Future is unconventional

Oil sands key to bolstering Alberta's output; bitumen expected to account for 86% by 2016

Gary Park

For Petroleum News

Bitumen production is on a roll, while conventional crude and natural gas are headed in the other direction – all further reinforcement of a trend that started to take shape in the early 1990s in Alberta and is gathering pace.

Canada’s largest energy storehouse is, to all intents, heavily dependent on its unconventional oil and gas supplies to meet demand, the province’s Energy and Utilities Board (EUB) said in its 2007-2016 outlook report.

The regulator estimates Alberta can hike its crude oil and equivalent production to 3.5 million barrels per day by 2016, provided nothing extreme occurs to derail expansion of the oil sands.

The board makes no mention of the impact from a possible hike in Alberta government’s royalties, or higher costs stemming from federal and provincial environmental regulations.

Crude bitumen output surpassed conventional crude in 2001 and has maintained a relentless growth trend ever since, totaling 1.25 million barrels per day last year, up 18 percent from 2005,while conventional crude slipped 5 percent to 543,700 bpd, putting bitumen ahead of Alberta’s traditional source by 231 percent.

Non-upgraded bitumen and synthetic crude is expected to climb to 3.1 million bpd by 2016, rising from 62 percent of overall production in 2006 to 86 percent.

The EUB offers no hope of a reversal in the downward path for conventional crude, with large pools becoming increasingly difficult to find.

It said 1,956 wells were placed on production last year, up 4 percent from 2005, and expects that number will remain around 2,000 for the rest of the forecast period, without stopping the decline in production.

Alberta exited 2006 with remaining established conventional crude reserves at 1.6 billion barrels, down 2 percent for the year despite additions of 171 million barrels from drilling and revisions.

The ultimate potential for conventional oil is estimated at 19.7 billion barrels, which the EUB said could benefit from technological advances raising the average recovery efficiency from its current 26 percent.

Remaining established bitumen reserves are 173 billion barrels, which have been reduced by only 3 percent since commercial operations started 40 years ago, while the ultimate potential relying on established technology is 315 billion barrels.

Finance Minister Lyle Oberg said the growth of oil sands production would be taken into account during the current review of Alberta’s royalty rates.

Indicating a shift in his thinking from an earlier support for higher royalties, he said the EUB statistics show that the province will derive higher revenues as production climbs.

On the conventional natural gas front, record drilling has slowed the decline of marketable reserves to 38.11 trillion cubic feet (excluding 1.25 tcf of ethane and other natural gas liquids) entering 2007, but the EUB anticipates production will decline over the forecast period by an average 2.5 percent a year from last year’s 4.9 tcf – 76 percent of Canada’s total production.

The trend won’t be affected by the regulator’s forecast of 13,000 successful wells per year from 2007 to 2016.

Alberta ended 2006 with remaining gas reserves estimated at 40.5 tcf and an ultimate potential of 223 tcf, excluding coalbed methane.

Record drilling replaced 68%

The pace of coalbed methane growth has slowed after connecting 6,000 wells to pipelines since 2001, with the well count forecast to decline from 2,434 in 2006 to about 1,900 this year because of the scaled-based activities during low gas prices.

However, the EUB projects a recovery to 2,400 wells in 2008 and 2009, followed by 2,500 a year to 2016.

Remaining established coalbed reserves are placed at 877 BCF, confined mainly to “dry” coal seams in central Alberta, but there is no attempt to estimate the ultimate potential, which the Alberta Geological Survey (part of the EUB) has placed at 500 tcf.

The EUB is not worried about Alberta having sufficient gas supplies to meet the needs of its core market and believes the province will “easily meet” its requirements of 44 percent of total output by 2016.

But it warns that volumes available for shipment out of the province to the rest of Canada and the United States will shrink under an EUB mandate that requires the province’s needs must be met before any long-term removal permits are approved.

The outlook projects average WTI crude prices of US$62 per barrel in 2007, rising to US$69 in 2016 and average gas prices of C$7.25 per gigajoule in 2007 and C$8.35 in 2016.