Raw Natural Gas: Wellhead Composition, Sour Gas Sweetening, and WCSB Sales-Gas Specifications
Raw natural gas is the unprocessed gas stream that flows directly from the wellbore, before any treating or conditioning, containing not only the methane that customers ultimately buy but also a mix of heavier hydrocarbons and non-hydrocarbon contaminants that must be removed before the gas is fit for a pipeline. A typical raw stream is dominated by methane, the lightest hydrocarbon, but also carries ethane, propane, butanes, and heavier condensate-forming components collectively called natural gas liquids, along with water vapour, hydrogen sulphide, carbon dioxide, nitrogen, helium, and sometimes trace mercury. The exact makeup varies enormously from field to field. A dry gas well produces almost pure methane with little liquid, while a rich or wet gas well such as many in the liquids-rich Montney and Duvernay of the Western Canadian Sedimentary Basin yields a stream heavy in natural gas liquids and valuable condensate. When the raw gas contains hydrogen sulphide it is classed as sour gas, and in Canada a stream is generally considered sour above about 5.7 milligrams of H2S per cubic metre, roughly 4 parts per million by volume. Sour gas is toxic and corrosive, and much of the WCSB, particularly deeper Devonian carbonate gas, is sour, which is why Alberta has a long history of large gas plants built specifically to strip and recover sulphur. Turning raw gas into marketable sales gas requires several conditioning steps in sequence: separation of free liquids and condensate at the wellhead, sweetening to remove H2S and carbon dioxide usually by an amine absorption process, dehydration to strip water and prevent hydrate formation and corrosion, and finally the recovery of natural gas liquids by cooling or absorption. The removed hydrogen sulphide is normally converted to solid elemental sulphur in a Claus process unit. The finished sales gas must meet pipeline specifications that in the WCSB typically cap H2S at around 16 milligrams per cubic metre, roughly a quarter grain per hundred cubic feet, limit carbon dioxide to about 2 percent, restrict water content to prevent hydrates, and hold heating value near 36 to 38 megajoules per cubic metre, close to 1,000 British thermal units per standard cubic foot. Handling, flaring, and venting of raw and sour gas in Alberta is governed by AER measurement and conservation rules including Directive 060 on flaring, incinerating, and venting, so that raw gas is conserved and safely processed rather than wasted.
Key Takeaways
- Wellhead Stream, Not Pipeline Gas: Raw natural gas is what comes straight out of the ground, a blend of methane with heavier hydrocarbons and contaminants. It is never delivered to consumers in this state. Between the wellhead and the sales pipeline it must be separated, sweetened, dehydrated, and have its liquids recovered, so raw gas is the feedstock for gas processing rather than a saleable product itself.
- Sour Versus Sweet Classification: Raw gas containing hydrogen sulphide above roughly 5.7 milligrams per cubic metre, about 4 ppm, is classed as sour; below that it is sweet. Sour gas is lethal at low concentrations and severely corrosive, driving special metallurgy, safety zones, and emergency planning. Much of the deeper WCSB Devonian gas is sour, which shaped Alberta's large sulphur-recovery gas plants and strict sour-well regulations.
- Contaminants Drive Processing Steps: Water vapour causes hydrates and corrosion, carbon dioxide is acidic and lowers heating value, nitrogen dilutes energy content, and H2S is toxic. Each contaminant maps to a treating step: dehydration for water, amine sweetening for H2S and CO2, and sometimes nitrogen rejection. The raw composition therefore dictates how complex and costly the gas plant must be for a given field.
- Liquids Add Major Value: Rich raw gas from the Montney and Duvernay carries ethane, propane, butane, and pentanes-plus condensate. Recovering these natural gas liquids at a plant turns a low-value dry-gas well into strong economics, since condensate in particular sells at a premium and is in demand as oil-sands diluent. The liquids content of raw gas is often what makes a WCSB well worth drilling at low gas prices.
- Sales-Gas Specs Set the Target: Finished sales gas must meet pipeline rules: H2S near 16 milligrams per cubic metre, carbon dioxide around 2 percent, tight water limits, and heating value close to 1,000 Btu per standard cubic foot. Raw gas is processed until it meets these numbers. The gap between a field's raw composition and the sales specification defines the entire conditioning task and its cost.
From Wellhead Separation to Amine Sweetening
Conditioning begins at the wellhead, where a separator drops out free water and condensate so only gas and its remaining vapour move downstream. If the stream is sour, it passes through an amine contactor where a circulating solvent such as MDEA chemically absorbs hydrogen sulphide and carbon dioxide, producing sweet gas overhead and a loaded amine that is regenerated with heat. The stripped acid gas is routed to a Claus sulphur-recovery unit that converts H2S to solid sulphur, often recovering more than 98 percent of the sulphur to meet Alberta conservation targets. This sequence turns a toxic raw stream into a gas safe for further processing.
Dehydration, Liquids Recovery, and Sales Delivery
After sweetening the gas is dehydrated, commonly by contacting it with triethylene glycol that absorbs water down to pipeline limits, preventing hydrate plugs and corrosion. The dry gas then enters a liquids-recovery unit where refrigeration or a turboexpander chills it to condense ethane, propane, butane, and pentanes-plus into a natural gas liquids stream that is fractionated and sold separately. The remaining residue gas, now mostly methane meeting heating-value and contaminant specs, is compressed into the sales pipeline. Each step moves the raw composition closer to the marketable product the transmission system will accept.
Fast Facts
Some of the sourest raw natural gas ever produced in Canada came from deep Devonian carbonate pools in Alberta and northeast British Columbia, where hydrogen sulphide can exceed 30 percent of the raw stream, a concentration high enough that the gas is more a sulphur resource than a fuel. The Alberta gas-processing industry became one of the world's largest producers of elemental sulphur as a by-product, and at times sulphur was stockpiled in enormous bright-yellow blocks near plants because it was recovered faster than it could be sold into fertilizer and industrial markets.
Related Terms
Raw natural gas becomes a product only after processing removes its contaminants, and its natural gas liquids are the high-value fraction stripped out along the way. When it carries hydrogen sulphide it is sour gas, demanding sweetening and sulphur recovery, and its water content must be cut by dehydration to prevent gas hydrate formation in pipelines. These terms trace the raw stream's path from wellhead contaminant mix to clean, saleable pipeline gas.
Sour Montney Gas Plant Near Dawson Creek
A producer developing liquids-rich Montney gas near Dawson Creek, British Columbia, tied wells producing a raw stream of about 2 percent hydrogen sulphide and roughly 60 barrels of condensate per million cubic feet into a new sour gas plant. The raw gas was too sour and too rich to sell, so the plant added amine sweetening, glycol dehydration, and a turboexpander liquids unit, a build costing on the order of 120 million CAD, with a small Claus unit to recover sulphur under provincial conservation rules.
Once conditioned, the residue gas met pipeline specification and the recovered condensate sold at a premium as oil-sands diluent, making the project economic even at soft gas prices. The value of the natural gas liquids stripped from the raw stream, not the methane, carried the return, a pattern typical across the liquids-rich WCSB.