Unconventional Fracture Model Research Articles

Unconventional Fracture Networks Simulation and Shale Gas Production Prediction by Integration of Petrophysics, Geomechanics and Fracture Characterization

The proficient application of multistage fracturing methods enhances the status of the Duvernay shale formation as a highly esteemed shale reservoir on a global scale. Nevertheless, the challenge is in accurately characterizing unconventional fracture behavior and predicting shale productivity due to the complex distributions of natural fractures, pre-existing faults, and reservoir heterogeneity. The present study puts forth a Geo-Engineering approach to comprehensively investigate the Duvernay shale reservoir in the vicinity of Crooked Lake. To begin with, on the basis of the experimental results and well-logging interpretations, a high-quality petrophysical and geomechanical model is constructed. Subsequently, the establishment of an unconventional fracture model (UFM) takes into account the heterogeneity of the reservoir and the interactions between hydraulic fractures and pre-existing natural fractures/faults and is further validated by 18,040 microseismic events. Finally, the analysis of well productivity is conducted by numerical simulations, revealing that the agreement between the simulated and observed production magnitudes exceeds 89%. This paper will guide the efficient development of increasingly important unconventional shale resources.

Fracture-controlled fracturing mechanism and penetration discrimination criteria for thin sand-mud interbedded reservoirs in Sulige gas field, Ordos Basin, China

Considering the problems in the discrimination of fracture penetration and the evaluation of fracturing performance in the stimulation of thin sand-mud interbedded reservoirs in the eighth member of Shihezi Formation of Permian (He-8 Member) in the Sulige gas field, a geomechanical model of thin sand-mud interbedded reservoirs considering interlayer heterogeneity was established. The experiment of hydraulic fracture penetration was performed to reveal the mechanism of initiation–extension–interaction–penetration of hydraulic fractures in the thin sand-mud interbedded reservoirs. The unconventional fracture model was used to clarify the vertical initiation and extension characteristics of fractures in thin interbedded reservoirs through numerical simulation. The fracture penetration discrimination criterion and the fracturing performance evaluation method were developed. The results show that the interlayer stress difference is the main geological factor that directly affects the fracture morphology during hydraulic fracturing. When the interlayer stress difference coefficient is less than 0.4 in the Sulige gas field, the fractures can penetrate the barrier and extend in the target sandstone layer. When the interlayer stress difference coefficient is not less than 0.4 and less than 0.45, the factures can penetrate the barrier but cannot extend in the target sandstone layers. When the interlayer stress difference coefficient is greater than 0.45, the fractures only extend in the perforated reservoir, but not penetrate the layers. Increasing the viscosity and pump rates of the fracturing fluid can compensate for the energy loss and break through the barrier limit. The injection of high viscosity (50–100 mPa·s) fracturing fluid at high pump rates (12–18 m3/min) is conducive to fracture penetration in the thin sand-mud interbedded reservoirs in the Sulige gas field.

Optimizing extreme limited entry design for lateral heterogeneous reservoirs

Extreme limited entry (XLE) method can enhance hydraulic fracture uniformity by elevating wellbore pressure to overcome reservoir heterogeneity. However, it increases surface pressure and decreases hydraulic fracturing efficiency. In this paper, the effects of stress shadow and heterogeneity of the lateral breakdown pressure on fracture propagation are numerically studied, from which an optimization method is proposed for the XLE design with the minimal requirement of fracturing pressure. Initially, the unconventional fracture model is applied to analyze fracture propagation in formations with homogeneous geomechanical parameters and various perforation designs. Fracture length distribution is correlated with perforation friction, revealing insights into the influence of geomechanical parameters and fracture spacing. Then, the uniformity of fracture propagation is assessed for different XLE designs by varying lateral breakdown pressures. Simulation results are utilized to develop a cross-plot of fracture length distributions vs normalized perforation frictions for optimizing an XLE design. In homogeneous reservoirs, decreasing perforation spacing and increasing perforation hole erosion rate slow down the reduction in the fracture length distribution span with perforation friction, necessitating a higher perforation friction for uniform fractures. In all simulated cases, a similar trend is observed when the distribution of fracture lengths is plotted vs the normalized perforation friction to the difference of breakdown pressure within one fracturing stage. It is recommended that this normalized value be maintained above 2 in an XLE design. This new plot makes the conventional horn-shaped plot more applicable to reservoirs with heterogeneous lateral breakdown pressures.

