Luyện nói tiếng Anh bằng Shadowing qua video: The Logistics of Natural Gas

An American household is typically delivered  two physical goods as utilities. The first is water—and the ability to turn on a tap and  reliably have fresh, clean water year round, no matter recent precipitation is undoubtedly  impressive, but a water utility is typically a fairly local service. Except in a few,  fascinating exceptions, water tends to be gathered from a natural source, processed,  and delivered to households fairly nearby.

It’s a fairly intuitive, fairly straightforward  process that has been going on, in some form, for hundreds, even thousands of years.  Natural gas, though—that’s a modern marvel.

The general rule, across the world, is that  natural gas production happens where people are not. This is in part a happenstance of  geography, in part the consequence of an aversion to proximity to production, but what it  means is that gas often has to travel hundreds, if not thousands of miles to get to its end-user.  To get low-density, flammable gas across an entire continent is far from easy, and it’s even harder  to do so profitably. Whereas gasoline and other liquid fuels are dense enough that the cost of  transport to the end-user by truck is marginal relative to the overall cost, the same is not  true for natural gas. Therefore, through time, what has turned the previously worthless gas into  a profitable commodity was figuring out how to make the transport economics work. And the answer  for that was pipelines—really, really long ones.

Taking the example of an end-user in  Basalt, Colorado, their town’s local network hooks up to a larger transmission  pipeline that follows the area’s highway down the valley until around here—under  this golf course, this dead-end offshoot connects with the long-distance transmission  pipelines spanning across Colorado. Now, the fact that this happens under a golf course  demonstrates something important—the pipeline operator does not own the land through which the  pipeline passes. Rather, they own the right for the pipeline to pass through others’ land—they  own an easement. When a pipeline is constructed, the company negotiates with landowners to purchase  the easement or, if negotiations don’t go well, acquires it through eminent domain. In exchange,  the landowner gets paid a lump sum, more of less equivalent to the reduction in property  value caused by the new easement. After all, the property value will be lower. Not only will  buyers be wary of living near a pipeline due to the low but non-zero risk of an accident, but  easements also come with restrictions on what one can do with the land. Typically, you can’t  build any buildings, you can’t plant any trees, you really can only have pavement, grass, or  dirt. The operator needs to be able to access the pipeline for maintenance and repair at any  time so they can’t have a permanent structure in the way. And these easements are legally-binding  for eternity—they are baked in with a property’s title, so buyers must still abide by the  restrictions agreed upon by the original seller.

Here, the adjacent housing development is laid  out in a way to avoid the largely-invisible right-of-way, then on the other side of the  river the right-of-way slides between buildings, barely even visible from a satellite view. But  as the hills start, the right-of-way takes its more typical form—a 50-foot wide stretch  of land devoid of trees. And that lack of trees originates, of course, from construction.  That process is fairly straightforward. First, heavy machinery is used to dig a trench. Then,  sections of pipe are laid out next to the trench, and a pipe-bending machine comes through to  bend the pipe to follow the topography. Next, these shorter sections are welded together into  longer sections, and the welds are strictly inspected—after all, structural integrity is  critically necessary to prevent an incident.

Once complete, they’ll place these long sections  in the trench on sandbags to prevent damage to their protective coating, then soft, rock-free  dirt is placed to directly surround the pipe, followed by the previously-removed dirt to  fill the rest of the trench. From there, the crews test the pipe by filling it with  water and pressurizing it well beyond its normal operating pressure, and that’s about it. Pipeline  construction is relatively straightforward and moves relatively fast—under the right conditions,  crews can install upward of a mile of pipe a day, often across quite remote environments.  But there is more to pipeline construction than just constructing the pipe—after all, if you put  natural gas into a pipeline in Texas, it doesn’t just magically flow to Colorado. That’s why  you need this—a compressor station. As the name implies, these are the facilities that compress  the gas, and it’s this pressure that propels the gas forward through the pipeline at a speed of  about 25 miles or 40 kilometers per hour. But they’re also important for making the economics  work. An average household uses about 200 cubic feet of natural gas a day. That’s a lot of volume  of gas—it’d fill up a 6-foot, or 2-meter cube, or the volume of about ten fridges. The economics  of transporting this gas would never work if it were done at its natural density. That’s why they  compress it—quite a lot, in fact, to between 500 and 1400 pounds per square inch, allowing a  pipeline to be used far more efficiently.

These compressor stations are also often  home to so-called “pig launchers,” which are more humane than they sound. That’s because  these are what are referred to as pigs—devices placed into the pipeline to perform some  function. Some pigs clean the pipeline, whereas others are smart pigs fitted with sensors  to inspect it for any vulnerabilities. While less relevant in natural gas pipelines, operators  will even use pigs to separate out two different products moving through a pipeline—they might send  a batch of traditional vehicle fuel, then a pig, then a batch of jet fuel, for example. And  wherever there’s a pig launcher there’s also a pig catcher that’s able to remove the device from the  pipeline while still allowing product to flow.

