Economic analysis of use of a floating production, storage, and offloading (FPSO) vessel to produce a dry-gas reservoir indicates that such use is technically feasible.
Moreover, this analysis indicates that, of three transportation options—pipeline, LNG, and CNG—shipping by CNG exhibits the best return on investment under a simplified payback analysis.
FPSO's acceptance
The FFPSO vessel has become an accepted solution for oil production in deepwater or remote offshore areas. Today's FPSO applications primarily deal with oil production, while associated gas is reinjected where there is no gas-pipeline infrastructure available. A few of these vessels process associated gas to recover NGL but still reinject the residue gas.
Continued technological developments in gas-utilization processes, expanding discovery of reserves in remote and deepwater locations offshore, regulatory requirements, and market pressures are combining to make recovery of associated gas in remote locations both technically and commercially possible.
The result will inevitably be a combination of traditional oil-production facilities and gas-utilization facilities on a single hull. Some producers already consider this option technically feasible.
But what about remote dry-gas discoveries? Such gas fields, no matter their sizes, are often not being produced. A potential means of production would be a pure gas FPSO (GFPSO).
A generic GFPSO would in essence be a floating gas production and conditioning facility. Being a movable and reusable asset, this concept could unlock many gas reserves that might otherwise remain stranded under conventional project-development scenarios.
The GFPSO's principal export products would be pipeline-quality gas, an LPG liquid, and a C5+ condensate liquid. While conventional shuttle tankers can transport the two liquid products, transportation of the residue gas remains the primary economic challenge.
Offshore gas can be transported by one of four generic methods:
- Gas transmission to shore in gaseous phase by pipeline.
- Volume reduction through either liquefaction or compression (LNG, CNG) followed by marine transportation.
- Conversion to other products by changing the "methane molecule" (methanol, synthetic crude: gas-to-liquids, or GTL), followed by marine transportation.
- Conversion to another form of energy such as electric power and transmission by a subsea cable to shore (gas-to-watts, or GTW).
Obviously, the simpler the required facilities, the lower the probable capital cost.
On this basis, the first two generic methods listed offer the most likely transportation options for the gas product from a GFPSO. This article examines the relative configuration and economics of a GFPSO using pipeline, CNG, or LNG as the gas-product transportation method.
Options
This article looks at facilities that process 400 MMscfd of produced gas. This volume is selected because, as will be seen later, the weight of topsides facilities necessary to produce this rate "fits" on commonly available hull sizes.
The facility is assumed to be in deepwater, nominally 800-1,000 m. The produced gas to the facility is assumed to be relatively rich gas (see accompanying box for composition).
Table 1 shows overall material balances for 400 MMscfd of produced gas. The pipeline-quality gas product will have an approximate gas heating value (GHV) of 1,058 btu/std. cu ft for all three transportation options.
The product rates are used to calculate revenues and costs from each transportation option. Shrinkage for liquid recovery and fuel use reduces the available export-gas volume. LNG suffers additional shrinkage due to a lower overall thermodynamic efficiency and the need for refrigerants.
Fig. 1 presents the GFPSO processing scheme for the pipeline and CNG options. Production facilities will include well-fluid cooling followed by hydrocarbon liquids, water, and gas separation. Gas conditioning will include dehydration and NGL recovery followed by compression.
The basic export products are pipeline quality gas, LPG mix, and stabilized condensate. The NGL liquid products are exported via shuttle tankers and their storage will be provided on the GFPSO.
Pipeline
Pipeline export is usually the simplest transportation option for gas. Pipeline construction is expensive, however, becoming more expensive with water depth and of course distance from shore.
Deepwater pipelines become limited in size as lay stresses in deep water reduce the pipe size that can be installed by existing lay barges. In some areas, bottom profiles at deepwater locations also reduce applicability of a pipeline solution.
This article makes the assumptions for the pipeline option shown in the accompanying box.
The export gas enters the pipeline directly from the GFPSO compression train at about 3,000 psig and 110° F. Some modification to the GFPSO flare and relief system may be needed if relief of the pipeline volume is to be considered during shutdown scenarios.
A GFPSO that transports residue gas by pipeline requires no equipment or technologies not currently in use on oil production FPSOs.
Compression
CNG as a gas transportation option has been receiving much industry attention with at least four firms offering schemes. All of these use specially equipped CNG ships to shuttle gas under high pressure from the production location to an onshore receiving infrastructure that could be a plant or pipeline.
