Design considerations for financing a national trust to advance the deployment of geologic CO2 storage and motivate best practices

This paper explores how the widely held public policy view of the evolution of the risk profile associated with geologic carbon dioxide (CO₂) storage profoundly influences the public policy dialogue about how to best address the long-term risk profile for geologic storage. Evidence emerging from research and pilot scale field demonstrations of CO₂ storage demonstrates that, with proper site characterization and sound operating practices, retention of stored CO₂ will increase with time thus invalidating the premise of an ever growing risk. The authors focus on key issues of fit, interplay, and scalability associated with the ability of a trust fund funded by a hypothetical $1 per tonCO₂ tipping fee for each ton of CO₂ stored in the United States under WRE450 and WRE550 climate policies to manage such risks in an economically efficient and environmentally effective manner. The authors conclude there is no intrinsic value – in terms of risk management or risk reduction – in creating a trust fund predicated solely on collecting a universally applied tipping fee that does not take into account site-specific risk profiles. If left to grow unchecked, a trust fund that is predicated on a constant stream of payments unrelated to each contributing site's risk profile could result in the accumulation of hundreds of billions to more than a trillion dollars contributing to significant opportunity cost of capital. Further, rather than mitigating the financial consequences of long-term CCS risks, this analysis suggests a blanket $1 per tonCO₂ tipping fee, if combined with a concomitant limitation of liability may increase the probability and frequency of long-term risk by eliminating financial incentives for sound operating behavior and site selection criteria—contribute to moral hazard. At a minimum, effective use of a trust fund requires: (1) strong oversight regarding site selection and fund management, and (2) a clear process by which the fund is periodically valued and funds collected are mapped to the risk profile of the pool of covered CCS sites. Without appropriate checks and balances, there is no a priori reason to believe that the amount of funds held in trust will map to the actual amount of funds needed to address long-term care expenses and delimited compensatory damages. For this reason, the authors conclude that financing a trust fund or other risk management instrument should be based on a site delimited estimate of potential future expected financial consequences rather than on the random adoption of a fixed funding stream, e.g., a blanket $1 per ton, because it “sounds” reasonable.     

Training carbon management engineers: Removing a major hurdle for geologic CO2 storage by increasing educational capacity

Implementing geologic storage of CO₂ at a material scale (ca. 1 Gt C/year) will require an industry comparable in size to the current oil and gas industry and a workforce trained in subsurface engineering. Since the same technologies that apply to hydrocarbon production apply to the subsurface storage of CO₂, petroleum engineering (PE) graduates will be valuable candidates to work in the carbon storage industry. We expect however that the demand for PEs from the oil and gas industry will increase, and that already strained educational capacity will not be sufficient to supply both industries. Thus we advocate building new targeted educational infrastructure. We present a model curriculum based on an existing accredited multidisciplinary degree program. This program combines the fundamentals of petroleum engineering with the subsurface architecture emphasis of geology and the environmental perspective of hydrogeology. We indicate key elements of this program that could be integrated with other, more traditional undergraduate engineering majors that also deal with the subsurface.     

Biofilm enhanced geologic sequestration of supercritical CO2

In order to develop subsurface CO₂ storage as a viable engineered mechanism to reduce the emission of CO₂ into the atmosphere, any potential leakage of injected supercritical CO₂ (SC-CO₂) from the deep subsurface to the atmosphere must be reduced. Here, we investigate the utility of biofilms, which are microorganism assemblages firmly attached to a surface, as a means of reducing the permeability of deep subsurface porous geological matrices under high pressure and in the presence of SC-CO₂, using a unique high pressure (8.9 MPa), moderate temperature (32 °C) flow reactor containing 40 millidarcy Berea sandstone cores. The flow reactor containing the sandstone core was inoculated with the biofilm forming organism Shewanella fridgidimarina. Electron microscopy of the rock core revealed substantial biofilm growth and accumulation under high-pressure conditions in the rock pore space which caused >95% reduction in core permeability. Permeability increased only slightly in response to SC-CO₂ challenges of up to 71 h and starvation for up to 363 h in length. Viable population assays of microorganisms in the effluent indicated survival of the cells following SC-CO₂ challenges and starvation, although S. fridgidimarina was succeeded by Bacillus mojavensis and Citrobacter sp. which were native in the core. These observations suggest that engineered biofilm barriers may be used to enhance the geologic sequestration of atmospheric CO₂.     