Now, this pipeline eventually emerges from the  mountains into another golf course, this time just south of the town of Eagle. From there it  connects to another pipeline—right continues east, but left eventually dead-ends just a few  miles down the road. This is common, because while one major category of customers for these  long-distance transmission pipelines is the local utilities that distribute gas to local users,  the other big customers are large industrial facilities that use so much natural gas that they  have a direct connection to the long-distance pipelines. In this case, it’s a plant that turns  gypsum mined nearby into plaster drywall, and it's energy-intensive enough that the facility operates  its own 6 megawatt natural gas power plant.

The rest of the pipeline, though, more or less  follows the path of route 6, then diverts south over a set of hills before reconnecting with the  highway and ending up here—another compressor station. Although, this compressor station isn’t  operated by Black Hills Energy like the pipeline up until this point—it’s operated by Xcel Energy.  That’s because here, the pipeline’s ownership changes, which is also abundantly common.  Pipelines in the US are highly regulated by the Federal Energy Regulatory Commission and, as  part of that, interstate pipeline operators are required to provide non-discriminatory open-access  to all qualified shippers. Effectively, they’re not even allowed to provide preference to their  own product. FERC also regulates rates—Black Hills Energy, for example, is allowed to charge $36.87  to reserve a dekatherm of pipeline capacity during the winter, when demand is higher. That guarantees  capacity, then they’ll charge another 10 cents per dekatherm for the actual transmission.  Alternately, shippers can pay just 94 cents per dekatherm, with no capacity charge, for  “interruptible transportation,” where product is shipped only if there is available capacity.  The fact that this system is open access is ultimately how product can find its way through  the nation’s web of pipelines all the way from where it’s produced. A shipper might pay a dozen  different companies for their transmission service to get the gas from its origin. And in  the case of an end-user in Colorado, it’s quite likely that the origin for  its gas is here—Texas’ Permian Basin.

There, the natural gas is extracted from the  ground and processed into its commodity form.

The area’s primary industry is the more  lucrative oil production, but natural gas is often a byproduct of that. Still to this day,  many rigs burn off natural gas if they lack the infrastructure to divert it for sale, but an  increasing number do capture both. But whether extracted via combined or dedicated rigs, it is  often difficult to fluctuate production quickly to match demand. And demand fluctuates wildly  considering so much of the use of the gas is for heating. So that’s the role of these 400 different  natural gas storage sites dotted across America.

Some of these sites are just the very areas  where gas was previously extracted from—depleted underground caverns. Once all of that original  gas is gathered, the giant Swiss-cheese holes in the ground—sometimes spanning thousands of  acres—sit empty and that makes them ideal for storage. They also already have existing wells,  existing extraction and injection methods, and existing pipeline connections. Here, gas is  reinjected into the impermeable natural caverns some 1,000 to 5,000 feet, or 300 to 1,500  meters below the ground, where the working gas—the natural gas that is commodified—occupies  the upper part of the cavern and a cushion gas maintains a pressure buffer at the bottom. Because  the depleted natural gas fields are established, proven, and widespread, their geology and  infrastructure generally makes them the most inexpensive and easiest way to store natural gas.  There is, however, another method that crept into more use about a decade ago as the country  ramped up some storage capacity: Salt caverns, which can quickly turn over storage since  they can accept a higher ratio of working gas to cushion gas. Leaching out and creating salt  caverns is expensive, but because of their high withdrawal and injection rate—which can cycle up  to 12 times per year—that cost can be justified.

This short withdrawal cycle is ideal for pumping  energy into power plants during peak periods, and because more natural salt caverns are  found in the South and Gulf area, this is where they’re increasingly being put to use.  The third type, similar to depleted oil fields in structure, are drained aquifers. These share  the characteristics of being underground natural storage areas, but because they were previously  stored water the surfaces can be permeable and the caverns less explored. It’s more expensive  to transform aquifers into natural gas storage so it’s primarily done in areas, like the  Midwest, where depleted oil fields are less common. Furthermore, aquifers require up to  80 percent cushion gas, meaning the amount of working gas they actually hold is far  less than something like a salt cavern, making injection and withdrawal more difficult.  But not all the gas extracted in Texas, or anywhere in the US for that matter, will even  be used in the US. Increasingly, gas is not only transported across a continent, but across the  world. And to get to such far-flung markets, it’s moved as a liquid, crossing oceans,  gulfs, seas, and straits in one of these.

This is a Q-Max class liquefied natural gas  carrier. There are 14 of them worldwide, and their classification signals that they are the very  largest vessel capable of docking at Qatar’s LNG terminals, making them the largest LNG carriers in  the world. But in terms of sheer capacity, these are small in comparison to their conventional  oil tanker contemporaries. A Q-Max can carry some 266,000 cubic meters of liquefied natural gas  whereas the world’s largest TI-class supertankers can carry up to 450,000 cubic meters of oil. And  yet these conventional oil tankers, with their superior storage, come at a fraction of the cost  of a LNG carrier, as the last TI-class supertanker cost $82 million in 2003, while a Q-Max runs in  the $200 to $300 million range. While smaller, more expensive to build, and more expensive to  maintain given the requirement of keeping natural gas in a fluid state, experts believe there  will soon be more LNG tankers plodding across the oceans than oil tankers. The reason as to why  has to do with some geography and some physics.

