7.3–1

“COST OPTIMIZATION,” THE CONTRACTOR’S APPROACH

“OPTIMISATION DES COUTS,” APPROCHEDE L’ENTREPRENEUR

David A. CoyleChief Technology Engineer, LNG

Charles A. DurrTechnology Vice President, LNG

Don K. HillLNG Technology Manager

The M.W. Kellogg CompanyHouston, Texas, U.S.A.

ABSTRACT

The contractor continuously works to improve existing and to develop new technologiesfor the LNG industry, thus enabling the contractor to deliver the most cost effective projectsto it clients. In optimizing the project cost, a strong emphasis is placed on cost reduction. Toidentify potential cost savings, a cost breakdown of an LNG plant is presented in this paperalong with a discussion of the major cost issues, including:

• Process Technologies• Feed Stock Compositions• Number and Capacity of Liquefaction Trains• Design Margins• Site Selection• Plant Layout• Design and Engineering Specifications• Type and Number of Mechanical Drivers• Cooling and Heating Medium• Schedule (life cycle)

The objective of making significant “cost optimization” comes only from new methodsand new innovations. This paper discusses new methods and innovations with increasedemphasis on value enhancement or "cost optimization" rather than focus simply on costreduction. These methods will be discussed in this paper along with proven examples and willdetail new technology areas to explore with emphasis on areas from the above cost issues list.

7.3–2

Since the contractor takes on the completion and guarantee risk for a project, thecontractor must expend an appropriate engineering effort to ensure that the risks associatedwith first-of-a-kind features are reduced to acceptable levels via risk management. Thecontractor uses experience as the foundation for launching new ideas and uses provenmethodologies to maintain confidence in advancements. This paper discusses riskmanagement methods with examples of how to make these advances in technology that arenecessary for significant “cost optimization.”

RESUME

L’entrepreneur travaille continuellement dans le but d’améliorer les technologiesexistantes et de développer les technologies nouvelles pour l’industrie du GNL, permettantainsi à l’Entrepreneur de délivrer les projets les plus rentables à ses clients. En optimisant lescoûts du projet, un effort important est accordé à la réduction des coûts. Afin d’identifier leséconomies potentielles des coûts, une décomposition des prix d’une usine GNL est présentéedans cet article ainsi que des commentaires sur les questions concernant les coûts majeurs,comprenant :

- Procédés technologiques- Composition du stock d’alimentation- Nombre et capacité des trains de liquéfaction- Marges de conception technique- Sélection du site- Plan d’implantation des installations- Spécifications des plans et de l’ingénierie- Type et quantité des dispositifs d’entraînement mécanique- Moyens de refroidissement et de chauffage- Calendrier (cycle de vie)

L’objectif de la réalisation des ‘coûts d’optimisation’ significatifs vient uniquement deméthodes nouvelles et de innovations nouvelles. Cet article examine les nouvelles méthodes et innovations avec une accentuation sur la mise en évidence de la valeur ou ‘optimisationdes coûts’ au lieu de se focaliser simplement sur la réduction des coûts. Ces méthodes serontdéveloppées dans cet article avec des exemples éprouvés et détailleront de nouveauxdomaines technologiques à explorer avec une mise en évidence des sujets figurant dans laliste des questions ci-dessus concernant les coûts.

Puisque l’Entrepreneur est en charge de la réalisation du projet et garantit les risques auniveau du projet, il doit accordé l’importance appropriée à l’ingénierie afin de s’assurer queles risques associés aux nouvelles techniques spécialisées soient ramenés à des niveauxacceptables grâce à la gestion des risques. L’Entrepreneur utilise son expérience comme basepour le lancement de nouvelles idées et utilise des methodes éprouvées pour maintenir laconfiance dans les innovations.

Cet article s’intéresse aux méthodes de gestion des risques et fournit des exemples surle moyen de réaliser ces progrès au niveau des technologies qui sont nécessaires à la réalisation d’une ‘optimisation des coûts’ significative.

7.3–3

“COST OPTIMIZATION,” THE CONTRACTOR’S APPROACH

INTRODUCTION

The baseload LNG plant contractor is working in an industry which continues to growmore competitive as gas reserves are targeted for the same demand markets. Not only mustLNG liquefaction projects compete against other LNG projects, but also against technologiessuch as gas-to-liquids conversion and pipelines. Increasing competition leads to renewed costreduction efforts to minimize the delivered gas cost. At the same time plant owners mustmaximize return on investment. Responding to these goals has led to applications of newtechnology and continued study of further savings possibilities. The contractor, havingsuccessfully bid and built baseload plants on a lump sum basis, is in a unique position to helpowners determine overall risks and returns, and optimize costs.

REDUCING LIFE CYCLE COST

A primary task during the early stages of project development is to define the overalleconomic goals. Generally the objective is to maximize the rate of return, or to minimize theplant life cycle cost, for the given project constraints on total cost, marketable product, or gasreserves. It is useful to create a model to better understand the effects of different economictrade-offs. This preliminary model does not have to be complex to provide useful information.The model should, however, take into account any impact on revenues by using a net presentvalue (NPV), internal rate of return (IRR), or life cycle cost method.

For example, Figure 1 is a graph based on a simple IRR model for a conceptual LNGplant. From this type of graph it is possible to state economic goals, such as:

- Spend up to $20 MM for each 1% increase in LNG production.

