Modeling of geomechanics and fluid flow in fractured shale reservoirs with deformable multi-continuum matrix

2021 ◽  
Vol 196 ◽  
pp. 107576 ◽  
Author(s):  
Yunhu Lu ◽  
Shiming Wei ◽  
Yang Xia ◽  
Yan Jin
Keyword(s):  
Fluid Flow ◽  
Shale Reservoirs

Integration of Geoscience and Engineering Concepts to Account for Natural Fractures in Fluid Flow within Shale Reservoirs

2021 ◽  
Author(s):  
Clay Kurison ◽  
Ahmed M. Hakami ◽  
Sadi H. Kuleli
Keyword(s):  
Fluid Flow ◽  
Hydraulic Fractures ◽  
Natural Fractures ◽  
Eagle Ford ◽  
Fracture Geometry ◽  
Ongoing Research ◽  
Linear Flow ◽  
Matrix Permeability ◽  
The Subject ◽  
Shale Reservoirs

Abstract Unconventional shale reservoirs are characterized by low porosity and ultra-low permeability. Natural fractures are known to be present and considered a critical factor for the enhanced post-stimulation productivity. Accounting for natural fractures with existing techniques has not been widely adopted owing to their complexity or lack of validation. Ongoing research efforts are striving to understand how natural fractures can be accounted for and accurately modeled in fluid flow of the subject reservoirs. This study utilized Eagle Ford well data comprising reservoir properties, stimulation metrics, production, microseismicity and permeability measurements from a core plug. The methodology comprised use of production data to extract a linear flow regime parameter. This was coupled with fracture geometry, predicted from hydraulic fracture modeling and microseismicity, to estimate the system permeability. From interpreting microseismic events as slips on critically stressed natural fractures, explicit modeling incorporating a discrete fracture network (DFN) assumed activated natural fractures supplement conductive reservoir contact area. Thus, allowed the estimation of matrix permeability. For validation, the aforementioned was compared with core plug permeability measurements. Results from modeling of planar hydraulic fractures, with microseismicity as validation, predicted planar fracture geometry which when coupled with the linear flow parameter resulted in a system permeability. Incorporation of DFNs to account for activated natural fractures yielded matrix permeability in picodarcy range. A review of laboratory permeability measurements exhibited stress dependence with the value at the maximum experimental confining pressure of 4000 psi in the same range as the computed system permeability. However, the confining pressures used in the experiments were less than the in situ effective stress. Correction for representative stress yielded an ultra-low matrix permeability in the same range as the DFN-based picodarcy matrix permeability. Thus, supporting the adopted drainage architecture and often suggested role of natural fractures in shale reservoir fluid flow. This study presents a multi-discipline workflow to account for natural fractures, and contributes to understanding that will improve laboratory petrophysics and the overall reservoir characterization of the subject reservoirs. Given that the Eagle Ford is an analogue of emerging shales elsewhere, results from this study can be widely adopted.

Matrix permeability and flow-derived DFN constrain reactivated natural fracture rupture area and stress drop — Marcellus Shale microseismic example

2021 ◽  
Vol 40 (9) ◽  
pp. 667-676
Author(s):  
Clay Kurison ◽  
Huseyin S. Kuleli
Keyword(s):  
Fluid Flow ◽  
Pore Pressure ◽  
Stress Drop ◽  
Marcellus Shale ◽  
Linear Flow ◽  
Matrix Permeability ◽  
Rupture Area ◽  
Microseismic Events ◽  
Shale Reservoirs ◽  
Stress Drops

Microseismic events associated with shale reservoir hydraulic fracturing stimulation (HFS) are interpreted to be reactivations of ubiquitous natural fractures (NFs). Despite adoption of discrete fracture network (DFN) models, accounting for NFs in fluid flow within shale reservoirs has remained a challenge. For an explicit account of NFs, this study introduced the use of seismology-based relations linking seismic moment, moment magnitude, fault rupture area, and stress drop. Microseismic data from HFS monitoring of Marcellus Shale horizontal wells had been used to derive planar hydraulic fracture geometry and source properties. The former was integrated with associated well production data found to exhibit transient linear flow. Analytical solutions led to linear flow parameters (LFPs) and system permeability for scenarios depicting flow through infinite and finite conductivity hydraulic fractures. Published core plug permeability was stress-corrected for in-situ conditions to estimate average matrix permeability. For comparison, the burial and thermal history for the study area was used in 1D Darcy-based modeling of steady and episodic expulsion of petroleum to account for geologic timescale persistence of abnormal pore pressure. Both evaluations resulted in matrix permeability in the same picodarcy (pD) range. Coupled with LFPs, reactivated NF surface area for stochastic DFNs was estimated. Subsequently, the aforementioned seismology-based relations were used for determining average stress drops needed to estimate NF rupture area matching flow-based DFN surface areas. Stress drops, comparable to values for tectonic events, were excluded. One of the determined values matched stress drops for HFS operations in past and recent seismological studies. In addition, calculated changes in pore pressure matched estimates in the aforementioned studies. This study unlocked the full potential of microseismic data beyond extraction of planar geometry attributes and stimulated reservoir volume (SRV). Here, microseismic events were explicitly used in the quantitative account of NFs in fluid flow within shale reservoirs.

scholarly journals Critical Review of Fluid Flow Physics at Micro- to Nano‐scale Porous Media Applications in the Energy Sector

