Multistage Fracturing Technology Research Articles

Research on Production Prediction Method of Multi-stage Fractured Shale Gas Horizontal Well

Abstract Shale gas is a crucial component of unconventional energy. Productivity evaluation of gas wells is essential to ensure efficient and stable production. However, predicting productivity has been challenging due to the complex characteristics of shale gas reservoirs and the use of multi-stage fractured horizontal wells (MFHW) technology in the development process. This study compares traditional production prediction methods with an optimized least squares support vector machine model (LSSVM). The traditional productivity prediction method involves establishing a mathematical model of the MFHW in a fully enclosed rectangular shale formation. The model considers the effects of shale gas adsorption, diffusion, and pressure sensitivity. The model’s analytical solution is obtained using Duhamel’s principle, Laplace transform, and inverse transform. An independent production data analysis software is developed based on the analytical solution of bottom-hole pressure to predict production. To implement the LSSVM model, the model’s input parameters must be determined first. The LSSVM model’s regularization parameters and kernel parameters are obtained through the particle swarm optimization (PSO) algorithm, and the prediction model is established. The model’s matching is evaluated by calculating the coefficient of determination (R2) and the normalized root mean square error (NRMSE). The results indicate that the traditional production capacity prediction method is suitable for stable production in terms of applicability. However, the LSSVM model does not have this limitation and generally provides more accurate predictions throughout the entire production process. For complex shale gas reservoirs that frequently switch wells and use multi-stage fracturing technology, the LSSVM model is more suitable for predicting shale gas well productivity.

Study on Fracturing Parameters Optimization of Horizontal Wells in Low-Permeability Reservoirs in South China Sea

The oil and gas resources in the deep Paleogene system of the South China Sea are abundant. However, due to its poor reservoir physical properties and strong heterogeneity, the deep Paleogene system needs to be commercially exploited by hydraulic fracturing technology. In view of the challenges of offshore low-permeability reservoirs, large-scale fracturing is not allowed because of the limited operation sites and complex string structure. Taking the H oilfield in the South China Sea as the target, based on the concept of the integration of geologic and engineering techniques, parameters such as the number of fracturing stages and the fracture length were optimized by a numerical simulation, and a study on the slurry rate and fracturing scale was carried out based on the type of fracturing and the pipe string structure. The results show that multistage fracturing technology is available in low-permeability offshore oil fields. It is suggested to adopt networking fracturing technology with a “slick water + high slurry rate” framework. A higher rate is recommended, and the fracturing scale of each stage should be 50 m3 of the sands and 700 m3 of the fluids. This research provides a new model for offshore low-permeability oilfield development.

Application of Acid Fracturing Technology to Improve Water Yield of Deep Carbonate Geothermal Wells

To achieve the “carbon peak” goal, green and low-carbon energy development is the key. The development and utilization of geothermal resources and the development of deep carbonate geothermal wells in China are analyzed. Based on the principle of chemical reaction between hydrochloric acid and the main components of carbonate rock, four rock samples from geothermal wells were dissolved with 15% and 20% hydrochloric acid, respectively. The comparison showed that 15% hydrochloric acid was more economical and effective. The percolation capacity of acid dissolution fractures was tested through percolation capacity experiments, and the optimal amount of acid solution was determined to be 2-8 PV. It was verified that acid dissolution helps improve fracture percolation capacity. Through the on-site testing of acid fracturing technology in the Xiong’an New Area, it has been verified that the on-site implementation of multi-stage acid fracturing has a significant effect on increasing production. Finally, conclusions are drawn. The method of using acid solution dissolution to increase the water yield of deep carbonate geothermal wells is feasible, and the multi-stage acid fracturing technology is suitable for deep wells and can increase the water output of geothermal wells, which has good promotion value.

