Shale plays in the U.S. are proliferating so fast, they have almost become routine rather than unconventional.

The latest attraction is the Ordovician-age Collingwood shale in northern Michigan. Named for the town of Collingwood in nearby Ontario, Canada, where the rocks crop out, the Collingwood formation was surface mined and retorted as an oil shale from 1859 to 1863, near Craigleith, Ontario, on Georgian Bay.

Today, some producers are looking at its potential with more modern techniques.

"The Collingwood is a localized uppermost member of the Trenton/Black River package of strata, which is a fine-grained organic-rich facies in the central Michigan Basin," explains Bill Harrison, professor emeritus and director of Western Michigan University's Michigan Basin core research lab, in the geosciences department.

"The Collingwood is present only in the north-central portion of the Michigan Basin, covering about 25,000 to 30,000 square miles, at depths ranging from around 9,000 feet beneath the surface to zero at the outcrop to the north in Canada."

It's common in the industry to refer to the Collingwood-Utica, in a nod to the overlying Utica shale, which covers perhaps 100 times more area than the Collingwood, among other differences.

"The thickest interval of Collingwood we've been able to map is only 40 feet thick, while the Utica ranges from 200 to 400 feet thick," Harrison says. "There have been shows in the Utica, but no well completions in Michigan, even though there has been some production from this zone in other parts of the country."

An intriguing aspect of the emerging Collingwood is that it is not a true shale; technically it's a fine-grained muddy carbonate—a micritic carbonate, Harrison explains. "We think this makes a big difference for the E&P companies because you don't treat a carbonate the same way as shale when trying to complete (a well)."

He notes the Collingwood's total organic content (TOC) is two to four times that of the Utica, tallying as much as 6.5% TOC in some of the test data they have.

For some time, operators have focused on the younger Devonian-age Antrim shale in Michigan, where about 10,000 mostly vertical wells have been drilled since the mid-1980s. It's another not-quite-shale shale, with high silica content and less than 50% clay, according to Harrison. The formation reaches about 3,000 feet deep in the center of the Michigan Basin, but wells drilled along the rim generally range between 400 and 2,500 feet in depth.

For some time, operators have focused on the younger Devonian-age Antrim shale in Michigan, where about 10,000 mostly vertical wells have ben drilled since the mid-1980s.

Gas produced from the Antrim currently accounts for almost 70% of Michigan's dry natural gas production, according to a Wood Mackenzie report, "Shale Sparks New Interest In Michigan Basin," by Alay Patel, upstream research analyst at the firm. The Antrim has produced more than 2.7 trillion cubic feet (Tcf) of gas, and WoodMac estimates its remaining potential is 10 Tcf.

Once majors such as Shell and others bowed out of the Michigan Basin early in the past decade, reportedly to seek more lucrative projects elsewhere, the area became a wide-open playing field for the independents.

Current interest in the Collingwood-Utica has been driven in large part by successful drilling results in the high-profile Marcellus shale play in Pennsylvania, along with promising results from wells drilled into the Utica in New York and Pennsylvania.

Leasing results

Leasing in the Collingwood play has been going on for at least a couple of years, some of it under the radar, via brokers participating anonymously for operator clients. Industry interest caught headlines in May 2010, however, when Encana announced it had been accumulating a significant land position in the promising new play during the past two years. The company said it acquired about 250,000 net acres at an average cost of about $150 an acre.

This was a bargain-basement price given that the state of Michigan land lease sale in May 2010 garnered an average price of $1,504 an acre when auctioning off about 100,000 acres. The highest bid was $5,500 an acre for a lease in Charlevoix County, according to the Michigan Department of Natural Resources and Environment (MDNRE).

"The sale took us all by surprise, bringing in $178 million," Harrison says. "In the whole history we've been leasing since the 1920s, we only had $190 million total. That one sale almost matched the entire 80-year history of leasing in Michigan, from state land anyway, and a lot of activity followed that sale."

"When that first well was announced, we had a steady stream of companies come to visit from all over country," says Bill Harrison, director of Western Michigan University's Michigan basin core research lab, in the geosciences department.

