SPE-159904-MS

SPE 159904	11

Fig. 11—Proposed shale reservoir interpretation workflow when a complete logging suite is available.

Fig. 12—Comparison of interpretations for all three wells. From left to right, Well 1, Well 2, and Well 3.

Fig. 12 presents the results for all three wells. Tracks 1, 4, and 5 present the mineralogy obtained from the geochemical well log data. Fluid analysis is presented in Tracks 2, 5, and 8, where the kerogen volume is denoted by magenta shading. The yellow curve in these tracks is the NMR porosity. Tracks 3, 6, and 9 compare the predicted water saturations to core data. Fig. 13 continues displaying the results for three wells and shows the comparison to core porosity in Tracks 2, 6, and 10, and shows the comparison to core grain density in Tracks 3, 7, and 11. Tracks 4, 8, and 12 compare the interpreted kerogen with that obtained from cross-plot porosity minus NMR porosity (blue curve) and density porosity minus NMR porosity (black curve). The results between the three wells are consistent and agree with core data.

12	SPE 159904

Fig. 13—Comparison of interpretations for all three wells and comparison to core porosity and grain density. From left to right, Well 1, Well 2, and Well 3.

The workflow proposed in Fig. 11 provides a robust method for evaluating the quality of a shale reservoir. Used in conjunction with sonic logs and rock mechanical properties, fracture simulators can be used to optimize fracture treatment design. Thus, the lateral placement can be determined to maximize production.

Conclusions

In shale reservoirs, the petrophysical evaluation components performed by the petrophysicist extend beyond the traditional formation evaluation and also include a geochemistry component. Generally, there will be large variations in the mineralogy, as shown in Fig. 2. This causes the grain density to have significant variation. This paper has shown that wireline geochemical logs can be effectively used to predict an accurate grain density, even when there are large variations in mineralogy and total organic carbon. The resulting mineral volumetric fractions (including kerogen) can also be used to compute, at each depth, the square root of an apparent complex matrix dielectric constant.

Dielectric measurements provide an alternative to micro-resistivity logs, and in tight shale plays with no invasion, an alternative to deep resistivity logs providing a high-resolution water saturation Sw because in this case, Sw ~ Sxo. The CRIM equation was effectively applied in an Eagle Ford Shale well to solve for dielectric water-filled porosity.

NMR measurements have also been shown to have value when incorporated into both gas and oil shale reservoir interpretations where there are minimal hydrogen index and polarization effects. The NMR porosity provides a minimal porosity constraint in an integrated petrophysical interpretation. When the crossplot porosity is normalized such that it overlays the NMR porosity in zones devoid of kerogen and hydrocarbon, the difference between crossplot porosity and NMR porosity is a good prediction of the kerogen volume. In addition, the difference between the NMR porosity and dielectric

apparent water-filled porosity, φwaterCRIM , is a lower bound on the volume of hydrocarbon.

Three Eagle Ford Shale wells demonstrated the value of an integrated interpretation using conventional logs, geochemical, dielectric and NMR logs.

Nomenclature
TOC	= total organic carbon
Ro	= vitrinite reflectance, %
R	= formation resistivity, Ω-m

φ= total porosity, pu

φDensity	= density porosity, pu
φxplot	= density-neutron cross-plot porosity, pu
φNMR	= NMR total porosity, pu
φwaterCRIM	= apparent water-filled porosity from CRIM, pu
φDielectric	= dielectric water-filled porosity, pu
water
Sw	= water saturation, %
Sxo	= flushed-zone water saturation, %
ε*	= complex dielectric constant
ε’	= real dielectric constant

SPE 159904	13

ε’’

ε*for

εmatrix*

εHC*

εmf*

εi*

ρ

ρgrain_density

ρmin-i

ρkerogen

Vi

Vkerogen Vhydrocarbon Wmin-i

Wkerogen

c j

=imaginary dielectric constant

=measured complex dielectric constant

=matrix complex dielectric constant

=complex dielectric constant of hydrocarbon

=complex dielectric constant of water in the zone investigated by the dielectric tool

=complex dielectric constant of mineral, i

=density, g/cc

=grain density, g/cc

=density of mineral, i, g/cc

=density of kerogen, g/cc

=volume fraction of mineral, i

=kerogen volume, pu

=hydrocarbon volume, pu

=bulk dry-rock weight fraction of mineral, i

=bulk dry-rock weight fraction of kerogen

=normalizing constant, adjusted so that cross-plot and NMR porosities overlay in hydrocarbon-free zones

=counter for number of core samples

Acknowledgements

The authors wish to thank the management team of Halliburton Energy Services for granting the permission to develop and publish the content of this paper. We also express our appreciation to the respective technical review group whose input has helped to produce the final document.

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