Global Development:
Ultra-heavy Crude Oil Upgrading

	Suncor’s bitumen upgrading plant near Fort McMurray, Alberta. Photo courtesy of Suncor Energy Inc.
	Bitumen-laden sands being loaded for transport from the Athabasca Oil Sands Project open pit Musky River Bitumen Mine 47 miles (75 km) north of Fort McMurray. (Photo courtesy of Royal Dutch/Shell Group)

Some ultra-heavy crudes (bitumen) such as those produced from Alberta’s oil sands, the Orinoco Basin, some Saudi fields and unexploited North Sea heavy crude are too viscous to be processed in conventional refineries. Crude oil upgraders have been built with more under construction to reduce the high viscosity of heavy crude oils so they can be processed in conventional refineries.

Canadian bitumen upgrading projects
Estimates of bitumen production are significant – an ultimate production potential of 315 billion bbl. Canadian bitumen production will more than double by 2017 to 3.23 million b/d from 1.32 million b/d in 2007, according to the latest Energy Resources Conservation Board of Alberta update. Discounted for various variables, the study estimated Canadian expenditures for 2007 through 2011 bitumen resource development would be Cdn$77 billion.

Different upgrading technologies and blending strategies provide different synthetic crude oil composition and properties. Typically Albertan upgraders convert much of the bitumen into light, sweet crude oil of about 32° American Petroleum Institute (API) gravity. The synthetic crude oil usually contains less than 0.2% sulfur with no vacuum resid.

Overall production of synthetic crude oil reached about 800,000 b/d in 2007. Calgary consulting firm Purvin & Gertz estimates about 600,000 b/d was light sweet synthetic crude oil with no vacuum resid and 200,000 b/d was medium or heavy synthetic crude oil with high sulfur content and containing more vacuum gas oil (VGO) or vacuum resid. Coking followed by hydrotreating produces synthetic crude oil without vacuum resid.

This type of crude oil production will increase in the next few years with upgrader expansions by Suncor, Athabasca Oil Sands Project (AOSP) and others plus planned upgrader start-ups at the OPTI/Nexen Long Lake project, the Canadian Natural Resources Ltd. (CNRL) Horizon project and elsewhere. Suncor’s upgrader to be associated with its Voyageur project will increase the firm’s overall bitumen upgrading capacity to 550,000 b/d by 2012.

Syncrude is a joint venture of Canadian Oil Sands Ltd., Imperial Oil, Petro-Canada, Nexen, ConocoPhillips, Mocal Energy and Murphy Oil. Recent upgrader expansions have increased capacity to 350,000 b/d.

Shell owns a 60% interest in the AOSP with Chevron and Marathon Oil each owning 20%. The project includes the Muskeg River Bitumen Mine 47 miles (75 km) north of Fort McMurray and the 155,000-b/d Scotford upgrader adjacent to Shell’s Scotford refinery in Fort Saskatchewan. The mine uses a novel paraffinic bitumen froth treatment process that results in selective asphaltene precipitation, thus partially upgrading the crude. This crude is diluted with solvent to reduce viscosity and transported by dedicated pipeline from the mine to the upgrader. A second dedicated pipeline returns solvent to the mine for reuse. The upgrader uses hydrocracking and hydrotreating to convert the ultra-heavy crude oil into low-sulfur synthetic crude oil. Two grades of synthetic crude are produced: Albian Light and Albian Heavy. These are processed in Shell’s Scotford and Sarnia refineries with some of this crude also sold to other refineries.

Total operates a bitumen mine at the Joslyn lease. The firm owns a 74% interest in this lease. Planned production is 200,000 b/d with production potential estimated at 230,000 b/d. Total also owns a 50% interest in the Surmont lease 37 miles (60 km) southeast of Fort McMurray. Total’s overall share of the total production from Surmont and Joslyn should reach more than 200,000 b/d within 15 years. Total has also acquired Synenco Energy, whose assets include the 114,500-b/d Northern Lights project. Total plans an upgrader in the Edmonton area, which will initially process 140,000 b/d of bitumen before 2015.

Nexen’s bitumen upgrader at its Long Lake project is more than 80% complete; plant start-up is scheduled for late 2008. The plant will produce 39°API light sweet oil. Production will reach the full design rate of 60,000 b/d in late 2009. Meanwhile, CNRL plans start-up of its Horizon bitumen project 43 miles (70 km) northwest of Fort McMurray in 2008. The project includes an upgrader, and initial synthetic crude oil production will be 110,000 b/d. Staged production expansions will increase production to between 232,000 b/d and 250,000 b/d and eventually to 500,000 b/d.

