Best Management Practices for Subseabed Geologic Sequestration of Carbon Dioxide Rebecca C. Smyth
Timothy A. Meckel
Bureau of Economic Geology, Jackson School of Geosciences, The University of Texas at Austin Austin, Texas, U.S. A.
[email protected]
Bureau of Economic Geology, Jackson School of Geosciences, The University of Texas at Austin Austin, Texas, U.S. A.
[email protected]
Abstract—A team led by the Gulf Coast Carbon Center at the Bureau of Economic Geology, Jackson School of Geosciences at The University of Texas at Austin, has been funded by the National Oceanographic Partnership Program (NOPP) through and in cooperation with the U.S. Department of Interior (DOI), Bureau of Ocean Energy Management (BOEM) to generate a Best Management Practices (BMPs) document on sub-seabed geologic sequestration of carbon dioxide (CO2) below the U.S. outer continental shelf. The team consists of scientists, engineers, lawyers, and business managers from academia, private industry, and State of Texas government from the following institutions: (1) Gulf Coast Carbon Center at the Bureau of Economic Geology (BEG), (2) Det Norske Veritas (USA) Inc (DNV), (3) Wood Group Mustang and sister company Wood Group Kenny (Wood Group), (4) Texas General Land Office (GLO), (5) Harte Research Institute for Gulf of Mexico Studies at Texas A&M University-Corpus Christi (HRI), and (6) The University of Houston Law Center. Individual team members have expertise in carbon sequestration monitoring, CO2-pipeline design and construction, and domestic and international offshore environmental policy. The BMPs will be reviewed by external experts after it is generated and before being submitted to BOEM. The purpose of the BMPs will be to provide technical guidance to BOEM and BSEE (U.S. DOI Bureau of Safety and Environmental Enforcement) to establish regulatory guidelines for offshore components of future U.S. Carbon Capture and Storage, which is sometimes referred to as sequestration, (CCS) industry. Sub-seabed geologic sequestration (GS) is the process whereby CO2 captured from large volume industrial sources (e.g., power plants, oil refineries) will be (1) compressed to supercritical state and transported via pipeline to offshore injection wells, and (2) injected into geologic strata deep (thousands of feet) below the seafloor. Objectives of the CO2 injection will be for “pure sequestration” (i.e., long-term storage of CO2 in subseafloor saline reservoirs) or sequestration combined with enhanced oil recovery (EOR). Sub-seabed geologic sequestration is very different from ocean dumping (i.e. dissolution of CO2 into circulating seawater) or injection of CO2 into deep water, shallow sub-seabed sediments. Some researchers proposed in the past that shallow subseafloor depths (< 1,000 ft) were sufficient for permanent CO2 storage in deep marine environments (> 11,000 ft water depth) (e.g., House et al., 2006). However, the shallow sedimentary subseafloor environment could become unstable and allow release of CO2 into ocean water, the end result of which would be ocean dumping. One mechanism of seafloor instability could be the release of gas from hydrates
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owing to pressure and temperature perturbations that may be introduced by shallow drilling and CO2 injection. Furthermore, the logistics of transporting CO2 hundreds of miles offshore to areas with sufficient water depths for storage in shallow subsea sediments would probably not be economically feasible. We want to emphasize that subseabed GS of CO2 is not ocean dumping. One of the biggest concerns for onshore GS is the potential to impact shallow drinking water resources. Injecting CO2 deep below the seafloor will avoid this potential consequence. But there are sensitive marine environments of concern in offshore settings, protection of which is critical. Environmental monitoring of marine ecosystems (nearshore, along CO2 pipeline corridors, and outer continental shelf) and subseafloor geological strata in which CO2 will be injected will be a large component of the BMPs. Topics being included in the BMPs, a draft of which will be submitted to BOEM in June of 2013, are: (1) site selection and characterization, (2) risk analysis, (3) project planning and execution, (4) environmental monitoring, (5) mitigation, (6) inspection and auditing, (7) reporting requirements, (8) emergency response and contingency planning, (9) decommissioning and site closure, and (10) legal issues. Where possible, we are using existing regulatory, policy, and technical guidance documents as a starting point for the BMPs. We think the most likely location for initiation of U.S. offshore geologic sequestration of CO2 will be in the western or central sectors of the Gulf of Mexico where extensive offshore oil and gas infrastructure already exists. Academic members of our project team are actively working on criteria for site selection [1]. However, private industry is also assessing the feasibility of offshore geologic sequestration below the Atlantic seafloor [2]. Index Terms—carbon sequestration, BOEM.
