Horn River Shales

?It’s not easy to get to Canada’s Horn River Basin. From the Lower 48, the first stop is Calgary. Next, an 800-mile car ride or chartered two-hour plane flight brings a traveler to Fort Nelson, British Columbia.

Fort Nelson is Mile 283 on the Alaska Highway, and the legendary road serves as the community’s main street. In its early days, the town was an outpost of North West Co., and more than 200 years later fur trappers continue to ply that trade. Today, the timber and oil and gas industries employ residents as well.

From the town, Horn River Basin shale-gas activity lies deep in muskeg, another two to three hours away.

This is tough and brutal country. Winters are pitiless, and temperatures skid to 40 degrees below zero (at that mark, Celsius and Fahrenheit scales converge). Unless an all-weather road has been built, muskeg is only passable when frozen. Otherwise, the area is an impossible bog.

Precision Drilling Rig #638 drills a Horn River Shale well for Devon Energy Corp. on its Komie Block, north of Fort Nelson, British Columbia. (Photo courtesy of Lowell Georgia)

Yet, its shale-gas potential could turn this isolated corner of Canada into one of the continent’s top gas fields. The Horn River Basin covers some 3.2 million acres, stretching from just north of Fort Nelson to the B.C./Northwest Territories border. The heart of the emerging shale play is thought to cover at least a million of those acres.

In-place gas volumes are stunning: the Canadian Society for Unconventional Gas estimates that as much as 500 trillion cubic feet (Tcf) of gas lies in place below the Horn River’s muskeg.

If a standard shale-gas assumption of 20% recovery is applied, the Horn River could hold up to 100 Tcf of recoverable reserves. Considered as a single field, that would place the Horn River in the rarified ranks of the top natural-gas accumulations on the planet. And this is brand-new, never-before-seen gas.

Auspicious geology

The Horn River shale play is cradled between two historic areas of oil and gas production. Along the basin’s eastern edge, the Slave Point carbonate platform initially produced from prolific reefal buildups; later, a horizontal drilling play in the overlying tight Jean Marie carbonate developed. A web of infrastructure from these activities laces across the platform.

On its western side, a dramatic fault system separates the Horn River from the Liard Basin. Production west of the Bovie Fault developed in Cretaceous sandstones at sprawling Maxhamish Field. This accumulation also spawned gas-collection and transportation facilities.

Most acreage in the center of the basin is already held by companies.

But within the basin itself, exploration was limited and without success. Since the 1960s, a few hundred wells were drilled in the Horn River Basin’s interior to no avail. Porous reservoir rocks were completely lacking, and production was never realized.

Nonetheless, it was well known that the quiet interior basin had accumulated tremendously thick, extremely fine-grained sediments. “These shales are locally quartz-rich, and not dominated by clay minerals, even though they are very fine-grained rocks,” says Vic Levson, Victoria-based executive director, resource development and geoscience branch, British Columbia Ministry of Energy, Mines and Petroleum Resources.

As the industry became comfortable with shale-gas development, several firms realized that shale in the Horn River might offer an attractive target.

Too, the province had been promoting the Horn River shales for some time. “We saw the shales developing in the

States and we knew we had some pretty good shale packages in B.C.,” says Levson. In 2004, the ministry released a comprehensive report on Devonian shales in northeastern B.C. “We compiled all existing information on the shales, most of which was taken from wells in the Slave Point reef play.”

Horn River shales are Upper to Middle Devonian in age, and their stratigraphy is unclear. There’s debate about whether the Horn River shales are all one formation, or if they should be divided into additional units.

Industry generally separates the shale into the uppermost Muskwa and Otter Park package and the underlying Klua and Evie shales, isolated from each other by a tight, thick carbonate zone. Regardless of lumping or splitting, total shale thickness reaches about 600 feet.

The shales vary internally and across the basin, thickening in various areas. “The upper shales—Muskwa and Otter Park—appear to be more prospective in some areas, and the Klua/Evie in others,” Levson says.

A land rush started in the Horn River Basin in 2006, when operators spent C$126 million on licenses in government sales. The next year, the province pulled in C$359 million for leases in the sparsely drilled basin. Sales in 2008 totaled an astonishing C$1.1 billion.

