Multiple FPSO developments in ultra-deep water could create an active shuttle tanker service market.
Julie Wilson, Wood Mackenzie
The first Floating Production, Storage and Offloading (FPSO) development is moving forward in the remote, ultra-deep waters of the US Gulf of Mexico (GOM) at Petrobras’ Cascade and Chinook Fields in the promising Lower Tertiary play, Fig. 1. FPSOs are commonly used in other deepwater provinces, but were prohibited in the GOM until recently. Their use makes sense in a frontier environment, especially from a transportation standpoint. Pipeline costs rise disproportionately as water depths increase, while shuttle tanker costs are insensitive to water depth and-to a certain extent-to distance. Wood Mackenzie has analyzed the transportation options of a hypothetical oil discovery in a remote part of the Lower Tertiary play, comparing the costs of shuttle tanker use to paying tariffs through new and existing pipelines.
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Fig. 1. The Lower Tertiary play is in the ultra-deep waters of the GOM.
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The shuttle tanker has a cost advantage over a pipeline when considering the full life of the field; however, the advantage is concentrated in the first half of the field’s life. Unit costs skyrocket in late life once production declines, since the shuttle tanker is a dedicated vessel. These costs could be defrayed by sharing the tanker with another FPSO operation.
Shuttle tankers hold several other benefits over pipelines, not least of which is the lower risk with an FPSO and shuttle tanker operation in a frontier play. Both vessels can be redeployed, if the development proves disappointing. Other advantages include: hurricane avoidance, flow assurance, destination flexibility and easier maintenance/repair.
However, there are barriers to the spread of shuttle tanker usage in the GOM. Costs are inflated and operations are complicated by the Jones Act-protectionist shipping legislation dating from 1920. Furthermore, stringent rules on gas use mean that a gas pipeline may need to be laid. It remains to be seen whether other operators will follow Petrobras in pioneering FPSO and shuttle tanker deployment in the GOM, or whether pipeline companies will be convinced to continue to build an extensive pipeline network to the new frontiers.
In the GOM, using FPSOs and shuttle tankers was prohibited until 2001, when the Mineral Management Service (MMS) issued an Environmental Impact Statement (EIS) that approved the FPSO concept. This laid the foundation for their use, after which the MMS announced it would review FPSO-based development plans on a case-by-case basis. It was hoped that this decision, coupled with successful FPSO use in other deepwater domains, would open development of more remote GOM areas, but no applications were made until 2006.
Then, Petrobras applied to use an FPSO in its Cascade and Chinook fields. However, barriers still remain: initial FPSO developments will require dedicated shuttle tankers. Using the extensive GOM pipeline infrastructure seems to be a more obvious development option.
ULTRA-DEEP WATERS
Exploration in the GOM is pushing into ever deeper waters. Spurred by discoveries in the Lower Tertiary play and the development progress in the region, drilling activity is gaining momentum in the Walker Ridge, Keathley Canyon and Alaminos Canyon areas. Williams has announced that it plans to spend $480 million to build oil and gas pipelines to connect the Perdido Regional Hub in Alaminos Canyon to existing networks. There are currently no plans for transportation infrastructure from the Lower Tertiary play.
The impact of laying pipelines to discoveries in waters greater than 5,250 ft (1,600 m), remote from existing infrastructure, is a cost increase. Pressures increase and temperatures drop, as water depths increase. This requires thicker pipelines and more insulation.
Installation costs increase as the number of capable vessels becomes more limited. Conversely, shuttle tanker cost is largely insensitive to increasing water depth and distance, unless the distances are so great that two tankers are needed. When distances are shorter, a pipeline is cheaper to install and makes more sense in the GOM where pipelines are plentiful.
Figure 2 shows, schematically, the impact of increasing water depth and distance on the overall capital and operating costs for pipelines and shuttle tankers. This chart reflects only the basic cost, does not reflect fees or returns on investment; nor does it consider the cost differences between an FPSO and other designs, such as a spar.
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Fig. 2. Increasing water depth and distance affect capital and operating costs for pipelines and shuttle tankers differently.
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At a certain point, the cost of a pipeline overtakes that of a shuttle tanker.
In addition, upstream risk is an important factor in this frontier play. A great deal of uncertainty surrounds the reservoirs in Lower Tertiary discoveries, both in size and long-term production performance. This undoubtedly played a part in Petrobras’ decision to take a phased approach to development. If the reservoir performance is disappointing, the FPSO and shuttle tanker can be redeployed, and sunk costs are kept to a minimum.
