Determination of porosity, hydrocarbon saturation and net reservoir thickness in unconventional shale oil and gas reservoirs is often a major petrophysical challenge due to the low porosities typically present in these reservoirs and the impact of kerogen on fundamental rock properties such as the grain density, porosity and permeability. The challenge is large in emerging play areas where core measurements are limited or not available, and quality information on total organic carbon (TOC) content and mineralogy may be sparse. Legacy wireline logging measurements such as Resistivity, Gamma Ray, Density, and Sonic are often the primary source of rock property information. Deriving accurate ranges for key volumetric parameters is essential for risking and assessing an economic value for these plays. Also important for assessing economic value is predicting the effectiveness of fracture stimulation to achieve expected ultimate recoveries (EUR's) that are economically attractive. This requires interpretations of the mechanical properties of the reservoir. The petrophysical characterization for emerging plays can be enhanced by utilization of analog core based trends as well as learnings gained from developing and mature plays. This paper focuses on the use of analogs to improve the petrophysical characterization in emerging plays where uncertainties are generally large.
The petrophysical evaluation of shale oil and gas reservoirs in emerging play areas is often very challenging. As in most shale oil and gas reservoirs, a basic understanding of the matrix lithological components, clay content, kerogen content, and maturity level is required for deriving reasonable ranges in key volumetric parameters such as the porosity, hydrocarbon saturation and net reservoir thickness. In emerging play areas, legacy wireline logging measurements such as Resistivity, Gamma Ray, Density, and Sonic are often the primary source of rock property information. Core measurements are limited or not available, and quality information on TOC and mineralogy may be sparse. As such, the volumetric parameters can have very large uncertainties. To reduce or manage these uncertainties, it is important to leverage data and learnings from developing and mature plays where there may be an extensive knowledge base of log and core data. This paper outlines a workflow for developing and using analog trends to improve the petrophysical evaluation in these challenging emerging plays.