Numerical simulation of proppant transport from a horizontal well into a perforation using computational fluid dynamics

With the increasing global demand for oil and gas, the development of unconventional resources such as shale gas is becoming ever more important. The key to developing unconventional oil and gas resources lies in horizontal wells with multistage fracturing technology. In the process of horizontal well segmentation fracturing, the distribution of the proppant among multiple clusters has a significant influence on the fracturing effect. However, the influence of various factors on the entry of proppant into the perforation and then into the fracture along the wellbore is unclear. In this paper, based on the flow characteristics of proppants in fracturing fluids, we investigate the wellbore–perforation proppant transport using a Eulerian multiphase flow model. The effect of different factors on proppant entry into the perforation in horizontal wells is studied. We first verify that the computational fluid dynamics model satisfies the accuracy requirements for studying the sand-carrying efficiency of proppants in a perforation cluster. Second, the effects of the proppant size, proppant density, fracturing fluid viscosity, perforation diameter, and fracturing fluid flow rate on the proppant transport efficiency are investigated. Finally, a mathematical model of the sand-carrying efficiency is established by multivariate nonlinear fitting. The results show that the proppant size has a more significant effect on proppant settling at low wellbore flow rates. Increasing the diameter of the proppant particles can accelerate proppant settling. Higher wellbore flow rates tend to reduce the sand-carrying efficiency, although using a low-density proppant can mitigate the effect of the wellbore flow rate. At low wellbore flow rates, increasing the perforation size makes it easier for the proppant to enter bottom perforations. Increasing the fluid viscosity helps to distribute the proppant evenly between perforations in different directions, but this effect diminishes as the flow rate increases. Finally, a formula for the wellbore sand-carrying efficiency is obtained and validated, providing a basis for optimizing the distribution of the proppant in the perforation. The results from this paper enhance our understanding of the sand and fluid feeding patterns of each perforation cluster and provide direction for improving the construction process and enhancing the fracture inflow capacity.

Applications of Differential Effective Medium (DEM)-Driven Correlations to Estimate Elastic Properties of Jafurah Tuwaiq Mountain Formation (TMF)

Organic-rich mud rocks are being developed on a large scale worldwide, including in the Middle East. The Jurassic Tuwaiq Mountain Formation (TMF) in the Jafurah Basin is a potential world-class unconventional play. Based on a petrophysical evaluation of the Jafurah basin, the TMF exhibits exceptional and unconventional gas characteristics, such as a high total organic content (TOC) and low clay content. Additionally, the TMF is in the appropriate maturity window, indicating that it has reached the required level of thermal maturity to generate hydrocarbons. Plans for the development of the Jafurah unconventional field use multistage hydraulic fracturing technology. The elastic properties of the shale formation, particularly its Young’s modulus and Poisson’s ratio, dictate how the rock responds to stress and deformation. These properties strongly impact the growth of hydraulic fractures in shale formations. Without a comprehensive understanding of the elastic properties, predicting the bulk mechanical response of the target zones and surrounding layers would be challenging. Therefore, this study aims to predict the elastic characteristics of the Jafurah shale play considering the variations in carbonate facies, the kerogen volume fraction, and the pore’s geometry. Petrophysical and XRD data were used to estimate the elastic properties of various tiers (geological units) of the TMF (Tiers 1, 2, and 3). Inclusion-based, differential effective medium (DEM) rock physics models were used to estimate the formation’s elastic and velocity properties as a function of the kerogen volume fraction and the pore’s geometry. The results showed that the Young’s modulus as well as the mineral and elastic brittleness indices increase as the volume fraction of calcite increases. At the same time, they decrease due to intensified clay and kerogen volumes. The effect of the TMF’s elastic parameters on the rock brittleness behavior was also investigated by considering the formation’s mineralogy, as well as clay and kerogen contents. The results led to the development of physics-based correlations of the mineral brittleness index as function of the Young’s modulus and Poisson’s ratio for various tiers of the TMF.

