Liquefied natural gas is an odorless, colorless, non-toxic, non-corrosive and non-flammable form of methane. As fuels go, it's pretty cool.
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Actually, LNG is colder than Antarctica on winter solstice. Methane is chilled to about minus 260 degrees — a temperature that transforms it from a vapor to a liquid, compressing its volume 600 times to make it more economical to store for later use or to ship long distances from countries endowed with natural gas to those starved for the fuel.
That's the broad story of LNG — a case of Adam Smith capitalism at work.
But in the details, the LNG story is a tale of brilliant physicists, savvy government engineers and entrepreneurial risk takers. LNG's back story includes a Nobel Prize, anxiety about U.S. air defense and a disaster that destroyed part of Cleveland.
LNG touches only a small portion of the world's gas supply, but it's the fastest-growing portion. Since , global demand for LNG has grown 140 percent and now accounts for roughly 10 percent of the methane consumed worldwide. The rest moves to market by pipeline.
Exhibit 2. Source: International Gas Union
LNG is exported from 19 countries, including from one U.S. plant in Nikiski, Alaska.
Since , Norway, Russia, Yemen, Peru, Angola and Equatorial Guinea all have started making LNG, while Qatar, Nigeria, Australia, Oman and Indonesia have expanded production.
Qatar's expansion was an act of sheer audacity. Qatar tripled its LNG production capacity to over 80 million metric tons a year — about 11 billion cubic feet a day — leaping past Malaysia and Indonesia as the world's largest LNG maker. Last year Qatari plants exported almost one-third of the LNG traded across the globe. In the mid-s, with construction under way, Qatari officials thought they'd be selling much of their LNG to the United States. The Lower 48 shale-gas boom blew apart that plan. But last year, as Japan idled nuclear power production after the Fukushima disaster, Qatari exports to Japan soared 56 percent over their level, according to the BP Statistical Review of World Energy. That dulled Qatar's pain of losing the U.S. market.
Meanwhile, more countries are clamoring for LNG to quench their growing energy appetite.
Since , China, Brazil, Chile, Dubai, Kuwait, the Netherlands and even Canada and Mexico all became first-time importers of LNG. They joined the mainstay LNG consumers of Japan, South Korea and Taiwan, according to the International Group of Liquefied Natural Gas Importers.
In all, 25 countries took LNG shipments last year, the gas importers group said.
Exhibit 3 Source: International Gas Union
As the world's demand for LNG grows, more locations are mulling entry into the production game. Export projects in Western Canada , Eastern Africa, Russia and the U.S. Gulf Coast are under consideration.
One other possible contender: Export of LNG made from Alaska North Slope gas. The main North Slope producers — ExxonMobil, ConocoPhillips and BP — jointly are at an early stage of considering such a project.
HOW IT WORKS
Chemical engineers have known for years how to liquefy vaporous methane.
And for decades LNG tankers — essentially massive thermos bottles that keep the gas cold and liquid — have sailed the oceans safely.
Like many great inventions, liquefied natural gas emerged as an industry via a progression of events over many years, responding to both commercial and geopolitical pressures.
A key development was learning methane's "boiling point," a temperature below which methane is a liquid and above which it's a vapor.
Most people likely are familiar with the boiling point of water: 212 degrees. Heat water above that temperature and the liquid becomes a vapor.
Methane's boiling point is about minus 260 degrees. Above that frigid temperature it's a vapor. Below it and you have a liquid.
But liquefying natural gas involves more than superchilling it and maintaining the temperature.
That's because a natural gas stream rising out of the ground contains more than just methane, although methane usually is the main component. The ethane, propane, butane, pentane, carbon dioxide, water and other components each have separate boiling points.
Ethane liquefies at minus 127, propane at minus 44, butane at plus 31 degrees, and so on. Like water at 32 degrees, these gases also have "melting points," a temperature below which they become solid. (Dry ice is nothing more than solid carbon dioxide, whose melting point is minus 109.)
Exhibit 4. Source: International Gas Union
These gases have different boiling and melting points because although they're all hydrocarbons — composed of hydrogen and carbon atoms — the number of atoms differs. The more carbon atoms a molecule contains, the heavier it is. That weight determines the temperatures and pressures that make the gas a vapor or liquid.
Methane has the fewest carbon atoms — one — so it has the coldest boiling point of these gases. If the entire produced natural gas stream were liquefied, some components — such as butane with its four carbon atoms and pentane with its five — would freeze solid before the methane vapors got cold enough to become liquid.
Chilling the entire gas stream to minus 260 to liquefy methane thus could produce a slushy slurry of product that would muck up the machinery. This is why the heavier hydrocarbons mostly are stripped from the gas stream before liquefaction.
THE PROCESS
Here's a quick walk along the LNG value chain:
Step one: Clean the natural gas stream so that mostly methane is being processed. The residual ethane and other components left behind after processing are in quantities too small to matter.
Sometimes this cleansing occurs before the gas reaches the liquefaction plant. More typically cleansing occurs at the plant.
Buyers in Japan and Europe typically like their LNG to be spiked with a little ethane or other carbon-rich gases because their mainstream gas burns hotter than mainstream gas in North America. Ethane, propane, butane, etc., have higher Btu contents than methane and serve as the spiking agents.
Step two: Superchill the methane.
A variety of techniques will liquefy methane. A Pennsylvania company called Air Products licenses the technology that dominates the industry.
Air Products uses several variations on the same process. Essentially, it starts by using propane to precool the methane. Propane is compressed and condensed, then its pressure is eased in steps to provide refrigeration that cools the methane. (Gas warms as it is compressed and then cools as the compression eases. This principle is applied throughout a typical liquefaction process.)
Exhibit 5. Source: Group of Liquefied Natural Gas Importers
Next, the cooled methane enters the main stage, a heat exchanger where the gas comes in contact with a blend of refrigerants that transforms the methane vapor into a liquid. Air conditioners work in a similar way: warm air passes over coiled tubing filled with a cold gas.
A new variation uses nitrogen as a final superchilling refrigerant. This allowed much bigger LNG plants to get built, and it partly explains how Qatar could construct so much capacity in recent years.
A technology that's a distant second in the market to Air Products' is licensed by ConocoPhillips. The company's Nikiski, Alaska, plant as well as plants in Trinidad and Tobago, Egypt, Angola, Equatorial Guinea and one site in Australia use it.
ConocoPhillips routes cleansed methane first into a propane heat exchanger to initially drop the temperature. Ethylene is used to drop the temperature more (you can make ethane colder than propane before it boils into a vapor). Then the gas enters a methane cold box connected to mighty compressors to cool the gas to near a liquid state. A final "flash blast" finishes the job.
