Co-injection Of CO2 Research Articles

Mechanism study of replacing adsorbed O2 molecules in different pore sizes under different CO2/N2 inert gas conditions

Injecting inert gases into the goaf is a crucial method for inhibiting coal spontaneous combustion. Research has verified that the co-injection of CO2 and N2 provides a more effective control measure compared to a single gas, but the microscopic mechanism underlying the synergistic displacement of O2 by CO2 and N2 remains unclear. Injecting inert gases into the goaf is a crucial method for inhibiting coal spontaneous combustion. Research has verified that the co-injection of CO2 and N2 provides a more effective control measure compared to a single gas, but the microscopic mechanism underlying the synergistic displacement of O2 by CO2 and N2 remains unclear. Here, for the constructed multi-scale aperture slit model, the Grand Canonical Monte Carlo simulation (GCMC) and Molecular Dynamics (MD) simulation are used to investigate the mechanism of displacing adsorbed O2 molecules under different CO2/N2 inert gas conditions. The results indicate that CO2 and N2 aggregated on opposing sides of the coal molecules and dispersed within the slit layer, respectively. At 1 nm pore size, the relative concentration of O2 for optimal displacement was 1.054. The absolute value of the average binding energy is small when the CO2:N2 gas ratio is 80:20 and 40:60 at 2 nm and 4 nm apertures, respectively. This suggests that as the aperture size increases, the displacement effect on O2 shifts towards a higher proportion of N2, with a more conspicuous replacement effect as the aperture widens. The smaller pores ranging from 1-2 nm predominantly feature CO2 displacing adsorbed state O2, while larger pores exceeding 2 nm primarily N2 facilitate the transportation of free state O2.

An Experimental Investigation of Surfactant-Stabilized CO2 Foam Flooding in Carbonate Cores in Reservoir Conditions

Carbon dioxide (CO2) injection for enhanced oil recovery (EOR) has attracted great attention due to its potential to increase ultimate recovery from mature oil reservoirs. Despite the reported efficiency of CO2 in enhancing oil recovery, the high mobility of CO2 in porous media is one of the major issues faced during CO2 EOR projects. Foam injection is a proven approach to overcome CO2 mobility problems such as early gas breakthrough and low sweep efficiency. In this experimental study, we investigated the foam performance of a commercial anionic surfactant, alpha olefin sulfonate (AOS), in carbonate core samples for gas mobility control and oil recovery. Bulk foam screening tests demonstrated that varying surfactant concentrations above a threshold value had an insignificant effect on foam volume and half-life. Moreover, foam stability and capacity decreased with increasing temperature, while variations in salinity over the tested range had a negligible influence on foam properties. The pressure drop across a brine-saturated core sample increased with an increasing concentration of surfactant in the injected brine during foam flooding experiments. Co-injection of CO2 and AOS solution at an optimum concentration and gas fractional flow enhanced oil recovery by 6–10% of the original oil in place (OOIP).

Formation integrity evaluation for geosequestration of CO2 in depleted petroleum reservoirs under cyclic stress conditions