Geomechanical analysis of the Naylor Field,Otway Basin,Australia: Implications for CO2 injection and storage

A geomechanical assessment of the Naylor Field, Otway Basin, Australia has been undertaken to investigate the possible geomechanical effects of CO₂ injection and storage. The study aims to evaluate the geomechanical behaviour of the caprock/reservoir system and to estimate the risk of fault reactivation. The stress regime in the onshore Victorian Otway Basin is inferred to be strike–slip if the maximum horizontal stress is calculated using frictional limits and DITF (drilling induced tensile fracture) occurrence, or normal if maximum horizontal stress is based on analysis of dipole sonic log data. The NW–SE maximum horizontal stress orientation (142°N) determined from a resistivity image log is broadly consistent with previous estimates and confirms a NW–SE maximum horizontal stress orientation for the Otway Basin.An analytical geomechanical solution is used to describe stress changes in the subsurface of the Naylor Field. The computed reservoir stress path for the Naylor Field is then incorporated into fault reactivation analysis to estimate the minimum pore pressure increase required to cause fault reactivation (ΔP_p).The highest reactivation propensity (for critically-oriented faults) ranges from an estimated pore pressure increase (ΔP_p) of 1 MPa to 15.7 MPa (estimated pore pressure of 18.5–33.2 MPa) depending on assumptions made about maximum horizontal stress magnitude, fault strength, reservoir stress path and Biot's coefficient. The critical pore pressure changes for known faults at Naylor Field range from an estimated pore pressure increase (ΔP_p) of 2 MPa to 17 MPa (estimated pore pressure of 19.5–34.5 MPa).     

The potential for increased atmospheric CO2 emissions and accelerated consumption of deep geologic CO2 storage resources resulting from the large-scale deployment of a CCS-enabled unconventional fossil fuels industry in the U.S.

Desires to enhance the energy security of the United States have spurred renewed interest in the development of abundant domestic heavy hydrocarbon resources including oil shale and coal to produce unconventional liquid fuels to supplement conventional oil supplies. However, the production processes for these unconventional fossil fuels create large quantities of carbon dioxide (CO₂) and this remains one of the key arguments against such development. Carbon dioxide capture and storage (CCS) technologies could reduce these emissions and preliminary analysis of regional CO₂ storage capacity in locations where such facilities might be sited within the U.S. indicates that there appears to be sufficient storage capacity, primarily in deep saline formations, to accommodate the CO₂ from these industries. Nevertheless, even assuming wide-scale availability of cost-effective CO₂ capture and geologic storage resources, the emergence of a domestic U.S. oil shale or coal-to-liquids (CTL) industry would be responsible for significant increases in CO₂ emissions to the atmosphere. The authors present modeling results of two future hypothetical climate policy scenarios that indicate that the oil shale production facilities required to produce 3 MMB/d from the Eocene Green River Formation of the western U.S. using an in situ retorting process would result in net emissions to the atmosphere of between 3000 and 7000 MtCO₂, in addition to storing potentially 900–5000 MtCO₂ in regional deep geologic formations via CCS in the period up to 2050. A similarly sized, but geographically more dispersed domestic CTL industry could result in 4000–5000 MtCO₂ emitted to the atmosphere in addition to potentially 21,000–22,000 MtCO₂ stored in regional deep geologic formations over the same period. While this analysis shows that there is likely adequate CO₂ storage capacity in the regions where these technologies are likely to deploy, the reliance by these industries on large-scale CCS could result in an accelerated rate of utilization of the nation's CO₂ storage resource, leaving less high-quality storage capacity for other carbon-producing industries including electric power generation.     

Permanent shallow subsoil CO2 flux chambers for monitoring of onshore CO2 geological storage sites

Public concern over the possibility of migration of stored CO₂ to the surface with resulting damage to vegetation or hazard to humans and animals is a matter which will need to be addressed to be able to satisfy likely regulatory requirements for onshore CO₂ storage in a number of jurisdictions. While soil CO₂ concentration is readily measured continuously and in situ with current technology, the measurement of CO₂ flux at depths below the soil A horizon may be a more sensitive and meaningful technique for early detection of a near surface CO₂ plume. We describe a system for the continuous measurement of soil CO₂ flux at a depth of approximately 1.3 m and present results from three instruments deployed at the Otway Basin Pilot Project in Victoria, Australia and one development system deployed at Sutton, near the Australian Capital Canberra.     

