Stimulated Rock Volume Research Articles

Advances in hydraulic fracture characterization via borehole microseismic and strain monitoring

We analyze the impact and challenges associated with microseismic monitoring in the development of unconventional reservoirs. We detail advanced methods that address some of these challenges and discuss emerging data analysis and acquisition technologies such as those provided by fiber-optic monitoring. During the development of unconventional resources, it is important to understand the stimulated rock volume obtained from the hydraulic fracturing treatment. Microseismic monitoring is one of the sources of information for estimating stimulated rock volume in which accurate hypocenter calculations provide the horizontal and vertical fracture geometry and extent. We developed hypocenter waveform-based relocation and collapsing techniques and demonstrated these on synthetic and field data to obtain an enhanced description of the fracture geometry. We further provide the initial analysis of a recently acquired data set composed of multiple monitoring wells instrumented with geophones and fiber optics operating simultaneously. Microseismic events recorded by the multiwell dual geophone/fiber setup show meaningful signal-to-noise ratio to enable a joint interpretation. Additional strain and temperature data provided by dynamic fiber-optic measurements extend the interpretation capabilities of the hydraulic fracturing phenomenon while providing an avenue for advanced research on fracture characterization.

Multi‐Scale Geomechanical Modelling of Unconventional Shale Gas: The Implication on Assisting Geophysics–Geology–Engineering Integration

In the development of unconventional shale play, simulation of the performance for wells needs to incorporate sufficient complexity in geology to take fully into account the variabilities in petrophysical and geomechanical properties. These parameters controlling the effective stimulated rock volume (eSRV) represent the heterogeneity and strong‐layering nature of unconventional reservoirs: high inter‐bedding anisotropy, flow behaviours and pre‐existing geological disconnections (bedding planes, faults, fissuring, natural fractures). This realistic simulation model includes direct information and interpreted understanding from data sources in a wide range of resolutions and scales and is finally coupled with hydraulic fracturing and reservoir depletion modelling in terms of mechanical. The multi‐scale geomechanical model incorporates processed seismic interpreted data (10 m scale), petrophysical core data (cm scale), routine scalar logs (m scale) and resistivity borehole image (0.25 cm scale). The vital role the multi‐scale geomechanical model plays during the entire workflow is to underpin the disconnection among actual well logs, conventional seismic interpretation and geological complexity by calculating and predicting field scale geomechanical parameters and in situ stresses distribution. Multiple research investigations and case studies on such integration include data acquisition and processing methods, modelling upscaling methodologies and data diagnostical techniques from multidisciplinary perspectives. Although these works show great progress in improved understanding of the spatial and temporal distribution of formation reservoir and geomechanical distribution, uncertainty remains as local stress variations and mechanical‐flow properties between layers are impossible to capture.

Case Study: Gas Lift-Plunger Lift Combination Creates Full Life Cycle Production Solution

From the Wolfcamp and Bone Spring in the Permian Basin to the Niobrara and Codell in the Denver-Julesburg Basin, lateral lengths of 10,000 ft or greater are becoming the norm in tight-oil resource plays (Rassenfoss 2022; Addison, 2021; S&P 2021). From a production standpoint, longer laterals equate to greater stimulated rock volume per wellbore. That means higher flow rates, but it can also introduce more dynamic behavior and steeper production declines. The extended-well trajectories are often accompanied by high dogleg severities, high gas/oil ratios (GORs), and sand and solids production (Whitfield 2023; S&P 2021). Efficiently accommodating all of these factors while cost-effectively managing natural declines over time can be a challenge for any single artificial lift method. However, the combination of gas lift and plunger lift technology gives operators a flexible option to optimize production beginning with initial peak flow rates at the start of production and extending all the way through to depletion. This “full life cycle” approach encompasses three distinct phases that collectively span the entire slope of the tight-oil well decline curve: - Gas lift in early to mid-life (from first production to ±300 B/D) - Plunger-assisted gas lift (PAGL) in the mid- to late-life plateau (from ±300 to ±100 B/D) - Plunger lift in late life (from ±100 B/D to last oil) An artificial lift approach leveraging gas lift, PAGL, and plunger lift at different points along the production timeline aggregately brings the key advantages of all three to bear in horizontal tight-oil wells, including - Gas lift’s ability to mimic natural reservoir flow, lifting fluids to surface by reducing the flowing tubing pressure and creating differential pressure between the reservoir and wellbore. Gas lift handles an array of production rates (up to 2,000-plus B/D) and well characteristics—including high GORs and solid content—and can adapt to rapidly changing conditions during early well life. - PAGL’s ability to increase reservoir drawdown, stabilize production, and reduce system surging as production diminishes to the point where gas lift starts to become inefficient in the mid-life phase. - Plunger lift’s ability to use pressure buildup below the plunger to carry accumulated fluids to surface at rates as low as a few B/D, requiring no external power source to surface the plunger. The plunger creates a “swabbing effect” as it passes through the tubing that helps draw fluids from perforated intervals while keeping tubing swept of paraffin, scale, asphaltene, sand, etc.