The geological storage of carbon dioxide (CO2), also referred to as CO2 geosequestration, represents one of the most promising options for reducing greenhouse gases in the atmosphere. However, most of the time, CO2 is captured with small amounts of other industrial gases such as sulphur dioxide (SO2) and hydrogen sulphide (H2S), which might be compressed together and stored in depleted petroleum reservoirs or aquifers. Moreover, during CO2 geosequestration in reservoirs, pressure variations during injection could force some amount of CO2 (with or without other acid gas impurities) into the caprock; thereby, altering the petrophysical, geochemical, and geomechanical properties of the caprock. Thus, the brittleness index of the reservoir and caprock might be impacted during CO2 geosequestration due to the chemical reactions between the rock minerals and the formation fluid. Furthermore, to meet the world net-zero carbon target, the promotion of CO2 utilization is paramount. This could be possible by developing an effective technology for cyclic CO2 geosequestration (with or without gas impurities). Therefore, studies on the co-injection of CO2 with other acid gases from industrial emissions, their withdrawal from the porous medium, and their impact on reservoir and caprock integrity are paramount. In this study, a dual-tubing string well completion technology was designed for cyclic injection and withdrawal of CO2 (with or without another acid gas), and numerical simulations were performed using TOUGHREACT codes, to model the cyclic process and investigate the co-injection of SO2 and H2S (separately) with CO2 in sandstone formations overlain by shale caprock. A novel technique of converting the volume fraction of minerals to their weight fraction was developed in this study, to evaluate the brittleness index of the sandstone reservoir and shale caprock during CO2 geosequestration. The findings of the study indicate that the porosity and permeability increase for the CO2 only and CO2–H2S injection cases, in the shale caprock; while for the CO2–SO2 injection case, porosity and permeability only decreased in the layers of the shale caprock contacted by SO2 and due to anhydrite precipitation. In all the injection cases, the porosity and permeability of the sandstone reservoir decreased in a few layers directly below the perforation interval of the production zone. However, in other regions in the sandstone reservoir, the porosity and permeability increased for the CO2 only and CO2–H2S injection cases. In contrast, for the CO2–SO2 co-injection case, porosity and permeability decreased in the layers of the sandstone rock contacted by SO2. In all the CO2 geosequestration cases, the brittleness of the shale and sandstone rocks investigated decreased slightly, except in the CO2–SO2 co-injection case where the brittleness of the sandstone rock decreased significantly. Based on the mineralogical composition of the formations in this study, co-injection of SO2 gas with CO2 gas, only decreased the brittleness index of the shale caprock slightly, but significantly decreased the brittleness of the sandstone reservoir.

Numerical simulation of CO2 storage by basalts in Xingouzui formation, Jianghan Basin, China

Sedimentary basins often develop large amounts of basalts, but there are few studies. The diagenetic history of basalts in sedimentary basins is different from that of continental flood basalts and deep-sea basalts. A large amount of basalt is developed in the Jianghan Basin. Minerals undergo varying degrees of alteration, such as the alteration of olivine into serpentine. Numerical simulations were used to study the interaction between basalt-CO2-formation water in the Xingouzui Formation. The effects of basalt alteration and CO2 injection mode (supercritical CO2, saturated CO2 water, co-injection of CO2 and water) on CO2 storage were investigated. The results show that the reactivity between unaltered basalt and CO2 is strong, and the maximum CO2 mineral trapping reaches 22–49 kg/m3 after CO2 injection for one month. However, the reactivity between the altered basalt and CO2 is obviously decreased. Compared with the unaltered basalt, the maximum CO2 mineral trapping for the altered basalt decreased by at least 15.4 % after CO2 injection for one year. For severely altered basalt with high serpentine content, the maximum CO2 mineral trapping even drops by more than 90 %. CO2 mineral trapping will be overestimated when the feedback of reservoir porosity and permeability changes on flow is not considered. The co-injection of CO2 and water can make full use of the advantages that water injection can promote CO2 dissolution and the resulting acidic environment is beneficial to mineral dissolution. This method could be an option after careful assessment of CO2 leakage risks and technical feasibility.

Study Evaluates CO2 Storage Potential During CO2 Mobility-Control Optimization

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 212969, “Evaluation of CO2 Storage Potential During CO2 Mobility-Control Optimization for Enhanced Oil Recovery,” by Alvinda Sri Hanamertani, SPE, Ying Yu, SPE, and Omar El-Khatib, SPE, University of Wyoming, et al. The paper has not been peer reviewed. _ CO2 mobility control through foam technology has enabled better sweep efficiency and, consequently, better oil productivity during enhanced oil recovery (EOR) processes. Along with enhancing oil production, a sound potential exists for in-situ generated foam to enhance CO2 storage. However, the effect of the different in-situ foam generation strategies on the combined goal of maximum oil production and carbon storage is not well elucidated in the literature. In the complete paper, the authors methodically evaluate the simultaneous optimization of CO2 storage and oil recovery using multiple injection strategies. Introduction The current investigation is a continuation of two previous studies that provided a methodology for screening and using foaming agents for optimized CO2 storage in sandstone and carbonate formations. A base case of tertiary CO2 flooding was established for comparison with in-situ foam generation by two approaches: single-cycle surfactant-alternating-gas (SAG) flooding and coinjection of CO2 and surfactant. Additionally, the effect of surfactant concentration on foam efficiency, CO2 storage capacity, and oil recovery were evaluated in both approaches at reservoir conditions. Materials and Methods Fluids and Porous Medium. In this study, a synthetic brine with total dissolved solids of 20 wt% was used as blank brine and laden with a commercial zwitterionic surfactant that was used to prepare surfactant solutions with concentrations of 0.5 and 1 wt% active matter in the synthetic brine. Three core plugs were drilled from an Indiana limestone outcrop block. The cores were then cleaned and oven-dried at 95°C. Experimental Procedure. Vacuum saturation with brine was commenced for the three cores. The porosity of the cores was calculated using their dry and brine-saturated weights. Then, the 100% brine-saturated core was placed in a core holder and loaded into an oven set to 90°C. The pore pressure was fixed at 2,000 psi, and the confining pressure was controlled at 3,000 psi throughout the flooding experiment. The brine permeability of the core samples was evaluated by measuring the pressure drop across the core at different brine-injection flow rates. In the first experiment (IL1), oil drainage with a flow rate of 0.2 cm3/min was performed to establish irreducible water saturation of 46.9%. This total flow rate was kept the same throughout the three experiments. Then, a waterflooding stage was begun and the oil recovery was recorded. After reaching a plateau in oil recovery, supercritical CO2 (scCO2) was injected during the EOR process until the oil production plateaued.

