scholarly journals Effect of Stress-Sensitive Fracture Conductivity on Transient Pressure Behavior for a Multi-Well Pad With Multistage Fractures in a Naturally Fractured Tight Reservoir

2020 ◽  
Vol 8 ◽  
Author(s):  
Zhan Meng ◽  
Honglin Lu ◽  
Xiaohua Tan ◽  
Guangfeng Liu ◽  
Lianhe Wang ◽  
...  
Keyword(s):  
Hydraulic Fracture ◽  
Flow Behavior ◽  
Flow Regimes ◽  
Pressure Curve ◽  
Late Time ◽  
Transient Pressure ◽  
Transition Flow ◽  
Pressure Derivative ◽  
Fracture Conductivity ◽  
Fracture Length

This paper presents a semianalytical solution for evaluating transient pressure behavior of a multi-well pad with multistage fractures in a naturally fractured tight reservoir by considering the stress-sensitive effect imposed by both natural and hydraulic fractures. More specifically, the model pertaining to matrix/natural fractures is considered as a dual-porosity continuum, while its analytical flow model can be obtained by use of a slab-source function in the Laplace domain. The hydraulic fracture model is solved by discretizing each fracture into small segments to describe the flow behavior, while stress sensitivity in both the natural fracture (NF) subsystem and hydraulic fracture (HF) subsystem has been taken into account. To validate the newly developed semianalytical model, its solution has been obtained and compared with those of a commercial numerical simulator. By generating the type curves, there may exhibit eight flow regimes: pure wellbore storage, skin effect transition flow, linear flow regime within HFs, early radial flow, biradial flow, transition flow, pseudo-steady diffusion, and the late-time pseudo-radial flow. Furthermore, late-time flow regimes are found to be significantly distorted by the multi-well pressure interference. The smaller the well-rate ratio is, the more distorted the pressure and pressure derivative curves will be. In addition, well spacing and fracture length are found to dominate the flow behavior when multi-well pressure interference occurs. As the well spacing is decreased, the fracture length is increased, and thus occurrence of multi-well pressure interference is initiated earlier. Permeability moduli of NFs and HFs impose no impact on the multi-well pressure interference; however, it can distort flow regimes, leading to a severe distortion of pressure and pressure derivative curves. Similarly, the effect of HF permeability modulus on the flow in a hydraulic fracture, the minimum fracture conductivity is another key factor affecting the “hump” on the pressure curve. As the crossflow coefficient is increased, flow exchange between matrix and NFs is increased. With an increase in the storage ratio, flow exchange lasts longer and the second “dip” on the pressure curve becomes deeper.

scholarly journals Pressure Transient Performance for a Horizontal Well Intercepted by Multiple Reorientation Fractures in a Tight Reservoir

Energies ◽  
2019 ◽  
Vol 12 (22) ◽  
pp. 4232 ◽  
Author(s):  
Guoqiang Xing ◽  
Shuhong Wu ◽  
Jiahang Wang ◽  
Mingxian Wang ◽  
Baohua Wang ◽  
...  
Keyword(s):  
Horizontal Well ◽  
Flow Behavior ◽  
Flow Equation ◽  
Finite Conductivity ◽  
Transient Pressure ◽  
Pressure Derivative ◽  
Fracture Conductivity ◽  
Fracture Spacing ◽  
Economic Production ◽  
Tight Reservoir

A fractured horizontal well is an effective technology to obtain hydrocarbons from tight reservoirs. In this study, a new semi-analytical model for a horizontal well intercepted by multiple finite-conductivity reorientation fractures was developed in an anisotropic rectangular tight reservoir. Firstly, to establish the flow equation of the reorientation fracture, all reorientation fractures were discretized by combining the nodal analysis technique and the fracture-wing method. Secondly, through coupling the reservoir solution and reorientation fracture solution, a semi-analytical solution for multiple reorientation fractures along a horizontal well was derived in the Laplace domain, and its accuracy was also verified. Thirdly, typical flow regimes were identified on the transient-pressure curves. Finally, dimensionless pressure and pressure derivative curves were obtained to analyze the effect of key parameters on the flow behavior, including fracture angle, permeability anisotropy, fracture conductivity, fracture spacing, fracture number, and fracture configuration. Results show that, for an anisotropic rectangular tight reservoir, horizontal wells should be deployed parallel to the direction of principal permeability and fracture reorientation should be controlled to extend along the direction of minimum permeability. Meanwhile, the optimal fracture number should be considered for economic production and the fracture spacing should be optimized to reduce the flow interferences between reorientation fractures.

