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Potential Environmental Impacts of the Proposed CIRI Underground Coal Gasification Project, Western Cook Inlet, Alaska
Prepared for: Center for Science in Public Participation 224 North Church Avenue Bozeman, MT 59715
Prepared by: Stratus Consulting Inc. PO Box 4059 Boulder, CO 80306-4059 303-381-8000 1920 L St. NW, Ste. 420 Washington, DC 20036 Contacts: Cameron Wobus Kaylene Ritter
Cook Inlet Region, Inc. (CIRI) has proposed a combined underground coal gasification (UCG), onsite power generation, and carbon capture and sequestration (CCS) project on CIRI-owned lands on the west side of Cook Inlet, Alaska (the site). Because the project is in an early phase of development, information describing the specifics of the CIRI project is limited at this time. In particular, the site geology has not yet been well characterized; the particular coal seams targeted for gasification have not been described; and the locations of carbon sequestration repositories have not been identified. Despite the lack of specificity surrounding this particular project, there are general environmental risks associated with UCG and CCS, many of which may apply to this site. Stratus Consulting was retained by the Center for Science in Public Participation to summarize the potential environmental risks associated with UCG and CCS in general, and the CIRI proposed project in particular. This document provides a summary of these general and sitespecific issues to the extent possible given currently available site information. Many of the risks and potential adverse impacts discussed herein are common across UCG and CCS. While both technologies are relatively young, there is a greater body of literature on CCS than UCG. We have summarized the risks for each technology here separately, based on the available literature on each technology. Some of the more detailed information currently available in the literature on CCS risks and summarized here, associated for example with wells, faults and fractures, is also likely applicable to UCG operations. This report is organized as follows:     The remainder of Section 1 provides an introduction and brief overview of the proposed project, as well as a general summary of the proposed technologies Section 2 provides a summary of the potential environmental risks associated with UCG, along with a review of lessons learned from pilot projects around the world Section 3 summarizes the potential environmental risks associated with CCS, with examples from pilot projects around the United States and the world Section 4 summarizes the limited information available on CIRI’s proposed project, as well as an overview of relevant general geologic information about the project area
approximately 60 kilometers west of Anchorage and north of Tyonek (Figure 1). such as injection into deep saline formations (DSFs). CIRI has proposed that this carbon would be sequestered via a process referred to as enhanced oil recovery (EOR). which generates a combustible gas product that can extracted and used for power generation.Stratus Consulting
 
Section 5 provides an overview of general environmental monitoring strategies for UCG and CCS implementation Section 6 provides a summary of recommendations. subsequent communications with CIRI have indicated that they are likely to consider other options for the CCS component of the project. The combination of the two technologies at a single commercial-scale site would be the first project of its kind in the world.
. Onsite construction of a 100-MW combined-cycle power plant that will be fueled with the gas product generated by UCG.
1. UCG of subsurface coal seams. in which CO2 is pumped into declining oil reservoirs to enhance the flow of oil to existing petroleum production wells. Capture of a portion of the carbon dioxide (CO2) generated by the entire process. Although details of the project remain limited at this time. the CIRI proposal generally contains three major components: 1. including a synthesis of site assessment and environmental monitoring requirements that should be implemented if the project proceeds beyond its current feasibility phase. and sequestration of this CO2 underground where it will not contribute to global carbon emissions. the possibility for success as a commercial venture and the type and extent of environmental impacts are largely unknown. Though their original plan outlined carbon storage via EOR.1 Overview of the Proposed Project
CIRI’s proposed project is located within the Susitna lowlands region of Alaska. While the combined approach holds promise as a “green” fossil fuel project.
1. UCG involves oxidizing coal in place by injecting air or oxygen into the subsurface. 3.1
Both UCG and CCS are emerging technologies. and commercial scale implementation of each has occurred at only a small number of sites around the world.
2009. Air or oxygen is pumped into a subsurface coal seam through an injection well. CO2 can be separated from the syngas stream prior to combustion and collected for CCS.g. Clean Air Task Force. A schematic of the UCG process is shown in Figure 2.Stratus Consulting
Figure 1. referred to as syngas (short for “synthesis gas”). Friedmann. and smaller amounts of CO2 and methane (e. Friedmann. which generates a combination of hydrogen and other gases.
Environmental Risks of UCG
2.1 The UCG Process and Overview of Environmental Risks
The UCG process involves oxidizing subsurface coal seams. 2009).
. carbon monoxide. 2009. which partially combusts the coal in-situ and creates the syngas product (Clean Air Task Force. 1985.
2. The syngas generated by the UCG process is primarily composed of hydrogen.. CIRI exploration location map. The syngas is extracted from the UCG burn cavity by a production well.. which brings the gas product to the surface to be burned. 2009). Stephens et al. The introduction of an oxidizing gas produces heat.
two main environmental risks have thus far been associated with the UCG process. and may create detrimental changes in surface or groundwater hydrology above the cavity. These organic and metal contaminants could migrate and contaminate groundwater aquifers. because the in situ burning of coal creates cavities in the subsurface. whereby the overlying rock layers partially collapse into the newly created void space. Second. surface disturbance is minimized relative to the disturbance caused by conventional mining. and the in situ gasification of coal allows many of coal’s potentially hazardous combustion products and leachable contaminants to remain in the ground. and trace metals in the coal may be released through geochemical reactions induced by the UCG process. p.
. Based on a limited number of pilot projects in the United States and a small number of full-scale operations worldwide. the process still creates environmental risks. UCG process. Organic contaminants such as polycyclic aromatic hydrocarbons (PAHs) may be generated during combustion of coal. UCG has a number of potential environmental benefits. Contaminants may also be released from adjacent geologic units. however.Stratus Consulting
Figure 2. Subsidence creates a hazard for any surface infrastructure that might be present above the UCG zone. In particular.
Source: Walter. Despite these potential benefits. First is the risk of groundwater contamination.
When compared to conventional coal mining. there is a risk of ground subsidence. 15. 2007.
sensitive ecosystems or species.. and metals and metalloids such as mercury. In addition.. 2. Rock units immediately adjacent to the targeted coal seam will also likely be influenced by UCG operations. there is the potential for the oxidation reaction to migrate beyond the target zone or become uncontrolled.2. which may be present as metal sulfide impurities in the coal (e. and human health and infrastructure. because all of the combustion occurs in the subsurface where it is difficult to monitor. Evaluating each of these risks requires an understanding of the subsurface geology. Uncontrolled migration and leakage of the syngas itself could result in contamination of overlying aquifers.g. and they can also be released as gases during the coal gasification process (Liu et al. 2000). the geologic factors that will influence the migration of any contaminants generated.2 Groundwater Contamination
One of the most important potential adverse environmental effects related to UCG is groundwater contamination. For example. and how these risks can be mitigated. 2004. arsenic. geochemical. by-products may be inadvertently generated from the coal during the UCG process. Mercury.. and selenium. including the structural integrity. These products may include organic contaminants such as PAHs. Their release could adversely affect water quality and air quality in the underground and on the surface depending on the temperature of the reaction. and benzene. uncontrolled migration and leakage of syngas to the surface could result in adverse impacts to local ecosystems and human settlements. The geologic units surrounding the seam may also be sources of contaminants.. Skousen et al. boron.Stratus Consulting
In addition. and hydrologic properties of the targeted coal seam and rock units surrounding the targeted coal seam. there are other potential adverse impacts to human health and the environment associated with UCG.1 Potential sources and types of contaminants
There are different sources and types of contaminants that may be associated with UCG operations. as well as inorganics including sulphate. arsenic. and selenium are volatile metals/metalloids. Evaluating risk also requires characterization of potential subsurface and surface receptors. and the presence of pathways from the coal to the surface. Here we describe the potential sources of contamination. oxidation and other geochemical processes in the surrounding rock could also result in
. Sury et al. contaminating surface water and/or air. 2006). such as groundwater and surface water resources. and thus. the type of geochemical reactions occurring during the gasification process.
