LNG PLANT ANT CO COSTS: PRESENT AND AND FUTURE TURE TRENDS
COUTS DES INSTALLATIO ATIONS DE GNL: TENDAN NDANCES CES ACTU ACTUELL ELLESET FUTURE TURES Robe Robert N . DiN D iNa apoli Vice Vi ce Presi President dent Merli erlin n Ass Associ ocia ates tes Atlanta, Georgia 30356 U.S.A Charles C. Yost III President Merli erlin n Ass Associ ocia ates tes Houston, Texas 77069 U.S.A.
ABSTRACT
New LNG projects are underway in Qatar, Oman, Trinidad and Nigeria. These projprojects are the first greenfield projects built in nearly 10 years. Contrary to past experience, capital investment per unit of production is 25 - 30% less, on a constant dollar basis, than previous projects. Cost reduction has been the subject of considerable discussion during past conferences with varying views of where and to what degree cost savings might be realized. The more cost effective designs currently being offered, however, are not the result of any single im provement or innovation but a combination of factors realized through the joint efforts of project sponsors, liquefaction process vendors, equipment suppliers and EPC contractors. Principle among these are the following: •
•
•
•
Maximizing of individual liquefaction train production for available refrigeration power in put and related equipment characteristi characteristics. cs. Reduction in the amount of over-design allowed for engineering unknowns and production/performance duction/performance guarantees. More cost effective arrangement and layout of equipment within the confines of established safety practices and code compliance. Renewed competition among process licensors and a more competitive bidding climate involving an increased number of qualified EPC contractors.
A quantitative measure of cost reduction is offered for each of these factors based on comparisons with past projects. The paper also presents an assessment of savings for new projects which can realistically realistically be expected in light of further cost reduction reduction efforts efforts and the need to maintain current levels of project reliability, operational flexibility and safety.
7.4–1 4–1
RESUME
Des projets d'installations de GNL sont en cours au Qatar, à Oman, dans l'île de la Trinité et au Nigéria. Ce sont les premiers projets entièrement nouveaux entrepris depuis presque 10 ans. Par rapport aux projets antérieurs, ils se caractérisent par un investissement de capitaux par unité de production inférieur de 25 à 30 % en dollars constants. La réduction des coûts a fait l'objet de nombreuses discussions au cours des congrès passés, divers points de vue ayant été exprimés sur les possibilités d'économie et l'ampleur de ces économies. Les projets plus économiques proposés actuellement ne résultent cependant pas de la mise en oeuvre d'une seule et unique amélioration ou innovation mais de la combinaison de plusieurs facteurs réalisés grâce aux efforts communs des promoteurs de projets, des fournisseurs de procédés de liquéfaction et d'équipement et des entreprises d'ingénierie. Parmi ces facteurs, nous retiendrons: •
•
•
•
Maximisation de la production des trains de liquéfaction en fonction de la capacité des installations frigorifiques disponibles et des caractéristiques des équipements connexes. Réduction du degré de surconception autorisé pour parer aux impondérables dtingénierie et satisfaire aux garanties de production/performances. Disposition et agencement plus économiques de l'équipement dans les limites des pratiques de sécurité établies et conformément aux codes en vigueur. Regain de concurrence au sein des donneurs de licences de procédés et compétition accrue au niveau des appels d'offres mettant en jeu un plus grand nombre d'entreprises dtingénierie qualifiées.
Le présent article donne une mesure quantitative de la réduction de coût associée à chacun de ces facteurs, basée sur des comparaisons avec des projets passés. Il présente en outre une évaluation des économies qu'il serait réaliste d'envisager pour les nouveaux projets en réduisant davantage encore les coûts, et traite de la nécessité de maintenir les niveaux actuels de fiabilité, de souplesse opérationnelle et de sécurité des projets.
