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Oil-Sands Mine Operators Raise Efficiency and Lower the Environmental Impact

Posted on: Wednesday, 26 July 2006, 06:00 CDT

By Anonymous

Oil-sands mine operators raise efficiency and lower the environmental impact.

A 300-lb bbl of 34 American Petroleum Institute (API) gravity synthetic crude from an oil-sand mining operation can begin life as more than 4.4 tons (4 tonnes) of "stuff." That means handling more than 1.1 million tons/d (1 million tonnes/day) of material for an operation the size of Canadian Natural Resources Ltd.'s Horizon development, which will produce 232,000 b/d of syncrude in 2012.

That 4 tons scooped from the ground first becomes slightly less than nearly 2.2 tons (2 tonnes) of oil sand. Separating the sand leaves about 1.16 bbl of bitumen, then upgrading reduces the volume to 1 bbl of 34 API syncrude.

It seems like a lot of work for just one barrel of crude that still must be made into something useful, like gasoline, diesel and asphalt.

A good thing about oil sand is that exploration cost is low, but development costs are not. During the past 5 years, according to the Alberta Energy Department, industry allocated Cdn$24.7 billion for oil-sands development.

Most of the world's oil-sands resource is found in northern Alberta, home of the Athabasca deposit, the world s largest petroleum resource. oil sand is visible on the banks of the Athabasca River near Fort McMurray, but most of the 1.7 trillion bbl of bitumen in place is buried under 164ft (50m) or more of muskeg and overburden.

According to the Alberta Energy and Utilities Board (EUB), more than 175 billion bbl of the resource is recoverable with current technology, and 315 billion bbl could be recovered with advanced technology.

Bringing oil sands into the mainstream oil supply has been difficult because conventional oil that is easier to produce and refine has been affordable for so long. However, with the light sweet crude price oscillating around US$70/bbl early this year, a spotlight has been focused on oil sand.

THE MOTHER LODE

Efforts to develop Canada's oil sands spanned most of the 20th century. It was the 1950s, however, before the potential of the resource began to attract serious attention, according to the Athabasca Regional Issues Working Group (RIWG).

Following the Alberta government's announcement of its oil-sands policy in 1962, Great Canadian oil Sands (now Suncor Energy Inc.) approved the first project in 1964 and production began in 1967. Syncrude Canada Ltd. brought a larger project onstream in 1978.

Last year, according to the RIWG,28 companies had or proposed 81 oil-sands-related projects in the three different northern Alberta deposits: Athabasca, Peace River and Cold Lake. Athabasca, the largest of the three, has nine companies operating and seven projects under construction.

In last year's crude-oil forecast, the Canadian Association of Petroleum Producers (CAPP) projected this year's production from oil sands at 1.267 million b/d. About 800,00(1 b/d of that is expected to come from oil-sands mining operations, the rest from in situ production.

ECONOMICS, ENVIRONMENT: TWO CHALLENGES

Thermal recovery is the choice for much of the resource, but an estimated 10% of the oil in place is close enough to the surface to be mined.

Mining oil sands is more costly than conventional production techniques and the process has an environmental impact that is more visible. Fundamental to the operation is clearing trees from the site and removing topsoil, muskeg, sand, clay and gravel. In situ operations disturb less than 10% of the surface land area over the deposit being developed.

To lessen long-term impact, operators stockpile topsoil and muskeg, and replace it as sections of the mined-out area; the rest of the overburden is used to reconstruct the landscape when mining is completed. Developers must restore oil-sands mining sites to at least the equivalent of their previous biological productivity, according to the Alberta Energy Department.

Oil-sands operations also produce significant amounts of carbon dioxide (CO2,) a greenhouse gas. Canadian oil-sands developers aim to reduce CO2 emissions per barrel by 45% by 2010, compared with 1990 levels.

Suncor Energy Inc., for example, has reduced greenhouse gas about 25% since 1990. During the same period, however, production increased more than four-fold, driving an increase in total emissions.

"This issue - net increases in environmental impacts despite 'per barrel' improvements - is a major issue for the industry," said Rick George, Suncor president and chief executive officer.

Emerging technologies, such as injecting CO2 from the oil sands into conventional oilfields, hold the promise of capturing emissions and adding to new crude production, he said.

