uncoventional gas guide october 2011

October 2011

s p e c i a l i s s u e

in cooperation with

Fire in the iceTest well on Alaska’s North Slope holds promise that CO2 can be sequestered while producing gas from hydrates

Whatever happened to coalbed methane?Booms in oil and gas activity come and go, but the CBM resource abides

big boom ahead For neW brunsWick?Signs point to robust shale gas potential, though environmental concerns could block development

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Editor’s note 5 Unconventional gas: where and how much? 6Three keys to unlocking shale gas 7

g a s h y d r a t e s

Fire in the ice 8Test well on alaska’s North slope holds promise that cO2 can be sequestered while producing gas from hydrates

By Graham Chandler

t e c h n o l o g y .

The future of fracking 12industry game-changing multistage horizontal fracking has been with us for well over a decade now. Where does the revolution go from here?

By Graham Chandler

t h e m a r i t i m e s .

Big boom ahead for New Brunswick? 16signs point to robust shale gas potential, though environmental concerns could block development

By Wes Reid

F r a c s a n d

Location, location, location 22sourcing frac sand closer to northeastern B.c.’s shale gas plays is key to stikine energy’s supply strategy

By R.P. Stastny

c o a l b e d m e t h a n e

Whatever happened to coalbed methane? 26Booms in oil and gas activity come and go, but the cBM resource abides

By R.P. Stastny

Advertisers’ index 30

on the cover: A single shale gas well in the Pennsylvania Marcellus.

photo: Chesapeake Energy

3O c T O B e r 2 0 1 1 o i Lweek s p e c i a l i s s u e

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there seems to be widespread recognition—in the industry at least—that shale gas is the future of the natural gas industry in North America, if not the world.

According to Energy Information Administration (EIA) esti-mates, technically recoverable shale gas reserves in the United States amount to around 862 trillion cubic feet. Mexico (never before a strong gas nation) has 681 trillion cubic feet. And Canada, the EIA says, is blessed with 388 trillion cubic feet (the Canadian Society for Unconventional Gas puts our marketable shale gas reserves somewhere between 128 trillion cubic feet and 343 trillion cubic feet). That’s nearly 2,000 trillion cubic feet in North America, or about a third of the estimated 6,622 trillion cubic feet of recov-erable global shale gas reserves, a number that slightly exceeds world proven conventional gas reserves of 6,609 trillion cubic feet.

It’s no wonder, then, that shale gas is being touted as the fuel of the future, the fuel that many say will carry us to a sustain-able nirvana powered by green technology, free at last from the shackles of dirtier hydrocarbons like (gasp!) oilsands bitumen, or bloodier hydrocarbons like (gasp!) oil from Nigeria or Yemen or Libya or Iraq or Iran or…well, you get my drift.

But somehow, that message just isn’t getting through, and the protest movement against shale gas is growing daily, at times appearing to rival the Greenpeace-led efforts to somehow stop the oilsands industry dead in its tracks.

At first, the voices were but a murmur: water wells in Pennsylvania were shown to be suddenly contaminated with methane, and environmentalists and documentarists were quick to point the finger at producers poking wells into the Marcellus shale, which spreads across parts of eight states and holds an estimated 84 trillion cubic feet of recoverable shale gas.

But this past summer, the protests spread north of the bor-der, and while not quite on the scale of the Freedom Summer civil rights protests in the United States a few decades ago, the naysay-ers are gaining strength in numbers, and spreading, especially in eastern Canada, where experience with living alongside oil and gas activity is limited.

In Quebec, 700 protesters embarked on a month-long trek from Rimouski, in the eastern townships, to Premier Jean Charest’s Montreal office, where they demanded a 20-year moratorium against shale gas developments. The government had already implemented a 30-month moratorium on work in the Utica shale gas (as much as 60 trillion cubic feet of recoverable reserves), but that wasn’t enough for the “Moratorium For A Generation” organ izers, who did not want to leave a legacy of “polluted water, contaminated air and noise to the next generation.”

In New Brunswick, protests erupted in April against plans by SWN Resources Canada Inc. to conduct geochemical and geo-physical surveys across a wide swath of land extending from Charlotte County, west of Saint John, to Northumberland and Kent counties, northeast of Fredericton.

Protests simmered over the summer, culminating in a two-day blockade of seismic equipment on a road north of Stanley in mid-August, and vandal attacks against other SWN Resources seismic equipment. In the wake of those actions, the company decided to suspend New Brunswick operations until next year, fearing for the safety of its employees and its equipment.

It’s been a hot summer for the shale gas business in Canada. I’m not sure winter will offer much relief. I — Dale Lunan

Hot summeralthough not quite to the scale of Freedom summer, shale opponents are sounding out


s e c t i o ne d i t o r ’ s n o t e

Unconventional gas: where and how much?

shale gascanadian shale gas resources are concentrated primarily in the Western Canadian Sedimentary Basin, but potential also lies within Quebec in the Utica play, in the Central Maritimes Basin in New Brunswick and Nova Scotia, in the Mackenzie Valley corridor in the Northwest Territories and in the Liard Basin in the Yukon. In northeastern British Columbia, the most advanced shale gas plays are found in the Horn River Basin and, to a lesser extent, in the Cordova Embayment. A number of companies exploring in these regions have advanced their exploration efforts to a point where pilot pro-jects with multiple wells have been completed, and natural gas is being produced and sold via the Spectra pipeline sys-tem. Large-scale commercial development will be dependent on market conditions. Current exploration and production is constrained by poor market conditions, but two new emerg-ing plays in Alberta are the deep Duvernay Formation and Colorado Group shales located in the western part of the prov-ince. Limited testing has taken place with encouraging results, but no commercial projects have been developed to date. The hydrocarbons that have been produced from the Duvernay tests suggest that there is a significant li quids and oil component associated with the gas production.

Current estimates suggest original gas-in-place reserves in Canada of some 1,111 trillion cubic feet of shale gas, with the marketable potential ranging from 128 trillion cubic feet to 343 trillion cubic feet. I

tight gasthe Western canadian sedimentary basin is host to most of canada’s conventional natural gas resources, and within this basin the northern and western regions con-tain much of the tight gas potential. Total original gas in place (OGIP) is estimated at 1,311 trillion cubic feet. Other regions within Canada, specifically the Mackenzie Delta in the Arctic and the Albert Formation in the Maritimes, are believed to have tight gas resource potential, but no estimates have been made due to lack of geo-logical data. While the OGIP value is very large, only a portion of these resources are deemed technologically recoverable. Marketable resources are estimated at between 230 trillion and 509 trillion cubic feet, with half attributed to the Deep Basin and the Montney in Alberta, and the rest to various accumulations in northeastern British Columbia. I

