Impediments to Refracturing Success in Shale Reservoirs

2021 ◽  
Author(s):  
Clay Kurison
Keyword(s):  
Hyperbolic Equation ◽  
Reservoir Simulation ◽  
Analytical Techniques ◽  
Horizontal Wells ◽  
B Value ◽  
Hydraulic Fractures ◽  
Fracturing Fluid ◽  
Minimal Impact ◽  
Wellhead Pressure ◽  
The Matrix

Abstract Stimulations in early horizontal wells in most shale plays are characterized by few and widely spaced perforation clusters, and low amounts of injected fracturing fluid and proppant. Low recovery from these wells has motivated refracturing although outcomes have been interpreted to range from successful to minimal impact based on operator specific evaluations. To tailor available technologies and improve quantification of upsides, there is need for mapping the spatial distribution of remaining resources and developing simpler but reliable analytical techniques. In this study, hydraulic fractures were assumed to be planar in a matrix with low porosity and ultra-low permeability. Consideration of natural fractures and their interaction with stimulation fluids led to addition of distributed fracture networks adjacent to the planar hydraulic fractures to define the composite fracture corridors. A sector model with the aforementioned architecture was used in reservoir simulation to investigate induced temporal and spatial drainage. These findings were used to explain the efficacy of widely used refracturing techniques and how post-refracturing reservoir response can be analyzed. Results from reservoir simulation showed remaining reserves were in the matrix between earlier placed hydraulic fractures aligned along initial perforation clusters, and beyond tips of hydraulic fractures. Upside from refracs could come from creation of new fractures in the matrix between earlier placed fractures and extension of tips of early fractures into virgin matrix. Assessment of these scenarios found the former to be optimal although depletion and existing perforations would limit the stimulation efficiency of new perforations. The second scenario would require large volumes of fracturing fluid to re-initiate fracture propagation. Yet this could trigger interference with offsets or affect drilling and stimulation of planned wells in adjacent acreage. For treatment efficiency, re-casing horizontal wells with competent liners and use of coiled tubing with straddle packers appears a better solution for bypassing old perforations. For the near wellbore and far field, re-stimulating new perforations at low injection rates could allow extension of fractures in virgin matrix surrounded by depleted strata. Real-time surveillance would be essential for mapping flow paths of refracturing fluid. For assessment of refracturing, actual and simulated flow exhibited persistent linear flow (PLF) that could be matched by Arps hyperbolic equation with a b value of 2. Incorporation of a novel fracture geometry factor (FGF) yielded an Arps-based equation that was tested on North American shale refracturing cases that often use post-treatment peak rate and wellhead pressure as measures of success. This study identified factors hindering the success of refracturing and proposed a modified Arps hyperbolic equation to analyze refracturing production data.

scholarly journals A parametric study of hydraulic fracturing interference between fracture clusters and stages based on numerical modeling

2020 ◽  
pp. 014459872095325
Author(s):  
Ang Chen ◽  
Xuyang Guo ◽  
Huiyong Yu ◽  
Lei Huang ◽  
Shanzhi Shi ◽  
...  
Keyword(s):  
Numerical Modeling ◽  
Hydraulic Fracturing ◽  
Horizontal Wells ◽  
Hydraulic Fractures ◽  
Fluid Viscosity ◽  
Shale Oil ◽  
Fracturing Fluid ◽  
Multi Stage ◽  
Study Results ◽  
Stress Contrast

Shale oil reservoirs are usually developed by horizontal wells completed with multi-stage hydraulic fractures. The fracture interference between clusters in a single stage and between consecutive stages has an impact on the stimulation quality in terms of fracture geometries and fracture widths. This study introduces a non-planar hydraulic fracture model based on the extended finite element method and its use in quantifying the effects of relevant parameters on multi-stage fracture quality in a realistic shale oil scenario. The numerical model is validated with field diagnostics based on vertical seismic profiling. Relevant parameters including stress contrast, fracturing fluid viscosity, cluster density, and fracturing in consecutive stages are quantitatively analyzed in the numerical study. Results show that effects of stress contrast on fracture quality are greater than those of fracturing fluid viscosity, while the effects are more significant in outer fractures instead of the inner fracture. Denser cluster design leads to greater inhibition for the growth of inner fractures which eventually divert them transversely. In fracturing for consecutive stages, the opening of fractures in the subsequent stages is inhibited and the fracture geometries are also altered by the inter-stage interference caused by the previous stage. Based on field data and numerical modeling, this study identifies key parameters and quantifies their effects on inter-fracture and inter-stage interference in multi-stage hydraulic fracturing in horizontal wells.

