CO2 Displacement Research Articles

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.

CO2 Injection for Enhanced Gas Recovery and Geo-Storage in Complex Tight Sandstone Gas Reservoirs

With the popularization of natural gas and the requirements for environmental protection, the development and utilization of natural gas is particularly important. The status of natural gas in China’s oil and gas exploration and development is constantly improving, and the country is paying more and more attention to the exploitation and utilization of natural gas. The Upper Paleozoic tight sandstone in the Ordos Basin is characterized by low porosity, low permeability and a large area of concealed gas reservoirs. By injecting carbon dioxide into the formation, the recovery rate of natural gas can be improved, and carbon neutrality can be realized by carbon sequestration. Injecting greenhouse gases into gas reservoirs for storage and improving recovery has also become a hot research issue. In order to improve the recovery efficiency of tight sandstone gas reservoirs, this paper takes the complex tight sandstone of the Upper Paleozoic in the Ordos Basin as the research object; through indoor physical simulation experiments, carried out the influence of displacement rate, fracture dip angle, core permeability, core dryness and wetness on CO2 gas displacement efficiency and storage efficiency; and analyzed the influence of different factors on gas displacement efficiency and storage efficiency to improve the recovery and storage efficiency. The research results show that under different conditions, when the injection pore volume is less than 1 PV, the relationship between the CH4 recovery rate and the CO2 injection pore volume is linear, and the tilt angle is 45°. When the injection pore volume exceeds 1 PV, the CH4 recovery rate increases slightly with the increase in displacement speed, the recovery rate of CO2 displacement CH4 is between 87–97% and the CO2 breakthrough time is 0.7 PV–0.9 PV. In low-permeability and low-speed displacement cores, the diffusion of carbon dioxide molecules is more significant. The lower the displacement speed is, the earlier the breakthrough time is, and the final recovery of CH4 slightly decreases. Gravity has a great impact on carbon sequestration and enhanced recovery. The breakthrough of high injection and low recovery is earlier, and the recovery of CH4 is about 3.3% lower than that of low injection and high recovery. The bound water causes the displacement phase CO2 to be partially dissolved in the formation water, and the breakthrough lags about 0.1 PV. Ultimately, the CH4 recovery factor and CO2 storage rate are higher than those of dry-core displacement. The research results provide theoretical data support for CO2 injection to improve recovery and storage efficiency in complex tight sandstone gas reservoirs.

Rough Surface Effect on CO2 Displacement at the Nanoscale

CO2 injection has great potential for enhancing shale oil recovery. Understanding the CO2 displacement in nanometer pores of shale is critical for developing effective CO2 injection techniques. In this work, we applied direct numerical simulation to study the effect of the rough surface on CO2 displacement in nanometer pores of shale. By quantifying CO2 displacement in rough nanochannels, we aimed to understand how surface roughness and morphology affect displacement progress. We found that the rough surface results in shrinkage of the CO2 displacement path, slowing overall displacement rate. Additionally, the pinch-point effect in a rough nanochannel impedes the smooth progression of the interface contact line, causing periodic velocity fluctuation that further hinders CO2 displacement. We also simulated the CO2 displacement in rough nanoporous media, finding that the rough surface leads to a substantial decrease in CO2 displacement efficiency, especially under low pressure gradient conditions. Our simulation results indicate that the rough surface of a shale nanometer pore has a nonnegligible effect on CO2 displacement.

Research on Displacement Efficiency by Injecting CO2 in Shale Reservoirs Based on a Genetic Neural Network Model