- Spend up to $6 MM for an additional day per year of plant availability.

- Spend up to $13 MM to reduce fuel consumption by 10%.

The converse is also true; if it is possible to cut $20 MM from the project cost whileimpacting LNG production by less than 1% then the cost cutting measure should beconsidered. These goals change from project to project, but performing this type of analysisduring the early development of a project helps to clarify important variables and put costcutting in proper perspective. Using such a model allows the contractor to optimize costcutting measures by balancing capital costs against net revenues.

However even when considering impact on revenues, reducing the capital cost of a plantis still important. For a plant life of 20 years, the capital depreciation is about 5% of capitalexpenditure (CAPEX) per year. Compare this figure against typical operating costs of 2-3%of CAPEX per year and annual fuel costs of 1-2% of CAPEX, and it is clear that reducingcapital expenditure is critical to the project success. At the same time the LNG net revenuesare about 30-40% of CAPEX per year (about 0.1% of CAPEX for every day of production);thus, maintaining high plant availability is still important.

7.3–4

Figure 1

To effectively cut costs one must first know where the greatest costs are found. Table 1below indicates the cost breakdown of a typical LNG plant by process unit and by component(i.e., equipment, bulk materials, and construction). Of course, there is no such thing as thetypical LNG plant because the plant design and cost is highly dependent on site.

In Table 1 the process units most affected by site include gas treatment, utilities andoffsites, and LNG storage and loading. The construction costs are also highly site specific anddepend on labor productivity and hourly rates in addition to construction methods such asmodular vs. stick built. Major cost issues are discussed in more detail below.

Table 1. Approximate LNG Plant Cost Allocation(Basis: 6 to 7 MMTPA Grassroots Plant)

Percent ofTotal Cost

GasTreatment

Liquefac-tion/

Refrig/N2Reject

Fraction-ation

Utilities&

Offsites

LNGStorage

&Loading

Total

Equipment 4 14 1 10 1 30

Bulk Materials 3 7 1 5 4 20

Construction 4 6 2 8 15 35

Misc 1 5 1 4 4 15

Total 12 32 5 27 24 100

Misc includes insurance, home offices costs, material freight & transport, etc.

0.7 0.8 0.9 1 1.1 1.25.0%

10.0%

15.0%

20.0%

25.0%

30.0%

Capital Cost

Inte

rnal

Rat

e of

Ret

urn

(%)

4 MMTPA

5 MMTPA

6 MMTPA

7 MMTPA

8 MMTPA

Typical LNG PlantEconomic Model

7.3–5

Table 1 Basis and Site Adjustments

1) Base CO2 concentration is 4%. For 10% CO2 the total Gas Treatment unit costincreases from 12% of total to about 16%, and utilities increase from 27% to30%.

2) Fractionation cost is based on no LPG extraction. To extract propane and butaneproducts, increase fractionation cost by 10% (from 5% to 5.5%) and add $100-150 per cubic meter of storage (double metal wall, single containment) or $200-300 per cubic meter for full containment storage (concrete outer wall). The costsper cubic meter are for the storage tanks only and do not include any additionalmarine facilities, fire protection, etc.

3) Utilities are based on gas turbine drivers and hot oil for process heat.

4) LNG storage costs are based on 200,000 cubic meters of full containment storage(the storage tanks are subcontracted, and most of the cost is in the constructioncategory). A single containment storage facility can be approximated by reducingthe construction figure from 15% to 11% for the storage and loading area.

5) Construction costs are based on US Gulf coast labor rates and productivities. Thiscategory includes design/supply/erect subcontracts, supply/erect subcontracts,direct hire erection, field staff, and indirect support facilities.

PROCESS TECHNOLOGIES

The main process technologies in an LNG plant are the gas treating and liquefactiontechnologies. The gas treating processes are highly dependent on feedstock composition andare further discussed below. Liquefaction processes (i.e. cascade, mixed refrigerant, orprecooled mixed refrigerant) represent a large portion of the total facility cost, as shown inTable 1. However the difference in cost from one technology to another is usually not a majorissue when considering the overall project cost.

Table 2 shows liquefaction unit equipment cost breakdown in more detail, includingrefrigeration services, for a propane precooled process (the trends will be similar for othertypes of processes). This table indicates that the major equipment costs are found in therefrigeration machinery and heat exchangers. The refrigeration machinery costs are mainly inthe drivers, which are completely independent of the selected process; a Frame 7 gas turbineis the same whether it is driving a single MR or cascade process.

The heat exchanger types and costs, on the other hand, do depend on the process yet thedependence is not dramatic. The exchangers make up about 36% of the total liquefaction unitequipment cost, and the liquefaction unit equipment cost is 14% of the total plant cost.Therefore the maximum impact on overall cost the exchangers can have is about 14% x 36%= 5%, and even this difference would require the exchangers for one process to have zerocost which is highly unlikely. While there are differences in installation costs between differentexchanger types, the impact of exchanger installation on overall cost remains low.

7.3–6

Table 2. Liquefaction Unit Equipment Cost Breakdown

Item % of Total Equipment Cost

Refrig. Machinery 58

Refrig. Aftercooling/Condensing &Subcooling Exchangers

10

Chilling and Liquefaction Exchangers 26

Drums, Columns & Misc 6

Total 100

The process technology selection thus tends to be based on equipment and other factorsin addition to cost. Such factors include:

• Safety — At some sites the quantities of hydrocarbon liquid inventories may be a factor.