Estimation of fracture half-length with fast Gaussian pressure transient and RTA methods: Wolfcamp shale formation case study

Accurate estimation of fracture half-lengths in shale gas and oil reservoirs is critical for optimizing stimulation design, evaluating production potential, monitoring reservoir performance, and making informed economic decisions. Assessing the dimensions of hydraulic fractures and the quality of well completions in shale gas and oil reservoirs typically involves techniques such as chemical tracers, microseismic fiber optics, and production logs, which can be time-consuming and costly. This study demonstrates an alternative approach to estimate fracture half-lengths using the Gaussian pressure transient (GPT) Method, which has recently emerged as a novel technique for quantifying pressure depletion around single wells, multiple wells, and hydraulic fractures. The GPT method is compared to the well-established rate transient analysis (RTA) method to evaluate its effectiveness in estimating fracture parameters. The study used production data from 11 wells at the hydraulic fracture test site 1 in the Midland Basin of West Texas from Upper and Middle Wolfcamp (WC) formations. The data included flow rates and pressure readings, and the fracture half-lengths of the 11 wells were individually estimated by matching the production data to historical records. The GPT method can calculate the fracture half-length from daily production data, given a certain formation permeability. Independently, the traditional RTA method was applied to separately estimate the fracture half-length. The results of the two methods (GPT and RTA) are within an acceptable, small error margin for all 5 of the Middle WC wells studied, and for 5 of the 6 Upper WC wells. The slight deviation in the case of the Upper WC well is due to the different production control and a longer time for the well to reach constant bottomhole pressure. The estimated stimulated surface area for the Middle and Upper WC wells was correlated to the injected proppant volume and the total fluid production. Applying RTA and GPT methods to the historic production data improves the fracture diagnostics accuracy by reducing the uncertainty in the estimation of fracture dimensions, for given formation permeability values of the stimulated rock volume.

Post-frac evaluation of deep shale gas wells based on a new geology-engineering integrated workflow

The development of shale gas reservoir is now shifting focus from mid-shallow reservoirs to deep reservoirs in the southern Sichuan Basin. For such reservoirs with high temperature, pressure, and stress difference, along with multiple folds, faults, and complex fracture networks, improving the stimulation performance of shale gas wells is the ultimate challenge. This study presents a new geology-engineering integrated workflow coupling hydraulic fracture simulation and reservoir simulation together with artificial intelligence to perform post-frac evaluations. A two-step calibration workflow of fracturing and reservoir simulations generated an ensemble of representative models, and a confidence interval of estimated ultimate recovery forecast were obtained. Four deep shale gas wells with two different completion versions (version 1.0 and version 2.0) in Y101 study area were evaluated. Some of the key learnings include: (1) the ratio of stimulated rock volume and drained rock volume is quantified to 8%–25% for the four characterized deep shale gas wells; (2) the version 2.0 completion design is able to stimulate the near-well region more effectively than version 1.0; (3) this novel geology-engineering integrated workflow performed the first reliable, robust and quantifiable post-frac evaluation in the southern Sichuan Basin deep shale reservoir.