No CNG ships have been constructed to date. All of the CNG technology firms are actively seeking a project that can support construction of one or more CNG vessels.
CNG as a transportation option for this article treats the CNG transportation cost as a tariff. The number of CNG ships required will vary with the distance to shore and reliability requirements and is reflected in a higher tariff for longer distances. Inlet pressure to the CNG ship is assumed to be 3,000 psig.
Allowance is made for infrastructure at the receiving location for offloading the gas either into storage or an existing pipeline infrastructure.
A GFPSO that transports residue gas by CNG carrier requires no equipment or technologies not currently in use on oil production FPSOs. The CNG carrier ship is a new design, but there are no technical barriers to prevent any of the proposed CNG carrier designs from being built. Obviously, such a ship will need to be available on the market or built as part of the project development before CNG can be considered as a transportation option.
Liquefaction
The LNG option requires a slightly different gas-processing scheme to account for efficient recovery of the NGL streams as part of the overall liquefaction scheme. In addition, some residue gas is used as fuel, and some of the NGL components are used as refrigerants for the LNG process. This arrangement accounts for the slightly lower LNG production rate.
Fig. 2 indicates the individual processing steps for the LNG alternative. The LNG process will contain the following basic steps:
Acid-gas removal (CO2, future H2S).
Dehydration and mercury removal (if necessary).
LNG liquefaction.
LPG-condensate extraction and fractionation.
The feed gas is assumed to contain no H2S (initially), carbonyl sulfide (COS), or mercaptans. CO2 must be removed to a 50-ppm level to prevent corrosion or freezing in the cryogenic section. Solid-bed dehydration to ppm levels is required to prevent hydrates and freezing at the cryogenic sections. Mercury (if present) removal is applied to parts-per-billion level to protect the main cryogenic heat exchanger (built of aluminum) from severe corrosion.
Liquefaction at –160° C. (–256° F.) is applied to convert the gas to a liquid (LNG) at almost atmospheric storage and transport conditions. Before the gas is liquefied, its heavy fraction (C5+) is separated to avoid freezing and subsequent plugging of the heat exchangers.
Typically, liquefaction is carried out with a mixed-refrigerant (MR) system as cooling medium using several types of heat exchangers. The MR system can consist of nitrogen, methane, ethane, or propane. For an offshore application, use of an all-nitrogen liquefaction cycle, operating in the gas phase, although less efficient thermodynamically, may be considered in order to reduce process complexity and improve operating safety. Mixed refrigerant is assumed here.
LNG is stored in the GFPSO hull in specially designed LNG storage tanks and offloaded to LNG tankers by LNG offloading systems specially designed for ship-to-ship transfer of cryogenic liquids using either loading arms or LNG over-the-bow loading equipment.
Allowance has not been made in the economic evaluation for LNG receiving and regasification facilities at the onshore receiving location. The assumption is that a facility of this kind would preferentially use an existing LNG regasification terminal. Including costs for a new regasification facility would obviously affect the LNG option's economics.
LNG is a mature technology for monetizing remote gas in onshore plants. Its first commercial application dates from 1964 when the first liquefaction plant was built in Arzew, Algeria. Over the past 20 years, there have been tremendous technology advances in LNG plant configuration, equipment design, and materials of construction applications, resulting in a more than a 50% reduction in overall capital cost for a LNG plant.
There are several LNG liquefaction technologies available. The industry has conducted a number of studies on marine implementation of these technologies using various hull types, process adaptations, and market economic assumptions.
Although none has yet been implemented on an FPSO, the industry in a large body of study and evaluation work has identified no insurmountable technical barriers to doing so.
Topsides weights; vessel size
The estimated topsides weights given here reflect all processing and support facilities required for each transportation option as described earlier. Table 2 shows the estimates of topsides weights and corresponding minimum vessel sizes.
The topsides for the CNG and pipeline cases are the same because the processing steps are identical, including export-gas compression. For vessel-size determination, estimated topsides weights were assumed to be a maximum of 10% of a vessel's total displacement. These then represent the smallest hull size that can accommodate the topsides facilities for each option.
It should be noted that for the pipeline and CNG options, requirement for liquid storage is somewhat less than normally encountered in an FPSO application. It is possible that a hull shape other than ship-shape could be a better structural or economic choice for a GFPSO using one of these options. This subject deserves of further study.
