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Bridging plugging is the most used method of plugging in unconventional oil reservoirs, and many factors affect the effect of bridging and plugging. Since the laboratory cannot simulate the actual leakage size of the lost formation and the corresponding leakage plugging process at the drilling site, the laboratory experiment results cannot reflect the actual leakage plugging construction effect. Aiming at the problem of frequent fracture leakage during drilling in Chepaizi block, Xinjiang, China, this paper proposes a set of machine learning methods based on a neural network. Three types of factors and 14 parameters with a strong correlation with the leakage control effect were screened out. Three categories of factors include construction parameters, choice of plugging material, and fluid properties of the carrier fluid. The training was carried out based on the collected field data, the appropriate activation function was set, and the deep well network structure was optimized. By improving the field plugging measures in the later period, the model was verified by these actual cases, and the results showed that the established model produced the highest R 2 of 0.974, has a good fit, and predicts well. [ABSTRACT FROM AUTHOR]

In order to determine the effective stress factor of proppants during the multi-stage hydraulic fracturing operation in horizontal wells and select the appropriate proppant type, the analysis of the effective stress characteristics of proppants is carried out. This analysis considers the geomechanics and long-term production characteristics of multi-stage fractured horizontal wells in reservoirs like Xinjiang Mahu shale oil and Southwest China shale gas. The analysis of influencing factors is also carried out. The results show that, during the multi-stage hydraulic fracturing operation in horizontal wells, the stress on proppants is not only related to geological factors such as reservoir closure stress, but also closely related to total injection volume, cluster spacing, liquid type, injection displacement and post fracture management. First, increasing injection intensity, reducing fracture spacing, using low viscosity fracturing fluid, adopting high injection displacement and utilizing reasonable flowback system can effectively supplement reservoir energy, postpone the effective stress peak of proppants, and increase the effective conductivity of proppants. Second, the production performance analysis results of nearly 300 horizontal wells (from Xinjiang oil field, Erdos tight oil reservoir, Sichuan shale gas reservoir, etc.) shows that: the effective stress of proppants in horizontal wells is only 50–60% of that in vertical wells, which results in a different proppant selection criterion in the volume stimulation of horizontal wells and provides the geomechanics basis of replacing ceramsite proppant with quartz sand to reduce cost and increase efficiency. Based on the above conclusions, the field test of replacing ceramsite proppant with quartz sand was carried out. The proportion of quartz sand increased from less than 30% in 2014 to 69% in 2019. Without any impact on production, the annual investment cost was decreased by more than 1 billion yuan, which set a great example for the promoted low-cost development of unconventional oil and gas reservoirs under low oil price background. [ABSTRACT FROM AUTHOR]

Previous studies on the technique for using the remaining oil are incomplete and inaccurate according to the position of the interlayer of the Steam-Assisted Gravity Drainage (SAGD) technique, and comparative studies of infilled horizontal wells are lacking. In this study, the SAGD well pair in the superheavy oil reservoir in the Z block in the Xinjiang Oilfield, China, was taken as an example. According to the reservoir's geological parameters and production parameters, a typical well group geological model was created for the first time. The model divided the well groups in block Z into three categories according to the position of the interlayer, the production degree of the horizontal section, the oil recovery ratio, and the available degree of reserve control. According to the geological classification results, different typical well groups without an interlayer, with an interlayer located above the steam injection well, and with an interlayer located between the well pairs were classified and analyzed using numerical simulations. This was the first time the infilled horizontal well technique was compared with the infilled vertical well-assisted SAGD technique. In addition, the steam chamber connection law of the infilled vertical well-assisted SAGD was clarified. The results show that for reservoirs without an interlayer, the use of infilled horizontal well-assisted SAGD could speed up the lateral connection of the steam chambers and reduce the residual oil saturation. For reservoirs with a low production degree in the horizontal section and that are affected by an interlayer, an infilled vertical injector could be used with the assisted SAGD technique to increase the oil recovery by 5%–13%. The results of this study provided strong guidance for the next step in using enhanced oil recovery techniques to achieve traditional SAGD production from superheavy oil reservoirs with an interlayer. [ABSTRACT FROM AUTHOR]