ConocoPhillips is part of a Syncrude joint venture in northern Alberta.

Extraction separation cell is part of Suncor's mining process.

The RIWG estimates more than Cdn$40 billion has been spent on oil- sands construction, and expects another $45 billion to be spent by 2010. That, along with market cycles during a typical multi-year span from concept to production, makes cost control critical.

EVOLVING TECHNOLOGY

Alberta's oil-sands companies invest $75 million to $100 million annually in research and development to improve economic and environmental performance, according to the RIWG, which estimates advances in technology have lowered operating costs per barrel 50% since 1981, exclusive of gas and electricity.

Energy used in mining and extraction has been reduced 45%. New technology also will reduce the time required to reclaim mine tailings ponds and eventually could reduce the volume of tailings.

Replacing draglines and bucket wheels with trucks and shovels has led to a 25% reduction in land disturbance, according to reports, and makes it possible to return disturbed land to its natural state several years earlier.

The use of hydrotransport, using water to move material from the mine to the separation plant, is a commercial technique expected to expand in use. Hydrotransport not only cuts cost, but it also performs some separation in the pipeline.

"By the time it gets to the plant, the bitumen has separated from the ore. It saves a step," said Eddy Isaacs, AERI managing director.

There are still opportunities to cut costs and boost efficiency. One goal is to improve the extraction process to reduce or eliminate chemical use and reduce energy requirements. The search is also on for ways to better use water by recycling tailings pond water.

There is another technological gap drawing attention. For a mining operation to be economically viable, the maximum depth of overburden that can be removed is about 246ft (75m), according to AERI guideline. Steam processes, however, cannot be used at depths shallower than about 492ft to 656ft (150m to 200m).

"In between, we just do not have a good method," Isaacs said. "We need new technologies to get at those resources that are too deep for surface mining and too shallow for in situ production."

From its formation until it began producing oil in 1978, Syncrude's focus was on R&D. Even after 40 years of developing technology, the company spends more than $40 million annually on R&D.

"Throughout three decades of production, incremental improvement and innovation have been part of the business," said Alain Moore, Syncrude spokesman.

Better materials extend equipment life, larger haulers provide economy of scale, and the shift from a dragline to the truck-and- shovel operation has reduced operating cost.

EXAMPLE BOTTOM LINES

As technology develops, synthetic crude made from oil-sands bitumen becomes increasingly competitive with conventional crude, "...historically, operating costs were our biggest challenge," George said.

New technology and a renewed focus on operational excellence have reduced operating costs for the oil-sands industry to about $20/bbl for upgraded light crude, he said. That is higher than global average lifting costs, but oil-sands exploration costs are near zero.

"Add it up on a full cycle basis, and oil sands are very competitive with domestic conventional crude," George said.

Cash operating costs from Suncor oil-sands base operations averaged $19.50/bbl last year compared with $11.95/bbl in 2004. The increase was primarily because of fixed operating costs being spread over lower production volumes, higher maintenance-related expenses and the impact of higher natural gas costs, according to the company.

Still, operating costs are under constant pressure, for example, from the rising cost of energy. So far, much of the effort to reduce that cost has focused on energy efficiency, reducing energy intensity 15% during the past 5 years, George said. Several companies, including Suncor, are looking at building gasification technology into future plants.

There was another challenge this year.

"There's some $70 billion dollars in planned capital spending in the oil sands over the next decade, and that represents another kind of growth challenge," George said. "... in the oil sands today, there isn't just one multi-billion dollar project on the go, there are a dozen."

In 2004, improved reliability and larger volumes lowered Syncrudes unit operating costs to $21.13/bbl of synthetic crude, compared with $23.64/bbl in 2003, according to Syncrude.

INTEGRATION AND BALANCE

Shell Canada calls its Athabasca oil Sands project the first fully integrated oil-sands project in 2\1 years. At full production, it supplies 10% of Canada's oil needs.

The project includes the Muskeg River mine 47 miles (75km) north of Fort McMurray; the Scotford upgrader next to Shells Scotford refinery north of Fort Saskatchewan; and the 306-mile (493-km) Corridor pipeline that moves bitumen to Scotford and diluent back to Muskeg River.