“Most of the center of the basin is now held by companies. There is still some open ground around on the margins, but virtually all the core area has been sold.”

The entire basin appears prospective for shale-gas production, says Levson, although there’s still a great deal to learn. Happily, lots of new data are coming available. British Columbia has a program of experimental schemes that allows operators to hold well data confidential for three years, and a number of these were issued in the Horn River during the past four to five years. As confidentiality periods wind down, more information will become available.

And what is coming out buttresses the high opinions already held about this striking new shale play.

Discovery to dominance

Calgary-based EnCana Corp. is widely credited with discovery of the Horn River shale play in 2003. The company encountered strong gas kicks in the shales while drilling a Middle Devonian carbonate test. EnCana was familiar with the region, as it was actively developing its Greater­­­ Sierra play in the Jean Marie carbonates to the east, says Mike Graham, executive vice president and president, Canadian Foothills division.

“It took us a little while to figure out the Horn River shales, but we eventually did,” says Graham. “We had a lot of help from our U.S. business units, because we weren’t used to the shales up here at the time.”

The company drilled a handful of vertical wells, took core, and completed and flow-tested the shales. “We were figuring out the shale’s attributes.”

EnCana began to accumulate acreage. In British Columbia, companies make requests to the provincial government to

In the Horn River Basin, operators drill two types of wells: experimental schemes, which allow for three-year confidentiality periods, and non-experimental wells.

Source: BC Ministry of Energy, Mines and Petroleum Resources, Oil and Gas Division, Geoscience Branch

post available Crown lands, and these lands are sold at public auctions. After EnCana launched its land program, other companies began to notice.

Apache Canada was also active at the sales, so the two firms decided to join forces going forward. EnCana’s position currently stands at 250,000 net acres. Most of its acreage is held jointly, but each firm still owns some tracts of 100% land. Horizontal drilling kicked off two years ago.

In 2008, the EnCana/Apache joint venture drilled seven Horn River wells; the most recent completion flowed gas at an average rate of just under 8 million cubic feet per day during its first 30 days of production.

“We’ve had wells online now for over a year, and we’re impressed with the decline rates. They are leveling out,” says Graham. “Obviously, time will tell. It’s still early.”

Certainly, the Horn shales look very good. They are wonderfully thick, from 150 to 350 feet per discrete interval; overpressured, in the range of 0.65 psi per foot; thermally mature; and they hold tremendous gas in place. “We think these shales have as much as 150- to 250 billion cubic feet (Bcf) per section.” Furthermore, the mineralogy makes the shales amenable to fracturing treatments.

“The Horn shales are similar to Barnett shale and have more gas in place,” says Graham.

EnCana’s drill-and-complete well costs are currently north of C$10 million. Once it gets its gas factory going, it expects costs to drop considerably. Initially, the company ran its laterals to 3,300 feet. Now, it drills 5,000- to 5,500-foot laterals. At present, the operator finds it’s actually cheaper to drill its wells than to frac them.

And, it’s doing more and bigger fracs. “Now we’re at a million gallons a stage, and as many as 14 stages per well,” says Graham. Stages are spaced some 400 feet apart, resulting in about eight-acre spacing per frac. “It’s similar to what’s being done in other shale plays—closer spacing really drives up recovery factors.”

EnCana measures its costs on a per-frac basis. It wants to bring costs on the Horn River fracs down to about C$750,000 each. It expects recoveries to range between 0.5 and 1 Bcf per frac.

A road stretches to the horizon from one of Devon's drilling pads in the Horn River Basin.

Naturally, current commodity prices present daunting economics. The Horn River Basin lies nearly at the end of the continent’s gas infrastructure, and the discount to Henry Hub is stiff. Processing is also required, as EnCana’s Horn gas contains close to 12% CO2 and trace amounts of H2S—just enough to be a real nuisance.

“However, we do have some real pluses going for us,” says Graham. “Our dollar has weakened quite a bit, which is good for producers. And the royalty system is very attractive in British Columbia. The government has done a tremendous job in incenting the industry.”

Within a handful of years, EnCana thinks it can pull the Horn River into the top half of its portfolio, and have supply costs sub-US$5 per thousand cubic feet (Mcf). “We’ve positioned our portfolio to have very low supply costs, and we think we’ll be one of the last producers standing even in a low-price environment.”

