Revolution Repeated

The Western Canada Sedimentary Basin. This article appears in the February issue of Oilweek.

By Peter McKenzie-Brown

First came the revolution in natural gas production – the shift to shale gas which, by bringing huge new stores of natural gas into the market drove prices down and made it necessary to fundamentally restructure Canada’s gas-prone petroleum sector. Now comes the revolution in the oilfield. Ironically, the same technologies that made shale gas possible are enabling the industry to begin the restructuring that the shift to shale gas made necessary.

“Oil doesn’t flow as well as gas,” Legacy Oil & Gas president Trent Yanko reminds us. “So in the oilfields of Alberta, especially, is a tremendous opportunity to recover unproduced oil. Original oil in place was in the billions of barrels, so if you can add only one, two, three percent to recovery there is quite an opportunity. You don’t have to be a wildcatter out in the jungle somewhere. All you have to do is better exploit what we already know is there.”

The technologies that made the shale gas revolution possible are beginning to have a similar impact in the light and conventional oil sector, which can now develop reservoirs that could not be exploited until energy prices and new technologies made production economic. For small companies in particular, this is presenting exceptional opportunities. From start-ups to mid-caps, companies like TriAxon and PetroBakken Energy are creating profitable enterprises from oilfields discovered 50 years ago. Already successful in similar enterprises, Legacy is taking on the big kahuna – the century-old field that put Canada’s petroleum headquarters on the map.
Juniors and the Treadmill

Since it became commonplace in the late 1980s, horizontal drilling has been enhanced by increased drilling efficiency. Much longer horizontal legs are now possible: many are two and three kilometres in length. This is possible because of improvements in bit design, the increasingly effective use of coil tubing and better down-hole motors. Other contributors include geo-steering and increasingly effective measurement-while-drilling (MWD) tools and techniques. Most important of all is multi-stage fracturing. The industry can now isolate many completion zones along lengthy horizontal wellbores: a two-kilometre horizontal leg can host up to 20 hydraulic fractures.

These technologies are making formations like the Bakken viable. Increasingly, the technologies that created the shale gas revolution – long horizontal wells and multistage fracturing – are being applied to aging light oil reservoirs in North America. This production phenomenon has also involved largely unacknowledged regulatory responses by the governments of Western Canada. These factors and other technologies are opening up important new opportunities for production from largely depleted reservoirs. For example, Gary Leach – executive director of SEPAC (the Small Explorers and Producers Association of Canada) – notes that “microseismic for the more precise design of frac jobs is a particularly important new technology.”

A year ago, TriAxon Resources represented a big success story among private junior oil companies. The company was created with what in 2006 was the novel idea of applying the cluster of new technologies to oil production. After screening available prospects, the company focused on the Bakken, Glauconite, Cardium, and Viking formations. The company raised $87 million in private financing; two and a half years later the partners sold out to Crescent Point Energy for $257 million.

Then, according to former president Jeff Saponja, he and his two partners – chief operating officer Colin Flanagan and operations vice president Rob Hari – took a two-week break before establishing TriAxon Oil Corp. – “TriAxon Two,” he calls it.

The opportunities come with a cost, of course. Saponja cautions that those technologies present unique challenges because they are so capital-intensive they. “Fifteen years ago, in the heyday of conventional oil exploration and production, you would put $150,000 to maybe $500,000 into the ground to get 200,000 barrels of oil,” according to Saponja. “Now you have to put maybe $4 million in the ground to get 200,000 barrels of oil, and you have a 50% to 80% initial rate of decline. To get these multistage frac wells to work you have to drill a lot of wells in these lower quality reservoirs.” This leads to what he calls the treadmill.

“To offset decline you have to be continually drilling, because the decline rate is so high. The main point of the equation is that these horizontal wells are very capital-intensive. Initially you get a very high rate of oil production but they will decline quite quickly. The economics are actually fairly marginal on a well to well basis, so you have to drill a lot of wells to benefit from scale. Except in the Bakken,” he says, “Most of these multistage frac wells really struggle if oil prices are below $60 or $70. For these wells to be really profitable, oil has to be over $80 a barrel.”

