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• Total storage resource estimates are fundamental to the development of CCS. • Reservoir pressure buildup is likely to be a key limit in the absence of brine production. • We introduce a new algorithm for calculating pressure-limited storage resources at basin scale. • Resulting reductions in total storage resource suggest larger project acreage requirements. • Pressure space (pressure times pore volume) is the key subsurface commodity for CCS. Storage resource estimates are part of the foundation for Carbon Capture and Storage (CCS) policy, project development and pipeline routing. Multiple generations of such estimates have found that hundreds and even thousands of gigatons of storage are available in basins around the world. However, these estimates have largely been based on basin-scale static capacity calculations that assume pore space is accessible to CO 2 , because basins have open boundaries that allow water to be displaced and avoid pressure build-up. However, as we now consider large-scale injection that stresses the system capacity, limitations to the flow of CO 2 and displaced brine must be considered. These limits include pressure interactions among multiple projects, physical lateral discontinuities such as faults and facies changes, overpressure, juxtaposition with impermeable basement, and regulatory requirements that require protection of freshwater. We present here a simple algorithm to estimate the total pressure-limited storage resource. Applying it to the example of the Texas coastal Miocene results in a significantly lower storage resource over our previous static capacity estimates (assuming no water production). Based on this assessment, we find that CCS is still unlikely to be capacity-limited, but effective regulation, land valuation and project development will require recalibration and consideration of all projects in pressure communication. We conclude that depth-dependent and geomechanically-limited pressure space, not pore space, is the key subsurface commodity. [ABSTRACT FROM AUTHOR]

Carbon capture, utilization, and storage (CCUS) is capable of significantly reducing anthropogenic carbon dioxide (CO 2) emissions. In the Canadian context, CCUS is an important tool in mitigating emissions in the oil and gas sector, which is a significant contributor of greenhouse gas emissions in Canada. Previous studies have demonstrated the viability of CCUS in the Alberta oil sands but have not considered all the critical factors impacting the success of a CCUS system including the availability of emission sources, the design of a CO 2 transportation network, the availability and capacity of suitable storage sites, the long-term fate of injected CO 2 , the economic viability of the system, and the overall policy environment. We consider all these factors in proposing a CCUS hub that captures CO 2 from a cluster of 10 large oil sands emitters for permanent storage in the Devonian Nisku and Wabamun saline aquifers. We forecast the oil sands emissions using a logistic model and simulate the pressure evolution and CO 2 plume migration to show that the aquifers can safely store the entirety of forecasted emissions, which amounts to over 1.9 gigatons by the end of the century. We design a pipeline network connecting the emitters and the storage formations, which is estimated to cost approximately $ 4-billion. We consider both privately-funded and publicly-funded scenarios for financing the pipeline network, taking into account relevant financial and policy incentives. Our work outlines the key points that must be considered when designing a large-scale CCS system, namely availability of emission sources, efficiency of pipeline route, storage capacity and injectivity, CO 2 migration and trapping, cost, and policy and financial incentives. This provides a comprehensive framework upon which future CCUS projects can be evaluated to ensure its long-term viability and success. • We propose a CCUS hub in the Alberta oil sands capable of storing a gigaton of CO 2. • A holistic framework is needed to evaluate the feasibility of gigaton-scale CCUS. • Physical and economic modelling demonstrate the feasibility of the proposed CCUS hub. [ABSTRACT FROM AUTHOR]

The advantages of approaching CCS as a fill-and-spill challenge, both in the AOI and elsewhere, would be numerous. These include: • Maximising net pore volume for storage: structures will be filled to spill as an objective, resulting in larger estimates of storage efficiency and, therefore, greater CO2 effective storage capacity for linked fairways as a whole compared with individual traps. • Increased efficiency and cost savings: leveraging supercritical CO2 buoyancy and low viscosity to naturally drive migration through the fairway will result in less infrastructure and less injector and pressure-management wells, reducing CAPEX and OPEX. • Decreased seal-breaching risk: in our new approach, several smaller traps are used, each with a greater top-seal pressure integrity than a single very large trap at the same burial depth. The cumulative "safe CO2 effective storage capacity" would therefore be much greater than in the conventional development of a very large stand-alone structure, with less risks of losing CO2 by seal breaching or lateral diffusion. • Natural pressure management: closures at the end of the fairway (such as the Bp15 Prospect in this study) can act as a safety buffer to excess injection or CO2 entering in solution into pore fluids (volume increase) and getting transported from the structure by fluid flow, enabling 'peace of mind' when planning on 'completely' filling traps in the fairway with CO2. • Optimised monitoring and permanent storage security: map-based flow-vector migration modelling can identify potential spill points early on, informing the placement of Multiphysics monitoring systems and injector hubs. • Exploiting fill-and-spill fairways for CCS is an entirely new concept with vast worldwide applicability. This work explores the subsurface CO 2 storage potential in UKCS Quadrants 43–44, by integrating 3D seismic interpretation, regional wellbore data and CO 2 migration modelling. We show 11 Bunter Sandstone domes linked together in a fill-and-spill "Bunter Mega-Fairway". These traps host a theoretical storage capacity of 8.4 Gt CO 2 (≈3–4 times the filled-to-spill theoretical capacity of the proposed Endurance storage site), while lessening CO 2 leakage risks. Within the mega-fairway, the Triassic Bunter Sandstone reservoir shows a P10-P90 thickness of 78–219 m, along with moderate-high porosities (11–28 %) and permeabilities (9–669 mD). A regionally-connected reservoir is suggested from spatially consistent, near-hydrostatic aquifer pressure gradients (≈0.51 psi/ft). The top-seal is laterally effective and structural closures are lower than the CO 2 columns necessary to breach the seal. At the mega-fairway storage depths, CO 2 would inhabit the reservoir as a supercritical fluid, enabling it to naturally migrate buoyantly from one trap to another, away from strategically-placed injector sites. Through the integration of migration spill-point modelling, multi-physics seabed monitoring nodes and fill-and-spill injection management, the maximum storage capacity could be achieved, while alleviating CO 2 leakage hazards and potentially decreasing the number of injector wells. Exploiting fill-and-spill fairways for CCS is a new concept with vast worldwide applicability. [ABSTRACT FROM AUTHOR]

Underground gas storage is widely recognized as a crucial strategy in pursuing low-carbon and even zero-carbon emissions. This paper is motivated to investigate the injection process of underground gas storage. CO 2 and H 2 are prominent representative stored gases, also chosen as studied ones for their significant differences in physical properties, especially density. Simulations are conducted on models with different heterogeneities. Sensitive cases are designed with a vertical/horizontal well and under different injection strategies, to study the storage capacity of underground aquifers and the transportation process of injected gases during the injection process. Results show that the variations of injection mass and injection time of horizontal well systems have almost the same trends and values as those of the vertical well system for both H 2 and CO 2. As the injection rate increases, the effective storage efficiency (net injection mass friction) of H 2 in the vertical well systems decreases while that in the horizontal increases, with relatively little difference for CO 2. For dissolution trapping in a vertical well system, evaluation parameters (average concentration, dissolution mass, and fraction) increase as rising heterogeneity enhances the fingering gas-water contact but is relatively constant as the injection rate varies. Nevertheless, in horizontal well systems, they are relatively constant for CO 2 but decrease for H 2 with increasing injection rate, as less injection time limits the vertical gravity-induced migration, but are relatively constant with heterogeneity, as increased heterogeneity weakens the gravity-induced migration contact while improving the horizontal fingering contact. Besides, in these cases, the post-injection has a limited effect on the injected mass and overall storage efficiency and is not suggested due to its low time efficiency. • 3D reservoir model is built to investigate the storage capacity of underground aquifers and the migration process of injected gases. • CO 2 and H 2 are chosen as benchmark gases, with significant differences in their physical properties, especially density, to prompt specialized boundary investigations. • Sensitive calculations are conducted based on vertical and horizontal well systems and under different injection strategies with varying heterogeneities. [ABSTRACT FROM AUTHOR]

