Search USGS⌕ Search

Geology topics

Steven T. Anderson

Publications and source records attributed to Steven T. Anderson.

At least 19 recordsLinked to original sources
USGS2025

Estimation of dynamic geologic CO2 storage resources in the Illinois Basin, including effects of brine extraction, anisotropy, and hydrogeologic heterogeneity

Since the vast majority of carbon dioxide (CO 2 ) storage resources in the United States are in deep saline aquifers, optimizing the use of these saline storage resources could be crucial for efficient development of geologic CO 2 storage (GCS) resources and basin- or larger-scale deployment of GCS in the country. Maximum CO 2 injection rates can be enhanced by extracting brine from the CO 2 storage unit. However, disposal of the extracted brine is both a technological and economic challenge. The lowest-cost option would likely be reinjection of the extracted brine into another formation above or below the CO 2 storage unit. Therefore, it is important to estimate brine injectivity as it will constrain the potential to increase CO 2 injectivity at an injection site that has access to multiple geologic storage units where either CO 2 or brine can be injected. Using a simulation-optimization framework, coupled with a non-isothermal, multiphase CO 2 -water-salt equation-of-state module, we developed a computationally efficient method for evaluating optimization of simultaneous CO 2 injection, brine extraction, and brine (re)injection at hypothetical injection sites deployed across a geologic basin. The Illinois basin is ideal for testing our methodology because it contains multiple geologic storage units with seals in between them to isolate injection of CO 2 in one unit from interfering with the injection of either brine or CO 2 in another unit above or below it. In addition, we investigated the relative effects of variation in key geologic parameters as well as two reservoir structures (hydrogeologic heterogeneity/anisotropy and homogeneity/isotropy) on CO 2 injectivities and enhancement of CO 2 injectivity through extracting brine. Results suggest that permeability, depth, and especially thickness of the storage unit could be the most influential parameters determining CO 2 injectivity. They also suggest that only injecting CO 2 into the storage unit with the greatest injectivity, enhancing that unit’s injectivity by extracting brine, and disposing of the produced brine in other suitable units could maximize total CO 2 injectivity in limited regions of the basin. At the majority of simulated injection sites, however, we found that injecting CO 2 into all of the accessible and suitable storage units was more likely to maximize the CO 2 storage resource.

Illinois, Kentucky, Indiana↗
USGS2025

Estimated ultimate recovery (EUR) Prediction for Eagle Ford Shale using integrated datasets and artificial neural networks

The estimated ultimate recovery (EUR) is an important parameter for forecasting oil and gas production and informing decisions regarding field development strategies. In this study, we combined site-specific geologic, completion, and operational parameters with the predictive capabilities of machine learning (ML) models to predict EURs of the wells for the Eagle Ford Marl Continuous Oil Assessment Unit. We developed an extensive dataset of wells that have produced from the lower and upper Eagle Ford Shale intervals and reduced the model complexity using principal component analysis. We tested the ML models and estimated the sensitivities of ML-predicted EURs to changes in the values of different input variables. The results of applying the optimized ML model to the Eagle Ford suggest that the approach developed in this study could be promising. The ML estimates of the EURs fit the DCA-based values with an R 2 ~ 0.9 and a mean absolute error of ~36 × 10 3 bbl. In the lower Eagle Ford Shale, the EUR estimates were found to be most sensitive to changes in porosity, net thickness of the interval, clay volume, and the API gravity of the oil; and that in the upper Eagle Ford Shale they were most sensitive to changes in the total organic carbon and water saturation, which suggests that it could be important to consider these parameters in assessing these intervals or close analogs.

