Wellbore Fracture Research Articles

Thermodynamics-based unsaturated hydro-mechanical-chemical coupling model for wellbore stability analysis in chemically active gas formations

A thermodynamics-based unsaturated hydro-mechanical-chemical (HMC) coupling model is developed to analyze the coupled response and stability of boreholes in chemically active gas formations. The newly coupled constitutive relations are formulated by incorporating the chemical effect into the solid-gas-liquid unsaturated framework to account for the interactions between rock deformation, gas-liquid two-phase flow, and chemical potential difference. Compared with previous models, the present model shows significant prediction differences in field variables and wellbore stability evolution. The maximum absolute difference of pore pressure, effective radial stress, effective tangential stress, and collapse pressure can reach 8.98 MPa, 7.64 MPa, 7.29 MPa, 7.65 MPa, respectively. It is more conservative to select a long-term wellbore collapse pressure rather than a short-term one to guide drilling operations. The two-phase flow behavior, jointly controlled by wellbore pressure, capillary pressure, and chemical osmosis effect, provides a more realistic observation of the mud intrusion process. Compared with low salinity muds, high salinity muds can effectively impede the mud intrusion into the formation, which is more conducive to preventing wellbore collapse, but at the same time increases the risk of wellbore fracture. Sensitivity analysis shows that solute diffusion and reflection coefficients affect early wellbore stability through pore pressure and solute transport, while the chemical swelling coefficient has a long-term effect through chemically induced deformation. The results can provide theoretical guidance for quantitative optimization of mud parameters and prevention of wellbore instability when drilling in chemically active gas formations.

Multiphase flow analysis of complex wellbore–fracture–cave connections in condensate gas reservoirs

The significant heterogeneity of fracture-caved gas reservoirs and the phase transition behavior with pressure depletion pose great challenges for flow behavior analysis and property estimation. Therefore, the objective of this paper is to develop robust and novel pressure transient analysis models for condensate-gas flow under pressure depletion in fracture-caved gas reservoirs. To characterize the complex connections between wellbore, fracture region, and caves, four conceptual models of wellbore–fracture–cave distributions are determined. The fracture region is considered as a dynamic three-zone (dry gas zone, condensate-gas two-phase zone, and transition zone) to characterize the phase transition during pressure depletion, while a variable storage concept is introduced to describe the phase transition in the wellbore and caves. The results indicate that six typical flow stages can be observed from the type curves: constant wellbore storage flow, variable wellbore storage flow, fracture linear flow (FLS), constant cave storage flow, variable cave storage flow, and transition flow. Moreover, the phase transition behavior in the fracture region is reflected in the changes of one-half slope straight lines during the FLS period, while the phase transition behavior in the wellbore and caves is reflected in the pressure derivative curve as a positive upward bending of the straight line with unit slope at later stage. The property estimation in the fracture-caved gas reservoirs (i.e., length and permeability of the fracture region, the storage coefficient of wellbore and cave) by matching with the actual pressure monitoring data provides a better understanding of the geological evidence.

Fracture Propagation of Multi-Stage Radial Wellbore Fracturing in Tight Sandstone Reservoir

Radial wellbore fracturing is a promising technology for stimulating tight sandstone reservoirs. However, simultaneous fracturing of multiple radial wellbores often leads to unsuccessful treatments. This paper proposes a novel technology called multi-stage radial wellbore fracturing (MRWF) to address this challenge. A numerical model based on the finite element/meshfree method is established to investigate the effects of various parameters on the fracture propagation of MRWF, including the azimuth of the radial wellbore, the horizontal stress difference, and the rock matrix permeability. The results show that previously created fractures have an attraction for subsequently created fractures, significantly influencing fracture propagation. A conceptual model is proposed to explain the variations in the fracture propagation of MRWF, highlighting three critical effect factors: the attraction effect, the orientation effect of the radial wellbore, and the deflection effect of the maximum horizontal principal stress. Fracture geometry is quantitatively assessed through the deviation distance, which indicates the radial wellbore’s ability to guide fracture propagation along its axis. As the azimuth increases, the deviation distances can either increase or decrease, depending on the specific radial wellbore layouts. Decreasing the horizontal stress difference and increasing the rock matrix permeability both increase the deviation distance.