• Plant Availability — Availability is the number of days per year the plant operates.Availability is a function of planned maintenance downtime in addition to the unscheduledshutdowns. The planned maintenance downtime in a gas turbine driven plant is usuallycontrolled by gas turbine maintenance. Unscheduled downtime (or loss of production) iscaused by unforeseen difficulties such as heat exchanger leaks, flow maldistribution,machinery trips, amine foaming, utility outage, and liquid carryover.

• Maintainability — Ease of maintenance can be impacted by heat exchanger type andinsulation systems (i.e. polyurethane foam, foam glass, or perlite).

• Operability — Operability is dependent on the stability of the process and machinery, andalso on the complexity and number of the control loops.

• Driver Selection — In addition to the relatively high capital costs, the drivers representa major part of the plant availability and operating costs. Gas turbine scheduled andunscheduled downtime accounts for about 60 % of the total plant downtime. The trendin LNG plants is towards larger gas turbines, but some owners prefer using smaller gasturbines running in a parallel arrangement to improve plant availability.

OFFSHORE LNG PLANTS

There is a growing interest in production of LNG offshore, either in a floating production,storage and offloading (FPSO) facility, on a platform, or on a gravity based structure (GBS).This environment is characterized by expensive real estate and special safety considerations.For offshore plants the following factors in addition to those mentioned above apply:

• Footprint — Processes with smaller footprints are directionally easier to lay out on anoffshore facility.

• Safety — As with onshore facilities, the size and location of hydrocarbon liquidinventories must be considered. Consequences of leaks relative to the accommodationarea is also an important part of the safety evaluation.

7.3–7

• Marine motions — Consider the ability of the process and equipment to handle motionson floating facilities. Special designs may be necessary to achieve high availability.

• Flaring — Another factor in marine facilities is the difficulty of flaring. Processes andequipment which result in low flare rates are easier to handle in marine environments. Toreduce flare rates, one possible practice is to increase design pressures on the criticalcircuits to reduce or eliminate the operating case scenarios. High integrity pressureprotection systems have also been applied in offshore production facilities.

FEEDSTOCK COMPOSITION

The main cost drivers in the feed gas composition are acid gases (CO2 and H2S). Highamounts of CO2 in the feed gas result in large acid gas removal units and larger utility dutiesfor heat and cooling. Selecting the optimum process is the best way to reduce acid gasremoval costs. The selection process must account for feed gas contaminants such asmercaptans, methanol, corrosion inhibitors, etc., while minimizing utility usage and capitalcosts.

In many cases amine units such as MDEA, MEA, Sulfinol or hot potassium carbonate arethe most cost effective choices. Where CO2 concentrations are on the order of 15% orhigher, unconventional processes such as membranes or cryogenic separation may beconsidered. When considering membranes, feed gas pretreatment upstream of the membranesto remove contaminants must be part of the evaluation. In one recent evaluation the feed gaspretreatment cost approached the cost of the membranes.

The LNG product specification typically limits H2S concentration to about 4 ppmv, andtotal sulfur to about 25 ppmv. If high sulfur concentrations are present in the LNG plantfeedstock then the acid gas removal unit must also remove the sulfur components. In thisregard, mercaptans usually cause special problems; the acid gas removal process often doesnot remove the mercaptans completely and the drier mol sieve following acid gas removalfinishes the task of mercaptan removal. Sulfinol is one solvent, however, which is capable ofremoving mercaptans to sufficiently low levels and thus has been selected at some high sulfurfeed gas sites.

Another cost reduction concept is to remove mercaptans with a cryogenic processfollowed by mol sieve treating [1]. The advantage of this method is that the stream treatedwith mol sieves is a small LPG stream instead of the entire LNG train feedstock. This methoduses the scrub column separation step to wash down mercaptans in addition to the usualheavy hydrocarbons. The mercaptans then go overhead in the fractionation unit deethanizer,depropanizer, and debutanizer columns where they can be combined into a single small streamfor convenient treatment.

7.3–8

NUMBER AND CAPACITY OF LNG TRAINS

The trend in LNG plants towards larger train sizes continues as a way to save costs byincreasing economy of scale, as indicated in Figure 2. Trains capable of 3.3 MMTPA arecurrently being constructed and train sizes in the 4.5-5.0 MMTPA range are beingproposed.[2].

LNG Train Time Line

0.00

1.00

2.00

3.0019

63

1970

1973

1978

1982

1984

1989

1994

1996

1999

Year

Tra

in C

apac

ity

(MM

TP

A)

Figure 2

Train size is limited by proven equipment sizes and manufacturer capabilities, but withina single train it is still possible to have parallel units where required and obtain the overalleconomy of scale benefits. Parallel units within one train can also serve the purpose ofproviding increased reliability in a single train plant.

Another concept which can reduce plant life cycle cost is to treat the refrigeration systemsas utilities. Increasing the size of the main refrigeration drivers improves economy of scale,but one disadvantage is the amount of scheduled downtime required for maintenance. To getaround this the plant can have spare refrigeration compressors tied into each LNG train, withthe spares located to minimize the cost of the large diameter piping runs.