scholarly journals Production Decline Analysis and Hydraulic Fracture Network Interpretation Method for Shale Gas with Consideration of Fracturing Fluid Flowback Data

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-9
Author(s):  
Jianfeng Xiao ◽  
Xianzhe Ke ◽  
Hongxuan Wu
Keyword(s):  
Shale Gas ◽  
Hydraulic Fracture ◽  
Early Time ◽  
Fracture Network ◽  
Microseismic Monitoring ◽  
Monitoring Data ◽  
Fracturing Fluid ◽  
Fracture Conductivity ◽  
Fracture Length ◽  
Interpretation Method

After multistage hydraulic fracturing of shale gas reservoir, a complex fracture network is formed near the horizontal wellbore. In postfracturing flowback and early-time production period, gas and water two-phase flow usually occurs in the hydraulic fracture due to the retention of a large amount of fracturing fluid in the fracture. In order to accurately interpret the key parameters of hydraulic fracture network, it is necessary to establish a production decline analysis method considering fracturing fluid flowback in shale gas reservoirs. On this basis, an uncertain fracture network model was established by integrating geological, fracturing treatment, flowback, and early-time production data. By identifying typical flow-regimes and correcting the fracture network model with history matching, a set of production decline analysis and fracture network interpretation method with consideration of fracturing fluid flowback in shale gas reservoir was formed. Derived from the case analysis of a typical fractured horizontal well in shale gas reservoirs, the interpretation results show that the total length of hydraulic fractures is 4887.6 m, the average half-length of hydraulic fracture in each stage is 93.4 m, the average fracture conductivity is 69.7 mD·m, the stimulated reservoir volume (SRV) is 418 × 10 4   m 3 , and the permeability of SRV is 5.2 × 10 − 4   mD . Compared with the interpretation results from microseismic monitoring data, the effective hydraulic fracture length obtained by integrated fracture network interpretation method proposed in this paper is 59% of that obtained from the microseismic monitoring data, and the effective SRV is 83% of that from the microseismic monitoring data. The results show that the fracture length is smaller and the fracture conductivity is larger without considering the influence of fracturing fluid.

scholarly journals Revising Transient-Pressure Solution for Vertical Well Intersected by a Partially Penetrating Fracture with Non-Darcy Flow Effect

Geofluids ◽  
2020 ◽  
Vol 2020 ◽  
pp. 1-17
Author(s):  
Shuheng Cui ◽  
Jie Kong ◽  
Hongwei Yu ◽  
Cheng Chen ◽  
Junlei Wang
Keyword(s):  
Flow Regime ◽  
Flow Regimes ◽  
Pressure Response ◽  
Darcy Flow ◽  
Transient Pressure ◽  
Fracture Conductivity ◽  
Flow Effect ◽  
Vertical Fracture ◽  
Dimensional Flow ◽  
Penetration Ratio

