Trace‐based and geostatistical inversion of 3‐D seismic data for thin‐sand delineation: An application to San Jorge Basin, Argentina

Torres‐Verdín, Carlos; Victoria, Marcos; Merletti, Germán; Pendrel, John

doi:10.1190/1.1820826

Cited by 9 publications

(9 citation statements)

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“…The ensuing estimation technique was referred to as geostatistical seismic inversion. Further developments of Haas and Dubrule's (1994) work can be found in the open technical literature (Debeye et al, 1996;Pendrel and van Riel, 1997;Torres-Verdín et al, 1999;Grijalba et al, 2000). Torres-Verdín et al (2000) compared standard geostatistical estimation techniques with geostatistical inversion of post-stack seismic data for reservoir delineation.…”

Section: A11 Problem Statementmentioning

confidence: 99%

“…A way to improve the vertical resolution of seismic amplitudes is to perform inversion (Sams et al, 1999;Torres-Verdín et al, 1999). The latter procedure can substantially reduce wavelet effects and hence deliver elastic parameters with a closer connection to petrophysical parameters than seismic amplitudes.…”

Section: A33 Using Inversion To Improve Seismic Amplitude Resolutionmentioning

confidence: 99%

“…Improvements and applications of this approach can be found in Debeye et al (1996), Pendrel andvan Riel (1997), Torres-Verdín et al (1999), andGrijalba et al (2000).…”

Section: A62 Background and Formulationmentioning

confidence: 99%

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Integrated Approach for the Petrophysical Interpretation of Post-and Pre-Stack 3-D Seismic Data, Well-Log Data, Core Data, Geological Information and Reservoir Production Data via Bayesian Stochastic Inversion

Torres‐Verdín¹,

Sen²

2004

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The present report summarizes the work carried out between September 30, 2000 and September 30, 2004 under DOE research contract No. DE-FC26-00BC15305. During the three-year project period, we carried out extensive studies on the inversion post-stack and pre-stack data together with well logs, petrophysical information and fluid flow data. We have achieved all the project goals including development of algorithm for joint inversion of pre-stack seismic data, well logs, and time records of fluid production measurements using stochastic inversion algorithms which were demonstrated on realistic synthetic and field data. Our accomplishments are:• Joint inversion of post-stack seismic, well log, fluid flow, and petrophysical data: we demonstrated the technique with application to data from the Gulf of Mexico.• Development of a robust pre-stack full waveform inversion algorithm: A new approach based on iteration-adaptive regularization that makes use of plane wave transformed seismic data, was developed and applied to OBC dataset from the Gulf of Thailand. The algorithm was also implemented on a cluster of personal computers.• Joint inversion of pre-stack seismic and well-log data: A new stochastic optimization algorithm that makes use of the essential features of seismic and well log data was developed and tested on realistic synthetic dataset.• Joint inversion of pre-stack seismic and fluid flow data: A novel technique was developed to optimally combine seismic and flow data. The technique makes very realistic estimate of porosity; sensitivity of the flow parameters to two disparate datasets was studied extensively. DE-FC26-00BC15305iv • Direct estimation of petrophysical parameters from seismic data: The pre-stack waveform inversion was modified to invert directly for porosity and saturation using the BiotGassmann equation at each iteration step.The final report contains abridged versions of some of our inventions. The works resulted in several peer-reviewed publications. Five papers have been communicated for peer-reviewed publication, and seven papers were presented at conferences. All of these publications and presentations stemmed from work directly related to the goals of our DOE project.

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Section: A11 Problem Statementmentioning

confidence: 99%

Section: A33 Using Inversion To Improve Seismic Amplitude Resolutionmentioning

confidence: 99%

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Integrated Approach for the Petrophysical Interpretation of Post-and Pre-Stack 3-D Seismic Data, Well-Log Data, Core Data, Geological Information and Reservoir Production Data via Bayesian Stochastic Inversion

Torres‐Verdín¹,

Sen²

2004

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“…These estimates are subsequently extrapolated away from wells via geostatistical techniques and upscaling procedures that yield a cellular reservoir model amenable to numerical simulation of multiphase fluid flow. Extrapolation of petrophysical parameters away from wells in some instances can be performed with the use of static seismic amplitude data, as done with geostatistical inversion (Torres-Verdín et al 1999). More recently, time-lapse seismic amplitude data have been acquired and interpreted to gain insight into the dynamic behaviour of producing hydrocarbon reservoirs (Al-Najjar et al 1999, Cooper et al 1999, Behrens et al 2001, Merkel et al 2001, Cominelli et al 2002, MacBeth et al 2005.…”

Section: Introductionmentioning

confidence: 99%

Using time-lapse seismic amplitude data to detect variations of pore pressure and fluid saturation due to oil displacement by water: a numerical study based on one-dimensional prestack inversion

