Electric Submersible Pumps (ESPs) are complex, high power electromechanical systems that operate in extreme environments under very tight geometric constraints. Despite the efforts of suppliers and operators ESPs will eventually fail, requiring replacement. In addition, it is sometimes necessary to intervene in a well to optimize or remediate production – a process not possible, or limited, with an ESP restricting access to the reservoir or lower completion. The process of installing or removing an ESP has changed little since their introduction almost 90 years ago. Removing (or installing) a conventional ESP requires pulling the tubing string, replacing the ESP and reinstalling the tubing string with the use of a rig or pulling unit (a "heavy workover" or HWO). This expensive, time consuming process creates significant logistical challenges and QHSE risks along with significant lost production. Increasing use of ESPs, along with today's difficult economic environment has brought a renewed interest in the potential of alternatively deployed ("rigless") ESP systems to improve project economics by reducing the cost of interventions while simultaneously increasing the oil produced per well. Evaluation of the economics associated with alternative deployed systems is not straightforward, with many nuances which are not obvious. This paper seeks to develop a framework which can be used to compare the economics of wireline retrievable ESP systems (WRESP) to conventional, tubing deployed ESP systems, taking into account the uncertainties surrounding the reliability of the various system components (both conventional ESP and WRESP) through the use of Monte Carlo simulation. This framework will be used to compare the likely economic outcomes in six ‘typical’ operating environments: West Africa Offshore, Middle East Land (high rate and moderate rate), Asia Offshore, Alaska, and US Land (lower 48) using (to the greatest extent possible) actual reliability data and operating parameters in these environments. The production and economic outcomes of both conventional ESP and WRESP deployments will be compared and presented along with the sensitivity of these outcomes to typical uncertainties in each of these environments.

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.