High Accuracy Estimation of Hydraulic Fracture Geometry Using Crosswell Electromagnetics

2021 ◽  
Author(s):  
Shubham Mishra ◽  
Vinil Reddy
Keyword(s):  
Hydraulic Fracture ◽  
Horizontal Wells ◽  
Hydraulic Fractures ◽  
Calibration Data ◽  
Formation Water ◽  
Fracturing Fluid ◽  
Production Forecast ◽  
Fracture Geometry ◽  
Field Development ◽  
Well Completion

Abstract Unconventional resources, which are typically characterized by poor porosity and permeability are being economically developed only after the introduction of hydraulic fracturing (HF) technology, which is required to stimulate the hydrocarbon flow from these impermeable/tight reservoir rocks. Since 1960, HF has been extensively used in the industry. HF is the process of (1) injecting viscous gel fluids through the wellbore into the subterranean hydrocarbon formation, at high pressures sufficient enough to exceed tensile strength of the rock and hydraulically induce cracks/fractures (2) followed by injecting proppant-laden fluid into the open fractures and packing up the fracture with proppant pack, after the injected fluid leaks off into formation. The resultant proppant pack keeps the induced fracture propped open and thus creates a highly conductive flow path for the hydrocarbon to flow from the far-field subterranean formation into the wellbore. Most the modern wells in unconventional reservoirs are horizontal/near-horizontal wells that are completed with large multiple HF treatments across the entire length of the horizontal wellbore (lateral), to increase the reservoir contact per well. Productivity of these wells is dictated by the stimulated reservoir volume (SRV), which is dependent on the number of fractures and conductive hydraulic fracture surface area of each fracture that is propped open. Therefore, estimation of the hydraulic fracture geometry (HFG) dimensions has become very critical for any unconventional field development. Key dimensions are hydraulic fracture length, height, and orientation, which are required to assess the optimum configuration of fracturing, well completion, and reservoir management strategy to achieve maximum production. Designs can be assessed based on HFG observations, and infill well trajectories, spacing, etc. can be planned for further field development. This workflow proposes a method to estimate and model all or at least two parameters of HFG in predominantly horizontal or nearly horizontal wells by use of interwell electromagnetic recordings. The foundation of this workflow is the difference in salinity, or more precisely resistivity, of the fracturing fluid and the resident fluid (hydrocarbon or formation water). The fracturing fluid is usually significantly less resistive than the hydrocarbon that is the dominant resident fluid where fracturing is usually conducted, or less resistive than the formation water in case the HF occurs in high water saturation regions. Therefore, the resistivity contrast between the two fluids will demarcate the boundary of hydraulic fractures and thus help in precisely modeling some or all parameters of HFG. The interwell recordings can be interpreted along a 2D plane between the two wells, one of them bearing the transmitter and the other with the receiver. The interpretations along a 2D plane can be used to calibrate a 3D unstructured HF model, thereby introducing a reliable calibration input that did not exist before. There can be multiple such 2D planes as more than one well can have a receiver, and, in that case, the 3D HF model has more calibration data and is even more precise. The reason this workflow significantly improves precision in HFG estimation and modeling is that it provides the ability to demarcate only the open portion of the HF and not the entire volume where pumping fluid entered, which would include parts that closed too quickly to contribute to the production from the well. Today, the industry, by its best methods, can only see the entire rock volume that broke due to fracturing, although significant parts of that broken volume might not be contributing to the production and thus are irrelevant in the 3D models upon which important decisions such as production forecast and project economics are based.

scholarly journals Simulação de Reservatórios de Óleo Leve com Poço Horizontal Hidraulicamente Fraturado

2017 ◽  
Vol 2 (2) ◽  
Author(s):  
Helio Souto
Keyword(s):  
Hydraulic Fracturing ◽  
Reservoir Simulation ◽  
Horizontal Well ◽  
Fractured Reservoirs ◽  
Horizontal Wells ◽  
Preconditioned Conjugate Gradient ◽  
Hydraulic Fractures ◽  
Tight Oil ◽  
Wellbore Pressure ◽  
Fractured Horizontal Wells

