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deep disposal

What to do about acid gas? Amid flaring restrictions and collapsed sulphur markets, the solution to the H2S-CO2 problem is increasingly to put it back where it came from.
[Print Article: March 2002, by Pat Roche] It was 1989 and Chevron Canada Resources wanted to install a sour-gas processing plant at its Acheson field, west of Edmonton, Alberta. But what to do with the acid gas -- the concentrated hydrogen sulphide and carbon dioxide cleaned from the gas stream?

Flaring wasn't an option. A year earlier, the Alberta Energy and Utilities Board had ordered that sulphur dioxide emissions from new plants could not exceed one tonne a day of sulphur, a dramatic drop from the previous limit of 10 tonnes a day. Though Acheson would exceed the one-tonne-a-day limit, the concentrations were too low to justify the cost of a Claus sulphur recovery plant.

"The only other technical alternative at the time was a process known as LO-CAT, which had a bunch of operating issues associated with it," says Bradley Lock, vice-president of operations with EnerPro Midstream Inc., Chevron's midstream unit. In addition, if LO-CAT had been chosen, the CO2 would simply have been vented to atmosphere.

Looking for a better way, Chevron chose a radical new approach. The company had a depleted reservoir in the area. Why not put the acid gas back into the Earth? It was a bold move at the time and for several years other producers remained on the sidelines to see how this pioneering project would fare.

"It's operated essentially trouble free," Lock says of Canada's first acid gas disposal scheme 13 years after it went onstream.

Other producers have also given the technology a thumbs up, if the flurry of applications since the late 1990s is any indication. Today, 30 acid gas injection schemes are operating across Alberta and nine disposal wells have been approved in British Columbia. Last year, the schemes in Alberta injected 182 million cubic metres of acid gas, according to EUB figures. Started at small plants because of flaring restrictions, injection disposal of acid gas is now being used in some Foothills-scale applications because rock-bottom sulphur prices have made recovery uneconomic.

Chevron, meanwhile, has installed three more acid gas disposal schemes -- at its West Pembina gas plant in 1994, at its Mitsue gas plant about a year later and at the Bigoray gas plant at the Pembina field in 2000. The West Pembina and Bigoray plants are in central Alberta. Mitsue, in northern Alberta, is essentially a sour-water disposal scheme where acid gas is in solution with large volumes of produced water. Says Lock: "They've essentially operated exactly as we've expected them to. They're all still operating today."

Like Acheson, Chevron's subsequent acid gas disposal schemes all handle H2S volumes that were too low to justify a full Claus plant, but would have exceeded the EUB's one-tonne-a-day emissions cap, says Lock. Small companies have faced the same dilemma. About two years ago Thunder Energy Inc. had slack capacity at its gas plant in the Rosalind area of east-central Alberta -- and gas available to fill that capacity. But boosting the throughput would have exceeded the board's emissions limits. The answer: injection disposal.

"And so by converting the plant into an acid gas injection plant, we were able to increase our gas throughput," says Doug Dafoe, Thunder's president. Besides operating the Rosalind plant for two years, Thunder has a 23% stake in an acid gas injection plant that Devon Energy Corporation brought onstream last December in the Rycroft area of northwestern Alberta.

"It's a better way to go -- zero emissions," says Dafoe. "You don't have any problems with odours or people worrying about what's being spewed all over the place." He adds the cost is reasonable and the technology is well understood.

Westcoast Energy Inc. apparently thinks so. Westcoast -- which has almost a half century of experience in gas processing -- opened its first acid gas injection plant at Jedney in northeastern British Columbia in 1996, with an injection capacity of four mmcf a day. A second Jedney plant, capable of injecting 3.4 mmcf a day, followed a year later.

Now it's halfway through construction of an even more ambitious facility. When it goes into service in early June, Westcoast's $105-million Kwoen plant will be Canada's biggest acid gas injection operation. It will process 300 mmcf a day of natural gas and dispose of 28 mmcf a day of acid gas.

Situated just east of the Rockies in the Grizzly Valley area of northeastern British Columbia, the Kwoen (pronounced cone) plant will include three 3,750-horsepower acid gas compressors. The gas will be shipped via six-inch pipeline to its first injection well, which is expected to take the plant's entire output for four years. When that well's injection capacity starts to decline, a second well will be brought onstream and the first one eventually will be phased out. A third injection well is expected to complete the project's 20- to 25-year lifespan.

Before a company can develop an acid gas injection project, it must first find a home for the gas. About one-third of Alberta's schemes are injecting into producing or depleted hydrocarbon reservoirs and the rest use deep saline aquifers. Westcoast's Kwoen operation will inject into depleted gas reservoirs. "The reason the plant is located where it is -- rather than, say, 10 or 20 miles away or somewhere else on our gathering system -- is because of the proximity to the acid gas injection wells," says Doug Thorneycroft, project manager.

Another company with acid gas injection experience in northeastern British Columbia is Petro-Canada. Since early 1997 the company has been injecting about 3.5 mmcf a day into a producing reservoir at Jedney. (The acid gas -- about 50% H2S and 50% CO2 -- is injected into the south end of the reservoir and hasn't affected production from the north end of the pool.) Petro-Canada brought a 500-mcf-a-day disposal well onstream last August at Parkland.

