Reservoir Characterization of the Haynesville Shale, Panola County, Texas Using Rock Physics Modeling and Partial Stack Seismic Inversion
Reservoir Characterization of the Haynesville Shale, Panola County, Texas Using Rock Physics Modeling and Partial Stack Seismic Inversion

Author: Sarah Bryson Coyle

Publisher:

Published: 2014

Total Pages: 186

ISBN-13:

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This thesis investigates the relationship between elastic properties and rock properties of the Haynesville Shale using rock physics modeling, simultaneous seismic inversion, and grid searching. A workflow is developed in which a rock physics model is built and calibrated to well data in the Haynesville Shale and then applied to 3D seismic inversion data to predict porosity and mineralogy away from the borehole locations. The rock physics model describes the relationship between porosity, mineral composition, pore shape, and elastic stiffness using the anisotropic differential effective medium model. The calibrated rock physics model is used to generate a modeling space representing a range of mineral compositions and porosities with a calibrated mean pore shape. The model space is grid searched using objective functions to select a range of models that describe the inverted P-impedance, S-impedance, and density volumes. The selected models provide a range of possible rock properties (porosity and mineral composition) and an estimate of uncertainty. The mineral properties were mapped in three dimensions within the area of interest using this modeling technique and inversion workflow. This map of mineral content and porosity can be interpreted to predict the best areas for hydraulic fracturing.

Anisotropic Analysis and Fracture Characterization of the Haynesville Shale, Panola County, Texas
Anisotropic Analysis and Fracture Characterization of the Haynesville Shale, Panola County, Texas

Author: Anthony William Barone

Publisher:

Published: 2015

Total Pages: 358

ISBN-13:

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In unconventional resources such as the Haynesville Shale, a proper understanding of natural fracture patterns is essential to enhancing the economic success of petroleum extraction. The spatial density of naturally occurring fracture sets affects drainage area and optimal drilling location(s), and the azimuth of the strike of the predominant fracture set affects the ideal orientation of wells. In the absence of data to directly determine these fracture characteristics, such as Formation Microimaging (FMI) logs, these natural fracture patterns can be analyzed by examining the seismic anisotropy present in the reservoir. Anisotropy introduced from aligned fracture sets creates predictable azimuthal variations in the seismic wavefield. This allows the reservoir anisotropy, and thus the fracturing present in the reservoir, to be studied indirectly through the azimuthal analysis of industry standard 3D seismic data. The work presented here outlines three distinct methodologies, which utilize azimuthal amplitude variations (AVAZ) present in 3D seismic data, to infer fracture characteristics without the need for substantial well log information. Two of these methods have been previously established and assume the reservoir to be characteristic of Horizontally Transverse Isotropic (HTI). The last method is novel and assumes orthorhombic anisotropy when inverting for fracture density and is able to unambiguously invert for fracture azimuth. All methodologies used in this work produced similar results, increasing confidence in the accuracy of these results through statistical repeatability. Fracture density inversion results indicate spatially varying fracture density throughout the area, with a distinct area of higher fracture density present in the Northwestern corner of the area analyzed. Spatially varying fracture density and localized pockets of fracturing is consistent with expectation from analyzing production data and FMI logs from other areas of the Haynesville. Fracture azimuth inversion results showed some variability; however, the novel method presented in this thesis indicates that the azimuth of the predominant fracture set is oriented at a compass bearing of approximately 82 degrees -- rotated slightly counterclockwise from an east-west orientation. Fracture azimuth results agree well with expectations from a regional stress analysis and from examining comparable formations with known fracture patterns in the surrounding area.

Reservoir Characterization and History Matching with Uncertainty Quantification Using Ensemble-based Data Assimilation with Data Re-parameterization
Reservoir Characterization and History Matching with Uncertainty Quantification Using Ensemble-based Data Assimilation with Data Re-parameterization

Author: Mingliang Liu

Publisher:

Published: 2021

Total Pages: 153

ISBN-13:

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Reservoir characterization and history matching are essential steps in various subsurface applications, such as petroleum exploration and production and geological carbon sequestration, aiming to estimate the rock and fluid properties of the subsurface from geophysical measurements and borehole data. Mathematically, both tasks can be formulated as inverse problems, which attempt to find optimal earth models that are consistent with the true measurements. The objective of this dissertation is to develop a stochastic inversion method to improve the accuracy of predicted reservoir properties as well as quantification of the associated uncertainty by assimilating both the surface geophysical observations and the production data from borehole using Ensemble Smoother with Multiple Data Assimilation. To avoid the common phenomenon of ensemble collapse in which the model uncertainty would be underestimated, we propose to re-parameterize the high-dimensional geophysics data with data order reduction methods, for example, singular value decomposition and deep convolutional autoencoder, and then perform the models updating efficiently in the low-dimensional data space. We first apply the method to seismic and rock physics inversion for the joint estimation of elastic and petrophysical properties from the pre-stack seismic data. In the production or monitoring stage, we extend the proposed method to seismic history matching for the prediction of porosity and permeability models by integrating both the time-lapse seismic and production data. The proposed method is tested on synthetic examples and successfully applied in petroleum exploration and production and carbon dioxide sequestration.

