Digging Into The Duvernay

Early results from Canada's oil-prone Duvernay shale have been drawing the industry's attention to west-central Alberta. The formation is an established source rock of light oil, and the play's fairway is vast, stretching from the Peace River Arch in the north to Calgary in the south. Covering an area over 300 miles long and 100 miles wide (about 19 million acres, or 12% of Alberta's total extent), the Duvernay offers a target, in terms of acreage, three times bigger than the red-hot Eagle Ford shale in Texas.

The play's early well results, rock quality, overpressuring, resource potential and economics have strengthened the expectation that the Duvernay could become the Canadian equivalent of the Eagle Ford.

The list of Duvernay operators with licenses or drilled wells includes an array of companies both large and small: ARC Resources, Athabasca Oil Sands, Bonavista Petroleum, Bellatrix Exploration, Chevron, Celtic Exploration, Canadian Natural Resources, ConocoPhillips , Charger Energy, Encana, Husky Energy, Longview Oil, NGL Energy Partners, PetroBakken Energy, China Petroleum & Chemical Corp., Royal Dutch Shell, Abu Dhabi National Energy Co., Trilogy Energy and Talisman Energy. A number of privately owned companies are also active.

We divide the emerging Alberta play into three sub-regions: the North Basin, West Shale Basin and East Shale Basin. Drilling has centered to date on the Kaybob South area in the North Basin, which covers more than 1,800 sections (some 1.2 million acres). Drilling is also taking off in the Willesden Green-Pembina area, a part of the West Shale Basin where operators are active across 600 sections (some 400,000 acres).

A new horizontal well drilled recently by Canadian Natural Resources between the two areas strengthens our belief that the play will be productive throughout much of the fairway, if not all of it. Sweet spots will undoubtedly emerge; to date most companies have focused on the overpressured gas-condensate window.

Catalysts for increased activity include operator disclosures of improved production results and land holdings in the gas-condensate window, and results from key wells extending the play. Based on recent well-permitting activity, we expect announcements to pick up through 2012.

The Duvernay is vast, and like the Eagle Ford, is anticipated to have oil, condensate and gas windows.

Economics

We examined the potential economics of the play based on an Eagle Ford analog, since not much public production data is available yet. Economics are greatly aided by Alberta's royalty incentives, including the 36-month (producing) 5% Crown royalty rate for shale-gas wells. Most Duvernay wells also qualify for the Natural Gas Deep Drilling Program (NGDDP) credit after the shale-gas royalty expires, extending royalty benefits out to 60 calendar months from the well's finished drilling date.

With only a handful of producing and tested wells, it is difficult at this point to build a definitive type curve. Our current Duvernay curve is based on the Eagle Ford East wet-gas window, with a post-processing estimated ultimate recovery (EUR) of 3.5 billion cubic feet equivalent and an initial 30-day rate of 5.5 million cubic feet equivalent per day, comprised of 2.9 million cubic feet per day of gas, 90 barrels per million cubic feet of condensate and 45 barrels per million cubic feet of natural gas liquids (NGLs).

Using flat $90-per-barrel WTI and $4.50-perthousand-cubic-feet (Mcf) Nymex, and including royalty incentives that result in five years of 5% royalty, the net asset value (NAV) of the type well is $3.9 million. Almost 80% of the NAV can be attributed to the royalty incentive. This type curve has yet to be validated by public data, but early gas rates are not far off, according to company disclosures and information in the public domain. The liquids rates, which can be difficult to validate from public sources and will vary with depth and other reservoir properties, are key to the economic success of this play.

Holding oil flat at $90 WTI, the breakeven gas price for our proposed Duvernay type well is $0.90 per Mcf (Nymex); removing the royalty incentives drives the number up to $3.66 per Mcf. Using a 20:1 ratio of gas-to-oil prices and including the royalty incentives result in breakevens of $3.42 per Mcf and $68 per barrel WTI.

The pace of drilling in the Duvernay is likely to lag the frantic tempo seen in U.S. shale plays, largely because Alberta's Crown land tenure system does not stimulate such activity. Lands acquired since sales took off in 2009 still have two or more years remaining in their initial term.