The principle purpose of this work is to formulate an accurate mathematical model to evaluate the transient pressure behavior of a well intercepted by a partially penetrating vertical fracture (PPVF) with non-Darcy flow effect. Fracture conductivity is taken into account by coupling the three-dimensional flow in reservoir and the two-dimensional flow within fracture; the Barree-Conway model is incorporated into the model to analyze non-Darcy flow behavior in fracture, which leads to the nonlinearity of the governing equations. A high-effective iterative algorithm using a combined technique of fracture-panel discretization and dimension transform is developed to render the nonlinear equations amenable to analytical linear treatment. On the basis of the solutions, the pressure response and its derivative type curves were generated to identify the evolution of flow regimes with time. Furthermore, the influences of fracture conductivity, penetration ratio, and non-Darcy characteristic parameters on pressure response are investigated. The results show that PPVF exhibits five typical flow regimes, and analytical solutions for each flow regime are similar to that for a fully penetrating vertical fracture (FPVF) that can be correlated with the penetration ratio and apparent conductivity. The non-Darcy flow effect is found to have more significant effect on the low and moderate conductivity, especially in early-stage flow regimes. When the penetration ratio is smaller than 0.5, the pressure behavior exhibit a more remarkable variation with penetration ratio. This study provides a better insight into understanding the influence of non-Darcy flow on flow regime identification.

scholarly journals Transient pressure analysis for vertical wells with spherical power-law flow

2012 ◽  
Vol 5 (1) ◽  
pp. 19-36 ◽  
Author(s):  
Freddy Humberto Escobar ◽  
Javier-Andrés Martínez ◽  
Luis-Fernando Bonilla
Keyword(s):  
Power Law ◽  
Oil Recovery ◽  
Flow Behavior ◽  
Direct Synthesis ◽  
Well Test ◽  
Transient Pressure ◽  
Pressure Derivative ◽  
Flow Behavior Index ◽  
Partial Completion ◽  
Transient Pressure Analysis

Heavy oil is considered nowadays as one of the unconventional reservoirs of main interest in the oil industry. Some of them display non-Newtonian pseudoplastic behavior which mathematical modeling differs from the conventional case and, therefore, the flow regimes display some particular behaviors.Fracturing fluids, foams, some fluids for Enhanced Oil Recovery (EOR) and drilling muds can also fall into this category. The spherical/hemispherical flow mainly caused by partial completion/penetration deserves a particular treatment for pseudoplastic flow. A single research for this case was found in the literature to introduce only its mathematical model. The pressure and pressure derivative behavior of spherical/hemispherical flow behavior of a slightly compressible, non-Newtonian power-law fluid (pseudoplastic) is studied in this work and conventional and Tiab’s Direct Synthesis (TDS) methodologies are extended for well test interpretation purposes. For pseudoplastic spherical/ hemispherical flow, the slope of the pressure derivative is no longer -½, besides it changes with the value of flow behavior index n, which indicates that the interpretation of pressure data for the dealt systems through the use of traditional methods should not be accurate. New Equations are introduced to estimate spherical/ hemispherical permeability and spherical/hemispherical skin factor for the systems under consideration. The Equations were successfully verified by its application to synthetic cases.

A Semianalytical Model for Production Simulation From Nonplanar Hydraulic-Fracture Geometry in Tight Oil Reservoirs

SPE Journal ◽  
2016 ◽  
Vol 21 (03) ◽  
pp. 1028-1040 ◽  
Author(s):  
Wei Yu ◽  
Kan Wu ◽  
Kamy Sepehrnoori
Keyword(s):  
Hydraulic Fracture ◽  
Transient Flow ◽  
Flow Behavior ◽  
Tight Oil ◽  
Well Performance ◽  
Fracture Permeability ◽  
Fracture Geometry ◽  
Fracture Conductivity ◽  
Fracture Width ◽  
Stress Dependent