Most LNG plants have on site more than one processing unit — called trains. The trains operate independent of each other, running in parallel to liquefy methane. Qatar hosts the world's largest trains — the biggest can handle about 1 billion cubic feet of natural gas per day. Qatar's most massive plant, at the Ras Laffan complex, features two such trains plus four smaller ones that together can process about 5 bcf a day. That's about twice the volume as has been discussed for an LNG plant that could process Alaska North Slope gas. Alaska's Nikiski plant is relatively small, with capacity to handle about 200 million cubic feet a day.
One final point about liquefying methane: About 10 to 15 percent of the gas gets consumed during the process. Much of it to run the plant's turbines, compressors and other machinery.
Step three: Store the LNG until it's shipped to market. Special insulated metal tanks keep the gas liquid. A small fraction will "boil off" — warm into a vapor — and this gas can be reliquefied or used to power the plant.
Storage tank dimensions vary widely, depending on whether the LNG is stored for truck fueling, peak shaving or import-export. The largest storage tanks stand as tall as a 14-story building (about 170 feet tall), are nearly as wide as a football-field length (280 feet in diameter) and can hold up to 200,000 cubic meters of LNG — the equivalent of roughly 4 billion cubic feet of vaporous methane, or about one-15th of daily U.S. gas production last year. In short: They can be big.
Step four: Ship the gas. Special tankers with insulated chambers keep the gas below minus 260. Again, a small volume of liquid methane vaporizes on the trip to market; this gas typically is used to power the ship or is reliquefied.
At the end of , 360 ships comprised the global LNG fleet, according to the International Gas Union . Ships typically get built in tandem with LNG plants and get contracted to sail between the plant and its customers. Just as the capacity to make LNG has skyrocketed in recent years, so has the tanker capacity, growing 150 percent since , the IGU said.
The average tanker capacity is about 3.1 bcf of gas (after the liquid gets converted back into a vapor). South Korea is the big builder of tankers. An average one can cost at least $150 million. The largest tankers were built for the Qatar expansion. They can carry about 5.5 bcf, but the tankers are too big for some LNG receiving ports.
Step five: Convert the liquid back into a vapor, called regasification.
This happens in the LNG destination port. LNG is offloaded into storage tanks. The LNG then is warmed into vapor as needed before entering the local gas pipeline system.
THE CRYOGENICS CRAZE
As an export product, LNG dates back less than 50 years, to .
That year, as Ford rolled out its new sports car, the Mustang, a British shipyard launched the Methane Princess, a tanker that carried the first commercial load of LNG, from a new plant in Algeria to a gas-hungry United Kingdom.
Within a few years, Algeria was sending LNG to France, too, and Libya was exporting it to Italy and Spain. In , a new Phillips and Marathon plant in Nikiski, Alaska, started shipping LNG made of Cook Inlet natural gas to Japan, inaugurating LNG trade to Asia. Japan is the world's top LNG consumer today.
But the true history of LNG dates to 100 years earlier as scientists studied how very low temperatures changed matter, a specialty called cryogenics.
Exhibit 6. Carl von Linde. Credit: de.wikipedia.org
In the s, German engineer Carl von Linde's pioneering work in compressed refrigeration found a ready market among breweries and slaughterhouses. Von Linde's technique for chilling air to extract the oxygen, developed around the turn of the century, also was a transforming moment. Isolating oxygen led to development of a torch that revolutionized metal cutting as well as welding for skyscrapers.
Other scientists and engineers hopped aboard the cryogenics craze.
Ethane for plastics, chlorine for sanitizing sewage, oxygen for hospital patients, nitrogen for cryosurgery are among the thousands of products and uses that trace their origins to chilling gases to isolate their components.
THE GAS THAT WOULDN'T BURN
The birth of liquefied methane stemmed from work that used cryogenics to isolate helium.
Helium is a marvelous gas that has been adapted to many uses today, such as cooling superconducting magnets in medical MRI scanners.
If helium isolation has a Eureka! moment, it arguably is a event in a small flatland town called Dexter, Kan.
A driller hit a "howling gasser" of a well there. Nine million cubic feet of gas spit to the surface each day before the well could be capped. Dreams of riches infused the locals. Ore smelters. Brick and glass plants. Soon they would be wildly prosperous.
To celebrate, the town tossed a huge party, the climax of which was to be lighting the gas jet. After speeches, a bale of burning hay was nudged to the escaping gas to produce a promised "great pillar of flame." But the gas failed to ignite. To everyone's surprise, the burning bale got snuffed instead.
A geologist and a chemistry professor soon teamed to solve the mystery of the gas that wouldn't burn.
They discovered the gas was mostly nitrogen. The amount of methane present wasn't enough to combust given all the non-flammable nitrogen — just as trace quantities of methane in the Earth's air don't burst into flame every time someone lights a cigarette.
They also found "inert residue" present in the Dexter gas. After further analysis, they learned this residue included helium.
This discovery was astonishing. To that time, helium was considered a rare element. But now it seemed helium could be found in an ordinary natural gas stream. As for Dexter, it was located in the planet's great cradle of helium: The natural gas deposits of the U.S. plains.
Exhibit 7. Heike Kamerlingh Onnes. Credit: en.wikipedia.org
The scene then shifted to the lab of Dutch physicist Heike Kamerlingh Onnes. In , he was the first to liquefy helium, chilling helium through a series of stages until getting it to minus 452 degrees, at which point the vaporous helium transformed into liquid helium, reaching its boiling point. It was the coldest temperature ever achieved on Earth. Onnes won the Nobel Prize in Physics five years later for his work.
World War I, with cryogenic isolation, became the great leap forward for helium and led eventually to the liquefaction of methane.
During the war, airships — dirigibles, zeppelins and the like — became an novel innovation of combat . Germans dropped bombs from them. The British hunted U-boats. A downside was hydrogen, the lighter-than-air gas used to float most airships. Hydrogen is spectacularly flammable, as the famous Hindenburg disaster demonstrated
But helium isn't flammable. The U.S. launched a crash research program in , as the country entered World War I, to find cheap ways to extract large volumes of helium from natural gas and stockpile it.
This research led the U.S. Bureau of Mines in to produce the first liquid methane as a byproduct of helium separation.
LNG'S EARLY YEARS
During the ensuing years, techniques for liquefying methane were refined and ideas for storing and transporting LNG were patented.
A public revulsion toward flaring natural gas as a waste product of oil production helped propel the industry. Better ways had to be found to move the gas from where it was produced and not needed to where it could be used. The solutions included long-distance pipelines for domestic transport and, much later, LNG for cross-ocean transport.
