Oil sands crib sheet: Production, pipelines and new technology

From takeovers to thermal evaporators, the oil sands are a global concern

September 01, 2012

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Alberta’s oil sands have fast become a global concern. Growth projections that see production doubling by the end of this decade are rife with challenges.

Pipeline constraints, cost overruns, competition, water use and greenhouse gas emissions are particular flashpoints. Those and other issues are documented here, because hey, you never know when an intimate knowledge of thermal evaporators may come in handy.

The Oil Sands Index

Production, costs and markets by the numbers

525,000 BPD The capacity of Enbridge Inc.’s proposed Northern Gateway pipeline
408,000 BPD The volume of oil nine companies committed to ship on Kinder Morgan Canada’s expanded Trans Mountain pipeline
$500 MILLION What Enbridge Inc. committed to spend to bolster safety features on its Northern Gateway pipeline after the U.S. National Transportation Safety Board released the results of its investigation into a 2010 pipeline rupture on the company’s Lakehead system
$6 BILLION The revised capital cost of Enbridge Inc.’s Northern Gateway pipeline
$4.1 BILLION The capital cost of a proposed expansion to Kinder Morgan Canada’s Trans Mountain pipeline
$3 TRILLION The value of China’s foreign exchange reserves
65% The percentage of Canadians in a May 2012 Alberta Oil poll conducted by Leger Marketing who thought Canada should not allow foreign ownership in oil sands development
44% The growth in Canadian inward foreign direct investment attributable to China between 2008 and 2010

Sources: Canadian Energy Research Institute; Canadian Association of Petroleum Producers; Wood Mackenzie; Baker Institute; Petroleum Human Resources Council of Canada; Conference Board of Canada; International Energy Agency

The proposed takeover of Nexen Inc. by state-run Cnooc Ltd. has raised eyebrows for its sticker price and political implications. A snapshot of the deal that shook Calgary (and Washington)

The Bid

$15.1 billion What Cnooc Ltd. offered for Calgary-based Nexen Inc. in 2012
$27.50 The price per common share offered by Cnooc to Nexen shareholders
61% The purchase price premium
$4.3 billion Nexen’s current debt will remain outstanding

What Cnooc Gets*

20% Increase in production
30% Increase in proved reserves
7.23% Stake in the Syncrude Canada consortium
20,000 Daily net production in barrels of oil equivalent from Nexen’s Long Lake oil sands property
17,000 Daily net production in barrels of oil equivalent from Nexen’s share of the Syncrude consortium
13,000 Daily net production in barrels of oil equivalent from Nexen’s Gulf of Mexico assets.
114,000 Daily net production in barrels of oil equivalent from Nexen’s North Sea assets
*Production figures are for the second quarter of 2012

A Complicated Calculation

Cnooc plans a new share listing on the Toronto Stock Exchange +
$22 billion of combined assets +
A Calgary headquarters for Cnooc’s North and Central American operations +
About 3,000 Nexen employees keep their jobs +
61% premium offered to Nexen shareholders
= Net Benefit!*
*To be determined

“I believe this merger could lead to a massive transfer of wealth from the American people to the Chinese government, and I strongly urge you to block this proposed transaction until, at a minimum, parties to the merger agree to pay royalties to the U.S. taxpayer on all oil produced off American shores or relinquish any ownership interests in these leases.”
-Democratic Congressman and ranking member of the U.S. Committee on Natural Resources Edward Markey urging Treasury Secretary Timothy Geithner in a letter to block the proposed takeover of Nexen by Cnooc.

“It’s not just Canadian oil moving in these pipelines anymore”

It was initially dubbed a rebirth. Some called it a stroke of irony. From the vantage of Alberta’s oil sands industry, the rapid ascent of so-called tight oil in the North American energy mix has been nothing short of an upheaval.

