Research for deployment: incorporating risk, regulation, and liability for carbon capture and sequestration

Carbon capture and sequestration (CCS) has the potential to enable deep reductions in global carbon dioxide (CO2) emissions, however this promise can only be fulfilled with large-scale deployment. For this to happen, CCS must be successfully embedded into a larger legal and regulatory context, and any potential risks must be effectively managed. We developed a list of outstanding research and technical questions driven by the demands of the regulatory and legal systems for the geologic sequestration (GS) component of CCS. We then looked at case studies that bound uncertainty within two of the research themes that emerge. These case studies, on surface leakage from abandoned wells and groundwater quality impacts from metals mobilization, illustrate how research can inform decision makers on issues of policy, regulatory need, and legal considerations. A central challenge is to ensure that the research program supports development of general regulatory and legal frameworks, and also the development of geological, geophysical, geochemical, and modeling methods necessary for effective GS site monitoring and verification (M&V) protocols, as well as mitigation and remediation plans. If large-scale deployment of GS is to occur in a manner that adequately protects human and ecological health and does not discourage private investment, strengthening the scientific underpinnings of regulatory and legal decision-making is crucial.     

Feasibility of a perfluorocarbon tracer based network to support monitoring, verification, and accounting of sequestered CO₂

Carbon capture and sequestration (CCS) will act as a bridging technology necessary to facilitate a transition from fossil fuels to a sustainable energy based economy. The Department of Energy (DOE) target leak rate for sequestration reservoirs is 1% of total sequestered CO(2) over the lifetime of the reservoir. This is 0.001% per year for a 1000 year lifetime of a storage reservoir. Effective detection of CO(2) leaks at the surface may require incorporation of a tracer tag into the sequestered CO(2). We applied a simple Gaussian Plume model to predict dispersion of a direct leak into the atmosphere and used the results to examine the requirements for designing a perfluorocarbon (PFT) monitoring network and tracer tagging strategy. Careful consideration must be given to the climate implications of using these compounds. The quantity of PFTs needed for tagging sequestered CO(2) is too large to be practical for routine monitoring. Tagging at a level that will result in 1.5 times background at a sampler 1 km from a leak of 0.01% per year will require 625 kg per year of PFT. This is a leak rate 10 times greater than the 1000 year DOE requirement and will require 19 tons of injected PFT over the 30 year lifetime of a 1000 mega watt coal fired plant. The utility of PFTs or any other tracer will be lost if the background levels are allowed to rise indiscriminately. A better use of PFTs is as a tool in sequestration research. Instead, geological surveys of sequestration sites will be necessary to locate potential direct pathways and develop targeted monitoring strategies. A global agreement on the use of tracers for monitoring CCS projects should be developed.     

Potential restrictions for CO2 sequestration sites due to shale and tight gas production

Carbon capture and geological sequestration is the only available technology that both allows continued use of fossil fuels in the power sector and reduces significantly the associated CO(2) emissions. Geological sequestration requires a deep permeable geological formation into which captured CO(2)can be injected, and an overlying impermeable formation, called a caprock, that keeps the buoyant CO(2) within the injection formation. Shale formations typically have very low permeability and are considered to be good caprock formations. Production of natural gas from shale and other tight formations involves fracturing the shale with the explicit objective to greatly increase the permeability of the shale. As such, shale gas production is in direct conflict with the use of shale formations as a caprock barrier to CO(2) migration. We have examined the locations in the United States where deep saline aquifers, suitable for CO(2) sequestration, exist, as well as the locations of gas production from shale and other tight formations. While estimated sequestration capacity for CO(2) sequestration in deep saline aquifers is large, up to 80% of that capacity has areal overlap with potential shale-gas production regions and, therefore, could be adversely affected by shale and tight gas production. Analysis of stationary sources of CO(2) shows a similar effect: about two-thirds of the total emissions from these sources are located within 20 miles of a deep saline aquifer, but shale and tight gas production could affect up to 85% of these sources. These analyses indicate that colocation of deep saline aquifers with shale and tight gas production could significantly affect the sequestration capacity for CCS operations. This suggests that a more comprehensive management strategy for subsurface resource utilization should be developed.     

