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.

If Nobody Hears a Blowout, Did it Really Happen?

Canada’s worst-ever blowout wasn’t a celebrity, and despite the passage of more than a decade the regulator has never formally investigated the event. Is that a good thing?

This article appears in the July issue of Oilweek

By Peter McKenzie-Brown

Klua d-27-J blew out near Fort Nelson BC. No neighbours were under threat, and the blowout took place in the sticks as most Canadians were getting ready for Christmas. No one was injured and, except for an incinerated rig, there was no damage to property. The media didn’t get wind of the disaster, so Klua was relegated to the world of “incidents.”

The blowout began on December 6, 1999 and took 12 days to shut in. But what an incident it was! Chairman Mike Miller of Safety Boss was part of a team of petroleum industry experts who prepared an important paper on Klua for a conference in Texas two years later. “Eyewitnesses reported that the drill string was lowered the last fraction of a meter with no resistance,” the paper says, “as if the bit had entered an underground cavern….” Then all hell broke loose.

According to Miller, at its peak the well spewed an estimated 250 million cubic feet of natural gas per day plus 5,000 barrels of condensate and 45,000 barrels of salt water. After ten days, crews ignited the well, which was flowing mildly sour gas. After pulling the incinerated substructure of the rig from the well, the hole was shut in and a control BOP installed.

When Oilweek recently contacted BC’s Oil and Gas Commission (OGC) for the formal report on this blowout, there was none. The Ministry of Environment would lead clean-up efforts, but otherwise the file is still open.

It’s a Matter of Safety

With oil leaking in the Gulf of Mexico, Canada is well-positioned to deal with the heightened risks - and reap the bountiful rewards - of frontier exploration.

Photo: Chevron Canada, which is drilling the ultra-deepwater Lona O-55 well in the Orphan Basin off Newfoundland with the Stena Carron Drillship, must meet several new requirements stemming from the Deepwater Horizon tragedy.

This article appears in the July issue of Oilweek.

By Peter McKenzie-Brown

As the United States administration and BP plc struggled to deal with what could turn out to be the largest-ever offshore oil spill, the Canadian oil and gas industry could look back in admiration at a frontier drilling history that has been relatively free of stains.

Oil and gas continues to be pumped from fields off the East Coast. Crude oil has been produced and shipped from the Arctic Islands. And natural gas from the Mackenzie Delta region is poised to supply southern markets, pending completion of a long-awaited natural gas pipeline from Inuvik. And in the Queen Charlotte basin, off the coast of British Columbia, where a moratorium has barred drilling since 1971, there lies a “new, rich petroleum province waiting to be explored,” says widely-respected petroleum geologist Henry Lyatsky.

He has been actively promoting lifting the moratorium even while the media were buzzing about the Gulf of Mexico blowout, believes there are excellent prospects in Canada’s west coast basins. Opening them up for drilling would reward the industry for decades of nearly incident-free frontier exploration.

Those sentiments would alarm most people outside the oilpatch, and they would alarm Canadian environmental activists to the point of apoplexy. That, however, is exactly the point: There is widespread concern around Canada that rapid growth in the petroleum sector would pose environment, health and safety (EHS) dangers. Those concerns illustrate how profoundly EHS has become part of our national DNA. And that is a very good thing.

The Three-legged Stool
The EHS stool has three legs: customs and social attitudes; regulatory and industrial codes; technical skills and operating environments. If the legs aren’t the same length, the stool wobbles. Since the three legs of the Canadian stool are level and strong, there are good reasons to encourage the industry to reach out to new operating environments.

Consider reality in much of the developing world, for example. “We do a lot of work out of Third World countries where clearly life is cheaper,” says Mike Miller, the chairman of Calgary-based Safety Boss Inc. “We were doing safety management on a huge construction project in Iran, and we just had a hell of a time to get people on board with it. One of the comments we heard was that if they killed someone it would just cost fifteen hundred bucks. You’d take $1500 to the family and that would be the end of it. So how much money are you going to spend on safety? Our contract was about enforcing Canadian safety standards, and we found so much resistance that at the end of the day we just said ‘This isn’t going to work, guys, because you aren’t going to stand behind us.’” In the end, Safety Boss got out of its contract.

Miller’s example illustrates the social attitude leg of the stool in much of the Third World. By contrast, in Canada the legal resources applied to safety and safe working environments are huge. Apart from representing personal tragedy, injury and loss of life are expensive propositions.

On the matter of the second leg of the stool, regulation, rich countries like Canada are increasingly focused on stringent EHS rules. The Canadian experience illustrates how regulation has saturated public opinion so deeply that environment, health and safety have become essential parts of the social fabric. According to Dale Dusterhoft, the chief executive officer of well service company Trican, there is a “continued focus on safety, environment and hazard issues and it comes from all levels, it comes from government, it comes from our customers who are the oil companies, it comes from the public at large and it comes internally from within the service industry. It now affects everything we do, and it is helping us make real progress.”

