Predicting critical gas rate when a well stops producing due unstable flow demands good understanding of fluid flow behavior in both reservoir and wellbore. Turner equation is well-recognized in the oil and gas industry to estimate critical gas velocity in the wellbore. This paper proposes the use of a basic diagnostic plot derived from Darcy flow equation to predict unstable flow as a phenomenon happening not only in the wellbore, but also in the reservoir due to gas blockage caused by an increase in liquid saturation near wellbore. It will be demonstrated that critical rate in the reservoir is linked to the relative permeabilities. This diagnostic can be used without knowing the relative permeabilities, as it clearly shows maximum limits of Water Gas Ratio (WGR) where the well experience unstable flow.

This proposed approach is a powerful diagnostic tool supported by well-known fluid mechanic equations with excellent track record in gas condensate and volatile oil fields developed under blowdown or gas injection with normal/over-pressure regimes. The objective of this approach is to aid production and reservoir engineers on decision-making process for gas injection strategies, tubing completion changes, artificial lift methods, compression projects, mechanical/chemical stimulations, healthy choke management strategy and well re-activation screening. By combining decline curve analysis or reservoir simulation with the proposed diagnostic plot, it is possible to predict when the well will reach critical flow conditions and proactively assess potential impact on reserves/production. Reservoir simulators have wellbore flow constraint options that can be related to the critical rate in the wellbore, but a constraint at reservoir level is still required to be included. This constraint can easily be implemented by setting a maximum WGR based on the correlation to avoid over estimation of hydrocarbons production forecast.

The simplicity of the proposed diagnostic plot aids engineers to identify and rank wells that need immediate or future interventions. Furthermore, this paper demonstrates that the diagnostic model can be easily calibrated with a single separator test close to its critical flow conditions. Future research could include additional reservoir parameters sensitivities such as skin, permeability, relative permeability, hysteresis, fluid types and finally incorporate this constraint as a standard into analytical and reservoir simulation models.

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