CO2 Injection Strategies Research Articles

Hydrate management strategies for CO2 injection into depleted gas reservoirs

Sequestering CO2 in depleted gas reservoirs using carbon capture, utilization, and storage technologies has emerged as a viable strategy for mitigating global carbon emissions. However, CO2 hydrate formation during injection processes is challenging and poses a risk to the operational integrity and efficiency of sequestration projects. This study investigated CO2 hydrate formation dynamics within silica gel environments that closely mimicked the median pore size of natural sandstone reservoirs, particularly targeting depleted gas fields in the East Sea of Korea. Integrating kinetic insights into experimental hydrate formation assessments and molecular dynamics simulations provided a comprehensive understanding of the CO2 hydrate formation mechanisms, as well as the formation dynamics and stability of the CO2 hydrates. For example, the hydrate formation kinetics were significantly reduced in the small pores, suggesting the feasibility of implementing more economical hydrate inhibitor injection strategies during CO2 injection. Moreover, this study evaluated the inhibitory effects of NaCl and methanol on CO2 hydrate stability by accurately measuring the three-phase (H-Lw-V) equilibria and employing silica gels (6 nm pore size). The presence of methanol and amorphous silica significantly impacted hydrate formation, with methanol potentially influencing the local structure around the hydrate phase and silica hindering hydrate growth through dynamic interactions with CO2 molecules. In addition, we elucidated the complex interplay between CO2, water, and methanol (hydrate inhibitor) within the constrained environments of porous media, offering strategic insights for the development of effective CO2 injection and sequestration strategies. Integrating molecular-level observations with real-world geological modeling presents a novel methodology for enhancing the safety, efficiency, and environmental sustainability of carbon capture and storage operations. The findings of this study provide critical insights into hydrate phase behavior, highlighting the importance of precise equilibrium determination under simulated reservoir conditions to effectively anticipate and mitigate hydrate formation challenges.

Interfacial properties of CO2 and liquid sulfur in high-sulfur gas fields: Molecular simulations on carbonate mineral surfaces

As the global energy landscape transforms, the development of high-sulfur natural gas has become increasingly critical. However, sulfur deposition during these gas field developments significantly affects operational efficiency. This study employed molecular dynamics simulation to explore the effectiveness of CO2 in alleviating sulfur deposition on carbonate rock reservoirs. Specifically, it examined the interfacial tension between liquid sulfur and CO2, the wettability of sulfur on carbonate rock mineral surfaces, and the kinetics of CO2 displacing liquid sulfur. Results show that as CO2 pressure increases from 10 MPa to 60 MPa, the interfacial tension between liquid sulfur and CO2 decreases by 84 %, from 35.54 mN/m to 5.53 mN/m. The contact angles of sulfur droplets on calcite and dolomite surfaces stabilize at 41.82° ± 2.10° and 44.33° ± 3.27°, respectively, indicating greater sulfur spread on calcite surfaces. With higher CO2 pressures, sulfur deposition on mineral surfaces and interfacial tension both decrease significantly, while the wetting angle of liquid sulfur increases, particularly on dolomite. At 60 MPa CO2 pressure, the adsorption energy of dolomite for liquid sulfur drops from 364.56 kcal/mol to 25.46 kcal/mol, a 93 % reduction, suggesting CO2′s dual role in displacing sulfur and promoting its desorption from mineral surfaces. Furthermore, the efficiency of sulfur deposition alleviation in carbonate rock slit structures improves and stabilizes at around 40 MPa CO2 pressure. This study presents a potential environmentally friendly approach for efficiently developing high-sulfur gas fields, and its findings provide practical insights for optimizing CO2 injection strategies to mitigate sulfur deposition.