CBM resources map

natural gas from coalthe total natural gas from coal (ngc) potential (original gas in place) in canada is esti-mated at some 801 trillion cubic feet, with most located in the Western Canadian Sedimentary Basin. Marketable resources for NGC are defined as those recover able resources that are feasible to be produced using existing technologies, as well as resources that are not constrained by environmental or stakeholder issues that may restrict access to resource development. Marketable resource potential in Canada has been estimated at between 34 trillion cubic feet and 129 trillion cubic feet, although the marketable potential in British Columbia (between four trillion and eight trillion cubic feet, against gas-in-place estimates of some 84 trillion cubic feet) has been discounted significantly, due to environmental or stakeholder issues that could impact access to the resource. I

Tight gas resources map

Shale gas resources map

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HYDRAULIC FRACTURING

Shallow groundwater aquiferDeep groundwater aquifer

Protective steel casing:Steel casing and

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Municipal water wellPrivatewell

Surface gas-well lease

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Induced shale fractures

Note: Buildings andwell depth not to scale

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Three keys to unlocking shale gas

What is hydraulic fracturing?hydraulic fracturing is the process of transmitting pressure by fluid or gas to create cracks, or to open existing cracks in hydrocarbon-bearing rocks, thousands of feet underground. The purpose of hydraulic fracturing an oil or gas reservoir is to enable the oil or gas to flow more easily from the forma-tion to the wellbore.

Multistage fracturing, the latest evolution in hydraulic fracturing, involves the segmentation of the horizontal leg of the wellbore. Each stage is isolated using either plugs or packers so that fracture energy, applied to the wellbore from the surface fracturing equipment, is concentrated within each stage. The result is the creation of extensive fracture patterns that allow the oil or gas to flow more easily to the wellbore. Stimulation procedures are applied to each stage individually.

Industry has a strong track record of safe development, demonstrated in hundreds of thousands of wells drilled throughout North America during the last 50 years. Still, the reality is that there are challenges associated with the level of public anxiety, specifically where hydraulic fracturing is concerned.

Canadian regulators and the natural gas industry are focused on the protection of surface and groundwater. A key element of successful hydraulic fracturing is proper well construction, which will ensure that groundwater is isolated from the wellbore and protected from completion and pro-duction operations. I

Source: Canadian Society for Unconventional Gas

What is horizontal drilling?the first stage in exploiting shale gas resources involves drilling a vertical well to a predetermined length above the shale gas reservoir. The well is then drilled (kicked off) at an increasing angle until it meets the reservoir interval in a horizontal plane.

Once horizontal, the well is then drilled to a selected length, which could extend as much as 2,500 metres. This portion of the well, called the horizontal leg, allows signifi-cantly increased contact of the wellbore with the reservoir compared to a vertical well. I


What is microseismic monitoring?operators use microseismic technology to observe the develop-ment of vertical and horizontal fractures in the rock formation in real time. Measurement of microseismic events that are occurring as the fracture stimulation takes place is important because adjustments can be made during the operation to ensure that the fractures created stay within the zone that has production potential.

Once completed, the microseismic model can be used to define the limit and reach of fracture stimulations in each wellbore and allow for optimal field development.

Industry will continue to advance technologies that will broaden unconventional resource opportunities, improve productivity and recovery potential, and allow for the environmentally, socially and economically responsible development of Canada’s unconventional natural resources. I


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t e c h n o l o g y

Ignik Sikumi #1 field trial wellsite in Alaska

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on april 28 this year, a drilling rig was released and moved off its ice pad on Alaska’s North Slope. Not so unusual, one might say. The Nordic-Calista Drilling Rig #3 was pretty standard but the well was something special. Dubbed the Ignik Sikumi—which in the native Iñupiaq language translates to “fire in the ice”—this highly instrumented research well could be the first field step to a process that would unlock trillions of cubic feet of pure methane gas from hydrates while sequestering CO2 to help combat global warming.

A 2008 report by the United States Geological Survey (USGS) estimated there are 85 trillion cubic feet of techni-cally recoverable natural gas in the form of methane hydrate deposits on the North Slope. That was more or less a highly educated guess; without extensive production and other critical data, it has to be. Considerable science and testing still needs to be done to refine and improve the figure and that’s where Ignik Sikumi comes in. And should its unique approach be successful, methane hydrate production would come with a huge bonus: reducing atmospheric CO2.

ConocoPhillips Canada operated the well under a research agreement with the U.S. Department of Energy’s National Energy Technology Laboratory (NETL). A complex and fully instrumented wellbore was needed to have available for field experiments, planned to start in the 2011-12 field season.

Once the well reached its planned depth of 2,597 feet, the full suite of wireline well logs were run: gamma-ray, resis-tivity, high-resolution density, neutron porosity, oil-based drilling fluid imaging, combinable magnetic resonance,

sonic scanner, and borehole resistivity scanner; followed by a series of pressure tests. Only then could it be completed, which was done with a fully instrumented tapered casing string that included downhole temperature and pressure gauges and a continuous Distributed Temperature Sensor (DTS) cable.

The wellsite was chosen for its multiplicity of test hori-zons—of varying porosity sandstones, which were already largely known and understood geologically. After all, a key to successful science experiments is minimizing the number of variables.

“You want to remove as much geologic risk as possible,” says Ray Boswell, NETL’s technology manager, Methane Hydrates. “You don’t want to be out exploring. You want to be where you have a good prior knowledge that the forma-tion exists in the condition you’re hoping to find it. And you want to be near a lot of existing wells and seismic.”

Now that it’s instrumented and ready, the well will be available for hydrate experiments starting this winter sea-son—most of them yet to be determined and approved—but the priority is the CO2 injection scheme.

The idea of injecting CO2 into hydrate-bearing forma-tions has been around for some time. But it hasn’t been until recently that lab testing and numerical modelling have established its practicality to the point where invest-ing substantially into a field trial could be justified. The lab and modelling studies, conducted by ConocoPhillips in partnership with the University of Bergen in Norway, have demonstrated the potential feasibility of exchanging CH4

Fire in the iceTest well on alaska’s North slope holds promise that cO2 can be sequestered while producing gas from hydratesBy Graham Chandler

>



(methane) for CO2 in porous and permeable sandstone reser-voirs such as these at the Ignik Sikumi location.

“This will be the first field test,” says Boswell, who explains the basics. “The basis for it is that a lot of gases will form hydrates in the presence of water in these unusually cold high-pressure conditions.” But CO2, he says, has a broader stability field—it is stable deeper and somewhat warmer. “So generally when the two gases are around, CO2 is the one water prefers to form the hydrate with,” says Boswell. “It’s the chemically preferred guest gas for hydrate formation.”

That’s how the idea got started. The scientific thinking was “if you bathed a gas hydrate in CO2, it would exchange, and that serves a lot of purposes including sequestration,” he says. So that led to some lab work bathing large masses of hydrates and CO2 gas, but at first it seemed much too slow to have any kind of a practical future. “But Conoco did some modelling with Bergen [which has some of the world’s lead-ing numerical modellers] and said, ‘We think it should occur much quicker than that if it is done in the conditions that you actually see in the field.’”

