Empirical and Numerical Investigation of the Effects of Hydraulic Fracturing Injection Rate on the Magnitude Distribution of Induced Seismicity Events

Abstract

Abstract Hydraulic fracturing operations to enable production from unconventional oil and gas reservoirs have been subject to public, industry, and regulator concerns regarding induced seismicity. The injection of fluids into deep formations to generate hydraulic fractures serves to create localized increases in pore pressures and reductions in the effective normal stresses acting on critically stressed faults, resulting in fault slip and induced seismicity. Amongst the different factors influencing induced seismicity, operational factors such as injection volume and rate are potentially important, and can be controlled (in contrast to geological factors, which cannot). In this paper, an empirical study is presented examining correlations between injection rate and volume and induced seismicity events and magnitudes for data compiled for the Montney play in northeastern British Columbia. The results of the empirical analysis show that injection rate has a slightly higher correlation to induced seismicity than injection volume, and that larger events (>M3) correlate with higher injection rates (>6-8 m3/min). Three-dimensional numerical modelling was also performed to further investigate the magnitude distribution of induced seismic events as a function of different injection rates. For the modelled geological scenario, the results indicate that lower injection rates resulted in a more distributed pore pressure perturbation interacting with an adjacent critically stressed fault, resulting in multiple slip areas producing several small magnitude events. In contrast, higher injection rates resulted in a more concentrated pore pressure perturbation interacting with the fault causing a larger area to slip, producing a singular large magnitude event.