The foam reinforced with Janus amphiphilic graphene oxide to control steam channeling in heavy oil reservoir

Foams have been considered effective diverters to decrease the mobility in the steam channel for heavy oil-recovery processes. Due to the high weight of chemical additive loss caused by adsorption to the rock surface and the poor thermal stability of these additives, the result of surfactant or polymer is usually unsatisfactory. To avoid these problems, nanoparticles can be utilized as novel assistants to enhance the generation and stabilization of foams. In this research, an amphiphilic graphene oxide (H-GO2), which is very effective at low concentrations, is utilized to enhance the foam performance in the process of plugging steam channeling. Compared with the foam prepared by using surfactant alone, the foam height and half-life at a low concentration (0.05 wt%) of H-GO2 in bulk medium increased by approximately 151% and 341%, respectively. The size distribution of bubbles in the presence of 0.05 wt% H-GO2 is uniform, and H-GO2 creates the gas-liquid interface film three times thicker than that of the surfactant without H-GO2. As NaCl concentration increased from 0.5 to 5 wt%, more foam was generated in a shorter time, and the half-life became longer. Excess NaCl causes less foam formation and a shorter half-life. Foam generation and stabilization are reduced with the CaCl2 concentration in solution increasing from 0 to 10 wt%, or the temperature increasing from 150 to 240 ℃. Corefloods with coinjected CO2 and water containing 0.05 wt% H-GO2 and surfactant can double the resistance factor of foam in the porous medium, compared with coinjection of CO2 and water containing only surfactant. The additional oil recovery of foam generated by surfactant alone is 14.6%. It is extraordinary that the increased recovery of 31.4% can be obtained by introducing only 0.05 wt% H-GO2 into the same foam. This work may provide a reference for steam channeling control in the steam injection development process of heavy oil oilfields.

Feasibility of hydrogen storage in depleted hydrocarbon chalk reservoirs: Assessment of biochemical and chemical effects

Hydrogen storage is one of the energy storage methods that can help realization of an emission free future by saving surplus renewable energy for energy deficit periods. Utilization of depleted hydrocarbon reservoirs for large-scale hydrogen storage may be associated with the risk of chemical/biochemical reactions. In the specific case of chalk reservoirs, the principal reactions are abiotic calcite dissolution, acetogenesis, methanogenesis and biological souring. Here, we use PHREEQC to evaluate the dynamics and the extent of hydrogen loss by each of these reactions in hydrogen storage scenarios for various Danish North Sea chalk hydrocarbon reservoirs. We find that: (i) Abiotic calcite dissolution does not occur in the temperature range of 40-180° C. (ii) If methanogens and acetogens grow as slow as the slowest growing methanogens and acetogens reported in the literature, methanogenesis and acetogenesis cannot cause a hydrogen loss more than 0.6% per year. However, (iii) if they proceed as fast as the fastest growing methanogens and acetogens reported in the literature, a complete loss of all injected hydrogen in less than five years is possible. (iv) Co-injection of CO2 can be employed to inhibit calcite dissolution and keep the produced methane due to methanogenesis carbon neutral. (v) Biological sulfate reduction does not cause significant hydrogen loss during 10 years, but it can lead to high hydrogen sulfide concentrations (1015 ppm). Biological sulfate reduction is expected to impact hydrogen storage only in early stages if the only source of sulfur substrates are the dissolved species in the brine and not rock minerals. Considering these findings, we suggest that depleted chalk reservoirs may not possess chemical/biochemical risks and be good candidates for large-scale underground hydrogen storage.

