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Underground CO2 storage is a promising technology for mitigating climate change. In this vein, the subsurface condition was inherited a lot of uncertainties that prevent the success of the CO2 storage project. Therefore, this study aims to build the 3D model under geological uncertainties for enhancing CO2 storage capacity in the Shahejie Formation (Es1), Nv32 block, China. The well logs, seismic data, and geological data were used for the construction of 3-D petrophysical models. The target study area model focused on four units (Es1 × 1, Es1 × 2, Es1 × 3, and Es1 × 4) in the Shahejie Formation. Well logs were utilized to predict petrophysical properties; the lithofacies indicated that the Shahejie Formation units are sandstone, shale, and limestone. Also, the petrophysical interpretation demonstrated that the E s 1 reservoir exhibited high percentage porosity, permeability, and medium to high net-to-gross ratios. The static model showed that there are lateral heterogeneities in the reservoir properties and lithofacies; optimal reservoir rocks exist in Es1 × 4, Es1 × 3, and Es1 × 2 units. Moreover, the pore volume of the Es1 unit was estimated from petrophysical property models, ranging between 0.554369 and 10.03771 × 106 sm3, with a total volumetric value of 20.0819 × 106 sm3 for the four reservoir units. Then, the 100–400 realizations were generated for the pore volume uncertainties assessment. In consequence, 200 realizations were determined as an optimal solution for capturing geological uncertainties. The estimation of CO2 storage capacity in the Es1 formation ranged from 15.6 to 207.9 × 109 t. This result suggests the potential of CO2 geological storage in the Shahejie Formation, China. [ABSTRACT FROM AUTHOR]

Highlights • Comprehensive fluid-rock interaction models were built for CPG system study. • Back and down flow of water complicates fluid-rock interactions near injector. • Salt precipitation can affect geochemical reaction during geothermal development. • Geochemical reaction and salt precipitation reduce heat mining rate up to 2/5. • Low salinity water injection can effectively reduce salt precipitation in CPG. Abstract The ubiquitous natural sedimentary reservoirs and their high permeability have made the CO 2 plume geothermal system increasingly attractive. However, the complicated fluid-rock interactions during the geothermal exploitation can cause severe reservoir damage, constraining the excellent heat mining performance of the CO 2 and decreasing the possible applications of the CO 2 plume geothermal system. In order to analyze and solve this energy issue affecting the geothermal exploitation, in this study, a comprehensive numerical simulation model was established, which can consider formation water evaporation, salt precipitation, CO 2 -water-rock geochemical reactions, and the changes in reservoir porosity and permeability in the CO 2 plume geothermal (CPG) system. Using this model, the geochemical reactions and salt precipitation and their effects on the geothermal exploitation were analyzed, and some measures were proposed to reduce the influence of fluid-rock interactions on the heat mining rate. The simulation results show that the gravity and the negative gas-liquid capillary pressure gradient induced by evaporation can cause the formation water to flow toward the injector. The back flow of the formation water results in salt precipitation accumulation in the injection well region, which can cause severe reservoir damage and consequent reductions to the heat mining rate. The CO 2 -water-rock geochemical reactions could result in the dissolution of certain minerals and precipitation of others, but its minimal influence on the heat mining rate can be ignored. However, salt precipitation can affect the geochemical reactions by influencing the CO 2 flow and distribution, which can reduce the heat mining rate up to 2/5 of the original. Sensitivity studies show that the reservoir condition can affect the salt precipitation and heat mining rate, so a sedimentary reservoir with high temperature, high porosity and permeability, and low salinity should be selected for CPG application, with an appropriately high injection-production pressure difference. The injection of low salinity water before CO 2 injection and the combined injection of CO 2 and water vapor can be applied to reduce the salt precipitation and increase the heat mining rate in the CPG system. [ABSTRACT FROM AUTHOR]