FIELD-BASED COST COMPARISON
Wood Mackenzie has analyzed the transportation options of a hypothetical oil discovery in a remote part of Walker Ridge. The discovery was sized at 200 MMbbl of oil and was at least 60 mi from the nearest deepwater infrastructure, and over 170 mi to shore, Table 1. We analyzed five different pipeline options to derive the fees that might be payable. Each of the options used existing infrastructure. We based our analysis on an assumed pipeline building cost, and the fees that would be required to earn the builder a minimal rate of return.
| TABLE 1. Hypothetical field parameters |
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We compared the results to the estimated cost of a shuttle tanker. Estimates were based on one dedicated shuttle tanker, for which the operator paid a set dayrate plus expenses. We used a range of present global shuttle tanker rates, with an uplift of 50%-100% applied for the Jones Act cost impact. We did not consider any cost difference between an FPSO and any other facility design. Neither did we consider the possible impact on field production levels-using one shuttle tanker could limit peak production and defer oil revenues.
The shuttle tanker has a cost advantage over the field’s full life, Table 2, but that advantage changes over time, Fig. 3.
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Fig. 3. The shuttle tanker has a cost advantage over the field’s full life, but that advantage drops in year 11.
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| TABLE 2. Life of field cost-average $/bbl |
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While we assume that the fees charged by the pipeline operator do not change, the shuttle tanker is assumed to be a dedicated vessel. As such, the dayrate time-charter fee is fixed over the lifetime of the field and is paid every day, whether the vessel is idle or working. In reality, the operator would hope to share the shuttle tanker with another FPSO development, thereby avoiding this unit cost increase.
At the most likely fee rate, the shuttle tanker maintains its annual cost advantage over the pipeline until year 11 of the field’s life. After this point, the declining production causes a rapid increase in unit cost. This cost profile is highly dependent on the field’s production profile.
One rate constraint is the FPSO and shuttle tanker capacities, which tend to flatten and extend peak production. The cost profile above would likely make late-life production uneconomic, leading to early abandonment. Whether this would be sanctioned by the MMS is debatable. This phenomenon might be mitigated by writing the contract such that dayrates are higher earlier in the field life or by shuttle-sharing with another FPSO.
We assumed that only one shuttle tanker would be employed for a single field. Given our assumptions of field size, FPSO and shuttle tanker capacities, and time taken to load, unload and travel between FPSO and port, one tanker would be sufficient. It is interesting to note that Petrobras has contracted two tankers. However, by our calculations, two shuttle tankers would still result in a lower unit cost over the first eight years of our hypothetical field. Given that Petrobras’ FPSO contract is for only five years (with a 3-yr extension option), it is likely that Petrobras’ two shuttle tankers are a lower-cost option than a pipeline. Moreover, with such a short life for this first development phase, the operator avoids much of the late-life, increasing unit cost problem.
SHUTTLE TANKER ADVANTAGES
In addition to an overall cost benefit, there are a number of advantages that a shuttle tanker operation has over a pipeline in ultra-deep water:
Hurricane impacts. A shuttle tanker can move out of harm’s way in the event of a hurricane. Pipeline and facility damage during the 2005 hurricane season led to long production shutdowns. Expenditures ran to hundreds of millions of dollars and production was lost forever due to platform destruction.
Maintenance and repair. Repair to a pipeline in ultra-deep water would be costly. There is limited availability of vessels capable of working in these water depths, so any repair would be subject to vessel availability. Such work may also impact other projects. Conversely, repair or maintenance of a shuttle tanker is straightforward, requiring only dock space.
Ocean floor topography. There are hills and canyons hundreds of feet high and deep on the ocean floor. Navigating this terrain can be problematic for pipeline designers, operators and installers, adding to pipeline cost and complexity.
Pipeline flow assurance. As the seabed water temperature drops with increasing distance and water depth, field operators must consider flow assurance issues. A shuttle tanker does not have any of these issues.
Destination flexibility. A shuttle tanker is able to deliver directly to a number of destinations, thus enabling the operator to take advantage of price differentials or arbitrage opportunities. On the Gulf Coast, this advantage may be limited. Depending on the shuttle tanker’s draft, there may be a small number of ports where a shuttle tanker can discharge its cargo. Moreover, the pipeline network is so well developed in the GOM and along the coast that it offers a number of different delivery options.