Louisiana, Mississippi, Texas↗
USGS2024

Managing basin-scale carbon sequestration: A tragedy of the commons approach

The Tragedy of the Commons is a well studied problem in the literature of ecology, economics, and environmental policy which illustrates the deleterious consequences of managing common pool resources when individual and social incentives are misaligned. In this work, we apply a simple model of carbon sequestration in a deep saline aquifer by two neighboring geologic CO 2 storage (GCS) operators to begin investigating if a Tragedy of the Commons framework applies to GCS. Specifically, we consider the pressure space as a “commons” because the injection by each firm at its own well increases the downhole injection pressure at both wells. We assume that a firm will decrease its injection rate if the downhole pressure at its well exceeds a predefined maximum (i.e., exceeds the “pressure limit”). With this assumption in place, we find that the same injection flowrates are optimal for both wells, regardless of whether they are owned by the same firm or competing firms. This suggests that GCS may not be best represented by a pure Tragedy of the Commons framework under our initial assumptions. However, there could be economic incentives or contractual obligations that may result in either or both GCS operators being unwilling to reduce their injection rates. Thus, we conclude the conference paper with a discussion of future extensions of our approach that may demonstrate closer alignment with the Tragedy of the Commons, including explicit definitions of pore-space rights, firm uncertainty regarding the parameters of the Theis equation, and the potential role of unitization.

Conference Paper↗
USGS2024

Energy-related rare earth element sources

Energy-related materials such as coal, coal-bearing wastes, and coal combustion products are traditionally thought of as sources or by-products of electric power generation. Increasingly, these materials are considered resources for their content of rare earth elements (REEs) and other useful constituents. In this chapter, we examine the distribution, modes of occurrence, and relative extractability of REEs from coal-derived materials. We also consider economic factors associated with recovery of REEs from these sources. While several coal-derived sources show promise for REE recovery at the pilot scale, in all cases, REE contents are much below those of primary ores, such that extraction and concentrating the REEs require new and innovative approaches that are largely developmental. Among coal-related sources, fly ash is the most REE-enriched, as REEs from coal are strongly retained in these refractory solids remaining after coal combustion. Partitioning of coal-derived elements into fly ash has been known for decades but this has yet to be commercially exploited. A key drawback shown in this chapter is that a significant fraction of REEs in fly ash is contained in highly insoluble aluminosilicate glasses that make up the largest portion of this material. In addition to testing chemical or physical pretreatment approaches to help improve the extractability of REEs from fly ash, current research is applying modern analytical approaches to better understand the distribution of REEs on increasingly smaller scales, in the interest of targeting their recovery. Next-most REE-enriched among coal-related materials are solid waste products of coal mining and wastes from coal preparation, both of which are REE-enriched relative to coal itself. These waste coals concentrate mineralogical constituents that are excluded during mining or removed during coal preparation because they do not contribute to the heating value of coal for power generation. Recovery of REEs from coal waste has shown promise at the pilot scale and has the added benefit of converting a waste into useful constituents. Total REE contents of commercial coals are, on average, much below the 300 parts per million interest level for REE recovery set by the U.S. Department of Energy (DOE). However, as reviewed in this chapter, certain horizons within coal beds show preferential REE enrichment and could be targeted by selective mining. Beyond this, certain coals are REE-enriched overall due to their unique geologic histories involving derivation from REE-enriched sediment sources, deposition of volcanic ash during coal formation, or interaction of coal with REE-bearing fluids. Acidic drainage from abandoned coal mines is produced by the breakdown of pyrite (FeS 2 ), which is unstable in oxygenated conditions. While these acidic fluids have lower REE contents than any of the coal-based solids described above, they are proportionally enriched in certain heavy rare earths, especially yttrium (Y). Precipitates from coal-based acid-mine drainage concentrate REEs to levels that are of interest for recovery, and these are also promising sources for extraction at the pilot scale.

Book chapter↗
USGS2023

Geologic energy storage

Introduction As the United States transitions away from fossil fuels, its economy will rely on more renewable energy. Because current renewable energy sources sometimes produce variable power supplies, it is important to store energy for use when power supply drops below power demand. Battery storage is one method to store power. However, geologic (underground) energy storage may be able to retain vastly greater quantities of energy over much longer durations compared to typical battery storage. Geologic energy storage also has high flexibility; many different types of materials can be used to store chemical, thermal, or mechanical energy in a variety of underground settings. The U.S. Geological Survey (USGS) has the capability to research and assess possible domestic geologic energy storage resources to help prepare the United States for the future of renewable energy.