Micro CT and Experimental Study of Carbonate Precipitation from CO2 and Produced Water Co-Injection into Sandstone

Carbon dioxide geological storage involves injecting captured CO2 streams into a suitable reservoir. Subsequent mineral trapping of the CO2 as carbonate minerals is one of the most secure forms of trapping. Injection of CO2 dissolved in water or co-injection of CO2 with water may enhance trapping mechanisms. Produced waters are already re-injected into reservoirs worldwide, and their co-injection with CO2 could enhance mineral trapping in low reactivity rock by providing a source of cations. Sandstone drill core from a reservoir proposed for CO2 storage was experimentally reacted with supercritical CO2 and a synthetic produced water. Micro computed tomography (CT), QEMSCAN, and SEM were performed before and after the reaction. The sandstone sample was predominantly quartz with minor illite/muscovite and kaolinite. The sandstone sub-plug micro-CT porosity was 11.1% and 11.4% after the reaction. Dissolved Ca, Mg, and Sr decreased during the reaction. After the reaction with CO2 and synthetic produced water, precipitation of crystalline carbonate minerals calcite and dolomite was observed in the pore space and on the rock surface. In addition, the movement of pore filling and bridging clays, as well as grains was observed. Co-injection of CO2 with produced waters into suitable reservoirs has the potential to encourage CO2 mineral trapping.

A Review of CO2 Storage in View of Safety and Cost-Effectiveness

The emissions of greenhouse gases, especially CO2, have been identified as the main contributor for global warming and climate change. Carbon capture and storage (CCS) is considered to be the most promising strategy to mitigate the anthropogenic CO2 emissions. This review aims to provide the latest developments of CO2 storage from the perspective of improving safety and economics. The mechanisms and strategies of CO2 storage, focusing on their characteristics and current status, are discussed firstly. In the second section, the strategies for assessing and ensuring the security of CO2 storage operations, including the risks assessment approach and monitoring technology associated with CO2 storage, are outlined. In addition, the engineering methods to accelerate CO2 dissolution and mineral carbonation for fixing the mobile CO2 are also compared within the second section. The third part focuses on the strategies for improving economics of CO2 storage operations, namely enhanced industrial production with CO2 storage to generate additional profit, and co-injection of CO2 with impurities to reduce the cost. Moreover, the role of multiple CCS technologies and their distribution on the mitigation of CO2 emissions in the future are summarized. This review demonstrates that CO2 storage in depleted oil and gas reservoirs could play an important role in reducing CO2 emission in the near future and CO2 storage in saline aquifers may make the biggest contribution due to its huge storage capacity. Comparing the various available strategies, CO2-enhanced oil recovery (CO2-EOR) operations are supposed to play the most important role for CO2 mitigation in the next few years, followed by CO2-enhanced gas recovery (CO2-EGR). The direct mineralization of flue gas by coal fly ash and the pH swing mineralization would be the most promising technology for the mineral sequestration of CO2. Furthermore, by accelerating the deployment of CCS projects on large scale, the government can also play its role in reducing the CO2 emissions.

A Multiphase, Multicomponent Reservoir-Simulation Framework for Miscible Gas and Steam Coinjection