Stratigraphic Reservoir Characterization for Petroleum Geologists, Geophysicists, and Engineers
Stratigraphic Reservoir Characterization for Petroleum Geologists, Geophysicists, and Engineers

Author: Roger M. Slatt

Publisher: Elsevier Inc. Chapters

Published: 2013-11-21

Total Pages: 87

ISBN-13: 012808278X

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Certain parts of this chapter have been taken directly from the publication Important geological properties of unconventional resource shales, by Roger M. Slatt, published in the fourth-quarter issue of the Central European Journal of Geosciences (2011). The journal’s permission to reproduce those parts of that paper here is gratefully acknowledged.

Stratigraphic Reservoir Characterization for Petroleum Geologists, Geophysicists, and Engineers
Stratigraphic Reservoir Characterization for Petroleum Geologists, Geophysicists, and Engineers

Author: Roger M. Slatt

Publisher: Elsevier Inc. Chapters

Published: 2013-11-21

Total Pages: 105

ISBN-13: 0128082704

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There are many tools and techniques for characterizing oil and gas reservoirs. Seismic-reflection techniques include conventional 2D and 3D seismic, 4D time-lapse seismic, multicomponent seismic, crosswell seismic, seismic inversion, and seismic attribute analysis, all designed to enhance stratigraphy/structure detection, resolution, and characterization. These techniques are constantly being improved. Drilling and coring a well provides the “ground truth” for seismic interpretation. Rock formations are directly sampled by cuttings and by core and indirectly characterized with a variety of conventional and specialized well logs. To maximize characterization and optimize production, many of these tools as possible should be employed. It is often less expensive to utilize a wide variety of tools that directly image or measure reservoir properties at different scales than to drill one or two dry holes.

Reservoir Characterization II
Reservoir Characterization II

Author: Larry W. Lake

Publisher: Academic Press

Published: 1991-04-28

Total Pages: 752

ISBN-13:

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Intended for petroleum engineers, geologists and hydrologists, this book provides a detailed survey of the current practices, problems, research and trends in the field of reservoir characterization. Topics discussed include mesoscopic, macroscopic and megascopic scales.

Stratigraphic reservoir characterization for petroleum geologists, geophysicists, and engineers
Stratigraphic reservoir characterization for petroleum geologists, geophysicists, and engineers

Author: Roger M. Slatt

Publisher: Elsevier

Published: 2006-11-03

Total Pages: 493

ISBN-13: 0080466818

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Reservoir characterization as a discipline grew out of the recognition that more oil and gas could be extracted from reservoirs if the geology of the reservoir was understood. Prior to that awakening, reservoir development and production were the realm of the petroleum engineer. In fact, geologists of that time would have felt slighted if asked by corporate management to move from an exciting exploration assignment to a more mundane assignment working with an engineer to improve a reservoir’s performance. Slowly, reservoir characterization came into its own as a quantitative, multidisciplinary endeavor requiring a vast array of skills and knowledge sets. Perhaps the biggest attractor to becoming a reservoir geologist was the advent of fast computing, followed by visualization programs and theaters, all of which allow young geoscientists to practice their computing skills in a highly technical work environment. Also, the discipline grew in parallel with the evolution of data integration and the advent of asset teams in the petroleum industry. Finally, reservoir characterization flourished with the quantum improvements that have occurred in geophysical acquisition and processing techniques and that allow geophysicists to image internal reservoir complexities.

Reservoir Characterization Using Laboratory Ultrasonic Rock Physics
Reservoir Characterization Using Laboratory Ultrasonic Rock Physics

Author: Ganiyat Oluwaseun Shodunke

Publisher:

Published: 2021

Total Pages: 0

ISBN-13:

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The quantity of hydrocarbon recovered from a carbonate reservoir varies depending on the quality (i.e., porosity, permeability, reservoir volume) of that reservoir, indirectly characterized from the elastic properties encoded in the seismic reflection data. Due to the complexity of carbonates, they require repeated updating of characterization and modeling during production. This creates added cost to well drilling but provides significant return in terms of decisive field development plans and knowledge of productive and nonproductive hydrocarbon zones. The purpose of this study is to understand the effects of pore-fluid composition on the elastic properties of the Viola formation reservoir found in Kansas, Oklahoma, and Texas, and implications for utilization of seismic data attributes in optimizing reservoir studies and guiding field development efforts. Rock physics experiments such as lab ultrasonic experiments and fluid replacement experiments integrated with seismic fluid replacement modeling were used to pursue a thorough understanding of the carbonate reservoir properties. Brine, oil, and water were injected into the carbonate rock during the fluid replacement experiment and ultrasonic waves were propagated through the rock to obtain Primary P wave velocity, Secondary S wave velocity, and elastic parameters such as Young's modulus, Shear (Rigidity) modulus, Bulk modulus, and Poisson's ratio. These parameters were also recorded for the rock under dry conditions, and they provided useful information about the seismic wave's response to fluids and lithofacies changes in the Viola carbonate rock. There was a noticeable response change in amplitude and some change in velocity and impedance of the wave traveling through the Viola limestone formation with the presence of and type of fluid present. Higher amplitudes and faster velocities were observed for dry rock wave signals, while lower amplitudes and slower velocities were recorded for brine and oil-saturated rock wave signals. The recorded results on the Viola cores were in accordance with previously observed Gassmann fluid replacement modeling results (Cimino, 2020) from the Viola well log data and seismic amplitude analysis (Vohs, 2016) from the Viola seismic data.