Fact Sheet↗
USGS2022

Dynamic estimates of geologic CO2 storage resources in the Illinois Basin constrained by reinjectivity of brine extracted for pressure management

Geologic carbon storage (GCS) is likely to be an important part of global efforts to decarbonize the energy industry. Widespread deployment of GCS relies on strategies to maximize CO 2 injection rates while minimizing reservoir pressurization that could induce seismicity and/or fluid leakage into groundwater resources. Brine extraction from CO 2 storage formations with subsurface reinjection elsewhere could mitigate pressure buildup associated with GCS. Therefore, evaluation of CO 2 storage resources should consider the injectivity of produced brine in geologic layers above or below the CO 2 storage formation. For this study, a methodology was developed to estimate brine injectivity from formation depth and thickness using flow modeling and optimization techniques. The methodology was demonstrated in the Illinois Basin, where GCS in the Mt. Simon Sandstone is ongoing. Based on pressure constraints and considering only regions of the shallower units where salinity and sealing conditions were met, maximum brine injection rates were estimated within the Mt. Simon and three overlying hydrostratigraphic layers. Results indicate that a large area exists where CO 2 injectivity could be optimized by brine extraction and reinjection.

Illinois, Indiana↗
USGS2020

Estimating the net costs of brine production and disposal to expand pressure-limited dynamic capacity for basin-scale CO2 storage in a saline formation

If carbon capture and storage (CCS) needs to be deployed at basin- or larger-scale, it is likely that multiple sites will be injecting carbon dioxide (CO 2 ) into the same geologic formation. This could lead to excessive pressure buildup, overlapping induced pressure fronts, and pressure interference with neighboring uses of the subsurface. Extracting the in situ brine from the storage formation could be necessary to relieve pressure constraints; control migration of the CO 2 plume, displaced brine, and the induced pressure front; and sequester more CO 2 while reducing potential risks. Such active pressure management could be very costly, and it could present a formidable economic constraint on the feasible scale of deployment of CCS. Alternatively, there may be high-injectivity zones (“storage sweet spots”) where a significant volume of CO 2 could be stored without producing brine. For simulated deployment of CO 2 storage sites across the Illinois Basin, the results of this study suggest that brine production could be required to sequester 20 % or more of the regional CO 2 emissions of major stationary sources in the Mount Simon Sandstone saline formation. In some cases, brine production could expand pressure-limited CO 2 storage capacity enough to more than compensate for the additional costs of pressure management, but only if produced brine could be cheaply reinjected onsite for disposal in an overlying geologic formation. With or without brine production, this study found that the lowest-cost deployment option was to inject CO 2 only into a potential storage sweet spot of the Mount Simon Sandstone.

Illinois, Indiana↗
USGS2019

Carbon dioxide mineralization feasibility in the United States

Geologic carbon dioxide (CO 2 ) storage is one of many methods for stabilizing the increasing concentration of CO 2 in the Earth’s atmosphere. The injection of CO 2 in deep subsurface sedimentary reservoirs is the most commonly discussed method; however, the potential for CO 2 leakage can create long-term stability concerns. This report discusses the feasibility of an alternative form of geologic CO 2 storage: CO 2 mineralization. In this method, CO 2 reacts with rocks and minerals to form solid and stable carbonate rocks. New pilot projects and laboratory-based kinetics experiments have revealed that this method, both in situ and ex situ, may be a viable option for storage. In situ storage targets in-place rocks at the surface or subsurface. Ex situ storage targets industrial byproducts at the surface like mine tailings. Environmental risks include induced seismicity for in situ methods if pressure is not managed properly, as well as potential water and land use effects. However, there are fewer long-term CO 2 -leakage concerns for mineralization methods compared to saline storage methods and therefore potentially lower long-term monitoring costs. The costs and benefits of CO 2 mineralization are compared to those of CO 2 storage in saline reservoirs using estimates of pressure-limited dynamic storage capacity. This report highlights the regional potential of areas in the United States for in situ and ex situ storage, as well as their proximity to potential sources of CO 2 . Especially suitable targets include asbestos or other ultramafic mine tailings, in situ ultramafic rocks on the East and West Coasts, the Columbia River basalts in the Pacific Northwest, the Midcontinent Rift basalts in the midcontinent, and the basaltic Hawaiian Islands.