By , science and capitalism converged to make commercial use of LNG.
That year the East Ohio Gas Co. built a plant in Cleveland that could process about 4 million cubic feet of gas per day into LNG. The company installed three insulated storage tanks to keep the LNG cold. The gas utility regasified LNG when customer demand peaked during winter.
This "peak shaving" concept is a key function of LNG today, the little publicized cousin of making large quantities of LNG for export. Small peak-shaving liquefaction plants and storage sites exist across the world.
The Cleveland operation ran smoothly for three years, until when the utility installed a fourth storage tank. It was war time, and many metals were in scarce supply for civilian use. The metals on this tank were inferior and failed on Oct. 20, .
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An estimated 1.2 million gallons of LNG spilled, so much that it flowed over the protective dike.
The liquid spread like batter on a griddle. Some dropped into the sewers, which filled with methane vapor as the LNG warmed above methane's boiling point. Gas seeped into basements. Houses blew apart as the gas contacted hot-water heater pilot lights.
The Cleveland catastrophe killed 128 people; 14,000 became homeless.
The LNG industry went dormant, except for a liquefaction plant Dresser Industries built for the Soviet Union in .
HEADED TO SEA
Exhibit 8. Source: BP Statistical Review of World Energy
The idea of water-borne LNG deliveries started to get traction in the mid-s.
A joint venture of Continental Oil Co. (Conoco) and Union Stock and Transit Co., a Chicago stockyards operation, did pivotal work on how this idea could work. The venture's name was Constock, a blend of the partners' names.
Union originally wanted Gulf Coast methane barged as LNG to Chicago for refrigeration at its slaughterhouses. But in the late s, with the United Kingdom, Japan and other countries expressing interest in LNG, the focus turned to trans-ocean shipments.
Constock worked on designing the entire system, from liquefaction to regasification. In , a test shipment of LNG left a new plant near Lake Charles, La., and sailed to a new receiving terminal on Canvey Island, down river from London. The ship — and its LNG cargo — weathered the rough Atlantic well. More test shipments ensued, proving that international trade of LNG could work.
New gas discoveries in Algeria made that country the first mover in LNG exports. The Methane Princess, carrying the world's first commercial load to Canvey Island, was small by today's standards. It could carry up to about 500 million cubic feet of gas (after regasification). The average LNG tanker today is five times larger.
But the Methane Princess proved to be a workhorse through the early years of LNG export. The vessel was finally scrapped in India during the mid-s. Another tanker with the same name sails in the LNG trade today.
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LNG industry says today’s operations are safe
As tragic as the Cleveland disaster was, it did imbue the LNG industry with a culture of safety.
If you’ll give them time, people from the industry will talk endlessly about safety within the entire LNG value chain, from liquefaction to storage, tankers and regasification. These operations are heavily regulated for safety across the world, and industry members will even boast about that regulation and insist that potential hazards are manageable.
To illustrate the concept of safety, visitors to ConocoPhillips’ plant in Nikiski see a series of demonstrations aimed to demystify LNG, including:
A plant manager pours LNG on the floor. Instantly, the gas forms into clear beads then — poof — vaporizes as it warms while absorbing heat from the carpet and air.
The manager dunks graham crackers in LNG then invites guests to eat them. They do so warily, misty vapor wafting from their mouths as they chew. This stunt can be an acutely effective in LNG-leery towns when the people consuming the crackers are children of community leaders and opponents.
The LNG industry does have a strong safety record, marred mainly by the Cleveland disaster, a fire and death at a Maryland import plant in and an explosion that killed 27 people at an Algeria liquefaction plant in .
As an industry website puts it: “LNG is transported many miles as it crosses the ocean, transferred to storage tanks, converted back to natural gas and then sent to market. The LNG industry has spent a considerable amount of time analyzing and assessing the hazards along the way and has either eliminated or developed mitigation techniques to reduce risks. As a result, in more than 50 years of commercial LNG use, no major accidents or safety or security problems have occurred, either in port or at sea.” (The Maryland accident actually was 33 years ago.)
The site stresses that “LNG is not explosive.” But the vapors are flammable — if they comprise 5 to 15 percent of the air and something ignites them. U.S. regulations require safety zones around LNG facilities so that any vapors accidentally released get fully diluted before they reach the property line.
University of Texas researchers concluded that although “LNG operations are industrial activities,” LNG can be safely transported and used if regulators hold the industry to the safety standards and protocols that have developed over time.
By. Bill White
This is part two of a special reporting project. Read part one: Inside the high-dollar race to sell natural gas as low-carbon.
On the airborne approach to South Korea’s capital, in a plane cutting through the clouds over the Yellow Sea, one of the first things that comes into view out the right-side windows is a spit of land, one that’s perfectly rectangular and pocked with two dozen lime-green tanks. Shooting out from the artificial promontory, stretching southwest across the open water for a full two-thirds of a mile, is a thin, L-shaped line of pipes, at the far end of which sits a dock. Lashed to the dock on the day I flew into Incheon, the port city that hosts South Korea’s main airport and abuts the megalopolis of Seoul, was a ship three football fields long. Stamped on its navy-blue hull were three white-block letters: “LNG.”
This is the world’s largest terminal for importing liquefied natural gas, or LNG, a fossil fuel whose top exporter this year is widely expected to be the United States. It also is a lifeline for South Korea, the world’s 14th-largest economy. LNG has been an increasingly important ingredient in the hydrocarbon brew that over the past four decades has fueled most of South Korea’s growth — a historic ascent from a war-ravaged society struggling for survival to an industrial powerhouse that exports some of the world’s most-advanced products, from steel to SUVs, from microchips to ships. For roughly the past half-decade, more and more of that LNG has been American-made. Since February , when the United States exported its first load of LNG, dispatching it from a plant on Sabine Pass in Cameron Parish, Louisiana that’s owned by Houston-based Cheniere Energy, more U.S. LNG has been shipped to South Korea than to any other spot on the globe. And the largest share of the U.S. LNG that South Korea imports is unloaded in Incheon.
The Incheon LNG terminal drains an LNG tanker approximately every other day in summer and about every 36 hours in winter, when the temperature drops and Korea’s energy consumption rises. KOGAS, the government-controlled company that owns it and four other LNG-import terminals along the South Korean coast, has hired 30 LNG tankers under multiyear contracts to ferry in the fuel from around the world. Here and back they go, over and over again, their hulls loaded on the voyage to South Korea and empty but for dregs on the return leg to pick up more. Six of those ships do nothing but ferry LNG to South Korea from Sabine Pass. Once one docks at this terminal, its cargo takes about 16 hours to drain from the ship. The typical tanker from Sabine Pass contains enough fuel to meet South Korea’s total demand for LNG for about 24 hours in the summer and about 10 hours in the winter. It is, on an almost unimaginable scale, the definition of plug and play, with a crucial middle step: burn.