<p>Since the 1960s, because of the relevance to the oil industry, the numerical simulation of hydrocarbon reservoirs has received special attention and has been the subject of extensive studies. The main goal of computational modeling and the use of numerical methods for reservoir simulation is to allow better placement and control of wells, so that there is a optimized oil recovery. In this work, production of hydraulically fractured horizontal wells in light tight oil reservoirs will be studied. In this case, fractures do not form a continuous conductive network and can communicate hydraulically with only the horizontal producer well. In order to do that, a simulator for three-dimensional oil flow in reservoirs, suitable for applications in the field scale, already developed, using the Cartesian coordinate system and a finite difference approach, will be applied for the study of hydraulically fractured horizontal wells. Originally, this simulator and its grid refinement tools had been used only on the simulation of naturally fractured reservoirs. The nonlinear partial differential equation resulting from physical-mathematical modeling, written in terms of pressure, will be solved numerically after discretization and linearization using the Preconditioned Conjugate Gradient method. The main objective is to study the combined effects of hydraulic fractures and horizontal well on the wellbore pressure profile, considering different light tight oil production scenarios. Numerical simulations displayed the influence of important parameters on the well-reservoir system in study, such as fracture permeability and matrix porosity. A study of this type is relevant on the discussion of reservoir production strategies, helping on the decisions about a hydraulic fracturing operation in order to obtain economic viability for the hydrocarbons recovery project.</p><p><strong>Keywords</strong>: reservoir simulation, light tight oil, horizontal well, hydraulic fracturing, nite diferences method.</p>

scholarly journals Ball sealer tracking and seating of temporary plugging fracturing technology in the perforated casing of a horizontal well

2021 ◽  
pp. 014459872110204
Author(s):  
Wan Cheng ◽  
Chunhua Lu ◽  
Guanxiong Feng ◽  
Bo Xiao
Keyword(s):  
Critical Parameter ◽  
Fluid Velocity ◽  
Stable State ◽  
Horizontal Wells ◽  
Terminal Velocity ◽  
Injection Rate ◽  
Fracturing Fluid ◽  
Perforation Hole ◽  
Horizontal Wellbore ◽  
Tight Reservoirs

Multistaged temporary plugging fracturing in horizontal wells is an emerging technology to promote uniform fracture propagation in tight reservoirs by injecting ball sealers to plug higher-flux perforations. The seating mechanism and transportation of ball sealers remain poorly understood. In this paper, the sensitivities of the ball sealer density, casing injection rate and perforation angle to the seating behaviors are studied. In a vertical wellbore section, a ball sealer accelerates very fast at the beginning of the dropping and reaches a stable state within a few seconds. The terminal velocity of a non-buoyant ball is greater than the fluid velocity, while the terminal velocity of a buoyant ball is less than the fluid velocity. In the horizontal wellbore section, the terminal velocity of a non-buoyant or buoyant ball is less than the fracturing fluid flowing velocity. The ball sealer density is a more critical parameter than the casing injection rate when a ball sealer diverts to a perforation hole. The casing injection rate is a more critical parameter than the ball sealer density when a ball sealer seats on a perforation hole. A buoyant ball sealer associated with a high injection rate of fracturing fluid is highly recommended to improve the seating efficiency.

Application of Heat Treatment to Prevent Fracturing Fluid-Induced Formation Damage and Enhance Matrix Permeability in Shale Gas Reservoirs

2021 ◽  
Author(s):  
Mingjun Chen ◽  
Peisong Li ◽  
Yili Kang ◽  
Xinping Gao ◽  
Dongsheng Yang ◽  
...  
Keyword(s):  
Heat Treatment ◽  
Hydraulic Fracturing ◽  
Shale Gas ◽  
Gas Transport ◽  
Formation Damage ◽  
Transport Capacity ◽  
Fracturing Fluid ◽  
Gas Reservoir ◽  
Shale Gas Reservoir ◽  
The Matrix