Relative permeabilities for two-phase flow through wellbore cement fractures

Multiple fluids are likely to exist in fractures and flow paths associated with leaky wellbores, including liquids (e.g., crude oil) and gases (e.g., gas exsolved from liquid). These fluids occupy and move through different portions of the pore spaces within the fractures depending on many factors, including fluid properties, fracture size, and the amount of the different fluids. Upward leakage of any phase, through the fracture, can contaminate water-bearing formations, create hazardous surface conditions, and compromise the functionality of the wellbore. Early signs of wellbore leaks may be expressed by anomalous pressure behavior at surface monitoring points on cavern storage wells. These pressure anomalies are difficult to interpret, necessitating knowledge of the factors that affect the multiphase flow in fractures and porous media. These parameters are critical to modeling multiphase flow in fractures. This insight can guide further diagnosis and maximize leak remediation. Our study focuses on the relationship of the liquid–gas relative permeabilities for representative variable-aperture wellbore cement fracture. To obtain the relative permeability of each phase, two-phase flow tests were conducted where both fluids were flowing simultaneously through a fractured wellbore cement specimen under a range of factors, namely (1) aperture size, (2) capillary numbers, and (3) viscosity ratio. The flow experiments were conducted under a range of confining stresses and flow velocities, using nitrogen gas and silicone oils (of different viscosities) in a specially designed pressure vessel. The sum of gas and oil relative permeabilities were found to be less than one under all conditions, which indicates that the presence of one phase affects the permeability of the other phase, and vice versa. Since the gas phase flow conditions include a significant inertial flow component in addition to viscous flow, the inertial flow coefficients at different saturation states are presented. The factors affecting the relationship between the relative permeabilities are discussed in detail. A new mathematical model for estimating the relative permeability of wellbore cement fracture is presented and experimentally validated.

Development of a Novel Dynamic Wellbore Fracturing Technology by Integrating Full-Scale Experimental Testing and FDEM Numerical Simulations

Development of a Novel Dynamic Wellbore Fracturing Technology by Integrating Full-Scale Experimental Testing and FDEM Numerical Simulations

Wellbore fracture recognition and fracture parameter identification method using piezoelectric ultrasonic and machine learning

Real-time monitoring of wellbore status information can effectively ensure the structural safety of the wellbore and improve the drilling efficiency. It is especially important to recognize the wellbore fractures and identify their parameters, which motivates us to propose a wellbore fracture recognition and parameter identification method using piezoelectric ultrasonic and machine learning. To realize a self-model emission detection, we innovatively utilize a single transducer to act as both an actuator and a sensor, allowing for the efficient acquisition of ultrasonic echo signals of the wellbore. For fracture recognition, we use the wavelet packet transform to extract features from the ultrasonic echo signal, while constructing a convolutional neural network model for fracture recognition. Then, we establish the relationships between the fracture width-depth parameter and the echo signal, including the peak value as well as the arrival time difference. The experimental results show that the proposed method effectively recognizes the fractures from the ultrasonic echo signal of the wellbore. At the same time, the established function truly reflects the relationship between the fracture parameters and the echo signal. Therefore, the proposed method can provide an identification function for quantitative monitoring of wellbore fracture parameters. Moreover, the functions can be used as a reference for other structural health monitoring, which has good application prospects.