Development of a hybrid process and system model for the assessment of wellbore leakage at a geologic CO2 sequestration site

Sequestration of CO2 in geologic reservoirs is one of the promising technologies currently being explored to mitigate anthropogenic CO2 emissions. Large-scale deployment of geologic sequestration will require seals with a cumulative area amounting to hundreds of square kilometers per year and will require a large number of sequestration sites. We are developing a system-level model, CO2-PENS, that will predict the overall performance of sequestration systems while taking into account various processes associated with different parts of a sequestration operation, from the power plant to sequestration reservoirs to the accessible environment. The adaptability of CO2-PENS promotes application to a wide variety of sites, and its level of complexity can be increased as detailed site information becomes available. The model CO2-PENS utilizes a science-based-prediction approach by integrating information from process-level laboratory experiments, field experiments/observations, and process-level numerical modeling. The use of coupled process models in the system model of CO2-PENS provides insights into the emergent behavior of aggregate processes that could not be obtained by using individual process models. We illustrate the utility of the concept by incorporating geologic and wellbore data into a synthetic, depleted oil reservoir. In this sequestration scenario, we assess the fate of CO2 via wellbore release and resulting impacts of CO2 to a shallow aquifer and release to the atmosphere.     

Effects of well spacing on geological storage site distribution costs and surface footprint

Geological storage studies thus far have not evaluated the scale and cost of the network of distribution pipelines that will be needed to move CO(2) from a central receiving point at a storage site to injection wells distributed about the site. Using possible injection rates for deep-saline sandstone aquifers, we estimate that the footprint of a sequestration site could range from <100 km(2) to >100,000 km(2), and that distribution costs could be <$0.10/tonne to >$10/tonne. Our findings are based on two models for determining well spacing: one which minimizes spacing in order to maximize use of the volumetric capacity of the reservoir, and a second that determines spacing to minimize subsurface pressure interference between injection wells. The interference model, which we believe more accurately reflects reservoir dynamics, produces wider well spacings and a counterintuitive relationship whereby total injection site footprint and thus distribution cost declines with decreasing permeability for a given reservoir thickness. This implies that volumetric capacity estimates should be reexamined to include well spacing constraints, since wells will need to be spaced further apart than void space calculations might suggest. We conclude that site-selection criteria should include thick, low-permeability reservoirs to minimize distribution costs and site footprint.     

Liquid CO2 displacement of water in a dual-permeability pore network micromodel

Permeability contrasts exist in multilayer geological formations under consideration for carbon sequestration. To improve our understanding of heterogeneous pore-scale displacements, liquid CO(2) (LCO(2))-water displacement was evaluated in a pore network micromodel with two distinct permeability zones. Due to the low viscosity ratio (logM = -1.1), unstable displacement occurred at all injection rates over 2 orders of magnitude. LCO(2) displaced water only in the high permeability zone at low injection rates with the mechanism shifting from capillary fingering to viscous fingering with increasing flow rate. At high injection rates, LCO(2) displaced water in the low permeability zone with capillary fingering as the dominant mechanism. LCO(2) saturation (S(LCO2)) as a function of injection rate was quantified using fluorescent microscopy. In all experiments, more than 50% of LCO(2) resided in the active flowpaths, and this fraction increased as displacement transitioned from capillary to viscous fingering. A continuum-scale two-phase flow model with independently determined fluid and hydraulic parameters was used to predict S(LCO2) in the dual-permeability field. Agreement with the micromodel experiments was obtained for low injection rates. However, the numerical model does not account for the unstable viscous fingering processes observed experimentally at higher rates and hence overestimated S(LCO2).     

