Hydraulic Fracturing “Sweet Spots” Identified Using Radiogenic Noble Gases
Within the past twenty years, the growing energy demands in the United States have been satisfied by the increased production of natural gas through hydraulic fracturing of organic rich shales. Although technological advances have stimulated fracking to be the dominant means of unearthing natural gas, there are still many unprofitable wells (>95% of gas production comes from 26% of wells). This is largely due to the uncertainty surrounding how fluids flow in a relatively impermeable rock, the inability to accurately model existing fractures, and the heterogeneous composition of shales. Undeformed shale has extremely low porosity and permeability (nanoDarcy) which restricts fluid flow. Brittle failure of these rocks increases the effective porosity and permeability, acting as the main contributor to fluid migration. Furthermore, natural fractures that intersect a borehole provide a flow pathway from the shale to the well. Therefore, information about natural fractures is critical to optimize unconventional hydrocarbon production. We propose that the utilization of noble gases will identify areas of fluid (hydrocarbon) accumulation and zones where fluids have migrated out of the shale, allowing for better placement of hydraulic fracturing stages within a horizontal borehole. Noble gases are particularly useful as tracers as their original gas composition remains independent of microbial activity, chemical reactions, or changes in oxygen fugacity. Specifically, we will be using radiogenic gases trapped within the mineral grains of shales. Organic material is rich in uranium and thorium, which through alpha decay radiogenically produces 4He. On rare occasions, an alpha particle will strike an 18O atom within the surrounding minerals (e.g., SiO2) and nucleogenically produce 21Ne* (asterisk denotes radiogenic component). These processes create a globally constrained 4He/21Ne* production ratio of ~22 x106. As 4He, 21Ne* and 40Ar* accumulate within the mineral grains, a concentration gradient begins to form with the surrounding pore space. To maintain equilibrium, the gases will want to diffuse in and out of mineral grains into the surrounding pore fluids. However, diffusion is only possible when formational temperature exceeds a gas and mineral pair’s closure temperature. Within quartz, closure temperatures for helium, neon, and argon are ~12°C, ~80°C and ~240°C, respectively. Based on the age and content of U, Th, and K within a shale, the expected [4He], [21Ne*], and [40Ar*] can be calculated. However, a migrating fluid in a fractured system can carry away gases present in pores, leaving a lower concentration of that specific species than the expected value. Since the ability of a specific gas to diffuse out of a mineral is a function of temperature, deviations from the 4He/21Ne* (globally constrained) and 4He/40Ar (U, Th, K dependent) ratios provide insight into the past temperature, volume, rate, and mechanism of fluid migration. Drill cuttings from Appalachian and Permian Basin horizontal boreholes will be heated to 1600°C using a laser ablation system. This process releases all gases within the lattice of the grains, which are then analyzed using a ThermoFisher Helix SFT Noble Gas Mass Spectrometer. Results will be compared to gas production data from each interval.
AAPG Datapages/Search and Discovery Article #90373 © 2019 AAPG Eastern Section Meeting, Energy from the Heartland, Columbus, Ohio, October 12-16, 2019