CO2 injection for enhanced oil recovery: Analyzing the effect of injection rate and bottom hole pressure

The goal of net-zero carbon emissions has led to widespread interest in lowering carbon dioxide (CO2) emissions. At the same time, the oil and gas industry seeks to enhance oil recovery (EOR) techniques to meet growing demand. CO2 flooding, a key EOR method, offers a dual benefit: reducing CO2 emissions and enhancing oil recovery. This study investigates the impact of injection rate and bottom hole pressure (BHP) on CO2 injection performance using the Nexus reservoir simulator, a novel application in CO2-EOR research. To the best of the author's knowledge, there is no previous research published in which the researchers used the Nexus reservoir simulator for the study of CO2-EOR. Cases are thoroughly investigated with various injection rates and BHP limitations. Simulation results show that BHP has a minimal impact on oil production, whereas increased injection rates significantly enhance cumulative oil production (COP) by 33.39% and extend reservoir life from 20 to 37 years. Total oil production increased to 33150.7 MSTB, accompanied by reduced water production and maintained reservoir pressure. These findings align with previous research, underscoring the importance of optimized CO2 injection strategies for maximizing oil recovery and reservoir performance.

Experimental Investigation of the Impact of CO2 Injection Strategies on Rock Wettability Alteration for CCS Applications

Carbon capture and storage (CCS) has been recognized as a pivotal technology for mitigating climate change by reducing CO2 emissions. Storing CO2 in deep saline aquifers requires preserving the water-wet nature of the formation throughout the storage period, which is crucial for maintaining rock integrity and storage efficiency. However, the wettability of formations can change upon exposure to supercritical CO2 (scCO2), potentially compromising storage efficiency. Despite extensive studies on various factors influencing wettability alteration, a significant research gap remains in understanding the effects of different CO2 injection strategies on wettability in deep saline formations (DSFs). This study addresses this gap by investigating how three distinct CO2 injection strategies—continuous scCO2 injection (CCI), water alternating with scCO2 injection (WAG), and simultaneous water and scCO2 injection (SAI)—affect the wettability of gray Berea sandstone and Indiana limestone, both selected for their homogeneous properties relevant to CCS. Using a standardized sessile drop contact angle method before and after CO2 injection, along with core flooding to model the injection process at an injection pressure of 1500 psi and temperature of 100 °F with a confining pressure of 2500 psi, the results indicate a shift in wettability towards more CO2-wet conditions for both rock types under all strategies with changes in CA of 61.6–83.4° and 77.6–87.9° and 81.5–124.2° and 94.6–128.0° for sandstone and limestone, respectively. However, the degree of change varies depending on the injection strategy: sandstone exhibits a pronounced response to the CCI strategy, with up to a 77% increase in contact angle (CA), particularly after extended exposure. At the same time, WAG shows the least change, suggesting that water introduction slows surface modification. For limestone, the changes in CA ranged from 9% to 49% across strategies, with WAG and SAI being more effective in altering its wettability. This study underscores the importance of selecting suitable CO2 injection strategies based on rock type and wettability characteristics to maximize carbon storage efficiency. The findings offer valuable insights into the complex interactions of fluid–rock systems and a guide for enhancing the design and implementation of CCS technologies in various geological settings.

Carbon accounting methods for the system-wide evaluation of carbon capture, utilisation and storage: A case study in Mexico's Southeast Region

Existing assessments of climate mitigation technologies, like carbon capture utilisation and storage (CCUS), often rely on life cycle assessments (LCA), which are helpful for quantification but may not always be the most complete tools for decision-making. The novel contribution of this study is to provide the first application of a consequential carbon accounting approach, presented as a time-series analysis, to measure the system-wide change in emissions from CCUS linked to CO2-enhanced oil recovery. This method includes emissions from marginal oil production, a variable typically excluded in other LCA methods. The method was applied to a hypothetical CCUS project in Mexico to understand critical factors determining whether such an intervention can effectively contribute to emissions reduction in alignment with net-zero goals. Four intervention scenarios were assessed, comparing two distinct CO2 injection strategies in oil reservoirs (water alternating gas and continuous gas injection) and two energy policy scenarios (current and sustainability). The findings suggest that the energy grid's role in overall emissions is relatively minor, with only a ∼2% difference between the compared scenarios, in contrast, the injection strategy has a significant impact on emissions. Scenarios 1 and 3 report a total change in emissions of −28.39 and −29.87MtCO2e, and scenarios 2 and 4 account for −19.63 and −21.22MtCO2e, respectively. The results highlight the importance of conducting system-wide analysis and comparing different scenarios to identify the critical components that drive changes in emissions and, therefore, support decision-making and project planning.

