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.

Unique Fall Off Signatures for Stage Fracture Characterization, Actual Field Cases

2021 ◽  
Author(s):  
Ahmed Farid Ibrahim ◽  
Mazher Ibrahim ◽  
Matt Sinkey ◽  
Thomas Johnston ◽  
Wes Johnson
Keyword(s):  
Flow Regime ◽  
Surface Area ◽  
Fiber Optics ◽  
In Situ Stress ◽  
Tensile Fracture ◽  
Finite Conductivity ◽  
Well Performance ◽  
Fracture Geometry ◽  
Fracture Conductivity ◽  
Diagnostic Plots

Abstract Multistage hydraulic fracturing is the common stimulation technique for shale formations. The treatment design, formation in-situ stress, and reservoir heterogeneity govern the fracture network propagation. Different techniques have been used to evaluate the fracture geometry and the completion efficiency including Chemical Tracers, Microseismic, Fiber Optics, and Production Logs. Most of these methods are post-fracture as well as time and cost intensive processes. The current study presents the use of fall-off data during and after stage fracturing to characterize producing surface area, permeability, and fracture conductivity. Shut-in data (15-30 minutes) was collected after each stage was completed. The fall-off data was processed first to remove the noise and water hammer effects. Log-Log derivative diagnostic plots were used to define the flow regime and the data were then matched with an analytical model to calculate producing surface area, permeability, and fracture conductivity. Diagnostic plots showed a unique signature of flow regimes. A long period of a spherical flow regime with negative half-slope was observed as an indication for limited entry flow either vertically or horizontally. A positive half-slope derivative represents a linear flow regime in an infinitely conductive tensile fracture. The quarter-slope derivative was observed in a bilinear flow regime that represents a finite conductivity fracture system. An extended radial flow regime was observed with zero slope derivative which represents a highly shear fractured network around the wellbore. For a long fall-off period, formation recharge may appear with a slope between unit and 1.5 slopes derivative, especially in over-pressured dry gas reservoirs. Analyzing fall-off data after stages are completed provides a free and real-time investigation method to estimate the fracture geometry and a measure of completion efficiency. Knowing the stage properties allows the reservoir engineer to build a simulation model to forecast the well performance and improve the well spacing.

Application Investigation of Light Proppant in Hydraulic Fracturing of Marcellus Shale

2021 ◽  
Author(s):  
Aymen Alhemdi ◽  
Ming Gu
Keyword(s):  
History Matching ◽  
Marcellus Shale ◽  
In Situ Stress ◽  
Production Performance ◽  
Well Performance ◽  
Fracture Permeability ◽  
Fracture Conductivity ◽  
Stimulated Reservoir Volume ◽  
Conductivity Distribution ◽  
Cumulative Production

Abstract Slickwater-sand fracturing design is widely employed in Marcellus shale. The slickwater- sand creates long skinny fractures and maximizes the stimulated reservoir volume (SRV). However, due to the fast settling of sand in the water, lots of upper and deeper areas are not sufficiently propped. Reducing sand size can lead to insufficient fracture conductivity. This study proposes to use three candidate ultra-lightweight proppants ULWPs to enhance the fractured well performance in unconventional reservoirs. In step 1, the current sand pumping design is input into an in-house P3D fracture propagation simulator to estimate the fracture geometry and proppant concentrations. Next, the distribution of proppant concentration converts to conductivity and then to fracture permeability. In the third step, the fracture permeability from the second step is input into a reservoir simulator to predict the cumulative production for history matching and calibration. In step 4, the three ULWPs are used to replace the sand in the frac simulator to get new frac geometry and conductivity distribution and then import them in reservoir model for production evaluation. Before this study, the three ULWPs have already been tested in the lab to obtain their long-term conductivities under in-situ stress conditions. The conductivity distribution and production performance are analyzed and investigated. The induced fracture size and location of the produced layer for the current target well play a fundamental effect on ultra-light proppant productivity. The average conductivity of ULWPs with mesh 40/70 is larger and symmetric along the fracture except for a few places. However, ULWPs with mesh 100 generates low average conductivity and create a peak conductivity in limited areas. The ULW-3 tends to have less cumulative production compared with the other ULWPs. For this Marcellus Shale study, the advantages of ultra-lightweight proppant are restricted and reduced because the upward fracture height growth is enormous. And with the presence of the hydrocarbon layer is at the bottom of the fracture, making a large proportion of ULWPs occupies areas that are not productive places. The current study provides a guidance for operators in Marcellus Shale to determine (1) If the ULWP can benefit the current shale well treated by sand, (2) what type of ULWP should be used, and (3) given a certain type of ULWP, what is the optimum pumping schedule and staging/perforating design to maximize the well productivity. The similar workflow can be expanded to evaluate the economic potential of different ULWPs in any other unconventional field.