7.4–2
LNG PLANT COSTS: PRESENT AND FUTURE TRENDS INTRODUCTION
Liquefaction segment capital costs represents a significant portion of the total LNG delivery chain capital cost. They typically can account for 35 - 40% or more of the total gas production-liquefaction-shipping-regasification project investment. The authors have published extensively on the subject since the early 1970’s. During that period the LNG industry has benefited from the dramatic worldwide growth in natural gas consumption. LNG plant costs over the period have also risen substantially. With the stabilization of crude oil prices in the 1980’s, maturing of primary Far East markets and the increasing competition of pipeline supply of natural gas, LNG projects have come under increasing pressure to reduce capital investment as a means of remaining competitive within the framework of prevailing fuel prices. Reduction of LNG project cost has been the subject of considerable discussion throughout the industry. Panels on cost reduction are commonplace at most international natural gas forums including this conference. Efforts to reduce plant costs are now being realized as new greenfield projects under construction in Qatar, Oman, Trinidad, and Nigeria are being built for a capital investment per unit of production 15 - 35% less than projects built 10 - 15 years ago. Contrary to what many may think, however, these new, lower cost projects are not the result of any single technical innovation or design improvement but a combination of factors realized through the joint efforts of project sponsors, liquefaction process vendors, equipment sup pliers and EPC contractors. HISTORICAL LNG PLANT COSTS
Before discussing the principle factors contributing to LNG plant cost reduction a discussion of major cost elements which make up total LNG plant cost investment cost and the historical trend in these costs over the past 30 years is useful in understanding how LNG plant costs have evolved to their present level. LNG Plant Project Cost Buildup
Table 1 shows the general distribution of major component costs as a percentage of total project costs for a typical greenfield, two train LNG plant installation. Important project variables which influence these costs are also noted in Table 1.
7.4–3
Table 1. Liquefaction Plant Major Project Cost Components
Major Project Variable % Cost Design/ Site Site/Project Project Distribution Capacity Labor Related Execution Liquefaction Trains 34 - 38 X X Utilities 12 - 16 X X LNG Storage & Loading 10 - 15 X X Buildings & Misc. 3-5 X EPC Contractor 14 - 16 X Marine Related 3-6 X X Infrastructure 0-6 X X Other Project Related 10 - 12 X
EPC related costs which typically involve the feed gas pretreatment, liquefaction, utilities and offsites, LNG storage and loading and marine facilities represent only about 80 85% of the total plant capital cost. Permanent infrastructure (housing community and sup port for operating personnel and marine support services) accounts for an additional 34%. The remaining 12 - 16 % accounts for Owner project management and start-up costs, CAR insurance and project venture costs. Project venture costs are substantial and include expenditures for pre-project feasibility and basic engineering studies, development of project specifications, and EPC bid evaluation. Venture costs also include expenditures for post-operational expenses for plant staffing, training, technical support services and related corporate expenses and typically can involve total expenditures of $100 to 200 million. In comparing project costs, particularly costs reported in trade journals and other publications, it is not always evident what, if any, costs outside of the EPC contract costs are reported. This can lead to erroneous conclusions regarding the competitive nature of one project vs. another. Total project cost should be considered in evaluating alternative project concepts. Another important fact to note is that for a worldscale size LNG plant less than 50% of the total LNG plant project cost is capacity related. These capacity related costs involve the liquefaction trains and supporting cooling system and a portion of the plant utility requirements. LNG storage costs are a function of tank design (the choice of containment system) and storage volume which is set primarily by shipping considerations (ship parcel size, and shipping schedule/delays etc.). Although emphasis is rightly given to processing and design related improvements as a means of reducing LNG plant costs, much of the cost of an LNG liquefaction project is beyond the influence of the design engineer and is mainly a function of site related conditions and project development and project execution efforts. Costs for the loading jetty
7.4–4
and related marine facilities, plant infrastructure, owner project management and venture costs are basically fixed for a given location regardless of the project size. Historical LNG Plant Cost Trends
Figure 1 shows the historical trend on a unit capital cost basis (US$/tonne per year) of the 17 greenfield LNG projects in operation or under construction. Cost data is also included for the Arzew, Algeria plant which was the first base load LNG plant constructed but which is no longer in operation. Capital cost data in Figure 1 is expressed as US dollars of the day at the year of initial start-up. If start-up was delayed for more than a year, capital cost is expressed as dollars of the day at the year of construction completion.