This took them back to the lab. “They put the gas hydrate into a porous media context, which means instead of bath-ing lumps of hydrates with CO2 they put the hydrates inside sand and then bathed it with the CO2.” It worked: they found that the rates were much higher. Moreover, it didn’t seem to produce a lot of free water. “So that is basically the reason they got interested to go to the field,” says Boswell.

But, he adds, “there is still a world’s difference between the lab and field. There are a number of physical things that go on downhole that require close control. One of the bigger challenges of the test is, unlike the lab, [that] it’s 2,000 feet down, so controlling everything that goes down the hole and back up is quite a complex challenge.”

So, assuming all goes well, plans are to build a new, smaller ice pad around the well early this winter drilling season—typically around Christmas, in Alaska. The well can then be re-entered and the casing perforated over the selected interval. From there, depending on weather, the team will have a 90- to 100-day season to conduct the experiment.

“That’s one reason we split the well drilling and the well testing into two years,” explains Boswell, “to maximize testing time.”

The general plan is to start with a nitrogen and CO2 mix injection and adjust the mix as the experiment pro-gresses. “There’ll be more nitrogen at the beginning and much more CO2 at the end,” explains Boswell. That’s because “the main scientific challenge is that if you inject CO2 into a hydrate-bearing formation directly, the major issue is injectivity—the sand is very porous, permeable but when it has hydrate in it that permeability gets very low.” So it’s yet unclear how easy it will be to inject the CO2. The biggest concern is that the remaining pore space is filled with free water and that could react with the CO2 and pro-duce a CO2 hydrate before it gets a chance to interact with the methane hydrate.

So the nitrogen gas is being injected first in an attempt to move some of that water out of the way. “We’ve done a lot of experimentation on just how to do that,” says Boswell. “The experiments have been favourable but it’s definitely a chal-lenge. It’s a lab project that’s been scaled up for the field. It’s nowhere near a technology demo or anything like that.”

After each injection there will be a soak period of about a week while the exchange goes on. “Then you shut it in, try and flow it back to see what you get back,” he explains. “The idea is, of course, [that] you should get back methane gas.” That would go on for about 45 days, and then the well would be depressurized. “We’re anticipating right now the 90 days’ operating time will be equally split between the exchange test and the depressurization test,” he says. “To find out what’s exchanged you have to reduce

Surface Conductor set @ 110 ft

10 3/4” Casing @ 1,473 ft.

Ground Elevation @ 53 ft; KB @ 31’ above ground

Fiber-optic DTS (Distributed Temperature Sensor) Cable (clamped to outside of tapered casing string)

Tapered Casing String 7 5/8” x 4 1/2” (crossover from 2,027 ft to 2,051 ft)

Triple “flat-pack“ Tubing(attached to outside of

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Low-temperature Cement

4 1/2” Pressure-Temperature Gauges

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4 1/2” Production Tubing

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No Vertical Scale

D-sand @ 2,060 - 2,114 ft

Electronic cable for surface P/T readout

The Alaska Ignik Sikumi #1 test well was completed specifically with future research in mind.

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the pressure in the well and create a gradient for fluid to flow towards the well.”

Although world leaders in gas hydrates research, Canadian scientists aren’t taking part in this test project.

“Canada declined the invitation to participate in the ConocoPhillips planning team, given Natural Resources Canada’s current R&D [research and development] activities and commitments,” says Scott Dallimore, research scien-tist at the Geological Survey of Canada, who headed up the international team in 2001-02 and 2007-08 at the Mallik hydrate test well in the Mackenzie Delta.

Dallimore did however have the chance to review the ConocoPhillips project and other ongoing research in this field, and agrees it has promise. “While the concept is very appealing, I anticipate that main challenge will be in scaling up from idealized laboratory-scale studies and theoretical modelling, to the field scale,” he says. “I think the ConocoPhillips effort will be an important first step to scope out the feasibility. However, it is likely just a starting point as this production method is, of course, quite complex. Practical engineering issues will have to be dealt with and geologic/geochemical processes quantified at a field scale.”

Boswell would agree. “It’s a small-scale thing; we prob-ably won’t impact an area of the reservoir bigger than a room,” he says. “But the idea is to get a controlled data set that you understand well enough so you can begin to cali-brate some of these numerical models that are predicting what happens in large areas over years.” Then it may go on to longer-term tests, multiple-well injections and production.

It’s not all Alaska, either. The U.S. Gulf of Mexico holds significant gas hydrates reserves for which NETL’s near-term plans are included too. The U.S. Minerals Management Service (now the Bureau of Ocean Energy Management, Regulation and Enforcement) in 2008 estimated there’s up to 34,000 trillion cubic feet of methane in hydrate form in the northern Gulf of Mexico—6,700 of that in high- concentration accumulations in sandy sediments in the type of reservoirs likely to be producible.

“In 2009 we did an expedition [in the Gulf of Mexico] with an industry group led by Chevron [Corporation] to try and determine just what are the resources that exist; we drilled seven sites and in four of them we found hydrates in sand reservoirs,” says Boswell. They had been overlooked (or avoided) by previous deepwater drilling.

“What we are hoping to do now is go back to those sites and collect samples,” he says. But gas hydrates are noto-riously hard to sample because once they’re out of their low-temp, high-pressure environments, they fizzle.

“By the time you get it to the ship deck, it’s gone,” says Boswell. “So you have to use pressure coring devices and take samples of pressure at depth.” He says NETL is working with Japan on producing a new tool kit for the purpose. “When these are built we hope to return and collect the samples.”

“But any time we need to do something in the Gulf of Mexico it’s not only expensive, because you’re in deep water, it’s also complex. But the marine setting, that is the next thing we want to do.” I



The future of frackingindustry game-changing multistage horizontal fracking has been with us for well over a decade now. Where does the revolution go from here?By Graham Chandler

multistage hydraulic fracturing has been the greatest game changer of the oil and gas industry in the past decade or so. Since the first successful slick water frac, in the Barnett Shale of Texas almost 15 years ago, it has been nothing short of a revolution. Impacts have been far and wide: economi-cally, environmentally, politically, technologically; all due to its promise of liberating a long-term reliable source of nat-ural gas—a relatively clean-burning energy source for the world. And it has allowed substantial new recovery of oil from wells previously deemed uneconomic.

In short, it has transformed the North American energy picture, and soon, the world. Where does it go from here?

“There are a couple of things,” reckons Dale Dusterhoft, chief executive officer of Trican Well Service of Calgary. “The producers are drilling longer wells and always trying to optimize their costs. And if you drill a longer well, that means you’re going to need to fracture it in more places.” Along with that, he says, there is a tightening of the stages,

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StackFRAC HD from Packers Plus could take horizontal multistage fracture stimulation to a new level of efficiency.

“so instead of the stages being, say, 200 metres apart they are 100 metres apart. And in some reservoirs, even closer than that, maybe 30–50 metres.” Many reservoirs are now at 30 –40 stages per well, he adds.