A related concept is to use very large (such as Frame 9) gas turbine generators for powergeneration, and use electric motors for the refrigeration compressor drivers [3,4]. Thisconcept improves plant availability because motors rarely need maintenance and the powergeneration configuration provides enough sparing to enable gas turbine maintenance to bedone without interrupting LNG production. The improved plant availability may justify theadded cost of the power distribution required. Also, if a given site is located where electricpower is in demand the plant can sell exported power to improve economics.

Some projects have a market which demands increased LNG deliveries some years afterinitial production. In such cases the contractor can minimize the life cycle cost by minimizingpreinvestment, that is, spending only what would be needed to satisfy the initial demand andthen expanding the capacity later. This can be accomplished by building an additional train ata later date or debottlenecking the original process units. This has the effect of delayingexpenditures for more capacity until they are needed; the process units may have a small

7.3–9

amount of preinvestment for the higher capacity, but the utility systems (which are normallyseveral parallel units anyway) can have the required additional units purchased and installedin the future.

Another concept along the same lines is to build a train for a lower initial capacity that iseasily expanded to a higher capacity at a later date. One way this is accomplished is bydelaying portions of the heat rejection equipment (e.g., propane condensers) purchases untilthe higher process efficiency is required. The compressor head required during the lowcapacity operation is therefore higher than during high capacity operation, and despite lowerthroughput the power required is about the same as high capacity operation. Thus the processconditions change between the high and low capacity cases, but the compressors are designedto operate under both sets of conditions. Depending on the capacity differences somecompressors may require new rotors and diaphragms, but the casing size is not changed. Acapacity increase of about 30% (from 3.5 to 4.5 MMTPA) is possible using this concept.

DESIGN MARGINS

Design margins are normally provided to positively prove the plant is producing therequired quantity of LNG. A contractor uses margins to cater for uncertainties related totechnical data and performance measurement. These uncertainties are real, and a plantdesigned without the margins may face the prospect of unresolved questions on whether thedesired LNG quantity is being produced. However, excessive margins and margins on top ofmargins are to be avoided. Thus early in the project development phase it is important for thecontractor and owner to agree upon and minimize the design margins to minimize the plantcost while still meeting the overall project objectives.

The contractor should be allowed a measurement tolerance margin in order to be able toassign responsibility if the plant performance is not as predicted. The process licensor,equipment manufacturers, and contractor will be unable to resolve who is at fault if plantperformance is short but all system components are within measurement tolerances ofrequired performance. The design margin for power is normally obtained by applying deratingfactors to the gas turbine drivers. Some of the derating factors are real and do not count asmargins, others can be considered as design margins which decline over time:

Fixed Factors

• Site Humidity and Altitude• Inlet/Outlet Pressure Drop Losses• Compressor Power Margin (API)

Variable Factors

• Air Compressor Fouling• Ageing (Non-recoverable losses)

7.3–10

The compressor power margin is usually based on the API 617 standard of 4%. Howeverthe compressor manufacturer can also be told to guarantee power with a zero positivetolerance. Since the manufacturers are able to predict power better than 4%, in a competitivebidding situation the zero tolerance criteria will usually provide a 1-2% margin of comfort forthe plant owner to make delivery guarantees. The air compressor fouling is a derating factor,and although it is shown as a variable factor the fouling occurs so quickly that the factorcould be considered as a constant 2% derating instead of the average of a varying0-4%.

The ageing factor is normally taken to be 4%, which is actually an average. Ageing occursrapidly during the first year and then slows as the major turnaround is approached after sixyears of operation. Even after the major turnaround the ageing loss is not completelyrecovered; continuous operation at high temperature causes the casing to become oval, andthe wider clearances which result reduce the power output. An operator should expect torecover only half of the ageing loss unless the entire casing is replaced.

Some plant owners are able to reduce the cost of the plant by sharing the ageing derationwith the contractor. The contractor is allowed to use the margin to pass the performance test,yet the guaranteed plant LNG production is based on aged gas turbine performance. Thus the4% ageing margin on power enables the contractor to save costs by avoiding margins onother equipment such as exchangers.

SITE SELECTION

Site selection has a major impact on overall plant cost, and generally involves striking thebest balance between several competing factors. Factors to be considered are soil conditions,contour and topography, marine bathymetry, water supply, existing infrastructure, anddistance from the natural gas source to the plant. The ideal site would have:

• stable soil conditions

• flat topography but with a steep drop offshore for minimum jetty length

• abundant fresh water supply

• existing roads and construction dock capable of handling equipment on the order of 300-500 tons

• a location close to the gas supply

The site containing all of these desirable features at one location probably does not exist.In a typical site selection exercise the contractor evaluates several possible sites, puttingestimated costs against each of the parameters above and minimizing the life cycle cost.

