Due to the significance of carbon utilization and storage, CO₂ huff and puff is increasingly receiving attention. However, the mechanisms and effects of CO₂ huff and puff extraction in medium to deep saturated heavy oil reservoirs remain unclear. Therefore, in this study, by targeting the medium to deep saturated heavy oil reservoirs in the block Xia of the Xinjiang oil field, measurements of physical properties were conducted through PVT analysis and viscosity measurement to explore the dissolution and diffusion characteristics of CO₂-degassed and CO₂-saturated oil systems. Multiple sets of physical simulation of CO₂ huff and puff in medium to deep saturated heavy oil reservoirs were conducted using a one-dimensional core holder to evaluate the EOR mechanism of CO₂ huff and puff. The results demonstrate that the solubility of CO₂ in degassed crude oil is linearly correlated with pressure. Higher pressure effectively increases the solubility of CO₂, reaching 49.1 m³/m³ at a saturation pressure of 10.0 MPa, thus facilitating oil expansion and viscosity reduction. Meanwhile, crude oil saturated with CH₄ still retains the capacity to further dissolve additional CO₂, reaching 24.5 m³/m³ of incremental CO₂ solubilization at 10.0 MPa, and the hybrid effect of CO₂ and CH₄ reduces oil viscosity to 1161 mPa·s, which is slightly lower than the pure CO₂ dissolution case. Temperature increases suppress solubility but promote molecular diffusion, allowing CH₄ and CO₂ to maintain a certain solubility at high temperatures. In terms of dynamic dissolution and diffusion, the initial CO₂ dissolution rate is high, reaching 0.009 m³/(m³·min), the mid-term dissolution rate stabilizes at approximately 0.002 m³/(m³·min), and the dissolution capability significantly decreases later on. CO₂ exhibits high molecular diffusion capability in gas-saturated crude oil, with a diffusion coefficient of 8.62 × 10⁻⁷ m²/s. For CO₂ huff and puff, oil production is positively correlated with the CO₂ injection rate and the cycle injection volume; it initially increases with the extension of the soak time but eventually decreases. Therefore, the optimal injection speed, injection volume, and soak time should be determined in conjunction with reservoir characteristics. During the huff and puff process, the bottom hole pressure should be higher than the bubble point pressure of the crude oil to prevent gas escape. Moreover, as the huff and puff cycles increase, the content of saturates in the oil rises, while those of aromatic, resin, and asphaltene decrease, leading to a gradual deterioration of the huff and puff effect. This study provides a comprehensive reference method and conclusions for studying the fluid property changes and enhanced recovery mechanisms in medium to deep heavy oil reservoirs with CO₂ huff and puff.

To optimize enhanced oil recovery (EOR) techniques for pre-fractured heavy oil reservoirs, this research conducted long-core flooding experiments using three distinct injection media: CO₂, water, and CO₂/water alternate huff-n-puff. A 35 cm composite core was employed to simulate the reservoir conditions after pre-fracturing. Experimental results indicated that the CO₂ huff-n-puff process yielded the highest oil production, enhancing the overall recovery factor by 33.0% compared to depletion production, with a total recovery factor of 43.8% after four optimized cycles. The CO₂/water alternate huff-n-puff process increased the recovery factor by 28.3%, achieving a total of 41.9% after four cycles. In contrast, water injection improved the recovery factor by only 15.2%, reaching a total of 26.2% after three cycles. By evaluating both oil recovery efficiency and oil exchange ratio, the optimal cycle numbers were determined as four cycles for CO₂ huff-n-puff, four cycles for CO₂/water alternate huff-n-puff, and three cycles for water huff-n-puff. Based on these optimized parameters, the CO₂/water alternate huff-n-puff process was identified as the most effective EOR method for the target reservoir. Furthermore, this study assessed the potential for CO₂ storage in the reservoir post-production. Calculations of CO₂ storage ratios during the huff-n-puff process demonstrated the feasibility of integrating enhanced oil recovery with carbon sequestration. The findings provide a practical strategy for improving heavy oil recovery in low-permeability reservoirs while concurrently exploring the benefits of CO₂ storage.

The characteristics and influencing factors of gas production in CBM wells are analyzed based on the field geological data and the productivity data of coalbed methane (CBM) wells in the Zhengbei block, and then the favorable areas are divided. The results show that the average gas production of No. 3 coal seam CBM wells in the study area is in the range of 0~1793 m³/d, with an average of 250.97 m³/d; 80% of the wells are less than 500 m³/d, and there are fewer wells above 1000 m³/d. The average gas production is positively correlated with gas content, critical desorption pressure, permeability, Young’s modulus, and Schlumberger ratio, and negatively correlated with fracture index, fault fractal dimension, Poisson’s ratio, and horizontal stress difference coefficient. The relationship between coal seam thickness and the minimum horizontal principal stress is not strong. The low-yield wells have the characteristics of multiple pump-stopping disturbances, unstable casing pressure control, overly rapid pressure reduction in the single-phase flow stage, sand and pulverized coal production, and high-yield water in the later stage during the drainage process. It may be caused by the small difference in compressive strength between the roof and floor and the coal seam, and the small difference in the Young’s modulus of the floor. The difference between the two high-yield wells is large, and the fracturing cracks are easily controlled in the coal seam and extend along the level. The production control factors from strong to weak are as follows: critical desorption pressure, permeability, Schlumberger ratio, fault fractal dimension, Young’s modulus, horizontal stress difference coefficient, minimum horizontal principal stress, gas content, Poisson’s ratio, fracture index, coal seam thickness. The type I development unit (development of favorable areas) of the Zhengbei block is interspersed with the north and south of the block on the plane, and the III development unit is mainly located in the east of the block and near the Z-56 well. The comprehensive index has a significant positive correlation with the gas production, and the prediction results are accurate.