• To address the problem of underground saline aquifers sparse data in two saline aquifers in Israel, geostatistical interpolation methods were used to fill in the missing data gaps. • We investigated several interpolation techniques to estimate three parameters of the aquifers (thickness, depth, and porosity) across the entire study area, and utilized the results to evaluate the range of CO 2 storage capacity. • In general, it can be argued that for SC CO 2 density calculations at shallow storage sites, the depth to the top of the aquifer is much more important than for very deep storage sites. • The range of calculated CO 2 capacities of the two aquifers examined indicate that they remain viable optionsfor CO 2 sequestration in Israel in the foreseeable future. • Our findings highlight the importance of explicitly stating the geostatistical method and grid resolution used in CO 2 capacity estimates, as well as in any interpolated map in general. The primary focus for future large-scale projects targeting the sequestration of CO 2 lies in underground saline aquifers. In southern Israel, two such aquifers were identified as suitable for CO 2 storage, however, the data available for these aquifers is limited and sparse. To confront this challenge, geostatistical interpolation techniques are often used to fill in the data gaps. In this study, we evaluate the impact of the interpolation method and cell size on the storage capacity of these two saline aquifers. Eight interpolation techniques are used to estimate three parameters of the aquifers (thickness, depth, and porosity), which serve as the basis for evaluating the CO 2 storage capacity, utilizing the US-DOE-NETL equation. Our findings show that the choice of the interpolation method and cell size has a significant impact on the calculated CO 2 storage capacity, and therefore stress the importance of documenting these parameters. Our evaluation also shows that shallow CO 2 storage sites exhibit a greater sensitivity to depth relative to deeper storage sites. The results of our study are applicable to early-stage assessments of regional CO 2 storage capacity in which data is limited. Calculated CO 2 storage capacities for the two aquifers indicate their continued suitability for CO 2 sequestration in Israel. [ABSTRACT FROM AUTHOR]

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• Strategy to enhance CO 2 injectivity with surfactant was tested by simulations. • Reduction in well BHP is proportional to surfactant quantity in a flat aquifer. • Lower pressure buildup reduces risk of unexpected damage, increasing CO 2 injection. • Proposed strategy is more effective for unfavorable reservoir or injection conditions. • Surfactant treatment alters CO 2 plume migration and trapping mechanism nonlinearly. Fossil fuels currently supply 80% of the world's energy demands and are primarily responsible for increasing carbon concentration in the atmosphere and the associated climate change. Achieving internationally discussed goals for reducing carbon emission will be either impossible or involve significant costs without implementing the CO 2 capture and storage (CCS). The volumetric CO 2 -storage capacity of a brine aquifer is among the most critical factors for the economically-viable & large-scale geologic CO 2 -storage projects. The maximum sustainable injection rate or CO 2 injectivity is another important criterion that depends on many reservoir properties. Based on previous experimental studies, we hypothesized that if the sweep efficiency of CO 2 is improved by using suitable additives, then a higher end-maximum CO 2 saturation can be achieved that, in turn, can increase the CO 2 injectivity. In this regard, a strategy to enhance the CO 2 injectivity was proposed by reducing the irreducible water saturation in a near-well region. In this study, the influence of reducing the irreducible water saturation and thus improving the relative permeability of CO 2 on the CO 2 injectivity and storage capacity is investigated in depth. A series of numerical simulations involving two test models – a hypothetical horizontal aquifer and a pilot test site in South Korea – were conducted to examine our assumptions with the concentration of surfactants confirmed from the previous experimental study. The results help to ascertain the applicability and effectiveness of the proposed injectivity-enhancing strategy. It was observed that the pre-injection of surfactant solution slows down the well-bottom-hole pressure and increases the total CO 2 injection capacity, with the effect deemed proportional to the quantity of surfactant for a hypothetical flat aquifer. However, a nonlinear relationship between the surfactant quantity and the injectivity was found in the case of the pilot test site, which revealed that the surfactant pre-injection influences the migration of CO 2 -plume and solubility trapping as well. [ABSTRACT FROM AUTHOR]

Highlights • Variability of grad-T, surface-T, water density, and water level depth in the Jurassic saline aquifer in Israel. • We apply a stochastic analysis and a Monte Carlo sensitivity analysis. • Sensitivity analysis was performed for CO 2 density and aquifer total capacity. • CO 2 density and the total capacity are very sensitive to the geothermal gradient and the piezometric-surface depth. • The one-factor-at-a-time analysis results are relevant for all shallow aquifers with uncertainty in thermodynamic conditions. Abstract CO 2 storage capacity assessment at a regional or country-size scale is one of the first tools for screening and ranking potential aquifers for deep geological storage. The estimated mass of the stored CO 2 depends on the density of the supercritical CO 2 , which in turn is controlled by the aquifer hydrostatic pressure and temperature conditions. In this paper, we examine the magnitude of error in CO 2 density and total storage capacity arising from uncertainties in subsurface temperature and pressure, and in particular from uncertainties in the surface temperature, geothermal gradient, depth of the piezometric-surface and the density of the formation water, that could propagate into the CO 2 density and the total storage capacity calculations. Using the Israeli saline Jurassic aquifer as a case study, we establish the spatial distributions of the above temperature and hydrostatic pressure components and evaluate the errors using 'Monte Carlo' and 'one-factor-at-a-time' analyses. Our study shows that the depth of the piezometric-surface and the geothermal gradient have the strongest effect on the CO 2 density and on the depth of the transition to supercritical CO 2 , whereas the influence of the surface temperature and the density of the formation water is rather small. As a side result of our study, we are showing that using average values or literature-derived values for the examined parameters, in the case of the Jurassic aquifer, over estimates the total storage capacity by 10% relative to the case where the spatial distribution of those parameters is used. While the analysis of the storage capacity was demonstrated here for the Jurassic saline aquifer in Israel, the conclusions concerning the effect of hydrostatic pressure and temperature uncertainties on the CO 2 density and on the depth of the transition to supercritical CO 2 are general and are especially important for relatively shallow or relatively thick aquifers in which the change in CO 2 density with depth is large. [ABSTRACT FROM AUTHOR]

Abstract In the majority of isolated sites, the diesel generator is seen as the best solution for the electrification. For these sites, access to the electricity grid is either difficult or expensive. The rising price of fuel and the interest in reducing greenhouse gas emissions have led researchers to think otherwise: meeting the energy needs with minimal damage. Renewable energy sources (RES) have experienced a significant drop in the purchase price, making their use in these regions very advantageous compared to conventional sources. One of the barriers to scaling up renewable energy sources (RES) is the intermittency of these sources. The variability experienced by the resources (sun, wind, etc.) is not correlated with the load demand. For that there is always interest to couple several different sources and form what is called a hybrid system. This paper is a review of Hybrid Renewable Energy System (HRES) for electricity generation. It presents the operating mode, the different structure of the HRES and the sizing software used to evaluate the Hybrid Renewable System (HRS) behavior. [ABSTRACT FROM AUTHOR]

Abstract In this study, the effect of Fe 3 O 4 nanoparticles on the CO 2 hydrate formation has been investigated at different concentrations (0.01 wt %, 0.07 wt % and 0.15 wt %), in the presence and absence of magnetic field. The experiments were carried out in a PVT cell at the temperatures of 274.15 K and 276.15 K and the initial pressures of 3, 3.5 and 4 MPa. The parameters studied in this work included the amounts of gas consumption, rate of hydrate formation, water to hydrate conversion and storage capacity. The results show that in the presence of magnetic field the effect of Fe 3 O 4 nanoparticles on these parameters is intensified. However, the best conditions for the CO 2 hydrate formation refer to 0.15 wt% concentration of Fe 3 O 4 nanoparticles in the presence of magnetic field at temperature of 274.15 K and pressure of 4 MPa. At this condition, compared to the pure water, the consumed CO 2 , storage capacity and water to hydrate conversion are increased by 443.9%, 443.6% and 434.6% and the induction time is decreased by 96.6% %, respectively. Also, the impacts of magnetic poles' orientations on the gas hydrate formation were studied. Findings implied that if the opposite poles of the two magnets be directed towards each other, then more significant influence can be observed. Furthermore, the reusability of Fe 3 O 4 nanoparticles has been investigated. The experimental results show that the effectiveness of reused nanoparticles on the CO 2 hydrate formation is very similar to fresh nanoparticles. Graphical abstract Image 1 Highlights • Fe3O4 nanoparticles decrease the induction time of CO2 hydrate formation. • Fe3O4 nanoparticles increase the amount of CO2 consumed in hydrate formation process. • Magnetic field increase the effect of Fe3O4 nanoparticles on CO2 hydrate formation. [ABSTRACT FROM AUTHOR]