Development of A Neural Boosted Model and JSL Code to Identify “Clean” or “Not Clean” Wells - A West Texas Sperry and Oklahoma Woodford Fractured Wells Coiled Tubing Cleaning Case Study

In a previous study, wellbore cleaning coefficient (WCC) correlations for cleaned wellbores out of debris and bridge plug remnants were developed for three conventional coiled tubing sizes (2.375”, 2.625”, and 2.875”). The following key performance indicators (KPIs): (1) slick water density ( ) ρ f , (2) slick water viscosity ( ) µ f , (3) hydraulic diameter c t (d - d ) between casing inner diameter (dc ) and coil tubing outer diameter (dt ), (4) average annular velocity ( ) v and (5) cleaning pressure gradient ∆P across a measured depth (MD) were employed in the empirical models. The models addressed operational conditions under which fractured wells will be identified as whether “clean” or “not clean”. In this study, the database from 150 wells, in the Spraberry formation in West Texas, was used to develop a predictive model to identify status of cleaned fractured wells: whether “clean” or “not clean”? About 70% of the data (99 wells) was used for training and about 30% (51 wells) for validation. 14 wells from the liquids-rich shale Woodford formation (Oklahoma) were utilized for testing. Six predictive modeling tools were designed to validate the derived empirical correlations. These tools are (1) Fit Stepwise, (2) Neural Boosted, (3) Boosted Tree, (4) Decision Tree (Partition), (5) Generalized Regression Lasso, and K-Nearest Neighbors. In the predictive models, independent variables are the annular velocity (AV), the Reynolds’ Number (Re), the Euler’s Number (Eu), and the coiled tubing roughness to internal radius ratio (ε/D). The dependent variable is well status; “clean” or “not clean”. Jump Scripting Language (JSL) code was used to develop user-friendly software. The software would be utilized to identify the fractured wellbore status, whether “clean” or “not clean”. Operators would be able to use the code to identify working conditions for which completed fractured wells are “clean” out of fracturing debris and remnants of bridge plugs or “not clean”. Input parameters to the code are AV, Re, Eu, and ε/D

Lost circulation material design for near-wellbore transverse fractures

The use of particulate lost circulation material (LCM) in drilling fluid is a common method for mitigating lost circulation from near-wellbore fractures that develop during subterranean drilling. Fracture width estimation is the center piece of designing the particle size distribution (PSD) of LCM blends. Width estimation of near-wellbore fractures has predominantly been based on assuming axial fracture development from wellbores. However, this assumption is not valid for all wellbore orientations. Shallow vertical and highly inclined or horizontal well sections in a normal subsurface faulting regime may give rise to configurations where drill-induced fractures develop transverse to the wellbore axis. A transverse fracture yields a substantially different width compared to an axial fracture. This study aims to demonstrate the width contrast between the two fracture geometries and the impact that such contrast would have on the LCM blend design. For this purpose, the width of near-wellbore transverse fractures is estimated using a linear elastic fracture mechanics solution to an axisymmetric model of the same. Contrary to the case of hydraulic fractures, the solution must consider the effect of wellbore cavity boundary conditions on the fracture width profile. Two case studies involving horizontal and vertical boreholes are examined. Results indicate that the assumption of axial fracture geometry could lead to substantial underestimation or overestimation of the fracture width depending on the wellbore inclination and magnitudes of the in-situ stress components. Application of the solution in selecting the compositions of blends made from three LCMs is demonstrated. The discrepancy between the LCM blends PSDs obtained based on the axial and transverse models of the wellbore fracture are discussed.

Proppant Migration Law Considering Complex Fractures

The placement of proppant within fractures is critical to the effectiveness of hydraulic fracturing. To elucidate the migration and placement patterns of proppant within multi-branched fractures during hydraulic fracturing, we conducted simulation experiments under both single-fracture and multi-branched-fracture conditions, varying injection rates and proppant sizes. The results of the research indicate that increasing the injection rate effectively increases the magnitude of vortex formation at the leading edge of sandbars and the drag forces acting on the proppant particles, resulting in increased particle migration distances. However, effective proppant packing near the wellbore entrance is not achieved at higher injection rates, leaving the fractures susceptible to closure under in situ stress, thereby reducing overall fracture conductivity. In addition, increasing the proppant size results in higher settling velocities and weakens the vortex’s ability to entrain the proppant particles. This results in shorter proppant placement distances, and the proppant cannot effectively reach the distant branched fractures. In addition, the diversionary effect of the branched fractures gradually reduces the flow rate in the distant branches, resulting in poorer proppant placement efficiency. Based on these findings, we recommend an approach that initially increases injection rates while reducing proppant size to ensure proppant placement in distant wellbore fractures and branched fracture networks. Subsequently, larger proppants can be used to effectively fill fractures close to the wellbore.

