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- Bon Voyage
November 2, 2011
CALGARY, AB, Nov. 2, 2011/ Troy Media/ – A century ago, Rudyard Kipling infuriated ‘Hatters,’ saying Medicine Hat, Alta., had ‘all hell for a basement.’ He was referring to the natural gas reservoir only 300 metres below the city.
‘The Hat’s' municipal officials tapped into the readily available reservoir, as did some townsfolk who had their own private gas wells to provide limitless gas for cooking, heating and lighting. It was economic heaven.
Today, harvesting that natural gas is considerably more challenging. It’s up to the producers of natural gas in Canada to make sure the product coming out of the ground is handled safely and refined to clear out the impurities, water and rogue hydrocarbons. A gas plant may look like a tangle of pipes, pumps, heaters, freezers, tanks and towers, but they’re all necessary to ensure the product on the market side of the process is a clean burning fuel.
Long before Kipling brought some measure of fame to Medicine Hat, natural gas was discovered in New Brunswick in 1859. Finds came a few years later in Ontario and 20 years later in southern Alberta. By 1908, the first pipeline in Alberta was created to deliver natural gas to far-reaching communities.
Third largest producer
Today, Canada is the world’s third largest producer of natural gas with an average annual production 6.4 trillion cubic feet. That gas flows through more than 480,000 kilometres of pipes, heating more than half the homes and businesses in Canada. It also flows into the U.S., providing 14 per cent of the natural gas it needs, according to the National Energy Board.
Natural gas can be a product of a well drilled specifically for gas or it can be a by-product from an oil well. If natural gas is produced from oil, the gas usually releases from the oil within the formation as the pressure in the rock is decreased during extraction. (Think of opening a carbonated beverage.) The products are then moved through separate pipelines for processing. If the gas is reluctant to be liberated on its own, low temperature separators are used.
At an oil refinery, the crude oil is heated to separate the different hydrocarbons present in the oil. Each hydrocarbon chain has a different boiling point and will drop out of the distillation column at different temperatures. Natural gases or ‘associated-dissolved’ are quick to boil out at roughly 40 Celsius while heavier hydrocarbons fall out at temperatures up to 600 Celsius.
Natural gas – or gas ‘non-associated’ from a well drilled purposely for gas – is mostly composed of methane, which is the preferred sales gas. But, depending on the source, it can include ethane, butane, pentane and propane. If you were awake during your high school Organic Chemistry class, you’ll recall these are the simplest hydrocarbons (C2H6, C3H8, C5H12, and so on) The heavier of the hydrocarbons are liquid at room temperature, which is good for fuel but bad for the gas lines.
Impurities come along
Other non-hydrocarbons may come along for the ride, including CO2, Nitrogen and H2S. In areas like Ram River near Rocky Mountain House, in central Alberta, gas is rich with ‘sour gas’ – toxic hydrogen sulphide, named such because it smells like rotten eggs. (The opposite ‘sweet gas’ is found in a number of locations, including the Horn River Shale in northeastern British Columbia.)
At the well-head, gas can be heated to reduce the likelihood of hydrate crystals from forming and/or scrubbed for a quick removal of large-particle impurities (like sand), then compressed into pipeline to move to a regional gas processing plant.
Gas plants are built close to the source of the raw gas, which can be expensive. Spectra Energy states, for example, that its plant under construction in the Horn River Shale region will cost $1.5 billion, and has the capacity to process 200 MMcf/day. As you can guess, increasing the complexity of a gas plant determines the cost.
Once at the plant, finer impurities are split out. Four different processes strip out: oil and condensate, water, natural gas liquids (NGLs), and sulphur and carbon dioxide. The infrastructure of the gas plant depends on how much separation is required.
The water or associated vapour is removed using a dehydrating agent like glycol that steals the moisture from the wet gas through absorption. Or it is done by condensing the water vapour in large adsorption towers, where the gas is passed through solid desiccant, such as activated alumina or a granular silica gel material. As the wet gas passes through, the water sticks to the desiccant and the gas departs the tower dry.
NGLs are pulled from the gas using another absorption system, with oil soaking up the NGL, instead of the glycol used in the dehydration system. A cryogenic expansion process is used to remove the lighter hydrocarbons, like ethane. As the temperature drops to -120 Fahrenheit (-84 Celsius), the NGLs condense, but the methane stays gaseous. Once the NGLs are removed, they are further separated by boiling off the hydrocarbons, by way of the de-ethanizer, the depropanizer, and the debutanizers.
Natural gas is considered sour if the H2S content exceeds 5.7 milligrams per cubic metre. Removing the H2S or ‘sweetening’ the gas is similar to the glycol dehydration process, except an amine solution is used to remove the hydrogen sulphide. It can also be removed using large solid desiccant towers with iron ‘sponges’ to remove the sulphide and carbon dioxide. The sulphur can be used in products ranging from fertilizers to matches.
When the gas has been stripped down to just dry methane, it is ‘pipeline quality’ and ready to send out or store.
Depleted gas reservoirs are the most favourable and economically feasible storage facilities for natural gas. Aquifers and salt cavern reservoirs can also be used, although they are more costly. By pumping the gas back into a proven highly porous and permeable reservoir, the product can be stored until the colder months when there is more demand for natural gas. Storing it also serves as a market buffer and reserves in case there is an interruption in production.
Enbridge Inc.’s gas distribution storage operation is one of the largest of its kind in Canada, with a capacity of approximately 100 billion cubic feet (Bcf). The company’s storage facilities are primarily located in southwestern Ontario.
In Alberta, Niska Gas Storage has 148 Bcf of storage in southern Alberta at the Countess and Suffield facilities. With Canada consuming an average of 8.6 Bcf of natural gas per day, just those facilities alone could supply more than a month’s worth of the country’s gas needs. That does not take into account how much is stored in the pipelines or smaller storage facilities. The U.S. holds much more – roughly 2,432 Bcf in storage – but also uses 62.4 Bcf/day.
The process of refining gas into a market-ready product is complex and expensive to design. But the techniques have been refined over decades to the point that they are efficient, safe and environmentally sound, using proven technologies.