Fluids injected during hydraulic fracturing (fracking) in unconventional shale oil and gas reservoirs, geothermal system enhancement, wastewater disposal, and carbon capture and storage can induce microseisms. The spatiotemporal distribution of induced earthquakes is often used to trace the growth of fractures in condensed layers and guides production. We analyze microseismicity behavior induced by fracking in the Montney Formation, one of the largest unconventional oil and gas reservoirs in North America. An optical fiber deployed in a horizontal well provides extensive spatial sampling and data coverage for microseismic imaging. We use a regularized, nonstationary regression to suppress noise in raw strain data. An elliptical vertical transverse isotropic (VTI) velocity model is derived from the Backus-averaged well-log sonic data and is updated to match the microseismic wavefronts. We image 41 previously cataloged microseisms using Geometric-mean Reverse Time Migration and compare our results with their initial locations. Our updated locations predict P- and Swave traveltimes with greater accuracy than the catalog locations. We find that the limited span of the optical fiber produces reflection (mirroring) artifacts in source images. Analyzing data sensitivity confirms the potential limitations imposed on source imaging by the geometry of borehole observations. We also propose a two-step procedure for estimating source focal mechanisms by combining DAS and geophone waveform data. Our study provides guidance for characterizing microseismic