Variation in energy available to populations of subsurface anaerobes in response to geological carbon storage

Microorganisms can strongly influence the chemical and physical properties of the subsurface. Changes in microbial activity caused by geological CO(2) storage, therefore, have the potential to influence the capacity, injectivity, and integrity of CO(2) storage reservoirs and ultimately the environmental impact of CO(2) injection. This analysis uses free energy calculations to examine variation in energy available to Fe(III) and SO(4)(2-) reducers and methanogens because of changes in the bulk composition of brine and shallow groundwater following subsurface CO(2) injection. Calculations were performed using data from two field experiments, the Frio Formation experiment and an experiment at the Zero Emission Research and Technology test site. Energy available for Fe(III) reduction increased significantly during CO(2) injection in both experiments, largely because of a decrease in pH from near-neutral levels to just below 6. Energy available to SO(4)(2-) reducers and methanogens varied little. These changes can lead to a greater rate of microbial Fe(III) reduction following subsurface CO(2) injection in reservoirs where Fe(III) oxides or oxyhydroxides are available and the rate of Fe(III) reduction is limited by energy available prior to injection.     

In situ observation of CO2 sequestration reactions using a novel microreaction system

A novel, externally controlled microreaction system has been developed to provide the first in situ observations of the reaction processes that control CO2 sequestration via mineral carbonation. The system offers pressure (to 20 MPa), temperature (to 250 degrees C), and activity control suitable for investigating a variety of fluid-fluid and fluid-solid interactions of environmental interest. Mineral sequestration efforts to date have effectively accelerated carbonation, a natural mineral weathering process, to an industrial timescale. However, the associated reaction mechanisms are poorly understood, limiting further process development. Synchrotron X-ray diffraction and Raman spectroscopy have been used to provide the first in situ insight into the associated supercritical mineral carbonation process. Magnesite was found to form directly under the reaction conditions observed (e.g., 150 degrees C and 15 MPa CO2),facilitating geologically stable sequestration. Thermodynamic analysis of fluid-phase species concentrations in the Na+ buffered H2O-CO2 reaction system found the primary aqueous reactant species to be CO2(aq) and HCO3-, with CO2(aq) more prevalent under the reaction conditions observed. The microreactor provides a powerful new tool for in situ investigation of a broad range of environmentally, fundamentally, and commercially important processes, including the reactions associated with geological carbon dioxide sequestration.     

Regulating the ultimate sink: managing the risks of geologic CO2 storage

The geologic storage (GS) of carbon dioxide (CO2) is emerging as an important tool for managing carbon. While this Journal recently published an excellent review of GS technology (Bruant, R. G.; Guswa, A. J.; Celia, M. A.; Peters, C. A. Environ. Sci. Technol. 2002, 36, 240A-245A), few studies have explored the regulatory environment for GS or have compared it with current underground injection experience. We review the risks and regulatory history of deep underground injection on the U.S. mainland and surrounding continental shelf. Our treatment is selective, focusing on the technical and regulatory aspects that are most likely to be important in assessing and managing the risks of GS. We also describe current underground injection activities and explore how these are now regulated.     

Regulating the geological sequestration of CO2

Governments worldwide should provide incentives for initial large-scale GS projects to help build the knowledge base for a mature, internationally harmonized GS regulatory framework. Health, safety, and environmental risks of these early projects can be managed through modifications of existing regulations in the EU, Australia, Canada, and the U.S. An institutional mechanism, such as the proposed Federal Carbon Sequestration Commission in the U.S., should gather data from these early projects and combine them with factors such as GS industrial organization and climate regime requirements to create an efficient and adaptive regulatory framework suited to large-scale deployment. Mechanisms to structure long-term liability and fund long-term postclosure care must be developed, most likely at the national level, to equitably balance the risks and benefits of this important climate change mitigation technology. We need to do this right. During the initial field experiences, a single major accident, resulting from inadequate regulatory oversight, anywhere in the world, could seriously endanger the future viability of GS. That, in turn, could make it next to impossible to achieve the needed dramatic global reductions in CO2 emissions over the next several decades. We also need to do it quickly. Emissions are going up, the climate is changing, and impacts are growing. The need for safe and effective CO2 capture with deep GS is urgent.     