2. phenols. Contaminants released from the coal and adjacent geologic units during the UCG process could also be released at the surface. Finally.
The types of contaminants potentially released as a result will depend upon the mineralogy and trace impurities of the surrounding rock. Note that fault and fracture zones are complex. Sealed faults and fractures may be re-opened as a result of UCG operations. or by the dissolution of minerals along fracture zones due to the geochemical conditions created by the UCG operations. Sury et al. If present. UCG injection and capture wells. thickness. and lateral continuity of surrounding rock units that separate the coal seam from any nearby aquifers. Key hydrogeologic factors that will determine whether or not groundwater becomes contaminated include the hydraulic conductivity (permeability). Physical properties of the rock. since the partial combustion of coal creates a cavity in the subsurface (see Section 2. or induced faults that can create new conduits for fluid flow. partings between geologic strata.Stratus Consulting
the release of contaminants. and their behavior under the conditions imposed by UCG operations may be difficult to predict. will influence the potential for induced fracturing. existing wells and boreholes associated with previous exploration. Fractures may also be re-opened by the pressure created as a result of the injected air/oxygen and the formed syngas. and the presence of fractures or faults that may create conduits for fluid migration out of the reactor zone. The potential for these induced fluid migration pathways to allow contaminant migration out of the UCG zone must be evaluated based on available geologic information. as well as pressure changes induced by UCG operations. well materials must be resistant to the potentially corrosive conditions created in the subsurface during operations.2 Factors that may influence the potential for groundwater contamination
Fully characterizing the groundwater systems surrounding the targeted coal seam is crucial for evaluating the potential for groundwater contamination from UCG activities. In order to maintain well integrity. 2. if not properly completed.3). or if the well materials have degraded over time. Transmissive faults and fractures are capable of transmitting gases and/or fluids. and oil and gas operations.. 2004). the process can create fractures. there are a number of factors related to the UCG process itself that can influence the migration of contaminants from the reactor zone.
. may also act as conduits for contaminants (Sury et al. In particular. Faults and fractures may be transmissive or sealed. and thus may also act as contaminant pathways. (2004) present a flow chart for evaluating the hydrogeologic setting of a proposed UCG project (Figure 3). may also act as contaminant pathways to groundwater aquifers if they are not properly plugged and sealed. and thus may act as direct contaminant pathways to groundwater aquifers from the UCG zone. Note that in addition to pre-existing hydrogeologic conditions such as the permeability and lateral continuity of confining layers.2.
1.Stratus Consulting
Figure 3. Concept for the general hydrogeological evaluation process.
Source: Sury et al. Figure 4..
Thus. UCG pilot projects in shallow seams and without careful reactor pressure control such as at Hoe Creek. In practice. 2007). these induced groundwater circulations can help to spread contaminants from the burn zone into overlying aquifers. where reactor pressure has been controlled to be lower than ambient pressure. appears to have had no escape of contaminated groundwater to its surroundings. ensuring that the UCG reactor zone pressure is lower than the ambient (hydrostatic) pressure should create inward hydraulic gradients. groundwater contamination is likely to be one of the most significant environmental concerns related to the UCG process. 2.g. In addition to geological controls. engineering controls are also important in limiting migration of contaminated groundwater from the reactor zone. Burton et al.g... 2007).. Walter. For example. 2008). 2007). were plagued with significant groundwater contamination issues (e. are likely to be more appropriate technical considerations. In summary.2. the Chinchilla project in Australia.. In particular.g. Shafirovich et al. Experience suggests that maintaining a reactor pressure lower than hydrostatic pressure may be one effective means of avoiding groundwater contamination issues (e. 2008). so that groundwater is flushed into the reactor rather than out of it.3 Mitigating groundwater contamination risks
Recommendations for groundwater protection have included ensuring that drinking water aquifers are at a distance of more than 25 times the seam height from the reactor (e.. which can generate rising plumes of potentially contaminated groundwater (Walter.Stratus Consulting
Finally.. detailed characterization of the hydraulic properties of the geologic units surrounding the reactor zone and an understanding of the hydrogeology of potential drinking water aquifers in the region. Groundwater models have been developed which suggest that heating in the reactor zone can create convection cells in overlying units.g. there may be conflicts between controlling gradients to minimize risk of groundwater contamination versus producing a more energy-rich product. Shafirovich et al. One potential problem with maintaining low reactor pressures is that higher pressures and temperatures create a higher methane content in the gas and therefore a more energy-rich product (e.
. Combined with the potential for fractures created by the collapse of the UCG burn cavity. A combination of careful site selection and proper engineering controls is essential to limiting groundwater contamination from UCG sites.. In contrast. Wyoming. conditions created by the burn itself may influence the potential for the spread of contaminated groundwater.
.g. deeper UCG projects in the United States and elsewhere have had fewer problems with surface subsidence (Burton et al.. subsidence occurred at the Hoe Creek pilot study.
.X. Burton et al.g. Burton et al. To minimize the risk of subsidence. The problem of surface subsidence related to UCG projects is analogous to subsidence related to subsurface coal mining operations.g. Burton et al.. Creedy and Garner. some commercially available software packages can also be adapted to evaluate subsidence risks for particular settings (e. 1977. 1993.. Other modeling frameworks have been developed to evaluate the potential for induced subsidence from evacuation of subsurface cavities (e. A modeling study by Dr. In addition to the width and depth of the cavity. In practice. Laboratory analysis of the geotechnical and thermal properties of the overburden and the coal are required to characterize the risk of surface subsidence. the overlying rock column is more likely to accommodate some of the resulting strain. 2007). Modeling studies also indicate that deeper coal seams will result in lower surface subsidence: as the depth of the cavity increases. (2007) suggest that coal seams targeted for UCG should be deeper than 200 meters (m). and the degree of fracturing of the overburden.. there may be no way to prevent collapse of the burn cavity itself during UCG operations. as a result. 2007). This recommendation appears to be based on a combination of experience from pilot studies and modeling constraints. Shu and Bhattacharyya.. resulting in a broad warping of the ground surface that will be more subdued for deeper UCG cavities (e. However. Shu and Bhattacharyya. These voids can result in subsidence of the land surface above the UCG reactor zone. For example. 2004) indicates that while the mechanical properties of the overburden are important in controlling collapse and subsidence. 2004).g. there is a well-developed literature on the physical parameters controlling the magnitude of subsidence that might be created by UCG projects (e. The factors controlling the amount of subsidence generated by the collapse of subsurface cavities include the depth and width of the subsurface cavity. the geotechnical properties of the overlying rocks (overburden). 1993). T. Ren (Appendix E of Creedy and Garner. An analytical model by Shu and Bhattacharyya (1993) suggests that the primary control on surface subsidence is the ratio of cavity width to depth. 2007). the thermal and mechanical properties of the coal seam itself also play an important role in controlling cavity growth.Stratus Consulting
2. where the target coal seam was approximately 10-m thick and only 4050-m deep.. physical properties of the overlying rock column can mitigate the effects of cavity collapse at the land surface. Thus wide and/or shallow cavities are the most likely to induce significant subsidence at the surface.3 Subsidence
Combustion of underground coal seams and removal of the resulting syngas creates void space in the subsurface. Gregg. the physical properties of the overburden and the coal seam will also be important in controlling the degree of subsidence at the surface.