SummaryThe solvent thermal resource innovation process (STRIP), a downhole steam-generation technology, has the capacity to show improved recovery factors with a significantly reduced environmental footprint compared with traditional thermal-enhanced-oil-recovery (TEOR) methods, most notably by delivering all the combustion heat to the pay zone. In this effort, a quarter-symmetry inverse-five-spot model and a multiphase, multicomponent reservoir-simulation framework were used to simulate the STRIP technology. Commercial simulators such as STARS - Thermal and Advanced Processes Reservoir Simulator [Computer Modelling Group Ltd. (CMG), Calgary, Alberta, Canada; CMG 2015b] often use the K-value approach to simulate TEOR. However, the method cannot simulate STRIP's carbon dioxide (CO2) and steam coinjection because the K-value method does not consider miscible gas injection. On the other hand, CMG's GEM - Compositional and Unconventional Simulator (CMG 2015a) includes the effects of miscible gases but does not provide comprehensive support for steam-injection processes, which are better handled by STARS. The novel simulation framework developed here leverages and combines the individual strengths of STARS (thermal features) and GEM (compositional features). In this framework, STARS simulated steam injection (but cannot directly simulate the effects of CO2) and was the governing model that synchronized temperature, pressure, and phase saturations for two parallel iterations of the GEM models (GEM-1 and GEM-2) at each timestep. Immiscible methane (CH4) was added to GEM models to maintain gas saturations equivalent to the STARS model. GEM-1 simulated hot-water and CH4 injection, but at increased rates to yield a pressure field and gas saturations equivalent to STARS. A final run of GEM-1 injected both CO2 and hot water and demonstrated the expected increase in oil production. Calibrated injection rates from GEM-1 were specified in GEM-2 to ensure equivalence of the pressure field. Next, the GEM-2 model also simulated hot-water and CH4 injection, but matched both water and oil productions along with oil saturations from the final GEM-1 run by altering relative permeabilities. Finally, the updated relative permeabilities were fed back to STARS, and iteration proceeded. Results from this framework were verified against a STARS steam-injection simulation. Finally, when considering coinjection of CO2, STRIP's superior performance was demonstrated through increased oil recovery and a lower steam/oil ratio (SOR).

Carbon sequestration potential of altered mafic reservoirs

Porous basaltic aquifers are currently being considered as a key geologic carbon storage host due to its widespread distribution and high reactivity. The co-injection of CO2 and groundwater into basaltic reservoirs has the potential to mineralize this gas into solid phases within years, thanks to the release of divalent cations. Many natural basalts, however, contain substantial alteration minerals. Here we explore the potential of basalt alteration minerals to provide the Ca to fix injected CO2 within calcite and/or aragonite. Preliminary results suggest that altered basaltic rocks can provide this Ca as efficiently as fresh basalts at 25 and 100 °C. Further experimental work is ongoing to confirm these findings at different temperatures and as a function of injected fluid chemistry.

Laboratory investigation of oil recovery by CO2 foam in a fractured carbonate reservoir using CO2-Soluble surfactants

Miscible CO2 flooding has been used as an EOR method for carbonate reservoirs which hold around 60% of the world's oil reserves. However, natural fractures, unfavorable mobility ratio and gravity segregation in carbonate reservoirs often lead to premature CO2 breakthrough and bypassed oil. To remedy this situation, CO2 foam has been used to reduce the mobility of the injected CO2. Typically, this employed a water soluble surfactant for foam propagation. However, surfactant transport in the aqueous phase was often hindered by surfactant adsorption and undesirable chemical reactions with reservoir minerals. In this study, we investigated whether CO2-soluble surfactants were more effective than water-soluble surfactant in oil recovery of fractured carbonate reservoirs under miscible conditions.A series of corefloods were conducted to determine the oil recovery factor (RF), speed of foam propagation and foam strength in artificially fractured carbonate cores at 35 °C (308.15 K) and 1500 psi (1.034*107 Pa) which was above minimum miscibility pressure. Silurian Dolomite outcrop with permeability of 150 md and West Texas Wasson crude were used. The cores were intermediate-wet indicated by both qualitative and quantitative tests. Three different surfactants were compared including an anionic water-soluble surfactant and other two nonionic CO2 soluble surfactants (2-ethyl-1-hexanol with different ethylene oxide groups) with distinct degree of solubility in CO2. Phase behavior experiments indicated these surfactants did not lower the interfacial tension significantly between the crude and water.RF of CO2 flooding was only 24% due to the heterogeneous nature of the fractured core. Co-injection of CO2 and water increased the RF to 35%, which was further increased to 54% when a water-soluble only surfactant presented. However, use of CO2 foam by the two CO2-soluble surfactants increased the RF to 71% and 92% respectively, with a higher RF for the surfactant that partitioned more to the CO2 phase. Also, pressure drop in different sections of the core confirmed that the surfactant which partitioned more into the CO2 phase gave a faster-propagating and stronger foam.These results educated that the partitioning of surfactant into the CO2 phase has several advantages. First, it allows surfactant to be transported in the CO2 phase ahead of the aqueous phase thus leading to faster foam propagation. Second, it generated a stronger foam. The combined effect of the two leaded to higher RF in current scenarios. Several hypotheses based on literature were raised and listed to further interpret the observations. Our results also reinforce that the so-called optimal CO2 soluble surfactant is case dependent and is the function of injection strategy, reservoir environment, and operation pressure or rates as well as other specific conditions. One could tailor a surfactant with suitable solubility in the CO2 phase to optimize oil recovery in fractured carbonates. We believed the results were encouraging enough to warrant further R&D and eventual field piloting.