Screening CO2 storage options in The Netherlands

This paper describes the development and application of a methodology to screen and rank Dutch reservoirs suitable for long-term large scale CO₂ storage. The screening focuses on off- and on-shore individual aquifers, gas and oil fields. In total 176 storage reservoirs have been taken into consideration: 138 gas fields, 4 oil fields and 34 aquifers, with a total theoretical storage potential of about 3200 Mt CO₂. The reservoirs are screened according to three criteria: potential storage capacity, storage costs and effort needed to manage risk. Due to the large number of reservoirs, which limits the possibility to use any pair-wise comparison method (e.g. Multi-Criteria programs such as Bosda or Naiade), a spreadsheet tool was designed to provide an assessment of each of the criteria through an evaluation of the fields present in the database and a set of scores provided by a (inter)national panel of experts. The assessment is sufficiently simple and allows others to review it, re-do it or expand it. The results of the methodology show that plausible comparisons of prospective sites with limited characterization data are possible.     

Public risk perspectives on the geologic storage of carbon dioxide

Carbon Dioxide Capture and Storage (CCS) technology has the potential to enable large reductions in global greenhouse gas emissions, but one of the unanswered questions about CCS is to what extent it will be accepted by the public. To provide insight regarding risk perception as an important component that will influence the public acceptance of CCS, this study discusses different notions of risk and their varying uses by the public, who generally use a social constructivist risk perspective, and risk experts, who generally use a realist perspective. Previous studies discussing the public acceptance of CCS have relied on survey response data and/or focus groups. This study instead uses the psychometric theory of public risk perception to postulate how the public is likely to respond to efforts to use geologic storage of CO₂, a component of the CCS architecture. Additionally this paper proposes further actions that could favorably impact the public's perception of risk from geologic storage projects. Through the psychometric analysis this study concludes that the risks of geologic storage are likely to eventually be considered no worse than existing fossil fuel energy technologies. However, since geologic storage of CO₂ is a new technology with little operational experience, additional field tests and a demonstrated ability to mitigate problems should they arise will be necessary to improve the public's perception of risk from CCS technologies.     

Preliminary assessment of CO2 geological storage opportunities in Greece

This paper provides a preliminary assessment of the suitability of Tertiary sedimentary basins in Northern, Western and Eastern Greece in order to identify geological structures close to major CO₂ emission sources with the potential for long-term storage of CO₂. The term “emissions” refers to point source emissions as defined by the International Energy Agency, including power generation, the cement sector and other industrial processes. The Prinos oil field and saline aquifer, along with the saline formations of the Thessaloniki Basin and the Mesohellenic Trough have been identified as prospective CO₂ geological storage sites. In addition, a carbonate deep saline aquifer occurring at appropriate depths beneath the Neogene-Quaternary sediments of Ptolemais-Kozani graben (NW Greece) is considered. The proximity of this geological formation to Greece's largest lignite-fired power plants suggests that it would be worthwhile undertaking further site-specific studies to quantify its storage capacity and assess its structural integrity.     

Corrective measures based on pressure control strategies for CO2 geological storage in deep aquifers

A prerequisite to the wide deployment at an industrial scale of CO₂ geological storage is demonstrating that potential risks can be efficiently managed. Corrective measures in case of significant irregularities, such as CO₂ leakage, are hence required as advocated by the recent European directive on Carbon Capture and Storage operations. In this regard, the objective of the present paper is to investigate four different corrective measures aiming at controlling the overpressure induced by the injection operations in the reservoir: stopping the CO₂ injection and relying on the natural pressure recovery in the reservoir; extracting the stored CO₂ at the injection well; extracting brine at a distant well while stopping the CO₂ injection, and extracting at a distant well without stopping the CO₂ injection. The efficiency of the measures is assessed using multi-phase fluid flow numerical simulations. The application case is the deep carbonate aquifer of the Dogger geological unit in the Paris Basin. A comparative study between the four corrective measures is then carried using a cost-benefit approach. Results show that an efficient overpressure reduction can be achieved by simply shutting-in the well. The overpressure reduction can be significantly accelerated by means of fluid extraction but the adverse consequences are the associated higher costs of the intervention operations.     