Abstract Structural trapping is the primary CO 2 geo-storage mechanism, and it has historically been quantified by CO 2 column heights, which can be permanently immobilized beneath a caprock, using a buoyancy force-capillary force balance. However, the high dependence of CO 2 -wettability (a key parameter in the above analysis) on pressure and temperature – and thus storage depth – has not been taken into account. Importantly, rock can be CO 2 -wet at high pressure, and this wettability reversal results in zero structural trapping below a certain storage depth (∼2400 m maximum caprock depth for a most likely scenario is estimated here). Furthermore, more relevant than the CO 2 column height is the actual mass of CO 2 which can be stored by structural trapping (m CO2). This aspect has now been quantified here, and importantly, m CO2 goes through a maximum at ∼1300 m depth, thus there exists an optimal storage depth at around 1300 m depth. [ABSTRACT FROM AUTHOR]

In this study, we evaluated the feasibility of using CO 2 +N 2 O mixed gas hydrates for the development of advanced greenhouse gas (GHG) sequestration technology. Structural characteristics of gas hydrates at different mole fractions of the gas mixture (CO 2 :N 2 O = 0.7:0.3 and 0.5:0.5) was analyzed using Raman spectroscopy and high-resolution X-ray powder diffraction. The mixed gas hydrates can contain both CO 2 and N 2 O molecules simultaneously, in small and large cages of structure I hydrate without structural deformation. Their volume can be expanded by increase of the N 2 O portion. The phase equilibrium condition of the mixed gas hydrates was more stable than that of pure CO 2 hydrates, and estimated dissociation enthalpies of the mixed gas hydrates were higher than those of the CO 2 hydrates. We confirmed that the mixed gas hydrates can reduce massive amounts of GHG emissions due to their potentially higher storage capacity. These research results provide basic knowledge useful for the simultaneous mitigation of the effects from major GHGs and application of the CO 2 +N 2 O mixed hydrates to advanced offshore GHG sequestration in marine sediment environments. [ABSTRACT FROM AUTHOR]

The development of industrial-scale CCS in Norway, starting with the Sleipner project in 1996, gives a uniquely long track record of experience with CCS and provides valuable insights for the projected global growth in CCS. By the end of 2017, the Sleipner and Snøhvit CCS projects had captured and stored 22 Mt of CO 2 in saline aquifers offshore Norway. CO 2 plume monitoring observations at Sleipner can be used to indicate an overall storage efficiency of around 5% of the pore volume, with approximately one tenth of this volume dissolved in the brine phase. These estimates are consistent with the fluid dynamics of CO 2 injection in which a gravity dominated processes are expected to give efficiencies in the range of 1-6%. Future projects may be able to find ways of improving these efficiencies. [ABSTRACT FROM AUTHOR]

In this study, the effect of argon as a co-contaminant in a CO 2 stream on interfacial tension, diffusion coefficients and storage capacity was experimentally determined under conditions relevant to carbon sequestration, using the pendant drop method. Interfacial properties affect primary capillary trapping mechanisms when CO 2 is injected since they set a limit to storage capacity in a geological formation. A strong increase in the isothermal interfacial tension at 45 °C and up to 20 MPa was observed with an increase in Ar co-contamination from 5 vol.% up to 100 vol.%. Since Ar content is present in small concentrations in most injected CO 2 streams, we focused on measuring brine-CO 2 interfacial tension and brine mixture (CO 2 and Ar) interfacial tension, with 5 vol.% and 10 vol.% of argon content at pressures from 7.5 MPa up to 40 MPa and in the temperature range from 40 °C to 80 °C, which has not previously been investigated and can be considered more oriented to real-world conditions for carbon sequestration. It was found that storage capacity decreased significantly from a scenario where pure CO 2 was injected, down to a scenario where 5 vol.% and 10 vol.% Ar were co-injected into the CO 2 stream. Additionally, the effect of other common impurities in CO 2 streams on interfacial properties and storage capacity is discussed. In order to evaluate the risk of CO 2 diffusion loss through a cap rock, we measured the diffusion coefficients of geological water in the injected fluid. It was found that the diffusion coefficients of water in Ar are higher in comparison to those of water in CO 2 . Small quantities of salt in water had a minor effect on the diffusion coefficients of brine in supercritical CO 2 . Experimentally obtained diffusion coefficients ( D ab ) were correlated to obtain the effective diffusion coefficient ( D eff ). It was found that, in the case of co-injection of Ar with CO 2 , the diffusive gas breakthrough could be enhanced. [ABSTRACT FROM AUTHOR]

In this paper, we present issues of electricity storage requirements based on comparative studies of various results. It was found that when we increase energy from VRE, the use of storage and its capacity increases until we reach some threshold. After that threshold, the storage use starts to decline even if we increase the size. An optimally utilized storage of about daily average demand would be sufficient to reach grid penetration of about 90% of the total demands from VRE. The understanding of the physics and economics of the future energy system is mandatory to build and operate it optimally. [ABSTRACT FROM AUTHOR]

• A modified predictive real-time control approach is presented to reduce peak outflows. • The limitation of storage capacity is overcome by predictive analysis and pre-action. • The required storage volume for the intra-storm release is quantified based on the predicted peak inflow. • Satisfactory control performance is realized in extreme rainfall events. Urban stormwater management has become an important aspect affecting the sustainable development of cities. Real-time control (RTC) of storage facilities is generally considered a cost-effective structural method for flood risk mitigation, but the capacity of storage is often limited by the available land space or local regulations. This study addresses the issue of integrating intra-storm predictive analysis and real-time control for enhancing the peak outflow reduction of a relatively small storage tank. A modified optimization-based approach is presented that utilizes the predicted peak inflow to quantify the required storage volume and subsequently determine the intra-storm release. A sponge city community in Shenzhen, China is selected as a demonstration study case. Numerical experiments based on historic rainfall events indicate that when the storage capacity is 43.9 m3/ha, the modified predictive RTC performs better in peak outflow reduction than an existing predictive RTC and rule-based RTC, with an improvement up to 22.7% and 58.2%, respectively. The modified approach also enhances system performance when storage capacities and rainfall depths vary from the base value. These findings highlight the potential of using the modified predictive RTC to sustainably reduce flood peaks even if the storage capacity is limited. [ABSTRACT FROM AUTHOR]

