Robert Klimentidis

D tomographic data at various scales is increasingly available through the wide adoption of CT (Micro Computed Tomography) and FIB-SEM (Focused Ion Beam - Scanning Electron Microscopy) technologies. However, upscaling these observations is very challenging. This paper provides a template of an upscaling protocol between FIB-SEM data on a micron sized sample and CT data on the same sample region but at millimeter- scale. We use a Devonian North American shale rock fragment in our study. Due to the large scale variations in the pore structure and drastic petrophysical property heterogeneity, shale rocks are very challenging and costly to study as compared to rock samples from conventional reservoirs. Using CT with voxel resolution of tens of microns, we are able to identify different rock heterogeneities. A smaller sample from each distinct heterogeneity region is then digitized using FIB-SEM 3D imaging with voxel resolution of a few nanometers. Stokes flow at pore-scale is used to...

The objectives of this study are to characterize the distribution and production of gas and water within the Mesaverde basin-centered gas play in the Piceance Basin and to determine the extent by which they are affected by variations in hydrocarbon charge and basin hydrodynamics. Several approaches have been taken in this study to understand the distribution of fluids within the Mesaverde Group. They include (1) modeling gas generation within the Piceance Basin, (2) mapping the gross gas column based on mud-log shows, (3) mapping the distribution of wells with high water production, and (4) identifying reservoir zones with high water production. This work has been integrated with the regional stratigraphic framework and fracture distribution to understand their influence on the movement of fluids within the basin. The results of these studies indicate that the distribution of gas within the Mesaverde Group reflects both total gas yield and the ability of different sandstone bodies w...

Quantification of porosity types and sizes coupled with in-situ reservoir capillary pressure data allows one to estimate potential hydrocarbon pore volume in a hydrocarbon transition zone. Integration of this data with economic gas rate production and reservoir quality data (such as sandstone compositional and textural trends on a field or basin scale) can provide a tool to evaluate Conventional vs. Tight-Gas zones in a prospect.

Many currently producing shale-gas reservoirs are overmature oil-prone source rocks. Through burial and heating these reservoirs evolve from organic-matter-rich mud deposited in marine, lacustrine, or swamp environments. Key characterization parameters are: total organic carbon (TOC), maturity level (vitrinite reflectance), mineralogy, thickness, and organic matter type. Hydrogen-to-carbon (HI) and oxygen-to-carbon (OI) ratios are used to classify organic matter that ranges from oil-prone algal and herbaceous to gas-prone woody/coaly material. Although organic-matter-rich intervals can be hundreds of meters thick, vertical variability in TOC is high (<1–3 meters) and is controlled by stratigraphic and biotic factors. In general, the fundamental geologic building block of shale-gas reservoirs is the parasequence, and commonly 10's to 100's of parasequences comprise the organic-rich formation whose lateral continuity can be estimated using techniques and models developed for source rocks. Typical analysis techniques for shale-gas reservoir rocks include: TOC, X-ray diffraction, adsorbed/canister gas, vitrinite reflectance, detailed core and thin-section descriptions, porosity, permeability, fluid saturation, and optical and electron microscopy. These sample-based results are combined with full well-log suites, including high resolution density and resistivity logs and borehole images, to fully characterize these formations. Porosity, fluid saturation, and permeability derived from core can be tied to log response; however, several studies have shown that the results obtained from different core analysis laboratories can vary significantly, reflecting differences in analytical technique, differences in definitions of fundamental rock and fluid properties, or the millimeter-scale variability common in mudstones that make it problematic to select multiple samples with identical attributes. Porosity determination in shale-gas mudstones is complicated by very small pore sizes and, thus, large surface area (and associated surface water); moreover, smectitic clays that are commonly present in mud have interlayer water, but this clay family tends to be minimized in high maturity formations due to illitization. Finally, SEM images of ion-beam-milled samples reveal a separate nano-porosity system contained within the organic matter, possibly comprising >50% of the total porosity, and these pores may be hydrocarbon wet, at least during most of the thermal maturation process. A full understanding of the relation of porosity and gas content will result in development of optimized processes for hydrocarbon recovery in shale-gas reservoirs.