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.

Getting More for Less

Making a buck in North America’s most expensive gas basin. This article appears in the February 2009 issue of Oilweek.

By Peter McKenzie-Brown
North America’s natural gas business is going through fundamental change, but Alberta’s conventional gas sector isn’t well positioned to compete. As Canadian Natural Resources' president Steve Laut told a conference call when he was discussing his company’s deep cuts in capital spending for 2009. “We are drilling (for gas) in B.C. but cutting back in Alberta.

The oilsands can withstand (Alberta’s) higher royalties, and on the oil side, the government got it right, but they missed it on gas. Alberta is the worst place for gas development in North America, and likely the world.” Why are things so bad? Part of the problem is the province’s much-maligned new royalty regime, which sapped the industry’s motivation to invest in the province’s traditional source of supply, conventional gas. In November the province gave explorers the option to pay royalties at the old rate for four years, provided the wells were more than 1,000 metres deep and spudded after the New Year.

This eleventh-hour tinkering “will have an improvement on activity levels in the province,” according to Tristone Capital vice president Cristina Lopez, “but it will not improve the cash flow outlook for companies that are going into a difficult commodity-price environment.” That’s a major reason for the decline in conventional exploration and development. “There’s been a tendency to assume that as long as we have gas opportunities in Alberta, people will come here to invest their money to get it out,” said Dave Russum, who is head of geosciences at AJM Petroleum Consulting. “We should not automatically assume that will be the case. When you change the royalty system and make other such changes, then investors will go to other opportunities where they have other advantages – closer to markets, or where there’s a better royalty regime or a lower cost structure.”

He notes that until this year there has been an absolute correlation between wells drilled and gas prices: When prices went up, so did the number of wells. This year, prices went up but drilling in Alberta went down. Was this an unintended consequence of Alberta’s new royalty regime? Probably, but other economic factors are also at play. Geological targets are changing; costs and prices are fluctuating for reasons that have nothing to do with natural gas activity levels (think oilsands); new technologies are fundamentally changing the economics of development; and issues related to environmentally responsive, full-cost accounting are playing an increasingly important role in project approvals.

A Fourth Amigo...Again
Three Western countries – Norway, Canada and the Netherlands – are now self-sufficient in natural gas (the UK was among them until four years ago). Soon, another country could join that small but lucky band. If you were to hazard a guess, which country do you think might join that group? That country, whose conventional gas production peaked in 1972, began focusing on unconventional natural gas in the 1980s.

Today, the Lower 48 states are producing gas at rates near their 1972 peak. Increasing supplies from unconventional gas fields and coal-bed methane are outstripping by far the decline from conventional sources, and LNG production from Alaska is possible. A number of commentators have suggested that these factors could soon make the United States again self-sufficient. An obvious implication is that Canada must develop alternative markets to help create price security.

According to Russum, only six percent of the sedimentary rock in the Western Canada Basin is prospective for conventional natural gas. However, the bulk of the other rocks are prospective for biogenic gas, tight gas, fractured gas or shale gas. Coal bed methane represents a tiny additional wedge on his pie. This gas-prone basin, where conventional gas production is in decline, still hosts huge volumes of undeveloped hydrocarbons.That’s a point worth remembering.

The cost of developing and delivering Western Canada’s gas varies greatly from region to region, but the WCSB is still one of the world’s most expensive onshore basins to develop. A recently released National Energy Board map illustrated the geographical diversity in cost related to developing and producing these gas supplies. The average cost of gas supplies ranges from $11.18 per thousand cubic feet in the BC Foothills to $6.58 per thousand in the adjacent Alberta Deep Basin. For gas producers and analysts, the critical factor in the NEB analysis was that gas prices need to average $7.88 per thousand cubic feet for producers to generate a risked after-tax rate of return of 15% in this basin.

 Given an average Alberta spot price for natural gas around $6 during 2007, the report intoned, “the average economics for new gas development in western Canada were marginal.... These results are consistent with the general impressions expressed by industry players about the tight economics of new gas....”

 Costs and Prices
If the economics are as bad as this NEB report suggests, why is a fair amount of gas exploration even taking place? According to University of Calgary economics professor Robert Mansell, “It depends on your outlook on prices. If you look into the future and you see average prices in the future at $12, say, then you want to establish a position in that play. Even if you think gas prices will never go above $8, you may want to establish reserves at today’s costs. You could sell them to people who have expectations of higher prices.” It’s all about price and cost.

 Even though unconventional gas is more expensive to develop than conventional production, that’s where about 60% of natural gas activity is going. Like the US, which made great progress developing unconventional gas during an era of lower prices, Western Canada is developing these resources in a period of price/cost disequilibrium – that is, lower prices and higher costs.

This is counterintuitive. In classical economics, adversity in the gas industry – the lower margins and riskier business environment of the last few years, for example – would force the industry to drive down costs and increase efficiency. The U of C’s Mansell squelched that assumption, first zeroing in on the dynamic relationship between price and cost. “Costs drive prices,” he said, “but prices also drive costs.” Supply costs go up and down depending on activity levels, rig and services availability, materials, labour, technology, changes in well productivity, changing drilling targets, and changing fiscal and tax regimes.

Crown land prices go up and down as well. The main way the recent downturn would force the gas industry to become more efficient, said Mansell, would be through consolidation. “In this environment, there’s likely to be much more rationalization.” As smaller companies combine into larger ones, they generally become more efficient.