Pathways towards large-scale implementation of CO2 capture and storage: A case study for the Netherlands

We sketch four possible pathways how carbon dioxide capture and storage (CCS) (r)evolution may occur in the Netherlands, after which the implications in terms of CO₂ stored and avoided, costs and infrastructural requirements are quantified. CCS may play a significant role in decarbonising the Dutch energy and industrial sector, which currently emits nearly 100 Mt CO₂/year. We found that 15 Mt CO₂ could be avoided annually by 2020, provided some of the larger gas fields that become available the coming decade could be used for CO₂ storage. Halfway this century, the mitigation potential of CCS in the power sector, industry and transport fuel production is estimated at maximally 80–110 Mt CO₂/year, of which 60–80 Mt CO₂/year may be avoided at costs between 15 and 40 €/t CO₂, including transport and storage. Avoiding 30–60 Mt CO₂/year by means of CCS is considered realistic given the storage potential represented by Dutch gas fields, although it requires planning to assure that domestic storage capacity could be used for CO₂ storage. In an aggressive climate policy, avoiding another 50 Mt CO₂/year may be possible provided that nearly all capture opportunities that occur are taken. Storing such large amounts of CO₂ would only be possible if the Groningen gas field or large reservoirs in the British or Norwegian part of the North Sea will become available.     

Informed and uninformed public opinions on CO2 capture and storage technologies in the Netherlands

Two research methods were used in this study to analyze the awareness and perception of the Dutch general public regarding Carbon dioxide Capture and Storage (CCS). In an Information-Choice Questionnaire (ICQ), a representative sample of the Dutch public (n = 995) was provided with all information on attributes of six CCS options, which experts deemed necessary to come to well-considered and well-informed opinions. A traditional questionnaire was used simultaneously (n = 327) to study uninformed evaluations of these technologies. The results showed that the Dutch public is mostly unaware of CCS and has little knowledge about how current energy use causes global warming. Uninformed respondents are still inclined to give their opinion however, which results in unpredictive, easily changeable opinions. ICQ respondents who processed information on attributes of CCS options were likely to base their option evaluations on this information, though not entirely. All in all, the results of the ICQ suggest that, after processing information deemed necessary by experts, Dutch people reluctantly agree with large scale implementation of each of the six CCS options.     

Life cycle modelling of fossil fuel power generation with post-combustion CO2 capture

Due to its compatibility with the current energy infrastructures and the potential to reduce CO₂ emissions significantly, CO₂ capture and geological storage is recognised as one of the main options in the portfolio of greenhouse gas mitigation technologies being developed worldwide. The CO₂ capture technologies offer a number of alternatives, which involve different energy consumption rates and subsequent environmental impacts. While the main objective of this technology is to minimise the atmospheric greenhouse gas emissions, it is also important to ensure that CO₂ capture and storage does not aggravate other environmental concerns. This requires a holistic and system-wide environmental assessment rather than focusing on the greenhouse gases only. Life Cycle Assessment meets this criteria as it not only tracks energy and non-energy-related greenhouse gas releases but also tracks various other environmental releases, such as solid wastes, toxic substances and common air pollutants, as well as the consumption of other resources, such as water, minerals and land use. This paper presents the principles of the CO₂ capture and storage LCA model developed at Imperial College and uses the pulverised coal post-combustion capture example to demonstrate the methodology in detail. At first, the LCA models developed for the coal combustion system and the chemical absorption CO₂ capture system are presented together with examples of relevant model applications. Next, the two models are applied to a plant with post-combustion CO₂ capture, in order to compare the life cycle environmental performance of systems with and without CO₂ capture. The LCA results for the alternative post-combustion CO₂ capture methods (including MEA, K⁺/PZ, and KS-1) have shown that, compared to plants without capture, the alternative CO₂ capture methods can achieve approximately 80% reduction in global warming potential without a significant increase in other life cycle impact categories. The results have also shown that, of all the solvent options modelled, KS-1 performed the best in most impact categories.     

