NEWS Canadian oilsands, heavy oil poised for surge in development

May 20, 1996
Syncrude Canada $1 billion expansion of its oilsands operation will center on this massive site at Fort McMurray, Alta. Photo courtesy of Syncrude. How Canadian OilSands Production Has Grown [106346 bytes] Operators in Canada's oilsands and heavy oil regions are on the brink of a period of growth that could last well into the next century.
Syncrude Canada $1 billion expansion of its oilsands operation will center on this massive site at Fort McMurray, Alta. Photo courtesy of Syncrude.

Operators in Canada's oilsands and heavy oil regions are on the brink of a period of growth that could last well into the next century.

Several factors are combining in a scenario a National Task Force report on oilsands says could dramatically increase investment and production in the next 25 years. By then, massive oilsands and heavy oil reserves in northern Alberta could account for as much as 50%-perhaps more-of Canada's oil production.

Technological improvements in recovery and processing have slashed production costs and put nonconventional oil on a more competitive footing with declining reserves of conventional crude in western Canada.

At the same time, persistent lobbying by industry and a well researched national study have persuaded federal and provincial governments to introduce a new royalty and fiscal regime designed to bolster oilsands investment.

New policies give clear incentives to investors to put money into oilsands and heavy oil projects. Policies also will provide a generic tax treatment for all new projects, long a major objective of oilsands promoters. Previously, royalty and tax agreements were negotiated for project case by case.

The task force report issued last fall after several years of study is seen by oilsands advocates as a landmark document. It sets out the case for the oilsands as a national asset that will generate long term economic growth and revenues as well as profits for investors and operators.

In a switch from the past, the task force says development will rely on incremental add-ons to activity rather than the multibillion-dollar megaprojects that have previously been pushed for new developments.

Spending plans

Plans for almost $3.5 billion (Canadian) in spending on oilsands have been disclosed since Ottawa and Alberta agreed to make the fiscal climate more attractive for investors (see table, OGJ, Mar. 18, p. 48).

The list includes projects in the Athabasca, Cold Lake, and Peace River areas. Major expansion plans by Syncrude Canada, Suncor Inc., and Imperial Oil Ltd. account for most of the total. The biggest chunk of expansion capital will go to projects in the Athabasca sands, where Canada's two commercial oilsands surface mining programs are operating.

Syncrude, a joint venture of 10 companies, has spelled out a spending campaign totaling $1 billion.

The group is coming off a record year in 1995. It increased production to 73.9 million bbl in 1995 from 69.8 million in 1994, reduced operating costs to $13.69/ bbl from $14.98 and reported earnings of $265 million, up from $158 million in 1994.

Production of its Syncrude sweet blend crude averaged 202,000 b/d in 1995.

Syncrude will spend $500 million in 1998 for a new bitumen mine and debottlenecking of its upgrading plant to increase production to 82 million bbl/year. It also will spend $500 million starting in 2001 on the Aurora project, a new remote bitumen mine and extraction plant that will increase production to 94 million bbl/year.

The company is gradually switching from a dragline and bucketwheel reclaimer operation to a shovel and truck operation and hydrotransport or slurry pipeline movement of bitumen.

Syncrude operates what it says is the largest surface mine in the world in terms of ore processed.

On average, more than 430,000 metric tons/day of oilsands are delivered to its extraction plant. Production has exceeded 500,000 metric tons some days.

Including overburden and materials mined by draglines, the total amount of material moved exceeds 1 million metric tons/day. About 2 metric tons of oilsand must be processed to produce 1 bbl of synthetic crude.

Jim Carter, Syncrude vice-president of operations, says increased efficiency and lower equipment purchase costs of the truck and shovel system offer significant savings on new mines for existing and new oilsands operators.

The slurry pipeline system for bitumen developed at Syncrude combines the functions of transporting and conditioning the ore along the way to the bitumen extraction step.

Eric Newell, Syncrude chief executive officer, says hydrotransport could be the key technology for expansion of oilsands mining.

Syncrude first began operating a prototype hydrotransport system in late 1993, developed mainly from surplus components by operations and maintenance staff. They shaved an original cost estimate of $100 million to a manageable $12 million.

The system had a 4 month payback and allowed a 3.5 million bbl increase in the group's sweet blend crude production in 1995. More important, it proved the worth of the new technology for future operations.

Syncrude also has increased its extraction rate from bitumen to 90%. Its two upgrading cokers, each with a rated capacity of 70,000 b/d, are operating routinely at 110,000 b/d and have increased run lengths to 2 years from 9 months.

Suncor operations

Suncor also is poised for growth after a strong performance in 1995 that carried into first quarter 1996.

The company's oilsands group achieved record production of 27.7 million bbl in 1995 and reduced its cash production costs to $13.75/bbl. Earnings from the oilsands division increased to $130 million in 1995 from $90 million in 1994.