Scientific Investigations Report↗
USGS2019

Estimating the pressure-limited dynamic capacity and costs of basin-scale CO2 storage in a Saline Formation

Deployment of carbon capture and storage (CCS) could be necessary to be able to satisfy baseload electricity demand, maintain diversity in the energy mix, and achieve mitigation of carbon dioxide (CO 2 ) emissions at lowest cost ( IPCC, 2015 ; U.S. DOE, 2016 ). If basin-, regional- or national-scale deployment of CCS is needed, it may be possible to store only a small fraction of the captured CO 2 in oil and natural gas reservoirs. The vast majority would likely have to be stored in saline formations. Pressure buildup as a result of injecting CO 2 into such reservoirs is expected to be an important source of risk associated with CO 2 storage, and could constrain dynamic storage capacities (maximum injection rates) to be far below estimates based on access to theoretical storage resources. Estimates of CO 2 storage costs based on an assumption of practical availability of the theoretical storage resource could lead to underestimation of the costs of CO 2 storage. In this study, simulation results suggest that the pressure-limited dynamic CO 2 storage capacity of the Mount Simon Sandstone could be less than 4% of the theoretical storage resource in this saline formation, and storage costs could be an order of magnitude higher than recent estimates. However, consideration of the geologic heterogeneity in this deep saline formation allowed definition of a high injectivity zone, and estimated costs of CO 2 storage in this “sweet spot” of the reservoir approached recent estimates that did not include costs for pressure management.

Illinois, Indiana, Kentucky↗
USGS2019

Improving pressure-limited CO2 storage capacity in saline formations by means of brine extraction

The carbon dioxide (CO 2 ) storage capacity of saline formations may be constrained by reservoir pressure limitations. Brine extraction could be necessary to increase the CO 2 storage capacity of a given formation, manage the extent of the underground CO 2 plume and induced pressure front, and control the migration direction. To estimate the additional CO 2 storage capacity of a saline formation that can be made accessible by extraction of in-situ brines, a three-dimensional (3D) generic cubic cell containing one CO 2 injector in the middle surrounded by four brine extractors at each corner of the cell was assumed. A series of Tough2-ECO2N reservoir simulations were constructed with varying reservoir properties and run. Based on a series of scenarios, a mechanism was developed and demonstrated that resulted in derivation of a function to provide estimates of the ratio of total CO 2 injection over the brine extraction rate for a given scenario. We selected multiple saline formations in U.S. basins and evaluated the potential to increase the combined dynamic CO 2 storage capacity of the selected saline formations to over 1000 million metric tonnes per year (Mt/yr) of CO 2 for 100 years by means of brine extraction. Such storage capacities may be adequate to accommodate the CO 2 injection rates suggested for the United States under a “beyond two-degree Celsius scenario” (B2DS) that has been proposed to maintain global temperature rise to less than 2°C above pre-industrial reported levels. The results suggest that B2DS goals could be achieved with a volume ratio of brine extraction to CO 2 injection as low as 1:4, which is far lower than the ratios that have been commonly assumed in the literature.

International Journal of Greenhouse Gas Control↗
USGS2019

Estimating market conditions for potential entry of new sources of anthropogenic CO2 for EOR in the Permian Basin

