue gas emissions.
Before CO2 from an anthropogenic source can be transported via pipeline, it must first be captured and compressed. 7 CO2 capture as an emissions reduction strategy is suitable only for large point sources, (e.g., power generators and large industrial sources).8 Most attention regarding capture technologies has focused on power plants, but capture technologies are already being extensively used in natural gas plants and can also be applied to large, energy-intensive CO2 emitting industries, including cement manufacture, oil and natural gas refining, ammonia production, ethanol production and iron and steel manufacture.9
5 The major components of greenhouse gases are carbon dioxide (CO2), methane (CH4), nitrous oxide (N2O), chlorofluorocarbons (CFCs), and ozone (O3). These gases account for about 0.04 percent of the atmosphere. They are referred to as “greenhouse gases” because they effectively capture radiation from sunlight in that they prevent radiant heat from reflecting back into space.
6 Nat’l Oceanic & Atmospheric Admin., Trends in Atmospheric Carbon Dioxide, available at: http://www.esrl.noaa.gov/gmd/ccgg/trends/.
7 Intergovernmental Panel on Climate Change, Special Report on Carbon Dioxide Capture and Storage, (Bert Metz et al. eds., 2005).
8 Id.
9 Global Climate Change and U.S. Law 708 (Michael B. Gerrard ed., 2007). Interstate Oil & Gas Compact Commission: A Policy, Legal, and Regulatory Evaluat ion of the
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CO2 capture technologies have long been used by industry to remove unwanted CO2 from gas streams or to separate CO2 as a product gas. But, for hydrocarbon combustion processes there currently are only three primary methods for capture: post-combustion, pre-combustion and oxy-fuel. Post-combustion involves scrubbing the CO2 out of flue gases or natural gas streams. Oxy-fuel involves combusting fuel in recycled flue gas enriched with oxygen to produce a CO2-rich gas. Pre-combustion uses a gasification process followed by CO2 separation to yield a hydrogen fuel gas. Of these methods, post-combustion CO2 capture using solvent scrubbing is one of the more established. There are several facilities at which amine solvents are used to capture significant flows of CO2 from flue gas streams.10
Both pre- and post-combustion systems are capable of capturing 80% to 90% of CO2 emissions from power plants. In addition to the capital and operating costs of scrubbing, a power plant equipped with CCS would need roughly 10% to 40% more energy and is therefore more costly than a plant of equivalent output without CCS.11
II. Geologic Storage
Once captured, CO2 can be injected into deep underground formations below the earth’s surface. Rather than being released into the atmosphere, CO2 can be stored 12 permanently in underground geological formations. Natural CO2 traps exist in many places around the globe. It is important to realize that geologic storage is not a new technology but merely an application of technologies developed over decades in the injection and storage of both natural gas and acid gas,13 and the injection of natural CO2 for purposes of enhanced oil recovery (EOR). Similarly, the regulation of CO2 geological storage by the states builds upon the extensive experience of the states in regulating the injection and storage of natural gas and CO2-driven EOR. Although the scale of CO2 geological storage projects will be much larger than the analogues set forth above, the technology is fundamentally the same.14 Ultimately, this technology holds promise of storing between 1.2 trillion to 3.6 trillion metric tons, the equivalent of hundreds of years, of CO2 captured from industrial sources.15
10 Tom Kerr & Brendan Beck, Technology Roadmaps: Carbon Capture and Storage (October 2009).
11 Supra note 7 at 4.
12 The term “storage” rather than sequestration will be used in this report, however the terms in this context are largely synonymous.
13 Acid gas is a combination of hydrogen sulfide (H2S) and CO2.
14 This is discussed in much greater detail in previous IOGCC publications. See Interstate Oil and Gas Compact Commission, Task Force on CO2 Geologic Sequestration, A Regulatory Framework for Carbon Capture and Geological Storage (2005), [hereinafter IOGCC Phase I Report], and Interstate Oil and Gas Compact Commission, Task Force on Carbon Capture and Geological Storage, Storage of Carbon Dioxide in Geologic Structures: A Legal and Regulatory Guide for States and Provinces (2007), [hereinafter IOGCC Phase II Report].
15 Congressional Budget Office, The Potential for Carbon Sequestration in the United States (September 2007), available at http://www.cbo.gov/ftpdocs/86xx/doc8624/09-12-CarbonSequestration.pdf. Interstate Oil & Gas Compact Commission: A Policy, Legal, and Regulatory Evaluat ion of the
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There are three primary options for the geologic storage of CO2:
1) Storage in depleted oil and natural gas reservoirs;
2) Storage in deep saline formations;
3) Adsorption within coal-beds that are un-minable because of depth, thickness, or other economic factors. 16
Additionally, there is the possibility of storage in organic shales, fractured basalts, and hydrates, although those will not be addressed here.17
The primary geological storage options involve injection of CO2 through wells into the receiving formations or coal layers. Figure 1 illustrates the geologic options for underground injection of CO2. There are advantages to injecting into deeper formations (deeper than 2,500 feet), because the CO2 can be emplaced in a supercritical state under pressures exceeding 1,200 pounds per square inch (psi). Supercritical CO2 occupies less pore space for a given quantity of CO2 thereby maximizing the reservoir capacity for storage.
Many regions of the United States offer one or more of these geologic options, the most common of which are discussed below.
A. Depleted Oil and Gas Fields
Depleted oil and natural gas fields offer geologic traps that represent a substantial reservoir capacity available for storage of CO2. Where these reservoirs are below 2,500 feet, they offer tremendous pore volume space for supercritical CO2 injection and storage. These geologic traps by their very nature, having confined accumulations of oil and natural gas over millions of years, have proven their ability to contain fluids and gas. Additionally, if storage pressures of CO2 stay below original reservoir pressures, fluid containment is assured if leakage from wellbore penetrations can be avoided.
16 See IOGCC Phase I Report, supra note 14.
17 Nat’l Energy Tech. Laboratory, Carbon Sequestration FAQ Information Portal, available at: http://www.netl.doe.gov/technologies/carbon_seq/FAQs/carbon-seq.html Interstate Oil & Gas Compact Commission: A Policy, Legal, and Regulatory Evaluat ion of the
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Figure 1. Potential CO2 Sequestration Reservoirs and Products.
Red lines indicate CO2 being pumped into the reservoirs for sequestration, green lines indicate enhanced recovery of fossil fuels caused by CO2 sequestration, and the blue line indicates conventional recovery of fossil fuels. The offshore natural gas production (blue line) and CO2 sequestration scenario is currently occurring off the coast of Norway at the Sleipner complex operated by Statoil. There, the gas produced is a mixture of CO2 and methane. The CO2 is removed and injected into a nearby saline aquifer.18
With many depleted oil and natural gas fields there is also huge potential for EOR at the same time that CO2 is stored in these formations using anthropogenic sources of CO2.19 Injection of CO2 for EOR has been in practice for the past three decades, most widely in the Permian Basin of west Texas and southeast New Mexico. It is important to note that during EOR operations, CO2 produced with the oil is not released into the atmosphere but is captured, separated and recycled back into the reservoir to recover additional oil. While the majority of CO2 currently utilized for EOR in the U.S. comes from naturally occurring CO2 source fields, as anthropogenic sources of CO2 become more available, there is a significant opportunity for storage at the same time that additional oil resources are produced.
B. Deep Saline Formations
The option offering the greatest potential storage volume among the geologic possibilities nationwide is the injection of CO2 into saline formations significantly below underground sources of drinking water. Access to saline aquifers often occurs close to existing CO2 emission sources, such as coal-fired power plants. The water in some of these formations, for example in the depth range of 4,000 to 5,000 feet in the Illinois Basin, has many times the salinity of sea water and hence is not usable as a potable resource. Research shows that injection of CO2 into these deeper saline formations could be contained through
18 U.S. Geological Survey Fact Sheet 26-03, March 2003 - Online Version 1.0, available at: http://pubs.usgs.gov/fs/fs026-03/fs026-03.html.
19 U.S. Department of Energy, Enhanced Oil Recovery/ CO2 Injection, available at http://www.fossil.energy.gov/programs/oilgas/eor/index.html. Interstate Oil & Gas Compact Commission: A Policy, Legal, and Regulatory Evaluat ion of the
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solubility trapping (CO2 dissolution in formation waters), structural trapping (formation of a secondary gas cap within formation boundaries), or through mineral trapping (carbonate precipitation). 20
C. Coal-beds
Coal-beds or unmineable coal seams provide a potential geologic storage option for CO2 through adsorption. Methane is chemically adsorbed on coal-beds to varying extents depending on coal character (maceral type, ash content, etc.), depth, basin burial history, and other factors and has been produced to an ever greater extent over the last decade to add to the nation’s natural gas supply. The expectation is that the adsorption sites on the coal matrix surface have stronger affinity for the CO2 than the methane and would retain CO2 and liberate producible methane. This is frequently referred to as enhanced coal-bed methane (ECBM). Coals deemed economically unmineable due to depth, limited thickness, or other factors would be the only coals potentially suitable for storage.
Commercial storing of CO2 in geologic formations as an incident of oil production has occurred for nearly 40 years. CO2 supplies to this industry have been separated and captured from natural gas processing plants, produced from high-quality naturally-occurring underground formations, captured from a coal-to-gas manufacturing facility, and captured from a few other industrial facilities. Estimates of the injected quantities over the last four decades are in the hundreds of millions of metric tons. There have been only limited amounts of CO2 injected into other types of geologic formations, however. Accordingly, since 2003 the U.S. Department of Energy through its Regional Carbon Sequestration Partnership (RCSP) Program has been actively engaged in CCS research and development in different locations around the country.21 The most recent phase of the partnership program will involve “the injection of 1 million tons or more of CO2 by each RCSP into regionally significant geologic formations of different depositional environments” so as to “demonstrate that CO2 storage sites have the potential to store regional CO2 emissions safely, permanently, and economically for hundreds of years.”22 This program will lay the foundation for the deployment of commercial scale CCS projects as early as 2020.23
Regional Carbon Sequestration Partnerships (RCSPs)
20 Thomas, David C. and Sally M. Benson, editors, Carbon Dioxide Capture for Storage in Deep Geologic Formations Results from the CO2 Capture Project: Capture and Separation of Carbon Dioxide from Combustion Sources, Vol. 1 (2005) pg. 793-795; see also Sally M. Benson “Multi-Phase Flow and Trapping of CO2 in Saline Aquifers”. (Paper No. OTC 19244). Published in the Proceedings of 2008 Offshore Technology Conference held in Houston, Texas, USA, May 5–8, 2008.