Scaling Microseismic Cloud Shape During Hydraulic Stimulation Using In Situ Stress and Permeability

AbstractForecasting microseismic cloud shape as a proxy of stimulated rock volume may improve the design of an energy extraction system. The microseismic cloud created during hydraulic stimulation of geothermal reservoirs is known empirically to extend in the general direction of the maximum principal stress. However, this empirical relationship is often inconsistent with reported results, and the cloud growth process remains poorly understood. This study investigates microseismic cloud growth using data obtained from a hydraulic stimulation project in Basel, Switzerland, and explores its correlation with measured in situ stress. We applied principal component analysis to a time series of microseismicity for macroscopic characterization of microseismic cloud growth in two‐ and three‐dimensional space. The microseismic cloud, in addition to extending in the general direction of maximum principal stress, expanded in the direction of intermediate principal stress. The orientation of the least microseismic cloud growth was stable and almost identical to the minimum principal stress direction. Further, microseismic cloud shape ratios showed good agreement when compared with in situ stress magnitude ratios. The permeability tensor estimated from microseismicity also provided a good correlation in terms of direction and magnitude with the microseismic cloud growth. We show that in situ stress plays a dominant role by controlling the permeability of each existing fracture in the reservoir fracture system. Consequently, microseismic cloud growth can be scaled by in situ stress as a first‐order approximation if there is sufficient variation in the orientation of existing faults.

Integrated flow model for evaluating maximum fracture spacing in horizontal wells

Multi-stage fractured horizontal wells are extensively used in unconventional reservoir; hence, optimizing the spacing between these hydraulic fractures is essential. Fracture spacing is an important factor that influences the production efficiency and costs. In this study, maximum fracture spacing in low-permeability liquid reservoirs is studied by building an integrated flow model incorporating key petrophysical characteristics. First, a kinematic equation for non-Darcy seepage flow is constructed using the fractal theory to consider the non-homogeneous characteristics of the stimulated rock volume area (StRV) and its stress sensitivity. Then, the kinematic equation is used to build an integrated mathematical model of one-dimensional steady-state flow within the StRV to analytically determine the pressure distribution in StRV. The resultant pressure distribution is utilized to propose an optimal value for the maximum fracture spacing. Finally, the effects of fractal index, initial matrix permeability, depletion, and stress sensitivity coefficient on the limit disturbed distance and pressure distribution are studied. This study not only enriches the fundamental theory of nonlinear seepage flow mechanics but also provides some technical guidance for choosing appropriate fracture spacing in horizontal wells.

Metre-scale damage zone characterization usingS-coda waves from active ultrasonic transmission measurements in the STIMTEC project, URL Reiche Zeche, Germany

SUMMARYStudies of controlled hydraulic stimulation experiments with active and passive seismic monitoring conducted in Underground Research Laboratories (URLs) benefit from specific knowledge of hydraulic parameters, close by microseismic monitoring revealing structural details of the rock mass, and detailed evolution of seismicity in response to injection operations. Microseismic monitoring is commonly used to characterize a stimulated reservoir volume, for example, in terms of damage evolution of the rock mass. Since seismic attenuation is affected by damage of the rock volume, active seismic sources covering sizes from the centimetre to decimetre scale may help us to investigate space–time varying attenuation properties in a reservoir. This may allow us to monitor damage evolution of the stimulated rock volume in more detail, also since active seismic sources produce stronger signals leading to a broader frequency range that can be analysed compared to passive seismic signals. Within the STIMTEC project in the URL Reiche Zeche (URL-RZ) in Freiberg (Germany), more than 300 active Ultrasonic Transmission (UT) measurements were performed before and after hydraulic stimulations in two boreholes in the targeted rock volume, an anisotropic metamorphic gneiss. The signal-frequency content ranges between 1 and 60 kHz. Assuming scattering attenuation to dominate over intrinsic attenuation, we here apply the single isotropic scattering model. S-coda waves of 88 spatially representative UT measurements are used to estimate the coda quality factor (QC). We obtain stable QC estimates for centre frequencies of octave-width frequency bands between 3 and 21 kHz. We group neighbouring UT measurements to stabilize the observations and form eight UT groups in total, covering different depth intervals in three boreholes and four different time periods to investigate scattering attenuation changes in a spatiotemporal manner. Our final mean QC ($\overline {{Q}_C} $) estimates show characteristic frequency-dependence as observed at the field scale in geological reservoirs. We find temporal variations of QC are strongly connected to hydraulic stimulation, and these variations are more significant than those resolved from velocity changes. $\overline {{Q}_C} $ estimates at frequencies above 15 kHz indicate healing of injection-induced small-scale fractures during a two-months post-stimulation phase. Larger fractures, mostly sampled by lower frequencies (<15 kHz), seem to be more persistent with time (over 15 months). We observe spatial differences of $\overline {{Q}_C} $ values near the mine galleries (driftway and vein drift) and relate these observations to different extents and characteristics of the galleries’ excavation damage zones. Our results further support previous assumptions based on borehole televiewer logs and mapped structures of an existing fault with larger damage zone that crosses the stimulated rock volume NW-SE between the galleries. We conclude that the coda analysis of active UT measurements complements established imaging methods used during experiments in URLs. In particular, coda analysis is a powerful tool for the detection of damage zones and for monitoring local fracture networks with immediate application for imaging georeservoirs considered for exploitation or underground storage of gases and liquids.

