Diluent availability will constrain Canada's heavy oil, bitumen development

Oct. 28, 2002
Despite significant proposed investments to develop Canada's heavy oil and bitumen reserves, production will continue to lag developments in Latin America.

Despite significant proposed investments to develop Canada's heavy oil and bitumen reserves, production will continue to lag developments in Latin America.

Besides limitations on labor in the construction trades in Alberta there are constraints on market access, refinery capacity to utilize these heavy crudes, and heavy crude oil transportation capacity.

Resources, new facilities

Recent publicity has documented the substantial heavy oil and bitumen resource potential in Western Canada, and major investments that have been announced (OGJ, June 10, 2002, p. 24; July 15, 2002, p. 27).

A report by Canada's National Energy Board (NEB) estimated that Alberta's oil sands may contain ultimate in-place bitumen resources of more than 2.5 trillion bbl.1 The NEB also estimated that the initial established reserves were 178 billion bbl, of which the cumulative production was approximately 3 billion bbl. The NEB also suggested that the Orinoco Belt in Venezuela also contained heavy and extra-heavy crude oil resources of comparable magnitude.

Conventional surface mining can recover oil sands, and extraction processes can liberate the bitumen from the sand. Steam-assisted gravity drainage (SAGD) can recover bitumen from reservoirs that are unsuitable for surface mining. It is clear that Western Canada has substantial heavy oil and bitumen resources.

These circumstances have prompted construction of massive and expensive upgrading facilities within Alberta. Suncor Energy Inc. and Syncrude Canada Ltd. built the two initial upgrading facilities during the 1960s and 1970s. Both these facilities have been expanded and further expansions are planned. A new facility owned by a consortium of Shell Canada Ltd., Chevron Canada Resources Ltd., and Western Oil Sands Inc. (WOS) is nearing completion.

Construction of the new facility by the Shell/Chevron/ WOS consortium and expansion of the Suncor plant have both encountered significant cost over-runs. Limitations on the skilled labor in the construction trades and particularly at locations in northern Alberta are the primary reason for these cost over-runs.

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Canadian heavy oil and bitumen production expanded during the 1990s from 449,000 b/d to 839,000 b/d in 2000 (Table 1). In the 1990s, the increase was 390,000 b/d. Table 1 shows that heavy crude oil production in Latin America increased b 2,425,00 b/d to 3,799,000 b/d in 2000 from 2,425,000 b/d in 1990 for a total increase of 1,374,000 b/d.

Although Canada has comparable bitumen resources to Venezuelan heavy and extra heavy crude oil and has several crude oil pipeline connections with the US, Canadian heavy oil and bitumen production was only 22% of the production in Latin America.

In March 2002, Canadian heavy crude and bitumen production was 1,040,000 b/d with about 80% of this heavy crude and bitumen exported to the US. The principal destinations are the refining centers in the Chicago/ Whiting, Minneapolis/St. Paul, Billings, Toledo, and Wood River, Ill.

Diluent blends

These volumes move in existing pipelines, and the viscosity is adjusted by addition of diluent consisting generally of C5+ or condensate. The diluted bitumen with C5+ is usually referred to as "dilbit."

The Alberta bitumen production during first quarter 2002 was 281,360 b/d. Based on the remaining established reserves of 175 billion bbl, the Alberta bitumen reserves life index is more than 1,700 years. (Note: Alberta Energy and Utility Board data may show higher reserves of bitumen, but inclusion of bitumen feedstock to oil sands upgraders would reduce the remaining life of established bitumen reserves to less than 1,000 years.)

Natural gas production in Alberta and British Columbia also increased during the 1990s, and processors were able to increase the recovery of C5+ and condensate in Alberta. With Alberta gas supply forecast to leveling, the Alberta C5+ and condensate supply should also level off (Fig. 1).

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Some producers have extended the diluent supply with the addition of modest quantities of butane. Others have sought to find diluent supply by railing diluent from US locations. For example, the C5+ at the Aux Sable plant near Chicago has being railed back to Hardisty, Alta.

Diluent recycle by rail is a high-cost source but may be justified by low market value in the US Midwest and circumstances in which the transport of diluent to Alberta represents incremental revenue to the railroad.

In some cases, the use of diluent depends entirely on economics. Modest amounts of diluent (3%) are blended into some heavy crudes in order to raise the gravity and lower the viscosity so that these crudes can qualify in the medium crude category, which has an 8% tariff surcharge vs. 22% for heavy crude.

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If the cost of diluent exceeds the transportation cost penalty by downgrading to heavy, then the producer could and likely would refrain from using a diluent.

