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Subsea High-Boosting Multiphase Pumps Increase Oil Recovery in Aging Field (Includes presentation slides)

Fig. 1—High-boost MPP operational boundaries. GVF = gas-volume fraction.

Introduction

The Girassol, Jasmin, and Rosa fields were discovered in Block 17 in the late 1990s and early 2000s, 210 km northwest of Luanda, Angola, in water depths of approximately 1400 m.

The Rosa Field started production in 2007 using a subsea tieback to the Girassol floating, production, storage, and offloading (FPSO) vessel. In anticipation of a plateau decline, the operator studied opportunities to develop marginal resources and improve recovery of mature fields. The Rosa Field emerged as one of the targets for improved oil recovery. It is the farthest from the Girassol FPSO vessel, using up to 20 km of subsea production flowlines. Consequently, the field sees a significant subsea-network-pressure drop, which, combined with an increase in water cut and constraints in topside gas compressor capacity, accelerated the production decline. By removing these limitations, oil production could be increased.

The operator conducted multidisciplinary conceptual and preproject development studies to select the best option to improve production rates and increase recovery factors by reducing wellhead backpressure.

Selection of Subsea Processing

A study was conducted to identify the most promising subsea processing solution to reduce backpressure at the wells and, hence, the required wellhead flowing pressure.

Several research and development initiatives already had been launched for the qualification of technical solutions that, along with accumulated deepwater experience, formed a springboard for the evaluation of subsea processing solutions. The following already-proven technologies were screened:

  • Subsea multiphase pumps (MPPs)

  • Subsea gas/liquid separation

  • Subsea oil/water separation

  • Three-phase separation

These solutions were compared in terms of technical maturity, complexity, and operability of each system.

Subsea MPPs. The MPP station would be installed inline at one of the subsea manifolds on a production loop. The MPP option was intuitively the simplest way to lower backpressure at the wellhead and reduce gas-lift requirements in the risers, at least under steady-state conditions.

Pros.

  • Technical maturity

  • Reduction of backpressure at the wellhead

  • Reduction or elimination of gas-lift in the riser under steady-state operations

  • Simpler design and easier operations than subsea separation units

  • Less costly than subsea separation options 

Cons.

  • Limited pressure differentials provided by MPP when compared with liquid pumps

  • Limited ability to cover operating range throughout field life

  • Greater power requirement when compared with liquid pumps

Gas/Liquid separation. This subsea separation system would be installed inline at one of the subsea manifolds, with the liquids routed with a pump through the existing production loop while gas is routed with a new line to the FPSO vessel.

One of the drivers for installing subsea gas/liquid separation units is to be able to depressurize the flowline system below hydrate-formation pressure during a shutdown. This removes the need for dead-oil-flushing systems and expensive pipe-in-pipe technology for flowline insulation.

The Rosa Field was different because existing production lines (pipe in pipe) are already designed to provide sufficient cooldown time in the case of a shutdown. Thus, the only benefit of the gas/liquid separation system compared with an MPP system was the possibility of using liquid pumps with higher pressure differentials, allowing a further reduction of wellhead pressure.

 Pros.

  • Reduction of backpressure at the wellhead

  • Elimination of gas lift in the riser in steady-state operations

  • Higher pressure differentials than those available with MPP technology

Cons.

  • No benefit with respect to flowline insulation or dead-oil-flushing systems for the Rosa Field (production lines are already installed)

  • Limited ability of liquid pump to cope with possible gas carry

  • Need to operate separation unit at low pressure to avoid hydrate formation in new gas line

  • Need for new gas line and riser to FPSO vessel

  • Need for sand management in separation unit

  • Complexity of operations

Oil/water separation. This subsea separation system would be installed inline at one of the subsea manifolds with hydrocarbons (gas and liquid) routed with an MPP through the existing production loop while produced water is treated then pumped to an existing water injection system. Study results indicate that the oil/water separation system was not as mature as MPP or gas/liquid separation systems.

Pros.

  • Acceleration of oil production

Cons.

  • Less mature than other systems

  • Control valve for deoiling remains to be qualified

  • More costly than MPP

  • Difficulty achieving and maintaining good quality of injection water

  • Complexity of operations with different functions and equipment (e.g., separation, pumping, deoiling, desanding) will likely affect availability and reliability

Three-phase separation. This subsea separation system would be installed inline at one of the subsea manifolds, with the gas routed to one leg of the production loop while the oil is routed to the other loop leg. The produced water is treated and then pumped to the existing water injection system.

The three-phase separation system is the most complex of all the options and has the same technical maturity concerns as the oil/water separation system.

Pros.

  • Greater reduction of backpressure at the wellhead (higher pressure differential) than is found with field-proven MPP technology

  • Elimination of gas lift in the riser under steady-state conditions

Cons.

  • Less mature than other systems

  • Control valve for deoiling remains to be qualified

  • More costly than MPP

  • Limited ability of liquid pump to cope with possible gas carry

  • Difficulty achieving and maintaining good quality of injection water

  • Change in production loop operating philosophy (one loop leg used for gas)

  • Complexity of operations with different functions and equipment (e.g., separation, pumping, deoiling, desanding) will likely affect availability and reliability

Selection of High-Boosting MPP Concept

On one hand, the MPP option was confirmed by a screening study as the simplest way to lower backpressure at the wellhead. On the other hand, the limitations of field-proven MPP technology (i.e., reduced pressure differential and narrow operating range) would constrain the optimization of production from the Rosa Field.

The optimal concept for the Rosa Field emerged naturally as the high-boosting MPP (i.e., pressure differential greater than 100 bar for a broad operating range) (Fig. 1, image at the top of the article). The results from the high-boosting MPP were as good as those from oil/water separation, but the high-boosting MPP has a higher degree of technical maturity.

Qualification of New Technology

In early 2008, a joint-industry project performed the first run with the high-boosting MPP prototype with encouraging results, leading to an estimation that this new technology should be available to be considered for engineering procurement and construction tender once complementary testing had been concluded.

In 2009, the complementary testing of rotodynamic behavior over long durations, with high-viscosity fluids, and with worn-out pistons was conducted. During the tests, the pump showed rotodynamic instability for some running conditions with viscous fluid. This complex problem of rotor instability was solved in January 2011, after almost 2 years of thorough troubleshooting. The solution came from the idea of using a field-proven technique that had been used on compressor balance pistons to improve rotor stability.

On 22 April 2011, the high-boosting MPP technology was ready for industrial application in line with field development planning and only few months before project sanction.

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper OTC 27151, “Selection of Subsea High-Boosting Multiphase Pumps for Incremental Oil Recovery of Aging Deep Offshore Fields,” by Charles Fernandes and Christine Roux, Total, prepared for the 2016 Offshore Technology Conference, Houston, 2–5 May. The paper has not been peer reviewed.

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