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Natural gas needs to be liquefied at an LNG plant in order to be shipped. This explains how this key link in the LNG value chain works.
The process described in the following is a generalization of the different links in a typical LNG value chain, deviations from this specifically described process occur.
Essentially, the LNG value chain can be divided into four main steps: natural gas production and exploration, liquefaction and storage, shipping, and finally, receiving, regasification and distribution. Production and exploration include extracting raw, unprocessed natural gas from reservoirs, rough on-site processing, and bringing the gas from the site of extraction to a treatment facility, often nearby. When brought to the treatment facility or liquefaction plant, hereafter referred to as an LNG plant, the gas is processed and treated through the gas liquefaction cycle, before getting stored and prepared for transport. Due to capacity and LNG technology like refrigerants and coolers, LNG is most commonly transported using designated LNG carriers, transferring large quantities of LNG by sea. LNG loading takes place at the exporting site and is then shipped to an onshore receiving terminal or an offshore unit with receiving capabilities. It is then heated for purposes of regasification and prepared for distribution to a gas network, where it can be utilized as fuel for instance for power generation.
This will focus on the second link in the chain, namely the process taking place at the LNG plant before shipment.
The LNG plant makes out the “black box” of LNG production where completely or partially untreated, raw natural gas in a gaseous state comes in, and refined LNG is shipped out. In general, two main processes take place at the plant: the gas treatment process and the liquefaction process. If natural gas is sold in gaseous state, liquefaction facilities are not necessary. This typically applies to areas with access to a pipeline network. However, when gas markets and gas fields are far apart, production costs are sufficiently low, and marine ports where a plant can be built is relatively close to the gas field, conditions facilitate LNG production.
LNG plant sites can be potentially massive in size and make out an expensive part of an LNG project. Production capacity and plant size vary, but key infrastructure in addition to the specific gas treatment and liquefaction equipment include equipment for handling boil-off gas (BOG) like venting, flaring or re-liquefaction, send-out-systems, and cryogenic storage tanks. The individual systems are often closely integrated. The plant also requires infrastructure for LNG loading to ships, which in case either a jetty or the jetty less transfer system can be used.
LNG plants are most commonly placed onshore, but for offshore gas fields, production, treatment, liquefaction, storage and transportation can take place using floating liquefied natural gas (FLNG) facilities.
The well stream of plant feed comes in gaseous form by pipe. Natural gas extracted from the ground contains impurities, water and other associated fluids, so before liquefaction can take place, the gas needs to go through a treatment process to remove undesired substances. The gas goes through a series of vessels, compressors, and pipes where gas is stepwise separated from heavier fluids and impurities.
First, water and condensate are removed, followed by removal of acid gas (carbon dioxide, Co₂), hydrogen sulfide (HS2) and mercury (Hg). These substances are unwanted, as they may cause ice forming during liquefaction and corrosion in pipelines and LNG heat exchangers. The remaining mix is precooled, and other, heavier, natural gas liquids are then separated from the mix before liquefaction takes place. Removed hydrocarbons can be stored and sold separately. The remaining gas mostly consists of methane and some ethane, which is brought to liquefaction.
Transporting compressed gas long distances by pipe can be costly and time consuming, but by cooling natural gas to -162°C, it turns into liquid matter, and its volume decreases by 600 times. This makes it possible to transport the gas by ship, and this process is made possible at the LNG plant. The liquefaction and LNG cooling process are based on thermodynamic refrigeration cycles, and takes place in cryogenic heat exchangers, which absorbs heat from the natural gas. Flash gas and BOG can be used as fuel for turbines used for onsite power generation.
We mainly separate between two main types of liquefaction processes: the classical cascade process where different refrigerants which vaporize at different temperatures are used, and the mixed refrigerant cycle where a continuous, single blend of refrigerants is cooled. Either way, the end product is LNG, which is stored in cryogenic tanks on site before being shipped off.
Shipping LNG overseas is by far the most common way to transport natural gas in liquid form. When LNG plants and fields are situated in remote areas, transportation of LNG by ship is often the preferred, or perhaps even the only, alternative for transporting natural gas. Therefore, LNG ships makes a key link in the LNG value chain, enabling transportation of gas between the liquefaction plant and regasification site.
Shipping LPG overseas is by far the most common way to transport natural gas in liquid form. When LPG plants and fields are situated in remote areas, transportation of LPG by ship is often the preferred, or perhaps even the only, alternative for transporting natural gas. Therefore, LPG ships makes a key link in the LPG value chain, enabling transportation of gas between the liquefaction plant and regasification site and/or Loading ISO Tank Containers Depot.
