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Induced seismicity and assessed basins (light grey colored) with shale oil and shale gas formations in the world. The base figure and basin location data are from USEIA (2013). The inset map (location of Oklahoma and surrounding shale gas basins) is redrawn from USGS (2013). The induced seismicity data (reported until June 2012) are from NAS (2013).
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We present an overview of the current status of unconventional energy development, particularly of shale gas, and underground CO 2 storage as a measure to mitigate greenhouse gas increase in the atmosphere. We review their potential to induce seismicity, which has caused debates among related energy enterprises , engineers, researchers, and environ...
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... gas is natural gas, mostly methane, trapped within shale formations that act as a reservoir. In the past, shale gas was not technically or economically feasible, mainly because of the low permeability of the reservoirs ( Jarvie et al., 2007). With the advent of the new technologies of horizontal drilling and hydraulic fracturing, shale gas has increasingly become a main source of energy supply. Figure 1 shows the assessed shale gas basins in the world (USEIA, 2013;USGS, 2013). According to USEIA (2013), there is a total of 7,299 trillion cubic feet (tcf) of technically recoverable shale gas in the world, which is a 10.2% increase from prior estimates in 2011. This increase can be attributed to new shale gas basins discoveries. USEIA (2013) also listed the top ten countries with technically recoverable shale gas resources, including China (15.3%), Argentina (10.9%), Algeria (9.7%), the U.S. (9.1%), and Canada (7.8%). However, technically recover- able does not mean economically recoverable when con- sidering the market and the current technology level of each country ( Arthur et al., 2009;USEIA, 2013). For example, China has the greatest shale gas resource ( Fig. 1), but it has not been developed much, mainly because of the technical challenges presented by fracking, water availability, and deficiency in infrastructure ( Mauter et al., ...
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... gas is natural gas, mostly methane, trapped within shale formations that act as a reservoir. In the past, shale gas was not technically or economically feasible, mainly because of the low permeability of the reservoirs ( Jarvie et al., 2007). With the advent of the new technologies of horizontal drilling and hydraulic fracturing, shale gas has increasingly become a main source of energy supply. Figure 1 shows the assessed shale gas basins in the world (USEIA, 2013;USGS, 2013). According to USEIA (2013), there is a total of 7,299 trillion cubic feet (tcf) of technically recoverable shale gas in the world, which is a 10.2% increase from prior estimates in 2011. This increase can be attributed to new shale gas basins discoveries. USEIA (2013) also listed the top ten countries with technically recoverable shale gas resources, including China (15.3%), Argentina (10.9%), Algeria (9.7%), the U.S. (9.1%), and Canada (7.8%). However, technically recover- able does not mean economically recoverable when con- sidering the market and the current technology level of each country ( Arthur et al., 2009;USEIA, 2013). For example, China has the greatest shale gas resource ( Fig. 1), but it has not been developed much, mainly because of the technical challenges presented by fracking, water availability, and deficiency in infrastructure ( Mauter et al., ...
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... the U.S., shale gas occupied only 1.6% of natural gas production in 2000 but by 2010 increased dramatically to 23.1%, a 14-fold increase ( Wang and Krupnick, 2013). The most active shale gas plays based on daily production include the Barnett Shale and the Marcellus Shale (Ground Water Protection Council and ALL Consulting, 2009;Kargbo et al., 2010; Table 1). The Barnett Shale play is located in the Fort Worth Basin of north-central Texas ( Fig. 1), which is the oldest and was once the largest producing gas field in the U.S. (Martineau, 2007). Natural gas production with hydraulic fracturing started there in 1999, with 78.8 bcf (bil- lion cubic feet) in 2000, and reached 2.09 tcf in 2012 (RRC, 2014), 26 times greater than in 2000. Meanwhile, Nicot and Scanlon (2012) reported that, in 2010, water used for frack- ing at the Barnett Shale comprised of about 9% of the 308 Mm 3 annual water use in Dallas, the 9 th largest city in the U.S., and they foresaw there would be strong competition for water between the local water supply and the water-inten- sive shale gas ...