A comprehensive review of numerical simulation methods for hydraulic fracturing

AbstractHydraulic fracturing unlocks previously inaccessible hydrocarbons in unconventional reservoirs by creating artificial pathways in the unconventional reservoir. Numerical simulation expands the scope of hydraulic fracturing design for various reservoir conditions. This review paper explores the synergy between numerical simulation and hydraulic fracturing modeling, focusing on critical elements like geomechanical behavior, geological conditions, and fluid dynamics. Analytical models in hydraulic fracturing design are discussed to underscore their foundational importance. The assumption of constant fracture height limits the application of Perkins–Kern–Nordgren model (PKN) and Kristianovich‐Geertsma‐de Klerk model (KGD). Radial models assume 3D flow but lack reliability in nonradial settings, and the Pseudo 3D model (P3D) shares PKN's assumptions with variable fracture height, sacrificing some details for efficiency. Planar 3D model (PL3D) enhances accuracy by discarding PKN's elastic response assumption but requires extended computation. Unconventional fracture model is effective for complex scenarios but relies on DFN modeling parameters for accuracy. The choice of numerical simulation method in hydraulic fracturing depends on the specific aspect studied, each with its strengths and limitations. For instance, boundary element methods are efficient for exterior problems, finite element modeling suits 3D nonplanar fractures, and the extended finite element method excels in hydraulic and natural fracture interactions. Peridynamics shows potential but needs further development for cost‐effectiveness. PFC and UDEC/3DEC‐based simulations can explore microscopic mechanisms. Combining these methods with other approaches provides a comprehensive study of realistic reservoir conditions. This review guides the selection of a suitable numerical simulation methodology based on the study's scope.

Intricate unconventional fracture networks provide fluid diffusion pathways to reactivate pre-existing faults in unconventional reservoirs

Hydraulic fracturing-induced earthquakes are typically triggered via a hydraulic connection between stimulated wells and pre-existing faults. Despite this, relatively little modeling has focused on fluid migration along fractures and faults in shale reservoirs. The experimental measurements and logging data were collected first to create a high-resolution 3D petrophysical and geomechanical model of a Duvernay reservoir. To simulate the real-time growth of complex hydraulic-natural fracture networks, an unconventional fracture model (UFM) is constructed that considers fluid flow, interactions between hydraulic and natural fractures, reservoir petrophysics, and geomechanics. Coupled poroelastic modeling quantifies the well-fault hydraulic connection in terms of spatiotemporal stress and pressure changes, assessing the fault stability during hydraulic fracturing. The UFM model is applied to three field case studies, and the findings are evaluated against those of induced earthquake clusters. The non-uniform intricate fracture networks are discovered to provide fluid diffusion pathways for hydraulic fracturing-induced earthquakes. To reduce possible seismic risks, fault stability must be assessed prior to hydraulic fracturing in unconventional reservoirs.

Hydraulic fracturing design for shale oils based on sweet spot mapping: A case study of the Jimusar formation in China

Multistage fracturing horizontal well is the main method of shale oil development. However, significant differences are observed between fracturing stages productivity due to reservoir heterogeneity. Therefore, it is necessary to incorporate reservoir heterogeneity characterization in hydraulic fracturing design so that ineffective clusters can be minimized. Taking the Jimusar formation as example, we apply an integrated fracturing design workflow that considers reservoir heterogeneity characteristics through sweet spot mapping to arrive at the optimum fracturing treatment. The geological and geomechanics models are constructed utilizing logs and core laboratory tests, from which the geological sweet spot (GSS) and engineering sweet spot (ESS) mapping are obtained. The GSS and ESS are later classified with respect to three different levels: type I (good), type II (medium) and type III (poor), based on which four sweet spot combinations are selected for fracturing design. Unconventional fracture model (UFM) is applied for the generation of complex fracture network, and performs productivity evaluation through reservoir numerical simulation. The simulation results suggest that to maximize the fluid withdrawal within stimulated region by reducing the productivity difference between stages, the fracturing scale of the stage containing type I GSS combination should be smaller than that of type II/III GSS in jimusar formation. And for regions with the same type GSS, the fracturing scale containing the type I ESS combination should be kept smaller than that of the type II/III ESS. The workflow will be helpful for the reservoir engineers in developing a reasonable fracturing plan that maximizes production performance or economic benefit for shale oil in future operations.

