CO2 Breakthrough Research Articles

A Cluster Based Cooperative Kinetic Model for CO2 Adsorption on Amine Functionalized Metal–Organic Frameworks

A new model for the adsorption kinetics of CO2 on amine functionalized metal–organic frameworks Mg2 (dobpdc) and Mn2 (dobpdc) is proposed. The equilibrium adsorption is evaluated using the cooperative lattice theory of Kundu et al. The lattice theory provides a microscopic interpretation of adsorption behavior on the basis of the state of adsorbed CO2: singly adsorbed, chain ends, and chain interiors. On this basis, the proposed kinetic model accounts for the kinetics of singly adsorbed CO2, as well as the kinetics of adsorption into chains. These two kinetic paths have separate yet coupled rate laws. This allows for the accurate description of complex kinetic phenomena observed in low partial pressure CO2 breakthrough curves on mmen-Mg2 (dobpdc). In addition to good numerical agreement with measured data, the approach developed in this work provides a needed microscopic interpretation of measured kinetic data in these systems. This microscopic picture may allow for more targeted material design and a pathway to include additional factors such as the effect of humidity on CO2 adsorption and kinetics.

The potential of direct air capture using adsorbents in cold climates.

Global warming threatens the entire planet, and solutions such as direct air capture (DAC) can be used to meet net-zero goals and go beyond. This study investigates using DAC in a 5-step temperature vacuum swing adsorption (TVSA) cycle with adsorbents' Li-X and Na-X, readily available industrial zeolites, to capture and concentrate CO2 from air in cold climates. From this study, we report that Na-X in cold conditions has the highest known CO2 adsorption capacity in air of 2.54mmol/g. This combined with Na-X's low CO2 heat of adsorption, and fast uptake-rate in comparison to other benchmark materials, allowed for Na-X operating in cold conditions to have the lowest reported DAC operating energy of 1.1 MWh/tonCO2. These findings from this study show the promise of this process in cold climates of Canada, Alaska, Greenland, and Antarctica to be part of the solution to global warming.

Hybrid Carbonated Engineered Water as EOR Solution for Oil-Wet Carbonate Formation

Carbonated water has proven advantages over conventional CO2 injection in terms of arresting free CO2 mobility, low-pressure injection, lower volume requirement, and higher efficiency. The term “engineered water” is designated to selective ion-spiked injection water with the advantage of the ion-exchange reactions with the rock minerals and releasing trapped oil. This article investigated the synergic effect of dissolved CO2 and engineered water for oil recovery and understanding inner mechanisms. Recovery efficiencies were evaluated through coreflood studies, which revealed that the hybrid water could recover 6–10% more oil than engineered water and about 3% more than carbonated water. HP-HT pendant-drop studies show the insignificance of IFT reduction. Wettability change from oil wet to near-water wet is attributed as a significant factor. The dissolution of Ca2+ and Mg2+ and deposition of SO42− observed in coreflooding may have a significant contribution to oil recovery. Pore enlargement evidenced in NMR-PSD and NMR-ICP results support this claim. The study confirmed that the EWI-CWI hybrid technique could be a promising EOR method, eliminating the requirement for high-pressure injection, the problems of gravity segregation, and the early breakthrough of CO2. It can also be an effective EOR solution, providing a significant cost advantage and higher oil recovery in addition to the environmental benefits of CO2 sequestration.

Thermo-/pH-Dual-Sensitive PEG/PAMAM Nanogel: Reaction Dynamics and Plugging Application of CO2 Channeling.