“No one really expected tight oil to boom as it has, so really no one predicted that you’d have problems along the pipeline routes in North Dakota, where all of a sudden you have production that surpasses Alaska,” says Mark Oberstoetter, a Canada upstream analyst with Wood Mackenzie based in Houston.

Production from the Bakken formation in North Dakota climbed past 600,000 barrels per day in April. Wood Mac predicts that number will double by 2015, to 1.2 million barrels daily, exacerbating transportation constraints in the Midwest oil hub of Cushing, Oklahoma, and potentially limiting the commercial viability of unsanctioned oil sands expansions as producers face thinner margins and high marginal costs.

Bitumen projects face “deep” and “protracted” price discounts if new export routes are not secured, Oberstoetter said in a spring report. That’s because “massive” growth in U.S. tight oil now competes directly with Canadian barrels moving south on existing pipelines, the report said.

The congestion could get worse. Oil sands production is poised to increase 44 per cent from today’s levels by 2015, to 2.48 million barrels per day, according to the Canadian Association of Petroleum Producers (CAPP). New technology and drilling techniques will increase production of conventional light oil 18 per cent over the same period, from 1.1 million barrels per day to 1.3 million barrels per day, CAPP predicts.

Canadian producers could face “chronic apportionment as a result of limited pipeline capacity to desired markets,” CAPP says in its 2012 crude oil forecast, describing the need for new outlets as “urgent.”

“It’s not just Canadian oil moving in these pipelines anymore,” says Greg Stringham, CAPP’s vice-president of oil sands and markets. The industry previously thought pipeline constraints leaving Western Canada wouldn’t materialize until roughly 2017, Stringham says. “Now we’re seeing that in about 2014-15.”

Name Operator Type/Startup Sanctioned Peak BPD
Kearl Phase 1 Imperial Oil Mine 2012 150,000
Firebag Phase 4 Suncor SAGD 2013 63,000
Christina Lake 1E Cenovus SAGD 2013 40,000
MEG Christina Lake 2B MEG Energy SAGD 2013 35,000
AOSP Muskeg Expansion Shell Mine 2014 115,000
Sunrise Phase 1 Husky SAGD 2014 60,000
CNRL Kirby South Phase CNRL SAGD 2014 45,000
Foster Creek Phase F Cenovus SAGD 2014 45,000
Cold Lake Phases 14-16 Imperial Oil CCS 2014 40,000
MacKay River Phase 1 PetroChina SAGD 2014 X 35,000
Horizon Phase 2A CNRL Mine 2014 X 12,000
Kearl Phase 2 Imperial Oil Mine 2015 150,000
Surmont Phase 2 Conoco SAGD 2015 83,000
Foster Creek Phase G Cenovus SAGD 2015 40,000
KKD – Corner Statoil SAGD 2015 X 40,000
Jackfish Phase 3 Devon SAGD 2015 35,000
Long Lake – Kinosis 1A Nexen SAGD 2015 20,000
Source: Wood Mackenzie

A New Kid on the Block

Engineers are stubborn, says Stuart Albion. They cling to technology and processes they trust. “If you have something you know that works and you trust it, it’s like a barnacle to a ship,” he says. “You’re not going to pry me off.”

He should know: As president of AMEC-BDR in Calgary, Albion leads a company whose corporate ancestor helped build the original oil sands plant in 1967. Nearly five decades later, more than half of all bitumen production comes from open-pit mines modeled on the original Great Canadian Oil Sands venture conceived by Sun Oil Company Ltd. president and chairman J. Howard Pew.

“We’re not about taking risks in that regard,” Albion says in an interview. The consequences of implementing unproven technology “are two years out and millions of dollars away.”

The sector has not stood still since its half-century-old birth pang. Production from in situ underground extraction schemes is now poised to eclipse output from traditional strip mines by 2015, opening up new business in a supply chain long dominated by giant trucks and even bigger shovels.

One area primed for growth is water treatment. “That is the expensive part of the whole operation and really what makes it go,” Albion says. He estimates a 10,000-barrel-per-day plant can use 30,000 barrels of water to make steam, for instance, depending on exact specifications.