more than 25 times the seam thickness from the nearest drinking water aquifer). subsidence will clearly present an engineering concern. Another potential environmental concern related to UCG is the relative lack of control on reaction rates in the subsurface. Subsidence can also have detrimental ecological effects. gas leakage to the surface and the potential for uncontrolled reaction rates appear to be the most significant concerns. vegetative die-off. mercury.
2. proper siting of a UCG project to minimize risk of contaminant releases or subsidence requires the following information:
. Parameters such as the rate of cavity growth or water influx to the burn zone cannot be controlled with existing technology. there are additional environmental concerns that should be addressed when designing a UCG project. and flow patterns in the subsurface.
2. such as creating depressions that may collect water. there is no substitute for site-specific geological information. Furthermore. The impacts of subsidence will depend on site-specific attributes. Volatilization of metals and metalloids such as arsenic..g. the only engineering control on reaction rate is the rate of gas injection. it is possible that even the rate of gas injection could become difficult to control. but could include asphyxiation. or power generating facilities. Of these. to the extent that UCG induced fracturing could provide pathways for increased air intrusion to the reactor zone. As a result. or altering groundwater recharge. which must be evaluated prior to initiation of a UCG project. or they could occur as a result of induced fractures created by subsidence (Gregg. As noted by Friedmann et al. buildings. 1977). or selenium.4 Other Environmental Risks
Although groundwater contamination and subsidence are most often cited as the primary environmental risks associated with UCG. discharge.Stratus Consulting
If the UCG zone underlies any significant infrastructure such as roads. more than 200-m deep. there is the potential for the generation of uncontrolled burns in the subsurface. or acidification of surface waters.5 Site Characterization and Monitoring Needs for UCG Projects
Although many authors have proposed “rules of thumb” for the proper siting of UCG projects (e. could also create toxic conditions if these volatile compounds migrate to the surface. At a minimum. Gas leaks to the surface may occur through pre-existing faults or fractures. if they occur. The potential environmental risks associated with a gas release will depend on the nature of the gas and the ecological resources present at the surface. capturing flow from rivers and streams. (2009).
so that their lateral continuity and relationship to overlying materials can be inferred based on geological constraints.. with particular attention paid to whether faults/fractures are sealed or transmissive Evaluation of existing wells and boreholes. such as sulfides. exploratory boreholes and downhole geophysical measurements should be tied to seismic lines to enable a complete characterization of the lateral continuity of coal seams and surrounding aquifers and aquitards. (2007) also stress the importance of understanding the depositional context of coal beds targeted for UCG. including depth. Empirical data from seismic lines and boreholes should therefore be coupled with an understanding of the depositional environment of the target coal seams. and horizontal and vertical hydraulic conductivity Laboratory analysis of the thermal and mechanical properties of the target coal seams and overlying stratigraphy. with particular attention paid to the potential size and spatial extent of the burnout area from UCG Geochemical and mineralogic characterization of the coal seam and host rock to evaluate potential contaminants of concern. or other trace impurities A pilot burn test of samples from the target coal seams that would identify the gases produced by UCG Identification and characterization of groundwater aquifers in the subsurface. thickness. and continuity of confining layers and overburden Characterization of the physical nature of the coal seam.
. Burton et al. including a consideration of the lateral continuity. and permeability. width. metalloids. and stability under UCG-imposed conditions. to enable an evaluation of the potential risk of subsidence resulting from UCG burnout Evaluation of existing and potential faulting in the area. because this basic geologic framework can be used to evaluate the lateral extent of coal seams and their connection to surrounding permeable units. coal seams deposited in tidal environments may be more laterally continuous than coals deposited along floodplains. metals. minor. permeability. porosity. their location. and the integrity of well construction and sealing/plugging materials. depth. groundwater flow directions. including their chemistry (e.g. and the overlying stratigraphy may also be more predictable based on basic principles of sequence stratigraphy. and trace). major. heterogeneity.Stratus Consulting
Characterization of the geologic units above and below the target coal seam. For example.
In order to properly characterize the subsurface stratigraphy.
Geologic Sequestration Systems
According to U. geologic sequestration (GS) systems for CCS consist of an injection zone and an overlying confining system. including humans.
3. The injection zone is a geologic formation or group of formations that are targeted for CO2 injection.. The primary risks of CCS relate to unanticipated or uncontrolled releases of CO2 from the sequestration zone. the following monitoring requirements should be considered:     The pressure in the burn cavity should be monitored and managed to ensure that hydraulic gradients are directed inward. Like UCG. loss of CO2 from the sequestration zone also negates the intended environmental benefits of the process. however. In addition. The combination of UCG and CCS technology may therefore become common.
Environmental Risks of CCS
Conceptually. radar interferometry. allow for greater storage of CO2 and are preferred injection zone materials. and (2) CO2 can be relatively easily and economically separated from the pre-combustion gas stream. EPA (2008). Formations with relatively high porosity and high permeability.S. since (1) coal seams are commonly located in the types of sedimentary environments where formations suitable for CCS are found. and/or high-resolution differential global positioning system (GPS) should be used to monitor for subsidence at the surface Gas detection monitoring should be implemented to detect any surface leakage of syngas that may occur. These artificially high pressures create a tendency for the injected CO2 to diffuse out of the injection zone. since CCS is designed to mitigate climate change risk. To maximize storage capacity. In addition. the CO2 is compressed and injected as a supercritical fluid. to detect any contaminant migration from the burn cavity Tiltmeters.
3. CCS also has a number of technological challenges and environmental risks that need to be carefully addressed. at the land surface. The environmental risks associated with such releases range from acidification of groundwater aquifers to asphyxiation of biota. the injected CO2 will have a tendency to rise due to
. compared to post-combustion separation (Friedmann et al. 2009).Stratus Consulting
If site characterization data demonstrate that the environmental risks of the project can be managed and the project proceeds. UCG may be well-suited to CCS. such as sandstones. to minimize groundwater flow out of the cavity Groundwater in surrounding aquifers should be sampled and monitored regularly.