Varela¹,

Torres‐Verdín²,

Sen³

et al. 2006

J. Geophys. Eng.

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We describe a numerical study performed to appraise the ability of seismic amplitude data to infer the time evolution of pore pressure and fluid saturation due to hydrocarbon production. To this end, we construct a synthetic, spatially heterogeneous hydrocarbon reservoir model that is subject to numerical simulation of multiphase fluid flow. Hydrocarbon production is assumed in the form of one water-injection well and four oil-producing wells. The synthetic reservoir model exhibits average porosities of 20% and poses significant vertical resolution constraints to the usage of seismic amplitude data to ascertain variations of pore pressure and fluid saturation. We assume the availability of migrated prestack seismic amplitude and use one-dimensional models to simulate trace by trace the seismic amplitude data before and after the onset of production. One-dimensional seismic amplitude data are simulated in time-lapse mode making use of a rock physics model that includes the effect of differential compaction between sands and shales as a function of depth of burial. The sensitivity study presented in this paper is based on one-dimensional inversion and hence sheds light on the vertical resolution properties of noisy seismic amplitude data. Multiphase fluid-flow parameters have a measurable impact on fluid saturation and pore pressure and hence on the spatial distribution and time evolution of elastic parameters. However, the inverted spatial distributions of elastic parameters at best correlate with smooth spatial averages of the actual distributions of pore pressure and fluid saturation. Because for the case under consideration time-lapse seismic amplitude variations are of the order of 5%, such a correlation would be difficult, if not impossible, to ascertain without the use of one-dimensional inversion. We show that the elastic parameters inverted from prestack seismic amplitude data provide more degrees of freedom to discriminate between time variations of pore pressure and fluid saturation in the reservoir compared to distributions of acoustic impedance inverted from poststack seismic amplitude data.

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“…Reflections result from the convolution of a source wavelet with a reflection coefficient, thus representing the boundary between two layers instead of the layer properties. Seismic inversion, which minimizes tuning effects or takes tuning effects into consideration, appears to provide a more robust approach for characterizing thin-bed reservoirs and is the subject of ongoing research (Salleh et al, 1999;Torres-Verdin et al, 1999;Riel, 2000;Pennington, 2001).…”

Section: Introductionmentioning

confidence: 99%

Calibration of Seismic Attributes for Reservoir Characterization

Pennington¹

2002

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The project, "Calibration of Seismic Attributes for Reservoir Calibration," is now complete. Our original proposed scope of work included detailed analysis of seismic and other data from two to three hydrocarbon fields; we have analyzed data from four fields at this level of detail, two additional fields with less detail, and one other 2D seismic line used for experimentation. We also included time-lapse seismic data with ocean-bottom cable recordings in addition to the originally proposed static field data. A large number of publications and presentations have resulted from this work, inlcuding several that are in final stages of preparation or printing; one of these is a chapter on "Reservoir Geophysics" for the new Petroleum Engineering Handbook from the Society of Petroleum Engineers.Major results from this project include a new approach to evaluating seismic attributes in timelapse monitoring studies, evaluation of pitfalls in the use of point-based measurements and facies classifications, novel applications of inversion results, improved methods of tying seismic data to the wellbore, and a comparison of methods used to detect pressure compartments. Some of the data sets used are in the public domain, allowing other investigators to test our techniques or to improve upon them using the same data.From the public-domain Stratton data set we have demonstrated that an apparent correlation between attributes derived along 'phantom' horizons are artifacts of isopach changes; only if the interpreter understands that the interpretation is based on this correlation with bed thickening or thinning, can reliable interpretations of channel horizons and facies be made. From the publicdomain Boonsville data set we developed techniques to use conventional seismic attributes, including seismic facies generated under various neural network procedures, to subdivide regional facies determined from logs into productive and non-productive subfacies, and we developed a method involving cross-correlation of seismic waveforms to provide a reliable map of the various facies present in the area. The Wamsutter data set led to the use of unconventional attributes including lateral incoherence and horizon-dependent impedance variations to indicate regions of former sand bars and current high pressure, respectively, and to evaluation of various upscaling routines. The Teal South data set has provided a surprising set of results, leading us to develop a pressure-dependent velocity relationship and to conclude that nearby reservoirs are undergoing a pressure drop in response to the production of the main reservoir, implying that oil is being lost through their spill points, never to be produced. Additional results were found using the public-domain Waha and Woresham-Bayer data set, and some tests of technologies were made using 2D seismic lines from Michigan and the western Pacific ocean.

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Trace‐based and geostatistical inversion of 3‐D seismic data for thin‐sand delineation: An application to San Jorge Basin, Argentina

Cited by 9 publications

References 1 publication

Integrated Approach for the Petrophysical Interpretation of Post-and Pre-Stack 3-D Seismic Data, Well-Log Data, Core Data, Geological Information and Reservoir Production Data via Bayesian Stochastic Inversion

Integrated Approach for the Petrophysical Interpretation of Post-and Pre-Stack 3-D Seismic Data, Well-Log Data, Core Data, Geological Information and Reservoir Production Data via Bayesian Stochastic Inversion

Using time-lapse seismic amplitude data to detect variations of pore pressure and fluid saturation due to oil displacement by water: a numerical study based on one-dimensional prestack inversion

Calibration of Seismic Attributes for Reservoir Characterization

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