Dan Themig would agree on the outlook for more stages. The reason is “more stages seem to deliver better results,” says the president of Packers Plus Energy Services Inc. “I would say if there’s one thing that’s going to drive us into the future, that’s going to be it.” He recently wrote in the Journal of Petroleum Technology that it appears that the key to suc-cessfully producing economic, long-life wells in many of these reservoirs may be performing even 50–100 fracture treatments to achieve good drainage. But “the good news,” he wrote, “is that it appears that effective drainage can be achieved with far smaller fracture treatments on a per-stage basis.”

That runs counter to what has been happening, Themig says. “The industry adopted horizontal multistage frack-ing so quickly that they kind of took a blanket philosophy to everything—whatever they did in the Barnett shale, they simply tried to apply everywhere. I have heard it referred to as the ‘sledgehammer’ effect: more water, more sand, more horsepower.” He doesn’t think that’s the way of the future. “It’s good for hydraulics and unlimited horsepower and for the sand producers, etc. but ultimately the bang for the buck diminishes pretty quickly. What we’ve found is that the drivers behind bigger frac jobs and more water are not necessarily the most effective drivers. We can’t drain as big an area as people had hoped with a single horizontal well.”

Increasing the stage numbers and less “sledgehammer,” Themig says, has been borne out in the Montney Basin, for example.

“They found they were pumping far too hard, so on a per-stage basis they cut the fluid and the proppant in half, increased the stage numbers as well so the overall fluid usage was considerably lower on the whole well, and on a per-stage basis it was less than half. So what they found is they made wells better than ever by increasing stage numbers. And so if I had to tell you anything across the board that we have seen as far as effectiveness, it is not big-ger jobs and more sand, it’s more stages that tend to deliver better ultimate recovery. We think that’s the direction the industry is going.”

With its new technology deployed, Themig says that Packers Plus is “in 40- to 60-stage territory, with plans for 100-plus, probably sometime early next year. It is a huge advance in efficiency, allowing an operator the capabil-ity to vary stage numbers to get to whatever the optimum is.” This will be a godsend for long-reach extended laterals, he figures, such as the 14,000-foot horizontal his company recently completed in North Dakota. In the Bakken, the com-pany also completed wells with dual and triple laterals, “so multilateral wells with multistage fracking is another thing we see in the future,” Themig adds.

Themig sees more multistage fracking put to use in pro-lific reservoirs in the future, too, such as the Swan Hills carbonate reservoir. Already prolific, drilling on the flank >


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areas where they could never make a commercial well before, some he says are sustaining 500 barrels per day. “We are doing work in Saudi Arabia, the Black Sea, West Africa with open-hole techniques in prolific reservoirs to where you can not only get great initial productivity, but effectively drain both the prolific and the really tight parts of the reservoir.”

Packers Plus–type open-hole completions aren’t the only way to frac horizontally; there are also cased-hole comple-tions. Separate camps in the industry favour one or the other; the choice often depends on the application. But both technologies are moving forward.

“We are using our mechanical devices with coiled tub-ing and it has turned into quick and efficient technology,” says Brad Rieb, director of technology for Baker Hughes’ Canadian Region. “I would say that probably still repre-sents—and it has been refined—the biggest step forward in the past year.” He says quietly behind the scenes that Baker Hughes has advanced its devices to third and fourth genera-tion. “They are almost a riskless wellbore intervention now.”

These technology advances permitting higher-stage numbers lead to advances in water and fluid handling. “I would say the majority of the technological developments we’ve been working on in the last few years has been to clean up our fluids,” says Trican’s Dusterhoft. “We have flu-ids that you can mix with drinking water and pass drinking water standards tests.”

Continued action on environmental protection is para-mount for the future of fracking, lest public opinion and

demands crimp it severely. Disclosure and compliance of frac fluids lead the pack.

“What we see in western Canada in the latest compliance issues is the recording of frac chemistry for the purpose of public disclosure,” says Baker Hughes’ Rieb. “We are now gladly participating in a harmonization of a database mani-festing all of the chemistries that are used. That is ongoing in the U.S., and evolution has taken it to Canada. For exam-ple, the BC Oil & Gas Commission uses the same database as in the U.S. It’s for transparency.”

Also helping address environmental issues is the bur-geoning field of stimulated reservoir simulation.

“As we go forward, you’ll see a lot more scientific approach to developing these reservoirs than what I would call the brute force approach,” says Trican’s Dusterhoft. “You will see more fine-tuning of treatments, and one of the tools for that is microseismic.”

Microseismic is, in fact, one of the hot research and development fields now and will play an increasingly active role in the fracking process going forward.

“Two main stakeholders are encouraging the demand for microseismic: geoscientists, who want to incorporate the data into a reservoir model for a more accurate under-standing of behaviour during production, and engineers requiring real-time understanding of how to cost-effectively and efficiently stimulate the well with hydraulic fractur-ing,” says Emmanuel Auger, microseismic technical advisor for CGGVeritas. “The two audiences have similar and yet

t e c h n o l o g y


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different needs that are driving the next phases of research and development in the field.”

There’s strong demand from both camps to provide real-time data and processing in the field to support opti-mal fracking. “If an operator can monitor the reactivity of the reservoir during stimulation, they can potentially adjust and modify the pressure and fluid injection accordingly and optimize the program’s effectiveness,” says Auger. “This is a significant improvement because it requires advanced pro-cessing capabilities, new technology and in-field expertise on site during drilling.”

Research and development on realistic synthetic data will estimate the sensitivity (determining the smallest event that can be imaged) and the uncertainties on several parameters, says Auger. The uncertainties include the position of the event, type of focal mechanisms and fracture orientation. “The microseismic community is striving to deliver more than just the time and position of the microseismic events, i.e., to go ‘beyond the dots.’”

Focal mechanisms, he explains, bring a wealth of infor-mation such as whether cracks open and close or just slip, the state of the local stress, the orientation of the cracks and further evidence of possible tectonic fault activations. Says Auger, “They enable adjustment of field models and when combined with real-time drilling data can help guide a well in the optimal production zone during hydraulic fracturing.”

Moves forward include the installation of permanent arrays that can make it possible to monitor several wells over

a long period to detect gradual variations in the reservoir and aid overall production optimization. “This is another area that CGGVeritas is actively researching,” says Auger, “and also one where we have seen much success and an increase in demand for our SeisMovie technology—perma-nent buried sensors and sources that capture variations in the reservoir over a long period of time.” These are expected to be applied to microseismic monitoring in the near future.

Also, “we are also intrigued by the potential that micro-seismic could offer to management and mitigation of the environmental concerns that have been voiced around unconventional reservoirs,” Auger adds.

Finally—on the non-tech side—a real threat seen limiting growth in the fracking industry is the looming labour short-age. “The industry in Alberta is faced with a growing crisis in labour availability,” says Baker Hughes’ Rieb. “If you look at the capital that is dedicated to expansion in the services and supply businesses, it is staggering and the common denomi-nator is people—to run trucks, drive trucks, load trucks, work in warehouses, blend and package chemistries, and run rigs.”