dioxide,
subseafloor,
geologic
INTRODUCTION AND BACKGROUND A comment from a reviewer of the abstract for this paper was: “This paper deals with the subject of carbon sequestration. It's an interesting subject, but doesn't belong in the marine renewables section.” This statement is indicative of the confusion about how and which agency can best regulate offshore subseabed GS of CO2. It is true that carbon sequestration is not a form of renewable energy, but like renewable energy, it is a way of reducing emissions of CO2 to the atmosphere from current forms of electricity generation, especially coal-fired power plants. There is much similarity
This is a DRAFT. As such it may not be cited in other works. The citable Proceedings of the Conference will be published in IEEE Xplore shortly after the conclusion of the conference.
between existing offshore oil and gas operations and those that will be necessary for OCS subseabed GS (e.g. submarine pipelines, offshore drilling rigs, platforms for well operations, maintenance, and inspection). Subseabed geologic sequestration (GS) is the process whereby CO2 captured from large volume industrial sources (e.g., power plants, oil refineries) will be (1) compressed to supercritical state and transported via pipeline to offshore injection wells, and (2) injected into geologic strata deep (thousands of feet) below the seafloor. Objectives of the CO2 injection will be for “pure sequestration” (i.e., long-term storage of CO2 in subseafloor saline reservoirs) or sequestration combined with enhanced oil recovery (EOR). Sub-seabed geologic sequestration is very different from ocean dumping (i.e. dissolution of CO2 into circulating seawater) or injection of CO2 into deep water, shallow subseabed sediments. Some researchers proposed in the past that shallow subseafloor depths (< 1,000 ft) were sufficient for permanent CO2 storage in deep marine environments (> 11,000 ft water depth) (e.g., [3]). However, the shallow sedimentary subseafloor environment could become unstable and allow release of CO2 into ocean water, the end result of which would be ocean dumping. One mechanism of seafloor instability could be the release of gas from hydrates owing to pressure and temperature perturbations that may be introduced by shallow drilling and CO2 injection. Furthermore, the logistics of transporting CO2 hundreds of miles offshore to areas with sufficient water depths for storage in shallow subsea sediments would probably not be economically feasible. We want to emphasize that subseabed GS of CO2 is not ocean dumping. Under the authority of the Outer Continental Shelf Lands Act (OCSLA), the DOI BOEM and BSEE have authority for managing the energy and natural resources on 1.7 billion acres of the OCS. Section 8(p)(1)(C) of the OCSLA (43 U.S.C. 1337), as amended by the Energy Policy Act of 2005, gave MMS (now BOEM and BSEE) the authority to issue leases, easements, and rights-of-way for activities that “produce or support production, transportation, or transmission of energy from sources other than oil and gas”. CCS is viewed as a way to support production of energy generation, through capture and sequestration of CO2 produced as a by-product of the production of electricity from a coal-fired power plant. “An example of one such potential project is PURGeN One, an onshore 400-Megawatt coal-fueled integrated gasification combined cycle electrical-generating and manufacturing facility that will be constructed in Linden, NJ. The CO2 emissions from the new plant and potentially neighboring industrial operations, totaling up to approximately 6 million tons annually, would be captured and transported via a submarine pipeline to injection wells 70 miles off the Atlantic coast for sequestration approximately 8,000 feet beneath the seabed” [4]. DOI also has the authority under the OCSLA to issue leases, easements, or rights-of-way for reuse of existing offshore infrastructure (43 U.S.C. 1337, 8(p)(1)(D)). It makes sense to reuse offshore facilities for subseabed GS, at least existing platforms, as much as possible. In fact, [5] has
published multiple reuse scenarios for infrastructure needed for OCS subseabed GS. We agree that it should be possible to use existing easements and rights-of-way for future CO2 pipelines, but due to different design specifications (higher pressure) needed for transport of supercritical CO2, the pipelines themselves will most likely need to be new construction. There has been discussion of the possible need for regulation of CCS and GS by other federal authorities besides the DOI BOEM and BSEE. According to 40 CFR 144, requirements for an Underground Injection Control Class VI injection well, which is the type of well permit needed for “pure CO2 sequestraion”. One of the biggest concerns for onshore GS is the potential to impact shallow drinking water resources, which are also known as underground sources of drinking water (USDWs). The primary objective of the UIC program, which is administered by the Environmental Protection Agency under the Safe Drinking Water Act (SDWA), is to protect USDWs from fluids being disposed in the deep subsurface. Since there are no USDWs below the OCS, injecting CO2 deep below the seafloor will avoid this potential consequence. On pages 77236-7 of 40CFR144 there is text on the “distinction between Class VI and other Federal rulemakings and initiatives”. But it is really text citing potential overlap between Class VI and these other rules, including the Marine Protection, Research, and Sanctuaries Act (MPRSA) and London Protocol Implementation. EPA states that CO2 GS may in some cases be considered ocean dumping, which is not a valid assumption. If this were true: 1.
