Some Downs, But a Lot That’s Up in Canada

American Association of Petroleum Geologists (AAPG)
Contributors: Ross Clark

What’s up with Canada, eh?

This seems like the perfect time to summarize Canadian oil and gas activity in 2012. With all the talk around unconventional resources, pipeline approvals, environmental footprint of oil sands production and United States energy independence, what’s happening in Canada?

First, we have had some significant downs – total wells drilled and commodity prices mostly, and increasing export capacity is still sometime in the future.

On the upside, Encana’s Deep Panuke gas field on the Scotian shelf should be on stream by the time you’re reading this with capacity of 300 mmcfg/d. Serious exploration opportunities are being pursued in unconventional oil and gas resources.

Drilled wells.

One indication that activity is down and not up in Canada is the number of wells drilled in 2012. Operators drilled 11,070 wells, down 14 percent from 12,869 in 2011.

This is the second lowest count in the last decade, according to the Daily Oil Bulletin (Jan. 28, 2013). Only 2009 had fewer wells drilled.

This is largely reflected in the shift to horizontal drilling for oil targets versus vertical well gas targets, as Canadian gas prices continue to feel the squeeze from extraordinary gas production growth in the United States and generally warmer winters.

Commodity prices.

Commodity prices always are good for discussion – and sometimes, some heated debate. Canada finds itself in a position not dissimilar to where the country was a few years ago, with current prices for various products settling at steep discounts to world and North American commodity markets (see accompanying table).

Probably of most significance to Canada is the beginning of a significant discount to West Texas Intermediate (WTI) for Canadian light crude oil and a widening differential between light and heavy crudes.

Historically the differential has been small, with Canadian prices a few percent and a few dollars lower, but in 2012 Light Sweet at Edmonton to WTI prices were discounted 7 percent, or about $7 per barrel.

However, of note is the trend – in December 2012 the spread was 16 percent, or $13.99.

Of even more interest is the widening differential between heavy and light crude prices. The price differential more than doubled between 2009 and 2012 ($10.55 to $21.54), but in December 2012 the differential was over $30 per barrel.

If the trend continues or stays the same, corporate capital budgets and government budgets will be significantly impacted.

Unconventional opportunities.

This is not an exhaustive list of activity or operators, but is intended to summarize the newer projects that are in the de-risking stage and their potential impact as they mature as exemplified by the Saskatchewan Bakken oil development.

Shale gas

♦ Duvernay: It is still early in the de-risking phase of the Devonian Duvernay play – but with attributes characterized as being similar to the Eagle Ford, there is a great deal of interest in the success of the play.

The majority of activity is located in central Alberta near Kaybob; others are exploring at Willesden Green.

As of late December 2012, according to public records, there have been approximately 90 horizontal wells licensed and 50 rigs released since 2010 spread across 18 operators. Public information available from the Energy Resources Conservation Board on performance is very sparse mostly due to the very recent activity.

Shell Canada is the most active driller. They have licensed 17 wells and drilled six, but there is no public information on performance.

Celtic Exploration is the next most active driller, having licensed 15 wells and rigs released 12. Their best well, based on public information, after the first four months of production settled in at just over three mmcfd with potential of about 60 bbls/mmcf of C3+ liquids or about 660 boepd.

Other operators active in the play are Husky Oil Operations (eight licensed wells, three drilled), Trilogy Resources (eight licensed wells, five drilled), Chevron (five and three) and Talisman (five and four).

Encana Corporation is exploring the Duvernay further south at Willesden Green, where it is shallower and probably less liquids’ rich. Public records indicate they have licensed eight wells and rig released six.


♦ Southern Alberta Bakken – The “Alberta Bakken,” as it has been called, also is very early in the de-risking phase, although much has been learned; the moniker has come to describe the petroleum system that encompasses reservoirs both above and below the Bakken Formation.

Horizontal completions have been made in the Bakken, Exshaw and Big Valley.

Since the first wells came on stream in late 2010, there have been over 130 wells (mostly horizontal) drilled to test the various reservoirs. Peak production was 1,300 bopd and 1.5 mmcfg/d from 22 wells.

Currently there are 33 producing wells making 400 bopd and 700 mcf/d gas. The best wells have first-three-month average production of about 300 boepd.

The top four horizontal well drillers are Deethree Exploration (29 licenses, 15 producers), Murphy Oil (26 licenses, five producers), Crescent Point Energy Corp. (22 licenses, eight producers) and Shell Canada Limited (14 licenses, four producers).

♦ Saskatchewan Bakken – The Bakken of southeast Saskatchewan, although mature, continues to be an active area.

There were 202 wells licensed and 103 producing wells drilled from January to December 2012. These wells were producing about 10,000 bopd, or about 100 bopd per well. Total Bakken production as of October 2012 was nearly 60,000 bopd from approximately 2,000 active wells with cumulative production of over 90,000,000 bo.

Although 17 different operators licensed horizontal wells targeting the Bakken Formation, PetroBakken Energy continues to be the top driller, having licensed 106 wells. Crescent Point Energy was the number two operator with 34 wells.

♦ Northwest Territories Canol Shale – MGM Energy spudded the East MacKay I-78 well on January 27, 2013. The well is targeting the Canol Formation shale and Bluefish member of the Hare Indian Formation on Exploration License 466B in the Central Mackenzie Valley. The well is a vertical test to be drilled to a depth of approximately 2,050 m.

Other players in the region are Husky (two wells drilled this past winter), ExxonMobil, Imperial, Shell and ConocoPhillips (three wells drilled).

The Canol shale play is said to be larger in areal extent than the Eagle Ford. The Canol shale is the principle source rock for the Norman Wells oil field discovered in 1920. Over 220 million barrels of oil has been produced from the Devonian Kee Scarp Formation.

The Canol shale is known to be naturally fractured and brittle due to chert and dolomite cementation, which should make the Canol shale a good candidate for exploitation using horizontal multi-stage hydraulically fractured wells.

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Carol Cain McGowen is the development manager for AAPG's Regions and Sections. She may be contacted via email , or telephone at 1-918-560-9403.

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Ross Clark is president of AAPG’s Canada Region.

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