Rieb figures that in order to address that shortage, the industry will need to get away from the massive dedicated manpower it takes to do the large stimulations. “You can have 60 people on location,” he says. “We need a way to reduce that, to reduce the footprint, to have one person just do more. There will be pressure to reduce that entire service sequence. There has to be a way. Sometimes I think it would be easier to do these jobs on the moon than some of the areas we work in.” I


t e c h n o l o g y

GLJ Petroleum Consultants

Big boom ahead for New Brunswick?signs point to robust shale gas potential, though environmental concerns could block developmentBy Wes Reid

shale gas activity may transform new brunswick into less of a have-not province. But environmental activists could block the way.

“We see a big boom here…probably three or four years down the road,” says New Brunswick Natural Resources Minister Bruce Northrup from his office in Fredericton, the province’s capital. “We’re into a lot of the seismic testing right now and a couple of exploratory wells this year, maybe a couple next year, and maybe a couple a year after that. To get the full 100 per cent development out of this, we’re look-ing at 2015, 2016.”

Throughout the past decade, technology advances in shale gas extraction have helped the hydrocarbon sector fea-sibly exploit the resource.

“It’s where all the growth in gas production in North America is coming from,” says Phillip Knoll, president and chief executive officer of Corridor Resources Inc.

The junior resource company has about 325,000 net acres of land leased in the Sussex sub-basin and the adjacent Elgin sub-basin in southern New Brunswick.

Corridor also has interests in Anticosti Island (891,906 net acres), Prince Edward Island (264,129 net acres) and an

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offshore prospect called Old Harry, encompassing 127,948 net acres of Newfoundland seabed, and 123,550 acres of Quebec seabed. It sits in the Gulf of St. Lawrence.

“We’ve got three major [exploration] projects we’re work-ing on and some existing production,” says Knoll. “Our existing production is out of our McCully field in New Brunswick. We’re producing about 16 million cubic feet a day of natural gas through conventional means. Also in New Brunswick we have our shale gas play and it is in the same vicinity as our McCully gas field. We also, of course, have a shale oil play on Anticosti Island.”

McCully is located near Sussex, a town that began experiencing economic resuscitation in 2007 when Corridor connected it to the Maritimes and Northeast Pipeline system.

Approximately 30 wells, tapping the field’s Hiram Brook tight sand reservoir, provide (via the pipeline) U.S. markets with about 16 million cubic feet of gas daily.

Stretching 1,400 kilometres, the Maritimes and Northeast Pipeline System was completed in 1999 to deliver natural gas across New Brunswick to markets in the northeast-ern United States from the Sable Offshore Energy Project (SOEP) in Nova Scotia. It carries 400 million to 450 million cubic feet of natural gas per day.

“That pipeline takes gas into markets in the Maritimes, but it also exports gas into the New England market, so we are ideally situated in New Brunswick to put gas into that system,” Knoll says.

Corridor’s shale gas play is occurring at the Lower Carboniferous Frederick Brook Shale structure cutting through the Elgin sub-basin.

The company partnered with Apache Corporation in 2009 as part of a two-phase exploration program employing horizontal drilling.

Apache spent $25 million during the first stage of the exploration but cut its losses by bowing out of the second, because the partners found insufficient resource in two wells they drilled at Elgin.

At the time, Apache Canada’s spokesman, Paul Wyke, said, “You know, cut and dry, the method we used to attempt to stimulate the wells didn’t work.”

The second phase, scheduled to last until 2013, would have cost Apache four times the amount it dished out for the first phase.

This has not fazed Knoll. His company is using part of McCully’s revenues to finance, at $25 million, natural gas exploration of Frederick Brook Shale.

“That provides us cash flow to help us move along these much bigger resource plays and the one of interest in New Brunswick is the Frederick Brook shale,” Knoll says. “We drilled a number of wells into the Frederick Brook shale and had some very impressive results, particularly in the Elgin area where we had a vertical well that had a small propane frac applied and it produced at 12 million [cubic feet] a day, peak rate.”

Corridor’s Elgin property has a resource estimate of potentially 67 trillion cubic feet of shale gas. The company plans to sink possibly two exploration wells there this fall.

“Early next year we’ll be doing some propane fracking on the wells we drilled and potentially some of the other wells in the area…to demonstrate how the area can be developed into a pilot project for shale gas development,” Knoll says.

mad about harryCorridor also has prospects at Anticosti Island near the mouth of the St. Lawrence River as well as at Old Harry, lying offshore in the Gulf of St. Lawrence between Newfoundland and Quebec.

“Old Harry is a massive structure and could conceivably hold a very large resource,” Knoll says. “At Anticosti, we’ve got a very large potential of shale oil. It’s in the range of 40 billion barrels of potential resource, but we have to do a lot of work going forward to determine if it can be extracted.

In February, we applied to the Canada-Newfoundland and Labrador Offshore Petroleum Board for the rights to drill an exploration well into the Old Harry structure sometime late in 2012 or probably 2013.”

Industry players are well aware New Brunswick is a socially, politically and economically stable region possibly

“That pipeline takes gas into markets in the Maritimes, but it also exports gas into the New england market, so we are ideally situated in New Brunswick to put gas into that system.”

— phillip Knoll, president and chief executive Officer, corridor resources inc.

Corridor Resources has a variety of development options throughout the Maritimes, from onshore assets in New Brunswick and Prince Edward Island to offshore prospects in the Gulf of St. Lawrence.

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holding more than 80 trillion cubic feet of natural gas and bordering the United States, a country possessing a plethora of available markets.

In addition, the province has a pipeline system in place, a competitive royalty system and a history of oil and gas pro-duction dating back to the 1850s.

Between 1850 and sometime in the 1870s, shale was mined for bitumen from the Albert Formation in New Brunswick and shipped to Philadelphia and Boston. The bitumen was distilled to produce kerosene.

On April 7, the provincial government unveiled an action plan comprising seven components, for managing exploration, development and production of natural gas in New Brunswick.

“Work on these components will take place concur-rently and in a coordinated manner by a multi-departmental working group that will ensure all of government has input into this process,” says Northrup. “We expect most of this work will be done over the next six to nine months, with the objective of ensuring [that] a safe and economically sound approach is in place, should development move forward in New Brunswick.”

The framework, if successful, could manifest numerous fiscally positive outcomes for the province’s public and pri-vate sectors.

“We’re wrestling with a $10-billion debt here, right now, and our health-care costs are going up, education costs are going up and pretty well everything is going up and noth-ing’s coming down,” Northrup says. “If we can help the companies up and have it environmentally friendly to the province of New Brunswick, I think it’ll be great for the province to have these royalties coming in.”

His Liberal opposition is demanding a moratorium be placed on shale gas play.

“We’re not saying ban the industry,” says Liberal leader Victor Boudreau. “We’re saying hit the pause button. Obviously, government is hungry to get these royalty revenues and I can appreciate that because we are coming

out of the worse financial crisis we’ve seen in 70 years, but that being said we can’t do it at the expense of our drinking water.”

