Logging data are measurements of physical properties of the formation surrounding a borehole, acquired in situ after completion of coring (wireline logging) or during drilling (Logging-While-Drilling, LWD). The range of data (resistivity, gamma radiation, velocity, density, borehole images,…) in any hole depends on the scientific objectives and operational constraints.

The current state-of-the-art technology for in-situ stress measurements involves an integrated approach that combines borehole breakout observations, drilling-induced tensile fractures, and hydraulic fracturing tests (i.e., "mini-fracs"). This methodology has achieved wide application in the oil and gas industry but has several limitations that often prevent successful in-situ stress measurements. One major limitation is that breakouts do not appear in all boreholes and are generally only a natural occurrence that cannot easily be controlled. Because borehole breakouts are used to directly measure the maximum horizontal in-situ stress magnitude, the absence of borehole breakouts presents a major data gap for in-situ stress measurements. In response to this data gap, a new US Department of Energy (US DOE)-sponsored thermal breakout technology that will provide a method for thermally inducing borehole breakouts and allow the consistent measurement of the maximum horizontal stress magnitude is currently in development. This thermal breakout technology involves heating the borehole and increasing the thermoelastic compressive stress in the rock until a breakout develops, which can be directly correlated to the maximum horizontal stress magnitude. The first step in this project was an analytical modeling study of the thermal breakout process. Based on the Kirsch solution (Kirsch 1898), a deterministic and statistical analysis was performed on the pertinent parameters that influence the maximum horizontal stress calculation. As a result of the analysis, the findings indicate that the thermal breakout technology is feasible and provides improved accuracy and/or an enhanced ability to measure the maximum horizontal stress. Future work as part of this US DOE-sponsored project includes additional validation through more detailed numerical modeling, laboratory testing, and field testing of the thermal breakout technology.

Fluid-filled fractures support guided waves known as Krauklis waves. The resonance of Krauklis waves within fractures occurs at specific frequencies; these frequencies, and the associated attenuation of the resonant modes, can be used to constrain the fracture geometry. We use numerical simulations of wave propagation along fluid-filled fractures to quantify fracture resonance. The simulations involve solution of an approximation to the compressible Navier-Stokes equation for the viscous fluid in the fracture coupled to the elastic-wave equation in the surrounding solid. Variable fracture aperture, narrow viscous boundary layers near the fracture walls, and additional attenuation from seismic radiation are accounted for in the simulations. We then determine how tube waves within a wellbore can be used to excite Krauklis waves within fractures that are hydraulically connected to the wellbore. The simulations provide the frequency-dependent hydraulic impedance of the fracture, which can then be used in a frequency-domain tube-wave code to model tube-wave reflection/transmission from fractures from a source in the wellbore or at the wellhead (e.g., water hammer from an abrupt shut-in). Tube waves at the resonance frequencies of the fracture can be selectively amplified by proper tuning of the length of a sealed section of the wellbore containing the fracture. The overall methodology presented here provides a framework for determining hydraulic fracture properties via interpretation of tube-wave data.

Abstract Weak bedding planes create a unique mechanism for hydraulic fracture height containment, providing one possible explanation for unusual patterns of height growth in shale formations. This paper describes an investigation into how bedding planes modify the interactions between multiple, simultaneously propagating hydraulic fractures in a formation with weak horizontal interfaces with laterally varying properties. The investigation used a 3-D simulator that fully coupled geomechanics, fracture mechanics, and fluid behavior. Three equally spaced fractures were simulated along a horizontal trajectory. Fluid was injected simultaneously into all three locations, and partitioned according to maintain a specified total injection rate. Variations in perforation spacing, fluid viscosity and injection rate are modeled. The four designs investigated were: 1) 10-cp fluid, 20b-pm injection rate with 30-m cluster spacing. 2) 100-cp fluid and 20-bpm fluid injection rate with 30-m cluster spacing. 3) 10-cp fluid and 40-bpm injection rate with 30-m cluster spacing. 4) 10-cp fluid, 20-bpm and 45-m cluster spacing. Results showed how these changes affected fracture area and shape. The propped surface area for each scenario was also estimated. The results suggested that the presence of laterally varying weak interfaces can significantly affect fracture interference.

Creation of an Enhanced Geothermal System relies on stimulation of fracture permeability through self-propping shear failure that creates a complex fracture network with high surface area for efficient heat transfer. In 2010, shear stimulation was carried out in well 27-15 at Desert Peak geothermal field, Nevada, by injecting cold water at pressure less than the minimum principal stress. An order-of-magnitude improvement in well injectivity was recorded. Here, we describe a numerical model that accounts for injection-induced stress changes and permeability enhancement during this stimulation. We use the coupled thermo-hydrological–mechanical simulator FEHM to (i) construct a wellbore model for non-steady bottom-hole temperature and pressure conditions during the injection, and (ii) apply these pressures and temperatures as a source term in a numerical model of the stimulation. A Mohr–Coulomb failure criterion and empirical fracture permeability is developed to describe permeability evolution of the fractured rock. The numerical model is calibrated using laboratory measurements of material properties on representative core samples and wellhead records of injection pressure and mass flow during the shear stimulation. The model captures both the absence of stimulation at low wellhead pressure (WHP ≤1.7 and ≤2.4MPa) as well as the timing and magnitude of injectivity rise at medium WHP (3.1MPa). Results indicate that thermoelastic effects near the wellbore and the associated non-local stresses further from the well combine to propagate a failure front away from the injection well. Elevated WHP promotes failure, increases the injection rate, and cools the wellbore; however, as the overpressure drops off with distance, thermal and non-local stresses play an ongoing role in promoting shear failure at increasing distance from the well.