For transport over large distances or when pipelines for natural gas are not available, the gas can be transported as liquified natural gas (LNG). Natural gas is commonly transported and stored in liquid state because its volume is decreased about 600 times compared to at gaseous state. By cooling the gas down to approximately -162°C, the gas condensates and becomes liquid. Regasification is the process of converting the gas back to gaseous state by heating the liquified gas.
To use the LNG as fuel, power generation, for heating, cooking etc., the LNG must be converted back to gaseous state. Typically, this process takes place at large import terminals where LNG carriers discharge their LNG cargo. At these terminals, the gas is stored at liquid state in tanks, and regasified before it is transferred as natural gas to the end user through a pipeline gas network. Alternatively, the LNG can be transported further by truck, rail or smaller ships and regasified closer to the consumers.
A regasification plant can use a heat exchanger with sea water as heat medium to increase the heat of the natural gas to change it from liquid to gaseous state. Air vaporizers can also be used where several large fans that push air through heat exchangers to vaporize the LNG. In periods of high demand, regasification might also be accelerated using underwater burners running on natural gas.
Traditionally, gas would be transferred from the LNG carrier in liquid form to the LNG terminal where the regasification would take place using onshore regasification technology, but floating solutions are becoming increasingly common today. In the following, some of these terminal technologies will be described.
At an import terminal with onshore regasification, LNG is received from an LNG carrier and is stored in large onshore tanks and regasified at the import terminal. Alternatively, a floating storage unit (FSU) can be used to store the LNG before regasification onshore. Another solution is to connect an FSU to a regas module placed on the jetty next to the berth. At onshore regasification terminals, air vaporizers and submerged combustion vaporizers have been the most common technologies.
Onshore regasification terminals are sometimes placed in the proximity of power plants or industrial plants so that they can exchange heat to vaporize the LNG with cooling energy for the plants to increase the total efficiency.
A floating storage and regasification unit (FSRU) is a floating terminal with storage and regasification facilities. These units can either be specifically designed for the purpose of storing and regasifying LNG or be modified LNG carriers.
Instead of using one single floating installation, the FSRU, for both storing and regasifying LNG, it is possible to separate these actions and perform them in two separate units. The two components are the floating storage unit (FSU) and the floating regasification unit (FRU), which in total perform the same task as the FSRU. Pipelines or hoses which transfers LNG and excess BOG make out the interface between the two units. This solution can be cheaper than utilizing an FSRU and make a good fit for areas with calm waters.
Building an onshore regasification terminal is a large, long-term investment which requires certainty of continuous supply of LNG. An FSRU on the other hand can be time chartered, moving capital expense to operational expense. Conversion of old LNG carriers to FSRUs also allow for short lead times. However, restrictions on FSRUs include capacity limitations and lifespan, where it in many cases will be surpassed by an onshore regasification terminal.
Due to its relatively reasonable price and short time from FID to utilization, the FSRU is becoming increasingly popular, and is predicted to play an important role in conjunction with future LNG technology.
An LNG jetty is a construction projecting pipelines from an onshore terminal out over water. It often consists of piles, a trestle, pipelines, access road, loading arms, and breasting and mooring dolphins. The process of designing and constructing a jetty can be time consuming, costly, and requires intervention in both onshore and marine environments. A jetty serves as a connection that enables transfer of LNG between a berthed ship and the onshore terminal. Depending on local conditions, the length of the jetty may vary from just tens of meters to several kilometers. A jetty can be combined with different terminal configurations, such as floating storage regasificationunits (FSRU), floating storage units (FSU), floating regasification units (FRU) and onshore terminals, which all commonly utilize a jetty to transfer LNG or gas to shore.
Piling is the process of setting deep foundations into the seabed. These deep foundations support the jetty topside. An LNG jetty needs to withstand rough conditions, which is why the piles needs to be driven through sand and sediments, deep into the seabed.
The topside of a jetty is the part of the structure which lies above water that is supported by the piles. The topside typically consists of a trestle with gas pipelines, serving as the connection between the onshore facilities and the jetty head. The jetty head holds the loading arms for loading or discharging LNG to and from the LNG carrier. It also comprises berthing and mooring dolphins used to moor the LNG carrier.
Breasting and mooring dolphins
Dolphins are marine constructions that extends above water level. They are used to extend the birth of the ship by providing extra mooring points. Together with the jetty trestle and the jetty head, the dolphins typically make a T-shape. Breasting dolphins serve to take up some of the berthing loads and as mooring points to restrict motion in the longitudinal direction of the vessel. Mooring dolphins are used for mooring lines only, often to restrict the transverse movement of the berthing vessel. These dolphins are usually connected by walkways for easier mooring line handling.