For 2009, EnCana and Apache plan 24 horizontal wells in the Horn River, mainly into the Muskwa and Otter Park. Initially, the partners budgeted about 40 wells, so the well count has dropped. However, the two dozen tests will feature longer laterals and more fracs, so the number of fracs has actually held steady.

“In the heart of the play, we think we can consistently drill wells that are capable of flowing 10 million cubic feet per day during the first 30 days,” says Graham. “We have the thickest, cleanest shales in the unstructured part of the basin, and we think they’ll be very economic.”

Currently, the company has approximately 6 million a day of net production from its interests in seven producing horizontal wells. EnCana is completing four wells on a pad in the Two Island Lake area, and will tie these into production shortly. By year-end, if all goes as well as planned, it could be producing close to 100 million gross a day.

“We think we could eventually produce 1 Bcf equivalent a day, net to EnCana, from the Horn River,” says Graham. “We see 200 to 300 Tcf of original gas in place in the basin; as in the Barnett, recoveries could go as high as 50% in places. “In a few more years, this could become one of our key resource plays.”

Lowering costs, raising rates

EnCana’s Horn River partner Apache Corp. was early to the play. The joint venture currently holds some 450,000 acres; half of that is net to Houston-based Apache.

“This play looks real. The numbers we are seeing are very encouraging, and our focus now is on reducing the unit cost of production,” says John Crum, Apache co-chief operating officer and president, North America.

Pipeline construction seemingly extends to infinity across the frozen muskeg. Sections are weighted to keep the line buried when summer temperatures thaw the muskeg.

“We believe we have gas on all our acreage, but we are concentrating our efforts in a fairly small area because we can build production volumes more quickly.”

The companies have zeroed in on the Two Island Lake area, in 94-O-8 and 94-O-9. As in many shale plays, the acid test for the Horn River is well performance on tight spacing. Drilling at Two Island Lake will investigate drainage area. The JV partners will continue to experiment with increasing both the length of laterals and number of frac stages in each lateral. At present, it appears that each additional frac stage adds to rate and recoverable reserves, but there will be a limit.

Apache is also intrigued with the lower Klua shale. The lower shale can be 150 feet thick at Two Island Lake, about half of the 320 feet attained by the upper shales. Rock evaluation data are strong, however, and the partners completed a Klua well in their 2008 program. It was fractured in four stages, and after six months is still producing about 1 million cubic feet per day.

“Results have been encouraging,” says Crum.

This year, Apache will drill 14 horizontal wells off a single pad into the upper Otter Park shale, and two wells into the Klua level. That pair will run immediately next to each other, to evaluate well performance on close spacing.

In a perfect world, Apache would prefer to drill out each pad with 28 wells, split evenly between the upper and lower shale packages. “But we’ll have a limited number of rigs working, so we’ll go after the biggest target first, which is the Otter Park.” It will save the lower shale for later.

“We can’t do anything about gas prices, so we’re working on lowering costs and getting higher volumes for the same costs,” says Crum. Pad drilling adds efficiencies, from well supervision to coordination of frac jobs.

One of the play’s challenges is its remote location. If the play goes as hoped, Apache wants to be able to ramp up volumes quickly. In that light, Apache and EnCana are rapidly adding infrastructure, putting in dehydration facilities and building a compressor station. A 24-inch, 40-mile pipeline will be ready this spring to carry gas from Two Island Lake to Spectra Energy Corp.’s pipeline system at the Cabin Lake compressor station.

The Horn River is a far piece from markets, and Apache figures its gas will likely sell at a discount to Nymex, basing its economics on a discount of about $2.38 per Mcf, including processing and pipeline tariffs. “The location affects both the price of doing things and the market on the other end,” says Crum.

“We still have a lot of hurdles to cross with this play.” Associated with any big gas development are environmental issues, and aboriginal and local effects have to be considered.

“But a great feature of the Horn River is it’s a blank slate. We have a chance here to get considerable volumes of gas out of the ground with minimal impact on the environment, and at the same time provide a lot of jobs for the Fort Nelson community. It can be a win-win for everyone.”

