Investigations on CO2 storage capacity in saline aquifers—Part 2: Estimation of storage capacity coefficients

Many studies on geological carbon dioxide (CO₂) storage capacity neglect the influence of complex coupled processes which occur during and after the injection of CO₂. Storage capacity is often overestimated since parts of the reservoirs cannot be reached by the CO₂ plume due to gravity segregation and are thus not accessible for storage. This work investigates the effect of reservoir parameters like depth, temperature, absolute and relative permeability, and capillary pressure on the processes during CO₂ injection and thus on estimates of effective storage capacity. The applied statistical characteristics of parameters are based on a large reservoir parameter database. Different measured relative permeability relations are considered. The methodology of estimating storage capacity is discussed. Using numerical 1D and 3D experiments, detailed time-dependent storage capacity estimates are derived. With respect to the concept developed in this work, it is possible to estimate effective CO₂ storage capacity in saline aquifers. It is shown that effective CO₂ mass stored in the reservoir varies by a factor of 20 for the reservoir setups considered. A high influence of the relative permeability relation on storage capacity is shown.     

Storage of CO2 in saline aquifers: Effects of gravity, viscous, and capillary forces on amount and timing of trapping

CO₂ can be effectively immobilized during CO₂ injection into saline aquifers by residual trapping – also known as capillary trapping – a process resulting from capillary snap-off of isolated CO₂ bubbles. Simulations of CO₂ injection were performed to investigate the interplay of viscous and gravity forces and capillary trapping of CO₂. Results of those simulations show that gas injection processes in which gravitational forces are weak compared to viscous forces (low gravity number N_gv) trap significantly more CO₂ than do flows with strong gravitational forces relative to the viscous forces (high N_gv). The results also indicate that over a wide range of gravity numbers (N_gv), significant fractions of the trapping of CO₂ can occur relatively quickly. The amount of CO₂ that is trapped after injection ceases is demonstrated to correlate with N_gv. For some simulated displacements, effects of capillary pressure and aquifer dip angle on the amount and the rate of trapping are reported. Trapping increases when effects of capillary pressure and aquifer inclination are included in the model. Finally we show that injection schemes such as alternating injection of brine and CO₂ or brine injection after CO₂ injection can also enhance the trapping behavior.     

Water/acid gas interfacial tensions and their impact on acid gas geological storage

Acid gas geological disposal is a promising process to reduce CO₂ atmospheric emissions and an environment-friendly and economic alternative to the transformation of H₂S into sulphur by the Claus process. Acid gas confinement in geological formations is to a large extent controlled by the capillary properties of the water/acid–gas/caprock system, because a significant fraction of the injected gas rises buoyantly and accumulates beneath the caprock. These properties include the water/acid gas interfacial tension (IFT), to which the so-called capillary entry pressure of the gas in the water-saturated caprock is proportional. In this paper we present the first ever systematic water/acid gas IFT measurements carried out by the pendant drop technique under geological storage conditions. We performed IFT measurements for water/H₂S systems over a large range of pressure (up to P = 15 MPa) and temperature (up to T = 120 °C). Water/H₂S IFT decreases with increasing P and levels off at around 9–10 mN/m at high T (≥70 °C) and P (>12 MPa). The latter values are around 30–40% of water/CO₂ IFTs, and around 20% of water/CH₄ IFTs at similar T and P conditions. The IFT between water and a CO₂ + H₂S mixture at T = 77 °C and P > 7.5 MPa is observed to be approximately equal to the molar average IFT of the water/CO₂ and water/H₂S binary mixtures. Thus, when the H₂S content in the stored acid gas increases the capillary entry pressure decreases, together with the maximum height of acid gas column and potential storage capacity of a given geological formation. Hence, considerable attention should be exercised when refilling with a H₂S-rich acid gas a depleted gas reservoir, or a depleted oil reservoir with a gas cap: in the case of hydrocarbon reservoirs that were initially (i.e., at the time of their discovery) close to capillary leakage, acid gas leakage through the caprock will inevitably occur if the refilling pressure approaches the initial reservoir pressure.     