Probabilistic design of a near-surface CO2 leak detection system

A methodology is developed for predicting the performance of near-surface CO(2) leak detection systems at geologic sequestration sites. The methodology integrates site characterization and modeling to predict the statistical properties of natural CO(2) fluxes, the transport of CO(2) from potential subsurface leakage points, and the detection of CO(2) surface fluxes by the monitoring network. The probability of leak detection is computed as the probability that the leakage signal is sufficient to increase the total flux beyond a statistically determined threshold. The methodology is illustrated for a highly idealized site monitored with CO(2) accumulation chamber measurements taken on a uniform grid. The TOUGH2 code is used to predict the spatial profile of surface CO(2) fluxes resulting from different leakage rates and different soil permeabilities. A response surface is fit to the TOUGH2 results to allow interpolation across a continuous range of values of permeability and leakage rate. The spatial distribution of leakage probability is assumed uniform in this application. Nonlinear, nonmonotonic relationships of network performance to soil permeability and network density are evident. In general, dense networks (with ～10-20 m between monitors) are required to ensure a moderate to high probability of leak detection.     

Ocean sequestration of carbon dioxide: modeling the deep ocean release of a dense emulsion of liquid Co2-in-water stabilized by pulverized limestone particles

The release into the deep ocean of an emulsion of liquid carbon dioxide-in-seawater stabilized by fine particles of pulverized limestone (CaCO3) is modeled. The emulsion is denser than seawater, hence, it will sink deeper from the injection point, increasing the sequestration period. Also, the presence of CaCO3 will partially buffer the carbonic acid that results when the emulsion eventually disintegrates. The distance that the plume sinks depends on the density stratification of the ocean, the amount of the released emulsion, and the entrainment factor. When released into the open ocean, a plume containing the CO2 output of a 1000 MW(el) coal-fired power plant will typically sink hundreds of meters below the injection point. When released from a pipe into a valley on the continental shelf, the plume will sink about twice as far because of the limited entrainment of ambient seawater when the plume flows along the valley. A practical system is described involving a static mixer for the in situ creation of the CO2/seawater/pulverized limestone emulsion. The creation of the emulsion requires significant amounts of pulverized limestone, on the order of 0.5 tons per ton of liquid CO2. That increases the cost of ocean sequestration by about $13/ ton of CO2 sequestered. However, the additional cost may be compensated by the savings in transportation costs to greater depth, and because the release of an emulsion will not acidify the seawater around the release point.     

Semianalytical solution for CO2 leakage through an abandoned well

Capture and subsequent injection of carbon dioxide into deep geological formations is being considered as a means to reduce anthropogenic emissions of CO2 to the atmosphere. If such a strategy is to be successful, the injected CO2 must remain within the injection formation for long periods of time, at least several hundred years. Because mature continental sedimentary basins have a century-long history of oil and gas exploration and production, they are characterized by large numbers of existing oil and gas wells. For example, more than 1 million such wells have been drilled in the state of Texas in the United States. These existing wells represent potential leakage pathways for injected CO2. To analyze leakage potential, modeling tools are needed that predict leakage rates and patterns in systems with injection and potentially leaky wells. A new semianalytical solution framework allows simple and efficient prediction of leakage rates for the case of injection of supercritical CO2 into a brine-saturated deep aquifer. The solution predicts the extent of the injected CO2 plume, provides leakage rates through an abandoned well located at an arbitrary distance from the injection well, and estimates the CO2 plume extent in the overlying aquifer into which the fluid leaks. Comparison to results from a numerical multiphase flow simulator show excellent agreement. Example calculations show the importance of outer boundary conditions, the influence of both density and viscosity contrasts in the resulting solutions, and the potential importance of local upconing around the leaky well. While several important limiting assumptions are required, the new semianalytical solution provides a simple and efficient procedure for estimation of CO2 leakage for problems involving one injection well, one leaky well, and multiple aquifers separated by impermeable aquitards.     