A study of carbon dioxide-enhanced oil recovery (CO 2 -EOR) and storage capacity in South Sumatera and West Java Basins, Indonesia has been conducted in conjunctions with the project plans of Indonesia National Electric Company to build carbon capture and storage ready coal power plants in Bojonegara of West Java and Muara Enim of South Sumatera. The Bojonegara power plant comprises 2×1000 MWe Ultra Super Critical Units, while Muara Enim consists of 2×300 MWe subcritical units. Those two power plants will produce approximately 11 and 4 million tons of CO 2 per year. The geology of South Sumatera and West Java Basins are proven to have kept oil and gas in place safely for long time periods and there are many oil and gas companies production still active in those basins. Those basins are confirmed to be used as storage of CO 2 , where capacity, injectivity, and confinement will be suitable to keep CO 2 in place for a period of time. CO 2 production from those power plants in South Sumatera and West Java may be offered to the nearby oil companies and transported to oil fields for CO 2 -EOR flooding to get additional revenue. A preliminary CO 2 -EOR screening has been done for the oil fields surrounding the power plants. There are two types of mechanisms for CO 2 -EOR, which depend on the nature of the oilfield: immiscible EOR and miscible EOR. Immiscible EOR occurs where the injected CO 2 does not mix with the oil but instead displaces the oil from the area where the CO 2 is injected and increases the pressure of the oil at the production wells so that it can be pumped out. Miscible EOR occurs where the supercritical CO 2 mixes miscibility with the residual oil to make it less viscous and facilitating its flow to the production wells. A total of 127 oil fields in South Sumatera has been analyzed to select which of those fields fulfill CO 2 -EOR injection criteria. EOR reservoir screenings were performed on those oil fields on which detailed information was available using the screening criteria proposed by Taber et al. The criteria include a set of parameters such as API gravity, oil viscosity, current pressure, temperature, oil saturation, remaining oil, formation depth, thickness, porosity, permeability, and rock type which help to determine whether or not a reservoir is suitable for CO 2 -EOR injection. 96 fields are classified as miscible displacement while the remaining 31 fields are categorized as immiscible. The result shows that the potency of additional recovery from those fields is around 661 million stock tank barrels with CO 2 requirement of approximately 243 million tonnes. In addition to EOR, pure CCS to inject the CO 2 emission into depleted gas fields in West Java and South Sumatera regions is also considered. The maximum storage capacity of West Java gas fields is approximately 395 million tonnes, while the storage capacity of South Sumatera is around 537 million tonnes. The potential for storing CO 2 in the saline aquifer was also calculated theoretically. The depleted gas fields and aquifers are considered enough to store the CO 2 emission from the power plants as long as 25 years. [ABSTRACT FROM AUTHOR]

Successful CO2 storage in abandoned oil and gas fields, building the underground gas storages, and enhanced oil and gas recovery require a functional 3D static geological model of the storage complex with the real geometry and conditions. Abandoned oil and gas field Lanzhot-Brodske North (LBr1) on the territory of the Czech Republic was selected for the preparation of a pilot research project of the geological CO2 storage. It is situated in the Northern part of the Vienna Basin, close to the Czech-Slovak border. The 3D-model includes a separate northern part of the LBr1 field. The 3D model is designed to serve as an input for the dynamic model and makes it possible to experiment and test simulations of the CO2 storage in a more-or-less real geological environment. The model documents areal and vertical extent of the storage complex, geological structure formed by the Lab reservoir horizon, trap seal built by the overlying clays, overlying and adjacent strata, aquifers, faults, natural and artificial migration paths. Further information provided by the model consists of the reservoir volume, pore space, reservoir properties, fluid distribution, and saturation by the pore fluids. A simplified 3D-model of the reservoir overburden offers a basis for risk analysis of potential fluid migration into shallower aquifers. [ABSTRACT FROM AUTHOR]

The successful deployment of carbon capture and storage as a means to mitigate greenhouse gas emissions requires the availability of significant geological storage capacity. Assessments that identify suitable sedimentary basins and their capacity are the first logical step in defining global carbon capture and storage potential. This paper presents a collation and summary of the current status of storage assessments worldwide known as the Global Storage Portfolio. The analysis found that there are substantial storage resources available in most regions of the world. Almost all nations that have published regional assessments have identified sufficient storage resources to support multiple carbon capture and storage projects. This analysis also found that the methods to determine and classify resources are highly variable across regions despite reliable assessment methodologies being available. Case studies on Europe and Southeast Asia discuss the different approaches being undertaken for their respective regional assessments and their progression towards being ready for the deployment of CCS. [ABSTRACT FROM AUTHOR]

A small scale injection project into an offshore aquifer near shoreline has begun which is seeking the connection with a capture project in Korea. The Pohang basin was selected as a site for a small-scale pilot project and detailed site characterization has been undertaken to establish a geological model for the site since 2013. A potential reservoir for CO 2 injection was found at a depth more than 730 meters in the southern offshore part of the Pohang basin from seismic surveys and one exploration well. The seismic interpretation revealed the reservoir is a steeply dip and horizontally fault bounded aquifer. In this study, numerical reservoir simulations were carried out for assessing CO 2 storage capacity especially in the dipping reservoir regarding the reactivation pressure of the bounded faults. At the same time, to investigate the effect of impurity in CO 2 stream was one of our goals. Captured CO 2 streams contain various levels of impurity which vary depending on the combustion technology and CO 2 sources. Specifically for geological storage, the non-condensable gases in CO 2 streams are not favorable because they can decrease density of the injected CO 2 stream and can affect buoyancy of the plume. The effect of the non-condensable gases on storage capacity, injectivity and plume migrations were tested in the reservoir. [ABSTRACT FROM AUTHOR]

Geological CO 2 storage is a mitigation technology to reduce CO 2 emissions from fossil fuel combustion. However, major concerns are the pressure increase and saltwater displacement in the mainly targeted deep groundwater aquifers due to injection of supercritical CO 2 . The suggested solution is storage of CO 2 exclusively in the dissolved state. In our exemplary regional case study of the North East German Basin based on a highly resolved temperature and pressure distribution model and a newly developed reactive transport coupling, we have quantified that 4.7 Gt of CO 2 can be stored in solution compared to 1.5 Gt in the supercritical state. [ABSTRACT FROM AUTHOR]

A series of probabilistic evaluation is performed using geologic formation modeling and grid-based Monte Carlo simulation to estimate geologic carbon dioxide (CO 2 ) storage capacities of target saline formations at a prospective storage site in the Janggi Basin, Korea. The Janggi Conglomerate (Reservoir 1) and the lower member of the Seongdongri Formation (Reservoir 2), both of which consist of conglomerate, sandstone, siltstone, and mudstone, are selected as target saline formations for geologic CO 2 storage at the site. The results of the probabilistic evaluation show that the theoretical fluid-phase CO 2 storage capacities are significantly higher than the theoretical aqueous-phase CO 2 storage capacities in both reservoirs, respectively. However, the effective fluid-phase CO 2 storage capacities are nearly equal to the effective aqueous-phase CO 2 storage capacities in both reservoirs, respectively. This arises because the aqueous-phase CO 2 storage efficiency factors are much higher than the fluid-phase CO 2 storage efficiency factors in both reservoirs, respectively. [ABSTRACT FROM AUTHOR]

The purpose of Carbon Capture and Storage (CCS) is to reduce emissions of greenhouse gases to the atmosphere as a climate change mitigation activity. However, given the relatively high costs currently associated with CCS, coupling CCS with Enhanced Oil Recovery (EOR) could provide a critical financial incentive to facilitate development of CCS projects in the near term. One issue is that projects to enhance oil production are primarily implemented to increase oil production with (tertiary recovery methods and any long term storage of CO 2 is considered a potential ancillary benefit. When projects are designed as CCS from the start, there is typically a site evaluation process to review the storage formation according to best practice criteria for CCS. In EOR, the formation where CO 2 would be stored is predetermined by the existing oil bearing reservoir, raising potential questions about monitoring, long-term CO 2 storage liabilities, potential, leakage, permanence and other issues that must be addressed in CCS projects but may fall outside the boundaries of a typical EOR project. Finally, although this paper is premised on historical and current experiences with enhanced oil recovery projects, similar considerations could also be given to enhanced recovery of natural gas. There are no specific technological barriers or challenges in transitioning and converting a pure CO 2 -EOR operation into a CO 2 storage operation but there are a number of legal, regulatory and economic differences which must be addressed if an EOR project is to serve as a CCS project. Lack of experience or unresolved issues related to EOR becoming CCS could create barriers unless the issues are fully understood and managed to the satisfaction of regulators. Understanding best practice and the policy and regulatory frameworks affecting CCS from EOR is an important driver for ensuring that CO 2 -EOR projects are developed in a manner which will enable the carbon stored to be recognised as a mitigation activity under local legislation/carbon market schemes and in national GHG inventories which support monitoring progress under the COP21 Paris Agreement. The paper provides an overview of the key issues in the USA, Canada, EU, Australia, and Brazil and provides recommendations for what companies need to do should they wish to transition from EOR to CCS for existing or future operations. [ABSTRACT FROM AUTHOR]

