Hydraulic Fracturing In Horizontal Wells Research Articles

Multiple hydraulic fracture propagation simulation in deep shale gas reservoir considering thermal effects

Deep and ultra-deep shale gas will gradually become the focus of unconventional oil and gas resources in the petroleum industry. In the development of shallow shale reservoirs, the multi-cluster hydraulic fracturing of horizontal wells is the commonly applied technique to create a network of fractures and achieve reservoir stimulation. However, for deep shale reservoirs, the behavior of multiple hydraulic fracture propagation is affected by stress interference between fractures. On the other hand, it is also influenced by the temperature disturbances caused by the injection of low-temperature fracturing fluids into high-temperature formations and the resulting thermal effects. Currently, most research on multiple hydraulic fracture propagation in shale only considers the interaction between fluids and solids while neglecting thermal effects. Therefore, based on the displacement discontinuity method, finite volume method, and finite difference method, this study established a numerical model for the non-planar propagation of multi-cluster hydraulic fractures in deep shale, considering the thermal effects. And the model was validated through numerical solutions of the temperature field and double-fracture propagation. Moreover, the number of fracture clusters, pumping rate, and formation temperature were selected as influencing factors, and the differences in multiple hydraulic fracture propagation with and without considering thermal effects were analyzed. The results show that as the formation temperature increases, the thermal effects become more significant, leading to greater differences in the morphology of multi-cluster fractures. Moreover, the thermal effects are more significant when the formation temperature exceeds 90 °C. Additionally, appropriately reducing the number of fracture clusters or increasing the pumping rate can to some extent mitigate stress interference between fractures and promote uniform fracture propagation. The findings of this study contribute to understanding the influence of thermal effects on multiple hydraulic fracture propagation and provide theoretical basis for the efficient development of deep shale gas.

FOUNDATION AND ASSESSMENT OF OPTIMAL FRACTURE GEOMETRY IN MULTI-STAGE HYDRAULIC FRACTURING OF HORIZONTAL WELLS

The article is dedicated to the calculation and assessment of the optimal geometry of fractures in the context of conducting hydraulic fracturing in horizontal wells. The significance of correctly determining the geometry of fractures to maximize well productivity and the efficiency of the hydraulic fracturing process is considered. The paper analyzes various methods for calculating and evaluating the optimal geometry of fractures, including numerical modeling, experimental research, and practical observations.Additionally, the article covers the results of experimental studies aimed at analyzing the behavior of fractures in different geological conditions. These studies include the analysis of physical and mechanical properties of rock formations, as well as the influence of well parameters on fracture formation. The obtained results can be useful for engineers and specialists in the oil and gas industry in designing and conducting hydraulic fracturing operations to increase hydrocarbon recovery from reservoirs.

Simulation and optimization of unstable dynamic propagation of multiple fractures in the shale formation

Multi-cluster hydraulic fracturing of horizontal wells is a well-adopted technique with high efficiency to increase the production of tight and shale formations. However, the stress shadows among clusters pose challenges to the synchronous propagation of hydraulic fractures during multi-cluster fracturing. In order to explore the fracture propagation mechanism and characteristics under the influence of stress shadow in low-spacing staged multi-cluster fracturing, a three-dimensional hydraulic fracturing model was generated using a lattice-based method. This model considered the impact of geological and engineering parameters on the propagation behavior of multiple fractures in shale formation. A variable pumping approach is adopted, where the fracturing fluid is initially injected at a high rate and then transitioned to a lower rate. Afterward, a method was proposed to quantitatively assess the extent of fracturing in a specific area (i.e., the stimulated area), considering the impact of stress shadow within a single stage. The simulation results demonstrated significant differences in the fracture stimulation area due to the influence of each parameter in the case of uncontrollable geological factors and controllable engineering factors. An increase in both Young’s modulus and stress anisotropy of the reservoir results led to a corresponding increase in the total fracture stimulation area. As the principal stress orientation increased, the fracture stimulation area gradually decreased. In terms of operational parameters, the stimulated area of hydraulic fractures gradually decreased as the fracture spacing increased. With increasing injection rate, the stimulated area initially expanded and then decreased, peaking at an injection rate of 0.04 m3/s. These findings can provide valuable insights into the propagation behavior of multi-cluster hydraulic fractures under uncertain parameters, with significant implications for future engineering applications.

