Abstract

In order to clarify the effectiveness of CO2 injection at high temperature and high pressure in Gulong shale oil, the conversion coefficient between shale T2 value and pore throat radius is first given based on the results of shale mercury injection and nitrogen adsorption experiments. Based on the T2 spectrum characteristics of saturated shale, shale pores are divided into small pores, medium to large pores, and lamellation fractures. At the same time, a calculation method for shale oil recovery is provided. Then, the effects of huff and puff cycle, soak time, and fractures on huff and puff oil displacement effect are examined, And analyze the degree of change in core pore structure after huff and puff, and finally compare the oil displacement effects of shale oil CO2 huff and puff and CO2 displacement, and provide the optimal oil displacement method. The experimental results show that the shale oil in the middle to large pores and lamellation fractures has the highest recovery after huff and puff, while the shale oil in the small pores has the lowest recovery. Increasing the soaking time only increases the shale oil recovery by0.81%, and fracturing can increase the shale oil recovery in the small pores by 11.33%, effectively utilizing the shale oil in the small pores, and improving the recovery of shale oil in small pores is the key to improving the recovery of Gulong shale oil; Compared to CO2displacement, CO2huff and puff can increase shale oil recovery by 30.98%, and shale oil in dry rock samples can be utilized, with better huff and puff effects than displacement; The combination of displacement and huff-n-puff can increase the recovery rate by more than 12.88% compared to only using huff-n-puff, and can significantly increase the recovery of shale oil in small pores; The pore structure of the core undergoes significant changes after huff and puff, and the difference in shale gravel content is an important reason for the significant differences in pore structure changes before and after shale huff and puff. The experimental results can provide important basic parameters for the practice of the Gulong shale oil field.

Abstract

The amount of CO2 being used as fracturing fluid has been more than 30,000 tons at Changqing oilfield in 2022, Which above several times over the sum of the last five years. A serials of experiments and experimental analyses devoted to the CO2 fracturing mechanism were conducted in order to provide some advices for the CO2 fracturing treatment design and improve the well performance. An experimental analysis for the CO2-core leakoff experiments was made in which compares the leakoff characteristics under the liquid and gas phase of CO2. The plot for the square-root time vs.leakoff rate was got. Two sets of CO2 fracturing physical simulation experiments on the cores of 762 × 762 × 914.4mm were carried out, which compares the fracture’s geometry and size with the slick water experiments’ results. The mechanism that lead to the rock breakdown pressures’ decreasing with CO2 fluid was researched based on the Elasticity mechanics and the Fracture Mechanics theory. The results show that CO2 has a very high leakoff rate within the core which leads to a lower rock breakdown pressure value and a smaller fracture size and an excellent capacity for complicating the rock’s fractures than the conventional fracturing fluid.

Abstract

During the production process of complex fault block reservoirs with low permeability, the systematic research on the combination of oil displacement and storage is fuzzy. This work aims at oil displacement and storage to supplement formation energy and evaluate storage potential. Firstly, the optimal development scheme is designed by layer division and miscible and ability. Secondly, based on large amounts of field data, the novel FAHP evaluation system for CO2 storage site selection is established. Thirdly, since judging adaptability evaluation is suitable, the carbon storage simulation is conducted to contain mineralization, dissolved and structural mechanisms. The results indicate that after 1.2HCPV CO2 injected cumulatively into reservoir, the cumulative oil increase reached 4001.80×104m3 and the final recovery rate was 44.46%, achieving a good effect. At the stage of injection, the CO2 capacity remaining in the reservoir was nearly 1657.53×104t and the gas storage rate reached 43.84%. The novel evaluation system for CO2 storage site selection shows that the target reservoir has more storage space, large injection capacity, high safety factor and low storage cost, which is allowed to storage. At the stage of storage, the effective storage capacity of target reservoir was 2257.48×104t, of which the structural storage capacity was 73.43% and the mineral storage capacity was the least (3.46%). The average annual CO2 storage capacity is about 225.74×104t, which is equivalent to planting 2031.69×104t trees or shutting down 135.69×104 cars for one year, achieving oil displacement/storage synergetic optimization. The findings of this study can offer engineers guidance for ensuring the long-term, stable and safe operation of CO2 storage. For complex fault block reservoirs with low permeability “green, low-carbon, efficient” development has a certain reference.

