Canadian oilsands and heavy oil operators are using operational upgrades and substantial research outlays as key weapons against an economic squeeze brought about largely by volatile oil prices.
Syncrude Canada Ltd. and Suncor Inc., the two major producers of synthetic oil from the Athabasca oilsands of northern Alberta, have made significant progress in trimming unit costs. That's important in operations that are part of the Canadian resource target of an estimated 1.7 trillion bbl of oil in place in Alberta oilsands (OGJ, Aug. 2, 1993, p. 25).
Imperial Oil Ltd., a major heavy oil producer with a 100,000 b/d capacity operation at Cold Lake, Alta., and a 25% interest in Syncrude, has cut operating costs by more than one third since it began commercial operations at Cold Lake in 1986. It also has spent more than $140 million on in situ and mining and extraction research for Syncrude operations. Imperial expects steadily rising demand for Canadian heavy oil with a widening supply shortfall starting in 1998 (see chart, P. 18).
Other Canadian heavy oil producers have trimmed costs and increased production by using development methods such as horizontal drilling. Some operators have simply reduced emphasis on heavy oil and increased their budgets for natural gas exploration and development.
Oil prices that hit a 5 year low in 1993 spurred efforts by individual operators and a cooperative effort by the industry to improve oilsands technology and operating efficiencies.
The Canadian Oilsands Network for Research and Development (Conrad) was formed late last year to coordinate nonproprietary research on oilsands technology among industry, government, and academic centers.
The Alberta Oilsands Technology and Research Authority (Aostra), now part of Alberta's energy department, also is active with a number of industry partners in oilsands and heavy oil research. Aostra has made significant gains in demonstration projects.
Paul Ziff, president of Ziff Energy Group analysts, Calgary, notes oilsands operations require large capital outlays. He estimates Alberta plants are investing $100-150 million/year on capital programs.
"These investments have to come from cash flow," Ziff said. "If prices are squeezed, so is the cash flow available for additional measures to reduce operating costs."
Ziff says price hedging techniques, which Suncor has used, could assist oilsands operators in coping with price fluctuations. And, he notes, a weak Canadian dollar has helped oilsands sales.
The analyst says eased restrictions on oil exports Ottawa is considering could attract more foreign capital for oilsands, on which royalty rates are lower than those on conventional oil.
UPGRADER PROBLEMS
Two relatively new heavy oil upgraders in Saskatchewan that process Canadian bitumen have been hit hardest by price spreads between heavy crude and more desirable light crude in the past year.
The BiProvincial upgrader at Lloydminster, operated by Husky Oil Ltd. with government partners, and Consumers' Co-operative Refineries Ltd.'s NewGrade Energy Inc. upgrader at Regina have been plagued by other financial problems.
The $1.6 billion Husky plant, in operation since 1992, experienced substantial cost overruns during construction and disclosed layoffs earlier this year. The NewGrade plant has had cost overruns and production shut-downs since it began operation in 1988. Both have had additional injections of capital from their backers.
Upgrader economics are based on price spreads between synthetic crude and heavy oil. Synthetic crude uses the West Texas intermediate crude price as a starting point, less transportation and adjustments for currency exchange. Heavy oil blend uses the Chicago posted crude price, adjusted for transportation tariffs, density, currency, exchange, and condensate that serves as a diluent.
The difference is affected by WTI, heavy, crude, and condensate prices, all of which are at the mercy of supply and demand.
Bill McQuittie, manager of Husky's Lloydminster plant, says upgraders have suffered from low differentials. No improvement is expected until early fall.
A $6/bbl differential is considered a breakeven point for upgraders, but the price spread was only $3.94 in May. Differentials have been well below breakeven for most of the past 2 years.
Participants in the Lloydminster plant, including the Alberta government, have declined to comment on the 46,000 b/d unit's losses.
Alberta Energy Minister Patricia Black said a comprehensive review of the upgrader operation is under way.
Ottawa holds a 31.67% interest in the upgrader, Alberta 24.17%, Saskatchewan 17.5%, and Husky, as operator, 26.67%.
Partners in the NewGrade $880 million Regina upgrader, owned by the Saskatchewan government and Federated Co-operative, Saskatoon, Sask., have focused on financial problems.
The owners each contributed an additional $75 million to the operation last fall, and Ottawa announced a $125 million grant for the upgrader in June. The Saskatchewan government has written off $235 million on the project. A debt load of $635 million was cut by $225 million under a recent restructuring program.
