LNG Production

There are multiple infrastructure pathway options for bringing LNG vehicle fuel to the marketplace. A successful strategy requires prudent selection among these options and will necessitate a time-phased integration of infrastructure pathways to match and accommodate growth in LNG vehicle fuel demand. While each of the options explored below have been used to some extent, the most successful to date (and the option that has provided the most LNG fuel) has been to locate and construct a purpose-built natural gas liquefier that produces LNG for use as a vehicle fuel.

Zeus Intelligence, in collaboration with NGVAmerica, has created an LNG fuel supply database that lists more than 30 LNG supply plants with trailer load-out to support the transportation market. These plants are capable of producing more than 3 million gallons of LNG per day, a number that is expected to increase to meet the growing demand for LNG as a transportation fuel. Follow the link below to access the database.

LNG Feedgas
Prior to liquefaction, all feedgas requires some amount of pretreatment to remove carbon dioxide (CO2), water, concentrations of sulfur compounds, very heavy hydrocarbons, and any other contaminants. Wellhead gas can contain significant amounts of water, nitrogen, and heavier hydrocarbons while pipeline gas, which has had these contaminants removed, contains mercaptans that must be removed before use as a transportation fuel.

Biomethane requires extraordinary conditioning because it contains very high CO2 (typically in the 40 to 60 percent range) and sometimes other compounds that may have destructive effects on natural gas engines or cause toxic exhaust gases. Although the feedgas is inexpensive and biome thane LNG typically has short distribution distances, the cost of natural gas upgrade equipment can be very expensive for low throughput biomethane production plants. Biomethane offers significant greenhouse gas (GHG) benefits, but may not make economic sense as a feedgas for LNG production.

Purpose-Built Pipeline Gas Liquefiers and Peakshaving Liquefiers
Peakshaving liquefiers are similar to purpose-built liquefiers with respect to the basic infrastructure elements, but were built for meeting peak winter home heating demand. Therefore only a small percentage of peakshaving liquefier capacity is available for transportation. The advantage of purpose-built liquefiers is that they can be located in or near areas of high LNG vehicle fuel demand, thereby minimizing the required distribution distances. However, other factors may also influence LNG plant location. For example, it is usually impractical to locate plants in urban areas for reasons associated with land cost, permitting challenges, and not-in-my-backyard attitudes. Niche opportunities to simplify plant requirements and enhance economics also affect the plant location. For example, the 86,000 GPD Applied LNG Technologies (ALT) plant near Topock, Arizona, is co-located with an El Paso interstate pipeline compression station, which minimizes land and feed gas distribution costs while still being near demand centers in Phoenix and Los Angeles. Similarly, the Clean Energy liquefier in Boron, California, is co-located with the U.S. Borax plant, which facilitates resource sharing opportunities (e.g., regeneration gas and heavy hydrocarbons are fed to the U.S. Borax power plant for electricity generation that is sent back to the Clean Energy plant).

Peakshaving plants are operated by natural gas utilities to liquefy and store large quantities of gas for later regasification to meet peak demand requirements. These plants would appear to be an ideal (but limited) source of LNG vehicle fuel because the plant investment has already been made. There are, however, challenges associated with this pathway. Some utilities are reluctant to draw on their stored LNG reserve for reasons other than their primary purpose. Similarly, utility regulatory agencies are cautious about approving such plans and may require partial reimbursement of ratepayers’ original capital investment. Finally, peakshaving plants are not necessarily located near areas of LNG vehicle fuel demand.

Pressure Reduction Liquefiers
The unique pipeline distribution circumstances of high pressure let-down to low pressure gas local utilities distribution lines is an opportunity to utilize an otherwise lost energy source. Installation of turbo-expanders at these locations (e.g., the pipeline city gate) can liquefy a fraction of the natural gas with little or no compression power investment. The primary benefit of a pressure reduction liquefier is the minimization or elimination of compression and compressor drive requirements. This reduces capital costs slightly and O&M costs substantially. Plant emissions are also reduced, and permitting may be more straightforward.

Another subtle advantage of using this type of liquefier at a pipeline pressure reduction location is simplified gas pretreatment because, for example, a small CO2-methane mixture flow can usually be discharged into the downstream low-pressure natural gas pipeline without any environmental or economic consequences.

Pressure reduction turbo-expander peakshaving liquefiers have been built in the past. For example, San Diego Gas & Electric built two liquefiers in Chula Vista, California, which were dismantled in the 1980s. More recently, Idaho National Laboratory (INL) developed a turbo-expander liquefier technology specifically for LNG vehicle fuel product ion at pipeline pressure reduction locations. In cooperation with the Pacific Gas & Electric Company (PG&E), a 10,000 GPD liquefier using this technology was demonstrated in West Sacramento, California. The potential locations for pressure reduction liquefaction facilities are fixed, and there is no flexibility for building them close to LNG demand if there is no available pipeline pressure let-down point nearby. This has the potential of increasing distribution costs. Because pipeline pressure let-down stations are usually owned and operated by local distribution companies (LDCs), this LNG option will generally involve subtle issues associated with LDCs’ roles as LNG transportation fuel marketers and applicable regulatory agency policies.

The production capacity of this type of liquefier is limited by the gas flow rate and pressure ratio at available pipeline pressure let-down locations. So, although the O&M costs of pressure reduction turbo-expander liquefiers are minimal, the LNG capital cost per gallon increases as capacity decreases.