Distributed acoustic sensing time-lapse vertical seismic profiling during zipper-fracturing operations: Observations, modeling, and interpretation

Recent advances in distributed acoustic sensing (DAS) technology allow active seismic monitoring of stimulated rock volume (SRV) development. We showcase an interstage DAS vertical seismic profiling survey acquired during a zipper-fracturing stimulation. Incident P waves scattered by the SRV and converted to S waves are observed in the data. The signals are associated not only with hydraulic fracturing stages of the instrumented well but also with the fracturing of an adjacent well in the zipper group. A workflow is developed to monitor and characterize the SRV, fracture closure time, and interactions between zipper wells. The 3D full-wavefield modeling confirms the data interpretation and provides additional insight. As a result, we have been able to estimate SRV properties, including SRV height, width, and the fracture closure time for all wells within the zipper group. Moreover, for adjacent wells, the length and azimuth of SRV can be constrained. Our work provides critical information for optimizing hydraulic fracturing operations.

The impact of changes in natural fracture fluid pressure on the creation of fracture networks

Complex fracture networks have been observed in mine-back experiments, core samples, and other fracture diagnostic measurements. The interaction between hydraulic and natural fractures plays a key role in the formation of this complexity in naturally fractured formations. In past studies, changes in fluid pressure in natural fractures induced by interaction with other fractures are neglected when interactions between natural and hydraulic fractures are considered. In this paper, a DDM-based hydraulic fracturing simulator is developed to investigate the effect of changes in fluid pressure in natural fractures on fracture behavior and the resulting geometry of complex fracture networks. A fully implicit method is used to solve for width and pressure simultaneously. The proposed model is validated against an analytical solution for such variations in the vicinity of a penny-shaped fracture. Two kinds of interactions between hydraulic and natural fractures are defined to clearly investigate the mechanism of the far-field failure of natural fractures. Comparisons with and without considering changes in fluid pressure in natural fractures are conducted to show how the geometry of hydraulic fractures changes when changes in fluid pressure in fractures are included. Key parameters such as in-situ stress, natural fracture orientation, and friction coefficient are varied to develop new failure and crossing criteria under different conditions.Simulation results show that (1) changes in fluid pressure in fractures can initiate isolated fractures to create a stimulated rock volume. In some instances this will result in a more branched and complex fracture network; (2) deflection of hydraulic fractures along natural fractures is promoted when the effect of changes in fluid pressure in natural fractures is taken into account; (3) hydraulic fractures tend to deflect along pre-existing natural fractures with no far-field failure when the stress contrast is low; (4) in formations with high in-situ stress contrast, far-field failure of natural fractures occurs more readily and is impacted by the orientation and frictional coefficient of the natural fractures; (5) as expected, well cemented (highly mineralized) fractures with larger frictional coefficients hinder the slip of natural fractures and result in more planar less branched fractures. The results for failure and crossing criteria we developed can improve the understanding of the formation of complex fracture networks in naturally fractured rocks.

