High-Voltage Subsea Pump Enables Low-Cost Boosting

Fig. 1—Subsea umbilical-termination assembly.

Introduction

The topside-generated electric energy used to power subsea pumps is delivered through a combination of transmission and distribution equipment. A medium-voltage (MV) circuit breaker is required between the power generator bus bar and the variable-frequency drive (VFD). The VFD, typically installed in a temperature-controlled room, is connected to the topside umbilical-termination unit (TUTU). The TUTU junction box interfaces the surface cables to the subsea umbilical. Depending on the water depth and the horizontal distance between the floating production unit and the load, the umbilical can be tens of kilometers long. The greater the distance, the greater the cost. Subsea, the umbilical is terminated on a subsea umbilical-termination assembly (SUTA), from which an MV electrical jumper connects the SUTA to the subsea motor (Fig. 1, image at the top of the article). This system is also known as SEPS, and its cost and complexity represent a substantial part of the subsea boosting system Capex.

The SEPS is designed and sized in accordance with the power load requirements. Typical MV subsea loads include electrical submersible pumps, water-injection pumps, and multiphase pumps (MPPs).

Currently, the subsea loads are typically greater than 1 MW and are supplied at voltages ranging from 4.16 to 6.6 kV at relatively high amperages. The power load itself is driven by the process requirements. For a subsea boosting project, differential pressure, flow rate, fluid viscosity, and gas-volume fraction are key parameters that will define subsea motor-shaft power.

This paper describes the advantages of a lower-transmission-current SEPS and how the problem was addressed through the development of a higher-voltage motor.

Alternatives for Operational-Envelope Expansion

Alternative A: Increase umbilical cable cross section. There are several advantages to increasing the conductor cross section.

  • SEPS configuration is maintained.

  • The number of installation operations and sequences remains the same.

  • The umbilical configuration with integrated power cables, controls, and hydraulics can be kept.

  • Power transmission capacity is increased.

Although technically feasible, Alternative A has substantial disadvantages.

  • Advantages related to maximum tieback distance are limited.

  • Amperage flowing through the system does not change. The same level of current will not improve SEPS efficiency.

  • Umbilical cost, both acquisition and installation, are higher.

  • Installation conditions are worse because of the increase in size of accessories and terminations.

Economically, Alternative A is a much-higher-cost solution. The total cost of a power umbilical is more than just the purchase price. Although the material cost is significant, the offshore installation costs must also be considered. This requires mobilization of a suitable lay vessel with the necessary support infrastructure and specialized personnel.

These difficulties and additional costs will deliver more power subsea, but tieback distances will not benefit from this alternative. Because of this, Alternative A is not recommended.

Alternative B: Subsea transformer deployment to increase transmission voltage. The suggested SEPS configuration for Alternative B includes two transformers: one topside to increase transmission voltage (step up) and one subsea to lower transmission voltage to the subsea motor level (step down).

This solution has several advantages.

  • Umbilical Capex is reduced. The substantial cross-section reduction for the same power will have a cascade effect that includes the junction boxes, accessories, and connections.

  • Umbilical weight reduction means less riser load on the floating production unit, allowing subsea boosting with old production units that typically have limited load capacity.

  • Installation time and cost is reduced through optimization of umbilical installation vessels. Longer umbilicals can be reeled if they are lighter and smaller.

  • Some operators limit cable gage on the production unit to 120 mm² for bend radius/cable tray reasons. Heavier umbilicals would require splitters in a junction box to cross over to parallel runs of 120 mm2. This would typically be installed in splash and hazardous zones within the unit. Umbilical cable reduction would eliminate this requirement.

  • Cable-mechanical-load reduction on the TUTU increases system reliability.

  • SEPS maximum power-transmission capacity is increased.

  • Tie-back-distance allowance is increased.

  • However, the solution also has some disadvantages.

  • The SEPS component count is increased with the step-up topside transformer and step-down subsea transformer. Those two pieces of equipment (especially the subsea transformer) will increase system costs.