EPA. preferential adsorption trapping. additional trapping mechanisms can occur to sequester the CO2.1. and formations targeted for enhanced oil and gas recovery). The confining system.Stratus Consulting
the relative buoyancy of supercritical CO2 compared to the native fluids (e. Mineral trapping occurs when the CO2 reacts with the injection zone rock and/or fluids to form solid minerals. Thus. it occurs relatively slowly compared to the other mechanisms [see IPCC (2005) and U. also sometimes referred to as a caprock. These formations are found in subsurface sedimentary basins and are deep enough (800–1. In this section. These include residual CO2 trapping. and will tend to sink. Although mineralization is the most permanent trapping mechanism in GS systems. 3. a physical stratigraphic trap that inhibits the upward migration of CO2. the types of geologic settings being considered for CCS. provides one of the most important trapping mechanisms. 2008). oil and gas reservoirs (both depleted formations. brine or saline water) present within the injection zone.S. regulatory considerations. DSFs are sedimentary geologic units in which the pore space between the formation rock is filled with saline (salty) water. Within the injection zone. 2005. Solubility trapping can occur as a result of the dissolution of CO2 into the fluid inhabiting the pore space of the geologic formations (e. Residual CO2 trapping occurs when the CO2 is retained by capillary forces in some of the pores of the injection zone geologic formation(s). U. The fluids become denser as a result of CO2 dissolution. saline water). a brief summary of current CCS operations. 3. The role of the confining system.000 m) to achieve pressures that will keep the CO2 in its compressed.g.2 Geologic settings under consideration for GS
There are a number of different types of geologic settings under consideration for sequestration. lowpermeability geologic formations such as siltstones or mudstones that are thick and laterally continuous are preferred formations for confining systems (IPCC. is to prevent the upward migration of the injected CO2.g.1 GS CO2 trapping mechanisms The CO2 is retained in the injection zone through a combination of different trapping mechanisms. and mineral trapping. CO2 trapping through preferential adsorption occurs when CO2 adsorbs to certain geologic materials such as coal and shale that have a high affinity for CO2.
. and potential risks and adverse impacts associated with CCS...1. These include deep saline formations (DSFs). thus further entraining the CO2 in the subsurface.S. EPA (2008) and references therein for more detailed descriptions of these trapping mechanisms]. we describe the mechanisms at play to keep CO2 sequestered in the subsurface. and coal seams. dissolution trapping.
and thus storage capacities are somewhat uncertain. demonstrating the potential ability to store CO2 and other fluids in the subsurface. such as volcanically deposited basalts. Other geologic settings.000 and 3. However. 2005.Stratus Consulting
supercritical phase. However. as a result of extraction activities. Oil and gas fields have stored oil and natural gas for hundreds of thousands to millions of years prior to resource extraction. CO2 accumulates underground naturally in a variety of geologic settings. However.g. Coal seams have also been suggested for GS. the estimated CO2 storage capacity associated with EOR sites is 90 billion tons (NETL. These reservoirs are typically very well characterized. Both depleted oil and gas fields. and DSFs are believed to have the greatest capacity for sequestration. because the penetrations could be conduits for CO2 leakage (Celia et al. 3.. CO2 is also used in some reservoirs to enhance the extraction of natural gas. There are many very large sedimentary basins across the United States. IPCC. 2005).. and may be overly optimistic. Similarly. NETL. which could then be captured for extraction. could potentially be transitioned to GS.700 billion tons of CO2 (NETL. Because of coal’s high affinity for CO2.. and are thus believed to be good potential candidates to store CO2 for long periods of time (Benson et al. these settings may be attractive candidates for immediate implementation of CCS. and EOR sites.. The National Energy Technology Laboratory (NETL) has estimated that DSFs may have the capacity to store between 1. According to NETL. Heller. 2007).
. and thus restrict further CO2 storage (Haszeldine.3 Natural and industrial analogs and existing CCS operations
Natural and industrial systems that have stored CO2 and other fluids (e. geologic repositories such as salt caverns. 2007). these formations are typically penetrated by many wells and boreholes. such as oil and gas fields. which is disadvantageous to GS. the sequestration of CO2 in coal beds may be challenging. 2006). gases such as natural gas) may provide analogs for GS. 2006. in a process called EOR. This is much smaller than the estimated capacity of DSFs.1. 2002. Thus. oil or gas-rich shale. for further discussion of these other settings). because coal’s high affinity for CO2 may displace methane present in the coal beds. because much of the needed infrastructure and CO2 injection technology is already in place. However. and abandoned mines may also be considered for GS. the small-scale fractures (cleats) that allow fluid flow through coal seams can become plugged as a result of CO2 adsorption. CO2 may be stored in coal beds through adsorption to the coal surface. 2007). but are not currently major focuses (see IPCC. compared to the other settings under consideration (Dooley et al. which is advantageous for their use to store CO2. 2004. 2005). CO2 is currently injected into some reservoirs to enhance the extraction of oil. CO2 may also enhance the extraction of methane from coal beds (enhanced coalbed methane). they are typically less well characterized than other settings.
Frio Brine Experiment (Texas). Currently operating commercial projects include the Sleipner project in the North Sea (Norway). These sites do provide some evidence that with careful management. 200 million metric tons of naturally occurring CO2 have remained trapped in the Pisgah Anticline in central Mississippi. and the In Salah Gas Formation project (Algeria). see NETL’s CO2 Storage website (http://www. confining systems can be exposed to repeated stress cycling (i.. 2005). and monitoring injected supercritical CO2 (Benson et al. 2005).uk/ccsmap).netl. such projects are designed to maximize oil production. Heinrich et al. DOE (2010) for a summary of this program].html) and the Scottish Centre for Carbon Storage website (http://www. While these operations demonstrate that fluids and gases can be stored in the subsurface.ed. the U.e. northeast of the Jackson Dome.gov/technologies/carbon_seq/core_rd/world_projects. and the currently underway regional projects supported by the U. depressurizing and pressurizing) without adverse effects on seal integrity. 2005). Department of Energy’s (DOE’s) Regional Carbon Sequestration Partnerships Program [see U. For a more comprehensive list of current and planned GS projects in the United States and around the world. Australia) and other potential sites in Europe and the United States. The oil and gas industry has engaged in this practice for nearly 100 years (IPCC.S.S. However.Stratus Consulting
and there are numerous natural analogs that demonstrate the long-term trapping of CO2 in the subsurface. pre-existing leakage pathways through the confining system.doe.
. Furthermore. and thus provide rather limited insight into the long-term storage of CO2 in the subsurface.. which may support the use of depleted oil and gas reservoirs for CO2 storage. or leakage at improperly sealed or plugged wells (Perry. Additional commercial GS projects that are in the planning stages and are anticipated to be underway in the near future include the Gorgon Joint Venture (Barrow Island. EOR has been practiced for over 35 years. For example.ac. either due to induced fracturing caused by application of excessive pressures to the formations.. 2007). As mentioned above. the oil and gas industry also has experience in the injection of CO2 through enhanced product recovery projects. for more than 65 million years with no evidence of leakage (IPCC. There are also a number of smaller-scale research field experiments that have recently been conducted or are underway at sites in the United States and internationally. and these projects contribute substantial knowledge about the design of CO2 injection wells and technologies for handling. 2003. these sites are generally used for temporary storage and hence do not provide insight into the long-term feasibility of underground storage of fluids and gases. IPIECA. there have been several instances of documented leakage of natural gas to the surface. Examples include the CO2 SINK Ketzin site in Germany. Industrial analogs include the practice of injecting and temporarily storing natural gas in underground reservoirs. While few in number. currently operating pilot and commercial CCS projects have thus far demonstrated that CCS can be successfully implemented. 2002. injecting. Experience from these natural gas storage operations is mixed.S. the Weyburn EOR project (Canada).geos.
