Integration of Core and Log Data to Quantify Producible Oil in Place: Eagle Ford Shale

Tuesday, 08 October 2013 Read 5016 times
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Production of oil from organic shale reservoirs is a function of porosity, hydrocarbon saturation, pore pressure, matrix permeability, and hydraulic fracture surface area plus fracture conductivity. Hydraulic fracture surface area, porosity, saturations and pore pressure dominate initial production rates. Matrix permeability becomes increasingly important in sustaining production later in time.

Permeability measurements to oil from organic shale core samples are not commercially available today. However, permeability to oil is believed to be a function of pore throat size, wettability, and water saturation, the same as a conventional reservoir. This work investigates pore size, wettability, and expelled hydrocarbon volumes using log and core-based nuclear magnetic resonance data from the Eagle Ford Shale focused on the comprehensive evaluation of one well. Comparisons with core porosity measurements, scanning electron microscope images (SEM) and mercury injection capillary pressure tests (MICP) are compared with the nuclear magnetic resonance (NMR) interpretation for calibration and validation. The NMR T2 distribution is partitioned into regions of bound and producible free fluid.

Two types of pore systems are present in the Eagle Ford Shale; kerogen-hosted (OM) and inter/intra particle (IP). Bore hole logs indicate the upper Eagle Ford Shale is dominated by IP porosity, and the lower Eagle Ford Shale is dominated by OM porosity. Core NMR indicates OM pores are hydrocarbon wet while IP pores have mixed wettability. Core pore fluids are not representative of in-situ conditions as the lighter portion of the hydrocarbons have been expelled during core recovery. Comparison between log and core measured NMR allows the quantification of the expelled hydrocarbon—those zones with the best producibility. Understanding which portion of a shale reservoir contains producible fluids impacts target zone selection.

About the Author

Richard E. Lewis
Petrophysics Technical Manager, Unconventional Resources
Schlumberger

Richard (Rick) Lewis is the developer of the gas shale evaluation workflow that was initially fielded ten years ago and has been applied to more than 3000 wells in North America. In his current position, located in Dallas, Rick manages a group responsible for the continual improvement for this workflow, for its introduction and application to the international market, and for the development of workflows for the evaluation of liquids-producing shales.

Rick is also the interface to the Schlumberger research and engineering groups for the development of evaluation technologies for unconventional reservoirs. Prior to this assignment, he was responsible for wireline interpretation development for the central and eastern United States. Rick has also worked for Shell Oil and the U.S. Geological Survey.

Rick received a BS degree from UCLA and MS and PhD degrees from Cal Tech, all in geology.

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