Historical Cost of LNG Plants US$ of the day per TPY Greenfield Projects 1000
Y P T / 100 $ S U
10 1960
1970
1980
1990
2000
Year of Start-up
Figure 1 Figure 2, an update of cost trend data published at the LNG 8 Conference, is a similar plot of greenfield project costs on an inflation adjusted, current (1998) dollar basis [1]. Inflation adjustments are derived using the Nelson Refinery inflation index.
7.4–5
Escalated LNG PLANT CAPEX 1998 US$/TPY Greenfield Projects 1000. Y P T / $ S U
100. 1960
1970
1980
1990
2000
Year of Startup
Figure 2 Cost trends shown in Figure 1 & 2 reflect the following evolution in plant design philosophy: •
•
•
•
The earliest LNG plants used variations of the classical cascade refrigeration cycle for natural gas liquefaction. Engineering/design technology is borrowed from experience in air separation, helium recovery, and oil refinery design. Capacities were small, on the order of 1 million tonnes per year (MMTPY). Cost are low for these plants which, for a variety of reasons, are not representative of succeeding LNG projects. Plants built in the early 1970’s (Libya, Brunei, and Algeria) were considerably larger than the first plants in Arzew and Alaska and utilized variations of the mixed refrigerant process in an effort to reduce project capital investment. Because of design and operating problems several of the projects failed to achieve design LNG production capacity. Design problems also led to significant cost overruns in a number of projects. The late 1970’s and very early 1980’s saw the emergence of the Air Products & Chemical, Inc. (APCI) developed propane precooled, mixed refrigerant (P-MR) process as the preferred liquefaction technology for use in large, multi-train processing configurations. Refrigeration compressors were steam turbine driven and basic plant design was robust with a large degree of built-in over capacity to insure security of supply. From the early 1970’s through the end of the 1980’s, inflation adjusted unit LNG plant costs reached a peak due in large part to the effects of high worldwide inflation, a reimbursable bidding strategy utilizing EPC contractors with proven LNG experience, and a conservative design philosophy to insure integrity of supply. Further increases in train capacity using the now proven APCI P-MR liquefaction technology occurred in the mid to late 1980’s. A major shift in plant design technology also occurred during this period with gas turbines becoming the preferred choice as drivers for the main refrigeration compressors. Air-fin cooling at the Northwest Shelf 7.4–6
Project in Australia proved to be a viable option to once-through seawater cooling or a closed loop cooling system.. CURRENT LNG PLANT DESIGN SITUATION
As can be seen from Figure 2 unit capital costs for projects currently under construction have been reduced by 25 - 35% from the peak costs experienced in the mid-1970’s to mid-1980’s. Table 2 shows the distribution of typical cost savings for a new two train 6.6 MMTPY LNG project using technology typical of plants now under construction com pared to a three train, 6.6 MMTPY project using older, 1980’s technology. Significant cost savings are achieved with the current plant designs in the liquefaction, EPC, and miscellaneous support service cost categories. Infrastructure and owner cost show somewhat less of a reduction in cost. Table 2. LNG Plant Cost Variation of Cost between Older and Current Basis of Design Basis: 1980’s Design Plant Cost = 100 1980's 1990's Variance Design Design (1990's/1980's) No. Trains 3 2 Train Capacity - MMTPY 2.2 3.3 Plant Capacity - MMTPY 6.6 6.6 Liquefaction 33.19 20.88 0.629 Utilities 12.01 10.26 0.854 LNG Storage & Loading 5.84 4.87 0.834 Buildings & Misc. 6.90 4.31 0.625 EPC 21.72 8.97 0.413 Subtotal 79.66 49.29 0.619
Marine Infrastructure Subtotal Owner Total
3.68 4.15 7.83
2.49 4.13 6.62
0.677 0.995 0.845
12.51 100.00
9.77 65.68
0.781 0.657
Economies of Scale
Economies of scale as a result of both larger individual train capacities and larger total production have had a major impact on reducing LNG plant capital costs. Train LNG ca pacities have steadily increased from 2.0 - 2.5 MMTPY for plants built in the 1980’s using the APCI liquefaction process to about 3.3 MMTPY for the Oman LNG plant which are the largest trains currently under construction.