The Impact of Formation Anisotropy and Stresses on Fractural Geometry—A Case Study in Jafurah’s Tuwaiq Mountain Formation (TMF), Saudi Arabia

Multi-stage hydraulic fracturing (MsHF) is the main technology to improve hydrocarbon recovery from shale plays. Associated with their rich organic contents and laminated depositional environments, shales exhibit transverse isotropic (TI) characteristics. In several cases, the lamination planes are horizontal in shale formations with a symmetric axis that are vertical to the bedding plane; hence, shale formations are known as transverse isotropic vertical (TIV) rocks. Ignoring the TIV nature of shale formations leads to erroneous estimates of in situ stresses and consequently to inefficient designs of fractural geometry, which negatively affects the ultimate recovery. The goal of this study is to investigate the effects of TIV medium characteristics on fractural geometry, spacing, and stress shadow development in the Jurassic Tuwaiq Mountain formation (TMF) in the Jafurah basin, which is a potential unconventional world-class play. This formation is the main source for prolific Jurassic oil reservoirs in Saudi Arabia. On the basis of a petrophysical evaluation in the Jafurah basin, TMF exhibited exceptional unconventional gas characteristics, such as high total organic content (TOC) and low clay content, and it was in the proper maturity window for oil and gas generation. The unconventional Jafurah field covers a large area that is comparable to the size of the Eagle Ford shale play in South Texas, and it is planned for development through multi-stage hydraulic fracturing technology. In this study, analytical modeling was performed to estimate the fractural geometry and in situ stresses in the anisotropic medium. The results show that the Young’s modulus anisotropy had a noticeable impact on fractural width, whereas the impact of Poisson’s ratio was minimal. Moreover, we investigated the impact of stress anisotropy and other rock properties on the stress shadow, and found that a large stress anisotropy could result in fractures being positioned close to one another or theoretically without minimal fractural spacing concerns. Additionally, we estimated the fractural aspect ratio in different propagation regimes and observed that the highest aspect ratio had occurred in the fractural toughness-dominated regime. This study also compares the elastic properties and confirms that TMF exhibited greater anisotropic properties than those of Eagle Ford. These findings have practical implications for field operations, particularly with regard to the fractural geometry and proppant placement.

Principal characteristics of marine shale gas, and the theory and technology of its exploration and development in China

The exploration and development theory and technology of marine shale gas with shallow burial depth of 3500 m in South China has become mature after more than 10 years of practice. In order to continuously promote the exploration and development of shale gas in China, based on the research results of many scholars, combined with production practice, the main characteristics of marine shale gas in China and the main theory and technology of exploration and development are further summarized. The results show that: (1) The basic characteristics of marine shale gas in southern China are marine deep-water shelf deposition, and organic-rich shale is distributed continuously in a large area; The organic matter is stored in situ after high thermal maturity gas generation, and the gas content of shale is affected by late tectonic activity; The reservoir space is dominated by nano-scale pores, and the reservoir is super-tight and ultra-low permeability, which has no natural productivity without well stimulation; Bedding and natural fracture affect the productivity of shale gas wells; The mechanical properties of shale rock determine the effect of horizontal wells. In the early stage of well production, the production rate is high and the decline is fast, while in the middle and late stage, the rate is low but the production cycle is long. (2) Based on the above characteristics, the theory of “sweet spot” and “sweet interval” of shale gas and the theory of effective development of artificial gas reservoir are established, that is, the sedimentary and tectonic interaction forms the “sweet area” or “sweet spot” of marine shale gas. Gas productivity is determined by geological and engineering factors, so the “sweet spot” must be found to develop. By constructing artificial gas reservoir through “making an artificial high permeability area, and reconstructing a seepage field”, the effective development of ultra-tight and low permeability shale gas reservoirs can be realized. It is the most effective technique for shale gas development to accurately create “transparent geological body” of reservoirs based on geology-engineering integrated evaluation technology and establish artificial gas reservoir through multi-stage fracturing technology. (3) The overpressure area in the southern Sichuan Basin is the “sweet area” for shale gas development. The “sweet interval” of the lower Silurian Longmaxi Formation with a thickness of 3–5 m and high brittle-rich organic matter is the optimal “golden target” for horizontal wells. (4) The development leapfrog from the first generation to the second generation has been realized by the key technology of multi-stage fracturing of horizontal wells. The EUR per well of Upper Ordovician Wufeng Formation and Longmaxi Formation in southern Sichuan has increased from 0.5 × 108 m3 in the initial stage to 1.0 × 108–1.2 × 108 m3 at present with a buried depth of shallower than 3500 m. (5) The effective area favorable for shale gas development in southern Sichuan is 2.0 × 104 km2, and it is estimated that the proven geological reserves of shale gas can reach 10 × 1012 m3. It is preliminarily predicted that the shale gas production in China will exceed 300 × 108 m3 in 2025 and reach 400 × 108 m3 in 2035.