Carbon capture and storage (CCS) in subsurface reservoirs has been identified as a potentially cost-effective way to reduce CO 2 emissions to the atmosphere. Global emissions reductions on the gigatonne scale using CCS will require regional or basin-scale deployment of CO 2 storage in saline aquifers. Thus the evaluation of both the dynamic and ultimate CO 2 storage capacity of formations is important for policy makers to determine the viability of CCS as a pillar of the greenhouse gas mitigation strategy in a particular region. We use a reservoir simulation model representing the large-scale Bunter Sandstone in the UK Southern North Sea to evaluate the dynamics and sensitivities of regional CO 2 plume transport and storage. At the basin-scale, we predict hydrogeological changes in the storage reservoir in response to multiple regional carbon sequestration development scenarios. We test the sensitivity of injection capacity to a range of target CO 2 injection rates and fluctuations in CO 2 supply. Model sensitivities varying the target injection rates indicate that in the absence of pressure management up to 3.7 Gt of CO 2 can be stored in the Bunter region over 50 years given the pressure constraints set to avoid fracturing the formation. Long-term (approx. 1000 years), our results show that up to 16 Gt of CO 2 can be stored in the Bunter region without pressure management. With pressure management, the estimate rises to 32 Gt. However, consideration must be given to the additional operational and economic requirements of pressure management using brine production. [ABSTRACT FROM AUTHOR]

A key uncertainty facing Carbon dioxide Capture and Storage (CCS) in saline aquifers is long term injectivity, which is primarily a function of the connected aquifer pore-volume within which formation brine can be displaced as the CO 2 is injected. Protracted injection testing to interrogate and prove the far-field connected pore-volume would increase the lead-in times for commissioning of storage sites and would significantly increase appraisal costs. Here we use natural gas production and subsequent reservoir recharge legacy data from the Esmond gas field in the UK sector of the southern North Sea to gain an understanding of the dynamic behaviour of the Bunter Sandstone, a major saline aquifer. Results suggest that Esmond has a connected pore volume of 1.83x10 10 m 3 , suitable for injecting CO 2 at a rate of up to 2 million tonnes per year for at least 55 years. 3D seismic data suggest that Esmond reservoir properties are likely to be replicated across the wider Bunter Sandstone aquifer, notably around the Endurance structure which was, until recently, proposed for a full-chain CCS project. [ABSTRACT FROM AUTHOR]

Geological storage of captured CO 2 , which typically will contain certain amounts of impurities, in saline aquifers is of potential to reduce greenhouse gas emissions into the atmosphere. The co-injection of the impurity SO 2 has an effect on the chemical reactivity of the fluid and solid phases as well as on the physical behaviour of the CO 2 plume. To address these influences we assessed the impact of SO 2 on the physicochemical behaviour of the CO 2 phase by pressure-volume-temperature calculations and geochemical modelling of fluid-rock interactions. As case study, the Ketzin pilot site in Germany was chosen. The results reveal that the presence of SO 2 causes a greater porosity decrease compared to pure CO 2 during the injection period. Certainly, any textural changes that occur in the vicinity of the injection well are of importance for selecting the right injection strategy and to reduce operational costs. We further assessed the impact of SO 2 on the overall CO 2 storage capacity at different depth. Particularly, there is a maximum reduction of the storage capacity at low depth, but the general impact of SO 2 concentrations <1% is comparatively low. Furthermore, short-term porosity changes that are induced by chemical reactions beyond the dry-out zone will reduce the pore spaces available for storage. [ABSTRACT FROM AUTHOR]

• We estimate total storage capacity in major onshore sedimentary basins in China. • We constrain storage capacity using a semi-analytical model of pressure build-up. • We develop a framework for probabilistic modeling of geological carbon storage. • Global Sensitivity Analysis determines rock attributes as key uncertainty sources. • CCS in China potentially plays a key role to mitigate global warming by 2060. We provide a probabilistic assessment of CO 2 storage capacity in major sedimentary basins in China. Our approach embeds constraints associated with the increase of reservoir pore pressure due to injection of CO 2 in the presence of resident brine. Pressure build-up must be limited to avoid fault reactivation, caprock failure, and possible leakage, resulting in more conservative estimates of CO 2 storage capacity as compared to volumetric estimates. We rely on a numerical Monte Carlo framework considering uncertainty in the values of reservoir size and major geological formation attributes (i.e., absolute permeability, porosity, and reservoir compressibility). Our work shows that 10 major basins can potentially store, on average, 1350 Gt of CO 2 during the next 30 years (lower and upper quartiles being 1100 and 1700 Gt of CO 2 , respectively). This far exceeds the likely amount (up to 175 Gt of CO 2) required to be stored by 2050. Our analysis also suggests that 6 basins (located close to the largest emission areas) can store about 93 Gt (on average) of CO 2 during the next 30 years. Underground carbon storage in China, coupled with other possible solutions, could meet the aims of the Announced Pledges Scenario (International Energy Agency) to mitigate global warming by 2060. We also perform a global sensitivity analysis to determine how our predictions of storage capacity may be affected by uncertainties in the simulation model input parameters. Moment-based global sensitivity metrics suggest that geological formation attributes are major sources of uncertainty, significantly affecting model outputs and the associated uncertainty. [ABSTRACT FROM AUTHOR]

Deep saline aquifers are a promising choice for geological carbon dioxide (CO 2 ) sequestration due to their greater storage capacity compared to other geological storage options. Injectivity and storage capacity are key concerns especially considering injection of CO 2 into low-permeability reservoirs. Estimation of the CO 2 injectivity and storage capacity was conducted with an analytical method and dynamic numerical modeling for an active demonstration site (Chenjiacun) of CO 2 sequestration in the Ordos Basin. The analytical estimate of the mass injectivity of the Liujiagou reservoir is 4.06 × 10 −6 kg Pa −1 s −1 , which is about 64% of the injectivity of the entire reservoir system, followed by the Shiqianfeng unit, which accounts for some 15.8%. The maximum injection rate for the Liujiagou reservoir was estimated to be roughly 15.1 kg/s, leading to 476,000 t of CO 2 injected per year. The maximum injection rates for the other four reservoirs are substantially smaller than that for the Liujiagou reservoir. The injectivity of the Liujiagou reservoir estimated by numerical simulation ranges from 0.7 to 3.0 × 10 −6 kg Pa −1 s −1 . The injectivity of the Shiqianfeng reservoir was estimated to be from 0.2 to 1.1 × 10 −6 kg Pa −1 s −1 . The injectivities of the remaining reservoirs (i.e., Shihezi downward) are smaller than 0.6 × 10 −6 kg Pa −1 s −1 . The maximum injection rate estimated from the numerical simulation is approximately 17 kg/s, leading to 536,000 t storage of CO 2 , with the injection pressure limited to 1.5 times hydrostatic pressure. The annual CO 2 storage capacity of the Chenjiacun site is estimated to be 0.53–0.69 Mt, for a single vertical injection well. About 5 injection wells may be required to deal with the current CO 2 emission rate from CSCLC coal liquefaction processes, which is about 3 Mt per year. The injectivity and storage capacity at Chenjiacun are not much smaller than that at In Salah and Ketzin, owing to the relatively great thickness and long perforated interval at Chenjiacun. In order to improve the reservoir injectivity and storage capacity further at Chenjiacun for large-scale CO 2 storage in the future, possible injection strategies and reservoir management options include introduction of stimulation measures and water-production wells at approximately 1000 m or even further away from the injection well, as well as using fully penetrating vertical wells with long perforated intervals. [ABSTRACT FROM AUTHOR]