One of the issues faced in developing acid gas disposal wells is the potential size of the emergency planning zone, which is based on the volume and rate of potential H2S release in the event of a pipeline leak. In this case, the volume is the amount of gas in the pipeline from the central compressor station to the wellsite.

Because the gas is compressed, the amount that could be released becomes a significant multiple of the pipe volume. That dramatically increases the size of the required emergency planning zone. And as the planning zone grows, the more residences it will likely include.

To reduce its emergency-planning radius on the Parkland project, Petro-Canada divided its acid gas pipeline into three segments, each with emergency shutdown valves, explains Tom Everest, a Petro-Canada production engineer. If there's a break on any segment, a low-pressure signal activates two emergency shutdown valves, which isolate that third of the pipeline.

Liquids also boost the radius of the emergency planning zone. When the reservoir starts to fill up and more compression is needed, the acid gas stream turns to liquid H2S and liquid CO2. "It again drives up your planning zone because the number of molecules in that pipe is much, much higher in a liquid phase," says Everest. One cubic metre of liquid acid gas occupies roughly 500 cubic metres at atmospheric pressure in gas phase.

But corrosion presents the biggest challenge. Surface vessels, valves and piping typically include lots of stainless steel, which costs about three to four times as much as carbon steel, estimates Damian Saunders, sales manager at Calgary-based Energy Industries Inc., which has been building acid gas compression packages since the early 1990s. Despite the cost, end-users tend to favour conservative designs with plenty of stainless steel to mitigate the cost of potential alterations or repairs in the field. All process piping and vessel connections are typically flanged to minimize potential leak points and corrosion, as safety is of paramount concern when dealing with such toxic substances, says Saunders.

In the wellbore, lots of nickel alloys are used in the tubulars and casing. Nickel casing, which is run throughout the injection zone to just above the cap rock, can cost $1,000 a metre. A packer is used to isolate the injection zone and all tubulars must be corrosion-resistant all the way to surface.

Special materials for acid gas injection aren't just limited to metals. To ensure long-term isolation of the injection zone, Halliburton Energy Services developed a latex-based annular sealant that it says is more reliable than conventional cement.

Carbon dioxide in the acid gas converts conventional cement to calcium carbonate over time. This isn't a problem in itself -- it simply means the cement becomes identical to the limestone in the formation, which still provides a good bond to the formation and casing interfaces. But if the injected acid gas isn't totally dehydrated, the water mixes with the H2S and CO2, producing extremely corrosive sulphuric acid and carbonic acid -- both of which will eat away at calcium carbonate.

"It might not happen instantly. But there are cases -- in Utah, for example -- where they've injected CO2 (and) lost isolation within weeks," says Don Getzlaf, Halliburton's cementing technology manager for Canada.

To guard against this threat, Halliburton uses Flexcem, a flexible sealant that contains no Portland, or conventional, cement. The latex-based sealant has been vulcanized -- treated with additives to improve the strength and resiliency of the slurry, which is pumped into the annulus across the injection zone where it sets like a solid rubber tire, says Getzlaf. "That is impermeable and unsusceptible to H2S or sulphur or acid. It's impermeable like a packer. So it's a liquid packer, a poured-in-place packer." Getzlaf says Flexcem has been used in acid gas injection in Western Canada and in PanCanadian Energy Corporation's field at Weyburn, Saskatchewan, which is under CO2 flood.

While most operators take pains to dehydrate acid gas prior to disposal, you can actually inject acid gas with water -- as long as there's lots of water.

You need enough water to keep the pH above 4.5 (an EUB requirement) and to ensure the solubility of the acid gas -- since free gas would wreak havoc with the injection pump, explains Dave Kopperson, general manager of technical services at PanCanadian. He says the company has successfully disposed of acid gas with produced water at two oil properties in east-central Alberta.

Kopperson says PanCanadian's experience showed that co-injection works. "I think we learned we could do it but I wouldn't want to say we would do it regularly," he says. "We'd look at the alternatives and we'd make a selection based on what made sense in the area -- including factors such as the amount of acid gas and the amount of water." Kopperson believes co-injection is best suited to Plains oil production (which is typically high water cut) when there is sour solution gas.

One economic benefit of disposing of acid gas with large volumes of produced water is that it "can actually be a less corrosive environment" than straight acid gas injection, says Kopperson. In PanCanadian's case, corrosion-resistant materials were needed anyway to get rid of produced water. In one case, PanCanadian was adding acid gas to the water before it went to the injection pumps, so minimal pressure was needed. "So you're not talking about a huge reciprocating compressor," says Kopperson. "We used a screw compressor, which is cheaper and somewhat more reliable in those conditions."

Injecting acid gas has two environmental benefits over flaring. Less CO2 -- one of the major greenhouse gases blamed for global warming -- goes into the atmosphere. And since H2S is not being burned, there are no emissions of sulphur dioxide, which combines with water vapour in clouds to form acid rain, which harms fish and trees. While flaring restrictions may have prompted the development of acid gas injection technology -- and oil and gas companies may not agree on the causes of global warming -- the result is that fewer emissions are going into the atmosphere. Says Petro-Canada's Everest: "At the end of the day we're probably doing the right thing anyway."

  • PLANT GROWTH Construction of Westcoast's Kwoen plant, which will be Canada's biggest acid gas injection operation.
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