The characteristics of hydraulic fractures in the near-wellbore region contain critical information related to the production performance of unconventional wells. We demonstrate a novel application of a fiber-optic-based distributed strain sensing (DSS) technology to measure and characterize near-wellbore fractures and perforation cluster efficiency during production. Distributed fiber-optic-based strain measurements are made based on the frequency shift of the Rayleigh scatter spectrum, which is linearly dependent on strain and temperature changes of the sensing fiber. Strain changes along the wellbore are continuously measured during the shut-in and reopening operations of a well. After removing temperature effects, extensional strain changes can be observed at locations around the perforation cluster during a shut-in period. We interpret that the observed strain changes are caused by near-wellbore fracture aperture changes caused by pressure increases within the near-wellbore fracture network. The depth locations of the measured strain changes correlate well with distributed acoustic sensing (DAS) acoustic intensity measurements that were measured during the stimulation of the well. The shape and magnitude of the strain changes differ significantly between two completion designs in the same well. Different dependencies between strain and borehole pressure can be observed at most of the perforation clusters between the shut-in and reopening periods. We assess that this new type of distributed fiber-optic measurement method can significantly improve understanding of near-wellbore hydraulic fracture characteristics and the relationships between stimulation and production from unconventional oil and gas wells.

Long-period long-duration (LPLD) seismic events are low-amplitude tremor-like seismic signals that have been observed in some microseismic monitoring data sets acquired during hydraulic fracturing operations. The LPLD events have been interpreted to be associated with slow slip along preexisting fractures presumed to either have high clay content or be misaligned with respect to the current-day principal stress directions. However, a recent study indicates that regional earthquakes, when recorded on vertical down-hole monitoring arrays, have similar signal characteristics to LPLD events and that care must be taken when analyzing and interpreting such signals. Using data from a hydraulic fracturing microseismic data set in which LPLD events have previously been identified and well documented, together with data from the EarthScope Transportable USArray, we have investigated the hypothesis that the documented LPLD events were regional earthquakes. We have determined that the LPLD events corresponded with signals recorded on the USArray at distances of up to 350 km away from the injection well, although they were not listed in any regional earthquake catalog. The spatial coverage of the USArray allows the sources of many of the LPLD events to be relocated outside of the treatment well area and thus suggests that they are regional earthquakes of magnitude smaller than M2.5 rather than locally sourced events related to the hydraulic fracturing stimulation process.

Summary Recent studies have identified and characterized a type of seismic event, known as an LPLD event, which have been detected in microseismic data sets acquired during hydraulic fracturing operations (e.g. Das and Zoback, 2011 ; 2013a ; 2013b ; Mitchell et al., 2013 ; Kwietniak, 2015 ). These events have been interpreted to be manifestations of slow-slip along preexisting fractures which are presumed to either be misaligned with respect to the current day principal stress directions or have high clay content ( Das & Zoback, 2013a ; 2013b ). A study by Caffagni et al. (2015) advise that care must be undertaken when analyzing and interpreting such events as regional earthquakes could be misinterpreted as LPLD events in vertical downhole seismic monitoring array data sets. We here show that signals associated in time with such LPLD events could be observed on many Earthscope USArray stations, even at distances up to 350 km from the injection well. The spatial coverage of the USArray enabled all of the LPLD events to be relocated in the North Texas-Oklahoma region, outside of the stimulated reservoir volume. We conclude that these LPLD events are not directly related to the hydraulic fracture stimulation process or the induced reservoir deformation process.