Carbon dioxide injection can help solve two issues in shale reservoir production. Firstly, it can reduce carbon emissions while, secondly, improving unconventional reservoir recovery. There are many controlling factors for CO2 injection to enhance oil recovery in shale reservoirs, and the effect of field implementation varies greatly. The key to popularizing this extraction technology is determining the main controlling factors of CO2 displacement efficiency. Using CO2 shale displacement laboratory results, the grey correlation analysis method was used to determine the main controlling factors affecting core oil displacement efficiency, such as shale reservoir physical parameters (rock compressibility, porosity, median pore size, matrix permeability, TOC, and oil saturation) and engineering parameters (soaking time and injection pressure). The genetic algorithm (GA) was introduced to optimize the backpropagation (BP) neural network to construct the prediction model of the CO2 indoor displacement experiments in shale cores. The results showed that the injection pressure among the engineering parameters, the CO2 soaking time among the gas injection parameters, and the porosity among the shale physical parameters were the main controlling factors affecting the oil displacement efficiency. The prediction accuracy of the genetic neural network model improved, and the coefficient of determination (R2) reached 0.983. Compared with the conventional neural network model, the mean absolute error (MAE) was reduced by 30%, the root mean square error (RMSE) was reduced by 46%, and the R2 increased by 11%. Optimizing the learning and training of the prediction model significantly reduces the cost of laboratory experiments. The deep-learning model completed by training can intuitively show the degree of influence of input parameters on output parameters, providing a theoretical basis for the study of CO2 displacement mechanisms in shale reservoirs.

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.

Experimental study of the effect of CO2 on rock seepage characteristics

The influence of different phase states of CO2 on the seepage characteristics of different rocks is one of the most important factors to enhance shale gas exploitation, such as CO2 fracturing and displacement, and achieve CO2 geological storage. Rock soaking experiments with different CO2 phase states were carried out to compare and analyze the influence of permeability, contact angle, starting pressure gradient and other seepage characteristic parameters of sandstone and shale before and after soaking. Research shows: After soaking in liquid and supercritical CO2, the permeability and contact angle of sandstone and shale increase in varying degrees, and the starting pressure gradient decreases in varying degrees. After soaking in liquid CO2, the permeability of sandstone and shale increased by 1.71% and 12.88% respectively, the contact angle increased by 3.23% and 7.47% respectively, and the starting pressure gradient decreased by 3.02% and 5.88% respectively. After supercritical CO2 immersion, the permeability of sandstone and shale increased by 37.37% and 48.82% respectively, the contact angle increased by 19.27% and 36.80% respectively, and the starting pressure gradient decreased by 35.39% and 39.34% respectively. Compared with sandstone, the seepage characteristics of shale after soaking in liquid and supercritical CO2 have greater changes; Compared with liquid CO2, the seepage characteristics of sandstone and shale change more after supercritical CO2 soaking. With the increase of supercritical CO2 soaking time, the contact angle of sandstone slightly increases, while that of shale obviously increases. Compared with liquid CO2, the change of seepage curves of sandstone and shale after supercritical CO2 soaking is more different.

The Influencing Factors of CO2 Utilization and Storage Efficiency in Gas Reservoir

Carbon Capture, Utilization and Storage (CCUS) technology is one of the most practical means to meet zero greenhouse gas emission goal of the Paris Agreement and to ensure profitability, which could achieve permanent sequestration of CO2. Due to the cost constraints of CCUS implementation, improving recovery and maximizing storage efficiency have become a critical part of ensuring economic efficiency. This research aims to analyze the effects of key factors on enhancing gas recovery and storage efficiency, combined with the validation of CO2 displacement and storage mechanisms. Therefore, long core experiments and different dimensional simulations were established based on R gas reservoir (one of the actual gas reservoirs in Northeast China), which were designed for sensitivity analyses of different influencing parameters and quantitative analyses of different storage mechanisms during CCUS process. When the conditions (temperature and pressure) were closer to the CO2 critical point, when the following parameters (the CO2 purity, the injection rate and the dip angle) became larger, when the reservoir rhythm was reversed and when the irreducible water was is in existence, the final displacement and storage effects became better because of weaker diffusion, stronger gravity segregation and slower CO2 breakthrough. The contributions of different storage mechanisms were quantified: 83.78% CO2 existed as supercritical fluid; 12.67% CO2 was dissolved in brine; and 3.85% CO2 reacted with minerals. Some supercritical and dissolved CO2 would slowly transform to solid precipitation over time. This work could provide theoretical supports for CCUS technology research and references for CCUS field application. At the same time, countries should further improve CCUS subsidy policies and make concerted efforts to promote the globalization and commercialization of CO2 transport.