Evaluating the impact of fractures on the performance of the In Salah CO2 storage site

The In Salah Gas Joint Venture CO₂ storage project has been in operation in Algeria since 2004 and is currently the world's largest onshore CO₂ storage project. CO₂ is injected into the saline aquifer of a gas reservoir several kilometres away from the gas producers. Current focus in the project is on implementing a comprehensive monitoring strategy and modelling the injection behaviour in order to ensure and verify safe long-term storage. A key part of this effort is the understanding of the processes involved in CO₂ migration within relatively low-permeability sandstones and shales influenced by fractures and faults. We summarise our current understanding of the fault and fracture pattern at this site and show preliminary forecasts of the system performance using discrete fracture models and fluid flow simulations. Despite evidence of fractures at the reservoir/aquifer level, the thick mudstone caprock sequence is expected to provide an effective flow and mechanical seal for the storage system; however, quantification of the effects of fracture flow is essential to the site verification.     

Basin-scale hydrogeologic impacts of CO2 storage: Capacity and regulatory implications

Industrial-scale injection of CO₂ into saline formations in sedimentary basins will cause large-scale fluid pressurization and migration of native brines, which may affect valuable groundwater resources overlying the deep sequestration aquifers. In this paper, we discuss how such basin-scale hydrogeologic impacts (1) may reduce current storage capacity estimates, and (2) can affect regulation of CO₂ storage projects. Our assessment arises from a hypothetical future carbon sequestration scenario in the Illinois Basin, which involves twenty individual CO₂ storage projects (sites) in a core injection area most suitable for long-term storage. Each project is assumed to inject five million tonnes of CO₂ per year for 50 years. A regional-scale three-dimensional simulation model was developed for the Illinois Basin that captures both the local-scale CO₂–brine flow processes and the large-scale groundwater flow patterns in response to CO₂ storage. The far-field pressure buildup predicted for this selected sequestration scenario support recent studies in that environmental concerns related to near- and far-field pressure buildup may be a limiting factor on CO₂ storage capacity. In other words, estimates of storage capacity, if solely based on the effective pore volume available for safe trapping of CO₂, may have to be revised based on assessments of pressure perturbations and their potential impacts on caprock integrity and groundwater resources. Our results suggest that (1) the area that needs to be characterized in a permitting process may comprise a very large region within the basin if reservoir pressurization is considered, and (2) permits cannot be granted on a single-site basis alone because the near- and far-field hydrogeologic response may be affected by interference between individual storage sites. We also discuss some of the challenges in making reliable predictions of large-scale hydrogeologic impacts related to CO₂ sequestration projects.     

Evaluation of carbon dioxide storage potential for the Bohai Basin,north-east China

The storage potential of selected sites within the Bohai Basin was assessed for the COACH project. The Gangdong oilfield is considered to have a small potential storage capacity (23 Mt) and to be possibly suitable for an enhanced oil recovery or small-scale storage pilot rather than large-scale storage. The Shengli oilfield province is considered to have a great potential storage capacity (472 Mt in eight selected fields), however, these fields, like those of the Gangdong oilfield province, are compartmentalised by faulting and stratigraphy and likely to be quite challenging for injection. Unmineable coal seams in the Kailuan mining area were also considered for storage, the estimated capacity is 504 Gt adsorbed onto the coal and 38,100 Mt void storage capacity. However, the coals have low porosity and permeability, so they would be expected to have poor injectivity. This is also an active mining area and so any storage site would have to be chosen carefully to avoid affecting future energy resources. The Huimin sub-basin within the Jiyang Depression was identified for consideration as an aquifer storage site; the Guantao Formation has good porosity and permeability in this region, and the regional-level storage capacity of these areas was estimated to be 0.7 Gt. The aquifers in the Huimin sub-basin appear promising for storage, however, less data are available than for the oilfields and the sealing formations are not directly proven to trap buoyant fluids, though in adjacent oilfield in the Shengli oilfield province, the Minghuazhen Formation forms a regional seal for the Guantao Formation.     