7.4–7
The increase in train capacity in plants using the P-MR liquefaction technology has been achieved by the use of large, single shaft gas turbines previously used in electric power generation service [2] [3]. Earlier gas turbine driven LNG plants used smaller, dual shaft gas turbines as compressor drivers. The 28 MW ISO rating of the GE Frame 5 gas turbine, the largest proven, dual shaft turbine available, limited maximum possible train capacity to about 2.7 MMTPY without resorting to the installation of more costly multiple compressor-drivers in parallel. LNG train production of 3.3 MMTPY for the P-MR liquefaction process is possible with the use of a GE Frame 6 gas turbine (ISO Rating of 38.5 MW) as driver for the propane refrigeration cycle compressor and a GE Frame 7 gas turbine (ISO rating of 80MW) for the mixed refrigerant compressor driver. Maximum economies of scale as far as train capacity is concerned is achieved by maximizing production for available installed gas turbine power. With the use of the large GE Frame 7 single shaft gas turbine as the driver for both the both P-MR refrigeration cycle compressors individual train production capacity in excess of 4.0 MMTPY is possible. APCI reports that fabrication technology and manufacturing capabilities exist for construction of spiral wound heat exchangers in this size range [4]. Since only about 50% of the cost of an LNG plant is truly capacity sensitive the total cost of a two train plant producing 8.0 MMTPY is not significantly greater than a two train plant producing 6.6 MMTPY. Since installation of at least two trains is desirable from a plant reliability standpoint, maximum economies of scale on a total plant basis are achieved by increasing individual train capacity. LNG plant cost studies performed by Merlin Associates indicate that a two train 8.0 MMTPY plant can be built for about 10 15% more than the cost of a two train 6.6 MMTPY plant. Unit cost per tonne basis for the larger plant is nearly 15% less than that for the smaller capacity project. Operating costs are also less for a larger train size, larger total production capacity plant on a unit cost ($/TPY) basis. Operating labor costs for a two train plant are essentially fixed regardless of the train capacity. Maintenance charges vary as a function of total plant capital cost. Other costs such as marine and harbor operation, technical support and administration services are essentially fixed for a worldscale size plant. Another important advantage of building a two train plant compared to a three train plant is the reduction in the EPC completion schedule. A two train plant can be completed 3 - 6 months earlier than a three train plant with significant savings in EPC contractor costs and field erection cost. Reduction in Over-design & Design Factors
The current LNG plant design basis represents a joint understanding on the part of both producers and buyers regarding security of supply, reliability, and assurance of meeting contractual obligations. It has evolved from more than thirty years of engineering design and plant operational experience. This has led, particularly in the early years when technology was largely unproven, to a generally conservative design philosophy stressing ample design margins, proven technology, and some degree of redundancy. Since the long term reliability of LNG supply is now a proven fact, the need for large over-design margins and an overly conservative design philosophy no longer exists. 7.4–8
Although design margins have been gradually decreased as the technology has matured a certain degree of design margin is still needed to account for: •
Equipment and process performance guarantees.
•
Variations in feed gas and processing conditions over the life of the project.
•
Expected variations in ambient air and water temperatures.
•
General design uncertainties and equipment sizing restrictions.