Carbon sequestration kinetic and storage capacity of ultramafic mining waste

Mineral carbonation of ultramafic rocks provides an environmentally safe and permanent solution for CO(2) sequestration. In order to assess the carbonation potential of ultramafic waste material produced by industrial processing, we designed a laboratory-scale method, using a modified eudiometer, to measure continuous CO(2) consumption in samples at atmospheric pressure and near ambient temperature. The eudiometer allows monitoring the CO(2) partial pressure during mineral carbonation reactions. The maximum amount of carbonation and the reaction rate of different samples were measured in a range of experimental conditions: humidity from dry to submerged, temperatures of 21 and 33 °C, and the proportion of CO(2) in the air from 4.4 to 33.6 mol %. The most reactive samples contained ca. 8 wt % CO(2) after carbonation. The modal proportion of brucite in the mining residue is the main parameter determining maximum storage capacity of CO(2). The reaction rate depends primarily on the proportion of CO(2) in the gas mixture and secondarily on parameters controlling the diffusion of CO(2) in the sample, such as relative saturation of water in pore space. Nesquehonite was the dominant carbonate for reactions at 21 °C, whereas dypingite was most common at 33 °C.     

CO2 hydrate composite for ocean carbon sequestration

Rapid CO2 hydrate formation was investigated with the objective of producing a negatively buoyant CO2-seawater mixture under high-pressure and low-temperature conditions, simulating direct CO2 injection at intermediate ocean depths of 1.0-1.3 km. A coflow reactor was developed to maximize CO2 hydrate production by injecting water droplets (e.g., approximately 267 microm average diameter) from a capillary tube into liquid CO2. The droplets were injected in the mixing zone of the reactor where CO2 hydrate formed at the surface of the water droplets. The water-encased hydrate particles aggregated in the liquid CO2, producing a paste-like composite containing CO2 hydrate, liquid CO2, and water phases. This composite was extruded into ambient water from the coflow reactor as a coherent cylindrical mass, approximately 6 mm in diameter, which broke into pieces 5-10 cm long. Both modeling and experiments demonstrated that conversion from liquid CO2 to CO2 hydrate increased with water flow rate, ambient pressure, and residence time and decreased with CO2 flow rate. Increased mixing intensity, as expressed by the Reynolds number, enhanced the mass transfer and increased the conversion of liquid CO2 into CO2 hydrate. Using a plume model, we show that hydrate composite particles (for a CO2 loading of 1000 kg/s and 0.25 hydrate conversion) will dissolve and sink through a total depth of 350 m. This suggests significantly better CO2 dispersal and potentially reduced environmental impacts than would be possible by simply discharging positively buoyant liquid CO2 droplets. Further studies are needed to address hydrate conversion efficiency, scale-up criteria, sequestration longevity, and impact on the ocean biota before in-situ production of sinking CO2 hydrate composite can be applied to oceanic CO2 storage and sequestration.     

A technical,economic, and environmental assessment of amine-based CO2 capture technology for power plant greenhouse gas control

Capture and sequestration of CO2 from fossil fuel power plants is gaining widespread interest as a potential method of controlling greenhouse gas emissions. Performance and cost models of an amine (MEA)-based CO2 absorption system for postcombustion flue gas applications have been developed and integrated with an existing power plant modeling framework that includes multipollutant control technologies for other regulated emissions. The integrated model has been applied to study the feasibility and cost of carbon capture and sequestration at both new and existing coal-burning power plants. The cost of carbon avoidance was shown to depend strongly on assumptions about the reference plant design, details of the CO2 capture system design, interactions with other pollution control systems, and method of CO2 storage. The CO2 avoidance cost for retrofit systems was found to be generally higher than for new plants, mainly because of the higher energy penalty resulting from less efficient heat integration as well as site-specific difficulties typically encountered in retrofit applications. For all cases, a small reduction in CO2 capture cost was afforded by the SO2 emission trading credits generated by amine-based capture systems. Efforts are underway to model a broader suite of carbon capture and sequestration technologies for more comprehensive assessments in the context of multipollutant environmental management.     

