CO2 Storage Efficiency Research Articles

A data driven model for the impact of IFT and density variations on CO2 storage capacity in geologic formations

Carbon dioxide (CO2) storage in depleted hydrocarbon reservoirs and deep saline aquifers is one of the most promising solutions for decreasing CO2 concentration in the atmosphere. One of the important issues for CO2 storage in subsurface environments is the sealing efficiency of low-permeable cap-rocks overlying potential CO2 storage reservoirs. Though we focus on the effect of IFT in this study as a factor influencing sealing efficiency or storage capacity, other factors such as interfacial interactions, wettability, pore radius and interfacial mass transfer also affect the mobility and storage capacity of CO2 phase in the pore space. The study of the variation of IFT is however important because the pressure needed to penetrate a pore depends on both the pore size and the interfacial tension. Hence small variations in IFT can affect flow across a large population of pores. A novel model is proposed to find the IFT of the ternary systems (CO2/brine-salt) in a range of temperatures (300–373 K), pressures (50–250 bar), and up to 6 molal salinity applicable to CO2 storage in geological formations through a multi-variant non-linear regression of experimental data. The method uses a general empirical model for the quaternary system CO2/brine-salts that can be made to coincide with experimental data for a variety of solutions. We introduce correction parameters into the model, which compensates for uncertainties, and enforce agreement with experimental data. The results for IFT show a strong dependence on temperature, pressure, and salinity. The model has been found to describe the experimental data in the appropriate parameter space with reasonable precision. Finally, we use the new model to evaluate the effects of formation depth on the actual efficiency of CO2 storage. The results indicate that, in the case of CO2 storage in deep subsurface environments as a global-warming mitigation strategy, CO2 storage capacity increases with reservoir depth.

Field-scale simulation of CO2 enhanced oil recovery and storage through SWAG injection using laboratory estimated relative permeabilities

Numerical simulations are widely used to investigate the performance of simultaneous water and gas (SWAG) injection in an oil field. However, they usually use two-phase water and gas relative permeability functions (krg) and one of the known correlations (e.g., Stone, Baker) to calculate oil relative permeability in a three-phase displacement. Moreover, the same krg is used for all SWAG injections, irrespective of miscibility conditions or fraction of gas injected (FGI).Recent experiments have shown that gas relative permeability functions in three-phase SWAG are significantly different from the conventionally used two-phase functions. This paper investigates the impact of using experimentally estimated three-phase gas relative permeability functions on co-optimization study of CO2 storage and enhanced oil recovery (EOR). A three-dimensional, layered reservoir model initially saturated with oil and connate water is used to examine different injection schemes for co-optimizing oil recovery and CO2 storage efficiency. The oil phase consists of a mixture of 0.65 hexane and 0.35 decane by molar fraction. Numerical simulations are run at 70 °C and at three pressures (1300, 1700, and 2100 psi) to represent immiscible, near-miscible, and miscible displacements, respectively. SWAG displacements are run at an FGI of 0.5 for immiscible, near-miscible and miscible conditions. Then the effect of FGI dependent relative permeability on co-optimization of CO2 storage and EOR is investigated in the near-miscible condition for FGI values 0.25, 0.5, 0.75 and 1.0.Experimentally estimated three-phase gas relative permeability results in lower CO2 mobility. This leads to higher CO2 saturation and lower water saturation at the end of simulation. The significant increase in CO2 storage efficiency and hence the co-optimization function are more prominent in near-miscible and miscible displacements than in immiscible. Although, for the homogeneous model, ultimate oil recovery is the same when two-phase or experimentally estimated three-phase relative permeabilities are used, ultimate recovery value is significantly affected in the heterogeneous reservoir model.

Effect of temperature and SiO2 nanoparticle size on wettability alteration of oil-wet calcite

Nanofluid treatment of oil reservoirs is being developed to enhance oil recovery and increase residual trapping capacities of CO2 at the reservoir scale. Recent studies have demonstrated good potential for silica nanoparticles for enhanced oil recovery (EOR) at ambient conditions. Nanofluid composition and exposure time have shown significant effects on the efficiency of EOR. However, there is a serious lack of information regarding the influence of temperature on nanofluid performance; thus the effects of temperature, exposure time and particle size on wettability alteration of oil-wet calcite surface were comprehensively investigated; moreover, the stability of the nanofluids was examined. We found that nanofluid treatment is more efficient at elevated temperatures, while nanoparticle size had no influence. Mechanistically most nanoparticles were irreversibly adsorbed by the calcite surface. We conclude that such nano-formulations are potentially useful EOR agents and may improve the efficiency of CO2-storage even at higher reservoir temperatures.

