Technology Unlocks Unconventional Opportunities

By Mike Byfield

Drawing natural gas from shale is like sucking it through a brick, literally - most bricks are baked from clay. Shale is the world's most common sedimentary rock, formed originally from clay and mud under geological pressure. Shale, although often gas-laden, is so impermeable that the pore space between the grains can be as tight as a single molecule of methane. Even so, shale deposits are currently the most exciting natural gas plays in North America. The Barnett, Marcellus, Horn River Basin and other shale prospects present the possibility of mammoth reserves at a time when North America's conventional gas reservoirs are in decline.

The Illinois-based Gas Technology Institute estimates that gas-in-place within U.S. shales ranges from 500-780 tcf, with a reasonable recoverability target of perhaps 20 per cent. Richard Neufeld, British Columbia's Minister of Energy, Mines and Petroleum Resources, cites provincial government studies that peg B.C.'s shale gas potential between 250 and 1,000 tcf, with an unknown recoverability factor. These are dramatic numbers. As a comparison, the Canadian Association of Petroleum Producers (CAPP) pegged this country's total proven natural gas reserves at less than 60 tcf in 2006.

Primarily due to its shale and tight gas prospects in the Montney and Horn River Basins, British Columbia's take from land sales has been soaring. The province took in $630 million in 2006, $1.05 billion in 2007, and $2.23 billion during the first nine months of this year. Per hectare, bids have averaged almost $3,820 to date in 2008, up from $1,480 in 2007. "It all tells me there's a great future here," Neufeld says.

Geologists traditionally regarded shales as a gas source rock, not a reservoir. Producers have routinely drilled through shale beds to reach more free-flowing sandstone and carbonate formations. "Like coalbed methane and tight formations in general, shale gas required the development of new technology. The solution has proven to be horizontal drilling coupled to hydraulic fracturing along the horizontal wellbores," says Dan Themig, president of Packers Plus Energy Services Inc. "It's the same technology that has transformed the Bakken [a tight rock formation in southeastern Saskatchewan and neighbouring states] into Canada's most significant light oil play."

The first horizontal wells to be stimulated employed what's commonly nicknamed a "Hail Mary" frac-a single massive fracture. Rather than breaking along the length of the wellbore, however, the formation would typically crack in just one spot. In addition, the powerful but unpredictable fracturing might extend cracks into an adjacent water-bearing horizon. "That approach clearly didn't work well," Themig says.

An alternative approach was attempted on horizontal wells which had been cased with a production liner and then cemented. The wellbore would be segmented with bridge plugs, then stimulated through perforations in the steel liner. This technique required multiple coiled tubing trips. Fracing each segment of the wellbore involved rig up and rig down of the stimulation equipment. This type of operation may take weeks and generates expenses that frequently prove uneconomic. Matters can get much worse if a mechanical plug gets stuck, and must be drilled or fished out.

A switch to pump-down bridge plugs and wireline-conveyed perforating guns helps create a more continuous operation but the in-casing plugs still have to be removed. Although horizontal drilling was well established by the turn of the century, the oilpatch was still hungering for an affordable horizontal stimulation method that reached beyond its classic "plug and perf" tool kit.

A Game-Changing Breakthrough Packers Plus stepped into that breach, pioneering open hole horizontal fracturing with expandable rubber packers. In 2001, two producers approached the Calgary-based private firm (30 per cent held by Schlumberger but independently operated) with horizontal prospects, one in the Montana Bakken and the other a supertight gas formation in Texas. Themig deployed two stimulation systems, then ran both operations within two weeks of each other. "We designed and manufactured those systems over an eight-week period, and we achieved a game-changing outcome," he says.

The Packers Plus StackFrac system has since been deployed on as many as 250 wells within a single field. Competitors have come up with broadly similar technology-for instance, Halliburton's Swellpacker system. The expandable packer approach enables producers to frac an open hole up to 11 times in a single sequence, starting at the end of the horizontal leg and working back in stages. Thanks to the savings in time, materials and reduced risk, open hole horizontal frac systems have won industry acceptance around the world. Expanding rubber packers, however, are limited to a maximum pressure of 10,000 psi. Also, their ball-activated control mechanism requires progressively smaller diameters of ball seat at each stage, which limits the total number of stimulation stages in the frac sequence. With horizontal wellbores now extending beyond 2,500 metres, that restriction becomes a more serious issue.

In any case, as a matter of policy, some producers prefer cemented casing to open hole completions. In response, Halliburton Group developed CobraMax H. "With this service, the number of frac intervals is not limited by mechanical restrictions," says Roch Romanson, a pinpoint stimulation specialist with Halliburton. Perforation is achieved with a water-jet bottomhole assembly deployed via coiled tubing. Sand plugs are used to isolate each stage for frac stimulation, which eliminates the risk of mechanical plugs.