21 U.S. Department of Energy, NETL, Carbon Sequestration: Regional Carbon Sequestration Partnerships, available at http://www.netl.doe.gov/technologies/carbon_seq/partnerships/partnerships.html.
22 U.S. Department of Energy, NETL, Carbon Sequestration: Regional Carbon Sequestration Partnerships – Development Phase, available at http://www.netl.doe.gov/technologies/carbon_seq/partnerships/development-phase.html.
23 U.S. Department of Energy, NETL, Technologies-Carbon Sequestration, available at http://www.netl.doe.gov/technologies/carbon_seq/index.html. Interstate Oil & Gas Compact Commission: A Policy, Legal, and Regulatory Evaluat ion of the
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Figure 2. US DOE NETL's Regional Carbon Sequestration Partnerships
The U.S. DOE NETL has formed a nationwide network of regional partnerships to help determine the best approaches for capturing and permanently storing gases that can contribute to global climate change. The Regional Carbon Sequestration Partnerships (RCSPs) are a government/ industry effort tasked with determining the most suitable technologies, regulations, and infrastructure needs for carbon capture, storage, and sequestration in different areas of the country. The seven partnerships that comprise the RCSPs represent more than 500 organizations in 40 states, three Indian nations, and four Canadian provinces.24
Big Sky Regional Carbon Sequestration Partnership (Big Sky)
Montana State University http://www.bigskyCO2.org/
Midwest Geological Sequestration Consortium (MGSC)
University of Illinois, Illinois State Geological Survey http://www.sequestration.org/
24 NETL: Regional Carbon Sequestration Partnerships. (n.d.). DOE - National Energy Technology Laboratory: Home Page. Retrieved July 28, 2010, from http://www.netl.doe.gov/technologies/carbon_seq/partnerships/partnerships.html. Interstate Oil & Gas Compact Commission: A Policy, Legal, and Regulatory Evaluat ion of the
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Midwest Regional Carbon Sequestration Partnership (MRCSP)
Battelle Memorial Institute http://www.mrcsp.org
Plains CO2 Reduction Partnership (PCOR)
University of North Dakota, Energy & Environmental Research Center http://www.undeerc.org/pcor/
Southeast Regional Carbon Sequestration Partnership (SECARB)
Southern States Energy Board http://www.secarbon.org/
Southwest Regional Partnership on Carbon Sequestration (SWP)
New Mexico Institute of Mining and Technology http://www.southwestcarbonpartnership.org/
West Coast Regional Carbon Sequestration Partnership (WESTCARB)
California Energy Commission http://www.westcarb.org/
A number of states are actively moving forward to develop laws and regulations that will govern the geologic storage of CO2, using as a base the model statute and rules created by the IOGCC in 2007.25 Wyoming, North Dakota, Louisiana, Texas, and Montana already have passed CO2 geologic storage statutes and have developed or are developing comprehensive rules. Numerous other states and provinces are moving forward to do the same.26 The U.S. Environmental Protection Agency (EPA) is also developing regulations under the Underground Injection Control (UIC) Program of the Safe Drinking Water Act (SDWA) covering the geological storage of CO2.27 The EPA rule development process is expected to be completed by 2011. The rule is also expected to authorize states to apply for and obtain primary enforcement responsibility, or primacy. State agencies that are granted primacy will oversee the injection activities under rules adopted in their states.28
25 IOGCC Phase II Report, supra note 14.
26 See Carbon Sequestration, http://groundwork.iogcc.org/topics-index/carbon-sequestration. This website contains up-to-date information on the status of state and provincial efforts to develop legal and regulatory frameworks for the geologic storage of CO2.
27 U.S. Environmental Protection Agency, Regulatory Development: Proposed rule for Federal Requirements under the UIC Program for Carbon Dioxide (CO2) Geologic Sequestration (GS) Wells, http://www.epa.gov//safewater/uic/wells_sequestration.html#regdevelopment.
28 Underground Injection Control Program, UIC Program Primacy, http://www.epa.gov/safewater/uic/primacy.html. Interstate Oil & Gas Compact Commission: A Policy, Legal, and Regulatory Evaluat ion of the
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III. Transportation
The focus of this report is on the policy, legal, and regulatory aspects of the transportation of CO2 -- that necessary connector of the capture and storage phases of CCS. The following analysis addresses the broad range of issues likely to be encountered by government and industry in the planning, financing, and construction of a transportation infrastructure that not only enables but encourages timely CCS development.
PART 3: ANALYSIS
The analysis that follows has four principal components.
The first component contains a snapshot of the existing physical and regulatory structure for CO2 pipelines in the U.S. as well as a discussion of certain other pertinent foundational issues such as CO2 commodity/pollutant discussion and potential CO2 pipeline build-out scenarios.
The second component examines: (1) the potential business models for pipeline construction and operation likely to emerge in the U.S.; (2) the state and federal regulatory systems that could conceivably develop to govern those business models; and (3) the impact that the prospective federal and state regulatory systems might have on the various business plans and development of the pipeline infrastructure -- intrastate, interstate and, international.
The third component addresses the economic aspects of the prospective regulatory frameworks.
The final section contains conclusions and recommendations of the task force to state and federal policy-makers as they contemplate development of laws and regulations governing CO2 pipelines.
I. Existing Physical and Regulatory Infrastructure in the U.S.
A. Existing CO2 Pipeline Infrastructure in the U.S.
1. CO2 Pipeline Basics
The existing CO2 pipeline infrastructure in the U.S. has evolved over nearly 40 years to support the injection of large quantities of CO2 for purposes of producing oil through EOR. There are more than 4,000 miles (see Table 3) of CO2 pipeline that connect a handful of major CO2 sources. The CO2 sources include naturally occurring geological formations, a few large natural gas processing plants, and one large coal-to-gas manufacturing facility, as shown on Figure 3.
According to a Massachusetts Institute of Technology (MIT) report,29 about 1.5 billion tons of CO2 are produced annually in the United States from coal-fired power plants. If all of this CO2 were to be transported for sequestration, the quantity would be equivalent to three times the weight and, under
29 Stephen Ansolabhere et al., The Future of Coal, (2007) *hereinafter “MIT Report”+. Interstate Oil & Gas Compact Commission: A Policy, Legal, and Regulatory Evaluat ion of the
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typical operating conditions, one-third the volume of natural gas transported annually by the U.S. natural gas pipeline system.30
A study prepared for the Interstate Natural Gas Association of America Foundation found that, depending upon the quantity of CO2 that must be stored and the degree to which EOR will be involved, the length of pipeline needed to transport CO2 will be in the range of 15,000 miles to 66,000 miles by 2030.31 These statistics highlight the scale-up challenge that faces the widespread deployment of carbon capture and storage.
CO2 pipelines are similar in many respects in design and operation to natural gas pipelines; however, because the CO2 is normally transported as a supercritical fluid,32 there are a number of significant differences. To maintain the product in its supercritical state, it is transported at pressures that range from 1,200 to 2,700 psi.33 These pressures are higher than the operating pressures used in most natural gas pipelines, which typically range from 200 to 1,500 psi.34 Booster stations along the pipeline route maintain the necessary pipeline pressure for CO2 pipelines.35 Because the supercritical CO2 behaves as a liquid in the pipeline, pumps, rather than compressors, are used at CO2 pipeline booster stations.36 The increased pressure in CO2 pipelines is typically accommodated with thicker-walled pipe than that used for natural gas transportation.37
30 Id.
31 ICF International, Developing a Pipeline Infrastructure for CO2 Capture and Storage: Issues and Challenges. (2009) [hereinafter ICF Report], available at: www.ingaa.org/File.aspx?id=8288.
32 CO2 becomes a supercritical fluid when it is compressed to approximately 1,200 psig at temperatures greater than 31.1 degrees Celsius. At this point, it assumes certain characteristics of both a gas and a liquid. Supercritical CO2 can be handled like a liquid but is more compressible than a typical liquid and retains the ability to diffuse through pores like a gas. The greater density and the ability to handle the product as a liquid, rather than as a gas, make the supercritical state more desirable for pipeline transmission.
33 The pipeline to the Weyburn site in Canada operates somewhat above these pressures, up to 2,964 psig. Myria Perry & Daren Eliason, CO2 Recovery and Sequestration at Dakota Gasification Company, Presented at the 19th Western Fuels Symposium in Billings, MT, Oct. 12-14, 2004 [hereinafter Perry and Eliason].
34 Naturalgas.org, Transportation of Natural Gas, www.naturalgas.org/naturalgas/transport.asp (last visited Dec. 2009). .
35 Naturalgas.org, Transportation of Natural Gas, www.naturalgas.org/naturalgas/transport.asp (last visited Dec. 2009).
36 ICF Report Supra Note 31.
37 Id. Interstate Oil & Gas Compact Commission: A Policy, Legal, and Regulatory Evaluat ion of the
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Table 1. Estimated CO2 Pipeline Design Capacity
Pipeline Diameter, in.
CO2 Flow Rate Lower Bound Upper Bound Mt/yr MMscfd Mt/yr MMscfd 4 0.19 10
6
0.19
10
0.54
28 8 0.54 28 1.13 59
12
1.13
59
3.25
169 16 3.25 169 6.86 357
20
6.86
357
12.26
639 24 12.26 639 19.69 1025
30
19.69
1025
35.16
1831 36 35.16 1831 56.46 2945
Pipeline diameters are calculated using rigorous iterative calculations38 but estimations correlating pipeline diameter and CO2 flow rates can be made. Table 1 shows such an estimation made by MIT.39
2. Costs of CO2 Pipeline Construction
The cost components of CO2 pipeline construction are analogous to those of natural gas pipelines with carbon steel being a major cost component. Because it can account for 15% to 35% of the total pipeline cost, the dramatic increase in carbon steel price over the last decade has resulted in higher pipeline costs, as shown in Table 2.