Optimizing CO2 Injection Strategies: A Deep Learning Approach to Prediction of CO2 phase across Seven Shale Basins

Optimizing CO2 Injection Strategies: A Deep Learning Approach to Prediction of CO2 phase across Seven Shale Basins

The impact of supercritical CO2 exposure time on the effective stress law for permeability in shale

Carbon dioxide (CO2) sequestration in shale formations is regarded as an effective approach for reducing CO2 emissions. Permeability is critical for CO2 geological sequestration as it impacts migration of CO2 in shale formations. The effective stress coefficient for permeability (χ) scales the relative influence of pore pressure on permeability compared to confining pressure. This study examined the changes in χ of dry and wet shale samples with different times of supercritical CO2 (ScCO2) exposure. The results suggest that, as ScCO2 exposure time increases from 0 to 40 days, the χ of dry shale increases from 0.8304 to 0.9563, and that of wet shale increases from 0.8379 to 1.0134. Wet shale exhibits a greater increase in χ than dry shale for the same exposure time. These changes in χ may result from CO2-shale interaction that converts smaller-sized pores in shale into larger-sized pores, based on nuclear magnetic resonance (NMR) measurements. Furthermore, the presence of water intensifies the response of shale to ScCO2, thereby enhancing this transformation. Our findings provide insights into the accurate prediction of shale permeability evolution during CO2 storage, and can assist in optimizing CO2 injection strategies as well as evaluating the potential for CO2 sequestration.

An experimental study of CO2 injection strategies for enhanced oil recovery and geological sequestration in a fractured tight sandstone reservoir

Carbon dioxide enhanced oil recovery has been considered and tested in unconventional oil reservoirs due to its additional environmental benefits from simultaneous CO2 geological sequestration. However, it will require a proper injection strategy to overcome unfavorable sweep efficiency in CO2 displacement, which is even magnified in unconventional oil reservoirs due to strong heterogeneity caused by natural and artificial fractures. In this study, we investigated three immiscible CO2 injection strategies at reservoir conditions using tight fractured sandstone cores from the Ordos Basin, China: water alternative gas injection, cyclic CO2 injection, and CO2 foam/surfactant alternative gas injection. A pressurization and miscible CO2 injection were then added after each injection strategy to examine the influence of residual liquid distributions on the miscible displacement efficiency after the tested injection schemes. The core plugs with comparable porosity and permeability were selected, and all cores reached a similar recovery factor (∼11%) after primary CO2 flooding. We found that the cyclic CO2 injection had best performance, with the highest incremental and accumulative oil recovery at 23.6% and 32.26%. Its relatively higher sweep efficiency indicated a uniform CO2 distribution at the end of the cyclic injection, which further led to the highest incremental recovery of 4.94% in the following miscible injection. Comparable CO2 storage capacities were observed in the three fractured core samples (12.21%, 12.98%, and 9.71%, respectively) after completing the miscible displacements. In general, cyclic CO2 injection is recommended as an effective CO2 EOR and geo-storage in tight fractured rocks.

Three-dimensional core reconstruction and performance evaluation of CO2 displacement in a tight oil reservoir

In this study, a three-dimensional tight sandstone core was reconstructed digitally using serials thin sections cut from a core sample used in laboratory carbon dioxide (CO2) flooding experiments. Based on the digital core, multiphase flow simulations were carried out to evaluate the performance of three prior laboratory-tested injection strategies: CO2 continuous injection, water alternative gas (WAG: CO2) injection, and cyclic CO2 injection. The chosen image-based reconstruction led to a close porosity and permeability match with the sampled core in an economical way. The numerical evaluation closely replicated the laboratory-tested procedures, thus providing realistic fluid distributions before CO2 injection. To determine saturation functions for CO2 injection after water flooding, sensitivities of endpoint relative permeability and capillary pressure to CO2 continuous injection were quantified. Water relative permeability was identified as a key factor. The saturation functions were used in a history match between simulations and laboratory data where close agreements were observed for all three CO2 injection strategies. Then critical enhanced oil recovery (EOR) operational parameters (soaking time, slug ratio, cycle size, and test duration) were optimized to maximize CO2 displacement performance, which led to the following observations: (1) While extended soaking after CO2 continuous injection increased incremental oil recovery, such increase was limited due to concurrent soaking during low-rate CO2 injection. (2) In WAG injection, CO2 and brine slug sizes and ratios were optimized: increasing the cycle size performed better than adjusting the slug ratio for favorable mobility control and efficient CO2 EOR. (3) For cyclic CO2 injection, the total CO2 injection volume was the most important factor, followed by the number of cycles, to allow CO2 diffusion into tight core to maximize the swept pore volumes. The history-matched simulations suggest that both WAG and cyclic CO2 injection can achieve high displacement effectiveness for the tight reservoir, compared with that achieved with slight soaking after CO2 continuous injection. The injected brine slugs in the WAG injection reduced the CO2 needed at the expense of reduced storage capacity. Compared to WAG, cyclic CO2 injection, though realizing the highest oil recovery and gas storage, requires more CO2.