Smart hydrogels, owing to their exceptional viscoelastic and deformable capacity in response to environmental stimulation involving temperature and pH, have been successfully applied in oilfields for purposes such as water and/or gas shutoff treatments. However, the CO2 breakthrough problem in low permeability reservoirs has not been well solved. In this work, a rheological method-based Avrami dynamics model and Dickinson dynamics model were employed to investigate the dynamic gelation process of thermo-/pH-dual-sensitive PEG/PAMAM nanogels to further our understanding of the microstructure of their gelation and pertinence plugging application. Plugging experiments were performed by alternating injections of CO2 and hydrogel solution in a slug type on three fractured low permeability cores with a backpressure of 13 MPa. The nanogels presented a secondary growth pattern from three to one dimension from micrometer to nanometer size with a morphological transformation from a sphere to an irregular ellipsoid or disk shape. The phase transition temperature was 50 °C, and the phase transition pH was 10. If both or either were below these values, the hydrogel swelled; otherwise, it shrank. Plugging results show that the plugging efficiency was higher than 99%. The maximum breakthrough pressure was 19.93 MPa, and the corresponding residual pressure remained 17.64 MPa for a 10 mD core, exhibiting great plugging performance and high residual resistance after being broken through by CO2.

Biogas upgrading to natural gas pipeline quality using pressure swing adsorption for CO2 separation over UiO-66: Experimental and dynamic modelling assessment

Biogas upgrading (CO2 removal) is an important process to produce biomethane that meets the fuel quality standards or pipelines injection specifications. Assessment of microporous UiO-66 as a potential adsorbent for CO2 removal from biogas was performed to gauge the viability of the media for methane purification and CO2 removal in pressure swing adsorption under non-isothermal conditions. UiO-66 was synthesized and characterized using various analysis tools such as SEM, BET, FTIR, XRD, TGA, particle size distribution, and TPD. A dynamic model for the proposed PSA system was built to study the effects of some parameters i.e., outside temperature, length/diameter ratio, and CO2 feed concentration on the purity and recovery of the product gases. The developed model was validated by comparing the simulation and experimental data from CH4 and CO2 breakthrough curves under similar operating conditions and adsorption bed geometry. A central composite design method was employed to optimize and examine the interaction effects of the studied parameters on the PSA system. The results confirmed the high separation performance of the PSA system using UiO-66 adsorbent with bioCH4 purity of 98.2 % and recovery of 94.68 %. The RSM model showed that the studied parameters possessed significant effects on PSA performance. The optimized parameters for achieving maximum purity and recovery were operating temperature of 290 K, length/diameter ratio of 5.6 and CO2 concentration of 39 %. Under those optimized conditions, the PSA cycle over UiO-66 recorded a purity of 99.99 %, recovery of 99.99 %, and system productivity of 8.57 mol/kg.hr.

Selective CO2/CH4 Separation by Fixed-Bed Technology Using Encapsulated Ionic Liquids

The performance of encapsulated ionic liquid (ENIL) sorbents has been experimentally evaluated in CO2/CH4 separation by means of gravimetric and fixed-bed measurements. Six ionic liquids (ILs) with CO2 chemical absorption ([Emim][Acetate], [Bmim][Acetate], [P66614][CNPyr], [Bmim][GLY], [Bmim][MET], and [Bmim][PRO]) were selected for the selective separation of CO2 from CH4. ENIL materials were prepared by encapsulation of these ILs in synthesized carbon submicrocapsules, achieving a ∼70% in mass of IL. Fixed-bed experiments of CO2 capture were carried out to evaluate the CO2/CH4 separation performance of prepared ENIL materials at different CO2 partial pressures and 303 K. Both thermodynamics and kinetics of CO2 sorption were analyzed. The experimental CO2 and CH4 isotherms in ENIL materials obtained from fixed-bed experiments were successfully compared to those obtained by reliable gravimetric tests and fitted to the Langmuir–Freundlich equilibrium model. In addition, experimental CO2 breakthrough curves were well-described by the linear driving force and Yoon and Nelson kinetic models, providing sorption rate constants. ENIL sorbents show high CO2 uptake capacity, comparable to conventional adsorbents, but with drastically higher selectivity, in concordance with the negligible CH4 solubility in ILs at the used operating conditions, with acetate-based ENIL materials being the best sorbents in thermodynamic terms. The obtained kinetic parameters revealed that the CO2 chemical sorption with ENIL materials overcomes the IL mass transfer limitations. The sorption rates are faster than those obtained with ENIL using IL physical absorbents and seem to be controlled by the reaction kinetics. The [P66614][CNPyrr]-based ENIL is found to be the most promising material, combining favorable kinetic and thermodynamic considerations for future development of CO2/CH4 separation using fixed-bed technology.

