July 2007
Special Focus

FPSO moves into the Gulf of Mexico

While Petrobras launches the first deepwater FPSO in the US Gulf, six years after regulators first approved the concept, a Pemex FPSO has already begun production closer to home.

Vol. 228 No. 7  


FPSO moves into the Gulf of Mexico

 Six years after US regulators approved the concept, Petrobras is launching the first deepwater project in the GOM. Meanwhile, a Pemex FPSO has begun production closer to home. 

David Michael Cohen, Production Engineering Editor

Despite their increasing popularity over the last 30 years as a means of offshore field development, the use of Floating Production, Storage and Offloading (FPSO) vessels has eluded the Gulf of Mexico, due to regulatory requirements and a lack of economic incentives. New technologies and stable $60-plus/bbl world oil prices have largely overcome these hurdles, and economic and environmental concerns arising from the 2005 hurricanes have increased the technology’s attractiveness, resulting in the recent launch of FPSO projects in the GOM.

In the last year, the US Minerals Management Service has approved general plans for a Petrobras FPSO to produce from Cascade and Chinook fields, and a Floating Production Unit, developed by Helix as a first step to an FPSO and operated by Helix subsidiary ERT at the old Typhoon field. The MMS expects many FPSO applications to follow the deployment of these projects. Meanwhile, a Pemex FPSO has begun producing from the Ku Maloop Zaap field in shallow water in the Mexican GOM.


Shell deployed the first FPSO, a converted 60,000-dwt tanker, in 1977 in the Castellon field offshore Spain. The vessel had a processing capacity of 20,000 bpd and operated in about 380 ft water depth. As floating production became an increasingly popular option, FPSO use also expanded. According to statistics provided by Infield Systems Ltd., FPSO installations accounted for about 25% of floating production sytems installed between 1977 and 1996. During the next 10 years, FPSOs accounted for 40% of production floaters installed. According to International Maritime Associates, Inc., at the end of 2006, 60% of floating production units operating and 71% on order were FPSOs. Until this year, they were in widespread use in all major areas except the GOM.1

In addition to their utility for developing deepwater resources, FPSOs are attractive because of their relatively low Capex requirements-they can be built in a shipyard rather than offshore, using largely conventional shipbuilding technologies-and the ease with which they can be redeployed to new locations.

The nomenclature used here distinguishes FPSOs from other ship-shaped facilities in that they incorporate production and storage in the same vessel. Other types of ship-shaped facilities include Floating Production Units (FPUs)-which do not have storage capacity and thus require a pipeline to transport oil-and Floating Storage and Offloading (FSO) vessels-which do not themselves process production from subsea wells, but rather accept oil from an adjacent production platform for storage and later offloading to a tanker.

In all cases, gas, whether it is associated or not, must be flared, re-injected, transported via pipeline or-on a floating unit-burned for electrical power. Schemes for transporting it as compressed gas, as liquefied gas or as hydrate exist, but are not yet commercial for floating units.


There are two ways to transport oil from offshore production to market: pipeline and tanker. Laying pipeline in deep and ultra-deep water with sufficient capacity to transport oil can be an expensive endeavor, which is one reason that oil production facilities tend to be built incrementally farther from shore, to tie into nearby, existing pipeline infrastructure. Production far from existing infrastructure requires oil storage on (FPSO) or near (FSO) production facilities and offloading to tankers for transport. This prevents tankers from being tied to a production facility for long periods while filling the tanker; it also allows time for gas and water separation from the oil before transport.

Thus, economic use of an FPSO requires:

  • Considerable distance from existing oil pipeline facilities
  • An economic option for handling associated gas
  • A regulatory environment favorable to oil storage and offloading.

These considerations have made the FPSO option viable for early deepwater field development, where economic risks are high and the reward uncertain for full field development, including pipeline infrastructure and fixed production facilities.