Although shale is an impermeable rock, natural fracturing can create sweet spots. Shale gas production in some areas - Michigan's Antrim Shale, the New Albany Shale in the Illinois Basin, the Upper Devonian shale formations in the Appalachian Basin, the Louisiana Haynesville, the Woodford Shale in Oklahoma, and others - dates back as much as a century. Natural flows were usually modest, and had petered out in some areas by the late twentieth century.

The modern shale boom began virtually unnoticed with a vertical well drilled to 8,000 feet in the Fort Worth Basin by Mitchell Energy. The independent producer's interest was spurred because its shallower gas reserves in the same region were in decline. At a time when majors were focused offshore and deep conventional structures in locations like the Rocky Mountain foothills, Mitchell doggedly continued to amass data on the Barnett, and experimented with different fracturing treatments.

A Simple, Slick Solution Large gel-based hydraulic fracs - which use a polymer to thicken the fluid that carries proppant (typically sand) into the fractures - proved too expensive. Adding to the cost problem were the low gas prices that plagued producers through much of the 1980s and early 1990s. By the time gas prices began to rise, Mitchell had made a key discovery: slick water fracs work very well in the Barnett and other brittle shales (the Horn River Basin's Muskwa Shale in northeastern B.C. is also relatively brittle).

Because a brittle shale does not bend much, a modest amount of sand is enough to prop open the fractures, which reduces cost. Also, the light proppant load eliminates the need for gel carriers. The term "slick" refers to a friction reducing chemical that enables the water to be pumped more quickly into the formation. When horizontal drilling and multi-stage fracturing were applied, gas production took more leaps.

Devon Energy Corp., which purchased Mitchell in 2001 for $3.5 billion, aggressively extended its shale work. Micro-seismic monitoring indicated that the slick water fracture patterns were surprisingly complex, according to Halliburton's Romanson, while frac water invasion of adjacent wells conclusively demonstrated the reach of the reservoir cracking. The Railroad Commission of Texas, which regulates oil and gas in that state, estimates that the Barnett Shale has 27 tcf in place, and annual production surpassed a trillion cubic feet last year.

Explorers soon began applying the Barnett lessons in Canada. In 2003, ARC Energy Trust began breaking open the Upper Montney formation in northeastern B.C. Development surged two years later after ARC completed the play's first multiple stage frac horizontal well at a cost of $7.9 million. With five fracs along 1,500 horizontal metres, the well is still producing 1.6 mmcf/d.

With experience, costs are coming down. ARC recently drilled a 1,900 metre horizontal well, fraced it eight times, spent $5 million and achieved initial production of eight mmcf/d. The company reports finding and development costs of about $10 per boe at its Dawson project, a netback of about $40 per boe, and total production potential of about five bcf (nearly one million boe) for each well.

Northeastern B.C. has drawn the attention of global giants. In August, the Royal Dutch/Shell Group paid $5.9 billion to acquire Duvernay Oil Corp. With current production of about 27,000 boe/d, Duvernay owns 450,000 net acres in B.C. and Alberta's Deep Basin, virtually all of it characterized by tight gas prospects. It also owns processing facilities in these districts. Further north, Imperial Oil (controlled by Exxon Mobil) has jumped into the Horn River Basin. (For an up-to-date look at the Muskwa Shale, Canada's premier shale prospect, read the accompanying article on page 8.)

Alberta's First Commercial Shale Project In Alberta, Stealth Ventures Ltd. says it's close to profitability on the province's first commercial shale gas field, located north of Wainwright. The Calgary-based junior holds 122 sections (70% net) in the Colorado Shale. Of its initial 49 wells, 47 have been deemed producers. In July, Stealth initiated a 70 well drilling program that should be completed this year, with as many as 85 scheduled for 2009 if market conditions warrant.

Although the Wildmere project is tiny by Barnett standards, Stealth says that its full-cycle finding and development costs have been an affordable $2.28 per mcf. At a gas price of $7.50 per mcf, the unconventional junior projects a 35% return on investment and forecasts that a new well should pay out within 36 months. Twenty-two of its wells have been fracture stimulated. The company's production is scheduled to reach 7.7 mmcf/d by the end of this year and 18.4 mmcf/d by 2011. Stealth says it has at least 1,000 drilling locations on its current shale gas land base, assuming eight wells per section.

At the leading edge of shale gas development in Saskatchewan is another junior, Panterra Resource Corp. As an early mover in sprawling prairie districts that have little or no historical production, Panterra accumulated more than a million net acres in three core areas - Foam Lake, Moose Jaw and Shell Lake - in exchange for work expenditures. "We'd spent $7.3 million by this spring, which fulfilled our provincial obligation," Panterra president Fred Rumak says.