While in government, his party leased 2.52 million acres of New Brunswick land to SWN Resources Canada Inc., a wholly owned subsidiary of Texas-based Southwestern Energy Company. The parent company was the first to extract shale gas and conventional gas from the highly pro-ductive Fayetteville Shale structure in Arkansas.

SWN’s acreage is situated north of Corridor’s properties in an area relatively unexplored.

It is investing $49 million exploring the property for gas—shale and conventional—over a three-year period. SWN completed a geochemical program designed to examine the hydrocarbon potential of its holdings. The information has been integrated into the evaluation of sub-basins optimizing the positioning of a 1,000- to 1,300-kilometre 2-D seismic survey.

That work has been completed, but the company will con-tinue with other 2-D seismic plans to test drill in places with the highest potential based on seismic data gathered.

“The exact timing and locations of any potential wells have not yet been determined and are pending Environmental Impact Assessment approval,” the SWN website states. “We expect to propose a drill location by the fourth quarter of 2011.”

Geologist Randy Ponder is vice-president of New Ventures at Southwestern Energy. He says: “It’s a nat ural extension of the expertise that we’ve gained in the Fayetteville and the Marcellus. The Frederick Brook Shale compares quite favourably to some of the shales that we’ve worked, including the Fayetteville, the Marcellus and the Haynesville. In fact, the Frederick Brook Shale’s TOCs [total organic carbons] are richer in places than any of those shales.”

Irrespective of Apache’s pullout, Ponder is optimistic about New Brunswick’s prospects as a shale gas region.

In the wake of protests and vandalism, SWN Resources Canada has decided to withdraw from evaluating its extensive New Brunswick holdings until next year.

“i would like to see it banned [permanently], because i’m going to be honest here, it makes me nervous if government gets to make decisions with industry without having to go before the people. a moratorium is one of these things a government can lift quite easily.”

— debra hopper, resident, Kent county, New Brunswick

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“Although we’ve just started the exploration phase, if suc-cessful, New Brunswick is going to be a significant part of Southwestern Energy’s business,” he says.

SWN bought into the province nearly two years ago when the Liberal Party was governing. Petroleum activity then had fewer regulations. The party, now in opposition, claims it is worried that fracturing rock to extract gas might contaminate drinking water.

David Pryce, vice-president of operations for the Canadian Association of Petroleum Producers (CAPP), believes the concern is unfounded.

“In New Brunswick, gas-bearing shale formations are typi-cally found between 2,000 and 3,000 metres below the surface,” he says. “That’s well below the level of fresh-water aquifers, which generally occur between 100 and 200 metres below sur-face. The vertical distance a hydraulic fracture will travel is from 30–100 metres, which means fresh-water sources are iso-lated from fracturing operations by significant distances and impermeable rock formations. The concentration of additives used in hydraulic fracturing fluid is less than one per cent.”

New Brunswick’s action plan includes three new regu-lations targeted towards hydrocarbon firms ambitious to explore, develop and produce shale gas.

Companies must conduct baseline testing on all potable water wells within a distance of 200 metres of seismic test-ing and 500 metres of oil or gas drilling before operations can commence. These requirements may be increased.

Companies have to provide full disclosure of all pro-posed, and actual, contents of all fluids and chemicals used in the hydraulic fracturing process, or fracking.

They must also establish a security bond to protect prop-erty owners from individual accidents, including the loss of or contamination of drinking water. Industry is left with the burden of proof.

The McCully natural gas field is New Brunswick’s lone commercial hydrocarbon development, but is not expected to be the last.

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“There are many special interest and environmental groups going around the province who have sensationalized this issue and only work on the emotional side. To hear that government is now saying, ‘OK, we need to have some pieces in place before we hit production level, and we are recognizing there needs to be proper protection in place,‘ …that is significant.”

— Bethany Thorne-dykstra, president, citizens for responsible resource development

Shale gas technology is not overly complex. Companies pump a solution containing water, sand and a small amount of chemicals at extremely high pressures against shale that has natural gas trapped inside it. This fractures the rock, releasing natural gas into production wells that pump the resource out into surface facilities.

In New Brunswick, nine oil and gas companies hold a total of 71 agreements to search for hydrocarbons on more than 3.4 million acres of land with SWN and Corridor lead-ing the pack in prospect ownership. >



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As shale gas activity grows increasingly popular throughout the world, these nine players salivate at the idea of striking the next huge reservoir in a province that has seen nearly $400 million applied to natural gas play since it began in 2000. Companies there expect to spend in excess of $200 million by 2013.

Another party excited by New Brunswick’s glowing hydrocarbon prognosis is its government. The province could reap royalties and tax revenues exceeding $250 million annu-ally, no small change for a jurisdiction groaning beneath a hefty debt and deficit.

show me the money?All the hoopla aside, industry and government there may never see shale gas revenue–flow grow. Citizens’ groups, environ-mentalists and political opposition parties, afraid that shale gas activity will contaminate water supplies, are mounting a cam-paign that could derail future shale gas play in the province.

“A lot of the information they’re hearing out there is absolutely incorrect,” says Tom Alexander, head of SWN’s operations in New Brunswick. “There is no widespread water pollution anywhere from these activities.”

Some protesters are calling for a moratorium on the activity while others remain dead-set against that sort of energy patch in their backyards, no matter how stringently government enacts and enforces regulations.

Debra Hopper and Paul Melanson, married for 38 years, are two such individuals. They reside in Kent County, a

breathtakingly bucolic area of New Brunswick canopied in clean air and perforated with crystal-clear lakes, ponds, riv-ers and streams.

“I’m reminded of the Joni Mitchell lyrics, ‘[they] pave[d] paradise, [and] put up a parking lot,’ only we’re look-ing at ‘frac paradise, put up hundreds of well pads’ [sic],’” Melanson writes in an email.

Hopper adds, “I would like to see it banned [perma-nently], because I’m going to be honest here, it makes me nervous if government gets to make decisions with industry without having to go before the people. A moratorium is one of these things a government can lift quite easily.”

Bethany Thorne-Dykstra upset, and may have set back, that movement last summer by taking a more moderate view of government’s plans for industry regulation. The president of Citizens for Responsible Resource Development had been protesting shale gas activity in her province, but after the provincial government unveiled its action plan and the three new regulations, she switched her stance.

“There are many special interest and environmental groups going around the province who have sensationalized this issue and only work on the emotional side,” she says. “To hear that government is now saying, ‘OK, we need to have some pieces in place before we hit production level, and we are recogniz-ing there needs to be proper protection in place, there needs to be a monitoring of this industry in order to make people better about this activity happening in their province,’ that is signifi-cant. And it really is what we’ve been asking for all along.’” I



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Location, location, locationsourcing frac sand closer to northeastern B.c.’s shale gas plays is key to stikine energy’s supply strategyBy R.P. Stastny

Photos: Stikine Energy

Water and proppant top the shortlist of essential ingredients for shale gas development, as they are critical to the comple-tions of long horizontal wells.