Hydraulically Fractured Horizontal Wells: A Technology Poised To Deliver Another Energy-Related Breakthrough of Enormous Scale

_ The development of efficient technologies for drilling and hydraulically fracturing horizontal wells has enabled the US to more than double hydrocarbon production since 2005 (Fig. 1), thereby providing unprecedented levels of energy security for America. America’s doubling of hydrocarbon output has also held down the price of energy worldwide, and by doing so, accelerated global economic growth. And it has helped reduce the greenhouse gas (GHG) intensity of energy production by backing out “dirtier” forms of energy, such as coal. Energy security—economic growth—reduced GHGs vented to the atmosphere: That’s a winning combination. One that America and many other countries have benefitted from immensely. Given the enormous positive contributions, it is worth noting that 20 years ago, few if any in our industry foresaw the immense potential of this technology, seeing it as being only applicable for extracting gas from ultratight reservoirs like the Barnett Shale, if they were aware of the technology at all. This oversight caused many companies to wait too long before deciding to pursue unconventional reservoirs and caused several of the “shale gas” pioneers to be late in recognizing that hydraulically fractured horizontal wells (HFHWs) could also be successfully applied in liquid-rich plays such as the Eagle Ford and Permian Basin. These are plays that today deliver far more value than that derived from the gas-prone reservoirs that comprised the initial suite of targets. And while events have proven beyond a doubt that HFHWs are a powerful tool for economically extracting hydrocarbons from both gas-prone and liquids-rich unconventional reservoirs, it seems likely that many in our industry are overlooking a third significant application of this technology: The use of HFHWs to extract heat from the Earth’s crust that can be utilized to generate electricity. Old Story, New Horizon What makes this third application particularly compelling as an investment opportunity is that the primary physical challenge that needs to be overcome to achieve attractive rates of return is strikingly similar to that which the oil and gas industry had to surmount to make both gas and liquids-rich unconventional reservoirs economic. The key to success in all of these cases boils down to an ability to create via hydraulic stimulation a sufficiently large amount of conductive, connected, fracture surface area. With this, one can reliably expect per-well production rates to be economic given the extremely slow rate at which hydrocarbons—and heat—move through unconventional reservoirs and the hot, dry, basement rocks that contain the bulk of the world’s geothermal resources. That converting from vertical to horizontal well geometries was critical for unlocking the potential of unconventional hydrocarbon reservoirs is now obvious, with this switch having allowed petroleum engineers to increase per-well fracture surface areas by several orders of magnitude. This move increased per-well flow rates by similar amounts (i.e., from subeconomic flow rates from hydraulically fractured vertical wells (HFVWs) to flow rates of thousands of BOE/D from HFHWs.

Numerical Simulation of Fracture Flow Interaction Based on Discrete Fracture Model

Hydraulic fracturing of horizontal wells is a common method for enhancing production in low-permeability and unconventional oil reservoirs. However, due to the interference between fractures, issues such as decreased production and water channeling often occur in hydraulic fracturing of horizontal wells. Therefore, studying how to mitigate the effects of fracture interference is of great significance for optimizing hydraulic fracturing design and improving oil and gas recovery rates. In this paper, an oil–water two-phase discrete fracture model was established, and the grid dissection was carried out by using the optimization method to obtain a triangular grid that can finely characterize the fracture in geometry. Then, typical discrete fracture models were designed, and the influences of the fracture permeability ratio, absolute fracture scale, oil–water viscosity ratio, and fracture length on the fracture flow interference were investigated separately. The degree of fracture interference was evaluated using the fracture fractional flow rate ratio, remaining oil saturation, and sweep efficiency. This study verified fracture interaction and identified that the threshold value of the fracture permeability ratio is 9 to classify the degree of interference. Sensitivity analysis shows that the absolute size of the fracture has a significant impact on fracture interference, while the impact of the oil–water viscosity ratio and fracture length on fracture interference is relatively small.

Investigation on Invasion Depth of Fracturing Fluid during Horizontal Fracturing in Low-Permeability Oil Reservoirs with Experiments and Mathematical Models

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.