The damage wrought on GOM production by hurricanes Katrina and Rita in 2005 brought to light a new advantage for self-propelled, ship-shaped production facilities, such as FPSOs, in the Gulf: their ability to move out of the way of dangerous storms. All three floating production projects currently being developed for the GOM incorporate disconnectable production buoys, which allow the vessel to detach and float away in the event of a severe storm, while the buoy sinks to a depth below the range of hurricane waves. Detachable production vessels also eliminate the need to evacuate crew, allowing them to perform valuable maintenance work during the downtime.


In 2001, after five years of discussions with oil companies, FPSO builders and operators interested in applying the development concept in the GOM portion of the Outer Continental Shelf, MMS released an Environmental Impact Statement (EIS) approving the general concept of an FPSO in the region and setting the regulatory parameters for such projects.2 Since that time, there were no applications for FPSO in the Gulf until Brazilian operator Petrobras submitted its plan for Cascade and Chinook fields in late 2006, said Mike Conner, a petroleum engineer in the MMS technical assessment section for the Gulf of Mexico OCS region.3 Among the requirements established in the EIS:4

  • FPSOs may operate in water depths greater than 650 ft, except in areas designated as lightering-prohibited areas by the US Coast Guard, consistent with the USCG’s classification of offloading from an FPSO as lightering, Fig. 1
  • Gas may not be flared; it must either be used on the vessel for fuel or brought to market
  • FPSOs must be double-hulled in compliance with the Oil Pollution Act of 1990
  • Shuttle tankers carrying oil from FPSOs to US ports must be US flagged, crewed by US citizens and/or legal aliens, and owned and operated by US citizens, as required by the Jones Act
  • FPSOs that are not US flagged are not allowed to port in the US.
Fig. 1

Fig. 1. Because the US Coast Guard classifies transfer of oil from an FPSO as lightering, FPSOs will not be allowed in lightering-prohibited areas. Courtesy of MMS. 

This last item sets up an unusual situation, in that a non-US flagged floating unit, disconnected from its buoy in advance of a severe storm, would either have to find a non-US port that will accept it, or stay in the Gulf and outmaneuver the storm.

The EIS report found the risk of spill onboard the vessel unique to FPSO operation to be 5% of the total risk, while risk of spill during offloading to a shuttle tanker was comparable to risk in lightering operations in the GOM, where spills have historically been few and of low volume. The risk of spill during shuttle tanker transport was found to be slightly less than the risk from pipeline transport. While the FPSO-unique risks are relatively small, the sheer magnitude of a possible spill is still considered a cause for caution.

“The major concern is oil storage, if something should happen in that facility,” Conner said. “If, for whatever reason, the FPSO got damaged and lost majority of its contents. The other form of transport for the product is pipeline; a major incident in pipeline would lose 400 to 5,000 bbl, whereas with an FPSO it could be up to 1 million bbl.”

Nonetheless, he said, the MMS had found that a double-hulled FPSO would not risk releasing more oil into the GOM than a fixed production platform.

Though the EIS, written before the storms of 2005, assumed a permanently moored FPSO as a base case, Conner said that now MMS will place “a lot of emphasis” on disconnectable-buoy designs. A disconnected buoy would be required to submerge to 200 ft. At this depth, he said, wave effects from storms become negligible according to model tests involving hurricane forces in bottle tanks, performed this year by SBM Offshore.

He also said the agency will favor some sort of moored system as opposed to dynamic positioning. Since the production buoy will always be moored, this means either a separate mooring system for the FPSO or a mooring system on the buoy that is sufficient for both the buoy and the FPSO, will be preferred over a (weakly) moored buoy tethered to a dynamically positioned vessel. However, Conner said a DP FPSO might be accepted for some water depths with a requirement that the vessel disconnect if it exceeds a predefined radius (which could range from 200 to 400 ft) from its center of operations. All Environmental Protection Agency requirements for discharge of produced water to the GOM and for disposal of any waste products such as sulfur would be applicable.