Multi-stage hydraulic fracturing technology in a well with horizontal working face

At present, hydraulic fracturing (HF) is still the most effective method of stimulating hydrocarbon flow and enhancing oil recovery in certain types of wells, particularly those with horizontal endings. In many regions, this is the only technology that enables development of fields with hard-to-recover reserves confined to low-permeability, poorly drained, heterogeneous and dissected reservoirs, which significantly increases hydrocarbon production and makes well construction economically viable. In this work, the authors have developed a new technology for interval hydraulic fracturing in a well with a horizontal target area, with the ability to inject fracturing fluid and hold excess pressure on either side of the fracturing unit by means of flap-type check valves. The fracturing is performed through a transport unit that runs directly through the casing and protects the plug from the abrasive effects of the gel-propellant mixture. After fracturing is complete, the transport unit is removed from the plug, and the rear cut-off valves are closed. No re-entry is possible after the adaptor has been removed from the well. For the next interval, the work cycle of plug, activation and fracturing is repeated using a new transport unit. For each repetition, the newly stimulated interval remains isolated until the fracturing operation is complete and all downstream plugs have been fractured. All installed plugs are drilled out before development. During all phases of the work, it is assumed that the well is prepared without the use of coiled tubing. The novelty and innovation lie in the technological solution of delivery to the target area and using easy-to-drill plugs to guarantee open interval separation and perform selective fracturing. Potential candidates are wells with 114 mm diameter casings with single- or multiple-acting fracturing sleeves to open-close after the horizontal part of the well has been prepared (the ‘equal-pass’ section requirement is for a 95 mm diameter bit). The proposed technical means and technology, in the opinion of the authors, will increase the efficiency of field development, reservoir conditions in which are characterized by low filtration parameters, high viscosity properties, etc. The authors do not think that the proposal will generally solve the problem of intensification of the inflow of reservoir fluid to the well and thereby increase oil recovery from the reservoir, but according to in their opinion, in some respects it will contribute to this. The final results will be obtained based on the results of extensive production tests.

Simulation-based evaluation of the effectiveness of fiber-optic sensing in monitoring and optimizing water circulation in next-generation enhanced geothermal systems

The success of multi-stage hydraulic fracturing technology in unconventional oil and gas reservoir development has attracted much attention from the geothermal community. Some pilot field experiments have been conducted to investigate the multi-stage hydraulic stimulation along horizontal or high-deviated wellbores in geothermal reservoirs (denoted as next-generation enhanced geothermal systems). One common output of such stimulation is that the created hydraulic fractures show various conductive capabilities, which could potentially lead to undesirable flow localization, early thermal breakthrough, and low cold water sweep efficiency. Monitoring the water circulation between horizontal wellbores connected through hydraulic fractures becomes important in avoiding early severe producing temperature reduction in practical operations. In this study, we investigate the effectiveness of distributed temperature sensing (DTS) and distributed strain sensing (DSS) in identifying dominant flow paths in geothermal reservoirs with multi-stage hydraulic stimulation and horizontal well completion designs. A coupled thermo-poro-elastic model for general-purpose geothermal reservoir simulation is developed and solved using a combined finite volume/finite element method, together with a fully implicit sequential coupling scheme. The temperature and strain responses along horizontal production wells are simulated and analyzed during water circulation. Reservoir temperature reduces in the area that is close to the water flow paths, which induces thermal contraction. These thermoelastic characteristics can be monitored by fiber-optic sensing, forming distinct signatures for flow-localization identification. DTS data may be dominantly influenced by the fractures with higher conductivity, ‘masking’ the signals related to fractures in the downstream, but DSS data can provide additional information for accurate identification of high conductive fractures. Successful mitigation strategies, for example plugging the dominant fractures illustrated in this study, could substantially increase the producing fluid temperature. The analyses in this study show that fiber-optic sensing is an effective technology to monitor and optimize water circulation in next-generation enhanced geothermal systems.