38 Rubin, E.S., Berkenpas, M.B., Frey, H.C., Chen, C., McCoy, S., and Zaremsky, C.J., 2007, Development and application of optimal design capability for coal gasification systems: Technical documentation for integrated gasification combined cycle systems (IGCC) with carbon capture and storage (CCS). Final Report of work performed for the U.S. Department of Energy under contract DE-AC21-92MC29094, Pittsburgh, Pennsylvania, Carnegie Mellon University, May 2007.
39 Carbon Capture and Sequestration Technologies Program, 2009, Carbon management GIS: CO2 pipeline transport cost estimation, Massachusetts Institute of Technology, Report for U.S. Department of Energy National Energy Technology Laboratory under contract DE-FC26-02NT41622. Interstate Oil & Gas Compact Commission: A Policy, Legal, and Regulatory Evaluat ion of the
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Figure 3. Existing or Planned CO2 Pipelines in the United States.40
40 Source: Steve Melzer, Melzer Consulting (2010) Interstate Oil & Gas Compact Commission: A Policy, Legal, and Regulatory Evaluat ion of the
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Table 2. CO2 Pipeline Capital Costs for Various Pipelines 41
Project
Year
Cost, $/in.
diameter-mile
Inflation adjusted
2009 dollars Dakota Gasification42 2000 37,300 46,500
Hall-Gurney (KS)43
2001
22,000
26,650 Regression Analysis of FERC Data44 2003 33,800 39,400
Coffeyville Resources45
2007, 2009
52,100–83,300
54,000 – 83,000 Oil and Gas Journal Average of Natural Gas Pipelines46 2008 65,100 64,900
Green Pipeline47
2009
93,750
3. CO2 Quality Specifications for Pipeline Transportation
Requirements for CO2 pipeline quality specifications are subjects of debate. To date, most existing compositional specifications appear only within private contracts between buyers and sellers. As a result, there is little publicly available information on the quality specifications of CO2 pipelines. However, uniform CO2 quality specifications may be useful to promote development of a national CO2 pipeline network. While imposing a national uniform quality specification on CO2 composition in pipelines can be expensive to a given plant in terms of both capital investments and operating costs, such uniform quality specifications may be necessary to promote a national CO2 pipeline infrastructure. Recognition today of what might be an appropriate national compositional specification would prove invaluable in the early stages of source and pipeline design.
Some early work48 attempted to group compositional specifications into three potential categories. The first type (Type I) would be for CO2 transported by point-to-point, single-use pipelines with a case-by-case compositional specification. This type of specification could be envisioned similar to most disposal pipelines in use today and could compositionally vary in dramatic fashion from pipeline to pipeline.
41 These costs were calculated using the information presented in the documents referenced in notes 15-32.
42 J.E. Sinor and Associates, Financial Future Brightens for Dakota Gasification, http://edj.net/sinor/sfr7-00art6.html (last visited Dec 2009).
43 G. Paul Willhite, Carbon Dioxide Flooding in Kansas Reservoirs, Presentation at the 14th Oil Recovery Conference, Wichita, Kansas, March 14–15, 2001.
44 Gemma Heddle, Howard Herzog, & Michael Klett, The Economics of CO2 Storage (2003).
45 Nat’l Energy Tech. Lab., NETL Carbon Sequestration Newsletter: Annual Index, September 2007 – August 2008 (2008); see also ICF Report, Supra note 31.
46 Oil and Gas Journal, Construction, Other Cost Increases Hit Home, Oil and Gas Journal v. 106, No. 33 (2008).
47 Gary Perilloux, Enhanced Oil Recovery Key to $720 million Deal, available at:www.2theadvocate,com/news/business/3875982.html.
48 Guidelines for Carbon Dioxide Capture, Transport, and Storage, Forbes, S., Verma, P.; Curry, Thomas, E., Friedmann, S. J., Wade, S.M., World Resources Institute Report , Oct 08, available at http://www.wri.org/publication/ccs-guidelines. Interstate Oil & Gas Compact Commission: A Policy, Legal, and Regulatory Evaluat ion of the
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Each permit would require a study of safety and operating procedures based upon the specific CO2 composition being transported. None of the existing CO2 pipelines fit this model.
The second type (Type II) could be referred to as the Uniform North American CO2 Pipeline Network Compositional Standard which would have restrictions designed to meet specified CO2 compositional requirements allowing compatibility with existing contracts between sources and sinks and, more importantly, allowing interconnections with future pipelines. The concept of multiple sources and sinks networked by interconnecting pipelines would provide pipeline “buffer” storage, increased reliability of source volumes, and injection capacity through the interconnection of multiple sources and sinks. Existing and future contracts between sources and sinks would need to reflect the “uniform” compositional standards. What may, at first glance, seem like an unachievable goal, in fact, generally reflects prevailing industry practice. All but a handful of the current pipelines fall within this category.
One of the most important factors is avoidance of nitrogen and methane concentrations that preclude dense phase operations. The most common specification is 5% of each, or, in aggregate, 10%. Higher concentrations of either nitrous oxide (N2O) or methane (CH4) raise minimum miscibility pressures to a level often unacceptable for EOR end use. Sulfur compounds, especially H2S, are carefully controlled for concerns with biologic exposure. Even low concentrations of H2S, for example, are hazardous to humans and wildlife, and those concerns require robust source, sink, and pipeline safety regimes.
Oxygen content also affects the quality of CO2 pipeline streams. High oxygen concentrations lead to microbial related corrosion of forged iron and steel. Oxygen also leads to chemical reactions and aerobic bacterial growth downhole either within the injection tubulars or in the geologic formation. As a result, the evolved specification has become an accepted concentration of less than 10 or 20 parts per million (ppm).
Water is another substance requiring critical control in CO2 streams. Corrosion is the key concern. Maximum specifications are often expressed in pounds (lbs) /million cubic feet (MMcf) or in ppm and are most commonly specified in the range of 20-30 lbs/ MMcf.
Type III composition standard would allow one or more quality specifications to vary. Varying specifications could be appropriate for small proprietary networks. Existing examples of this Type III approach are evident in the Dakota Gasification, Val Verde, Canyon Reef Carriers, and Zama pipelines. All four of these pipelines allow a higher level of hydrogen sulfide (H2S), and therefore cannot deliver the CO2 stream into a pipeline with more standard specifications without treating the CO2 stream to remove the excess H2S. These Type III pipelines serve a dual purpose -- transporting CO2 for EOR and economical disposal of H2S. Another example where a Type III compositional standard would be appropriate could be where higher nitrogen content is required to assist with injection into coal beds.
It is notable that both Type II and Type III pipeline operators have chosen to seek a dense phase state of CO2 (operating above 1,200 psi) for efficiency and end use purposes. Type I lines would not necessarily require dense state CO2 for transportation.
Table 3 lists the 47 major North American CO2 pipelines. There are others, however, these pipelines are high-pressure (exceeding 1,000 psi maximum allowable internal pressure) and of sufficient length (10 miles or greater) to warrant inclusion. It is worth noting that most of the pipelines included in Table 3 Interstate Oil & Gas Compact Commission: A Policy, Legal, and Regulatory Evaluat ion of the
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fall into the Type II category and allow interconnection. No example of a Type I pipeline exists at this time. Table 4 compares CO2 stream compositions for several different streams.
Table 3. The Major North American CO2 Pipelines49
PIPELINE
Owner/Operator
Length (mi)
Length (km)
Diameter (in)
Estimated Max Flow Capacity (MMcfpd)
Estimated Max Flow Capacity (million tons/yr)
Location Adair Apache 15 24 4 47 1.0 TX
Anton Irish
Oxy
40
64
8
77
1.6
TX Beaver Creek Devon 85 137 WY
Borger, TX to Camrick, OK
Chaparral Energy
86
138
4
47
1.0
TX, OK Bravo Oxy Permian 218 351 20 331 7.0 NM, TX
Centerline
Kinder Morgan
113
182
16
204
4.3
TX Central Basin Kinder Morgan 143 230 16 204 4.3 TX
Chaparral
Chaparral Energy
23
37
6
60
1.3
OK Choctaw (aka NEJD) Denbury Onshore, LLC 183 294 20 331 7.0 MS, LA
Comanche Creek (currently inactive)
PetroSource
120
193
6
60
1.3
TX Cordona Lake XTO 7 11 6 60 1.3 TX
Cortez
Kinder Morgan
502
808
30
1117
23.6
TX Delta Denbury Onshore, LLC 108 174 24 538 11.4 MS, LA
Dollarhide
Chevron
23
37
8
77
1.6
TX El Mar Kinder Morgan 35 56 6 60 1.3 TX
Enid-Purdy (Central Oklahoma)
Merit
117
188
8
77
1.6
OK Este I to Welch, TX ExxonMobil, et al 40 64 14 160 3.4 TX
Este II to Salt Creek Field
ExxonMobil
45
72
12
125
2.6
TX Ford Kinder Morgan 12 19 4 47 1.0 TX
Free State
Denbury Onshore, LLC
86
138
20
331
7.0
MS Green Line I Denbury Green Pipeline LLC 274 441 24 850 18.0 LA
Joffre Viking
Penn West Petroleum, Ltd
8
13
6
60
1.3
Alberta Llaro Trinity CO2 53 85 12-8 77 1.6 NM
Lost Soldier/Werrz
Merit
29
47
WY Mabee Lateral Chevron 18 29 10 98 2.1 TX
McElmo Creek
Kinder Morgan
40
64
8
77
1.6
CO, UT Means ExxonMobil 35 56 12 125 2.6 TX
Monell
Anadarko
8
77
1.6
WY North Ward Estes Whiting 26 42 12 125 2.6 TX
North Cowden
Oxy Permian
8
13
8
77
1.6
TX Pecos County Kinder Morgan 26 42 8 77 1.6 TX
Powder River Basin CO2 PL
Anadarko
125
201
16
204
4.3
WY Raven Ridge Chevron 160 257 16 204 4.3 WY, CO
Rosebud
Hess
NM Sheep Mountain Oxy Permian 408 656 24 538 11.4 TX
Shute Creek
ExxonMobil
30
48
30
1117
23.6
WY Slaughter Oxy Permian 35 56 12 125 2.6 TX
Sonat (reconditioned natural gas)
Denbury Onshore, LLC
50
80
18
150
3.2
MS
49 Melzer Consulting, Hattenbach, BlueSource (2010) Interstate Oil & Gas Compact Commission: A Policy, Legal, and Regulatory Evaluat ion of the
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TransPetco TransPetco 110 177 8 77 1.6 TX, OK
W. Texas
Trinity CO2
60
97
12-8
77
1.6
TX, NM Wellman PetroSource 26 42 6 60 1.3 TX
White Frost
Core Energy, LLC
11
18
6
60
1.3
MI Wyoming CO2 ExxonMobil 112 180 20-16 204 4.3 WY
Canyon Reef Carriers
Kinder Morgan
139
224
16
204
4.3
TX Dakota Gasification (Souris Valley) Dakota Gasification 204 328 14-12 125 2.6 ND, Sask
Pikes Peak
SandRidge
40
64
8
77
1.6
TX Val Verde SandRidge 83 134 10 98 2.1 TX
Totals:
4,111
6,611
*Tabulation does not include many shorter high pressure truck lines to individual fields
Table 4. CO2 Stream Compositions from Various Processes
Component
Kinder Morgan
CO2 Pipeline Specs50
Ethanol Plant51
Great Plains Synfuels Plant52
Gas
Processing Plant53
Coffeyville Resources Ammonia–UAN Fertilizer Plant54
Food-Grade
CO2 Specs55 CO2 ≥ 95 vol% > 98 vol% 96.8 vol% ≥ 96 vol% 99.32 vol% ≥ 99.9 vol%
Water
≤ 30 lb/MMcf
Dry
< 25 ppm
≤ 12 lb/MMcf
0.68 vol%
≤ 20 ppmw H2S ≤ 20 ppmw < 2 vol% ≤ 10 ppmw ≤ 0.1 ppmv
Total Sulfur
≤ 35 ppmw
40 ppmv
< 3 vol%
≤ 10 ppmw
≤ 0.1 ppmv N2 ≤ 4 vol% 0.9 vol% 0 ppm None
Hydrocarbons
≤ 5 vol%
2300 ppmv
1.3 vol%
≤ 4 vol%
CH4: ≤ 50 ppmw; others: ≤ 20 ppmw O2 ≤ 10 ppmw 0.3 vol% 0 ppm ≤ 10 ppmw ≤ 30 ppmw
Other
Glycol: ≤ 0.3 gal/MMcf
0.8 vol%
≤ 330 ppmw Temperature ≤ 120°F 120°F 100°F ≤ 100°F 100°F
50 Kinder Morgan, Quality Specifications of Sales Contract Between Resolute Natural Resources and Kinder Morgan, www.secinfo.com/dsvRu.u4Kg.6.htm#1stPage (last visited Dec 2009).