“You have to be continually drilling to offset decline. It’s called the treadmill. The main point of the equation is that these horizontal wells are very capital-intensive. Initially you get a very high rate of oil production but they will decline quite quickly. The economics are actually fairly marginal on a well-to-well basis, so you have to drill a lot of wells to benefit from scale. Except in the Bakken,” he says, “Most of these multistage frac wells really struggle if oil prices are below $60 or $70. For these wells to be really profitable, oil has to be over $80 a barrel.”

Does it make sense for private companies like TriAxon to stay public? According to Saponja, the economics of staying private are iffy. “These are very expensive wells. For a junior to stay on the treadmill becomes very difficult after you reach 3,000 or 4,000 barrels a day because you need a lot of capital to grow production and combat decline. The challenge that juniors face is that they have to either get their hands on more capital or be prepared to monetize their assets by selling them off. That’s the case for going public: it gives you access to low-cost capital. However, my partners and I are happy building basements, then selling them to the highest bidder.”

Midcaps in the Bakken
The highest bidder for TriAxon One was Crescent Point Energy – one of the two largest players in the Bakken, and the main competitor of PetroBakken, a midcap headed by Gregg Smith. “Our decline rates in the Bakken are about 60% in the first year, so we have to keep drilling to maintain production rates. You have to experiment a lot to be successful in plays like this. When you come into these plays your initial results are going to be mixed, but as you refine your drilling and production systems they improve.”

With considerable satisfaction, Smith notes his company’s success in drilling bilaterals from a single wellpad. “For PetroBakken to drill a single horizontal, the cost is $2.4 million. However, to drill two bilaterals from a single pad costs $3.6 million. It’s much more capital-effective, and it delivers an extra 50,000 barrels per well into the bargain.”

According to SEPAC’s Leach, the obviously improved economics of tighter spacing is generating “a regulatory response. The design of wellpads has to be different, and the new wellpads provide both environmental and economic benefits. Regulators are beginning to respond in all three western provinces.”

He adds, “The Cardium just began to take off in early 2009, and it was SEPAC companies – junior and midsized companies – that set the stage for this. Those sectors are looking to restructure because of the long-term poor prospects for natural gas, and this has played a role in that. It’s really turned around the fortunes of the industry, and generated a lot of investor interest.” With some satisfaction, he notes that multinational companies are coming back to North America to get back into the light and conventional oil resource plays. This involves a turnabout for some companies. for example, Talisman sold off a lot of its Alberta oil production just a few years ago.

PetroBakken’s Smith stresses that the situation in Canada is quite different than that in the United States. The Americans “are drilling shale oil plays. (By contrast) most of the horizontal wells with multistage fraccing in Canada are into reservoirs that were previously simply uneconomic or marginally economic (if you were trying to produce) oil from a vertical well.” This is all changing now, he says. “Now you’re seeing people try to tie up shale oil plays like the Alberta Bakken, the Duvernay and the Nordegg.”

Back to the Future
Of course, old hands in the oil industry are the first to tell you that technology has always been the key factor in expanding production. In fact, in this period of oilfield revolution the importance of technology is more obvious than ever before. According to Legacy president Trent Yanko, “Technology has always been an important part of oilfield development in Canada. I started out in Saskatchewan in 1980s, which was really Canada’s leader in horizontal drilling because of a major government incentive program.” After a few years the industry found itself drilling more horizontals in Saskatchewan than anywhere else in North America – “even the Austin Chalk” in Texas.

“Southeast Saskatchewan has been a classic case of the use of technology to extend the life of reservoirs,” Yanko continues. “Since the 1960s the industry has applied waterflood there, horizontal drilling, CO2 injection and other technologies, each of them extending the life of the province’s south-eastern petroleum reserves. As a result, in the late 1990s oil production matched what everybody thought had been the peak oil levels of 1966, and today the province is at record production.”

Almost all of the reservoirs now being developed with these technologies were discovered after 1947, when the Leduc discovery ushered in the industry’s modern age. Yanko, however, has plans to apply them in the petroleum industry’s birthplace. “Through the acquisition of a private company in July,” he says, “we acquired the Turner Valley oilfield. We control most of the production and all the facilities there.”

