Actual Fracturing Research Articles

Numerical Simulation Study on Dynamic Interaction between Two Adjacent Wells during Hydraulic Fracturing

The heterogeneity in fracture formation significantly influences the hydraulic fracture propagation among adjacent wells, underscoring the urgency to comprehend the underlying fracture mechanisms. Specifically, in shale gas or oil extraction fracturing operations, stress interactions among neighboring fracturing clusters, or mutual interference during the propagation of parallel fractures, are commonplace. At present, there is relatively little research on the sensitivity parameters of adjacent borehole fracture propagation morphology. Consequently, we employed ABAQUS software 2022 to construct a numerical model simulating the fracturing of adjacent boreholes in opposing directions. Upon validating the model’s fidelity, we systematically explored the influence of various engineering and geological factors on fracture morphology and propagation length. Our findings revealed a three-phase evolution: independent fracture propagation, subsequent mutual repulsion, and, ultimately, mutual attraction. It is worth noting that increasing the elastic modulus from 10 GPa to 80 GPa, and increasing the crack length by 16.30%, is beneficial for crack propagation, while the horizontal stress difference profoundly shapes the crack mode, but has a relatively small impact on the overall crack length. When HSD increases from 0 MPa to 15 MPa, the total crack length only changes by 1.24%. In addition, the filtration coefficient of the reservoir is a key determining factor that has a significant impact on the morphology and length of cracks generated by adjacent boreholes. Increasing the filtration coefficient from 1 × 10−14 m3/s/Pa to 5 × 10−12 m3/s/Pa reduces the total length of cracks by 60.77%. Notably, an optimal injection rate exists, optimizing fracturing outcomes. Conversely, the viscosity of the fracturing fluid exerts a limited influence on fracture morphology and length within the confines of this simulation, allowing for the selection of a suitable viscosity to ensure smooth proppant transport during actual fracturing operations. In designing fracturing parameters, it is imperative to aim for sufficient fracture propagation length while harnessing “stress interference” to foster the development of intricate fracture networks. Ultimately, our research findings serve as a solid foundation for engineering practices involving hydraulic fracture propagation in adjacent boreholes undergoing opposing fracturing operations.

Qualitative Analysis and Quantitative Evaluation of Fracturing Disturbance in the Mahu 18 Block

In response to the fracturing disturbance problem in the Mahu 18 block, based on the production data of on-site fracturing disturbance well groups, the actual fracturing disturbance cases in the block were first statistically divided. The complex fracturing disturbance situation in the block was divided according to the relationship between the number of fracturing wells and the number of production wells. Then, the disturbance types were classified based on the production dynamic response characteristics of the disturbed wells, and the degree of disturbance was quantitatively evaluated for the different types. The results indicate two main types of fracturing interference in the Mahu 18 block: the fracture communication type, and the pressure wave interference type formed through inter-well connectivity through the reservoir matrix. The fracturing disturbance dominated by fracture communication can cause serious water channeling to the production well through the direct connection of inter-well fractures, leading to a surge in water production. This type of fracturing disturbance often has a severe negative impact on the production well. In addition, the pressure and production (water production, liquid production, oil production) in the production dynamic response characteristics of disturbed wells during fracturing disturbance were used as evaluation indicators to quantify the impact of different types of fracturing disturbance from multiple perspectives.

Numerical characterization of acid fracture wall etching morphology and experimental investigation on sensitivity factors in carbonate reservoirs