51 S.G. Chen, Y. Lu & M. Rostam-Abadi, Assessment of Geological Carbon Sequestration Options in the Illinois Basin: Task 2 – Assess Carbon Capture Options for Illinois Basin Carbon Dioxide Sources (2004).
52 Perry and Eliason, Supra note 33; see also Ray Hattenbach, Blue Source LLC, Personal Communication with Melanie Jensen, Energy & Environmental Research Center regarding pipeline specifications, November 2009 [hereinafter Hattenbach].
53 Keith Tracy, Carbon Pipeline Development: Presented at ACI Carbon Capture and Sequestration Summit, Washington, DC, September 14–15, 2009.
54 Dan Kubek, Large CO2 Sources & Capture Systems: Presented at Workshop on Future Large CO2 Compression Systems, Gaithersburg, Maryland, March 30, 2009, http://www.nist.gov/eeel/high_megawatt/upload/2_3-Kubek-Approved.pdf.
55 Logichem Process Engineering, http:www.logichemprocess.com/CO2%20Food%20Grade%20Specs.pdf. Interstate Oil & Gas Compact Commission: A Policy, Legal, and Regulatory Evaluat ion of the
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4. Pricing for CO2
Traditionally, the value for CO2 is based upon purity, pressure, and location of the CO2 stream. Markets for CO2 are primarily limited to food grade applications (e.g., beverages, cooling/freezing, solvent markets) and enhanced oil recovery.
In addition to CO2 for EOR and food grade applications, markets for commodity CO2 include the following uses:
1) As a raw material feedstock for some chemical processes, including the manufacture of methanol and nitrogen urea.
2) As a fire retardant agent in hand-held and larger-scale fire extinguishing systems.
3) To make dry ice.
4) For the treatment of alkaline water.56
Other uses of CO2 under development include:
1) To enhance natural gas recovery.
2) To enhance coal-bed methane recovery.
3) To enhance algae production to make biofuels.
4) To enhance agricultural plant growth with CO2.
5) To enhance oil shale and oil sands recovery.
6) Mineralization to produce aggregate products.
7) As a feedstock for various fuels.
8) As a feedstock to create chemical products.
Despite these current and planned uses of CO2 and the regional nature of existing EOR operations, the volumes utilized in EOR have accelerated in recent years and are now approximately 10 times the volumes used for food grade and other applications.57
56 Southern States Energy Board (SSEB). (2010). [Internal Report]. Unpublished data.
57 Id. Interstate Oil & Gas Compact Commission: A Policy, Legal, and Regulatory Evaluat ion of the
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Food grade compositional specifications are considerably more difficult to achieve than CO2 intended for EOR applications. Sulfur compounds impact the taste and smell of food and beverages, so strict controls are placed upon their presence. As mentioned earlier, dense phase, miscibility, and pipeline safety concerns drive the compositional standards for EOR applications so compositions can be more relaxed and thereby reflect in a lower unit cost of CO2 than for food grade applications.
The delivered price of CO2 from natural underground sources has been approximately $1.25/Mcf ($22/ton).58 For new contracts, a base price of $1.25 to $1.50/Mcf ($22 to $26/ton) is tied to $60 to $70/bbl oil; the CO2 price increases with the price of oil by a mutually agreed-upon formula.59 Modern contracts between buyers and sellers have tied CO2 prices directly to the price of oil, resulting in a somewhat higher price in recent contracts (to as much as $30/ton for $70/bbl oil prices).
By comparison, in mature EOR areas the cost to compress and transport for 50 miles the CO2 captured from high-purity (>95%) man-made sources such as natural gas-processing plants and hydrogen production plants is estimated to be $1.30 to $1.75/Mcf ($23 to $30/ton).60 The cost of compressing and transporting a similar amount of CO2 recovered from low-purity (<15%) sources a similar distance would range from an estimated $2.85 to $4.00/Mcf ($50 to $70/ton).61 Estimates reveal that the Great Plains Synfuels Plant sells its CO2 to Encana for about $19/ton ($1.10/Mcf).62
(a) Possible Risks of CO2 Pipeline Operation.
Pipeline transportation of CO2 is not without risk. However, these risks have not posed a threat to human health and safety. Risks include pipeline damage, corrosion, and leaks/blowouts. These are reasonably rare events. According to the National Response Center’s accident database, there were 12 accidents in 3,500 miles of CO2 pipelines between 1986 and 2008 and no human injuries or fatalities were reported for any of these accidents.63 By contrast, there were 5,610 accidents causing 107 fatalities and 520 injuries related to natural gas and hazardous liquid pipelines (a category that does not include CO2 pipelines)64 during the same period.65 Among the tools available to ensure safe operation of a pipeline are the inclusions of fracture arrestors approximately every 1,000 feet, block valves to isolate pipe sections that are leaking, the use of high durometer elastomer seals, and automatic control
58 Ron Wolk, Proceedings of the workshop on future large CO2 compression systems (2009).
59 Hattenbach, supra note 52.
60 Id.
61 Id.
62 Don Remson, CO2 Enhanced Oil Recovery Overview, National Energy Technology Laboratory presentation,(2008), available at: http://www.netl.doe.gov/energy-analyses/pubs/CO2_Presentation2.pdf.
63 Parfomak and Folger, infra note 138.
64 The Department of Transportation’s regulations definition of the term “hazardous liquid” (from 49 C.F.R. § 195.2) does not include carbon dioxide. See also discussion of regulatory background in n.65, infra.
65 Id. Interstate Oil & Gas Compact Commission: A Policy, Legal, and Regulatory Evaluat ion of the
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systems that monitor volumetric flow rates and pressure fluctuations.66 Other methods include aircraft and/or satellite monitoring of pipeline rights of way, implementation of periodic corrosion assessments, and internal cleaning and inspection using pipeline “pigs.” The use of specific safety and monitoring tools will vary depending on the location, size, and pressure of the pipeline.
The U.S. Department of Transportation (DOT) Office of Pipeline Safety (OPS) sets and enforces standards for the safe operation of CO2 pipelines. 67 Its definition of CO2 is “a fluid consisting of more than 90% carbon dioxide molecules compressed to a supercritical state.”68 CO2 is not considered a hazardous liquid by the regulation, which covers design, pipe, valves, fittings, flange connections, welding, breakout tanks, leak detection, inspection, pumps, compressors, etc. The siting of new CO2 pipelines is not regulated by any federal agency, but is subject to regulation by the states.
5. Safety Regulation of Carbon Dioxide Pipelines in the U.S.
The federal Pipeline Safety Reauthorization Act of 1988 included a provision to regulate the safety of CO2 pipelines.69 Pipelines that both “start and stop” within a state boundary are considered intrastate and would be regulated by the state authority if that authority has adopted regulations that are at least as stringent as the applicable federal safety regulations. Pipelines traversing more than one state are interstate pipelines and their safety is regulated by the Federal Pipeline and Hazardous Materials Safety Administration (PHMSA) within the DOT. PHMSA also would regulate those intrastate facilities within a state that has not adopted regulations as stringent as federal safety regulations.
In June 1991, the Research and Special Programs Administration of the DOT issued Docket PS-112 establishing safety regulations for transporting CO2 by pipeline in a supercritical state. The effective date for these safety regulations was July 12, 1992. CO2 is transported as a supercritical liquid at pressures exceeding 1,275 psig. This is done to transport larger volumes using smaller diameter pipelines.
These pipelines are regulated under 49 CFR Part 195, Transportation of Hazardous Liquids by Pipeline. DOT has not classified CO2 as a hazardous liquid, but as DOT explained in promulgating the rules, it retained the regulations governing CO2 pipelines within the section addressing such liquids “for administrative convenience.”70 The federal government chose to regulate the transportation of CO2 by
66 John Gale & John Davison, Transmission of CO2—Safety and Economic Considerations, Energy, v. 29, 1319–1328 (2004).
67 49 C.F.R. § 195 (1991).