For many countries, including South Korea, transitioning from coal, the highest-carbon fossil fuel, to natural gas, which emits about half as much carbon as coal when it’s burned to generate electricity, is key to slashing greenhouse-gas emissions to “net zero” by midcentury, the target scientists say is necessary to avoid the worst consequences of climate change. As a percentage of global energy, indeed, coal use is declining; renewable energy is increasing, though from a much smaller base; and natural-gas consumption remains on the rise. But for natural gas to help rather than hurt the planet, its own carbon footprint will have to be zeroed out.
That footprint includes emissions both of carbon dioxide, which is released when natural gas is burned, and of methane, which is natural gas’s main component and makes its way into the atmosphere when natural gas is released directly into the air, often through gas-system leaks. Methane is, pound for pound, some 80 times more dangerous to the atmosphere than carbon dioxide for the first 20 years after it wafts skyward, making methane a crucial target for near-term climate action. Natural gas’s footprint, moreover, encompasses the entire supply chain — all the way from production (in, say, Louisiana) through consumption (in, say, South Korea).
If current policies and market trends continue, the International Energy Agency projects, the portion of combustion-related global greenhouse-gas emissions that come from natural gas will rise, to 24% in from 21% in . The use of LNG is expected to grow far faster, with half the increase through coming from the U.S. Humanity won’t stanch global warming if it doesn’t decarbonize the U.S. LNG that, even allowing for the steady growth of renewable energy, it seems certain to burn for many years to come.
Last year, Cheniere, the biggest U.S. LNG exporter, began providing KOGAS and Cheniere’s other customers a “cargo-emissions tag” for each LNG load Cheniere sells — a chit the exporter says quantifies the load’s carbon footprint. One purpose, Cheniere’s CEO has told investors, is to inform each buyer about how many carbon “offsets” — separate instruments sold with the promise that they have financed emission-cutting projects somewhere else — the Cheniere customer would need to buy to zero out the atmospheric damage embedded in its LNG purchase.
Questions loom about the environmental validity of Cheniere’s carbon tags and of a host of other efforts by the U.S. LNG industry to quantify and reduce the carbon footprint of the natural gas it sells. But even if those initiatives’ metrics are accurate, they will address only the smaller side of natural gas’s environmental ledger: production. The other side — consumption — is, according to myriad studies, far more damaging to the climate. Just as driving the average car over its lifetime produces more greenhouse gas than does manufacturing the car, burning natural gas to produce power or products typically emits more carbon than does producing and liquefying that gas.
An August peer-reviewed scientific paper whose research Cheniere funded underscored the planetary damage caused by the consumption of Cheniere’s product. In the case of Cheniere LNG that was shipped to and burned to produce power in China — the only country whose gas consumption the paper analyzed — 31% of greenhouse-gas emissions from the entire LNG process came from producing the LNG in the U.S. and shipping it to China; 69% of total emissions came from transporting it within China and burning it there. Credibly decarbonizing natural gas would require mitigating emissions on both sides of that ledger and of the ocean: not just at the wells, processing plants and liquefaction terminals in the countries that export LNG, but also at the import terminals, distribution pipelines and power plants in countries such as South Korea that buy and burn the gas.
Curbing climate change is, at its core, about transforming massive systems — huge agglomerations of infrastructure, which operate for decades and so lock in high or low emission paths. Decarbonizing the rapidly expanding international natural-gas system is emerging as one of the most monumental tasks. Much of the world is starting to wrestle with it — from rich countries such as the United States and Germany to emerging markets and developing economies, notably those in Southeast Asia, where emissions are rising the fastest and the global climate fight will, in large measure, be won or lost.
South Korea — the world’s ninth-largest greenhouse-gas emitter, right above Canada — is particularly reliant on natural gas, and it has resolved to curb the planetary damage its hydrocarbon habit is wreaking. Though the country aspires to get most of its energy from renewables by midcentury, it will, by necessity, continue for decades to burn mammoth quantities of natural gas.
As a first step toward decarbonization, South Korea is trying to wring emissions reductions from its current fossil-fueled system. In addition to converting coal-fired power generation to gas, that means fixing or replacing inefficient LNG tankers and leaky gas pipelines. It’s a pricey process, a symphony of small shifts. But those pushes won’t be enough to catapult the South Korean economy down the path to net zero. So the country is betting big on two technological transformations, neither of which has yet achieved scale. One is to grab and bury gargantuan quantities of carbon emissions, including from natural-gas combustion — a process known as “carbon capture and storage,” or CCS. The other is to ramp up a new and potentially cleaner mainstay fuel: hydrogen.
The stakes of this revolution are huge, and the fights over it are growing. South Korea’s new president, Yoon Suk Yeol, who took office last year, has dialed back aggressive renewable-energy targets rolled out in by his predecessor, Moon Jae-in, saying the Moon shot was unrealistic and was wasting money. A consortium of South Korean companies has inked an agreement with Petronas, the Malaysian oil company, to explore the possibility of shipping South Korean carbon emissions to Malaysia to be buried there, but the deal remains prospective. Shiny machines to convert natural gas to hydrogen are popping up in small projects across the South Korean peninsula, but a hydrogen rollout at a scale that could meaningfully curb the country’s power-plant and industrial emissions remains a gauzy vision. If one place on the planet epitomizes both the imperative to decarbonize LNG and the difficulty of doing so, South Korea is it.
Out on the KOGAS pier, Cheniere’s carbon tags mattered not at all. When I mentioned them to Yang Jaehoon, a wiry, affable man who, as the KOGAS terminal’s dockmaster, is responsible for the safe unloading of the gargantuan ships, he looked at me quizzically and told me he had “never heard” of such things. One of his colleagues, Lee Jaehoon, a bespectacled KOGAS veteran who earned a master’s degree from Penn State and spent years working in KOGAS’ LNG operation before shifting in early to the company’s now strategically important hydrogen arm, knew of the Cheniere chits. But he said KOGAS doesn’t currently consider them — and certainly isn’t buying offsets to try to negate emissions from the production of the LNG it imports. With natural-gas prices soaring, KOGAS and other Korean LNG buyers these days “are not concerned about carbon” from that part of the LNG chain, he told me. “The priority is to secure the LNG.”
That isn’t to say South Korea — the world’s third-largest LNG consumer, behind only its neighbors, China and Japan — doesn’t have big plans to decarbonize its LNG-reliant economy. Like many other nations, including the United States, it has pledged to slash its greenhouse-gas emissions to “achieve the goal of carbon neutrality” by .