Competition adsorption of CO2/CH4 in shale: Implications for CO2 sequestration with enhanced gas recovery

The competitive adsorption of CO2/CH4 mixtures in shale is a prerequisite for optimizing the process of CO2 sequestration in shale with enhanced gas recovery (CO2-ESGR). In this study, pure and binary adsorption of CH4 and CO2 in shale was measured at pressures up to 13 MPa and the temperature of 323.15 K using volumetric method. Pure and binary adsorption showed that CO2 is preferentially adsorbed in shale, and the adsorption amount of binary CO2/CH4 increased with the increase of CO2 composition. The selectivity factor of CO2 over CH4 (SCO2/CH4) in all the tested samples is greater than 1 and closely related to the pressure and CO2/CH4 concentration, as well as the CO2 phase state. SCO2/CH4 generally decreased with the increase of pressure in the case of 50%CH4 + 50%CO2, while first decreased and then increased with the increase of pressure in the cases of 25%CH4 + 75%CO2 and 75%CH4 + 25%CO2 for most of the tested shale samples. The SCO2/CH4 for most of tested shale samples in the case of 50%CH4 + 50%CO2 is the largest, and the SCO2/CH4 in the case of 75%CH4 + 25%CO2 is greater than that in the case of 25%CH4 + 75%CO2, indicating that the SCO2/CH4 initially increased then decreased with the increase of CO2 fraction. Thus, the CO2 is suggested to be injected when the reservoir pressure reduced to a certain level, and the injection pressure, rate and amount of CO2 should be optimized, to obtain an optimal SCO2/CH4 to improve the efficiency of CO2-ESGR and maximize the CO2 storage capacity. Furthermore, the binary CO2 and CH4 adsorption data were predicted using various models. The Ideal Adsorption Solution Theory (IAST) model fitted the experimental adsorption data the best, followed by the Extended Langmuir (E-L) and Loading Ratio Correlation (LRC). The results provide a firm basis for optimizing the CO2 injection strategies and estimating CO2 storage potential for CO2-ESGR operation.

Gridding Effects on CO2 Trapping in Deep Saline Aquifers

Three-dimensional numerical models of potential underground storage and compositional simulation are a way to study the feasibility of storing carbon dioxide in the existing geological formations. However, the results of the simulations are affected by many numerical parameters, and we proved that the refinement of the model grid is one of them. In this study, the impact of grid discretization on CO2 trapping when the CO2 is injected into a deep saline aquifer was investigated. Initially, the well bottom-hole pressure profiles during the CO2 injection were simulated using four different grids. As expected, the results confirmed that the overpressure reached during injection is strongly affected by gridding, with coarse grids leading to non-representative values unless a suitable ramp-up CO2 injection strategy is adopted. Then, the same grids were used to simulate the storage behavior after CO2 injection so as to assess whether space discretization would also affect the simulation of the quantity of CO2 trapped by the different mechanisms. A comparison of the obtained results showed that there is also a significant impact of the model gridding on the simulated amount of CO2 permanently trapped in the aquifer by residual and solubility trapping, especially during the few hundred years following injection. Conversely, stratigraphic/hydrodynamic trapping, initially confining the CO2 underground due to an impermeable caprock, does not depend on gridding, whereas significant mineral trapping would typically occur over a geological timescale. The conclusions are that a fine discretization, which is acknowledged to be needed for a reliable description of the pressure evolution during injection, is also highly recommended to obtain representative results when simulating CO2 trapping in the subsurface. However, the expedients on CO2 injection allow one to perform reliable simulations even when coarse grids are adopted. Permanently trapped CO2 would not be correctly quantified with coarse grids, but a reliable assessment can be performed on a small, fine-grid model, with the results then extended to the large, coarse-grid model. The issue is particularly relevant because storage safety is strictly connected to CO2 permanent trapping over time.

