A Deterministic Method of Evaluating an Upper Jurassic Shale Gas Formation in North America and for Predicting Maturity Index and Total Organic Carbon (TOC) from Wireline Logs

Zeinali, Hannah¹; Bateman, Richard M.; and Sepehri, Jay
¹[email protected]

Before shale resources started to play an important commercial role in current hydrocarbon production, geochemistry was limited to source rock studies for hydrocarbon exploration purposes. Starting in the late 20th century shale was identified as both source rock and reservoir and geochemistry became an inseparable portion of reservoir studies. This trend extended to petrophysical studies and to reservoir evaluations in shale plays.

For shale gas reservoirs containing a large amount of organic matter, defining geochemical parameters such as thermal maturity (VRO), total organic carbon (TOC) and Kerogen Type is critical in predicting important reservoir parameters such as porosity and hydrocarbon saturation. These parameters normally, obtained from core data, are limited to only a few points, are difficult to recover and very dependent on the handling procedures and lab study. Despite recent studies of shale reservoirs, prediction of geochemical parameters still remains a challenge and demands more research.

There is no general workflow for petrophysical interpretation of shales containing organic matter and most of the stochastic approaches are based on a computerized evaluation. A deterministic modeling approach has been applied to wireline logs for the petrophysical interpretation and computation of hydrocarbon saturation, porosity, permeability and OGIP in the reservoir section. The model is constructed based on the quick-look conventional petrophysical interpretation and X-ray diffraction (XRD) data. The petrophysical interpretation is finally confirmed by forward modeling.

This paper also addresses the log derived thermal maturity index (MI) and TOC calculations in a large upper Jurassic shale gas formation located in North America, using conventional wireline log and confirms by comparison with core data and geochemical log data. From the ternary diagrams derived from geochemical data, the average percentage of clay for this case is 40%. As the amount of OGIP is directly proportional to the thermal maturity of organic content and is helpful for predicting hydrocarbon phases, so estimating MI is essential for shale gas evaluation.

59 geochemical core data points from three wells were employed for calibrating well log data. The techniques described, demonstrate the methodology for evaluation of shale gas potential and can be applied elsewhere.

AAPG Search and Discovery Article #90166©2013 AAPG International Conference & Exhibition, Cartagena, Colombia, 8-11 September 2013