Numerical and Empirical Evaluation of Noble Gas Diffusivity to Reconstruct Paleo Fluid Flow in the Appalachian Basin

Abstract

The increased production of natural gas, through hydraulic fracturing and directional drilling has highlighted the need to improve our knowledge of pathways for fluid flow and the history of geological fluid migration in the crust, specifically in tight shales. Understanding fluid transport phenomena along naturally existing and induced pathways (e.g., open fractures) in shales is critical to produce an accurate estimate of recoverable hydrocarbons from these unconventional reservoirs. Nonetheless, accurate estimates of fluids-in-place and recoverable fluids remain enigmatic. Because the rate of production of ⁴He and ²¹Ne* in the crust is fixed at a nearly constant ratio (⁴He/²¹Ne* ~22x10⁶) and the rates of diffusion of these radiogenic isotopes from the lattices of mineral grains within the formation are temperature-, mineralogy-, and potentially fluid migration-dependent, noble gas data can be used to infer porosity, temperature of paleo crustal fluid migration, and volume of reservoir stimulation within shale formations. By analyzing the noble gas signatures of rock samples from petroleum basins and developing robust numerical models of noble gas diffusion from mineral grains to fluids, we can determine the source, migration pathways, residence time, permeability, and porosity of the deposited sediments. Herein, we integrate radiogenic noble gas (e.g., ⁴He, ²¹Ne*, and ⁴⁰Ar*, where * denotes a radiogenic component) data of Marcellus Shale cuttings and cores at surface, subcrop, and borehole depths with novel numerical models for noble gas diffusion that incorporate temperature, pressure, fluid chemistry, and porosity conditions in prospective reservoirs. These data suggest that noble gases and numerical modelling allow us to constrain effective porosity and zones of preferential fluid flow in shales. Specifically, our data suggest that in combination, these techniques allow us to identify areas along the lateral legs of wells that display anomalous hydraulic conductivity (preferential zones of gas accumulation) and high hydraulic conductivity (e.g., fracturing, faults).

AAPG Datapages/Search and Discovery Article #90350 © 2019 AAPG Annual Convention and Exhibition, San Antonio, Texas, May 19-22, 2019