When calculating the downhole stresses affecting a wellbore during depletion it has become a standard industry practice to assume only the pore pressure changes, and not the rock mechanical properties. This assumption has the potential to underestimate the total horizontal stress (Sh) causing unrealistic fracture containment. It will also overestimate the effective horizontal stress (Sh' = Sh - Biot * Pore Pressure) for open-hole wellbore failure. High effective horizontal stress assumption can potentially transform rock from brittle to ductile behavior and failure mechanics from shear to compaction and the model becomes overly conservative. Ductile and compaction failure can cause changes in well integrity, as well as changes in fracture geometry from offset infill wells. This paper will document changes in rock properties in the Bakken formation during variable depletion (10% to 65%) and recalculate rock properties (velocities, mechanical properties - Young's modulus, Poisson's ratio, and Biot's anisotropic compressibility constant) as a function of effective stress due to production in order to accurately calculate fracture geometry at an offset well and parent well bore integrity. Hydraulic fracturing simulations are performed to simulate well communication between the fractured well and the depleted parent well along with the potential to re-fracture the parent well using the pore pressure, linear, and non-linear models. Laboratory testing performed on rock samples is shown to validate the non-linear model.

Until 2015, North America's unconventional resource market was known to be home to the largest oil shale deposits of economic value. Although the recent commodity price fluctuations have exposed the role of geo-politics, world economies and commodity trading on the life cycle of assets, few field development studies have consider the impact of commodity cycles on the development of in-fill wells. Papers have been presented to demonstrate the impact of vertical fracture connectivity and fracture asymmetry on in-fill well performance (due to delayed in-fill drilling), but little has been done on validation and coupling the impact of depletion, due to production, and hydraulic fracturing (due to in-fill efficiency fracture operations). This paper presents results from the analysis of in-fill drilling on well performance. Production data, fracture treatment data, completion and production timing are analyzed using pressure/ production history matching techniques and compared with results predicted by data driven models (developed to match well performance) with the aim of proposing in-fill development strategies. Analysis of the field production data indicates that timing of in-fill wells (following the parent well) can influence the in-fill production depending on the level of depletion (cumulative fluid produced) and the size/type of fracture treatments pumped. Analysis of raw production data, modeling results from multi-domain model based coupled simulations and high resolution monitoring data also indicates that the order of the in-fill operations (East-West, Zipper, etc.) also has a significant impact on performance. This paper presents a simplistic approach to understand the impact of the quest for operational efficiencies and economic cycles on development strategies.

This paper covers the methodology to derive all geomechanical properties (Young's modulus, Poisson's ratio and vertical/horizontal variable Biot constants as a function of rock type) for 13 different stress models. Minimum horizontal stress (Sh) is a key parameter controlling fracture height growth during hydraulic fracturing simulation. Assuming a homogeneous formation (rock property Horizontal:Vertical = 1.0) or poorly derived inputs for the anisotropy model can lead to incorrect fracture geometry. A major assumption made using the various stress models is the Biot poro-elastic constant. Many default models assume a Biot poro-elastic constant of one, which is valid for coarse grained conventional reservoirs where porosity is greater than 20%. Most of the reservoirs stimulated with hydraulic fracturing today do not fall in that porosity range, therefore an alternative derivation for the Biot poro-elasticity and its variability requires additional discussion. Models derived and compared with their associated uncertainties in this paper include: Ben Eaton – isotropic, anisotropic, dynamic and modified with correction factor; default from auto log calibration; Vernik, Jaeger & Cook; Hubbert & Willis; Thiercelin – MC envelope and stiffness tensors (Cij); Segall & Penebaker. The geomechanical properties from the different stress models noted above were inserted into a gridded fracturing simulator. The outputs were compared to actual job and calibration data for; minimum horizontal stress, end of job net pressure and fracture geometry for each of the models. When comparing fracture geometries from each stress model against calibration data it is apparent that the chosen stress model will have a substantial influence on the result. This illustrates the importance of choosing the correct stress model for fracture simulations.

The North American unconventional resources energy growth driven by the combination of horizontal drilling, completion tools and hydraulic fracturing innovations has revitalized some conventional plays across the globe that were considered marginal prior to the unconventional boom. This paper presents the workflows utilized to implement unconventional technologies that have resulted in incremental hydrocarbon resources being unlocked. A multi-domain approach is utilized to understand the results from the application of horizontal drilling, completion tools and hydraulic fracturing innovations to the Turner play. High tier log and core data is used initially to create petrophysical and geomechanical models. Numerous petrophysical and geomechanical models are generated based on the uncertainty in model building. Appropriate models are selected based on fracture pressure matching and production history matching techniques. These models are then used to drive the design and optimization process of future offset wells. Characterization of the reservoir (permeability range, pressure and fluid saturations) has led to the understanding that completion techniques used in unconventional plays (slickwater fluid system with tight cluster spacing) cannot be blindly applied. An understanding of fracture geometry and reservoir quality enables changes to be implemented on lateral landing, stage count and job size resulting in incremental production. The importance of reservoir characterization and forward modeling of the application of horizontal technologies is crucial to ensuring efficient allocation of resources to maximize production. This paper showcases the application and evolution of unconventional technologies and workflows to conventional plays to gain incremental production results.

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