There can be economic penalties implicit in the use of C5+ as diluent because in Alberta C5+ generally has a value comparable to light crude.

During periods of high diluent demand, the price for C5+ in Western Canada may reflect a significant premium (Fig. 2).

In the US Midwest and other markets which receive Canadian heavy and dilbit, the value of C5+ to a refinery is often less than its cost.

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Fig. 3 shows that the sharp escalation in the C5+ premium corresponds to increased Alberta bitumen production. Typically the dilbit consists of 28% C5+ , and thus bitumen requires a significant portion of the available C5+ . The diluent demand varies seasonally.

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In the winter, diluent demand is greater because the lower ambient temperatures require greater amounts of diluent; and lower production of asphalt in Western Canada reduces diluent recycle.

Fig. 3 also shows that the bitumen production declines after the sharp escalation in C5+ premiums (January 1998 and January 2001). During 2000, Alberta bitumen production increased steadily, to 317,000 b/d in December 2000 from 265,000 b/d in January, reaching 330,000 b/d in June 2001.

In October 1999, the Alberta price for C5+ was a discount to Alberta light sweet crude. In January 2001, Alberta premium for C5+ was (US) $4.58/bbl and the premium was $3.03/bbl in June 2001. By November 2001, Alberta bitumen production declined to 289,000 b/d and the premium for Alberta C5+ disappeared.

Depending on currency exchange rates, the pipeline toll for heavy crude from Edmonton or another pipeline terminal to Illinois is about $1.48/ bbl.2 This does not include the bitumen transportation from the field to the pipeline terminal.

Bitumen is generally shipped as dilbit, and the costs associated with diluent acquisition and use can significantly raise the effective transportation cost of deliveries to Illinois, and other US destinations.

Diluent costs

These diluent costs include acquisition costs, pipeline transportation costs for the diluent from a location such as Edmonton or Fort Saskatchewan to the point of production such as Cold Lake or the Fort McMurray region, and the costs of moving the diluent as dilbit from the field via a pipeline terminal, and the pipeline toll from the terminal to the refining center, less the value of the diluent at the end-use refinery.

Generally the delivered cost of C5+ in the dilbit will exceed its value. For June 2001, the value of C5+ plus at Edmonton was $30.53/bbl, and the estimated cost of the diluent transport exceeded the value of C5+ in the US Midwest by $8.80/bbl of diluent, or $3.42/bbl of bitumen at a 72/28 blend ratio (see accompanying sample calculation, this page).

The analysis arbitrarily assumes that the US Midwest refinery value of diluent in the dilbit is equal to the price of natural gasoline on the US Gulf Coast. A significant portion of the diluent cost was a result of the decline in the US Gulf Coast price for natural gasoline from $34.15/bbl in January 2001 to $23.91/bbl in June 2001.

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Although the cost of the diluent will fluctuate, it can be a significant cost when the acquisition costs of C5+ is a significant premium to light crude at Edmonton. For June 2001, the loss associated with the diluent transport exceeded the published pipeline toll for bitumen by a factor of 2.3, making the total cost of moving bitumen $4.90/ bbl.

Fig. 1 shows that the expected Alberta supply of C5+ and condensate is relatively flat; the actual diluent availability is slightly larger than shown because of C5+ and condensate supply from British Columbia.

Fig. 3 shows that premium for C5+ in Alberta rises sharply when Alberta bitumen production exceeds 300,000 b/d. Over short distances, such as bitumen deliveries to an Edmonton refinery or the upgrader at Lloydminster, diluent can be recovered at the refinery or upgrader and recycled or returned to the field.

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Recent data published by the NEB indicate that the diluent recycle was approximately 17,800 b/d in first quarter 2002.3

The diluent pool can also be expanded by railing C5+ or natural gasoline from more-distant locations such as the Aux Sable plant in Illinois. The return of diluent by rail is limited by economics.

The diluent supply can be and is also extended by commingling butanes with the diluent material.4 Butane spiking is limited by crude oil vapor-pressure specifications.

Due to the lack of additional C5+ supply, producers are considering use of alternative diluents such as synthetic crude. The blended bitumen with a synthetic crude is called "synbit."

There are substantial volumes of sweet and some sour synthetic crude available in the Fort McMurray area. Because the viscosity of synthetic crude is much higher than C5+ , more of this type of diluent is required to achieve the same overall viscosity reduction. The synbits may contain approximately 45% synthetic.

As with C5+ , there is an issue of cost, suitability, and value of the synbit in the refinery centers. Given the potential for cost overruns in Alberta for bitumen upgrading projects, together with premiums on transportation, and the lack of a clearly economic diluent, the competitiveness of Alberta heavy oil and bitumen may suffer in relation to similar supplies from other heavy oil producing regions, primarily Venezuela and Mexico.