Design margins for these purposes typically amount to 8 - 12% of design capacity. It is difficult to quantify the impact of reduction in design margins on total project cost. However, it is apparent that project sponsors are not pre-paying for excess capacity with the current basis of design. The newer gas turbine driven LNG plants have tended to maximize train production for the installed turbine power utilizing, in some instances, available power in starting turbines and motors to supplement main turbine power output. With this design approach there is very little excess capacity available through simple de bottleknecking. Capacity increases of more than 7 - 10% require substantial significant expenditures. The older steam turbine driven plants, on the other hand, had built-in overcapacity margins of as much as 35 - 40%. This earlier excess capacity, once demonstrated, was readily purchased by the original buyers eager to meet increasing market demand from a proven source of supply. Sales efforts for new projects now focus on selling full design output. Incremental production often must now be sold on a spot or short term basis until sufficient long term demand is created. Engineering Design Standards & Plant Layout Consideration
The original engineering and design specifications used for LNG plants were adapted from specifications developed for older hydrocarbon processing industries - primarily oil refineries and petrochemical plants. As LNG-specific experience was accumulated, these older specifications were modified by adding to them while not fully deleting non-LNG specific elements, leading to increasingly more rigorous and all inclusive design standards. These standards are now undergoing an intensive review with the objective of achieving more cost effective designs while still maintaining a high level of safety and reliability. A major part of this effort has been a more realistic approach to hazards associated with LNG fires. This fact allows a reduction in spacing between major plant areas and reduction in the amount of fireproofing required within the process areas. The result has been a significant reduction in the footprint of the liquefaction train with a corresponding reduction in bulk material requirements i.e. piping, valves, structural steel etc., fireproofing and related material expenses, project management and erection labor costs. Estimated cost savings from these redesign efforts are on the order of 9 - 13% in bulk materials and erection labor costs equivalent to savings of several hundred million dollars for a worldscale size LNG plant. It is important to note that cost reductions as a consequence of reevaluation of design standards, fire and safety philosophy and design margins has been achieved without compromising plant safety and integrity.
7.4–9
Competitive Technology and EPC Contractor Considerations
EPC contracting strategy has had a significant impact on final LNG project cost. It influences the overlay project execution duration, scope and cost of the Front End Engineering Design (FEED) work, EPC contract selection, responsibility for performance guarantees and cost and scope of the Owner project management effort. A lump sum bidding strategy involving 3 or 4 qualified bidders typically results in the lowest cost project. Initial attempts with the use of lump sum contracts for greenfield LNG projects, however, were not very successful. Limited contractor experience coupled with high inflation during the 1970s, when several LNG projects were started, led to significant cost overruns and completion delays. These early projects also did not have the benefit of a strong and technically competent international oil company to function as project technical leader. This early experience led to a choice of reimbursable type contracts administered by the project Operating Company‘s project management team. This approach allowed the developed of LNG specific basic design concepts and detailed design practices as a joint Owner/EPC contractor effort but at some additional engineering cost. The contractor responsible for the FEED was usually awarded the EPC contract providing a continuity of effort. This approach allows acceleration of project completion by pre-ordering critical items of equipment during the FEED phase while shifting some finalization of design until the EPC execution phase. As noted earlier significant reduction in EPC contractor costs is possible with a two train plant compared to a three train plant. Engineering and procurement cost are less due to fewer items of equipment, a reduction in the number of layout and piping drawings, and reduced field construction supervision. As LNG plant engineering and construction techniques matured and design bases better defined, both owner/operators and EPC firms became more inclined to structure LNG construction projects on a lump sum basis. The development of comprehensive LNG Project Specifications now allows a widening of qualified EPC contractors beyond the limited number with specific LNG construction experience. The combination of LNG-specific Project Specifications and engineering design practices together with increased competition among EPC contractors and a reduction in the number of trains to produce a given annual quantity of LNG has led to a reduction of several hundred million dollars in liquefaction plant EPC costs in recent years. A more competitive situation is also developing regarding selection of liquefaction process technology. The recent selection of cascade liquefaction technology developed by Phillips Petroleum Co. for the Trinidad LNG project is the first use of liquefaction technology other than the P-MR process since the early 1970’s. Black & Veatch Pritchard is marketing an improved version of the all-mixed refrigerant technology used in earlier plants built in Algeria. BHP and others are also offering alternative liquefaction technologies each claiming cost advantages over existing technology. In general, efforts to reduce costs by simplifying processing configuration are made at the expense of lower thermodynamic efficiency. From a total LNG plant cost perspective the impact of liquefaction technology is relatively small, as is discussed later. A competitive environment for liquefaction 7.4–10
technology, however, should encourage more cost effective designs and provide the op portunity to tailor liquefaction process selection to fit non-traditional project requirements. Summary of Cost Reduction Efforts
Table 3 shows Merlin Associates’ estimates of distribution of capital cost reduction for a 2 train plant producing 6.6 MMTPY based on current design technology compared to a 3 train plant producing 6.6 MMTPY based on technology typical of LNG plants built in the 1980’s. Estimate basis is the same as used to develop comparative cost data shown in Table 2. Table 3. Distribution of LNG Plant Capex Reduction
Basis: 6.6 MMTPY Plant Capacity Millions 1-1-98 US$
Liquefaction Utilities LNG Storage & Loading Buildings & Misc. EPC Subtotal
S.E. Asia Location
Design OverTotal Standards & Capacity & Competitive Capex Economies Basis of Safety EPC Bidding Reduction* of Scale Design Factors Strategy 285 80 180 25 40 5 30 5. 25 60 295 705
5
25 50
90
285
35
295 295
0
0
Marine Infrastructure Subtotal
25 1 26
0
25 1 26
Owner
65
40
10
796
130
321
Total
5
15 35
310
Note:* Two train 1990's design vs. 3 train 1980's design
Referring to Table 3, engineering design standards and layout considerations and com petitive EPC bidding strategy considerations each account for some 40% of the total cost reduction with an additional 16% due to benefits of larger train size. The remaining 4% can be attributed to reduction in design safety factor margins. The substantial reduction in EPC cost is not only the result of a more competitive bidding environment but the evolution in quality of the bid specification package to the point where contractors have a firm and equal basis for developing lump sum bidding and a reduction in the EPC completion schedule.