Study on the Fracture Propagation in Multi-Horizontal Well Hydraulic Fracturing

Multi-horizontal well hydraulic fracturing is a widely employed and highly effective method for stimulating tight and shale reservoirs. However, most existing studies primarily focus on investigating the impact of intra-well interference on fracture propagation while neglecting the influence of inter-well interference. Here, a multi-well hydraulic-fracture-propagation model is established to examine the effects of inter-well interference on fracture propagation within a multi-well system. In this study, based on the bilinear T-S criterion, the stiffness degradation is used to describe the damage and evolution process of fracture, the coupling process of fluid flow and solid damage and deformation is realized, and the dynamic distribution of inter-fracture flow is realized by using Kirchhoff function on the basis of the cohesive zone method (CZM) finite element model. Finally, the fracture-propagation model of multiple horizontal wells is established. Based on this model, the mechanism of inter-well interference on fracture propagation is studied, and the influence law of Young’s modulus and fracture displacement on fracture propagation in multi-wells is investigated. The results show that the reservoir can be divided into self-influence area, tension area and compression area according to the stress distribution state in the hydraulic fracture propagation of multi-wells. The propagation rate of hydraulic fractures in horizontal wells is significantly accelerated when they propagate to the local tension area generated by the fracture tip of neighboring wells, and rapidly decreases as the hydraulic fractures continue to propagate to the compression area of neighboring wells. Rocks with a lower Young’s modulus tend to be more plastic, forming hydraulic fractures with usually lower fracture lengths and usually larger fracture widths. The hydraulic fracture has an inhibitory effect on the propagation of fractures closer to each other in neighboring wells, and this inhibitory effect gradually increases as the distance decreases. The dominance of the dominant fracture to propagate in the self-influence area gradually decreases under inter-well and intra-well interference. As the dominant fracture propagates into the tension and compression areas of the neighboring well fractures, the feed fluid will show a brief rise and then eventually stabilize. This study quantifies the effect of inter-well interference on fracture propagation and lays the foundation for treatment optimization of small well spacing hydraulic fracturing.

Numerical simulation of fracturing and imbibition in shale oil horizontal wells

The shale oil reservoir is characterized by tight lithology and ultra-low permeability, and its efficient exploitation requires the technology of multi-stage and multi-cluster hydraulic fracturing in horizontal wells and shut-in imbibition. After multi-stage and multi-cluster hydraulic fracturing, a complex fracture network is formed, and a large volume of frac fluid is stored within the fracture network. During shut-in, imbibition and exchange between oil and water occurs under the action of the capillary force and osmotic pressure, and the formation pressure builds up in the shale reservoir. On basis of the characteristics of shale oil reservoir, we establish a model of imbibition during fracturing injection and shut-in by coupling oil–water two-phase flow and saline ion diffusion in the hydraulic fractures (HFs) network, natural fractures (NFs) and matrix system under the action of capillary force and osmotic pressure. The DFN method and the multiple continuum method are introduced to characterize fluid flow between the HF and the NF and that between the NF and the matrix respectively, which avoids the problem of a large amount of computation of seepage within the complex fracture. Then, the discrete fracture network (DFN) model and the multiple continuum model are solved with the finite element method, and it is verified in flow field, saturation field and concentration field that the models are accurate and reliable. We propose the imbibition exchange volume for quantitative evaluation of the imbibition degree and a method of calculating the imbibition exchange volume. Simulation of oil and water flow in the fracturing and shut-in stages is performed based on these models. It is found that imbibition in the shale reservoir is driven by mechanisms of pressure difference, capillary force and osmotic pressure. The osmotic pressure and capillary force only cause an increase in the imbibition rate and a reduction in the imbibition equilibrium time and do not lead to variation in the peak of imbibition exchange volume. The imbibition equilibrium time under the action of the capillary force and osmotic pressure is reduced from 150 to 45 d compared with that under the action of the pressure difference. If imbibition equilibrium is reached, low initial water saturation, strong rock compressibility, high formation water salinity and high matrix permeability enhance imbibition and exchange of oil and water in the reservoir. The leakoff volume of frac fluid is generally larger than the imbibition exchanged volume. Leakoff equilibrium occurs slightly earlier than imbibition equilibrium. The imbibition equilibrium time is mainly affected by reservoir permeability and NF density. The number of interconnected fractures mainly affects the frac fluid volume within the hydraulic fracture in the fracturing process. The stimulated reservoir volume (SRV) mainly affects frac fluid imbibition exchange in the shut-in process.