Rivaling the Barnett

Oklahoma City-based Devon Energy Corp. was interested in the Horn River play early on, intrigued by its parallels to its marquee Barnett shale assets in North Texas. It initially looked at B.C.’s Devonian shale potential in 2006 when it recompleted a Muskwa shale interval in a suspended well in Wildmint Field, 60 miles northeast of Fort St. John. Positive test results spurred interest in acquiring a land position in the Horn River Basin, where the shale is thickest.

Devon attended its first sale of Horn River Crown land in 2006, and rights went for C$800 to C$1,500 per hectare (one hectare equals 2.47 acres). “Land was never cheap; a company had to believe in the play without much information,” says Brent Snyder, Horn River exploration manager, Devon Canada.

In the 2006-07 winter season, Devon drilled and cored a stratigraphic test on its central block. That well intersected 500 feet of shale and flowed gas after completion.

“Results were good, which raised our confidence in the play,” says Gerry de Leeuw, Devon Canada vice president of exploration.

Indeed, the Horn River shales compared quite favorably with the Barnett shale, a play mastered by Devon in the U.S. Although both occur at depths between 6,500 to 8,500 feet, the Horn River shales are thicker, hotter, more highly pressured, more siliceous and contain more gas in place per section. Devon estimates the Horn River shales hold between 200 and 300 Bcf of raw resources per section, compared with the Barnett’s 75 to 200 Bcf.

The company jumped into the leasing fray that rocked B.C. in 2007 and 2008. After the dust settled, Devon had acquired 153,000 acres of drilling licenses in the Horn River, in several chunks of land in the central, western and northern reaches of the play.

“Each block is large enough to be developed as a stand-alone project,” says Snyder. Government leases have two phases: an operator has five years to validate a license with a well and, after validation, licenses are held for an additional nine years. Cmpanies can validate a number of sections with each well, so the pressure to hold leases is light when compared with the situation in the U.S. Devon, for instance, needs to drill just 20 additional wells to validate its entire position.

In Devon’s central Komie area, depth to the base of the 650-foot gross shale section is 8,700 feet. On its western block, wells need to reach 9,200 feet to penetrate the entire shale section.

To date, Devon has concentrated its work on its Komie Block, a bit south of EnCana and Apache’s Two Island Lake area. In 2008, Devon drilled a stratigraphic test and two horizontal tests. This year, it has drilled three horizontal wells and is shooting 3-D seismic across its block.

“We have approximately 500 feet of high-grade shale, in the Muskwa, Otter Park and Evie zones,” says Snyder. “We’re still trying to define net pay, as we are in the early stages of play development.” The high-resistivity shales are overpressured, competent and have porosities around 5%. Some swelling clays are present in overlying shale and carbonate strata, so Devon drills its wells with oil-based muds.

To date, it has drilled laterals varying from 2,500 to 4,600 feet in length, and fractured them in multiple stages. Two wells with 2,500-foot laterals were treated with four stages each. “Per frac stage, we’re seeing similar results on our wells to what other operators have reported,” says de Leeuw.

“Our challenges right now are drilling and getting the completions designed just the way we want. It’s a classic resource play. Now that we, and others, have tested the play, there’s very little risk on the geology,” he says. “It’s mostly commercial risk: how do we get the wells drilled and at what cost?”

Devon’s initial pilot wells run C$12 million each; that cost should drop to some C$8.5 million when it shifts to full-scale pad developments. The pads allow numerous efficiencies, particularly in logistics and personnel use. The company is also investigating potential of the Mississippian Debolt as a water-source and -disposal zone on its block, another cost-saving measure.

Currently Devon produces 3 million a day from the Horn River play. “We see potential for 300 million a day in raw gas production from our Komie Block alone,” says de Leeuw. “Across our entire position, we think we have potential for raw gas recovery of up to 1.2 Tcf and net potential production of 700 million cubic feet per day.”

That compares quite favorably with the Barnett. Devon’s net production from that North Texas shale play stood at nearly 1.2 Bcf a day during the fourth quarter of 2008.

Northwestern story

While Devon, EnCana and Apache are occupied in the east-central slice of the basin, there’s another theater of activity on its northwestern side.