PreviousNext No AccessSEG Technical Program Expanded Abstracts 2012Vibroseis as an impulsive seismic source - 3D field testing Permian Basin TexasAuthors: J.W. (Tom) ThomasDana M. JurickDwight OstenJ.W. (Tom) ThomasDawson GeophysicalSearch for more papers by this author, Dana M. JurickDevon EnergySearch for more papers by this author, and Dwight Ostenretired TexacoSearch for more papers by this authorhttps://doi.org/10.1190/segam2012-1452.1 SectionsSupplemental MaterialAboutPDF/ePub ToolsAdd to favoritesDownload CitationsTrack CitationsPermissions ShareFacebookTwitterLinked InRedditEmail Abstract Dawson Geophysical Company and Devon Energy with significant contribution from Fasken Oil and Ranch LTD acquired and processed five comparable 3D seismic surveys with diverse acquisition techniques. Each data set was recorded over a common surface area of 6.25 square miles in the Permian Basin, 14 miles north-west of Midland Texas. The purpose of the testing was to directly compare the data character and quality of the different acquisition techniques. The tests included the simultaneously sourced “Galcode method”, plus the single sweep, low energy, high CMP fold technique and the high effort multi-sweep per vibrator source point (VP) conventional philosophy. Secondarily, the recording strategy allowed comparisons to be made on data “sourced” with one or two vibrators per source point. All five test volumes were recorded over the same land area in six days and processed with the same processing flow. Three of the test case scenarios utilized the coded sweep methodology that we introduced in Denver during 2010 with the SEG abstract and presentation titled Galcode: Simultaneous Seismic Sourcing. Two of the three coded source scenarios tested the simultaneous “chirp” methodology and the third evaluated the “thump” or impulse vibroseis source method. A fourth test was recorded with a single sweep per source point and a fifth data set was recorded with conventional technique that acts as the baseline reference data set. One and half days of field time was allocated for each test. The time per source point was estimated for each scenario and the number of source points or fold acquired for each test varied. Important in our conclusions is the assessment that the conventional data set was deemed to produce the poorest quality stacked data of the five data sets recorded and processed. Permalink: https://doi.org/10.1190/segam2012-1452.1FiguresReferencesRelatedDetails SEG Technical Program Expanded Abstracts 2012ISSN (print):1052-3812 ISSN (online):1949-4645Copyright: 2012 Pages: 4609 Publisher:Society of Exploration Geophysicists HistoryPublished: 25 Oct 2012 CITATION INFORMATION J.W. (Tom) Thomas, Dana M. Jurick, and Dwight Osten, (2012), "Vibroseis as an impulsive seismic source - 3D field testing Permian Basin Texas," SEG Technical Program Expanded Abstracts : 1-5. https://doi.org/10.1190/segam2012-1452.1 Plain-Language Summary PDF DownloadLoading ...

Performing accurate depth-imaging is an essential part of deep-water Gulf of Mexico exploration and development. Over the years, depth-imaging technology has provided reliable seismic images below complicated salt bodies, and has been implemented in workflows for both prospect generation as well as reservoir development. These workflows include time domain preprocessing using various multiple elimination techniques, anisotropic model building, and depth-imaging using anisotropic reverse time migration (RTM). However, the accuracy of the depth-migrated volumes is basically unknown because they are tested only in the locations where a well is drilled. In order to learn about the accuracy of anisotropic deep water Gulf of Mexico model building, and depth-imaging tools which are used for processing and imaging of field acquired data, we created a 3D vertical transverse isotropic (VTI) anisotropic earth model and a 3D seismic data set representing subsalt Gulf of Mexico geology. The model and data set are referred to as the Tempest data set, the original being created several years ago. The recent model and data set were created incorporating upgraded technology to reflect recent developments in data acquisition, model building and depth-imaging. Our paper presents the new Tempest anisotropic model, data set, and RTM prestack depth-migration (PSDM) results. The Tempest RTM PSDM is being used to learn about the differences between the exact geological model and the RTM PSDM image, helping in the interpretation of real RTM prestack depth-migrated data.

ABSTRACTMonitoring of induced microseismic events has become an important tool in hydraulic fracture diagnostics and understanding fractured reservoirs in general. We compare microseismic event and their uncertainties using data sets obtained with surface and downhole arrays of receivers. We first model the uncertainties to understand the effect of different acquisition geometries on location accuracy. For a vertical array of receivers in a single monitoring borehole, we find that the largest part of the final location uncertainty is related to estimation of the backazimuth. This is followed by uncertainty in the vertical position and radial distance from the receivers. For surface monitoring, the largest uncertainty lies in the vertical position due to the use of only a single phase (usually P‐wave) in the estimation of the event location. In surface monitoring results, lateral positions are estimated robustly and are not sensitive to the velocity model.In this case study, we compare event location solutions from two catalogues of microseismic events; one from a downhole array and the second from a surface array of 1C geophone. Our results show that origin time can be reliably used to find matching events between the downhole and surface catalogues. The locations of the corresponding events display a systematic shift consistent with a poorly calibrated velocity model for downhole dataset. For this case study, locations derived from surface monitoring have less scatter in both vertical and horizontal directions.