Integrated Simulation for Hydraulic Fracturing, Productivity Prediction, and Optimization in Tight Conglomerate Reservoirs

With the development of advanced horizontal drilling and multistage hydraulic fracturing techniques, the productivity of unconventional tight oil such as that found in the Baikouquan Formation of the Mahu Sag in the Junger Basin has been increasing. The Mahu oilfield is the largest tight conglomerate reservoir in the world. However, predicting the productivity of fractured horizontal wells in tight oil remains a challenge due to the high heterogeneity of the reservoir and complexity of its hydraulic fractures. Therefore, this study proposes a workflow for coupled geological modeling, along with fracturing and reservoir simulations in tight conglomerate reservoirs. Taking well block Ma131 as an example, a three-dimensional geological model is first built according to the results of geophysical research. The unconventional fracture modeling is used next to establish a fracturing simulation. Given the lack of natural fractures and the high concentration of conglomerate in the study area, the method of the multiple groups of microscale natural fractures is used to simulate the impact of gravel on fracture propagation. The feasibility of the method is verified with microseismic monitoring data and treating curves. Thereafter, an unstructured grid and the INTERSECT reservoir simulator are used to simulate the production performance of horizontal wells. The stress sensitivity effect of the rock matrix and fractures and the changes in the formation flow field caused by fracturing are considered in the reservoir simulation. Hydraulic fractures are found to be unable to form complex fracture networks easily under the conditions of high stress difference, high gravel content, and undeveloped natural fractures. However, they show the characteristics of macroscopic simplicity and local branching. Reducing cluster spacing can increase the complexity of hydraulic fractures and the productivity of horizontal wells. Finally, the proposed integrated simulation process is used to optimize well spacing, fracturing stimulation parameters, and the production system. Overall, the study serves as a guide for maximizing the production and economic benefits of tight conglomerate reservoirs.

Numerical Investigation of Major Impact Factors Influencing Fracture-Driven Interactions in Tight Oil Reservoirs: A Case Study of Mahu Sug, Xinjiang, China

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

Interpretation of Hydraulic Fractures Based on Microseismic Response in the Marcellus Shale, Monongalia County, West Virginia, USA: Implications for Shale Gas Production

Summary Hydraulic fracturing is critical for extracting shale gas in the subsurface. The treatment technique of multistage hydraulic fracturing is widely used to maximize production. In multistage hydraulic fracturing, not all pumping stages make the same contribution for production, although the designed stimulation process is almost same in every pumping stage. In this study, we characterize the microseismic responses of hydraulic fracturing. Significant variations of microseismic characteristics are observed among the different pumping stages. Pre-existing natural fractures are examined along the horizontal well in selected stages. Combined with the Mohr’s circle analysis, results of the fracture study show that induced hydraulic fractures can be captured by pre-existing natural fractures. Induced hydraulic fractures are simulated by the unconventional fracture model (UFM), and the result reveals that the stress-shadow effect diverts the direction of hydraulic fractures. The diverted hydraulic fracture affects the development of the hydraulic fracture network, which has influence on production. The treatment of two-step pumping is investigated by application of hydraulic diffusivity. Hydraulic fracturing performance and production could be optimized by the treatment of two-step pumping in a single stage. The second pumping creates new fractures and fills the fractures with additional proppants to maintain production for a long duration.