A bit of intrigue surfaced when Traverse City-based O.I.L Niagaran reportedly forked over $138 million for leases in several counties. The small firm (no more than four employees) reportedly was tight-lipped about its intentions, and some industry folks speculate it was picking up at least some of the acreage for other operators who preferred anonymity.

Also during the May sale, Chesapeake Energy Corp. picked up 80,000 net acres, according to Wood Mackenzie's report, which also noted Linn Energy acquired 25,000 net acres.

It's been a wild ride here for the past several months. However, the state's second lease sale, October 25, which offered up 450,000 acres to bidders—or four times the May sale—was a bit of a dud, relatively speaking. About half of the properties, or 273,000 acres, were leased. The auction brought in $10 million, or less than $40 an acre—a far cry from the May sale. A spokesperson for MDNRE says that a few more auctions will be needed to see if a trend emerges.

Exploration spark

Encana's announcement of its significant land position, along with information about results for its initial Collingwood exploration well in Missaukee County, is credited with sparking the sizeable land grab in May.

The St. Pioneer #1-3 horizontal well was drilled by Encana subsidiary Petoskey Exploration LLC to a total vertical depth of about 9,500 feet and total measured depth of about 15,000 feet. Encana reported in May that natural gas is being produced primarily from the Collingwood interval, with contribution from the overlying Utica shale, which is a typical clay shale, Harrison says.

During a 30-day initial production test, the well flowed about 2.5 million cubic feet a day, including natural gas liquids constituents and condensate, according to Randy Eresman, president and chief executive officer for Encana. He said the company plans to drill additional exploration wells this year that will help determine the play's ultimate potential.

Given that the Collingwood is an exploration play, mum's the word at Encana and other operators regarding specifics on current and planned activity.

Yet you can't hide a drilling rig.

"One of the test wells being drilled now, which I think is Encana, is at about 4,500 feet. My guess is if it produces, it will be in the oil window," Harrison says. "The first producing well at 9,500 feet, that's in the gas window in the Michigan Basin.

"The whole 5,500-foot horizontal leg in that first well is in the Collingwood, but where they're drilling, it's only 25 feet thick, with the maximum distance from the Utica about 10 feet," he notes.

"They did a 15-stage massive hydraulic frac in that horizontal leg and probably fraced up into the Utica, but we don't know for sure. Each perf zone was about 100 or 150 feet in the borehole, so they opened up a huge amount of rock.

"When that first well was announced, we had a steady stream of companies come to visit from all over the country," Harrison says. "We have at least a dozen cores in that interval where people passed through drilling for other targets, and we had one company after another here all summer long."

He notes that the university's core research laboratory has been collecting cores and data in the Michigan subsurface for almost 30 years, with the intent to preserve the geological materials and data to use in education and research, and to make available to the industry.

Giants move in

Operators who drill in the Collingwood may soon find themselves working alongside one of the Big Guys in the industry. Oil giant Chevron recently announced it will acquire Atlas Energy Inc. for $4.3 billion, which will place the major in the prolifically productive Marcellus shale play and various other plays, including the Antrim and the Collingwood, no doubt.

Atlas currently holds approximately 105,000 prospective acres under lease in the Collingwood formation, according to Phillip Koro, president of Atlas Gas & Oil Co. LLC and Atlas Energy Indiana LLC. Atlas also holds the mineral rights to more than 271,000 acres in Michigan where the company is a well-established producer in the Antrim shale.

"Atlas is well-positioned in the Collingwood with existing acreage in close proximity to existing midstream pipelines and gas-processing infrastructure," Koro says. "Atlas is developing its first exploration well in the Collingwood, in Kalkaska County. With little production data available for the Collingwood, Atlas plans to complete this well to determine the formation's potential productivity and economic viability before making further assumptions.

"Our target depth for our first well is approximately 9,000 feet below the surface," Koro says.