Within 2 years, the net effect of the restructuring will be to reduce interest bearing loans by another $50 million. Net effect on upgrader economics will be a reduction in operating cost to $5.30/bbl from $6.30, based on current interest rates.
NewGrade's design capacity is 50,000 b/sd for an 11 month/year run, reduced to 47,500 b/cd by turnaround. Throughput has been climbing steadily, averaging more than 52,000 b/sd during July 1, 1993-May 30, 1994.
KEY INGREDIENTS
J.D. McFarland, vice-president and general manager of oilsands for Imperial Oil Ltd., says improving oilsands and heavy oil operations and development of new technology are important keys to successful oilsands development.
But, he says, operators must accept as facts of life that plentiful crude oil supply and flat prices are likely to be around for a long time.
"Alberta's oil sands have the potential to sustain and grow the wealth creation capacity of Canada's petroleum sector now and well into the next century," he said.
"The challenge we face is realizing this potential in today's very competitive, interconnected world crude oil market."
McFarland cites four keys to achieving the potential:
- Unencumbered access to specialized markets, mainly U.S. export markets, that are in peace now and are projected to grow.
- Continuous improvement in oilsands operations to improve financial results, increase investor confidence, and lower production costs.
- Development of new technology for cost breakthroughs and more competitive capital and operating costs for existing and new supply.
- Ensuring informed and supportive stakeholders, including investors, customers, governments, local communities, and the general public.
McFarland believes all of those objectives are achievable today, but the industry must stop thinking in terms of "next year or next century." The philosophy must be dropped, he says, that the full promise of the oilsands will be realized only when light crude supplies decline and prices jump at some point in the future.
The Imperial executive says further research and development is needed before a new major oilsands mining project will be commercially viable. An example, he says, is the OSLO project to develop a new operation on leases held by Syncrude partners in the Fort McMurray area. It is on indefinite hold because of economics.
"The prize locked in the oilsands of northern Alberta is truly enormous," McFarland said. "So are the challenges we face as an industry in unlocking that potential. Where we are today falls short of the mark."
Total bitumen and heavy oil deposits in place in Alberta are estimated at 1.7 trillion bbl, but only about 5% is considered recoverable by present technology.
McFarland said, "With tittle real potential for price growth, we must continue to affect what we can control-drive down costs, pursue technology breakthroughs, tailor development pace to market growth, and nurture positive relationships with our stakeholders. These are the keys to future development."
Here are some examples of what's going on in the field:
SYNCRUDE OPERATIONS
Syncrude, operator of the world's largest oilsands plant near Fort McMurray Alta., north of Edmonton, has made reduced unit operating costs a prime objective. Capital spending on operational upgrades since Syncrude went on stream in 1978 almost matches the original $2.3 billion cost. Per barrel costs have been reduced 50% since then.
The Syncrude group, Canada's second largest crude producer, has succeeded in cutting unit operating costs from $17.17/bbl in 1989 to $15.47 in 1993. The running average from April 1993 to the end of March 1994, was $14.48/bbl, but the average in the first quarter of this year was $16.08 due to a turnaround.
The Syncrude operation remains vulnerable to price fluctuations.
Declining oil prices in 1993 reduced Syncrude's deemed unit price for the synthetic crude it produces to $21.20/bbl, $1.63/bbl less than the price it received in 1992.
Syncrude Pres. Eric Newell set targets for 1994 to reduce per unit costs to less than $15/bbl and to reach production of 72 million bbl or 197,000 b/d. That compares with record production in 1993 of 67 million bbl or 183,561 b/d.
Syncrude's budget includes capital spending of $129 million, including costs for operational upgrades and technology development.
The Syncrude group, in which Imperial is the lead partner with a 25% interest, spent $79 million in 1992 and $88 million last year, most of it on projects to improve efficiency and reduce unit costs. It also spent $26 million on research and development in 1993 and estimates technology changes from that investment will save about $250 million/year in production costs.
Syncrude is building a research center in Edmonton, scheduled for completion this year, that will provide advanced laboratory and research facilities for 125 scientists, engineers, and technologists.
Major construction items in 1993 included installation of an extraction auxiliary production system (EAPS), completion of a third tailings line to a sand disposal area, several mine development projects, and a sulfur degassing and blocking unit. The tailings line was completed for less than half the estimated $30 million cost because of construction cost control.