Performance Evaluation of CO2 Soaking and Flooding Processes in Tight Oil Reservoirs

CO2 injection has been proven to be an effective method to improve oil recovery of tight oil reservoirs. CO2 soaking and flooding are common processes used to constitute some CO2 injection patterns. To investigate the difference of oil recovery performance and asphaltene precipitation distribution between CO2 soaking and CO2 flooding processes, CO2 soaking and flooding tests under immiscible and miscible conditions were carried out with tight core samples. Then the NMR technique was utilized to analyze the microscopic remaining oil distribution and the asphaltene precipitation distribution after each test. The results indicated that the oil recovery in the small pores less than 0.6 μm was more influenced by the injection pressure, while the oil recovery in the large pores larger than 0.6 μm was more influenced by injection patterns. On the other hand, the asphaltene precipitation degree in different pores is usually relevant to oil recovery. In the large pores, the asphaltene precipitation degree of the soaking process was much lower than that of CO2 flooding by 8.02 and 19.76% under immiscible and miscible conditions, respectively. In the small pores, the asphaltene precipitation degree of the soaking process was higher than that of CO2 flooding by about 4%. Moreover, as injection pressure increased, the asphaltene precipitation caused by the soaking process was much less than that caused by CO2 flooding. The results of the study can provide some theoretical support to determine a better CO2 injection strategy for tight oil reservoirs with different characteristics.

Evaluating CO2 breakthrough in a shaly caprock material: a multi-scale experimental approach

The potential of underground CO2 storage relies on the sealing efficiency of an overlaying caprock that acts as a geological barrier. Shales are considered as potential caprock formations thanks to their favourable hydro-mechanical properties. In this work the sealing capacity of Opalinus Clay shale to CO2 injection is studied by means of capillary entry-pressure and volumetric response. The overall objective of this work is to contribute to the safe design of a CO2 injection strategy by providing a better understanding of the geomechanical response of the caprock material to CO2 injection and eventual breakthrough at different scales. This is achieved by relating lab-measured hydro-mechanical properties of the studying caprock material (porosity, permeability, volumetric response) to field-related parameters (effective stress, injection pressure). A number of CO2 breakthrough tests is performed in Opalinus Clay samples under two different scales, meso and micro. At the meso-scale, CO2 injection is performed in oedometric conditions under different levels of axial effective stress in both gaseous or liquid phase. In parallel, the material’s transport properties in terms of water permeability are assessed before CO2 injection at each corresponding level of effective stress. The impact of CO2 phase and open porosity on the material’s CO2 entry pressure are demonstrated. The correlation between measured entry pressure and absolute permeability is discussed. A second testing campaign at a smaller scale is presented where CO2 breakthrough is for the first time identified with in-situ X-ray tomography. CO2 injection is performed under isotropic conditions on an Opalinus Clay micro-sample (micro-scale), and CO2 breakthrough is identified through quantitative image analysis based on the measured localised volumetric response of the material. This innovative methodology provides important insight into the anisotropic response of this complex material that is indispensable for its representative modelling in the context of safe geological CO2 storage.

