Energies

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26 pages, 5772 KiB

Open AccessArticle

A Reference Thermal-Hydrologic-Mechanical Native State Model of the Utah FORGE Enhanced Geothermal Site

by Robert Podgorney, Aleta Finnila, Stuart Simmons and John McLennan

Energies 2021, 14(16), 4758; https://doi.org/10.3390/en14164758 - 5 Aug 2021

Cited by 14 | Viewed by 2969

The Frontier Observatory for Research in Geothermal Energy (FORGE) site is a multi-year initiative funded by the U.S. Department of Energy for enhanced geothermal system research and development. The site is located on the margin of the Great Basin near the town of [...] Read more.

The Frontier Observatory for Research in Geothermal Energy (FORGE) site is a multi-year initiative funded by the U.S. Department of Energy for enhanced geothermal system research and development. The site is located on the margin of the Great Basin near the town of Milford, Utah. Work has so far resulted in the compilation of a large amount of subsurface data which have been used to improve the geologic understanding of the site. Based on the compiled data, a three-dimensional geologic model describing the structure, composition, permeability, and temperature at the Utah FORGE site was developed. A deep exploratory well (Well 58-32) and numerous tests conducted therein provide information on reservoir rock type, temperature, stress, permeability, etc. Modeling and simulation will play a critical role at the site and need to be considered as a general scientific discovery tool to elucidate the behavior of enhanced geothermal systems and as a deterministic (or stochastic) tool to plan and predict specific activities. This paper will present the development of a reference native state model and the calibration of the model to the reservoir pressure, temperature, and stress measured in Well 58-32. Full article

(This article belongs to the Special Issue Modelings and Analysis of Hydraulic Fracturing in Reservoirs)

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22 pages, 10659 KiB

Open AccessArticle

Stress Reversals near Hydraulically Fractured Wells Explained with Linear Superposition Method (LSM)

by Ruud Weijermars and Jihoon Wang

Energies 2021, 14(11), 3256; https://doi.org/10.3390/en14113256 - 2 Jun 2021

Cited by 8 | Viewed by 2924

Abstract

Prior studies have noted that the principal stress orientations near the hydraulic fractures of well systems used for energy extraction may wander over time. Typically, the minimum and maximum principal stresses—in the horizontal map view—swap their respective initial directions, due to (1) fracture [...] Read more.

Prior studies have noted that the principal stress orientations near the hydraulic fractures of well systems used for energy extraction may wander over time. Typically, the minimum and maximum principal stresses—in the horizontal map view—swap their respective initial directions, due to (1) fracture treatment interventions, and (2) pressure depletion resulting from production. The present analysis shows with stress trajectory visualizations, using a recently developed linear superposition method (LSM), that at least two generations of stress reversals around hydraulic fractures occur. The first generation occurs during the fracture treatment; the second occurs immediately after the onset of so-called flow-back. During each of these stress swaps in the vicinity of the hydraulic fractures, reservoir directions that were previously in compression subsequently exhibit extension, and directions previously stretching subsequently exhibit shortening. The pressure change in the hydraulic fractures—from over-pressured to under-pressured (only held open by proppant packs)—caused the neutral points that separate domains with different stress states to migrate from locations transverse to the fracture to locations beyond the fracture tips. Understanding such detailed geo-mechanical dynamics, related to the pressure evolution in energy reservoirs, is extremely important for improving both the fracture treatment and the well operation, as future hydrocarbon and geothermal energy extraction projects emerge. Full article

(This article belongs to the Special Issue Modelings and Analysis of Hydraulic Fracturing in Reservoirs)

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12 pages, 3697 KiB

Open AccessArticle

Hydraulic Fracturing Simulations with Real-Time Evolution of Physical Parameters

by Qiuping Qin, Qingfeng Xue, Zizhuo Ma, Yikang Zheng and Hongyu Zhai

Energies 2021, 14(6), 1678; https://doi.org/10.3390/en14061678 - 17 Mar 2021

Cited by 1 | Viewed by 1986

Abstract

During hydraulic fracturing, expansion of internal micro-fractures deforms the rock to different extents. Numerical studies typically assume fixed parameters; however, in the field site, parameters are likely to vary. Error accumulation underlies deviation of simulation results from actual data. In this study, it [...] Read more.