Time-lapse seismic integrated with surface microseismic for SRV characterization in the Vaca Muerta Formation

Time-lapse (4D) seismic acquisitions were performed in the unconventional play of the Vaca Muerta Formation to monitor hydraulic stimulation efficiency and characterize the stimulated rock volume (SRV) in horizontal drains. Two 4D pilots were carried out by acquiring 3D surveys before and after hydraulic stimulation. The pilots targeted different stratigraphic landings characterized by distinct lithological and geomechanical properties. The 4D pilots were performed in synergy with surface microseismic acquisitions. The combined acquisition enabled joint interpretation of the results. Time-lapse acoustic inversions were performed to identify changes in acoustic impedance. They revealed the vertical dimension of the SRV more precisely than the analysis of the envelope of the wet microseismic events. These wet events are interpreted as hydraulically connected to the well. The 4D signal is interpreted as the envelope of the induced hydraulic fractures, defined here as the fractured rock volume. This volume refers to where the rock frame has been directly affected by the stimulation job. The image provided by 4D seismic represents the most direct and accurate measurement of the volume encircling the flow pathways created by the fracture network generated by the hydraulic stimulation. This information is key to assessing ultimate hydrocarbon recovery and optimizing the development of unconventional reservoirs. The added value of the microseismic is the mapping of subtle events associated with the reactivation of critically stressed faults/lineaments. These provide preferential pathways that could connect to the well. They also help in the understanding of hydraulic interactions between the wells and their individual SRVs. The findings of these studies indicate that the optimal lateral and vertical well spacing should be designed based on 4D monitoring for drainage optimization and on microseismic for the analysis of interwell structural interferences.

Unsupervised learning from three-component accelerometer data to monitor the spatiotemporal evolution of meso-scale hydraulic fractures

Abstract Enhanced geothermal systems can provide a substantial share of the global energy demand. There exist several hurdles in the engineering implementations of such geothermal systems. One such hurdle is the accurate monitoring of the fracture networks created in subsurface through hydraulic stimulation of these systems. Micro seismicity associated with the stimulation is the primary means to locate the event hypocenters for estimating the stimulated rock volume. Existing methods for location the hypocenters are restricted to only the highest amplitude impulsive signals that are simultaneously detected on several sensors. Consequently, a large portion (usually ∼99%) of the measurements are left unused. In this paper, an unsupervised manifold-approximation followed by clustering of 3-component accelerometer data is used to analyze the seismicity recorded on a monitoring well. With this method, a larger portion of the measured signal is used for the monitoring of the hydraulic fracture network. We analyze the EGS Collab experiment 1 microseismic data, recorded at the Sanford Underground Research Facility, South Dakota. Using the data from a single three-component accelerometer, the polarization features viz. Azimuth, incidence, rectilinearity, and planarity are used as inputs for the unsupervised manifold approximation followed by clustering. Our study shows that density-based clusters in the projected 3D space correspond to distinct types of hydraulically fractured zones around the injection point. We show that the temporal evolution of these clusters can be used to track fracture creation and propagation.

Insights Into Hydraulic Fracture Growth Gained From a Joint Analysis of Seismometer‐Derived Tilt Signals and Acoustic Emissions

AbstractHydraulic fracturing is performed to enhance rock permeability, for example, in the frame of geothermal energy production or shale gas exploitation, and can potentially trigger induced seismicity. The tracking of increased permeabilities and the fracturing extent is often based on the microseismic event distribution within the stimulated rock volume, but it is debated whether the microseismic activity adequately depicts the fracture formation. We are able to record tilt signals that appear as long‐period transients (180 s) on two broadband seismometers installed close (17–72 m) to newly formed, meter‐scale hydraulic fractures. With this observation, we can overcome the limitations of the microseismic monitoring alone and verify the fracture mapping. Our analysis for the first time combines a catalog of previously analyzed acoustic emissions ([AEs] durations of 20 ms), indirectly mapping the fractures, with unique tilt signals, that provide independent, direct insights into the deformation of the rock. The analysis allows to identify different phases of the fracturing process including the (re)opening, growth, and aftergrowth of fractures. Further, it helps to differentiate between the formation of complex fracture networks and single macrofractures, and it validates the AE fracture mapping. Our findings contribute to a better understanding of the fracturing processes, which may help to reduce fluid‐injection‐induced seismicity and validate efficient fracture formation.

