Seismic Sensitivity to Variations of Rock Properties in the Productive Zone of the Marcellus Shale, WV

Seismic Sensitivity to Variations of Rock Properties in the Productive Zone of the Marcellus Shale, WV
Author: Sharif Munjur Morshed
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Total Pages: 0
Release: 2013
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The Marcellus Shale is an important resource play prevalent in several states in the eastern United States. The productive zone of the Marcellus Shale has variations in rock properties such as clay content, kerogen content and pore aspect ratio, and these variations may strongly effect elastic anisotropy. The objective of this study is to characterize surface seismic sensitivity for variations in anisotropic parameters relating to kerogen content and aspect ratio of kerogen saturated pores. The recognized sensitivity may aid to characterize these reservoir from surface seismic observations for exploration and production of hydrocarbon. In this study, I performed VTI anisotropic modeling based on geophysical wireline log data from Harrison County, WV. The wireline log data includes spectral gamma, density, resistivity, neutron porosity, monopole and dipole sonic logs. Borehole log data were analyzed to characterize the Marcellus Shale interval, and quantify petrophysical properties such as clay content, kerogen content and porosity. A rock physics model was employed to build link between petrophysical properties and elastic constants. The rock physics model utilized differential effective medium (DEM) theory, bounds and mixing laws and fluid substitution equations in a model scheme to compute elastic constants for known variations in matrix composition, kerogen content and pore shape distribution. The seismic simulations were conducted applying a vertical impulse source and three component receivers. The anisotropic effect to angular amplitude variations for PP, PS and SS reflections were found to be dominantly controlled by the Thomsen [epsilon] parameter, characterizing seismic velocity variations with propagation direction. These anisotropic effect to PP data can be seen at large offset (>15° incidence angle). The most sensitive portion of PS reflections was observed at mid offset (15°-30°). I also analyzed seismic sensitivity for variations in kerogen content and aspect ratio of structural kerogen. Elastic constants were computed for 5%, 10%, 20% and 30% kerogen content from rock physics model and provided to the seismic model. For both kerogen content and aspect ratio model, PP amplitudes varies significantly at zero to near offset while PS amplitude varied at mid offsets (12 to 30 degree angle of incidences).

Rock-physics and 3C-3D Seismic Analysis for Reservoir Characterization

Rock-physics and 3C-3D Seismic Analysis for Reservoir Characterization
Author: Fabiola Del Valle Ruiz Pelayo
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Total Pages:
Release: 2016
Genre: Geophysics
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The elastic properties (density and velocity) of organic shales are largely controlled by kerogen content, porosity, clay content, and e ective pressure. Since surface-seismic measurements can have a complicated dependence on rock properties, it is essential to understand the relationship between the elastic response and variations in rock properties to correctly assess the target reservoir. In this sense, a combination of rock-physics and seismic modeling is applied to relate variations in key properties, such as kerogen content and porosity, to di erences in the elastic response of a 3C-3D seismic volume in the Marcellus Shale (Bradford County, Pennsylvania). Well log analysis and rock physics modeling indicate that density is more sensitive to kerogen content than Vp/Vs or P impedance. Organic-rich intervals (kerogen content > 6 wt. %) are characterized by densities lower than 2.5 g/cc. Vp/Vs and P-impedance are more sensitive to variations in clay content than density; Vp/Vs values lower than 1.6 are attached to clay content lower than 25 %. The interplay between mineralogy and kerogen content causes an increase in velocity in the organic-rich interval, where the e ect of kerogen on the elastic moduli seems to be masked by a decrease in clay content and increase in quartz and calcite. Elastic AVA modeling shows that the sensitivity to the presence of the organic-rich facies increases with angle for both PP and PS (converted-wave) reflections. Additionally, the compressibility seems to be more sensitive to the organic-rich facies than the rigidity. A comparison between PP and PP-PS inversions show that the addition of PS data decreases the P-impedance, S-impedance and density estimation errors by 58, 80, and 17 %, respectively. We used this procedure to create 3D-density maps to indicate promising reservoir quality. These predictions suggest good reservoirs where two gas wells (not used in the analysis) are producing.