Cascade and Chinook fields lie 165 mi offshore Louisiana in about 8,500 ft of water, at Walker Ridge Blocks 206 and 425, respectively, in the MMS-designated central Gulf of Mexico planning area. No production analogs exist for these fields on similar reservoirs in the GOM, and the only well test performed on an analog reservoir in the quadrant was at Chevron’s WR 758 Jack-2 well. Most of the reservoir data for Cascade and Chinook comes from seismic surveys, well logs, cores and fluid samples.5 Uncertainty in the best development approach, plus the fact that the nearest pipeline infrastructure is about 100 mi away, persuaded operator Petrobras to conduct a phased development starting with three production wells (two at Cascade, one at Chinook) to an FPSO, rather than a full field development.

“For a situation like this, where we have just a couple of wells and there are a lot of uncertainties, it does not justify building an oil pipeline,” said Cesar Palagi, Walker Ridge asset manager for Petrobras. “FPSO is the best solution to fit all of these conditions.”

Production system design. Oil will flow from the field to the FPSO via four Free-Standing Hybrid Risers (FSHRs), two from Cascade and two from Chinook, Fig. 2. The risers will tie into a moored production buoy that will be detachable from the FPSO. A passive turret will allow the FPSO to weathervane on the buoy with prevailing environmental conditions.

Fig. 2

Fig. 2. The Petrobras FPSO will produce oil via four Free-Standing Hybrid Risers (FSHRs), two from Cascade and two from Chinook. Another FSHR will transport gas to pipeline. Courtesy of Petrobras. 

Flowlines will be looped to allow round-trip pigging. Electrical submersible pumps on the seabed will help the produced fluids overcome the 8,200-ft static head of water depth.

The FPSO will have nominal production capacity of 80,000 bopd, with a minimum storage capacity of 500,000 bbl and gas processing capacity of 16 MMcfd. Gas produced from the field will be burned for electrical power aboard the FPSO. In initial operations and in the event of disconnect, diesel will be used for additional fuel.6 Because flaring is not permitted, a small export pipeline will be constructed to handle the remaining gas. The export line, like the production lines, will be connected to the buoy via FSHRs. Palagi said the gas export line will probably tie into part of the Green Canyon pipeline structure, about 100 mi away. He added that, though its diameter is not yet determined, the gas pipeline will be relatively small and much cheaper to lay than an oil pipeline, since produced oil is expected to have a low gas-to-oil ratio.

Storm mitigation measures. The FPSO will be designed to stay in place up to a 100-yr winter storm. It will detach from its buoy and sail away under its own power in case of more severe weather. A planned disconnection would take 24 hr, which Petrobras predicts will be more than enough time to avoid a severe storm given current weather forecasting capabilities. The FPSO would be able to conduct an unplanned disconnection safely in 10 hr. Palagi said requirements for an emergency disconnection are not being considered because the FPSO will be fully moored.7

As a non-US-flagged vessel, the FPSO will not be permitted to port. The vessel will simply move out of the range of the storm until it passes, and then return, Palagi said.

This is a common practice in other hurricane- and iceberg-prone locations, but the geographic restrictions of the Gulf of Mexico might make this approach problematic.

“In most cases, Category 3 or 4 storms move at about 10-12 knots,” said Chuck Roeseler at the US National Weather Service. “But there have been storms that have violated that rule. In 1995, Hurricane Opal intensified rapidly overnight and shot northeast toward the Florida panhandle at 15-20 knots.

“It’s rare, but if something like that happened in the middle of the Gulf, you’d have a hard time getting out of the way.”8

FPSOs have maximum speeds ranging approximately from 5 to 15 knots. Palagi said the Petrobras vessel will be required to travel at more than 10 knots. He added that the FPSO will sail “in a safe direction, not against the same direction of the hurricane,” and said that similar storm-avoidance procedures are required by cruise ships, DP facilities and supply boats in the GOM.

