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- Volume 32, Issue 7, 2014
First Break - Volume 32, Issue 7, 2014
Volume 32, Issue 7, 2014
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Hydraulic fracturing-induced seismicity: an overview of recent observations and implications on development
By A. BaigAdam Baig and Ted Urbancic demonstrate that many instruments are insufficient to characterize induced seismicity associated with hydraulic fracturing and that more realistic target magnitudes are needed. An accurate magnitude calculation is critical to assessing the impact of hydraulic fracturing on seismic hazards as well as correctly characterizing the fractures that are activated during the stimulation. Recently, Warpinski (2013) asserted that seismicity associated with hydraulic fracturing rarely attains magnitudes above 0.5; on the other hand Holland (2011) documents hydraulic fracture-induced seismicity in the Eola field in Oklahoma reaching magnitudes of 2.8. While it can be argued that the latter dataset may be unusual, there is a fundamental difference between the datasets considered in that the former data are collected from downhole monitoring arrays utilizing 15Hz geophones, primarily tasked with the routine tasks of hydraulic fracture monitoring of delineating stimulation volumes with event locations; whereas Holland’s study used USArray broadband stations with the low-frequency response necessary to accurately characterize the larger magnitude events. Given the ubiquity of arrays of 10 Hz or 15 Hz geophone arrays for industrial monitoring of hydraulic fracturing, it is an open question whether and how frequently larger-magnitude events (>M0) are generated during these stimulations given the inadequacy of these instruments for characterizing larger-magnitude events.
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The use of amplitude ratios to constrain source mechanisms of microseismic data: A case study from the Montney Shale, Alberta
Authors M. Lee, T. Davis and S. MaxwellMatthew Lee, Thomas Davis and Shawn Maxwell analyze data from the downhole arrays used to monitor hydraulic stimulations at the Montney shale play in Canada. The Reservoir Characterization Project at Colorado School of Mines has been working in conjunction with Talisman Energy Inc. since 2009 to analyze two hydraulic stimulations in the Montney Shale play in Canada. Specifically, the project originates from the monitoring of two five stage horizontals from the Pouce Coupe area in North-Western Alberta. The completions were monitored using a variety of microseismic methods (surface, shallow water well and downhole). This paper will focus on analysis of data from the downhole arrays that were used to monitor the hydraulic stimulations.
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Understanding treatment optimization in shale plays
Authors C. Neuhaus, M. Ellison and C. TelkerCarl Neuhaus, Mary Ellison and Cherie Telker show how microseismic monitoring can help to build up a clearer picture of hydraulic fractures. Microseismic monitoring provides important information to understand reservoir characteristics, field development, wellbore completions, and treatment design strategies. Partially due to the rapid development of shale plays across the United States in the past decade, several operating companies have determined that it is advantageous to monitor hydraulic fracturing treatments of unconventional reservoirs to have a better understanding of the formation and ultimately produce more hydrocarbons.
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Improved reservoir characterization and monitoring of the Long Lake heavy oil SAGD project using time-lapse multicomponent seismic data
Authors K. Schiltz, L. Zeigler and D. GrayKelsey Schiltz, Loren Zeigler and David Gray demonstrate how the integration of timelapse compressional and multi-component seismic data has resulted in a geologic model of low permeability shales and enhanced the understanding of the steam chamber through imaging of the heat and pressure fronts in the Long Lake bitumen field in Alberta, Canada. Long Lake is a bitumen field covering 63,000 acres within the Athabasca oil sands in Alberta, Canada. Bitumen is a special type of heavy oil that is less than 10 API and is immobile at in situ conditions. Long Lake bitumen (~8 API) is produced from the Lower Cretaceous McMurray Formation using an in situ thermal recovery method called steam-assisted gravity drainage (SAGD).