CO2 storage capacity estimation: Methodology and gaps

Implementation of CO₂ capture and geological storage (CCGS) technology at the scale needed to achieve a significant and meaningful reduction in CO₂ emissions requires knowledge of the available CO₂ storage capacity. CO₂ storage capacity assessments may be conducted at various scales—in decreasing order of size and increasing order of resolution: country, basin, regional, local and site-specific. Estimation of the CO₂ storage capacity in depleted oil and gas reservoirs is straightforward and is based on recoverable reserves, reservoir properties and in situ CO₂ characteristics. In the case of CO₂-EOR, the CO₂ storage capacity can be roughly evaluated on the basis of worldwide field experience or more accurately through numerical simulations. Determination of the theoretical CO₂ storage capacity in coal beds is based on coal thickness and CO₂ adsorption isotherms, and recovery and completion factors. Evaluation of the CO₂ storage capacity in deep saline aquifers is very complex because four trapping mechanisms that act at different rates are involved and, at times, all mechanisms may be operating simultaneously. The level of detail and resolution required in the data make reliable and accurate estimation of CO₂ storage capacity in deep saline aquifers practical only at the local and site-specific scales. This paper follows a previous one on issues and development of standards for CO₂ storage capacity estimation, and provides a clear set of definitions and methodologies for the assessment of CO₂ storage capacity in geological media. Notwithstanding the defined methodologies suggested for estimating CO₂ storage capacity, major challenges lie ahead because of lack of data, particularly for coal beds and deep saline aquifers, lack of knowledge about the coefficients that reduce storage capacity from theoretical to effective and to practical, and lack of knowledge about the interplay between various trapping mechanisms at work in deep saline aquifers.     

Coalbed methane reservoir data and simulator parameter uncertainty modelling for CO2 storage performance assessment

Laboratory studies and a number of field pilots have demonstrated that CO₂ injection into coal seams has the potential to enhance coalbed methane (CBM) recovery with the added advantage that most of the injected CO₂ can be stored permanently in coal. The concept of storing CO₂ in geologic formations as a safe and effective greenhouse gas mitigation option requires public and regulatory acceptance. In this context it is important to develop a good understanding of the reservoir performance, uncertainties and the risks that are associated with geological storage. The paper presented refers to the sources of uncertainty involved in CO₂ storage performance assessment in coalbed methane reservoirs and demonstrates their significance using extensive digital well log data representing the Manville coals in Alberta, Canada. The spatial variability of the reservoir properties was captured through geostatistical analysis, and sequential Gaussian simulations of these provided multiple realisations for the reservoir simulator inputs. A number of CO₂ injection scenarios with variable matrix swelling coefficients were evaluated using a 2D reservoir model and spatially distributed realisations of total net thickness and permeability.     

An experimental and numerical investigation into the impact of dissolution/precipitation mechanisms on CO2 injectivity in the wellbore and far field regions

Carbon dioxide capture and storage (CCS) technology is gaining credibility as the best short to medium term solution for significantly reducing net carbon emissions into the atmosphere. From a capacity point of view, deep saline aquifers offer the greatest potential for CO₂ storage. In this respect, well injectivity is considered a key technical and economical issue. Rock/fluid interactions – dissolution/precipitation of minerals, in particular carbonates – are currently considered as one of the principal reasons for wellbore injectivity changes in aquifers.This research investigated the mechanisms involved in injectivity losses through experimental and theoretical methods. The impact on injectivity of permeability changes occurring at various distances from the wellbore was studied using an idealised CO₂ injection well flow model. A new experimental set-up was used to investigate the effect on dissolution/precipitation mechanisms of the pressure and temperature changes that the fluid is subjected to as it advances from the wellbore.Numerical modelling of the injection wellbore has shown that changes in the petrophysical properties of the reservoir several metres away from the wellbore can still have a significant impact on injectivity. As indicated by the experimental research carried out, pressure and temperature gradients that exist inside the reservoirs may lead to re-precipitation in the far field, however no significant permeability and porosity changes were detected to suggest major losses of injectivity due to these effects.     

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.     