AMEC PLC acquired Calgary-based Bower Damberger Rolseth Engineering Ltd., or BDR, for $45 million in 2008 as a way to capitalize on the changing profile of oil sands production. BDR specializes in designing systems that house so-called thermal evaporators marketed to oil sands operators by the likes of General Electric Co.

The evaporators, long used to treat water at power plants and pulp and paper mills, are built-for-purpose to replace warm lime softening as the principal means of removing contaminants from produced water at in situ plants before it is pumped through boilers and returned to the reservoir as steam.

The units do a better job of stripping impurities from water pumped to the surface with bitumen, Albion says, improving recycle rates and facility run-time by reducing the likelihood of fouling equipment with unwanted contaminants in the fashion of an industrial-scale accumulation of lime in a tea kettle. “The same thing happens to your boiler if you don’t clean that stuff up before you put it through,” he says.

AMEC has installed the evaporators, which look like “Saturn rockets,” at several project sites, including Connacher Oil and Gas Ltd.’s Algar plant and Southern Pacific Resources Corp.’s recently commissioned McKay development, Albion says.

Orders have otherwise been slow, in part because evaporators are so new to the oil and gas industry. “It’s starting to gain some traction, but it’s very much a new-kid-on-the-block type of design,” he says. Translation: blame the barnacles.

Long Live King Coal Natural Gas

Robert Curl has a recipe for making the oil sands environmentally palatable.

Start with rock-bottom natural gas prices. Add aging coal plants in the United States. Next toss in pollution rules that limit emissions of carbon dioxide per kilowatt-hour of electricity produced. Then crank up oil sands production to five million barrels per day for processing on the U.S. Gulf Coast, sit back, and watch the U.S. trade deficit shrivel.

“The Canadian oil sands are sort of a win-win situation for the U.S.,” the professor emeritus in chemistry and natural sciences at Rice University’s James A. Baker III Institute for Public Policy and Nobel Prize laureate says in an interview.

His buoyant outlook emerges in a June paper published with Dagobert Brito, a Rice colleague and professor of political economy. They argue the U.S. government should “foster” policies to get more Canadian oil sands to Gulf Coast refineries, offsetting the additional carbon dioxide created by increased bitumen production in Canada – a sticking point among opponents of TransCanada Corp.’s $7 billion-plus Keystone XL pipeline – by substituting cheap natural gas instead of coal to make electricity in American power plants.

“We can offset the CO2 emissions just in well-to-tank from Canadian oil sands, and we don’t really hurt anybody except people” – namely, coal users and producers – “that I don’t see how we can avoid hurting if we’re going to do anything about CO2 emissions,” Curl says.

The prescription is based on the notion of “carbon allocation.” Since fossil fuels aren’t going away in the near or medium term, the thinking goes, and emissions must be controlled, it makes sense to consider “the optimal allocation” of the industrial and consumer byproduct in an economy.

From that perspective, Curl says, “The liquid fuels from oil sands are more valuable than the burning of coal, even when coal is cheaper” on an energy equivalency basis than natural gas. That’s in no small part because coal is “by far the biggest emitter of CO2 per unit of energy obtained,” the professor writes.

The share of electricity generated by natural gas in the U.S. is already growing. It climbed to 32 per cent this past April, Washington’s Energy Information Administration said in July, or roughly the same as the share of power generated by coal and the highest level recorded since the energy fact-finding agency began collecting monthly statistics in the 1970s.

Curl and his colleague calculate that, on a well-to-tank basis, the additional carbon associated with up to five million barrels per day of bitumen production can be effectively offset by encouraging that shift, ultimately replacing slightly more than 19 per cent of the present coal-fired generating capacity in the U.S. with combined-cycle natural gas.

Such a transition is technically and economically doable, the pair writes. “Whether it is politically feasible is another question.”

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