CO 2 storage potential in Greece concerns mainly aquifers and a few hydrocarbon fields. The potential for CO 2 storage in oil and gas fields in Greece lies offshore, in the Prinos-Kavala basin, in NE Greece, whereas the biggest share of the point source CO 2 emissions come from NW Greece. Potential for storage also exists in lignite fields, which have been extensively mined for power generation. This paper presents an overview of the potential for CO 2 storage throughout various sites in Greece, including the Mesohellenic Trough (MT), located in Northwestern Greece. Geological model building of the MT allowed to make an assessment of the CO 2 storage potential of the trough and provided an estimation of the CO 2 storage capacity in the Pentalofos and Eptahori reservoirs. According to the geological model, characterized by horizontal maximum dimensions of 47 km by 100 km and covering a surface area of 3813 km 2 , the deepest point where we can store CO 2 corresponds to the base of the Tsarnos member, at -2544 m depth. We estimate that altogether we can store up to a maximum of 728 Gt of CO 2 in the Pentalofos Formation (Tsarnos and Kalloni Members) and Eptahori Formation. The location of the potential storage sites, relatively close to emission points, forms interesting combinations, which are briefly presented in this paper. The results presented here will serve as a basis for pursuing this worthwhile piece of research in order to determine the most reliable and most cost efficient ways of transporting and storing CO 2 in Greece. [ABSTRACT FROM AUTHOR]

Carbon capture and storage (CCS) is a key technology which could be utilized to stabilize CO 2 concentrations in the atmosphere. While all the components of integrated CCS systems exist and are in use today in the fossil-fuel extraction and refining industries, very few large-scale integrated CCS projects are currently in operation, due mainly to the high cost of implementation. For this reason, in the last few years the concept of CO 2 capture, utilization and storage (CCUS) has been advanced, based on the premise that utilizing CO 2 captured from anthropogenic sources, particularly in CO 2 enhanced oil recovery (EOR) operations, would provide revenue that will, accordingly, reduce costs and facilitate deployment. When a large number of oil reservoirs are found in a particular region or jurisdiction, it is very difficult to ascertain which oil reservoirs are suitable for CO 2 -EOR by using detailed reservoir analysis and numerical simulations. In such cases, reserves databases may contain sufficient information to allow a region- or jurisdiction-wide identification (screening) of oil reservoirs suitable for CO 2 -EOR. Based on industry's experience to date with CO 2 -EOR, a set of 14 criteria has been developed to screen oil reservoirs in terms of their suitability for CO 2 -EOR, including operational and reservoir characteristics, and reservoir size. Using the published statistical analysis of the performance of 31 CO 2 -EOR operations in Texas, it is possible to estimate the incremental oil recovery factor and the net CO 2 utilization factor for a given oil reservoir suitable for CO 2 -EOR, hence the incremental oil recovery and associated CO 2 storage for that reservoir. In terms of CCUS, two additional screening criteria are introduced, which relate the size and location of large CO 2 sources with respect to the location and potential CO 2 storage capacity of a given oil reservoir suitable for CO 2 -EOR. If more than one oil reservoir meets these conditions for a particular large CO 2 source, the reservoirs could be ranked using a weighted normalized parametric procedure that takes into account reservoir storage capacity in relation to the size of CO 2 emissions from that particular source, the distance between the source and the reservoirs, and the depth of the reservoirs. The screening and ranking procedures for identifying oil reservoirs suitable for CO 2 -EOR and CO 2 storage has been applied to Alberta, Canada, where there are close to 13,000 oil reservoirs recorded in the reserves database of the oil and gas regulatory agency. Application of the screening criteria identified 136 oil reservoirs in 85 oil fields that are suitable for CO 2 -EOR. The criteria that have the greatest impact on screening are oil gravity, minimum miscibility pressure and reservoir size. Second-order criteria in terms of impact are reservoir temperature and oil viscosity. Porosity and initial oil saturation have almost no effect, mostly because most reservoirs would normally satisfy these criteria. The cumulative incremental oil production at 2 HCPV injected CO 2 in these 136 oil reservoirs is estimated to be 759, 1742 and 2858 MMSTB at P 10 , P 50 and P 90 , respectively, with corresponding cumulative CO 2 storage capacity of 213, 868 and 1742 Mt CO 2 . Considering a maximum straight distance of 300 km between any of the 38 large CO 2 sources in Alberta and oil fields with reservoirs suitable for CO 2 -EOR, and a minimum storage capacity equivalent to 5 years of emissions leads to the identification of 29 oil fields that are suitable for both CO 2 -EOR and CO 2 storage (i.e., CCUS). The methodology presented herein for screening oil reservoirs for CO 2 -EOR and CO 2 storage can be applied to any region or jurisdiction in the world, possibly with some adjustments regarding some threshold values and weighting coefficients for reservoir ranking. [ABSTRACT FROM AUTHOR]

The first dynamic modeling study of CO 2 geological storage in the Baltic Sea basin is presented. The focus has been on the southern part of the Dalders Monocline. The objective is to get order-of-magnitude estimates of the behavior of the formations during potential industrial scale CO 2 injection and subsequent storage periods, with an emphasis on two important aspects of CO 2 storage: the injection-induced pressure impact and the long-term upslope migration. In order to maximize the confidence in the model predictions, this work employs a set of different modeling approaches of varying complexity, including a semi-analytical model, a sharp-interface vertical equilibrium (VE) model and a TOUGH2-ECO2N model. The semi-analytical model provides fast estimation of the pressure buildup as well as its sensitivity to variation of the reservoir parameters. Given a certain pressure threshold, a maximum injection rate is estimated from the semi-analytical model and is then fed to the numerical models. The pressure buildup predicted by the numerical models fall close to that by the semi-analytical solution. Extensive modeling of the post-injection upslope migration and trapping evolution together with sensitivity analysis suggests that it is unlikely for CO 2 to leak through the north end of the formation. Under the currently considered scenario, the dominant constraint for the storage capacity is the pressure buildup. The pressure limited capacity ( C p ) of the southern Dalders Monocline for the scenario studied here is estimated to be about 100 Mt for a 50-year injection duration. C p is found to increase with permeability as C p ∼ k 0.926 . Given the knowledge of the dominant constraint for capacity, storage optimization can be specifically targeted on the injectivity issue and operational strategies can be designed to relieve the pressure buildup (e.g., by adding brine production wells, using horizontal wells). [ABSTRACT FROM AUTHOR]

Carbon capture and storage (CCS) is a promising technology for reducing atmospheric CO 2 emissions from industrial CO 2 emitters. The high cost of carbon capture is one of the major barriers to the implementation of CCS. CO 2 captured from industrial emitters contains various impurities such as N 2 , O 2 , Ar and SO x , and storing the impure CO 2 underground would eliminate the need for purification and substantially reduce the cost. However, the impurities may negatively impact CO 2 storage. In this work, we studied the impact of impurities on the storage capacity of CO 2 in geological formations through density changes. Density measurements for CO 2 mixtures with N 2 , O 2 , Ar and SO 2 were carried out in CO 2 storage pressure and temperature ranges. The observed density behaviors and the impact on the storage capacity of CO 2 are analyzed. The experimental and analytic results suggest that N 2 , O 2 and Ar would bring about a minimum of the storage capacity at a certain pressure, where about 15 mol% N 2 , O 2 and Ar could reduce the storage capacity for CO 2 by over 65%. The reduction of the storage capacity decreases with increasing temperature. The results also suggest that Ar could represent the three air-derived impurities combined in density and storage capacity evaluations for CO 2 mixtures. Moreover, the results suggest that SO 2 could bring about a maximum of the storage capacity, where more CO 2 could be stored in given space compared to pure CO 2 case. Based on the analysis, a generalization is proposed to predict whether a minimum or a maximum for the CO 2 storage capacity would occur with different impurities. [ABSTRACT FROM AUTHOR]