That would be a daunting challenge for any nation, but it presents an especially herculean lift for South Korea, which ranks 28th among nations in population but seventh in energy use. The country, with slightly less land than Kentucky, has nearly 52 million residents, close to one-third more people than California. Its summers are muggy, its winters frigid and its living standards high. It is surrounded on three sides by ocean and on the fourth by North Korea, a nuclear-armed enemy, intensifying its imperative for a secure energy supply. It gets 38% of its total energy from oil, 25% from coal and 19% from LNG — basically all of which it imports from abroad. By far its biggest domestic energy source is nuclear power, which provides 12% of the country’s total energy and is intensely controversial among South Koreans. Though South Korea has ambitious plans for expanding renewables, which currently provide just 7% of its energy, the country has little open space for, and lots of public opposition to, solar and wind power. What South Korea does have, in spades, is grit and skill. Which is why it has built a thriving economy by burning ship after ship of imported hydrocarbons to make things that it sells throughout the world.
Since late , when South Korea’s government declared its goal of carbon-neutrality by , it has published a series of plans for meeting that long-term objective, as well as intermediate emissions-reduction targets for . Important details continue to be hotly debated, but, according to the latest plans, the country aims by to “dramatically phase down,” and perhaps shutter, all its coal-fired power production; to drastically increase renewable energy, so that renewables directly supply 60% or more of electricity; and to use hydrogen to deliver nearly one-fourth of all the energy the country consumes. To spur such a hydrogen revolution, the government is moving toward offering a range of incentives.
It’s a grand vision. Today, according to government figures, the portion of South Korea’s energy that comes from hydrogen rounds to zero. And even if the hydrogen dream took shape, South Korea would depend on LNG for years to come. For one thing, the country’s latest power-generation plan, which runs through , projects that LNG that year will provide 21% of South Korea’s electricity, about the same percentage it projects renewable energy will provide after a dramatic ramp-up. In other words, South Korea is assuming that any hydrogen shift would take a decade or more to gain real steam. For another thing, South Korea’s plans note that much of the hydrogen the country hopes to use in coming decades would itself come from LNG.
Hydrogen is a potent energy carrier — which is why the Hindenburg, an airship buoyed by hydrogen, famously caught fire in . But hydrogen exists on its own within Earth’s atmosphere only in minuscule amounts. Today it is produced, or “cracked,” mostly from natural gas and largely for use in petrochemical and other chemical production.
The South Korean government has issued what it heralds as its “first master plan” to transform the country into a hydrogen economy. The plan, released in November , anticipates that some, and perhaps quite a lot, of the hydrogen South Korea aspires to consume over the next quarter century still will come from natural gas — but that much of it will be paired with carbon capture to keep the resulting carbon out of the sky. Starting in the s, the plan envisions, some unspecified portion of South Korea’s total hydrogen consumption would be cracked from water, in a carbon-free process powered largely by the wind and the sun. Either way, most of the hydrogen South Korea burned — 82% of it in , the master plan projects — would be produced oceans away, in countries with a lot of space to bury carbon dioxide, or to erect large wind and solar projects, or both. If all went well with this halcyon vision, the atmosphere wouldn’t be the only beneficiary. The shift also would benefit South Korean industry, which wants to exploit hydrogen the way it has exploited oil and LNG: by deploying its ships and its energy-trading know-how to profit from yet another new foreign-energy market.
That’s the plan, anyway. I got a sobering look at the present when I visited Yeongheung Island, a well-known fishing spot in the Yellow Sea that’s home to quaint seafood restaurants, coves with gorgeous ocean views, and one of South Korea’s largest coal-burning power plants. The island sits only about 10 miles southwest of the Incheon LNG terminal, across the open water. But driving there requires traversing a network of causeways, a trek that takes about an hour. According to a brass plaque in a pagoda on a hill overlooking the Yeongheung power plant, the plant site was chosen in the early s by the then-chief executive of Korea Electric Power Corp., the government-owned electricity company better known as KEPCO, when he flew overhead in a helicopter and decided the island would be a perfect place to burn mountains of coal. KEPCO later birthed subsidiaries including Korea South-East Power Co., which owns the plant.
On its west side, the Yeongheung plant has three Yellow Sea berths for ships bringing in black rock; on the afternoon I visited, the berths were occupied by vessels that had brought coal from Australia, Canada and Russia. Immediately inland of the docks squatted massive outdoor piles of coal separated by provenance, and thus by calorific value. Surrounding the piles stood the plant’s six coal-burning units. Each was housed in a 300-foot-tall, white-metal-clad building. Beside the cluster rose four 600-foot-tall smokestacks, painted with cheery stripes of pink or blue. The oldest unit began operating in , the newest in . Together, Yeongheung’s six units cranked out 32 gigawatt-hours of electricity in , an amount equal to roughly three-quarters of the electricity that all of South Korea’s solar, wind and other non-hydro renewables projects together generated that year. Indeed, South-East Power says this coal-fired plant alone generates 23% of all the juice consumed by the Seoul metropolitan area, home to half of South Korea’s people.
Yeongheung is a microcosm of the country’s energy woes at a time when climate change is upending long-held economic assumptions. In , South Korea’s government announced its intent to phase down the burning of coal as part of its plan to reach carbon-neutrality by . As a result, two of Yeongheung’s coal-burning units now are slated for shutdown in . Also in , in a badly timed coincidence, a long-planned $350 million construction project began at Yeongheung to fit the plant’s two oldest units with new equipment to reduce their smog-causing emissions, a project that had been designed to help significantly extend the plant’s life.
Today, those two units are out of commission, their sides punched with massive construction holes. And Yeongheung is the subject of a fight. Environmental activists and the Incheon city government have asked the national government to close those two units even earlier, in . Yet Hong Youngjin, who oversees the current pollution-reduction project at Yeognheung for Korea South-East Power, told me that, with an additional upgrade, those units could run to or later, allowing them to produce more electricity for the country and more revenue for the company. The power company intends to replace the plant’s older coal-burning units in with units that burn gas, shipped in as LNG.
Hong showed me around the place late in the afternoon. As we stood in the fading light overlooking the plant from the hilltop pagoda, he was fatalistic. Ultimately, the plant “maybe should be shut down,” he said. Twenty years from now, “maybe gas turbines should be occupying this site.” But then he posited that even a shift to gas probably wouldn’t suffice for the planet. “Some people say the gas turbine is a ‘bridge,’” Hong said. “But we have to cross the bridge.” He has plenty of years left to work, and he told me he’d like to transition from his job in coal to one in wind power. “That’s my market, I think.”
