Remote dry gas fields often fail to be produced because of either technical or economic factors. Where no gas pipeline infrastructure is available, FPSOs prim-rily process oil and simply re-inject associated gas. Rethinking FPSO capabilities could provide an alternative solution for stranded and associated gas.
A gas-only FPSO (GFPSO) could well be the solution the industry needs to bring remote dry gas fields into production.
Technology developments in gas utilization processes, continuing discovery of both oil and gas reserves in remote and/or deepwater locations, increasingly strict regulatory requirements, and changing market pressures combine to drive both technical and commercial aspects of recovery of associated gas in remote locations. The result will inevitably be a combination of traditional oil production facilities and gas utilization facilities on a single vessel. Some consider this option to be technically feasible now.
In theory, a GFPSO, a floating gas production and conditioning facility, is feasible. Existing technology supports construction. But a GFPSO project would have to be justifiable both technically and economically.
Because the GFPSO is a movable and re-usable asset, cost can be recovered from multiple fields, which also means that the GFPSO can be applied to smaller reservoir sizes than might be necessary to justify a fixed installation. This could unlock many gas reserves that might otherwise remain stranded.
Principal export products from a GFPSO would be LPG liquid, a C5+ condensate liquid, and pipeline quality residue gas.
Transporting residue gas remains the biggest problem facing implementation of a GFPSO. Produced gas could be transported or readied for transport by one of four generic methods:
- Exporting the gas through a pipeline
- Reducing gas volume through liquefaction or compression – LNG or compressed natural gas (CNG)
- Converting gas to another form of energy such as electric power
- Converting the methane molecule to a liquid product – methanol or gas-to-liquid (GTL).
Each option presents a set of considerations that require additional evaluation.
To evaluate options, a few assumptions need to be made. The first of these is the production rate necessary to allow a GFPSO to function economically. For the purpose of this evaluation, the rate is set at 400 MMcf/d of feed gas. The weight of topside facilities necessary for this flowrate can be carried by commonly available hull sizes.
Each of the production options has its own merits and drawbacks, all of which have been considered. In this evaluation only the pipeline, LNG and CNG options were considered, because the power generation and GTL options, for the given feed gas rate, would exceed commonly available hull sizes.
Exporting by gas pipeline
Gas export by pipeline is the simplest transportation option. All equipment and technologies used when gas is exported via pipeline are in use on modern oil-production FPSOs.
Pipeline construction is expensive, however, and expenses rise as water depth and distance from shore increase. Pipelines become limited in size as lay stresses intensify in deep water and reduce the size of pipe that can be installed. Severe bottom profiles also reduce applicability of a pipeline solution.
For evaluating the pipeline option, the following assumptions have been made:
- First 500 km subsea, with the rest onshore
- Booster stations every 500 km onshore
- Inlet pressure of 3,000 psig offshore and 1,400 psig at onshore arrival
- Outlet pressure of 1,000 psig
- Line size of 24-26 in.
The LNG option requires a unique gas processing scheme. LNG must provide for efficient recovery of the NGL streams as part of the overall liquefaction scheme. Most LNG processes use hydrocarbon refrigerants that are obtained from NGL production. This accounts for the slightly lower LNG production rate.
Specially designed LNG storage tanks in the GFPSO hull store the LNG, which is offloaded to LNG tanker ships by LNG offloading systems specially designed for ship-to-ship transfer of cryogenic liquids. These use either conventional LNG loading arms or specially designed over-the-bow LNG loading equipment.
The economic evaluation does not include costs for LNG receiving and re-gasification facilities at the onshore receiving location. The assumption is that a GFPSO project would use existing LNG re-gasification terminals. Addit-ional costs for new re-gasification facilities would impact the economics of the LNG option.
There are several LNG liquefaction technologies presently available. None have been constructed offshore on a floating substructure to date. The consensus seems to be that floating offshore LNG is doable and that it is only a matter of time before the first project appears.