Abstract The low flowback efficiency of fracturing fluid would severely increase water saturation in a near-fracture formation and limit gas transport capacity in the matrix of a shale gas reservoir. Formation heat treatment (FHT) is a state-of-the-art technology to prevent water blocking induced by fracturing fluid retention and accelerate gas desorption and diffusion in the matrix. A comprehensive understanding of its formation damage removal mechanisms and determination of production improvement is conducive to enhancing shale gas recovery. In this research, the FHT simulation experiment was launched to investigate the effect of FHT on gas transport capacity, the multi-field coupling model was established to determine the effective depth of FHT, and the numerical simulation model of the shale reservoir was established to analyze the feasibility of FHT. Experimental results show that the shale permeability and porosity were rising overall during the FHT, the L-1 permeability increased by 30- 40 times, the L-2 permeability increased by more than 100 times. The Langmuir pressure increased by 1.68 times and the Langmuir volume decreased by 26%, which means the methane desorption efficiency increased. Results of the simulation demonstrate that the FHT process can practically improve the effect of hydraulic fracturing and significantly increase the well production capacity. The stimulation mechanisms of the FHT include thermal stress cracking, organic matter structure changing, and aqueous phase removal. Furthermore, the special characteristics of the supercritical water such as the strong oxidation, can not be ignored, due to the FHT can assist the retained hydraulic fracturing fluid to reach the critical temperature and pressure of water and transform to the supercritical state. The FHT can not only alleviate the formation damage induced by the fracturing fluid, but also make good use of the retained fracturing fluid to enhance the permeability of a shale gas reservoir, which is an innovative method to dramatically enhance gas transport capacity in shale matrix.

Pressure Depletion Mapping Using Multi-Well DFITs and its Applications in Hydraulic Fracture Characterization and Permeability Estimation: Examples from Montney Formation

2021 ◽  
Author(s):  
Behjat Haghshenas ◽  
Farhad Qanbari
Keyword(s):  
Data Analysis ◽  
Surface Area ◽  
Reservoir Simulation ◽  
Production Data ◽  
Hydraulic Fractures ◽  
Fracture Geometry ◽  
Fracture Conductivity ◽  
Field Case ◽  
Pressure Depletion ◽  
Montney Formation

Abstract Recovery factor for multi-fractured horizontal wells (MFHWs) at development spacing in tight reservoirs is closely related to the effective horizontal and vertical extents of the hydraulic fractures. Direct measurement of pressure depletion away from the existing producers can be used to estimate the extent of the hydraulic fractures. Monitoring wells equipped with downhole gauges, DFITs from multiple new wells close to an existing (parent) well, and calculation of formation pressure from drilling data are among the methods used for pressure depletion mapping. This study focuses on acquisition of pressure depletion data using multi-well diagnostic fracture injection tests (DFITs), analysis of the results using reservoir simulation, and integration of the results with production data analysis of the parent well using rate-transient analysis (RTA) and reservoir simulation. In this method, DFITs are run on all the new wells close to an existing (parent) well and the data is analyzed to estimate reservoir pressure at each DFIT location. A combination of the DFIT results provides a map of pressure depletion around the existing well, while production data analysis of the parent well provides fracture conductivity and surface area and formation permeability. Furthermore, reservoir simulation is tuned such that it can also match the pressure depletion map by adjusting the system permeability and fracture geometry of the parent well. The workflow of this study was applied to two field case from Montney formation in Western Canadian Sedimentary Basin. In Field Case 1, DFIT results from nine new wells were used to map the pressure depletion away from the toe fracture of a parent well (four wells toeing toward the parent well and five wells in the same direction as the parent). RTA and reservoir simulation are used to analyze the production data of the parent well qualitatively and quantitatively. The reservoir model is then used to match the pressure depletion map and the production data of the parent well and the outputs of the model includes hydraulic fracture half-lengths on both sides of the parent well, formation permeability, fracture surface area and fracture conductivity. In Field Case 2, the production data from an existing well and DFIT result from a new well toeing toward the existing wells were incorporated into a reservoir simulation model. The model outputs include system permeability and fracture surface area. It is recommended to try the method for more cases in a specific reservoir area to get a statistical understanding of the system permeability and fracture geometry for different completion designs. This study provides a practical and cost-effective approach for pressure depletion mapping using multi-well DFITs and the analysis of the resulting data using reservoir simulation and RTA. The study also encourages the practitioners to take every opportunity to run DFITs and gather pressure data from as many well as possible with focus on child wells.

Sign in / Sign up

Export Citation Format

Share Document