A field test in the Xinjiang oilfield in China shows that the viscosity of heavy oil has a certain influence on the combustion dynamics and injection-production performance of fire flooding. The experiment in this study uses a one-dimensional combustion tube to study the temperature, gas composition, and air injection pressure and the production performance of the fire flooding of heavy oil with different viscosities. The results show that the oil viscosities of 1180–22500 mPa·s can achieve stable combustion, and the O2 content of the gas produced during the stable combustion stage is <0.5%. The higher the viscosity of the heavy oil, the higher the temperature in the burned zone and the smaller the range of the temperature increase in the unburned zone. The air injection pressure will increase rapidly until a stable seepage channel is formed, and then, it will drop to a level close to the formation pressure. High-viscosity heavy oil requires a higher air injection pressure and will remain in the high-pressure stage for a longer period of time. Low-viscosity heavy oil has a low water cut in the early stage of fire flooding, a large oil production rate, and a low and stable air–oil ratio. The water cut of high-viscosity heavy oil increases rapidly in the early stage of fire flooding and then decreases gradually, so a good air–oil ratio can only be obtained in the middle and late stages of fire flooding. Thus, fire flooding may be more suitable for application in common heavy oil and some extra heavy oil reservoirs with lower viscosities. [ABSTRACT FROM AUTHOR]

It is challenging to enhance heavy oil recovery in the late stages of steam flooding. This challenge is due to reduced residual oil saturation, high steam-oil ratio, and lower profitability. A field test of the CO2-assisted steam flooding technique was carried out in the steam-flooded heavy oil reservoir in the J6 block of the Xinjiang oil field (China). In the field test, a positive response to the CO2-assisted steam flooding treatment was observed, including a gradually increasing heavy oil production, an increase in the formation pressure, and a decrease in the water cut. The production wells in the test area mainly exhibited four types of production dynamics, and some of the production wells exhibited production dynamics that were completely different from those during steam flooding. After being flooded via CO2-assisted steam flooding, these wells exhibited a gravity drainage pattern without steam channeling issues, and hence, they yielded stable oil production. In addition, emulsified oil and CO2 foam were produced from the production well, which agreed well with the results of laboratory-scale tests. The reservoir-simulation-based prediction for the test reservoir shows that the CO2-assisted steam flooding technique can reduce the steam-oil ratio from 12 m3 (CWE)/t to 6 m3 (CWE)/t and can yield a final recovery factor of 70%. [ABSTRACT FROM AUTHOR]

Microfractures are key for migrating and aggregating hydrocarbon source rocks and fracturing oil-gas exploitation in tight reservoirs. In this study, rock samples from the Lucaogou Formation tight reservoirs in Xinjiang, China, were studied using multidisciplinary techniques to investigate the genetic types and main control factors of microfractures. Results indicated that the Lucaogou Formation mainly developed diagenetic microfractures followed by tectonic microfractures, with slight formations of granular microfractures. These observations were used to clarify the relationship between the development of microfractures and the pore fluid content, lithology, mineral composition, and stratum thickness. A higher pore fluid content corresponded to a lower compressive strength of the rocks and a larger ring count, resulting in a higher probability of failure and microfracture formation. Tight reservoirs containing more quartz and carbonate minerals were found to develop more microfractures. Quartz grains showed fractures at the margins under stress, which increased the pore permeability of rocks. Carbonate minerals tended to form microfractures owing to corrosion. Microfracture formation mechanisms differed depending on lithology, and microfractures were found to develop most in dolomite and dolomitic siltstones and least in mudstone. Muddy rocks developed fewer tectonic fractures because they can easily absorb stress and undergo plastic deformation. Within a certain stratum thickness range, the average single-well fracture space and stratum thickness showed positive correlations. Moreover, the fracture space increased and the fracture density decreased as the stratum thickness increased. When the stratum thickness was less than 2.5 m, the fracture space increased linearly with the stratum thickness, and when the stratum thickness was greater than 2.5 m, the fracture space remained constant. This study will provide an essential scientific basis for enhancing tight oil recovery. [ABSTRACT FROM AUTHOR]