This study attempts to determine feasible carbon dioxide (CO2) price thresholds for entry of new sources of anthropogenic (man-made) CO2 for utilization in enhanced oil recovery (EOR) in the Permian Basin. Much of the discussion about carbon capture, utilization, and storage (CCUS) has focused on the high costs of carbon capture as the major barrier to entry of new anthropogenic sources of CO2 for EOR. In addition, a recent study by Edwards and Celia (2018) suggests that the lack of a CO2 transportation network to efficiently transport CO2 from ethanol plants in the Midwest to EOR sites in the Permian Basin could be a prohibitive barrier to commercial-scale entry (without some Government assistance to help finance the construction of new CO2 pipelines), despite the costs of carbon capture from ethanol plants being relatively low. Thus, entry of additional sources of anthropogenic CO2 for use in EOR in the Permian Basin could be primarily by major carbon emitters that are located closest to the existing CO2 pipeline network that currently transports mostly natural CO2 (extracted from geologic reservoirs) to EOR sites. Data from the U.S. Environmental Protection Agency (EPA)’s Greenhouse Gas Reporting Program (GHGRP) (U.S. Environmental Protection Agency, 2019) suggest that numerous major CO2 emitters are located within 50 km of the existing pipeline network that provides CO2 for EOR in the Permian Basin. The costs for connecting these potential sources of CO2 to the existing transportation infrastructure could be very low. Of these potential sources of anthropogenic CO2, the leading emitters are coal-fired electricity generation plants, and the sources with next-largest emissions are natural gas-fired power plants. However, the CO2 concentrations in the emission streams of these types of power plants is typically far lower than that for ethanol plants and some other industrial facilities (including natural gas processing plants), which causes the estimated capture costs (using currently available technologies) to be far higher, in general. In addition, the potential cost (per metric ton of CO2 supplied) of adding these new sources of anthropogenic CO2 for EOR in the Permian basin could be greater than expanding production of existing suppliers and developing new sources of natural CO2. On the other hand, their proximity to the existing pipeline network could allow them to be viable sources of anthropogenic CO2 for EOR in the Permian Basin, and the relative competitiveness of these sources with the existing use of natural CO2 could be further enhanced if they qualify for the recently revised 45Q tax credit (Heitkamp, 2017). The results of this study provide some estimates of the potential gaps in the costs of CO2 supply from these distinct sources, and the potential implications of the results for the market conditions that could be necessary to overcome those gaps are discussed.

Conference Paper↗
USGS2018

Estimating the pressure-limited CO2 injection and storage capacity of the United States saline formations: Effect of the presence of hydrocarbon reservoirs

The U.S. Geological Survey (USGS) national assessment of carbon dioxide (CO 2 ) storage capacity evaluated 192 saline Storage Assessment Units (SAUs) in 33 U.S. onshore sedimentary basins that may be utilized for CO 2 storage (see USGS Circular 1386). Similar to many other available models, volumetric analysis was utilized to estimate the initial CO 2 injection and storage capacity of these SAUs based on aquifer characteristics and buoyant and residual trapping. The factor being almost always overlooked in most CO 2 storage capacity models is that many of the evaluated SAUs contain large numbers of both conventional and unconventional discovered and undiscovered oil and gas reservoirs. The hydrocarbon production and pressure distribution of the resident oil and gas reservoirs may be negatively influenced by the propagated CO 2 plume and pressure front resulting from a CO 2 injection and storage operation in the surrounding SAU. To have a more realistic and accurate estimation of CO 2 injection and storage capacity in saline formations, a model was previously developed that considers the CO 2 injectivity of a given formation, underground pressure build-up limitations imposed by the rock fracturing pressure and the presence of hydrocarbon reservoirs within these aquifers. The developed method estimates the pre–brine extraction, pressure-limited CO 2 injection and storage capacity of a saline formation by applying 3D numerical simulation only on the effective injection area (A eff ) surrounding each CO 2 injection well utilizing TOUGH2-ECO2N simulation software.

Sligo and Hosston Formations↗
USGS2018

Estimating the potential costs of brine production to expand the pressure-limited CO2 storage capacity of the Mount Simon Sandstone

