Free Gas and ESP; Case Studies Illustrating the Difference Between Flowrate Oscillations, Gas Locking and Instability

Abstract

Abstract Electrical submersible pumps (ESP) oil well production often requires handling large amounts of free gas, leading to numerous ESP trips, which limits drawdown. To maximize production and eliminate downtime, a technique was developed to distinguish between three possible different causes i.e. gas locking, ESP flowrate oscillations, and dynamic instability and thereby improve design and operating procedures. The theory is illustrated with case studies and real time data. The main objective was to determine the cause of observed well instability and understand the interaction between the pump and the remainder of the wellbore. In addition to using classical steady-state nodal analysis, the analysis used downhole flowrate simulations to capture ESP transient oscillations. Furthermore, system dynamic stability analysis identified when and why the interaction between the pump and the wellbore results in flowrate and pressure instabilities, which can lead to pump mechanical failure. Combining holistic well analysis with a review of case studies led to identifying several types of gas-induced problems, root causes, and solutions. For each type, diagnostic techniques were developed in addition to design and operational recommendations. Interestingly, in some cases, where traditional diagnostics would have pointed to gas locking in the pump as a root cause, the new analysis demonstrated that well slug flow regime dominated the well and ESP behaviour. A key conclusion from the analysis was that real-time measurement of intake, discharge, and wellhead pressures is necessary to correctly distinguish between pump gas lock, well flow regime issues (e.g. slugging) and system instability. Furthermore, real-time downhole measurement of transient flow rate through the pump is indispensable feedback to operators for managing wellhead pressure and pump frequency with the aim of maximizing drawdown, stabilizing the well, and extending the ESP run life. A key finding is that irrespective of the cause, it is always best to operate the ESP at rates greater that the best efficiency point, which usually requires over staging the design. Finally, the case studies presented in this paper illustrate the importance of capturing the relative slopes of the pump and well system curves as well as how they change with time. Combining new models with real-time data improves the accuracy of diagnostics and therefore enables increasing the GVF that ESP wells can handle and thereby maximizing production by either eliminating trips and/or maximizing drawdown.