Low-permeability (tight) and shale (gas and oil) reservoirs have emerged as a significant source of energy in North America. Recent advances in technology, such as long horizontal lateral/multi-lateral drilling combined with hydraulic fracturing, and new surveillance techniques, have enabled commercial production from ultra-low permeability reservoirs, previously considered source or cap-rock, not reservoirs. Forecasting well production for reserves estimation, hydraulic fracture stimulation optimization, and development planning remains a challenge because of complex reservoir behavior and flow geometries associated with current wellbore architectures/stimulation treatments used to exploit tight formations. Depending on the completion design, transient flow periods can last for weeks to years, and hence traditional methods requiring boundary-dominated flow are strictly inapplicable for most of the commercial life of many wells completed in tight formations.

Recently, several analytical (type-curve, flow-regime analysis and simulation) and empirical approaches have been introduced to match and forecast tight reservoir production. The challenge is to develop routine techniques that can be used to forecast tight formation production, while adequately addressing the complex physics of the problem.

In this work, we build on recent attempts to combine analytical and empirical methods ("hybrid" methods) for forecasting tight/shale gas reservoirs completed with multi-fractured horizontal wells. We forecast the homogenous completion (equal hydraulic fracture length) case using established analytical procedures for transient linear flow (pre fracture interference), combined with the Arps decline curve for late-time (boundary-dominated) flow. We also examine the heterogeneous completion (unequal hydraulic fracture length) case to establish the impact of heterogeneities on decline characteristics post fracture-interference. Finally, we present an innovative method for designing hydraulic fracture and well spacing.

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