According to the U. and influences of neighboring projects. and the regulations are designed to ensure that injected fluids do not endanger USDWs.1. Environmental Protection Agency (U. Full commercial-scale deployment of GS will also involve injecting much larger volumes of CO2 than currently operating projects. and semisolids). EPA (2010). current projects likely do not demonstrate the full range of scenarios that may be encountered in commercial-scale deployment. and thus experience adverse pressure effects that can cause fracturing or other adverse impacts. GS of CO2 through well injection meets the definition of “underground injection” in Section 1421(d)(1) of the SDWA. The U. EPA) Underground Injection Control (UIC) program regulates the injection of fluids into the subsurface (including liquids. pilot projects can nevertheless provide useful information. territories.S.S. and began in 1996). and thus may be more likely to:  Encounter geologic heterogeneities that may serve as CO2 leakage pathways.
. EPA.S. the U. states.Stratus Consulting
Operating commercial and experimental projects have demonstrated thus far that CO2 can be injected and sequestered in geologic formations. and tribes that have primacy for UIC programs (“Primacy States”) act as co-regulators to protect USDWs from any potential endangerment from underground injection of CO2.
However. Because of their smaller scale. or potential anthropogenic pathways such as unplugged wells and boreholes Face challenges regulating pressure. such as the displacement of brine into overlying aquifers.S. Specifically. For example. and hence do not yet demonstrate the long-term storage of CO2 in the subsurface over required storage time periods of hundreds to thousands of years.S. 3. these sites have been operating for only a relatively short period of time (Sleipner is the longest running operation. particularly if multiple projects are implemented and evaluated across a variety of geologic settings. gases. or regional effects on groundwater flow Encounter basin-wide effects. including faults and fractures.4 Regulatory framework for CCS
Federal and State regulations address the injection of fluids into the subsurface for the protection of underground sources of drinking water (USDWs). and the U. commercial-scale GS projects will encompass areas that may be miles in diameter (as opposed to for example the small fraction of a mile encompassed by most DOE pilot projects). EPA has authority for underground injection under the SDWA UIC program. However. under the Safe Drinking Water Act (SDWA).
S. 2005). 2005. 2007). their stratigraphic position with respect to the confining system. The applied injection pressures may also induce fracturing or reactivate faults. The Proposed Rule describes a new class of wells for the regulation of CO2 injection. EPA’s website (http://www. their orientation. and their geometry with respect to the applied pressures. well construction.2 Potential Risks and Adverse Impacts Associated with CCS
The main environmental risks associated with CCS are related to the potential for leakage from the GS formation. Identifying and evaluating abandoned wells may be particularly challenging in some geologic settings.Stratus Consulting
In July 2008. the U.html) for the history and current status of the Proposed Rule. Such wells may also act as pathways for brines to contaminate overlying freshwater aquifers. Experience from other analogous injection projects (such as those used in oil and gas operations) has shown that leakage from the injection well itself. See U. 2005). These include the level of applied pressure. Faults and fractures may also be induced if the GS system is overpressurized
. Benson. and site closure. is one of the most significant well failure modes (Benson et al. Carey et al. or potentially causing changes in groundwater flow directions.. Wells (and other artificial penetrations such as boreholes) have been identified as one of the most probable conduits for the escape of CO2 from GS systems (Gasda et al. whether they are sealed or transmissive. such as depleted oil and gas fields.. the GS injection and monitoring wells themselves need to be properly constructed and operated in order to avoid leakage of CO2. 2004. Furthermore. and fracture zones. The potential for existing faults and fractures to act as fluid pathways in GS systems is a function of numerous factors. such as displacing large volumes of brine.S. as the acid generated when CO2 contacts water may degrade well construction materials over time (Scherer et al. such as the proposed CIRI site and southern Alaska in general.epa.
3. and may have other adverse impacts to the subsurface. and addresses issues related to siting. IPCC. EPA published a Proposed Rule for Federal Requirements for CO2 GS wells under the UIC program. or cement well materials. may be more likely to have transmissive faults and/or fracture zones. Even properly completed wells may pose a risk of leakage. If not properly sealed and plugged. Key attributes of GS systems that have been identified as particularly important when evaluating the potential risk of leakage of CO2 from the injection zone include wells.gov/safewater/uic/wells_sequestration. Tectonically active settings. wells and boreholes that were previously installed during exploration and resource extraction can be a direct conduit for CO2 to escape from depth to the surface. monitoring. faults. as a result of improper completion or deterioration of the casings. 2005. IPCC.. and other fluids such as brine. comparable to those described above for UCG.. 2002. and the potential for adverse impacts in the subsurface associated with the applied injection pressures. packing. and may be unsuitable for GS.
see U. 2002). EPA.S. careful site characterization. and the geosphere. 1998. Benson et al.S. The risk of injection pressure exceeding fracture pressure can be reduced through understanding the relevant geologic attributes. and the levels of exposure. and permeability of the confining system. such as brine) and changes in subsurface pressure caused by CO2 injection. groundwater and surface water. EPA (2008). There are numerous potential adverse impacts resulting from the leakage of CO2 (as well as other fluids. the proximity of the release to the receptor. However. surface-dwelling animals (Benson et al. such releases do reduce the climate benefits of capturing CO2.. 2007). 2008). 2005). for a more detailed discussion. EPA (2008):  Human health and welfare: Adverse health effects caused by CO2 can range from minor. and aquatic
. A number of factors affect exposure. reversible effects to mortality. or other harvested natural resources. groundwater and surface water. sudden). thickness. the physical capacity. 2002. 2002). The potential impact categories are briefly summarized below. injectivity and geochemical and geomechanical properties of the injection zone may also influence the likelihood of leakage. small releases of CO2 from GS may not adversely impact local environmental receptors (e. The potential for existing and induced fractures and faults to result in adverse impacts will depend on numerous additional factors. which could in turn result in adverse economic impacts to humans Atmospheric impacts: In some cases. forestry. Impacts are also affected by whether the release is acute but limited (in time or spatial extent) or chronic.S. 2002). ecological receptors.. whether they may be connected to other fluid-conducting pathways (such as wells). slow vs. fisheries. categories of receptors that could potentially be adversely impacted by CCS include human health and welfare.. including but not limited to the concentration and volume of the release. CEC. thus decreasing the overall effectiveness of GS as a climate change mitigation strategy.. humans). Furthermore.g. Resources that could potentially be impacted by CO2 leakage include mineral extraction. depending on the concentration of CO2 and the length of the exposure (Benson et al. careful operation of GS systems. The vulnerability of a GS system to these adverse impacts is a function of both the presence of the key receptors in the impact categories.. and whether or not they may be resealed by geochemical processes associated with GS (U. According to U.Stratus Consulting
during injection of CO2. and monitoring (IPCC. the rate of release (i. the atmosphere. plants (MeGee and Gerlach.. Saripalli et al. ecosystems. and wind or wave dispersion. Release of CO2 may also adversely impact recreational and economic resources by restricting access or use or by changing the quantity and quality of the resource.e. 1996. including whether the faults are connected to an overlying receptor. Additional factors that will influence the risk of CO2 leakage include the lateral extent. Ecosystem impacts: Leakage of CO2 could have adverse impacts on soil-dwelling animals and microbes (Sustr and Siemk.