Study on CO2–Water Co-Injection Miscible Characteristics in Low-Permeability Near-Critical Volatile Oil Reservoir

Low-permeability near-critical volatile reservoirs are characterized by light oil, complex fluid phase, and strong reservoir inhomogeneity, etc. Purely injecting CO2 will create a series of problems, such as serious gas channeling, low sweep efficiency, and low oil recovery. Therefore, in this paper, through a combination of experiments and simulations and in the process of studying the problem from simple to complex, we carried out phase equilibrium experiments for CO2-near-critical volatile oil and CO2-near-critical volatile oil-formation water, as well as experiments for minimum miscible pressure of slim-tube with pure CO2 and CO2–water co-injection to the comparative study of the miscible characteristics and displacement oil efficiency between pure CO2 injection and CO2–water co-injection. It provides an important reference for improving oil recovery by CO2–water co-injection in low-permeability near-critical volatile reservoir. The results of CO2-near-critical volatile oil/CO2-near-critical volatile oil-formation water phase equilibrium experiments show that the saturation pressure, density, and gas–oil ratio of the system increase, and the viscosity decreases with the increase in CO2 injection. In the three-phase system of CO2-near-critical volatile oil-formation water, the CO2 content in the flash gas of crude oil, gas–oil ratio, and gas–water ratio are negatively correlated with the water saturation. The results of slim-tube experiments and simulations on the miscible characteristics and displacement oil efficiency of pure CO2 injection and CO2–water co-injection show that the recovery degree of crude oil under CO2–water co-injection is higher than that of pure CO2 injection, and the CO2 dissolved transition section in oil and gas is shorter and the gas breakthrough time is later under CO2–water co-injection, which effectively increases the sweep efficiency and improves the degree recovery of crude oil. When CO2–water co-injection, the ratio of water is higher, the later the gas–oil ratio rises, the later the CO2 breakthrough, and the higher the degree of crude oil recovery. It indicates that when CO2–water co-injection, the ratio of water is higher, the more CO2 is dissolved in water, which effectively inhibits the occurrence of gas channeling and increases the sweep area, thus improving the degree recovery of crude oil. The research results of this paper provide an experimental basis and theoretical foundation for CO2–water co-injection for enhanced crude oil recovery in low-permeability near-critical volatile reservoirs.

Experimental and simulation study of CO2 breakthrough curves in a fixed-bed adsorption process

This paper focuses on the laboratory experiments of low-temperature adsorption of CO2 at elevated pressure and on the validation of our mathematical model with the data obtained. The numerical approach uses fitting of adsorption isotherm parameters and sensitivity analysis of parameters influencing the breakthrough curve shape and onset time. We first evaluate the results of breakthrough experiments for zeolite 13X. Then, we use the results obtained to design a dynamic mathematical model to predict the breakthrough curve profile. Experimental results show that zeolite 13X possesses high adsorption capacities (over 10 % of its weight at adsorption temperatures of 293 K and below), as expected. The mathematical simulation was accurate at predicting the breakthrough onset time; however, this prediction accuracy declined with the outlet CO2 concentration exceeding 75 %, which is discussed. The sensitivity analysis indicated that the choice of different estimates of mass transport and bed porosity, as well as the choice of numerical scheme, can lead to a more accurate prediction, but the same set of parameters is not suitable for all process conditions.

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.

