Summary The Otter field in the northern North Sea has been developed with three subsea production wells, each equipped with dual electric submersible pumps (ESPs). Dual ESPs were selected because they maximize well availability and minimize operating costs associated with workovers. The field is located 21 km from the host platform, making this development the longest subsea tieback with ESPs completed to date. The equipment selected for the ESP system is described here, including downhole, subsea, and topside equipment. The rigorous testing program is also described, proving that ESPs could be successfully operated and controlled as well as receive data at such a distance from the variable-frequency drives. The experience gained during the development and the operational philosophy developed for the Otter field will serve as a guide to future long-stepout or deepwater subsea developments by identifying critical components. Factors limiting the development of fields at greater stepouts are also discussed. Conclusions on the steps required to implement a successful development and some of the pitfalls to avoid are listed in this paper. Introduction The Otter field lies in the northern area of the North Sea on the edge of the Viking Graben area (see Fig. 1). The field is operated by Total E&P UK plc on behalf of the joint venture partners Dana Petroleum (E&P) Ltd., Esso E&P UK Ltd., and Shell UK Ltd. The field was discovered in 1978 by Phillips Petroleum; however, it remained undeveloped until 2002 because of the limited size of the discovery and technical challenges. Operation of the field was acquired by Fina Exploration in 1997, and interest in developing the field renewed. To prove reserves and well deliverability, a delineation well (210/15a-5) was drilled and tested in 1998. The results of this well were encouraging, and a development screening study was launched. A further delineation well was drilled in 2000 to confirm a field extension to the north before launching the development project. The hydrocarbon reserves in the Otter field are found in faulted compartments of the Middle Jurassic Brent sequence, with the top reservoir at approximately 2000 m below sea level. The reservoir has good porosity and excellent permeability, with horizontal wells able to produce in the range of 15 to 20,000 bbl/D. The reservoir fluid was undersaturated at initial conditions, with a gas/oil ratio of 450 scf/bbl, and contains low levels (<0.3mol%) of carbon dioxide and traces of hydrogen sulfide. The reservoir was initially normally pressured at approximately 62 bar greater than the bubblepoint. Wells flow during the initial production stage but require artificial lift once the water cut increases or pressure depletion occurs. Development Strategy. The development consists of three production wells, each equipped with dual ESPs, and two water-injection wells to provide pressure support. A full description of the Otter development can be found in Ref. 1. The subsea equipment comprises a combined four-slot drilling template with integral production manifold, which were installed before drilling operations started. The water depth at the template location is 184 m. A satellite well (the delineation well 210/15a-5, located 35 m from the main installation) is tied in to the template as a water injector. Both the template and satellite well have independent protection structures to avoid damaging the installations with dropped objects or fishing activity. The manifold is tied back to the Eider platform, operated by Shell UK, at a distance of 21 km. The Eider platform receives Otter production by means of a 10-in. line and supplies injection water to the manifold through a 10-in. line. The flowlines are linked at the manifold to allow round-trip pigging. Eider also provides control and monitoring of manifold and well functions by means of a single multicore umbilical and provides power for the ESP via three subsea cables. The design of the manifold and Xmas trees is such that all tie-ins of the completed wells can be carried out from the drilling rig with the onboard remote-operated vehicle (ROV). A schematic representation of the development is shown in Fig. 2. Development Schedule. The Otter development project was sanctioned in December 1999, and major contracts were placed in the following months. The combined template, manifold, and protection structures were installed in October 2000. Pipelines were laid in September 2001. Pipeline tie-ins, cable, and umbilical installation and hookup were completed during the winter of 2001/2002. Drilling operations commenced in June 2002 with the semisubmersible rig Transocean John Shaw. Production from the first well started in October 2002, with drilling and completion operations continuing on the subsequent wells while producing from the template. Drilling operations were completed in May 2003. Artificial-Lift Options Considered It was identified early that selecting the artificial-lift method for Otter would be critical to the economic success of the development. Several host platforms were considered, one of which had the possibility of supplying lift gas, and the option of using a floating production, storage, and offloading vessel (FPSO) to limit investing in subsea infrastructure was also considered. Gas Lift. At the initial stage, gas lift was the preferred option because it was believed to be the most reliable and, therefore, offered the lowest operating costs. However, detailed studies into the multiphase flow of produced hydrocarbon and lift gas in the export line indicated that slugging could be a significant problem, which could give rise to severe difficulties during production. Operability studies also indicated that difficulties controlling a multiwell gas lift system a long distance from the host platform could cause additional flow instability. Hydraulic Submersible Pumps. This technology is gaining popularity2 and was believed to offer potential advantages for a remote subsea development. However, the open-loop systems most commonly used increased the volume of produced fluids to be treated on the host installation and would have limited the plateau oil production rate. Closed-loop systems were considered, but this was seen as unproven technology, particularly for a subsea application.