Integration of subsurface dynamic coupled modelling and monitoring technologies for CCS: examples from existing projects


 Introduction
 Host rock injectivity and storage complex integrity (containment) for CO2 sequestration are critical factors to ensure that capacity targets are met while preventing CO2 leakage over time and confirm permanent storage.
 
 Figure 1 sketches the typical CO2 injectivity problem. Evaluating injectivity, capacity and containment requires assessing key phenomena such as: seal and faults capillary controls, non-isothermal reactive flow, geomechanical failure induced in the seal, along faults and/or fractures and in the vicinity of the wells. Additional analyses will also be needed to evaluate the completion integrity of the wells (injectors, monitoring and existing wells) under variable load conditions in terms of pressure, temperature and chemistry. The listed phenomena, and their likely effects, are analysed by means of dynamic coupled modelling, considering co-existing (geo)mechanical and dynamic flow simulations. Therefore, coupled modelling improves the risk analysis allowing to evaluate the Thermo-Hydro-Mechanical-Chemical (THMC) processes associated to CO2 injection.
 Analyses
 In this presentation we will provide some examples of integration of subsurface dynamic coupled modelling and monitoring technologies for CCS. Some of these examples are derived from existing projects.
 
 Injectivity impairment during CO2 injection is a well-known issue often observed at well and field scale (e.g. Snøhvit, Ketzin, Decatur projects [1], [2]). Loss of injectivity is governed by the interactions between CO2-brine phase behavior, CO2-solid phase (rock) behavior, salt precipitation, multi-phase flow. Characterizing zonal injectivity and developing mitigation strategies will be therefore important for project success. Figure 2 (left and center) shows an example of time-lapse CO2 saturation evolution during injection and consecutive non-isothermal processes associated to Joule-Thompson effect (H2O vaporization, cooling and induced salt precipitation due to dry-out). Temperature and pressure changes can lead to near wellbore failure (thermal and pressure induced fracturing) impacting injection performance due to near wellbore fracturing and consecutive permeability changes (Figure 2 right).
 To close the evaluation loop, the integrated subsurface characterization workflow is completed by measurements to image the subsurface before and after CO2 injection. This provides essential insights into the storage complex quality before injection and effective monitoring during injection and permanent storage, tracking the position of the CO2 pressure and concentration plumes, assessing surface heave, and detecting any risks or potential leakage paths. There is a tight link between subsurface dynamic coupled modelling and existing monitoring technologies. This link expands the well-known MMV (Measurement, Monitoring and Verification) process into a more integrated 3MV process (Modelling, Measurement, Monitoring and Verification), opening to the definition of a subsurface digital twin supporting successful CCS operations. We will briefly introduce methods and technologies enabling the subsurface dynamic modelling and monitoring of CO2 injection and storage. Seismic and borehole petrophysical and geophysical measurements for initial subsurface characterization and consecutive monitoring will be described.