Study on gas injection development effect of tight reservoir based on fluid occurrence state

Based on the tight oil reservoir conditions of Lucaogou Formation in Jimusar Sag, Xinjiang, this paper conducts a full-scale characterization experiment of pore structure and designs the optimization numerical simulation of the development scheme based on the geological model combination with the fluid occurrence state. A comparative study on the development methods of tight reservoirs shows that the enhanced oil recovery effect of CO2 flooding is obviously better than that of CH4 flooding and water flooding. When the production bottom hole pressure is lower than the formation fluid saturation pressure, changing the production bottom hole pressure has little impact on the productivity of CO2 flooding in tight reservoirs. The recovery factor increases with the increase of injection rate, but when the injection rate is higher than 15,000 m³/d, the increase of oil recovery and the oil change rate decrease obviously; The complex fractures near the well can help to increase the swept volume of CO2 flooding, while the complex fractures far away from the well will cause channeling, which is not conducive to production. Combined with the occurrence state of the fluid, it is obtained that in the process of CO2 displacement, when the adsorption is considered, when the adsorption components are the same, with the increase of the adsorption capacity, the recovery factor decreases; When the adsorption capacity is constant, the higher the proportion of heavy components is, the lower the recovery factor is; With the increase of adsorption capacity, the permeability decreases more. The fluid occurrence state in tight oil reservoirs is very different from that in conventional reservoirs, and the adsorption phase accounts for a larger proportion, which seriously affects the flow capacity of the fluid during the development process. However, conventional numerical simulation rarely considers the influence of fluid occurrence state.

Comparison of electrocardiogram parameters during two methods of euthanasia in white leghorn hens

This study's objective was to evaluate if electrocardiogram (ECG) parameters differ depending on euthanasia method, and if welfare implications result. Sixteen mature laying hens previously outfitted with subcutaneous wireless telemetry and housed in conventional cages or aviaries were used. Manual cervical dislocation (CD) and 30% CO2 displacement were chosen. Continuous ECG data collection began 5 min prior to the procedure to establish a baseline, then continued during and following euthanasia until complete cessation of cardiac activity. Insensibility and euthanasia were determined by an experienced handler to be loss of posture and the end of neuromuscular convulsions with no noticeable breathing. The attending veterinarian monitored and confirmed successful euthanasia via auscultation of the heart. Veterinary confirmation occurred within 5 min for all hens, thus a 5-min sampling period was used. Samples of ten successive QRS complexes per hen per minute were used to calculate average QRS complex amplitude and heart rate. Data were analyzed using the Glimmix Procedure in SAS 9.4, and reported as deviations from baseline. Housing was not a significant factor (p > 0.05). Heart rate showed a significant effect for method (p = 0.0232), time (p < 0.0001), and method*time interaction (p = 0.0001). Compared to baseline, heart rate for CD was 238 bpm higher at minute 1 (p < 0.0001) and 106 bpm higher at minute 2 (p = 0.0027) compared to CO2. While there was no significant effect of method on QRS amplitude (p = 0.6220), there was a time effect (p = 0.0266). Cervical dislocation as a method of euthanasia may induce a greater stress response in laying hens compared to CO2 displacement.

Characteristics of Gas Seepage and Pore Structure Response in CO2-ECBM Process of Low Permeability Coal Seam

