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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]

The Jurassic Badaowan formation of the tight oil reservoir in northwest Xinjiang, China, is featured by a complex in situ stress pattern, leading to an unclear understanding of the orientation and geometry of a propagated hydraulic fracture. In this regard, a three-dimensional (3-D) in situ stress field was first configured based on a detailed mechanical earth model of the region of concern. Secondly, a fluid-solid-damage coupling model was established to explore the influences of the in situ stresses and the engineering parameters on fracture propagation. Finally, a systematic approach was proposed to characterize the updated stress field and the fracture morphology reconfigured by the in situ stress. The findings disclose that the reservoir is mainly controlled by reverse faults that generate horizontal fractures in most parts of the region. The in situ stress follows the strike-slip fault pattern where vertical fractures are dominant in the central and southeastern part of the reservoir, where the vertical fracture tends to be constrained in the oil layer when the interlayer minimum stress difference ∆Sh becomes greater than 4 MPa in the southeast. In addition, as the injection rate increases, the width of a fracture increases, whereas its height decreases. The viscosity has negligible effect on the fracture height, but its increase can enlarge the fracture width and decrease the length. Here, the cross-dipole shear wave logging record in a field well was used to verify the proposed method, showing that the predicted fracture morphology was consistent with the field test result. The research can aid field engineers in predicting fracture morphology for optimizing a fracturing scheme. [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 developing the Benbutu oilfield in Xinjiang, hole size irregularities were often encountered in the water- and hydrocarbon-containing sections, and these greatly affect the quality of the cementing job and damage the reservoirs. To protect the oil and gas reservoirs in the Benbutu oilfield, an elastic polymer microsphere NWL was developed through soap-free emulsion polymerization and was characterized. A reservoir protective agent CBJ was formulated with NWL, a selected anti water-block agent, a kind of rigid acid soluble nanometer particles (CaCO3) and a petroleum resin in a certain quantity ratio. Laboratory experiment was conducted to evaluate CBL in the aspects such as: the compatibility of CBL with the sizes of formation fractures, the acid solubility and oil solubility of CBL, the compatibility of CBL with the drilling fluids presently used, and the reservoir protection performance of CBL. CBL was also tested in field operations. CBL has the particle size distribution that is suitable for plugging formation fractures, good acid solubility and oil solubility. Drilling fluids treated with CBL have filtration rate reduced by about 20%, and percent permeability recovery by more than 80%. Field application and laboratory study show that CBL has good reservoir protection effect, it can be used to protect the reservoirs of Benbutu oilfield in accordance with the local conditions and maximize the production of oil wells. [ABSTRACT FROM AUTHOR]

The low-velocity flow in tight reservoir deviates from the traditional Darcy's law, and this phenomenon is described as nonlinear flow. In order to study the main controlling factors of low-velocity nonlinear flow and the flow characteristics of tight reservoir, the tight oil reservoir in Jimsar Sag, Xinjiang, China, was taken as the research object. Firstly, the physical model experiment of single-phase simulated oil flow is carried out. Then, by analyzing the physical properties of the reservoir and crude oil and experimental data, a fluidity-based low-velocity nonlinear flow mathematical model was established for the "upper and lower sweet spot" reservoirs. At last, according to the influence of fluidity and the wettability index on the threshold pressure gradient, a three-dimensional figure was constructed. Research results show that the parameters in the nonlinear flow mathematical model and fluidity have a good power function relationship. Moreover, for the "upper and lower sweet spot" reservoirs, the relative average errors between the calculated data of the nonlinear flow mathematical model and the experimental data are 4.75 and 3.76%, which indicate good adaptability to tight oil reservoirs in the Jimsar Sag. In the three-dimensional figure, the "upper and lower sweet spot" reservoirs are divided into three different main controlling factor areas corresponding to the change in threshold pressure gradient. In addition, the calculation data of the nonlinear flow mathematical model conform to the regional division of the characteristic figure, clarifying the influencing factors of the low-velocity nonlinear flow in tight reservoirs. [ABSTRACT FROM AUTHOR]

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]