BA Energy Inc. plans to use its proprietary deasphalting and pyrolysis processes to produce a cracked, sour synthetic crude oil. Ivanhoe Energy Inc. recently announced plans to develop an in situ bitumen recovery and upgrading project using its proprietary heavy oil to light oil cracking process that would also produce a cracked, sour synthetic crude.

The new Fort Hills upgrader project, led by Petro-Canada, will be in the Fort Saskatchewan area; however, rising costs have resulted in delay or cancellation of some projects. For instance, Total E&P Canada and StatoilHydro Canada have delayed plans for their upgraders. Reports indicate Husky has cancelled its stand-alone upgrader expansion at Lloydminster. Development has slowed for the stand-alone upgraders planned by BA Energy and North West Upgrading Inc.

Processing bitumen in existing refineries
With growing production, Canadian synthetic crude and bitumen exports likely will rise, particularly to U.S. refineries. U.S. importers include Sunoco, Marathon Oil and Sinclair Oil. There are plans are to modify some U.S. Midwest refineries to process increased bitumen volumes. These projects include WRB Refining (a ConocoPhillips-EnCana Corp. joint venture) at Wood River, Illinois; BP’s refinery at Whiting, Indiana; and Marathon’s refinery at Detroit, Michigan. Bitumen producer Husky has purchased BP’s Lima, Ohio, refinery and formed a joint venture with BP for the Toledo, Ohio, refinery. These projects could add considerable capacity for processing bitumen heavy crude.

Potential new markets for Canadian bitumen blends also include the U.S. Gulf Coast, California and Asia. The large Gulf Coast refining market already processes more than 2.5 million b/d of heavy crude. Companies plan for more upgrading, but they also have concerns about heavy crude supplies from Venezuela and Mexico. To meet future demand, several pipeline proposals have been offered to deliver Canadian bitumen to the Gulf Coast from Alberta via Chicago, Illinois, or Cushing, Oklahoma.

California has experienced a decline in conventional heavy crude production exceeding 100,000 b/d in five years while imports have increased by more than 200,000 b/d, mostly from Latin America. Proposed pipeline expansions and new pipeline projects proposed from Alberta to the British Columbia coast would allow Canadian bitumen exports to California or Asia.

Even after upgrading, refining crude oil in conventional refineries presents challenges. For example, Shell’s Scotford refinery had to be modified to process the synthetic crude produced in its Scotford upgrader.

“As bitumen-derived crude oils become a larger portion of the refinery feedstock slate, more vacuum gas oil and heavy coker gas oil will be fed to the catalytic cracker to convert these heavy fractions to gasoline and distillate-range materials,” said Warren Ewert of ConocoPhillips, speaking at the American Chemical Society/American Institute of Chemical Engineers joint meeting earlier this year. “Gas oil hydrotreating may be required in order to obtain suitable cat cracker conversions and yields.”

Motiva (a joint venture of Royal Dutch Shell and Aramco), has begun a US$7 billion, 325,000-b/d expansion of its Port Arthur, Texas refinery. After the expansion, the refinery will be able to process ultra-heavy, sour crudes from Canada, Venezuela and Saudi Arabia. Valero is also expanding its Port Arthur refinery to increase its ability to process heavy crudes.

Chevron is beginning construction of a demonstration unit using its vacuum resid slurry hydrocracking process said to significantly increase yields of gasoline, diesel and jet fuel from heavy and ultra-heavy crude oils. The 3,500-b/d unit is being built at its Pascagoula, Mississippi, refinery.

Without upgrading, bitumen producers must dilute bitumen with lighter (less viscous) petroleum to meet pipeline viscosity and density specifications for shipment to existing refineries. Condensate is usually used although some companies have used synthetic crude oil and other light streams. Since 2005, companies have blended some of the diluted bitumen or synthetic crude with conventional heavy crudes for sale to Canadian refineries. Even with increased upgrading capacity, producers will need more diluent. Little additional Canadian condensate is available, so producers may use imported condensate or synthetic crude oil. Naphtha could be imported from U.S. Midwest refineries.