Intermediate storage of carbon dioxide in geological formations: A technical perspective

Enhanced oil recovery (EOR) through CO₂ flooding has been practiced on a commercial basis for the last 35 years and continues today at several sites, currently injecting in total over 30 million tons of CO₂ annually. This practice is currently exclusively for economic gain, but can potentially contribute to the reduction of emissions of greenhouse gases provided it is implemented on a large scale. Optimal operations in distributing CO₂ to CO₂-EOR or enhanced gas recovery (EGR) projects (referred to here collectively as CO₂-EHR) on a large scale and long time span imply that intermediate storage of CO₂ in geological formations may be a key component. Intermediate storage is defined as the storage of CO₂ in geological media for a limited time span such that the CO₂ can be sufficiently reproduced for later use in CO₂-EHR. This paper investigates the technical aspects, key individual parameters and possibilities of intermediate storage of CO₂ in geological formations aiming at large scale implementation of carbon dioxide capture and storage (CCS) for deep emission reduction. The main parameters are thus the depth of injection and density, CO₂ flow and transport processes, storage mechanisms, reservoir heterogeneity, the presence of impurities, the type of the reservoirs and the duration of intermediate storage. Structural traps with no flow of formation water combined with proper injection planning such as gas-phase injection favour intermediate storage in deep saline aquifers. In depleted oil and gas fields, high permeability, homogeneous reservoirs with structural traps (e.g. anticlinal structures) are good candidates for intermediate CO₂ storage. Intuitively, depleted natural gas reservoirs can be potential candidates for intermediate storage of carbon dioxide due to similarity in storage characteristics.     

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.     

A method for quick assessment of CO2 storage capacity in closed and semi-closed saline formations

Saline aquifers of high permeability bounded by overlying/underlying seals may be surrounded laterally by low-permeability zones, possibly caused by natural heterogeneity and/or faulting. Carbon dioxide (CO₂) injection into and storage in such “closed” systems with impervious seals, or “semi-closed” systems with non-ideal (low permeability) seals, is different from that in “open” systems, from which the displaced brine can easily escape laterally. In closed or semi-closed systems, the pressure buildup caused by continuous industrial-scale CO₂ injection may have a limiting effect on CO₂ storage capacity, because geomechanical damage caused by overpressure needs to be avoided. In this research, a simple analytical method was developed for the quick assessment of the CO₂ storage capacity in such closed and semi-closed systems. This quick-assessment method is based on the fact that native brine (of an equivalent volume) displaced by the cumulative injected CO₂ occupies additional pore volume within the storage formation and the seals, provided by pore and brine compressibility in response to pressure buildup. With non-ideal seals, brine may also leak through the seals into overlying/underlying formations. The quick-assessment method calculates these brine displacement contributions in response to an estimated average pressure buildup in the storage reservoir. The CO₂ storage capacity and the transient domain-averaged pressure buildup estimated through the quick-assessment method were compared with the “true” values obtained using detailed numerical simulations of CO₂ and brine transport in a two-dimensional radial system. The good agreement indicates that the proposed method can produce reasonable approximations for storage–formation–seal systems of various geometric and hydrogeological properties.     

Analytical solution for estimating storage efficiency of geologic sequestration of CO2

During injection of carbon dioxide (CO₂) into deep saline aquifers, the available pore volume of the aquifer may be used inefficiently, thereby decreasing the effective capacity of the repository for CO₂ storage. Storage efficiency is the fraction of the available pore space that is utilized for CO₂ storage, or, in other words, it is the ratio between the volume of stored CO₂ and the maximum available pore volume. In this note, we derive and present simple analytical expressions for estimating CO₂ storage efficiency under the scenario of a constant-rate injection of CO₂ into a confined, homogeneous, isotropic, saline aquifer. The expressions for storage efficiency are derived from models developed previously by other researchers describing the shape of the CO₂-brine interface. The storage efficiency of CO₂ is found to depend on three dimensionless groups, namely: (1) the residual saturation of brine after displacement by CO₂; (2) the ratio of CO₂ mobility to brine mobility; (3) a dimensionless group (which we call a “gravity factor”) that quantifies the importance of CO₂ buoyancy relative to CO₂ injection rate. In the particular case of negligible residual brine saturation and negligible buoyancy effects, the storage efficiency is approximately equal to the ratio of the CO₂ viscosity to the brine viscosity. Storage efficiency decreases as the gravity factor increases, because the buoyancy of the CO₂ causes it to occupy a thin layer at the top of the confined formation, while leaving the lower part of the aquifer under-utilized. Estimates of storage efficiency from our simple analytical expressions are in reasonable agreement with values calculated from simulations performed with more complicated multi-phase-flow simulation software. Therefore, we suggest that the analytical expressions presented herein could be used as a simple and rapid tool to screen the technical or economic feasibility of a proposed CO₂ injection scenario.     

