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Results for “International Journal of Greenhouse Gas Control”

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13 recordsLinked to original sources
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

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↗
USGS2012

Geochemical modeling of changes in shallow groundwater chemistry observed during the MSU-ZERT CO2 injection experiment

A field experiment involving the release of carbon dioxide (CO 2 ) into a shallow aquifer was conducted near Bozeman, Montana, during the summer of 2008, to investigate the potential groundwater quality impacts in the case of leakage of CO 2 from deep geological storage. As an essential part of the Montana State University Zero Emission Research and Technology (MSU-ZERT) field program, food-grade CO 2 was injected over a 30 day period into a horizontal perforated pipe a few feet below the water table of a shallow aquifer. The impact of elevated CO 2 concentrations on groundwater quality was investigated by analyzing water samples taken before, during, and following CO 2 injection, from observation wells located in the vicinity of the injection pipe, and from two distant monitoring wells. Field measurements and laboratory analyses showed rapid and systematic changes in pH, alkalinity, and conductance, as well as increases in the aqueous concentrations of naturally occurring major and trace element species. The geochemical data were evaluated using principal component analysis (PCA) to (1) understand potential correlations between aqueous species, and (2) to identify minerals controlling the chemical composition of the groundwater prior to CO 2 injection. These evaluations were used to assess possible geochemical processes responsible for the observed increases in the concentrations of dissolved constituents, and to simulate these processes using a multicomponent reaction path model. Reasonable agreement between observed and modeled data suggests that (1) calcite dissolution was the primary pH buffer, yielding increased Ca +2 concentrations in the groundwater, (2) increases in the concentrations of most major and trace metal cations except Fe could be a result of Ca +2 -driven exchange reactions, (3) the release of anions from adsorption sites due to competitive adsorption of carbonate could explain the observed trends of most anions, and (4) the dissolution of reactive Fe minerals (presumed ferrihydrite and fougerite, from thermodynamic analyses) could explain increases in total Fe concentration. Highlights ► Because the possibility of CO 2 leakage cannot be completely ruled out, the potential impact of CO 2 intrusion on the quality of fresh water aquifers overlying CO 2 storage sites needs to be investigated. ► Geochemical data from a field experiment involving the release of carbon dioxide (CO 2 ) into a shallow aquifer were evaluated. ► Geochemical model used to assess possible geochemical processes responsible for the observed increases in the concentrations of dissolved constituents. ► Reasonable agreement between observed and modeled data suggests that increases in the concentrations of most major and trace metal cations except Fe could be a result of Ca +2 -driven exchange reactions and the release of anions from adsorption sites due to competitive adsorption of carbonate could explain the observed trends of most anions.

Montana↗
USGS2011

Effects of reduction in porosity and permeability with depth on storage capacity and injectivity in deep saline aquifers: A case study from the Mount Simon Sandstone aquifer

The Upper Cambrian Mount Simon Sandstone is recognized as a deep saline reservoir that has significant potential for geological sequestration in the Midwestern region of the United States. Porosity and permeability values collected from core analyses in rocks from this formation and its lateral equivalents in Indiana, Kentucky, Michigan, and Ohio indicate a predictable relationship with depth owing to a reduction in the pore structure due to the effects of compaction and/or cementation, primarily as quartz overgrowths. The regional trend of decreasing porosity with depth is described by the equation: ϕ ( d ) = 16.36 × e −0.00039* d , where ϕ is the porosity and d is the depth in m. The decrease of porosity with depth generally holds true on a basinwide scale. Bearing in mind local variations in lithologic and petrophysical character within the Mount Simon Sandstone, the source data that were used to predict porosity were utilized to estimate the pore volume available within the reservoir that could potentially serve as storage space for injected CO 2 . The potential storage capacity estimated for the Mount Simon Sandstone in the study area, using efficiency factors of 1%, 5%, 10%, and 15%, is 23,680, 118,418, 236,832, and 355,242 million metric tons of CO 2 , respectively.