On multistage hydraulic fracturing in tight gas reservoirs: Montney Formation, Alberta, Canada

The combination of horizontal drilling and multistage hydraulic fracturing technology has unlocked production of petroleum from tight/shale rock. Prediction of single or multistage hydraulic fracturing treatments along horizontal wells in tight formations remains a challenge and thus optimization of these stimulation treatments is difficult. Currently, there are few effective approaches to characterize multistage hydraulic fracturing in tight rock reservoirs. In this paper, we use a three-dimensional tight rock simulator based on the Unconventional Fracture Model (UFM) to understand multistage hydraulic fracturing in the Montney Formation in Alberta, Canada. We use geological and geomechanical properties, stress magnitude and orientation, completion and production data to history match and characterize fracture volume and conductivity in the Montney Formation. Predictions of fractures from the history-matched reservoir model reveal the strong connection between the fracture conductivity and reservoir permeability, elastic rock properties as well as stresses distributions. The field example demonstrates how stress maps and rock properties calculated from density and gamma logs are integrated to yield predictive hydraulic fracturing capability. This study illustrates the critical role of reservoir permeability on fracture extent and conductivity. This workflow can be used to develop strategies for (1) refracturing of existing wells, (2) design and number of perforations, and (3) prediction of fracture propagation in later stages.

Fracture Modeling Using a Constructed Discrete Fracture Network From Seismic Data

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 179130, “Calibrated Complex Fracture Modeling Using a Constructed Discrete Fracture Network From Seismic Data in the Avalon Shale, New Mexico,” by Foluke Ajisafe, Manoj Thachaparambil, Donald Lee, Ben Flack, Kim Hemsley, Efe Ejofodomi, and Christopher Taylor, Schlumberger, prepared for the 2016 SPE Hydraulic Fracturing Technology Conference, The Woodlands, Texas, USA, 9–11 February. The paper has not been peer reviewed. The objective of this study is to validate the concept of using a seismically derived discrete fracture network (DFN) calibrated with borehole measurements, for complex-hydraulic-fracture modeling. This study was applied successfully on a two-well horizontal pad in the Avalon Shale located in the Delaware Basin, New Mexico. The work flow presented in this paper shows the successful application of seismic data in creating DFNs required to model hydraulic fractures in unconventional reservoirs. Introduction In the past, hydraulic-fracture modeling was limited to planar models for conventional reservoirs, with the absence of natural fractures. In unconventional reservoirs, planar models are highly limited in properly simulating complex fracture geometries. In recent years, a state-of-the-art complex- fracture-network model, also known as an unconventional fracture model (UFM), was developed. The model simulates the fracture propagation, rock deformation, and fluid flow in the complex fracture network created during a treatment. A key difference between the UFM and the conventional planar-fracture model is the ability to simulate the interaction of hydraulic fractures with pre-existing natural fractures. In shale plays, conventional DFN models are built out of 1D fracture-dip interpretation from a borehole-image log or from core in the same or a nearby well. However, because the hydraulic fractures created during a stimulation treatment usually extend hundreds of feet away from the wellbore, it is important to characterize and understand the natural fractures away from the wellbore. Therefore, a more-accurate DFN model than the simple conventional model is crucial in unconventional plays for optimizing well spacing and stimulation design to ultimately achieve maximum effective drainage while maximizing returns. In this study, the authors use an established work flow for extracting seismic-scale fracture networks and extending their population properties to model corresponding subseismic fractures that are critical to understanding and calibrating complex-hydraulic-fracture geometry created during stimulation. Geology The Avalon unconventional shale play consists of siltstone, limestone, clay, chert, and organics. It can be subdivided into three zones: upper, middle, and lower. In the past, the Avalon shale has been exploited by vertical drilling, but recently, horizontal drilling has been the trend to fully exploit this unconventional play.

Numerical Modeling of Hydraulic Fractures Interaction in Complex Naturally Fractured Formations

A recently developed unconventional fracture model (UFM) is able to simulate complex fracture network propagation in a formation with pre-existing natural fractures. A method for computing the stress shadow from fracture branches in a complex hydraulic fracture network (HFN) based on an enhanced 2D displacement discontinuity method with correction for finite fracture height is implemented in UFM and is presented in detail including approach validation and examples. The influence of stress shadow effect from the HFN generated at previous treatment stage on the HFN propagation and shape at new stage is also discussed.