Risk in frontier plays. The construction of a pipeline to remote, ultra-deep waters requires an investment of hundreds of millions of dollars, which is then physically static. Pipeline builders make the commitment to build a pipeline based on guaranteed throughput from one or more anchor fields that will fill their pipeline for a short period, before decline sets in and spare capacity opens up.
The income from the anchor field(s) usually provides a minimal return, and might only cover the cost of capital. Incremental returns are based on the pipeline owner capturing new business from existing discoveries and exploration in the vicinity. The expectation is that a production hub with a pipeline connection will stimulate exploration activity and reduce the economic threshold size of prospects and discoveries in their catchment areas.
In any play this carries a degree of risk, but in a frontier play such as the Lower Tertiary, this risk is very high. Of course, the high cost of construction is a barrier to entry to other pipelines, so the potential rewards are also very high.
A shuttle tanker connected to an FPSO development carries much lower initial risk, since the shuttle tanker and FPSO can be redeployed. However, they are unlikely to encourage and capture new business from other discoveries, unless there are further FPSO developments and a shuttle tanker market develops.
WHY NO SHUTTLE TANKERS?
FPSOs and shuttle tankers have long been used in many provinces-both deepwater areas with little infrastructure, such as West Africa and Brazil, and mature areas with existing pipelines, such as the North Sea. So, why has GOM not embraced this tried and trusted concept?
The government ban on FPSOs appears to have been founded on environmental concerns. The MMS ruling in 2002, that it would consider FPSO applications, did not lead to a rush of FPSO development plans. This was largely because the existing infrastructure gave pipelines a cost advantage. It was also anticipated that any FPSO application would involve a large amount of red tape-and possibly the opposition of the general public. It is no coincidence that a Brazilian company is the first to develop an FPSO plan; American companies are more sensitive to the potential public backlash.
Another barrier is the Jones Act. This legislation was designed to protect American jobs and industry at a time of economic depression. It stipulates that any ships that ply their trade between US ports must be built in the US, owned and crewed by US nationals and be flagged in the US. An FPSO would qualify as a US port.
The Act means that any newbuild shuttle tankers would need to be built in one of the few remaining American shipyards. Advances in efficiency by Asian shipyards mean that they can build a ship for half the cost of an American yard-and in a third of the time.
Conversion of existing “Jones Act” vessels might be a more cost-effective solution. However, their numbers are small and the market is already very active. The cost savings in contract dayrate may not be significant, but a conversion would be much quicker to execute.
If a number of FPSO developments were to move forward, then we might see the development of a shuttle tanker fleet, such as in the North Sea. There, costs can be kept low as specialist, third-party, shuttle-tanker operators manage a fleet that can be used for several projects and fields.
WHAT TO DO WITH GAS?
One of the other key issues is what to do with the gas. Flaring is not allowed in the GOM and gas injection is not common, since the gas is too valuable for the US market to re-inject it. Some gas can be burned as FPSO fuel, but this will not use all the gas.
Petrobras plans to install a very small gas export line for its Cascade/Chinook development. It is unclear what the economics of this small line are, but it is likely that the size will minimize costs and installation issues. A gas line also has fewer flow assurance issues than an oil line, again keeping costs down.
The use of compressed natural gas tankers could be an option, if this technology can be proved on a commercial basis. Since FPSOs do not have space or technology for gas storage, two CNG tankers might need to alternate, so that one is constantly attached to the FPSO.
CONCLUSIONS
The development of Cascade and Chinook via FPSO and shuttle tanker is an important first step in establishing this facility in the remote, ultra-deep waters of the GOM. It is unclear whether other GOM operators will continue the trend, or whether they will convince pipeline operators that it is worth taking the risk of building pipeline infrastructure into the Lower Tertiary play. Even if shuttle tanker use remains limited, their presence will provide a competitive alternative to pipelines. 
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THE AUTHOR
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Julie Wilson began her career working for BP in the UK for eight years in political, commercial and financial analysis roles. She joined Wood Mackenzie in 1999 covering Latin America and moved to Houston in 2000 in an upstream consulting role, managing a variety of international engagements. Since August 2006, Wilson, as Lead Analyst, has led the US Gulf of Mexico Upstream Research team that produces in-depth field-by-field analysis of the US Gulf of Mexico deep water.
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