The $11.6 million EAPS system is the first full scale, commercial implementation of an oilsands slurry pipeline. Mixing the oilsand and water in a pipeline promotes bitumen separation, eliminates one extraction stage, and reduces costs.
The total system moves an average 357,800 metric tons/day of oilsand to extraction units.
Syncrude says EAPS also will facilitate future development of mining and extraction operations at significant distances from its upgrading operations.
Another project to move two conveyor trains into a mined-out pit, begun in 1993, will save an estimated $20 million in capital spending and $12 million in operating costs.
Syncrude also is preparing to develop the northern portion of its lease beginning in 1998 and will switch to shovel mining and truck transportation from its existing dragline, bucket-wheel, and conveyor belt system. The change is designed to reduce total mining outlays by an estimated $500 million or 70cts/bbl of bitumen.
The group is starting the switch to shovel and truck operation, scheduled for completion by 1998. The operation acquired five 246 ton trucks in 1993 for removing overburden to supplement an existing fleet of 240 tonners and 170, 190, and 200 ton trucks.
Syncrude also reduced its direct payroll workforce by 542 persons since 1988 by attrition but has increased crude shipments by 25% in the same period with a 401/c increase in productivity. The company plans further workforce reductions by attrition to 3,600-3,700 persons by 1997 from about 4,300 at present.
The company sees the aboriginal population in its project area as significant stakeholders in the operation.
Syncrude has an aboriginal target of 13% of its workforce for direct staff' and contractors by 1997. Direct payroll and contract workers from the aboriginal community now total 564 employees or 10.6% of the workforce. The company has been recognized by native employment organizations for its, programs.
Newell credits much of the improvement in productivity to a $15 million/year in-house training program that is based on a system of continuous learning and upgrading for employees. The workforce also is organized into semiautonomous teams in which workers are encouraged to develop new and more cost efficient ways of doing things.
SUNCOR COSTS
Suncor, which produces 67,000 b/d of synthetic oil, or 5% of Canada's crude oil needs, also is using technology to improve per unit costs on its Athabasca oilsands leases.
Rick George, Suncor chairman, president, and chief executive officer, says the company is not relying on higher oil prices to increase profits. Instead, it is focusing on costs and other factors it can control.
The company's oilsands group reduced cash costs for producing synthetic crude to $16/bbl in 1993 from $19.50 in 1992. George has set a target to reduce costs to $12/bbl in 1992 dollars by mid-1996. Oilsands costs in first quarter 1994 were $13.50/bbl, and the company has set a goal of $14.25 average this year.
George credits much of the cost improvement to operational upgrades that increased productive capacity to 68,000 b/d in 1993 from 60,000 b/d. The company also used price hedging on some production in 1993, which it says had a positive effect on prices of about $1.06/bbl.
In addition to its production of sweet crude, Suncor is producing and shipping customized feedstocks and intermediate products directly to Sunoco and other customers. The customized product offers operational flexibility to produce a better mix of high value products.
Suncor made a major change in technology in late 1993 with a switch from bucket-wheel excavator systems to giant shovels, trucks, and large capacity sizers.
The change was completed 6 months ahead of schedule at a cost of $72 million, well below the $100 million original estimate. The new method also resulted in a staff reduction of about 360 workers with an additional cut of about 100 expected this year.
The new system includes two mineral sizing plants, two Marion 301-M electric cable shovels with 58 cu vd capacity that can load a 240 ton truck with excavated oilsand in 1.5 min, and nine 240 ton Haulpak 830-E trucks. Loaded weight of the trucks is 415 tons.
The main components of the sizers are a 500 ton hopper and an apron feeder that feeds oilsand into a set of rolls where it is sized down to a maximum 14 in. and discharged onto a conveyor. The sizers can handle all types of oilsand materials at a minimum sustainable rate of 8,000 tons/hr.
ENVIRONMENTAL FOCUS
Suncor plans to focus on environmental upgrading this year, which is also expected to help cut costs.
Environmental spending is budgeted at $60 million, including $7 million to reduce odorous emissions, $13 million to enhance sulfur recover from the plant upgrader, $35 million for limestone scrubbing technology to reduce sulfur dioxide emissions, and $5 million for other environmental items.
Total outlay for the limestone scrubbing project, approved this year, is budgeted at $175 million during 3 years. The limestone scrubbers, along with new sulfur recovery equipment, are expected to cut total sulfur dioxide emissions by at least 75%.