Abstract

Reservoir wettability representing the competitive adsorption for different fluids on the surface, helps to predict the capture capacity and risk assessment for CO2 geological sequestration. Numerous simulated models have been applied to reveal rock wettability with various pressures. However, most papers investigated the wettability alteration without considering CO2 flow in the pores. There required an accurate model to describe the change in wettability of the reservoir during CO2 injection. In this paper, the molecular simulation was conducted to investigate the wettability alteration of reservoirs during the CO2 injection process. Considering the continuous CO2 injection, we employed a model referring to quartz-CO2-solution. In this model, CO2 flow is regarded as a stationary layer. After that, we studied the wetting behavior of reservoirs with various pressures ranging from 0 MPa to 62.3 MPa. The results show that the contact angle first dramatically increases until 12.2 MPa from 67 °to 102.9 °and after that enters a ramp region and ultimately reaches a finial value 120.7 °, which shows the CO2 injection pressure weakens the water-wet property of reservoirs. Water clusters predicting the wettability are hard to move through the CO2 atmosphere with the increase of pressure. Thus, the water cluster exhibits a hysteresis at a high pressure, resulting in the water cluster being hard to change and expend a long time to be equilibrated. Moreover, it is noted that the interaction of rock-CO2 gradually increases with the increase of pressure, indicating that more CO2 can be captured in tight sandstones. This paper proposed a model considering CO2 flow in the CO2 injection process, which can deepen the understanding of the wettability alteration in different CO2 densities during CO2 injection for CO2 geological sequestration, which further guides the operation of CO2 in Carbon Capture, Utilization and Sequestration project.

Abstract

Carbon dioxide (CO2) has great utilization potential in the exploitation of deep geothermal resources, especially hot dry rock (HDR). As a clean and renewable resource, HDR geothermal presents a promising prospect in meeting the growing demand for energy and achieving low-carbon solutions. To address the challenges posed in HDR development, such as large water consumption, simple fracture pattern and corresponding fast thermal breakthrough of Enhanced Geothermal System (EGS), a novel non-aqueous stimulation method which combines the advantages of supercritical CO2 (SC) fracturing and dynamic shock effect is proposed and investigated in this paper, i.e. supercritical carbon dioxide shock (SCS) fracturing. To determine its stimulation performance in HDR, we performed controllable lab-scale SCS fracturing experiments on high-temperature granites subjected to true tri-axial stresses. By comparing with conventional water fracturing and SC-CO2 fracturing, the fracture initiation behavior and stimulation performance of SCS fracturing were investigated quantitatively based on CT scanning and reinjection tests, with respect to fracture morphology and conductivity. Effects of critical parameters were analyzed as well, such as shock pressure, in-situ stress and rock temperature. Results indicate that the breakdown pressure of granite is 24.2~57.5% lower than the shock pressure during SCS fracturing, and it decreases with increasing rock temperature. SCS fracturing could create complex fracture network with more interconnected branches and larger seepage spaces. The volume, area and width of fractures by SCS fracturing are 545.3%, 98.4% and 126.3% higher than those of water fracturing, respectively. The fracture conductivity is 3.4~7.0 times and 4.5~21.2 times higher, as compared to water fracturing and SC fracturing. As the rock temperature increases, both the tortuosity and conductivity of fractures improve dramatically, which benefits to extend the flow path of working medium and enhance the heat transfer performance. In-situ stress plays a relatively weak role in controlling fracture propagation of SCS fracturing. At horizontal stress difference coefficient of 0.14~0.60, the fracture propagation behaves more randomly in direction, contributing to forming complex fractures with multi-branches. Higher shock pressure conduces to the stimulation performance enhancement of SCS fracturing, improving the complexity and connectivity of fracture networks, and promote the fracture to get rid of the control of in-situ stress in EGS. The key findings are expected to provide a novel insight into developing HDR geothermal in a more environmentally and more efficient way, and achieving CO2 utilization and storage.

Abstract

CO2 flooding can effectively improve the recovery factor of low permeability reservoir. However, problems such as strong heterogeneity and gas channeling in low permeability reservoir restrict the development of CO2 flooding. At present, the industrial application of CCUS in Jilin Oilfield is in the stage of large-scale promotion. It is of great significance to study the matching foam control technology suitable for low permeability reservoir with high temperature and acid resistance. In combination with the characteristics of Jilin oilfield oil reservoir, considering the strong penetrability of CO2 and its acidity when encountering water, the mechanism of action of single agent molecular characteristic groups and the evaluation of changes in micro bubble diameter and liquid film. It is clear that high temperature and CO2 medium is the key factors affecting the comprehensive performance of CO2 foam, make full use of the characteristics of strong foaming of long carbon chain, good foam stability of double bonds and inhibition of CO2 adsorption by multiple hydroxide groups to improve the high temperature resistance, CO2 resistance and comprehensive performance of foam,the indoor parallel core displacement experiment shows that on the basis of CO2 flooding, injecting the foam control slug can effectively improve the diversion rate of high and low permeability cores and further improve the displacement efficiency of low permeability cores. The field foam control test of CO2 flooding has played a good role in raising pressure, reducing gas and increasing oil. The gas injection pressure increased by 3.2MPa, gas production decreased by 57.3%, and the cumulative oil increased by 1355t. At present, foam channeling control technology is gradually popularized and applied in Jilin Oilfield, which is of great significance for CO2 flooding in low permeability reservoir to expand the wave reach volume and further improve the oil recovery.