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This document provides technical background for StageOpt. This tool helps to better understand fluid and proppant distribution between perforations and clusters within a fracturing stage. Limited entry technique is often used to achieve uniform fluid distribution between clusters. This, however, does not automatically guarantee uniform proppant distribution. In view of this observation, StageOpt allows users to overcome this obstacle and to better design perforation design by focusing on both fluid and proppant distribution between clusters. The algorithm in StageOpt is based primarily on the paper Dontsov (2023), but it also incorporates practically important features, such as the effect of stress shadow from previous stage, perforation erosion, and other phenomena. In this write-up, flow distribution between perforations is described first, and the effects of perforation friction, near-wellbore pressure drop, as well as perforation break down and stress shadow are included. Then, proppant distribution between perforations is discussed as a function of perforation orientation. Finally, perforation erosion is added to the model. The erosion changes perforation diameter as a function of several parameters, including the flow rate through the perforation as well as the amount of proppant that flows through it. The change of perforation size in turn changes magnitude of perforation friction, which then changes the distribution of slurry, that consequently changes proppant flow distribution. Such a coupled system often leads to complex results that are hard to deduce without systematic physical modeling, which is exactly what StageOpt provides.

To maximize value from an EGS system, engineers need to optimize flow rate, well spacing, and well configuration. Numerical simulations yield interesting and surprising results regarding the effect of coupled processes on long term thermal performance. Thermoelastic fracture opening and propagation can have a significant negative effect on the uniformity of flow. On the other hand, interactions between fracture opening and buoyancy driven fluid circulation cause downward fracture propagation during long-term circulation that greatly improves the thermal longevity of the system. Passive inflow control design can significantly mitigate the negative effect of thermoelastic fracture opening on flow uniformity, while maintaining the positive effects of thermoelastic fracture opening and propagation on flow rate and thermal longevity. Overall, simulations suggest that an EGS doublet with 8000 ft laterals at 475' F, using inflow control at the production well, could sustain electricity generation rates of 8 to 10 MWe for more than 30 years. Without inflow control, 6 to 8 MWe over 30 years is possible; however, there is greater risk of uncontrolled thermal breakthrough., Comment: Originally posted as a ResFrac Blog post on July 24 2023

This is the most exciting time in my lifetime for geothermal. There are many, many innovative things happening. To name a few, promising new approaches to Enhanced Geothermal Systems, geothermal projects in sedimentary and lower enthalpy formations, new approaches for geothermal exploration, lithium extraction from produced brines, geothermal energy storage, integrations with CO2 storage and capture, and new technologies for producing energy from hot water that is coproduced with oil and gas. However, this post is about a concept about which I remain skeptical, deep closed-loop heat exchangers. These designs are sometimes called Advanced Geothermal Systems, AGS. To clarify, this blog post discusses the use of closed-loop heat exchangers in deep geothermal wells, 1000s of ft deep. This is a different application than the use of closed-loop heat exchangers in very shallow wells, 10s of ft deep, for ground source heat pumps. The fundamental challenge is that closed-loop heat exchanger designs rely on conduction, and sometimes free convection, to bring energy into the well. These processes are inherently much slower than forced convection, which is what drives energy transport into a conventional geothermal well. Slower energy transport means less revenue, and therefore, worse economics. In the past few years, there have been many creative new ideas for using closed-loop heat exchangers for geothermal energy production. Usually, these proposals recognize the challenge facing closed-loop, but introduce a wrinkle intended to overcome the problem. Despite these efforts, there are still daunting technical hurdles to widespread deployment of deep closed-loop geothermal. In this post, I go through some of the proposed designs and discuss key issues., Comment: This article was originally posted as a ResFrac Blog post