Application of multistage acid fracturing technology in deep carbonate thermal reservoirs

As the most common stimulation treatment in carbonate reservoirs, acid fracturing is also frequently used in carbonate geothermal wells, but it has not been applied in deep carbonate thermal reservoirs. The application of a multi-stage acid fracturing technology in Xiong’an deep carbonate thermal reservoir is introduced in this paper. The field application of technology has achieved a good stimulation effect. Multistage acid fracturing technology can effectively communicate the aquifer of carbonate thermal reservoir, improve the length of acid corrosion fracture, increase the conductivity of thermal reservoir and improve the water yield of a geothermal well. The technology is worthy to be popularized.

A new meshless method to solve the two-phase thermo-hydro-mechanical multi-physical field coupling problems in shale reservoirs

The efficient development of shale reservoirs relies on multi-stage hydraulic fracturing technology in horizontal wells involving the difficulty of multi-scale flow for either gas or water phases, which is characterized by the changes in the stress and temperature fields. The original simulation methods are unable to accurately solve the multi-physics field-coupled problems under such complex mechanical conditions or have low stability for two-phase gas-water problems. For this purpose, this study conducted the shale gas production simulation by the meshless finite difference method (GFDM) for the first time to ensure the stability and accuracy of calculations. Bases on the previous multi-sector coupled physical model for shale gas development and proposes a coupled thermo-hydro-mechanical multi-physical field mathematical model considering two-phase gas-water flow. The model is postulated based on different sectors considering various characteristics of gas/water flow, namely desorption attributes, deformation degree and heat transfer characteristics. This method was used to calculate the variation of the multi-physical field and compare the properties of gas-water flow within different reservoir conditions without any non-convergence situation during the calculation. The simulation results indicate that the stress field has a crucial effect on the yield, such that discard of its coupling causes the yield to be overestimated by 12.5%. In contrast, the temperature field has a marginal effect (less than 1%) and can be neglected according to the operating conditions. Furthermore, the stress field significantly characterizes the micro-fracture sector, which is also the major flow-contributor, such that the yield is overestimated by 11% in absence of its coupling, while the effect of stress field in the matrix sector is lower than 1%.

Analysis of Stress State and Damage Characteristics of the Cement Sheath

The sealing problem of the cement sheath often appears in gas wells for underground energy exploitation, especially when horizontal multistage fracturing technology is used in the shale gas industry. In this article, according to the elastic–plastic mechanics and Mohr–Coulomb yield criteria, an analytical solution of the equations is obtained by considering the effect of pressure on the fluid column, volume shrinkage, or expansion and geological characteristics on the initial stress of the cement sheath. The analysis of the example indicates that the smaller the initial stress of the cement sheath, the lower its radial stress and circumferential stress, which is under the maximum inner casing pressure of 150 MPa. With the increase of initial stress of the cement sheath, it is easier for the first and second interfaces to enter the plastic and damage state for the cement sheath. The smaller the initial stress of the cement sheath, the earlier the damage appears, and it develops with the increase of inner casing pressure more quickly. When the initial stress of the cement sheath is less than 7.9 MPa, the damage factor finally reaches 1 with the increase of internal casing pressure; however, when the initial stress of the cement sheath is greater than 34.2 MPa, the damage factor always remains 0 with the increase of inner casing pressure. The results preliminarily revealed that the initial stress of the cement sheath plays a decisive role in promoting its integrity and may provide guidance for the choice of the formula of cement and construction methods in the oil field.