Microscopic transport and phase behaviors of CO2 injection in heterogeneous formations using microfluidics

CO2 injection into the geological formations is a promising option to enhance oil recovery while simultaneously contributing to carbon storage. Conventional core tests provide critical insights but still leave ambiguous transport mechanisms due to the limitation of real-time visualization. This study aims to directly observe the multiphase flow behaviors and phase change in CO2 injection at pore-scale using microfluidics. Our all-in-one chip design provides a universal platform to reproduce various CO2 injection strategies in the formation with permeability contrast, including flooding and huff-n-puff processes, and integrated a rapid measurement of minimum miscibility pressure (MMP). Miscible injection eliminates the capillary force in immiscible scenario, and promotes stable film-wise displacement with a higher recovery rate and an attenuated heterogeneity impact. We find that effective huff-n-puff operations require a sufficient gas concentration to generate bubbles and an adequate pressure gradient to push the dissolved gas displacement, which supports the importance of high depressurization rate from both physical phenomenon and inherent mechanism. Huff-n-puff re-energizes the reservoir after immiscible flooding through deep gas-oil interactions and induces a considerable growth in cumulative recovery. These micromodel results can significantly improve our fundamental understanding on detailed multiphase transport phenomena in CO2 injection and help to optimize implementation schemes.

Analysis of Vertical Permeability and Its Influence on CO2 Enhanced Oil Recovery and Storage in a Carbonate Reservoir

Summary The objective of this study is to improve understanding of the geostatistics of vertical (bed-normal) permeability (kz) and its influence on reservoir performance during CO2 enhanced oil recovery (EOR) and storage. kz is scrutinized far less often than horizontal permeability (kx, ky) in most geological and reservoir modeling. However, our work indicates that it is equally important to understand kz characteristics to better evaluate their influence on CO2 EOR and storage performance prediction. We conducted this study on approximately 9,000 whole-core triaxial permeability (kx, ky, kz) measurements from 42 wells in a San Andres carbonate reservoir. We analyzed kz data, including heterogeneity, correlation, and sample sufficiency measures. We analyzed wells with the largest and smallest fractions of points with kz > kmax = max(kx, ky) to explore geological factors that coincided with large kz. We quantified these geological effects through conditional probabilities on potential permeability barriers (e.g., stylolites). Every well had at least some whole cores where kz > kmax. This is a statistically justifiable result; only where Prob(kz > kmax) is statistically different from 1/3 are core samples nonisotropic. In conventional core data interpretation, however, modelers usually assume kz is less than kmax. For the well with the smallest fraction (11%) of cores where kz >kmax, the cumulative distribution functions (CDFs) differ and coincide with the presence of stylolites. We found that kz is approximately twice as variable as kx in many wells. This makes kz more difficult to interpret because it was (and usually is) heavily undersampled. To understand the influence of kz heterogeneity on CO2 flow, we built a series of flow simulation models that captured these geostatistical characteristics of permeability, while considering kz realizations, flow regimes (e.g., buoyant flow), CO2 injection strategies, and reservoir heterogeneity. CO2 flow simulations showed that, for viscous flow, assuming variable kx similar to the reservoir along with a constant kz/kx = 0.1 yields a close (within 0.5%) cumulative oil production to the simulation case with both kx and kz as uncorrelated variables. However, for buoyant flow, oil production differs by 10% [at 2.0 hydrocarbon pore volume (HCPV) of CO2 injected] between the two cases. Such flows could occur for small CO2 injection rates and long injection times, in interwell regions, and/or with vertically permeable conduits. Our geostatistical characterization demonstrates the controls on kz in a carbonate reservoir and how to improve conventional interpretation practices. This study can help CO2 EOR and storage operators refine injection development programs, particularly for reservoirs where buoyant flow exists. More broadly, the findings potentially apply to other similar subsurface buoyancy-driven flow displacements, including hydrogen storage, geothermal production, and aquifer CO2 sequestration.

Numerical Simulation and Optimization of CO2-Enhanced Gas Recovery in Homogeneous and Vertical Heterogeneous Reservoir Models