PLANT LAYOUT

Plant layout is an important aspect of cost, schedule and accessibility. Keeping the pipingruns short reduces the amount of straight run piping and supports, but if plot is reduced toomuch then more fittings are required. More fittings tend to increase piping costs and the tightspaces resulting from short pipe runs reduce accessibility for maintenance. Thus the

7.3–11

contractor must optimize the plot keeping in mind safety, maintenance, and low cost. Besidesreducing footprint, other layout related cost savings are possible:

• Run pipeways first, not pipes; straight pipe is not expensive but fittings and valves are

• Keep equipment as close to the pipe rack as possible to avoid additional structuralsupports

• Try to keep nozzles on the pipe rack side of equipment to simplify piping access

• Use low level pipe racks where possible to save costs

• Consider using precast concrete structural supports

DESIGN PRACTICES AND ENGINEERING SPECIFICATIONS

Design practices and engineering specifications impact every aspect of the plant, and thusrepresent an opportunity for significant cost savings. Cost saving exercises often focus onequipment because the potential cost savings in equipment are relatively easy to identify.However, just as important are the cost savings related to bulk materials. After all, asindicated in Table 1, within the process trains the bulk materials have a cost similar to theequipment. No single item is likely to save a large percentage of costs, but taken togethermany small savings can add up to a sizable total.

Attached to this paper, Table A-1 is a listing of previously published cost saving concepts[5-14]. A successful contractor will have a database of these concepts and more to beproposed in the right situation. The cost savings concepts presented in Table A-1 are onlysome of those that are possible, and the list encompasses both design practices andengineering specifications.

One example from Table A-1 is cryogenic valve specifications. Both ethylene plants andLNG plants have valves in cryogenic service, but the LNG plant valve specifications aretypically much more stringent. In past LNG plants the valve specifications have requiredradiography and cryogenic testing where the valve holds helium pressure while submergedin a liquid nitrogen bath. Furthermore, the LNG service valve casings were also radiographed.The ethylene plant valves on the other hand are basically off the shelf stainless steel valves.

The facilities required for performing such tests tends to limit the number of vendorswhich are able to bid on cryogenic valves, thus the cost of testing and the limited vendorsboth tend to increase the cost. A recent comparison of 4”-300# RF gate valves made of 304SS indicates that the ethylene plant valve was $1280 while the LNG plant valve was $2600(exclusive of testing which would be done on only one of the purchased 4"-300# RF gatevalves). Before changing LNG plant cryogenic valve specifications however, a survey of theethylene industry’s experience with the less stringent valves would be in order.

Also attached at the end of this paper is Table A-2, which summarizes key projectdecisions related to standards and specifications. The owner requirements with regard to thestandards and specifications for the design, procurement and construction of an LNG projecthave a large impact on the plant cost. Because of the large quantities of expensive materials

7.3–12

involved, small increases in technical requirements result in significant additions to theinstalled cost.

At the start of an LNG project a comprehensive document is prepared to provide adetailed definition of the design and operation of the plant, including requirements imposedon the safety, quality, operability and reliability of the plant. This document essentially fixesthe plant cost, for EPC contractors who receive this document for lump sum bidding of theEPC phase can only influence plant cost via efficiencies in execution technology and risktolerance. These influences are small compared to the influence of project specifications onplant cost. Thus preparing and completely understanding the cost impact of a well thoughtout project specification document is imperative. Cost differences between LNG projects builtto date can clearly be attributed to specification differences, market differences and sitespecific differences with the latter two being essentially out of the owner's control.

Project specifications are usually dictated by the owner technical specialists andengineering departments. Typically, owner technical specifications are the product of manyyears of evolution, covering multiple types of processes and plants. These "generic"specifications may contain requirements in excess of accepted minimum internationalstandards. Given the large quantity of expensive equipment and bulk materials in an LNGplant, even small “excesses” in technical specifications can have a significant cost impact.

This underscores the need in an LNG project to critically examine the technicalspecifications that are to be applied. It must be emphasized that these “excesses” may bejustified and the resultant increase in capital costs accepted by the owner based on hisemphasis on ease of operation, safety, risk aversion and the like. The issue is not one oftrimming specifications but one of understanding all the consequences of the specificationsand accepting the resultant capital cost.

MAJOR PROCESS DRIVER SELECTIONS

The cost of the main process drivers per unit of power is important, but even moreimportant is annual LNG production. LNG plants are generally designed to the limit of themain process drivers, thus the process driver selected has a major influence on the ultimatecapacity of the plant. Because of the large fixed costs in LNG plants such as LNG storage andmarine facilities which are independent of LNG production within a certain range, increasingLNG production improves overall economics. Thus if one driver selection makes more LNGthan another, the selection making more LNG will have better economics, assuming that thereserves and market can support the additional production.

Table 3 is a summary of published gas turbine data for several GE models. The industrialFrame 5, 6, and 7 are currently used in LNG service. The Frame 9 and aero-derivative LM-2500+ and LM-6000 have yet to be used in LNG service.

With respect to availability, it may be preferable to use parallel smaller drivers instead ofa large single driver to maintain high availability. With the large single driver LNG productionis halted completely while the driver is maintained, but with multiple smaller drivers theproduction continues at a reduced rate. Thus the facility as a whole is more fully utilized withthe smaller drivers even though the total driver cost is higher. This concept is especially

7.3–13

applicable in a single train facility, where there is no opportunity to stagger maintenancecycles between two trains.

