The advent of high-power multiphase pumps is changing the world of oil production. In particular, they allow continued production from fields that are nearing the end of their useful lives. These revolutionary pumps have been in operation since autumn 1999 on the Dunbar platform, in the UK sector of the North Sea.
Multiphase pumping (MPP) is essentially a means of adding energy to the unprocessed effluent. This technique allows the transport of gas and liquid mixtures over longer distances without the need for prior phase separation. It also empowers the wells to produce at a lower wellhead flowing pressure (WHFP). Thus, the production and ultimate recovery from existing fields and weak wells increase. The life of a field can be extended and development costs can be reduced. The Dunbar field, operated by Total, is a perfect example of how these benefits have been realized in practice.
The Dunbar field in detail
The Dunbar field is located 120 km northeast of the Shetland Islands and 440 km from Aberdeen, UK. Dunbar is a wellhead platform that is operated as a satellite of the Alwyn North Platform located 22 km to the northeast. In the first phase of production, the wellhead pressure was sufficient for the effluent to flow naturally from Dunbar fields along a 16-inch multiphase pipeline to the Alwyn platform (Fig. 1). The introduction of multiphase pumps in Dunbar allowed production to continue in the face of declining well-head pressure.
Fig. 1 The Dunbar and Alwyn fields.
Minimizing space and weight with MPP
The operating company considered two main alternatives to develop their field. One was a conventional system (Fig. 2) that comprised a separator operated at low pressure with the liquids pumped and the gas compressed upstream of the multiphase pipeline.
The other was an innovative system (Fig. 3) that used MPP to combine several wells and boost the low-pressure wells directly into the multiphase pipeline. Why did the operating company select the Sulzer MPP solution over a separator-based solution? Weight and space restrictions on the Dunbar platform favored the design of the MPP cantilevered module extension. This module was over 30% lighter than a conventional system. Installing the pumps vertically minimized the space requirements. There were no major modifications required to the existing process facilities other than tying in the MPP.
Fig. 2 Conventional concept.
Fig. 3 Innovative concept using multiphase pumps.
Smart well segregation scheme
A well segregation scheme provides operational flexibility. This scheme of three independent production headers — high pressure (HP), low pressure (LP), and low low pressure (LLP) — makes maximum use of the natural energy of the wells. This minimizes the electrical power requirements. HP wells bypass the pumps. LP and LLP wells are routed to one of the two MPP to maximize production. In the early years of MPP operation, this routing was based on the wellhead pressures (see LP and LLP wells in Fig. 3). In recent years, other factors — such as gas-to-liquid ratio and water production — have also influenced the routing. At present, about 20 wells are routed to the MPP; there are plans to route other wells there in the future to accelerate production.
In 1999, the largest offshore multiphase pumps in the world were installed on the Dunbar platform. No other offshore multiphase pump is larger, even today, in 2016. The two pump packages were incorporated into a module at the fabrication yard. The module, which is 12 x 7.5 x 19 meters (LxWxH) in dimension, weighs 650 tons (Fig. 4).
Sulzer and ABB worked as partners to supply the pump set packages. Each pump set comprises the following main items: Process cooler, buffer tank at pump section, Sulzer multiphase pump, epicyclic gearbox, lube oil and seal oil systems, electric motor and frequency converter, transformer and antiharmonic filters.
The design parameters of the pump in use are:
- Total capacity 180 000 barrels per day (bpd)
- Gas volume fraction GVF 75%
- Speed range 3 500 to 6 000 rpm
- Motor rating 4 500 kW
Fig. 4 Inside the module is the Dunbar multiphase pump.
MPP design upgrades
The reducing Dunbar wellhead pressures over time increase the ratio of gas-to-liquid flow rates. This produces liquid slugs that cause MPP instability, particularly, increased subsynchronous vibration, which sometimes causes MPP trips.Sulzer R&D center located in Winterthur, Switzerland, dedicates considerable effort to developing new solutions for MPP. The charts (Fig. 5 and 6) show the reduction in subsynchronous vibration resulting from a revised balance drum design. The influence on vibrations is remarkable. Fig. 5 shows vibrations with the conventional balance drum, Fig. 6 with the revised balance drum.
Fig. 5 System vibrations with conventional balance drum.
Fig. 6 Reduced system vibrations with revised balance drum.
Good collaboration between Sulzer and Total made it possible to apply these improvements to the Dunbar MPP in 2013. This helped to improve the stability of the pump. Three mechanical modifications to the pump led to success. A redesign of the balance drum provides additional damping of the Dunbar MPP rotor on the balancing machine. Significant changes to the manufacturing process for hollow shafts provide additional stiffness and better pump rotor-dynamic behavior. The installation of a Sulzer-patented damping device on the shaft provides additional damping.
Improved control reduces vibrations
The pump can either run in manual or automatic mode. In manual mode, the operator adjusts the speed by hand to maximize the production while maintaining the pump within its preferred operating range.
Sulzer improved the control system of the MPP by developing an automatic mode. In this mode, the operator defines a torque set point, and the pump speed is adjusted by software automatically to reach this set point. Automatic torque control dampens liquid slugs to minimize pump vibration. These modifications together with good management of well routing allow further reduction of wellhead pressures and increased MPP availability of over 90%.
Evolution of process conditions from 1999 to 2016
The exhaustion of the Dunbar wells has led to a significant decrease of the wellhead pressures (Fig. 7). These pressures have dropped from a pressure of 70 bar(g) in 1999 to a pressure of less than 30 bar(g) in 2016. The discharge pressure required has also decreased — from about 125 bar(g) to 62 bar(g). Consequently the inlet gas volume fraction (GVF) has increased from 77% in the early days to 90 – 92%. Thanks to the wide range of operation of the helico-axial hydraulics, the pump is still in operation with the same hydraulic design it had in 1999.
The flexibility of the Sulzer MPP will help the company Total E&P UK optimize late-life production from the Dunbar reservoir. Wellhead pressures of 20 bar(g) and below can be processed in the future without the need for significant investment.
Fig. 7 Pressure development at Dunbar field over the years, measured at multiphase pump G2100B.