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Increasing the accuracy of microseismic monitoring using surface patch arrays and a novel processing approach
Authors P.-F. Roux, J. Kostadinovic, T. Bardainne, E. Rebel, M. Chmiel, M. Van Parys, R. Macault and L. PignotP.-F. Roux, J. Kostadinovic, T. Bardainne, E. Rebel, M. Chmiel, M. Van Parys, R. Macault and L. Pignot present an acquisition and processing technique to further decrease the noise recorded at the surface of the Earth when monitoring hydraulic stimulation. It is well known that fluid injection into reservoirs, be it in the context of enhanced geothermal systems or for the stimulation of hydrocarbon reservoirs, generates so-called ‘induced’ seismic activity (Evans, 1966). Early on, the link between the stimulation and this activity has been established, and it has become increasingly obvious that measuring the microseismicity generated by the injection would provide a wealth of information on the mechanical processes at work during the stimulation. Historically, downhole geophone tools have been used to monitor microseismic activity during stimulation programmes. Such tools usually offer a very high sensitivity to the microseismic sources, provided that the observation well is close enough to the treated well (Rutledge and Phillips, 2003). However, this becomes limited when more information on the source mechanism (usually termed focal mechanism and represented by the infamous moment tensor) is required. This is because of the three-dimensional nature of the focal mechanism, which means it cannot be retrieved properly using a single observation point. In addition, a poorly situated observation well may indeed lead to a reduced detection capability.
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Characterization of hitherto unseen reservoirs: a case study of lithology and fluid prediction using seismic QI
Authors F. Tsuneyama, K. Takahara, A. Nagatomo, K. Tanioka, M. Enomoto and T. NishizukaAfter encountering a couple of gas zones in Well-1X, Idemitsu applied the in-house techniques to the 2D seismic lines across Well-1X to investigate the character of gas-bearing reservoirs in angle-stack seismic and obtained a clue to differentiate the target reservoirs from shale background. Subsequently, Idemitsu devised a specific AVO method to illuminate sandstone and carbonates reservoirs separately in the seismic data, namely ‘sandstone stack’ and ‘carbonate stack’ sections from angle gather, which resulted in revealing a series of potential reservoirs continuing intermittently below the bottom of Well-1X. Upon subsequent acquisition of 3D seismic, implementation of similar techniques provides the distributions of all the potential reservoirs on top of the detailed configuration of structures. This paper presents the representative seismic sections to demonstrate that the characters in lithology stacks, together with the extraction method of potential reservoirs using elastic-impedance-inversion, results in a Rock Physics Template (herein after, RPT). The discussion includes the rock physics properties of those reservoirs linking to why and how the properties reflect into seismic characters.
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How seismic anisotropy improves the reliability of exploration DHI (AVO)
Authors M. Ferla, F. de Finis and R. BacenettiOver the past two decades seismic anisotropy has increased its role in many seismic processing and inversion workflows. The inadequacy of an isotropic velocity model has been emphasized in prestack depth migration (PSDM), which is highly sensitive to the accuracy of the velocity field. Moreover the correct characterization of the anisotropic elastic properties of subsurface formations is fundamental for the identification of explorative targets. In this paper, we discuss an example of integrated workflow based on anisotropic Thomsen’s parameters estimation, velocity and AVO models. We present interesting results of modelling for special cases of exploration interest, highlighting the anisotropic effects for gas sands embedded in shales. Our approach has been applied to a real dataset, confirming the importance of models that account for the seismic anisotropy. We demonstrate that anisotropy is the physical factor that could explain the inability of elastic synthetics to match the prestack amplitudes of field data in some cases. These considerations led to more realistic reservoir models and explained some pitfalls in AVO interpretation.
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Volumes & issues
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Volume 42 (2024)
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Volume 41 (2023)
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Volume 40 (2022)
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Volume 39 (2021)
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Volume 38 (2020)
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Volume 37 (2019)
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Volume 36 (2018)
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Volume 35 (2017)
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Volume 34 (2016)
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Volume 33 (2015)
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Volume 32 (2014)
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Volume 31 (2013)
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Volume 30 (2012)
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Volume 29 (2011)
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Volume 28 (2010)
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Volume 27 (2009)
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Volume 26 (2008)
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Volume 25 (2007)
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Volume 24 (2006)
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Volume 23 (2005)
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Volume 22 (2004)
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Volume 21 (2003)
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Volume 20 (2002)
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Volume 19 (2001)
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Volume 18 (2000)
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Volume 17 (1999)
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Volume 16 (1998)
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Volume 15 (1997)
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Volume 14 (1996)
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Volume 13 (1995)
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Volume 12 (1994)
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Volume 11 (1993)
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Volume 10 (1992)
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Volume 9 (1991)
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Volume 8 (1990)
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Volume 7 (1989)
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Volume 6 (1988)
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Volume 5 (1987)
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Volume 4 (1986)
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Volume 3 (1985)
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Volume 2 (1984)
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Volume 1 (1983)