The Otter field in the Northern North Sea has been developed using three subsea production wells each equipped with dual electric submersible pumps (ESP). Dual ESP were selected as they will maximise well availability and minimise operating costs associated with workovers. The field is located 21 kilometres from the host platform, making this development the longest subsea tie-back with ESP completed to date. The equipment selected for the ESP system is described, including downhole, subsea and the topsides equipment. A rigorous testing programme was performed to prove that over such a distance from the variable frequency drives ESP could be successfully operated, controlled and data received. The experience gained during the development will serve as a guide to future long step-out or deep-water subsea developments by identifying critical components and the operational philosophy developed for the Otter field. Factors limiting the development of fields at greater step-out are discussed. Conclusions can be drawn on the steps required to implement a successful development and some of the pit falls to be avoided. Introduction The Otter field lies in the Northern area of the Northern North Sea on the edge of the Viking Graben area (see Figure 1). The field is operated by TotalFinaElf exploration UK plc on behalf of the joint venture partners Dana Petroleum (E & P) Ltd, Esso Exploration and Production UK Ltd and Shell UK Ltd. The field was discovered in 1978 by Phillips Petroleum, however the field remained undeveloped until 2002 due to the limited size of the discovery and technical challenges. Operatorship of the field was acquired by Fina Exploration in 1997 and at this time interest in developing the field was renewed. To prove reserves and well deliverability a delineation well, 210/15a-5, was drilled and tested in 1998. The results of this well were encouraging and a development screening study was launched. A further delineation well was drilled in 2000 to confirm a field extension to the North prior to the launch of the development project. The hydrocarbon reserves in the Otter field are found in faulted compartments of the Middle Jurassic Brent sequence, with the top reservoir at around 2000m below sea-level. The reservoir has good porosity and excellent permeability, with horizontal wells able to produce in the range 15-20,000 bbl/d. The reservoir fluid was under saturated at initial conditions with a gas/oil ratio of 450 scf/bbl, and contains low levels (<0.3%mol) of carbon dioxide and traces of hydrogen sulphide. The reservoir was initially normally pressured, approximately 62 bar above the bubble point. Wells flow during initial stage of production, but require artificial lift once water cut increases or the pressure depletion occurs. Development Strategy The development consists of three production wells each equipped with dual ESP and two water injection wells to provide pressure support. A full description of the Otter development can be found in Ref 1.

Electric submersible pumps (ESPs) used as an artificial lift method have a relatively short life span despite the industry's efforts to improve reliability. The resulting economic impact realized in workover costs and production loss is substantial. This has driven efforts toward design change by introducing retrievable ESP independent of the completion string and hence extending ESP wells’ life cycle. This paper covers the company's first installation of a rigless shuttle ESP system, including a customized completion design and special deployment procedures. A comprehensive approach was taken to deploy this technology, from procurement to installation, in a detailed process. It started with acquiring reservoir data and setting up matching specifications for the required equipment in order to issue a competitive tender. Following technical evaluation of tender submissions, the most suitable technology was selected for the field trial. The completion design was then customized to accommodate the new technology without jeopardizing well integrity. Fit-for-purpose well barriers were incorporated in the completion design because conventional barriers were not applicable. Detailed running procedures were produced from dedicated workshops and risk assessment reviews. Project execution was closely monitored and firmly controlled. The company has accomplished the first successful offshore deployment of the shuttle ESP system in the MENA region. The system was deployed using tailored procedures for installation and comprehensive testing while ensuring compliance with well barrier requirements. Following successful deployment, the ESP performance was positively tested. Part of the project validation requirement was a rigless retrieval and redeployment the ESP system. The ESP retrieval process was challenging due to unexpected tar or asphaltene material encountered above the ESP. However, contingency retrieval procedures were promptly amended with detailed steps to overcome this challenge, which led to successful retrieval and redeployment of the ESP without NPT. This success is paving the way for a major change in the company's field development strategies by considering rigless, replaceable ESP systems instead of the conventional ESPs. This paper sheds the light on a new advancement in completion technology that has a strong potential to prevail for ESP-lifted wells in the future. The focus of the paper is on the design and execution parts, as well as installation and post-completion operations while maintaining sufficient well barriers―the challenging aspect that appears to be slowing down the wider use of this technology as a replacement of conventional ESP completions.