"Based on our understanding of the Collingwood, we expect our well in Kalkaska County primarily will produce natural gas, while areas in the northern section of the formation display the potential to produce liquid hydrocarbons. Additional testing is needed to ascertain the Collingwood's potential productivity."

BreitBurn Energy Partners LP has a strong position in Michigan, which accounted for about 59% of its 2009 production. The master limited partnership focuses on development drilling rather than exploration and is quite active in the Antrim shale. The firm is currently monitoring, executing technical work and consolidating its lease position in the Collingwood play as it evolves. Its leasehold sets it up to move quickly should the economics of the fledgling play appear to be solid.

"In November 2007, we purchased Quicksilver's business unit with about 90% to 95% of the assets in Michigan, for about $1.5 billion," says BreitBurn chief executive officer Hal Washburn, who co-founded the company in 1988 with Randy Breitenbach.

"We have 125,000 net acres in the prospective Collingwood-Utica area, and about 120,000 is below our current Antrim or other production. So, it's held by production, enabling us to watch the play develop. We've also acquired 5,000 acres or more since the play began.

"It appears there's a dry-gas window, a wet-gas window and an oil window in the play, and the majority of our acreage is in wet gas or the oil window, which makes for more robust economics today," he notes. "The dry gas is to the south where we don't have much acreage.

"We're in the very early stages of this play, and while the Encana well was a great first well in a shale play, it was not economic," Washburn emphasizes. "This play could be very interesting, but other wells have to be drilled because like other shale plays, it will take experimentation to see what works. The nice thing about Michigan is we have a great infrastructure and good take-away capacity as it's produced a lot of gas historically."

The Collingwood is a localized uppermost member of the Trenton/Black River package, and the thickest interval mapped so far of the shale is only 40 feet thick.

Historically, Michigan gas has garnered a premium to Henry Hub pricing owing to its proximity to Midwest and Northeast markets, along with declining production in Canada, according to Wood Mackenzie. Even when the demand for natural gas is low, there is ongoing potential to sell gas to storage facilities.

Even if the Collingwood wells can be developed economically, obstacles exist. Probably the most prominent centers around the hydraulic-fracturing process. The issue is permeability.

Most shales have little or no porosity and permeability. Where permeability is excessively low, the size of the gas or gas/oil molecules compared to the pore throats becomes an issue. For example, gas-molecule movement of a few feet per year has been modeled by Chunlou Li at BJ Services' shale-gas-technology group.

"The implication is if you don't place a high-permeability pathway close to where a gas molecule resides today in the reservoir, it will never find its way to the wellbore," says Randy LaFollette, manager of shale-gas technology at BJ Services. "There's no geological time to wait around for these things to migrate out at their own pace—therefore we frac."

Michigan has comprehensive laws and rules enforced by DNRE that regulate fracturing, along with all other aspects of hydrocarbon drilling and production, according to Hal Fitch, director of DNRE's Office of Geological Survey, which functions principally as a regulatory agency.

Fitch notes that about 12,000 wells have been hydraulically fraced in Michigan since the mid-1980s, most of them in the Antrim shale. He says DNRE has no evidence that hydraulic fracing has caused any adverse impacts to the environment or to public health in Michigan.

"Despite the benign history of hydraulic fracing in Michigan, it recently has become a public concern to many people, primarily due to issues raised in other states," Fitch says. "The concerns center on migration of gas or fracture fluids, water use, management of produced water, surface spills, and identification of chemical additives."

With the Collingwood play in its infancy, the potential for extensive development is unknown. Fitch emphasizes that the agency is taking a proactive approach in addressing large-scale hydraulic fracing and other issues associated with deep shale development.

The good news is that even though fracing in deep shale-gas wells may require large volumes of water on a per-well basis, Collingwood development is anticipated to require significantly fewer wells, he adds. The agency has proposed 640-acre spacing, but the input received from a few companies is that it's too early to establish a spacing system.

"We expect to go further," he says. "It's a matter of timing, when there's enough data to determine what the spacing should be." M

Louise S. Durham is a consulting petroleum geologist.

Comments