Building any multi-billion dollar project requires a well-coordinated plan, aligned project sponsors, and financial backing. Project viability will be scrutinized on a continual basis, sometimes even after the project is completed.
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To develop a liquefaction facility for the 21st century, a few key elements are necessary, including the right location, partners, financial plan, equipment, and people. Moreover, they need to be at the right place at the right time.
The difficult part is defining what is “right” so as to achieve the lowest cost and shortest schedule. “Lowest cost” is the most crucial driving factor. Although life-cycle cost is often cited as a criterion in plant design, it seldom becomes more influential than lowest capital cost. It’s important to know the major contributors to LNG plant cost and why certain elements are necessary. These necessary elements add a corresponding, and unavoidable, cost to any project.
The specific cost of an LNG plant has become a fashionable metric to compare projects against each other. “Dollars (USD) per ton of annual LNG production,” commonly referred to as “dollars per ton” is frequently cited in technical and commercial literature in spite of the fact that location, market, and scope make valid project comparisons difficult.
Due to “economy of scale,” a relative increase in capacity will usually lower specific costs as long as equipment sizes increase proportionally (as opposed to adding one or more modules of equal capacity). In addition, variations in capital cost are strongly affected by:
• Plant location
• Labor cost
• Feed gas composition
• Product specification
Competition among contractors and liquefaction process technologies are often seen as significant factors affecting cost. Technology selection is not as significant an impact as often portrayed in the total project cost, but it does impact plant operation, availability, and efficiency. With equal conditions among participating contractors, the cost impact of contractor competition is limited. Most of the project cost is beyond the influence of designers and contractors and is mainly a function of site- related conditions, project development, and project execution objectives. Capital cost reduction must be balanced with other important objectives, such as safety, reliability, and operation and maintenance practices.
For this paper, a base production rate of 4.5 Mt/a (million tons per year) of LNG is chosen to allow fair comparisons without distortion due to “economy of scale.” In the analysis, this paper addresses only the LNG liquefaction portion of the LNG value chain, as highlighted in Figure 1.
Technical considerations
The primary drivers for the capital cost of an LNG liquefaction facility are site specific in nature. Surprisingly, less than 50% of the LNG plant cost is capacity related. As a result, most of the cost of an LNG liquefaction project is beyond the influence of the design engineer and is a function of site-related conditions, project development and project execution efforts.
Although there is no typical or standard LNG plant, major sections found in most LNG plants include:
• feed gas handling and treating
• liquefaction
• refrigerant
• fractionation
• LNG storage
• marine and LNG loading
• utility and offsite
Even with all these elements, each LNG plant is unique to a specific location and market destination.
By starting with the most basic plant design, site-specific elements will be added to the project to show the impacts on plant-specific cost.
Alternative cost distribution
Instead of evaluating total plant cost by process area, plant cost is presented in five major categories: material-related, location-related, sponsor & contractor, labor, and financing. Defining overall plant cost within these areas allows for cost-sensitivity analysis of project-specific items, and determination of how strongly they influence cost.
Material related cost. includes all tagged equipment and auxiliary material, including bulks — e.g. piping, electrical, structural steel, and concrete. Material costs can vary substantially from historical norms depending on project technical requirements and condition of the materials market during procurement efforts.
Location related cost. Site preparation is not a large component of plant cost, but the cost of site preparation will vary significantly with soil conditions and location. This cost is also dependent on plant size. A separate sensitivity analysis will show cost effects for different degrees of site preparation work. LNG storage tanks are not a strong function of plant production rate, but depend on ship size and loading frequency. Similarly, cost of marine facilities is largely independent of plant capacity and configuration and totally depends on plant location.
Sponsor and contractor cost. covers the owner’s personnel used during project development and items such as legal, permitting, etc. Cost for the owner’s personnel is commonly estimated as 10% of total plant cost. Contractor cost includes engineering, construction management, and other related costs.
Labor cost at the plant location. Commonly identified as a “subcontract” cost. Although this cost includes some material-related items such as paint and insulation, in the main it covers the work-hour cost for erecting the plant.
Financing cost. Includes the interest on equity and debt, as well as operating capital necessary for initial phases of the project until LNG revenues will cover operating costs. It is seldom included in the evaluation of the specific cost metric. Upon review, these financing costs rank on the same level as labor, sponsor/contractor, and equipment costs.
CAPEX versus life-cycle cost
Project stakeholders prefer a low CAPEX and life-cycle cost project. This commercial outcome is the most desirable project goal. However, as CAPEX is the largest single component of life-cycle cost — and to avoid the complications of life-cycle analysis — this paper will only address CAPEX of a project.