Carbonate reservoirs are marked by their low porosity and permeability, naturally occurring fractures that develop in a stochastic fashion and exhibit significant heterogeneity. Deep acidification techniques are essential for the efficient development of such oil and gas reservoirs. The effective distance of acid etching (acid etch fracture length) and the fracture conductivity stand as the two most critical parameters for assessing the efficacy of acidizing. The primary objective of using this technique is to extend the effective distance of the acid etch and enhance the fracture conductivity. The "relay-style" full-length acid etched fracture testing method is employed, achieving an accurate match between the testing temperature, pressure, fracture length, and the actual acid fracturing conditions. It employs a large-scale rock plate acid etching experimental device, in conjunction with 3D laser scanning technology, and utilizes orthogonal experimental design methods to conduct detailed numerical characterization of the rock plate fracture surfaces before and after etching with various acid fluid types, acid injection amounts, and acid injection rates. It quantifies the change in the concentration of the residual acid fluid after the acid-rock reaction, calculating the etching volume of the acid fluid and the length of the acidizing fracture. The experimental results demonstrate that both the gelled acid and the clean diverting acid exhibit long acidification distances and strong inhomogeneous etching capabilities. The etch morphology of the clean diverting acid is dominated by pitting-type and stripe-like dissociation, exhibiting a wavy pattern. In contrast, the etch morphology of the gelled acid appears band-like and groove-like. As the acid injection amount increases, the etch length increases. Under on-site working conditions, etch lengths of 46.42 m and 41.63 m were recorded for 20% gelled acid and clean diverting acid, respectively, after 60 min acid injection time. The factors affecting the etch length sensitivity are in the following order: acid injection rate > acid type > etching time. The optimal acid fracturing parameters to achieve the maximum etch length are: The etch is performed at a pump rate of 600 mL/min for 90 min using gelled acid. Quantitative characterization of acid etch fracture morphology can optimize designing parameters of acid fracturing techniques, enhance the efficiency of their modification, and further enhance the development benefits of oil and gas carbonate rock reservoirs.

Fracturing and Dome‐Shaped Surface Displacements Above Laccolith Intrusions: Insights From Discrete Element Method Modeling

AbstractInflation of viscous magma intrusions in Earth's shallow crust often induces strain and fracturing within heterogeneous host rocks and dome‐shaped ground deformation. Most geodetic models nevertheless consider homogeneous, isotropic, and linear‐elastic media wherein stress patterns indicate the potential for failure, but without simulating actual fracturing. We present a two‐dimensional Discrete Element Method (DEM) application to simulate magma recharge in a pre‐existing laccolith intrusion. In DEM models, fractures can propagate during simulations. We systematically investigate the effect of the host rock toughness (resistance to fracturing), stiffness (resistance to deformation) and the intrusion depth, on intrusion‐induced stress, strain, displacement and spatial fracture distribution. Our results show that the spatial fracture distribution varies between two end‐members: (a) for high stiffness or low toughness host rock or a shallow intrusion: extensive cracking, multiple vertical surface fractures propagating downward and two inward‐dipping highly cracked shear zones that connect the intrusion tip with the surface; and (b) for low stiffness or high toughness host rock or a deeper intrusion: limited cracking, one central vertical fracture initiated at the surface, and two inward‐dipping fractures at the intrusion tips. Abrupt increases in surface displacement magnitude occur in response to fracturing, even at constant magma injection rates. Our modeling application provides a novel approach to considering host rock mechanical strength and fracturing during viscous magma intrusion and associated dome‐shaped ground deformation, with important implications for interpreting geodetic signals at active volcanoes and the exploitation of geothermal reservoirs and mineral deposits.

Heterogeneous Fenton treatment of shale gas fracturing flow-back wastewater by spherical Fe/Al2O3 catalyst.

In this work, efficient Fenton strategy have been proposed for degradation of shale gas fracturing flow-back wastewater using the spherical Fe/Al2O3 supported catalyst. Prior to actual fracturing fluid treatment, the typical model wastewaters such as p-nitrophenol and polyacrylamide were employed to evaluate the catalytic properties of prepared catalyst, and then Fenton treatment of the shale gas fracturing flow-back wastewater was performed on the self-assembled catalytic degradation reactor for continuous flow purification. Results showed that under the conditions of 0.25 mol L-1 impregnating concentration, pH 4, 50 g L-1 catalyst and 0.75 mL L-1 30% H2O2, the removal efficiency of p-nitrophenol and polyacrylamide reached 74% and 61%, respectively, while the COD removal of fracturing flow-back fluid was approximately 48% with the residual 88 mg L-1 COD, meeting the emission standards of the integrated wastewater discharge standard (GB 8978-1996, COD < 100 mg L-1). This work offers new alternatives for Fenton treatment of real wastewater by efficient and low-cost supported catalysts.

