A Workflow to Evaluate Mineralogy, Porosity, TOC, and Hydrocarbon Volume in the Eagle Ford Shale
- Eric Eric Murphy (Chesapeake Energy Corp.) | Greg Praznik (Halliburton) | John Quirein (Halliburton) | James Elmer Galford (Halliburton Energy Services Grp) | James M. Witkowsky (Halliburton Energy Services Grp) | Songhua Chen (Halliburton Co.)
- Document ID
- Society of Petroleum Engineers
- SPE Unconventional Resources Conference and Exhibition-Asia Pacific, 11-13 November, Brisbane, Australia
- Publication Date
- Document Type
- Conference Paper
- 2013, Society of Petroleum Engineers
- 6.5.4 Naturally Occurring Radioactive Materials, 1.2.3 Rock properties, 1.6.9 Coring, Fishing, 5.2 Reservoir Fluid Dynamics, 5.8.4 Shale Oil, 5.8.2 Shale Gas, 5.6.1 Open hole/cased hole log analysis, 5.1.1 Exploration, Development, Structural Geology, 4.3.4 Scale, 5.4.2 Gas Injection Methods, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 5.5.2 Core Analysis
- Eagle Ford, Geochemical, NMR, Dielectric, Workflow
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The Eagle Ford Shale hydrocarbon-fluid properties depend on the source rock maturity and, within the formation, occur in varying degrees of gas, gas condensate, and oil. Using conventional logs and pyrolysis data, several log-core regressions, such as delta log R, density, and uranium, can be derived to predict total organic carbon (TOC). TOC can be used with geochemical elemental measurements for a more accurate assessment of the formation kerogen and mineralogy, as well as hydrocarbon volumes. Nuclear magnetic resonance (NMR) porosity measures an apparent total porosity in the organic shale plays, measuring only the fluids present and excludes the kerogen. The complex refractive index method (CRIM) with the mineralogy log data can be used to compute accurate dielectric porosities, which exclude both kerogen and hydrocarbon. Integrating the core TOC, predicted TOC, mineral analysis, NMR, and dielectric information, a final verification of the kerogen volume, porosity, hydrocarbon content, and mineral analysis can be assessed.
This paper will describe the integration of conventional logs, a geochemical log, an NMR log, and dielectric to predict TOC, kerogen volume, and hydrocarbon volume, as well as total porosity and mineralogy. The log data is compared to core data from three Eagle Ford wells. Based on the results from these three wells, a comprehensive workflow is developed for unconventional source rock reservoir interpretation. The workflow is then applied to two additional Eagle Ford wells and the results are compared to core data. While the workflow is demonstrated with Eagle Ford data it is believed that it will be applicable in other unconventional source rock reservoirs. It will be demonstrated how the proposed approach will help eliminate some coring operations and can be used to help make decisions on optimum lateral placement.
The Eagle Ford (known as the Boquillas formation in outcrop) is an Upper Cretaceous (Cenomanian to Turonian) formation comprised of limestone, marls, and claystones with some clays originating from volcanic ash (tuffs). It is a ‘self-contained' petroleum system, consisting of interstratified source, seal, and potential reservoir. Much of the Eagle Ford Group is a mixed siliciclastic/carbonate unit that records a second order, Late Cretaceous transgressive, and high stand of eustatic sea level. Within the Eagle Ford, two major depositional units have been recognized regionally (Dawson 1997; Dawson 2000). The lower unit's depositional environment was low energy and slightly anoxic, consisting of organic-rich, pyritic, and fossiliferous marine shales, which mark the maximum flooding surface, or the deepest water during Eagle Ford deposition. The different fauna present in the Eagle Ford suggest the waters were calm and within the photic zone. The upper unit consisted of a small regressive high stand forming this carbonate layer toward the top of the Eagle Ford, identifiable by high-energy features, such as ripple marks from storm-generated waves and interbedded carbonaceous siltstones (Liro et al. 1993; Grabowski 1995; Robinson 1997).
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