2018 ◽  
Vol 2018 ◽  
pp. 1-31 ◽  
Author(s):  
Harpreet Singh ◽  
Rho Shin Myong
Keyword(s):  
Porous Media ◽  
Fluid Flow ◽  
Liquid Flow ◽  
Gas Flow ◽  
Energy Sector ◽  
Hydrogen Gas ◽  
Flow Modeling ◽  
Shale Reservoirs ◽  
Media Applications ◽  
Fluid Flow Modeling

While there is a consensus in the literature that embracing nanodevices and nanomaterials helps in improving the efficiency and performance, the reason for the better performance is mostly subscribed to the nanosized material/structure of the system without sufficiently acknowledging the role of fluid flow mechanisms in these systems. This is evident from the literature review of fluid flow modeling in various energy-related applications, which reveals that the fundamental understanding of fluid transport at micro- and nanoscale is not adequately adapted in models. Incomplete or insufficient physics for the fluid flow can lead to untapped potential of these applications that can be used to increase their performance. This paper reviews the current state of research for the physics of gas and liquid flow at micro- and nanoscale and identified critical gaps to improve fluid flow modeling in four different applications related to the energy sector. The review for gas flow focuses on fundamentals of gas flow at rarefied conditions, the velocity slip, and temperature jump conditions. The review for liquid flow provides fundamental flow regimes of liquid flow, and liquid slip models as a function of key modeling parameters. The four porous media applications from energy sector considered in this review are (i) electrokinetic energy conversion devices, (ii) membrane-based water desalination through reverse osmosis, (iii) shale reservoirs, and (iv) hydrogen storage, respectively. Review of fluid flow modeling literature from these applications reveals that further improvements can be made by (i) modeling slip length as a function of key parameters, (ii) coupling the dependency of wettability and slip, (iii) using a reservoir-on-chip approach that can enable capturing the subcontinuum effects contributing to fluid flow in shale reservoirs, and (iv) including Knudsen diffusion and slip in the governing equations of hydrogen gas storage.

Role of Turbulent Flow in Generating Short Hydraulic Fractures with High Net Pressure in Slickwater Treatments

2015 ◽  
Author(s):  
Brandon C. Ames ◽  
Andrew P. Bunger
Keyword(s):  
Fluid Flow ◽  
Turbulent Flow ◽  
Flow Regime ◽  
Flow Model ◽  
High Rate ◽  
Hydraulic Fractures ◽  
Fracture Length ◽  
Wellbore Pressure ◽  
Net Pressure ◽  
Shale Reservoirs

Abstract This paper provides an argument for considering turbulent flow for hydraulic fracturing using slickwater in shale reservoirs. It shows that the tendency of models that assume laminar fluid flow to over-predict fracture length and under-predict net pressure can be corrected by instead recognizing that the flow regime is turbulent for high rate, water-driven hydraulic fractures. Firstly, we provide a rationale supporting the appropriateness of assuming turbulent flow. Then, using a Perkins-Kern-Nordgren (PKN) fracture model and parameters similar to slickwater treatments in shale reservoirs, we show that the laminar flow model overpredicts fracture length and underpredicts fracture width and net pressure, compared to the turbulent flow model. The result, if indeed a hydraulic fracture grows in the turbulent fluid flow regime, is that matching the length with the laminar model requires input of an unreasonably large leak-off coefficient, resulting in an exacerbation of the underprediction of the wellbore pressure. On the other hand, the turbulent model is shown to be able, in principle, to account for short, high pressure hydraulic fractures without resorting to inflating the leak-off coefficient or compromising the calibration of the model to the wellbore pressure.

Nonempirical Apparent Permeability of Shale

2014 ◽  
Vol 17 (03) ◽  
pp. 414-424 ◽  
Author(s):  
H.. Singh ◽  
F.. Javadpour ◽  
A.. Ettehadtavakkol ◽  
H.. Darabi
Keyword(s):  
Fluid Flow ◽  
Pore Size ◽  
Flow Rate ◽  
Gas Flow ◽  
Operating Conditions ◽  
Pore Geometry ◽  
Apparent Permeability ◽  
Knudsen Flow ◽  
Proposed Model ◽  
Shale Reservoirs

Summary Physics of fluid flow in shale reservoirs cannot be predicted from standard flow or mass-transfer models because of the presence of nanopores, ranging in size from one to hundreds of nanometers, in shales. Conventional continuum-flow equations, such as Darcy's law, greatly underestimate the fluid-flow rate when applied to nanopore-bearing shale reservoirs. As a result of the existence of nanopores in shales, the molecular mean free path becomes comparable with the characteristic geometric scale, and we hypothesize that under this condition, Knudsen diffusion, in addition to correction for the slip boundary condition, becomes the dominant mechanism. Recently, a few models have been developed that use various empirical parameters to account for these modifications (Javadpour 2009; Civan 2010; Darabi et al. 2012). This paper aims to provide a different approach to modeling apparent permeability in shale reservoirs. The proposed model is analytical, free of any empirical coefficients, and has been derived without invoking the assumption of slip flow at the pore wall. Our model of apparent permeability represented by a single analytical equation, depends only on pore size, pore geometry, temperature, gas properties, and average reservoir pressure. The proposed model is valid for Knudsen numbers less than unity and it stands up under the complete operating conditions of a shale reservoir. Our model reasonably predicts results as reported by other models. Finally, the model shows that pore-surface roughness and mineralogy have a negligible influence on gas-flow rate, whereas pore geometry and pore size play a significant role in the proportion of diffusion in total flow rate. Our study shows that a combination of Darcy flow and Knudsen flow—ignoring the Klinkenberg effect—can describe gas flow for a range of Knudsen flow applicable to a shale-gas system.

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