The pilot project of CO2 flooding has been implemented in the conglomerate oil reservoir in Xinjiang, China. The target reservoir is characterized by the low-porosity (ranging from 8.53% to 11.02%) and low-permeability (ranging from 3.30 to16.18 mD) parameters. The objective of the pilot CO2 flooding is to overcome the water sensitiveness of the formation. However, the field application of the CO2 injection is complicated by technical difficulties including gas channeling and low sweep efficiency. To control the oil recovery factor, it is critically important to investigate the efficiency of the oil displacement in pores and throats of the formation in the process of water and CO2 flooding. In this paper, in order to quantitatively determine the oil displacement in the pores of different sizes, the authors have studied the process of the water and CO2 flooding in the core samples obtained from the conglomerate oil reservoir in the Xinjiang Oilfield. The displacement efficiency is evaluated by the online nuclear magnetic resonance (NMR) method. Before testing, the samples are saturated with oil till the oil saturation reaches 48.27%. In the process of water flooding, the water content in the large pores reaches 28.70%, the displaced oil is produced mainly from the large pores, and the oil saturation is reduced to 27.78%. In the process of CO2 flooding, the oil displacement efficiency is increased by 17.97%, including an increment of 7.17% for the middle-size pores and 8.61% for the large pores. The large and the middle-size pores contribute to the high oil recovery, while the oil in the small pores is difficult to recover. The ultimate oil saturation is 19.97%, and the overall recovery factor is 60.44%. At the late stage of CO2 flooding, a foam-like structure is developed in the large pores, which is prone to plug the pore throats of the large pores and boost the residual oil displacement in the small pores, thereby further enhancing the oil recovery factor. This study is focused on comprehensive research on the relationship between the pore size and the oil recovery factor in a conglomerate oil reservoir. The results can be useful for guiding the implementation of site-specific EOR technologies. [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]

• 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]

• The super-heavy oil reservoir with interlayers were classified quantitatively by geological and producing parameters. • New way was given for evaluating the development effects of SAGD during the mid-later stages in super heavy oil reservoirs. • Fuzzy comprehensive evaluation method and analytic hierarchy processes were introduced firstly to the evaluating processes. • New standards the ranking of five producing parameters were determinated based on influences for developments effects. The problems of energy consumption and decreasing production are prominent during the middle and later stages of steam-assisted gravity drainage (SAGD) in super-heavy oil reservoirs. Geological parameters and production parameters have an important impact on the development effects. However, there is no quantitative method to evaluate production effects of SAGD during the middle and later stages. In order to fill this gap, this study proposed a new approach to quantitatively evaluate the development effects of SAGD by considering the geological and production parameters for super-heavy reservoirs. Where, the primary factors controlling reservoir's characteristics and development effects of SAGD were determined by using numerical simulation method. There are 42 well pairs that have already entered the middle and later stages using SAGD in the Xinjiang oil field, China, which were taken as an example. Firstly, a fuzzy cluster analysis model was established to classify reservoir by considering three geological indicators. The results indicated the potential of production for each well pair. Then a fuzzy comprehensive evaluation model was established to evaluate development effects by considering five production indicators. The new standards and ranking of evaluation indicators were quantitatively confirmed by using analytic hierarchy processes. Finally, the approach combined reservoirs classification and development effects evaluation to provide a quantitative and comprehensive evaluation of each well pair. The oil recovery ratio and utilization degree of the horizontal section can clearly reflect the development effects according to comprehensive evaluation results, which means that when the well group meets the recovery factor less than 3.0% and the utilization degree of horizontal section less than 85.0%, the development effects are evaluated as "Category III". Based on the evaluation results, the corresponding follow-up adjustment measures can be adopted. This study has guidance on the development of technical countermeasures for different types of well pairs. [ABSTRACT FROM AUTHOR]