Mobility control in carbon dioxide-enhanced oil recovery process using nanoparticle-stabilized foam for carbonate reservoirs

Recent developments in the subject of using silica-nanoparticles (SiNPs) for stabilizing carbon dioxide (CO2)-foam have led to a renewed interest in the enhanced oil recovery (EOR) in oilfields. This study investigates the mobility control in the process of CO2 EOR through unfractured and fractured limestone cores. Toward this aim, laboratory tests were performed by co-injection of CO2 and 12 nm methyl-coated SiNPs solution to generate stable CO2 foam in the cores. In addition, sodium chloride (NaCl) and decane were used to examine the sensitivity of foam generation to salinity and to signify hydrocarbon (HC) phase in the experiments, respectively. The results revealed that SiNPs were able to generate stabilized CO2 foam in both unfractured and fractured limestone cores. A critical shear rate was established in the generation of foam with different conditions in the core-flood experiments. The cores with lower matrix permeability had a lower value of critical shear rate for foam generation. Moreover, the magnitude of apparent viscosity was found to be a crucial factor for mobility control and to obtain an optimum quality of foam. The results indicated that increasing NaCl concentration to 3 wt.% causes a decrease in the value of critical shear rate at applied temperatures. Furthermore, the findings revealed that a real mobility control in CO2 EOR process can only be reached when the generated foam still interacts with HC in the reservoir.

U(VI) removal efficiency by the oxidation of Fe(II) under the only injection of O2 and co-injection of CO2 and O2

Batch experiments were carried out to investigate the U(VI) removal efficiency by the oxidation of Fe(II) under the only injection of O2 and co-injection of CO2 and O2. Experiment results show that under the only injection of O2, the synergistic effect of Fe(II) and O2 could effectively remove U(VI) from the solution. For the different initial concentrations of Fe(II) at 2, 5, 10, 25, 50, 100 mg/L, almost all the removal rates of U(VI) reach up to 90% in the neutral conditions. There is no inevitable correlation between the removal efficiency of U(VI) and the initial concentration of Fe(II), revealing that the coprecipitation of U(VI) with Fe-oxides plays a dominant role in the removal of U(VI) rather than the simple sorption to the surface of Fe-oxides. Under the co-injection of CO2 and O2, the generated carbonate ions have a significant effect on the removal efficiency of U(VI) by the synergistic effect of Fe(II) and O2. The removal efficiency of U(VI) increases with the initial concentration of Fe(II). In the presence of carbonate ions, U(VI) is easy to bind with HCO3- to form uranyl carbonate complexes such as UO2(CO3)20 and UO2(CO3)42-, which would hinder the process of sorption and co-precipitation of U(VI) with Fe-oxides.

Different flow behavior between 1-to-1 displacement and co-injection of CO2 and brine in Berea sandstone: Insights from laboratory experiments with X-ray CT imaging