Ohio, Illinois, Michigan, Kentucky, West Virginia,↗
USGS2010

Assessment of basin-scale hydrologic impacts of CO2 sequestration, Illinois basin

Idealized, basin-scale sharp-interface models of CO2 injection were constructed for the Illinois basin. Porosity and permeability were decreased with depth within the Mount Simon Formation. Eau Claire confining unit porosity and permeability were kept fixed. We used 726 injection wells located near 42 power plants to deliver 80 million metric tons of CO2/year. After 100 years of continuous injection, deviatoric fluid pressures varied between 5.6 and 18 MPa across central and southern part of the Illinois basin. Maximum deviatoric pressure reached about 50% of lithostatic levels to the south. The pressure disturbance (>0.03 MPa) propagated 10-25 km away from the injection wells resulting in significant well-well pressure interference. These findings are consistent with single-phase analytical solutions of injection. The radial footprint of the CO2 plume at each well was only 0.5-2 km after 100 years of injection. Net lateral brine displacement was insignificant due to increasing radial distance from injection well and leakage across the Eau Claire confining unit. On geologic time scales CO2 would migrate northward at a rate of about 6 m/1000 years. Because of paleo-seismic events in this region (M5.5-M7.5), care should be taken to avoid high pore pressures in the southern Illinois basin. ?? 2010 Elsevier Ltd.

International Journal of Greenhouse Gas Control↗
USGS2012

Sequestration of non-pure carbon dioxide streams in iron oxyhydroxide-containing saline repositories

Iron oxyhydroxide, goethite (α-FeOOH), was evaluated as a potential formation mineral reactant for trapping CO 2 in a mineral phase such as siderite (FeCO 3 ), when a mixture of CO 2 -SO 2 flue gas is injected into a saline aquifer. Two thermodynamic simulations were conducted, equilibrating a CO 2 -SO 2 fluid mixture with a NaCl-brine and Fe-rich rocks at 150 °C and 300 bar. The modeling studies evaluated mineral and fluid composition at equilibrium and the influence of pH buffering in the system. Results show siderite precipitates both in the buffered and unbuffered system; however, the presence of an alkaline pH buffer enhances the stability of the carbonate. Based on the model, an experiment was designed to compare with thermodynamic predictions. A CO 2 -SO 2 gas mixture was reacted in 150 ml of NaCl-NaOH brine containing 10 g of goethite at 150 °C and 300 bar for 24 days. Mineralogical and brine chemistry confirmed siderite as the predominant reaction product in the system. Seventy-six mg of CO 2 are sequestered in siderite per 10 g of goethite.

International Journal of Greenhouse Gas Control↗
USGS2016

Determining CO 2 storage potential during miscible CO 2 enhanced oil recovery: Noble gas and stable isotope tracers

Rising atmospheric carbon dioxide (CO 2 ) concentrations are fueling anthropogenic climate change. Geologic sequestration of anthropogenic CO 2 in depleted oil reservoirs is one option for reducing CO 2 emissions to the atmosphere while enhancing oil recovery. In order to evaluate the feasibility of using enhanced oil recovery (EOR) sites in the United States for permanent CO 2 storage, an active multi-stage miscible CO 2 flooding project in the Permian Basin (North Ward Estes Field, near Wickett, Texas) was investigated. In addition, two major natural CO 2 reservoirs in the southeastern Paradox Basin (McElmo Dome and Doe Canyon) were also investigated as they provide CO 2 for EOR operations in the Permian Basin. Produced gas and water were collected from three different CO 2 flooding phases (with different start dates) within the North Ward Estes Field to evaluate possible CO 2 storage mechanisms and amounts of total CO 2 retention. McElmo Dome and Doe Canyon were sampled for produced gas to determine the noble gas and stable isotope signature of the original injected EOR gas and to confirm the source of this naturally-occurring CO 2 . As expected, the natural CO 2 produced from McElmo Dome and Doe Canyon is a mix of mantle and crustal sources. When comparing CO 2 injection and production rates for the CO 2 floods in the North Ward Estes Field, it appears that CO 2 retention in the reservoir decreased over the course of the three injections, retaining 39%, 49% and 61% of the injected CO 2 for the 2008, 2010, and 2013 projects, respectively, characteristic of maturing CO 2 miscible flood projects. Noble gas isotopic composition of the injected and produced gas for the flood projects suggest no active fractionation, while δ 13 C CO 2 values suggest no active CO 2 dissolution into formation water, or mineralization. CO 2 volumes capable of dissolving in residual formation fluids were also estimated along with the potential to store pure-phase supercritical CO 2 . Using a combination of dissolution trapping and residual trapping, both volumes of CO 2 currently retained in the 2008 and 2013 projects could be justified, suggesting no major leakage is occurring. These subsurface reservoirs, jointly considered, have the capacity to store up to 9 years of CO 2 emissions from an average US powerplant.