Numerical simulation of single-cluster and multi-cluster fracturing of hydrate reservoir based on cohesive element

Horizontal well multistage fracturing technology has potential as a technical method to improve the permeability of clayey silt natural gas hydrate (NGH) reservoirs as it can increase the contact area between a horizontal well and an NGH reservoir. Although this technology has been successfully applied to the exploitation of shale gas and coalbed methane, the relevant technical experience cannot be directly applied to clayey silt NGH reservoirs. Based on the properties of the clayey silt NGH reservoir at the SH2 site in the Shenhu area of the South China Sea, herein, we established a three-dimensional hydraulic fracturing model based on cohesive elements to analyze the influence of the fracturing fluid injection rate on the initiation and propagation of single-cluster fractures and the influence of fracture spacing on simultaneous fracturing and sequential fracturing of multi-cluster fractures. We comprehensively analyzed the distribution characteristics of fracture morphology and the phenomenon of stress interference between fractures under different conditions. The results showed that without fracture interference, fractures tended to propagate to the middle and upper parts of the reservoir owing to the low fracture propagation resistance. Simultaneous fracturing and sequential fracturing produced different staggered fracture distribution patterns, which were caused by the geostress field changing owing to the generation of fractures. Our findings broaden the understanding of hydraulic fracturing in clayey silt NGH reservoirs.

Numerical Simulation Research on Influencing Factors of Post-Fracturing Flowback of Shale Gas Wells in the Sichuan Basin

The horizontal well multistage hydraulic fracturing technology is the most effective way to exploit shale gas resources. Compared with conventional reservoir fracturing, the flowback rate of a fracturing fluid in a shale reservoir is extremely low, and a large amount of fracturing fluid remains in the formation. Therefore, the research on the mechanism of shale reservoir fracturing fluid flowback process will contribute to laying a theoretical foundation for improving the effect of the innovation for increasing output of shale gas wells. Based on the shale in the Sichuan Basin, this study first describes basic experiments on physical properties such as the porosity, permeability, mineral composition, wettability, and microstructure. The physical properties of shale reservoirs were also analyzed, which laid the foundation for subsequent modeling. Second, CMG software is used to establish a numerical model that fits the characteristics of the flowback process. The effect of reservoir properties, fracturing parameters, drainage–production system, chemical permeability on gas and water production in the flowback process and their mechanisms are also analyzed. According to most numerical simulation results, the lower cumulative gas production will be with the higher cumulative water production which means the higher flowback rate. The pursuit of only a high flowback rate is not advisable, and the development of the drainage–production system requires reasonable control of the fracturing fluid flowback rate. This study provides a theoretical basis for the optimization of shale gas drainage–production system after hydraulic fracturing.

Evolution of physical and mechanical properties of cementing materials during underground energy exploitation and storage

The sealing problem of cement sheath often appears in gas wells for the increasing depth of underground energy exploitation and storage, especially when horizontal multi-stage fracturing technology is used in the shale gas industry. To investigate the effect of high temperature and high pressure (HTHP) on the evolution of the physical and mechanical properties of cement stone, conventional triaxial compression tests of cement stone at 5 different temperatures from 25 °C to 135 °C, with confining pressure varying from 5 to 45 MPa were tested. It was found that with increasing confining pressure and temperature, the mechanical properties of cement stone change from strain softening to ideal plasticity, finally, become strain hardening. The specimens show irregular longitudinal splitting under low confining pressure and room temperature. When the confining stress rises to 30 MPa and the temperature rises to 95 °C, expansive destruction occurs in the radial direction. In addition to the above, the failure mode shows single a shear plane or multiple splitting planes. Peak strength of cement stone is proportional to confining pressure and is inversely related to temperature. There is a negative correlation between elastic modulus and temperature. The effect of temperature on cohesion and friction angle is complex, and with the increasing temperature, the cohesion continuously decreases. The friction angle increases until the temperature reaches 60 °C, but then it starts to drop dramatically. The results of the physical and mechanical properties of cement stone guide the cementing design and construction of horizontal wells and the safety evaluation during underground energy exploitation and storage.