sub-seabed GS would need to seek a permit under SDWA Class VI and MPRSA rules. MPRSA was established in 1972 and implements the London Convention on the Prevention of Marine Pollution by Dumping of Wastes and Other Matter (London Convention), and 2. under the authority of the 1996 Protocol to the London Convention (London Protocol), sub-seabed GS is OK if it is GS and if the CO2 stream is fairly pure. EPA says that if the London Protocol is ratified (US has signed only) they will need to consider writing associated rules. Furthermore, the CO2 that will be injected in the subseabed below the OCS will not be hazardous waste so it will not be subject to the Comprehensive Environmental Response, Compensation, and Liability or Resource Conservation and Recovery acts. Below we outline the topics that will be included in the BMPs and provide some details of how a subseabed GS site will be selected using examples from studies currently being conducted in the Gulf of Mexico.
BEST MANAGEMENT PRACTICES A team led by the Gulf Coast Carbon Center at the Bureau of Economic Geology, Jackson School of Geosciences at The University of Texas at Austin, has been funded by the National Oceanographic Partnership Program (NOPP) through and in cooperation with the U.S. Department of Interior (DOI), Bureau of Ocean Energy Management (BOEM) to generate a Best Management Practices (BMPs) document on sub-seabed geologic sequestration of carbon dioxide (CO2) below the U.S. outer continental shelf. The team consists of scientists, engineers, lawyers, and business managers from academia, private industry, and State of Texas government from the following institutions: (1) Gulf Coast Carbon Center at the Bureau of Economic Geology (BEG), (2) Det Norske Veritas (USA) Inc (DNV), (3) Wood Group Mustang and sister company Wood Group Kenny (Wood Group), (4) Texas General Land Office (GLO), (5) Harte Research Institute for Gulf of Mexico Studies at Texas A&M University-Corpus Christi (HRI), and (6) The University of Houston Law Center. Individual team members have expertise in carbon sequestration monitoring, CO2-pipeline design and construction, and domestic and international offshore environmental policy. The BMPs will be reviewed by external experts after it is generated and before being submitted to BOEM. The purpose of the BMPs will be to provide technical guidance to BOEM and BSEE (U.S. DOI Bureau of Safety and Environmental Enforcement) to establish regulatory guidelines for offshore components of future U.S. Carbon Capture and Storage, which is sometimes referred to as sequestration, (CCS) industry. At present, the only large-scale subseafloor GS site for CO2 is operated by Statoil in the Norwegian North Sea. But offshore CO2 GS projects are being planned in Australia, Europe, and the U.S. Much expertise in onshore GS is being gained in the U.S. through partnership projects between private industry and the DOE NETL. Offshore GS of CO2 is fundamentally similar to onshore storage in terms of geological considerations (geologic reservoir characteristics and trapping mechanisms). However, offshore settings involve initially higher pressures (beneath the water column) and lower temperatures at the seafloor, both of which favor denser CO2 phases throughout subseafloor storage depths when compared with onshore settings. The subtopics that will be included in the BMPs are: • Subtopic 1: site selection and characterization, including data collection, capacity assessment, and modeling requirements • Subtopic 2: risk analysis • Subtopic 3: project construction, operation, decommissioning • Subtopic 4: operational and environmental controls and monitoring, verification, and accounting • Subtopic 5: mitigation • Subtopic 6: inspection and auditing • Subtopic 7: reporting requirements
• • •
Subtopic 8: emergency response and contingency planning Subtopic 9: site closure Subtopic 10 post-operation monitoring and management