Steam injection is the most popular used method in recovering heavy oil reservoirs. Many researchers were engaged in enhancing oil recovery (EOR) methods by using various well configurations. Laboratory experiments and field applications have verified the feasibility of extra-heavy oil recovery by steam injection using vertical injector -horizontal producer. It was also referred to as a steam assisted gravity drainage (SAGD) process. However, the characteristic of steam chamber growth and production performance during the vertical injector-horizontal producer steam injection process have not been fully understood. In this study, a 3D physical model was constructed to investigate the mechanisms of the steam injection process using vertical injector-horizonal producer. Numerical simulations were also conducted to verify the laboratory experiment and field application. In the aspect of steam chamber growth, the results revealed that three stages were included during the steam injection process. In the aspect of developing mechanisms, it can be divided into steam flooding and gravity drainage stages. Moreover, the results show that about 43.9% of original oil in place (OOIP) was produced in the gravity drainage stage. In addition, subcool showed significant difference in steam flooding and gravity drainage stages. The temperature distribution mode of the horizontal producer was analyzed and proved to be a significant factor that influences the production performance. Sensitivity analysis by using numerical simulation demonstrated that oil viscosity is the dominant factor that impact the production performance. The results guided the development of pilot test area in Xinjiang Oilfield, China. The study can provide a clearer understanding of the vertical injector-horizontal producer steam injection process in recovering heavy oil reservoirs. • The vertical injector- horizontal producer steam injection process was divided into three stages. • The dominant driving forces, steam flooding and gravity drainage, varies in different developing stages. • Production performance at different developing stages were analyzed, and most oil was developed by gravity drainage. • The results were used to guide the development of the pilot test area in Xinjiang Oilfield. [ABSTRACT FROM AUTHOR]

Fracture-driven interactions (FDIs) in unconventional reservoirs significantly affect well production and have thus garnered extensive attention from the scientific community. Furthermore, since the industry transitioned to using large completion designs with closer well spacing and infill drilling, FDIs have occurred more frequently and featured more prominently, which has primarily led to destructive interference. When infill wells (i.e., "child" wells) are fractured, older, adjacent producing wells (i.e., "parent" wells) are put directly at risk of premature changes in production behavior. Some wells may never fully recover following exposure to severe FDIs and, in the worst case scenario, will permanently stop producing. To date, previous investigations into FDIs have focused mainly on diagnosis and detection. As such, their formation mechanism is not well understood. To address this deficiency, a three-dimensional, multi-fracture propagation simulator was constructed based on the unconventional fracture model (UFM) and applied to a system that included both an older, adjacent passive well ("parent" well) and an active well ("child" well). Herein, the theoretical framework for overall complex fracture modeling is described. Furthermore, numerical simulation results are presented, demonstrating the critical roles of in-situ stress distribution and pre-existing natural fractures and aiding in the development of appropriate strategies for managing FDIs. [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]

Steam-assisted gravity drainage (SAGD) methods have been widely applied in oil-sands exploitation globally. SAGD processes are effective only after thermal and hydraulic communication between the injector and producer has been established during the start-up operation of the well pair. The geomechanical SAGD dilation startup has been considered a promising technology that can enhance permeabilities of heavy-oil reservoirs and reduce thermal conformance time. However, limited studies have focused on the practical operational procedures of geomechanical SAGD dilation startup. This paper presents the application of SAGD dilation startup technology in a shallow super heavy-oil reservoir in the Karamay oil field, China. The general reservoir geology and geomechanical characteristics were investigated and used to propose a practical approach to determine dilation initiation pressure. We also summarize the SAGD well completions and geomechanical SAGD dilation startup procedures. A case study using a real SAGD well is presented and analyzed. We then share the field operation procedures and results after dilation startup. The objective of the research was to reduce the steam circulation time and achieve uniform thermal conformance along the SAGD well. Our field results highlight the promising potential of using water injection to create a dilated zone and dramatically enhance reservoir permeability. The performance of SAGD dilation startup in the Karamay oil field is evaluated by comparing the cumulative oil production rate with those from SAGD wells using conventional startup. • The geomechanical properties of Karamay heavy oil reservoirs are characterized. • A practical approach to determine dilation initiation pressure for SAGD startup is proposed. • A field case study of geomechanical SAGD dilation startup is presented and analyzed. [ABSTRACT FROM AUTHOR]