Hydraulic Fractures in Core From Stimulated Reservoirs: Core Fracture Description of HFTS Slant Core, Midland Basin, West Texas

Gale, Julia; Elliott, Sara J.; Laubach, Stephen E.

doi:10.15530/urtec-2018-2902624

Cited by 99 publications

(40 citation statements)

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“…The upscaling method used in the present study sought to reduce the overall number of fractures to be modeled by upscaling the natural fracture widths and fracture permeabilities (strengths) for a dense natural fracture network. Original natural fracture apertures in the subsurface were assumed to be 5 mm (0.2 inches), which follows from core observations that kinematic apertures were estimated to have been more than 1 mm wide [57]. A combination of object-based and flow-based upscaling was developed for this study, with an in-depth discussion of this topic given in Appendix C. The proposed upscaling method was applied to produce field models for DRV around a single hydraulic fracture with a representative, upscaled natural fracture distribution of the HFTS.…”

Section: Field Models Using Data From the Hydraulic Fracture Test Sitmentioning

confidence: 99%

Impact on Drained Rock Volume (DRV) of Storativity and Enhanced Permeability in Naturally Fractured Reservoirs: Upscaled Field Case from Hydraulic Fracturing Test Site (HFTS), Wolfcamp Formation, Midland Basin, West Texas

Nandlal

Weijermars

2019

Energies

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Hydraulic fracturing for economic production from unconventional reservoirs is subject to many subsurface uncertainties. One such uncertainty is the impact of natural fractures in the vicinity of hydraulic fractures in the reservoir on flow and thus the actual drained rock volume (DRV). We delineate three fundamental processes by which natural fractures can impact flow. Two of these mechanisms are due to the possibility of natural fracture networks to possess (i) enhanced permeability and (ii) enhanced storativity. A systematic approach was used to model the effects of these two mechanisms on flow patterns and drained regions in the reservoir. A third mechanism by which natural fractures may impact reservoir flow is by the reactivation of natural fractures that become extensions of the hydraulic fracture network. The DRV for all three mechanisms can be modeled in flow simulations based on Complex Analysis Methods (CAM), which offer infinite resolution down to a micro-fracture scale, and is thus complementary to numerical simulation methods. In addition to synthetic models, reservoir and natural fracture data from the Hydraulic Fracturing Test Site (Wolfcamp Formation, Midland Basin) were used to determine the real-world impact of natural fractures on drainage patterns in the reservoir. The spatial location and variability in the DRV was more influenced by the natural fracture enhanced permeability than enhanced storativity (related to enhanced porosity). A Carman–Kozeny correlation was used to relate porosity and permeability in the natural fractures. Our study introduces a groundbreaking upscaling procedure for flows with a high number of natural fractures, by combining object-based and flow-based upscaling methods. A key insight is that channeling of flow through natural fractures left undrained areas in the matrix between the fractures. The flow models presented in this study can be implemented to make quick and informed decisions regarding where any undrained volume occurs, which can then be targeted for refracturing. With the method outlined in our study, one can determine the impact and influence of natural fracture sets on the actual drained volume and where the drainage is focused. The DRV analysis of naturally fractured reservoirs will help to better determine the optimum hydraulic fracture design and well spacing to achieve the most efficient recovery rates.

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Section: Field Models Using Data From the Hydraulic Fracture Test Sitmentioning

confidence: 99%

Impact on Drained Rock Volume (DRV) of Storativity and Enhanced Permeability in Naturally Fractured Reservoirs: Upscaled Field Case from Hydraulic Fracturing Test Site (HFTS), Wolfcamp Formation, Midland Basin, West Texas

Nandlal

Weijermars

2019

Energies

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“…This said, the simulations should be considered recognizing that there are many complexities that play a significant role in hydraulic fracture propagation and proppant placement that are not included in the models and there are number of simplifications in these models such as homogenous permeability, absence of significant natural fracture systems and poroelastic effects which can be tested in future studies. Additionally, recent core through hydraulic fracture studies in the Eagleford and Wolfcamp formations have highlighted a number of surprising results such as the propagations of multiple hydraulic fractures in close proximity and common occurrence of branching fractures (Gale et al 2018;Raterman et al 2017). This phenomena is not currently sufficiently understood to be incorporated into the models.…”

