Abstract

The emergence of shale and oil plays in North America has caused the industry to re-examine the methods which we use to quantify the resource and recoverable reserves in place. We recognize that unconventional gas and oil reservoirs are geologically and petrophysically heterogeneous at a variety of scales. Organic mudstone systems exhibit storage and flow characteristics which are uniquely tied to nano-scale pore throat and pore size distribution and possess common organic and clay content. Appraisal of these system is also challenged by the complex fluid compositions and distribution.

We present a novel workflow and methods for systematically modeling reservoirs with complex mineral and fluid composition. One of the primary objectives is for consistent and improved accuracy of reservoir storage capacity estimates. The workflow provides direct core to log calibration of static properties throughout the workflow. It also allows for calibration to dynamic properties such as pore pressure and fluid phase properties via PVT tests using industry standard correlations such as Standing and Vasquez and Beggs.

The log calibration process utilized is a “hybrid” simultaneous inversion approach in which direct measurements of total clay content, total organic carbon (TOC) and pyrite from core or cuttings are used as inputs to constrain the inversion process. Other inputs are conventional log data, whose response is affected by the presence of fluids (hydrocarbons and water) and various minerals, and organic material. Results from the inversion calculations, including volumes of other rock constituents, are compared against physical measurements from core and/or cuttings. Numerous examples will be presented.