SCHEDULE

Considering the time value of money and the amount of resources required for baseloadLNG plants, reducing schedule is a worthwhile effort. Delaying a $2 billion expenditure onemonth at an interest rate of 10% is worth about $16 MM, thus there is clearly incentive toreduce schedule or at least delay expenditures as much as possible for items off the criticalpath. Possibilities for reducing schedule are as follows:

• Use single containment LNG storage instead of double or full containment

Table 3. GE Gas Turbine Data

Frame 5M5382C

Frame 6M6511B(PG-6551B)

Frame 7M7121EA

Frame 9PG9171E

LM2500PE LM6000P

ISOPowerRating(kW)

28,340 37,800(39,160)

88,200 123,400 22,800 44,090

Cost(US$/kWFOB)

151 155 131 182 212 207

Numberof Shafts

2 1 1 1 2 2

Footprint(sq.meter)

51 53 73 100 14 11

Mass (kg) 116,800 138,300 165,600 267,000 30,000 40,000

• Limit shop testing of compressors (full load string testing on one string only)

• Design structural steel and piping such that long lead equipment can be installed after thebulk materials are in place (all nozzles on pipe rack side, for example).

• Use modularized piping and insulation systems

7.3–14

RISK MANAGEMENT

Cost savings and technical innovations go hand in hand. The challenge when applying newtechnology is to achieve the expected cost savings despite a lack of proven experience or alimited track record. This outcome is possible using risk management techniques, where thetrue amount of risk is determined and active steps are taken to obtain a successful outcome.

The usual risk management program usually begins by identifying prototype/unprovenequipment proposed for the project. If the project is sufficiently innovative, appointing a riskmanager on a full time basis is warranted. In LNG plants where the stakes are especially high,even one or two new developments justify special attention to risk.

The risk manager, with input from engineering and construction groups, determines areasof high risk. Below are some examples of factors leading to high risk in technology andexecution:

· Site located where soil conditions are highly variable

· Climate makes heavy construction difficult (snow, mud, etc.)

· Process conditions are outside of proven or tested technical data correlations

· Process stream physical properties are outside of proven processing experience (forexample, near-critical pressures make vapor and liquid densities closer than previousexperience and increase the risk of successful vapor-liquid separation).

· Feedstock to the plant is not well sampled and highly variable

· Equipment type is in service for the first time (a recent example is cryogenic liquidexpanders)

· Equipment capacity or physical size is larger than previously installed

Once the above factors are identified the next step is to plot a course of action tominimize the risk. Such actions may include:

• Perform more sampling of soil conditions and/or feed gas.

• Initiate laboratory tests of technical and physical data.

• Test equipment in shop at new conditions.

• Perform surveys of owners taking similar risks to determine if those owners have madeany design or operating improvements (for the liquid/vapor density ratio example above,find out what devices might have been used in a similar service, and the degree of successusing the given device).

• Complete extra computer analyses using tools such as dynamic simulations andcomputational fluid dynamics.

Project execution can also be changed to minimize site related risk. If weather and climatemakes construction unpredictable, then modular construction can reduce risk. With modularconstruction the modules are constructed in a shop with controlled conditions, and only thefinal part of the construction effort must be accomplished in the more difficult environment.

7.3–15

The process design can also take high risk factors into account, by selecting processingsteps which are more forgiving. For example, one project may have some gas wells containingsulfur compounds while most of the gas is sulfur free (though carbon dioxide is present). Inthis case there is a risk of receiving gas with sulfur at a future date. An acid gas removalsolvent and molecular sieve combination can be selected which would be capable of removingsulfur if the sulfur later shows up. The purchased equipment would be minimized and selectedto handle only the carbon dioxide but the system would be designed for additional circulationof solvent if required for sulfur removal in the future.

When designing the process around such risks, the engineer must always keep in mind theconsequences if the worst case scenario does occur. By doing so the magnitude of the riskis more clearly defined. In some cases the remedy may be relatively inexpensive, such asadding a drum or internals for better vapor/liquid separation. In other cases the remedy mightbe the expensive installation of more rotating equipment and supporting utilities to replacea primary process driver which does not perform as intended. Identifying the fallback positionfor the worst case scenario enables the contractor to determine the extent of effort needed tomanage the risk.

LNG TERMINAL COST REDUCTION

Reduced costs and shorter engineering and construction schedules are important for LNGreceiving terminals just as they are for the liquefaction facilities. The need to reduce costs andshorten schedules for LNG terminals is increasing as the owners of these facilities shift fromthe large gas and utility companies to independent power producer (IPP) owner/operators.Not only are multiple IPPs competing for the same markets, these producers must evaluatemultiple competing opportunities in different locations and countries. To satisfy these needs,LNG terminal designs and the associated costs must be prepared in a timely manner.

To identify significant potential cost savings, a contractor should breakdown the cost ofan LNG receiving terminal and identify major issues for the given site. To facilitate costestimation and evaluating design options, the terminal has been subdivided into logicalmodules or blocks, such as:

• LNG Storage

• Jetty Head

• Jetty Trestle

• Pipe Yards

• Boil Off Gas Recovery

• LNG Pumping

• LNG Vaporization

• Power Generation

• Utilities

• Safeguarding Facilities

• Building and Infrastructure

• Instrumentation and Electrical

A simplified breakdown by modules is given in Table 4 below for a terminal designedfor 4 MMTPA sendout (6 MMTPA maximum). The terminal has 3 x 90,000 m3 storagecapacity and a jetty approximately 500 meters long.