Abstract CO2-enhanced gas recovery (CO2-EGR) is a promising, environment-friendly technology to produce more natural gas from depleted reservoirs and simultaneously sequester CO2. The subsurface flow in the heterogeneous reservoir is usually different from homogenous one, and the heterogeneity significantly affects the gas recovery. The effects of heterogeneity and the optimization of CO2 injection strategy are the key factors in CO2-EGR. Thus, one of the goals of this paper is to conduct simulations of CO2-EGR in both homogeneous and heterogeneous reservoirs to evaluate the effects of reservoir heterogeneity on CO2-EGR. The second goal is to perform optimization studies to determine optimal CO2 injection time and injection rate for achieving optimal natural gas recovery. The CO2-EGR simulations were conducted in a 3D reservoir model with a 'five-spot' well pattern by using the multi-phase simulator TOUGH2. The results show that the layers with low permeability as well as gravity segregation retard upward migration of CO2 and promote horizontal displacement efficiency. The breakthrough time of CO2 and reservoir space of underexploited natural gas directly affect the gas recovery. The optimal injection time is determined as the depleted stage, and the corresponding injection rate is optimized by using a genetic algorithm (GA) integrated with TOUGH2. The optimization of CO2 injection parameters leads to recovery factors (RFs) reaching 62.83% and 64.75% in the homogeneous and heterogeneous cases while simultaneously obtaining the economic benefit of about 8.67 and 8.95 million USD. This study shows significant economic potential as well as environmental benefits of using CO2-EGR in the depleted gas reservoir by optimizing the CO2 injection parameters. The findings of this work could assist in determining the optimal injection strategy for using CO2-EGR in industrial scale gas reservoirs.

Relative Permeability Hysteresis and Capillary Trapping during CO2 EOR and Sequestration

Residual or capillary trapping is an important mechanism of CO2 trapping in underground porous media. Recent experimental investigation has shown that relative permeability and capillary pressure are function of saturation changing direction or hysteresis phenomenon in addition to the saturation and hysteresis leads to irreversible change in relative permeability and capillary pressure curve. In this paper, an extended review was performed on the relative permeability hysteresis models. Moreover, an experimental investigation was conducted during CO2 injection as the non–wetting phase in carbonate rocks at pressure and temperature of 10.3 MPa and 60 ℃. In this study, the effects of absolute permeability of carbonate rock samples and CO2 injection strategy on hysteresis phenomenon in the CO2 residual trapping process were investigated. During first part of experiments, CO2 relative permeability was examined during CO2 injection and brine injection at constant rate of 0.2 cc/min as drainage and imbibition process for different absolute permeability of rock samples. During second part of experiments, CO2 trapping saturation was calculated during the continuous CO2 injection and CO2 Water Alternative Gas (WAG) injection. Results of first part of experiments showed that increasing of the absolute permeability leads to increasing initial and residual CO2 saturation at the end of drainage and imbibition process, respectively. Moreover, it was concluded that increasing rock permeability results in increasing of the hysteresis effect on the CO2 relative permeability. In the second part of experiments, results revealed that CO2 WAG injection strategy has higher CO2 residual saturation in compared to CO2 continuous injection at equal pore volume of injected CO2. The findings of this paper can be applied for investigating of CO2 sequestration projects in aquifers for improvements of CO2 residual trapping and studying the performance of capillary trapping as one of the main mechanisms of CO2 trapping.

Numerical simulation and optimization of injection rates and wells placement for carbon dioxide enhanced gas recovery using a genetic algorithm

The aim of CO2 enhanced gas recovery (CO2-EGR) is to extract more natural gas from depleted gas reservoirs and simultaneously sequestrate large amount of CO2. To achieve these dual objectives, the optimization of CO2 injection strategy in CO2-EGR is proposed to achieve maximum benefit. Thus, the focus of this work is to study CO2-EGR by numerical simulation and optimization. For this purpose, a 3D reservoir model with ‘five-spot’ well pattern (an injection well and four production wells) is established for simulations using the multiphase simulator TOUGH2, and the main focus is on optimization of CO2 injection rate and well placements by coupling the genetic algorithm (GA) with TOUGH2. Simulations are performed to determine the optimal injection rate for both two types of injection wells placements, one vertical injection well with number of perforations at various depth and orthogonal horizontal wells on top of the reservoir. The results show that multipoint perforations in the vertical injection well and the horizontal injection wells with appropriate length show improvement in natural gas recovery and CO2 storage compared to the injection location at the reservoir bottom. More importantly, the optimized injection rate determined by GA-TOUGH2 can substantially improve the natural gas recovery factor for both vertical and horizontal well injection. After computing a number of optimized cases, it’s shown that the case employing the horizontal injection wells with optimized injection rate of 0.0778 kg/s achieves the maximum recovery of 67.21% and maximum CO2 storage efficiency of 69.54%, equal to 23.88 × 106 kg of natural gas exploited from the depleted reservoir and 74.52 × 106 kg of CO2 stored in pore volume of 1.81 × 106 m3 of the reservoir. This case also has minimum injection pressure jump of 0.08 MPa thereby reducing the risk of formation fracture and CO2 leakage. However, by conducting a simple cost/benefit analysis, it is determined that this optimally performing case is not the best economically because of higher drilling cost of horizontal well compared to a vertical well. It is found that a vertical well with two suitably placed perforations with optimized injection rate of 0.1025 kg/s is economically superior since the previously used production wells can be reused for CO2 injection, which can therefore reduce both the equipment and the drilling costs. It is hoped that the findings of this work should provide some insights into the optimization of CO2-EGR with maximum economic benefit for implementation in industrial practice.