The company also plans to spend $10 million during the next 10 years to refurbish boilers for its generating plants.
During a regular 1993 turnaround, the Fort McMurray plant completed modifications to its bitumen upgrader, which increased productive capacity to 68,000 b/d from 60,000. Production averaged 69,000 b/d during second half 1993.
Suncor also has acquired three new leases that could extend its operations by as many as 50 years at a production rate of 68,000 b/d. The company expects to deplete its current leases by 2003. Further delineation work is planned to define the new leases.
Suncor also is conducting studies to determine the best technologies for mining, transportation, and extraction of bitumen from a new mine. It says the cost of opening a new mine could be significantly higher than an early preliminary estimate of $100 million. Present plans call for spending on new mine development to begin in 1997 and be spread over 3 years.
Dee Parkinson, executive vice-president of Suncor's oilsands group, says cost reductions and conversion to the truck and shovel mining operation have ensured the long term future of the plant. She says the new leases are a further confirmation of a commitment to produce light, sweet crude that is cost competitive with conventional crude.
IMPERIAL AT COLD LAKE
The history of Imperial's heavy oil operation at Cold Lake in eastern Alberta reflects fluctuations in crude oil prices and the continental market for heavy oil as feedstock for upgraders and high and medium conversion refineries. Export markets account for about two-thirds of Imperial's sales of blended bitumen from Cold Lake.
Imperial has a phased development project at Cold Lake. There have been several expansions placed on hold because of unfavorable economics since the project went commercial in 1986.
Phases 7 to 10 of the project were originally disclosed in 1987 with a price tag of $325 million. Phases 7 and 8, involving 240 wells, a steam generation plant and distribution system, bitumen collection pipeline, and a central processing facility, were completed in 1988 but mothballed until late 1992.
Development Phases 9 and 10 of the project currently remain deferred.
Despite oil price fluctuations, Imperial has succeeded in increasing bitumen production from 60,000 b/d in 1986 to 100,000 b/d at present. Unit operating costs have been cut from more than $7/bbl to less than $4 in 1993.
Imperial's McFarland says reduced operating costs have been critical to improving financial results of the operation and increasing investor confidence. He attributes some of the more than one third reduction in operating costs since 1986 to economies of scale. But much of it is due to increased operating efficiency.
"Operating efficiency is really the knife edge of our business at Cold Lake," McFarland said.
"When you consider that fuel to generate steam alone makes up nearly 35% of our direct operating costs and is growing, the efforts of staff at Cold Lake to continuously reduce costs is commendable."
Methods to reduce Cold Lake costs include close monitoring of energy use, a strategic approach to maintenance, building relationships with local contractors, control of discretionary spending, and a positive ratio of staff size to productivity.
The Cold Lake operation has obtained power shedding credits from utilities in return for an agreement to reduce power use during peak demand periods in the provincial system. Close monitoring of energy use also has reduced power requirements.
Imperial has built a network of local contractors that can provide quality maintenance on a price competitive basis.
The operation has increased water reuse, which has cut water treatment costs and fuel costs as a result of the higher temperature of recycled water.
The company uses cyclic steam stimulation to recover heavy oil which is about 985 ft below the surface.
Imperial spent nearly $250 million on research and development and pilot projects for Cold Lake before going to a commercial operation in 1986.
SHELL PEACE RIVER PROGRAM
Shell Canada Ltd., which operates a 10,000 b/d oilsands plant near Peace River, Alta., began a steam injection program late in 1993 for bitumen production. The technique requires precise placement of wells but will reduce costs because less steam injection is required.
Peace River's $11 million horizontal well project is the first application of a new process called enhanced steam assisted gravity drainage (Esagd).
The process uses gravity to drain heated bitumen from the surface to an underground steam chamber and into two production wells by first injecting steam into the cavity through two injection wells. The injector and producing wells are drilled to 1,886 ft with horizontal sections as long as 3,300 ft.
Shell estimates it will take as long as 2 years to evaluate the technology and its application to a commercial project.
Alberta's Aostra will contribute 30% of costs of the project up to $6.5 million. The project is based on Aostra technology with enhancements by Shell. Both can license the technology.
Shell expects oil production of about 1,000 b/d from the two wells. If tests are successful, it will consider using the method to begin a staged development of the rest of its Peace River holdings.