In this study, we compare the changes in CO2 saturation and pressure drop for two modes of injections: (i) a displacement of brine by supercritical CO2 injection (1-to-1 displacement), and (ii) a forced co-current injection of supercritical CO2 and brine at the same flow ratio (co-injection), respectively, in a laboratory core-flooding experiment using a Berea sandstone sample. The Berea sandstone sample showed a weak bedding structure that consists of high- and low- porosity layers. The main flow direction was set perpendicular to the bedding layers. We utilized the X-ray CT technique to image the rock interior and obtain the information of local porosity and saturation of each voxels in a three dimensional volume. The results show that the co-injection needs a much higher pressure drop to maintain the constant flow rate than the 1-to-1 displacement at similar saturation degrees. Moreover, the co-injection shows significant fluctuations in saturation and pressure drop, whereas the 1-to-1 displacement shows more gradual and monotonous changes. The spontaneous fluctuations in saturation and pressure drop during co-injection are basically coincident in temporal pace, and can be explainable by the intermittent flow of brine and CO2 as shown in differential saturation images. Furthermore, the X-ray images show that the CO2 mainly flows through built flow pathway during the 1-to-1 displacement; whereas the CO2 flows near uniformly and does not strictly rely on pore size and capillarity during the co-injection. CO2 saturation distributes more uniform among image pixels during the co-injection. These dissimilarities between the co-injection and 1-to-1 displacement suggest differences in fluid flow mechanism between them. In the 1-to-1 displacement, the pathway of CO2 flow was created by the forward motion of CO2 over the capillary pressure force. CO2 preferred to first percolating through large-size pores and gradually expanded the percolation region while the CO2 saturation grew. In this process, the displaced brine mainly flowed in its remained phase-pathway–less phase interference occurred. The connection of flow pathway for CO2 naturally satisfied the maintaining of the flow rate. In contrast, during the co-injection, both phases flowed in the pore space. The connection of the phase-pathway was affected by the phase snap-off effect. The transport efficiency of such a partially disconnected flow-pathway was significantly lower than the 1-to-1 displacement case, leading to that much higher drive force of pressure drop was necessary to let the fluids flow at setting rates. Nevertheless, the reachability of CO2 to low-porosity sites during the co-injection was higher than during the 1-to-1 displacement. Our findings are important for understanding of co-injections in applications of relative permeability measurement, and enhanced efficiency in capillary trapping, usage of pore space in CO2 geological storage and in oil recovery.

Effect of impurities on the onset and growth of gravitational instabilities in a geological CO2 storage process: Linear and nonlinear analyses

Because 75% of the total cost of carbon capture and storage (CCS) arises from the separation of CO2 from gas streams (Nsakala et al., 2001), the co-injection of CO2 and impurities such as H2S, N2, and SO2 is considered a cost-effective alternative to pure CO2 geological sequestration. Here, the effect of the impurities on the onset of gravitational instability has been analyzed theoretically and numerically. Linear stability equations have been derived and solved analytically and numerically. Double diffusive effects make the system stable or unstable depending on the values of the diffusivity ratio, δB, and buoyancy ratio, rβrC. In addition, using the Fourier spectral method, we have traced the temporal evolution of the gravitational fingers numerically. The shape and the growth history of the fingers are strongly dependent on the impurity content. The time-periodic oscillatory motions are not observed in the present linear and nonlinear analyses. For a given Rayleigh number, the dissolution of N2 and H2S impurities makes the system stable, whereas dissolved SO2 accelerates the onset of instability.

Geothermal exploitation from depleted high temperature gas reservoirs via recycling supercritical CO2: Heat mining rate and salt precipitation effects

The geothermal energy in depleted high temperature gas reservoirs can be developed using existing wells and surface facilities via recycling water or supercritical CO2 after natural gas production. For a typical medium-size gas field, the recoverable geothermal energy can be equivalent to over 10milliontons of standard coal. The injection of CO2 can improve the heat mining rate, and it can also enhance gas recovery at the early stage of the process and achieve geological storage of CO2. However, a big concern in the injection of CO2 is the salt precipitation induced by the interactions between the injected CO2 and the formation water, which might cause reservoir damage and subsequently affect the flow behavior and the heat mining rate. In this paper, a comprehensive model of geothermal exploitation from gas reservoirs via CO2 injection was established, in which the processes of formation water evaporation, salt dissolution and precipitation, and their effects on formation porosity and permeability were incorporated. The influences of various parameters on geothermal recovery and salt precipitation were investigated by using this model, including the saturation and salinity of formation waters, injection-production pressure difference, and the permeability and porosity of the gas reservoirs. The results show that, for the gas reservoir studied at a temperature of 130°C (i.e. with a volume of 1000m×500m×50m), the heat mining rate of one injector-producer pair can be maintained at about 5MW with a CO2 recycling rate of 3000t/day for 30years. The effect of salt precipitation is moderate, and it is dependent on the reservoir conditions. Especially, salt precipitation occurs severely in the near well region when the remaining water saturation is higher than the irreducible water saturation. Meanwhile, water evaporation induced by CO2 injection may cause a back flow of formation water due to the effects of gravity and capillarity, which can intensify the evaporation and increase the salt precipitation and enrichment in the region. This can cause a reduction of permeability which therefore decreases the heat mining rate. Different methods for reducing salt precipitation was proposed and evaluated accordingly, including injection of low salinity water prior to CO2 injection and co-injection of CO2 and fresh water.

