Otter: A 21-Kilometer Subsea Tieback With Dual Electric Submersible Pumps

Abstract

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.

Subsea Processing: A Holistic Approach to Marginal Field Developments

“…The energy power required to boost the fluids is much reduced as the FSU will typically be positioned 0.5 to 3Km away from the subsea facilities 13 . However, the pumps required to cover this is very readily available.…”

Analysis of Possible Applications of Dual ESPs—A Reservoir-Engineering Perspective

“…Published DESP applications in the subsea environment have established the feasibility of coupling a conventional downhole ESP with a subsea booster system in terms of increased equipment reliability and improved economics (Horn et al 2004). We used a simple numerical model to understand the effect of various parameters on reservoir performance with such a DESP completion.…”

“…In general, applications of the second pump have been either to increase the pumping capacity (Moreno et al 1998) or to act as a backup to improve the reliability of the pumping system (Sarawyn 2003;Horn et al 2004). DESPs have been used for managing reservoir issues such as water coning (Gonzalez et al 2003) and multiple production zones (Almeida et al 2002;Magherini et al 2003).…”

Sensorless control of a PMSM with a transmission system including shunt branches

“…These ESPs are basically composed of a pump and a motor, and are usually supplied by a topside variable speed drive (VSD) through a feeding cable that can have a length of several kilometers [1]. These ESPs range up to a few MW in size, and were originally driven by induction motors (IM).…”