To understand Turner Valley’s significance, it’s worth noting that the field’s proximity to Calgary is the reason Canada’s petroleum sector is headquartered in the city. And, as SEPAC’s Gary Leach observes, Calgary now hosts the 45% of the world’s publicly traded oil and gas companies.

As he discusses this property, Trent Yanko becomes palpably excited. “There is still a lot of meat on the bone. There’s been less than 1% decline in (annual) oil production (from Turner Valley) over the last fifty years. The original oil in place was 1.3 billion barrels of 40° oil, and the historical recovery factor to date is only about 12%. So we think it has huge development potential. Before we acquired the property, the last vertical wells were drilled there in the 1940s. There was some horizontal drilling in the 1990s, but the field has been non-core for a long time.”

Although Legacy is proceeding cautiously, its president is thinking big. To begin with, Yanko believes Legacy has mapped a Cardium trend right on top of the field – “11 miles long and about 1½ miles wide,” with 10 metres gross maximum thickness. “In Turner Valley there’s a vertical well that just missed the Cardium and still produced more than 19,000 barrels. Otherwise, that trend hasn’t even been touched.”

“We believe the application of horizontal drilling and multi-stage frac technology can increase the recovery factor,” he adds. “So can infill drilling and reactivation of the waterflood. This property hits a lot of our hot buttons.” In the fall, the company drilled a number of vertical wells into the field. “We are going to frac them, and they will provide a great controlled environment to help us understand the horizons for future horizontal drilling. These wells will help us design that drilling program properly.”

When Turner Valley was first drilled in 1913, it was a wet gas field from which liquids were extracted and natural gas flared. A century later, with conventional gas again a marginally economic commodity, the prize sought in Turner Valley reservoirs is again its hydrocarbon liquids. The difference today is the toolkit.

Unconventional Challenges

There's nothing unconventional about shale gas in western Canada, but the technology to get at it? Now that's a different story

Photo: Rig for coil tubing. This article appears in the June Unconventional Gas Guide

By Peter McKenzie-Brown

In a recent presentation to the Petroleum History Society, Dave Russum – geosciences vice-president for AJM Petroleum Consulting – recounted the development of unconventional gas in Western Canada. According to Russum, evolving technology is making unconventional gas – what he says should correctly be called “conventional gas from unconventional reservoirs” – a commercially viable commodity. Despite the lower-price environment for natural gas, rapid innovation in down-hole technologies has made shale reservoirs viable sources of gas production.

The most important of these is horizontal drilling. Since the technology became widespread in the late 1980s, horizontal drilling has been enhanced by increased drilling efficiency. Much longer horizontal legs are now possible: many are two and three kilometres in length. This is possible because of improvements in bit design, the increasingly effective use of coil tubing and better down-hole motors.

Geo-steering is another increasingly critical down-hole technology. In recent years it has been given a lift by high-impact measurement-while-drilling (MWD) tools and techniques.

Another contributor to the shale-gas revolution is multi-lateral horizontal drilling – the ability to drill several laterals from a single well. As one example, last year Trident Exploration drilled a 2,400-metre vertical well into the Montney formation near Dawson Creek. At depth, the company drilled two 1,000-metre horizontal laterals. This achievement illustrates the revolution taking place in horizontal drilling – although 1,000-metre laterals are puny by the standards of some drilling programs.

Two other technologies are more directly related to reservoir production. The industry can now isolate many completion zones in horizontal wellbores. This makes reservoir fracturing possible over long distances. What’s more, microseismic technologies now enable geo-engineers to improve reservoir development and productivity by monitoring fracture efficiency within reservoirs.

Although these technologies are increasing in sophistication and declining in relative cost, they have led to a fundamental change in gas-field economics. The petroleum sector’s spending patterns are shifting, with a much bigger portion of the development pie now being invested underground. For the first time, the industry is investing more down-hole than in gathering lines and other surface facilities.

