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.

Production analysis of actual data shows long-term transient flow geometries with boundaries in a large number of gas wells which are produced from tight gas reservoirs. In this paper, long-term linear and bilinear flows caused by the presence of natural fracturing are discussed. Linear and bilinear flows as a source of matrix block drainage are investigated. Systematic methodologies to analyze production data for estimation of reservoir properties and OGIP under linear, bilinear, and boundary dominated flows in tight gas wells are described. Application of these methodologies in various actual tight gas wells from industrial sources and validation of these procedures by using numerical simulation are shown. Long-term transient flows and short fracture half-length in various post hydraulic fractured wells suggest the convenience to develop tight gas fields with a tighter spacing between wells. Introduction Short-term linear and bilinear production data analysis may characterize fracture properties in a hydraulically fractured well1,2, but long-term linear and bilinear flow production may be generated and controlled by the reservoir geometry and/or by the natural occurring reservoir properties3,4. This paper deals with gas wells showing long-term linear and bilinear flows during the transient period and also with gas wells showing outer boundary dominated flow. Long-term linear and long-term bilinear transient behaviors have been detected in almost all-tight basins producing gas. Actual field data show transient flow for many years in a large number of wells because of their extremely low permeability5–14. Long-term linear7,13 and long-term bilinear behavior4 have been reported in tight gas wells that did not have particularly large fracture treatments. Several authors discussed the occurrence of bilinear flow regime in reservoirs7,12. Some of them presented models, solutions, and type curves under different conditions for both homogeneous and dual porosity reservoirs2,15–19. Some conditions causing bilinear flow are: a vertical well between two parallel leaky boundaries due to faulting or sedimentary process, a vertical well near a high conductivity infinite fault, a vertical well with a finite conductivity fracture20,21, a horizontal well in a fractured reservoir with transient dual porosity behavior during the intermediate linear flow period, a horizontal well in a layered reservoir with transient dual porosity behavior during the intermediate linear flow period and a linear reservoir with transient dual porosity behavior. In a previous paper22, long-term linear flow caused by both the presence of natural fractures and vertical linear flow due to high permeability streaks are shown. In this paper, linear and bilinear flow regimes as a source of the matrix block drainage are discussed. Afterwards, we show stepwise methodologies for linear, bilinear, and boundary dominated flows that can be used to analyze production data and estimate reservoir properties, pore volume, Vp, OGIP, and movable-reserves from gas wells in conventional and tight gas reservoirs. Later, gas rate forecasting, well spacing or infill drilling can be determined. Finally, we show several actual tight wells where linear, bilinear, and boundary dominated flows are detected and characterized. Matrix block drainage in a fracture network system Natural fractured reservoirs are often encountered in tight gas reservoirs. Five different models to characterize naturally fractured reservoirs including anisotropic models and dual porosity were discussed by Cinco-Ley23.

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.

We propose a novel concept relating to using net-to-gross (NTG) ratios in characterizing hydraulic fracture deliverability. Current NTG considerations applied in unconventional resources are primarily petrophysics-based. However, the variability of in-situ stress and material properties in the vertical direction greatly influence placement and vertical connectivity of a given hydraulic fracture. Hence, the areas of low connectivity within the created fracture system, such as pinch offs, can impact production performance and thus become a key asset development driver that ultimately influences project economics. Therefore, characterizing pinch offs in a created fracture network becomes a necessity. Such characterization can be accomplished by splitting NTG into two components—petrophysical (NTG-P) and stimulation (NTG-S). The focus of this work is the NTG-S. The proposed NTG-S is currently based on hydraulic fracture and production models coupled with calibration data from offset wells. For a given stress and material property profile, hydraulic fracture geometries are estimated using a fracture simulator with multiple calibration points. The post fracture closure width profile from the calibrated fracture model indicates possible pinch points along the created fracture height. The calibrated fracture geometry is then integrated into a production model, where the impact of the pinch points on well performance is simulated while honoring the actual production data. High-resolution stress logs and fullbore cores can help to address uncertainty in location and severity of pinch points and aid in reducing the non-uniqueness that is inherent to production models. NTG-S influences the productive fracture height, which in turn impacts the drainage volume and drainage area around a well. Subsequently, the drainage area affects well spacing and completion design considerations. For a given productive fracture surface area, overestimating NTG-S (assuming a large productive fracture height) can result in an assumed short drainage length, leading operators to laterally place offset wells closer than needed. Conversely, underestimating NTG-S can cause operators to space offset wells too far apart, resulting in lower recoveries. Consequently, in very thick unconventional reservoirs, stacked horizontal wells may be more appropriate. Accounting for NTG-S allows optimizing lateral landing points to ensure optimum drainage configuration is achieved.

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