As a result. 2007. 2008). there is the potential for unanticipated migration and leakage of injected CO2 and other fluids such as brine. Specific purposes for site characterization. such as dissolution. 2004. particularly calcifying organisms (Turley et al. which decreases buoyancy. or result in the desorption of metal and organic contaminants adsorbed to geologic formations (Jaffe and Wang.
3.S. Impacts could also include induced seismic activity. the dissolution of CO2 in the water can create acidity which can in turn dissolve metal-bearing minerals.. Geosphere: Changes in subsurface pressure from GS can have direct impacts on the local landmass itself. EPA. as well as the potential for adverse impacts caused by excessive pressure. 2004. This assumption is based on a number of factors.
In general. 2006. and improved characterization and modeling of the GS system over time (U. including earthquakes in the extreme case (Healey et al. 2003.Stratus Consulting
organisms. Pressure changes associated with injection of CO2 may also cause changes in flow directions in groundwater and surface water bodies and points of recharge and discharge (Nicot et al. The spatial area affected by pressure changes associated with injection will typically be significantly larger than the injected CO2 plume itself. 2007). site characterization and monitoring to evaluate potential risks are necessary components of GS projects. 2004). Particular attention may be required to address protected or endangered species if present. monitoring. IPCC. Birkholzer et al. 2007). the overall likelihood of adverse impacts is expected to decline over time at GS sites. 2007). including the greater permanence of secondary trapping mechanisms. Spicer et al. For example. and mineralization. Tsang et al.. 2005). and thus.. 1968) and land deformation through uplift (Quintessa.... The pressure-induced displacement of brine or salty waters into overlying aquifers can also negatively impact water quality. Wang and Jaffe.  Groundwater and surface water quality and quantity: Leakage of CO2 into aquifers can have detrimental impacts on water quality. 2004.3 Site Characterization and Monitoring Needs for CCS Systems
While experience from existing projects and natural and industrial analogs to GS demonstrates that CO2 can be safely sequestered in geologic formations. adverse impacts associated with pressure changes could potentially be experienced over very large spatial areas.. the anticipated return to pre-injection pressure conditions once injection stops in most cases. This may in turn negatively impact municipal water supplies. and can potentially result in the loss of USDWs. Miles et al. and the water balance of local ecosystems. Subsurface pressure changes that exceed the subsurface geologic formation’s geomechanical strength could cause fracturing or reopening of faults and fracture zones (Quintessa. and applicable technologies at CCS sites include:
and annually. For example. or to other sources. CO2 is ubiquitous in the environment. 2007. and anticipated monitoring needs during injection. targeted monitoring techniques if needed. WRI.. monitoring techniques can be tested and selected to target site-specific attributes (Benson et al. and could include seismic surveys. and detecting unanticipated leakage: The movement and fate of injected CO2 are influenced by injection-related factors. Benson. Available technologies to monitor that injection controls are handled appropriately include wellhead and formation pressure gauges. 2004. 2009. Determining background levels of CO2 and understanding natural fluctuations is necessary to discern whether detected CO2 is attributable to leakage from the GS site. 2009. During site characterization. Johnson. electrical measurements of subsurface conductivity/resistance. Freifeld et al. Confirming the quantity and location of injected CO2. and land surface deformation monitoring technologies (Benson et al. and thus measurements need to be taken prior to injection. During injection and site closure. 2009). Bacon et al. which can result in leakage. and spatially. 2005. many technologies.. tracers. properties of the CO2. and wellhead and formation pressure are important to verify the amount of CO2 injected and to avoid leakage. NETL. Ensuring injection controls. formation fluid sampling. atmospheric and soil gas monitoring technologies. Existing pressure gradients and gradients induced by injection can influence CO2 movement. Specific locations and site features should be identified and targeted for monitoring if they are known or suspected to have elevated risk of CO2 leakage and adverse impacts. 2008. and so techniques that measure the injection rate
. and concentrations vary diurnally. 2009). As a result. 2004. In addition. seasonally.Stratus Consulting
Establishing baseline conditions. core logging. Examples of technologies that may be applied include seismic imaging. IPCC. surface water sampling. such as seismic profiling. many different subsurface parameters may need to be measured to assess the location and quantity of the injected CO2. and properties of the GS formations. wellhead and formation pressure monitoring techniques.. Identifying and providing oversight of targeted locations and site features. The techniques selected to establish a baseline will be dependent upon site-specific conditions. and air and soil gas sampling. borehole logs. monitoring can help identify existing or newly developed risks and inform the application of additional. The specific type of monitoring technique to be used will depend upon the specific site characteristic that is being assessed. the injection rate. identify CO2 on a comparative basis. existing wells and faults should be targeted for characterization and monitoring because of their elevated potential to act as CO2 conduits. 2004).. pressure measurements at the wellhead and in the formation. Monitoring the condition of the injection well. temperature and fluid composition measurement techniques. and wellbore annulus pressure measurements (Benson et al..
2009. GAO. 2009. Site-specific receptors may also be targeted for monitoring. NETL. or USDWs.  Assessing environmental and human health impacts of leakage if they occur. Benson.. and sampling overlying hydrologic systems (Chabora and Benson. Resolving liability/legal disputes. 2008. 2009).
. 2009). such as minerals or oil and gas reserves. Other examples of techniques that may be used to confirm the location and quantity of injected CO2 include seismic surveys. monitoring for land surface deformation. Detecting induced microseismicity. were adversely impacted by injected CO2 that has migrated outside the target formation.. Microseismic activity may be induced by CO2 injection if pressures within the target zone are high enough to cause a release of accumulated strain on fault zones. Monitoring techniques can help assess the severity of adverse impacts by providing information on the amount of leaked CO2. and fluid and mineral sampling methods (Benson et al. Damages could be sought by parties that have an interest in the impacted resources from the legally responsible injector of the CO2. including sampling air using eddy covariance. 2009. such as electrical resistance tomography. using tracers (small quantities of a chemical compound or isotope added to trace flow patterns). electrical and electromagnetic methods. measuring productivity of local flora and fauna. 2009).. adverse impacts to the environment and human health can occur. Several monitoring techniques may be used to detect surface leakage. Darby et al. resistivity and other types of logging. infrared and other techniques. Bachu and Bennion. 2007. For example. Monitoring could potentially be used to help resolve disputes arising from unanticipated leakage of CO2. can be implemented.. such as sensitive or endangered species. Schwarz et al. Monitoring can assist with determining which injector is liable in the event that multiple injectors are in proximity to the damaged resources. 2007. liability disputes could arise if other underground natural resources. There may also be questions about the long-term liability and legal responsibility of leakage from sites after closure of operations. Bachu et al. sampling soil gas with soil gas probes.. Jones et al. 2009. so that mitigative actions. If CO2 leaks from the targeted injection zone. Monitoring can help recognize induced microseismicity. CCSReg. 2004.Stratus Consulting
and formation pressure gradients can help monitor CO2 in the subsurface. to ensure that they are not adversely impacted by unanticipated CO2 migration and leakage. such as reducing the injection pressure. gamma ray. if leakage occurs while one project is operational and a nearby project is in post-injection site care phase. the leaking CO2 could be emanating from either the closed or the currently operational project (Wilson et al. 2009.. Liability disputes could be complicated by the additional factor that projects can be in injection and post-injection site care phases at varying times.