Investigation of Rupture and Slip Mechanisms of Hydraulic Fractures in Multiple-Layered Formations

SPE Journal ◽  
2019 ◽  
Vol 24 (05) ◽  
pp. 2292-2307 ◽  
Author(s):  
Jizhou Tang ◽  
Kan Wu ◽  
Lihua Zuo ◽  
Lizhi Xiao ◽  
Sijie Sun ◽  
...  
Keyword(s):  
Fluid Flow ◽  
Hydraulic Fracture ◽  
Fracture Propagation ◽  
Propagation Model ◽  
Rock Deformation ◽  
Hydraulic Fractures ◽  
Fracture Geometry ◽  
Fracture Width ◽  
Hydraulic Fracture Propagation ◽  
Fracture Height

Summary Weak bedding planes (BPs) that exist in many tight oil formations and shale–gas formations might strongly affect fracture–height growth during hydraulic–fracturing treatment. Few of the hydraulic–fracture–propagation models developed for unconventional reservoirs are capable of quantitatively estimating the fracture–height containment or predicting the fracture geometry under the influence of multiple BPs. In this paper, we introduce a coupled 3D hydraulic–fracture–propagation model considering the effects of BPs. In this model, a fully 3D displacement–discontinuity method (3D DDM) is used to model the rock deformation. The advantage of this approach is that it addresses both the mechanical interaction between hydraulic fractures and weak BPs in 3D space and the physical mechanism of slippage along weak BPs. Fluid flow governed by a finite–difference methodology considers the flow in both vertical fractures and opening BPs. An iterative algorithm is used to couple fluid flow and rock deformation. Comparison between the developed model and the Perkins–Kern–Nordgren (PKN) model showed good agreement. I–shaped fracture geometry and crossing–shaped fracture geometry were analyzed in this paper. From numerical investigations, we found that BPs cannot be opened if the difference between overburden stress and minimum horizontal stress is large and only shear displacements exist along the BPs, which damage the planes and thus greatly amplify their hydraulic conductivity. Moreover, sensitivity studies investigate the impact on fracture propagation of parameters such as pumping rate (PR), fluid viscosity, and Young's modulus (YM). We investigated the fracture width near the junction between a vertical fracture and the BPs, the latter including the tensile opening of BPs and shear–displacement discontinuities (SDDs) along them. SDDs along BPs increase at the beginning and then decrease at a distance from the junction. The width near the junctions, the opening of BPs, and SDDs along the planes are directly proportional to PR. Because viscosity increases, the width at a junction increases as do the SDDs. YM greatly influences the opening of BPs at a junction and the SDDs along the BPs. This model estimates the fracture–width distribution and the SDDs along the BPs near junctions between the fracture tip and BPs and enables the assessment of the PR required to ensure that the fracture width at junctions and along intersected BPs is sufficient for proppant transport.

Comparison of Fractured-Horizontal-Well Performance in Tight Sand and Shale Reservoirs

2011 ◽  
Vol 14 (02) ◽  
pp. 248-259 ◽  
Author(s):  
E.. Ozkan ◽  
M Brown ◽  
R.. Raghavan ◽  
H.. Kazemi
Keyword(s):  
Hydraulic Fracture ◽  
Horizontal Well ◽  
Flow Model ◽  
Horizontal Wells ◽  
Natural Fracture ◽  
Well Performance ◽  
Fracture Conductivity ◽  
Fractured Horizontal Well ◽  
Shale Reservoirs ◽  
Fractured Horizontal Wells