CO2-responsive gel particles and wormlike micelles coupling system for controlling CO2 breakthrough in ultra-low permeability reservoirs

CO2 flooding in ultra-low permeability reservoirs is an effective means to boost oil production, while the complex fractures formed by fracturing in the initial development stage induce severe CO2 channeling. Therefore, a CO2-responsive coupling system, which coupled CO2-responsive gel particles (CRPGP) with CO2-responsive wormlike micelles (CTWM) was prepared to restrain CO2 breakthrough. To testify the EOR capacity during CO2 flooding of the responsive coupling system, the interaction between CRPGP and CTWM, and responsiveness of coupling system was investigated, followed by core flooding and rock slab flooding experiments. Experiment results showed that after the coupling system was exposed with CO2, the particle size of CRPGP increased, spherical micelles of CTWM transformed to wormlike micelles, CRPGP and CTWM were integrated through hydrophobic association among wormlike micelles and hydrophobic chains in CRPGP, and the coupling system’s apparent viscosity increased from 10.4 mPa·s to 2339 mPa·s. Moreover, 0.5 pore volume (PV) CO2-responsive coupling system injection and further CO2 flooding could dramatically boost oil production in fractured cores and rock slabs, which was primarily ascribed to the aggrandizement of sweeping volume resulting from the plugging effect of CRPGP and mobility ratio improvement of the coupling system. Compared with single slug plugging of fractures, multi-stage regulation of fractures could establish a higher-pressure gradient, and more crude oil in the matrix was activated with enhanced oil recovery (EOR) of 22.8%. All the experimental results demonstrated that the CO2-responsive coupling system has great EOR capacity during CO2 flooding, which provided novel insights for ultra-low permeability reservoirs EOR technology that incorporated with CO2 resource utilization and storage.

Displacement characteristics of CO2 flooding in extra-high water-cut reservoirs

Carbon dioxide (CO2) flooding is a widely applied recovery method during the tertiary recovery of oil and gas. A high water saturation condition in reservoirs could induce a ‘water shielding’ phenomenon after the injection of CO2. This would prevent contact between the injected gas and the residual oil, restricting the development of the miscible zone. A micro-visual experiment of dead-end models, used to observe the effect of a film of water on the miscibility process, indicates that CO2 can penetrate the water film and come into contact with the residual oil, although the mixing is significantly delayed. However, the dissolution loss of CO2 at high water-cut conditions is not negligible. The oil-water partition coefficient, defined as the ratio of CO2 solubility in an oil-brine/two-phase system, keeps constant for specific reservoir conditions and changes little with an injection gas. The NMR device shows that when CO2 flooding follows water flooding, the residual oil decreases—not only in medium and large pores but also in small and micro pores. At levels of higher water saturation, CO2 displacement is characterized initially by a low oil production rate and high water-cut. After the CO2 breakthrough, the water-cut decreases sharply and the oil production rate increases gradually. The response time of CO2 flooding at high water-cut reservoirs is typically delayed and prolonged. These results were confirmed in a pilot test for CO2 flooding at the P1-1 well group of the Pucheng Oilfield. Observations from this pilot study also suggest that a larger injection gas pore volume available for CO2 injection is required to offset the dissolution loss in high water saturation conditions.

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

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

An insight into CO2 sequestration and EGR in Longmaxi and Niutitang shale formations via experimental analysis

In the global effort toward climate change mitigation, geologic storage of CO2 in shale plays is becoming critical while it can improve production from these reservoirs. In this study, the gas storage capacity and CO2 sequestration suitability of the Longmaxi and Niutitang shale gas reservoirs is investigated and compared via XRD analysis, programmed pyrolysis, low pressure N2 and CO2 adsorption, high pressure CH4 adsorption, and MICP analysis. Results showed that clay and TOC controls on micropore heterogeneity and connectivity happens only within the Longmaxi Formation. Furthermore, both components play a role in the adsorbed quantities of gas in the formation which revealing a higher storage capacity in mesopore-macropores. This was verified by a positive correlation between adsorbed volume within the mesopore-macropore space. The Longmaxi Formation was also found to own better pore connectivity and PSD homogeneity of mesopore-macropores, indicating easier pathways for CO2 movement channels within the pore network. Furthermore, the samples from the Longmaxi exhibited a positive relationship between adsorbed volume with the CO2 breakthrough pressure and median pore diameter, alike between the mesopore-macropore volume and CO2 breakthrough pressure. This means, the injected CO2 will displace adsorbed methane within the mesopore-macropore and will be adsorbed and stored in such pores. Overall, superiority of the Longmaxi shale over the Niutitang for CO2 storage and EGR would be significant for future operations in similar shale gas reservoirs in China and around the globe.