In the event that a storm necessitates detachment, the production buoy will sink to about 200 ft. The procedure is facilitated by the freestanding hybrid risers, which use flexible jumpers from their own buoys to the production buoy. This isolates the rigid vertical part of the risers from the stresses generated by submerging and raising the production buoy. The FSHRs also significantly reduce the hangoff load on the buoy when connected to the FPSO, and isolate the rigid risers from vessel motions.

Petrobras is accepting bids on the FPSO. Companies offering to construct the vessel include SBM Offshore, Modec and Bluewater. A separate bidding process for the risers is ongoing. Petrobras is partnering with Devon on Cascade field and with Total on Chinook. First oil is expected in late 2009.


While the Petrobras FPSO represents a sea change in the development of the deepwater Gulf of Mexico, it won’t be the first ship-shaped production unit in the US GOM. Helix Energy Solutions Group is set to achieve that distinction, with an FPU to operate in 2,100 ft of water at the old Typhoon field, renamed Phoenix, in Green Canyon Blocks 236 and 237. First oil is expected in fall 2008.

The choice of a detachable ship-shaped unit for this location, which Helix subsidiary Energy Resource Technology (ERT) acquired in August 2006, was influenced by the fate of the Typhoon TLP, which Hurricane Rita destroyed in September 2005. Helix is finishing removal of debris from the old Typhoon site, while construction of the FPU Helix Producer I, a converted train ferry, is underway in Croatia, Fig. 3.

fig. 3

Fig. 3. The FPU Helix Producer I is being built from a train ferry in a shipyard in Croatia. Courtesy of Helix. 

The vessel will have nominal production capacity of 30,000 bopd and 50 MMcfgd from two flexible production risers in “lazy-wave” configuration. Two more flexible risers will deliver gas and oil, respectively, from the FPU to existing pipelines for export.9

The facility is designed to stay connected in conditions that do not exceed a combination of a 100-yr loop current and a 10-yr winter storm. In harsher conditions, a controlled disconnection, which includes flushing the flowlines, would take 10-12 hr. An emergency disconnect could be performed in 30 sec.

The Helix Producer I will be Bahamas-flagged, so it-like the Petrobras FPSO-will not port in case of a severe storm, but instead will maneuver to avoid the storm.

“We feel like it’s safer to be out at sea,” said Cory Weinbel, general manager of Production Facilities.10

As the FPU moves out of the path of an oncoming storm, the production buoy will settle to its equilibrium depth of 130 ft, short of the 200 ft suggested by MMS. Weinbel said the depth of the submerged buoy is limited by the weight the buoy has to support and by the capacity of the onboard winch that is used to reconnect the buoy to the FPU.

The buoy will have minimal mooring, and the vessel will be dynamically positioned. Emergency disconnect would commence if the FSU exceeded a 500-ft radius from its tetherline position.

An initial Deep Water Operations Plan (DWOP) was submitted to MMS, and Helix is answering agency questions regarding that plan before submitting a final, more specific DWOP, Weinbel said. The contract for topsides modules was awarded to Kiewit Offshore, and fabrication began in June 2007.10

Helix plans to use the expertise it gains in the Phoenix project to expand into the FPSO market.

“This covers a lot of ground just on the ship-shaped unit, and we would just ratchet up one notch to include the storage,” Weinbel said.

Such a project may not be far away. In January, Helix and Norway-based AGR Group purchased a tanker, which they call Shiraz and plan to convert to an FPSO for deployment either in the GOM or an Asia-Pacific location.


