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The induction motor has dominated the global ESP market for decades; however permanent magnet motors (PMM) are gaining acceptance for use in artificial lift. Some PMM vendors have made claims of 20% - 30% reduction in electric operating costs, improved efficiency, and wider applications for today's challenging wells. This paper describes a testing program conducted to understand the characteristics of PMM's, to verify vendor claims and evaluate how to leverage this downhole motor technology to reduce operating expenses. Two International Oil Companies (IOC's) partnered to sponsor a Motor Evaluation Test (MET) program from 2014 - 2015. A motor test protocol was drafted, and ESP motor sizes of 100 HP 450 series were targeted for evaluation. Six ESP vendors agreed to participate, contributing their motor and variable frequency drives (VFD). Four induction motors and four permanent magnet motors, each partnered with the vendor supplied VFD, were evaluated. The objective of the testing was not to differentiate the vendor's products, but to understand the differences in the motor technologies. An independent third-party witness was selected from industry experts to supervise the testing, ensuring to follow the test protocols, manage data security, and test validation. The results were analyzed, documented and reported to vendors by the sponsor companies. The PMM was found to be a cost competitive alternative to the IM for equivalent ESP installations with a VFD. In existing fields, a phased-in approach to replace failed IM with PMM may be economic. For new field developments the PMM offers the benefits of power savings and use in challenging well bore configurations. Alternatively deployed (AD) ESP with PMM may offer reduced well intervention cost as well an improved ability to pass through build angles that would challenge the longer IM system.

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Chevron began development of an offshore oilfield in Angola, West Africa, in 1997 using ESP's as the preferred artificial lift method due to favorable reservoir and fluid characteristics, and limited capacity of the available gas lift injection infrastructure. The initial ESP's were deployed on coil tubing (CT) to reduce initial costs, future ESP replacement downtime and the dependence on the availability of a jack-up rig. Due to difficulties experienced in supporting the CT operations in the remote area, subsequent new completions and ESP replacements have been carried out utilizing standard threaded tubing. To date, there are 28 wells producing with ESP's from 3 platforms. ESP run life has been excellent over the life of the field with 5-year MTF, and some ESP's surviving longer than 10 years. However, when an ESP fails it must compete with other economic opportunities within the +600 well portfolio for rig time to replace the failed equipment and return to production. Over time increasing rig day rates and declining oil production rates have created challenging economics. Typically, more than one ESP failure on a platform is required to provide competitive project economics to justify mobilizing a rig, resulting in well downtime increasing to an average of over 12 months. This paper describes the process undertaken to evaluate and select an alternative deployed ESP system to significantly reduce workover costs and time-waiting-on-replacement, improve economics and ensure continued field development. This was a collaborative effort of more than a dozen partners, service companies and contractors across 3 continents. It includes detailed evaluation of the existing well bores and requirements for the new ESP's. Requirements comprised a new wellhead design, larger tubing (resulting in tighter tolerances), a new cable clamp design, VFD controller certification, confirming pumps could be replaced on tractor due to high well deviation, etc. One example was the decision to perform the ESP connector head, motor lead cable and ESP cable splices in a US factory to improve reliability and reduce time over rig floor connections. Multiple FIT tests were performed and evaluated to ensure project success. The first two new alternatively deployed ESP's were successfully installed and placed on production in June 2017. A surface electrical failure in a VFD in early 2018 resulted in a damaged downhole ESP motor in one well. The motor was successfully retrieved and replaced via wireline tractor, at a hole angle of 88°, under pressure, without killing the well. The well was successfully returned to production in August 2018.