Waiting for the snow to melt…
Hydrocarbon production from shale has become a main energy source for the United States. Consequently, an increased knowledge of the petrophysical properties of shale such as porosity, permeability, tortuosity, and fluid-rock interactions (e.g., contact angle, imbibition) will improve production efficiency. Because of their minute size (nanoscale), the knowledge of pore structure (i.e., pore geometry and connectivity) has proven difficult to understand. Analyzing the pore size distribution and pore connectivity of Gothic Shale from selected locations in the Montezuma County of Colorado will lead to recommendations for greater oil production efficiency, fostering innovation into a thriving, environmentally safe, oil and gas industry. \nThis study investigated the pore structure and fluid interaction of Gothic Shale to understand the movement of hydrocarbon molecules in unconventional shale reservoirs, specifically focusing on the nano-scale pore geometry and connectivity of the organic matter and minerals, which are affected by maturity and mineralogy. In order to achieve this, a total of 10 core samples collected from four wells (A for 9-21 Antelope; KF for 1-4 Kissinger Federal; NF for 1-4 Norton Federal; UM for 44-34 Ute Mountain) received tests for organic carbon, pyrolysis, x-ray diffraction, contact angle, mercury injection capillary pressure, and fluid imbibition. \nPyrolysis results showed samples contained a percent carbonate from 42 – 69% with one outlier, sample UM8741, having a percent carbonate of 34%. TOC content varies within the dataset, containing values from 0.74 – 2.14. Tmax values ranged from 445 – 529⁰C corresponding with a vitrinite reflectance range from 0.92 – 1.79. Most samples are classified as a type of carbonate mudstone (i.e. mixed or silica-rich) and are dominated by either calcite or dolomite minerals. Samples NF5913 and UM8741 deviated from the other samples and contained a majority of quartz, these samples were classified as a mixed mudstone. \nDependent upon the availability of sample size, contact angle and core plug porosity /permeability were conducted for selected samples. MICP results show that many of the samples have porosity that fell within 0.5-1.0%. The dataset had an average porosity of 0.593% with the lowest porosity, 0.224%, found in the NF5915 (5915 ft of 1-4 Norton Federal) sample, and the highest, 0.951%, in sample NF5871, both of which are calcite dominated carbonate mudstones. Most samples had pore types that were dominated by either micro-fractures, particularly 1-10 micrometer sized pores, or inter-clay platelet pores (2.8-5 nm sized pore-throats). Furthermore, no correlation was found between pore size distribution and mineralogy or maturity. Permeability values reached 1.378 mD for sample A5989; however, this was an exception. The average value of the dataset was 0.541 mD. \nContact angle results show both API brine and 10% IPA are good wetting fluids, however 10% IPA typically displays better wettability. For most samples, n-decane imbibition showed higher slopes for pore connectivity in the rock matrix, indicating that the pore system has a better connection to oil wetting fluids, the only exceptions being KF5898 and A5985. Correlations between mineralogy (clay, carbonates, quartz) and pore connectivity are found, and discussed in further detail.
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