KBR has developed a cost analysis model that allows detailed modifications to a project, such as adding equipment, modifying labor cost and efficiency, or adjusting the cost of capital based on risk assessment. Results from this model will be presented for a variety of plant configurations, giving an absolute cost for the referenced areas of expense. Plant costs are reported using a generic metric of currency per annual ton of LNG product, symbolized by “¢/t” and referred to as “currency per ton.” This metric allows easy comparison from one design with known parameters to another with assumed (or known) differences.
Plant configurations
Primary factors that set the plant configuration are:
• Feed gas composition and conditions that establish the gas treating and NGL recovery
• LNG product specifications, which control the severity of NGL recovery and nitrogen rejection
The pictograph in Figure 2 illustrates the elements of feed gas treating that could be required for any LNG project and the corresponding shrinkage of the available feed gas to achieve the targeted LNG capacity. Higher levels of NGL recovery may be driven by the overall product economics: i.e. if the value of LPG exceeds the value of incremental LNG. Although deep NGL recovery improves the revenue stream and life-cycle cost for the project, it increases the metric when evaluating LNG specific cost.
To develop proper cost comparisons for different project configurations, the analysis will keep the following items constant:
• Production rate of 4.5 Mt/a of LNG
• 95% plant availability
• Average ambient temperature of 22ºC.
• Gas turbine drivers and air cooling
Development of base plant
If the feed gas arriving at an LNG plant is within range of the required product specifications, only a core plant is needed, which includes liquefaction and refrigeration. The base plant cost (defined as Plant 1) is determined by the minimum number of equipment items required for such an LNG project. This scenario could be achieved by the presence of an existing upstream LPG recovery plant.
The base plant requires a minimal scope for utilities and offsite facilities. This scope includes LNG storage tanks, jetty with loading equipment, relief systems, fire protection, and storage of imported refrigerant. This scheme could be developed if an LNG plant is adjacent to an industrial complex. Utilities such as electric power, water, effluent treatment, and heating and cooling medium can be obtained from outside the LNG plant boundary limits. This example is represented by Figure 3.
Plant 1 will be incrementally expanded by adding utilities, acid gas treating, fractionation, extensive feed gas treating, and other processes that could be required at various locations. Plant 1 results in a small LNG plant, where imported utilities result in operating cost increases for a minimum capital cost. This scenario can be achieved by upstream feed-gas treating (reflected in feed-gas price) with imported utilities adding to operating expenses instead of capital investment. The plant will increase in size, adding treating and processing units, up to the maximum (Plant 6) required.
Outlining six design cases
Plant 1, illustrated in Figure 3, includes only the process units required for liquefaction. Feed gas arriving at the plant boundary limit is expected to be ready for liquefaction. In this case, all utilities are imported except fire-protection and relief-system equipment integral to safe facility operation. Offsite facilities include only LNG storage and the loading system.
Plant 2 includes all items in Plant 1 plus all utility systems, while Plant 3 includes all items in Plant 2 with the addition of feed-gas treatment units. The treatment systems included in Plant 3 are acid gas removal (AGRU), dehydration, and mercury removal.
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Plant 4 will add a fractionation unit to Plant 3. The presence of a fractionation unit includes additional equipment for LPG storage and loading.
Plant 5 will add extensive feed-gas treating facilities to Plant 4. These facilities include a slug catcher, condensate stabilization, and provision for high CO2 extraction within the AGRU. As a result of the high CO2 extraction, there will be accommodation for CO2 sequestering.
Plant 6 will add a sulfur recovery unit (SRU) to Plant 5 and provide for maximum LPG recovery within the process unit.
Comparing the six cases will highlight the effects of site-specific criteria on the overall project cost. Each case has a different cost per annual ton due to the particular scope required to produce the same amount of LNG. Baseline results for each case are presented in Table 1. The metric is shown as an internally developed “currency per annual ton”, abbreviated as ¢/t. This currency unit allows comparison among designs with known parameters to other locations with assumed (or known) differences.
Changes to an individual cost item, such as site preparation, affect other table cost elements. Therefore, increasing site preparation cost has a greater effect on total cost than the basic change of cost in that row. Sensitivity analysis in the following paragraphs will show the overall effect on total cost as a function of basic changes in scope.