Both the pipeline and LNG options show a trade-off beginning at about 2000-km distance from the market.
At least four companies are offering CNG transportation plans that have been the focus of industry attention over the last several years. The CNG concept uses specially equipped ships to shuttle gas under high pressure from the production location to an onshore receiving infrastructure. The CNG option demonstrates the lowest overall investment for the operator. The problem is that the process works only if CNG ships are available. Despite considerable industry attention, no CNG ships have been constructed. All of the CNG technology providers are actively seeking a project that can support construction of one or more of these vessels.
Since no vessel has yet been built, the economics of initial CNG projects will have to reflect the capital cost of vessel construction, an issue that is not considered in this analysis.
Topsides weights and vessel size
Topside weights have been estimated for each option. The weights include all processing and support facilities required.
For the CNG and pipeline options, the topsides are the same. Processing steps are identical, including compression for gas export.
The weight for the LNG option reflects the increased equipment count required by the LNG process. The minimum vessel size is based on topside weight being no more than 10% of the vessel's dwt. The vessel sizes represent the smallest hull size that can accommodate the topside facilities for each option.
The liquid storage requirement in the pipeline and CNG options is somewhat less than normally found in an oil production FPSO application. A hull shape other than ship-shape might be a better structural and/or economic choice for a GFPSO using one of these options. It is certainly an issue that is worthy of further study.
Capital and operating costs
Capital and operating costs are based on publicly available information or, where appropriate, Fluor's in-house data developed for various projects or studies. These are rough order of magnitude costs with accuracy is in the 30%-40% range. Product shipping costs are included under operating cost for the CNG and LNG options, and the ships are not capitalized.
A simple payback before tax method was used to compare the four alternatives. Simple payback is defined as overall capital cost divided by first year gas revenue minus operating cost. Field development costs are assumed to be identical for all cases and are not included in the overall capital costs.
Gas revenue to the field operator is assumed to be $0.80/MMbtu and is included in the revenue calculation. Destination gas price is assumed to be $4/MMbtu. Since hydrocarbon liquid recovery would be the same for each option, no credit is reflected in the economics for the liquids revenues.
The economic analysis used is quite simple. Cost estimates have an accuracy of 30%-40%, and conclusions are based on assumed sales prices. Using this simple payback method, the CNG case has the highest return on investment.
The CNG production model is based on chartering the CNG carriers, which represents about 85% of the total project costs. Under this assumption, the CNG case requires the lowest initial capital investment.
The first CNG project, however, will most likely need to offer the CNG ship operator enough incentive to justify the construction of an initial CNG fleet. It is difficult to say what form this incentive might take. Development of the first CNG project could require some form of guarantee(s) or capital input from the field operator. This would significantly impact the simple payback analysis given here.
In contrast to the CNG option, LNG production requires the highest capital outlay regardless of the distance to market. LNG transport vessels are also included in this analysis as operating costs and are not capitalized. Since there is an existing fleet of LNG carriers and an existing LNG shipping business, it is less likely that a field operator would have to provide incentives for LNG shippers. This will be a more valid assumption as the global spot market for LNG develops.
Though pipeline has been the transportation choice for most offshore gas field developments, most pipelines have been in relatively shallow water for fairly short distances. Capital investment for new pipelines for long distances and/or deepwater applications becomes significant. LNG becomes a competitive alternative in the 2,000-km distance to market range.
The simple economics used in this analysis do not reflect the intricacies of economic analysis for any real project development. Each individual project must be evaluated on the basis of its own unique parameters. Any of the options studied here could be the most economic under the proper set of physical and commercial project conditions.
References available upon request from the authors.
Editor's Note: This is a summary of an OTC paper. Wagner, Jan and Cone, Stan: "Gas FPSO – How Soon to Reality?" OTC 15303 presented at the 2003 Offshore Technology Conference, Houston, Texas.