At least one of the Cook Inlet producers.
.250 ft (Belowich.com/) and from the coastal management and exploration permit applications they submitted in late 2009 (Belowich. no details have been given as to the mechanisms of capturing or sequestering the CO2. or by re-injecting CO2 into the burn cavities left behind by UCG. The CIRI proposal indicated that CO2 would be sequestered via EOR.
4.org. has apparently already indicated that they are not interested in this project (AlaskaCoal. CCS could possibly be accomplished by GS into DSFs or other geologic settings. we have obtained general information about their plans from the website that they have set up for this project (http://www. recognizing that the details of their plans are not likely to emerge until after their exploratory drilling has been completed. and CIRI has since indicated that EOR may not be a viable alternative. 2009). however. Results from deep borehole exploration could also enable identification of potential CCS targets.500 ft. CIRI would need to partner with Cook Inlet oil producers to supply their carbon stream to existing oil infrastructure. the stratigraphy of the overlying geologic units. CIRI’s presentation of their proposed project indicates that the target coal seams for UCG will be more than 650 feet (ft) deep and will be isolated from freshwater aquifers by “strong and impermeable overlying rock layers” (CIRI. Chevron. In such case.000 ft. for EOR to occur.Stratus Consulting
4. 2009). however. and one to 1. there have been no details provided about the thickness of the coal seams targeted. 2009). three boreholes to 2. However.cirienergy. This section contains a brief description of their plans based on this information. 2009). CIRI’s exploration permit indicates that they plan to drill two deep boreholes to 2. Again. Beyond these generalities. The stated goal of these boreholes is to enable stratigraphic correlation across major faults and with stratigraphic information from an existing borehole on the site. CIRI also indicates that they will be capturing CO2 from their syngas stream using existing technologies. Either of these alternatives would require significant additional investigation into the geology of the targeted sequestration zones. or the quality and character of the coal beds themselves.1
CIRI Proposal and Study Site
Information on CIRI Proposal
Although the details of CIRI’s proposed project are limited.
More recent stratigraphic work by Flores et al. There are two major coal-bearing units present in the study area: the Beluga Formation. and the underlying Tyonek Formation.
.4 billion tons based on field mapping and aerial reconnaissance surveys. thus the courses of the rivers in which the coal beds were formed are likely to have been controlled by motion on this fault. suggesting a fluvial-estuarine depositional environment. thickness. The coal beds in the Tyonek Formation are typically thicker than those in the Beluga Formation: Some of the Tyonek Formation coals are as much as 5070 ft thick. A brief description of available geologic information is included here. and conglomerates of a generally nonmarine origin (Barnes. stratigraphy. Barnes (1966) estimated the coal reserves in the region at 2. and the Beluga Formation as a set of coalescing alluvial fans. (2007). Merritt.. this section describes the general geologic setting of the proposed project. which includes interbedded clays. 2009). a general understanding of the depositional environments of the coal beds targeted for UCG is one means of assessing their lateral continuity. Both of these Miocene (523 million year) units belong to the Tertiary-aged Kenai Group.g.1 Coal bearing units
The Susitna lowlands region is well known for its coal resources. 1966). boring logs and more detailed development plans from CIRI will be necessary before the relationships between coal beds. 1990.Stratus Consulting
4. Given the complex geological and structural setting of the proposed exploration area. Flores et al. (1997) indicates that some of the beds within the Tyonek Formation may also have been tidally influenced. Flores et al. and characteristics of coal seams that will be relevant to evaluating environmental risks of the project. their general geochemistry. as well as the role of faults in exposing different packages of coal-bearing units at the surface.2.. Merritt (1990) describes the Tyonek Formation as the result of channel and floodplain sedimentation. 4. (1997) also suggest that much of the Tyonek Formation was laid down while the Castle Mountain Fault (CMF) was active. silts. and faults can be evaluated. sands. and their connection to surrounding aquifers. Subsequent studies have improved understanding of the depositional environment. As suggested by Burton et al. with particular attention paid to the tectonics. 1997). permeable units.2 Site Geology
Although information about the specific coal beds that CIRI is targeting for UCG remains limited. and distribution of coal beds throughout the region (e. while the Beluga Formation coals are typically less than 8 ft (Belowich.
The influence of seismicity on fracture generation and fluid migration at the proposed site also warrants further investigation once more detailed site plans have been released. Although the stratigraphy is generally shallowly dipping throughout the study area.7 and 4. the Tyonek and Beluga formations are warped by an east-northeast trending syncline..2. except where locally influenced by motion along the CMF and Moquawkie (Bruin Bay) fault zone. Where these faults are present. motion along these faults is likely to have caused local warping and fracturing near these faults. 2002). and the attitude of these beds indicates that the axis of this “U” becomes deeper to the east.000 ft. The CIRI exploration block is crossed by the CMF along its northern edge. A syncline is a “U” shaped warping of geologic layers.
2. aligned and offset river drainages along its course in the vicinity of the exploration block are consistent with recent motion along this fault as well. with the western block displaced upwards relative to the eastern block. Both of these faults are highangle.2
The Beluga and Tyonek formations are typically flat to shallowly dipping (< 15 degrees). Haeussler et al. with the northern block upthrown relative to the southern block. and is nearly bisected by the northeast-trending Moquawkie/Bruin Bay Fault (Figure 4).. 2007). the stratigraphic package is tilted or gently folded so that dips can be up to 3550 degrees (Barnes.
. The influence of these major faults and associated fractures on fluid migration warrants further investigation. The Moquawkie/Bruin Bay Fault offsets the stratigraphy by an additional 2. which plunges shallowly to the east (Belowich.Stratus Consulting
4. The plunge is the direction and angle that the axis of this “U” is tilted..000 ft. respectively (e.2 It is not clear from CIRI’s plans whether the coal beds involved in this structure may be the target of their exploration further to the northeast. with the most recent dated surface rupture occurring approximately 670 years ago. The 30-ft thick Beluga coal bed crops out in a “U” shape along the Beluga River canyon.g. The entire Cook Inlet region is very active seismically (Figure 5). The CMF offsets the Tyonek Formation by as much as 4..5 occurred along the eastern portions of the CMF in 1984 and 1996. These faults and fractures are potential pathways for fluid migration to the surface.g. Recent work on portions of the CMF indicates that it is active. and both have accommodated significant displacement. Willis et al. The Moquawkie/Bruin Bay Fault has received relatively less attention in the literature. In the southwestern corner of the CIRI exploration block. 1966). however. Moderate earthquakes of magnitude 5. 2009). and an average recurrence interval of approximately 700 years (e.
this section provides some general comments on the needs and importance of site characterization and environmental monitoring at UCG and CCS sites The need for flexibility and responsiveness in site characterization and monitoring cannot be overemphasized for a project such as the proposal from CIRI. Geologic systems are inherently heterogeneous and complex.