Summary Two key technologies such as horizontal drilling and hydraulic fracturing have led to the economic production of unconventional resources such as shale gas and tight oil. In reality, a nonplanar hydraulic-fracture geometry with varying fracture width and fracture permeability is created during the hydraulic-fracturing process. However, it is challenging to simulate well performance from the nonplanar fracture geometry. For the sake of simplicity, the nonplanar fracture geometry is often represented by ideal planar fracture geometry with constant fracture width, which one can easily handle analytically, semianalytically, and numerically. However, such ideal fracture geometry is inadequate to capture the physics of the transient flow behavior of the nonplanar fracture geometry. Although significant efforts were made in recent years to numerically model well performance from the complex fracture geometry, these approaches are still challenging to model the nonplanar fracture geometry with varying width because of a large considerable fracture-gridding issues and an expensive computation cost. In addition, the effect of nonplanar fracture geometry on well productivity and transient flow behavior was not reported in the literature. Hence, a model to handle the nonplanar fracture geometry by considering varying fracture width and fracture permeability is still lacking in the petroleum industry. Zhou et al. (2014) proposed a semianalytical model to handle the complex fracture geometry with constant fracture width. However, the semianalytical model did not consider the effects of stress-dependent fracture conductivity and the nonplanar fracture geometry as well as planar fracture geometry with varying fracture width along the fracture. In this work, we extended the semianalytical model to simulate production from the nonplanar fracture geometry as well as planar fracture geometry with varying width. In addition, the effect of stress-dependent fracture conductivity was implemented in the model. We verified the semianalytical model against a numerical reservoir simulator for single planar fracture with constant width. We performed two case studies. The first case contains a comparison of two planar fractures, one with constant fracture width and another with varying fracture width. In the second study, we compared two fractures with different fracture geometries such as planar fracture geometry and nonplanar fracture geometry, which were generated from the fracture-propagation model. In addition, transient flow regimes were investigated on the basis of a log-log graph of the dimensionless pressure drop and pressure-drop derivative vs. the dimensionless time. This work can provide critical insights into understanding the well performance from tight oil reservoirs with the nonplanar hydraulic-fracture geometry.

scholarly journals Transient Pressure Analysis of Inclined Well in Continuous Triple-Porosity Reservoirs With Dual-Permeability Behavior

2020 ◽  
Vol 8 ◽  
Author(s):  
Sheng-Zhi Qi ◽  
Xiao-Hua Tan ◽  
Xiao-Ping Li ◽  
Zhan Meng ◽  
You-Jie Xu ◽  
...  
Keyword(s):  
Radial Flow ◽  
Integral Transform ◽  
Flow Regimes ◽  
Response Characteristic ◽  
Flow Coefficient ◽  
Fracture System ◽  
Inversion Algorithm ◽  
Transient Pressure ◽  
Pressure Derivative ◽  
Pressure Transient

Inclined wells has recently been adopted to develop fractured-vuggy carbonate hydrocarbon reservoirs (FVCHRs) composed by matrix, fracture and vug system. Therefore, it is significant for us to describe pressure transient of inclined well for FVCHRs. In this paper, it is assumed that vug and fracture system connect with wellbore, and inter-porosity flow from vug to fracture system appears. Therefore, the pressure transient responses model of inclined well with triple-porosity dual-permeability behavior was built. The model is solved by employing Laplace integral transform and finite cosine Fourier transform. Real-domain solution of the model is obtained by Stehfest inversion algorithm. On the basis model of the published paper, the solution of the simplified model of this paper was validated with horizontal and vertical well of FVCHRs with triple-porosity dual-permeability behavior, and results reach a good agreement. Type curve, according to pressure derivative curve characteristic, can be divided into eight flow regimes, which includes wellbore storage, skin reflect, early vertical radial flow, top and bottom boundary reflection, linear flow, inter-porosity flow from vug to fracture, inter-porosity from matrix to vug and fracture and pseudo-radial flow regimes. The influence of some vital parameters (inclination angle, inter-porosity flow coefficient, well length and permeability ratio etc.) on dimensionless pressure and its derivative curves are discussed in detail. The presented model can be used to understand pressure transient response characteristic of inclined wells in FVCHRs with dual-permeability behavior.

