Mark H. Tobey1, David E. Schmude2, and Richard E. Newhart2
1Independent Petroleum Geochemist, Castle Rock, CO
2EnCana Oil & Gas (USA), Inc., Denver, CO
Thermal maturity evaluation of gas shale prospect areas is an essential element of exploration risk assessment. Source rock shales need to be sufficiently mature to yield significant quantities of gas, and in many cases the presence of hydrocarbon liquids can lead to deleterious production issues. Two conventional means of determining the thermal maturity of sediments include optical kerogen analysis (kerogen isolate and whole rock vitrinite and solid hydrocarbon reflectance) and pyrolytic analysis (Rock-Eval). The quality of reflectance data often is dependent upon the skill and experience of the organic petrographer, and in dry gas maturity sediments, Rock-Eval based maturation data can be unreliable due to the lack of residual generative potential. Moreover, regional heat flow differences and burial history differences complicate maturation assessments. Thus it is not uncommon that conflicts exist among published reports of maturation, and between published and independently obtained maturation data. One objective means of assessing the relative maturity of tight gas shales when other maturation data are inconsistent is through isotopic examination of trace gas trapped within core. Trace gases extracted from archived core samples as old as 35 years were used to successfully validate regional thermal maturation assessments and establish a hierarchy of relative maturities. The application of this technique, and the interpretative complexities of these data, are reviewed.
AAPG Search and Discovery Article #90092©2009 AAPG Rocky Mountain Section, July 9-11, 2008, Denver, Colorado