Meanwhile, one of the world’s biggest FPSOs began oil production in June 2007 at Pemex’s Ku Maloob Zaap field, about 65 mi offshore the city of Carmen, Mexico, Fig. 4. The Yùum K’ak’náab (Mayan for “master of the sea”) operates in about 330 ft water depth, and has capacity to process 600,000 bopd and to store 2.2 million bopd. Eight flexible, 15-in. risers hang from a fully moored, detachable production buoy: four production risers, three oil export lines and one gas export line. The vessel will export 1.2 million bopd, mostly by shuttle tanker but with pipeline transport available.11 In addition to operating as an FPSO for KuMaZa, the vessel will act as an FSO for neighboring fields.12

fig. 4

Fig. 4. The Pemex FPSO Yùum K’ak’náab began oil production in shallow Mexican waters in June 2007. FPSO technology was chosen to mix and process crude oils of various qualities to produce a Maya-type blend that is cheaper to export. Courtesy of Pemex. 

Strategic project coordinator Ricardo Villegas Vazquez explained in an email why Pemex opted for an FPSO in such shallow water.

“The use of FPSO is needed to handle crude of a very low API and high viscosity, to process and mix it in place, because it is very costly to try to transport it to land using pipelines and pumping,” Villegas said. “The water depth does not matter in this case; the important thing is to reduce the cost of handling the crude oil.

“The target of the FPSO is to improve the quality of the crude oil and to produce a manageable blend, at low cost, that is similar to the crude oil that we export from Cantarell.”*

Like the Petrobras project, the Pemex FPSO is designed to stay on location in 100-yr winter-storm conditions.


No FPSO proposal for the US was submitted between 2001, when the MMS approved the concept, and late 2006. This can be attributed to the lack of a proven regulatory context for such a project. With Petrobras and Helix establishing that context, and exploration of the deepwater GOM continuing to yield promising results, other companies are likely to follow suit.

“In certain areas where there is no infrastructure, I would expect to see some applications,” said Conner, the MMS engineer.

The next few years may lay the groundwork for the widespread use of FPSOs in the region. WO  

*The email quote is translated from Spanish.


1 McCaul, J. R., “May 2006 Maritime Technology Reporter: Growing requirement for floating production systems,” International Maritime Associates, Inc., April 12, 2006, http://www.imastudies.com/id164.htm accessed June 4, 2007.
2 US Minerals Management Service, Recommendations and record of decision: Proposed use of floating production, storage, and offloading systems on the Gulf of Mexico Outer Continental Shelf Western and Central Planning Areas, Dec. 13, 2001.

3 Conner, M., Chief, Technical Assessment and Operations Support Section, Gulf of Mexico OCS Region, US Minerals Management Service, telephone interview by author, May 29, 2007.
4 US Minerals Management Service, Gulf of Mexico OCS Region, Proposed use of floating production, storage, and offloading systems on the Gulf of Mexico Outer Continental Shelf, western and Central Planning Areas: Final environmental impact statement, January 2001.
5 Ribeiro, O., Palagi, C., Mastrangelo, C. and A. Corte, “The design of an FPSO to operate in the Gulf of Mexico,” OTC18950 presented at the Offshore Technology Conference, Houston, April 30-May 3, 2007.
6 Palagi, C., Walker Ridge asset manager, Petrobras America, Inc., personal interview, Petrobras offices in Houston, June 1, 2007.
7 Palagi, C., email interview, June 11, 2007.
8 Roeseler, C., US National Weather Service, telephone interview, June 7, 2007.
9 Weinbel, C., “Use of a ship-shaped floating production unit for the Phoenix development,” presented at the Marine Technology Society Houston Section meeting, April 26, 2007.
10 Weinbel, C., Production Facilities general manager, Helix Energy Solutions, telephone interview, June 8, 2007.
11 Villegas, R., Ku Maloob Zaap strategic project coordinator, Pemex, email interview, May 25, 2007.
12 Aanesland, V., Kaalstad, J. P., Bech, A. and A. Holm, “Disconnectable FPSO: Technology to reduce risk in GoM,” OTC 18487 presented at the Offshore Technology Conference, Houston, April 30-May 3, 2007.


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