CO2 injection strategies for enhanced oil recovery and geological sequestration in a tight reservoir: An experimental study

Considering the worldwide development of tight and ultra-tight oil reservoirs, the increasing demand for fossil energy and long-term environmental concerns regarding large CO2 emissions, application of dual-purpose carbon dioxide (CO2) sequestration/enhanced oil recovery in oil reservoirs has gained considerable attention [1,2]. However, unlike its mature application in conventional reservoirs, the effectiveness of CO2 EOR and geological sequestration in tight reservoirs is still under investigation [3]. In this work, we investigated the efficiency of different injection strategies on simultaneous CO2 EOR and storage in ultra-low permeability (<1 milli-Darcy) [4] core samples from Yanchang Formation in the Ordos Basin, China. Three injection strategies were tested including gas continuous flooding, water alternative gas injection, and cyclic gas injection. Core-flooding experiments under immiscible and miscible conditions were conducted. Furthermore, to investigate underlying mechanisms of oil recovery and carbon storage in tight cores, interfacial tension tests, viscosity measurements, contact angle measurements, and constant composition expansion tests were performed using reservoir rock and fluids. We found that water alternative gas injection was superior to continuous gas injection in achieving the goal of simultaneous high oil recovery and high CO2 storage. However, cyclic CO2 injection provided the most efficient strategy for enhanced oil recovery in the tight rocks studied in this work with a comparatively higher gas storage capacity than the other injection strategies.

A modeling and numerical simulation study of enhanced CO2 sequestration into deep saline formation: a strategy towards climate change mitigation

The net increase in anthropogenic carbon dioxide (CO2) emissions from fossil fuel combustion contributes significantly to the global warming and climate change. CO2 capture and storage (CCS) in geological formations, specifically in deep saline aquifers, is among the very promising strategies to control and mitigate emissions into the atmosphere. Injection of CO2 into a reservoir may result in the formation of pore pressure which can initiate cracks and trigger fault activities. CO2 may leak into the atmosphere and invade shallow groundwater sources. Release of CO2 into the atmosphere has enormous effects on the environment and significantly contributes to global climate change. Therefore, storage safety, injection efficiency, and monitoring remain crucially important considerations in CO2 injection. This study attempts to establish an optimal CO2 injection strategy that aims at enhancing CO2 storage with an increased safety at Ordos basin. Furthermore, it establishes the safety limits of CO2 plume migration from the central axis of the injection well. In the investigation, injection parameters such as injection rate and bottom hole pressure were analyzed. The CO2 plume migration analysis was performed, and migration limits were determined. Simulation results revealed that different formation layers have varying storage capacities and pressure withstanding ability. The site maximum storage rate goal of storing 100,000 t of CO2 per year was attained. It is advised to perform injection at the Majiagou layer due to sufficient storage capacity and greater depth of over 2400 m from the surface. This study recommends that an optimum CO2 sequestration strategy which does not result into excessive migration of injected CO2 plume and limit formation pressure buildup should be adopted. Therefore, deep underground storage at an average depth of above 2400 m is optimum, because it has an adequate storage space to accommodate the desired rate of 100,000 t/year. Besides, its geological settings favor storage safety in the event of significant uplift that may cause induced seismicity. Furthermore, it will also limit CO2 plume that may come into contact with shallow groundwater sources. Likewise, investing in low carbon and carbon-free energy technologies and enhancement of energy efficiency systems around the site is also recommended.