A Volume Fracturing Percolation Model for Tight Reservoir Vertical Wells

Based on the non-linear seepage characteristics of tight reservoirs and the reconstruction mode of vertical wells with actual volume fracturing, a seven-area percolation model for volume fracturing vertical wells in tight reservoirs is established. Laplace transform and Pedrosa transform are applied to obtain analytical solutions of bottom hole pressure and vertical well production under a constant production regime. After verifying the correctness of the model, the influence of the fracture network parameters on the pressure and production is studied. The research results indicate that as the permeability modulus increases, the production of volume fracturing vertical wells decreases. The penetration ratio of the main crack and the half-length of the main crack have a small impact on production, while the diversion capacity of the main crack has a significant impact on the initial production, but it is ultimately limited by the effective volume of the transformation. Under constant pressure conditions, the greater the width and permeability of the ESRV region, the higher the vertical well production rate is. The smaller the aspect ratio of the ESRV region, the higher the mid-term yield and the faster the yield decrease. The research results show guiding significance for the design of vertical well volume fracturing in tight reservoirs.

Study on fracture conductivity under dynamic sand laying mode

The existing API static sand laying fracture conductivity evaluation experiment ideally believes that the proppant is evenly and statically laid in the fracture, without considering the actual fracturing conditions, the proppant migrates along the fracture and leaks into the formation. In order to more truly simulate the actual fracturing conditions, the experimental study of fracture conductivity is carried out by using the dynamic conductivity testing device, which is closer to the field reality than static sand laying. The parameters of the indoor dynamic sand laying diversion experiment are determined by the similarity criterion and the indoor fracturing fluid rheology experiment. The orthogonal experiment and the shear support fracture dynamic diversion experiment are designed to study the effects of pumping displacement, fracturing fluid viscosity and construction sand ratio on the dynamic sand laying diversion ability, and optimize the on-site construction parameters. The experimental results show that increasing the construction displacement, sand ratio and selecting the appropriate fracturing fluid viscosity have a positive impact on the fracture conductivity of dynamic sand laying support, among which the sand ratio has the greatest impact. Under the condition of effective closure stress of the reservoir, the natural non sanding shear fracture and the dynamic paving shear fracture with 12% sand ratio have no conductivity, which is difficult to meet the requirements of field production. When the 1-3 mm shear joint is dynamically paved with 18% sand ratio and the closing pressure is 30-70 MPa, the conductivity is positively correlated with the sand concentration, but it is nonlinear with the shear dislocation. The shear joint pump injects 18% proppant with sand ratio, which can support the fracture under high closing pressure and provide conductivity. It is necessary to appropriately increase the pump injection ratio of more than 18% sand ratio according to the proportion of on-site shear cracks to effectively support shear cracks.

Experimental investigation of the fracture initiation and propagation for sandstone hydraulic fracturing under the effect of evenly distributed pore pressure

Pore pressure is disregarded in traditional laboratory rock hydraulic fracturing experiments, and the effect of pore pressure is not clear. An integrated experiment for seepage and hydrofracturing was established and used to perform sandstone hydraulic fracturing experiments under an initial evenly distributed pore pressure. The experimental results show that there is a positive correlation between the breakdown pressure and the pore pressure at the initiation stage. The data fitting results show that the breakdown pressure and pore pressure follow a linear growth trend. As the pore pressure increases, the acoustic emission energy at the moment of borehole wall fracturing correspondingly increases. After borehole wall fracturing, the reduced magnitude of the pumping pressure also increases, indicating that the initial rupture range is positively correlated with pore pressure. During fracturing propagation, the propagation range and opening of the fracture increase as the initial pore pressure increases within the same pumping time. During hydraulic fracturing, a pore pressure gradient is generated on both sides of the mineral particles. When the tensile stress or shear stress induced by the pore pressure gradient reaches the ultimate strength of the mineral particle bonding surface, the particle bonding surface breaks and opens. This experimental process is more similar to the actual hydraulic fracturing process of oil and gas reservoirs. These results provide a more comprehensive theoretical basis for resolving technical problems of unconventional oil and gas resource exploitation.