Water isn’t the problem in northeastern British Columbia. There’s plenty of that for pumping deep into the earth and cracking rock. The problem is finding proppant to hold those fractures open.

The most commonly used proppant is sand. Currently, some 900,000 tonnes of frac sand per year is pumped into the ground in the Montney and Horn River basins, but none of it is sourced locally. That’s because there aren’t any suit-able sand deposits in the region.

The closest quarry is in the Peace River area of Alberta, some 600 kilometres away. Frac sand is also shipped from Saskatoon, Sask., 3,200 kilometres away, from Nebraska and even from Texas—more than 5,000 kilometres away.

Producers may not like paying $200–$450 for a tonne of sand, especially when 80 per cent of that cost is in shipping the stuff, but soon there may be another option.

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Crushing site at the Angus pilot plant site

Stikine Energy’s two proppant sand pilot plants are located in the heart of British Columbia’s shale gas region.

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hard-rock mining know-howThe management of Vancouver-based hard-rock mining pub-lic company Stikine Energy Corp. runs a molybdenum mine near Revelstoke, B.C., a town that also attracts recreation-minded Calgarians, inevitably some of whom work in the oil and gas business.

“When we heard at the mine site about frac sand being imported up into northeastern B.C...I thought, ‘Who in their right mind would be paying almost $500 a tonne for sand?’” says Scott Broughton, Stikine’s president and chief execu-tive officer.

Running the numbers for the Montney and the Horn River basins, Broughton saw a $1-billion-per-year opportun-ity, with a runway of a quarter of a century or more. His idea was to find suitable quartz-pure sandstone deposits proxi-mate to the two giant B.C. gas plays, and use innovative but proven mining processes to liberate the sand grains for use as proppant.

The glacial history of northeastern British Columbia left a few sand and gravel deposits, but they are contaminated with many other minerals, making high-quality frac sand difficult to extract. So Stikine found quartzite rocks with sand grains that could be liberated by essentially accelerat-ing the erosion process.

“These deposits are remnants of what the glaciers scoured,” Broughton says. “They were strong enough to still stand proud in ridge-like forms.”

Stikine settled on two prospects. Its Angus deposit is about 100 kilometres southwest of the Montney Basin. The other deposit is called Nonda, about 150 kilometres northeast

of the Horn River Basin. Both were chosen for their proxim-ity, resource size and the suitability of sand grain size.

“Nonda is a massive deposit of essentially 100 per cent silica sandstone,” Broughton says. “More importantly, in its matrix, it has exactly what they’re pumping in the Horn River Basin, which is 40/70 sand and 100 mesh.”

The Angus is also a very large deposit of primarily coarser material: 20/40, 30/50 and 40/70-mesh sand. (The lat-ter is predominantly used in the Montney.)

off the shelfIn considering mining processes for liberating the sand from the rock, Stikine did its investors a favour by choosing a proven, off-the-shelf technology.

“We quickly came to this idea of an attrition process—specifically scrubbing,” Broughton says. “It’s a common piece of equipment at every frac sand plant in the world. It’s a wet process that uses impellers to bang particles into each other.”

The front end is a dry process that uses a vertical shaft grinder. That material is then mixed with water to create a slurry, which is driven by impellers to create particle-on-particle collisions, liberating the sand grains without actually breaking them.

“Water pressure controls that process,” Broughton says. “The water’s pushing up and gravity’s pulling down on these particles. We can do very good separation on the sand sizes and also remove the odd-shaped pieces and the grains that did break to achieve a high-quality final product.”

If breaking down rock into sand sounds energy-intensive, in the context of hard-rock mining and processing, it’s not. The deposits are at the surface, allowing for simple recovery from open pits.

More significantly, from the pilot work Stikine has done at its Abbotsford pilot plant, Broughton is impressed with how readily the sand grains liberate from their rock matrix.

This past July, Stikine took delivery of new motors and motor controllers for its Abbotsford plant scrub-bers. Broughton says that equipment is more efficient and moves its production of 40/70 mesh sand into full American Petroleum Institute spec.

“To date, we’ve worked with Nonda samples, but we also have 500 tonnes of Angus sample there and will show what kind of yields that produces,” he says.

In June, Stikine announced a strategic agreement with the Kaska Dena Council aboriginal group to advance the Nonda project. It now also has engagement agreements with other First Nations in the area. Parallel to that consultation work, Stikine is conducting baseline wildlife, vegetation and aquatic environment studies for each site.

So Stikine seems on track to potentially dominate frac sand supplies in northeastern British Columbia. Its geo-graphic advantage could result in frac sand costs being cut in half. That’s about $125 per tonne versus the current >

Raw material is fed to the crusher at the Nonda pilot plant.


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$250 per tonne. Even better for Stikine is that its markup at this price would be 100 per cent compared to the competi-tion’s 20 per cent markup at double the costs.

progress to dateStikine engaged Wardrop Engineering Inc. to help scope the project, provide economic assessments and to describe the project capital costs, from plant construction to roads and power transmission infrastructure.

“It’s actually been a really busy summer,” Broughton says. “We’ve now got Wardrop’s draft preliminary economic assessment for the Nonda project. So we should have an announcement [soon] on the size of the resource, a break-down on capital and operating costs, as well as a cash flow model. We hope to follow up with the same for Angus in about two months.”

Wardrop’s data will go into project descriptions detail-ing the size of the proposed mines and their outputs, which will allow it to file for regulatory permits. The permitting process is the single biggest indeterminate for investors, especially since permitting involves both federal and provin-cial agencies. But Broughton is optimistic about the pending year-long permitting process.

“British Columbia has had, in its recent history, some challenges with how the feds have responded to min-ing projects,” he admits. “However, Stikine’s management has strong mining experience, we understand permitting and, in comparison to metal-mining projects that involve leaching, water quality and other issues, this project’s en vironmental impacts are relatively benign.”

The idea of “more sustainability resource development” gets a lot of mileage these days. If Stikine can deliver on its promises of providing locally sourced frac sand, Montney and Horn River gas producers could eliminate the long hauling of

close to a billion tonnes of sand each year, reducing green-house gas emissions and improving road safety.

If Stikine’s price projections are in the right ball park, cut-ting frac sand costs in half could also improve the economics of the Montney and the Horn River basins compared to other basins closer to consumer centres south of the border.

And even if activity levels in northeastern British Columbia drop off, Stikine’s quarries, which have access to more resource than could ever be used in the Montney or the Horn River com-bined, could be shipped to other basins in North America. I

What to knoW70/40 mesh is between 0.212- and 0.425-millimetre sand grains.

20 mesh is 0.85-millimetre sand grains.

Sand costs represent about 15 per cent of a shale gas well completion in northeastern British Columbia.

Filling rock buckets at the sampling site Stikine Energy’s Nonda pilot plant

Liberated sand is sorted into desired size fractions, dewatered and bagged for storage.