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... Marcellus Shale is located in the Appalachian Basin, across six states, including Pennsylvania and New York ( Fig. 1), and now holds the largest store of recoverable shale gas in the U.S. (Yu and Sepehroori, 2014; Table 1). The Mar- cellus produced about 365 bcf of natural gas in 2007 and drastically increased its production to 5.1 tcf in 2014, about 18% of total natural gas production in the U.S. (USEIA, 2014). With the introduction of fracking, the Marcellus has been revitalizing since (Arthur et al., 2009). Considine et al. (2011) projected that, if the price of natural gas does not fall, gas production at the Marcellus could support 250,000 jobs, with state and local tax revenues of 2 billion dollars. Despite of economic benefits, there are concerns with development of the Marcellus Shale. The large amount of water used to stimulate the shale formation, about 3 mil- lion gallons per hydraulic fracturing operation, is of great concern to regional and local water managers in this area (Harper, 2008;Soeder and Kappel, 2009). Furthermore, environmental concerns regarding groundwater contamina- tion due to fracking have still not been resolved (Beaver et al., 2014). To date, the environmental externalities of shale gas development have not stopped most countries worldwide from pursuing the resource; the economic benefit and potential for energy security outweigh the costs. Thus, the continued development of shale gas implies the elevated potential for induced seismicity ...
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... fracking (stimulation) water injection has been reported to induce seismicity (Smith, 2012;Ehrenberg, 2012;Davies et al., 2013;Ellisworth, 2013;NAS, 2013 and references therein). Ellisworth (2013) reported that the largest earth- quake induced by the hydraulic fracturing process had a magnitude of 3.6, and thus did not pose a serious risk. Davies et al. (2013) compiled induced earthquakes worldwide that have occurred since 1929, from which they concluded that hydraulic fracturing operation itself cannot cause felt earth- quakes. Ehrenberg (2012) suggested the more comprehen- sive conclusion that the largest earthquake in the U.S. related to fracking had a magnitude of 2.8. Smith (2012) andMcGarr (2014) also presented similar opinions, that the risk of induced seismicity associated with current fracking activity with proper management is low. Although it is not conclu- sive, many published papers and researchers have converged on the notion that fracking does not pose a large induced seismic hazard, but wastewater injection from fracking is risky with several M5.0+ earthquakes induced in the last 5 years. Figure 4 shows the number of earthquakes of greater than M3.0 that have occurred in Oklahoma (see location in Fig. 1 and the inset map) since 1973 (USGS, 2015). Because the state of Oklahoma is tectonically stable, the average number of earthquakes recorded from 1973 to 1999 was only 1.6 per annum (USGS, 2014), but since 2009, earthquakes have drastically increased to nearly 600 in 2014 (USGS, 2015). The largest one, M5.6, hit Oklahoma in November 2011. This increase coincided with the start of wastewater injec- tion in 2009. In this state, most of vertical gas production wells have evolved to horizontal wells since 2008, and from 2008, gas production and wastewater injection expanded dramatically (USDOE, 2009;Keranen et al., 2014). Keranen et al. (2013Keranen et al. ( , 2014 attributed this unprecedented earthquake swarm to high-rate wastewater injection into disposal wells, drawing much attention from mass media and the public community, because swarms of quakes have continued in 2014 and several thousand disposal wells are active (as of 2013) in the state at depths of 3 to 6 km (Stateimpact, ...
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... induced seismicity is not limited to wastewater injec- tion ( McGarr et al., 2015 ; Fig. 1); other activities of concern include underground CO 2 storage in carbon capture and storage (CCS) projects (Zoback and Gorelick, 2012;Hitzman, 2014;Verdon, 2014), deep drilled enhanced geothermal systems (EGS) (Majer et al., 2007;Giardini, 2009;Brodsky and Lajoie, 2013;Karvounis et al., 2014;Kuehn et al., 2014), and conventional oil and gas extraction (NAS, 2013). Like wastewater injection, injection of CO 2 or water can also cause felt (M3.0+) earthquakes ( Lei et al., 2008). Thus, public concerns about these induced earthquakes can decelerate the practical application of energy technologies (NAS, 2013;Clarke et al., ...
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... The fault may be activated, and thereby leading to the occurrence of seismic activities (Guglielmi et al., 2015;Bao and Eaton, 2016;Elsworth et al., 2016;Ye and Ghassemi, 2020;Shi et al., 2022). Many countries have banned the hydro-fracturing related projects due to the dramatically increased frequency of earthquakes, for instance, the Germany, UK, and the France (Lee et al., 2016;Li et al., 2019;Evensen et al., 2022;Zhu et al., 2024). Despite of this, hydro-fracturing is still one of the most efficient and cleanest way to extract shale gas (Ferguson et al., 2021;Wu et al., 2021;Wang et al., 2022). ...