Pipelines for transferring LNG are placed on the jetty with associated valves, loading arms and safety systems. Loading arms works as the interface between the pipelines and the LNG carrier and connects to the carrier manifold with the pipelines to shore. Emergency release couplings (ERC) are fitted at the end of the arm towards the vessel manifold and serves to separate the jetty pipelines safely from the vessel in case of an emergency.
Dredging is a process utilized in shallow waters to improve accessibility for ships. To avoid running aground, ships require a certain water depth depending on the draught of the ship and the loading condition. LNG carriers typically have a draught of 10 to 15 meters, which sets the standard for the depth of LNG jetties. Tides and waves must also be considered, and a safety margin is always added. If the waters outside the LNG terminal are too shallow, dredging is done to excavate materials from the sea floor beneath the ship berth and in the approach area. A dredger is a floating plant that picks up the sediments and debris from the bottom and removes it mechanically or by suction.
Not only can LNG plants- and regasification facilities be costly, but a jetty alone will require a substantial initial capital expenditure (CAPEX). Operating costs (OPEX) include work hours spent on personnel operating the jetty during LNG transfer, and numerous tugboats needed to position the LNG carrier correctly and securely.
Carrying out a jetty project is time consuming, potentially ranging from 2 to 5 years in duration. Preliminary work related to the project include activities such as feasibility studies, environmental impact assessment, getting governmental approval, and reaching investment decisions. Once this is in place, the actual construction work on the jetty can start, including necessary dredging and LNG pipeline and equipment production, in addition to any necessary ship fixing or FSRU conversion.
In most cases, dredging is a necessity for the feasibility of LNG transfer from ship to shore. However, due to concern for local wildlife and ecosystems, it is preferable that both dredging and environmental intervention in general is limited to a minimum. A jetty could potentially be of massive dimensions, which again will require vast interventions in both on- and offshore environments. Several jetty projects have proven themselves to be damaging to local environments, as seen in e.g. the Gorgon gas project in Australia.
A jettyless transfer system serves as an innovative solution to the above mentioned implications of a jetty. Read more about jettyless LNG compared to traditional LNG jetty here.
Knowledge of the economics of the LNG value chain is key to effectively manage financial risk in LNG projects. LNG is now so cheap that incentives for fuel-switching are no longer on the critical line to secure future adoption of natural gas from coal and oil. Nevertheless, adequate allocation of volumes and the establishment of associated agreements between suppliers, buyers and other relevant stakeholders needs to be configured in a manner favouring natural gas in the long run.
In order to understand the economics of the LNG Value chain, and the opportunities ahead, we first need to revisit the different links; natural gas production and exploration, liquefaction and storage, shipping, and receiving, regasification and distributei, we will go into further detail regarding the economic factors of the value chain and project development process, and identify sources of financial risk in LNG projects. To start off, let’s take a look at the composition of the LNG value chain again.
The chain starts off with the exploration and production of natural gas, and includes extracting unprocessed natural gas from gas reserves, rough on-site processing, and bringing the gas from the site of extraction to a processing facility. Here the feed-gas is first cleaned from impurities and liquids to reach certain specifications. It is then sent to a liquefaction plant for pre-cooling and liquefaction, and finally stored and prepared for transportation. The LNG is most commonly transported in large quantities by designated ships called LNG carriers. LNG loading takes place at the exporting site before the gas is shipped to an onshore receiving terminal or an offshore unit with receiving capabilities. It is then regasified and prepared for distribution to a gas network, where it can be utilized for e.g. power generation.
In some projects, an integrated company is responsible for multiple links in the chain, most commonly upstream production and liquefaction. In the integrated commercial structure the revenues come from the ability to conduct the whole upstream process from production to liquefaction, in a profitable manner. Moreover, if a company only owns the liquefaction plant, it can source natural gas from one or several producers, and profit from the price margins between the natural gas and final LNG product sold to customers. This is the merchant commercial structure. A third one is the tolling commercial structure, which is common in the US. In this structure the liquefier does not claim ownership to either the natural gas or LNG, but simply gets a fee for the liquefaction services.
The same three commercial structures also apply for in the case of import terminals. The integrated company can integrate further forwards in the supply chain to include the export terminal in addition to the upstream production and liquefaction assets. The merchant structure is practically the same as for the export terminal, but reversed, meaning that the owner of the import terminal buys LNG and sells natural gas. The tolling structure is also similar, but with liquefaction services switched out with services such as offloading, storage and regasification.
Evidently, the LNG value chain can be both technically and commercially complex, and no value chain is exactly identical to the next one. To ensure that the project provides value to all it’s participants each link in the chain must perform its obligations and operations, as the failure of one link may greatly affect other important links in the value chain. Compliance between the different stakeholders in a project is facilitated from the very beginning of the project development process, where the cost drivers and potential issues for a specific LNG value chain is identified.