CO2-ECBM is a method of enhanced coalbed methane extraction followed by cutting greenhouse gas emissions and new energy development. In order to reveal the characteristics of gas flow in porous media and the pore structure response characteristics of coal rocks, the experiments were carried out to simulate the process of CO2 displacement of N2 at a buried depth of 900 m, including monitoring the changes in gas permeability and strain of coal samples along with a comparison of the pore structure of low-temperature liquid nitrogen adsorption on coal samples both before and after displacement were both done. The findings of the experiment are listed below. The N2 permeability of the LiuZhuang sample ranges from 0.0008mD to 0.0014mD, whereas the permeability of QiDong is around 0.0003mD. With an increase in gas injection duration and an expansion of the coal matrix for N2 adsorption, the permeability steadily decreases. The efficient stress compression of the coal pore fracture structure during sample preparation and testing avoids the visible fracture region, which results in poor permeability. The displacement stages of CO2 can be divided into three phases. Free nitrogen flows from the end of the position and the permeability diminishes during the phase of free nitrogen. When CO2 is introduced into the penetration stage, the permeability tends to rise, however when there is no penetration, the permeability test values are frequently low. During the CO2 steady displacement phase, gas permeability gradually declines. Axial and radial strains are progressively raised during the initial stage of the CO2 injection whereas they are gradually reduced during the initial stage of the N2 injection. While CO2 is continuously supplied through the coal body stage, there are modest axial and radial strain changes. The axial and radial stresses are stabilized by the CO2 displacement. The overall pore volume of the coal significantly rises following the displacement. The increase part of the pore volume is primarily focused on the pore of absorption and filling (aperture &lt; 10nm), whereas the decreased part is mainly concentrated in the diffusion pore of the Fick type and the permeability part (aperture &gt; 50nm). The increased in pore volume ratio surface area is centered mostly in the fill pore region (aperture 10 nm) and is four times greater than it was before the displacement. The CO2 injection exerts an expansion impact on the adsorptionfilled and diffusion pores during the CO2-ECBM process, whereas the compression effect on the percolation pores results in a reduction in permeability.

Pore-scale Analysis of CO2-brine Displacement in Berea Sandstone and Its Implications to CO2 Injectivity

For storage in deep saline formations, where CO2 is injected into the pore spaces of rocks previously occupied by saline groundwater (brine), relative permeability is a key input parameter for predictive models. CO2 injectivity is considered to reach the maximum value at the CO2 endpoint relative permeability when brine saturation becomes irreducible. The objective of this study is to investigate the effect of viscosity ratio, interfacial tension and wettability on relative permeability during CO2-brine drainage. A multiphase lattice Boltzmann model (LBM) is employed to numerically measure pore-scale dynamics in CO2-brine flow in the sample of Berea sandstone. CO2/brine with interfacial tension from 30 to 45 mN/m and viscosity ratio from 0.05 to 0.17 (the range of values expected for typical storage reservoirs conditions) are carried out to systematically assess the influence on the relative permeability curves. Although CO2 storage in sandstone saline aquifers is predominantly water wet, there are contradictory results as to the magnitude of the contact angle and its variation with fluid conditions. Therefore, the range of wetting conditions is studied to gain a better insight into the effect of wettability on supercritical CO2 displacement. In this study, it is observed that interfacial tension variations play a trivial impact while both of viscosity ratio and wettability are likely to have a significant effect on relative permeability curves under representative condition of storage reservoirs. We also perform a near-wellbore scale geomechanics analysis to investigate the impact of relative permeability on CO2 injectivity. The result shows that water-wet condition facilitates the CO2 injection when there is no fracture induced.

Mechanism of Surfactant Enhancement of CO2 Displacement Recovery in Interlayer Shale Oil Reservoirs

Aiming at the problem that few studies have been conducted on the combination of multiple media in enhanced oil recovery (EOR), the physical simulation experiment of surfactants + CO2 (SPC) was carried out to analyze the influence of surfactant on the CO2 displacement effect of interlayer shale oil reservoir. The results show that when the displacement flow volume (DFV) reaches 20 PV, the oil displacement efficiency (ODE) of SPC displacement is 0.42~3.00% higher than that of CO2 displacement. The ODE of small pore displacement can be increased by 1.51~3.61%. And the relative displacement content (RDC) ratio of free oil of tight shale oil reservoir can be increased by 7.10~20.54%. When the DFV is 5 PV, the ODE can be improved more significantly. It shows that the efficiency of small pore displacement can be increased by 1.74~2.33%. It also indicates that the ODE can be increased by 7.03% of the ultralow permeability shale oil reservoir. And the RDC ratio of free oil of tight shale oil reservoir can be increased by 10.34~21.50%. Surfactant can improve the wettability of the reservoir and make the rock sample wet. This research can help to understand the influence of surfactant on CO2 displacement effect and reveal the mechanism of SPC displacement improving the ODE of interlayer shale oil reservoir, providing theoretical basis for the effective development of interlayer shale oil reservoir.