The company, which built the first commercial oilsands plant in 1967 and led the way in truck and shovel technology, is entering a new growth phase that will include a new oilsands mine, an in situ heavy oil recovery project, and a joint venture shale oil research project in Australia.

Spending on oilsands will include more than $600 million to increase productivity at existing operations and develop a new mine.

The company is spending $300 million to increase production at its existing oilsands operation to an eventual 105,000 b/d. Production averaged 76,000 b/d in 1995.

Suncor also is spending $190 million on measures to reduce sulfur dioxide emissions.

And the company is spending $15 million on the first phase of a steam assisted gravity drainage (SAGD) heavy oil project at Burnt Lake, Alta. It says the property holds 1 billion bbl of recoverable oil that could become economically viable, depending on the success of new technology and the market price for heavy oil.

Another growth project is an initial $7 million outlay for a feasibility study of the Stuart shale oil development project in eastern Australia. If feasibility studies are positive, Suncor will spend another $65 million to build a pilot plant at Gladstone, Queensland.

More operations

In addition to Syncrude and Suncor, several operators are starting or expanding projects in the Athabasca sands.

Gulf Canada Resources Ltd. will spend $30 million this year on the first phase of its Surmont 3,000 b/d SAGD heavy oil project. The company plans a second phase in 1998-99 to increase production to 20,000 b/d, but no cost estimate has been disclosed.

Japan Canada Oil Sands Ltd. will spend $69 million at its Hangingstone lease in 1997 for a SAGD bitumen project. Production estimates are not available.

A new $170 bitumen mine and extraction complex plus a minerals extraction plant is scheduled for 1997 by Solv-Ex Corp. on its Bitumount lease. The plant would mine 14,000 b/d of bitumen and 100,000 metric tons of alumina plus 200,000 metric tons of synthetic silica from tailings. The minerals would be extracted from waste sludge from the Syncrude and Suncor plants.

Gibson Petroleum Ltd. will spend $7 million in 1996-97 on a SAGD bitumen project under way at an industry/government test site in the Fort McMurray, Alta., area. Production is to increase to 4,500 b/d from 2,000 b/d.

The Cold Lake heavy oil area in Northeast Alberta will attract heavy investment with projects announced worth about $1.5 billion.

Imperial tops the list with $540 million in spending in 1996 and 1997 to expand its existing in situ bitumen operations. The company says reasons for expansion include strengthening prices of heavy crude, a continuing increase in North American demand for Canadian heavy crude, and progress in reducing operating costs.

Imperial has spent more than $1.2 billion to date on Cold Lake development.

Amoco Canada Petroleum Ltd. also is a heavy spender with more than $500 million allocated for expansion and development of its Wolf Lake and Primrose leases.

Dave Newman, chairman and CEO of Amoco Canada, says recent actions by the Alberta and federal governments have created predictable, long term fiscal terms and the economic certainty to continue expansion of the company's heavy oil business.

Amoco will spend $175 million this year on its Wolf Lake and Primrose leases. It will spend $100 million in 1997 and the same in 1998 as part of a $500 million project to increase heavy oil production to more than 50,000 b/d.

Alberta Energy Co. Ltd. also is increasing its Cold Lake investment with a $13 million program on its Foster Creek lease for a 1,000 b/d heavy oil SAGD pilot plant. The company also plans to spend $200 million in 1997-98 on a 30,000 b/d commercial heavy oil project.

Suncor Inc., a pioneer in Canadian oilsands projects with its operation in northern Alberta, has mapped an expansion program that includes a new mine and an in situ recovery project. The company currently has three Marion electric cable shovels capable of loading a 240 ton capacity Haulpak 830E truck in three scoops. Photo courtesy of Suncor.

Policy the key

Eric Newell, Syncrude chairman and CEO, says a single fiscal and resource allowance policy was the key element achieved by the task force initiative.

Newell said, "Investors are quite willing to accept risks around things like crude oil prices, but they think they ought to know what the tax and royalty regime is going to be. To me, the big thing was to get a generic regime that suits everybody. Then the market decides what goes ahead."

Two multibillion dollar oilsands mining proposals-the Alsands group and the OSLO project-were shelved in the 1980s because investors were unwilling to risk uncertain economics.

The oilsands task force report warned that while the oilsands are a secure supply of oil creating significant wealth, the future of the resource is not assured.

"Before stakeholders agree to pay the economic and social costs of new development, they must be convinced the prize is worth the investment," the report said.

Newell says oilsands operations' economics are tied closely to the price of crude. One potential problem that could slow growth would be a severe drop in crude prices.

Noting development failures in the 1980s, the report said the credibility of a strategy for doubling or tripling production depends upon demonstrating that there are fresh approaches to and new levers for development.

Newell said, "The report sent a strong signal to policy-makers that a special focus on the oilsands is in the public interest. Time is running out for our domestic conventional light and medium crude, and something has to be done to make up the shortfall. There is only one major, relatively untapped source of petroleum left on the North American continent: the Alberta oilsands."