The conventional wisdom is that widespread deployment of carbon capture and storage (CCS) is likely necessary to be able to satisfy baseload electricity demand, to maintain diversity in the energy mix, and to achieve mitigation of carbon dioxide (CO2) emissions at lowest cost (IPCC, 2014). If national-scale deployment of CCS is needed in the United States, it may be possible to store only a small fraction of the captured CO2 in oil and natural gas reservoirs (including as a result of CO2 stored in conjunction with utilization for enhanced oil recovery). The vast majority of the captured CO2 would have to be stored in brine-filled reservoirs (Dahowski et al., 2005). Given a lack of long-term commercial-scale CCS projects, there is considerable uncertainty in the risks, dynamic capacity (maximum rate of injection), and their cost implications for geologic storage of CO2. Pressure buildup in the storage reservoir is expected to be a primary source of risk associated with CO2 storage, and could severely limit storage capacities. Most current cost estimates for commercial-scale deployment of CCS estimate CO2 storage costs under assumed availability of a theoretical geologic capacity to store tens, hundreds, or even thousands of gigatons of CO2, without including the costs of the pressure management that will be necessary to make that storage capacity practically available. These assumptions often lead to considerable underestimation of the costs of CO2 storage (Anderson, 2017). We consider the potential impacts on CO2 storage capacity and costs of producing formation waters (brines) to manage pressure. Given that pressure limitations could constrain injection rates per well to be far below the design capacity of a typical CO2 injection well, brine production could possibly increase the efficiency of CO2 injection. We analyze the net costs of pressure management by producing brines. Our results could have implications for how long and to what extent decision makers can expect to be able to deploy CCS before transitioning to other low- or zero-carbon energy technologies.

Conference Paper↗
USGS2017

Economics, helium, and the U.S. Federal Helium Reserve: Summary and outlook

In 2017, disruptions in the global supply of helium reminded consumers, distributors, and policy makers that the global helium supply chain lacks flexibility, and that attempts to increase production from the U.S. Federal Helium Reserve (the FHR) may not be able to compensate for the loss of one of the few major producers in the world. Issues with U.S. and global markets for helium include inelastic demand, economic availability of helium only as a byproduct, only 4–5 major producers, helium’s propensity to escape earth’s crust, an ongoing absence of storage facilities comparable to the FHR, and a lack of consequences for the venting of helium. The complex combination of these economic, physical, and regulatory issues is unique to helium, and determining helium’s practical availability goes far beyond estimating the technically accessible volume of underground resources. Although most of these issues have been analyzed since helium was recognized to be a valuable mineral commodity in the early 1900s, very few economic models have been developed that adequately consider the unique characteristics of helium and helium markets. In particular, there is a notable lack of recent empirical work to estimate the responsiveness of helium demand, supply, prices, and trade patterns to the ongoing drawdown and sale of helium reserves stored in the FHR. In general, existing models of helium either do not account for an oligopoly controlling supply, or they do not evaluate potential helium extraction and storage programs based on an intertemporal maximization of the value of the resource. Such models could be of very limited use to decision makers. This review found only one working paper with a helium market model that has incorporated both of these vital considerations. That and other economic studies along similar lines could be very useful in helping inform current helium policy discussions and decisions.

Natural Resources Research↗
USGS2017

3D Pressure‐limited approach to model and estimate CO2 injection and storage capacity: saline Mount Simon Formation

To estimate the carbon dioxide (CO 2 ) injection and storage capacity of saline formations, we used Tough2‐ECO2N simulation software to develop a pressure‐limited (dynamic) simulation approach based on applying three‐dimensional (3D) numerical simulation only on the effective injection area (A eff ) surrounding each injection well. A statistical analysis was performed to account for existing reservoir heterogeneity and property variations. The accuracy of the model simulation results (such as CO 2 plume extension and induced injection well bottomhole pressure values) were tested and verified against the data obtained from the Decatur CO 2 injection study of the Mount Simon Formation. Next, we designed a full‐field CO 2 injection pattern by populating the core sections of this formation with a series of the simulated effective injection areas such that each simulated A eff acts as a closed domain. The results of this analysis were used to estimate the optimum number and location of the required CO 2 injection wells, along with the dynamic annual CO 2 injection rate and overall pressure‐limited storage capacity of this formation. This approach enabled us to model separate CO 2 injection activities independently at different sections of the same saline formation and to model and simulate faults and natural barriers by considering them as boundary conditions for each simulated A eff without constructing full‐field models. Using this approach, a series of modeled A eff with relevant properties may be redesigned to model any other saline formation with a similar structure.