Operating environments represent the third leg of the stool, and they reflect the industry’s collective experience. The sector has a wealth of experience in the Western Canada Basin and is increasingly knowledgeable about the frontiers. The industry’s technical knowledge and skill-sets are formidable.

Safety Costs
Although serious industrial incidents have become rare, as long as there is an oil industry there will probably be kicks and blowouts. The story of Canada’s oil patch is full of these events, some of which have become legend: Royalite #4 at Turner Valley (1924); Atlantic Leduc #3 (1948); Amoco’s second sour gas blowout at Lodgepole (1982-83). The most blowout-prone exploration program in Canadian history was probably Panarctic’s 1969-70 effort in the High Arctic. Of 17 holes, two were spectacular gas blowouts and three were relief wells drilled to bring those blowouts under control.

To some extent because of the disasters of its cowboy years, Canada’s safety record is now excellent– especially since the high-profile Lodgepole event. In years of high drilling activity the industry now sinks three times as many wells as it did in ’82 and drills four times as many metres, yet blowout rates have substantially declined. In 2008, for example, the ERCB recorded 0.118 blowouts per 1,000 non-abandoned wells.

This partly reflects technological advance. “Almost all blowouts occur because of human error,” says Mike Miller of Safety Boss. “Fewer than 5% occur because of corrosion. It’s almost always when there’s a rig over the hole – whether it’s a drilling rig, a service rig or a snubbing unit. That’s where the human error takes place. Today we can put holes down in half to a quarter of the time it used to take so there’s less exposure of time to risk. That’s one reason we have fewer blowouts: we can drill wells so much faster.”

Miller also commends the ERCB’s strict regulations for sour gas drilling. “We now classify wells with significant sour gas content as critical wells, for which a whole new set of rules apply, including the requirement for emergency response plans. That’s made a huge difference.” So big, reports the Energy Resources Conservation Board’s Bob Cullan, that “there hasn’t been a single sour gas blowout since Lodgepole. That’s because we have the toughest sour gas drilling regulations in the world.”

The cost of safety is huge, and it has meant big changes in operating procedures. Mike Miller describes dramatic changes in the safety business since his father founded the company. “People (doing safety turnarounds at gas plants) now have fall-arrest equipment. They don’t do anything without fire protection and breathing air equipment. A friend of mine tells me that at the plant he works at, the safety bill used to be $20,000. Now it’s like $300,000 to $400,000. Every time someone goes into a vessel someone has to be there to watch. They may need to have specialized safety equipment or even specially trained personnel to watch that person in the vessel.”

He adds, “I appreciate the safer work environment, but the paperwork can be simply overwhelming. Now on blowouts we have to take a safety certified officer, and their job is simply to do the safety recording – to record every detail of the safety meetings we have. ‘We met at such-and-such a time, these are the hazards we discussed, people have to wear such-and-such protection equipment, here’s what we said and did.’”

To put costs in perspective it is worth noting that, according to an ERCB report, the direct costs of the 1982 Lodgepole disaster (lost production, lost drilling rig, operations and remediation) totalled $200 million. In a technical presentation nearly ten years ago, Mike Miller estimated that indirect costs – more stringent critical sour gas well procedures, equipment and emergency response planning, which can amount to a quarter to a half million dollars for a deep test – had been in the order of $1 billion. The cost of EHS is high, but Canadians are clearly prepared to pay it.

So is Canadian business. Chief executive officer Dale Dusterhoft of Trican, which is a key player in hydraulic well fraccing, describes the safety issues his employees face as long-distance driving (often over rough terrain); controlling high-pressures and chemicals; and working with moving parts and equipment. “Whenever you have those elements, you have safety issues,” he says. While he acknowledges that there is more paperwork than ten years ago, he says “It’s just part of the process. It doesn’t hinder our operations. We have a safety meeting prior to each job, and we have to document every one. What’s more, every individual there has to sign off that they were in attendance and heard it and understood it. But these are just good business practices. They take a bit more time, but they save money in the long run because you don’t have as many incidents.”

High Arctic
Canada’s early experience in the High Arctic – a 17-well drilling program that included three relief wells to control two major blowouts – illustrates how bad things can be when you don’t properly prepare for drilling in new exploration territory. The stool becomes wobbly, and the risk of an uncontrolled release of hydrocarbons – the fancy phrase for blowout – becomes greater.

In that context consider that the EHS stool is shaky in most Third World countries, yet there are big increases in deep water drilling off the shores of Africa, Brazil, China and India. “Aside from the oil sands,” ARC Energy’s Peter Tertzakian pointed out in a recent research note, “offshore drilling is where most of the world’s incremental oil barrels now come from, and it’s those higher-cost marginal barrels that set price. Indeed, a large fraction of the world’s growing oil needs since the early 1990s has come from the discovery of new, deep offshore reservoirs.” In North America, much of that oil has come from the American sector of the Gulf of Mexico.