The geothermal exploitations from the single-continuum (i.e. sandstone here) and dual-continuum (i.e. hot dry rock here) reservoirs using CO 2 have unique advantages and huge application potentials. However, the salt precipitation caused by the evaporation can damage the reservoir and reduce the heat mining rate. In this paper, two comprehensive simulation models are established to analyze the fluid flow, salt precipitation, and its effects on the reservoir properties and heat mining rate during the geothermal exploitation using CO 2 from the sandstone and hot dry rock reservoirs. For the sandstone reservoir, the formation water will flow back to the injection well under the actions of the gravity and the gas-liquid capillary pressure driven by evaporation, which can result in a lot of NaCl precipitating in the injection well. The salt precipitation in the sandstone reservoir can make the steady heat mining rates decrease by about 1/3. For the hot dry rock reservoir, the formation water in the matrix system can be drawn to the fracture through the fracture-matrix interface due to the capillary pressure, which complicates the distribution of the salt precipitation in the fracture system. Under the actions of the back flow in the fracture and flow exchange between fracture and matrix, the salt precipitation mainly occurs in the areas near the injection and production wells, which makes the steady heat mining rate decrease by about 1/2. Both the low-salinity water injections prior the CO 2 injection and after the salt precipitation occurred can effectively reduce the salt precipitation for the sandstone, but only the low-salinity water injection after the salt precipitation occurred can dissolve the precipitated salt and effectively recover the heat mining rate. [ABSTRACT FROM AUTHOR]

Foam is of practical interest in many industrial processes, and can be used for blocking gas channeling and mobility control during the process of CO 2 storage and improved oil recovery (IOR). It is important to develop new kinds of foam agents, which can tolerate high temperature and salinity under complex reservoir conditions. It is also desirable to develop chemicals that have CO 2 -sensitivity for selective channeling blocking. CO 2 -sensitivity is referred to that injected chemical can be converted into effective foam agent in formation water with CO 2 presence. In this paper, an organic amine, octadecyl dipropylene triamine, was studied in terms of chemical mechanisms for foam generation and CO 2 -sensitivity. The chemical can be converted into a Gemini surfactant like agent to generate CO 2 foams in-situ. The effects of important influencing factors on foaming performance at reservoir conditions were evaluated, including CO 2 purity, chemical concentration, temperature, pressure and water salinity. The results indicated that the amine chemical has good CO 2 -sensitivity for generation of CO 2 foams and has exhibited extraordinary features with high temperature and salinity tolerance. CO 2 flooding assisted by this type of chemical will broaden the scope of reservoirs that can be candidates for CO 2 IOR and geo-storage. [ABSTRACT FROM AUTHOR]

Utilization of supercritical CO 2 as heat transmission fluid for geothermal development associated with geological storage can achieve the double wins of economic benefits and environmental protection. The advantages of supercritical CO 2 in thermodynamics and injectivity have been recognized widely. The main concerns of this technology are focused on the water production process at the beginning of CO 2 injection and the long-term complicated CO 2 -water-rock interactions in the geothermal reservoirs. These factors may significantly constrain the excellent heat mining performance of supercritical CO 2 , and lower the application potential of the technology. In this paper, the interactions between rocks and fluids in typical geothermal reservoirs and their effects on the heat mining performance of supercritical CO 2 are studied based on an established reservoir simulation model. The development of different CO 2 seepage zones in the reservoir, and the relevant rock-fluid interactions in these zones are investigated. The negative influence of water production and the change of reservoir properties induced by rock-fluid interactions on the CO 2 heat mining performance are also assessed. The simulation results indicate that both of the salt precipitation induced by pore water vaporization, and the geochemical reactions between CO 2 and rocks in the geothermal reservoir can damage the reservoir properties, especially serious salting out may occur around the production well and reduce the heat mining rate of CO 2 significantly. Overall, the existing pore water can reduce more than 27% of the cumulative mined heat as well as nearly 45% of the heat mining rate after 40 years. Some measures, such as selecting reservoirs without water, and injecting fresh water, can be applied to mitigate the damage of pore water to CO 2 heat mining performance. [ABSTRACT FROM AUTHOR]