Quantitative Analysis on Areal Displacement Efficiency in a Supercritical CO2-Water-Quartz Sands System

Micromodels were developed to improve our understanding of how CO2 flooding and storage efficiency are affected by the wettability in supercritical CO2-water-quartz sands systems. The micromodel in a pressurized chamber allowed to visualize scCO2 spreading and porewater displacement at high pressure and temperature conditions. CO2 flooding followed by fingering migration and dewatering followed by formation of residual water were observed. Measurement of areal displacement efficiency at equilibrium decreases as the salinity increases, whereas it increases as the pressure and temperature increases. Experimental results provided fundamental information on migration and distribution of injecting scCO2 under reservoir conditions and CO2 sequestration progress.

An Experimental and Numerical Analysis of Water-Alternating-Gas and Simultaneous-Water-and-Gas Displacements for Carbon Dioxide Enhanced Oil Recovery and Storage

Summary This paper presents an experimental and numerical study that delineates the co-optimization of carbon dioxide (CO2) storage and enhanced oil recovery (EOR) in water-alternating-gas (WAG) and simultaneous-water-and-gas (SWAG) injection schemes. Various miscibility conditions and injection schemes are investigated. Experiments are conducted on a homogeneous, outcrop Bentheimer sandstone sample. A mixture of hexane (C6) and decane (C10) is used for the oil phase. Experiments are run at 70°C and three different pressures (1,300, 1,700, and 2,100 psi) to represent immiscible, near-miscible, and miscible displacements, respectively. WAG displacements are performed at a WAG ratio of 1:1, and a fractional gas injection (FGI) of 0.5 is used for SWAG displacements. The effect of varying FGI is also examined for the near-miscible SWAG displacement. Oil recovery, differential pressure, and compositions are recorded during experiments. A co-optimization function for CO2 storage and incremental oil production is defined and calculated by use of the measured data for each experiment. The results of SWAG and WAG displacements are compared with the experimental data of continuous-gas-injection (CGI) displacements. A compositional commercial reservoir simulator is used to examine the recovery mechanisms and the effect of mobile water on gas mobility. Experimental observations demonstrate that the WAG displacements generally yield higher co-optimization function than CGI and SWAG with FGI = 0.5 displacements. Numerical simulations show a remarkable reduction in gas relative permeability for the WAG and SWAG displacements compared with CGI displacements, as a result of which the vertical-sweep efficiency of CO2 is improved. More reduction of gas relative permeability is observed in the miscible and near-miscible displacements than in the immiscible displacement. The reduced gas relative permeability lowers the water-shielding effect, thereby enhancing oil recovery and CO2-storage efficiency. More water-shielding effect is observed in SWAG with FGI = 0.5 than in WAG. However, increasing FGI from 0.5 to 0.75 in the near-miscible SWAG displacement shows a significant increase in oil recovery, which is attributed to reduced water-shielding effect. So, an optimal FGI needs to be determined to minimize the water-shielding effect for efficient SWAG displacements.

Pre-injection brine production in CO2 storage reservoirs: An approach to augment the development, operation, and performance of CCS while generating water

Two of the most important challenges facing the global energy sector are to reduce the CO2 intensity and the water intensity of energy production. Because many economies will continue to depend on fossil fuels as primary energy sources, CO2 capture and storage (CCS) must play a major role in curbing CO2 emissions. A large portion of CO2 storage will need to occur in saline reservoirs because these resources are more widely distributed than hydrocarbon resources—where CO2 capture utilization and storage (CCUS) can be deployed for enhanced oil recovery (EOR). CCS deployment can be accelerated with a pressure-management strategy, called pre-injection brine production that proactively manages project risks linked to reservoir pressure. In this approach, a CCS wellfield is deployed sequentially, one well at a time, with each well being used for three stages: (1) monitoring, (2) brine production, and (3) CO2 injection. Using the same well to produce brine before injecting CO2 provides pre-injection reservoir diagnostics needed for proactive planning of wellfield operations. Because pressure drawdown is greatest where CO2 injection will subsequently occur, reservoir pressure is efficiently managed per well, and per unit of removed brine. This approach to managing geologic CO2 storage can (1) identify resources with sufficient CO2 storage capacity and permanence, and provide information needed to effectively manage those resources prior to injecting CO2; (2) increase CO2 storage capacity and efficiency; (3) limit pore-space competition with neighboring subsurface operations; and (4) reduce the duration of post-injection site care and monitoring, while (5) creating the opportunity to generate water, using an emerging CCUS technology called enhanced water recovery (EWR). Although beneficial consumptive use of produced brine may be preferred in water-constrained regions, there may be situations where the brine composition is not economically treatable, which could necessitate reinjecting some or all of the produced brine into a separate reservoir. In this study we consider a range of brine-disposition options, from 100% reinjection in the subsurface to near zero net injection of fluid, which maximizes the water generation benefit per tonne of stored CO2. These options are analyzed for a case where a nearby saline reservoir overlying a CO2 storage reservoir is used to store some or all of the brine removed from the CO2 storage reservoir.