One nonproducing vertical well on a land license can easily hold 18 or more sections for an additional five years, and favorable one-year extensions to Crown leases can be obtained. Combining to slow drilling's tempo are the tenure system, the lack of a poster-child boomer, and minimal fears of competitive drainage because it is a tight shale.

While much of the Duvernay land holdings are newer, with no pending expiry issues, many operators with pre-existing operations and positions in the fairway have been busy drilling land expiries. Leading the drilling charge are Athabasca Oil Sands, Bonavista Petroleum, Bellatrix, Celtic Exploration, Husky Energy, NGL Energy Partners, PetroBakken, Trilogy Energy, and Yoho Resources, which have varying levels of shale and tight formation experience.

Larger caps with new land holdings, a roster encompassing ConocoPhillips, Canadian Natural Resources, Encana, and Talisman Energy, don't appear to be in any rush and have been more active on nonexpiring, newer lands. TAQA, the private E&P unit of Abu Dhabi National Energy Co., has continued to actively chase expiries, probably on old PrimeWest and Northrock holdings.

Some preliminary production figures have emerged from Celtic, ConocoPhillips, and Trilogy’s early horizontals, among others, and results are improving over time.

Royal Dutch Shell has also been pursuing expiries and has been an active acquirer, as evidenced by recent changes in well license names that show the company has purchased a portion of PetroBakken's Duvernay rights for C$82.5 million. The sale, announced April 11, consisted of 46.5 net sections and two wellbores.

Operators have focused on drilling land licenses instead of leases. This allows them to hold more land with each well drilled, and they do not need to establish productivity, something required under a lease. The combination of thicker pay, location in the gas-condensate window and more expiries probably have driven activity to date in the Kaybob South area.

Early results

Some preliminary production figures have emerged from Celtic, ConocoPhillips, and Trilogy's early horizontals, and results are improving over time. Like others following the play, we await additional well data and higher rates. Commitments by operators to move into development mode are a year or more away.

In addition to the wells listed in the accompanying table, Yoho on February 14 issued a press release with test rates on its new operated Kaybob South horizontal located in 13-22-62-21W5, a well drilled 50-50 with Celtic. Test rates look positive and establish this well as the best producer to date, even though it came up a little short on lateral length, in our opinion. Cleanup rates up casing were as much as 6.8 million cubic feet per day, followed by an 11-day flow test up tubing at rates between 6- and 7.7 million per day at flowing tubing pressures of 1,450 to 2,174 pounds per square inch (psi). Field condensate rates at the end of the test were 658 barrels per day.

Early well results, rock quality, overpressuring, resource potential and economics have strengthened the expectations for the Duvernay shale in relation to other shales.

On April 11, Bellatrix Exploration announced results from its first well, a horizontal located in 8-24-44-10W5 in the Willesden Green-Pembina area of the West Shale Basin. This is a key location, since it is the first well with press-released results and the second producer in the area.

The first area well and producer was drilled by ConocoPhillips about 15 miles east at 2/11-16-44-7W5. Bellatrix's reported overpressuring at 0.81 psi per foot extends the overpressured trend across the fairway to Kaybob South, 120 miles to the northwest, where we have observed similar values, a very positive result. While the company encountered minimal liquids, up-dip shallower wells to the east in less mature areas should encounter more liquids.

For the Duvernay in the Kaybob South area, we calculate a raw gas-in-place (GIP) estimate of 70 billion cubic feet per section, close to Trilogy's estimate of 75 billion. With a recovery factor of 35% and four wells per section, the recovery works out to about 6 billion cubic feet per well. A more optimistic evaluation of pay parameters increases the GIP estimate to 130 billion cubic feet per section—almost double.

The next year will reveal far more about the potential of this vast oil and liquids-prone shale in Alberta—and whether it will rival the resource base of its U.S. cousin, the Eagle Ford shale.

Ross Runciman is a vice president of energy research at ITG Investment Research and has more than 20 years of industry experience. Brook Papau is an associate in energy research at the firm.

As of the date of the submission of this article, the authors have a financial interest in the securities of Canadian Natural Resources, Husky Energy, and Talisman Energy. As of 12 months from the date of submission of this article, ITG Investment Research Inc. and/or its non-broker-dealer affiliates has provided research services and/or products to ARC Resources, Canadian Natural Resources, Chevron, ConocoPhillips, Encana, and Talisman Energy for remuneration.