Experimental study of two-phase flow properties of CO2containing N2in porous media

In preliminary analyses, the co-injection of CO2 with H2S, SO2 and N2 impurities has been shown to reduce total carbon capture and storage (CCS) cost. The multiphase flow properties of impurities in the CO2–brine system in porous media are the key to understanding the mechanisms and nature of geological CO2 sequestration projects. In this study experiments were performed on the multiphase flow process of CO2/N2/brine system at conditions similar to aquifer pressure and temperature using the X-ray CT technique. Experiments at various rates of CO2 injection that affect saturation and spatial distribution of injected gas were conducted in this experiment. The results indicate an strong relationship between gas saturation and porosity distribution in porous media, and the increasing capillary number leads to lower saturation in downward injection. Small capillary numbers and higher fractional flows in the gas phase both result in uniform saturation maps in the core. The CO2 clusters seem larger at high capillary numbers and the high CO2 collection regions extend based on the saturation distribution in the lower CO2 fraction as the flow pattern stays similar as the same capillary number. CO2 containing N2 tends to retain more correlative relationships at different gas injection rates compared with the pure CO2 stream. Even though both distribution and saturation are storage concerns, the N2 component has little effect on gas distribution, whereas it brings about an overall increase in the saturation for most experiments. Thus the N2 enhanced the storage performance of CO2.

Experimental investigation of CO2-foam stability improvement by alkaline in the presence of crude oil

Dissolution of CO2 in heavy crude oil results in a significant reduction in the oil viscosity. However, CO2 injection in viscous oil reservoirs lacks acceptable sweep efficiency due to the high mobility of CO2. Co-injection of CO2 and an appropriate surfactant can generate CO2-foam in situ providings a means of controlling CO2 mobility and hence, improving sweep efficiency and oil recovery. Foam injection has been studied in the past but in the majority of these studies, foam has been investigated in the absence of crude oil. It is known that the stability of foam is adversely affected by crude oil and this problem has been a major obstacle for the application of foam injection for enhanced oil recovery (EOR).In this paper we present the results of a comprehensive series of visual experiments on foam stability in the presence of different heavy crude oil samples. Through these experiments, we have evaluated and compared the performance of a number of surfactants for foam generation. We have also tested the impact of three different alkalis (NaOH, Na2CO3, and Borate) on foam stability. The effect of gas type (CO2 versus N2) has also been investigated experimentally.The results show that while addition of NaOH drastically decreases the stability of CO2-foam, Na2CO3 and, in particular, Borate can significantly increase the stability of CO2-foam. For these alkalis, there is an optimum concentration which corresponds to maximum foam stability. The results also reveal that higher oil viscosity increases the stability of CO2-foam. Anionic surfactants with smaller carbon number produce better foam stability compared to non-anionic surfactants. As expected, foam stability increased with increasing surfactant concentration but there was an optimum surfactant concentration corresponding to maximum foam stability beyond which foam stability decreased. The results also revealed that N2-foam was more stable compared to CO2-foam.

Numerical Study on the Field-scale Aquifer Storage of CO2 Containing N2

The possibility of co-injecting these gaseous compounds with CO2 to decrease the operational cost of carbon capture and storage by lowering the requirement of CO2 capture or adding impurities is being considered. Some studies have analyzed the possible geochemistry effects of impurities such as H2S and SO2. However, few studies have focused on the effect of N2 or other non-condensable gas impurities in CO2 stream. Accordingly, this study performed some preliminary numerical simulations on the migration process of CO2/N2 mixture. A modeling tool was established based on the pressure-volume-temperature, viscosity, solubility, and relative permeability characteristics, as well as on the capillary pressure curve, geochemistry model, and COMSOL-Multiphysics software. Then, the migration processes of different N2/CO2 mixtures were evaluated using the modeling tool. The numerical simulation results showed the following: 1) co-injection of CO2 and N2 decreased the storage capacity of CO2 in the aquifer; 2) CO2 plume with N2 moved faster than pure CO2 plume, and CO2 plume with N2 had a higher gas saturation than pure CO2 plume; and 3) a chromatographic partitioning process occurred during the migration process of the gas mixture, suggesting that N2 in the migration front may be an effective monitoring or warning gas for CO2 leakage given the non-toxicity and inertness of N2.