Scenario simulations of CO2 injection feasibility, plume migration and storage in a saline aquifer, Scania, Sweden

Deep saline aquifers have large capacity for geological CO₂ storage, but are generally not as well characterized as petroleum reservoirs. We here aim at quantifying effects of uncertain hydraulic parameters and uncertain stratigraphy on CO₂ injectivity and migration, and provide a first feasibility study of pilot-scale CO₂ injection into a multilayered saline aquifer system in southwest Scania, Sweden. Four main scenarios are developed, corresponding to different possible interpretations of available site data. Simulation results show that, on the one hand, stratigraphic uncertainty (presence/absence of a thin mudstone/claystone layer above the target storage formation) leads to large differences in predicted CO₂ storage in the target formation at the end of the test (ranging between 11% and 98% of injected CO₂ remaining), whereas other parameter uncertainty (in formation and cap rock permeabilities) has small impact. On the other hand, the latter has large impact on predicted injectivity, on which stratigraphic uncertainty has small impact. Salt precipitation at the border of the target storage formation affects CO₂ injectivity for all considered scenarios and injection rates. At low injection rates, salt is deposited also within the formation, considerably reducing its availability for CO₂ storage.     

Hydraulic characterisation of the Stuttgart formation at the pilot test site for CO2 storage, Ketzin, Germany

The paper presents an approach for the interpretation of hydraulic tests of a CO₂ storage reservoir. The sandstone reservoir is characterised by a fluviatile channel structure embedded in a low-permeability matrix. Pumping tests were carried out in three wells, with simultaneous pressure monitoring in each well.The hydraulic parameters (permeability and storativity) and the boundary configurations were calibrated using three different approaches: (i) parameter calibration and type curve interpretation for single-hole tests, (ii) calibration of the entire build-up phase for cross-hole tests, and (iii) calibration of the initial pressure response for cross-hole pumping tests. In addition, the arrival time of the pressure response was determined and provides additional information about the pathways of hydraulic connection.The measured pumping test permeabilities of the formation were much lower than those measured on the cores, which is very unusual. The pumping test permeabilities are mainly between 50 mD and 100 mD (millidarcy), while core samples show a mean aquifer permeability of 500–1100 mD. Based on this it was concluded that some kind of continuous low-permeability structure exists, which was supported by core material. Three possible aquifer configurations were considered. The first and second were derived from traditional pumping test analysis and were conceptualised using flow boundaries. Each of the analyses provides a different result. A method was developed in which these differences were resolved by interpreting the pressure response with respect to its spatial and temporal sensitivity. This solution lead to a third configuration which was mainly based on spatially-variable permeabilities. Taking into account the pumping test results, the geological background and the behaviour of injected CO₂, we consider only the third configuration to be realistic. The results are in good agreement with modelled CO₂ arrival times and pressure history.     

Integration of counter-current relative permeability in the simulation of CO2 injection into saline aquifers

Carbon dioxide (CO₂) injection into saline aquifers is one of the promising options to sequester large amounts of CO₂ in geological formations. During as well as after injection of CO₂ into an aquifer, CO₂ migrates towards the top of the formation due to density differences between the formation brine and the injected CO₂. The time scales of CO₂ migration towards the top of an aquifer and the fraction of CO₂ that is trapped as residual gas depends strongly on the driving forces that are acting on the injected CO₂.When CO₂ migrates to the top of an aquifer, brine may be displaced downwards in a counter-current flow setting particularly during the injection period. A majority of the published work on counter-current flow settings have reported significant reductions in the associated relative permeability functions as compared to co-current measurements. However, this phenomenon has not yet been considered in the simulation of CO₂ storage into saline aquifers.In this paper we study the impact of changes in mobility for the two-phase brine/CO₂ system as a result of transitions between co- and counter-current flow settings. We have included this effect in a simulator and studied the impact of the related mobility reduction on the saturation distribution and residual saturation of CO₂ in aquifers over relevant time scales. We demonstrate that the reduction in relative permeability in the vertical direction changes the plume migration pattern and has an impact on the amount of gas that is trapped as a function of time. This is to our best knowledge the first attempt to integrate counter-current relative permeability into the simulation of injection and subsequent migration of CO₂ in aquifers. The results and analysis presented in this paper are directly relevant to all ongoing activities related to the design of large-scale CO₂ storage in saline aquifers.     