To utilize the combined effects of earth-to-air heat exchanger (EAHE) and phase change material (PCM) in indoor thermal environment regulation during summer, this study proposes a combination mode, i.e., EAHE–PCM. In this method, EAHE continuously provides cool air to indoor spaces. PCM integrated into building envelopes stores excess cold provided by EAHE at night and transfers it indoors across time. We performed two full-scale comparative experiments (EAHE–PCM combined operation mode and PCM alone operation mode) on typical summer days in hot-summer and cold-winter regions. The results showed that the maximum reduction in the EAHE outlet air temperature and moisture content reached 21.6 °C and 4.55 g/kg, respectively, inducing an average cooling capacity of approximately 1186.5 W. The use of EAHE decreased the time-averaged PCM internal temperature by 6.0 °C in 24 h compared to the PCM alone operation mode, thereby activating the phase change process of PCM between 19:54 and 9:45. Therefore, PCM can store excess cold provided by the EAHE via latent heat and transfer it to indoor air through the melting process, resulting in a 157 min lag in the PCM internal temperature rise. When the ambient air temperature varied between 26.3 and 45.2 °C, the EAHE–PCM combined operation mode decreased the time-averaged indoor air temperature by 6.6 °C compared to the PCM operation alone, which helped maintain the indoor air temperature within the comfort temperature range of 22–28 °C for 73% in 24 h, with a peak temperature of 30.6 °C. • EAHE–PCM is proposed to regulate the indoor thermal environment during the summer. • Excess cold provided by EAHE is stored by PCM via phase change process. • EAHE–PCM decreased the time-averaged indoor air temperature by 6.6 °C. • EAHE–PCM maintained indoor air temperature within the comfort temperature range. [ABSTRACT FROM AUTHOR]

At the time the IPCC Special Report on Carbon Capture and Storage was published in 2005, the concept of CO 2 storage efficiency was not introduced yet and, consequently, no numerical values were published in the literature. CO 2 storage efficiency is defined as the ratio of the volume of CO 2 injected into an aquifer rock volume to the pore space in that volume and this concept has been first introduced in 2007 in regional-scale assessments of storage capacity in the United States and Europe. Since then many papers, reviewed in this article, have been published on the subject of efficiency of CO 2 storage and associated values. CO 2 storage efficiency depends on a multitude of factors that can be grouped into several categories: (1) Characteristics of the storage aquifer, such as in situ conditions of pressure, temperature and salinity, displacement characteristics of the CO 2 /brine system, lithology, porosity, permeability, heterogeneity and anisotropy, aquifer areal extent, thickness and boundaries; (2) Characteristics of the confining aquitards, mainly permeability and capillary entry pressure; (3) Characteristics of the CO 2 storage operation, such as injection rate, duration of injection; number of injection wells, their orientation and their spacing, and injection strategy, including water production and/or injection; and (4) Regulatory constraints, such as maximum bottom-hole injection pressure, and definitions used to establish the volume of rock assigned for CO 2 storage for a given project, such as scale of assessment (local or regional), relevant time (e.g., at cessation of injection or at plume immobilization), and relevant aquifer area (e.g., footprint of the CO 2 plume itself, area where aquifer pressure is higher than a critical pressure, or area of tenure). Depending on the combination of factors listed above, values of storage efficiency as calculated to date and published in the literature vary in a wide range (from <1% to >10%, by a factor of 20 and even higher) and no single value or set of values can be universally used. Storage efficiency has both a spatial and a temporal dependency; being first pressure- and then space-limited; therefore it is critical in all assessments to specify the relevant aquifer area and time of reference. For closed aquifers, the cross-over time from pressure-limited to space-limited is achieved very quickly, and storage efficiency is based on the compressibility of the system. For open aquifers, a CO 2 storage operation is most likely pressure-limited during its entire life. Storage resource estimates are theoretically time and space independent in the sense that the entire aquifer is considered, and the estimate represents what would be achieved if all the aquifer pore space would be accessible through a very large number of wells and over a very long period of time, much longer than a project life-time and the period of time needed to achieve climate stabilization. Volumetric estimates could be used for regional-scale evaluations of CO 2 storage resources using values at the lower end of the spectrum of published values for storage efficiency. Dynamic estimates, based on numerical simulations that take into account operational and regulatory factors should be used for local-scale CO 2 storage reserves estimates. Storage efficiency can be increased using storage engineering technology, such as water extraction and/or (re)injection, and the type and location of various injection and producing wells. [ABSTRACT FROM AUTHOR]

Water extraction from carbon dioxide (CO 2 ) storage reservoirs may be a method to enhance storage capacity and to actively manage storage reservoirs. Previous investigations into the use of water extraction have utilized homogeneous models to assess the feasibility of this technology. This study addressed water extraction based on four hypothetical CO 2 storage sites, which varied with respect to heterogeneous lithology, variable structure, and complex internal geometry. The simulation results showed the increased CO 2 storage capacity achieved through the use of water extraction varies greatly based on site conditions, ranging from 4% to 1300% in the four cases investigated. In all scenarios, water extraction reduced the maximum reservoir pressures approximately 10–20% during injection. In most scenarios, CO 2 plume movement could also be influenced through the use of water extraction. The last two aspects may be very beneficial for risk management and monitoring, verification, and accounting practices for all of the CO 2 storage projects. [ABSTRACT FROM AUTHOR]

The Plains CO 2 Reduction (PCOR) Partnership, through the Energy & Environmental Research Center, is collaborating with Petroleum Technology Research Centre in site characterization; risk assessment; public outreach; and monitoring, verification, and accounting activities at the Aquistore project. The PCOR Partnership constructed a static geological model to assess the potential volumetric storage capacity of the Aquistore site and provide the foundation for dynamic simulation for the dynamic CO 2 storage capacity. Results of the predictive simulations will be used in the risk assessment process to define an overall monitoring plan and assure stakeholders that the injected CO 2 will remain safely stored. [ABSTRACT FROM AUTHOR]

In 1998, the IEA Greenhouse Gas R&D Programme (IEAGHG) assessed the global potential for CO 2 enhanced coal bed methane (CO 2 -ECBM) recovery and associated CO 2 storage based on data from the one successful pilot project at the time in the San Juan Basin in the USA. After 1998, subsequent CO 2 injection projects in coal seams were generally determined not to be successful. Nonetheless, these projects contributed to “lessons learned” that helped advise further research and demonstration (R&D) activities. IEAGHG recently reassessed the status of R&D in CO 2 -ECBM and CO 2 storage. In this assessment, the primary objectives were to: (1) assess the global status of coalbed methane (CBM) production and the potential effects on CO 2 storage; (2) review the current status of research into the enhanced gas recovery (EGR) and geological storage of CO 2 in coals; and (3) develop an updated assessment of the global potential for EGR and geological storage of CO 2 in coal formations. The paper summarizes the results of this work, along with other related activities. It reviews the results from more recent CO 2 - ECBM and CO 2 storage trials in the San Juan Basin in the USA, the results of other small-scale demonstration projects conducted by the U.S. Department of Energy's (DOE's) Regional Carbon Sequestration Partnerships (RCSP) Program, and reviews the status of an ongoing DOE-funded project conducted by CONSOL and Virginia Tech University in the USA, as well as for the Coal-Seq Consortium. The IEAGHG study concluded that the technical recovery potential for methane from the world's coal seams is estimated to be 79 trillion cubic meters (Tcm) globally, 29 Tcm associated with conventional CBM recovery, and 50 Tcm from the application of CO 2 - ECBM recovery as a secondary production technique. This could facilitate the potential storage of nearly 488 billion metric tons (or gigatonnes (Gt)) of CO 2 in unmineable coal seams. [ABSTRACT FROM AUTHOR]

The inherent complexity of microporous rocks together with their relatively low adsorption capacity as compared to commercial adsorbents represent a new scientific and technical challenge in the study of adsorption at supercritical conditions. In this paper, CO 2 adsorption isotherms are analyzed that have been measured on various microporous samples, thus including natural adsorbents, such as shales and clay minerals, and engineered materials, such as zeolites. The analysis focuses on the estimation of the density of adsorbed CO 2 , a parameter that is key to quantify the storage capacity of a given material. It is shown that the latter is significantly overestimated when the volume of the adsorbed phase is neglected, this being unfortunately a common practice in the assessment of the storage potential of geologic formations. At the same time, estimates of the density (or volume) of the adsorbed fluid are largely uncertain with values ranging between the critical and the solid density of the adsorbed even when the same experimental conditions are considered. More data at representative conditions are needed to assess the real contribution of adsorption to the storage capacity of shales. Simultaneously, experimental protocols need to be refined to quantify high-pressure adsorption in microporous solids, thus including the characterization of structural parameters, such as the porosity and the (inaccessible) skeletal volume. [ABSTRACT FROM AUTHOR]