Direct Visualization of Nanoscale Salt Precipitation and Dissolution Dynamics during CO2 Injection

CO2 injection to enhance shale oil recovery provides a win-win solution to meet the global fuel shortage and realize ultimate carbon neutrality. When shale reservoirs contain high salinity water, CO2 injection can result in salt precipitation to block the nanometer pores in the shale, causing undesirable formation damage. Understanding salt precipitation and dissolution dynamics at the nanoscale are fundamental to solving this practical challenge. In this work, we developed a shale micromodel to characterize salt precipitation and dissolution based on nanofluidic technology. By directly distinguishing different phases from 50 nm to 5 μm, we identified the salt precipitation sites and precipitation dynamics during the CO2 injection. For the salt precipitation in the nanometer network, we identified two precipitation stages. The ratio of the precipitation rates for the two stages is ~7.9 times that measured in microporous media, because of the slow water evaporation at the nanoscale. For the salt precipitation in the interconnected micrometer pores, we found that the CO2 displacement front serves as the salt particle accumulating site. The accumulated salt particles will in turn impede the CO2 flow. In addition, we also studied the salt dissolution process in the shale micromodel during water injection and found the classical dissolution theory overestimates the dissolution rate by approximately twofold. This work provides valuable pore-scale experimental insight into the salt precipitation and dissolution dynamics involved in shale formation, with the aim to promote the application of CO2 injection for shale oil recovery.

Effects of competitive adsorption on production capacity during CO2 displacement of CH4 in shale

During CO2 displacement of CH4 in shale, competitive adsorption results in reduced pore space used for gas flow in shale, which is closely associated with the production capacity of shale-gas reservoirs. Thus, the present work investigates the effects of CO2–CH4 competitive adsorption on production capacity. Herein, a slit–pore model is developed in terms of gas storage (CO2 and CH4) and graphene pores using molecular dynamics and implemented via large-scale atomic/molecular massively parallel simulator. The effects of CO2 injection pressure, temperature, and velocity and of pore size on CO2–CH4 displacement and competitive adsorption properties are simulated and examined. Hence, the displacement efficiency of CH4 and the adsorption layer thickness of the CO2–CH4 binary mixture are determined. Moreover, based on a basic seepage model of planar linear flooding, the effect of CO2–CH4 competitive adsorption on production capacity is analytically investigated. Results demonstrate that the production capacity with consideration of adsorption layer thickness is less than that without consideration of adsorption layer thickness, illustrating that CO2–CH4 competitive adsorption behaviors are closely connected with permeability, flow rate, and production capacity of shale-gas reservoirs, especially for shale-gas reservoirs containing large numbers of pores and slits.

Study on the Differences between Various Gas Injection Sources in the Process of Coal Seam Methane Replacement by Gas Injection.

To study the differences between various gas injection sources in the process of coal seam methane replacement, experimental research was conducted to study the influences of different gas injection sources and gas injection ratios on coal seam methane replacement by considering the strong adsorption gas CO2 and the weak adsorption gas N2. The experimental results show that the temperature rise effect of the CO2 injection gas is greater and lasts longer than that of the N2 injection gas in the process of coal seam methane replacement by gas injection, and the temperature rise can promote the desorption of adsorbed methane well. However, due to the different effects of gas compressibility, the increase in gas pressure caused by injecting N2 under the same conditions is higher than that of CO2; due to the strong adsorption of CO2, the gas pressure after injecting CO2 continues to decrease slowly. From the displacement effect, the adsorbability of the injection source gas has a significant effect on the displacement rate and injection-placement ratio, while the injection ratio has a significant effect on CO2 displacement but not on N2 injection. From the experimental results, for N2 injection, the effects of coal seam methane replacement by gas injection can be enhanced by improving the gas injection method and process; for CO2 injection, the effects of coal seam methane replacement by gas injection can be improved by the following two aspects: gas injection volume and gas injection time.

