Atlantic Oil: How Optimistic, How Realistic?
By Tom Standing
Reprinted from ASPO USA weekly newsletter.
As a friendly neighbor, Canada is arguably the most valuable foreign supplier of oil to the U.S. Canada nosed out Saudi Arabia to become the largest supplier to the U.S. in 2004 and 2005, and has been among the top four suppliers since the mid-1980s. Pipelines bring crude oil and refined products directly into the northern tier states. In March, the first synthetic crude oil to be extracted from Alberta's "oil sands" was pipelined 2,200 miles at 80,000 b/d to refineries in Oklahoma. Operators plan to expand capacity to 190,000 b/d. With U.S. oil imports increasing, Canada's contribution is vital to future U.S. supply.
In their June 2005 "Worldwide Liquids Capacity Outlook to 2010," Cambridge Energy Research Associates (CERA) projects Canada's "conventional liquids production capacity" will hold steady through 2010. CERA expects expanding production from new fields in the Atlantic east of Newfoundland (White Rose produces in early 2006, Ben Nevis-Hebron and Avalon produce by 2010) to offset the decline of mature resources in the West. Superficially, it sounds plausible, but it warrants careful analysis that CERA does not provide. With stable production of conventional oil, CERA projects a 35% increase in total liquids capacity by 2010. Such robust growth would propel Canadian oil production continuously into record territory exclusively through expansion of mining and steaming of bitumen-laden sands in northeastern Alberta. We will test the veracity of that rosy projection in this two-part Commentary. History of Conventional Oil Production in Canada
To examine the progress of conventional oil, we separate production in the Atlantic region from that in the West. Resources in Alberta and Saskatchewan have always dominated Canadian oil production. The great bulk of resources were discovered from the late 1940s through the early l960s. Today these are no longer flush oil fields.
The industry gradually built production rates through the l950s and 1960s, passing one million b/d in 1968. The accompanying graph shows that production in the West peaked in 1973 at 1.8 million b/d. The first giant discovery in the Atlantic offshore was still six years away, and production from the oil sands came only from pilot projects.
Western production slipped until 1982, but recovered and held steady through 1992. With increasing drilling rates during 1993-1997, production reached a secondary peak in 1997. Despite record-high drilling rates after 1999, production declined 3.4% per year from 2000 to 2005. If the decline continues at 3.0% per year after 2005, western production will lose about 150,000 b/d by 2010. By any reasonable analysis, the industry will not be able to offset western decline with new production in the Atlantic.
Aggressive Development of Atlantic Oil
We can expect Atlantic production to peak by 2008. Hibernia and Terra Nova fields are now and will remain "king" and "queen" of the Atlantic. Estimated ultimate recovery (EUR) of Hibernia is around 900 million barrels. Hibernia began producing in late 1997 and produced about 460 million bbl by yearend 2005, roughly half of its EUR.
Operators continue to drill Hibernia aggressively to maintain a production rate of 200,000 b/d. In 2003 they drilled 7 wells from the single Hibernia platform, totaling 31 miles of hole. One well set the world record for longest borehole, 5.9 miles to tap a new reservoir. They will drill two more extended-reach wells in 2006. Operators will also delineate reserves in 2006 for the Avalon sands, also part of Hibernia. Despite reserve additions and the Avalon sands, the large fraction of produced reserves at Hibernia points to a production decline in 2007. The timing and rate of decline are uncertain, but Hibernia's production might decline by 70,000 b/d in 2010, thus producing 130,000 b/d.
Operators rate Terra Nova at "370-470 million bbl of proved and probable reserves." Development drilling will continue, similar to the pace at Hibernia. Terra Nova produced 105,000 b/d in 2002, its first full year of production. By yearend 2005 Terra Nova had produced 170 million barrels, approaching 40% of the upper limit of its EUR. Thus it has about two years of flush production at 130,000 b/d remaining before decline sets in. An optimistic outlook is for Terra Nova to produce 100,000 b/d in 2010. Terra Nova teamed with Hibernia to produce about 330,000 b/d in 2005.
Resources for 2010
White Rose is a prolific but smaller field that began producing in November 2005. Operators estimate its "proved and probable reserves" at 200 million barrels. They expect it to reach a plateau rate of 100,000 b/d in mid-2006. But such a high ratio of production to reserves would lead to a steep decline by 2009. Its production rate in 2010 might be around 60,000 b/d. Ben Nevis-Hebron, however, will not be prolific. In February 2002, Chevron and its partners deferred development indefinitely for poor economics, citing poor reservoir properties, complex geology, and heavy oil. Chevron's vague statement that BNH "...may have longer-range development potential," could be why CERA expects BNH to produce by 2010. BNH would contribute minor production anyway because each well would drain a small volume of rock at low rates, regardless of "advanced technology."
Hibernia, Terra Nova, and White Rose are likely to be the only Atlantic fields producing in 2010. Their combined production will be roughly 290,000 b/d, about 40,000 b/d below 2005. But CERA expects production growth in the Atlantic to offset declining conventional oil in the West. If the West loses 150,000 b/d, Canadian conventional oil production will decline by 190,000 b/d during 2005-2010.
- "Worldwide Liquids Capacity Outlook to 2010," Cambridge Energy Research Associates, 2005
- "20th Century Petroleum Statistics," DeGolyer and MacNaughton, 2005
- Oil and Gas Journal, Worldwide Production Reports, final issue each year
- "Canadian Industry Broke Records During ‘97," Oil and Gas Journal, June 22, 1998
- "Canadian Drilling Sees a Decade of Improving Success Rates," Oil and Gas Journal, September 22, 2003
- "Forecast and Review," Oil and Gas Journal, January 16, 2006
- www.ogjonline.com search by name of any oil field
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