Production performance analysis of multi-fractured horizontal well in shale gas reservoir considering space variable and stress-sensitive fractures

Multi-stage fracturing technology makes shale gas production economically viable. In this paper, an innovative model incorporating space variable and stress-sensitive fractures is established for the production of MFHW in shale. Multi-transport mechanisms including Darcy flow, Knudson diffusion, Surface diffusion are considered in the mathematical model. Three space variable conductivity patterns (Linear, Exponential, and Logarithmic variations) are introduced and adopted. Based on the discretization method, a novel method is proposed which can simulate uniform and space varying fractures conveniently. Then the semi-analytical solution is obtained by Stehfest numerical inversion and an iteration method. And good agreements with previous models are observed in the validation. Afterward, the pressure transient type curve is generated and eight flow periods are identified. Subsequently, the influences of several vital parameters are discussed in detail. The results show that space varying fracture enlarges the pressure drop and decreases the productivity of early time. Such an effect is enhanced as the space variable coefficient is increased. And this influence decreases with the increase of initial conductivity. Considering stress-sensitive fractures, a ‘hump’ appears in the pressure derivative curve and the early time productivity decreases. A bigger stress-sensitive coefficient accelerates the appearance of the ‘hump’ and makes the ‘hump’ sharper. The ‘hump’ and productivity decline caused by dynamic conductivity becomes more obvious with the decrease of the minimum conductivity. Complex transport mechanisms enhance inter-porosity flow. The inter-porosity flow would appear earlier with complex transport mechanisms. The model can simulate the gas flow of MFHW more realistically. It can help for better understanding of the production dynamic of MFHW in shale. • A semi-analytical approach is established for the pressure and rate transient of MFHW in shale gas reservoir. • Space variable and stress-sensitive fractures and multi-transport mechanisms of shale gas are considered. • A new solution and an iteration method are utilized to solve the space varying fracture and nonlinear problem. • Effects of some vital parameters on production performance are analyzed.

Failure evaluations for packers in multistage fracturing technology with immobile strings

With the development of unconventional oil and gas resources, the multi-stage fracturing technology with immovable string has been developed rapidly due to its advantages of large construction capacity and multiple fracturing stages. But the failure of packer has become a bottleneck restricting the development of technology. In this paper, the mechanical properties of corroded ((under the environment of I(North Troyes),II(Jeannajor) and III(Khasib)) ) and uncorroded rubber of the packer were tested by designed experiments at first. The experimental values showed that elastic modulus, shear strength and tensile strength decreased when packers were corroded. Then, according to packers' structure and load characteristics, taking the rubber cylinder, rubber support, center pipe, tubing and string as research object, the dynamic model was established for tubes and packers in fracturing layers. Based on conditions of the shear strength, pressure seal and axial movement for rubber cylinder, the safety evaluation method was proposed for packer sealing system. And the failure evaluation of multistage fracturing packer in Gao182-151 well in Daqing Field was carried out by the method established in this paper. At last, we could get the following results: the sealing safety coefficients of upper and lower packers were all greater than 1.0 during the fracturing process of layer I to IV. The axial displacement of the packer's rubber of the non-corrosive and corrosivewere all 0.00. So the packers were sealed well in each stage of fracturing, and no leakage accidents occurred during the entire fracturing process of Gao 182-151 Well. But in the fracturing layer I, the shear safety factor of the corroded (under corrosive environment of I(North Troyes),II(Jeannajor) and III(Khasib)) rubber were is 1.00, 1.10, 0.99 respectively. The shear strength was less than or equal to 1.10 and it didn't not satisfy the shear strength. Therefore, we could get the conclusion that the corroded rubber did not meet the shear strength and rubber tearing was prone to occur in the fracturing layer I. So it is recommended to replace the rubber with a new one before the construction of Gao 182-151Well.