Mount Simon Formation↗
USGS2017

Case study - Dynamic pressure-limited capacity and costs of CO2 storage in the Mount Simon sandstone

Widespread deployment of carbon capture and storage (CCS) is likely necessary to be able to satisfy baseload electricity demand, to maintain diversity in the energy mix, and to achieve climate and other objectives at the lowest cost. If all of the carbon dioxide (CO 2 ) emissions from stationary sources (such as fossil-fuel burning power plants, and other industrial plants) in the United States needed to be captured and stored, it could be possible to store only a small fraction of this CO 2 in oil and natural gas reservoirs, including as a result of CO 2 utilization for enhanced oil recovery. The vast majority would have to be stored in saline-filled reservoirs (Dahowski et al., 2005). Given a lack of long-term commercial-scale CCS projects, there is considerable uncertainty in the risks, dynamic capacity, and their cost implications for geologic storage of CO 2 . Pressure buildup in the storage reservoir is expected to be a primary source of risk associated with CO 2 storage, and could severely limit CO 2 injection rates (dynamic storage capacities). Most cost estimates for commercial-scale deployment of CCS estimate CO 2 storage costs under assumed availability of a theoretical capacity to store tens, hundreds, or even thousands of gigatons of CO 2 , without considering geologic heterogeneities, pressure limitations, or the time dimension. This could lead to underestimation of the costs of CO 2 storage (Anderson, 2017). This paper considers the impacts of pressure limitations and geologic heterogeneity on the dynamic CO 2 storage capacity and storage (injection) costs. In the U.S. Geological Survey (USGS)’s National Assessment of Geologic CO 2 Storage Resources (USGS, 2013), the mean estimate of the theoretical storage capacity in the Mount Simon Sandstone was about 94 billion metric tons of CO 2 . However, our results suggest that the pressure-limited capacity after 50 years of injection could be only about 4% of the theoretical geologic storage capacity in this formation. Because this is far less than emissions of CO 2 from stationary sources in the region around the Mount Simon Sandstone, the costs to accommodate the potential annual demand for CO 2 storage in this formation could be significantly greater than current estimates. Our results could have implications for how long and to what extent decision makers can expect to be able to deploy CCS before transitioning to other low- or zero-carbon energy technologies.

Conference Paper↗
USGS2016

Cost implications of uncertainty in CO 2 storage resource estimates: A review

Carbon capture from stationary sources and geologic storage of carbon dioxide (CO 2 ) is an important option to include in strategies to mitigate greenhouse gas emissions. However, the potential costs of commercial-scale CO 2 storage are not well constrained, stemming from the inherent uncertainty in storage resource estimates coupled with a lack of detailed estimates of the infrastructure needed to access those resources. Storage resource estimates are highly dependent on storage efficiency values or storage coefficients, which are calculated based on ranges of uncertain geological and physical reservoir parameters. If dynamic factors (such as variability in storage efficiencies, pressure interference, and acceptable injection rates over time), reservoir pressure limitations, boundaries on migration of CO 2 , consideration of closed or semi-closed saline reservoir systems, and other possible constraints on the technically accessible CO 2 storage resource (TASR) are accounted for, it is likely that only a fraction of the TASR could be available without incurring significant additional costs. Although storage resource estimates typically assume that any issues with pressure buildup due to CO 2 injection will be mitigated by reservoir pressure management, estimates of the costs of CO 2 storage generally do not include the costs of active pressure management. Production of saline waters (brines) could be essential to increasing the dynamic storage capacity of most reservoirs, but including the costs of this critical method of reservoir pressure management could increase current estimates of the costs of CO 2 storage by two times, or more. Even without considering the implications for reservoir pressure management, geologic uncertainty can significantly impact CO 2 storage capacities and costs, and contribute to uncertainty in carbon capture and storage (CCS) systems. Given the current state of available information and the scarcity of (data from) long-term commercial-scale CO 2 storage projects, decision makers may experience considerable difficulty in ascertaining the realistic potential, the likely costs, and the most beneficial pattern of deployment of CCS as an option to reduce CO 2 concentrations in the atmosphere.

Natural Resources Research↗