During hydraulic fracturing, expansion of internal micro-fractures deforms the rock to different extents. Numerical studies typically assume fixed parameters; however, in the field site, parameters are likely to vary. Error accumulation underlies deviation of simulation results from actual data. In this study, it was found that the mean velocity of an in-lab active source obtained from the hydraulic fracturing experiment decreased. To explain the effect of physical parameter (velocity) on numerical simulation results, we performed numerical simulations based on the extended finite element method (XFEM) of indoor hydraulic fracturing considering the velocity variation. The simulation results considering the change of the physical parameter (velocity) of the rock sample reflect the rock damage evolution more exactly. Consequently, the real-time evolution of physical parameters during hydraulic fracturing should be considered in numerical simulations. Rock damage evolution can be better captured using the offered modification of physical parameters. The present work provides theoretical guidance for hydraulic fracturing simulations to some extent. Full article

(This article belongs to the Special Issue Modelings and Analysis of Hydraulic Fracturing in Reservoirs)

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30 pages, 12572 KiB

Open AccessArticle

Coupled Thermo–Hydro–Mechanical–Seismic Modeling of EGS Collab Experiment 1

by Jianrong Lu and Ahmad Ghassemi

Energies 2021, 14(2), 446; https://doi.org/10.3390/en14020446 - 15 Jan 2021

Cited by 7 | Viewed by 2539

Abstract

An important technical issue in the enhanced geothermal system (EGS) is the process of fracture shear and dilation, fracture network propagation and induced seismicity. EGS development requires an ability to reliably predict the fracture network’s permeability evolution. Laboratory and field studies such as [...] Read more.

An important technical issue in the enhanced geothermal system (EGS) is the process of fracture shear and dilation, fracture network propagation and induced seismicity. EGS development requires an ability to reliably predict the fracture network’s permeability evolution. Laboratory and field studies such as EGS Collab and Utah FORGE, and modeling simulations provide valuable lessons for successful commercial EGS design. In this work we present a modeling analysis of EGS Collab Testbed Experiment 1 (May 24, Stim-II ≅ 164 Notch) and interpret the stimulation results in relation to the creation of a fracture network. In doing so, we use an improved 3D discrete fracture network model coupled with a 3D thermo-poroelastic finite element model (FEM) which can consider fracture network evolution and induced seismicity. A dual-scale semi-deterministic fracture network is generated by combining data from image logs, foliations/micro-fractures, and core. The natural fracture properties (e.g., length and asperity) follow a stochastic distribution. The fracture network propagation under injection is considered by an ultrafast analytical approach. This coupled method allows for multiple seismic events to occur on and around a natural fracture. The uncertainties of seismic event clouds are better constrained using the energy conservation law. Numerical simulations show that the simulated fracture pressure profiles reasonably follow the trend observed in the field test. The simulations support the concept that a natural fracture was propagated from the injection well connecting with the production well via intersection and coalescence with other natural fractures consistent with plausible flow paths observed on the field. The fracture propagation profiles from numerical modeling generally match the field observation. The distribution of simulated micro-seismicity have good agreement with the field-observed data. Full article

(This article belongs to the Special Issue Modelings and Analysis of Hydraulic Fracturing in Reservoirs)

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22 pages, 6413 KiB

Open AccessArticle

Hydraulic Fracture Propagation in a Poro-Elastic Medium with Time-Dependent Injection Schedule Using the Time-Stepped Linear Superposition Method (TLSM)

by Tri Pham and Ruud Weijermars

Energies 2020, 13(24), 6474; https://doi.org/10.3390/en13246474 - 8 Dec 2020

Cited by 8 | Viewed by 2568

Abstract

The Time-Stepped Linear Superposition Method (TLSM) has been used previously to model and analyze the propagation of multiple competitive hydraulic fractures with constant internal pressure loads. This paper extends the TLSM methodology, by including a time-dependent injection schedule using pressure data from a [...] Read more.