A Semianalytical Solution of a Vertical Fractured Well With Varying Conductivity Under Non-Darcy-Flow Condition

SPE Journal ◽  
2015 ◽  
Vol 20 (05) ◽  
pp. 1028-1040 ◽  
Author(s):  
Luo Wanjing ◽  
Tang Changfu
Keyword(s):  
Flow Condition ◽  
Effective Conductivity ◽  
Early Time ◽  
Flow Equation ◽  
Darcy Flow ◽  
Pressure Curve ◽  
Well Test ◽  
Transient Pressure ◽  
Fracture Conductivity ◽  
Fractured Well

Summary Fracture distributions (simple or complex fractures), fracture-conductivity heterogeneity (uniform or varying conductivity along the fracture), and flow regimes inside the fracture (Darcy or non-Darcy flow) are the three main issues that have been widely investigated for transient-pressure analysis of vertical fracture systems. In this study, we focus on the latter two issues by proposing a semianalytical solution to discuss the transient-pressure behaviors of a varying-conductivity fracture under non-Darcy-flow condition. First, a general fracture-flow equation is established for the uniform-/varying-conductivity fracture under Darcy/non-Darcy flow. Second, for the case of a varying-conductivity fracture, a dimension transformation and an unequal-length-discretization model are proposed to obtain the pressure solution. Then, the transient-pressure response for the case of non-Darcy flow in the fracture can be also obtained by use of an iterative procedure in each timestep in the Laplace domain. It is shown that results from our solutions agree very well with those reported in the literature (Guppy et al. 1982; Poe et al. 1992). Third, the transient-pressure behaviors of the varying-conductivity fracture under Darcy- and non-Darcy-flow condition are discussed in detail. Results show that non-Darcy flow in the fracture mainly reduces the effective conductivity and the transient-pressure curve follows the curve of an equivalently constant conductivity except for the case of extremely small conductivities. The pressure behaviors of varying-conductivity fractures depend on the value of average conductivity, the distribution of conductivity along the fracture, and the maximum-minimum-conductivity ratio. The presence of the varying conductivity not only affects the effective conductivity in the early and late times, but also changes the shape of the pressure curve, especially for the high-conductivity fracture in the early time. It is very difficult to accurately estimate the fracture parameters by well test for most of the cases of varying conductivities under non-Darcy flow in the fracture.

Impact of the Cluster Spacing on Hydraulic Fracture Conductivity and Productivity of a Marcellus Shale Horizontal Well

2021 ◽  
Author(s):  
Mohamed El Sgher ◽  
Kashy Aminian ◽  
Ameri Samuel
Keyword(s):  
Hydraulic Fracture ◽  
Marcellus Shale ◽  
Technical Information ◽  
Gas Production ◽  
Production Performance ◽  
Valuable Insight ◽  
Fracture Conductivity ◽  
Fracture Properties ◽  
Gas Recovery ◽  
The Impact

Abstract The objective of this study was to investigate the impact of the hydraulic fracturing treatment design, including cluster spacing and fracturing fluid volume on the hydraulic fracture properties and consequently, the productivity of a horizontal Marcellus Shale well with multi-stage fractures. The availability of a significant amount of advanced technical information from the Marcellus Shale Energy and Environment Laboratory (MSEEL) provided an opportunity to perform an integrated analysis to gain valuable insight into optimizing fracturing treatment and the gas recovery from Marcellus shale. The available technical information from a horizontal well at MSEEL includes well logs, image logs (both vertical and lateral), diagnostic fracture injection test (DFIT), fracturing treatment data, microseismic recording during the fracturing treatment, production logging data, and production data. The analysis of core data, image logs, and DFIT provided the necessary data for accurate prediction of the hydraulic fracture properties and confirmed the presence and distribution of natural fractures (fissures) in the formation. Furthermore, the results of the microseismic interpretation were utilized to adjust the stress conditions in the adjacent layers. The predicted hydraulic fracture properties were then imported into a reservoir simulation model, developed based on the Marcellus Shale properties, to predict the production performance of the well. Marcellus Shale properties, including porosity, permeability, adsorption characteristics, were obtained from the measurements on the core plugs and the well log data. The Quanta Geo borehole image log from the lateral section of the well was utilized to estimate the fissure distribution s in the shale. The measured and published data were utilized to develop the geomechnical factors to account for the hydraulic fracture conductivity and the formation (matrix and fissure) permeability impairments caused by the reservoir pressure depletion during the production. Stress shadowing and the geomechanical factors were found to play major roles in production performance. Their inclusion in the reservoir model provided a close agreement with the actual production performance of the well. The impact of stress shadowing is significant for Marcellus shale because of the low in-situ stress contrast between the pay zone and the adjacent zones. Stress shadowing appears to have a significant impact on hydraulic fracture properties and as result on the production during the early stages. The geomechanical factors, caused by the net stress changes have a more significant impact on the production during later stages. The cumulative gas production was found to increase as the cluster spacing was decreased (larger number of clusters). At the same time, the stress shadowing caused by the closer cluster spacing resulted in a lower fracture conductivity which in turn diminished the increase in gas production. However, the total fracture volume has more of an impact than the fracture conductivity on gas recovery. The analysis provided valuable insight for optimizing the cluster spacing and the gas recovery from Marcellus shale.