Jilin Oilfield has been conducting a large-scale demonstration project on CO 2 EOR and storage in China. CO 2 separated from a nearby natural gas reservoir (15–30 vol% CO 2 ) has been injected into the northern part of H-59 oil block with the permeability of 3.0 mD and porosity of 12.7%. After six years of operation, nearly 0.26 million ton of CO 2 (0.32 Hydrocarbon Pore Volume) has been injected under a miscible or near-miscible flooding mode with CO 2 utilization efficiency of 6.3 MScf/bbl, and an expected enhanced oil recovery of over 10% would be achieved. A systematic and thorough reservoir surveillance program has been conducted to facilitate efficient operation and evaluation. Casing annulus gas composition was analyzed to monitor gas breakthrough in production wells as well as the gas tracer to detect CO 2 flow across the reservoir. Bottom hole pressure (BHP) survey of producers and fluid sampling were combined to evaluate the miscibility effect in conjunction with the injection-production data analysis. It is revealed that the designed miscible flooding is best described as near-miscible due to the large pressure difference between injector and producer, and the gas channeling and fractures/heterogeneities cause the miscibility instability. Gravity-stabilized displacement may develop in the downdip part of the reservoir during the flooding process. The vaporization and condensation effects have been observed and confirmed through laboratory core flooding and field produced oil compositions analysis. A key insight from the evaluation study is that CO 2 near-miscible flooding is more flexible and easily realizable relative to miscible, particularly in the tight oil reservoir. Further study would be necessary to optimize the reservoir development program under the near-miscible flooding design. [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]

Abstract: CO2 injection into oil and gas reservoirs associated with large aquifers takes advantages of lower geological leakage risk associated with oil and gas traps, and large storage capacity of their connected aquifers. The storage capacity in such combined reservoirs can be assessed by a material balance method which considers different trapping states of CO2 in oil reservoirs and aquifers. Case studies of five oil reservoirs selected from Shengli and Jiangsu oilfields in China are conducted and the results show that CO2 storage capacity can be greatly increased if the lateral and underlying aquifers are included. Oil and water displacement and CO2 dissolution in remaining oil are the main forms of CO2 trapping in oil reservoirs, while CO2 gas trapping and dissolution in saline water are the main mechanisms for CO2 storage in associated aquifers. CO2 injection into combined reservoirs can be a favorable option for the oil industry in the near future, and the potentials of CO2 EOR and storage deserve further detailed studies. [Copyright &y& Elsevier]

• A comprehensive model of geochemical reactions is built for CO 2 EOR and storage. • CO 2 trapping mechanisms in high-temperature oil reservoir are detailed analyzed. • CO 2 injection methods are evaluated to maximize the oil recovery and CO 2 storage. • WAG with additional CO 2 injection is suggested for EOR and storage in oil fields. CO 2 -formation water-rock geochemical reactions can occur, affecting the reservoir physical properties and CO 2 trapping forms during the CO 2 enhanced oil recovery (CO 2 -EOR) process. In this paper, based on the properties of the reservoir and fluids in a high-temperature oil reservoir, a comprehensive model, including formation water evaporation, dissolution, diffusion of CO 2 in water, CO 2 -water-rock geochemical reactions, and relation of porosity and permeability, is established to simulate the CO 2 EOR process and subsequent geological storage. The geochemical reactions and CO 2 trapping forms in these two stages are analyzed using this model, and the influences of reservoir heterogeneity and different CO 2 injection schemes on EOR and CO 2 geological storage are studied. The results show that the geochemical reactions can change reservoir porosity and permeability, but their effect is little, and most of the injected CO 2 is trapped as the supercritical gas during the CO 2 EOR process. During the stage of CO 2 geological storage, the supercritical CO 2 continuously converts into mineral form under the action of geochemical reactions, which results in the reservoir pressure decreasing. Whether the reservoir is heterogeneous or homogenous, the water-alternating-gas (WAG) scheme should be the first choice because it can enhance both oil recovery and CO 2 storage efficiency in the EOR process. The injection of CO 2 after the CO 2 EOR process can improve the CO 2 storage capacity and simultaneously maintain the reservoir pressure stabilization. [ABSTRACT FROM AUTHOR]

Abstract For oil reservoirs featured with ultra low permeability, CO 2 huff-n-puff can be a promising approach for enhanced oil recovery. To understand its production performance and the effects of different factors in field operation, a series of CO 2 huff-n-puff experiments under various conditions were conducted using a 1D sandpack model, and the extraction effect of CO 2 and its influence on oil production have been analyzed. The experimental results show that, as cyclic CO 2 injection quantity increases, the cyclic oil recovery factor is improved, but the CO 2 utilization factor is reduced, and there will be an optimum cyclic injection quantity from economic point of view. Both cyclic oil recovery factor and CO 2 utilization factor are improved with the increasing reservoir temperature, while injection of low temperature CO 2 may impose an adverse influence on oil recovery performance. In addition, the cyclic oil recovery factor and CO 2 utilization factor firstly rise and then fall with the increasing soaking period. The results presented in this study are expected to provide some guidance to the field implementation of CO 2 huff-n-puff technique in ultra low permeability oil reservoirs. Highlights • The performance of CO 2 huff-n-puff in ultra low permeability oil reservoirs was experimentally studied. • The effects of different operation parameters were investigated. • The effect of bottom hole temperature of CO 2 on oil production was analyzed. [ABSTRACT FROM AUTHOR]