Interference tests are used in shale reservoirs to evaluate the strength of connectivity between wells. The results inform engineering decisions about well spacing. In this paper, we propose a new procedure for interpreting interference tests. We fit the initial interference response with the solution to the 1D diffusivity equation at an offset observation point. It is advantageous to use the initial interference response, rather than the subsequent trend, because it is less affected by nonlinearities, time-varying boundary conditions, and uncertainties about flow geometry and regime. From the curve fit, we estimate the hydraulic diffusivity and conductivity of the fractures connecting the wells. For engineering purposes, it would be useful to quantify the impact of interference on well production. Thus, we seek a relationship between the degree of production interference (DPI) and an appropriate dimensionless quantity that can be derived from the estimate of fracture conductivity. Using simulations run under a wide range of conditions, we find that the classical definition for dimensionless fracture conductivity does not achieve a consistent prediction of DPI. This occurs because the dimensionless fracture conductivity is derived assuming radial flow geometry, but the dominant flow geometry during shale production is linear. We also find that the CPG (Chow Pressure Group) metric does not yield consistently accurate predictions of DPI. As an alternative, we derive a dimensionless quantity similar to the classical dimensionless fracture conductivity, but derived for linear, flow geometry. Using this approach, we calculate a dimensionless interference length that collapses all cases onto a single curve that predicts DPI as a function of fracture conductivity, well spacing, and formation properties. We conclude by applying the new method to field cases from the Anadarko and Delaware Basins.

This document is designed to give a new ResFrac user the tools that they need to succeed. It describes what ResFrac does and how to use it. We cover much more than just button pressing. Using ResFrac successfully requires high-level engineering skills: how to design and execute a modeling workflow, how to think critically about problems, and how to communicate the results.

This post provides commentary on recent four papers on diagnostic fracture injection testing (DFIT). The first paper uses in-situ deformation measurements to directly observe fractures opening and closing during fracture injection-falloff tests (Guglielmi et al., 2022). The second compares various stress measurement techniques in a series of fracture/injection tests from the Bedretto project (Broker and Ma, 2022). The third statistically reviews results from applying the interpretation procedure from McClure et al. (2019) to 62 DFITs across nine different shale plays (McClure et al., 2022). The fourth is an op-ed written in JPT (Journal of Petroleum Technology) by an advocate of the tangent method for estimating DFIT closure stress (Buijs, 2021; 2022).

This document describes the functioning of the automated history matching and optimization workflow implemented with the ResFrac hydraulic fracturing and reservoir simulator. The purpose of the automated history matching and optimization workflow is enable automated calibration of simulator models to observed data and application to forward optimization. The automated workflow works by solving a formal mathematical optimization problem to minimize misfit with observations from any point in the lifecycle of a hydraulically fractured reservoir, or to maximize a quantity of interest associated such a reservoir, such as net present value. Objective function evaluations in the optimization problem consist of runs of the ResFrac simulator, which is a physics-based model of hydraulic fracturing and reservoir phenomena. The workflow employs a proxy model to improve computational speed and applies experimental design and Bayesian sampling techniques to generate points with which to train the proxy model. This document also provides an overview of the software infrastructure developed to support the automated workflow., Comment: 10 pages, one figure

In a uniform stress field, a tensile hydraulic fracture will favor propagation in the plane formed by the maximum (most compressive) and intermediate principal stresses. For the propagation of hydraulic fractures in non-uniform stress fields, especially those where the principal stress directions change spatially, things become much more complex, are less well understood, and therefore are more difficult to predict. Such is often the case when a hydraulic fracture is initiated from a borehole drilled in the direction of the minimum principal stress. This is a well-known problem that has been the subject of several numerical and experimental studies. The purpose of this paper is to offer new insights from a series of hydraulic fracture tests conducted in sub-horizontal boreholes drilled in the Sanford Underground Research Facility. This project, called the Enhanced Geothermal Systems (EGS) Collab project, has developed a test bed at a depth of approximately 1478 meters underground consisting of sub-horizontal injection, production, and monitoring wells. This paper presents stimulation test data, and supporting geologic/geophysical characterization data. The test data are compared to previous numerical and experimental studies to determine how well this new experimental data compares with previous modeling, laboratory, and field tests.