Capital, operating cost; conclusions
Capital and operating cost estimates reflect the technical basis described earlier and appear in Table 3.
All costs are in 2002 US dollars and reflect publicly available information or, where appropriate, Fluor's in-house data developed for various projects or studies.
For the CNG and LNG cases, product-shipping costs estimates included as operating cost, and the ships are not capitalized. The CNG ships are assumed chartered at 15% capital charge rate.
Table 4 gives operating-cost estimates for each option.
A simple payback-before-tax method compared the three alternatives. The method is defined as overall capital cost divided by first-year gas revenue less operating cost. It should be noted that the field development costs were not considered in the overall capital costs and would be the same for all cases.
Gas costs to field operator were assumed to be $0.80/MMbtu and reflected in the revenue calculation. Gas price at destination was assumed to be $4.00/MMbtu. No credit for hydrocarbon-liquid recovery (C3/C4 mix and stabilized condensate) is reflected in the economics, as these would be the same for each option.
Table 5 outlines the basis used to calculate project revenue. Table 6 presents the simple paybacks for all three alternatives and varying distances to the market. It is this simple payback method that makes CNG appear to offer the best return.
CNG carriers represent about 85% of the total project costs and will be chartered. The CNG case, therefore, requires the lowest initial capital investment by the field operator.
The first CNG project, however, must offer the CNG ship operator enough incentive to justify investing in construction of an initial CNG fleet.
It is difficult to say what form this incentive might take. Development of the first CNG project may require some form of guarantee or capital input from the field operator that could significantly affect the simple payback analysis given here.
The LNG case, on the other hand, requires the highest capital outlay regardless of the distance to market. LNG carriers are also included as operating cost, thus not capitalized.
There being an existing fleet of LNG carriers and an existing LNG shipping business, it is less likely that a field operator would need to provide incentives for LNG shippers such as might be necessary for the first CNG projects. As a spot market for LNG develops, this will be an increasingly more valid assumption.
Though pipeline has been the transportation method of choice for past gas-field developments, most of these developments have been in relatively shallow water. Initial investment for pipelines for long distances or deepwater applications becomes significant and LNG becomes a competitive alternative probably somewhere in the 2,000-km distance range.
The pipeline and CNG options are marine transport methods that impose nothing new on the FPSO itself. Mounting an LNG plant on a floating facility has been under study by the industry for some time.
Although no unit has been built, it is generally agreed that there are no insurmountable technical barriers to an LNG FPSO.
These simple economics do not reflect the intricacies of economic analysis of any actual project development. Every project must be evaluated on the basis of its own unique parameters. Any of the options studied here may be the economic winner under the proper set of project circumstances.
The conclusion that can be reached from this analysis, however, is that the concept of a commercially viable GFPSO project is feasible and there are technically proven options available for production of stranded dry-gas reserves. The actual economic justification and transportation method will depend on the unique combination of parameters facing any individual project development.
The authors
Jan Wagner ([email protected]) is technical director for process engineering at Fluor Canada Ltd., Calgary, and manager of business development for the Atlantic Canada region. He has more than 30 years' experience in engineering and construction, focusing primarily on upstream oil and gas production, both onshore and offshore. He joined Fluor in 1977 in Germany and again in 1989 in Canada as senior process engineer. Before joining Fluor, he was with MW Kellogg in the Netherlands 1974-77 and the SNC Group in Canada 1982-89. Wagner holds a master of science (1967) in chemical engineering from the University of Prague and is a member of the Association of Professional Engineers in Alberta, Ontario, Nova Scotia, and Newfoundland.
Stan Cone (stan.cone@ fluor.com) is director of process and specialty engineering for Fluor Corp.'s energy and chemicals unit, focused on the upstream and offshore sector. He has 30 years' experience in engineering and construction, primarily associated with upstream oil and gas production, both onshore and offshore. He joined Fluor in 1972 as a process engineer and subsequently became director of technology, production and pipelines. Cone was also managing director of Sime Crest Sdn. Bhd., Kuala Lumpur, regional manager, Far East for Brown & Root, and manager of facility engineering at Torch Operating Co.-Nuevo Energy, Houston. He holds a BSc (1970) in chemical engineering from Texas Tech University, Lubbock, an MSc (1972) in chemical engineering from the University of Houston, and an MBA (1989) in international management from Rice University, Houston.