To explore the effects of fracture inclination angle θ and confining pressure σ 3t on the slip behaviors and friction properties of fractures, the triaxial unloading-induced slip experiments were performed on the shale fractures. The results show that the σ 3t controls the slip modes of fractures, while the θ affects the occurrence of the stick-slip events during the quasi-static slip stage. With the increase in σ 3t , the main slip modes of fracture transform from the stable-slip to stick-slip, and eventually to the creep-slip. The increase in θ facilitated the occurrence of stick-slip events. As the θ increased from 30° to 50°, the number of stick-slip events increased from 0 to 3 and from 2 to 4 for σ 3t = 10 MPa and 20 MPa, respectively. For σ 3t = 40 MPa, no stick-slip event occurred in the slipping process. The θ and σ 3t have great effects on interaction modes between asperities, which directly affected the friction properties of fractures. With increasing σ 3t , the void spaces between the asperities were further compacted, resulting in the transition of asperity interaction from overriding mode to shear-off mode. The transition of asperity interaction model therefore brought about the weakening of friction coefficient at the activation point and the onset of dynamic slip stage. There is a competitive relationship between the θ and σ 3t for the evolution of the friction properties of fractures. As the θ increase from 30° to 50°, for σ 3t = 10 MPa, the mean sheared-off thickness decreased from 0.502 mm to 0.433 mm, while for σ 3t = 40 MPa, the mean sheared-off thickness decreased from 0.505 mm to 0.319 mm. With the increment of θ , the anisotropy of joint roughness coefficient was weakened. We suggested that by adjusting the fracturing angle of hydro-fracturing, the earthquakes with large seismic moments may be effectively mitigated.
... The concept of pressure management is not new in reservoir engineering, as the injection of fluids, such as water or gas, into hydrocarbon reservoirs to maintain field pressure in secondary recovery applications is a common practice applied for decades [48]. Nevertheless, unlike hydrocarbon reservoirs, when injecting CO 2 into saline aquifers where the porous medium is already occupied with incompressible fluids (brine solution), pressure build-up takes place quite quickly which, if uncontrolled, may lead to high pressures that can fracture the caprock, reactivate faults, open natural or artificial conduits and channels that promote CO 2 leakages, and even drive both CO 2 and formation brine to shallow water-supply aquifers [49][50][51][52][53][54], as illustrated in Figure 4. ...
... The concept of pressure management is not new in reservoir engineering, as the injection of fluids, such as water or gas, into hydrocarbon reservoirs to maintain field pressure in secondary recovery applications is a common practice applied for decades [48]. Nevertheless, unlike hydrocarbon reservoirs, when injecting CO2 into saline aquifers where the porous medium is already occupied with incompressible fluids (brine solution), pressure build-up takes place quite quickly which, if uncontrolled, may lead to high pressures that can fracture the caprock, reactivate faults, open natural or artificial conduits and channels that promote CO2 leakages, and even drive both CO2 and formation brine to shallow water-supply aquifers [49][50][51][52][53][54], as illustrated in Figure 4. For instance, potential conduits for vertical CO2 movement in the form of fluid chimneys in the Utsira Formation at the Sleipner project were recognized, and sequential surveys were conducted to ensure that no excess of pressure resulted in CO2 migration to the upper layers [56,57]. ...
To mitigate dangerous climate change effects, the 195 countries that signed the 2015 Paris Agreement agreed to “keep the increase in average global surface temperature below 2 °C and limit the increase to 1.5 °C” by reducing carbon emissions. One promising option for reducing carbon emissions is the deployment of carbon capture, utilization, and storage technologies (CCUS) to achieve climate goals. However, for large-scale deployment of underground carbon storage, it is essential to develop technically sound, safe, and cost-effective CO2 injection and well control strategies. This involves sophisticated balancing of various factors such as subsurface engineering policies, technical constraints, and economic trade-offs. Optimization techniques are the best tools to manage this complexity and ensure that CCUS projects are economically viable while maintaining safety and environmental standards. This work reviews thoroughly and critically carbon storage studies, along with the optimization of CO2 injection and well control strategies in saline aquifers. The result of this review provides the foundation for carbon storage by outlining the key subsurface policies and the application of these policies in carbon storage development plans. It also focusses on examining applied optimization techniques to develop CO2 injection and well control strategies in saline aquifers, providing insights for future work and commercial CCUS applications.