PreviousNext No AccessBeijing 2014 International Geophysical Conference & Exposition, Beijing, China, 21-24 April 2014Using Microseismic to Estimate Stimulation Efficiency, Application and DrawbacksAuthors: X. Zhang*M. HollandW. van der ZeeD. MoosX. Zhang*Baker Hughes IncorporatedSearch for more papers by this author, M. HollandBaker Hughes IncorporatedSearch for more papers by this author, W. van der ZeeBaker Hughes IncorporatedSearch for more papers by this author, and D. MoosBaker Hughes IncorporatedSearch for more papers by this authorhttps://doi.org/10.1190/IGCBeijing2014-341 SectionsAboutPDF/ePub ToolsAdd to favoritesDownload CitationsTrack CitationsPermissions ShareFacebookTwitterLinked InRedditEmail Abstract Microseismic has become a standard monitoring tool for estimating hydraulic fracturing effectiveness. Because microseismic events are signatures of rock failures during or after stimulation, the event locations are sometimes used to determine the stimulated rock volume (SRV). However, the linkage between events and relevant flow properties within the reservoir engineer's stimulated reservoir volume requires the use of a physically meaningful and quantitatively scaled parameter. The lack of such a direct connection may be one reason why discrepancies are often observed between the effective production volume and microseismic-calculated SRV. In this study, an improved workflow for microseismic SRV characterization is presented using data from a case study in a Devonian shale gas reservoir. The workflow honors the event's spatial distribution, corrects for detection range bias and provides a measure of stimulation effectiveness within the SRV. Furthermore, the uncertainties inherent in the processed microseismic event dataset from the relatively low number of detected events and limited magnitude range are investigated and the consequences and drawbacks in using microseismic to characterize the underlying fracture network of the stimulated reservoir is presented. Keywords: microseismic, monitoring, volume, fracturesPermalink: https://doi.org/10.1190/IGCBeijing2014-341FiguresReferencesRelatedDetailsCited ByMicroseismic 101: Monitoring and Evaluating Hydraulic Fracturing to Improve the Efficiency of Oil and Gas Recovery from Unconventional Reservoirs18 November 2015 Beijing 2014 International Geophysical Conference & Exposition, Beijing, China, 21-24 April 2014ISSN (online):2159-6832Copyright: 2014 Pages: 1360 publication data© 2014 Published in electronic format with permission by the Society of Exploration Geophysicists and Chinese Petroleum SocietyPublisher:Society of Exploration Geophysicists HistoryPublished: 24 Apr 2014 CITATION INFORMATION X. Zhang*, M. Holland, W. van der Zee, and D. Moos, (2014), "Using Microseismic to Estimate Stimulation Efficiency, Application and Drawbacks," SEG Global Meeting Abstracts : 1351-1354. https://doi.org/10.1190/IGCBeijing2014-341 Plain-Language Summary KeywordsmicroseismicmonitoringvolumefracturesPDF DownloadLoading ...

Hydroshearing is used to improve well injectivity in Engineered Geothermal Systems (EGS). During hydroshearing, cold water is injected at bottom-hole pressures less than the minimum principal stress to promote permeability enhancement through selfpropping shear failure of pre-existing fractures. By interacting with the typically complex natural fracture network, a tortuous flow path with high surface area is promoted to allow for efficient heat exchange. Using the Mohr-Coulomb failure criterion, we consider three mechanisms that directly influence shear failure during injection: (1) Fluid pressurization decreasing the effective normal stress (i.e., normal stress minus pore pressure) on fractures amenable to slip and promoting failure. (2) Cooling of the rock matrix, leading to a thermoelastic decrease in normal stress on these fractures (3) Pressurization within the rock matrix, leading to a poroelastic increase in normal stress on these fractures. Recently, we have implemented stress-permeability relationships to describe hydroshearing in the thermo-hydro-mechanical simulator FEHM. We have previously shown that this model is capable of reproducing the response of the Desert Peak EGS well 27-15 to shear stimulation. In this work, we analyze the relative importance of processes (1)-(3), including their non-local implications, to provide a deeper understanding of hydroshearing physics. In addition to the direct effect of fluid pressure (process 1), we show that thermoelastic stresses exert a strong influence on fracture failure during hydroshearing. The magnitude of these thermoelastic stresses is sensitive to the product of Young’s modulus and the thermal expansion coefficient, as well as the difference between injection fluid temperature and ambient formation temperature. Increasing the injection wellhead pressure (WHP) amplifies injectivity gains due to the thermoelastic effect, and can dominate over the direct fluid pressure effect when the contrast between injection fluid temperature and formation temperature is large. Even when the surface temperature of the injection fluid is constant, increasing WHP delivers a greater volume of water to the formation at a lower temperature (by minimizing heating in the wellbore), thereby increasing both the rate and magnitude of thermoelastic stressing. We also present evidence that remote stress changes induced by thermoelastic cooling near a well can play an important role in propagating the front of permeability enhancement at long elapsed times. This effect is anisotropic, promoting activation of shear fractures in a direction parallel to the minimum horizontal principal stress, which in a normal faulting setting would be perpendicular to the expected strike of highly stressed fractures. This provides a new mechanism for widening the stimulated volume created during hydroshearing, promoting the creation of a more efficient and sustainable heat exchange fracture network.