Michael Myers

Stress And Pore-pressure Dependence of Sound Velocities In Shales: Poroelastic Effects In Time- Lapse Seismic

We have measured the stress, stress-path, and pore-pressure dependence of p-wave velocities of different shales. In good approximation, for small deformations, vertical velocity changes are proportional to changes in vertical effective stress. For low-permeability, undrained formations such as shales, it has been well established that pore pressures change as a function of mean-total stress changes and deviatoric stress changes. Analytical and finite-element geomechanical modeling, for a linear-elastic, isotropic half space, demonstrate that a ubiquitous porepressure increase in the low-permeability non-producing formations accompanies depletion of an adjacent reservoir. This pore pressure increase results in positive seismic timelapse time shifts in the overand underburden and may nearly cancel the negative time shifts due to archinginduced total vertical stress increase in the sideburden. Thus, poroelastic effects might offer an alternative explanation for the observation of mostly positive time shifts in time-lapse seismic, which was previously attributed to an asymmetric velocity-strain dependence for loading and unloading.

Application of Multiple Imaging Tools for Organic Material Characterization in Shale Reservoirs

Vitrinite reflectance and Rock-Eval pyrolysis (Tmax) are the two standard techniques applied to determine source rock maturity. For samples with small volumes of organic material (OM), or for high maturity samples, or where vitrinite is rare to absent (e.g. pre-Silurian rocks which do not have vitrinite macerals), the application of these techniques is difficult. Additionally, in organic rich source rocks vitrinite is rare, making reflectance analysis non-robust. Because of these difficulties, there is a need for new methods to accurately characterize of shale kerogen thermal maturity.

Multi-modal SEM Imaging for Shale Reservoir Characterization

Recent advances in imaging technologies have allowed us to interrogate materials at progressively higher resolutions over larger areas or volumes of sample. As we have begun to investigate geomaterials at resolutions on the single nanometer scale, our observations have upended several long-lived paradigms of geoscience. This has proved particularly true in shale reservoirs. Although it is fascinating to continue to look more deeply into these reservoirs, we are also faced with three daunting challenges. The first involves development of standard protocols for imaging. As we push the limits of our imaging tools, the details of sample preparation, the composition and thickness of conductive coatings, the configuration of the electron column, the excitation voltage and choice of electron signal to use for imaging, and the preand post-processing of image data all influence the results of our analyses. The second challenge involves the processing of extremely large volumes of image data. Individual images can be larger than 100 gigabytes in size, too large for many of the existing tools for image analysis to open and segment. The third challenge, involves the upscaling of our observations from the nanometer scale of the pore space to the vertical thickness of the formation (hundreds of meters) and the basin scale (hundreds of kilometers). This paper presents an evaluation of how the details of sample preparation, image acquisition, and image processing influence the results of porosity and Total Organic Carbon (TOC) analysis from SEM image data in shale reservoirs.

Organic Matter Characterization in Shales: A Systematic Empirical Protocol

Increased economic interest in shale oil and gas has prompted new exploration in shale reservoirs. This has catalyzed new research into how storage and delivery work in tight gas sands and shales. Focusing on the organic matter (OM) present in the shales we have developed a process enabling us to study changes in OM before and after heating and extraction using various solvents in the laboratory. We compare the changes in OM during laboratory heating and extraction to observations made on subsurface samples at varying maturity. The OM was characterized using a Field Emission Scanning Electron Microscope (FE-SEM) at various imaging voltages as deemed necessary.

Uniaxial Complex Relative Permittivity Tensor Measurement of Rocks From 40 Hz to 4.5 GHz

We develop a set of combined measurement techniques and calculation workflows to determine the complex uniaxial dielectric tensor of a rock sample from 40 Hz to 4.5 GHz. This unique method provides the ability to develop interpretation models bridging electrical logging tools with their corresponding operational frequencies and measurement direction. It further highlights the presence and importance of accounting for electrical anisotropy dispersion in formation evaluation. This permits the industry to initiate the desired electrical logging programs and apply appropriate borehole raw data corrections. The required workflow utilizes three measurement systems, which when combined result in measuring the electrical dispersion over a broad frequency range in the radial and axial directions on the same vertical rock sample. The measurement process is grouped into a high-frequency device from 10 MHz to 4.5 GHz and a low-frequency system from 40 Hz to 100 MHz. The high frequency is a two-port coax to circular waveguide and is described in this paper for measuring broadband data of dielectric dispersion properties of reservoir rocks in both anisotropic directions. The low frequency consists of combining both parallel plate capacitor and one-port coax with a circular waveguide terminated by a short (0

Use of cutting velocities for real time pore pressure and fracture gradient prediction

\Omega

Measuring compaction and compressibilities in unconsolidated reservoir materials via time-scaling creep

) or open (infinite ohms) to obtain dispersion curves in both the axial and radial directions. The theoretical basis of each of the above systems is described. Two reservoir rocks are tested and their results are reported. In conclusion, the added value this laboratory capability presents will yield a higher quality of borehole data and a more quantitatively accurate petrophysical interpretation.