Relationship between oil recovery and CO2 storage efficiency under the influence of gravity segregation in a CO2 EOR system

Integrating the technologies of EOR and CO2 sequestration could economically bring large quantities of CO2 storage capacity and increase recoverable oil, which could be called “green oil”. Gravity segregation, particularly in CO2 gas flooding, is an important factor for the successful application of CO2 flooding. A major goal of this study was to analyze how miscibility conditions and CO2 injection rate affect both oil recovery and CO2 storage efficiency under an environment of gravity segregation. This paper presents experimental observations of both EOR and CO2 sequestration for CO2 flooding in immiscible and near-miscible conditions at various CO2 injection rates using two-dimensional vertical Berea sandstone slabs (20 × 20 cm). The experiments were run under immiscible and near-miscible conditions with various CO2 injection rates. CO2 was injected continuously up to a maximum three-pore-volume injection into sandstone saturated with n-decane. From the results, both oil recovery and CO2 storage efficiency in the near-miscible conditions were much better than the immiscible conditions in the case of a vertical system containing a gravity segregation environment. Ultimately, in the relationship between oil recovery and CO2 storage efficiency, from this study, we propose that they behaved similarly, with a trend corresponding to the CO2 injection rate in immiscible conditions, whereas they showed the opposite relationship in near-miscible conditions.

A Laboratory and Numerical-Simulation Study of Co-Optimizing CO2 Storage and CO2 Enhanced Oil Recovery

Summary This paper presents experimental observations that delineate co-optimization of carbon dioxide (CO2) enhanced oil recovery (EOR) and storage. Pure supercritical CO2 is injected into a homogeneous outcrop sandstone sample saturated with oil and immobile water under various miscibility conditions. A mixture of hexane and decane is used for the oil phase. Experiments are run at 70°C and three different pressures (1,300, 1,700, and 2,100 psi). Each pressure is determined by use of a pressure/volume/temperature simulator to create immiscible, near-miscible, and miscible displacements. Oil recovery, differential pressure, and compositions are recorded during experiments. A co-optimization function for CO2 storage and incremental oil is defined and calculated using the measured data for each experiment. A compositional reservoir simulator is then used to examine gravity effects on displacements and to derive relative permeabilities. Experimental observations demonstrate that almost similar oil recovery is achieved during miscible and near-miscible displacements whereas approximately 18% less recovery is recorded in the immiscible displacement. More heavy component (decane) is recovered in the miscible and near-miscible displacements than in the immiscible displacement. The co-optimization function suggests that the near-miscible displacement yields the highest CO2-storage efficiency and displays the best performance for coupling CO2 EOR and storage. Numerical simulations show that, even on the laboratory scale, there are significant gravity effects in the near-miscible and miscible displacements. It is revealed that the near-miscible and miscible recoveries depend strongly on the endpoint effective CO2 permeability.

Effect of gravity segregation on CO2 sequestration and oil production during CO2 flooding

