In the Williston Basin, thin reservoirs coupled with large stimulation jobs result in large vertical hydraulic fractures and out-of-zone contribution of fluids to the wells. To understand the extent of vertical fracture growth and the source of fluids reaching the wellbore, the time-lapse elemental and isotopic composition of produced waters were compared with the in-situ pore water chemistry reconstructed from core analysis (residual salts analysis (RSA)) for a set of wells in Williams county, ND.
Residual salts analysis was performed on 28 core plugs from the Lodgepole (LP), Upper Bakken Shale (UBS), Middle Bakken (MB), Lower Bakken Shale (LBS), and Three Forks (TF). RSA data indicate that the sampled formations have distinct fingerprints, predominantly in terms of strontium abundance [Sr] and strontium isotopic compositions (87Sr/86Sr). Once baseline compositions for all formations were established, time-lapse produced water samples were taken from two lateral wells (1MB and 1TF; high-impact stimulation) proximal to the baseline RSA data. Time-lapse water chemistry from both lateral wells indicates that from initial flowback through 7 months of production >80% of the produced water is sourced predominantly from the TF with minimal water contribution from other formations. Large compositional changes in the produced water within this time-period are caused by operational disturbances and/or changes in flow rate.
Preliminary, these data suggest that high-impact stimulation results in large vertical hydraulic fractures that stay open for at least 7 months resulting in produced water being dominated by a TF source. Based on produced water data from older wells with lower-impact completions, the relative contribution of water from the TF diminishes over time indicating continued, but diminished communication with the TF. Results from this study also have implications about irreducible and critical water saturations, which both have critical impact in reservoir models. A comprehensive understanding of the origins of fluids from different subsurface storage units improves well stimulation and production programs and ultimately, well economics.