7.3–16

Table 4. Receiving Terminal Cost Breakdown in Percent of Total Cost

Cost Elements Jetty* LNGStorage*

Sendout Utilities GeneralFacilities

Total

Equipment - - 5.7 3.6 0 -

Bulk Materials - - 3.3 2.4 1.9 -

Construction - - 9.2 6.8 1.9 -

Misc - - 5.3 3.2 0.6 -

Total 11.0 45.1 23.5 16.0 4.4 100

* - Subcontract, breakdown not provided.

The impacts of various options within a module must be discussed with the owners, suchas the contribution of additional land area needed for lower cost single containment tanksversus the cost of full containment tanks that can be sited closer together. Opportunities toimprove economics using cold utilization should also be explored. Cold utilization can beespecially effective when LNG receiving terminals are integrated with power plants.

The use of these building blocks allows for a rapid design and cost estimation, which canbe used to evaluate alternate sites and design options. A clear and thorough understandingof the various options early in the design process will lead to fewer regrets later.

SUMMARY

The contractor must always be looking for ways to turn technical challenges intoopportunities for cost savings. Several cost savings concepts are presented above, and thecontractor should maintain a data base of cost saving ideas - an idea rejected at one site maybe just the answer for another. New technical innovations also reduce costs. The contractormust be innovative in addition to staying abreast of the latest developments in equipment,materials, and project execution. The contractor also plays the important role of evaluatingnew technologies to ensure the new benefits outweigh the risks. The contractor’s ability toperform these functions will be a key part of a growing LNG industry made more attractiveby lower costs.

7.3–17

Table A-1Design Practices and Engineering Specification Cost Saving Concepts

Acid Gas Removal

Concept CostImpact

Use plate and frame type of exchangers for lean-rich exchanger service. Low

Use improved gas treating processes such as cryogenic distillation,formulated solvents, mixed solvents, membranes, etc. For natural gases withhigh acid gas content.

Med

Integrate acid gas removal and dehydration steps into a single adsorbent bed.For natural gases with low acid gas content.

High

Use of solvents that can handle high acid gas loading and are energy efficient.For natural gases with low acid gas content.

Med

Use air-cooling for the solvent regenerator overhead condenser, and mountthis air-cooler atop the regenerator column. For natural gases with low acidgas content.

Med

Reduce absorber diameter by using proprietary trays or structured packing. Low

Dehydration & Mercury Removal

Use regenerable mol sieves for dehydration & mercury removal in a commonvessel.

Med

Integrate the heat duty for drier regeneration with gas turbine exhaust. Low

Reduce size of dryer beds by deeper precooling & shorter cycles. Low

Liquefaction

Selection of a liquefaction process that is simpler and/or has fewer pieces ofequipment. Efficiency can be a secondary consideration.

High

Use gas turbines & optimize their selection. High

Use electric motor drives for the major compressors with power supply viagas turbine generators.

Med

Use plate fin exchangers in place of S/T or spool-wound exchangers. Med

Use of innovative heat exchanger designs to improve operation. Low

Use cryogenic liquid expanders. Med

For high pressure feed gases, use turbo expanders to let down pressure. Med

7.3–18

For high pressure feed gases that are acid gas free and have little heavies,reduce refrigeration power by liquefying the natural gas at supercriticalpressure.

Med

For high nitrogen feeds, use a nitrogen column instead of a straight flash. Med

Fractionation

Small refrigeration unit dedicated to the columns only. Low

Import refrigerant for the columns. Low

Storage & Loading

Use larger & fewer tanks. High

Avoid unnecessary LNG storage capacity. High

Selection of tank type (single vs. full containment). High

Use larger & fewer LNG loading pumps. Med

Use a less conservative storage tank boil-off system design. Med

Reduce loading line size. High

Flare the ship loading vapor Low

Combine the flash gas vapor with the boil-off gas compressor. Med

Use pre-stressed concrete wall instead of embankment design for LNG tanks. Med

Utilities & Offsites

Purchase nitrogen instead of on-site generation. Med

Use a slip stream from the gas turbine inlet air compressor for instrument airuse.

Med

Use waste heat from gas turbine exhaust. Low

Reduce the number of spared equipment in power generation. High

Simplify the flare and liquid disposal systems. Med

7.3–19

Project Execution

Improve project execution techniques. High

Relax design standards & specifications. High

Maximize the design & supply scope of vendor items. Med

Develop multifunctional equipment to reduce equipment count & piping. Low-Med

Take steps to minimize rework. Med

Delay the installation/construction of non critical infrastructure items untilafter the plant is completed and operating.

Med

Consider “core in shell” arrangement for propane chillers. Low

Evaluate if suitable for modular construction. Adopt modular engineeringtechniques.

Med-High

Use the latest (client approved) computer tools and document management. Low

Invest heavily in the FEED package so that all major technical & equipmentdecisions are made early in the project.

Med-High

General

Investigate smaller LNG plants for specific projects. Med

Take maximum advantage of economy of scale. Build larger & fewer trains. High

Promote competition in the manufacture of specialized equipment such asspool-wound & printed exchangers, liquid expanders, etc.

Med-High

Promote the development & use of innovative designs and concepts for plant,equipment and materials.

Med-High

Allow more flexibility in LNG sales contracts. Med

Use enhanced vessel internals to reduce diameter of large drums. Low

Consider above ground electrical cabling to reduce costs & facilitate sitepreparation.

