Methods Improve Shale Core Analysis

HOUSTON–The fundamental properties of gas shales make them virtually impossible to analyze with conventional core analysis methods or petrophysical models based on log data. This includes permeabilities in the tens to hundreds of nanoDarcies, low effective porosities (typically less than 10 percent), and high kerogen and clay contents. The tightness of the rock and the abundance of clay minerals and kerogen generally creates a number of technical challenges to core analysis. Permeability, effective porosity, and oil, water and gas saturations are fundamental reservoir properties for assessing in-place hydrocarbons, producibility and overall economics. In unconventional shale systems, porosities are very low and permeabilities are 100 to 1,000 times lower than what was considered “tight” only a few years ago. Since a fraction of a small number is even smaller, it follows that the oil, water and gas content in tight shale pore space is also very small. However, the abundance and volumetric extent of these plays are large. Some twothirds of the sedimentary rocks in the earth’s crust are shales. Their lack of significant porosity and pore-filling hydrocarbons is amply compensated by volumetric extent, providing favorable conditions for economic production. The problem is how to evaluate the properties of these tight, small-particle sized systems. Analysis of the microstructure of tight shales suggests four types of porosity, with organic and nonorganic porosity being the dominant differentiators. Organic porosity may be the most relevant porosity for hydrocarbon accumulation and production. The microstructure also suggests a biased distribution of fluids, with hydrocarbons predominantly hosted in the organic porosity and brines in nonorganic pores. The separation and potential hydraulic discontinuity between brines and hydrocarbons pose important questions to standard concepts of pore saturations and the relative mobility of fluids in pore space. In addition, a larger portion of the water content in tight shales is immobile, either through capillary, double-layer, or structural forces of varying magnitudes. Defining and discriminating “free” pore water from “bounded” or “matrix” water is a challenge. To understand reservoir properties in tight shales, it is necessary to not only reconsider the meaning of previously defined concepts for conventional porous media, but also to find a new way to measure them. New analytical methods have been developed to evaluate cores from gas shale reservoirs by using crushed material to enable better access to the pore space, a high-throughput retort system practical for commercial-scale analysis to separately measure free/bound/structural water volumes, visually distinguish water from oil, and pressure transient analyses to determine permeability. Applying conventional core analyses to kerogenand clay-rich rocks fails to separate free from bound waters, and water from light oils, thereby missing critical inputs into calculating effective saturations, effective porosities and claybound water volume. In addition, the amount of oil recovered from retort, as an independent quantity, can be a useful proxy for kerogen maturity. In conventional reservoirs with large pore volumes and low clay content, these distinctions are more muted. In regard to permeability measurements, unconventional reservoirs are usually too tight to allow for steady-state methods, and microfracturing is often too pervasive to allow for reliable permeability measurements on whole plug samples. Crushed sample pressure decay Methods Improve Shale Core Analysis The “Better Business” Publication Serving the Exploration / Drilling / Production Industry DECEMBER 2012