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.
Introduction
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.
Optimization Strategy
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 stableflow 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.
Phase III—Further VSD Test Campaign and VSD Commissioning as Permanent Solution. The plan is to continue with the VSD testing of the remaining 24 wells with two portable power skids. Estimated time was 7 months. The implementation of the VSD solution considers the following steps:
As a permanent solution, VSDs will be implemented in the successful wells (three wells already tested from the VSD trial campaign) by procuring new power skids equipped with VSDs and step-down and step-up transformers.
Where necessary, old wells will be equipped with VSDs; future wells will be fitted with VSDs as standard practice.
The first step will be repeated per the VSD test results.
Anticipate Workover for ESPResizing and -Deepening Jobs
The second optimization technique considered resizing the ESPs and deepening the pump. More than 50% of the wells were completed in the upper reservoir (U1), which has poor rock properties and low pressure support with respect to the lower reservoir (U2). One of the main identified issues was the relatively low intake pressure in most of the wells, facilitating gas liberation and consequent trapping in the annulus. In addition, the annulus lines are not connected to the flowlines and there are no dedicated venting lines. Moreover, wells were completed without ESP packers because of a low gas/oil ratio.
Well-Design-Strategy Review
The asset team paid particular attention to reviewing the well-design strategy for production optimization. Originally, the pump-setting implication was not considered in the early well-design phase. In all the wells for which intake pressure is low (less than 400 psi), a direct relation to the shallow pump- setting points exists. In all cases, the main constraints include limited clearance to set the ESP and Y-tool during the completion phase and setting the top of the 7-in. liner 1,000 ft (vertical depth) above the top of the reservoir interval. On the basis of the well production history and the preceding considerations, a new well-design strategy for the U1 reservoir was discussed and approved for use in a pilot well.
Summary and Conclusions
An optimization strategy was tested and showed significant added value for the operating company, establishing guidelines as well as a standard methodology for further production- optimization activities. Relevant conclusions are as follows:
Upgrading the ESP surface equipment by changing from SWB to VSD showed a significant improvement of more than 1,700 BOPD added from the three wells tested. This represents a production increase of more than 20% for individual pilot cases and 2.4% for the field production quote.
Power consumption can be decreased considerably when the ESP systems are operated by VSDs rather than SWBs. Using VSDs resulted in 20% less power being required to achieve production equivalent to that achieved using the existing SWB.
The cost of the ESP can be optimized when a VSD is used. Fewer stages and optimum motor sizes can be selected to establish a conservative differential pressure across the choke.
A VSD operation provides great flexibility to monitor and control the drawdown to be applied in the wellbore to prevent or mitigate early water breakthrough.
It has been possible to reactivate some unstable wells by adding more lifting head when the frequency was increased. One case study showed stable operation at flow rates greater than 700 BOPD.
Anticipated workover for ESPresizing and -deepening jobs can have a significant effect. One case study shows potential gains of 300 BOPD, which represents more than 50% of the actual well production. In addition, it will be possible to mitigate any potential gas-lock issues from poor intake submergence.
A review of well-design strategy for the U1 reservoir needs to be implemented in upcoming wells. One case study showed a production increase of more than 25% (250 BOPD) by setting the pump 490 ft (vertical depth) deeper.
Setting the top of the 7-in. liner in Well No. 5 at 3,730 ft (740 ft deeper than the conventional plan) led to saving extra well interventions for further ESPdeepening jobs.
A further well-test campaign is required in the remaining 24 candidate wells in order to assess the oil gains and plan the optimization technique accordingly.
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