68 Id.
69 Pipeline Safety Reauthorization Act of 1988 (P.L. 100-561, Oct. 31, 1988).
70 Some confusion has arisen from the fact that regulations applicable to CO2 pipelines are included under the heading entitled “Transportation of Hazardous Liquids by Pipeline.” 49 C.F.R. pt. 195. This led some commentators to assume, erroneously, that CO2 is a “hazardous liquid” under the regulations. This is not accurate. The Department of Transportation proposed safety regulations for CO2 pipelines in 1989 precisely because the regulations governing transportation of “hazardous liquids” did not apply to CO2. See Notice of Proposed Rulemaking, “Transportation of Carbon Dioxide by Pipeline”, 54 Fed. Reg. 41912 (October 12, 1989). Interstate Oil & Gas Compact Commission: A Policy, Legal, and Regulatory Evaluat ion of the
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pipeline under this set of rules due to the characteristics of the pipeline. As mentioned above, when CO2 is compressed under high pressure for transportation, it becomes a dense phase gas (or supercritical liquid) and flows in a manner analogous to liquids. Therefore, the liquids pipeline safety rules are applied to these pipelines rather than the natural gas safety rules. The regulations cover the large transmission pipelines and the production lines as they enter the field of production and any return lines to a plant for recycling. Once the production lines branch off to individual wells, they do not fall under the scope of the safety regulations.
There are nine states with CO2 pipelines of varying lengths within their boundaries. From information obtained from PHMSA, the following states report CO2 pipeline mileage data through annual reports and map data (ranked here in decreasing order in terms of miles of CO2 pipeline): Texas, New Mexico, Wyoming, Mississippi, Colorado, Oklahoma, North Dakota, Utah, and Louisiana.
There are 21 different companies operating a total of 3,637 miles of CO2 transmission pipelines (see Appendix I). Almost one-third (1,200) of the federally regulated interstate pipeline miles are located in Texas, followed by New Mexico with 966 miles. The lowest mileage is 75 in Louisiana. All of these pipelines are covered under the federal pipeline safety program and regulated under Part 195.
Pipeline safety regulations and operations in Texas reflect the coordination between federal and state authorities. Texas has nearly 1,700 miles of CO2 pipelines -- including interstate transmission, intrastate transmission, and production field distribution lines. Most of the CO2 is brought into Texas from New Mexico and Colorado where several key natural CO2 sources exist. The CO2 is primarily used in EOR projects. Tertiary EOR projects typically occur where CO2 is injected into underground formations to produce additional oil following primary and secondary recovery methods. There are approximately 183 authorized CO2 EOR projects active in Texas71.
All regulated Texas pipelines have a permit (Form T-4); issued by the Railroad Commission of Texas (RRC) that details the pipeline route. Pipeline permits and new construction reports can be viewed online at the RRC’s website under the licensing and permit tab.72 Only those pipelines regulated by the RRC’s Pipeline Safety Division are required to file new construction reports.
The term “hazardous liquid” is defined at 49 C.F.R. § 195.2, and does not include carbon dioxide. Commentators were concerned that including CO2 pipeline regulations under the section heading for "hazardous liquids” would lead to confusion. In response, the Office of Pipeline Safety said it had “no good reason to dispute” this notion, and indeed it agreed that carbon dioxide “should not be included in the definition of ‘hazardous liquids’”. Id. Nevertheless, the Department said it would not change the title heading “because it would result in an awkward title” Id. The distinction between carbon dioxide and hazardous liquids is maintained at 49 C.F.R. § 195.0 which essentially provides that “*t+his part prescribes safety standards and reporting requirements for pipeline facilities used in the transportation of hazardous liquids or carbon dioxide.” Id. (emphasis added) Although CO2 is listed as a Class 2.2 (non-flammable gas) hazardous material under DOE regulations (49 C.F.R. § 172.101), the agency applies nearly the same safety requirements to CO2 pipelines as it does to pipelines carrying hazardous liquids such as crude oil, gasoline, and anhydrous ammonia (49 C.F.R. § 195).
71 Victor Carrillo, Chairman, Railroad Commission of Texas
72 The licensing and permit tab can be found at: www.rrc.state.tx.us/licenses/index.php. Interstate Oil & Gas Compact Commission: A Policy, Legal, and Regulatory Evaluat ion of the
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The RRC has adopted the federal pipeline safety rules under Chapter 117 of the Texas Natural Resources Code. With regard to CO2, the RRC’s rules, for the most part, mirror the federal regulations. However, there are more stringent Texas regulations regarding cathodic protection and integrity management. If the pipeline contains more than 100 ppm of hydrogen sulfide, the permit to construct the pipeline must be approved at the Commission level rather than administratively by RRC staff. Many of the pipelines in west Texas contain large amounts of H2S and have been approved by the RRC and monitored for compliance with the RRC’s Rule 36 governing H2S safety regulations by the Oil & Gas Division. The Oil & Gas Division has field representatives designated as H2S experts to assist in the review and permitting of these pipelines and other production-related activities. Other states may have similar requirements for their intrastate pipelines.
There are 40 pipeline permits held by 19 different operators transporting CO2 in Texas. Of the 40 permits, 15 are listed as interstate and would be regulated by the federal PHMSA office in Houston. These interstate pipelines range in size from 8 to 24 inches. The remaining 25 permits are listed as intrastate and total 483 miles. The RRC regulates 314 of the intrastate miles under its state-specific pipeline safety program. The remaining 169 miles are considered part of the production process and are not included in the regulations set out in Part 195.
The RRC lists 22 pipeline systems in Texas. The Pipeline Safety Division conducts routine safety evaluations on these systems at least once every three years. The pipelines take CO2 that is brought into the state and delivers it to the fields that are using CO2 for EOR. Some of those fields include piping necessary to transport recovered CO2 within and between fields for further use.
One of the newer projects, the Denbury Green Pipeline Project, is a 24-inch pipeline from Donaldsonville, Louisiana, to the Hastings Field, south of Houston, Texas. The pipeline is being designed to transport both naturally occurring and anthropogenic CO2. Denbury plans to purchase anthropogenic CO2 from at least four plants; however, those plants have yet to be built. At this time, Denbury has filed the pipeline permit only for the portion located just inside the Texas border. The Green Pipeline is expected to be completed by late 2010.
The pipeline network feeding the Permian Basin is the most intensely developed CO2 pipeline network to date. The oldest pipeline is the Canyon Reef pipeline that has been in operation since the early 1970s.
B. Existing Regulatory Infrastructure for CO2 Pipelines in the U.S.
As stated earlier, CO2 pipelines are subject to safety regulations at the federal level and economic and other regulation at the state level. Safety regulation is assured by PHMSA within DOT and by state regulators applying standards that are at least as stringent as the federal standards.
As detailed below, economic regulation of the terms and conditions of service (including rates and conditions of access) of CO2 pipelines is subject to the states. At the federal level, CO2 pipelines are neither “common carriers” under the Interstate Commerce Act (ICA) administered by the Surface Transportation Board (STB), nor “natural gas companies” under the Natural Gas Act (NGA) administered by the Federal Energy Regulatory Commission (FERC). However, there may be a federal carriage obligation imposed in certain circumstances involving use of federal land. In one case, the federal Interstate Oil & Gas Compact Commission: A Policy, Legal, and Regulatory Evaluat ion of the
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antitrust laws have been used to modify some terms and conditions of service. These points are explained below.
1. Regulatory Status under the ICA and the NGA.
(a) Jurisdiction under the Interstate Commerce Act. When originally adopted in 1906, the Hepburn Act73 added regulation of oil pipelines as common carriers to the pre-existing regulatory responsibilities of the Interstate Commerce Commission (ICC). The statute originally extended the provisions of the Interstate Commerce Act (ICA) to those “engaged in the transportation of oil or other commodity, except water and except natural or artificial gas, by means of pipe lines”.74 The exact wording of the ICA pipeline provisions changed several times over the years due to the transfer of oil pipeline regulation to FERC in 1977 under the Department of Energy Organization Act 75 and the re-codification of the U.S. Code in 1978. Those changes deleted the qualifiers "natural or artificial", leaving the exclusion of pipelines transporting "gas"). Following the changes, FERC acquired regulatory jurisdiction over oil pipelines, while the ICC retained jurisdiction over the transportation of other commodities except for pipelines transporting “gas” (or water).76 A question was posed, however, as to whether the exclusion of “gas” (in the 1978 re-codification) or of “natural or artificial gas” (in the originally-adopted statute) included all gases or was intended to exclude only gases used for heating (i.e., methane pipelines subject to regulation by the FERC under the NGA).
Two requests for a declaratory order to resolve this question were filed with the ICC in 1980 on behalf of Cortez Pipeline Company and ARCO Oil & Gas Company in conjunction with the construction of a new interstate CO2 pipeline. The ICC invited public comment on the requests in light of their precedential character. The agency analyzed the applicable statutory provisions and ultimately concluded that under the “plain meaning” of the statute (referring back to the originally enacted text that excluded the transportation of “natural or artificial gas”), Congress excluded the entire “universe” of gas types. Following public comment on a proposed ruling, the agency issued a final order declaring that the agency lacked jurisdiction under the ICA over the interstate transportation of CO2 by pipeline.77
In 1995, the ICC was abolished pursuant to the Interstate Commerce Commission Termination Act of 1995 (the “Termination Act”), and certain of its authorities and responsibilities were transferred to a
73 34 Stat. 584, 59th Cong., 1st. Sess. 1, ch. 3591, enacted June 29, 1906.
74 Id.
75 Section 402 (b) of the Department of Energy Organization Act, originally codified at 42 U.S.C. 7172
(b), repealed by Pub. L. 103-272, 108 Stat. 1379 (1994).
76 49 U.S.C. 15301 (a).