  • The solution requires high-voltage-penetrator qualification for the step-down transformer primary side.

Because of the economic and technology significance of the subsea power penetrators, Alternative B was split into Alternatives B1 and B2. Alternative B1 uses drymate connections on the primary side of the step-down transformer. Alternative B2 uses wetmate connections.

Alternative B1: Dry connections on step-down transformer primary. This alternative, which has been used for an oil-boosting MPP project in West Africa, has intrinsic installation difficulties. Because the transformer is directly terminated to the umbilical, they both need to be installed together.

Because of the size of the transformer, and depending on the water depth, a special vessel might be required for the umbilical installation. If such a vessel is not readily available, mobilization costs and service rate can make this operation extremely costly.

Alternative B2: Wet connections on step-down transformer primary. Wetmate connections on the subsea step-down transformer primary will not affect existing vessel infrastructure or the integrated umbilicals termination. This is because the transformer can be installed separately from the umbilical.

Also, using wetmate connectors increases cost and decreases overall system reliability.

Alternative B2 is technically feasible and could be economically attractive for high shaft powers (> 4 MW). Because it decouples transformer and umbilical installation, it allows longer step-out distances (> 20 km). It is the preferred solution for these applications and is especially superior when associated with Alternative C.

Alternative C: Increase subsea motor voltage from 6.6 to 13.6 kv. In Alternative C, an increased voltage motor is fed by a topside VFD with a step-up transformer. Alternative C has several advantages in addition to those already explored in Alternative B.

  • The high-voltage motor eliminates the subsea-transformer requirement for installations with high shaft power and long step-outs. The elimination of the subsea transformer and its connections will reduce SEPS cost and complexity.

  • Without the subsea step-down transformer, the number of connections remains the same as in an ordinary boosting system. Thus, higher power is obtained without reducing reliability.

  • The technology risk is low. Surface 13.8-kV motors are widely used offshore and throughout the industry.

If run at 13.6 kV, raw-water injection systems currently installed with 120-mm² cables could have been installed with 25-mm² cables. The multiphase pump and subsea separator, which currently use 240-mm² cables, could have been installed with 35-mm² and 70-mm² cables. At 13.6 kV, a-70 mm² umbilical can cover the current envelope covered by 240-mm² cable.

  • Maximum shaft power increases from 2.17 to 2.3 MW.
  • Maximum tie-back distance increase from 9.7 to 17.6 km.

A 120-mm² cable serves up to 3.1-MW shaft power and tie-backs of 20.4 km. Nonetheless, Alternatives B and C have the following common disadvantages.

  • A 13.6-kV subsea motor or step-down transformer must be designed.
  • A topside VFD with an output voltage of 15 kV or with an output step-up transformer is required.
  • Power penetrators must qualified for 8.7/15 (17.5) kV.

These issues do not present any technology challenges and should require a low-complexity qualification program. To eliminate these barriers, operators and suppliers have collaborated on a joint-industry project to develop a 13.6-kV subsea motor.

The proposed subsea motor is a brushless synchronous machine, a permanent magnet motor (PMM) with a cable-wound stator operating with pressurized water-based barrier fluid.

Conclusions

Three alternatives aiming at SEPS cost reduction were assessed. In the first alternative, an increase in the umbilical cross section was investigated, whereas the second and third alternatives targeted transmission-voltage increase. Voltage levels have a large effect on SEPS cost and operational envelope. High current levels demand cables with larger cross sections, and that could affect overall system reliability. To lower the transmission current, voltage must be increased. The third alternative, which involved developing a higher-voltage motor, proved to be the best fit for the problem.

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper OTC 27929, “High-Voltage Subsea Pump—A Low-Cost Subsea Boosting Enabler,” by A. Margarida, Petrobras; J. Pimentel and E. Thibaut, Total; and E. Cardoso, SPE, Technip, prepared for the 2017 Offshore Technology Conference, Houston, 1–4 May. The paper has not been peer reviewed.


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