Elizabeth Diaz

3D Visualization and Classification of Pore Structure and Pore Filling in Gas Shales

Shale gas is a growing resource worldwide as many basins are being explored and produced. However, little is still known and understood about two key parameters in gas shales: the gas-filled porosity and permeability. Digital rock physics technique, presented in this paper, contains three basic steps: (a) 3D CT imaging at 200 nanometer resolution, and/or FIB-SEM (focused ion beam combined with SEM) imaging at 3-15 nanometer resolution (b) segmentation of the digital volume to quantitatively identify the components, including the mineral phases, organic-filled pores, and free-gas inclusions; and (c) computations of TOC (Total Organic Content), porosity, pore connectivity, and permeability in three axis. A number of gas shale samples have been used, to specifically analyze the pore systems. The characteristics including dual porosity, organics distribution, gas-filled porosity distribution, and how these properties relate to the maturity of the organic material. Pore geometries (pores filled either with organics or free gas) of these samples fall into the following categories: (a) relatively large (up to 4 micron) with poorly disconnected pores; (b) pores connected by very thin (down to 15 nanometers) conduits; (c) dual porosity system where the large pores are interconnected by large conduits and very thin conduits are interconnected and also connected to the large pores. Within each of these three categories, the pore space may be (a) completely filled with organics or (b) partially or completely filled with gas. The latter is of most interest as it is a gas source. In such systems we observe various geometries of pore space, including (a) disconnected pores floating in the organics and (b) connected pores within the organics. TOC, open pore volumes, as well as pore-space connectivity are not just qualitatively estimated from the images but quantitatively computed for a given sample. Our ongoing effort is to relate the quantitative patterns thus computed to the maturity of shale.

Shale Reservoir Properties from Digital Rock Physics

A majority of the whole core samples recovered in the US today come from shale reservoirs. A primary reasonnfor so much shale coring is that shale well log analysis requires rigorous core calibration to provide reliable datanfor reservoir quality, hydrocarbon-in-place, and hydraulic fracturing potential. However, the uncertainty inninterpreting shale well log data is sometimes matched or exceeded by the uncertainty observed in traditionalnmethods of analyzing core samples. Most commercial core analysis methods in use today were developednoriginally for sandstones and carbonates exceeding 1 millidarcy in permeability. High quality, organic-rich shalenon the other hand is usually lower than 0.001 millidarcy. This extremely low permeability creates substantialnchallenges for existing methods and has contributed to the rapid rise of a new approach to reservoir evaluationncalled Digital Rock Physics (DRP).nDRP merges three key technologies that have evolved rapidly over the last decade. One is high resolutionndiagnostic imaging methods that permit detailed examination of the internal structure of rock samples over a widenrange of scales. The second is advanced numerical methods for simulating complex physical phenomenon andnthe third is high speed, massively parallel computation using powerful graphical processing units (GPUs) thatnwere originally developed for computer gaming and animation.nBased on pore-scale images from a wide range of organic shales, it can be seen that organic material is presentnin a variety of forms. Three primary forms of organic matter are commonly observed; non-porous, spongy, andnpendular. Non-porous organic components fill all of the available non-mineral space leaving virtually no porositynor fluid flow path. Porous or “spongy” organic material is commonly encountered in thermally mature gas shales.nPendular organic material appears to fill the small inter-granular and grain contact regions, leaving open porenspace in the larger voids. These pore types are largely controlled by kerogen type and thermal maturity, and theynexert large influence on the porosity, permeability, and overall shale reservoir quality.

Shale Reservoir Properties From Digital Rock Physics

A majority of the whole core samples recovered in the US today come from shale reservoirs. The uncertainty in interpreting shale well log data is sometimes matched or exceeded by the uncertainty observed in traditional methods of analyzing core samples. Most commercial core analysis methods in use today were developed originally for sandstones and carbonates exceeding 1 millidarcy in permeability. High quality organic-rich shale on the other hand is usually lower than 0.001 millidarcy. This extreme low permeability creates substantial challenges for existing methods and has contributed to the rapid rise of a new approach to reservoir evaluation called Digital Rock Physics or DRP.