Evaluation of hydraulic fracturing of horizontal wells in tight reservoirs based on the deep neural network with physical constraints

Accurate diagnosis of fracture geometry and conductivity is of great challenge due to the complex morphology of volumetric fracture network. In this study, a DNN (deep neural network) model was proposed to predict fracture parameters for the evaluation of the fracturing effects. Field experience and the law of fracture volume conservation were incorporated as physical constraints to improve the prediction accuracy due to small amount of data. A combined neural network was adopted to input both static geological and dynamic fracturing data. The structure of the DNN was optimized and the model was validated through k-fold cross-validation. Results indicate that this DNN model is capable of predicting the fracture parameters accurately with a low relative error of under 10% and good generalization ability. The adoptions of the combined neural network, physical constraints, and k-fold cross-validation improve the model performance. Specifically, the root-mean-square error (RMSE) of the model decreases by 71.9% and 56% respectively with the combined neural network as the input model and the consideration of physical constraints. The mean square error (MRE) of fracture parameters reduces by 75% because the k-fold cross-validation improves the rationality of data set dividing. The model based on the DNN with physical constraints proposed in this study provides foundations for the optimization of fracturing design and improves the efficiency of fracture diagnosis in tight oil and gas reservoirs.

Interaction of natural and hydraulic fractures: the impact on reservoir pressure buildup and risk of shear fault reactivation in the Upper Devonian Duvernay Formation, Fox Creek, Alberta

The interaction of natural and hydraulic fractures may facilitate lateral fluid propagation in an unconventional reservoir resulting in fast fluid pressure transmission from treatment wells to a fault zone and potential fault shear slip reactivation and associated induced seismicity. Several induced earthquakes (up to 4.1 Mw) occurred since 2013 during hydraulic fracturing of the Upper Devonian Duvernay Formation in the Western Canada Sedimentary Basin. The mechanism of lateral fluid migration in the unconventional reservoir is not well understood. The current study aims to investigate the interaction of natural fractures and hydraulic fractures for the case study in the area south of Fox Creek, where a linear zone of induced earthquakes (up to 3.9 Mw) occurred along a fault in 2015 during hydraulic fracturing of horizontal wells. We analyze the growth of hydraulic fractures in presence of natural fractures, the impact of resulting complex fracture network on fluid transmission and fluid pressure buildup around the treatment wells. Hydraulic fracture modeling (HFM), reservoir simulations and 3D coupled reservoir-geomechanical modeling are applied to match the timing of hydraulic fracture propagation and transmitted fluid pressure increase in the fault zone versus induced earthquake occurrence. HFM results are verified by microseismic clouds distribution. Reservoir simulations are validated by a history matching of fluid injection volume and bottomhole pressure data. Additional HFM simulations are carried out to optimize the pumping schedule in the studied well pad that would help to prevent hydraulic fractures reaching the fault and minimize the risk of induced seismicity.Article highlightsStress anisotropy and simulated natural fractures impact lateral growth of complex hydraulic fractures and reservoir pressure buildup.Predicted fluid pressure transmission to a fault zone results in fault dextral shear slip reactivation matching induced seismicity.Optimized pumping schedule helps to minimize risks of fault reactivation and induced seismicity while preserving overall pad performance.

Geochemical insights from formation waters produced from Wolfcampian and Leonardian intervals of the Midland Basin, Texas, USA

The lower Permian of the Midland Basin of West Texas consists of mudrocks with some tight sandstones and carbonate-dominated intervals (Wolfcamp and Spraberry formations) averaging a thickness of 975 m (3200 ft). They have been the target of a large revitalization of oil and gas production from the basin using hydraulic fracturing stimulation and horizontal well technology. Little is known about the aqueous geochemistry of these intervals. We sampled produced formation water from 53 wells across the basin and put them in the context of the basin flow history. Analyzing for major and minor elements and stable water and strontium isotopes, we determined that: (1) TDS values vary from 72 to 135 g/L, decreasing with increasing depth and increasing stratigraphic age; (2) ionic composition is consistent with that of Na–Cl brines found elsewhere in the basin with no major impact of meteoric input or halite dissolution as sometimes seen in the Permian Basin; (3) stable water isotopes (δ18O +5.0 ± 2.0‰ and δ2H −28 ± 5‰ VSMOW) are enriched; slightly radiogenic 87Sr/86Sr ratio is consistent with local carbonates. Interpretative results suggest that the modern resident brines of the low-permeability Lower Permian originated as Permian evaporative brines coeval with Upper Permian thick halite deposition. They would have dolomitized Permian carbonates in their gravity-driven downward migration and been further modified through water-rock interactions, including smectite-illite conversion.