The company holds leases on 150,000 acres with estimated recoverable reserves of 14 billion bbl of bitumen.
Aostra executive Doug Komery has said if tests are successful, Shell could increase Peace River production to 30,000 b/d.
Shell's plans at Peace River will be influenced by test results. The company, which i; reviewing all its operations to cut costs, could build an upgrader or scale back its Peace River operation.
Shell began commercial production on its Peace River leases, 311 miles northwest of Edmonton, in 1986. it currently produces about 10,000 b/d there.
Shell says there was strong demand in 1993 from U.S. refiners and local asphalt contractors for its bitumen blend, but reservoir performance problems were encountered and third party suppliers were used to meet some customer requirements.
Shell acquired a 100% interest in its Peace River leases in 1992 when it bought the 30% outstanding interest held by Pecten Canada Ltd., a unit of Shell Petroleum Inc.
AMOCO OPERATIONS
Amoco Canada Petroleum Ltd. has increased its heavy oil holdings and proposes new technology to improve the efficiency of its production operations. The company has reduced unit operating costs to one third of 1992 levels with technical changes that include a new fuel gas distribution system.
Amoco made a significant move in 1993 when it traded a minor interest in Syncrude for acreage in the Northeast Alberta heavy oil area. Amoco traded it's 3.75% interest in Syncrude to Alberta Energy Co. for 16 townships of land in the Primrose heavy oil area and $26.4 million. The deal increased Alberta Energy's share in Syncrude to 13.75%.
Amoco has been active in heavy oil development in Northeast Alberta since the early 1980s, mainly in Elk Point/Lindbergh field where it holds a 79% interest. Heavy oil has increased from 14% of Amoco's total crude and condensate production in 1991 to about 24% at present.
The company holds more than 360 sections of land in the Primrose air weapons range. The company won a directional drilling program at Primrose in 1986 to produce 25,000 b/d, but it was shelved due to a slump in oil prices.
The plan was revived in 1992, when Amoco also bought the 23,000 b/d Wolf Lake heavy oil production plant in the area from BP Canada Ltd. and Petro-Canada. The Wolf Lake thermal operation lies next to Primrose. It produces about 5,300 b/d.
Amoco has an application before Alberta's Energy Resources Conservation Board for a revised development plan at Primrose and for use of surplus capacity at the Wolf Lake plant for Primrose. The company says the new recovery process will be more economic, have reduced environmental impact, and will be phased to give some flexibility in adapting to oil price fluctuations.
The original project was approved using cyclic steam stimulation technology and vertical or directional wells with 104 wells/section and recovery of 18% oil in place.
The proposed modification would use horizontal wells with a combination of primary and thermal recovery mechanisms. It would require only 20 wells/section with projected recovery of more than 50% oil in place. It would use substantially less water than the first plan.
The 20 sections of land involved in the original plan would yield top production of 25,000 b/d. Amoco says the new technology will produce as much as 50,000 b/d from 20 sections. That production target would not be reached until 2010, but the level could then be sustained from the same land until 2050.
The current Primrose approval expires in 2018, but Amoco is not seeking a change in the expiration date.
Amoco says if approval is received in mid-1994, project development would begin late this year or early in 1995. Construction would be modular with each module having 16 horizontal wells on four pads.
It is laying a 12 in. diameter pipeline between the Primrose pilot site and the Wolf Lake plant to handle pilot production. A loop pipeline is planned after commercial operation begins.
MEANWHILE, IN OTTAWA...
On the political front, Ottawa is considering changes to regulations on oil exports that could increase foreign investment in oilsands development in return for a share of production. Japanese and South Korean companies are considering investment. japan's Mitsubishi already owns a 5% interest in Syncrude.
The National Energy Board recently issued a report that said the current regulatory regime does not appear to have inhibited development of oilsands. But NEB said it would be wise to head off potential impediments to capital required for development of the resource.
"Such action would send a clear signal to potential investors that the government of Canada fully supports further development of Canada's oilsands resource," the board said.
"The board believes removal of such impediments is most relevant to potential investments in large scale, capital intensive projects for which assured long term access to markets may be particularly important to investors. These would likely be similar to Suncor and Syncrude."
Present oil exports are approved under orders with terms of only I year for light crude and 2 years for heavy oil. Regulatory changes could permit, without public hearing, export terms of as long as 15 years for synthetic crude.
Copyright 1994 Oil & Gas Journal. All Rights Reserved.