In this study, we attempted to analyze CO2 sequestration and oil production in the environment of gravity segregation, and ultimately making a relationship between them during the CO2 flooding. In order to utilize the depleted oil field after finishing the CO2 flooding as CO2 storage, quantitative characteristics of CO2 storage efficiency to be possible in that oil field should be understood for preventing a leak through fractures generated by high-pressured CO2 of free gas state prior to the injection of CO2. As an experimental system, we designed a two dimensional CO2 flooding apparatus equipped with sandstone plate. The apparatus had dip angles of 0° (horizontal system) and 90° (vertical system) to simulate gravity segregation condition. Experimental results for the vertical system showed that oil production was heavily influenced by gravitational effects for immiscible condition. This situation is analogous to thick reservoirs in which gravity dominates over viscous forces. However, for near-miscible condition, the gravity override phenomenon was not significant, and these results suggest that reservoir thickness should not be a criterion when using CO2 flooding. CO2 storage efficiency for near-miscible system was found to be much better than that for immiscible system regardless of the gravitational effect. For designing the CO2 EOR scheme in terms of relationship between CO2 storage and oil production, particularly in the case of high permeable homogeneous sandstone, we found out that the trapped CO2 as free gas state and oil recovery during the CO2 flooding were monotonically decreased without critical value of inflection point corresponding to CO2 injection rate increase.

CO2 enhanced oil recovery and storage using a gravity-enhanced process

CO2 flooding offers a means to recover significant amounts of oil while simultaneously sequestering CO2. Recent methods for CO2 geological storage have focused on CO2 injection into deep brine aquifers, or by water-alternating-gas (WAG) injection in a miscible gas flooding process using vertical wells. There is significant uncertainty in the amount of CO2 that can be stored using these methods owing to reservoir heterogeneity and variations in reservoir/fluid parameters. It would be useful therefore to have a more robust process that can also increase both CO2 storage and oil recovery in a symbiotic relationship, where increased storage leads to greater oil recovery.This paper considers an alternative process that maximizes both storage and oil recovery simultaneously using only horizontal wells in a gravity-enhanced miscible process. A reduced-order model (ROM) is developed to consider a wide range of reservoir heterogeneities and fluid properties. Monte-Carlo simulations using the ROM show that achieving very high storage and oil recovery is possible using the gravity-enhanced process and that the approach is very robust. For example, after 2.0 moveable pore volumes injected (MPVI), probabilistic forecasts show that CO2 storage efficiency across two standard deviations ranges from about 81% to 93%, indicating that nearly all of the available pore space (excluding immobile water) at the end of injection is occupied by CO2. Oil recoveries after 2.0 MPVI varied from 79% to 93% of the original mass of oil-in-place (OOIP). These storage and recovery efficiencies are significantly greater than any process reported to date. Response functions developed can also be used to estimate the maximum amount of stored CO2 and corresponding oil recoveries for a wide range of reservoir and fluid properties. Such estimates are critical for regional and national assessment of CO2 storage potential.

Effects of permeability heterogeneity on CO2 injectivity and storage efficiency coefficient

AbstractWe study the dependency of CO2 storage efficiency coefficient (E) and injectivity index (Iinj) on the geostatistical parameters of the permeability field. CO2 injection simulations are conducted for multiple realizations of log‐normally distributed permeability fields parameterized by log permeability standard deviation (σ) and dimensionless horizontal correlation length (λ). Results show that the injectivity index increases with increasing λ, the magnitude of the effect depending on σ. Increasing σ leads to poorer injectivity for cases with small λ, but improves injectivity when λ is large. Further analysis indicates that the enhancing effect of σ on injectivity can be attributed to cases with channelized flow, while the decrease effect of σ is seen in more dispersive flow regime. The dependence of injectivity on both λ and σ is captured with a linear correlation between Iinj and a parameter group , where ξ is a dimensionless scaling parameter. The storage efficiency coefficient, on the other hand, decreases with both increasing σ and λ, and a simple linear fit is found between E and the parameter group λσ2, a well‐established heterogeneity parameter group describing e.g. macro‐dispersivity in solute transport studies. These relationships provide potentially useful tools for the preliminary evaluation of a site. Future studies should address the validity of the relationships in alternative injection scenarios and domain geometries. © 2015 Society of Chemical Industry and John Wiley & Sons, Ltd

A comparison of volumetric and dynamic CO2 storage resource and efficiency in deep saline formations

A reliable carbon dioxide (CO2) storage resource estimation method is crucial if carbon capture and storage in deep saline formations (DSFs) is to gain widespread deployment for reducing anthropogenic CO2 emissions to the atmosphere. Most of the published methodologies are based on a volumetric calculation and do not consider the effect of site-specific dynamic factors (e.g., injection rate, pressure interference). Several studies suggest these dynamic components may play the dominant role in storing CO2 in DSFs. In this study, CO2 storage resource estimates and efficiencies for two deep saline systems were calculated using volumetric and dynamic methodologies.Comparison of the results indicates that dynamic CO2 storage efficiency is time-dependent. For short injection lengths (∼50 years), an open system has an efficiency similar to a closed system, and volumetric storage resource estimates are too high. For long injection time frames (∼2000 years), the dynamic storage resource of open systems approaches the volumetric potential. These results suggest that volumetric assessments are reliable provided it is understood that it may take hundreds of wells and/or injection for hundreds of years to reach a formation's effective CO2 storage resource potential. Additionally, operational factors such as water extraction can increase CO2 storage resource and efficiency.