Med

To minimize the cost of depressuring consider design for no repressuringwhile cold.

Med

Re-evaluate cryogenic valve specifications. Med

Review fireproofing of structural steel. Med

7.3–20

Consider eliminating spare relief valves and minimizing other valves withinthe operating units.

Med

For S/T exchangers, consider TEMA C instead of TEMA R for someservices.

Low

Use hot oil instead of steam in all heat exchangers. Med

Design common facilities for AGRU, dehydration, and fractionation areas. High

Use magnetic bearings & dry gas seals in compressors. Med

Table A-2Project Specification Philosophies

· Plant life, availability/ reliability requirementsDesign margins — required minimum production rates, operation under extremeweather conditions

· Equipment sparing philosophy especially in the utility area· Source of fire water/configuration of firewater pumps· Spill containment arrangement· RV philosophy, including spares· Philosophy for block valves & control valve bypasses· Choice of gate vs. ball valves· Deluge system philosophy· Flanged vs. welded connections· Details of LNG tank design (type of outer tank, insulation system, foundation system,

hydrotest requirements, tank internals, etc)· Choice of SS vs. 9% Ni for cryogenic vessels· Choice of metallurgy for cryogenic pipes· Instrument philosophy (extent of gas detection, alarms, redundancy, combining major

systems, etc.)· Extent of DCS interface with ship navigation and mooring system· Philosophy regarding Local (field) Instrument Rooms, Analyzer houses and need for

blast resistance· Philosophy regarding Factory Test for major instrument systems· Types of pipe rack: precast concrete vs. steel· Use of elevated structures to reduce plot area· Philosophy/design with regards to bimetallic transition joints· Design requirements for cryogenic pipe supports· Expansion loops vs. bellows· Extent of paving/roads· Trenches/ditches--concrete lined, crushed stones?· Foundation material selection vis à vis soil characteristics· Drainage philosophy· Underground vs. above ground electrical cables· Electrical cable trays: type of design

7.3–21

· Philosophy regarding vendor packages--"customize" to project requirements vs.accept "standard vendor package"

· Extent of vendor documentation, especially for package items· Performance risk—accept standard vendor risk or require more risk to be taken by

vendor· Extent of testing/inspection for equipment and materials· Certification and traceability of materials for critical equipment: are vendor standards

acceptable?· Need for cryogenic design approval test for cryogenic valves· Type of insulation: PUF vs. foamglas· Extent of insulation, insulation thickness and density· Choice of materials for underground pipes· Fire proofing philosophy· Prefabrication vs. field installation of buildings· Philosophy on pneumatic vs. hydrostatic testing· Extent and applicability of local codes/regulations (e.g., noise, emissions, waste

disposal, etc.)· Extent of plant infrastructure (clinic, recreation, canteen, transportation, etc.)· Requirements for "local content" in terms of materials and labor· Restrictions on material sourcing country, vendor qualifications· Risks and liabilities to be imposed on contractors

REFERENCES CITED

1. C. Durr, F. de la Vega, “Method for Removing Mercaptans from LNG”, U.S. PatentNumber 5,659,109

2. V. Perez, W.E. Hauhe, J.A. Freels, K.Davis, C. Durr, “The 4.5 MMTPA LNG Train -A Cost Effective Design”, Twelfth International Conference on Liquefied Natural Gas,1998.

3. M.W. Kellogg Study - “LNG Plant Driver Study”, Sept. 1996.

4. I. Aoki and Y. Kikkawa, “LNG Plant Combined with Power Plant”, Second DohaConference on Natural Gas, 1997.

5. C.A. Durr and R.R. Tarakad, “Modular Engineering in LNG Plant Design”,GASTECH86, 1986.

6. C.A. Durr and F.F. de la Vega, “Cost Reduction in Major LNG Facilities”, 17th WorldGas Conference, 1988

7. R. Klein Nagelvoort and P.J.A. Tijm, “Cost Reductions in LNG Export Facilities”, 14th

World Petroleum Congress, 1994.

8. D.A. Coyle, C.A. Durr, F.F. de la Vega, D.K. Hill and C. Collins, “LNG Plant Designin the 1990's”, GPA Convention, 1995.

7.3–22

9. I. Aoki and Y. Kikkawa, “Technical Efforts Focus on Cutting LNG Plant Costs”, Oil andGas Journal, July 3, 1995.

10. C-H. Chiu and F.W. Richardson, “Project Challenges of a Baseload LNG Plant”,GASTECH93, 1993.

11. J.D.T. Bernard, “Considerations Leading to a No Steam, No Cooling Water, Base LoadLNG Plant”, LNG8, Session II, 1986.

12. R. Klein Nagelvoort and E. Kennedy, “Development and Expansion of LNG and LPGExport Projects”, 19th World Gas Conference, 1994.

13. J. Tarlowski, C. Collins, F.F. de la Vega, “Developments in the Design of LNG ImportTerminals”, GASTECH93, 1993.

14. A.O. Fredheim and R.S. Heiersted, “Possibilities for Cost Reduction in Base-Load LNGPlants”, Eurogas Conference, 1996.

15. P. Tijm, E. Stanton, and R. Klein Nagelvoort, “Liquefied Natural Gas: Reducing Costs”,June 1995.