Calculation of Wellbore Fracture Pressure Under Multi Field Coupling Based on M-Integral of Configuration Mechanics

Calculation of Wellbore Fracture Pressure Under Multi Field Coupling Based on M-Integral of Configuration Mechanics

Coupled Thermal-Hydraulic-Mechanical Modeling of Near-Well Stress Evolution in Naturally Fractured Formations during Drilling

Naturally fractured formations usually have strong heterogeneities. Drilling and production operations in such formations can involve unwanted formation failure risks such as wellbore collapse and wellbore fracturing. This study presents a coupled thermal-hydraulic-mechanical numerical model for near-well stress evolutions during drilling in naturally fractured formations. The evolution of pressure, temperature, and geo-mechanical responses on the wellbore wall and in the near-well region is simulated. The effects of wellbore pressure, internal friction angle, and natural fracture length on formation rock risks are discussed. A failure index is used to quantify the formation rock failure risks. The existence of natural fractures magnifies the heterogeneous system response induced by drilling. Increasing the wellbore pressure from a relatively low value can improve the support for the wellbore wall, which reduces the failure risks caused by shearing. In mechanically weak formations, the effect of natural fractures on formation rock failure becomes more significant. When the natural fracture length is large, the near-well region tends to have greater failure risks as the formations become more mechanically weak. This study provides a quantitative understanding of the effects of drilling and formation parameters on failure risks.

Numerical simulation of near wellbore fracture propagation in interbedded continental shales with competing perforations

To reduce near wellbore fracture complexity in continental laminated shales, in-plane perforations completion technology is introduced. The global embedded cohesive elements are capable to simulating arbitrary fracture propagation growth while the laminae effects on fracture propagation path can be considered in established finite element model. Numerical simulations reflect that the existence of weak micro fractures only locally alter the fracture propagation path but laminae can change the fracture propagation path greatly. Furthermore, the in-situ stress anisotropy, pump rate, perforation intersection angle and perforation angle with laminae are critical factors for affecting the fracture propagation path and breakdown pressure. There is a great impact of laminae on the fracture branching at the contact interface and hydraulic fracture tends to cross laminae at high approaching angle but propagate horizontally along laminae at low approaching angle. In most cases, hydraulic fracture tends to propagate along the laminae rather than across the laminae. The adjustment of pump rate, fluid viscosity, perforation intersection angle and perforation angle with laminae can enhance the possibilities of hydraulic fracture across laminae. It was also found that hydraulic fractures induced from different perforations can interact and overlap with each other, resulting in different fracture geometry and pressure behavior for individual fracture. The fracture width of interior fracture is almost close at the near wellbore zone at the end of pumping, and exterior fractures generally deviated away from the perforation tunnel direction because of stress interference of neighboring fractures. Additionally, although a fracture initiated initially from a perforation tunnel to short distance, hydraulic fractures still finally would reorient itself to maximum principle in-situ stress direction, thus increase more chances of creating one large and main fracture along the maximum principle in-situ stress orientation with larger horizontal stress contrast. Therefore, the existence of laminae can enhance the potential of fracture complexity near wellbore but the selection of suitable perforation scenarios in one defining plane can increase the possibility of form a main fracture. The simulation results from this study offer some important insights to hydraulic fracturing design with multiple perforations on interbedded continental shales stimulation.

Hybrid geothermal energy and hydrocarbon resources production by repurposing horizontal wells in shale gas reservoirs in Horn River Basin, British Columbia, Canada

The production of geothermal energy from the depleted oil and gas reservoirs could represent one of the practical pathways of the clean energy transition for the hydrocarbon energy industry. In this study, a new strategy for repurposing oil and gas wells into geothermal energy production system is proposed to co-produce hydrocarbon and geothermal resources during the transition. At a certain stage in a hydrocarbon production system of fractured horizontal wellbores, one vertical injection well is added to connect to the end of the horizontal wellbores to form a U-loop system with open fractures in the lateral part. Cold water is injected through the injection well, transported along the U-loop system, and geothermal energy is produced along with natural gas for utilization. Natural gas production continues as long as the pressure of the horizontal well remains lower than the reservoir pressure. An example application case from a typical shale gas production system in the Horn River Basin of British Columbia, Canada has been examined in this study. The results show that reduction in cumulative gas production is limited if the injection well is added at a middle or later stage. The outlet temperature from this system behaves like those in a closed-loop geothermal system and could be stable for several decades of operation. Although the time of conversion is sensitive to gas production, it does not affect the bottom hole temperature much. The water flow rate does not affect the cumulative gas production but considerably affects the formation temperature. The horizontal length of the fractured wellbore will significantly affect the gas production performance and geothermal energy output. Fracture length and permeability have critical impact on gas production but less influence on geothermal energy recovery.