Modeling Hydraulic Fracturing Using Natural Gas Foam as Fracturing Fluids

Stranded gas emission from the field production because of the limitations in the pipeline infrastructure has become one of the major contributors to the greenhouse effects. How to handle the stranded gas is a troublesome problem under the background of global “net-zero” emission efforts. On the other hand, the cost of water for hydraulic fracturing is high and water is not accessible in some areas. The idea of using stranded gas in replace of the water-based fracturing fluid can reduce the gas emission and the cost. This paper presents some novel numerical studies on the feasibility of using stranded natural gas as fracturing fluids. Differences in the fracture creating, proppant placement, and oil/gas/water flowback are compared between natural gas fracturing fluids and water-based fracturing fluids. A fully integrated equation of state compositional hydraulic fracturing and reservoir simulator is used in this paper. Public datasets for the Permian Basin rock and fluid properties and natural gas foam properties are collected to set up simulation cases. The reservoir hydrocarbon fluid and natural gas fracturing fluids phase behavior is modeled using the Peng-Robinson equation of state. The evolving of created fracture geometry, conductivity and flowback performance during the lifecycle of the well (injection, shut-in, and production) are analyzed for the gas and water fracturing fluids. Simulation results show that natural gas and foam fracturing fluids are better than water-based fracturing fluids in terms of lower breakdown pressure, lower water leakoff into the reservoir, and higher cluster efficiency. NG foams tend to create better propped fractures with shorter length and larger width, because of their high viscosity. NG foam is also found to create better stimulated rock volume (SRV) permeability, better fracturing fluid flowback with a large water usage reduction, and high natural gas consumption. The simulation results presented in this paper are helpful to the operators in reducing natural gas emission while reducing the cost of hydraulic fracturing operation.

Acoustic velocity and permeability of acidized and propped fractures in shale

From geochemical reactions to proppant emplacement, hydraulic fracturing induces various chemomechanical fracture alterations in shale reservoirs. Hydraulic fracturing through the injection of a vast amount and variety of fluids and proppants has substantial impacts on fluid flow and hydrocarbon production. There is a strong need to improve our understanding on how fracture alterations affect flow pathways within the stimulated rock volume and develop monitoring tools. We have conducted time-lapse rock-physics experiments on clay-rich (carbonate-poor) Marcellus shales to characterize the acoustic velocity and permeability responses to fracture acidizing and propping. Acoustic P- and S-wave velocities and fracture permeability were measured before and after laboratory-induced fracture alterations along with microstructural imaging through X-ray computed tomography and scanning electron microscopy. Our experiments indicate that the S-wave velocity is an important geophysical observable, particularly the S-wave polarized perpendicular to fractures because it is sensitive to fracture stiffness. The acidizing and propping of a fracture decrease its elastic stiffness. This effect is stronger for acidizing, so it is possible that proppant monitoring will be masked by chemical alteration except when propping is highly efficient (i.e., most fractures are propped). However, fracture permeability is undermined by the softening of fracture surfaces due to acidizing, while being greatly enhanced by propping. These contrasting effects on fluid flow in combination with similar seismic attributes indicate the importance of experiments to improve existing rock-physics models, which must include changes to the rock frame. Such improvements are necessary for a correct interpretation of seismic velocity monitoring of flow pathways in stimulated shales.