Experimental Study of Hydraulic Fracture Propagation Behavior during Multistage Fracturing in a Directional Well

Due to the limited space of offshore platform, it is unable to implement large-scale multistage hydraulic fracturing for the horizontal well in Lufeng offshore oilfield. Thus, multistage hydraulic fracturing technology in directional well was researched essentially to solve this problem. Modeling of fracture propagation during multistage fracturing in the directional and horizontal wells in artificial cores was carried out based on a true triaxial hydraulic fracturing simulation experiment system. The effects of horizontal stress difference, stage spacing, perforation depth, and well deviation angle on multifracture propagation were investigated in detail. Through the comparative analysis of the characteristics of postfrac rock and pressure curves, the following conclusions were obtained: (1) multistage fracturing in horizontal wells is conducive to create multiple transverse fractures. Under relatively high horizontal stress difference coefficient (1.0) and small stage spacing conditions, fractures tend to deflect and merge due to the strong stress interference among multiple stages. As a consequence, the initiation pressure for the subsequent stages increases by more than 8%, whereas in large stage spacing conditions, the interference is relatively lower, resulting in the relatively straight fractures. (2) Deepening perforation holes can reduce the initiation pressure and reduce the stress interference among stages. (3) When the projection trace of directional wellbore on horizontal plane is consistent with the direction of the minimum horizontal principal stress, fractures intersecting the wellbore obliquely are easily formed by multistage fracturing. With the decrease of well deviation angle, the angle between fracture surface and wellbore axis decreases, which is not conducive to the uniform distribution of multiple fractures. (4) When there is a certain angle between the projection trace of directional wellbore on horizontal plane and the direction of minimum horizontal principal stress, the growth of multiple fractures is extremely ununiform and the fracture paths are obviously tortuous.

Application of nanoindentation creep tests to characterize viscoelasticity behavior of deep Longmaxi shales

The development of deep shale gas reservoirs has become economically and commercially viable through novel horizontal well completion and multistage hydraulic fracturing technologies in recent years. In the Sichuan Basin, the deep Longmaxi shale is a major target formation that has attracted increasing interest. Shale is generally characterized as a sedimentary rock with fine grains, high clay, and organic content, low permeability and porosity, and high heterogeneity and anisotropy. Geomechanical characterization of these organic-rich rocks usually includes an estimation of the elastic modulus, strength properties, hysteresis behavior, and creep deformation. Understanding and characterizing the viscoelastic behaviors of shale is essential because they affect the elastic and fracture properties of rock and cause a series of drilling problems related to the wellbore stability, such as borehole shrinkage, pipe sticking, and casing collapse. The viscoelastic behavior of specimens retrieved from a deep well in the Sichuan Basin was examined using nanoindentation creep tests. Nanoindentation is a technique based on a hard tip, which is pressed into the surface of a sample. The advantage of this test is the use of a small sample volume, such as drilling cuttings or fragments, which are obtained easily during drilling. The results indicated that the creep modulus parallel to bedding and normal to bedding is similar, while the creep modulus of drilling cuttings is the lowest. A linear relationship was both observed between the creep modulus and hardness, Young’s modulus for deep Longmaxi shale. The Burgers creep model showed good agreement with the experimental data. The creep behavior of Longmaxi shale exhibited anisotropy, and the effect of drilling fluids could aggravate the creep displacement. These results have elucidated the creep properties in engineering problems of shale gas formation, drilling, and stimulation.

Evolution and management of thick-hard roof using goaf-based multistage hydraulic fracturing technology—a case study in western Chinese coal field

The mining-induced breaking of thick-hard roof is characterized by the microseisms and energy release. To preliminary control rock burst caused by the breakage of the thick-hard roof in panel #42202 of Shengdong coal field, a goaf-based multistage hydraulic fracturing technology was developed, and corresponding mathematical model for hydraulic fracturing position determination and synergetic support system comprised of collapse filling, coal pillars, and load-bearing strata were established. The results show that a distressed zone with a height of 29 m along the drilling direction and a width of 230–300 m along the radial direction of the drilling hole was created. Compared with the effect of single-hole fracturing, the influence scope increased into 70 m for double-hole fracturing. The hydraulic pressure gradient drop of 12.8 MPa was observed, as the termination of hydraulic fracturing with an initiation hydraulic pressure of 33.1 MPa. Additionally, the mining weighting period interval, front abutment coefficient, peak pressure, and roadway surrounding rock stress were reduced by 20.0–69.7%, 5.8–7.9%, 13.4–18.6%, and 22.2–32.1%, respectively.