77 Interstate Commerce Commission, Cortez Pipeline Company, "Petition for Declaratory Order – Commission Jurisdiction Over Transportation of Carbon Dioxide by Pipeline" and Arco Oil and Gas Company, "Petition for Declaratory Order -- Jurisdiction Over Interstate Pipeline Transportation of Carbon Dioxide”, Nos. 37427 and 37529, 45 Fed. Reg. 85177 (December 24, 1980) (“Tentative Declaratory Order”); Arco Oil and Gas Company "Petition for Declaratory Order -- Jurisdiction Over Interstate Pipeline Transportation of Carbon Dioxide,” No. 37529, 46 Fed. Reg. 18805 (March 26, 1981) (“Final Declaratory Order”). Interstate Oil & Gas Compact Commission: A Policy, Legal, and Regulatory Evaluat ion of the
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newly created STB.78 There was no change, however, in the applicable substantive law governing the regulation of pipelines.79 Moreover, the savings provisions of the 1995 ICC Termination Act (Section 204 of the statute)80 confirmed the validity of prior rulings of the ICC and specifically provided for the continuing legal effectiveness of the prior orders and determinations of the ICC “until changed in accordance with the law.”81
(b) Jurisdiction under the NGA. The developers of the Cortez Pipeline also presented the jurisdictional question to FERC under the NGA and the Natural Gas Policy Act of 1978, seeking a comparable declaratory order regarding jurisdiction. FERC granted the request, finding that a gas that was 98 percent pure carbon dioxide with traces of methane in the remaining 2 percent (which was not separated from the main production) was not "natural gas" within the meaning of the NGA.82 As a result, the CO2 pipeline operator would not become a "natural-gas company" under the NGA by constructing or operating the proposed CO2 pipeline. The 1979 jurisdictional ruling was reiterated in a 2006 order granting abandonment of a natural gas pipeline for conversion to CO2 transportation.83
2. Jurisdiction under Mineral Leasing Act of 1920.
Federal regulatory jurisdiction may occur if a CO2 pipeline crosses federal land and receives a right of way authorization issued by the Bureau of Land Management (BLM) under the Mineral Leasing Act of 1920 (the MLA).84 Section 28 of the MLA imposes a “common carrier” obligation on pipeline and related
78 Interstate Commerce Commission Termination Act of 1995 (ICCTA), Pub. L. No. 104-88, 109 Stat. 803 (1995).
79 As amended by the Termination Act, section 15301 of the Interstate Commerce Act, 49 U.S.C. 15301(a) provides in material part that the Surface Transportation Board has jurisdiction over “transportation by pipeline, or by pipeline and railroad or water, when transporting a commodity other than water, gas, or oil.”
80 Section 204 (a) of the ICCTA. The saving provision was not included in the codification of the Termination Act, but may be found in the notes to the codification of the sections establishing the Surface Transportation Board available at:(http://www.law.cornell.edu/uscode/html/uscode49/usc_sec_49_00000701----000-notes.html). As recognized by the STB itself, the saving provision of ICCTA “provides that ICC precedent applies to the Board”. GWI Switching Services, L.P., et al, (August 12, 2001), at n. 12, http://www.stb.dot.gov/decisions/readingroom.nsf/389e96bb615974918525653f005497a0/9cc76279022bab0085256a8e006bfb45?OpenDocument (last visited June 29, 2008). See also “Class Exemption For Motor Passenger Intra-Corporate Family Transactions”, STB Finance Docket No. 33685, (February 18, 2000), http://www.stb.dot.gov/decisions/readingroom.nsf/UNID/4B9598F2477DF0828525688900662DA5/$file/30325.pdf, mimeo, at 10 (under section 204(a) of ICCTA, ICC precedent in effect on the date of enactment of the ICCTA continues in effect until modified or revoked in accordance with law).
81 For a discussion of the jurisdictional issue, see Vann and Parfomak, “Regulation of Carbon Dioxide (CO2) Sequestration Pipelines: Jurisdictional Issues” (January 7, 2008 and April 15, 2008) (Congressional Research Service, Order Code RL34307) (hereafter “CRS 2008 CO2 Pipeline Jurisdictional Analysis”) (discussing Cortez rulings by ICC and FERC) available at: http://assets.opencrs.com/rpts/RL34307_20080415.pdf.
82 Cortez Pipeline Company, 7 FERC 61,024 (1979).
83 Southern Natural Gas, 115 FERC 62,266 (2006), at P.3.
84 Mineral Leasing Act of 1920 (MLA), as amended, 30 U.S.C. § 185. Interstate Oil & Gas Compact Commission: A Policy, Legal, and Regulatory Evaluat ion of the
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facilities that are authorized under that act. The statute thus requires the owner or operator to transport “without discrimination” all “oil or gas” delivered to the pipeline “without regard to whether such oil or gas was produced on Federal or non-Federal lands.”85 The BLM’s decision to issue the right of way authorization under section 28 of the MLA rather than under another federal land statute86 was challenged in court, but affirmed in 1992.87
Philip M. Marston and Patricia A. Moore provided a useful summary of the federal regulatory landscape in a 2008 article in the Energy Law Journal.88
[I]t seems fair to say that CO2 pipelines are neither “common carriers” under the Interstate Commerce Act nor “natural gas companies” under the Natural Gas Act. They may however be “common carriers” under the *Mineral Leasing Act+ if: (a) they cross federal land that is subject to that act, and (b) if the [Bureau of Land Management] issues right of way authorization under the [Mineral Leasing Act] rather than the [Federal Land Policy and Management Act]. The operation of CO2 pipelines remains subject of course to other generally applicable federal law.
3. CO2 Pipeline Regulation under State Law.
State governments began to address CO2 pipeline regulation several decades ago, when new facilities were being built or expanded. Several states have enacted laws or promulgated regulations89 specifically designed to address and encourage CO2-based oil production, which may include mechanisms for obtaining a right of eminent domain to acquire rights of way for CO2 pipelines. The following discussion of state regulation is intended only to provide a general overview of regulation in selected states. A thorough inventory of state statutory and regulatory law is included in Appendix II.
85 Section 28 of the MLA, provides in relevant part as follows:
(a) Rights-of-way through any Federal lands may be granted by the Secretary of the Interior or appropriate agency head for pipeline purposes for the transportation of oil, natural gas, synthetic liquid or gaseous fuels, or any refined product produced therefrom to any applicant possessing the qualifications provided in section 181 of this title in accordance with the provisions of this section. . . . .
(r)(1) Pipelines and related facilities authorized under this section shall be constructed, operated, and maintained as common carriers.
(2)(A) The owners or operators of pipelines subject to this section shall accept, convey, transport, or purchase without discrimination all oil or gas delivered to the pipeline without regard to whether such oil or gas was produced on Federal or non-Federal lands.
30 U.S.C. §§ 185(a), (r)(1), (r)(2)(A).
86 Previously, the BLM had acted under the Federal Land Policy and Management Act (FLPMA) which does not impose a comparable carriage obligation.
87 Exxon Corp. v. Lujan , 970 F.2d 757 (10th Cir. 1992) (hereafter Lujan).
88 Philip M. Marston and Patricia A. Moore, From EOR to CCS: The Evolving Legal and Regulatory Framework for Carbon Capture and Storage, ENERGY LAW JOURNAL, V.29,No.2, P.421 at P.455 (2008).
89 See IOGCC Groundwork (www.groundwork.iogcc.org) for state-by-state regulatory information Interstate Oil & Gas Compact Commission: A Policy, Legal, and Regulatory Evaluat ion of the
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Texas
In 1991, the Texas Legislature enacted laws that brought CO2 and hydrogen pipelines under regulation by the Texas Railroad Commission under certain defined circumstances.90 The statute gives the CO2 pipeline operator a choice of operating as either a private carrier (without a right of eminent domain) or a common carrier (in which case the operator may exercise a state-granted power of eminent domain). The statute includes within the definition of common carrier a person who owns, operates, or manages, wholly or partially, pipelines for the transportation of carbon dioxide or hydrogen in whatever form to or for the public for hire, “but only if such person files with the commission a written acceptance of the provisions of this chapter expressly agreeing that, in consideration of the rights acquired, it becomes a common carrier subject to the duties and obligations” of that statute. The statute provides that “common carriers have the right and power of eminent domain.”
In short, Texas offers the option of remaining a private contract carrier or of becoming a common carrier by filing with the regulatory commission, while reserving the power of eminent domain to those that elect the common carrier option.
It may be noted that under the Texas statute, the grant of eminent domain power to a CO2 pipeline is not limited to those transporting for EOR purposes, but applies to any pipeline transporting CO2 without imposing any limitation of purpose. A pipeline carrier that accepted the common carrier option could use the pipeline either for EOR or for transportation to a free-standing geologic storage location.
Mississippi
The Mississippi CO2 legislation dates from 1984.91 It does not impose common carriage duties on CO2 pipelines but grants a more limited power of eminent domain than under the Texas law, as the availability of eminent domain is limited to the construction of CO2 pipelines “for use in connection with secondary or tertiary recovery projects located within the state of Mississippi for the enhanced recovery of liquid or gaseous hydrocarbons.”92 Hence, a pipeline developer under the Mississippi statute is unable to exercise eminent domain if the pipeline is used solely for purposes of reducing CO2 emissions via geologic storage.
90 Tex. Nat. Res. Code Ann.§ 111.019(a). For a review of Texas law governing exercise of eminent domain powers by common carrier pipelines generally, see Comment, “Judicial Battles Between Pipeline Companies And Landowners: It’s Not Necessarily Who Wins, But By How Much”, 37 HOUSTON L. REV. 125 (2000), http://www.houstonlawreview.org/archive/downloads/37-1_pdf/hlr37p125.PDF (last visited May 11, 2008).
91 Miss. Code Ann. § 11-27-47 (2009)
92 Miss. Code Ann Sec. 11-27-47(1972), http://www.mscode.com/free/statutes/11/027/0047.htm (last visited June 30, 2008). The rules of the Mississippi Oil and Gas Board in its Rulebook (at §53-1-3) define the term "gas" as including carbon dioxide. See § 53-3-159. Interstate Oil & Gas Compact Commission: A Policy, Legal, and Regulatory Evaluat ion of the
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Louisiana
Louisiana allows the exercise of “expropriation” (which is to say condemnation) of property for piping or marketing of carbon dioxide for use in connection with a secondary or tertiary recovery project for the enhanced recovery of liquid or gaseous hydrocarbons approved by the Commissioner of Conservation. 93 The exercise of that power is conditioned on approval of the enhanced recovery project by the Commissioner of Conservation and issuance of a certificate of public convenience and necessity for the pipeline.94 Unlike Mississippi, Louisiana law applies even if the CO2 transportation is entirely in connection with projects in other states.95 In that case, the commissioner’s approval “shall consist of confirmation that the applicable regulatory authority of that state or jurisdiction has approved or authorized the injection of carbon dioxide in association with such project.”96 Similar to Mississippi, and in contrast to the Texas statute, Louisiana law limits the expropriation power to pipelines to supporting secondary or tertiary recovery of hydrocarbons.