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Whatever happened to coalbed methane?Booms in oil and gas activity come and go, but the cBM resource abidesBy R.P. Stastny

before the current light-oil resource play, before the shale gas boom that preceded it, and somewhere in between the first wave of the oilsands boom and the shale gas boom, there was another Alberta resource development boom: coalbed methane.

Coalbed methane is, of course, natural gas from coal (NGC). The preferred term for industry is, of course, CBM, presumably to differentiate it from its U.S. counterpart, which is mired in bad press to this day because of a dewater-ing issue, and the release of that water to the surface.

In the heyday of Alberta’s CBM development, in and around 2006, the estimated resource in place for the resource was estimated at 528 trillion cubic feet in the Western Canadian Sedimentary Basin. Production in 2006 was about 600 million cubic feet per day from over 6,000 wells. And growing. Fast.

About 95 per cent of those wells went into the Horseshoe Canyon Formation at the time. This relatively shallow basin east of Calgary boasts the uncharacteristic feature of being a dry coal, which means the coal seam yields its methane without having to first pump out water.

Most coalbed methane actually requires dewatering. The prolific U.S. coalbeds in the Powder River Basin of Wyoming are wet coals, for example. Regulators there at one time allowed this water to be released to surface, which caused much contention around depleted aquifers, flooded fields and degraded water sources—concerns that migrated northward to Alberta.

While these fears weren’t an issue in the densely popu-lated rural communities of Horseshoe Canyon, farmers were taken aback by the pace of CBM development, which one critic recently characterized as the natural gas industry “carpet-bombing some of the Alberta’s best agricultural land with 10,000 shallow CBM wells.”



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A multi-well coalbed methane lease near Barrhead, northwest of Edmonton.


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And yet today, there is remarkable silence around CBM development. It has completely fallen off the radar among media types. Industry conferences ignore the subject. And when analysts are asked to comment on coalbed meth-ane, they have surprisingly little to say. Here’s one such conversation:

“So whatever happened to CBM?”“I have no contribution to make,” says a major Calgary

firm analyst, who would probably prefer to remain anony-mous. “It’s been a long time since I’ve looked at the field.”

“So who in your company covers CBM? I was already referred to you by [X] in your firm. He says you’re the person to talk to on CBM.”

“And I was just about to suggest you talk to [X].”

evolutionIt is sometimes suggested that in an attempt to drum up funds, oil and gas producers often will chase plays that are unceremoniously dubbed “the latest flavour of the day.” And CBM in Alberta certainly saw a lot of producers jump on the bandwagon. However, when shale gas established itself in the last decade as a viable gas target, thanks to new horizontal well and multi-frac completions technology, CBM lost its lustre.

The reason was largely because of shale’s superior resource per well. It cost much more to drill and complete deep shale gas wells, but their initial production volumes were also quite astounding (in the millions-of-cubic-feet per-day range instead of, say, 100,000 cubic feet per day in the Horseshoe Canyon). That, combined with the vastness of northeastern B.C. in-place shale resource estimates, reduced CBM to a walk-on part in an entirely different movie the industry was now buying tickets for.

Another factor in CBM’s fall is the lack of opportunities it presents for improving its economics.

“If you look at what has been achieved by any of the oper-ators in the Horn River or the Montney in [British Columbia] and most of the shale gas operation in the United States, the operators have achieved significant improvements in production rates combined with reductions in capital and operating costs,” says Kevin Heffernan, vice-president of the Canadian Society for Unconventional Gas.

“In some cases, it’s a 40, 50 and 60 per cent reduction in capital and operating costs, whereas I think we’ve pretty much got coalbed methane costs down as far as they will go, and we’ve pretty much figured out how to maximize the pro-duction rates and IPs [initial production] from those wells.”

Even in the Mannville Coals, a deeper Alberta coal formation that typically also provides higher production rates, there is little room for improvement. The economics are further challenged by the coal’s dewatering require-ment. Dewatering runs in the face of what producers typically want, which is to pay out the well as quickly as possible.

From the heyday of CBM in Alberta, gas prices have seemingly normalized in the $4-per-thousand-cubic-feet range, and these low prices have forced some dedicated CBM public companies, such as Trident Resources Corp. and Ember Resources Inc., to restructure as private con-cerns in order to continue operating.

Shale gas producers don’t seem as hard pressed, although many are scrambling to find liquids-rich gas sweet spots to improve the economics of their production stream. And a few analysts question how enthusiastic pro-ducers in dry gas shale plays will be if gas prices remain at their low levels.

still some interestThat said, the sizable CBM resource in Alberta is still there. It just needs higher gas prices for producers to get excited about it.

Remarkably, Encana Corporation, Quicksilver Resources Inc. and others are still drilling CBM wells. At a Canadian

“i think we’ve pretty much got coalbed methane costs down as far as they will go, and we’ve pretty much figured out how to maximize the production rates.”

— Kevin heffernan, vice-president,

canadian society for unconventional Gas

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Coalbed methane potential extends across much of southern and central Alberta.



Association of Petroleum Producers Investment Symposium in June, Encana’s executive vice-president and president of its Canadian Division, Mike Graham, said: “Encana’s CBM resource play, although dry gas, is still very competitive within our portfolio. We own large contiguous blocks mostly on fee lands and we also own a lot of the infrastructure.”

Encana’s second-quarter CBM production was 476 million cubic feet equivalent per day, which was 12 per cent higher than the second quarter of 2010 as a result of successful drilling, acquisitions and third-party production. The com-pany drilled 320 net wells and brought 538 new wells on stream. For 2011, it plans to drill 450 net wells.

Encana also reports it is doing more pad drilling this year to allay land disturbance concerns in more populated rural operating areas but also reduce its supply cost on this resource play to around $3 per thousand cubic feet.

Quicksilver is also committed to CBM and says one of the things that allow it to continue drilling and bring on CBM production at economic rates is ownership of the infrastruc-ture. Paying to have its gas processed could make marginal economics uneconomic unless the wells happen to be in par-ticularly productive areas.

The top producers from the Horseshoe Canyon coals are Encana, Quicksilver, Nexen Inc. and Apache Canada Ltd. Nexen and Trident Exploration are the producers in the Mannville coals.

According to an Energy Resources Conservation Board’s 2010 summary of reserves and production, CBM contributed

7.4 million cubic metres (261 million cubic feet) and “activity in CBM has increased from a few test wells in 2001, to more than 16,000 producing connections [wells] in 2010.”

Currently, 86 per cent of producing CBM wells are in the Horseshoe Canyon. In 2010, CBM contributed eight per cent of Alberta’s total marketable gas production, which the ERCB projects will increase to 13 per cent by 2020.

“There were 1,085 successful new CBM and CBM- hybrid connections: 1,075 in the Horseshoe Canyon and 10 in the Mannville [in 2010]…” the report says. The ERCB also expects the addition of 1,200 new CBM and CBM-hybrid wells each year in the Horseshoe Canyon over the next decade.

So even though few people talk about it, coalbed methane is still around and still a viable, if not exciting, proposition. I

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Over the years, coalbed methane producers and the agriculture industry have learned to co-exist.



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