CO 2 foam is effective for mobility control and blocking of high permeability channels in the process of CO 2 flooding for enhanced oil recovery. CO 2 foams are much less stable than nitrogen foams due to the specific properties of CO 2 , and selection of surfactants as foaming agents is important for foam performance under harsh reservoir conditions. In this study, different surfactants and their mixtures were tested to evaluate their performance as CO 2 foam agents, and the experiments were conducted using a visualized foam meter and a core flooding facility at high pressure and high temperature conditions. The influences of temperature, pressure, salinity and the HLB value of surfactants on CO 2 foaming capability were investigated. The synergistic effect of the surfactants was also evaluated in order to increase high temperature tolerance of the foams. The experimental results show that the performance of CO 2 foams at high temperature is greatly dependent on the types of the surfactants used. For nonionic and anionic-nonionic surfactants, there is a critical or optimum HLB value for best foam performance. Pressure has a positive effect on the stability of CO 2 foams but dependent on the HLB value of the surfactants. Combined or mixed surfactants have a synergistic effect that can significantly improve the performance of CO 2 foams and increase the foam's stability at high temperatures. [ABSTRACT FROM AUTHOR]

• Feasibility investigation of N 2 alternating CO 2 injection for improving CO 2 storage and oil production. • Analysis of mobility adjustment by N 2 slug during continuous CO 2 injection. • Comparison of gas channeling phenomenon, gas swept area, EOR, and CO 2 storage of different gas injection methods at a field scale. • Recommendation of potential oil reservoirs suitable for NAC technology. The feasibility of N 2 alternating CO 2 injection was investigated for improving CO 2 storage and oil production. Schemes of continuous CO 2 injection and N 2 alternating CO 2 injection were evaluated using laboratory experiments and numerical simulation. According to the core flooding experiments, the CO 2 storage factor and enhanced oil recovery of N 2 alternating CO 2 flooding were 2.1% and 7.1% lower than continuous CO 2 injection. The larger the N 2 slug volume in N 2 alternating CO 2 injection, the lower the EOR and CO 2 storage factor due to the reduction of CO 2 concentration in the gas phase and CO 2 solubility in oil and water. However, the N 2 slugs in N 2 alternating CO 2 injection significantly reduced mobility differences between different flowing zones, and thus can increase the gas swept area in an oil reservoir. The gas swept area of the oil reservoir under N 2 alternating CO 2 injection mode is 1.78 times that of continuous CO 2 injection, resulting in a 44% higher cumulative oil production. Besides, the scheme of N 2 alternating CO 2 injection was optimized and resulted in 19.6% more CO 2 storage than continuous CO 2 flooding at a field scale. This study provides valuable experimental and theoretical support for improving CO 2 storage and oil production in an oil reservoir. [ABSTRACT FROM AUTHOR]

The dynamic oil-CO 2 mixing and miscible flow in porous media are complex and important phenomena that occurs during CO 2 injection for enhanced oil recovery (EOR) and geological storage. In this study, microfluidic experiments at pore-scale were conducted to simulate and investigate the mixing and flow behavior of oil and CO 2 in porous media with dead-end pores. The non-uniform oil-CO 2 mixing and bi-directional diffusion (CO 2 into oil and oil components into CO 2) in dead-end pores were observed. Based on the experimental observation, a novel oil-CO 2 miscible flow model was established. The model can describe the effects of diffusion, flow velocity distribution, fluid properties change, and pore structures on oil-CO 2 mixing and oil displacement. The diffusion coefficient between CO 2 and oil in porous media was figured out by matching the experimental results using the new model. The modeling results indicate that diffusion plays an important role in oil-CO 2 mixing, especially in deep dead-end pores. Without diffusion, over 70% of oil components would remain in their original place during CO 2 flooding. In complex porous media, advection induced by CO 2 flow dominates oil displacement in the early stage of CO 2 flooding, which can reduce the average oil mole fraction by 24%. Then diffusion increasingly influences the oil-CO 2 mixing and oil displacement, reducing the average oil mole fraction by over 35%. Without diffusion, much of the dead-end, column, and corner oil would remain in place in the oil reservoir. During CO 2 flow in complex porous media, reducing oil viscosity due to mixing with CO 2 can decrease the flow resistance in the main flow channels, which in turn can decrease the fluid flowing through the surrounding pores and is not conducive to oil displacement. In practice, even though a high CO 2 injection rate can produce oil quickly, it might affect the overall oil recovery factor and lower the CO 2 utilization efficiency. • Microfluidic experiment of pore-scale oil-CO 2 mixing in dead-end pore under miscible condition. • Mathematical model of pore-scale dynamic oil-CO 2 mixing and oil displacement. • Sensitive factor analysis of oil-CO2 mixing and oil displacement in porous media. • Characteristics of dynamic CO2 injection and storage in porous media. [ABSTRACT FROM AUTHOR]