Granulation of alkaline metal nitrate promoted MgO adsorbents and the low-concentration CO2 capture performance in the fixed bed adsorber

Magnesium-based adsorbents with the modification of alkaline metal salts are considered the competitive candidates for CO2 capture at intermedium temperature. In this article, the NaNO3 promoted MgO adsorbents were prepared and granulated, and the characterization methods were used to detect the microstructure of the granular adsorbents, including NaNO3 distribution, BET specific surface area, micropore size and microcrystal aggregation. The thermogravimetric analyzer (TGA) tests were carried out to investigate the optimal CO2 adsorption and desorption temperatures and the cyclic stability of the NaNO3 promoted MgO granules. Moreover, the pretreatment of carbonization and calcination was adopted to improve the cyclic stability of the granular adsorbents. Furthermore, the fixed bed adsorber with 40 g NaNO3-MgO granules was used to capture CO2 from 50% CO2 mixture gas with N2 and from 20% CO2 mixture gas with N2, respectively, and the CO2 breakthrough behaviors in the fixed bed were investigated. It was found that NaNO3-MgO adsorbents were suitable for the middle and high-concentration CO2 capture (such as 50% CO2 feed gas) in fixed bed adsorber with the higher CO2 recovery efficiency, but the CO2 recovery efficiency was lower for the low-concentration CO2 capture (such as 20% CO2 feed gas) at ordinary pressure. Because about 10 kPa CO2 partial pressure in the gas phase was needed to overcome CO2 mass transfer resistance in the molten salt layer on MgO surface during adsorption, the appropriate pressurization would improve the low-concentration CO2 capture efficiency in the fixed bed adsorber.

Injectivity and plugging characteristics of CO2-responsive gel particles for enhanced oil recovery in fractured ultra-low permeability reservoirs

Although CO2-responsive gel particles (CRGP) injection appears to be a viable strategy for delaying CO2 breakthrough in fractured ultra-low permeability reservoirs, few studies have been conducted to thoroughly evaluate the injectivity and plugging characteristics of CRGP. In the present work, the swelling kinetics of the CRGP at various temperatures and salinities were first characterized through the change in CRGP volume. The rheology properties of CRGP dispersion solution were then evaluated. And then, taking the resistance coefficient, residual resistance coefficient and plugging rate as indexes, the effect of matching coefficient, injection rate, and injection concentration on CRGP injectivity and plugging characteristics was investigated using simulated artificial fractures. Finally, the empirical correlations of injectivity and plugging characteristics parameters were established. According to experimental result, the equilibrium swelling ratio of CRGP was greater than 40-fold at varied salinity conditions. The shear-thinning capabilities of the CRGP dispersion solution, as well as its favorable storage modulus, endowed CRGP with favorable in-depth migration and plugging properties. In addition, in terms of fracture plugging by CRGP, the plugging ratio of CRGP in fractures was higher than 90% when the matching coefficient ranged from 1.0 to 2.0, the injection rate was less than 0.5 mL/min, and CRGP concentration was larger than 3000 mg/L. The acquired empirical relationships were expected to guide the selection of CRGP size, injection concentration, and injection rate for fracture plugging.