One of the biggest challenges faced by the industry in general is the cost incurred due to the limited operating life of electric submersible pump (ESP) systems and the need for workover operations (WO) to replace the pumps. The impact of current methods on the total cost of ownership is well understood within the artificial lift industry. To address this problem and reduce the dependence on rigs for WO, the owner is undertaking a series of field trials of the latest generation of rigless wireline-deployed ESP replacement systems. This paper details the field experience gained to-date while carrying out the appraisal for this technology. This field trial includes harsh downhole environments with high H2S content. It also addresses several key parameters such as success criteria, selection of completion equipment, well control contingencies to adhere to operator’s policies, and details of the planning and execution phases. The paper also provides a comparison between the conventional and the rigless ESP deployments, as well as results and lesson learned. The partial results of this initial technology appraisal indicates that it has the potential to drastically lower ESP operating costs by reducing production deferment, minimizing HSE exposure, diverting rigs to other operations, and positively impacting asset value. By sharing real-world lessons learned about technology deployment, the paper will serve as a guide to other operators as they look for ways to improve ESP cost efficiency.

An operator planned to install ESPs to overcome high water cut and minimize the gas supply risk for a gas lift completion at a platform in the Gulf of Mexico. The platform is an oil collection point and its continuous operation is essential during any rig-assisted interventions. To maintain platform operation, three wells were selected for deployment of rigless electrical submersible pump (ESP) replacement systems to avoid the future use of a workover rig. The challenge was to allow a single-trip ESP deployment using the crane facilities with existing height limitations. A special surface connection system was designed to allow long ESP sections to connect under pressure at the wellhead. The technology is based on a propriotery system and method of connecting long strings at the surface using a surface lubricator and an adapted deployment stack. The system elements are located between the pump intake and protector seal sections of a standard ESP string that can easily and economically sourced in most locations. This new technology reduces the number of wireline/slickline runs needed, and the system features allow verification of mechanical connection integrity at the surface prior to deployment in the well. The successful deployment and commissioning of a rigless ESP replacement system in the SM 130 A-26 well in the Gulf of Mexico was completed in October 2019 without incident. Prior to the deployment of the rigless ESP replacement system, it was decided to perform hydraulic stimulation operations to improve the well productivity. This operation resulted in higher than expected well inflow with increased water cut. At the time of writing this paper, the ESP system had recently failed to start due to stuck pump (possibly scale related). Due to the ability to perform a rigless system upgrade for the unanticipated well inflow conditions, the operator is planning for the first rigless replacement of the existing ESP to achieve higher flow rate during the last quarter of 2021. The successful deployment of the alternative ESP deployment technology demonstrated the potential to improve the economics of the existing production facilities by reducing production deferment, minimizing health, safety, and environment (HSE) exposure; and improving the asset value. This paper discusses the engineered solution and application of the technology required to deploy long ESP strings, modifications required for the specific well conditions, and the lessons learned during the first successful deployment of rigless ESP technology in the Gulf of Mexico. Due to the performance and capability demonstrated in the first successful installation, Talos Energy has recently installed its second rigless ESP replacement system in a recompleted zone and is planning for installing its third system in the SM 130 field in 2022.