... However, there are still considerable gaps in our understanding of their developmental mechanisms and precursors. Recently, public concern has arisen regarding induced seismicity involved in enhanced geothermal systems and the hydrofracturing of shale gas (Lee et al., 2016). Timely SIs covering natural earthquakes and induced seismicity may be beneficial to the IUGS community. ...
... Examples include consolidating clays (Sahimi, 2011), soil and rock at large depths where the uniaxial stress is high (Biot, 1941(Biot, , 1956Iliev et al., 2008), shale formations into which chemicals or used water are injected to increase production, and storing CO 2 in geological formations. Injection of CO 2 into such formations causes, together with the brine that is already in the pore space, swelling (Rahromostaqim & Sahimi, 2018, 2019 and deformation of their solid matrix that may trigger seismic events and even earthquakes (Rothert & Shapiro, 2003;Maxwell et al., 2008;Tafti et al., 2013;Lee et al., 2016). Deformation of a porous medium changes its morphology and, therefore, its porosity, pore-size distribution (PSD), permeability, elastic moduli, and other properties. ...
Estimating flow and transport properties of porous media that undergo deformation as a result of applying an external pressure or stress is important to a wide variety of processes, ranging from shale formations into which a fracking liquid is injected to CO2 sequestration in geological formations. We propose a novel model for estimating the effective permeability of such porous media. Given the pore‐size distribution (PSD) of a porous medium before deformation, as well as the Young's modulus of its grains, the model uses Hertz‐Mindlin theory of contact between grains to compute the new PSD that results from applying an external pressure P to the medium and utilizes the updated PSD in the effective‐medium approximation to estimate the effective permeability at P. Comparison between the predictions and experimental data for several types of sandstones indicates excellent agreement between the two.
... HF involves the injection of a pressurized fluid composed by large volumes of water (∼90%), sand and man-made chemical additives. Thus, international concerns have been raised regarding water and environmental impacts closely related to shale production, including surface and groundwater withdrawals, aquifer pollution, baseflow decrease, air quality degradation, induced seismicity during produced water disposal, landscape fragmentation, changes in land use, threats to biota or human health risks, among others (Arciniega-Esparza et al., 2017;Barcelo and Bennett, 2016;Brittingham et al., 2014;Clancy et al., 2018;Entrekin et al., 2018;Kim and Lu, 2018;Kondash et al., 2017;Lee et al., 2016;Nicot et al., 2014;Rutqvist et al., 2013;Slonecker et al., 2012;Wolaver et al., 2018). ...
Massive development of unconventional resources using hydraulic fracturing (HF) procedures, has been carried out since the last three decades, with focus on Texas, USA, including the Eagle Ford (EF) play. International concerns have been raised regarding water and environmental impacts closely related to shale production. The aim of this paper is to map spatio-temporal trends of HF development (water use and well density) examining the entire production period in the EF. We used FracFocus as the main source of HF information, from 2009 to 2017. Our database managed in Python, SAGA GIS and QGIS, comprised 15,013 oil and gas well records. Statistical results show that median HF water use has been progressively increasing over time, from ~18,000 m3/well (2010) to ~38,000 m3/well (2017). Mapping results illustrate that both well density and HF water use peaked in 2014, whereas the area required for HF encompassed ~16,800 km2 or ~70% of the play surface area. We summarize our results in a public domain interactive GIS-based digital map.
... (continued on next page) regarding the water and ecological impacts accompanying unconventional energy resource development. These include surface-groundwater withdrawals associated with HF procedures (Mitchell et al., 2013;Reagan et al., 2015), induced seismicity caused by produced water injection (Lee et al., 2016;Rutqvist et al., 2013), localized geohazards (Kim and Lu, 2018), traffic-related (Goodman et al., 2016) and other threats to biota and ecosystems (Brittingham et al., 2014;Souther et al., 2014;Wolaver et al., 2018a), changes in land use (Cox et al., 2017;Wolaver et al., 2018b), landscape fragmentation (Pierre et al., 2017;Willow et al., 2014), air-water quality degradation (Ahmadi and John, 2015;Pinti et al., 2016), and human health risks (Barcelo and Bennett, 2016). As a result, the response of regulatory agencies globally has been varied, with some governments allowing or incentivizing development and others placing a moratorium on the development of unconventional resources (de Melo-Martín et al., 2014). ...
