Due to the high viscosity of Jimsar crude oil and the lipophilicity of the reservoir, CO2 has an excellent performance in development of Jimsar shale oil. However, previous studies mostly focused on CO2 fracturing, but the replacement of crude oil by CO2 is rarely reported. Therefore, we conducted research on oil replacement by CO2 through systematical experiments. Firstly, we designed an experimental approach based on nuclear magnetic resonance to quantify the replacement ratio of oil. Next, a series of experiments were conducted for analyzing the effect of pressure, soaking time, permeability, and fractures on replacement ratio. Finally, oil-water imbibition experiments were conducted to compare its development effect with CO2 replacement for target reservoir. The study shows that the replacement capacity of CO2 for crude oil increases with pressure. In the experiment, the replacement ratio increases from 27.46% (10 MPa) to 56.70% (40 MPa) after 24 hours. On the microscopic scale, the crude oil in large pores is replaced out firstly, then the smaller pores. And on the macroscopic scale, the replacement of crude oil is from outside to inside. High permeability and fractures in the core promote the intrusion of CO2 into the core, raising the replacement ratio significantly. Since Jimsar reservoir is oil-wet, the oil recovery of oil-water imbibition is far less than that of CO2 replacement. The minimum pore through which oil can be exploited by oil-water imbibition is 1 mu m, while for CO2 replacement the value is 0.08 mu m. This study provides fundamental for CO2 increasing oil recovery in Jimsar shale oil.

To investigate the impact of CO 2 on rocks during the whole period of CO 2 pre-pad energized fracturing operation for thin interbedded shale reservoir, including fracturing and well shut-in, a series of laboratory triaxial fracturing experiments and CO 2 soaking experiments were conducted on thin interbedded shale (from Jimsar formations). In these experiments, combined with computed tomography (CT), the effect of fracturing fluid, horizontal principal stress difference, vertical principal stress, and natural fractures on fracture morphology were studied respectively. And based on X-ray diffraction (XRD) and scanning electron microscopy (SEM) experiments, the dissolution of minerals and the changes of pore structure before and after CO 2 soaking were analyzed. The results of the fracturing experiment show that the bedding planes are easy to be opened by low viscosity of CO 2 and the longitudinal fractures intersect with bedding planes to build a complex fracture network. During CO 2 fracturing of thin interbedded shale, the horizontal principal stress difference is no longer a crucial factor to form a complex fracture network, but the vertical stress and natural fractures play important roles. And the soaking experiments indicate that the main dissolved mineral is carbonate whose dissolution ratio can reach 45.2% after soaking for 5 days, leading to the expansion of original pores or the exposure of new pores.

Baikouquan oil field is composed of multiple interbedded, thin, low-permeability layers, which are required to vertically fracture multiple layers and to create complex fractures for economic development. However, conventional fracture technologies create a single, simple fracture, having poor feasibility for this field. Therefore, we conducted research on fracturing technology by spontaneously selecting geologic sweet spots based on diversion. This technology can vertically fracture the thin layers one by one and horizontally divert the fracture to non-depleted areas. Firstly, a triaxial diverted fracturing experiment approach was setup, and then diverted fracturing experiments were carried out to verify the feasibility of diverted fracturing and to study the fracture geometry and the law of diversion. Next, experiments were carried out to evaluate the performance of the diversion agents. The valuated properties comprise the diversion pressure, stability time, and degradation based on which to optimize the selection of the diversion agents. Finally, the fracturing technology was applied to well b21004 of Baikouquan oil field, and post-frac performance was evaluated. The experimental results show that multiple and complex fractures are realized through temporary plugging. Diversion performance evaluation tests show that a 4 wt% concentration of 1–5 mm granules + 20/60 mesh powder and a 3 wt% concentration of 1–7 mm granules + 20/60 mesh powder + fiber can hold up enough pressure to force the fracture to divert. The field treating pressure curve shows that there is a 3–10 MPa pressure increase when there are pump diversion agents, which is a clear sign of fracture diversion. Plugging the fracture mouth gives a faster and a higher incremental pressure. Before this fracturing, the well had almost stopped oil production. After the stimulation, the initial oil production rate became 20 + t/d, which shows the effectiveness of this fracturing technology for Baikouquan oil field.

CO2前置蓄能压裂焖井期间,CO2持续与储层岩石发生作用.为探索CO2对吉木萨尔页岩作用效果及变化规律,明确提高采收率机理,分别对浸泡前后的吉木萨尔页岩进行渗透率测试实验、X射线衍射实验和扫描电镜实验,在分析渗透率宏观变化规律的基础上,对矿物组成、微观表面形态和孔喉结构变化规律进行解释.实验结果表明:使用CO2水溶液对吉木萨尔页岩长期浸泡后,其渗透率增大,浸泡7天增大约65％,浸泡14天增大约1.4倍;CO2水溶液对碳酸盐岩矿物有明显的溶蚀作用,在地层条件下使用CO2水溶液对岩样碎块浸泡5天后,碳酸盐岩溶蚀率可达到45.2％;从微观表面溶蚀情况来看,经CO2水溶液浸泡后,原有孔隙被溶蚀扩大或出现新的孔隙,从而提高了渗透率.现场试验结果表明,通过增加裂缝复杂度、增加焖井时间和使用"CO2+水基压裂液"复合压裂的方法对增强碳酸盐岩矿物溶蚀及提高地层渗透率有显著影响.