International Journal of Greenhouse Gas Control↗
USGS2018

Using mercury injection pressure analyses to estimate sealing capacity of the Tuscaloosa marine shale in Mississippi, USA: Implications for carbon dioxide sequestration

This work used mercury injection capillary pressure (MICP) analyses of the Tuscaloosa Group in Mississippi, including the Tuscaloosa marine shale (TMS), to assess their efficacy and sealing capacity for geologic carbon dioxide (CO 2 ) sequestration. Tuscaloosa Group porosity and permeability from MICP were evaluated to calculate CO 2 column height retention. TMS and Lower Tuscaloosa shale samples have, respectively, Swanson permeability values less than 0.003 md and 0.00245 md; porosity from 3.86% to 9.86% and 1.34% to 7.96%; median pore throat sizes from 0.00342 to 0.0111 μm and 0.00311 to 0.017 μm; and pore radii from 0.0130 to 0.152 μm and 0.0132 to 0.149 μm. Mercury entry pressures for the TMS and Lower Tuscaloosa range from 4.9 to 57.1 MPa and 5.0 to 56.3 MPa, respectively. Calculated CO 2 column heights that the TMS sample set can retain in the reservoir range from 23 to 255 m when the TMS is near 100% water saturation. Potential top seal leakage is more likely to be influenced by the numerous well penetrations through the confining system of the TMS rather than capillary failure. Results of this study demonstrate desirable sealing capacity of the TMS for geologic CO 2 sequestration in reservoir sandstones of the Lower Tuscaloosa and could provide an analogue to other potential CO 2 sequestration top seals.

Louisiana, Mississippi↗
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↗
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↗
USGS2020

Methodology for estimating the prospective CO2 storage resource of residual oil zones at the national and regional scale

Residual oil zones (ROZs) are increasingly gaining interest as potential reservoirs for carbon dioxide (CO 2 ) storage. Here, we present a national- and regional-scale methodology for estimating prospective CO 2 storage resources in residual oil zones. This methodology uses a volumetric equation that accounts for CO 2 storage as a free phase in pore space and as a dissolved phase in oil and does not assume any oil production associated with CO 2 storage. Reservoir modeling and the CO 2 -SCREEN tool are used to demonstrate that CO 2 storage in residual oil zones will predominantly take place in the free phase (approximately 92–97%) with some storage as dissolution in oil (approximately 3–8 %). Based on this preliminary demonstration, the CO 2 storage efficiency for ROZs using this national- and regional-scale method ranges from 0.61 to 7.1 %. This range indicates ROZs have a similar efficiency potential for storing CO 2 as deep saline formations (0.51–5.4 %).

International Journal of Greenhouse Gas Control↗
USGS2007

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. ?? 2007 Elsevier Ltd. All rights reserved.

International Journal of Greenhouse Gas Control↗
USGS2023

Predicting methane emissions and developing reduction strategies for a Central Appalachian Basin, USA, longwall mine through analysis and modeling of geology and degasification system performance

Coal mine methane is a safety concern in active mines due to explosion risk and an environmental concern due to the greenhouse gas (GHG) properties of methane emissions to the atmosphere. Depending on the mine design and operation, structural and stratigraphic characteristics of the geology, and the properties of coal beds affected by mining, a significant amount of methane can be released during coal extraction. These emissions may be low and uniform, but they also can be high and abrupt, if not captured by using pre- and post-mining methods of degasification or not controlled by ventilation during mining. Therefore, emissions should be monitored and predicted accurately for underground safety and GHG reduction. Ventilation and degasification systems should be designed accordingly by taking into account the mine geological properties and the degasification system's performance. This paper presents a comprehensive study to predict emissions and proposes alternatives to reduce emissions in a longwall mine extracting metallurgical coal from the Pocahontas No. 3 coal bed in Virginia (Central Appalachian Basin), USA. The work focused on mining activity in four adjacent panels through analysis and modeling of geology and evaluation of the performance of the methane control system. Results showed that the mine geology contained a significant amount of gas within and around the panel areas, which was controlled by utilizing different degasification methods besides ventilation during mining. The study showed that after pre-mining degasification using fractured vertical wells and in-seam horizontal wells, each panel potentially contained ∼19 MMscf and ∼ 2 MMscf of gas remaining to be handled by the gob gas ventholes (GGVs) and the ventilation, respectively, per acre of mining. It was shown that extending the pre-mining degasification duration of vertical wells by as much as 4 years or drilling more horizontal wells with closer spacing could significantly reduce ventilation and gob emissions during the mining of coal.

Kentucky, Virginia, West Virginia↗