The Time-Stepped Linear Superposition Method (TLSM) has been used previously to model and analyze the propagation of multiple competitive hydraulic fractures with constant internal pressure loads. This paper extends the TLSM methodology, by including a time-dependent injection schedule using pressure data from a typical diagnostic fracture injection test (DFIT). In addition, the effect of poro-elasticity in reservoir rocks is accounted for in the TLSM models presented here. The propagation of multiple hydraulic fractures using TLSM-based codes preserves infinite resolution by side-stepping grid refinement. First, the TLSM methodology is briefly outlined, together with the modifications required to account for variable time-dependent pressure and poro-elasticity in reservoir rock. Next, real world DFIT data are used in TLSM to model the propagation of multiple dynamic fractures and study the effect of time-dependent pressure and poro-elasticity on the development of hydraulic fracture networks. TLSM-based codes can quantify and visualize the effects of time-dependent pressure, and poro-elasticity can be effectively analyzed, using DFIT data, supported by dynamic visualizations of the changes in spatial stress concentrations during the fracture propagation process. The results from this study may help develop fracture treatment solutions with improved control of the fracture network created while avoiding the occurrence of fracture hits. Full article

(This article belongs to the Special Issue Modelings and Analysis of Hydraulic Fracturing in Reservoirs)

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29 pages, 9607 KiB

Open AccessArticle

Experimental and Numerical Study on Proppant Transport in a Complex Fracture System

by Zhaopeng Zhang, Shicheng Zhang, Xinfang Ma, Tiankui Guo, Wenzhe Zhang and Yushi Zou

Energies 2020, 13(23), 6290; https://doi.org/10.3390/en13236290 - 28 Nov 2020

Cited by 20 | Viewed by 2257

Abstract

Slickwater fracturing can create complex fracture networks in shale. A uniform proppant distribution in the network is preferred. However, proppant transport mechanism in the fracture network is still uncertain, which restricts the optimization of sand addition schemes. In this study, slot flow experiments [...] Read more.

Slickwater fracturing can create complex fracture networks in shale. A uniform proppant distribution in the network is preferred. However, proppant transport mechanism in the fracture network is still uncertain, which restricts the optimization of sand addition schemes. In this study, slot flow experiments are conducted to analyze the proppant placement in the complex fracture system. Dense discrete phase method is used to track the particle trajectories to study the transport mechanism into the branch. The effects of the pumping rate, sand ratio, sand size, and branch angle and location are discussed in detail. Results demonstrate that: (1) under a low pumping rate or coarse proppant conditions, the dune development in the branch depends on the dune geometry in the primary fracture, and a high proportion of sand can transport into the branch; (2) using a high pumping rate or fine proppants is beneficial to the uniform placement in the fracture system; (3) sand ratio dominates the proppant placement in the branch and passing-intersection fraction of a primary fracture; (4) more proppants may settle in the near-inlet and large-angle branch due to the size limit. Decreasing the pumping rate can contribute to a uniform proppant distribution in the secondary fracture. This study provides some guidance for the optimization of proppant addition scheme in the slickwater fracturing in unconventional resources. Full article

(This article belongs to the Special Issue Modelings and Analysis of Hydraulic Fracturing in Reservoirs)

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20 pages, 7517 KiB

Open AccessArticle

In-Situ Stress Measurements at the Utah Frontier Observatory for Research in Geothermal Energy (FORGE) Site

by Pengju Xing, John McLennan and Joseph Moore

Energies 2020, 13(21), 5842; https://doi.org/10.3390/en13215842 - 9 Nov 2020

Cited by 31 | Viewed by 3610

Abstract

A scientific injection campaign was conducted at the Utah Frontier Observatory for Research in Geothermal Energy (FORGE) site in 2017 and 2019. The testing included pump-in/shut-in, pump-in/flowback, and step rate tests. Various methods have been employed to interpret the in-situ stress from the [...] Read more.

