Sizing electric submersible pumps (ESPs) for unconventional wells presents new challenges compared to traditional applications, typically conventional, vertical wells. These challenges are due to the highly dynamic, rapidly changing nature of unconventional wells compared to conventional wells. Traditional ESP sizing software is not structured to design for dynamic conditions, but rather a single point in time. The objective is to design an ESP tool fit for unconventional design applications. Because of the rapidly changing conditions of unconventional wells, it is difficult to balance the lifetime sizing needs of the equipment with needs of the equipment during peak demand. Changing flow rates, water cuts, pump intake pressure (PIP), and gas oil ratio (GOR) have a great effect on stage size, total dynamic head (TDH), and motor horsepower (HP) requirements at different points over time. The new design tool will allow the user to upload a well type curve and help chose a pump and motor combination by calculating different TDH and motor horsepower requirements for each day over the life of the well. Optimized ESP sizing will allow oil and gas operators to install one initial ESP at the completion of the well which lasts until production rates have declined to the conversion point of a lower rate form of artificial lift. This has significant cost savings implications both for capital and operational budgets, by avoiding overspending on oversized equipment upon the initial install of the wells, and greatly reduced the work of the operations team by eliminating workovers needed to downsize equipment. The use of this design tool allows much more rigorous reviews of vendor designs, to avoid over sizing equipment while still capturing high initial production rates during the early production life of the well. ESPs designed using the new design tool will be compared to historical ESP designs provided by the vendors on analogous wells. Production numbers, run life, and historical ESP data streams will be compared between wells designed using the old methodology vs the new design tool.

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.

Over the last few decades numerous improvements have been made on electrical submersible pump (ESP) components, however, ESP reliability has just marginally increased. Operators have tried different approaches to incentivize ESP vendors to improve ESP reliability, including: strategic alliances, rental agreements, performance based contracts, just to name just a few. None of these approaches seem to have worked and the high reliability goal remains elusive. ESP failures have important economic implications for oil and gas operators, including nonproductive time (NPT), production deferral, production losses and the high cost of ESP replacements, especially for offshore or remote wells. Saudi Aramco has set an aggressive target of operating ESPs an average of 10 years without failure. This paper explores the likelihood of developing such an ESP system, it discusses the fundamental issues that currently prevent achieving higher reliability levels and also evaluates from different angles the potential solutions for approaching the reliability improvement challenge. Finally, it discusses the technical, operational, economic and market implications of such alternatives for both oil and gas operators and ESP vendors.