Micro-Displacement and Storage Mechanism of CO2 in Tight Sandstone Reservoirs Based on CT Scanning

Tight sandstone reservoirs are ideal locations for CO2 storage. To evaluate the oil displacement efficiency and storage potential of CO2 in the tight sandstone reservoir in the Huang 3 area of the Changqing Oilfield, four kinds of displacement experiments were conducted on core samples from the Chang 8 Formation in the Huang 3 area. These experiments were performed using micro-displacement equipment, digital core technology, and an online CT scanning system; the different oil displacement processes were recorded as three-dimensional images. The results show that the CO2 flooding alternated with water scheme can improve crude oil recovery the most. Comparing the cores before and after the displacement shows that the amount of crude oil in pores with larger sizes decreases more. The remaining oil is mainly in thin films or is dispersed and star-shaped, indicating that the crude oil in the medium and large pores is swept and recovered. The CO2 displacement efficiency is 41.67~55.08%, and the CO2 storage rate is 38.16~46.89%. The proportion of remaining oil in the throat of the small and medium-sized pores is still high, which is the key to oil recovery in the later stages.

Characterization of Residual Oil Distribution in Sandstone by NMR: A Microscopic View on Oil Recovery by Miscible CO2 Flooding

Abstract Miscible CO2 flooding gains rising popularity due to high displacement efficiency and potential carbon negativity. It is well documented that pore-level heterogeneity is one of the dominant mechanisms responsible for the variation in oil recovery efficiencies of miscible CO2 flooding. However, owing to a lack of understanding of miscible CO2 displacement behaviors at pore level, quantitative analysis of the mechanisms for the influence of pore-level heterogeneity on the oil recovery efficiency of miscible CO2 flooding remains problematical. Recently, NMR has been widely used to investigate microscopic residual oil distribution and pore-level displacement behaviors of various agents. Nevertheless, current NMR-based methods for determining microscopic residual oil distribution require the use of fluorinated oil, Mn2+ solution, or heavy water for eliminating the mutual interference of oil and water NMR signals. The differences in properties of reservoir fluids and additional agents could give rise to the change in displacement characteristics and consequently affect the analysis results on pore-level displacement behaviors. In this study, a method to determine microscopic residual oil distribution in sandstone during gas floodings based on NMR T2 spectrum without additional agents except reservoir fluids is proposed. Using the method, we can avoid the possible changes in the displacement characteristics caused by additional agents. Miscible CO2 flooding experiments are conducted with ultra-low and extra-low permeability cores. The T2 spectra of cores before and after flooding are measured using a 23 MHz low-field NMR instrument. Residual oil distributions in cores are quantitatively characterized using the proposed method, and then, oil recovery efficiencies from different-sized pore throats are evaluated. It is found that for both cores about 60% of the residual oil is distributed in pore throats with &amp;lt;0.26 μm radius. Oil residing in pore throats with &amp;gt;0.03 μm radius is displaceable for miscible CO2 flooding, which indicates that the thickness of the raffinate layer in the pore should be less than 0.015 μm. More than 30% of the residual oil is distributed in unswept areas, and thus, the sweep efficiency improvement is expected to effectively enhance the oil recovery of miscible CO2 flooding. The sweep efficiency is negatively affected by the pore-size heterogeneity. For the ultra-low and extra-low permeability cores, the standard deviation of pore size is 0.39 and 1.15, respectively, and correspondingly, the sweep efficiency is 84.33% and 72.84%, respectively. In the core, the oil recovery efficiencies from swept pore throats with &amp;lt;3 μm radius are similar and exceed 50%. Pore throats with &amp;gt;3 μm radius can form a preferred flow path, which will significantly reduce the oil displacement efficiency from swept pore throats with &amp;lt;3 μm radius. The findings of this study can help for better understanding of the microscopic CO2 miscible displacement behaviors and the mechanisms for the influence of pore-level heterogeneity on the oil recovery efficiency of miscible CO2 flooding.