One evening, I took a high-speed train from Seoul down to Ulsan, and then a taxi to a Hyundai-owned hotel that sits across the street from the shipyard gate. The next morning, I met with Min Junki, head of the shipyard’s technical-planning department. Sporting a company-issued gray jacket with his name in yellow lettering by his right lapel, he was all business, which made sense. Thanks in large part to the booming global LNG trade, the Hyundai shipyard is turning away customers; anyone placing an order today for an LNG tanker, which typically costs around $250 million, won’t get it for nearly four years. On an exceedingly quick drive through the shipyard — Min not only wouldn’t let me snap pictures, but he rejected my pleas that the driver of our Hyundai SUV slow down so I could get a better look — we saw perhaps a half-dozen LNG tankers in various stages of construction. Workers in hard hats and bright-yellow vests biked around the bustling yard, which occupies 2.2 square miles and employs some 30,000 people.
In the lobby of the Hyundai hotel, Min talked me through ways to curb carbon emissions from LNG ships. One option, he said, is to run the ship’s engines not on heavy oil fuel, the conventional, higher-emitting ship fuel, but on “boil-off gas” — natural gas that, during the voyage, wafts up as the LNG being transported in the ship’s tanks heats up. All Hyundai LNG tankers, like most such ships sold today, come with “dual-fuel” engines, which can run either on heavy fuel oil or on gas from the ship’s supply of LNG; Hyundai estimates that burning natural gas rather than fuel oil can cut carbon emissions on a voyage by as much as 25%. Then there are special energy-saving features customers can choose. Some of those add-ons reduce drag; they include a more sleekly shaped rudder and a contraption that reduces resistance while the ship is moving by whooshing air along the underside of its hull. (“It’s optional, but most owners select it,” Min said of the “air-lubrication system,” which Hyundai estimates curbs energy consumption by 4% to 5%.)
Among the most ambitious carbon-cutting measures is one Hyundai is still working on: a device to capture methane that escapes, unburned, from engines running on LNG. Traditionally on ships, this “methane slip” simply shoots skyward, exacerbating climate change. “Methane slip is a very big problem for us,” Min said. The device Hyundai is developing aims to capture methane before it slips out — and then to burn it, augmenting the ship’s power and emitting carbon dioxide, which is less damaging to the atmosphere than methane. If Hyundai can commercialize it, Min said, the methane-slip equipment might one day cut the greenhouse-gas emissions from a Hyundai LNG tanker by as much as 20% or 30%. “But it depends on the development of the technology,” which the company won’t have ready to sell for at least two or three years.
A quicker way to curb carbon emissions from LNG tankers than waiting for new ships is to change the way those already on the water operate. But that’s easier said than done, as I learned from another outgrowth of the Hyundai industrial powerhouse, Hyundai LNG Shipping. It operates a fleet of LNG tankers that includes the Peacepia, the ship that, when I visited the Incheon LNG terminal, had just arrived from Sabine Pass with its tanks full of Cheniere LNG. Chung Wooram, who helps schedule Hyundai’s LNG-tanker routes, told me when I met with him in the company’s Seoul office that the trip from Sabine Pass to South Korea takes about 28 days, “if all goes very well.” We were speaking in a cavernous conference room, one of its walls dominated by a backlit map of the world that displayed the company’s LNG-shipping routes in dotted blue lines. “But normally,” Chung said, “that’s impossible.”
The culprit is the Panama Canal. On the wall map, the canal shortens considerably the long blue line that traces the route from Sabine Pass to South Korea. In real life, though, canal traffic can hold up ships for anywhere from a few days up to a couple of weeks. Occasionally, when the wait at the canal is very bad, a Hyundai-line ship ferrying Sabine Pass LNG will take a different route from Sabine Pass, heading east across the Gulf of Mexico, down through the Atlantic, around the southern tip of Africa, and up to South Korea. That adds some 10 days to the trip, burning fuel all the while.
Today, the added carbon emissions of idling at the canal or of chugging around South Africa are “never considered,” Chung told me. But that’s about to change. Carbon-emission rules from the International Maritime Organization, a United Nations body that regulates ship safety and pollution, take effect this year. The new regulations will give each voyage a rating from A to E based on what the IMO calls a “carbon-intensity indicator,” a ratio of the fuel the trip consumed to the amount of cargo it moved. Those responsible for ships that get particularly low ratings will have to submit improvement plans, says the IMO, which is also urging ports and regulators to provide incentives for ships that get good ratings. Hyundai LNG Shipping, said Ahn Sehoon, a Hyundai LNG Shipping project manager, will “have to manage well to keep a good grade.”
Because they were built less than a decade ago, meaning they’re relatively young as tankers go, the Peacepia and a second Hyundai-line tanker contracted by KOGAS to transport Sabine Pass LNG have dual-fuel engines, so they’re comparatively energy-efficient. But most of the Hyundai-line tankers that KOGAS has contracted — older ships that import LNG to South Korea from closer locales, such as Qatar, Oman, Malaysia, Indonesia and Australia — run on an earlier type of engine called a steam turbine. Those are much less efficient. Under the new IMO rules, Ahn told me, they will have to be run at markedly lower speeds to minimize their emissions — not at their designed speed of about 19.5 knots per hour, but at more like 15 or 16 knots per hour, a slowdown that will significantly lengthen their LNG-delivery times. Moreover, after , the IMO’s carbon rules are expected to tighten further. At that point, Ahn said, continuing to operate the steam-turbine tankers may prove wholly uneconomic, and even the newer Sabine Pass tankers, speculated Chung, Ahn’s colleague, may need physical retrofits to pass muster.
After cleaning up the ships that bring in LNG, South Korea’s next tranche of chances to curb LNG emissions is to minimize leaks in the equipment that reheats the gas and in the pipelines that transport it. KOGAS’ Incheon terminal heats — or, in industry parlance, “regasifies” — the LNG with two types of warmers. One, used in the summer, runs the LNG through pipes surrounded by seawater, which at that time of year is warm enough to coax the LNG back into a gaseous state. The other, used in the winter, when the seawater is colder, burns natural gas to heat water to warm the LNG. As I was being shown the machinery, I asked KOGAS’ Lee Jaehoon whether the facility used special cameras, of the sort increasingly employed by companies in the LNG-production process in the United States, to detect methane leaks from KOGAS’ gas-handling equipment. He was surprised and intrigued. “There is such an instrument? Interesting,” he said. “I will talk to our headquarters to determine whether it’s applicable to our future terminals.”
