Undifferentiated mineralogy and organic content

An operator wanted to better understand the mineralogy and organic content of an Eagle Ford shale oil reservoir to improve completions decisions. Of particular concern was differentiating the total organic content into kerogen and producible light oil.

Insight through quantified spectroscopy and NMR measurements

Litho Scanner high-definition spectroscopy service precisely measures an extended set of key elemental yields, including carbon, to accurately quantify the mineralogy and directly determine the TOC independently of the wellbore environment and reservoir resistivity. The in situ TOC is computed by subtracting the amount of inorganic carbon (IC) associated with carbonate minerals from the total inelastic measurement of carbon. The Litho Scanner service TOC is the carbon contributed by all organic matter present in the formation: kerogen, oil, bitumen, filtrate, gas, coal, etc.

To visually differentiate the kerogen content within the TOC, the total porosity calculated using bulk density (PHID) that was corrected with the matrix density obtained from the Litho Scanner service's measurement of the elemental weight fractions is compared with the total porosity determined with the CMR-Plus magnetic resonance tool (TMCR). The CMR-Plus tool uses the 50-burst acquisition technique, which collects more data by applying prepolarization. The porosity measured by the CMR-Plus tool responds to fluids but is not sensitive to kerogen. The porosity deficit from the comparison identifies the proportion of kerogen from the TOC; thus, the remaining in situ TOC is associated with the liquid hydrocarbon content.

Petrophysical determination of reservoir quality

By visually determining the kerogen content and producible oil from Litho Scanner service and CMR-Plus magnetic resonance logging of the Eagle Ford reservoir, the operator was able to accurately assess reservoir quality.