In-situ stress variability within a reservoir is a primary parameter that controls hydraulic fracture initiation, growth, connectivity, and ultimately drainage and well spacing. This paper highlights the importance of characterizing the variability of in-situ stress and demonstrates the risk of underestimating stimulation treatment size when a treatment design is applied in a “copy-paste” fashion without any modifications to account for variation in pore pressure and in-situ stress across a basin. Thermal maturity and hydrocarbon generation from unconventional shales has a direct effect on pore pressure and the in-situ stress distribution in reservoir and barrier rocks. An examination of the Bakken Petroleum System (BPS) identifies regions of thermal maturity and higher pore pressure due to hydrocarbon expulsion. Consequently, the elevated pore pressure and the resulting in-situ stress vary vertically and laterally within the basin.

Multiple pore pressure profiles and corresponding stress profiles across the BPS were considered to quantify the impact of in-situ stress variability on hydraulic fracture geometry. These profiles include effects of normal pore pressure regime, over-pressure regime or pressure profiles transitioning from over pressure to normal pressure regimes. For a given stress profile, hydraulic fracture geometries are estimated using a fracture simulator, with multiple calibration points. The hydraulic fracture system and reservoir interactions are simulated in a subsequent production modeling phase which estimates drainage area characteristics, recovery forecasts and optimum well spacing for developing an asset.

Results from stress profile sensitivity emphasize the need to address variability of in-situ stress as it directly impacts well spacing considerations in an asset development plan. For example, stress profile with a normal pore pressure regime results in longer hydraulic fracture lengths in the Middle Bakken (MB) thus requiring three wells per section to infill the asset. Conversely, stress profile with over-pressure regime in MB results in much shorter hydraulic fracture lengths thus requiring more than three wells per section to develop the asset. Incorrectly assuming overpressure in a normally pressured zone could lead to over-engineering of wells and unnecessary costs, whereas incorrectly assuming normal pressure in zones that are in fact overpressured could lead to sub-optimal completions and/or a reduction in overall production.

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