CLIMATE CHANGE IMPACTS UNCERTAINTY FOR WATER RESOURCES IN THE SAN JOAQUIN RIVER BASIN,CALIFORNIA1

ABSTRACT: A climate change impacts assessment for water resources in the San Joaquin River region of California is presented. Regional climate projections are based on a 1 percent per year CO₂ increase relative to late 20th Century CO₂ conditions. Two global projections of this CO₂ increase scenario are considered (HadCM2 and PCM) during two future periods (2010 to 2039 and 2050 to 2079). HadCM2 projects faster warming than PCM. HadCM2 and PCM project wetter and drier conditions, respectively, relative to present climate. In the HadCM2 case, there would be increased reservoir inflows, increased storage limited by existing capacity, and increased releases for deliveries and river flows. In the PCM case, there would be decreased reservoir inflows, decreased storage and releases, and decreased deliveries. Impacts under either projection case cannot be regarded as more likely than the other. Most of the impacts uncertainty is attributable to the divergence in the precipitation projections. The range of assessed impacts is too broad to guide selection of mitigation projects. Regional planning agencies can respond by developing contingency strategies for these cases and applying the methodology herein to evaluate a broader set of CO₂ scenarios, land use projections, and operational assumptions. Improved agency access to climate projection information is necessary to support this effort.     

Analytical solution to evaluate salt precipitation during CO2 injection in saline aquifers

Carbon dioxide sequestration in deep saline aquifers is a means of reducing anthropogenic atmospheric emissions of CO₂. Among various mechanisms, CO₂ can be trapped in saline aquifers by dissolution in the formation water. Vaporization of water occurs along with the dissolution of CO₂. Vaporization can cause salt precipitation, which reduces porosity and impairs permeability of the reservoir in the vicinity of the wellbore, and can lead to reduction in injectivity. The amount of salt precipitation and the region in which it occurs may be important in CO₂ storage operations if salt precipitation significantly reduces injectivity. Here we develop an analytical model, as a simple and efficient tool to predict the amount of salt precipitation over time and space. This model is particularly useful at high injection velocities, when viscous forces dominate.First, we develop a model which treats the vaporization of water and dissolution of CO₂ in radial geometry. Next, the model is used to predict salt precipitation. The combined model is then extended to evaluate the effect of salt precipitation on permeability in terms of a time-dependent skin factor. Finally, the analytical model is corroborated by application to a specific problem with an available numerical solution, where a close agreement between the solutions is observed. We use the results to examine the effect of assumptions and approximations made in the development of the analytical solution. For cases studied, salt saturation was a few percent. The loss in injectivity depends on the degree of reduction of formation permeability with increased salt saturation. For permeability-reduction models considered in this work, the loss in injectivity was not severe. However, one limitation of the model is that it neglects capillary and gravity forces, and these forces might increase salt precipitation at the bottom of formation particularly when injection rate is low.     

Petrophysical analysis to investigate the effects of carbon dioxide storage in a subsurface saline aquifer at Ketzin, Germany (CO2SINK)

To test the injection behaviour of CO₂ into brine-saturated rock and to evaluate the dependence of geophysical properties on CO₂ injection, flow and exposure experiments with brine and CO₂ were performed on sandstone samples of the Stuttgart Formation representing potential reservoir rocks for CO₂ storage. The sandstone samples studied are generally fine-grained with porosities between 17 and 32% and permeabilities between 1 and 100 mD.Additional batch experiments were performed to predict the long-term behaviour of geological CO₂ storage. Reservoir rock samples were exposed over a period of several months to CO₂-saturated reservoir fluid in high-pressure vessels under in situ temperature and pressure conditions. Petrophysical parameters, porosity and the pore radius distribution were investigated before and after the experiments by NMR (Nuclear Magnetic Resonance) relaxation and mercury injection. Most of the NMR measurements of the tested samples showed a slight increase of porosity and a higher proportion of large pores.     