On a global scale, the demand for natural gas  is in places far from the supply. In 2023, these three countries were the largest LNG importers in  the world, with China narrowly outpacing Japan.

For decades, these three countries have been  at the top of the list, with Japan the world’s number one year in year out until 2021. And for  two of these three countries, total consumption exactly matches or very nearly matches imports.  Put simply: Japan has very limited natural gas, and South Korea has almost none. And while  China does have a strong domestic supply, it cannot nearly keep pace with its own demand.  The difficulty is, most of the big suppliers are far away and across oceans that make any sort  of pipeline project infeasible. So geography has dictated if natural gas is to get from the  US or Qatar or Russia or Norway or Australia, it’s likely going to be by ship.  But it’s physics that makes natural gas cost competitive. For natural gas to enter  a liquid state, it needs to be cooled to and kept at -260° Fahrenheit or -162° Celsius—which  is what makes LNG ships so expensive to build and expensive to run. But it’s worth the trade  off because once cooled into a liquid, natural gas shrinks to 1/600th of its previous volume.  While natural gas has been lobbied as a cleaner, more efficient energy source by proponents,  it’s really this incredible transformation from voluminous gas to energy dense liquid that  makes this energy source so remarkable, and now, so important on a global scale. By keeping the  gas at -260 Fahrenheit, the common adage goes, a beach ball’s worth of gas shrinks down to the  size of a ping pong ball. But that example lacks scale. Phrased in another way, that a single  ship’s worth of LNG becomes 600 ship’s worth of gas in its natural state, it becomes easier  to understand why LNG has skyrocketed in trade volume decade after decade—even if it’s  incredibly expensive and labor intensive to keep the stuff at such a cold temperature.  Before liquid natural gas can be loaded onto an expensive boat, it needs to be cooled down  at an expensive liquefaction facility. At each liquefaction facility there are what the industry  calls trains—where the gas is treated to remove impurities, then progressively cooled to turn  raw gas into clean gas then clean gas into liquid gas. At Sabine Pass in coastal Louisiana, the  oldest operational liquefaction terminal in the US—as well as the largest—there are currently six  separate functional trains. The first five cost, as estimated by Cheniere Energy which owns and  operates the facility, between $17.5 and $18.5 billion dollars to build, while the sixth added  later cost of about $2.5 billion. After trains, the product is then stored, awaiting a ship.  At Sabine Pass, LNG is stored in five separate tanks capable of holding an absurd 500 million  cubic meters worth of gas. Once a ship has been positioned in a vessel berth—of which Sabine  Pass has three—and once the ship’s tanks have been cleaned and prepared to take on the freezing  liquid, loading arms are then bolted onto the ship and the filling process begins while crews  monitor ice build up on the adjoining pipes. If the ship’s tanks have already been cooled, filling  will take up to about 15 hours. This process needs to be fairly quick, as Chenaire reported that it  filled 423 cargoes in 2022, and 425 in 2023.

Once the liquid natural gas is on the move, it’s  now the job of tanker operators to monitor its freezing cargo and minimize loss on account of  off-boiling. There are two main categories of LNG tankers—those with independent tanks, like the  recognizable Moss-style with its spherical tanks, and those with the less distinguishable integral  tank—where the tank functions as a part of the hull. The former is older, deals with less  sloshing—a danger that can damage tanks or increase boil-off inside the tank—and is reliably  safe on account of the tank’s isolation from the hull. The latter is capable of carrying far more  and because of this are becoming more prevalent, and are reliably safe on account of the tank’s  pliability should the hull be struck. But both rely less on continuously cooling their product  than just keeping it cold in the first place, as both tank structures are maximally insulated  with more than 20 centimeters of foam and multiple barriers surrounding the tanks. Still, some  boil-off is bound to occur, but rather smartly, that’s what powers the boat. And should the tank  experience too much boil-off, there are systems in place to slow the process, whether by running  gas back through reliquification, or by cooling the tank by spraying liquid from the bottom of  the tank in the gap at the top. Keeping an eye on all this is a crew of about 20-29 members,  with at least one cargo engineer focused on the composition of gas within the tanks specifically.  Upon reaching its port of call, the process is effectively reversed, in a similarly labor  and infrastructure intensive process with regasification equipment in place of trains.  Ultimately, for as dispersed as users of natural gas are, and diverse as the uses of natural  gas are, the process of making, moving, and regassing LNG is remarkably confined. Across the  world’s two largest LNG producers, LNG exporting is confined to only seven active locations—6 in  the US and just one in Qatar. And as for imports, Japan with the longest history of LNG reliance  is home to around just 30 regasification plants.

But like all fossil fuels, demand for natural  gas is expected to soon peak. New buildings are increasingly being built with heat pumps, electric  water heaters, induction stovetops, and other cleaner, more efficient electric alternatives.  In fact, already, in New York City, for example, certain new buildings are banned from adding  natural gas hookups. So this incredible network of pipelines and tankers will grow increasingly  irrelevant in the coming decades. For now, though, it’s one of the world’s most fascinating  interconnected distribution systems.

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