Shell is the overall project administrator as well as operator of the Scotford Upgrader. Albian Sands Energy Inc., a company created by the joint venture, operates the Muskeg River Mine. Terasen Inc. built the Corridor Pipeline.

The project is operated in strict accordance with the principles of sustainable development, according to Shell Canada, and that involves balance and integration: integrating the economic, social and environmental aspects of everything it does and balancing short- term wants with long-term needs.

MINING

Oil-sands mining operations and technology vary by operator, but much of the process is fairly straight forward. For most operators, it includes fundamental steps similar to those involved in Syncrude's operation - removing overburden and oil sand, separating bitumen from the sand, managing tailings and reclamation.

Traditionally, draglines piled the oil sand in windrows and bucket wheel reclaimers placed it on a conveyor system. That process is being phased out in favor of truck-and-shovel operations.

Syncrude, for example, has retired three of its four walking draglines and three of its four bucket-wheel reclaimers. Now its mining operation uses mechanical as well as electric drive trucks ranging in capacity from 240 tons to 400 tons, and electric and hydraulic shovels. The 56-yd^sup 3^ hydraulic shovels at its Aurora mine and the 400-ton haul trucks at Aurora and the North Mine are the largest in the world.

EXTRACTION

Water makes up about 4% of the oil sand by weight. It surrounds each grain of sand providing a water envelope that makes it possible to separate oil and sand by water-based extraction methods. At Syncrude s Mildred Lake and Aurora sites, extraction plants process about 568,000 million tons (515,000 tonnes) of oil sand per day to produce 610,000 b/d of diluted bitumen. The process recovers more than 90% of the bitumen contained in the oil-sand feed.

At Mildred Lake, oil sand enters large horizontal, rotating drums where it is mixed with steam, hot water and caustic soda to provide slurry for bitumen separation. Aurora froth is mixed in the tumblers with the dry oil sand and the resulting slurry is discharged onto vibrating screens where large materials - rocks, sticks and lumps of clay - are rejected.

The slurry is then diluted and blended with that from the North mine hydrotransport system.

Blended slurry is fed to the four primary separation vessels (PSVs) and two auxiliary settling areas, smaller versions of the PSVs. Bitumen floats to the surface as primary froth and the sand settles out. "Middlings" and underflow streams are pumped to the tailings oil recovery (TOR) vessels that recover most of the remaining bitumen using Syncrude-developed technology.

Bitumen recovery is further improved by the secondary flotation plant, which processes middlings from the TOR vessels. Froth from the secondary flotation plant is combined with the primary troth stream from the PSVs, deaerated and heated, and fed to the froth treatment plant.

Froth treatment minimizes the amount of water and solids going to the upgrader. A naphtha recovery unit, also developed by Syncrude, recovers naphtha from all froth treatment tailings.

TAILINGS MANAGEMENT

Material remaining after the bitumen is extracted - tailings - includes water, fine silt and clay particles as well as some residual hydrocarbons. The tailings are stored in three main areas on the base leases.

In 1991, as one area reached its final design height, another facility was brought onstream to serve as the main site for sand storage. At this site, the solids (sand, silt and clay) settle out, and the remaining water and fines are transported by gravity to another site for further clarification.

RECLAMATION

Syncrude spends about $7 million each year to reclaim land disturbed by the operation. Each year, soil is reconstructed, trees and shrubs are planted, and grasses are sown to prepare the land for future uses. The Syncrude site is home to the largest privately- managed wood bison herd in the world. The company also monitors vegetation to detect potential impacts from emissions and conducts a periodic census of wildlife.

Raw ore is dumped into the crusher and transported in a conveyor belt to the ore silo.

A SAMPLING OF PROJECTS, EXPANSIONS

Syncrude is the worlds largest producer of crude oil from oil sands and supplies 13% of Canada s petroleum requirements. Its oil- sand mine produces bitumen from the unconsolidated sands of the McMurray formation in an operation that includes a utilities plant, a bitumen extraction plant and an upgrading facility. Final product is a light, sweet crude oil for domestic consumption and export.

