CSUR Montney Event Hears About China’s Natural Gas Matters

Among the risks facing Montney producers is the behemoth would-be LNG customer in China increasing its own domestic natural gas supply — something easier said than done, according to Aaron Engen, vice-chair of BMO Capital Markets.

“I have had conversations with some of the producers there, and they know there are lots of reserves in Western China,” he told last week’s Canadian Society for Unconventional Resources (CSUR) B.C. and Alberta Montney technical session. “There are three things they have been trying to tackle as they think about developing that region of Western China.”

Firstly, he said, Chinese producers must understand the fracking technology necessary to unlock the country’s vast hydrocarbon reserves, which is in part why China’s larger firms participate in Western Canada’s energy industry: They are gaining knowledge of North American hydraulic fracturing techniques.

“The second thing they’re looking for is infrastructure. There is no way to move gas from Western China into the East. Have conversations with the [National Resource Commission] or [National Energy Administration] in China, and they will talk about building out energy infrastructure, pipelines, gas processing facilities, and the like to move gas west to east. Interestingly, they’re planning on doing it in a very different way.”

Rather than centrally planning pipelines and processing facilities, Engen added, Chinese regulators are letting developers develop projects on an economic basis, determining midstream needs and then building infrastructure.

Most notably, he noted, the third, “more tricky” issue that China must resolve in order to produce domestic natural gas is supplying the large volumes of water necessary for fracking in the relatively waterless area where those reserves reside in the western part of the country. He said: “Something has to be done there.”

Diluent dilemma: More Montney risk factors

Closer to home, another risk facing Montney producers in 2020 is “a bit of a shake-up” expected in the condensate market over the upcoming months due to changes in oilsands diluent demand, suggested Nathan Nemeth of Wood Mackenzie Ltd.

“Diluent is a big business,” the WoodMac researcher told the CSUR event. “In 2018-19, [oilsands producers paid] nearly US$14 billion moving and buying condensates, and that is why we see a lot of operators talking about reducing their diluent demand.”

For 2020, he noted, the diluent market faces the prospect of several diluent recovery models, with recovery units sending back more diluent for reuse and thus reducing the overall diluent demand. Nemeth highlighted one proposed Bruderheim project that would see a 30-per-cent blend ratio reduced to less than five per cent.

“The other thing oilsands producers are talking about is partial upgrading. A lot of them have been looking at this technology,” Nemeth said. “When you add it all up from just [three projects] it is 110,000 barrels per day of condensate that could stay in Alberta. And then there are other risks as well for the diluent market.”

Condensate is very important to Montney economics, he added, but actually tracking down where those liquids are coming from has been very difficult for analysts. “You can look at financial reports, but often when you go back to the well data it’s hard to reconcile condensate production possibilities from the reports you see on the well data.”

Despite all the issues, Nemeth said that the Montney keeps Canadian energy production growing or relatively flat, largely due to economics based around the liquids-rich resource. “The Montney is the biggest source of production growth in the WCSB, and understanding the economics of that is crucial when trying to determine your AECO prices.”

Currently, he noted, half of this valuable Montney condensate comes from two operators — Seven Generations Energy Ltd. and Ovintiv Inc. Along with a handful of other operations, the “top 10” companies account for about 75 per cent of condensate production. The analyst said many of these firms could boost their production with ease.

“While two producers produce the majority of the condensate, we have a whole bunch of smaller operators whose volumes are not as large, and for them to actually increase their production, it would be relatively easy.”

Completions matter: Operators seek continued Montney optimization

The shale industry has invested significantly in optimization over the last 10-15 years, noted Erfan Sarvaramini, GLJ Petroleum Consultants Ltd. geomechanics consultant. The primary reason for this: Good production and performance always follows an excellent completion. Considering some of the heavily-studied design parameters, proppant tonnage and intensity likely top the list, he said.

“I’m not sure exactly how much increasing proppant tonnage intensity will influence the performance — [initial production] and [estimated ultimate recovery]. Does it double it, triple it? … Nobody knows. It’s a difficult question, but what we know for sure is the demand for proppant has been significantly increasing over the last 10 to 15 years.”

For the British Columbia and Alberta Montney, pumping rates have the most impact on performance, he said, and geomechanical properties are key for well design, because that impacts the dynamic of fracturing — from stage spacing to proppant transport to fracture geology.

Despite the focus on well completions over the past 10 to 20 years, the industry still sees wellbore stability problems in the Montney, and this often-overlooked factor represents the most obvious place to keep saving money on these wells, according to Amy Fox, geomechanical consultant with Enlighten Geoscience Ltd.

“We are in a very tectonic basin here, and so it’s important to build an accurate geomechanical model, and stresses can vary significantly as you get closer to the deformation front,” Fox said. “And so, Montney wells in one location won’t be the same as in another location.”

She added: “Although it can be difficult to find, there’s usually sufficient data out there in the public database to build a geomechanical model so you can start optimizing things. Once you’ve done that geomechanical model, doing wellbore stability predictions is simple. It’s very easy, and can make a big difference to your drilling program.”

According to Farhan Alimahomed, regional technology domain manager for OneStim at Schlumberger, an expedient means to formulate subsurface analysis is what industry is missing in the Montney. He said: “We need to turn some of these long-term workflows to do them quicker.”

In order to speed up the pace, he added, industry should remember models are just subsurface simplifications. As such, striving for a “100-per-cent answer” and “closing the loop” to account for completion designs, well spacing and stacking, along with all other elements, is not as key as simply trying to “get in the right direction” on these wells.

 “We cannot capture the complexities that exist in the ground. They’re the best tools we have today, and if we can use the best tools we have today to see relative differences between the various cases, then I think that will really help us drive in certain directions rather than others.”

Montney leverage: Why Canadian LNG has an edge

Canada has a shipping advantage in terms of selling its LNG to foreign buyers in Asia, suggested the president and chief executive officer at Rockies LNG Partnership.

“We think that will be part of our leverage,” Greg Kist told the CSUR audience. “There are new technologies we are going to use to drive down capital costs. If we can do that, then we’ll have an opportunity to capture these growing markets. We must employ innovative solutions to drive down costs.”

The Rockies LNG solution: Floating liquefaction, storage and offloading. He said: “It’s not new, but it’s becoming more and more pervasive in international development. We believe that floating LNG has a really important place for LNG development in Canada, because it substantially reduces environmental impacts, especially in challenging terrain such as in northeastern B.C.”

He added: “In our case, what we’re talking about are three barges, with each of these barges capable of four million tonnes per annum of output, which means you would need about two bcf per day of feed gas for that entire plant.”

Regarding project timelines, the proponents view 2027 as when they hope to have that first barge in place, which means Rockies LNG needs a final investment decision (FID) sometime late-2022. “We’re just coming to the end of our feasibility phase right now. We hope early in Q2 we’ll be moving into the next pre-[FID] phase.”