Immense potential of shale gas to supplement domestic energy needs and the recent engineering strides in multi-staged fractures in long horizontal well laterals have inevitably increased interest in exploitation of such plays across the country. However, because of the continuous nature of these plays, the production potential can change significantly from one location to the other often within close proximity. For a project to be economically viable, under downward price pressures, large number of wells in multi-well drilling campaigns needs to produce commercial quantities of gas. Not surprisingly, numerous attempts are being made to type-cast mineralogy, organic contents, fracture design and completion optimization in order to reduce exploration and exploitation risks. Many uncertainties still remain, however. The proposed model (SGPM) is developed to mitigate some of these challenges. It is simple and easy-to use and unlike grid-based fine-grid models it focuses more on the flow around individual wells while conserving overall mass. First, the current status of modeling from fine grid dual-porosity/dual permeability simulations to analytical models for horizontal wells with multiple vertical fractures is explained. The assumptions, formulation and the need for SGPM are described next. The model is validated with vertical and horizontal well productions from various shale gas plays. Results of extensions to the model to account for multi-phase flow are displayed thereafter.
This paper contributes in the following manner:
Provides an alternate framework to history match and forecast shale gas production. This model is better suited for reservoir engineers’ routine reserves estimation work because of its quicker turnaround time.
Provides a relatively simpler framework to incorporate specialized asset specific physics and geomechanics.
Multi-phase flow feature enables accurate condensate production in plays like Marcellus and Eagle Ford.