To date, the company has extensively drilled, cored and conducted fracs on a pilot basis. "There's no way to hurry this process," Rumak says. "We've hired topnotch consulting firms in the U.S. to evaluate our data, which takes time. Some of our reservoir engineering is now complete and we've got some completion recommendations. A 2-D seismic program will proceed this year. Although the methodical approach can be frustrating for investors and even for our board at times, a junior must proceed cautiously in this game if it wants to survive and ultimately prosper."

In New Brunswick, Corridor Resources Inc. says its Elgin block's Frederick Brook formation constitutes a "world class shale play with huge shale thickness over a large prospective area." This spring, the Halifax-headquartered firm reported that its E-67 vertical well encountered 1,200 metres of gassy shale. The junior producer, with a $71 million capital budget for 2008 and existing conventional gas production nearby, plans to drill and multiple frac a horizontal well in the Frederick Brook formation.

Chasing A Shale Superplay In Quebec Outside of B.C., and potentially in the same league, Canada's most dramatic unconventional gas prospects are the Utica and Lorraine Shales, now in play along the Saint Lawrence River in Quebec. At the centre of that development is Questerre Energy Corp., a Calgary junior that's attracted a pair of heavyweight partners through its original land holding of nearly two million acres.

On September 2, Talisman Energy Inc. announced test results from its Gentilly #1 well. The probe sits about 100 kilometres south of Quebec City. The vertical well reportedly flowed at 800 Mcf per day from one completed interval on a sustained basis during the 18-day test period. "We are encouraged by the initial results," states John Manzoni, Talisman's president and CEO. "We have additional testing to do on the well, including zones within the Basal Lorraine and Lorraine shale formation, but this is a very promising start to our unconventional program in Quebec."

The Lorraine shale sits on top of the Utica and can be up to 6,500 feet thick. The Utica shale ranges between 300 and 1,000 feet. Early indications show that both the Lorraine and Utica rocks are thick, porous and appear brittle and over pressured, all of which are considered conducive to fracture stimulation.

Its deal with Questerre gives Talisman the option to earn 760,000 net acres through drilling in Quebec. Talisman, a Calgary-based company, says it is in the early stage of evaluating rock properties and reservoirs. Its Quebec plans call for testing three to four more pilot areas over the next 18 months, including up to four more wells prior to year-end.

Meanwhile Forest Oil Corp. through its Canadian subsidiary has farmed into another block of Questerre's land. In April, the Denverbased unconventional gas company revealed results from two vertical pilot wells that had been drilled to a total depth of 4,800 feet in 2007. Production rates from the Utica Shale reportedly tested up to one mmcf a day. "Based on technical data and the vertical pilot well program, the preliminary net resource potential on Forest's acreage is estimated to be approximately four tcfe," Forest said in a press release in early April. Forest can earn a 60% working interest in this project, with the remainder divided between Questerre and Gastem Inc., a Montreal junior.

Questerre has also farmed out 600,000 acres in the Gaspe Peninsula to another Quebec junior, Junex Inc., retaining a five per cent royalty interest in any future production. Junex now holds a total of six million shale-prospective acres in the province. Forest is in the process of drilling three more Utica wells in Quebec, two on the Questerre-Gastem block and another on the Junex acreage, with results expected before year-end. Although Questerre president Michael Binnion is encouraged by results so far, the Calgarian cautions, "We're still at a very early stage of development."

The Pipeline And Water Factors Beyond geology, Binnion says Quebec can satisfy two other criteria that are crucial to shale gas development. "First, gas processing and pipeline capacity isn't necessarily available in every area, whether you're talking about northern B.C. or densely settled regions of the U.S. where rights-of-way may be difficult to negotiate. Second, water is required for fracturing purposes. It must be fresh and plentiful, and a local supply is not always readily at hand." The Texas Railroad Commission points out that a horizontal multi-stage frac in the Barnett Shale can consume 83,000 barrels of water.

In terms of production rates, a frac-stimulated shale well typically enjoys an initial flush, then declines by 65-70% during its first year. By the third or fourth year, output usually stabilizes at a rate which may endure for decades. Estimated ultimate recoveries of original gas in place are typically about 20% but the industry still has limited experience in that respect. Re-fracturing the same well after years of production will often liberate more natural gas.

In July, Germany's largest bank released a research report that concluded shale gas is probably a bonafide bonanza. Its authors, Shannon Nome and Patrick Johnston of Deutsche Bank Securities Inc., commented, "For all the seeming hype, we actually believe that this heavy focus on gas shales is very well placed." While shale gas currently represents an estimated 10% of U.S. production, the report forecasts that its percentage can double within the next three years. "In fact," the two analysts predict, "we believe shale gas will be the country's #1 source of supply growth over the next decade."