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The southern Junggar Basin, Xinjiang, has abundant coalbed methane (CBM) resources. Currently, the Baiyang River development pilot test area (BYR block for short) in the Fukang east block has achieved large-scale CBM development, but the productivity characteristics and its controlling factor are still unclear. Based on the field production data of the BYR block and experimental tests, this paper summarizes the gas and water production characteristics and presents the analysis results of the geological and geochemical responses to the productivity of CBM wells. The productivity of CBM wells in the BYR block was generally characterized as medium-to-low yield. The productivity was jointly controlled by the burial depth, structure condition, thickness and number of co-production coal seams, and hydrogeological conditions. The gas production first increased and then decreased with the increase in the burial depth of the coal seam, and a burial depth between 750 and 1000 m was the most beneficial to increasing the gas production due to the good gas preservation conditions and suitable permeability and stress conditions. The total thickness of the co-production coal seams had a positive effect on the productivity of gas wells, but the productivity was also affected by the number of co-production coal seams and interlayer interference. In the BYR block, the co-production of the nos. 41 and 42 coal seams was the most favorable combination form for CBM drainage. The productivity of CBM wells had a good response to the Na+, K+ and HCO3− concentrations but a poor response to δD-H2O and δ18O-H2O. Based on the concentrations of the main ions and TDSs of the coal seam water, a productivity response index δ* was established, and there was a good positive correlation between the productivity and δ*. [ABSTRACT FROM AUTHOR]

There are large, heavy oil reserves in Block X of the Xinjiang oilfields, China. Due to its large burial depth (1300 m) and low permeability (26.0 mD), the traditional steam-injection technology cannot be used to obtain effective development benefits. This paper conducts experimental and simulation research on the feasibility and mechanism of CO 2 -energized fracturing of horizontal wells and N 2 foam huff-n-puff in deep heavy oil reservoirs with low permeability in order to further explore the appropriate production technology. The foaming volume of the foaming agent at different concentrations and the oil displacement effect of N 2 foam at different gas/liquid ratios were compared by the experiments. The results show that a high concentration of foaming agent mixed with crude oil is more conducive to increasing the foaming volume and extending the half-life, and the best foaming agent concentration is 3.0∼4.0%. The 2D micro-scale visualization experiment results show that N 2 foam has a good selective blocking effect, which increases the sweep area. The number of bubbles per unit area increases as the gas/liquid ratio increases, with 3.0∼5.0 being the optimal gas/liquid ratio. Numerical simulation results show that, when CO 2 -energized fracturing technology takes into account the advantages of fracturing and crude oil viscosity reduction by CO 2 dissolution, the phased oil recovery factor in the primary production period can reach approximately 13.7%. A solvent pre-slug with N 2 foam huff-n-puff technology is applied to improve oil recovery factor following primary production for 5∼6 years, and the final oil recovery factor can reach approximately 35.0%. The methodology formulated in this study is particularly significant for the effective development of this oil reservoir with deeply buried depth and low permeability, and would also guide the recovery of similar oil deposits. [ABSTRACT FROM AUTHOR]

The understanding of formation has always been a challenge for field development. In this paper, we evaluate the reservoir parameters and gas well productivity based on production data. The model of nonuniform conductivity of fractures in multistage fracturing horizontal wells (MFHW) is used to interpret the transient pressure data. Binomial and exponential deliverability equations and pressure dimensionless productivity formula are combined to evaluate the gas well productivity. After that, the key factors that influence gas well production are analyzed, and the gas rate vs. oil nozzle is presented. Results show that the fracture half-length and conductivity for high- and low-conductivity fractures, respectively, are obtained, apart from the reservoir pressure, permeability, skin factor, etc. The test time in each oil nozzle is recommended to extend to achieve stability and to obtain a more accurate absolute open flow potential. The findings of this study provides a guidance for the production data analysis of nonuniform conductivity of fractures in MFHW in the future work. And it can help for the better understanding of predicting gas production rates in MFHW. [ABSTRACT FROM AUTHOR]

• The addition of nano-silica can significantly improve oil production after fracturing. • Nano-silica improved in the anti-swelling performance of the gel-breaking fluid. • Nano-silica had an excellent oil-washing effect. • Field tests showed the cumulative oil production of the test wells was significantly enhanced. Nanomaterials have the characteristics of reducing water molecular clusters and improving surface properties. Therefore, it can effectively enhance the oil displacement (or imbibition) effect while developing low permeability and unconventional reservoirs. Volume fracturing based on horizontal wells has become the primary technology in developing unconventional reservoirs. In this paper, we investigated the effect of nano-SiO 2 on the rheology, flowback, and subsequent oil displacement performance of fracturing fluid. Results showed that nano-SiO 2 had little impact on the swelling and dispersion properties of the two thickeners (i.e., guar gum and emulsion polymer). The apparent viscosity of these two thickener solutions decreased by less than 15% after aging for 24 h. Nevertheless, nano-SiO 2 particularly influenced the rheological properties of guar gum based fracturing fluid. That is to say, the increase in the amount of nano-SiO 2 gradually reduced the temperature and shear resistance of the fracturing fluid. When the concentration of nano-SiO 2 reached 5%, the temperature and shear resistance of fracturing fluid decreased by 40%–60% in the temperature range of 80 to 100 °C. However, nano-SiO 2 had little effect on the fracturing fluid's breaking time and the solution's viscosity after breaking, and the surface tension of the solution slightly increased after breaking. The fracturing fluid added with nano-SiO 2 improved the performance of inhibiting clay swelling after the gel was broken. In addition, the solution after gel breaking had an excellent demulsification effect on emulsified crude oil when the concentration of nano-SiO 2 was less than 0.2%. While the concentration of nano-SiO 2 was greater than 0.5%, the increase in nano-SiO 2 concentration gradually strengthened the emulsification between crude oil and gel-breaking fluid. Nano-SiO 2 also had an excellent oil displacement effect, and it increased the recovery efficiency of primary water flooding by 9.99–13.34 percentage points. IThe field test of nanoparticle flooding and fracturing integrated technology was carried out for two wells in the Mahu tight oil reservoir of Xinjiang Oilfield, NW China. The pilot tests of the two wells were very successful, and the cumulative oil production on the 180th day after the fracturing operation was 20–50% higher than that of the comparison well. [ABSTRACT FROM AUTHOR]

In the past, reservoir engineers used numerical simulation or reservoir engineering methods to predict oil production, and the accuracy of prediction depended more on the engineers' own experience. With the development of data science, a new trend has arisen to use deep learning to predict oil production from the perspective of data. In this study, a hybrid forecasting model (CNN-LSTM) based on a convolutional neural network (CNN) and a Long Short-Term Memory (LSTM) neural network is proposed and used to predict the production of fractured horizontal wells in volcanic reservoirs. The model solves the limitation of traditional methods that rely on personal experience. First, the production constraints and production data are used to form a feature space, and the abstract semantics of the feature time series are extracted through convolutional neural network, then the LSTM neural network is used to predict the time series. The certain hyperparameters of the whole model are optimized by Particle Swarm Optimization algorithm (PSO). In order to estimate the model, some production dynamics from the Xinjiang oilfield of China are used for comparative analysis. The experimental results show that the CNN-LSTM model is superior to traditional neural networks and conventional decline curves. [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]