CO2 storage and enhanced coalbed methane recovery: Reservoir characterization and fluid flow simulations of the Big George coal,Powder River Basin,Wyoming, USA

Coalbeds are an attractive geological environment for storage of carbon dioxide (CO₂) because CO₂ is retained in the coal as an adsorbed phase and the cost of injection can be offset by enhanced coalbed methane (ECBM) production. This paper presents the findings of a CO₂ storage feasibility study on coalbeds in the Wyodak-Anderson coal zone of the Powder River Basin, Wyoming, USA, using reservoir characterization and fluid flow simulations. A 3D numerical model of the Big George coal was constructed using geostatistical techniques, with values of cleat and matrix permeability and porosity constrained through history-matching of production data from coalbed methane (CBM) wells in the field area.Following history-matching, several ECBM and CO₂ storage scenarios were investigated: shrinkage and swelling of the coal was either allowed or disallowed, a horizontal hydraulic fracture was either placed at the injection well or removed from the model, the number of model layers was varied between 1 and 24, and the permeability and porosity fields were constructed to be either homogeneous or heterogeneous in accordance with geostatistical models of regional variability. All simulations assumed that the injected gas was 100% CO₂ and that the coalbed was overlain by an impermeable caprock. Depending on the scenario, the simulations predicted that after 13 years of CO₂ injection, the cumulative methane production would be enhanced by a factor of 1.5–5. Including coal matrix shrinkage and swelling in the model predicted swelling near the injection well, which resulted in a slight reduction (10%) in injection rate. However, including a horizontal hydraulic fracture in the model at the base of the injection well helped mitigate the negative effect of swelling on injection rate. It was also found that six model layers were needed to have sufficient resolution in the vertical direction to account for the buoyancy effects between the gas and resident water, and that capturing the heterogeneous nature of the coal permeability and porosity fields predicted lower estimates of the storage capacity of the Wyodak-Anderson coal zone.After noting that gravity and buoyancy were the major driving forces behind gas flow within the Big George coal, several leakage scenarios were also investigated, in an effort to better understand the interplay between diffusion and flow properties on the transport and storage of CO₂. The modeling predicted that the upward migration of gas due to the buoyancy effect was faster than the diffusion of CO₂ and therefore the gas rapidly rose to the top of the coalbed and migrated into overlying strata when an impermeable caprock was not included in the model.     

Performance of lime-BHA solidified plating sludge in the presence of Na2SiO3 and Na2CO3

This research investigated the performance of lime-BHA (black rice husk ash) solidified plating sludge with 2 wt% NaO from Na(2)SiO(3) and Na(2)CO(3) at the level of 0, 30 and 50 wt%. The sludge was evaluated for strength development, leachability, solution chemistry and microstructure. The lime-BHA solidified plating sludge with Na(2)SiO(3) and Na(2)CO(3) had higher early strength when compared to the control. The addition of Na(2)SiO(3) and Na(2)CO(3) increased the OH(-) concentration and decreased the Ca(2+) and heavy metal ions in solution after the first minute. The XRD patterns showed that the addition of Na(2)SiO(3) resulted in the formation of calcium silicate hydrates, while the addition of Na(2)CO(3) resulted in CaCO(3). The heavy metals from the plating sludge, especially Zn, were immobilized in calcium zincate and calcium zinc silicate forms for the lime-BHA with and without Na(2)SiO(3) solidified wastes, while samples with Na(2)CO(3) contained Zn that was fixed in the form of CaZnCO(3). The cumulative leaching of Fe, Cr and Zn from the lime-BHA solidified plating sludge decreased significantly when activators were added, especially Na(2)CO(3).     

A response surface methodology to address uncertainties in cap rock failure assessment for CO2 geological storage in deep aquifers

Cap rock failure assessment, either tensile fracturing or shear slip reactivation of pre-existing fault, is a key issue for preventing CO₂ leakage from deep aquifer reservoirs up to the surface. For an appropriate use in risk management, the uncertainties associated with such studies should be investigated. Nevertheless, uncertainty analysis requires multiple simulations and a direct use of conventional numerical approaches might be too computer time consuming. An alternative is to use conventional analytical models, but their assumptions appear to be too conservative. An intermediate approach is then proposed based on the response surface methodology, consisting in estimating the effective stress state after CO₂ injection as a linear combination of the most influential site properties based on a limited number of numerical simulations. The decision maker is provided with three levels of information: (1) the identification of the most important site properties; (2) an analytical model for a quick assessment of the maximal sustainable overpressure and (3) a simplified model to be used in a computationally intensive uncertainty analysis framework. This generic methodology is illustrated with the Paris Basin case using a large-scale hydromechanical model to assess cap rock failure in the injector zone.