Nor is such advanced leak-finding technology employed on South Korea’s gas pipelines. To be sure, KOGAS, as well as companies around the country that receive natural gas from the main national pipeline and distribute it through smaller local pipes, say they routinely check their pipes for damage. And KOGAS has gas-leak alarms at its processing facilities for fire prevention, Lee noted. But it doesn’t regularly check its plants or pipelines for leaks using methane-detecting cameras, he said.
A far bigger climate problem for South Korea than pipeline leaks is the carbon pollution from the power plants and other industrial facilities that burn the LNG the country imports. That is why South Korean industry is eyeing the hydrogen dream.
But hydrogen is a panacea for the planet only on paper. The climate impact of shifting to hydrogen will depend on how the hydrogen is produced. If the hydrogen is cracked from natural gas — “gray hydrogen,” according to a rhetorical color scheme employed by promoters of the hydrogen vision and by regulators monitoring the effort — it may be worse for the climate than burning natural gas directly, according to an August study by scientists at Cornell and Stanford. If it’s cracked from natural gas but the resulting carbon emissions are captured and sequestered — “blue hydrogen,” in the lingo — then its carbon footprint may or may not be significantly trimmed.
An important environmental rationale for burning blue hydrogen rather than continuing to burn natural gas directly is that it’s more cost-effective. The carbon emissions from cracking the natural gas can be captured at a relative handful of gas-cracking hydrogen plants rather than at a much larger number of gas-burning power stations. But the August academic study concluded that blue hydrogen won’t be as blue as many suggest if its production captures only the greenhouse gas emitted from the cracking of the methane — and not the leaks from the production of the natural gas or the emissions from the generation of the electricity used to do the cracking. In practice, the study concluded, the carbon footprint of so-called blue hydrogen exceeds by more than 20% that of natural gas burned directly.
If, however, hydrogen is cracked from water using only renewable energy — “green hydrogen,” according to the color chart — then it can be carbon-free. South Korea aspires to get much of its hydrogen from renewable sources, notably the sun and the wind. But because siting large-scale solar and wind projects is so hard in the densely populated country, most of the renewably cracked hydrogen, if it materializes, is expected to come from other countries with more land. South Korea, the thinking goes, would, using specially designed ships, import the ostensibly carbon-free hydrogen in the future much as it imports carbon-laden LNG today.
Commercializing any of those hydrogen hues will require first figuring out how to burn the stuff. That’s its own engineering challenge, one being undertaken at the headquarters of South Korea’s dominant builder of power-plant turbines. The massive facility, in the city of Changwon, in a picturesque, hilly region in the south of the country, spreads across 1.5 square miles. This is the home of the company formerly known as Doosan Heavy Industries, which boasts that its turbine-manufacturing shop is South Korea’s largest indoor factory, encompassing 18 roofed acres, about the size of 10 soccer fields. Since Doosan’s founding in , about a decade after the end of the Korean War, the company, lubricated by government-related contracts, has built machines that have powered the South Korean economic miracle: turbines for power plants that run on coal, nuclear fuel and natural gas. Now the firm, rechristened with a gentler name, Doosan Enerbility, says it is pursuing a clean new future, by making turbines that burn hydrogen.
The biggest change necessary for Doosan’s turbines to burn hydrogen instead of natural gas is a new design of their nozzles, the component in a turbine that injects fuel to mix with air for combustion. Managing combustion is notoriously tricky with hydrogen, which burns hotter than natural gas. Each hole in a turbine can have a diameter ranging from a fraction of a millimeter to a few millimeters, depending on the turbine’s size and the nozzle’s design. In a hydrogen turbine, the holes have to be shaped, positioned and constructed to inject the fuel in a way that’s tailored to hydrogen’s more-violent combustion, a key element of which is what engineers call its higher “flame speed.” The nozzle itself must be built to withstand greater vibrations during combustion.
Designing a hydrogen nozzle is the job of engineer Lee Donghun. I met him in Doosan’s test lab for gas-turbine combustors. One side of the squat building, brimming with metal parts in various shapes and sizes, resembled a very expensive garage. The other side, filled with a two-story-tall contraption of shiny ducts to test turbines, looked like something from NASA. “Decarbonization is the only goal for all of our activities,” said Lee, a man who has spent the past quarter century perfecting how to burn copious quantities of fossil fuel.
His new task isn’t easy. The expectation in the industry is that, in an initial hydrogen rollout, relatively small concentrations of hydrogen — perhaps 20% — will be mixed with natural gas and burned in turbines. A low blend like that might require only relatively minor nozzle changes. But minor doesn’t mean simple. When Lee and his colleagues built their first test hydrogen nozzle, “we had some difficulties” making it, he told me. Translation: “It cracked.”
The ultimate goal is to burn 100% hydrogen in a power-plant turbine. That would require a fundamentally different nozzle design, and Lee’s team is crafting such a device. Unlike a traditional natural-gas nozzle, a cylinder whose holes are drilled flush into its top, this all-hydrogen nozzle’s holes are arrayed in a new pattern. Tiny, four-sided pyramids cover the nozzle’s circular outer end, and in each pyramid’s side sits a hole. The reconceived design, called a “micromixer,” looks vaguely like a grater for a very large hunk of cheese. One was sitting on a table in the lab, and as I moved to take a picture of it, Lee intervened. “I’m sorry,” he said. “This nozzle is confidential.”
Doosan hopes to begin manufacturing a commercial turbine that burns low blends of hydrogen in roughly five years, and one that burns pure hydrogen a few years after that. “There are so many things we have to study and test,” Lee said, sounding weary. The notion of devoting his energy to developing a technology that phases out hydrocarbons struck him as stunning and daunting — for his country, for his employer and for himself. “Big shift,” he told me, as we said goodbye. “Very difficult shift.”
An even bigger difficulty will be ginning up enough hydrogen for Doosan’s next-generation nozzles to burn. Among the companies eyeing that opportunity is SK Gas. Its corporate parent, SK Group, is Korea’s second-largest conglomerate, behind only Samsung Group. SK Group ranks 129th on the Fortune Global 500 list, and it posted sales of $135 billion. SK Group got its start selling textiles immediately after the Korean War. Today its subsidiaries develop electricity from coal, gas, solar and wind; make chemicals, computer chips and vaccines; and peddle logistical services and mobile- plans. SK Gas now markets itself as aiming to become a “net-zero solution provider,” selling “low-carbon solutions” such as LNG and “zero-carbon solutions such as clean hydrogen.” As part of that strategy, the company is gaming out the prospect of building a hydrogen-supply hub.