A multi-scale coupled productivity prediction model for conflagration compression fracturing of shale

A multi-fracture pressure flow regime coupled productivity prediction model considering shale gas adsorption and desorption, mass transfer and diffusion and cross-scale zoning was established based on cross-scale seepage characterization in unmodified area, interstitial matrix area, main fracture area, branched micro-fracture area and broken damage area formed from by conflagration compression fracturing. Then, geometric similarity, hydropower similarity and coupled iteration were used to build the model and complete the calculation. Finally, the effects of regional cross-scale seepage, number of fractures, production pressure difference, and fracture zone scale on gas well productivity were analyzed. The following results were obtained. First, the seepage flow of shale gas in different fractured areas is a continuous changing process. Among them, the unaffected area is dominated by transition flow and slip flow while continuous flow exists in the microfracture area-wellbore broken area and artificial fracture area. Second, the productivity of gas wells increases with the increase of fracture length and number, but the productivity increase tends to be stable after the fracture length exceeds 2 m. It is worth to mention that the increase of the number of fractures is more conducive to improving the productivity of shale gas under this condition. Third, when the number of high energy gas fractures is 6, its mining capacity is equivalent to that of hydraulic fracturing fractures with a half-fracture length of about 100 m. Fourth, when the production pressure difference exceeds 22 MPa, the free gas production capacity shows a decreasing trend. Therefore, the preferred production pressure difference is about 22 MPa. Fifth, the greater the number of artificial fractures, the greater the contribution of the increase in the diffusion coefficient to productivity, and the existence of wellbore fracture zone is also conducive to the stimulation of gas wells.

Mechanism Analysis of Wellbore Fracture and Internal Strain State

Mechanism Analysis of Wellbore Fracture and Internal Strain State

Comparative Evaluation on the Coupled Fracture Characteristics for Longmaxi Anisotropic Shale

Abstract The shale fracture characteristics are important for realizing the complex hydraulic fracture network, predicting wellbore fracture pressure, and optimizing wellbore trajectory and the rock fragmentation efficiency. Through a three-point bending test of notched semicircular specimens of Longmaxi shale, the coupled relationship of mode-I fracture toughness (Kic), peak fracture force (Pmax), energy release rate (GI), applied work (W), and loading rate was studied by using kernel density analysis method. The results showed that the dynamic characteristics of force-displacement curve exhibited obvious loading angle dependence, including two types of the “deformation accumulation-brittleness” and “deformation accumulation-brittleness-plasticity.” The Kic and GI increased linearly with Pmax increasing. With the increasing of the loading angle, the dispersion degree of Pmax, Kic, GI, and W all increased. The GI increased nonlinearly with the increasing of Kic. With the increasing of the loading rate, the Kic basically increased linearly. The dynamic Kic under static and quasistatic conditions had strong anisotropy. At the high loading rate, the anisotropy index gradually decreased as the loading rate increasing. The results have significant implications for the design of hydraulic fracturing and the exact fracture control of Longmaxi shale.

High-quality fracture network mapping using high frequency logging while drilling (LWD) data: MSEEL case study