An Unsupervised Clustering Method for Selection of the Fracturing Stage Design Based on the Gaussian Mixture Model

In order to further improve the efficiency and economic benefits of multi-stage fracturing of unconventional oil and gas horizontal wells, it is urgently needed to conduct comprehensive reservoir quality evaluation research on the whole horizontal well section. Firstly, based on logging data, focusing on reservoir quality and completion quality, and comprehensively considering key factors such as reservoir physical property indexes and fracability indexes, a subjective and objective coupled evaluation model of the entropy weight method (EWM) and the analytic hierarchy process (AHP) without bias is established to obtain the composite reservoir quality index. Then, unsupervised gaussian mixture model (GMM) clustering algorithms are used to classify the reservoir comprehensive quality index and finally four grades of fracturing stages are established. Taking shale oil well A and B of the Permian Lucaogou Formation in Jimsar Sag, Junggar Basin, as examples, the comprehensive reservoir quality evaluation and clustering model training, testing, and prediction were carried out. By comparing the clustering results with the actual fracturing stages and oil production, it is found that the evaluation results obtained by the GMM clustering algorithms based on the coupled evaluation model of EWM and AHP can identify the good fracturing grades. The algorithm can also predict the fracturing grades of other wells in the same block. It proves the accuracy of the method proposed in this paper and provides a favorable technical basis for determining the placement of multi-cluster fracturing perforation.

Understanding Unconventional Reservoir Fracturing: A Transdisciplinary Methodological Approach

A better understanding of hydraulic fracturing behavior is even more crucial in unconventional plays as more new-well or infill-well are drilled and completed nowadays. Having integrated different sources of information/data such as the general trend of hydraulic fracturing practices during the last 20 years, DFIT and fracturing simulation, core analysis data, outcrops, the Hydraulic Fracturing Test Site (HFTS), and fracturing monitoring in the wells or between wells such as pressure, tracers, DAS, DTS, DSS and so on, we proposed an innovated conceptual model of hydraulic fracturing coming along with some associated concepts; The transdisciplinary integration approach we used in this research follows all fundamental physics law and meticulously logical reasoning and analogy with crossing validation, the first principle thinking epistemologically because of the physics of unconventional fracturing is much more complicated than any single discipline can explain. More often than not, the solution coming from any discipline or data source is not a unique one. The cognition of the morphology or the called fracture pattern of hydraulic fracturing is critical, which is virtually the conceptual model of fracturing. The conceptual model can directly impact the fracturing design and the way to evaluate actual fracturing. Using the proposed conceptual model, Fracturing Impact Volume (FIV), one can better explain what fracturing has done for unconventional plays and why it worked. With the proposed conceptual model and tossing aside the fracture network as the fracturing goal, many current fracturing practices can be improved significantly, and the way of production can be revised. This is a significant concept shifting in the unconventional fracturing arena, and it is certainly not an easy task, but this paper makes a compelling case. With the FIV model in mind, the perception of “the greater the pumping rate, the better the fracturing be” becomes unnecessary or makes little sense. This paper will decode the shale oil/gas flow mechanisms and demonstrate a better way to fracture and produce unconventional resources like shale oil/gas.

Nanoindentation-Based Three-Parameter Fracability Evaluation Method for Continental Shales

Shale fracturing evaluation is of great significance to the development of shale oil and gas resources, but the commonly used shale evaluation methods (e.g., the method using the brittleness index based on mineral composition or elastic parameters) have certain limitations. Fractures and beddings affecting fracturing are not considered in these methods. Therefore, it is necessary to develop a new method to evaluate fracturing more comprehensively. The samples used in this research were taken from four typical continental shale basins of China, namely the Bohai Bay Basin, the Ordos Basin, the Songliao Basin, and the Junggar Basin. From a microscopic point of view, a three-parameter evaluation method involving multi-dimensional factors has been developed based on the nanoindentation method. Then, the fracturing coefficient K2 is obtained by combining the ratio β of the fracture indentation to the total indentation and the uneven coefficient m. After that, the fracability coefficient K3 is the ratio of the elastic modulus parallel to bedding to that perpendicular to bedding. Finally, the correlation between fracability coefficients K1, K2, and K3 is used to evaluate the overall fracturing performance of shale. The results of this evaluation method are in good agreement with the actual fracturing performance. It can be concluded that this method is highly reliable and practical and well worthy of promoted applications.