The uncertainty of diluent sourcing and its impact on bitumen blend quality makes new refinery project planning difficult. For example, sulfur content can vary depending on the diluent available for blending. Special metallurgy may be required to process Athabasca and Peace River bitumen, which have high total acid numbers. Some refineries planning to process increased volumes of bitumen will require additional coking capacity.

Syncrude and Suncor produced crudes have a relatively high proportion of VGO that may exceed fluid catalytic cracker (FCC) capacity at some refineries. Synthetic crude oil produced by coking and hydrotreating tend to be fairly aromatic. This can result in diesel and jet fuel qualities being poor to marginal. Also, VGO is fairly refractory for FCC units, limiting conversion. Newer upgraders are expected to overcome some of these disadvantages. For example diesel cetane number has improved from as low as 33 to between 40 and 45 using synthetic crude from some of the newer upgraders. The new OPTI upgrading process configuration uses VGO hydrocracking and is expected to reduce aromaticity.

Venezuelan upgraders
In 2007, Venezuela’s PdVSA took controlling stakes in the four upgraders designed to convert extra-heavy (8° to 9°API) crude oil from its Orinoco Basin into 26° to 32° API synthetic crude. Estimated 2005 total synthetic crude oil production has been estimated at 600,000 b/d. The Petropiar (formerly Hamaca) upgrader previously operated by Chevron has a synthetic crude production capacity of 190,000 b/d. The Petrocedeno (formerly Sincor) upgrader origin-ally constructed by Total has a synthetic crude oil production capacity of 80,000 b/d. Capacity of the Petromonagas (formerly Cerro Negro) upgrader originally operated by ExxonMobil is 120,000 b/d, and the Petrozuata upgrader, once operated by ConocoPhillips, has a synthetic crude oil production capacity of 104,000 b/d.

European developments
Upgraders are being built in Europe to process very heavy crude oil from the North Sea, Russia, the Middle East, Venezuela and Africa. The Sonhoe Development Co. is building a heavy crude upgrader in Teeside, U.K. Construction is planned to begin in 2009 with the plant coming on-stream between 2012 and 2014. It will process 200,000 b/d of heavy, sour and/or acidic crude oils produce diesel, naphtha and jet fuel. About half the heavy crude processed will come from the North Sea, and the facility will include a 110,000-b/d hydrocracker. Other process units will include vacuum and thermal cracking units as well as a distillate hydrotreater.

Lukoil’s subsidiary Lukoil Neftochim Burgas AD is planning an upgrader to convert Urals blend vacuum residue and gas oil at its 165,000-b/d refinery in Burgas, Bulgaria. The upgrader is scheduled to come on stream in 2012.

Reducing environmental impact
Upgrader operators are making efforts to reduce the environmental impact of their plants. For example, Suncor has reduced water use per barrel of oil by nearly 50% during the past five years. This reduction in water consumption made it unnecessary for Suncor to seek permission for increased water use with the construction of its third (Voyageur) upgrader. Meanwhile, Suncor reduced greenhouse gas (GHG) emissions per barrel of oil processed in its first upgrader by about 50% compared with 1990 levels. Upgrader expansion and construction of the new Voyageur upgrader is increasing total GHG emissions. Technologies such as carbon dioxide (CO2) capture and storage are under development by Suncor and other upgrader operators in the hope of reducing total GHG emissions.

Efforts also are being made to reduce other air emissions. The budget for Suncor’s Voyageur upgrader includes about Cdn$800 million to reduce sulfur dioxide emissions by constructing a new sulfur plant. Efforts are being made to reduce nitrogen oxide production and reduce plant odors. The Sonhoe upgrader will be capable of storing produced C02, which can be transported by pipeline for storage in North Sea rock formations to reduce GHGs.

The future
Rising construction costs are affecting the pace of upgrader construction in Canada. Shell Canada Country Chair David Collyer said the company may proceed with construction of a 400,000-b/d upgrader next to its existing Scotford upgrader. The firm is also considering shipping the heavy crude to Motiva’s Martinez, California, refinery and the Shell – Petroleos Mexicanos joint venture refinery in Deer Park, Texas, for processing. Both refineries would need to be modified to process the Canadian crude.

Shell has canceled plans to build a new heavy oil refinery near Sarnia, Ontario, which would have expanded the refinery’s production capacity by about 250,000 b/d. Meanwhile, North West Upgrading Inc. has halted construction of its Cdn$4.2 billion oil sands processing plant, delaying start-up until 2012.