Will FPSOs be useful in the ultra-deep water of the US Gulf of Mexico? One operator intends to answer this question first-hand.

The Gulf of Mexico benefits from the wide availability of infrastructure. The Gulf’s first FPSO will begin production in 2010 in Walker Ridge quadrant on the eastern end of the frontier Lower Tertiary. (Image courtesy of Wood Mackenzie)

The use of floating production, storage and offloading vessels (FPSOs) has become a successful means of producing deepwater fields throughout the world. Beginning in the 1970s, FPSOs were first used by Shell off the coast of Spain and Petrobras offshore Brazil. Over the last 30 years their use has been expanded worldwide with 125 FPSOs in operation to date, according to “The World Floating Production Report 2008-2012” published by Douglas-Westwood Ltd. The Quest Floating Production Database states that more than half of the world’s floating production systems are FPSOs.

While the use of FPSOs has grown worldwide, this technology has never been deployed in the Gulf of Mexico — until now. They have been used in many regions, including areas where conditions are sometimes harsh, such as offshore northwest Australia and the east coast of Canada. Until recently, however, there was a moratorium on FPSO use in the Gulf of Mexico.

Industry regulators in the United States believed the frequency of violent storms in the Gulf could lead to catastrophic oil spills from FPSOs. However, an in-depth study conducted by the US Minerals Management Service (MMS) in the late 1990s found that FPSOs were at no more risk than other floating production systems already in use in the Gulf, with only 5% of total spill risks classified as FPSO-unique.

In 2002, the MMS issued an Environmental Impact Statement approving the use of FPSOs in
deepwater developments in the Gulf of Mexico. At the time, it was hoped that the decision would open more remote areas in the Gulf. It would be four more years before Petrobras filed the first application.

Why no rush?

“Shuttle Tankers vs. Pipelines in the GoM Frontier,” a report published by Wood Mackenzie Ltd. in January 2008, cites several reasons for the slow acceptance of FPSO developments in the Gulf.

The Jones Act — a Depression-era protectionist shipping legislation passed in 1920 — was designed to protect American jobs and industry. The law stipulates that only US-built ships can operate between US ports. They must be owned and crewed by US nationals and be flagged in the United States. Although the FPSO itself would not be subject to Jones Act regulations, it would qualify as a US port.

FPSOs require dedicated shuttle tankers. Due to technological advances, Asian shipyards can now build shuttle tankers for half the cost and in a third of the time compared to American shipyards. Converting existing “Jones Act” vessels could be more cost-effective. The number of vessels available for conversion is small and, in today’s active market, the savings would be concentrated more in time of execution rather than contracted day rates.

The question of infrastructure

The wide availability of existing pipelines on the outer continental shelf also contributed to slow acceptance of FPSO use in the Gulf. The steady development of infrastructure occurred primarily due to the lack of options. Since the MMS decision was announced in 2002, the question of cost has been the driving feature of developing deepwater fields in the Gulf with additional pipelines, at least where reserves can be proven.

For many years, discoveries in the Gulf of Mexico tended to be medium to small in size. Most of these were extensions of plays found onshore and in shallow water. As a result, pipeline infrastructure in the Gulf incrementally followed these discoveries as they advanced into deeper water.

For the Lower Tertiary play, there are current plans to extend portions of the pipelines to the Western Gulf, but the Central and Eastern portions are virtually isolated from extending infrastructure. Any development in these areas will incur a substantial risk. However, a phased development approach appears to be more flexible with an FPSO rather than with a permanently fixed pipeline.

Upstream risk is an important factor in the remote areas of the Gulf of Mexico. Without a full knowledge of the Lower Tertiary’s size and long-term production performance, a full field development program including a long-distance pipeline is a substantial financial risk.

By using an FPSO in the first phase of development of this remote play, Petrobras will lower its initial risk. The FPSO can be redeployed if the field
performs below expectations.

Other disadvantages of pipelines to frontier plays include the impact of hurricanes, which can lead to long-term production shutdowns (Figure 1). Maintenance and repair can also be costly, especially with a limited availability of vessels capable of working in extreme depths.

The topography of the seafloor in the Lower Tertiary also presents challenges to pipeline designers and engineers. The seafloor associated with Walker Ridge, Keathley Canyon and Alaminos Canyon contains high hills and deep canyons hundreds of feet in elevation, which makes navigation problematic for operators and installers. In addition to topography, the extreme depths of the Lower Tertiary play would require additional flow assurance measures, either through mechanical or chemical means.

Shuttle tankers, on the other hand, are virtually impervious to water depths. With the FPSO concept, the initial cost of operating a frontier play is drastically lower. However, there is an inevitable shift in cost as the field declines. The benefits of shuttle tankers would only remain feasible if more FPSOs began operating in this remote region to allow for a tanker-sharing scenario.

Stepping in with confidence

Based on experience, Petrobras leads the way in producing deepwater fields where infrastructure is not readily available. The company currently operates 16 FPSO vessels worldwide.

Placing an FPSO in the Gulf of Mexico is part of Petrobras’ plan to invest US $4.9 billion in the United States by 2012. In 2007, Petrobras held exploration rights to 193 blocks in deep or ultra-deep water.

Based on preliminary interpretation of the Cascade and Chinook fields in the Walker Ridge quadrant of the Gulf of Mexico, the operator announced in 2007 at the Offshore Technology Conference that it would develop the fields with an FPSO, with first production scheduled for 2010.

The vessel will have liquid processing capacity of 80,000 b/d, gas processing capacity of 16 MMcf/d and an oil storage capacity of 600,000 bbl. The FPSO will be moored in 8,000 ft (2,440 m) of water and will have a disconnectable turret that will allow it to move off station in case of inclement weather. The project will also include a small gas export pipeline and two committed shuttle tankers provided by OSG for oil export with a mooring system.

Environmental standards were addressed in 2006 with the introduction of Petrobras’ freestanding hybrid riser system, which uses flexible jumpers to isolate the hard pipe riser from fatigue-inducing motions of the FPSO. In the case of approaching hurricanes, the system can be easily disconnected and submerged to a predetermined depth to avoid the impact of the storm, allowing the FPSO to retreat to safe waters until severe conditions subside.

Phasing into the Gulf

Currently there are no plans to build transportation infrastructure in the Central Gulf from the Lower Tertiary play where Petrobras plans to use an FPSO. Cascade and Chinook fields will be developed in phases to better deal with the uncertainties inherent to the newer Lower Tertiary play.

With no producing fields analogous to these discoveries, the primary support for reservoir interpretation is provided by seismic surveys and well data, which are insufficient to justify a full field development program. The company plans to use its proven early production system to avert some of the risk associated with developing ultra-deepwater fields that have unknown performance ratings.

The company’s phased development approach provides a window for the development of new technology, acquisition of reservoir performance data and operational experience and, most importantly, early cash flow.

It is uncertain at this point what the outcome will be for the first FPSO-based development in the Gulf of Mexico. It is perhaps too early to determine whether other operators will continue the trend or convince pipeline operators to extend the current infrastructure to the Lower Tertiary play. It is vital that at least some operators are willing to be first in bringing an FPSO market to the Gulf. If successful, the move could provide a viable alternative to pipelines.