Summary This paper presents a discussion of fractured-horizontal-well performance in millidarcy permeability (conventional) and micro- to nanodarcy permeability (unconventional) reservoirs. It provides interpretations of the reasons to fracture horizontal wells in both types of formations. The objective of the paper is to highlight the special productivity features of unconventional shale reservoirs. By using a trilinear-flow model, it is shown that the drainage volume of a multiple-fractured horizontal well in a shale reservoir is limited to the inner reservoir between the fractures. Unlike conventional reservoirs, high reservoir permeability and high hydraulic-fracture conductivity may not warrant favorable productivity in shale reservoirs. An efficient way to improve the productivity of ultratight shale formations is to increase the density of natural fractures. High natural-fracture conductivities may not necessarily contribute to productivity either. Decreasing hydraulic-fracture spacing increases the productivity of the well, but the incremental production gain for each additional hydraulic fracture decreases. The trilinear-flow model presented in this work and the information derived from it should help the design and performance prediction of multiple-fractured horizontal wells in shale reservoirs.

A New Method of Optimization Design of Hydraulic Fracture Parameters in Low Porosity and Fractured Gas Reservoir

2013 ◽  
Vol 380-384 ◽  
pp. 1656-1659
Author(s):  
Xiu Ling Han ◽  
Fu Jian Zhou ◽  
Chun Ming Xiong ◽  
Xiong Fei Liu ◽  
Xian You Yang
Keyword(s):  
Simulation Model ◽  
Hydraulic Fracture ◽  
Optimization Design ◽  
Outer Part ◽  
Gas Production ◽  
Natural Fracture ◽  
Fracture Permeability ◽  
Gas Reservoir ◽  
Fracture Conductivity ◽  
High Production Rate

A new composite reservoir simulation model of lower computation cost was used to optimize hydraulic fracture length and fracture conductivity during performing a hydraulic fracturing. The simulation model is divided into inner part and outer part. The inner part is dual-porosity and dual-permeability system, and the other is single porosity system. The research shows that the natural fracture permeability and density are the most influential parameters; a relative long fracture with high hydraulic fracture conductivity is required for a high production rate due to non-Darcy flow effects. A shorter primary fracture is better in a gas reservoir of high natural density. The composite model represents the flow characteristic more accurately and provides the optimal design of fracturing treatments to obtain an economic gas production.

Developing a Tool for 3D Reservoir Simulation of Hydraulically Fractured Wells

2007 ◽  
Vol 10 (01) ◽  
pp. 50-59 ◽  
Author(s):  
Josef R. Shaoul ◽  
Aron Behr ◽  
George Mtchedlishvili
Keyword(s):  
Simulation Model ◽  
Reservoir Simulation ◽  
Hydraulic Fracture ◽  
Fracture Plane ◽  
Tight Gas ◽  
Fracture Conductivity ◽  
Fracture Width ◽  
Fracture Simulation ◽  
Reservoir Simulator ◽  
Actual Fracture