Two decades after Syncrude's first barrel was shipped July 30, 1978, the billionth bbl was produced, 5 years ahead of schedule. Last year, the company produced 78.1 million bbl of its Syncrude Sweet Blend.

SWEET PREMIUM

"Syncrude has been producing oil from oil sands for almost 30 years, but this might be its busiest year yet," Moore said. "The attention being focused on oil-sands operators has increased dramatically, especially from south of the border."

Early this year, the company was Hearing completion of a multi- staged expansion that will boost total daily production from 240,000 b/d to about 350,000 bbl of Syncrude Sweet Premium (SSP), a lower sulfur, low nitrogen product with a higher smoke point and cetane number.

At 34 API, SSP will have about the same gravity as Syncrude Sweet, which historically has traded at prices close to those of West Texas Intermediate. About half the production of Syncrude Sweet is consumed in Canada; much of the rest goes to the Chicago area.

Oil sands supply costs.

The $8.4 billion expansion is scheduled to go online during the middle of this year, but because the project is complex, it will take a little time to build production to the 350,000-b/d mark, Moore said. By year-end, production is forecast at about 315,000 b/ d.

The mining segment of the expansion has been operational since early this year.

Capacity is being increased all along the value chain from mining to extraction to upgrading. Increasing upgrading capacity accounts for the lion's share of the project cost. "The current expansion will include improvement in virtually every technology and process, along with significant innovation," Moore said.

For example, on the mining and extraction side, the Aurora train - Train 3 -will use Low Energy Extraction, a technology developed by Syncrude. The original hot-water process used to wash oil from the sand was a breakthrough technology when introduced, but it requires a water temperature of about 175F (80C). The process drops the required temperature to between 94F and 103F (35C and 40C).

"Reducing the energy needed to heat water is a tremendous cost benefit," Moore said. "And the process reduces greenhouse gas emissions per barrel of oil produced."

Extraction efficiency is also aided by use of hydrotransport to move oil sands from the crushers to the separation facility. Hydrotransport makes lower process temperatures possible because the oil begins to separate from the sand in the pipeline even before it arrives at the extraction facility.

Heavy oil economics.

"Hydrotransport is an industry standard," Moore said.

Syncrude developed the technology and has licensed it to other operators.

The company also created the industry's first satellite mine. Aurora mine is 21 miles (35km) from the main extraction facility. In operating Aurora, Syncrude discovered the phenomenon of natural froth lubricity, in which water forms around the bitumen as it moves down the pipeline, allowing the relatively viscous material to move more easily.

Syncrude s long-term vision is to build to a capacity of 500,000 b/d, but further expansion is subject to approval of Syncrude's owners, of which Canadian oil Sands Trust is the largest.

SUNCOR MILESTONE

When Sun oil announced the $250 million Great Canadian oil Sands project in 1963, it was the largest single private sector investment in Canada's history. By 1981, it had produced 200 million bbl; by 1996, 500 million bbl.

In 2001, production expanded to 225,000 b/d and the Voyageur growth strategy, a multiphased plan to increase oil production to half a million b/d by 2010 or 2012, was announced. Last year, a $450 million expansion of upgrading facilities increased production capacity to 260,000 b/d.

Also last year, Suncor completed rebuilding damage from a January fire and worked to boost capacity to a planned 350,000 b/d in 2008.

PETRO-CANADA ADDS FORT HILLS

Early last year, Petro-Canada acquired the majority interest and operatorship of the Fort Hills project from UTS Energy Corp. (UTS). Later in the year, mining partner Teck Cominco Ltd. joined the consortium. Petro-Canada has a 55% interest, UTS has 30% and Teck Cominco holds a 15% interest.

Fort Hills, one of the largest remaining undeveloped groups of oil-sands leases in the Athabasca region, is estimated to contain at least 2.8 billion bbl of recoverable bitumen. The project has received regulatory approval to produce up to 190,000 b/d.

Fort Hills contains a well-denned and high-quality bitumen ore that has been delineated through extensive drilling. Current development plans call for an initial 50,000 b/d mine by 2009, with an upgrader to follow within a year or two. According to the company, it is evaluating the possibility of doubling that initial development to 100,000 b/d.

President and Chief Executive Officer Ron Drenneman in a speech earlier this year said the Fort Hills design basis will be announced n\ear year-end.