Chemical Reactions of Portland Cement with Aqueous CO2 and Their Impacts on Cement’s Mechanical Properties under Geologic CO2 Sequestration Conditions

To provide information on wellbore cement integrity in the application of geologic CO2 sequestration (GCS), chemical and mechanical alterations were analyzed for cement paste samples reacted for 10 days under GCS conditions. The reactions were at 95 °C and had 100 bar of either N2 (control condition) or CO2 contacting the reaction brine solution with an ionic strength of 0.5 M adjusted by NaCl. Chemical analyses showed that the 3.0 cm × 1.1 cm × 0.3 cm samples were significantly attacked by aqueous CO2 and developed layer structures with a total attacked depth of 1220 μm. Microscale mechanical property analyses showed that the hardness and indentation modulus of the carbonated layer were 2-3 times greater than for the intact cement, but those in the portlandite-dissolved region decreased by ∼50%. The strength and elastic modulus of the bulk cement samples were reduced by 93% and 84%, respectively. The properties of the microscale regions, layer structure, microcracks, and swelling of the outer layers combined to affect the overall mechanical properties. These findings improve understanding of wellbore integrity from both chemical and mechanical viewpoints and can be utilized to improve the safety and efficiency of CO2 storage.

Numerical research on CO2 storage efficiency in saline aquifer with low-velocity non-Darcy flow

Low permeability saline aquifers, which are widely distributed around this world, have great potential for injected CO2 storage. Fluid flow in low permeability layers shows characteristics of low-velocity non-Darcy flow. A mathematical model considering the effect of threshold pressure gradient (TPG) for CO2 flow and storage in low permeability saline aquifer has been developed, and the corresponding numerical model has been formulated and solved. From the numerical results, we can conclude that the injection rate, cumulative CO2 injected, and the storage efficiency for the case with TPG are always less than those of the case without TPG because of the sharp pressure decline and increased energy consumption. Under this paper's calculation condition, the storage efficiency when considering TPG is about 10% less than the case without considering TPG. If the TPG effect was to be ignored in the design of CO2 storage in low permeability saline aquifers, the CO2 storage efficiency will be overestimated. The research enlarges the theoretical basis of carbon capture and storage (CCS) and provides a more accurate method to evaluate CO2 storage efficiency.

Review of CO2 storage efficiency in deep saline aquifers

At the time the IPCC Special Report on Carbon Capture and Storage was published in 2005, the concept of CO2 storage efficiency was not introduced yet and, consequently, no numerical values were published in the literature. CO2 storage efficiency is defined as the ratio of the volume of CO2 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 CO2 storage and associated values. CO2 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 CO2/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 CO2 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 CO2 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 CO2 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 CO2 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 CO2 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 CO2 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.

Distribution of injected CO2 in a stratified saline reservoir accounting for coupled wellbore‐reservoir flow

AbstractGeological storage in sedimentary basins is considered a viable technology in mitigating atmospheric CO2 emissions. Alternating high and low permeability strata are common in these basins. The distribution of injected CO2 among such layers affects e.g. CO2 storage efficiency, capacity and plume footprint. A numerical study on the distribution of injected CO2 into a multi‐layered reservoir, accounting for coupled wellbore‐reservoir flow, was carried out using the T2Well/ECO2N code. A site‐specific case as well as a more general case were considered. Properties and processes governing the distribution of sequestrated CO2 were identified and the potential to operationally modify the distribution was investigated. The distribution of CO2 was seen to differ from that of injected water, i.e. it was not proportional to the transmissivity of the layers. The results indicate that caution should be taken when performing numerical simulations of CO2 injection into layered formations. Ignoring coupled wellbore‐reservoir flow and instead adopting a simple boundary condition at the injection well, such as an inflow rate proportional to the transmissivity of each layer, may result in significant underestimation of the proportion of CO2 ending up in the shallower layers, as not all relevant processes are accounted for. This discrepancy has been thoroughly investigated and quantified for several CO2 sequestration scenarios.