Other states with significant CO2 operations also have provisions for pipeline right of way acquisition or address other aspects of a regulatory regime needed for transport, injection, or storage of CO2. Examples include Wyoming, New Mexico, Colorado, and North Dakota.97
This area of the law is dynamic. States are in a constant process of developing their particular regulatory frameworks. As noted above, a thorough inventory of the current status of state statutory and regulatory law is included in Appendix II.98
In addition to state statutory law, CO2 pipelines may in certain cases be subject to carrier obligations under common law. The traditional view holds that a carrier ceases to be a "private" or "contract"
93 Louisiana R.S. Sec. 19:2(10)(2007).
94 Louisiana R.S. 30:4 (c)(17)(b). The Commissioner is also tasked to regulate the construction design and operation of pipelines transmitting carbon dioxide to serve secondary and tertiary recovery projects for increasing the ultimate recovery of oil or gas, “including the issuance of certificates of public convenience and necessity for pipelines serving such projects approved hereunder.”
95 Id.
96 Id.
97 For a review of state legislative action governing CCS as of early 2008, see D. Eugene, “State CCS Progress”, 24 NATURAL GAS & ELECTRICITY 8 (May 2008)(discussing in particular Wyoming, New Mexico, California, North Dakota, Texas and Kansas). See also Robert R. Nordhaus and Emily Pitlick, "Carbon Dioxide Pipeline Regulation", 30 ENERGY L. J. 85 (2009).
98 A number of resources are available that endeavor to track changes in state law governing CO2 pipeline regulation. The University College London’s Carbon Capture Legal Programme (CCLP) has created one such site with links to recently passed legislation at both the U.S. and state levels (available at:
http://www.ucl.ac.uk/cclp/ccsdedlegnat-US.php#state), as well as around the world (http://www.ucl.ac.uk/cclp/ccsdata.php). Interstate Oil & Gas Compact Commission: A Policy, Legal, and Regulatory Evaluat ion of the
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carrier and becomes a common carrier when it "holds itself out" to the public as a common carrier by posting rates and offering to carry for all.99
C. CO2: Commodity or Pollutant – Resource Management – A New Paradigm
The evolution of CO2 as either a commodity or a pollutant has significant implications for how CO2 will be handled and transported. The traditional conversation regarding the status of CO2 has centered on whether CO2 is a commodity or a pollutant. In this discussion, the PTTF hopes to move beyond that limited focus toward a more constructive paradigm of “Resource Management.”
Resource Management -- Regulation that seeks to manage, maintain, and advance the beneficial uses of a commodity while regulating and controlling any harmful or deleterious effects of the commodity.
Classification of CO2 as both a commodity and as a pollutant creates an immediate conflict which needs to be addressed for the sake of future CCS implementation and to ensure the consistency of future CCS with current CO2 pipeline operations.100 The Government Accountability Office identified regulatory uncertainty of how injection, capture, and storage of CO2 will be handled as one of the chief hurdles to the development of a CO2 pipeline network.101
Classification of CO2 as a pollutant would lead to greater regulatory oversight, permitting requirements, safety inspections, etc. Classification of CO2 as a commodity would require some federal oversight but not to the extent required by a pollutant classification. There is another regulatory option that looks beyond the “pollutant v. commodity” dichotomy. Perhaps a more practical way of looking at CO2 transportation, capture, storage, and injection is through the lens of “resource management.” Resource management changes the scope of the “either/or” classification inherent in the pollutant v. commodity discussion, to a “both/and” mode of looking at CO2. The resource management regulatory paradigm focuses on managing and maintaining the beneficial uses of a commodity, while regulating and controlling any harmful or deleterious effects of the commodity.
With either model there are issues that need to be addressed in terms of CO2. A key issue affecting the implementation of a regulatory framework is the quality of the CO2. High quality CO2 (almost pure) presents little challenge to capture, storage, and transportation. Less compression is needed to move the CO2 through the pipeline because the CO2 stream is close to pure. CO2 quality also might have an effect on the storage and injection requirements. Pure CO2 is more likely to be injected because environmental concerns are diminished. For example, injection of CO2 with high H2S content is more
99 Marston and Moore, From EOR to CCS, supra 88
100See CRS Report for Congress: Carbon Dioxide (CO2) Pipelines for Carbon Sequestration: Emerging Policy Issues, updated January 17, 2008.
101U.S. Government Accountability Office. (September 2008). Climate Change: Federal Actions Will Greatly Affect the Viability of Carbon Capture and Storage as a Key Mitigation Option (Vol. GAO-08-1080, p. 4) (U.S. Government Accountability Office). Retrieved from http://www.gao.gov/new.items/d081080.pdf Interstate Oil & Gas Compact Commission: A Policy, Legal, and Regulatory Evaluat ion of the
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likely to raise public safety concerns because of the issues associated with acid gas. That being said, acid gas injection is an oilfield activity that has been in safe practice since the early 1990’s. A CO2 stream with high levels of impurities is less likely to be transported via pipeline because of the greater compression requirements and expense of moving such “impure” CO2.
Adding to the regulatory uncertainty of development of a CO2 infrastructure are legal challenges to government action concerning the handling of CO2 emissions. In 2003, the EPA disclaimed jurisdiction under the Clean Air Act (CAA) to regulate CO2 and concluded that even if the EPA had authority to regulate CO2, it would not do so.102 In 2007, 30 complainants petitioned the U.S. Supreme Court to challenge the EPA’s conclusion disclaiming jurisdiction to regulate CO2.103 The Supreme Court, in a 5-4 decision, held that the CAA gave the EPA authority to regulate CO2 emitted from automobile exhaust.104 The Court concluded that "greenhouse gases fit well within the Clean Air Act’s capacious definition of air pollutant.105" The Supreme Court concluded that the Administrator of the EPA may regulate CO2 under the CAA based upon the results of an endangerment finding. In December 2009, the EPA issued an endangerment finding declaring that “elevated concentrations of greenhouse gases in the atmosphere may reasonably be anticipated to endanger the public health and to endanger the public welfare of current and future generations.”106 Under the endangerment finding, the EPA concluded that CO2 emissions from automobiles posed a threat to human health and the environment.107 Since the EPA made a finding of endangerment under Section 202 of the CAA, it is reasonable to assume that the EPA will issue a similar finding for fossil fuel electric generation projects, because the same endangerment finding language is found in Section 108 of the CAA, which sets the national ambient air quality standards (NAAQS). Every pollutant regulated under Section 202 is also regulated under Section 108.
In addition to the purity issue and the EPA actions on CO2, there also are political issues associated with the development of the CO2 infrastructure. Whether CO2 is treated as a commodity, pollutant, or transport resource to be managed, the likelihood of public opposition to pipeline transport is high, just as with other resource infrastructure.
“Federal models for “commodity v. pollutant” and “resource management” can be applied to the states. It seems reasonable to conclude that where states have oil and gas production, the development of a
102 Mass v. EPA, 549 U.S. 497 (2007)
103 Id.
104Mass. v. EPA, 549 U.S. 497, 528-529 (2007).
105Id.
106U.S. EPA. (2009, December 07). Greenhouse Gases Threaten Public Health and the Environment / Science overwhelmingly shows greenhouse gas concentrations at unprecedented levels due to human activity [Press release]. Retrieved July 30, 2010, from http://yosemite.epa.gov/opa/admpress.nsf/7ebdf4d0b217978b852573590040443a/08d11a451131bca585257685005bf252!OpenDocument.
107U.S. EPA, Endangerment and Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of the Clean Air Act (2009), http://www.epa.gov/climatechange/endangerment.html. Interstate Oil & Gas Compact Commission: A Policy, Legal, and Regulatory Evaluat ion of the
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CO2 infrastructure is more likely to occur because of the usefulness of CO2 for enhanced oil recovery. State oil and gas regulatory agencies will most likely regulate CO2 as a commodity. However, if CO2 regulation is left to the state’s environmental quality department, then CO2 will most likely be regulated as a pollutant. The spirit of the “resource management” paradigm is based upon the hybrid regulatory framework envisioned by cooperation between commercial and environmental regulators. Some states have opted to regulate CO2 under both commerce regulatory agencies and environmental management agencies. For instance, some states may recognize that CO2 is valuable as a commodity for EOR thereby granting the state oil and gas agency regulatory authority for these activities, while granting the environmental agency the authority to regulate CO2 for storage only purposes.
Classification of CO2 as either a pollutant or commodity is necessarily narrow. By looking at CO2 regulation through the “resource management” paradigm, the discussion of CO2 and its potential will be broadened by bringing multiple stakeholders to the discussion of how to regulate CO2. The resource management paradigm opens a dialogue among multiple agencies ensuring that CO2 use is regulated appropriately, thereby encouraging the development of a viable CO2 infrastructure.
D. Future Pipeline Build-out Scenarios
Any discussion of the barriers and opportunities related to CO2 pipeline infrastructure to support CCS (including CO2-EOR) necessarily relies on assumptions about the timing, scope, and configuration of the anticipated growth in the current pipeline network.
Except for pipelines associated with business-as-usual CO2-EOR and other commercial uses, pipelines for CCS will be associated with enactment of legal restrictions on industrial emissions of carbon dioxide. Legal restrictions on industrial emissions of carbon dioxide could result from enactment of carbon regulation by Congress, by state governments108, and/or imposition of CO2 emissions standards by the EPA under the federal Clean Air Act as a result of EPA’s recent endangerment finding.109
There are substantial uncertainties under these scenarios regarding whether they will occur, and if so, when; and the timing, stringency, and manner of imposition of CO2 controls on industrial facilities. Regardless of how CO2 emissions controls are implemented, it is reasonable to assume that they will be phased in over a substantial number of years, perhaps a decade or more. This suggests that it is unlikely that a nationwide infrastructure of CO2 pipelines will need to be built in the near future over a short period of time. The more likely result is a gradual build-out of infrastructure over time as CO2 emission controls or carbon caps tighten.