Subtopic 1 - site selection and characterization, including data collection, capacity assessment, and modeling requirements (BEG, DNV). We will need to include both EOR and nonEOR, however real or hypothetical case study examples that may be used to justify suggested requirements will be mostly EOR-related. Will also use PURGeN One and current offshore Miocene work at BEG as examples. Data requirements will most likely guide industry to areas that have already undergone O&G exploration; hence most information is from the western and central planning areas of the Gulf of Mexico. There are no existing geology and geophysics requirements for CO2 injection, but injectivity testing will need to be required. Include geomechanical analysis, including identification of transmissive faults during injectivity testing. Subtopic 2 - risk analysis (BEG, DNV, Wood Group, GLO, HRI) a. nearshore (State waters) and coastal habitats – Coastal division of GLO b. pipeline c. platform d. injection well e. seafloor (within area of estimated horizontal subseafloor CO2 migration, projected up to seafloor) i. survey of benthic organisms ii. ocean current identification iii. archaeological resources f. subseafloor geological strata i. overlying resources ii. geohazards Subtopic 3 – project planning and execution (BEG, Wood Group, GLO) a. project design and construction i. nearshore ii. pipeline iii. platform iv. injection well b. project operation, maintenance, and inspection i. nearshore ii. pipeline iii. platform iv. injection well Concerning pipeline design – Emergency cutoff valves along the pipeline, which will be used to shut off the flow of CO2 should a leak develop, may not be currently required for subsea pipelines, but will need to be recommended in the BMP. According to team, API code does specify use of
emergency cutoff valves, but they may not be required in practice. Subtopic 4 – environmental monitoring (BEG, DNV, Wood Group, GLO, HRI) a. operational phase i. nearshore ii. pipeline iii. platform iv. subseafloor geological strata v. injection well b. post-operational phase i. seafloor ii. subseafloor geological strata There will be a need to balance environmental/operational controls with economic viability. The project team thinks EPA Class VI well regulations are not directly applicable to CO2 injection wells used for offshore geologic sequestration, especially if they are associated with EOR. However as in onshore settings, geologic sequestration (i.e., containment of CO2) will need to be demonstrated for OCS settings. Suggested terminology to use is “requirements as low as reasonably practical” Subtopic 5 - mitigation (BEG, DNV, Wood Group, GLO, HRI) a. nearshore and coastal habitats b. pipeline c. injection well (This falls under BSEE regulations – e.g. 30 CRF 250) Subtopic 6 – inspection and auditing (BEG, DNV) a. pipeline b. platform c. injection well
Subtopic 9 – decommissioning and site closure (BEG, DNV, Wood Group, GLO, HRI) a. pipeline b. platform c. injection well Subtopic 10 – legal issues (BEG, GLO, DNV, and HRI) a. liability and bonding b. post-operational management/long-term stewardship issues c. SUBSEABED GEOLOGIC SEQUESTRATION SITE SELECTION PROCESS For subtopics 1, 2, and 4, BEG will bring complementary resources to the BMPs through project examples. One is a site underlying Texas submerged lands, which is being funded by the GLO, DOE NETL, and the Jackson School of Geosciences at UT Austin. The job of geologic characterization of the subsurface determines the details as to whether a location is suitable for sequestering CO2 over geologic time. The work flow for geologic subsurface characterization comes in four basic sequential steps: Ascertain regional geological setting
Delineate sites reservoir architecture
Subtopic 7 – reporting requirements (BEG, Wood Group, GLO). Much of this is already in existing regulations. Needs to include OSHA incidents, health and safety compliance monitoring, and operational/engineering/technical requirements
Determine fluid & rock-fluid properties
Subtopic 8 – emergency response and contingency planning (BEG, DNV, Wood Group, GLO) a. nearshore (State waters), coastal habitats (will refer to existing GLO regulations) b. pipeline c. platform d. injection well Much of this is already in existing regulations, such as 30 CFR 195, 254. Can refer to naturally occurring gas seeps on the seafloor as examples for what could be possible outcome. Also want to consider worst-case scenario discharge event. We will want to refer back to Subtopic 2 in this section..
