Geologic characterization and reservoir properties of the Upper Smackover Formation, Haynesville Shale, and Lower Bossier Shale, Thorn Lake field, Red River Parish, Louisiana, USA

Abstract

The Late Jurassic Haynesville-Bossier Shale Play is a prolific, unconventional shale gas play extending over east Texas and northwest Louisiana. Initial development was extremely successful with estimated ultimate recovery values of approximately 10 BCF per well for the best producing wells. The Upper Jurassic stratigraphic section in which these shales reside has a complex geologic evolution related to deposition during rift to passive margin development in the northern Gulf of Mexico Basin. Characterization of this section provided insight into its geologic character at multiple scales, reservoir property distribution, and exemplified links between regional proximal-to-distal depositional settings, facies character, and unconventional reservoir quality. Two cores covering approximately 320 ft of stratigraphic section and associated core-based data were utilized in the study. Identification and multiscale petrographic characterization of core-based lithofacies, integration of core-based compositional data, core-based reservoir quality data, and petrophysical well log response provided the basis for the characterization. Facies exhibit significant variation throughout the stratigraphic section, ranging from coarse, heavily carbonate-cemented calcarenite facies at the base to organic-poor, argillaceous mudrocks at the top. Within the reservoir facies-containing interval, facies range from siliceous siltstone to mudrock to laminated, massive, argillaceous calcarenite to calcilutite. Compositional datasets reflect this facies variation at the mineralogical and elemental scale. The distribution of geologic character and reservoir properties in this more distal section is likely directly linked to updip sediment supply and sea level variations. Significant amounts of material were likely transported into the intrashelfal basin from more proximal depositional settings on the Sabine Uplift. Within the primary reservoir facies, porosity and permeability are high, with average core-based porosity values of 8-12% and microdarcy permeabilities. The highest porosity and permeability values in reservoir facies were over 13% and 0.005 md based on GRI analyses. A variety of interparticle and intraparticle pore types was observed, often with variably porous pyrobitumen fill and variable character cements. Non-pyrobitumen-associated organic matter porosity was also observed rarely and was not found to be cemented. The largest pores were associated with rigid framework grains such as quartz grains and carbonate allochems, although coarser portions of the formations appear to contain more interparticle-intrapyrobitumen pores that are partially or totally occluded with cements. The fact that this high reservoir quality is found consistently throughout the reservoir portion of the section likely contributes to the high production rates aforementioned. Diagenesis has affected the reservoir quality in this section through compactive, replacive, and cementation processes based on SEM scale work in this study. Petrophysical well log response was interpreted to be controlled mainly by organic content, clay content versus quartz/carbonate content, porosity, and depositional fabric/layering and can provide insight into stratigraphic variations at the well log resolution scale and lower.