The time frame from initial idea and feasibility studies, to construction and completion can be as much as ten years. Hence, for the development to be executed successfully a suitable project structure must be established. Where various risks and rewards are anticipated and adequately distributed between the participants to align all stakeholders interests. This is crucial for the project to attract customers and investors and secure sales contracts and capital. Not to mention keeping all parties satisfied through the entire lifetime of a project, which can vary from 20-40 years for a liquefaction project. Import facilities, both the traditional land based ones and FSRUs are cheaper than the liquefaction projects, but needs similar considerations of long time perspectives and cooperation between multiple partners.
It is common to divide the progression of a project under development into different phases, where the pre- and post-FID (Final Investment Decision) phases are the most general ones. Reaching FID requires three work streams to function in parallel, namely the commercial, technical and financial work stream. The necessary contracts and agreements are established in the commercial, while the technical works team includes technical feasibility and selection of a suitable engineering, procurement and construction (EPC) contractor. The simultaneous progression of both is key to enable favourable financing terms. The FID itself is a critical point, deciding whether or not a project will go ahead with further development, including the timely and costly construction phase. Before the FID can be made, pre-FID inquiries and activities include:
Post FID-activities include the actual construction work on the project, which potentially takes the longest time and highest costs. For the generalized value chain discussed in this, activities in this phase include the design of pipeline networks from reserve site to liquefaction plant, drilling, deciding on whether to build new or to utilize existing liquefaction and regasification plants, securing LNG carriers and choosing technology for receiving and/or loading LNG from the carriers.
According to a publication from The Oxford Institute for Energy Studies, the cost breakdown by LNG plant area (LNG liquefaction plant) can be estimated as in the figure left side. Pre-operational cost drivers include the range and complexity of the project itself, but marine facilities, including jetties and extensive dredging (CAPEX directly connected to the building of a jetty) are also highlighted as a major cost generating item of budget.
CAPEX for regasification plants typically consists of costs associated with vessel berthing, storage tanks, regasification equipment, send-out pipelines, and metering of new facilities (IGU, 2017). Hence, also this link in the value chain highlights cost drivers connected to the interface between LNG ships and onshore facilities.
Construction costs (CAPEX) accounts for a substantial part of a project investment, but also considering the sum of operational costs (OPEX) across the entire supply chain is key to identify potential sources of financial risk. Combined figures from PwC and a publication from the journal Industrial & Engineering Chemistry Research (I&EC) break down the operating cost for a general value chain as following:
Project economics is a development risk for an LNG project, and should be monitored and managed correctly. Long-lasting contracts have traditionally been the ground layer for financing LNG projects, and high project costs combined with an increasingly dynamic monetary market can largely impact a project’s FID. Post-FID cost-overruns are also a big source of financial risk.
To develop natural gas projects of sufficient scale to defend the costs associated with a liquefaction plant, large upfront capital investments have typically been required. In order to secure payback, the majority of gas volumes are sold to large, credit worthy buyers through long term take-or-pay contracts before first gas. However, new supply coming from the US and Australia has flooded the market. The excess LNG not tied to rigid contracts has been bought by trading houses and portfolio players and allocated to new buyers on the short-term and spot market, often priced based on relative supply and demand of natural gas instead of traditional oil-indexation. This has enabled smaller players to enter the market and utilize the emerging contract flexibility to take on smaller amounts of natural gas on short notice and competitive prices. This solution is highly compatible as a supplement for season and weather dependent renewables such as hydro, solar and wind.
Enabling LNG to smaller, less credit-worthy players has been attempted through various business models, one of them being the hub and spoke model. Where a large scale carrier transports the LNG in large quantities to a centralized hub, where it is further re-distributed to smaller offtakes. Demonstrated as a suitable solution to regions of scattered demand, such as in the Caribbean and Central America, which can benefit from proximity Henry Hub indexed contracts from the US Gold Coast. This allows the utilization of economies of scale through sourcing LNG through conventional suppliers and infrastructure, with the flexibility provided by innovative technology and commercial structures.
As implied earlier, intervening in projects targeting the interface between onshore off/on-loading facilities and ships could be a way to reduce financial risk. As discussed in another post, carrying out a jetty project alone, could take between two to five years. Operating costs (OPEX) include work hours spent on personnel operating the jetty during LNG transfer, and numerous tugboats needed to position the LNG carrier correctly and securely. Also evident is how the FSRUs and FLNGs have moved regasification and liquefaction offshore to avoid large CAPEX, complex permitting processes and sunk costs of onshore terminals. For the same general purpose Canaf Energy has developed a floating jettyless IQuay transfer system serving as a cheaper solution to the corresponding implications of a jetty, further cutting project cost and increasing flexibility of LNG projects. Contributing to the mission of enabling sustainable and cleaner energy solutions to more people, quicker.