A scientific injection campaign was conducted at the Utah Frontier Observatory for Research in Geothermal Energy (FORGE) site in 2017 and 2019. The testing included pump-in/shut-in, pump-in/flowback, and step rate tests. Various methods have been employed to interpret the in-situ stress from the test dataset. This study focuses on methods to interpret the minimum in-situ stress from step rate, pump-in/extended shut-in tests data obtained during the stimulation of two zones in Well 58-32. This well was drilled in low-permeability granitoid. A temperature of 199 °C was recorded at the well’s total depth of 2297 m relative to the rotary Kelly bushing (RKB). The lower zone (Zone 1) consisted of 46 m of the openhole at the toe of the well. Fractures in the upper zone (Zone 2) were stimulated between 2123–2126 m measured depths (MD) behind the casing. The closure stress gradient variation depended on the depth and the injection chronology. The closure stress was found to increase with the pumping rate/volume. This stress variation could indicate that poroelastic effects (“back stress”) and the presence of adjacent natural fractures may play an important role in the interpretation of fracture closure stress. Further, progressively increasing local total stresses may, consequently, have practical applications when moderate volumes of fluid are injected in a naturally fractured or high-temperature reservoir. The alternative techniques that use pump-in/flowback tests and temperature signatures provide a valuable perspective view of the in-situ stress measurements. Full article

(This article belongs to the Special Issue Modelings and Analysis of Hydraulic Fracturing in Reservoirs)

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35 pages, 15828 KiB

Open AccessFeature PaperArticle

Three-Dimensional Geomechanical Modeling and Analysis of Refracturing and “Frac-Hits” in Unconventional Reservoirs

by Shahla Feizi Masouleh, Dharmendra Kumar and Ahmad Ghassemi

Energies 2020, 13(20), 5352; https://doi.org/10.3390/en13205352 - 14 Oct 2020

Cited by 20 | Viewed by 3348

Abstract

Field experience has demonstrated that infill well fractures tend to propagate towards the primary well, resulting in well-to-well interference, or so-called “frac-hits”. Frac-hits are a major concern in horizontal well refracturing because they adversely affect the productivity of both wells. This paper provides [...] Read more.

Field experience has demonstrated that infill well fractures tend to propagate towards the primary well, resulting in well-to-well interference, or so-called “frac-hits”. Frac-hits are a major concern in horizontal well refracturing because they adversely affect the productivity of both wells. This paper provides a 3D geomechanical study of the problem for the first time in order to better understand frac-hits in horizontal well refracturing and its mitigating solutions. To our knowledge, this is the only refracturing study focused on fracture mechanics and within the context of coupled proroelasticity using a single model. The modeling is based on the fully coupled 3D model, GeoFrac-3D, which is capable of simulating multistage fracturing of multiple horizontal wells. The model couples pore pressure to stresses, and makes it possible to create dynamic models of fracture propagation. The modeling results show that production from production well fractures leads to a nonuniform reduction of the reservoir pore pressure around the production well and in between fractures, leading to an anisotropic decrease of the total stress, potentially resulting in stress reorientation and/or reversal. The decrease in the total stress components in the vicinity of the production fractures creates an attraction zone for infill well hydraulic fractures. The infill well fractures tend to grow asymmetrically towards the lower stress zone. The risk of frac-hits and the impact on the “parent” and “infill” well production vary according to the reservoir stress regime, in situ stress anisotropy, and production time. By optimizing well and fracture spacing, fracturing fluid viscosity, and the timing of refracturing job, frac-hit problems can be minimized. The simulation results demonstrate that the risks of frac-hits can be potentially mitigated by repressurization of the production well fractures before fracturing the infill well. Full article

(This article belongs to the Special Issue Modelings and Analysis of Hydraulic Fracturing in Reservoirs)

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