The pipeline benefit of adding a diluent is the reduction in viscosity of the bitumen, as Fig. 4 shows, where C8 represents synthetic crude.

This viscosity reduction allows for a greater flow at a given pressure drop between pumping stations (i.e., for a 900-psi pipeline with 240-mile station spacing, the maximum pressure drop is 3.75 psi/mile in the following example).

Up to a certain point (optimum point), adding diluent allows for greater flow capacity, above the additional diluent. In effect, additional bitumen can also be transported.

Beyond this optimum point, the capacity gain from the viscosity reduction no longer creates capacity for additional bitumen, only for the added diluent (Fig. 5). The calculations for both Figs. 4 and 5 assume a bitumen with 10° API gravity.

As there is usually a loss of value in transporting diluent and the primary purpose is to transport the bitumen, there is no benefit in adding diluent beyond this optimum point. As a result of this, the optimum blend ratio and the resulting target viscosity are different for different types of diluent.

Sample pipeline

Analysis and pipeline simulation for a 36-in. pipeline operating at 900 psi and 60° F. with a 240-mile station spacing shows that, with C5+ , the optimum flow for dilbit is 420,000 b/d, based on 35% C5+ as diluent. The bitumen capacity is 65% of 420,000 b/d or 273,000 b/d. The viscosity of the dilbit is 39 cp. At greater than a 35% blend ratio, the net capacity to carry bitumen declines.

A similar analysis for synbit indicates that the optimum flow for synbit is 323,000 b/d, based on 45% synthetic as diluent. The bitumen capacity is 55% of 323,000 b/d or 177,000 b/d.

The viscosity of the synbit is 202 cp. At greater than a 45% blend ratio, the net capacity to carry bitumen declines. Use of synthetic crude reduces the capacity of the pipeline for bitumen by almost 35%.

While these results depend on the configuration of the pipeline, the fluid properties of the bitumen and diluent, and other factors, the conclusion is similar for all cases. Using heavier diluent reduces not only the net amount of bitumen transported (as a greater percentage of diluent is required), but also the total capacity of the pipeline to carry synbit, as the optimum target viscosity is higher and the resulting pipeline capacity is lower.

This result is masked by the typical batch pipeline's specifications, in which either a maximum viscosity of the blended material or maximum density are set as the controlling parameters. If the maximum viscosity on the pipeline is 202 cp at 60° F., a 24.5% C5+ blend will achieve this viscosity, and the dilbit capacity is 323,000 b/d, with a bitumen capacity of 244,000 b/d.

As previously shown, the same pipeline could carry 273,000 b/d of bitumen if the C5+ blend is increased to 35% and the dilbit viscosity reduced to 39 cp. As this conclusion is based on a constant pressure drop between stations, additional horsepower at each station is required to transport the greater volumes of dilbit.

The bitumen that is transported must pay for the loss in value on the diluent. If the pipeline uses a constant maximum viscosity as the controlling parameter, a similar capacity (323,000 b/d at 202 cp) is created with use either of 24.5% C5+ or 45% synthetic. The loss in value on the 24.5% C5+ must be paid for by the 75.5% bitumen.

Thus, if there is a $4/bbl loss in value on the C5+ used as diluent, the bitumen transport cost increases by $1.30/bbl (i.e., $4/bbl.3.24.5/75.5 = $1.30/bbl). With synthetic diluent, a similar impact will occur if the loss in value on synthetic crude is $1.59/bbl (i.e., $1.59/bbl 3 45/55 = $1.30/bbl).

The value of synthetic crude in the synbit is therefore a critical factor. Unless the value of the synthetic crude in the synbit at the point of pipeline receipt is equal to or greater than its value as a segregated crude oil, there will be no incentive to use synthetic crude as diluent, unless the bitumen producer pays a premium.

The use of heavier diluents to transport the bitumen will likely damage the economics of producing and marketing bitumen. The move to heavier diluents is limited by the availability of C5+ to use as diluent. Attempts by new bitumen producers to obtain C5+ will lead to higher costs of C5+ for all bitumen producers, or premiums for synthetic crude.

Thus, the competitiveness of Alberta bitumen suffers as additional bitumen supply is brought on stream.

The basic circumstances have been understood for some time and partially explain why there have been significant investments in upgrading capacity in Western Canada. The upgrading projects, which are underway and nearing completion, have experienced significant cost over-runs.

These circumstances suggest that, due to restrictions on labor and infrastructure in Alberta, there is a limit on the number of oil sands upgraders that can be built in any period of time. There are several proposed facilities, and these projects, if they proceed, will likely strain the available engineering and manpower capability.