Drag Reduction Mechanism of Viscoelastic Slick-Water Fracturing Fluid in Tortuous and Rough Fractures

Slick-water can effectively reduce the flow drag of fracturing fluid. Many studies have focused on the drag reduction performance of slick-water in wellbore and perforation, but there has been little research on drag reduction characteristics in fracture flow. In this paper, a new visualization experiment system is used to simulate real fracture. The fracture surface is produced through actual triaxial hydraulic fracturing and is copied by a three-dimensional printer using resin material to maintain its shape feature. In comparing the experimental results, it was found that the main factors affecting drag reduction in a fracture are the relative molecular weight and the added concentration. Unlike the flow rule of the drag reducer in a pipeline, when the concentration is greater than 0.10%, a negative DR effect begins to appear. The influence of molecular weight is related to the flow stage; the increasing of molecular weight causes a reduction in DR effect when the flow rate is 0.24 m/s. However, the flow rate exceeds 0.5 m/s; drag reducers with higher molecular weight demonstrate better drag reduction performance. The drag reduction mechanism analysis in fractures was obtained from visualization observations, and the flow characteristics of fluid were characterized by using tracking particles. Drag reduction effect occurs mainly on the surface of the fractures in contrast to near the centre of the flow channel. This research can provide a reference for the experimental study on drag reduction in fractures and is of great significance to the optimization and improvement of drag reducing agent.

Numerical modeling of fluid flow in tight oil reservoirs considering complex fracturing networks and Pre-Darcy flow

Multistage hydraulic fracturing for horizontal wells is extensively applied in the exploitation of tight oil reservoirs. Complex fracture networks with different scales are created and hydrocarbon flowing in the matrix demonstrates a Pre-Darcy characteristic due to a strong interaction of rock and fluids in nanoscale pores. The modeling of complex fracture networks and a Pre-Darcy effect is required in numerical simulation of tight oil reservoirs. In this paper, stochastic fracture networks are employed to mimic actual fracturing networks according to the corresponding probability density functions (PDFs), and microseismic events are used to constrain the locations of fractures. The numerical simulation for tight oil reservoirs is developed by considering complex fracture networks and the Pre-Darcy effect based on an embedded discrete fracture model (EDFM) framework. Finally, the influences of fracture network properties including isolated fractures, connected fracture networks and the Pre-Darcy effect on well production are investigated via integrating the developed fracture network generation and tight oil numerical simulator. The results indicate that for isolated fractures with no direct connection with a wellbore, there is little influence on well performance. The influence becomes more obvious when isolated fractures connect to a wellbore, and an increase in fracture length and conductivity can enhance well performance especially when fractures lie off streamline lines. Similarly, for a connected fracture network, an increase in fracture network properties (number, length and conductivity) can promote well performance and fractures perpendicular to a horizontal wellbore can generate a maximal flow rate compared with other fracture orientations. The fracture network connectivity plays an important role in the fluid flow, and there are good relationships between well production and two proposed parameters, which can be treated as candidates to characterize the flow characteristics in fractured reservoirs.

Rock physical and chemical alterations during the in-situ interaction between fracturing fluid and Silurian organic-rich shales in China

Hydraulic fracturing has been proved to be an effective way to unlock shale gas resources. During this process, fracturing fluid comes into contact with shale reservoirs and interact with the rocks. This could cause alteration of the pore systems in shales, thereby affecting gas transport and production. To illustrate this geochemical process and identify the physical and chemical alterations of shales, fluid-shale interaction at in-situ conditions is studied for typical marine organic-rich shales from the Silurian Longmaxi Formation in the Sichuan Basin, using actual fracturing fluid and deionized water over a 5-day period. The minerals and pore structures before and after the reaction were examined by X-ray diffraction (XRD), field emission scanning electron microscope (FE-SEM), QEMSCAN, computed tomography (CT) scanning, nitrogen adsorption testing and organic geochemical analysis. Results showed that, the fracturing fluid and deionized water caused indiscernible changes to the organic matter, but a variety of alterations on carbonate minerals. Calcites and dolomites were markedly dissolved, but quartzs, albites and illites remained relatively unaltered. More dolomites crystals were precipitated in the deionized water-shale interaction than in the fracturing fluid-shale interaction, and some of the fractures seemed to be filled by flocculation of friction reducers or deposited mineral particles. The fracturing fluid could enlarge the pore volumes and improve pore connectivity, and the invasion depth of fracturing fluid after 120 h’ was around 60 μm. The dissolved pores and loosening/shedding of particles detected by CT increased through time, and the calculated 3D pore volume increased by 67% at 24 h, 117% at 72 h, and 430% at 120 h compared to that of the initial sample. The XRD and nitrogen adsorption data indicated that new pore volumes increased with higher contents of carbonate minerals in the sample and longer treatment by fracturing fluid. The mineral and pore-scale alterations of shale reservoirs indicated that fracturing fluid-shale interaction (FFSI) enlarged the reservoir reconstruction volume, increased well performance during shut-in period and should be considered as part of the well treatment optimization process.