Simultaneous CO2 injection and water production to optimise aquifer storage capacity

The estimates for geological CO₂ storage capacity worldwide vary, but it is generally believed that the capacity in saline aquifers will be sufficient for the amounts of CO₂ that will need to be stored. The effort required to select and qualify a geological storage site for safe storage will, however, be significant and storage capacity may be a limited resource regionally. Both from a economic and resource management perspective it is therefore important that potential storage sites are exploited to their full potential.In static capacity estimates, where the maximum stored amount of CO₂ is given as a fraction of the formation pore volume, typically arrive at efficiency factors in the range of a few per cents. Recent work has shown that when the dynamic behaviour of the injected CO₂ is taken into account, the efficiency factor will be reduced because of the increase in pore pressure in the region around the injection well(s). The increase in pore pressure will propagate much further than the CO₂. The EU directive on geological CO₂ storage specifically addresses the restriction that will apply when different storage sites are interacting due to pressure communication. Consequently, the pore pressure increase at the boundary of the storage license area will be an important limiting factor for the amount of CO₂ that can be injected.One obvious method to control the pore pressure is to produce water from the aquifer at some distance from the CO₂ injection wells. This paper discusses results from simulations of CO₂ injection in two aquifers on the Norwegian Continental Shelf; the Johansen aquifer and the southern part of the Utsira aquifer. These aquifers are candidates for injection of CO₂ shipped out via pipeline from the Norwegian West Coast. The injected amounts of CO₂ over a period of 50 years are 0.518 Gtonne for the Johansen aquifer and 1.04 Gtonne for the Utsira aquifer.Several design options for the injection operations are investigated: Injection of CO₂ without water production; injection into several wells to distribute the injected fluids and reduce the local pressure increase around each injection well; and injection with simultaneous production of water from one or more wells. The boundaries of the aquifer formations are assumed closed in all simulations. The possible consequences of other types of boundary conditions (semi-closed or open) are briefly discussed.     

Modeling the impacts of climate policy on the deployment of carbon dioxide capture and geologic storage across electric power regions in the United States

This paper summarizes the results of a first-of-its-kind holistic, integrated economic analysis of the potential role of carbon dioxide (CO₂) capture and storage (CCS) technologies across the regional segments of the United States (U.S.) electric power sector, over the time frame 2005–2045, in response to two hypothetical emissions control policies analyzed against two potential energy supply futures that include updated and substantially higher projected prices for natural gas. This paper's detailed analysis is made possible by combining two specialized models developed at Battelle: the Battelle CO₂-GIS to determine the regional capacity and cost of CO₂ transport and geologic storage; and the Battelle Carbon Management Electricity Model, an electric system optimal capacity expansion and dispatch model, to examine the investment and operation of electric power technologies with CCS against the background of other options. A key feature of this paper's analysis is an attempt to explicitly model the inherent heterogeneities that exist in both the nation's current and future electricity generation infrastructure and in its candidate deep geologic CO₂ storage formations. Overall, between 180 and 580 gigawatts (GW) of coal-fired integrated gasification combined cycle with CCS (IGCC + CCS) capacity is built by 2045 in these four scenarios, requiring between 12 and 41 gigatonnes of CO₂ (GtCO₂) storage in regional deep geologic reservoirs across the U.S. Nearly all of this CO₂ is from new IGCC + CCS systems, which start to deploy after 2025. Relatively little IGCC + CCS capacity is built before that time, primarily under unique niche opportunities. For the most part, CO₂ emissions prices will likely need to be sustained at over $20/tonne CO₂ before CCS begins to deploy on a large scale within the electric power sector. Within these broad national trends, a highly nuanced picture of CCS deployment across the U.S. emerges. Across the four scenarios studied here, power plant builders and operators within some North American Electric Reliability Council (NERC) regions do not employ any CCS while other regions build more than 100 GW of CCS-enabled generation capacity. One region sees as much as 50% of its geologic CO₂ storage reservoirs’ total theoretical capacity consumed by 2045, while most of the regions still have more than 90% of their potential storage capacity available to meet storage needs in the second half of the century and beyond. A detailed presentation of the results for power plant builds and operation in two key regions: ECAR in the Midwest and ERCOT in Texas, provides further insight into the diverse set of economic decisions that generate the national and aggregate regional results.