Simulation of gas flow behavior in shale gas reservoir

The importance of shale gas production in altering the global energy system is growing. There is consensus that hydraulic fracturing in horizontal wells is the most cost-effective and efficient method for accessing shale gas resources. For hydraulic fracturing to be successful in the long run as shale gas production expands, a number of key characteristics must be optimized. The research focuses on the development of reservoir simulators (Companion of St. Michael and St. George-International Monetary Exchange (CMG-IMEX)) and analyzing the parameters, which have a major impact on gas flow in the shale gas reservoir. In the process of gas flow characterization, the approach is to consider a dual porosity model for analyzing the reservoir simulation model of a shale gas reservoir. With the use of a model, we are able to analyze the flow of shale gas from tight reservoirs through the conductive fractures to the wellbore. The development of this research could lead to enhanced production from the shale gas wells.

Analysis of the Induced Stress Fields Around Hydraulic Fractures Considering the Influence of Natural Fractures and Bedding Planes.

Natural fractures (NFs) and bedding planes (BPs) are well developed in shale reservoirs. The propagation of hydraulic fractures (HFs) and the opening of NFs and BPs can produce induced stress fields (ISFs) within the fracturing process, causing interference to the in situ stress field. Aiming at the "stress shadow" effect among HFs in horizontal wells, the calculation models of HFs, BPs, and NFs for induced stress distributions are established based on displacement discontinuity theory, which can quantitatively characterize the composite ISF of the three under different connecting states. In addition, the interference coefficient of stress intensity factor (ICSIF) is introduced to quantitatively evaluate the interference degree of the composite ISF to the propagation of HFs. The results show that: (1) the ISF forms a "tensile stress concentration zone" near the fracture surface to promote the HFs opening and a "compressive stress concentration zone" at the fracture tips to suppress the propagation of HFs; (2) the ISF forms an elliptical effective swept area around the fracture, which is affected by the propagation height of HFs, while NFs or BPs generate local disturbances to the ISF; (3) the in situ stress reverses in the swept area, and the stress reversal interval is related to the in situ stress difference, fracture propagation height, Poisson's ratio, fracture net pressure, and fracture spacing; (4) the reasonable fracture spacing and fracture propagation height of horizontal wells can be determined by the ICSIF. The study can provide theoretical guidance for optimizing the fracture spacing and promoting the uniform propagation of multiple fractures in staged fracturing of horizontal wells.

Analytical model of hydraulic fracturing horizontal well gas production capacity of a water-bearing tight sandstone reservoir considering planar heterogeneity

Previous models of the gas-production rate of hydraulic fracturing horizontal wells were by assuming permeability heterogeneity, which is unrealistic in water-bearing tight gas reservoirs because of sandstone–mudstone crossover. Therefore, we develop an analytical model to describe the gas-production dynamics of hydraulic fracturing horizontal wells that consider permeability heterogeneity. In addition, threshold pressure gradient, stress sensitivity, and slippage are incorporated into the model. To solve this model analytically, the elliptical flow is transformed to radial flow by conformal transformation. The gas-production rate, reservoir pressure distribution, and average formation pressure are obtained by superposition principle, boundary pressures are calculated by material balance method, and the dynamic supply boundary propagation is modeled by steady-state sequential replacement. Actual field production data from Ordos Basin, China, is used to verify the new model, which increases the accuracy by 11.3% over previous models (98.6% vs 87.3%). The propagation distance of the dynamic supply boundary is predicted (in the fracture direction, it is 109.3 m, and in the vertical fracture direction, it is 44.2 m). We analyze how stress sensitivity, the dynamic threshold pressure gradient, matrix permeability, pressure difference, and initial water saturation affect gas production rate and dynamic supply boundary. Based on orthogonal experimentation, the factors affecting the gas production rate and dynamic supply boundary of tight gas reservoirs can be ranked in the following order: pressure difference > permeability > initial water saturation. This analytical model can accurately characterize gas production and pressure response, and it is easy to use and rapid to calculate.