Sensitivity of Seismic Response to Variations in the Woodford Shale, Delaware Basin, West Texas

Sensitivity of Seismic Response to Variations in the Woodford Shale, Delaware Basin, West Texas
Author: Na Shan
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Total Pages: 212
Release: 2010
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The Woodford Shale is an important unconventional oil and gas resource. It can act as a source rock, seal and reservoir, and may have significant elastic anisotropy, which would greatly affect seismic response. Understanding how anisotropy may affect the seismic response of the Woodford Shale is important in processing and interpreting surface reflection seismic data. The objective of this study is to identify the differences between isotropic and anisotropic seismic responses in the Woodford Shale, and to understand how these anisotropy parameters and physical properties influence the resultant synthetic seismograms. I divide the Woodford Shale into three different units based on the data from the Pioneer Reliance Triple Crown #1 (RTC #1) borehole, which includes density, gamma ray, resistivity, sonic, dipole sonic logs, part of imaging (FMI) logs, elemental capture spectroscopy (ECS) and X-ray diffraction (XRD) data from core samples. Different elastic parameters based on the well log data are used as input models to generate synthetic seismograms. I use a vertical impulsive source, which generates P-P, P-SV and SV-SV waves, and three component receivers for synthetic modeling. Sensitivity study is performed by assuming different anisotropic scenarios in the Woodford Shale, including vertical transverse isotropy (VTI), horizontal transverse isotropy (HTI) and orthorhombic anisotropy. Through the simulation, I demonstrate that there are notable differences in the seismic response between isotropic and anisotropic models. Three different types of elastic waves, i.e., P-P, P-SV and SV-SV waves respond differently to anisotropy parameter changes. Results suggest that multicomponent data might be useful in analyzing the anisotropy for the surface seismic data. Results also indicate the sensitivity offset range might be helpful in determining the location for prestack seismic amplitude analysis. All these findings demonstrate the potentially useful sensitivity parameters to the seismic data. The paucity of data resources limits the evaluation of the anisotropy in the Woodford. However, the seismic modeling with different type of anisotropy assumptions leads to understand what type of anisotropy and how this anisotropy affects the change of seismic data.

Seismic Reservoir Characterization of the Haynesville Shale

Seismic Reservoir Characterization of the Haynesville Shale
Author: Meijuan Jiang
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Total Pages: 0
Release: 2014
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This dissertation focuses on interpreting the spatial variations of seismic amplitude data as a function of rock properties for the Haynesville Shale. To achieve this goal, I investigate the relationships between the rock properties and elastic properties, and calibrate rock-physics models by constraining both P- and S-wave velocities from well log data. I build a workflow to estimate the rock properties along with uncertainties from the P- and S-wave information. I correlate the estimated rock properties with the seismic amplitude data quantitatively. The rock properties, such as porosity, pore shape and composition, provide very useful information in determining locations with relatively high porosities and large fractions of brittle components favorable for hydraulic fracturing. Here the brittle components will have the fractures remain opened for longer time than the other components. Porosity helps to determine gas capacity and the estimated ultimate recovery (EUR); composition contributes to understand the brittle/ductile strength of shales, and pore shape provides additional information to determine the brittle/ductile strength of the shale. I use effective medium models to constrain P- and S-wave information. The rock-physics model includes an isotropic and an anisotropic effective medium model. The isotropic effective medium model provides a porous rock matrix with multiple mineral phases and pores with different aspect ratios. The anisotropic effective medium model provides frequency- and pore-pressure-dependent anisotropy. I estimate the rock properties with uncertainties using grid searching, conditioned by the calibrated rock-physics models. At well locations, I use the sonic log as input in the rock-physics models. At areas away from the well locations, I use the prestack seismic inverted P- and S-impedances as input in the rock-physics models. The estimated rock properties are correlated with the seismic amplitude data and help to interpret the spatial variations observed from seismic data. I check the accuracy of the estimated rock properties by comparing the elastic properties from seismic inversion and the ones derived from estimated rock properties. Furthermore, I link the estimated rock properties to the microstructure images and interpret the modeling results using observations from microstructure images. The characterization contributes to understand what causes the seismic amplitude variations for the Haynesville Shale. The same seismic reservoir characterization procedure could be applied to other unconventional gas shales.