Microseismic
Microseismic has made great strides in the last decade. One of the leaders in this area is Houston-based Microseismic Inc. The company was founded in 2006 by Peter Duncan, who originally hales from New Brunswick, got his Ph. D. in geophysics from the University of Toronto, and cut his teeth in resource development in Alberta and offshore Nova Scotia working for Shell Canada. He stresses that the technology in itself is not new. It is well established academically and within government organizations – for use in earthquake location, for example. Applying the technology to producing reservoirs, however, is a new and rapidly developing field.

Duncan explains microseismic with vivid analogies. “Regular oil and gas seismic is like an X-ray,” he says. “Microseismic is more like a stethoscope. You can ‘hear’ the sound of fluids underground.” This is an area of rapid technological growth.

According to Duncan, “We can cement geophones on the surface and underground to enable people to better produce these gas shales, and monitor production for the life of the field. With the developments we are making today, these arrays are like a big-dish microphone. (Using a computer) you can essentially beam-steer that array around the reservoir to find out what’s going on where. The cost-effective way to do this is to set up a permanent array of phones to monitor the fraccing of every well during the development of the field.” For shale gas production, a key feature of this technology is that it can tell you where well fraccing has been effective, and where it hasn’t.

“With this system, you can monitor other subsurface phenomena – for example, the injection of water or other production fluids into the reservoir. An important application has been the use of these systems to monitor cyclic steam injection in the oilsands.” Both Shell and Esso have been doing this, although using different microseismic suppliers.

What’s the cost? Microseismic is more expensive in the Montney formation than it is in the Barnett shales of northern Texas, for example. However, a technical paper from EnCana has suggested that the incremental cost of monitoring a frac stage with one of these permanent arrays is relatively small – fully amortized, about $10,000 per frac stage. If that monitoring enables geo-engineers to increase ultimate gas production by correcting fracturing inefficiencies, it’s a small price to pay for what could be much greater cash flow.

Coil Tubing
The workhorse of underground technologies is coil (“coiled”) tubing – a tool that began to make big inroads into industry operations around 1990, and has since transformed many aspects of underground drilling and workover operations. It refers to metal piping spooled on a large reel and used for interventions in wells and sometimes as production tubing in depleted gas wells. Coiled tubing is often used to carry out operations previously done by wirelining. The main benefit of coil tubing over wireline is that you can pump chemicals through the coil. With coil tubing you are able to push tools and chemicals into the hole; wirelining relies on gravity.

The tool string at the bottom of the coil can range from something as simple as a jetting nozzle, for jobs involving pumping chemicals or cement through the coil, to a larger string of logging tools, depending on the operations. Coil tubing is also used for relatively inexpensive work-over operations. It is used to perform open-hole drilling operations.

Of particular importance in the context of shale gas production, coil tubing can be used to fracture the well – a process where fluid is pressurized to thousands of psi on a specific point in a well. This blasts the rock into rubble, thereby permitting the flow of hydrocarbons to the well-bore.

Fractious
The move to more intensive down-hole spending is shifting the industry away from its traditional ways of doing business, and even the seasonal patterns it follows. Consider fraccing.

Fraccing is a stimulation technique which improves production from geological formations where natural flow is restricted. Hydraulic fracturing pumps a mix of water, sand and some soluble chemicals into the well at high pressure, thus fracturing the formation and holding the fractures open so hydrocarbons can flow more freely into the wellbore.

Dave Russum takes the story from this simple explanation to the use of multi-stage fracturing techniques on horizontal wells. “Between the heel and the toe of a horizontal well,” he says, “you isolate an interval close to the toe and frac that region. Then you move back towards the heel, isolate another interval and do another frac. This breaks up a lot of rock, making a lot more gas available. These new technologies are enabling us to access a whole lot more low-permeability rock than you would ever be able to reach with a vertical well.”

In the days of vertical drilling, producers generally fracced just one or two zones per well. With today’s technology, it is possible to frac a single well up to 17 times – although a well that required so much work would likely have a horizontal reach of 3,000 metres or more.

To fracture just one of EnCana’s Horn River shale gas wells in north-eastern BC, you need a fracturing crew equipped with perhaps 45,000 horsepower of compression. To put that in perspective, in Western Canada perhaps 800,000 horsepower is available.