Damage mechanism of water-based fracturing fluid to tight sandstone gas reservoirs: Improvement of The Evaluation Measurement for Properties of Water-based Fracturing Fluid: SY/T 5107-2016

At present, evaluation on reservoir damage induced by fracturing fluid mainly refers to The Evaluation Measurement for Properties of Water-based Fracturing Fluid: SY/T5107-2016 (referred to as the industry standard below). However, the fracturing fluid displacing core process stipulated in the industry standard is not consistent with the fast invading process of fracturing fluid into the reservoir under high pressure during the actual fracturing construction. Besides, the influences of fracturing fluid residues, gel breaking mode, original water saturation and other factors are not taken into consideration in the experiments to evaluate the damage of fracturing fluids. Thus, the accuracy of evaluation results is influenced. In this paper, tight sandstone cores of the Lower Jurassic Ahe Formation (J1a) in Dibei area of Kuqa Depression of the Tarim Basin were selected as samples. The invading process of fracturing fluid into a tight sandstone reservoir was simulated by modifying experimental process and method. Then, the damage degree of fracturing fluid to gas reservoir was evaluated and the damage mechanisms of fracturing fluid were analyzed systematically. And the following research results were obtained. First, the modified evaluation method takes into account the influences of several factors, such as the original water saturation of gas reservoir, the instantaneous “breakdown” effect of high-pressure during fracturing and the fracturing fluid residues, so it can evaluate the damage degree of fracturing fluid to tight sandstone gas reservoirs more objectively. Second, the evaluation results based on the industry standard show that the damage degree of fracturing fluid to the permeability of tight sandstone gas reservoirs is medium to strong, whereas the damage degree evaluated by the modified method is medium to weak. Third, the retention of fracturing fluid residues in fractures is the main cause of permeability damage. The residues can easily block fractures and fracture surface pores. Most of them retain in the pores in the surface layer of matrix cores (invasion depth less than 3 cm), so residues are filtered by matrix pores. Fourth, when fracturing fluid migrates inwards from the core surface, high molecular polymers retain in the form of thin-film lamellar, local flaky nodular and crystal inclusion in turn in the reservoir pores. Fifth, under the experimental conditions, salting-out crystals appear and are unevenly distributed in the cores. In fractures, salting-out crystals and high molecules are polymerized to form composite inclusions. In matrix pores, salting-out crystals and a small number of fragments (e.g. illite) are enclosed to form a complex. Sixth, migratory particles caused by speed sensitivity are usually combined with residues and high molecular polymers to form composite inclusions, thus blocking pores and fractures.

Study on a New Rock Fracability Evaluation Model of Shale Gas Reservoir

Shale gas is an important unconventional energy resource that needs large-scale fracturing to form industrial deliverability. The evaluation of reservoir fracability plays a key role in the optimization of the sweet spot, the design of multistage fracturing, and the prediction of economic benefit. Based on volumetric fracturing, the study proceeded from the fracture complexity of the fractured core, and the bursting pressure experiment technology using the constant strain rate method was established. After the core has fractured, the fracture morphology was extracted and the fracture parameters including fracture area ratio and fracture declination dispersion were calculated to construct the fracture complexity of the pressed core. Combined with the core strength, the fracability index of the core was determined to evaluate the reservoir fracability. This method can represent not only the fracturing effect but also the fracturing difficulty. Compared with the monitoring data of hydrofracture-induced microseism of the sample well, the core fracturing index was found to be in good agreement with the actual fracturing effect. This method is more reasonable than the traditional brittleness index method and rock mechanics parameter method.