The Relationship Between the Taghanic Unconformity and Marcellus Shale Production in Doddridge and Ritchie Counties, West Virginia

The Relationship Between the Taghanic Unconformity and Marcellus Shale Production in Doddridge and Ritchie Counties, West Virginia
Author: Emily Adams
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Total Pages: 113
Release: 2016
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The Marcellus Shale, a geologic unit that extends from New York to West Virginia within the Appalachian region, is the source of trillions of cubic feet of natural gas due to organic-rich properties. The formation of the unit was coupled with a period of eustatic sea-level rise that resulted in reactivation of a peripheral bulge leading to the development of the Taghanic unconformity. Stratal variances such as thinning or removal of units within the region are predominately found within the Marcellus Shale as a result of the Taghanic unconformity. Most specifically, in West Virginia, the Taghanic unconformity dominates Marcellus Shale thickness deviations. Areas where thickness of the unit varies considerably are located within Doddridge and Ritchie counties. This project aids in understanding how stratigraphic thinning or removal of the Marcellus Shale in relation to hydrocarbon production differences between Doddridge and Ritchie counties, West Virginia may be a result of the Taghanic unconformity. Data are derived from log images obtained by the West Virginia Geological and Economic Survey that are correlated to establish the stratigraphy. This study shows the Middle Devonian Marcellus Shale thins from ~55-95 feet in the northeast to ~15-60 feet in the southwest of the counties. This is the result of depositional thinning of the lower Marcellus Shale and erosional removal of part of the upper Marcellus Shale. Additionally, the erosional boundary becomes more extensive towards the southwest. The average first 12 months of gas production from the Marcellus Shale indicates a larger quantity produced within Doddridge County (656,411 MCF) in comparison to Ritchie County (94,209 MCF). Variations in production values may be attributed to erosional features and thinning trends of the Marcellus Shale related to the Taghanic unconformity as well as additional factors such as gas extraction method, and reservoir properties.

Multicomponent 3D Seismic Interpretation of the Marcellus Shale Bradford County, Pennsylvania

Multicomponent 3D Seismic Interpretation of the Marcellus Shale Bradford County, Pennsylvania
Author: Mouna Gargouri
Publisher:
Total Pages:
Release: 2012
Genre: Geophysics
ISBN:
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High spatial variability of petrophysical and petrochemical properties of the Marcellus formation was reported by Hill et al. (2002). This creates a major challenge in reservoir characterization with conventional seismic data. An investigation into the potential of integrated compressional P-wave and converted-wave seismic interpretation, to help characterize geological properties of the Devonian Marcellus shale, has been conducted based on the 3C-3D data set acquired. Synthetic and real seismic data have been used to conduct this evaluation. Interval Vp/Vs analysis has been performed and the Poisson's ratio was generated to map lateral changes in lithology and rock properties. Sweet spots are interpreted to area with high quartz, an anomalous low Vp/Vs. The Vp/Vs Marcellus map shows the lateral lithological variability and therefore brittle areas. An inversion was run for the compressional P and the converted PS sections to examine the anomalies observed within the Vp/Vs map. The anomalies distinguished within the Vp/Vs map were noticeable in the inversion sections. The inversion was followed by a seismic attribute analysis to understand the distribution of fractures. The curvature and the coherency attributes delivered highly fractured area and major faults. This study documents the results of an integrated workflow of seismic interpretation, seismic inversion and seismic attribute analysis. It illustrates the potential of the Vp/Vs analysis to discriminate between shale-rich and sand-rich material and the ability of the curvature and coherency attribute to potentially highlight zones of intense fracturing.

Seismic Characterization of the Eagle Ford Shale Based on Rock Physics

Seismic Characterization of the Eagle Ford Shale Based on Rock Physics
Author: Ricardo Zavala-Torres
Publisher:
Total Pages:
Release: 2014
Genre: Geophysics
ISBN:
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The findings of this dissertation on seismic characterization of the Eagle Ford Shale based on rock physics using actual well-log data from productive and unproductive wells in Mexico can be immediately and effectively applied to avoid future failures and can be corroborated with current and new locations for exploration and production. It was found that basic sequence stratigraphy techniques developed for unconventional reservoirs can be applied to the case of the Eagle Ford Shale in Mexico. Using well log correlation and petrophysical techniques to estimate reservoir properties, it was concluded that the zone where the horizontal well was drilled at Montanes-1 was located above the condensed sequence, bypassing the pay zone below the maximum flooding surface in the transgressive system track. It is verified that the productive well Emergente-1 was drilled in the correct zone with hydrocarbon saturation at the transgressive system track below the maximum flooding surface. It was found that using mineral assessment methods to compute brittleness, and the proper geosteering analysis is a consistent approach for placement of future horizontals. Based on that, it is concluded that any estimation of rock physics and anisotropic parameters derived from well logs at the source rock interval will be deceiving and will give a false estimation. It was concluded that the isotropic rock physic model known as friable-sand or modified friable-shale (unconsolidated sand or unconsolidated shale), or most recently called “soft-sand model”, was proved to match the data better than any other rock physic model tested to predict velocity and density. The term “non-source rock model” will be used instead for the rock physic model because it is more consistent with the Eagle Ford Shale case analyzed here. For the orientation of maximum horizontal stress, it is concluded by integrating VSP, microseismic and borehole data, that a straight north-south orientation of future horizontals is needed in order to generate the fractures in the straight east-west azimuth correlating with the maximum horizontal stress orientation.