Low-Cost Measurement of Hydraulic Fracture Dimensions Using Pressure Data in Treatment and Observation Wells – A Workflow for Every Well

2021 ◽  
Author(s):  
A. Kirby Nicholson ◽  
Robert C. Bachman ◽  
R. Yvonne Scherz ◽  
Robert V. Hawkes
Keyword(s):  
Hydraulic Fracturing ◽  
Real Time ◽  
Hydraulic Fracture ◽  
Full Scale ◽  
Pressure Data ◽  
Observation Well ◽  
High Quality ◽  
Fracture Length ◽  
Geometry Model ◽  
Observation Wells

Abstract Pressure and stage volume are the least expensive and most readily available data for diagnostic analysis of hydraulic fracturing operations. Case history data from the Midland Basin is used to demonstrate how high-quality, time-synchronized pressure measurements at a treatment and an offsetting shut-in producing well can provide the necessary input to calculate fracture geometries at both wells and estimate perforation cluster efficiency at the treatment well. No special wellbore monitoring equipment is required. In summary, the methods outlined in this paper quantifies fracture geometries as compared to the more general observations of Daneshy (2020) and Haustveit et al. (2020). Pressures collected in Diagnostic Fracture Injection Tests (DFITs), select toe-stage full-scale fracture treatments, and offset observation wells are used to demonstrate a simple workflow. The pressure data combined with Volume to First Response (Vfr) at the observation well is used to create a geometry model of fracture length, width, and height estimates at the treatment well as illustrated in Figure 1. The producing fracture length of the observation well is also determined. Pressure Transient Analysis (PTA) techniques, a Perkins-Kern-Nordgren (PKN) fracture propagation model and offset well Fracture Driven Interaction (FDI) pressures are used to quantify hydraulic fracture dimensions. The PTA-derived Farfield Fracture Extension Pressure, FFEP, concept was introduced in Nicholson et al. (2019) and is summarized in Appendix B of this paper. FFEP replaces Instantaneous Shut-In Pressure, ISIP, for use in net pressure calculations. FFEP is determined and utilized in both DFITs and full-scale fracture inter-stage fall-off data. The use of the Primary Pressure Derivative (PPD) to accurately identify FFEP simplifies and speeds up the analysis, allowing for real time treatment decisions. This new technique is called Rapid-PTA. Additionally, the plotted shape and gradient of the observation-well pressure response can identify whether FDI's are hydraulic or poroelastic before a fracture stage is completed and may be used to change stage volume on the fly. Figure 1Fracture Geometry Model with FDI Pressure Matching Case studies are presented showing the full workflow required to generate the fracture geometry model. The component inputs for the model are presented including a toe-stage DFIT, inter-stage pressure fall-off, and the FDI pressure build-up. We discuss how to optimize these hydraulic fractures in hindsight (look-back) and what might have been done in real time during the completion operations given this workflow and field-ready advanced data-handling capability. Hydraulic fracturing operations can be optimized in real time using new Rapid-PTA techniques for high quality pressure data collected on treating and observation wells. This process opens the door for more advanced geometry modeling and for rapid design changes to save costs and improve well productivity and ultimate recovery.

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