Notwithstanding the BP-operated Macondo well disaster, it is rich-world companies that are best suited to drilling the world’s offshore petroleum basins. Because of our national attitudes and far-flung technical expertise, environment, health and safety are well served when Canada-based companies drill offshore fields. This reality applies as much to basins in Canada as to those in the Third World.

The Beaufort Sea and the East Coast Offshore
In Canada’s Beaufort and East Coast basins there have been important EHS developments in recent months.

Going to the ends of the earth is nothing new for the Canadian oil and gas industry. Beginning in 1976, drilling expeditions in the Beaufort Sea were innovative and daring and continued for nearly a decade. The wells were in shallow water, however – often using equipment that sat on the sea floor.

Last fall the National Energy Board began a safety inquiry in anticipation of a revival of drilling in the Beaufort Sea. The review was triggered by a proposal from Imperial and Exxon Mobil to start deeper Beaufort drilling, using a new vessel built on the scale of a battleship. The Board is investigating serious concerns about opening up deeper northern waters for drilling. The previous generation of regulations assumed that in the event of a blowout the operator could drill a relief well in the same season.

The Board began developing its new regulatory approach because the Arctic work season is too short to follow the old rules for the next wave of bigger wells. After the Macondo disaster began, the Board announced that it would review Arctic drilling requirements in light of findings from the American inquiries into that event. “We need to learn from what happened in the Gulf,” NEB Chair Gaétan Caron said in a statement. “The information taken from this unfortunate situation will enhance our safety and environmental oversight.” The regulator is making sure all three legs of the EHS stool are the right size for deep Beaufort drilling.

Off the east coast, the Gulf debacle created consternation for a different reason: a new, deep well was being spudded. In May, Chevron began drilling Canada’s deepest offshore oil well 430 kilometres northeast of St. John’s in the offshore Orphan Basin in the North Atlantic. Lona 0-55 was spudded in 2,500 metres of water (compared to Macondo’s 1,500 metres). Despite political calls for postponement because of the risk of an ultra-deep-water blowout, Newfoundland defended the project as critical to its economic development. The gist of the government’s argument was that oil is too crucial to the economy to call off exploration. That sounds quite a bit like damning with faint praise.

In response to public criticism, the government of Newfoundland appointed master mariner Mark Turner, an expert in marine safety and environmental management, to review the province’s ability to prevent and respond to an offshore oil spill.

It isn’t surprising that environmentalists and the political opposition sounded their respective horns on the remote prospect of a North Atlantic blowout. Serious offshore oil blowouts always attract attention, and rightly so. Injuries and fatalities are more common. They pollute, they’re hard to clean up and contamination can last for years. When dispersants are appropriate at all, they are the least bad of the available tools. And offshore oil blowouts have a disproportionate impact on wildlife: a deer can walk past a puddle of oil, but fish, whales and seals have nowhere else to go.

However, crucial facts were lost in the conversation about Lona O-55. One is that there has never been a crude oil blowout offshore Canada. Another is that only hundreds of wells have been drilled in Canada’s vast east coast, compared to tens of thousands in the much smaller US segment of the Gulf. Also lost in the debate is that all Canadian offshore wells have recently become governed by a more robust regulatory regime – one which offers greater EHS flexibility as a carrot, but bigger sticks for those who fail to perform. That means better safety and environmental protection rather than less, as the knee-jerk critics protest.

The new rules governing offshore drilling were posted in the Canada Gazette last December, and took effect at the beginning of this year. They are performance-based rather than prescriptive regulations, and the industry certainly believes that is a good thing.

According to Patrick Delaney of the Petroleum Services Association of Canada, the trend in regulation is undergoing a fundamental shift to performance-based regulation from prescriptive rules. As he explains, under the new approach the regulator essentially says, “The journey is from A to Z” – Z being a plan which meets the regulator’s EH&S goals. “We aren’t going to tell you how to get there. But before you start it’s up to you to prove that you can do it safely. This is a safer approach.”

For offshore operators, the days are now over when agencies of government specify the safety equipment the industry should use. “A lot of governments are making this shift,” adds Delaney. “Alberta recently announced that it is doing a complete review of its regulations, and that it will move away from prescriptive to performance-based regulation.”

Paul Barnes, who is Atlantic Canada manager for the Canadian Association of Petroleum Producers, is another advocate of performance-based regulation. It’s more “modern,” he says. Britain, Norway, Australia – all the advanced countries with offshore petroleum operations are adopting it. “It is part of a robust regulatory system in Canada,” he adds. “We have a strong track record of safety and environmental performance. Canada needs energy and the world needs energy, and oil’s going to be a big part of the energy mix for a long time to come. Let’s get on with it.”