Newell says the task force took a long term view of development during 25 years, and the industry has learned that running oilsands plants effectively is a job for long distance runners, not sprinters.

The 25 year outlook says maximum development of the 300 billion bbl of potentially recoverable oilsands translates into a doubling or tripling of current production to 800,000 to 1.2 million b/d.

The report assumes these factors during the forecast period:

  • Fossil fuel will remain a major driving force in the world's economy in the first half of the 21st century, particularly for transportation.

  • Growth in the price of conventional crude oil will remain flat at about $25 (Canadian)/bbl.

  • Research and development will deliver a suite of technologies that will reduce supply costs and improve efficiency and sustainable development.

  • Exports of Canadian bitumen, crude oil, and transportation fuels will be free from restrictive government regulations.

Resource base

The Alberta Energy & Utilities Board (AEUB) and the National Energy Board (NEB) differ on the volume of bitumen in place in the four major oilsands deposits in northern Alberta: Athabasca, Wabasca, Cold Lake, and Peace River. Combined, they cover about 48,000 sq miles, about the size of Belgium.

AEUB estimates there are 1.7 trillion bbl of bitumen in place, while NEB estimates there are 2.5 trillion bbl. The agencies agree that about 300 billion bbl are ultimately recoverable. There are currently 4 billion bbl that can be produced under existing permits-more than the remaining established conventional crude reserves in western Canada.

Government approach

The theme of the task force report, that development of the oilsands is an undertaking in the national interest, was accepted by Ottawa and Alberta. Both governments have signed on for royalty and tax initiatives to stimulate investments.

The study says a series of smaller scale expansions of existing operations could add as much as 14.6 million bbl/year to production to reach volumes of 800,000 b/d to 1.2 million b/d of bitumen and upgraded crude by 2020.

The task force sees an oilsands future that could include new products and activities such as coke desulfurization and metals extraction.

The growth strategy also includes:

  • A number of remote mining and in situ operations linked to upgraders and heavy oil refineries in Canada and existing market areas in the U.S.

  • An expanded petrochemical complex beyond what exists at Fort Saskatchewan near Edmonton.

  • A collaborative research effort by industry, government, and universities to reduce the capital and operating costs for oilsands production. The Canadian Oilsands Network for Research and Development (Conrad), which coordinates research by industry, government, and academia, is seen as a model for future joint research efforts.

  • A network of nitrogen and hydrogen plants and operations linked with upgraders. These could support other industries as independent suppliers with an advantage of low power costs and huge reserves of natural gas in Alberta.

  • A network of new pipelines for shipments of bitumen from producing fields to processing plants as well as markets.

Current oilsands production of bitumen and blended crudes is well connected via pipelines to diverse markets in North America. Canada's Interprovincial and Trans Mountain pipelines move refined products east to the Great Lakes and U.S. Midwest and west to Pacific Coast markets. Crude oil moves as far east as Montreal and south of Chicago to St. Louis and eastern Kentucky.

Canadian operators see the U.S. Rocky Mountain area, where conventional crude is declining, as a growth market for upgraded oilsands production. Washington state and California are also seen as potential markets for oilsands production.

Oil supply

Oilsands production has increased seven-fold since the first commercial production in 1967 and has doubled in the past decade to more than 400,000 b/d. Synthetic or upgraded crude represents more than 14% of Canada's current petroleum supply. Bitumen produced via in situ projects in deep deposits such as Cold Lake account for an additional 7.5% of Canadian production.

Syncrude Canada and Suncor mine more than 325,000 b/d of Athabasca bitumen and upgrade it to 280,000 b/d of light, low sulfur, crude oil blends. Oilsands account for 21% of Canada's light and medium crude production.

Sixteen in-situ operations in Alberta produce a total of more than 150,000 b/d. Forecasts call for an increase of 175,000 b/d to as much as 315,000 b/d by 2005.

In addition to Alberta operations, 110,000 b/d of synthetic crudes are produced at the BiProvincial Upgrader operated by Husky Oil Ltd. at Lloydminster, Sask., and the NewGrade heavy oil upgrader at Regina, Sask. Most of the feedstock for those plants comes from Saskatchewan heavy oils and bitumen in the Cold Lake area.

The task force report says continued technology research is required to lower the economic threshold for grassroots projects and make replacement reserves available. The study says science and technology will be the lever to reduce operating costs for integrated mining operations to $6-7 (U.S.)/bbl and total supply costs to $15 (U.S.) by 2010.

J.P. Bryan, chairman of Gulf Canada with interests in Syncrude, predicts the combine will produce oil for $9 (U.S.)/bbl by the turn of the century.

"That is as competitive as you need to be in North America," he said.

Copyright 1996 Oil & Gas Journal. All Rights Reserved.