While there are plans to expand Alberta bitumen production, the expansion of Canadian bitumen production has lagged the expansion of production of heavy crude oil in Latin America (Table 1). One of the reasons for the Canadian circumstances may be the research emphasis on production, extraction, upgrading, and environmental issues in Alberta. While these matters were important, the development of pipeline technology and pipeline concepts has been left to the private sector.

Other pipeline technology

In contrast to the situation in Canada, Petróleo de Venezuela SA (PDVSA) has undertaken several investigations of the transportation of heavy and extra-heavy crude, and PDVSA personnel have presented numerous papers on transportation.

Venezuela has successfully expanded heavy oil production by correctly identifying transportation as one of the key constraints in marketing heavy and extra heavy oil. Canada perhaps has something to learn from the Venezuelans.

In Canada, there has also been interest in some unconventional pipeline designs to solve this problem. One option is the use of heated, insulated pipelines with minimal or no diluent. With the insulation and heat requirement, these pipelines can have significantly higher costs.

The issue of the bitumen cooling and solidifying during an extended pipeline shutdown must also be managed, either by flushing the lines with intermediate storage or some other mechanism.

There are also concepts in which the bitumen is commingled or emulsified with water. At the destination, the water would be separated from the commingled stream. The treatment of the water may present technical challenges. One economic concern is the supply and transport of water. The transporter would have to obtain approval to export water and the bitumen would have to pay the entire pipeline, dehydration, and water purification costs.

Conclusions

The facts and issues discussed offer some obvious conclusions:

The existing C5+ and condensate supply can be enhanced by diluent recycle, but the extent of diluent recycle is limited by economics.

Butane spiking can marginally expand the diluent pool but is limited by the penalties on the butane content in C5+ exceeding 5%.

Synthetic crude offers another source of diluent, but it is less effective than C5+ because more is required.

The existing markets the Chicago/Whiting, Minneapolis/St. Paul, Billings, Toledo, and Wood River areas are well served by Canadian heavy crude oil and bitumen. And, although there is potential for further investments in these regions, the refiners are often reluctant to make these investments and some refineries are vulnerable to closure.

Canadian bitumen producers therefore face a double challenge of diluent supply and expansion of market access.

There have been significant cost overruns at the oil sands and bitumen upgraders that under construction, and no immediate short-term solution to this problem appears.

Even with continued investments in bitumen upgrading, existing Alberta bitumen reserves will not be fully exploited, and there will little incentive to exploit the full bitumen resource potential in Alberta.

The proven reserves of Alberta bitumen will last a long time, and the Alberta bitumen resource potential will last a very long time.

Events of the last 15 months, including curtailments by the Organization of Petroleum Exporting Countries, political uncertainty in Venezuela, and possible war with Iraq, make clear North America's vulnerability to crude supply disruptions. Increased pipeline movement of the raw bitumen production from Canada to other parts of the US could mitigate this vulnerability. Such movements will likely be based on pipeline concepts that expand the diluent availability or eliminate it completely and access new markets.

References

  1. National Energy Board, "Canada's Oil Sands: A Supply and Market Outlook to 2015," October 2000, p. 5.
  2. Enbridge Pipelines Inc. pipeline toll NEB No. 223, and Lakehead pipeline toll FERC No.38.
  3. National Energy Board, "Western Canada Crude Availability 2002," Table 2 (available on NEB website).
  4. Hawkins Gas Consultants, "LPG Outlook 2002" multiclient study, July 2002. Government of Alberta, "AOSTRA: A 15 Year Portfolio of Achievement."

The authors

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David J. Hawkins (dh@ hawkinsgas.com) is president of Hawkins Gas Consultants Ltd., Calgary. He joined the Canadian affiliate of Purvin & Gertz Inc. 1976-97, then consulted 1997-99 for Alliance Pipeline. Hawkins holds a doctorate in control systems from the Victoria University of Manchester (England) and a BASc in engineering science and MASc in chemical engineering from the University of Toronto. He is a member of the Canadian Society for Chemical Engineering and the International Association for Energy Economics. He is a registered professional engineer in Alberta and Ontario.

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Glen F. Perry ([email protected]) is an independent consultant and previously serviced as vice-president of business development for Alliance Pipeline through January 2001. He was co-inventor of the patents that were obtained on the Alliance pipeline technology. Perry also had worked for Direct Energy Marketing Ltd., Unocal Canada, Dome Petroleum Ltd., and Foothills Pipe Line Ltd. He holds a BS in mathematics from the University of Calgary.