Summary This paper describes the development and capabilities of a novel and unique tool that interfaces a hydraulic fracture model and a reservoir simulator. This new tool is another step in improving both the efficiency and consistency of connecting hydraulic fracture engineering and reservoir engineering. The typical way to model hydraulically fractured wells in 3D reservoir simulators is to approximate the fracture behavior with a modified skin or productivity index (PI). Neither method captures all the important physics of flow into and through the fracture. This becomes even more critical in cases of multiphase flow and multilayered reservoirs. Modeling the cleanup phase following hydraulic fracture treatments can be very important in tight gas reservoirs, and this also requires a more detailed simulation of the fracture. Realistic modeling of horizontal wells with multiple hydraulic fractures is another capability that is needed in the industry. This capability requires more than an approximate description of the fracture(s) in the reservoir-simulation model. To achieve all the capabilities mentioned above, a new tool was developed within a commercial lumped 3D fracture-simulation model. This new tool enables significantly more accurate prediction of post-fracture performance with a commercial reservoir simulator. The automatically generated reservoir simulator input files represent the geometry and hydraulic properties of the reservoir, the fracture, the damaged zone around the fracture, and the initial pressure and filtrate fluid distribution in the reservoir. Consistency with the fracture-simulation inputs and outputs is assured because the software automatically transfers the information. High-permeability gridblocks that capture the 2D variation of the fracture conductivity within the reservoir simulator input files represent the fracture. If the fracture width used in the reservoir model is larger than the actual fracture width, the permeability and porosity of the fracture blocks are reduced to maintain the transmissibility and porous volume of the actual fracture. Both proppant and acid fracturing are handled with this approach. To capture the changes in fracture conductivity over time as the bottomhole flowing pressure (BHFP) changes, the pressure-dependent behavior of the fracture is passed to the reservoir simulator. Local grid refinement (LGR) is used in the region of the wellbore and the fracture tip, as well as in the blocks adjacent to the fracture plane. Using small gridblocks adjacent to the fracture plane is needed for an adequate representation of the filtrate-invaded zone using the leakoff depth distribution provided by the fracture simulator. The reservoir simulator input can be created for multiphase fluid systems with multiple layers and different permeabilities. In addition, different capillary pressure and relative permeability saturation functions for each layer are allowed. Introduction Historically, there have been three basic approaches commonly used for predicting the production from hydraulically fractured wells. First, analytic solutions were most commonly used, based on an infinite-conductivity or, later, a finite-conductivity fracture with a given half-length. This approach also was extended to cover horizontal multiple fractured wells (Basquet et al. 1999). With the development of reservoir simulators, two other approaches were developed. For complicated multiwell, multilayer, multiphase simulations (i.e., full-field models), the fracture stimulation was usually approximated as a negative skin. This is the same as increasing the effective wellbore radius in the simulation model. An alternate approach, developed initially for tight gas applications, was to develop a special-purpose numeric reservoir simulator that could explicitly model the flow in the fracture and take into account the special properties of the proppant, such as the stress-dependent permeability or the possibility of non-Darcy flow. Such models typically were limited to a single-layer, single-phase (oil or gas) situation.

A Novel Analytical Fracture-Permeability Model Dependent on Both Fracture Width and Proppant-Pack Properties

SPE Journal ◽  
2020 ◽  
Vol 25 (06) ◽  
pp. 3031-3050
Author(s):  
Bailu Teng ◽  
Huazhou Li ◽  
Haisheng Yu
Keyword(s):  
A Priori ◽  
Brinkman Equation ◽  
Fracture Permeability ◽  
Permeability Model ◽  
Fracture Conductivity ◽  
Fracture Width ◽  
Unit Conversion Factor ◽  
Viscous Shear ◽  
Unit Conversion ◽  
Darcy Parameter

Summary For an empty fracture, the fracture permeability (kf) is mainly influenced by the effect of viscous shear from fracture walls and can be analytically estimated if the fracture width (wf) is known a priori (i.e., kf=β2wf2/12, where β2 is the unit-conversion factor). For an adequately propped fracture, the fracture permeability is mainly influenced by the proppant-pack properties and can be approximated with the proppant-pack permeability (kf=kp, where kp is proppant-pack permeability). It can be readily inferred that as the effect of viscous shear fades (or the proppant-pack effect becomes pronounced), there should be a regime within which both the viscous shear and the proppant-pack properties exert significant influences on the fracture permeability. However, the functional relationship between fracture permeability, viscous shear (or fracture width), and proppant-pack properties is still elusive. In this work, we propose a new fracture-permeability model to account for the influences of the proppant-pack permeability, proppant-pack porosity (ϕp), and fracture width on the fracture permeability. This new fracture-permeability model is derived from a modified Brinkman equation. The results calculated with the fracture-permeability model show that with different values of the Darcy parameter, the fluid flow can be divided into viscous-shear-dominated (VSD) regime, transition regime, and Darcy-flow-dominated (DFD) regime. If the Darcy parameter is sufficiently large, the effect of proppant-pack permeability on fracture permeability can be neglected and the fracture permeability can be calculated with the VSD fracture-permeability (FP) (VSD-FP) equation (i.e., kf=β2ϕpwf2/12). If the Darcy parameter is sufficiently small, the effect of viscous shear on fracture permeability can be neglected and the fracture permeability can be calculated with the DFD-FP equation (i.e., kf=kp). Both the VSD-FP and DFD-FP equations are special forms of the proposed fracture-permeability model. For the existing empirical/analytical fracture-conductivity models that neglect the effect of viscous shear, one can multiply these models by the coefficient of viscous shear to make these models capable of estimating the fracture conductivity with large values of Darcy parameter.

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