Integrated Work Flow Delivers Precise Properties Input for Unconventional Simulation

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 203374, “Is My Completions Engineer Provided With the Correct Petrophysical and Geomechanical Properties Inputs?” by Philippe Gaillot, Brian Crawford, and Yueming Liang, SPE, ExxonMobil, et al., prepared for the 2020 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, held virtually 9–12 November. The paper has not been peer reviewed. To simulate the performance of unconventional wells effectively, incorporating sufficient geological complexity is essential to allow for realistic variability in the petrophysical and mechanical properties controlling the productivity of the effective stimulated rock volume (ESRV). The complete paper presents an integrated work flow to model mechanical properties at sufficiently high resolution (centimeter scale) to accurately honor rock fabric and its height and complexity effects on hydraulic fracturing and, therefore, on production. Once upscaled, outputs of this work flow enable a more-realistic borehole view of reservoir quality, fluid-flow units, and geomechanical stratigraphy, all information key to optimal asset development. Introduction Simulating hydraulic fractures with pre-existing natural mechanical discontinuities remains an important challenge. In most cases, the trend is to include more details in the simulations and apply more computational power to solve the problem. While these complex numerical simulations allow simultaneous interaction between multiple phenomena, the validity of the predicted hydraulic fractures, and thus ESRV productivity, may be questionable if inputs to the hydraulic-fracturing and production models do not capture the effective fine-scale complexity of the formation properties, namely the minimum in-situ horizontal stress contrast between layers, the changing layer properties, and the mechanical and flow properties of the interfaces. The complete paper presents a seven-step work flow wherein core poroelastic anisotropies derived from quantitative mineralogy and well-established micro-mechanical theory are integrated into a high-vertical-resolution multiphysics petrophysical model able to capture the centimeter-scale level of heterogeneity observed from cores. The resulting high-vertical-resolution well frame-work enables a detailed well-scale calibration and recognition of facies and stacking patterns; an accurate and core-calibrated geochemical, petrophysical, and geomechanical characterization of individual beds; and an identification and characterization of the interfaces between beds.

Cyclic Gas Injection EOR in Eagle Ford Can Increase Estimated Ultimate Recovery

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 200427, “Evaluation of Eagle Ford Cyclic Gas Injection EOR: Field Results and Economics,” by George Grinestaff, SPE, Chris Barden, and Jeff Miller, SPE, Shale IOR, prepared for the 2020 SPE Improved Oil Recovery Conference, originally scheduled to be held in Tulsa, 18–22 April. The paper has not been peer reviewed. Cyclic-gas-injection-based enhanced oil recovery (CGEOR) in the Eagle Ford was begun in late 2012 by EOG Resources and, at the time of writing, has expanded to more than 30 leases by six operators (266 wells). An extensive EOR evaluation was initiated to analyze the results recorded in these leases. The authors write that CGEOR in Eagle Ford volatile oil can yield substantial increases in estimated ultimate recovery (EUR) with robust economics, depending on compressor use and field life. Introduction Eagle Ford Source Rock and Reservoir. The Eagle Ford shale represents some of the world’s richest source rocks. The Upper Cretaceous seafloor received abundant organic debris and preserved it in an anoxic environment. The low permeability of the shale and limestone helped generate hydrocarbons when pore pressure exceeded overburden pressure. The resulting natural fractures provided a means to expel oil, much of it migrating into the overlying Austin Chalk and Tertiary sandstones. The primary target area for produced-gas injection EOR is currently in the volatile oil window between 9,000 and 11,000 ft true vertical depth, which yields oil API gravity of greater than 40. Initial gas/oil ratio (GOR) typically ranges from 1,000 to 3,000 scf/bbl. Eagle Ford EOR History. The first large-scale CGEOR project was implemented in October 2014. Rapid development has occurred since then, but, in the complete paper, the authors present the first commercial EOR projects by EOG Resources because these have the longest CGEOR production history. Recent projects show more-efficient startup, cycling, and higher optimization of gas injection. Therefore, the analysis of EOR in this paper takes a conservative approach of using the first projects because they appear to have lower EOR recovery but more production history. Evaluation Methodology Unconventional EOR Work Flow. Analysis of CGEOR production and results has been completed using production history and reservoir simulation to provide a rigorous evaluation. The authors use a 14-component fracture element model with a very fine grid to predict well GOR, EUR, and reservoir behavior for the compositional process. The element model is then scaled up to mimic the average well for a given pad or lease, and then cycle operations are developed based on CGEOR simulation runs and criteria. Unconventional CGEOR provides a direct response after the first cycle of gas injection; however, the base depletion profile also is important for understanding economics for increased oil production or incremental EOR. A history match of the base depletion is first completed to match an average well at the pad level (approximately one 640-acre section with 10 to 14 wells). The element is then scaled up based on well completion, stimulated rock volume, and EUR for the base depletion.