Initiation and Propagation of Multiple Fractures in the Horizontal Well of Shale Reservoirs Under Pulse Injection Hydraulic Fracturing

Pulse injection hydraulic fracturing (HF) can release high-energy peak pressure in a split-second, forming a complex hydraulic fracture network in shale reservoirs. However, the initiation and propagation of multiple fractures in the horizontal well of shale reservoirs under pulse injection HF have been inadequately studied. Hence, in this study, a HF model coupling the fracturing fluid flow along the fracture and the rock deformation was adopted, and the effect of the pulsed injection method on multistage HF of horizontal wells was determined. The results show that the pulsed injection HF can improve the fracturing effect of horizontal wells. However, no matter how the injection displacement and pulse frequency change, the propagation length of cracks at both ends seriously disturbed by stress almost remains unchanged. When the dominant fracture is temporarily shielded, the fluid pressure of the non-dominant fractures at both ends disturbed by stress compression increases, and the non-dominant fractures can be further expanded. Thus, a new composite multistaged HF scheme suitable for horizontal wells with pulse-temporary shielding in shale reservoirs was proposed. The method presented here can be adopted to optimize the fracture growth regime and provide a scientific basis for the fracturing operation of the horizontal well in shale reservoirs.

Physical and numerical simulation of inter-fracture flooding in heterogeneous tight oil reservoirs

The existing tight oil reservoirs are mainly developed after hydraulic fracturing of horizontal Wells with low recovery. Traditional enhanced oil recovery (EOR) methods are difficult to apply in tight reservoirs, because huff-puff drives oil to the distal end, water breakthrough exists in inter-well flooding, and ASP flooding cannot enter the small pore throat of the tight reservoir. A new EOR method of inter-fracture flooding is proposed. This method solves the problem that the injection water cannot enter the matrix in tight reservoir by inter-fracture flooding. Inter-fracture flooding reduces the distance between the injection and production ends and reduces the risk of water channeling. Inter-fracture flooding increases the pressure gradient during water flooding in the reservoir and establishes an effective water displacement system in the heterogeneous tight reservoir. In this paper, physical simulation experiments and numerical simulation are designed to study the EOR effect of inter-fracture water flooding in heterogeneous tight reservoirs. The results showed the following: (1) Inter-fracture asynchronous water flooding (IFAWF) can improve oil displacement efficiency by 6%–16% compared with inter-fracture synchronous water flooding (IFSWF). (2) Compared with IFSWF, IFAWF can greatly improve the oil displacement efficiency of the core with low permeability in the heterogeneous model by more than 20%. (3) Effective water sweep cannot be achieved by IFSWF, but can be achieved by IFAWF. (4) IFAWF established effective displacement in 0.1mD tight heterogeneous reservoir. Studies have shown that inter-fracture flooding can lower the reservoir development permeability threshold and will be an important EOR method for tight oil and shale oil in the future.

An effective integration optimization algorithm for regional fracturing design and drilling placement

Hydraulic fracturing horizontal well technology has a pivotal role in exploiting unconventional resources, but it often requires considerable investment. Integrated optimization of the fracturing design, horizontal well, and drilling platform placement in the whole region is an efficient way to reduce cost and increase economic benefits. However, it is difficult to quickly complete these optimizations because traditional reservoir numerical simulation requires extensive resources in terms of labor, time, and computation. Therefore, we proposed a new algorithm, named Gaussian Process Regression-Bilevel Programming Genetic-Critical Circle Intersection Momentum Shift (GPR-BPG-CCIMS) algorithm to effectively co-optimize the fracturing design, horizontal well and drilling platform placement in the whole region. BPG algorithm shares the merits of Bilevel Programming (BP) and genetic algorithm (GA), which is used for optimizing the horizontal well and fracturing parameters. CCIMS algorithm is applied to optimize the drilling platform placement by merging and shifting drilling platform positions. GPR model is a production proxy model based on machine learning to improve optimization efficiency. The proposed algorithm was applied to a real shale gas reservoir to verify the effectiveness of the algorithm. The results showed that the GPR model exhibited great prediction accuracy by providing the high coefficient of determination (R2 = 0.999), the high percentage of accuracy-precision (PAP = 99.017) and the low root mean square error (RMSE = 0.022). The optimal fracture half length, cluster spacing, fracture fluid per meter, horizontal section length, well location, and drilling platform location were obtained by GPR-BPG-CCIMS algorithm. Compared with the actual net present value (NPV), the optimized NPV was increased by 181 million dollars. The proposed algorithm successfully co-optimizes the engineering parameters of the whole region in a short consumption time, which effectively supports the development scheme design and decision-making. The optimization framework can be extended to other shale gas basins.