The atmospheric background of perfluorocarbon compounds used as tracers

There are seven cyclic perfluoroalkane compounds, which can be detected in extremely low concentrations, that are used to track mass movement and transfer in a variety of research and practical applications. They are used in leak detection in underground storage and pipelines and in atmospheric transport and diffusion research on local, regional, and continental scales. They are likely to be a used globally for monitoring carbon sequestration in geological formations. The atmospheric background levels of these compounds must be accurately known, and trends in their concentrations determined for these compounds to be effective in monitoring CO2 reservoirs and because there are environmental concerns about their release. Results of measurements of perfluorocarbon background concentrations from two recent field programs are presented, and trends in these values examined using data collected over the last 25 years. The current atmospheric concentrations of these compounds are in the low parts per quadrillion levels, and their annual atmospheric growth rate is less than 1 part per quadrillion per year. The environmental effects of these compounds are examined and found to be negligible at current release rates.     

Effect of organic matters on CO2 hydrate formation in Ulleung Basin sediment suspensions

Marine sediment core samples collected from a gas hydrate deposit site (Ulleung Basin (UB), East Sea, Korea) were explored to identify the role of sediment organic matters (SOMs) on the formation of CO(2) hydrate. Two distinct CO(2) hydrate formation regimes (favorable (≤40 min) and unfavorable (>250 min)) were observed from the hydrate formation tests. CO(2) hydrate induction time in UB sediment suspensions was approximately seven times faster than that in UB sediment suspensions without SOMs (baked UB), showing a direct influence of SOMs. Spectrometric and spectroscopic analyses confirmed the existence of different types of SOMs including nonhumic and humic substances in UB sediment samples. We found SOMs with aromatic ring structures in all sediment extracts and SOMs with amine and amide groups and lignin in alkaline extracts. SOMs were extracted from UB sediment core samples (1 g each). Measured CO(2) hydrate induction times were different in baked UB sediment suspensions with different extracts of UB sediments. The experimental results demonstrated that SOMs can play a significant role to accelerate the formation of CO(2) hydrate in UB sediment suspensions, suggesting that the gas hydrate deposit site at UB may be a proper place for CO(2) sequestration as a form of CO(2) hydrate.     

Application of amine-tethered solid sorbents for direct CO2 capture from the ambient air

While current carbon capture and sequestration (CCS) technologies for large point sources can help address the impact of CO(2) buildup on global climate change, these technologies can at best slow the rate of increase of the atmospheric CO(2) concentration. In contrast, the direct CO(2) capture from ambient air offers the potential to be a truly carbon negative technology. We propose here that amine-based solid adsorbents have significant promise as key components of a hypothetical air capture process. Specifically, the CO(2) capture characteristics of hyperbranched aminosilica (HAS) materials are evaluated here using CO(2) mixtures that simulate ambient atmospheric concentrations (400 ppm CO(2) = "air capture") as well as more traditional conditions simulating flue gas (10% CO(2)). The air capture experiments demonstrate that the adsorption capacity of HAS adsorbents are only marginally influenced even with a significant dilution of the CO(2) concentration by a factor of 250, while capturing CO(2) reversibly without significant degradation of performance in multicyclic operation. These results suggest that solid amine-based air capture processes have the potential to be an effective approach to extracting CO(2) from the ambient air.     

Rate of CO2 attack on hydrated Class H well cement under geologic sequestration conditions

Experiments were conducted to study the degradation of hardened cement paste due to exposure to CO2 and brine under geologic sequestration conditions (T = 50 degrees C and 30.3 MPa). The goal was to determine the rate of reaction of hydrated cement exposed to supercritical CO2 and to CO2-saturated brine to assess the potential impact of degradation in existing wells on CO2 storage integrity. Two different forms of chemical alteration were observed. The supercritical CO2 alteration of cement was similar in process to cement in contact with atmospheric CO2 (ordinary carbonation), while alteration of cement exposed to CO2-saturated brine was typical of acid attack on cement. Extrapolation of the hydrated cement alteration rate measured for 1 year indicates a penetration depth range of 1.00 +/- 0.07 mm for the CO2-saturated brine and 1.68 +/- 0.24 mm for the supercritical CO2 after 30 years. These penetration depths are consistent with observations of field samples from an enhanced oil recovery site after 30 years of exposure to CO2-saturated brine under similar temperature and pressure conditions. These results suggest that significant degradation due to matrix diffusion of CO2 in intact Class H neat hydrated cement is unlikely on time scales of decades.