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.

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.

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.

Multi-stage hydraulic fracturing technology for enhanced production from unconventional reservoirs has improved significantly during the past decade. However, multi-stage fracturing for multiple closely spaced long horizontal wellbores introduces several technical challenges. One example is Fracture Driven Interaction (FDI). In this study, we document a Fracture Driven Interaction case study where the primary well was drilled into the Three Forks Formation, and an offset well was drilled in the Middle Bakken. The idea of this study was to investigate the possibility of frac-hit as the cause of the low production rate in the offset well. This study estimates the stress in the petroleum system, and combine that with petrophysical analysis to construct a fully coupled hydraulic fracturing, geomechanics and reservoir numerical model. The model matched the production data and the results show the occurrence of a fracture driven interaction was a result of stress decrease due to depletion. Fracture driven interaction effect was severe on the offset well reducing the stimulated reservoir volume, thus jeopardizing the production.

Like many unconventional plays, the Eagle Ford, once one of the most active shale plays in the world with over 250 rigs running, saw a vast amount of data collected during the boom over a very short time. As with most unconventional resources, a lack of validation of reservoir parameters prevailed in the early history of these plays (emerging plays) and thus, hypothesis drove drilling and completion optimization programs. The 2015 drop in commodity prices accelerated the need to optimize well designs and spacing and stacking patterns in a less capital-intensive manner. A sector model was built that enabled discrete modeling of the 4 development wells in place and significant remaining undeveloped potential to be completed both within and near the sector model area. From this model, substantial understanding around the key parameters driving subsurface performance both from the rock and wellbore design perspectives was gained. As in-fill drilling has occurred in other areas of the play, a learning curve developed around the understanding of vertical connectivity, fracture geometry, well interference and the impact of clusters and job size on fracture contact with the reservoir. This learning curve has been applied to the integrated model to understand what an optimized infill drilling program for the area would look like at various hydrocarbon pricing scenarios. This paper utilizes an integrated model approach to understand reservoir performance on a pad with four wells completed across multiple horizons in the Eagle Ford. Wireline quad combo compressional and shear log suites (including azimuthal anisotropy and VTI sonic processing, resitivity/acoustic borehole imagers, and NMR), core (geomechanical, geochemical analysis, routine core analysis and specialized core analysis), completion data (fracture treatments with pre-and post-job shut-in pressures), production data (1200 days of production history with a bottom-hole pressure gauge and calculated bottom hole pressures from rod pumps) are used to build petrophysical models, geo-models, geomechanical models, fracture propagation models and reservoir models with the aim of understanding completion and production drivers. A workflow is presented that enables these models to improve our understanding of layering effects (vertical connectivity), fracture asymmetry (pressure sinks or sources), well interference (hydraulic vs. propped lengths) and the impact of clusters and job size on fracture contact with the reservoir.