Hydraulic fracturing (HF) operations have transformed the unconventional energy industry, leading to a global increase in hydrocarbon production. Despite this, only the US, China, Canada and Argentina currently dominate production of unconventional resources, with the majority of shale basins globally remaining unprofitable to develop. An important gap in current water-energy nexus research, which this study addresses, is the assessment of potential water use to satisfy HF procedures in emergent plays. This work presents a screening tool for assessing first-order estimates of water impacts in undeveloped shale plays, testing the approach in the trans-boundary Eagle Ford (EF) play in northeast Mexico. We couple surface water and groundwater stress indicators derived from global hydrological variables to depict a baseline water stress index. Relative water stress is mapped for proposed blocks to be leased by the Mexican government in the future. We simulate four HF scenarios to assess new total water stress indicators for each block, considering shale production schemes using representative well drilling density (well lateral length(s) per unit area) and HF water intensity (HF water volume per unit lateral length) from existing EF development in Texas. Results suggest that the most feasible management scenario would consider the drilling of ∼1360 new unconventional wells/yr with projected HF water use of ∼57 Mm 3 /yr (0.7% of the total water withdrawals). The remaining scenarios will largely affect groundwater resources. Though applied to the EF in Mexico, this screening tool can assess water use constraints in emerging unconventional plays globally.
... Injecting fluids into hydrocarbon reservoirs to maintain pressure has been common practice in the past decades, although it is a much novel concept in CO 2 storage. By injecting CO 2 into saline aquifers there will be a pressure build up, if uncontrolled, high pressures can fracture the caprock, reactivate faults (Lee et al., 2016;Rutqvist et al., 2008Rutqvist et al., , 2007, and even drive CO 2 and formation brine through leakage pathways into shallow water-supply aquifers (Bachu, 2008;Carroll et al., 2009). As a result, pressure build up will limit the effective storage capacity of the saline aquifer (Birkholzer and Zhou, 2009); in order to control the previous, the extraction of brine from the aquifer has been proposed to potentially increase the effective volume of CO 2 that can be injected into an aquifer. ...
CO2 storage capacity in saline aquifers can dramatically be reduced by pressure build up due to the CO2 injection process. In this paper, a novel optimisation strategy that maximises the CO2 storage capacity utilisation and net profits before tax is presented in a scenario of simultaneous CO2 injection and brine production to help control pressure build up and increase the effective storage capacity. The strategy is tested at the region surrounding the Forties and Nelson fields, assuming both as pure saline aquifer traps. The optimisation was performed considering constraints such that the CO2 plume distribution does not migrate outside the license boundaries, the fracture pressure is not reached within the reservoir, and the CO2 injection and brine production rates occur within feasible limits. The problem was first formulated analytically with the aid of surrogate models, and then optimised using the SIMPLEX and Generalized Reduced Gradient methods.
Results for the Forties and Nelson fields show that by allowing five brine production wells producing up to 2.2 MMtonnes/year, the CO2 storage capacity increased between 112-145% compared to the case where no brine production is practiced.
... Parts of the United States ( Figure 1) have seen a dramatic increase in earthquake rates over the past decade because of industrial activities, especially disposal of wastewater from oil and gas operations into subsurface sedimentary rock [Ellsworth, 2013;Keranen et al., 2013;Rubinstein et al., 2014]. Injected fluids can increase pore pressure on faults, leading to frictional instability and slip [NRC, 2013;Lee et al., 2016]. Previous research has investigated the impact of well-operational parameters [e.g., Weingarten et al., 2015], meter- scale dynamics of induced moment release [e.g., Guglielmi et al., 2015], or the relative likelihood of slip on specific faults [Holland, 2013;Walsh and Zoback, 2016], but less attention has been paid to what factors influence the susceptibility of a region as a whole to induced seismicity. ...