Construct subsurface model
Ascertain regional geological setting. The regional geological setting describes the megascopic scale heterogeneity. The geologic province, sub-province, and formations are determined and described during the analysis of the regional geologic setting. The goals of this step are to determine regional stratigraphy and structure and to Characterizing regional aquifers. This scale of analysis sets the basis for detailed characterization of injection zone. Steps needed for this analysis include: 1. 2. 3.
Perform literature search Data collection Obtain stratigraphic column
4.
5. 6. 7. 8. 9.
Choose major formation boundaries some of which should be targeted as maximum flooding surface shales and/ or what may be a regional seal. Generate type logs noting the character of picks and lithology Obtain/Construct regional cross sections (integrate log and seismic data) Map structure of major formation boundaries Construct isopach maps on potential seal zones Demarcate dominant facies distributions , .g., clastic-rich in updip areas, carbonate- or shalerich in downdip areas; proportion of shale increases toward the south…etc. A % Facies-type map would capture this.
A typical result of evaluating the regional geologic setting is the construction of a map integrating the known elements, an example of which is provided below.
Delineate site’s reservoir architecture
Data needs for analysis of the regional geological setting are: 1. Previous basin studies 2. Regional tectonic maps 3. Previous reservoir studies 4. Previous production data 5. Stratigraphic column 6. Final base map of basin including cuural, geomorphic, and well locations 7. Seismic data 8. Paleontological data 9. Cores and core analysis 10. Digital well logs
Determining reservoir architecture is the first step in reservoir characterization. This step consists of four basic tasks. Reservoir architecture is determined from analysis of the core, well log, and seismic data. Establishing a reliable, high - resolution, internal reservoir stratigraphy of time-equivalent genetic units that weredeposited during discrete episodes of general tectonic, climatic, and/or base-level stability, and their bounding surfaces is the important starting point that allows quantitative facies mapping of the framework reservoir sandstones. Determining reservoir architecture is a four step process that combines all aspects of geological analysis (see below).
Data should be integrated in order to fully appreciate the geologic setting. Examples of characterization data are shown below. Determine fluid and rock-fluid properties Several technical issues must be addressed to make sequestering CO2 in brine-bearing aquifers a viable option. The most critical issue is to have the CO2 sequestered in such a way that it reaches permanent residency within the subsurface rock in which it is injected. Permeable strata and leaky faults could cause CO2 to migrate back to the surface if the CO2 resides in the rock as a mobile phase. Mineral trapping and solution into brine are two mechanisms that show promise in achieving permanent sequestration. However, if the CO2 were to reside within the rock as an immobile (residual) phase, permanent sequestration could be achieved quicker and at greater volumes.
Construct a subsurface model Constructing a reservoir model by the integration of reservoir architecture with established fluid-flow trends is a critical step in reservoir characterization and forms the basis for testing and interpreting the working hypothesis of reservoir architecture. The goal is to determine which geological architectural elements control fluid-flow movement and therefore define the model framework compartments and flow units. The initial task is to design petrophysical models at the scale where geologic architecture controls fluid flow in the reservoir. The second task has two concurrent subtasks: (1) identifying correspondence between stratigraphic-unit geometries, structural setting, and fluidflow trends and (2) establishing reservoir model framework (compartments and flow units). The goal of this step is to determine what portion of the stratigraphic and structural heterogeneity is influencing fluid flow within the reservoir. The third task, determining distribution of petrophysical properties within the reservoir, has traditionally been accomplished by summing or averaging calculated properties at the wellbore and then mapping them in two dimensions.
However, greater computing power allows the distribution of petrophysical properties to be modeled in three dimensions; therefore, little or no averaging of the wellbore data is needed. In addition, the inter-well property distribution is being accomplished either by deterministic or by stochastic methods. The final result of a subsurface model is a static gridded geocellular framework with populated geologic properties. ACKNOWLEDGMENT We would like to acknowledge the DOI BOEM for funding this project and NOPP for funding travel to this meeting. Preliminary work presented here represents input from project team members and GCCC colleagues not listed as authors, especially Mr. David Carr and Ms. Vanessa Nunez REFERENCES [1] http://www.beg.utexas.edu/gccc/miocene/ [2] http://www.nytimes.com/2009/04/18/business/energyenvironment/18clean.html?_r=3 [3] House et al., 2006 [4] BOEM, 2010 [5] Element Energy (2010)