Influences of diffusion-limited transport in the crystals and initial water on the gaseous CO2 dynamic replacement in CH4 hydrate

CO2–CH4 dynamic replacement is a process of the CO2–CH4 replacement method. In this process, CO2 is injected into CH4 hydrate-bearing sediment continuously to recover CH4. The dynamic replacement process can be divided into the CO2 displacement stage and the subsequent dynamic replacement stage and is affected by the existence of initial water and diffusion-limited transport caused by the mixed hydrate layer. Effective fugacity is utilized to combine the thermodynamic model and kinetic model to investigate the effects of the above two factors on the CH4–CO2 dynamic replacement process. Initial water is assumed to distribute in the pore space. The CH4 hydrate decomposition due to the decrease of CH4 partial pressure in the gas phase during the CO2 displacement stage is considered. Our investigation results show that diffusion-limited transport is the main factor that restricts the replacement percent in the displacement stage, the effect of the existence of initial water on the replacement percent is more obvious than that of the diffusion-limited transport. CO2 storage efficiency is less than 10% during the entire dynamic replacement and is mainly affected by the existence of initial water rather than the diffusion-limited transport. The temperature increase is mainly due to newly formed hydrate. Finally, more CH4 hydrate is exploited near the outlet than that near the inlet. Therefore, the CH4–CO2 replacement method needs to be enhanced near the inlet. CO2 is mainly sequestrated in the CO2 hydrate formed through free water. CO2 sequestrated in the mixed hydrate is mainly distributed near the inlet, while the CO2 sequestrated in the CO2 hydrate is mainly distributed near the outlet.

Experimental Study of Oil Displacement and Gas Channeling during CO2 Flooding in Ultra—Low Permeability Oil Reservoir

Aiming to solve the problems of poor CO2 displacement efficiency and serious gas-channeling and low well-opening rates in ultra-low permeability reservoirs, we carry out CO2 displacement experiments under different permeability reservoirs by using different development methods, water drive to gas drive procedures, and different fracture positions to clarify the effects of physical formation properties, injection methods, and fracture parameters on CO2 displacement efficiency in C8 ultra-low permeability reservoirs. The experimental results show that the recovery degree of CO2 miscible drive increases with an increase in permeability. When the gas–oil ratio is greater than 2000 m3/m3, serious gas channeling can be observed in both the miscible drive and immiscible drive. In addition, when the water drive is altered to be a gas drive, the water cut of 0.45 mD and 0.98 mD cores decreased, and the recovery degree increased by 13.4% and 16.57%, respectively. A long fracture length will deteriorate gas channeling and lower the CO2 oil-displacement efficiency. However, the fracture location is found to have little impact on the recovery of CO2 displacement.

Study on the Plugging Limit and Combination of CO2 Displacement Flow Control System Based on Nuclear Magnetic Resonance (NMR)

CO2 displacement is an important technology to reduce emissions and improve crude oil recovery, as well as prevent CO2 escape. Effective storage is key to the successful implementation of this technology, especially for medium and high permeability reservoirs. The current flow control systems that are applied to seal gas escape are mainly gas/water alternation, CO2 foam, and CO2 foam gel, but there is no clear understanding of the plugging limits of various flow control systems and the mechanism of their combined use of residual oil. Therefore, in this paper, a series of core replacement experiments are conducted for different flow control systems and their combinations. The quantitative characterization of the core pore size distribution before and after the replacement is carried out using the NMR technique to try and determine the plugging limits of different plugging systems, and to investigate the residual oil utilization patterns of self-designed flow control system combinations and common flow control system combinations under two reservoir conditions with and without large pores. The results show that the plugging limits of water/gas alternation, CO2 foam, and CO2 foam gel systems are 0.86–21.35 μm, 0.07–28.23 μm, and 7–100 μm, respectively, as inferred from the T2 (lateral relaxation time) distribution and pore size distribution. When different combinations of flow control systems are used for repelling, for reservoirs without large pore channels, the combination of flow control systems using higher strength CO2 foam first can effectively improve the degree of crude oil mobilization in small pore throats, compared to using gas/water alternation directly. For reservoirs containing large pore channels, using high-strength CO2 foam gel first to seal the large pore channels increases the degree of utilization of the large pore channels; using water/gas alternation first causes damage to the middle pore channels; High-strength CO2 foam gel seals the large pore channels when the plugging strength is not enough; and using water/gas alternation can effectively improve the degree of utilization of small and medium pore channels. The results of this paper can provide theoretical guidance for the multi-stage flow control of CO2 displacement in the field.