Thanks to the Montney and Horn River shale plays, Western Canada can hold its own in the natural gas renaissance; however, production from these developing plays will not offset declines in the region’s conventional gas production, according to Ziff Energy Group’s Edward Kallio, director of gas consulting.
In Ziff’s view, the Montney is not a shale but rather a tight gas play. Regardless, Kallio called it “the best play in North America,” after adjusting for basis, followed by the Horn River. “Montney economics are a little over $4, adjusted for basis; Horn River economics are a little over $5,” Kallio told attendees at the Argus Shale Liquids & Gas Summit in Houston Tuesday.
Kallio said the western side of the Montney is more shale, but its core area is tight gas.
“We see 2.6 Bcf/d coming out of this play [by 2020],” Kallio said. “We don’t see a whole lot of upside over and above the 2.6 Bcf/d because of the aerial extent of the play. The infrastructure is more mature here than in the Horn River play, so this gas will come up more quickly. There is high liquids content in some parts of this play, but it’s not homogeneous in terms of liquids. Liquids are a little more eastward and the farther west you go the less liquids content you have and the more gassy it gets.”
Recently Calgary-based Talisman Energy Inc. and South Africa-based Sasol Ltd. said the latter would acquire a stake in Talisman’s Montney Shale assets and could develop a gas-to-liquids (GTL) plant in the region (see Shale Daily, Jan. 3; Dec. 21, 2010).
Kallio said such a project could probably produce gas liquids for about $75-80/bbl based on the full-cycle well costs in the Montney. The plant could be selling that output into a $100/bbl market, Kallio said. “And you’ve got a high-quality synthetic diesel coming out of these facilities, which Sasol can then use to fractionate as feedstock to some of their other facilities, so they’re very much vertically integrated…”
The analyst said GTLs could be another area for gas demand growth besides power generation and natural gas vehicles. “We could have a gas demand uptick from gas-to-liquids,” he said. “I would be very surprised if Sasol is not looking at a gas-to-liquids facility somewhere in the Lower 48, and I would expect that we’ll hear something about that in the not-too-distant future.”
Ziff also expects to see 2.6 Bcf/d from the Horn River by 2020, assuming that one liquefaction plant is built at Kitimat to enable the export of liquefied natural gas (LNG) to Asian and potentially other markets (see Shale Daily, March 21). If current plans for liquefaction capacity are expanded, the Horn River will produce more to fill it, Kallio said.
“It’s a beautiful play,” he said. “If you’re a geologist, you really like this play, lots of potential there. With more liquefiers this will grow more quickly. You could see 5-10 Bcf/d coming out of this play…It’s dry gas, however; Asian countries like a wetter gas stream. This is very dry; it’s very deep, and it has a high CO2 [carbon dioxide] content, so that’s another issue in terms of processing.”
One of the things Kallio said he and others like about the Horn River is its high quartz content. “When you smack it, it cracks, which is what you want when you’re fracking wells.”
The Horn River will have a long lead time before production really ramps up, Kallio said. “It’s among the higher-cost shale plays in North America. That’s by virtue of its location, not so much because of the geology and the well costs…You pay a basis penalty as compared to Marcellus gas or even Barnett gas. You’re getting Henry Hub minus. Right now it’s Henry Hub minus 30 cents, but there are some structural issues at play in Western Canada which are really going to affect that basis.
“One is the Ruby Pipeline will be built from the Rockies into Malin [OR], which will displace between 700 and 900 MMcf/d of gas back into Canada. And because of structural issues again on the TransCanada pipeline, the toll is very high and that gas doesn’t want to clear. Canadian pipelines can’t discount their tolls to increase volumes, so you have basically a fixed cost on the pipeline divided by less volume flowing through the pipe. So business as usual, we see about 2.6 Bcf/d coming out of the Horn River play.”
Kallio said British Columbia has done a good job on the regulatory side. Roads are getting built and infrastructure is in place to support development of the province’s gas resource. “They’ve put in place a very good royalty regime… production is really growing on this side [of the plays].”
However, despite the unconventional supply growth, it won’t be enough to overcome declines from conventional production.
“Even though tight gas and shale gas will come on, it’s not going to offset completely the declines in the conventional and also the declines in the coalbed methane activity in the basin,” Kallio said. “We’ll be down to 13.9 Bcf/d out of the basin. We’re a little over 14 [Bcf/d] now, 14.3…We peaked out at 17 Bcf/d in 2001 or 2002… It’s really a story of decline in Western Canada. We do not expect this to really improve until we see higher gas prices North America-wide.”
Overall, Kallio said Ziff projects that North American shale plays will be producing 27 Bcf/d by 2020. “The shale gas is growing,” he said. “By 2020 we’ll be an 82 Bcf/d market. Shale gas will be roughly a third of that, over a third of that.”
Ziff is about to embark on an in-depth study of the Marcellus Shale and its impact in the Northeast.
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