Modeling and interpretation of scattered waves in interstage distributed acoustic sensing vertical seismic profiling survey

Optimization of well spacings and completions are key topics in research related to the development of unconventional reservoirs. In 2017, a vertical seismic profiling (VSP) survey using fiber-optic-based distributed acoustic sensing technology was acquired. The data include a series of VSP surveys taken before and immediately following the hydraulic fracturing of each of 78 stages. Scattered seismic waves associated with hydraulic fractures (HFs) are observed in the seismic waveforms. Kinematic traveltime analysis and full-wavefield modeling results indicate that these scattered events are converted PS-waves. We have tested three different models of fracture-induced velocity inhomogeneities that can cause scattering of seismic waves: single HF, low-velocity zone (LVZ), and tip diffractors. We compare the results with the field observations and conclude that the LVZ model has the best fit for the data. In this model, the LVZ represents a stimulated rock volume (SRV). We have developed a new approach that uses PS-waves converted by SRV to estimate the half-height of the SRV and the closure time of HFs. This active seismic source approach has the potential for cost-effective real-time monitoring of hydraulic fracturing operations, and it can provide critical constraints on the optimization of unconventional field development.

A method for modeling multiscale geomechanical effects in the stimulated rock volume

I have developed a workflow to efficiently simulate geomechanical effects in the stimulated rock volume (SRV) by including regional geologic structures such as faults and folds as well as high-resolution-oriented mechanical stratigraphy. The motivation is that the local model used for hydraulic fracture analysis should include macroscale 3D geomechanical effects derived from regional tectonic and seismic data. A practical computational strategy is developed to link multiple 3D geomechanical models derived at different scales and their associated stress effects. I apply the workflow to a synthetic reservoir problem composed of a tectonic-scale structural framework model with three embedded mechanical stratigraphic models representing three stimulated vertical wells. I first combine regional stresses solved with 3D finite-element analysis with perturbation stresses from elastic dislocation modeling using elastic superposition concepts. I then apply the macroscale stress effects as unique boundary conditions to an embedded finite-element submodel, a mesoscale stratigraphic model representing the SRV allowing for resolution of variable stress amplification, and stress rotation in geologic sublayers. Finally, I conduct hydraulic-fracture simulations within the SRV models. The simulated hydraulic fractures are controled by the structural position and mechanical stratigraphy. Closest to the back limb of the main structural anticline, hydraulic fractures tend to be height-restricted, and in some realizations, fractures propagate horizontally. Adjacent to the fold and a fault, where differential stresses are elevated, fracture growth is the most unconstrained in height and length. Results suggest that this multiscale approach can be applied to better predict and understand behaviors related to unconventional reservoir stimulation. The workflow could easily be modified for other operational problems and geologic settings.

Effect analysis of borehole microseismic monitoring technology on shale gas fracturing in western Hubei

Hydraulic fracturing technology is an important means of shale gas development, and microseismic monitoring is the key technology of fracturing effect evaluation. In this study, hydraulic fracturing and microseismic monitoring were simultaneously conducted in the Eyangye 2HF well (hereinafter referred to as EYY2HF well). The target stratum of this well is the second member of the Doushantuo Formation of the Sinian System, which is the oldest stratum of horizontal shale gas wells in the world. A total of 4341 microseismic fracturing events were identified, and 23 fracturing stages of the well were defined. The fluctuation of the number of events showed a repeating “high-low” pattern, and the average energy of these events showed minimal differences. These findings indicate that the water pressure required for the reconstruction of the EYY2HF well is appropriate. The main body of the fracture network extended from northwest to southeast, consistent with the interpretation of regional geological and seismic data. The stimulated rock volumes showed a linear increase with the increase of the fracturing stage. Some technological measures, such as quick lift displacement, quick lift sand ratio, and pump stop for secondary sand addition, were adopted during fracturing to increase the complexity of the fracture network. Microseismic fracture monitoring of the well achieved expected effects and guided real-time fracturing operations and fracturing effect evaluation.