Source: Belowich. However.
Environmental Monitoring for UCG and CCS
It is difficult at this stage to provide detailed comments on environmental monitoring needs at the CIRI site due to the lack of site-specific information. Figure 3. 2009. environmental monitoring will likely need to be an iterative process. As a result. with data
5. CIRI exploration area generalized geology. and their properties can be highly variable over a variety of spatial scales.Stratus Consulting
Figure 5.. if needed. 2009). and employed technologies can then be altered so that monitoring occurs where the produced or injected fluids have come to be located. Overall. and
. Longer time intervals between measurements may be sufficient during later phases of syngas generation and CO2 injection. 2006. The location of the CIRI site is approximately at the intersection of the two faults located west of Anchorage. The initial start-up of both phases of the project is likely to be the most intensive period for modeling activities. Monitoring data gathered during the initial UCG burnout phase and the early CO2 injection phase can then be used to refine models. and data are needed for model and instrument calibration. including model calibration and refinement. the frequency of measurements may be greatest during the early part of the project.
Source: AEIC. If unanticipated conditions are detected.
gathered during initial site characterization and monitoring likely used as initial inputs for a flexible set of models (Bacon et al. when the least is known about the site. Cook inlet seismicity. the location and frequency of monitoring.
A series of faults at the site that were not included in the model simulations were believed to be responsible for the unanticipated results (Friedmann. once models are refined and are able to adequately predict subsurface fluid movement. and associated impacts on surface water resources. and Weyburn (Saskatchewan). there remain a number of environmental risks associated with both UCG and CCS. at Sleipner. the lateral dimensions of the CO2 plume were much smaller than predicted by pre-injection model simulations. At these sites. or human health The risk of induced microseismicity as a result of overpressurizing CCS target zones.Stratus Consulting
for verification as initial field data are collected. none of the unanticipated migration resulted in leakage. frequency.
.. however. Frio (Texas).
6. and the CO2 remained sequestered in the intended injection zone. 2009). flexibility and responsiveness in monitoring activities. The intensity of modeling activities may also slow with time. however. 2003). Hovorka et al.. iterative site characterization. 2001. location. At Weyburn. For example. All of these examples. Unpredicted CO2 migration was also observed at Frio. and the need for dynamic monitoring plans so that the location. 2003). Unrecognized discontinuous silt layers within the injection zone were responsible for the unanticipated distribution of CO2 (Johnson and Nitao.
The project proposed by CIRI has a number of potential environmental benefits when compared to conventional coal mining. the plume spread out less laterally and more vertically. and quantity.. reinforce the need for careful. modeled predictions of the location and shape of the CO2 plume were partially incorrect. The need for careful site characterization and monitoring is illustrated by experience at wellcharacterized GS sites such as Sleipner (North Sea). At each of these sites. where the CO2 migrated much more quickly than anticipated (Doughty et al. Some of the most important of these risks are:     The risk of groundwater contamination as a result of UCG and/or CCS The risk of subsidence resulting from cavity formation in the UCG burn-out zone The risk of syngas and/or CO2 releases to the surface. ecosystems. and types of field measurements can be adjusted as needs and conditions change. model simulations based on initially gathered site characterization data did not accurately predict the migration and location of the injected CO2. Kharaka et al. As described above. Compared to predictions. 2005. thus demonstrating the potential for successful storage of CO2 in the subsurface.
thickness. environmental monitoring is likely to be an iterative process. the data requirements for environmental characterization follow:  Detailed stratigraphic information compiled from borehole and seismic data. thickness. and groundwater flow directions in subsurface aquifers Detailed geologic mapping of active and fossil fault zones in the areas proposed for UCG and CCS. Only when all of these additional data needs have been met can an informed permitting and regulation process proceed. and monitoring of injection pressures for CCS. along with a characterization of their hydraulic properties. to evaluate the potential for groundwater contamination from the proposed project Baseline characterization of groundwater conditions. the target GS sites.
While the CIRI proposal holds some promise as a marriage of new technologies for energy exploitation.5 and 3. including the depth. including monitoring of hydrostatic pressure in the UCG burnout zone to ensure inward hydraulic gradients. Groundwater monitoring in the areas surrounding UCG and CCS injection zones. the CIRI proposal is far too general to enable a reasoned evaluation of the environmental risks of the project. minimum requirements for monitoring follow:    Pressure monitoring. Air monitoring to detect potential escapes of syngas and/or CO2 to the surface. and surrounding rocks. to detect the potential for escape of contaminated groundwater. these data requirements still need to be met. Monitoring of induced surface motions. Sections 2. hydraulic conductivity.Stratus Consulting
If the project proceeds.3 describe the minimum environmental characterization data that are required for such a reasoned evaluation to occur. further risks to the environment can be mitigated through comprehensive site monitoring. As described in Section 5. including the potential for subsidence induced by UCG cavity formation and the potential for induced microseismicity induced by increased pressures in GS formations. however. and geotechnical properties of coal seams and overlying stratigraphic units Geochemical and mineralogical characterization of the target coal seams for UCG. including the depth. Both of these air monitoring campaigns would require establishment of baseline conditions prior to project initiation. To summarize.
Hepple.edu/maps/southcentral_cook_map. Benson.. Hoversten. S.M. S. D. M. Overview of geologic storage of CO2.F. Apps. 1966. New York. Barnes. R. J. M. J. Chromatographic partitioning of impurities contained in a CO2 stream injected into a deep saline aquifer: Part 1. Wilson and D. Alaska Earthquake Information Center. Accessed January 5. F. 2010. Monitoring geological storage of carbon dioxide. Benson (ed. S. S. and N. Revised November 30. 2009.M.. Validation of CO2 injection simulations with monitoring well data. S. Lippmann. Benson. PH4-29. Sminchak. Gerard (eds. Monitoring. In Carbon Capture and Sequestration: Integrating Technology. E. Geology and Coal Resources of the Beluga-Yentna Region. Effects of flow conditions. V2: Geologic Storage of Carbon Dioxide with Monitoring and Verification. 73−100. November/December.S. Gasperikova. Bacon. Gupta. Alaska Coal Update. UK. pp. Chromatographic partitioning of impurities (H2S) contained in a CO2 stream injected into a deep saline aquifer: Part 2. Berkeley. 2004. 2009. International Journal of Greenhouse Gas Control 3:458−463. September 29. and M. London. Tsang.M. Benson. In Results from the CO2 Capture Project. C. Prepared for Cook Inlet Region. Prepared for the IEA GHG Programme.. and H. Geology Survey Bulletin 1202-C. S. International Journal of Greenhouse Gas Control 3:464473. Available: http://www. Hong. and M. 665672. Cook Inlet Seismicity (figure).Stratus Consulting
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