“We do not believe that there will be sufficient capacity to perform all of the jobs necessary, should (BC’s Horn River and Montney shale gas) plays grow,” said Kevin Lo of FirstEnergy Capital in a research note. He also worried about the logistics of bringing in enough propping agent: fracturing a single horizontal well in these reservoirs can require up to two thousand tonnes of sand.

Dale Dusterhoft, a senior vice president at Trican Well Service, paints an even grimmer picture. “Some of the Horn River wells require up to 45,000 horsepower of compression,” he says, “and with 10 holes per pad you may have 40,000 horsepower tied up for 10 weeks.” He adds, “There will be shortages of equipment when we get up to full development of the shales” – a plus for service companies like his own, which will then charge premium day rates, but a worry for the big players in the region.

Although environmentalists have voiced concern that fraccing chemicals may contaminate groundwater, Dusterhoft argues that before wells are fracced the formations are securely sealed away from potential fresh-water reservoirs. And anyway, he says, in the unconventional wells in north-eastern BC “we only use a polymer as a friction reducer, and maybe something to stabilize the clays. Mostly we just run water and sand.” When fraccing is completely successful, he says, “All the fractures connect up with each other, so we can get maximum production. We like to say we can ‘farm’ the reservoir.”

Huge fraccing jobs like those in north-eastern BC require a great deal of logistical support. Each hole can require 2,000 to 3,000 tonnes of fine-grained sand as a propping agent. Imagine the parade of trucks bringing such a harvest of ancient beach sand up the road to north-eastern BC – often from quarries in Saskatchewan. To take on such a project may require a 40-member crew and 20 or more hydraulic compression systems mounted on huge fraccing trucks.

Because so much water is required, a typical job requires a large water storage pit in addition to a string of high-volume steel tanks. The amount of water being used in these jobs has actually led to a seasonal shift in the fraccing business. According to Dusterhoft, “Now (the industry is) drilling during winter freeze-up, as we always have, but fraccing in the summer. All the bigger operators are trending in that direction.” The reason is that the water is easier to deal with in warmer weather. In the longer term this will require upgrading to all weather-roads to Horn River and Montney. Until those upgrades are completed, service companies are leaving equipment in the area during freeze-up.

The shift to unconventional gas production occurred much more quickly than anyone expected, Dusterhoft said, and it has important implications. For one thing, it is contributing directly to the reduced number of wells being drilled in Western Canada. There are now about as many horizontal wells being drilled as those being directionally drilled.

To put that in perspective, drilling costs at Horn River are in the $5-7 million range per well, while they are maybe $4-5 million each at Montney. Add to that the cost of fraccing – say, $2-3 million per well – and it’s clear that the industry is putting a lot of money in the ground. But the production profiles for these wells make it worth the cost. These wells may produce 7.5 million cubic feet of gas per day for the first year. Production declines rapidly in the early stages but the optimists believe they may level off at, say, 2 million cubic feet per day and maintain those production levels for years.

Challenging to Extract
AJM’s Russum disputes this. “Each reservoir is different,” he says. “We don’t fully understand the science of shale gas reservoirs. I certainly don’t think we can apply a one-size-fits-all model to their production profiles. Some wells may simply stop producing in only a year or two.”

In wrapping up this commentary, it may be useful to return to Dave Russum’s assertion that there is no unconventional gas – only “conventional gas from unconventional reservoirs.” Russum stressed that shale gas plays are only one part of this important new resource, and that they have all benefitted from advancing technology. He defined this commodity as “any methane not trapped in a porous, permeable, buoyancy-driven system.”

What are the characteristics of these unconventional reservoirs? They are extremely variable. The methane within them is not freely dispersed and they have low or heterogeneous permeability. The source rock and the reservoir are closely related, and these resources represent large but low-concentration resources. They have unusual pressure regimes, and in many cases they represent a lower-quality version of conventional reservoirs. In short, they are more challenging to extract – a state of affairs that can best be resolved with evolving technology, as the story of shale gas amply illustrates.