Technology
While companies employ cost-cutting measures (shutting in higher-cost gas supplies during tough times, for example), Mansell makes the case that real efficiencies are more likely to arise in periods of relative prosperity than in periods of economic adversity. “In a tight margin environment, would companies put more R&D and technology into increasing efficiency? It’s not clear. They actually have more free cash to play with in a higher price environment (and are therefore in a better position to increase efficiency). However, if a company is financially healthy, it can even increase profits in a low-cost environment by applying new technologies.” In other words, greater efficiency in the petroleum sector comes mostly from technology –improved drilling, seismic and other technologies used in exploration and development – along with the obvious benefits of such capital infrastructure as plant and pipeline.

According to Mansell, “It’s a dynamic environment. Mostly because of better know-how, over longer periods of time the industry is getting 1.5% to 2% more output per unit of input each year.” How is that happening? AJM’s Dave Russum puts a technical slant on things. “Per well costs are higher than in the past, that’s true. However, we now understand that in certain kinds of gas resources we can greatly increase productivity by increasing drilling density in lower-quality gas reserves. You need to be able to fracture the maximum amount of the reservoir.” So important has this trend become that it is contributing directly to the reduced number of wells being drilled in Canada. This year, nearly 40% of the wells drilled in Canada will involve horizontal or directional drilling – twice the level of ten years ago.

For the first time, First Energy Capital said in a recent research note, the number of horizontal wells will match the number directionally drilled, and more and more of well costs are in completion technology. Fracturing consists of injecting a fluid into a well to cracks or fractures already present in the formation and create new ones. Russum is especially keen on combining and the use of multi-stage fracturing techniques prior to completion of horizontal wells. “Between the heel and the toe of a horizontal well,” he says, “you can isolate an interval close to the toe, frack that region, then move back towards the heel, isolate another interval and do another frack. This breaks up a lot of rock, and makes 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.”

As the U of C’s Mansell points out, “Current costs may not reflect future costs. As you learn more about the resource, costs could come down substantially – not only the cost of production, but also the cost of finding new reserves.” Recent innovations in fracking wells illustrate how this can happen. Companies have made great strides in increasing the number of fracks they can make in a single horizontal well. Horizontal wells drilled into shale reservoirs now average eight fracks each – an astonishing improvement from only ten years ago, but one that is causing potential bottlenecks in the system.

According to Kevin Lo of FirstEnergy Capital, to fracture just one of the Horn River shale gas wells in north-eastern BC, you need a fracturing crew equipped with more than 30,000 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,” he said 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.

Stewardship
Another area where big changes are happening, of course, is in environmental practice and policy. Take the case of EnCana’s application to drill in the Suffield National Wildlife Area, where a hearing began last September. The gas at Suffield is shallow, biogenically-derived gas in mixed sand and shale sequences. Since it is not generated in the same temperature and pressure systems that create conventional hydrocarbons, shallow biogenic gas is an unconventional variety. The Milk River and Medicine Hat sands of south-eastern Alberta and south-western Saskatchewan are classic examples of this type of unconventional gas. This was the first gas produced in western Canada. It is continuously gas-producing, and it is the largest gas-producing region in the WCSB.

For efficient production of biogenic gas in this area you need close well spacing, and you generally can’t use horizontal drilling because the wells are so shallow. Developing production in these fields is almost like assembly-line manufacturing. You haul in a small rig on a system that causes minimal surface disturbance, drill and complete the well in a day. You can use nitrogen and CO2 fracks, which reduce environmental damage in really shallow wells. Then other crews come along, install the wellhead and tie production in to a pipeline.

Sounds pretty green, doesn’t it? Not according to the Alberta Wilderness Association’s Joyce Hildebrand. “Extracting resources is only one of the mandates of the government, whether at the provincial or federal level,” she says. “Another mandate given to the government by citizens of Canada and Alberta is to set aside environmentally significant areas so that they are off-limits to human activities, such as oil and gas exploration, that may compromise their natural values; to preserve species that have been designated as endangered, threatened or otherwise at risk, and to preserve the habitat that those species depend on.”

She adds, “The evidence is overwhelming that doubling the number of wells, and constructing the necessary associated infrastructure such as pipelines and roads, in the Suffield NWA will seriously compromise the habitat of (species at risk). If the habitat goes, the species go. So as a society, we need to decide whether we want to sacrifice the conservation of that endangered prairie ecosystem for the acceleration of the resources under the ground. Those two choices are incompatible – it’s one or the other. There is no possibility here of ‘balancing’ the two….The sooner we begin to work on a macroeconomic policy that is based on something other than the well-funded rhetoric that economic growth and conservation of wilderness is compatible, the better. The situation at Suffield is one example where that needs to be challenged.”

The issues are complex, and the ERCB has a long history of listening carefully to all sides and dealing with these situations fairly. However, this is only right. As the U of C’s Mansell explains, economic theory supports the environmentalists’ point of view. “In theory,” he says, “you want to be as close as possible to full-cost and-full benefit accounting from a social point of view. Policy decisions should incorporate all incremental benefits and the incremental costs – including costs and benefits that don’t necessarily show up in the market. How you estimate that isn’t an easy question to answer, but your accounting should be based on a benefit-cost analysis.”

Since a poll by the provincial government found that only 16% of Albertans believe the province does a good job of looking after the environment, this story has legs. So there you have it. Alberta may be “the worst place for gas development in North America.” However, the WCSB remains an important gas basin, and activity throughout the region is helping illustrate gathering industrial trends. On the policy side, issues related to full-cost accounting will likely take years to iron out – but at least they are being heard.