The site for the prospective hub is on a patch of dirt along the coast in Ulsan, the city that, beyond being Hyundai’s home, also is South Korea’s undisputed petrochemical capital. “It’s a very compressed Houston,” Hong Jongbum, an ex-Bain & Co. consultant and the SK Gas vice president putting together the emerging hydrogen play, told me in a conversation in SK Gas’ handsome headquarters in a Seoul office tower. In that petrochemical sprawl, another SK Group unit now operates a plant that produces 30,000 tons of hydrogen annually to sell to industrial customers. Though that ranks the unit as a sizable hydrogen producer in South Korea, it amounts to a fraction of a percent of the quantity of hydrogen that the South Korean government wants the country to produce by . But SK’s current hydrogen production isn’t merely too small; it’s also the wrong color. The hydrogen SK makes is gray, because the carbon produced when it is cracked from natural gas simply escapes into the sky. The government wants hydrogen that’s blue or green.
SK’s notional hydrogen hub might one day provide that next-generation hydrogen. Part of the hub is a done deal, but it’s far from clean. It’s a new LNG terminal that SK Gas is building in the Ulsan chemical complex. As a result of two contracts SK Gas has inked, much of the LNG imported into that terminal will come from the United States, including from a liquefaction terminal about 50 miles northeast of Sabine Pass, near the Gulf Coast town of Lake Charles, Louisiana. To store the LNG it imports, SK Gas is building four big tanks in Ulsan, and it’s mulling building two more.
In the near term, SK Gas plans to sell that LNG directly to Ulsan industrial customers. In the long term, it may decide to install machines to crack the gas into hydrogen — machines that wouldn’t merely process fossil fuel, but also would be powered by it — and then to capture the resulting carbon.
But SK Gas hasn’t decided yet whether it will add the hydrogen-producing capacity to the forthcoming LNG terminal. Doing so would require a way to dispose of the carbon dioxide produced by cracking the natural gas into hydrogen. One option is a technology under development by C-Zero, a U.S. company in which SK Gas has taken a stake. C-Zero aims to capture carbon emissions and package them into solid blocks intended to be sold or buried forevermore. “We’re thinking, ‘Just put it in the ground,’” Hong told me. “That is perfect for Korea.”
SK Gas’ decision about whether to build out the hydrogen hub will rest largely on the prospects for government subsidies for capturing and storing carbon — either through C-Zero bricks, if that technology pans out, or through some other means. The U.S. last year rolled out a significant increase in subsidies for capturing and storing carbon as part of the Inflation Reduction Act. The South Korean government has yet to follow suit on its turf.
Realizing that dream for the company has been the job of Jung Gwangjae, a KOGAS veteran. In early , soon after the South Korean government issued its hydrogen master plan, he shifted from running corporate strategy for KOGAS to heading up the company’s newly created hydrogen division. When I spoke with him a few months ago, he made no attempt to sugarcoat the difficulty of the hydrogen pivot. He recalled that, the year before he assumed his new post, KOGAS was “seriously considering” buying a shipload of supposedly low-carbon LNG, largely as a way to telegraph its green commitment. But the load’s price was too high for KOGAS’ patron, the South Korean government, to stomach. “So we didn’t buy it,” he told me. That experience underscores what Jung views as the hydrogen imperative. Trying to achieve significant decarbonization by greening LNG will make already-pricey LNG even more expensive, he said, because “LNG as a bridge fuel will bear much more burden.” Better, he reasons, to pour increasing quantities of hydrogen into the mix. Jung, who recently switched to another job, predicted that, by , the liquid that KOGAS distributes through its pipelines will be perhaps 70% LNG and 30% hydrogen. Yet even that relatively light hydrogen mix would require a massive increase in the production of affordable blue or green hydrogen.
To prepare, KOGAS is beginning to consider updating one of its LNG terminals to import hydrogen. It’s targeting not the Incheon terminal but one that, as the crow flies, sits about 25 miles to the south, in the port city of Pyeongtaek, “because it’s farther away from people,” meaning it would be politically easier to get approval to build, explained KOGAS’ Lee Jaehoon, who had accompanied me on the Incheon dock. The idea is to build a pipeline to send the hydrogen from Pyeongtaek to Incheon, where it would be mixed with LNG into a blend of the sort that KOGAS envisions selling and that Doosan is trying to develop turbines to burn.
KOGAS has a research and development lab in the city of Ansan, which happens to sit between Pyeongtaek and Incheon. Ever since the KOGAS lab opened in , its researchers have pursued a mission that was, if not smooth, at least clear: improve the reliability and cut the cost of the national system supplying South Korea with LNG to burn.
Now the lab is wrestling with a more jarring mandate, which is to transform South Korea’s energy system to make it climate-safe. Hours after I visited the Incheon terminal, I was welcomed at the Ansan lab. After a discussion in which seven KOGAS scientists and I sat around a room-sized, rectangular conference table — talking, sipping iced coffee and separated from each other by clear plastic panels, for Covid safety — the researchers led me on a tour of the lab. At one station, an experiment was underway to test a membrane to separate hydrogen from water, a process crucial to the prospect of so-called green hydrogen. But a problem had arisen. The membrane had leaked. “That is very dangerous,” Kim Dongmin, the research engineer working on the project, explained to me. “If hydrogen and oxygen mix, they can explode.”
So can plans to decarbonize an economy reliant on LNG. As the research in Ansan plays out, the fossil-fueled global economy continues to hum, and the planet continues to warm. In Louisiana, Cheniere and its suppliers are working to measure and mitigate methane emissions from the LNG they are producing and exporting. In Ulsan, Hyundai Heavy Industries is developing its emissions-cutting features for LNG ships. In Changwon, Doosan is iterating its newfangled power-plant nozzles. And in facilities all across South Korea, SK and KOGAS are planning for the possibility of trading quantities (which might be significant) of hydrogen (which might be clean).
If all goes exceedingly well, these efforts may be enough to meaningfully reduce the damage that natural gas is doing to the planet. But first they will have to succeed. And then they will have to expand. And then they will have to endure. And then they will have to be augmented by equally successful and sweeping efforts in country after country around the globe.
A lot could go wrong, and a lot almost certainly will. But at this late hour in the world’s warming, as the use of natural gas continues to rise despite the protestations of those who wish it wouldn’t, humanity appears to have little responsible alternative but to get serious about decarbonizing this fossil fuel.
At approximately the moment I was finishing my afternoon lab visit in Ansan, the Peacepia, the tanker I had watched that morning disgorge its chilled gas in Incheon, was departing the world’s largest LNG terminal and heading back out to sea. It was embarking on another monthlong, fossil-fueled voyage across the globe — returning to Sabine Pass, where it would pick up its next load.
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