The Marcellus Shale and Energy Environmental Laboratory (MSEEL) provides a comprehensive dataset and field tests that can be used to study the significance of preexisting natural fractures in different subsurface engineering problems such as the effectiveness of the stimulation of an unconventional reservoir, optimized geothermal fluids movement and integrity of the CO2 storage site. Conventionally natural fracture intensity is obtained using sonic and micro-resistivity imaging logs. However, these techniques significantly suffer from two major deficiencies: Human bias in log interpretation and extremely long interpretation time. These two deficiencies are well-recognized in the industry; however, no standard procedures exist to address them. In this study, a new automated machine learning workflow (AMLW) is introduced that uses the LWD high-resolution acceleration data along the horizontal laterals to predict the natural fracture intensities originally obtained using sonic and micro-resistivity imaging. The accuracy and robustness of the new workflow to predict the near wellbore fracture intensities are tested using both regression and classification approaches. Both the regression and classification approaches were able to predict the fracture intensities with high accuracy (average Mean Squared Error of 0.0085 for regression and average accuracy of 0.94 in the confusion matrix for classification). We have shown that only 10%–15% of the labeled resistivity image log is required for training and validation of the machine-learning model. The Automated workflow resulted in K-Neighbors Regressor and classifier algorithms as the best algorithms with a 52.74% and 139.3% improvement in comparison to the Gradient Boosting Regression algorithm (i.e. the fifth best algorithm).

Compression of Particulate Materials in Wellbore Fractures and Enhancement in the Wellbore Breakdown Limit

Abstract Fluid loss during subterranean drilling often occurs through fractures that develop or preexist around the wellbore. Particulate additives, known as lost circulation material (LCM), are commonly added to the drilling fluid to mitigate lost circulation. The LCM forms an impermeable agglomerate within the fractures while preventing further tensile failure of the wellbore wall. The outcome is enhancement in the wellbore breakdown limit. A semi-analytical elastic solution is developed to estimate the width of near-wellbore fractures that partially close on the LCM agglomerate. The solution uses stress–strain data from confined compression testing on LCMs. The compression test results are modeled through a modified form of Kawakita’s (1971) powder compaction equation. The developed constitutive model is embedded within the described semi-analytical solution for the wellbore fractures. The solution adopts an incremental loading approach to treat the nonlinearities arising from the characterized LCM constitutive behavior, as well as large deformation of the LCM agglomerate within the partially closed fractures. At each incremental load, the nonlocal stress equilibrium along the fracture length is described via an integral equation. Successive solutions to these integral equations determine the unknown fracture width of partially closed fractures. A competition between the fractures tendency for propagation and the wellbore wall tendency for secondary tensile failure determines the overall stability of the fractured wellbore. Mechanical behavior of the LCM agglomerate under compression is identified as a key parameter that controls both mechanisms, thereby, the gain in breakdown limit of a fractured and LCM-treated wellbore.

Pressure transient behavior modeling of a multi-horizontal well pad with damaged fracture in shale gas

Multi-fractured horizontal wells significantly promoted the development of shale gas, and multi-well pads are applied generally in field application. The interference between adjacent wells attributed to the close well spacing becomes an issue that must be considered. Also, with the proppant accumulation in near-wellbore, fracture damage with low permeability and strong stress sensitivity usually occurs in far from wellbore fracture section. A semi-analytical model of multi-horizontal well pad with damaged fractures is established for the first time with a method that can deal with non-uniform fractures. Based on numerical inversion, the type curve is obtained and eight regimes are identified by the characteristics of the pressure derivative curve. Good agreement with the numerical simulation manifests the correctness of our model. Afterward, the influences of crucial parameters on pressure transient are studied. Considering the influence of adjacent wells, the pressure derivative curve elevates since well interference regime and finally maintains at a value of ∑0.5qwDi during whole system radial flow. Well spacing has an impact on the appearance time of the well interference regime. The pressure transient type curve since well interference regime moves up with higher production rate of adjacent wells. The damaged fracture section influences the early time pressure transient. With the increase of damaged fracture length, the early time pressure drop is enhanced. With consideration of stress sensitivity, ‘hump’ would be identified in the pressure derivative curve. Compared with undamaged fracture section, the ‘hump’ caused by the stress-sensitive damaged fracture section appears earlier due to a sharper conductivity decline. The model reveals the flow mechanism of stress-sensitive partially propped fractures and provides some new insights on pressure transient analysis of multi-horizontal well pad in shale gas.