Jilin oilfield is conducting the first large scale demonstration project on CO 2 EOR and storage in the northeast China. CO 2 with high purity is produced from a nearby natural gas reservoir and injected into the tight oil reservoir of H-59 block. Up to early in 2012, more than 20×10 4 tons of CO 2 has been injected into the reservoir through a miscible flooding scheme. In order to track the migration of CO 2 in the reservoir and ensure a long-term storage safety, a monitoring program has been deployed in the field. The used monitoring techniques include wellbore integrity detecting, produced fluid sampling, CO 2 gas tracer, electric spontaneous potential measurement, micro-seismic and cross-well seismic. An environmental monitoring program is also implemented for verifying CO 2 leakage. Preliminary results indicate that it is effective to detect the movement of CO 2 in the oil reservoir by jointly applying various monitoring techniques based on wellbores. After more than four years of operation since 2008, nearly 80% of injected CO 2 has been stored in the reservoir with the rest of injected CO 2 breakthrough in the production wells. CO 2 storage safety needs more detailed and comprehensive monitoring data for further verification. The obtained preliminary monitoring experience can provide valuable guidance for the future enlarged Jilin project and other CO 2 EOR and storage operations. [ABSTRACT FROM AUTHOR]

Highlights: [•] Three types of geothermal reservoir are potential sites suitable for CO2 injection. [•] Artificially created HDR reservoirs will not provide much CO2 storage potential. [•] Sedimentary geothermal reservoirs have large pores which benefit for heat mining. [•] A simple method is presented for calculating recoverable geothermal potential China. [•] HDR reservoir selection and CO2 loss to surrounding formation need further studies. [ABSTRACT FROM AUTHOR]

Complex geochemical reactions can occur during the water and CO 2 flooding for improved oil recovery, influencing the reservoir porosity and permeability, especially for low-permeability reservoirs. Core flooding experiments can be adopted to assess this effect, but it usually takes months or even years to accomplish. In this study, scaling and geochemical reaction experiments were firstly conducted to investigate the precipitation and dissolution of the main minerals induced by water and CO 2 injection, based on a typical low-permeability oil reservoir in Xinjiang Oilfield China. Secondly, reactive flow simulation models were then established, based on the experimental data, to evaluate the influence of the geochemical reactions on the porosity and permeability in the reservoir. The experimental results show that the injection water can result in severe mineral precipitation after it mixes with the original formation water, while the injected CO 2 can acidize the formation water and result in the dissolution of some minerals (e.g. calcite and silicate) and precipitation of dolomite, which can change the composition of the formation water. The simulation results show that severe carbonate precipitation can occur near the injection well, resulting in a decrease in porosity and permeability after 10 years of water injection. However, the change of rock minerals induced by CO 2 injection can cause a slight increase in porosity and permeability near the injector, which benefits the injection of ultra-low permeability reservoirs. Therefore, CO 2 flooding is recommended for improved oil recovery. • Geochemical reactions during water and CO 2 flooding were contrastively analyzed. • Water compatibility experiments show serious scaling occurs after water injection. • CO 2 geochemical reaction experiments indicate mineral dissolution is not strong. • Calcite precipitation reduces the permeability by 10% during the water flooding. • CO 2 geochemical reactions slightly increase the permeability during CO 2 flooding. [ABSTRACT FROM AUTHOR]