Hydrodynamic Analysis of CO2 Migration in Heterogeneous Rocks: Conventional and Micro‐Bubble CO2 Flooding Experiments and Pore‐Scale Numerical Simulations

AbstractThe hydrodynamics of CO2 flooding determine its capacity and efficiency in CO2 geological storage; however, this is not sufficiently understood. In this study, a medical X‐ray CT was used to visualize CO2 flooding in a Berea sandstone sample, and the migration pattern and distribution of injected CO2 were carefully analyzed in a series of comparison experiments. For conventional flooding, CO2 migrated mostly along the high‐porosity and large‐pore‐size layers, leaving a large area of low‐porosity and small‐pore‐size regions undisplaced. Comparatively, before CO2 broke through, CO2 fingering developed and migrated slowly for micro‐bubble flooding, showing that CO2 micro‐bubbles infiltrated into more regions than the CO2 continuous fluid. After CO2 breakthrough began, the micro‐bubble CO2 continued to enter some previously undisplaced regions; however, this was inconspicuous for conventional flooding. Finally, micro‐bubble flooding increased CO2 saturation by 6.1% over conventional flooding. Compared to conventional flooding, an essential hydrodynamic change by micro‐bubble flooding weakened the resistance of interface tension over CO2 infiltration into the small pores. Accordingly, two types of hydrodynamic models were proposed for conventional and micro‐bubble CO2 flooding, and their simulated pore‐scale CO2 migration results in a cluster of heterogeneous pores were compatible with the aforementioned core‐scale experimental observations. According to these models, both the small sizes and high injection rates of micro‐bubble CO2 were instrumental in enhancing the displacement effect. The filter for micro‐bubble CO2 injection in our experiment achieved even injection of the small CO2 micro‐bubbles at a relatively high rate, ensuring its practical potential in field applications.

Experimental Analysis and Performance Investigation of Immiscible Super-Critical CO2 Flooding Processes in Tight Oil Reservoir

CO2 flooding, a promising technique of enhanced oil recovery, is widely used for its capability of boosting oil recovery, and reducing greenhouse gas emissions. In this study, the oil displacement performance of supercritical CO2 is tested in laboratory under immiscible flooding. The results show that: Supercritical CO2 improves oil recovery, by virtue of its low viscosity, high diffusivity, and easy dissolution. With the same pore volume (PV), supercritical CO2 flooding significantly boosted the oil recovery factor. The factor reached the maximum, when almost 1.5PV of CO2 was injected. As CO2 moved from the gas phase to the supercritical state, the oil displacement efficiency increased by 10%. To obtain the same oil recovery factor, non-supercritical flooding needed to inject more CO2 than supercritical flooding. Light hydrocarbon components (C1-7) in crude oil were gradually extracted before CO2 breakthrough, while heavy hydrocarbon components (C7+) were extracted mainly after CO2 breakthrough. In addition, supercritical CO2 flooding extracted more intermediate hydrocarbons than critical CO2 flooding. To sum up, supercritical flooding outperforms non-supercritical flooding in injection performance, oil displacement efficiency, and oil exchange rate.

Laboratory evaluation of a novel Self-healable polymer gel for CO2 leakage remediation during CO2 storage and CO2 flooding

For CO2 storage in subsurface reservoirs, one of the most crucial requirements is the ability to remediate the leakage caused by the natural fractures or newly generated fractures due to the increasing pore pressure associated with CO2 injection. For CO2 Enhanced Oil Recovery (EOR), high conductivity features such as fractures and void space conduits can severely restrict the CO2 sweep efficiency. Polymer gels have been developed to plug the leakage and improve the sweep efficiency. This work evaluated a CO2 resistant branched self-healable preformed particle gel (CO2-BRPPG) for CO2 plugging purpose. This novel CO2-BRPPG can reform a mechanical robust adhesive bulk gel after being placed in the reservoir and efficiently seal fractures. In this work, the swelling kinetics, self-healing behavior, thermal stability, CO2 stability, rheology, adhesion property and plugging performance of this novel CO2-BRPPG were studied in the laboratory. Results showed that this CO2-BRPPG has good self-healing abilities, and the self-healed bulk gel has excellent mechanical and adhesion strength. Gel with a swelling ratio of ten has an elastic modulus of over 2000 Pa, and the adhesion strength to sandstone is 1.16 psi. The CO2-BRPPG has good CO2 phase stability at 65 °C, and no dehydration was observed after 60 days of exposure to 2900 psi CO2 at 65 °C. Core flooding test proved that the swelled particles could reform a bulk gel after being placed in the fractures, and the reformed bulky gel has excellent CO2 plugging efficiency. The supercritical CO2 breakthrough pressure gradient was 265 psi/feet (5.48 MPa/m). This work could offer the experimental basis for the field application of this CO2-BRPPG in CO2 storage and CO2 enhanced oil recovery.