Adapted sequential Gaussian simulations with Bayesian approach to evaluate the CO2storage potential in low porosity environment

Sequential Bayesian simulations are used to model the porosity distribution and assess the CO2 storage potential in the Beauharnois Formation of the Saint-Flavien reservoir (Québec, Canada). The low porosity Beauharnois Formation is characterized by a complex geology, mostly composed of dolostones with a strong presence of limestone, sandstone, and shale. In such a complex geological environment, we transform the porosity distribution into a normal one to artificially stretch the range of porosity. This allows a clearer definition of the statistical relation between acoustic impedance (AI) and porosity, and a better identification of petrophysical families in the reservoir unit. Guided by seismic derived AI cubes, 250 realizations of porosity are simulated by Bayesian sequential simulations (BSS), all respecting the initial porosity well logs, the a priori porosity distribution, and the statistical relation between AI and porosity. All realizations present different but realistic distributions of porosity. We estimate the connectivity between zones with porosity greater than 1.0%. The average porosity in the connected pockets is approximately 1.4% for all three selected realizations. We estimate 0.5Mt to 1.25Mt of CO2 could be injected in the 3D model representation of the Beauharnois Formation in Saint-Flavien, with a CO2 storage efficiency factor of 27% to 36%.

Analytical model of CO2 storage efficiency in saline aquifer with vertical heterogeneity

CO2 injection into saline aquifers for storage is the most effective way to reduce greenhouse gas emissions. However, the storage layers are heterogeneous because of millions of years of tectono-sedimentary evolution. A multilayer supercritical CO2–brine two-phase displacement model with vertical heterogeneity was established to make clear the impact of heterogeneity on storage efficiency. The analytical solutions were obtained after simplifying the mathematical model. The results show that, the percolating resistance increased with the increase of injection rate and radial extent, with the decrease of heterogeneity coefficient and porosity. Larger heterogeneity coefficient or higher injection rate will result in lower sweep efficiency, and is not conducive to CO2 storage. Larger radial extent or larger porosity will result in higher sweep efficiency, and is conducive to CO2 storage. Calculation showed that heterogeneity coefficient has much more significant effect on storage efficiency than other influencing factors such as injection rate, radial extent and porosity. The analytical solutions of supercritical CO2–brine two-phase displacement model considering vertical heterogeneity provide an easy and accurate method for the evaluation of CO2 storage.

Multiwell CO2 Injectivity: Impact of Boundary Conditions and Brine Extraction on Geologic CO2 Storage Efficiency and Pressure Buildup

CO2 storage efficiency is a metric that expresses the portion of the pore space of a subsurface geologic formation that is available to store CO2. Estimates of storage efficiency for large-scale geologic CO2 storage depend on a variety of factors including geologic properties and operational design. These factors govern estimates on CO2 storage resources, the longevity of storage sites, and potential pressure buildup in storage reservoirs. This study employs numerical modeling to quantify CO2 injection well numbers, well spacing, and storage efficiency as a function of geologic formation properties, open-versus-closed boundary conditions, and injection with or without brine extraction. The set of modeling runs is important as it allows the comparison of controlling factors on CO2 storage efficiency. Brine extraction in closed domains can result in storage efficiencies that are similar to those of injection in open-boundary domains. Geomechanical constraints on downhole pressure at both injection and extraction wells lower CO2 storage efficiency as compared to the idealized scenario in which the same volumes of CO2 and brine are injected and extracted, respectively. Geomechanical constraints should be taken into account to avoid potential damage to the storage site.

CO2-DISSOLVED: a Novel Concept Coupling Geological Storage of Dissolved CO2 and Geothermal Heat Recovery – Part 4: Preliminary Thermo-Hydrodynamic Simulations to Assess the CO2 Storage Efficiency

The CO2-DISSOLVED project aims at assessing the technical-economic feasibility of coupling CO2 storage in a saline aquifer and geothermal heat recovery. The proposed infrastructure basically relies on a standard geothermal doublet where CO2 would be injected after having been entirely dissolved in the cooled brine. The objective of this preliminary thermo-hydrodynamic modeling study was to quantify the expected CO2 storage lifetime and efficiency. The results first confirmed that CO2 will inevitably be produced in the extracted brine after 2-15 years of continuous injection, depending on the operating parameters. However, mass balance calculations evidenced that after a 30 year injection period, 37-85% of the total CO2 injected should remain stored in the aquifer.