7.4–11
Cost reduction as a result of revised design standards and more cost effective equipment layout has a substantial impact on bulk material requirements and supply and erect subcontracts. Erection labor costs are also reduced. FUTURE TRENDS IN COST REDUCTION
In Merlin Associates’ judgment additional capital cost reductions of the magnitude realized for the plants now under construction cannot be realistically expected for projects in the foreseeable future. A substantial portion of the cost reductions discussed in this paper are one time savings relating to more realistic and cost effective design standards and fire and safety analysis and a more competitive EPC bidding climate. Larger Train Sizes
Some further cost reduction through economies of scale will be realized. As noted earlier, single train sizes in excess of 4 MMTPY are possible using the P-MR process and two frame 7 gas turbine driver. Reductions on the order of 15% on a unit cost basis are thought possible by increasing plant production capacity by increasing individual train size. Further increases in train capacity for the P-MR process approach limits in shipping considerations for the large spiral wound heat exchanger and in being able to match maximum gas turbine power availability to compression requirements. Design studies have been undertaken utilizing a single large turbine (GE Frame 9 size) as a single driver for all liquefaction cycle compressors (precoooling and mixed refrigerant) as a means of reducing equipment (and cost) while maximizing power utilization [5]. Additional power and hence production capacity can be achieved through use of larger turbine starter motors which would then be used as driver helper motors. One downside to larger train sizes is that larger trains bring larger increments of product to the market place. In the past it has not been unusual for a single buyer to contract for the full production from a train to be delivered to a single market. The current train size has increased by nearly 75% from 1985 to 1996 and is now probably too large to be utilized in a single market growth step. This significantly increases marketing complexity for new projects particularly for the multi-train arrangement desirable from a supply security standpoint. Another drawback to larger train sizes and total project capacity is the increasingly larger gas reserves required in a single location to support the project over the life of the sales contract. Newer sales contracts may be for as long as 25 years compared to 20 years for earlier contracts. Reserve requirements for an 8 MMTPY project over the longer, 25 contract life amount to about 300 Bcm (10.5 TCF). This is a sizable gas reserve and there are only a limited number of undeveloped fields of this magnitude in the world today. Alternative Liquefaction Processes
Some further cost reduction as a result of alternative liquefaction process selection may be possible, although, in Merlin Associates’ opinion, this has yet to been demonstrated. The magnitude of potential savings is limited, however, since compression related equipment costs represent nearly 40% of the total liquefaction train cost of approximately 7.4–12
$200 - 250 million and there is no substantial difference in thermodynamic efficiency among the commercially available liquefaction processes. Some cost differential may be realized, however, as a result of the particular arrangement of compressors, number of casings required and specific compressor design of each process. Of the remaining train cost only about $60 - 120 million is liquefaction process selection sensitive. Even a 25% reduction in heat exchanger related costs constitute a savings of only $15. - 30 million per train or a maximum of 4% of total LNG project cost. Single Train Projects