In recent years, there has been discussion in the literature regarding methods of estimating the magnitude of the minimum principal stress from subsurface fracture injection tests, commonly called Diagnostic Fracture Injection Tests (DFITs). McClure et al. (2016) used modeling and mathematical analysis to propose that changes should be made to common interpretation techniques. Subsequently, Craig et al. (2017) attempted to refute those findings using field and laboratory observations. This discussion paper reviews the interpretations from Craig et al. (2017) and concludes that their conclusions are unsupported by the data presented.

ResFrac is a combined hydraulic fracturing, reservoir, and hydraulic fracturing simulator. It describes multiphase fluid flow (black oil or compositional), proppant transport, transport of non-Newtonian fluid additives, and thermal transport. It also includes stress shadowing from fracture propagation and porothermoelastic responses from pressure change in the matrix. It uses constitutive equations that smoothly transition between equations for flow through an open crack to flow through a closed crack (with or without proppant). This document provides a detailed technical description of the code, along with validation simulations to confirm numerical accuracy.

I propose the 1D Subgrid Method for calculating fluid exchange between fractures and matrix with a non-conforming mesh. The method is demonstrated on linear and radial flow problems. The method has negligible computational cost and is accurate at all levels of mesh refinement.

Bed load transport is the movement of particles along the top of a bed through rolling, saltation, and suspension created by turbulent lift above the bed surface. In recent years, there has been a resurgence of interest in the idea that bed load transport is significant for proppant transport during hydraulic fracturing. However, scaling arguments suggest that bed load transport is only dominant in the laboratory and is negligible at the field scale. I review laboratory experiments that have been used to develop concepts of bed load transport in hydraulic fracturing. I also review the scaling arguments and laboratory results that have been used to argue that viscous drag, not bed load transport, is dominant at the field scale. I compare literature correlations for fluvial sediment transport and for pipeline slurry transport with published laboratory data on proppant transport in slot flow. The comparisons indicate that fluvial transport correlations are suitable for predicting the rate of sediment erosion due to flow of proppant-free fluid over a bed. The pipeline slurry correlations are suitable for predicting the ability of proppant that is already in suspension to flow in bed transport without settling, but only if the aspect ratio of the flowing region in the slot is close to unity. This can occur at the laboratory scale, but not in the field. The comparison indicates that at low rates of proppant flow, the equilibrium bed height in a laboratory proppant transport experiment can be predicted from pipeline slurry correlations. However, as the volumetric flow rate and the aspect ratio of the flowing region in the slot increase, the applicability of the pipeline slurry correlations breaks down. Laboratory experiments using higher volumetric flow rate indicate that bed load transport rates are too low to be significant at the field scale, even if the flow velocity is very high.

We develop a statistical method for identifying induced seismicity from large datasets and apply the method to decades of wastewater disposal and seismicity data in California and Oklahoma. The method is robust against a variety of potential pitfalls. The study regions are divided into gridblocks. We use a longitudinal study design, seeking associations between seismicity and wastewater injection along time-series within each gridblock. The longitudinal design helps control for non-random application of wastewater injection. We define a statistical model that is flexible enough to describe the seismicity observations, which have temporal correlation and high kurtosis. In each gridblock, we find the maximum likelihood estimate for a model parameter that relates induced seismicity hazard to total volume of wastewater injected each year. To assess significance, we compute likelihood ratio test statistics in each gridblock and each state, California and Oklahoma. Resampling is used to empirically derive reference distributions used to estimate p-values from the likelihood ratio statistics. In Oklahoma, the analysis finds with extremely high confidence that seismicity associated with wastewater disposal (or other related activities, such as reservoir depletion) has occurred. In California, the analysis finds that seismicity associated with wastewater disposal has probably occurred, but the result is not strong enough to be conclusive. We identify areas where temporal association between wastewater disposal and seismicity is apparent. Our method could be applied to other datasets, extended to identify risk factors that increase induced seismic hazard, or modified to test alternative statistical models for natural and induced seismicity., Comment: Contact Mark McClure (mark.w.mccl@gmail.com) for access to the raw data, the code used to perform the analysis, or the Supporting Material