A workflow was developed to properly assess the CO 2 storage resource potential of a deep saline formation using the methodology proposed by the U.S. Department of Energy. To illustrate the workflow, the Minnelusa Formation of the Powder River Basin is used as an example of how a CO 2 storage resource methodology could be applied to a saline formation given varying levels of information. It is important to accurately estimate the effective volumetric CO 2 storage resource potential of a target formation, and new storage efficiency values are presented with the workflow. [ABSTRACT FROM AUTHOR]

Supercritical CO 2 has good mobility and certain heat capacity, which can be used as an alternative of water for heat recovery from geothermal reservoirs, meanwhile trapping most of injected CO 2 underground to achieve environmental benefits. In this paper, different types of geothermal resources are assessed to screen reservoirs suitable for geological storage and heat mining by CO 2 injection, in terms of geological properties, heat characteristics, storage applicability, and development prospects, etc. Deep saline aquifer, geopressured reservoir and hot dry rock are selected as the potential sites, mainly due to their relatively positive geological conditions for CO 2 circulation and storage. Reservoir simulations are conducted to analyze the storage efficiency and heat extracting capacity of CO 2 in the promising geothermal reservoirs. A simple calculation method is presented to estimate the potentials of CO 2 storage and heat mining in the major prospective geothermal regions of China. The preliminary assessment results show that the recoverable geothermal potential by CO 2 injection in China is around 1.55×10 21 J with hot dry rocks as the main contributor. The corresponding CO 2 storage capacity is up to 3.53×10 14 kg with the deep saline aquifers accounting for more than 50%. CO 2 injection for geothermal production is a more attractive option than pure CO 2 storage due to its higher economic benefits in spite of that many technological and economic issues still need to be solved in the future. [ABSTRACT FROM AUTHOR]

This paper reports on research sponsored by the U.S. Department of Energy (USDOE) to assess factors influencing enhanced gas recovery (EGR) and CO 2 storage in selected gas shales in the Eastern USA [1] . The paper also summarizes work sponsored by the IEA Greenhouse Gas R&D Programme (IEAGHG), which builds upon the lessons learned regarding EGR and CO 2 storage in the U.S., combined with a global assessment of shale gas potential [2] , to develop a high-level estimate of the potential for EGR and CO 2 storage in gas shales globally [3] . In total, the four selected shale gas plays in the Eastern USA addressed in this assessment cover an area of 470,000 square kilometres (182,000 square miles). These shales may contain an estimated 170 trillion cubic meters (Tcm) (6,000 trillion cubic feet (Tcf)) of gas in place, and have a maximum theoretical storage capacity of over 600 billion metric tons (gigatonnes, Gt). Accounting for assumptions about the portion of the gas in-place in these shale plays that may be recoverable, and the portion of this recoverable resource that could be economic to produce using EGR techniques with CO 2 injection, nearly 34 Tcm (1,200 Tcf) of EGR potential is estimated to be associated with the injection of CO 2 into these shale gas plays. Of this, 13 Tcm (460 Tcf) could be economic to recover with reasonable gas prices and/or modest incentives. This could facilitate the storage of nearly 50 Gt of CO 2 . Building upon this work, as well as an assessment by the U.S. Energy Information Administration (USEIA) that provides a “first- order” view of the gas in-place and technically recoverable resource for 48 shale gas basins and 69 shale gas formations in 32 countries, an estimate was developed of the global the potential for EGR and CO 2 storage in gas shales [3] . An estimated 188 Tcm (6,600 Tcf) of shale gas resources are potentially technically recoverable globally (not including consideration of the potential EGR realized as a result of CO 2 injection in shales). This could facilitate the potential storage of 740 Gt of CO 2 in gas shales. Of this, as much as 71 Tcm (2,505 Tcf) could be economic to produce with EGR, and could facilitate the economic storage of 280 Gt of CO 2 . [ABSTRACT FROM AUTHOR]

Recently, the IEA Greenhouse Gas R&D Programme and U.S. Department of Energy commissioned the Energy & Environmental Research Center to address concerns related to the validity of volumetric techniques for estimating the CO 2 storage efficiency of saline formations. Two deep saline systems were compared using volumetric and dynamic storage resource estimation methods. Results indicate that volumetric estimates are valid and nearly equivalent to dynamic results, provided that boundary conditions are properly considered and a sufficient number of injection wells and duration of injection are used. For short time frames (e.g., 50 years of injection), volumetric estimates may be optimistic. [ABSTRACT FROM AUTHOR]

The United States Department of Energy's National Energy Technology Laboratory (DOE-NETL) is developing a volumetric- based methodology for calculating prospective CO 2 storage resource of organic-rich shale formations. Similar to natural gas, carbon dioxide (CO 2 ) can be stored in organic-rich shale as free-gas within fractures and pores and as a sorbed component on organic matter and clays. The proposed methodology includes three screening criteria to serve as guidelines for assessing CO 2 storage. The absence of thorough, comprehensive geologic and petrophysical data for unconventional shale reservoirs is noted as a significant limitation and source of uncertainty in estimating CO 2 storage resource. Future work is aimed towards analyzing geologic data from organic-rich shale in order to refine the methodology and reduce the uncertainty associated with CO 2 storage in these complex formations. [ABSTRACT FROM AUTHOR]

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Storing CO2 in oil reservoirs is not only an effective method for reducing CO2 emissions and greenhouse effects, but also a means to be more economical by enhancing oil recovery. The evaluation of CO2 storage capacity in oil reservoirs which is very important for the implementation of CO2 storage includes the evaluation of theoretical, effective, practical and matched storage capacities. Based on the volumetric balance theory, considering CO2 dissolved in remaining oil and water, sweep efficiency and displacement efficiency, this paper utilizes three methods to calculate theoretical and effective CO2 storage capacity in oil reservoirs, in which CO2 volumetric sweep efficiency, oil recovery factor and sequestration factor are key parameters. This work presents a reservoir numerical simulation method, an empirical formula method, and a stepwise regression method. The feasibility, superiority and limitations of the methods for calculating these three key parameters and storage capacities - including theoretical and actual CO2 storage capacities - were analyzed through simulated applications in three reservoirs of the Xinjiang Oilfield of China. The results indicated that the assessment results of stepwise regression has a high level of accuracy, and that this oilfield can provide a large storage capacity and is thereby worthy of further study. [ABSTRACT FROM AUTHOR]

Abstract: Estimating the carbon dioxide (CO2) storage capacity of deep saline aquifers is important for identifying those most suitable for sequestration, and for planning the future development of CO2 storage projects. Currently, capacity estimates are highly uncertain due in part to uncertainty in the dominant constraint on capacity: both the pressure buildup from injection and the space available to trap CO2 have been identified as constraints, but have not been rigorously compared to determine the conditions under which each is more limiting. In this study, we evaluate their relative importance in an idealized aquifer using simple, but dynamic models of how pressure rises during injection and how CO2 becomes trapped in the pore space. We show that there exists a crossover injection duration, T c , below which pressure constraints dominate, but above which the CO2 migration becomes the more limiting constraint. We illustrate this behavior by applying the models to the Fox Hills Sandstone. [Copyright &y& Elsevier]

Abstract: A new Phase Change Material (PCM) based on a salt hydrate which can be incorporated in latent heat storage systems for efficient handling of thermal energy around 100°C has been prepared. Compared with the pure salt hydrate, the results showed that the newly developed salt hydrate PYCO-PCM-1 is of high thermal stability. The storage capacity of 83.33 kWh m-3 for a temperature range ΔT = 20K, corresponds to about four times the energy which can be stored with the same volume of water. Expanded graphite has been proven as a promising additive for improving the conductivity of PYCO-PCM-1. [Copyright &y& Elsevier]