"Oil sands is a big growth area for Petro-Canada, and we're one of the few established players who is well positioned down the 'fairway' of top-quality leases," he said.

The company this year expects to work on the Fort Hills mine, extraction and upgrading Design Dasis Memorandum (DBM), which establishes key design parameters and a more detailed project schedule. Once the DBM is completed near the end of the year, a regulatory application will be filed late this year or early next, according to the company.

In February, the Fort Hills Energy Ltd. Partnership purchased two additional oil-sands leases for $60 million. Leases 437 and 438 comprise a total of 12,968 acres (5,252 hectares) and increase the Fort Hills projects land holdings to 59,138 acres (23,951 hectares).

CNRL: STRUCTURE, DISCIPLINE

Canadian Natural Resources Ltd.s (CNRL) Horizon oil-sands project, which is 43 miles (70 km) north of Fort McMurray, covers 115,000 acres (46,575 hectares). Drilling on the leases indicates an estimated 16 billion bbl of bitumen in place. Using existing mining technology, 6 billion bbl could be recovered, according to the company.

Horizon will involve three development phases spanning the period from 2005 through 2012. Synthetic crude production will begin in the second half of 2008, ramping up to a rate of 110,000 b/d. A second phase is expected to increase production by 45,000 b/d in 2010, and the third phase, completed in 2012, will take total production to 232,000 b/d.

The phased approach for the project is highly structured and disciplined, according to the company, and significant investment in front-end engineering and design will result in cost certainty.

Horizon mining operations will consist of mobile equipment and bitumen extraction facilities, and upgrading facilities will use delayed coking and hydrotreating. All the upgrading facilities are on the Horizon plant site to allow energy integration and sharing of common infrastructure.

CNRL's capital investment for the project is estimated at $10.8 billion including contingencies.

KEARL: A NEW INITIATIVE

Imperial's Kearl project is a joint venture proposed by Imperial Oil Resources Ventures Ltd. and ExxonMobil Canada Properties. Imperial will operate the project, which is near the Horizon project. The western part of leases 6 and 87 are areas deemed suitable for surface mining.

Expected eventual production, based on a phased development scenario, could be 300,000 b/d of bitumen, beginning with an initial 100,000-b/d development. Total recoverable bitumen is estimated at 4.4 billion bbl.

Application was made to regulators in July and a regulatory decision is expected early next year.

Preliminary cost estimates suggest a phased mining and bitumenseparation development with no associated upgrading facilities would cost between $4.5 billion and $6.5 billion in 2005 dollars. About 44% of the cost will go to the first train and 60% for the two subsequent trains.

"The Kearl oil-sands mine is Imperial's most advanced new initiative," said company spokesman Pius Rolheiser.

If Imperial decides to build the project, the first phase would come onstream in 2010. According to the current plan, the second mine train would start up in 2012 and the third in 2018. At this point, an upgrader is not planned as part of the initial development; the first 100,000 b/d will be brought to market as raw bitumen.

"But we haven't made final upgrading decisions," Rolheiser said. "We're looking at a range of upgrading options for later phases."

SYNENCO'S NORTHERN LIGHTS

Synenco Energy Inc.'s major focus is its Northern Lights project, an oil-sands mining and bitumen extraction project north of Fort McMurray. and an upgrading facility near Edmonton. Synenco is the managing partner of the Northern Lights Partnership (NLP); SinoCanada Petroleum Corp., a subsidiary of China's Sinopec. owns the remaining 40%. In addition to its interest in NLP, Synenco holds a 100% interest in an oil-sands lease adjacent to the NLP lands.

In April, Synenco announced the signing of a contract to complete the DBM for the Northern Lights project. Submission of the application is targeted for the middle of this year.

When completed, Northern Lights would produce 100,000 b/d of light, sweet synthetic crude during a 30-year period. The plan is to develop the project in two 50,000-b/d phases. Phase one start-up is scheduled for mid-2010, with production from Phase two starting in the third-quarter of 2012.

An independent estimate of NLPs resource indicates 1.49 billion bbl of bitumen in place.

Copyright Hart Energy Publishing, LP Jul 2006

Source: Oil & Gas Investor

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