Because the volume of LNG that can be produced is relatively small, pressure reduction liquefiers can be used to supply the initial demand for LNG as a vehicle fuel and support peak demands in a later, more developed market, but they will not be able sustain large LNG demand.

Nitrogen Rejection Units and Gas Separation Plants
Nitrogen rejection units (NRU) reduce the nitrogen content of natural gas produced from wells so that it meets pipeline composition specifications. Gas separation plants (GSP), also called natural gas liquids plants or gas stripping facilities, separate ethane, propane, butane, and heavier hydrocarbons from natural gas in order to market these gases and/or increase methane content so that natural gas meets pipeline specifications. NRUs and GSPs usually employ cryogenic separation processes that can be modified to co-produce LNG vehicle fuel. In addition to the relatively minor gas processing equipment modifications needed to co-produce LNG, NRUs and GSPs usually also require installation of LNG storage tanks and tank-truck loading facilities.

NRUs that have co-produced LNG include:

  • Shute Creek, Wyoming plant can produce 66,000 GPD of over 97 percent methane LNG
  • Painter, Wyoming plant can produce 35,000 GPD of over 98 percent methane LNG
  • Santana, Kansas plant which can produce 10,000 GPD of over 97 percent methane LNG

While LNG can be co-produced very economically at NRUs and GSPs (because feedgas is relatively inexpensive and most of the equipment expense can be considered a “sunk cost”), these sources have two major drawbacks. First, they are not located near areas where LNG is currently in high demand. As a result, distribution distances and associated costs are substantial. Second, the quantities of LNG that can be economically co-produced are limited because the plants were originally designed with mass and energy balances optimized for other purposes. However, these facilities can be used to meet nascent LNG demand in the near term and to provide peakshaving for spikes in LNG demand in the longer term.

Biomethane to LNG
LNG produced from biomethane, including landfill gas (LFG) and digester gas, has the greatest potential for significant full fuel cycle GHG emission reductions compared to almost all other conventional and alternative fuels. In addition to providing GHG benefits, there is very high public interest in this pathway (e.g., refuse trucks fueled by the refuse they collect), and substantial government funding is available for biomethane projects. Many high flow-rate biomethane sources, such as large landfills, are already being used for other purposes, including electric power generation. All biomethane sources have high concentrations of CO2(for example, LFG is typically 50 percent CO2), water, sulfur compounds, and inert gases.They sometimes also contain trace amounts of highly problematic components, such as siloxanes, halogenated compounds, and toxics. These issues combine to create the two biggest challenges for biomethane-to-LNG: plants must be small (i.e., on the order of 10,000 GPD LNG) to match available biomethane sources, and the required gas pretreatment systems are expensive. Although the pretreatment and liquefaction equipment is significantly more expensive than that for pipeline gas liquefaction plants, the feedgas cost is much less expensive, or even zero.

The Altamont plant, built by a Linde and Waste Management joint venture at the Altamont landfill east of the San Francisco Bay Area, is perhaps the most successful LFG-to-LNG project to date. While the $15.5 million cost of this 13,000 GPD project is relatively expensive on a cost per capacity basis, $2 million of funding was provided by government agencies.

Onsite Small-Scale Liquefiers
In this pathway, a small-scale liquefier is co-located with an LNG fueling station. The feed gas may come from an LDC or other source and is not limited by supplier. The pathway eliminates the need for distribution from the liquefaction facility to the fueling station, and this infrastructure model resembles that of CNG. The small-scale liquefier can be built to meet local demand and does not require a large, sustained demand to stay in operation. However, there is a subtle tradeoff involving the optimum liquefier throughput and the production schedule vs. LNG storage capacity required to support a given station (analogous to the CNG station compressor vs. cascade size tradeoff). Another advantage of this pathway is that it eliminates the need for one of the two LNG storage tanks needed by most other LNG infrastructure options.

The main drawback of the onsite small-scale liquefaction option is the relatively high cost of small gas upgrade systems. This cost is exacerbated by the fact that LDC-distributed pipeline gas is odorized, and the sulfur containing mercaptan odorants must be removed prior to liquefaction.

Another challenge is the station capacity flexibility. While liquefier size will initially match demand, the small-scale liquefier will not be able to match any increases in demand, and additional capacity will need to be built or distributed to the fueling station. The capital cost of small-scale liquefiers is less than that of purpose-built liquefaction facilities that accommodate much larger LNG demand, but they have a higher cost per LNG gallon. However, there have been recent small-scale liquefier technology advances, which were motivated by applications ranging from LNG transportation fuel production to LNG cargo ship boil-off gas re-liquefaction.

In onsite small-scale liquefaction, because there is no distribution cost, feedgas price is the most important cost driver. Another consideration in overall LNG cost is that onsite liquefaction shares the LNG storage cost with the fueling station, therefore reducing the overall capital and per-gallon LNG cost. There are additional operating costs, especially if liquid nitrogen is necessary for an external nitrogen liquefaction loop.

To learn more about LNG safety, please review our LNG Safety Q&A Reference document.

*Permission was granted to use material in this section from American Natural Gas Alliance (ANGA). Content is derived from ANGA-commissioned report published by TIAX – “U.S. & Canadian Natural Gas Vehicle Market Analysis: Liquefied Natural Gas Infrastructure.”