Examining cost elements
Cost of material. As the number of equipment items increases, total cost of material will increase. However, the relative increase in equipment cost over the six configurations rises at a lower proportional rate than expected, since major equipment, such as refrigerant compressors, process drivers, and the main cryogenic heat exchanger (MCHE), are already included in the base configuration. Materials cost includes bulk materials and any other costs related to equipment (e.g. electrical items).
Materials cost. This is a primary concern in the currently active marketplace to build baseload LNG facilities. The proportion of material cost to total plant cost affects comparisons of specific cost among LNG projects, as the material market has outpaced economy of scale benefits over recent years.
Site Preparation. The required plot area will increase as a function of the total equipment count. Therefore, costs for site preparation increase, from Plant 1 through Plant 6, with the incremental scope added to each plant. In Table 1, basic site preparation cost is included in the calculation, which requires some earth movement-type work for each example.
Tanks. Although many plants have used single containment (SC) tanks over the last 40 years, the trend is now toward use of full containment (FC) tanks, which reduce the plot space required for LNG storage, but increase tank cost as much as 70%. In addition to increasing cost, FC tanks require longer construction time, which may have a schedule cost impact. LNG storage tank cost does not vary in a constant capacity analysis, but cost differences could arise due to varying soil and seismic site conditions. For the analysis in this paper, site deviations for LNG storage are not included. As seen in Table 1, LNG tank cost is kept constant for all cases and LPG storage tanks are added to the cost for Plants 4, 5, and 6.
Marine Facilities. In general, LNG liquefaction sites are remotely located with less favorable conditions than those in major population centers. To reach a sea-bed clearance of at least 13.5 m, the jetty head needs to be located far enough offshore or dredging will be required. Some locations may also require a breakwater — i.e. a physical wave barrier — to achieve necessary targets for ship-loading availability. Costs for marine facilities can be significant and totally independent of process configuration and plant capacity, unless a second berth is required to offload a high plant capacity. For the 4.5 Mt/a facility, a 700 m long jetty trestle and breakwater was considered.
The jetty includes two major sections: jetty head and trestle. Construction of the jetty head, consisting of breasting dolphins, mooring dolphins, and gangways, vary little from site to site. Trestle cost is primarily dependent on its length and sub-sea soil conditions, which affect both the structure and LNG loading lines. If the jetty head needs to be moved further offshore, trestle length will increase as well as the overall cost of the marine systems. In some cases, trestle length could extend several kilometers.
Sponsor and Contractor Cost. For present purposes, cost for sponsors is kept at a constant ratio of total plant cost, but could vary for issues such as permitting and legal costs. As each plant requires additional scope, sponsor costs will increase due to added complexity. Contractor cost is a function of scope of work and project location, determined in proportion to the number of equipment items. Contractor cost includes home office services, construction management, construction equipment, and temporary facilities. Business expenses not part of the other categories are included in this section.
Labor Cost. A major contributor to the specific cost metric is cost of labor, which is both plant size and location dependent, and varies significantly based on project location. With labor costs accounting for up to 50% of construction cost, labor impact has to be considered separately from equipment cost. The difference in labor from site to site can be as much as US$50/ton. The cases presented in Table 1 are for a labor rate and productivity factor for an African location.
Financing Cost. The cost of financing, i.e. the interest required for equity and debt during project development, will vary according to the risk and availability of capital for a specific project.
Additional cost contributors
Stick Built Construction vs. Modular Design. Most plants are stick built (constructed piece by piece) unless the availability of labor, cost of traditional construction, or adverse climate conditions favors modular design. Modular design is proposed when stick-built construction is not feasible based on the site conditions and the project execution plan. Modular design allows the manufacture of plant sections at specialized industrial fabrication yards, and is commonly used in the design of topsides for offshore projects. This approach is intended to relocate construction labor and reduce the magnitude of site-specific construction costs. Modular design allows parallel construction paths, but can add schedule risk if module shipping has to occur within a small window of favorable weather conditions. In general, there is no cost advantage to modular design. Commonly, more structural steel and engineering is required than for a stick-built plant, but modular design could mitigate escalating costs anticipated for a challenging or remote location.
Summary
A redefined specific cost, based on a clear understanding of the scope of each project, could be a suitable way to review complex projects in challenging locations. This article demonstrates that the cost for a plant can vary by 100% or more when site specific conditions demand different considerations. As a result, it is clear that no two LNG projects are created equal. n
Acknowledgment
The primary difference between liquified natural gas (LNG) and normal natural gas lies in their physical states and handling properties. LNG is natural gas that has been cooled to around -162 degrees celsius, causing it to condense into a liquid state. This process reduces the volume of natural gas significantly, making it more practical for storage and transportation purposes compared to its gaseous form.