A Comparative Study on Wellbore Pressure Transmission of Water and Carbon Dioxide during Fracturing

Hydraulic fracturing is one of the most effective ways for the development of unconventional oil and gas resources, CO2 has been regarded as an excellent alternative to water as its broad application prospects in unconventional reservoir development and benefit for CO2 utilization. The wellbore pressure will keep rising before fracture initiation during hydraulic fracturing, and fluid properties have significant influence of wellbore pressure transmission especially for CO2 fracturing. In this paper, a wellbore pressure transmission model based on the definition of fluid compressibility is established and coupled with wellbore flow model of compressible fluid to calculate the borehole pressurization rate for water-based and CO2 fracturing. The model has been verified by field data. The results show that the borehole pressurization rate for both water-based and CO2 fracturing reveal rising trend as pump rate increasing, and borehole pressurization rate of water-based fracturing is 10∼20 times that of CO2 fracturing with same pump rate. Moreover, the borehole pressurization rate increases linearly with pump rate of water-based fracturing, but excessive pump rate might reduce borehole pressurization rate of CO2 fracturing. The research results can simulate more perceptions for the optimizing design of actual hydraulic fracturing operating.

Investigation of Hydraulic Fracturing Crack Propagation Behavior in Multi-Layered Coal Seams

Coalbed methane is not only a clean energy source, but also a major problem affecting the efficient production of coal mines. Hydraulic fracturing is an effective technology for enhancing the coal seam permeability to achieve the efficient extraction of methane. This study investigated the effect of a coal seam reservoir’s geological factors on the initiation pressure and fracture propagation. Through theoretical analysis, a multi-layered coal seam initiation pressure calculation model was established based on the broken failure criterion of maximum tensile stress theory. Laboratory experiments were carried out to investigate the effects of the coal seam stress and coal seam dip angle on the crack initiation pressure and fracture propagation. The results reveal that the multi-layered coal seam hydraulic fracturing initiation pressure did not change with the coal seam inclination when the burial depth was the same. When the dip angle was the same, the initiation pressure linearly increased with the reservoir depth. A three-dimensional model was established to simulate the actual hydraulic fracturing crack propagation in multi-layered coal seams. The results reveal that the hydraulic crack propagated along the direction of the maximum principal stress and opened in the direction of the minimum principal stress. As the burial depth of the reservoir increased, the width of the hydraulic crack also increased. This study can provide the theoretical foundation for the effective implementation of hydraulic fracturing in multi-layered coal seams.

Analytical interpretation of hydraulic fracturing initiation pressure and breakdown pressure

The rock collapse during Hydraulic Fracturing (HF) is the result of the accumulation of rock damage to a certain extent. That means there are two key pressure values: the fracture initiation pressure (FIP) and the breakdown pressure (FBP), which characterize the micro damage initiation and the macroscopic fracture stable expansion respectively. However, various conventional analytical breakdown pressure models cannot clearly distinguish and quantitatively characterize the difference between FIP and FBP. This paper presents a combined model. The fracture initiation is defined to start when the stress intensity factor at some point inside the rock reaches the fracture toughness. The breakdown is defined as the derivative of stress intensity factor versus radius is positive, not only as the onset of fracture initiation. According to the comparison and analysis of the actual fracturing experiments, this combined model makes it possible to accurate predict the FIP and the FBP respectively.

Uncertainty Analysis of Factors Influencing Stimulated Fracture Volume in Layered Formation

Hydraulic fracture dimension is one of the key parameters affecting stimulated porous media. In actual fracturing, plentiful uncertain parameters increase the difficulty of fracture dimension prediction, resulting in the difficulty in the monitoring of reservoir productivity. In this paper, we established a three-dimensional model to analyze the key factors on the stimulated reservoir volume (SRV), with the response surface method (RSM). Considering the rock properties and fracturing parameters, we established a multivariate quadratic prediction equation. Simulation results show that the interactions of injection rate (Q), Young’s modulus (E) and permeability coefficient (K), and Poisson’s ratio (μ) play a relatively significant role on SRV. The reservoir with a high Young’s modulus typically generates high pressure, leading to longer fractures and larger SRV. SRV reaches the maximum value when E1 and E2 are high. SRV is negatively correlated with K1. Moreover, maintaining a high injection rate in this layered formation with high E1 and E2, relatively low K1, and μ1 at about 0.25 would be beneficial to form a larger SRV. These results offer new perceptions on the optimization of SRV, helping to improve the productivity in hydraulic fracturing.