Hydraulic fracturing and horizontal well drilling technologies have enabled the oil and gas industry to safely unlock large reserves of oil and gas in unconventional resources, especially in shale gas and oil, and tight gas and tight oil reservoirs. However, there is an ongoing debate on whether "the best practice" is to drill a horizontal well in the direction of minimum horizontal stress, which would create transversely fractured well or to drill the well in the direction of maximum horizontal stress, which would create longitudinally fractured well. Additionally, little work has been done to understand the complex relationship that exist between principal stresses, well azimuth and/or lateral direction.

This paper presents the results of a comprehensive multiphase flow study that investigated the relationship between the principal stresses and lateral direction in hydraulically fractured horizontal wells, and its impact on well performance. Secondly, the study also incorporated previous studies, where applicable, of a single phase flow study that was conducted by the co-authors of this paper. Both studies focused on transversely fractured wells versus longitudinally fractured wells, and how well azimuth affects productivity, reserves and economics of horizontal wells. The previous study primarily focused on wells that produced single phase fluids, and used single phase reservoir numerical models to study well performance. The study investigated the importance of lateral direction as a function of reservoir permeability, lateral length, fracture-half length, number of fracture stages, fracture conductivity, and well completion type (open-hole vs cased-hole). The Single phase study also included a number of actual field cases where the results were compared to actual wells in both oil and gas reservoirs that had transversely fractured or longitudinally fractured horizontal wells.

This study would extend the findings of the single phase flow study by adding multiphase flow dimensions such as effects of relative permeability, non-Darcy flow, adsorption gas, stress dependent permeability on induced fractures and conductivity changes in the fracture from the tip to the wellbore. The study used black oil reservoir simulator to study two phase flow mechanisms such as gas-water (dry gas reservoir) and under-saturated oil reservoir (oil-water), and compositional reservoir simulator to model three-phase flow (oil-gas-water) to investigate each parameters' impact on well performance. This study is unique as it examines the permeability ranges from wells with 1 Nano-Darcy (0.000001 md) to 10.0 milli-Darcy in a multiphase flow reservoir simulation. Additionally, this paper presents the first multiphase flow study that thoroughly compared the performance of transversely fractured versus longitudinally fractured horizontal wells.

Key features of the study that would benefit the petroleum industry are;

  1. Methodologies for modeling shale gas and shale oil wells with stress dependent permeability, adsorption gas and non-Darcy flow effect using black oil models and compositional reservoir simulators.

  2. Reservoir permeability based cut-off criterion that can be used as guide when selecting whether to drill transversely fractured vs longitudinally fractured horizontal wells.

  3. Integrating the reservoir objectives and geo-mechanical limitations into horizontal well completions and stimulation strategies.

  4. Incorporate the effect of reservoir fluid type and fluid properties such as oil composition and density (API) into the decision analysis when comparing transverse horizontal wells to longitudinal horizontal wells.

  5. Stimulation optimization strategies focused on well recovery, productivity and EUR as function of hydraulic fracture spacing (or number of fracture stages) and reservoir permeability

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