Shear waves from microearthquakes induced by hydraulic fracturing are observed on three-component (3C) accelerometers along a 2 km surface profile. The S-wave waveforms exhibit at least two distinct phases suggesting shear-wave splitting. This observation

Abstract A matched filter technique that uses cross-correlation and migration of the recorded waveforms has been successfully used to relatively locate microseismic events. In addition to producing consistent relative locations, the matched filter corrects for radiation pattern effects and near-surface structure. The relative locations produced using this methodology were compared with a proprietary, direct location method. The new results produce a solution set that reveals two parallel trends of microseismic events which are interpreted as 1500' long fracture zones approximately 100' wide. We observed asymmetric fracture growth and re-fracturing of the previously stimulated zones. Time correspondence of the observed evolution of seismic events with engineering pump curve data reveals approximate linear growth rates of several feet per minute and possible proppant placement along the induced fractures.

Performing depth imaging is an essential part of deepwater Gulf of Mexico (GOM) exploration. Over the years, depth-imaging technology has provided the most reliable seismic images below salt and has been implemented in the workflows of the prospect generation process. But how accurate are these images? Since model building for depth imaging is partially an interpretative process, and depth imaging involves resolving seismic propagation through complicated geologic features, it is easy for the resulting prestack depth-migrated images to include imaging and positioning errors.

PreviousNext No AccessSEG Technical Program Expanded Abstracts 2008A realistic deep water Gulf of Mexico 3D simulation and imaging — The Tempest simulation, datasets and imagingAuthors: David KesslerJeff CoddFatmir HoxhaClaude PignolAlex BridgeRichard BrietzkeAdam SeitchikDana JurickDavid KesslerSeismicCity CorporationSearch for more papers by this author, Jeff CoddSeismicCity CorporationSearch for more papers by this author, Fatmir HoxhaSeismicCity CorporationSearch for more papers by this author, Claude PignolSeismicCity CorporationSearch for more papers by this author, Alex BridgeDevon Energy CorporationSearch for more papers by this author, Richard BrietzkeDevon Energy CorporationSearch for more papers by this author, Adam SeitchikDevon Energy CorporationSearch for more papers by this author, and Dana JurickDevon Energy CorporationSearch for more papers by this authorhttps://doi.org/10.1190/1.3054827 SectionsSupplemental MaterialAboutPDF/ePub ToolsAdd to favoritesDownload CitationsTrack CitationsPermissions ShareFacebookTwitterLinked InRedditEmail Abstract The Tempest 3D model and dataset were generated to test industry's ability to correctly image deep water Gulf of Mexico subsalt structures. The project included four steps: (a) design of a 3‐dimensional model based on real Gulf of Mexico geology; (b) acquisition design that included narrow azimuth, mid (range) azimuth and wide azimuth geometries; (c) numerical simulation using two‐ way wave equation algorithm and construction of three synthetic datasets; (d) application of various prestack depth migration algorithms for testing of subsalt imaging quality. The project parameters acquisition design and prestack depth migration algorithm parameters were all selected based on a single guideline: to be done as close as possible to field data acquisition and imaging. By following this guideline we obtained a dataset which realistically represents our ability to resolve subsalt imaging challenges. In this paper we present the project steps and demonstrate its main results.Permalink: https://doi.org/10.1190/1.3054827FiguresReferencesRelatedDetailsCited ByInvestigation of deep-water Gulf of Mexico subsalt imaging using anisotropic model, data set and RTM — TempestGEOPHYSICS, Vol. 76, No. 5 SEG Technical Program Expanded Abstracts 2008ISSN (print):1052-3812 ISSN (online):1949-4645Copyright: 2008 Pages: 3713 publication data© 2008 Copyright © 2008 Society of Exploration GeophysicistsPublisher:Society of Exploration Geophysicists HistoryPublished: 15 Dec 2008 CITATION INFORMATION David Kessler, Jeff Codd, Fatmir Hoxha, Claude Pignol, Alex Bridge, Richard Brietzke, Adam Seitchik, and Dana Jurick, (2008), "A realistic deep water Gulf of Mexico 3D simulation and imaging — The Tempest simulation, datasets and imaging," SEG Technical Program Expanded Abstracts : 378-382. https://doi.org/10.1190/1.3054827 Plain-Language Summary PDF DownloadLoading ...