The shallow, thin super-heavy oil reservoir demonstrates certain characteristics, such as shallow reservoir depths, low-formation temperature, and high crude oil viscosity at reservoir temperatures. In the current production process, the central area of P601 is undergoing high-frequency huff and puff operations, facing certain problems such as decreasing production, low recovery rates, and rapid depletion of formation pressure. Through physical simulation experiments, the various elements of HDNS-enhanced oil recovery technology were analyzed. Nitrogen plus an oil-soluble viscosity reducer can improve the thermal recovery and development effect of super-heavy oil. With the addition of the viscosity-reducing slug, the recovery rate of steam flooding was 58.61%, which was 23.32% higher than that of pure steam flooding; after adding the 0.8 PV nitrogen slug, the recovery rate increased to 76.48%. With the increased nitrogen injection dosage, the water breakthrough time was extended, the water cut decreased, and the recovery rate increased. Nitrogen also plays a role in profile control and plugging within the reservoir; this function can effectively increase the heating range, increase steam sweep efficiency, and reduce water cut. So, the synergistic effects of steam, nitrogen, and viscosity-reducing agents are good. This technology enhances the development of shallow-layer heavy oil reservoirs, and subsequent development technologies are being compared and studied to ensure the sustainable development of super-heavy oil reservoirs.

In the development of hydrocarbon fields, it is becoming known that CO2 injection (which is sometimes done to improve hydrocarbon production) can cause pore blockage and wettability alteration by the promotion of asphaltene deposition. In hydrocarbon reservoirs, the result is poor oil recovery performance during carbon dioxide (CO2) injection. If CO2 is being injected into a legacy hydrocarbon reservoir (i.e., one that still contains residual oil) the same process will occur. Once again, the ability of fluid (this time supercritical CO2) to flow will be impeded, but it is also possible that asphaltene deposition will also reduce the overall pore volumes in which CO2 could otherwise be stored. In this work, the residual oil distribution and the permeability decline caused by organic and inorganic precipitation after miscible CO2 flooding and water-alternating-CO2 (CO2-WAG) flooding have been studied by carrying out core-flooding experiments at high pressures and temperatures in an artificial three layer system. For simple CO2 injection during CCUS operations, flooding experimental results indicate that the low-permeability layers retain a large oil production potential even in the late stages of production, which could impede CO2 emplacement and provide significant heterogeneity, while the permeability decline due to asphaltene precipitation is more significant in high-permeability rocks. In contrast, we found that CO2-WAG can reduce the influence of heterogeneity on the oil production, but it results in more serious reservoir damage, with permeability decline caused by CO2–brine–rock interactions becoming significant. In addition, miscible CO2 flooding has been carried out for rocks with similar permeabilities but different wettabilities and different pore-throat microstructures in order to study the effects of wettability and pore-throat microstructure on formation damage. Reservoir rocks with smaller pore-throat sizes and more heterogeneous pore-throat microstructures were found to be more sensitive to asphaltene precipitation, making these less attractive for CCUS reservoirs. However, rocks with larger, more connected pore-throat microstructures became less water wet due to asphaltene precipitation to pore surfaces, ultimately leading to a lower pore volume in which CO2 can be stored. Taken together, there may be a case for not simply injecting CO2 in CCUS operations, but alternating the CO2 injection with injection of water in order to stabilise CO2 flow and reduce formation damage by asphaltene precipitation.

Injection of CO2 into subsurface reservoirs occurs during Enhanced Oil Recovery (EOR) and also during Carbon Capture and Storage (CCS) operations. During CO2 injection, the efficacy and distribution of fluid flow in sandstone reservoirs is controlled by the pore-throat microstructure of the rock. Furthermore, CO2 injection promotes asphaltene precipitation on the pore surface and can also affect fluid flow in the pore throats, decreasing the permeability and altering reservoir wettability. In this work, miscible and immiscible CO2 flooding experiments under reservoir conditions (up to 70℃, 18 MPa) have been carried out on four samples with very similar permeabilities but different pore-throat structures in order to study the effects of pore-throat microstructure on formation damage. The features of pore-throat structure were evaluated by fractal theory, based on pore size distributions and rate-controlled porosimetry (RCP) mercury intrusion curves. Reservoir rocks with smaller pore throat sizes and more heterogeneous and poorer pore-throat microstructures were found to be more sensitive to asphaltene precipitation, with corresponding 15-20% lower oil recovery and 4-7% greater decreases in permeability than that of rocks with homogeneous and better pore-throat microstructure. However, the water-wettability index of cores with larger and more connected pore-throat microstructures was found to drop by an extra 15-25% than heterogeneous core due to more asphaltene precipitation caused by the larger sweep volume of injected CO2 they consequently experienced, which is a disadvantage for EOR. In addition, immiscible flooding exacerbates the differences from 4-7% to 8-15% in permeability decline of the rocks with different pore-throat structures. Miscible flooding leads to more asphaltenes being precipitated from the crude oil, triggering in average an extra 11% change in wettability in comparison to immiscible flooding. Keywords: CO2 flooding, asphaltene precipitation, pore size distribution, pore-throat microstructure, reservoir blockage, wettability alteration