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Using Noble Gases to Identify Hydraulic Fracturing "Sweet Spots" in Organic Rich Shales

Abstract

Growing global energy demands have been largely satisfied by hydraulic fracturing and directional drilling, but total UOG recovery from shale production sites remains <25% for gas and <9% for oil of the total estimated HC in place according to the US EIA. Recently, the average per-well recovery has improved slightly, predominantly due to ‘brute force’ approaches that increase the length of the lateral wells, the total number of HF stages, and the associated consumptive water usage. Much of this lost productivity stems from uncertainty in evaluating fluids-in-place, fracture openness, fluid transport phenomena, and fracture hydraulic conductivity and connectivity in heterogeneous and exceedingly low permeability (nano-Darcy scale) organic-rich shales.

Geochemical techniques, (e.g., hydrocarbon molecular and isotopic chemistry) and petrophysical characterization (e.g., mineralogy, porosity, fracture network analysis), are used to evaluate the hydrocarbon source and fluid compartmentalization of shales. However, these tracers are subject to microbial activity, chemical reactions (e.g., sulfate reduction), or changes in oxygen fugacity, which can obfuscate key information. The ubiquitous presence of noble gases (He, Ne, Ar, etc.) in crustal minerals provides an alternative source of hydrocarbon tracers due to their inert chemical behavior. The noble gas composition in paired fluids and mineral solids can elucidate the physico-chemical conditions of fluid origin and residence time, migration mechanisms, timing of vein-fill fracture mineralization, permeability, and storage conditions (e.g., hydrocarbon-water interactions, seal bypass, hydrocarbon degradation).

Because 4He diffuses readily through quartz and other silicates over geologic time and equilibrates with pore fluids while the blocking temperature for 21Ne* is ~80oC (onset of catagenesis), the ratio of 4He/21Ne* acts as a significantly more robust tracer of fracture-related fluid flow in black shales than He migration alone (e.g., significant losses of 4He relative to Ne in residual grains occur near faults/high fracture zones). This ratio can be used to estimate the rock volume on which fluids interact, the length-scale of fluid migration, and provide insights into the temperature conditions (i.e., burial depth) at which paleofluid flow occurred.

We report the 4He/21Ne* measurements of drill cuttings and associated fluids from the horizontal portions of two Appalachian Basin horizontal wells collected using laser-induced thermal heating (Teledyne Fusions CO2 Stepped Heating System) on bulk-shale grains and a Thermo Fisher Helix SFT Noble Gas Mass Spectrometer. Preliminary results from this study suggest that noble gases can differentiate hydraulically conductive zones of faulting and increased fracture intensity from low conductivity zones or localized traps of gas accumulation.