--> --> Abstract: A Petrophysical Model to Estimate Free Gas in Organic Shales, by Michael Holmes, Dominic Holmes, and Antony Holmes; #90124 (2011)

Datapages, Inc.Print this page

Making the Next Giant Leap in Geosciences
April 10-13, 2011, Houston, Texas, USA

A Petrophysical Model to Estimate Free Gas in Organic Shales

Michael Holmes1; Dominic Holmes1; Antony Holmes1

(1) Digital Formation, Denver, CO.

A method is presented whereby conventional open hole logs -density, neutron, Pe, GR, and resistivity - can be used to quantify the volume of free gas in organic shale. The calculations involve determining silt and clay mineral volumes in the shale fraction of the rock. Porosity associated with the clay minerals is subtracted from total porosity, and the difference remaining is silt porosity. Silt porosity is added to any, usually very small, amounts of clean formation porosity which might exist when shale volume is less than 100%. This summed porosity is then combined with water saturation to determine free gas volumes. A summation of free gas-filled shale porosity can then be compared with cumulative adsorbed gas volume to yield a comprehensive petrophysical analysis.

Gas in shale reservoirs is composed of two distinct types. Adsorbed gas is attached to the rock surface, and is gradually released to the wellbore as pressure is released. Free gas is located in the (small) volume of shale porosity, and behaves in the same way as in conventional reservoirs when pressure is reduced. Both types of gas will produce over time, but at different rates. Therefore, it is desirable to distinguish between adsorbed and free gas if possible. Most prior work in the petrophysical field has been directed towards quantification of total organic carbon (TOC), from which gas content and adsorbed gas volume is available. Often, it is assumed that the volume of free gas is about the same as adsorbed gas. Any free gas in an organic shale is located within small to very small volumes of porosity in the silt fraction. Typical values are in the 2% to 6% range, and rarely exceed 10%. The method presented here is based on a component analysis of the rock. The clean and silt fraction is typically quartz, calcite, and dolomite, and other components such as plagioclase. Shale components are clay minerals - typically illite, smectite, kaolin, etc. - and silt. If XRD data are available, the components can be defined. If not, reasonable estimates can be made from porosity cross plots. Using the porosity of individual clay minerals, total clay porosity can be calculated, subtracted from total shale porosity, to yield silt porosity.

Hydrocarbon saturation is determined by comparing shale apparent water resistivity with the value of apparent water resistivity in a shale interpreted to be low in TOC.