A systems managing approach to electric submersible pumps

Schlumberger’s Lorne Simmons looks at technical solutions to the the problems of high water cut

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By  Administrator Published  August 31, 2006

For mature wells and fields like many of those throughout the Middle East, high water cut is a frequent problem, which can be greatly helped with the use of electric submersible pumps (ESP) for artificial lift.

The benefits of ESPs are further enhanced with downhole monitoring, both to optimise production and to monitor the performance of the pump itself. That is, in addition to running the pump to achieve optimum production performance for the well and the reservoir, an operator must monitor the ESP itself to identify problems as soon as they occur so that better decisions can be made for remediation or repairs.

A modular systems approach to artificial lift provides excellent overall results with regard to both pump performance and production optimisation. Such a system comprises:

• Reliable artificial lift products including appropriate and reliable monitoring sensors.

• A surveillance and control system for remote data acquisition and transmission, alarms and alerts, and remote operations and problem resolution.

• A data analysis and optimisation service that is a framework for selecting candidate wells, analysing the data collected, making recommendations for adjustments and validating results.

This article discusses specific requirements for each of these three modules with regards to electrical submersible pumps, and provides some case studies from the Middle East where this systems approach has been particularly successful.

Monitoring and Sensors

Monitoring of ESPs requires reliable, accurate downhole sensors that operate continuously for the life of the pump and with the ability to track several specific parameters so that both pump operation and production performance are tracked. These sensors must also trigger programmable alarms for notification of problems and, for certain parameters, automated trips that will shut down the pump automatically (if certain measurements exceed or fall below a user-specified level) to prevent equipment damage or production-related problems.

Parameters that must be monitored for ESPs include: current leakage, discharge temperature and pressure, intake temperature and pressure, motor oil and winding temperature, motor and pump vibration and y-point voltage.

Additional benefit comes from sensors that also measure pressure and temperature at the sandface. It is important to get these measurements away from the effects of the ESP to determine more accurate well performance or possible production problems. For example, sandface pressure facilitates accurate transient analysis of build surveys for well performance monitoring while vibration provides an early indication of solid production.

Surveillance and Control

With the proper equipment in place to monitor and capture the necessary data parameters, that data then needs to be stored, analysed, transmitted and, when required, acted upon, all remotely and in real time. In addition, proper personnel must be automatically notified when events occur, and this system must also provide remote pump startup and speed control, and resolution of some pump problems.

The surveillance and control system must work seamlessly and reliably with the downhole monitoring equipment to perform all these tasks, and it requires the right information and communication technology and infrastructure in place to complete these tasks reliably and securely.

A key feature must include the ability to monitor and compare actual data against models for both the well and the pump, enabling remote pump adjustments and problem resolution. Specifically for ESPs, the surveillance and control system should allow: survey pump performance against pump curve models and well performance against well models; compare variable speed drive (VSD) operating plans to updated models of the pump and well production plan; detect early changes in reservoir sandface properties; maintain formation integrity and control water coning; and make pressure tests.

An automated surveillance and control module is particularly beneficial for mature fields with a large number of producing wells and in remote locations with limited access. It can also be helpful in mitigating issues with limited technical personnel because data can be transmitted to remote operation centers where teams of professionals can monitor multiple locations at once.

Analysis and Optimisation

This service takes the data captured in the previous system and combines it with an operator’s field data, some well testing, and advanced diagnostic tools to troubleshoot and optimise underperforming artificially lifted wells.

Performance is predicted for various well-operating parameters by matching onsite well data with wellbore models of an operator’s artificial list system. A complete dataset enables efficient and accurate testing of recommendations to adjustments to the artificial lift system.

This testing allows adjustments to the actual system to be made confidently and rapidly, so that production improvements can be realised as soon as possible.

Expected baseline improvement for this analysis and optimisation is a 10%t net increase to oil production, but far more significant gains have been achieved, verified by production measurements taken before and after optimisation. For example, from an operation in the Middle East, an 88% oil production gain was achieved from 30 wells in a remote land operation with high water cut and high-production ESPs.

Case Study Examples

Phoenix MultiSensor monitoring systems were installed with ESP systems in 18 wells in the Wafra Field.

In one example, the monitoring system’s vibration reading provided the operator with early warning of abnormal pump wear. The pronounced vibration response prompted a detailed analysis of lifting performance with Schlumberger’s LiftPro service software, the analysis and optimisation service element of this proprietary modular system.

The graph image shows the increase in vibration during a three-week period that alerted the operator to the problem. It was determined that unexpected sand production caused a breakdown in the pump performance and the onset of severe wear, which caused the pump intake pressure to rise (pump lost Pd (head)). The well flow rate decreased and the pump moved into downthrust causing further wear. The vibration readings peaked at 18 gn, indicating a major problem with pump operation. The ESP was severely worn and the production was lost. However, the operator had enough information to decide whether to run the pump to destruction or organise workovers.

In another example from this field, a programmed sensor tripped an ESP when the motor temperature reached a non-life-threatening 120ºC, protecting the ESP from exposure to excessive temperature, minimising ESP shutdowns, and prolonging run life and production.

Post-event data analysis using LiftPro XP software showed the electrical submerisible pump as running against a closed valve, which increased the motor temperature because there was no cooling flow.

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