Unified transient analysis (UTA) of production and shut-in data from hydraulic fractured horizontal wells

Market-induced production shut-downs and restarts offer us an opportunity to gather step-rate and shut-in data for pressure transient analysis (PTA) and rate transient analysis (RTA). This study presents a unified transient analysis (UTA) to combine PTA and RTA in a single framework. In this new approach continuous production data, step-rate data, shut-in data and re-start data can be visualized and analyzed in a single superposition plot, which can be used to estimate both A f k and infer formation pore pressure in a holistic manner by utilizing all available data. Most importantly, it shows that traditional log-log and square root of time plots can lead to false interpretation of the termination of linear-flow or power-law behavior. Field cases are presented to demonstrate the superiority of the newly introduced superposition plot, along with discussion on the calibration of long-term bottom-hole pressure with short-term measurements. • A unified transient analysis (UTA) is proposed to unify rate and pressure transient analysis of hydraulic fractured horizontal wells. • Inexpensive short-term bottom-hole pressure measurement is beneficial to calibrate long-term bottom-hole pressure. • Traditional log-log plot and square root of time plot may falsely interpret formation linear-flow as power-law behavior. • Hydraulic fracture surface area can be overestimated if only surface measurements are used.

Study on temperature distribution prediction of horizontal wells during fracturing treatment

In recent years, fiber-optic distributed temperature sensors (DTS) have been widely used for the dynamic monitoring of horizontal well during fracturing treatments. It is proposed to address the frequent issues of unknown artificial fracture initiation location, unclear crack extension pattern, unknown fracturing fluid injection success, and difficult fracturing effect evaluation in the hydraulic fracturing of horizontal wells. The temperature prediction model is the basis for fracturing diagnosis based on DTS monitoring, however, the quantitative prediction of temperature distribution throughout the horizontal well fracturing process remains a challenge. In this paper, a set of temperature-distribution prediction model for multi-stage fracturing in horizontal wells is established, with various micro-heat effects taken into account, and the models are solved through coupling. The temperature distribution during multi-cluster fracturing, and the temperature distribution characteristics during staged fracturing of horizontal wells have been analyzed. Moreover, the influence of fracturing fluid displacement, formation filtration coefficient, fracture width, and height on temperature distribution has also been clarified. The findings of this study provide theoretical support for fracturing performance diagnosis, fracture initiation identification, and analysis of the whereabouts of fracturing fluids using DTS monitoring. It has a great significance on fracturing effect evaluation and fracturing design optimization for horizontal wells.

Experimental research on inter-fracture asynchronous injection-production cycle for a horizontal well in a tight oil reservoir

One of the existing tight oil reservoir development methods is development after hydraulic fracturing of horizontal wells. This type of development method severely limits the recovery rate of tight oil reservoirs. The other conventional enhanced oil recovery methods are not suitable for tight oil reservoirs. The water injection performance of fractured vertical wells is poor, and water breakthrough easily occurs during water injection in horizontal wells. In order to improve the recovery factor of tight oil reservoirs and to achieve sustainable development of tight oil reservoirs, finding a suitable method of enhancing the recovery factor of tight oil reservoirs is the top priority. Based on the concept of periodic asynchronous water flooding to supplement energy between horizontal fractures, in this paper, an effective method of improving the recovery rate of tight oil reservoirs is discussed. Physical simulation experiments were designed to improve the recovery efficiency of horizontal wells with an inter-fracture asynchronous injection-production cycle (IFAIPC). The feasibility of the method was verified. Two different sets of experiments were designed: 1) the experiment that simulates a homogeneous reservoir with a section with two fractures (M1), and 2) an experiment that simulates a heterogeneous reservoir with three sections of four fractures (M2) and the fourth section with five fractures (M3). The results show that during the IFAIPC process, the permeability of the rock sample tends to decrease gradually. In particular, in the first five cycles, the permeability decreases significantly. Water injection becomes difficult as the permeability decreases, and there is a feasible critical value for water injection. In homogeneous reservoirs, water breakthrough is slow. The degree of recovery and the ultimate recovery rate before water breakthrough are high. The use of IFAIPC in heterogeneous reservoirs can effectively increase the swept volume and delay the rise of water saturation. The IFAIPC method can effectively improve the recovery of tight oil reservoirs by more than 10% in the first five injection-production cycles. The experiments confirm the feasibility and effectiveness of using the IFAIPC method in tight oil reservoirs.