Wastewater reinjection increases pore fluid pressure and can make faults frictionally unstable, triggering earthquakes. Little is known, however, about how regional geomechanical properties influence the likelihood that disposal will induce seismicity. We investigate the impact of preinjection conditions on the proportion of possible fault orientations destabilized by a specified pore pressure increase. Stress state is the most important factor, with 7 times as many planes unstable in extension than contraction—indeed, normal or strike-slip faulting environments characterize most injection-induced seismicity—and additional fivefold increases in transitional stress states. Geomechanical susceptibility depends inversely on overburden density and depth, consistent with the shallow hypocenters of most induced events. The coefficient of friction and initial pore pressure have little impact: Faults initially below hydrostatic pressure can slip during gravity-fed injection. Combining these factors, site-specific geomechanical analyses could determine 300-fold variations in the likelihood of induced seismicity before disposal, offering a proactive way to manage hazard.
... With advances and improvements in hydraulic fracturing technologies and horizontal well drilling, the development of shale gas production from deep shale formations has expanded all over the world, especially in the United States and China (Tang et al., 2011;Olmstead et al., 2013;Warner et al., 2013). Although these resources have a significant economic value and can mitigate greenhouse gases emissions partly caused by burning coal, shale gas development has drawn significant public and regulatory attention to its possible negative environmental impacts, in particular, fate of fluid that is generated by hydraulic fracturing and potential contamination to groundwater systems due to leakage (Gregory et al., 2011;Howarth et al., 2011;Osborn et al., 2011;Warner et al., 2013;Lee et al., 2016). ...
Various environmental problems related to flowback fluid have recently become a concern for hydraulic fracturing during shale gas production. Detailed studies on the geochemical reactions during hydraulic fracturing are performed for the Lower Silurian Longmaxi shale formation, Fuling block, Sichuan basin, SW China, through water-rock interaction experiment conducted under reservoir conditions, and comparisons with field test data are made. Results show that the total dissolved solids (TDS) of the flowback fluid increases and Ca²⁺, Na⁺, Cl– and SO42– make dominant contributions. The increases of Na⁺ and Cl– are assumed to be caused by halite dissolution and mixing with in situ formation water in the marine facies reservoir. The main geochemical reactions are inferred to be pyrite oxidation and the dissolution of calcite, dolomite and plagioclase, resulting in increases of major ions in the flowback fluid. Heavy metals, including Mn, Ni, Mo and Zn, exceed the drinking water criteria of China, and the potential threat from leakage should be a concern. Besides of CH4, as the specific pollutant to groundwater system, inorganic geochemical monitoring of shallow groundwater system should track TDS, major ions of Cl–, SO42–, Na⁺, and Ca²⁺, trace elements of Li, Ni, Pb, Cu, Zn, Mn, Mo and Rb, and stable isotopes, such as ¹⁸OH2O, ²HH2O and ¹³CDIC.
... In addition to studying the geochemical interactions between aqueous CO 2 moieties and supercritical CO 2 with the formation's structure and mineralogy, a growing area of research in this field is the management of brine displacement and subsequent subsurface pressure build-up within both the storage formation and any overlying formations Buscheck et al., 2016Buscheck et al., , 2011Cihan et al., 2015;Gaus, 2010;IPCC, 2005). Excess formation pressure can cause seismic events and/or drive CO 2 leakage through pre-existing wells in the formation or through natural faults with the potential to hydraulically fracture the formation seals (Lee et al., 2016;Varre et al., 2015). Accumulation of subsurface pressure might require lower rates of CO 2 injection and possibly reduce a formation's CO 2 capacity. ...
Subsurface pressure management is a significant challenge in geologic CO2 storage. Elevated pressure generated from the injection of supercritical CO2 can be managed by the withdrawal of brine from saline formations before or during CO2 injection; however, management of the extracted brines is non-trivial because they may have high concentrations of dissolved solids and other contaminants. Dewatering a brine can reduce the volume needing disposal; in addition, water separated from the brine can be a source of usable low salinity water. This review will summarize the composition of brines extracted from select domestic geologic CO2 storage sites, will calculate the minimum of work of dewatering, and will provide a critical review of developed and developing desalination/dewatering technologies that could be applied to brines extracted from saline formations before or during geologic CO2 storage operations. Herein are also highlighted, when appropriate, the similarities and the differences between dewatering brines produced from oil/gas operations and brines extracted from geologic CO2 storage. Since a source of steam or natural gas is likely unavailable/unsuitable for dewatering brines extracted during CO2 storage, the ideal treatment processes should have a high electrical efficiency and, if possible, should be able to take advantage of the inherent elevated temperature of these brines.