Multi-scale and Integrated Characterization of the Marcellus Shale in the Appalachian Basin

Multi-scale and Integrated Characterization of the Marcellus Shale in the Appalachian Basin
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Release: 2010
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Historic data from the Department of Energy Eastern Gas Shale Project (ESGP) were compiled to develop a database of geochemical analyses, well logs, lithological and natural fracture descriptions from oriented core, and reservoir parameters. The nine EGSP wells were located throughout the Appalachian Basin and intercepted the Marcellus Shale from depths of 750 meters (2500 ft) to 2500 meters (8200 ft). A primary goal of this research is to use these existing data to help construct a geologic framework model of the Marcellus Shale across the basin and link rock properties to gas productivity. In addition to the historic data, x-ray computerized tomography (CT) of entire cores with a voxel resolution of 240mm and optical microscopy to quantify mineral and organic volumes was performed. Porosity and permeability measurements in a high resolution, steady-state flow apparatus are also planned. Earth Vision software was utilized to display and perform volumetric calculations on individual wells, small areas with several horizontal wells, and on a regional basis. The results indicate that the lithologic character of the Marcellus Shale changes across the basin. Gas productivity appears to be influenced by the properties of the organic material and the mineral composition of the rock, local and regional structural features, the current state of in-situ stress, and lithologic controls on the geometry of induced fractures during stimulations. The recoverable gas volume from the Marcellus Shale is variable over the vertical stratigraphic section, as well as laterally across the basin. The results from this study are expected to help improve the assessment of the resource, and help optimize the recovery of natural gas.

Rock Properties, Seismic Modeling, and 3C Seismic Analysis in the Bakken Shale, North Dakota

Rock Properties, Seismic Modeling, and 3C Seismic Analysis in the Bakken Shale, North Dakota
Author: Andrea Gloreinaldy Paris Castellano
Publisher:
Total Pages:
Release: 2017
Genre: Geophysics
ISBN:
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A solid understanding of the factors that affect the seismic velocity and the amplitude variation with offset (AVO) is imperative for a reliable interpretation of seismic data and related prospect de‐risking. To understand the relationship between rock properties and their elastic response (i.e. velocity and density), petrophysical properties, rock‐physics, seismic modeling, and fluid substitution are analyzed. Seismic inversions and statistical predictions of rock properties are integrated to delimit prospective intervals and areas with high total organic carbon (TOC) content within the Bakken Formation, North Dakota. The shale intervals can be recognized by cross‐plotting well logs velocities versus density. The hydrocarbon potential is observed on logs as low densities, high gamma‐ray response, low P and S‐wave velocities, and high neutron porosities. Organicrich intervals with TOC content higher than 10 wt. % deviate from the ones that have lower TOC in the density domain, and exhibit slightly lower velocities, lower densities ( 2.3 g/cc), and a generally higher shale content ( 40%). Within the study area, Well V‐1 shows the highest TOC content, especially at the Upper Bakken depths with approximately 50% of clay volume. TOC is considered to be the principal factor affecting changes in density and P and S‐wave velocities in the Bakken shales. Vp/Vs ranges between 1.65 and 1.75. Synthetic seismic data are generated using the anisotropic version of Zoeppritz equations including estimated Thomsen parameters. For the tops of Upper and Lower Bakken, the amplitude becomes less negative with offset showing a negative intercept and a positive gradient which correspond to an AVO Class IV. A comparison between PP and PP‐PS joint inversions shows that the P‐impedance error decreases by 14% when incorporating the converted‐wave information in the inversion process. A statistical approach using multi‐attribute analysis and neural networks allows to delimit the zones of interest in terms of P‐impedance, density, TOC content, and brittleness. The inverted and predicted results show fair correlations with the original well logs. The integration between well‐log analysis, rock‐physics, seismic modeling, constrained inversions and statistical predictions contribute in identifying the vertical distribution of good reservoir quality areas within the Bakken Formation.