Production Optimization With Artificial-Lift ESP Pilot Systems in a Mature Oil Field
- Adam Wilson (JPT Special Publications Editor)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- July 2015
- Document Type
- Journal Paper
- 100 - 101
- 2015. Society of Petroleum Engineers
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- 239 since 2007
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This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 171917, “Production Optimization Over 20% With Artificial-Lift ESP Pilot Systems in Mature Oil Field: Case Study From Middle East,” by Hector Aguilar, Aref Ali Al Marzooqi, Tarek Mohamed El Sonbaty, and Leigber Villarreal, ADCO, prepared for the 2014 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 10–13 November. The paper has not been peer reviewed.
A production-optimization strategy of an artificial-lift system resulted in the mitigation of challenges related to reservoir heterogeneities and completion design. An approach integrating reservoir dynamic data and electrical-submersible-pump (ESP) performance was established as a guideline for ESP surveillance and diagnostics and for targeting candidates for production optimization by implementing at least one of the possible solutions: upgrading ESP surface equipment, anticipating workovers for ESP-resizing and -deepening jobs, and reviewing well-design strategy.
The field is an anticlinal structure 26 km long and 6 km wide with two main complex carbonate reservoirs, upper (U1) and lower (U2), exhibiting considerable lateral and vertical lithological changes and, consequently, variations of reservoir properties.
Oil production started in 1983 through an initial-development phase. An artificial-lift project using ESP systems was implemented in 1994 to increase and sustain oil production. All producer wells are equipped with an ESP, a Y-tool, and a single completion string. All wells completed before 2014 have been operated on a fixed frequency of 50 Hz through switchboard (SWB) panels.
A full-field development plan was reviewed to increase oil production by 40% by the end of 2013, to consider long-term sustainability in view of future expansion, and to stretch the target plateau beyond 2013. This target has been reached mainly by increasing the number of infill horizontal producer wells but also through the upgrading and expansion of surface facilities to handle increased volume of produced fluids.
The asset team managing the field was presented with the challenge of increasing field production. An experienced project manager was assigned to lead a team representing different disciplines (development, engineering, operation, and ESP design and optimization) that cover all surface and subsurface aspects of the project. A detailed performance review was conducted per well for the entire field. It indicated that 27 wells were suitable candidates for potential production optimization, representing approximately 50% of the wells. The three well categories were defined as follows.
Boost Production. This includes wells in which the ESP operates at a relatively high intake pressure. The only identified constraint has been the fixed frequency of 50 Hz delivered by the existing SWB panels.
Reactivate Production. This includes wells that did not produce at stable flow rates or never produced because of shallow ESP settings.
Sustain Production. This includes wells whose performance has been deteriorating because of backpressure or wells with increasing water cut. The optimization team has identified three possible optimization techniques to be evaluated and implemented in pilot wells on the basis of well category.
Optimizing ESP Surface Equipment A methodology established priorities and qualified the best candidates to replace existing SWB panels with variablespeed drives (VSDs). The project was conducted in three phases.
Phase I—Well Modeling. Wells were modeled through nodal-analysis software on the basis of historical production and actual performance data from recent available production tests to identify wells in which the backpressure effect becomes relevant and lifting capacity has deteriorated considerably.
Phase II—VSD Trial Test Campaign. Three out of 27 wells were tested with VSDs by hooking up a portable power skid for a long-duration test.
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