EOG Resources Inc., Quicksilver Resources Inc., Stone Mountain Resources Ltd. and Ramshorn Canada Investments Ltd. each have sizeable positions in this corner. Their areas of interest lie east of the Bovie Fault and gas infrastructure serving Maxhamish Field.

Private firm Stone Mountain Resources Ltd. was formed in April 2006. It’s backed by First Reserve Corp. and Quintana Energy Partners LP, and the balance is owned by management and a few Calgary-based individuals.

“Initially, we were a conventional player looking at northeastern British Columbia,” says Harvey Klingensmith, president and chief executive. Stone Mountain bought a small public company that held some scattered acreage in the Horn River Basin, and the leases were expiring.

In winter 2007-08, it drilled a pair of vertical wells to extend licenses on two parcels of acreage. It cored and logged the wells, and was deep into its evaluations when news of the basin’s potential began to break.

Stone Mountain has partnered with Ramshorn Canada Investments, a subsidiary of Nabors Industries, on the Horn River acreage. The pair formed the Stone Mountain Venture Partnership, operated by Stone Mountain Resources. The entity holds 37 sections of land. Ramshorn has an adjoining 34-section block that it holds 100% as well.

To date, the partnership has completed one vertical well and drilled and completed two horizontals. A third horizontal is currently in completion, and a fourth is being drilled. Additionally, Stone Mountain is operating the construction of a 60-million-cubic-foot-a-day gas plant, which will be owned by Ramshorn Canada.

Stone Mountain has not yet released test results, but is encouraged by what it has seen, says Klingensmith. “Our drilling results have been very good, and we consider this a world-class shale-gas play.”

The operator has built two 20-acre pads, each capable of hosting up to 24 wells. At present, two wells are completed on the first pad and two are drilled on the second. Its total for 2009 will be seven horizontals, split between the pads.

Work can continue year-round and production from the initial batch of wells will start shortly. That’s because last year the partners built a 10-mile, all-weather road and laid a 15-mile, 12-inch pipeline to connect their gas to Spectra’s Maxhamish system. The road, which joins the Fort Liard highway, qualified for British Columbia’s infrastructure credit, a nice boost.

After Stone Mountain put in the road, it made a deal with neighboring operators EOG, Ramshorn and Quicksilver that allowed them use as well. “It’s an example of parties working together to utilize the infrastructure in a very remote area,” says Klingensmith.

“We expect this to be a major producing area for 30 to 40 years, and we’re in it in the beginning,” he says. “At current gas prices, the economics of the Horn River are not as robust as we would like, but we are thinking in longer terms.”

Market options

While the Horn River Basin has no infrastructure in its middle, its eastern and western flanks have produced gas for decades. For more than 40 years, Calgary-based Spectra Energy Corp. and its predecessor companies have operated more than 600 miles of gathering lines along the basin’s sides.

Additionally, Spectra’s Fort Nelson plant is one of the largest sour-gas processing plants in the world. Built to handle gas produced from Slave Point reefs, the Fort Nelson gas plant currently operates at half of its 1-Bcf-per-day capacity.

Spectra recently held an open season and received firm commitments of 760 million a day for gathering and processing capacity from seven Horn River Basin producers. Starting this year, Spectra plans to reactive existing capacity at its Fort Nelson plant and add new processing capacity at its Cabin Lake compressor station.

Initially, Horn River Basin operators expect to fill up the Spectra system. Beyond that, a group, headed by EnCana and including Devon and Apache, plans to build a processing plant at Cabin with initial capacity of 400 million a day. “That will be in addition to Spectra and will be onstream in 2011,” says EnCana’s Graham.

EnCana is applying for approvals for a plant with capacity of 800 million a day, but that can be further expanded in 400-million-a-day increments depending on future needs and regulatory approvals.

Gas sold into Spectra’s system travels south and east through British Columbia to markets in the Pacific Northwest. “We eventually want to access eastern markets as well,” says Graham. A connection from Cabin to the Nova system would allow Horn River gas to travel to those premier destinations.

So, the Horn River has all the right stuff: thick, attractive shales; encouraging drilling results; long-lasting land positions; and connections to markets. Its development may be slower in this price environment than it would have been a year ago, but it will certainly be developed and will, within a few years, take its place among the top gas-producing basins on the continent.