Section: Limitationsmentioning

confidence: 99%

Integrated Analysis of the Coupling Between Geomechanics and Operational Parameters to Optimize Hydraulic Fracture Propagation and Proppant Distribution

Singh

Zoback

et al. 2019

Day 2 Wed, February 06, 2019

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This paper presents an analysis of the interactions between stimulation design and two important geomechanical effects: the variation of least principal stress (S hmin) between lithological layers and the stress shadow effect that arises from simultaneously propagating adjacent hydraulic fractures. To demonstrate these interactions, hydraulic fracture propagation is modeled with a 5-layer geomechanical model representing an actual case study. The model consists of a profile of S hmin measurements made within, below and above the producing interval. The stress variations between layers leads to an overall upward fracture propagation and proppant largely above the producing interval. This is due to interactions between the pressure distribution within the fracture and the stress contrast in the multiple layers. A sensitivity study is done to investigate the complex 3-D couplings between geomechanical constraints and well completion design parameters such as landing zone, cluster spacing, perforation diameter, flow rate and proppant concentration. The simulation results demonstrate the importance of a well characterized stress stratigraphy for prediction of hydraulic fracture characteristics and optimization of operational parameters.

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“…137-55), groundwater transport (Gudmundsson, 2000), magma migration (Gudmundsson, 2011, pp. 525-52) and heat transfer (Pruess, 1983;Ghassemi & Kumar, 2007;Shaik et al 2011), and engineering operations such as outcomes of hydraulic fracture treatments (Gale et al 2018) and effective waste disposal (SD Ware et al unpub. data, 1996;Figueiredo et al 2016).…”

Section: Introductionmentioning

confidence: 99%

Natural fractures at depth in the Lower Cretaceous Kuqa Depression tight sandstones: identification and characteristics

Nian

Li²,

Hou³

et al. 2020

Geol. Mag.

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The Kuqa Depression in the northern Tarim Basin, NW China, is characterized by fault-controlled anticlines where natural fractures may influence production. Natural fractures in the Lower Cretaceous tight sandstones in the depression have been studied using seismic profiles, borehole images, cores and thin-sections. Results show that thrust faults, two types of opening-mode macrofractures and two types of microfractures are present. Thrust faults were generated during Cenozoic N–S-directed tectonic shortening and have hydraulically linked Jurassic source rocks and Cretaceous sandstones. Opening-mode fractures can be subdivided on the basis of sizes, filling characteristics and distribution patterns. Type 1 macrofractures are barren or mainly calcite-lined. They have straight traces with widths (opening displacements) that are of the order of magnitude of 10 μm, suggesting that their primary role is that of migration channels. Type 2 macrofractures are calcite-filled opening-mode fractures. They have an elliptical or tabular shape with sharply tapering tips. Transgranular microfractures are lens-shaped and open or filled mostly by calcite; maximum widths range between 0.01 mm and 0.1 mm. Intragranular microfractures are the most common microfracture type. They are filled by calcite, feldspar or quartz. The macrofractures and transgranular microfractures have regular distributions, while most intragranular microfractures are irregularly distributed owing to their inherited origin. The results imply that natural fractures in the tight sandstones were formed as tectonic, diagenetic and natural hydraulic origins. In situ stress and cementation analyses suggest that Type 1 macrofractures and their genesis-related microfractures have controlled the present flow system of the tight sandstones.

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Hydraulic Fractures in Core From Stimulated Reservoirs: Core Fracture Description of HFTS Slant Core, Midland Basin, West Texas

Cited by 99 publications

References 0 publications

Impact on Drained Rock Volume (DRV) of Storativity and Enhanced Permeability in Naturally Fractured Reservoirs: Upscaled Field Case from Hydraulic Fracturing Test Site (HFTS), Wolfcamp Formation, Midland Basin, West Texas

Impact on Drained Rock Volume (DRV) of Storativity and Enhanced Permeability in Naturally Fractured Reservoirs: Upscaled Field Case from Hydraulic Fracturing Test Site (HFTS), Wolfcamp Formation, Midland Basin, West Texas

Integrated Analysis of the Coupling Between Geomechanics and Operational Parameters to Optimize Hydraulic Fracture Propagation and Proppant Distribution

Natural fractures at depth in the Lower Cretaceous Kuqa Depression tight sandstones: identification and characteristics

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