Amine and fluorine co-functionalized MIL-101(Cr) synthesized via a mixed-ligand strategy for CO2 capture under humid conditions

The selective capture of CO2 in humid conditions on metal–organic frameworks is challenging due to competitive adsorption of H2O and CO2 on the active sites. Herein, amine and fluorine co-functionalized MIL-101(Cr) was synthesized and evaluated for use as CO2 adsorbent to overcome this issue. MIL-101(Cr)–NH2-F0.5 (CrA-F0.5) was prepared using a mixed-ligand strategy, and contains 2.9% nitrogen and 0.5% fluorine while maintaining the MIL-101(Cr) structure. Numerically, one 4F ligand per 20 amino ligands was included in the CrA-F0.5 structure. The calculated selectivity for CO2/N2 of CrA-F0.5 is 108 (CO2/N2 = 15/85) at 20 ℃ and 1 bar, and this value was 3.7 and 2.1 times higher than that of MIL-101(Cr) and MIL-101(Cr)–NH2, respectively. The results of CrA-F0.5 adsorption of CO2 indicated that amine and fluorine groups served as adsorptive sites for CO2 in this structure. The moderate isosteric heat of CO2 adsorption value (45 kJ mol−1) of CrA-F0.5 merits in desorption of CO2. The result of a hydrophobicity index test, indicated that CrA-F0.5 was 2.5 times hydrophobic than MIL-101(Cr)–NH2. In a CO2 and N2 breakthrough test, compared to the dry condition, the CO2 breakthrough time at 30 ℃ and 1 bar was reduced by 40% for MIL-101(Cr)–NH2 and by 10% for CrA-F0.5 in 60% relative humidity. The CO2 and N2 breakthrough results under humid conditions were consistent with the hydrophobicity index value, and the excellent water repellency of CrA-F0.5 was confirmed. CrA-F0.5 is considered a candidate suitable for CO2 adsorbent in an actual post-combustion CO2 adsorption process.

Effect of Reservoir Heterogeneity on CO2 Flooding in Tight Oil Reservoirs

Carbon dioxide (CO2)-enhanced oil recovery (EOR) has great potential and opportunity for further development, and it is one of the vital carbon capture, utilization, and storage (CCUS) technologies. However, strong heterogeneity is one of the several challenges in developing reservoirs, especially for China’s continental tight oil reserves. This study investigates the effects of heterogeneous porosity and permeability on CO2 flooding evolution in low-permeable tight formation. We simulated CO2-EOR using a numerical model developed on the platform of TOUGH2MP-TMVOC to evaluate the effect of different levels of heterogeneity on oil production, gas storage, and flow behaviors in a tight reservoir, controlled by standard deviation and correlation length. A comparison of nine cases reveals that porosity heterogeneity commonly intensifies flow channeling, and there is an oil production decline with higher standard deviation and longer correlation length of porosity field. In addition, the porosity correlation length has a negligible effect on reservoir performance when the standard deviation is relatively low. Furthermore, strong heterogeneity also has a negative impact on the storage capacity of CO2 and oil production. Notably, as the standard deviation was raised to 0.1, a small sweep region arose with the early CO2 breakthrough, which led to a worse flooding effect. Finally, this study exemplifies that a higher injection/production rate and CO2 alternating N2 injection strategies can improve oil recovery in highly heterogeneous reservoirs.