LNG is much denser than normal natural gas, occupying about 1/600th of the volume when in liquid form. Specialised cryogenic tanks and ships are required to store and transport LNG safely due to its extremely low temperature.
In contrast, normal natural gas is predominantly used in its gaseous state for applications such as heating, cooking, and electricity generation. LNG can be converted back into its gaseous form through a process called regasification upon reaching its destination, allowing for versatile use across various industries and sectors.
This transformation and the need for specialised infrastructure differentiate LNG from normal natural gas, enabling efficient long-distance transportation and broader accessibility of natural gas resources.
Liquid natural gas (LNG) has a wide range of industrial applications, and is primarily used for its power as an energy supply for the following scenarios:
Energy production
LNG is used as a fuel for power generation in various industries, including electricity generation plants and industrial facilities that require large amounts of energy.
Transportation
LNG is increasingly being used as a fuel for heavy-duty vehicles, such as trucks, buses, and ships. It offers environmental benefits compared to traditional fuels like diesel, including lower emissions of pollutants and greenhouse gases.
The global demand for liquefied natural gas (LNG) is projected to increase significantly in the coming years, fueled by global energy transition initiatives and substantial industrial shifts from coal to gas, particularly in China. And that's why at Tower, we recognise the importance of this trend, especially within the shipping industry, including industrial marine and cruise sectors, where LNG-powered vessels are advancing. We work closely with customers in these sectors to provide tailored solutions including our range of marine FR coveralls.
Industrial processes
LNG is used fuel for manufacturing diverse items such as electronic devices, fabrics, fertilisers, pharmaceutical products or plastics, among many others.
Heating and cooling
LNG can be used for heating purposes in industrial facilities, for domestic heating and cooling applications, such as in refrigeration and air conditioning systems.
In the workplace, the responsibility for managing health and safety, including the handling of hazardous substances like LNG, is governed by legal frameworks and regulations in the UK. HSE is the lead agency for LNG safety.
The terminal operator has a duty to prepare and test emergency procedures for dealing with the consequences of a major accident. The Local Authority must prepare an emergency plan which details how an emergency relating to a possible major accident in its area will be dealt with. The primary responsibility for ensuring safety lies with the operator of the LNG site.
The HSE assesses safety reports submitted by operators before and during construction of Control of Major Accident Hazards (COMAH) sites. They conduct regular inspections during construction and throughout the site's operational life to ensure ongoing safety.
Given the nature of LNG sites, the HSE collaborates closely with other relevant agencies like the Maritime and Coastguard Agency and Hazardous Substances Authorities to coordinate responses as needed.
However here are the key stakeholders responsible for health and safety in the workplace:
Employers
Employers have the primary legal responsibility for ensuring the health, safety, and welfare of their employees and others who may be affected by their work activities. This includes implementing risk assessments, providing appropriate training and supervision, and maintaining a safe working environment.
Employees
Employees have a legal duty to cooperate with their employer on health and safety matters. They must follow workplace procedures, use safety equipment provided, and report any hazards or concerns to their employer.
Cost savings
LNG can offer cost savings compared to traditional fuels like diesel or coal, especially in regions with abundant natural gas resources. It can be a cost-effective alternative for power generation, transportation, and industrial applications.
Environmental benefits
LNG produces fewer emissions of air pollutants and greenhouse gases compared to coal and oil. It helps reduce environmental impact and supports efforts to combat climate change.
Energy security and reliability
LNG enhances energy security by diversifying fuel sources. It reduces dependency on imported oil and promotes stability in energy supply chains, contributing to reliable energy access.
Transportation and logistics
LNG is versatile for transportation, allowing for efficient movement via ships, trucks, or pipelines. Its flexibility in storage and distribution supports effective energy logistics.
Government incentives
Many governments provide incentives and support for LNG adoption, including tax incentives, subsidies for infrastructure development, and regulatory support. These incentives encourage investment and use of LNG.
Risk mitigation
LNG can offer risk mitigation benefits, particularly in terms of energy supply resilience and stability. Its storage capabilities and diversified sourcing reduce risks associated with disruptions in traditional fuel supplies.
In summary, LNG offers cost savings, and environmental benefits through reduced emissions, enhances energy security and reliability, supports efficient transportation and logistics, attracts government incentives, and provides risk mitigation advantages for energy supply chains. These benefits position LNG as a valuable and strategic energy resource for various industries and applications.
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