PreviousNext No AccessSEG Technical Program Expanded Abstracts 2008Evaluating the accuracy of deep water Gulf of Mexico depth imaging — The Tempest resultsAuthors: Richard BrietzkeAlex BridgeDana JurickAdam SeitchikRichard BrietzkeDevon Energy CorporationSearch for more papers by this author, Alex BridgeDevon Energy CorporationSearch for more papers by this author, Dana JurickDevon Energy CorporationSearch for more papers by this author, and Adam SeitchikDevon Energy CorporationSearch for more papers by this authorhttps://doi.org/10.1190/1.3054828 SectionsSupplemental MaterialAboutPDF/ePub ToolsAdd to favoritesDownload CitationsTrack CitationsPermissions ShareFacebookTwitterLinked InRedditEmail Abstract Performing depth imaging is an essential part of deep water Gulf of Mexico exploration. Over the years, depth imaging technology has proven to provide the most reliable seismic images below salt. These depth images are used for structural interpretation and prospect generation. But how accurate are these images? Since model building for depth imaging is partially an interpretative process, and the imaging involves resolving seismic propagation through complicated geologic features, it is easy for the resulting prestack depth migrated images to include imaging and positioning errors. In order to analyze subsalt depth imaging accuracy, Devon Energy Corporation provided several seismic contractors a 3D wave equation simulated dataset called Tempest. This dataset was used for model building and depth imaging. The results of this work enabled us to quantitatively measure the accuracy of subsalt depth imaging and use this analysis to build better models for depth imaging and to better interpret subsalt prestack depth migrated seismic data. In this paper we describe the motivation for this project, the velocity models and prestack depth migration results produced by the various contractors that participated in imaging the data and the analysis of the developed models and depth migrated volumes.Permalink: https://doi.org/10.1190/1.3054828FiguresReferencesRelatedDetailsCited byInvestigation of deep-water Gulf of Mexico subsalt imaging using anisotropic model, data set and RTM — TempestFatmir Hoxha, Jacqueline O’Connor, Jeff Codd, David Kessler, Alex Bridge, Dana Jurick, Richard Brietzke, and Kenneth Beeney21 November 2011 | GEOPHYSICS, Vol. 76, No. 5 SEG Technical Program Expanded Abstracts 2008ISSN (print):1052-3812 ISSN (online):1949-4645Copyright: 2008 Pages: 3713 publication data© 2008 Copyright © 2008 Society of Exploration GeophysicistsPublisher:Society of Exploration Geophysicists HistoryPublished Online: 15 Dec 2008 CITATION INFORMATION Richard Brietzke, Alex Bridge, Dana Jurick, and Adam Seitchik, (2008), "Evaluating the accuracy of deep water Gulf of Mexico depth imaging — The Tempest results," SEG Technical Program Expanded Abstracts : 383-387. https://doi.org/10.1190/1.3054828 Plain-Language Summary PDF DownloadLoading ...

The operational condition that dominates the survey planning and implementation is the presence of major shipping transit fairway to and from the Suez Canal. This shipping thoroughfare covers about 70% of the survey area. Operational considerations necessitate a shooting orientation that closely parallels the shipping lanes, which approximates the strike direction of the subsurface target. Shooting in the dip direction, across the shipping lanes, was not considered to be operationally feasible for a 3D spread or operation. A 3D seismic acquisition program took place in the northern Gulf of Suez, Egypt during early 2003 (figure 1). The marine towed streamer survey was preceded by an acquisition feasibility, design and modeling study that used a variety of techniques. The primary goal of the 3D survey design work was to specify and assess a set of key acquisition parameters that could be implemented in the field which, critically, had to support the successful implementation of modern demultiple, noise attenuation and 3D image processing techniques and technology. It was important to look for a solution that integrated operational realities and specific processing requirements. Previous 2D seismic acquisition programs in the area have utilized a limited offset streamer, presumably to accommodate dip and strike shooting through the shipping lanes. The 2D results typically suffer from marginal to very poor demultiple results and very poor imaging of the target structures. It was estimated that poor results were probably due to a combination of high residual noise levels related to limited demultiple technology and 2D imaging limitations. Exploration drilling results, based at least partially on the 2D datasets, have been disappointing to date. As a primary design tool on this project, we used 2D and 3D wave equation simulation. The aim of the wave equation simulation was to generate realistic synthetic seismograms that could be used to assess the effect of different field design parameters on exploration objectives. The goal was to design an economic and operationally feasible 3D survey that met the exploration objectives of our staff. This presentation will demonstrate how the wavefield simulation work was utilized and found to be useful for 3D seismic survey planning. Wave equation simulation was used in preparation of the acquisition program specifications. The technique was utilized to produce synthetic seismogram shot records that were in turn examined, interpreted and processed to assess the impact of various parameter combinations on meeting technical, operational and economic requirements set by the exploration staff. Introduction