Single train projects are now under consideration for situations where there are not sufficient proven gas reserves to support a worldscale size, multi-train plant and/or where market demand will not initially support the full output of a multi-train plant. The need for multiple trains in order to insure integrity of supply is of less importance now as long term reliability of LNG plants has been demonstrated and annual availability can be reasonably well predicted. Many LNG buyers now have a diversity of supply sources and are no longer dependent on a single LNG plant for product. Single train plants were considered for both the Oman and Rasgas LNG projects, for a period of time, although both finally went ahead as two train projects after sufficient sales contracts were secured to support installation of more than one train. The Trinidad project is another example of a small (3 MMTPY) project sized to fit initial reserve estimates and market demand. It is considered a one train project although the use of dual, 50% capacity refrigeration compressors installed in parallel for each of the three refrigeration circuits provides an annual availability comparable to a two train plant. Additional trains are now being considered for the Trinidad project with the discovery of additional gas reserves. A large, single train plant can now be built for a lower capital cost than a multi-train plant of the same capacity built with older design technology. Total financeable cost is lower for a smaller, single train plant than a larger project and can be brought fully onstream earlier. Project economics under these conditions can be competitive with larger projects under certain circumstances. Predictions for Future Cost Reduction
In Merlin Associates’ opinion continuing efforts in maximizing train capacity through process optimization and combined gas turbine-motor drivers might result in a further 4 7% decrease in unit capital cost ($/TPY) basis. Alternative liquefaction technology may offer some cost advantage for small capacity LNG projects (2 MMTPY max.) and/or plants located offshore either on floating barges or fixed structures. Also use of simpler but less efficient liquefaction processes may provide the incentive in terms of reduced capital expenditure for developing gas reserves now considered to be uneconomic for world scale size projects. It should also be remembered that project sponsors, host countries, and LNG buyers must commit to substantial capital outlays throughout the entire delivery chain to achieve an economically viable project. Continuing efforts at cost reduction must not compromise security of supply, reliability and assurance of meeting contractual obligations. 7.4–13
Cost reduction efforts will continue, however, as project sponsors now find that many LNG projects, even if they must be initially constructed as one train facilities, can produce an acceptable rate of return at prevailing market fuel prices. REFERENCESCITED
1.
DiNapoli, R.N. “Evolution in LNG Project Costs and Estimation Techniques for New Projects”, Eighth International Conference on Liquefied Natural Gas , Los Angeles, June 1986.
2.
Nagelvoort, R.K., Poll, I., & Ooms, A.J., “Liquefaction Cycle Development”, Ninth International Conference on Liquefied Natural Gas, Nice, October 1989.
3.
Liu, Y-N, Lucas, C.E., & Bronfenbrenner, J.C., “Optimum Design of Liquefaction Plants with Gas Turbine Drivers’, Eleventh International Conference on Liquefied Natural Gas, Birmingham, July 1995.
4.
Liu, Y-N, Edwards, T.J., Gehringer, J.J. & Lucas, C.E., “Design Considerations of Larger LNG Plants”, Tenth International Conference on Liquefied Natural Gas, Kuala Lumpur, May 1992.
5.
Salimbeni, A.B., & Camatti, M., “Compressors for Base Load LNG Service”, Eleventh International Conference on Liquefied Natural Gas, Birmingham, July 1995.
BIBLIOGRAPHY
DiNapoli, R.N., “Estimating costs for base-load LNG Plants”, Oil & Gas Journal”, November 17, 1975. DiNapoli, R.N., “LNG costs reflect changes in economy and technology”, Oil & Gas Journal , April 4, 1983. DiNapoli, R.N. “Economics of LNG Projects”, Oil & Gas Journal , February 20, 1984. DiNapoli, R.N. & Yost, C.C., “A Generic Cost Model for estimating LNG Plant Capital Costs”, Symposium on Liquefied Natural Gas - AICHE Meeting , Houston, TX., April 1991. DiNapoli, R.N., Yost, C.C., & Nissen, D., “Strategic Evaluation Central to LNG Project Formation”, Oil & Gas Journal , July 3, 1995.
7.4–14