Another uncertainty that impacts future CO2 pipeline networks is whether future geologic storage sites will be sited throughout the United States or concentrated in a handful of major locations in regions of the country that are deemed to have particularly favorable geology for storage. The pipeline networks
108A number of northeastern states have already enacted legislation imposing constraints on carbon dioxide emissions. See http://www.rggi.org.
109Endangerment and Cause or Contribute Findings for Greenhouse Gases under the Clean Air Act, available at: http://www.epa.gov/climatechange/endangerment/downloads/FinalFindings.pdf. Interstate Oil & Gas Compact Commission: A Policy, Legal, and Regulatory Evaluat ion of the
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supporting these models would be quite different. And the costs of pipeline construction and operation would be expected to influence the future growth of geologic storage sites.
Experts have put forth several models of what a future CO2 pipeline network to support CCS might look like. One assumes a nationwide network, similar to that for natural gas, which would transport CO2 from geographically dispersed industrial sources to a handful of large-scale storage sites. A variant of that model assumes the gradual build-out of regional networks that integrate new supply sources into the existing pipeline infrastructure serving EOR operations with local storage. Under a third model, CO2 injection sites might be located close to many large CO2 power plant sources, requiring much shorter “stub” type pipelines linked directly to the storage location.
Analogies to the natural gas network must not be overstated, because under either of the first two models, a CO2 pipeline network required to accommodate wide-spread deployment of carbon capture is likely to look quite different from the nation's natural gas pipeline network. The natural gas pipeline network is essentially a “many-to-many” network. It links hundreds of thousands of individual gas sources (producing wells and processing plants) with millions of individual delivery points, comprised of both large and small end users. Because of historical and seasonal requirements, the network includes extensive gas storage facilities of varied types, including underground formations (e.g., former producing fields, aquifers, and salt domes) as well as above-ground facilities (typically holding the gas cryogenically converted to liquefied natural gas or “LNG”).
While it is unclear how existing business models for CO2 pipelines may evolve if CCS becomes widespread, all such models will be dealing with a different mix of supply sources and delivery locations than is the case for natural gas. This results because CO2 pipelines for CCS purposes will almost certainly be built to link a relatively small number of large output sources of CO2 (power plants and other large stationery sources) with a relatively small number of injection sites, which are likely to begin with EOR fields and gradually expand to include free-standing geological storage facilities. Movement in this direction has been underway for the last several years with regard to current pipeline construction and feasibility planning.
The phenomenon can be illustrated by a simple example. Take the case of a 500 megawatt (MW) power plant that produced 3 million metric tons per year and captured 80% of the CO2. This would produce approximately 2.4 million metric tons available for off-take.110 If this amount were delivered ratably on a daily basis, it would amount to about 6,575 metric tons per day, or, in volumetric terms, approximately 125,000 Mcf of dense-phase gas available for transport.111 The output of just eight such plants would fill
110 MIT Report, supra note 29.
111There are 19.01 thousand cubic feet (Mcf) of CO2 in one metric ton (i.e., 1,000 kilograms) at 60°F and 1 atmosphere. Therefore, 6,575 metric tons of CO2 at the same conditions × 19.01 Mcf/metric ton equals 124,991 Mcf. To convert U.S. short tons of 2,000 pounds each to Mcf of CO2, a conversion factor of 17.24 is applied instead. Interstate Oil & Gas Compact Commission: A Policy, Legal, and Regulatory Evaluat ion of the
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the largest existing 30-inch CO2 pipeline, which has a capacity of approximately 1 billion cubic feet per day (Bcf/d).112
Even under the very aggressive schedule for CCS deployment developed by the International Energy Agency’s (IEA) Blue Map scenario, the number of power plant source locations in North America is projected to be roughly 17 plants by 2020 and reach only 250 point sources over approximately 40 years.113 While the addition of carbon capture from industrial sources would increase the number of individual supply sources, the overall number of supply sources at the end of 40 years projected by IEA still would be more than three orders of magnitude – more than 3,000 times -- fewer than the 478,000 natural gas wells that currently feed into the natural gas pipeline system.114 And it is by no means certain that CCS will be deployed as quickly as projected under the IEA Blue Map scenario.
Accordingly, rather than the “many-to-many” set of network receipt and delivery points that characterizes the natural gas industry, the CO2 pipeline network is unlikely over the next half-century to develop beyond a “few-to-few” type network. Under that scenario, a handful of large CO2 sources feed pipelines whose capacity is specifically dedicated to those sources and that carry the gas to a select number of large EOR injection sites that have contracted for long-term supply. The remainder would be delivered to free-standing geologic storage facilities that receive surplus CO2 that cannot be marketed for use in EOR operations. The rate at which CO2 supply captured from anthropogenic sources may come to exceed EOR demand is a major uncertainty in evaluating potential pipeline network development.
It would appear extremely unlikely that the CO2 pipeline network would ever resemble the natural gas pipeline network, with millions of retail delivery points for CO2 deliveries or with networks of small CO2 “gathering lines” to receive small amounts of anthropogenic CO2 captured from small point sources. The cost of compressing small amounts of CO2 for dense-phase transportation would by itself render such a system cost-prohibitive. As a result, any future pipeline network for CCS purposes is likely to be a “wholesale-oriented” business from end to end, quite unlike the natural gas network.
These underlying realities may have major implications for potential legal and regulatory structures. New capture sources will require pipeline off-take capacity that is specifically dedicated to receive the plant’s CO2 output. Failure to accommodate the requirement to ensure the availability of designated amounts of capacity for very lengthy periods could pose a significant regulatory barrier to wide-scale commercial deployment of CCS technologies.
112The largest capacity existing CO2 pipeline, the 30-inch, 803 kilometer “Cortez” pipeline operated by Kinder Morgan, LLP, has an estimated annual capacity of 19.3 million tons. See Table 4.1 of Intergovernmental Panel On Climate Change, Special Report On Carbon Dioxide Capture An Storage, (Bert Metz, ed., Cambridge University Press 2005) (hereafter “IPCC Special Report on CCS”), at 183 ((19.3 million tons per year/365 days) multiplied times a conversion factor of 19.1 equals 1.001 billion cubic feet/day of dense phase gas).
113International Energy Agency, “Technology Roadmap: Carbon capture and storage” (2009), at 17 (projections under the “BLUE Map” scenario).
114U.S. Energy Information Administration, Natural Gas Annual (2008), at 1 (Table 1) (showing over 478,000 natural gas producing wells in 2008). Interstate Oil & Gas Compact Commission: A Policy, Legal, and Regulatory Evaluat ion of the
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II. Prospective Business Models and State and Federal Regulatory Options
In this section the PTTF examines:
1) the potential business models for pipeline construction and operation likely to emerge in the U.S;
2) the state and federal regulatory systems that could conceivably develop to govern those business models; and
3) the impact that the prospective federal and state regulatory systems might have on the various business plans and the development of the intrastate, interstate, and international pipeline infrastructure.
A. Leading Potential Business Models for CO2 Pipeline Build-out in the U.S.
With a view towards possible storage of anthropogenic CO2, it seems reasonable to survey the present development of CO2 infrastructure and the policy frameworks that have developed around this successful business. The analysis will help to gain insights that may facilitate future development should CO2 capture and storage be required by federal or state carbon regulation.
There are 36 CO2 pipelines operating in the U.S. today. Of these, six cross state boundaries and one pipeline crosses the international border between the U.S. and Canada. This indicates that the overwhelming number of CO2 pipelines operating in the U.S. do so in a single state (intrastate) with the majority of them in Texas. Below, various operating models are defined, discussed, and compared to actual pipelines currently operating in the U.S.
Model Definitions
Intrastate Dedicated Pipeline Model: a model where parties enter into a contract to develop a pipeline to carry CO2 under specific terms and conditions. Under this model, the carrier does not require state assistance, i.e., eminent domain authority or an exclusive franchise, and the business arrangement is a contractual agreement between private parties and does not involve economic regulation. Because all of the transport capacity is committed to receiving the output of a particular set of CO2 sources there is limited access for subsequently developed capture projects. In certain states, such as Mississippi and North Dakota, the carrier may have eminent domain authority; however, such authority does not concomitantly subject the carrier to economic regulation.
Intrastate Open Access Model: a model where a pipeline is developed with significant government involvement and includes defined rights of access. In return for certain benefits such as eminent domain authority or an exclusive franchise, the developer is subject to government regulation. This regulation could take the form of defined rights of access (open access or common carrier), economic regulation (rate-setting) or other forms of government oversight. Interstate Oil & Gas Compact Commission: A Policy, Legal, and Regulatory Evaluat ion of the
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Interstate Dedicated Pipeline Model: a model similar to the intrastate dedicated model except that the pipeline crosses state boundaries.
Interstate Open Access Model: a model similar to the Intrastate Open Access Model except that some form of federal action [oversight/approval/involvement/regulation] is necessitated.
Government/Public Option Model: a model that involves government financing and/or ownership of facilities. Under a government/public option model, a local, state, or federal entity would finance or build pipeline facilities or charter a corporation to do so.
1. Intrastate Dedicated Pipeline Model Description and Examples
Most of the intrastate pipelines in this model have been built by a single operator and in some instances by multiple owners, each having a dedicated proprietary portion of the pipeline’s capacity. These lines were built, for the most part, without the need or use of eminent domain to acquire the pipeline right of way. The lines typically are not subject to federal siting, regulatory, or legal framework unless they cross federal lands. If federal lands are not involved, they may have to obtain siting approval from state and local agencies. The pipelines have been built either to deliver the owners’ CO2 to their oil fields (considered to be a private carrier) or to deliver CO2 to third party customers under long-term CO2 supply contracts (considered to be contract carriers). Many of the existing intrastate lines operate in both of these modes, but with the contract carriage being limited to surplus capacity that is not required by the owner for its own use. With only limited access available, normally under long-term contracts, transportation rates are negotiated, are not subject to regulation, and may differ among customers.
Table 5. Examples of Intrastate Dedicated Pipelines
Pipeline Name
Operators
From
Length
Diameter
Capacity
CO2 Source
End Use
(St) To (St)
(Miles)
(in)
(106 t/yr) Adair Apache TX – TX 15 4 1.0 Bravo Dome EOR
Anadarko P River
Anadar