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The technique of refracturing is an effective method to solve the rapid decline in oil well production caused by factors such as severe reservoir energy loss and fracture failure after the initial hydraulic fracturing of low-permeability reservoirs. The key to designing refracturing lies in establishing a model for evaluating the potential fracturing layers. Based on the geological characteristics of the low-permeability conglomerate reservoir in the Lower Wuerhe area of the Eig District of the Xinjiang Oilfield, this paper studies the influence of different development approaches on the distribution pattern of remaining oil in the reservoir. A coupled model of remaining oil distribution and the in situ stress field is established and discusses the characteristics of the four-dimensional in situ stress field under different development modes. This paper analyzes the influence of geological factors and well network factors on the distribution of residual oil, and analyzes the influence of various factors, such as reservoir properties and injection and extraction parameters, on ground stress. Based on the residual oil distribution and ground stress changes, an evaluation method for screening potential fractured layers in reservoirs with different development modes (water injection development and depletion development) is developed. [ABSTRACT FROM AUTHOR]

Multistage fracturing in horizontal well has become one of the important techniques for the efficient development of low-permeability sandstone reservoirs. In multistage hydraulic fractured horizontal wells (MHFHWs), the depth of fracturing fluid invasion into the formation is a key parameter evaluating the imbibition enhancement after fracturing. However, few studies have been conducted on the invasion depth of fracturing fluids combining experiments and mathematical models under high-pressure differences in MHFHWs. Therefore, in this work, a mathematical model with experimental validation is proposed for evaluating the fracturing fluids invasion under high pressure. We first conducted a series of displacement experiments under different pressure differences to obtain the breakthrough time and invasion velocity. All core samples are taken from the block X of Xinjiang oilfield. A mathematical model of fracturing fluid injection was then established, considering the two-dimensional filtration of fracturing fluid. Then, the calculated invasion velocity was validated against the experimental data. Afterward, the invasion depth and invasion volume were determined for this typical horizontal well. Results show that at the end of 72 min, the invasion depth reaches 1.516 m when measured by core experiments and 1.434 m when calculated by the proposed model. The total invasion volume of all fracturing stages is estimated as 21,560.05 m3 and the actual total fluid volume injected is 24,019.6 m3. The paper formed a scientific and reasonable evaluation method of fracturing fluid invasion depth during the fracturing of horizontal wells, which provides solid theoretical support for the effective evaluation of fracturing to improve oil recovery. [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]

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]

• 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]

Horizontal well with subdivision cutting fracturing technology is a new technical way to improve the efficient development of shale reservoirs. Subdivision cutting fracturing has the characteristics of stronger inter-fracture interference, more variable parameters and constraints. This fracturing technology has no efficient method to optimize the discrete and continuous fracture parameters integrally. A new automatic integrated optimization algorithm is proposed. The algorithm adopts the SPSA nested binary search algorithm to optimize the discrete and continuous fracture parameters. Considering the flow mechanism of multi-scale media in shale reservoirs, a numerical flow simulation model of subdivision cutting fractured horizontal wells is established. Then, taking the NPV as the objective function, a multi-parameter integrated optimization model is established. Make the method apply to a typical test shale reservoir. The optimization results show that the NPV of the optimum fracture parameter combination is 37.69%–57.36% higher than that of the uniform fracture distribution combination. And the optimum fracture combination presents a spindle-like distribution. This method is applied to an actual shale reservoir in Xinjiang to verify the broad application. The fracture parameter combination of two parallel horizontal wells in the reservoir is optimized. The optimization results show that the NPV has been dramatically improved, with an increasing range of 37.94%–96.84%. And the fractures of two adjacent horizontal wells present zipper staggered distribution. The integrated optimization method of fracture parameters can provide theoretical guidance for hydraulic fracturing design. • A new optimization method of SPSA nested binary search algorithm is proposed to realize the integrated optimization of discrete and continuous fracture parameters. • Considering the flow mechanism of multi-scale media in shale reservoirs, an optimization model with NPV as the objective function is established. • The method has a fast convergence speed and a significant increase in NPV, and the optimized fracture parameters combination is in line with the heterogeneous distribution. [ABSTRACT FROM AUTHOR]

There are only a few related studies focused on the steam assisted gravity drainage (SAGD) dilation start-up technology (termed as dilation start-up in this paper), especially with true triaxial stress physical modelling experiments in the laboratory. Therefore, in order to better understand the dilation start-up process, four large-scale (1050 mm × 410 mm × 410 mm) true triaxial experiments of SAGD start-up with dual horizontal wells were conducted for the first time by using the oil sands from the Xinjiang oilfield, northwest China. The dilation process characterized by temperature changes at different positions inside the experimental samples was monitored in real time. The performance differences between dilation start-up and conventional start-up were discussed in detail, and the effects of dilation pressure and dilation time on the dilation process were also studied. The experimental results indicate that dilation start-up can significantly reduce the well communication time between injector and producer, and enhance the range of dilation zone and improve the uniformity of dilation zone along the horizontal wellbores. Moreover, we find that dilation pressure is an essential factor influencing the dilation effect. The average communication parameter increases by 5% if dilation pressure increases by 10% whereas the standard deviation of communication parameter decreases. The evolution of dilation zone with time shows that long-time dilation prompts the uniform propagation of dilation zone along the horizontal wellbores. This study provides guidance for the optimization of SAGD dilation start-up in shallow heavy oil reservoirs. • Four large-scale true triaxial experiments of SAGD start-up with dual horizontal wells were conducted. • Dilation process characterized by temperature changes inside the samples was monitored in real time. • Effects of dilation pressure and dilation time on the SAGD dilation start-up were studied. [ABSTRACT FROM AUTHOR]