Technology is improving the ability to produce heavy oil, but there is a new economic paradigm: Portfolio managers can no longer consider the upstream separate from downstream operations.

At room temperature, ultra-heavy oil is as thick as peanut butter. Lighter versions ooze like honey. Temperature affects the viscosity, so if a sample jar of heavy oil is spilled on the ground in cold weather, just wait a few minutes and roll it up like a rug.

The term "heavy oil" can be confusing. It applies to a wide range of crude that requires an equally broad range of techniques to produce it. Most often, producers drill for heavy oil, but in some cases it is mined, using trucks the size of small buildings to haul away the ore. It's important to remember that what works for one heavy-oil field may not work at all in the next.

Until recently, heavy oil in commercial quantities was considered a resource limited to Canada, Venezuela and the western U.S. Viscous crude was known to exist elsewhere, but there was little interest in producing it.

Now, with portfolio managers scrambling to book long-term reserves, heavy oil is drawing more interest. Large-scale production of heavy oil will likely have a profound impact, not only on the structure of the oil industry, but on global politics and economics as well. The Society of Exploration Geologists (SEG) estimates that there could be more than 6 trillion barrels of heavy oil worldwide, with 80% of those deposits in the Western Hemisphere.

California's heavy-oil region, centered in Kern County, has been a steady producer for more than 100 years; four of its largest fields have produced more than 1 billion barrels each. California's history illustrates two of the main selling points for asset managers: Heavy-oil plays tend to last a long time, and they produce a lot of oil.

Far north of California's heavy-oil region lies an even larger supply. The U.S. Department of Energy (DOE) estimates Alaska's North Slope holds 10- to 20 billion barrels of heavy oil. There are also significant deposits in Brazil, Mexico, the Middle East and Asia, but two countries hold the lion's share.

Canada and Venezuela hold 90% of the world's known heavy-oil reserves, according to the Alberta Research Council as reported by CSEG Recorder, a publication of the Canadian Society of Exploration Geophysicists. Venezuela has the world's largest known deposits, and by 2015, heavy oil will make Canada the world's fifth-largest oil producer. Russia is also likely to be one of the world's top heavy-oil producers in the next decade.



Nature of heavy crude

Heavy oil has several definitions, but the term generally covers anything with an API gravity of 22 or lower. Because heavy crude is difficult to transport and refine, it sells at a discount. The California Independent Petroleum Association recently noted that the price spread between light and heavy crude is about $12.50 a barrel. That varies, of course, with location. The spread can also be greater if the heavy crude has other detracting components, such as high sulfur content.

Heavy oil is also harder to process than lighter crudes, so few refineries take it. Although 45% of all refineries could be upgraded to process heavy crude, only about 25% can do so today, and most of those are in the U.S. For the refiners who can use it, heavy crude is a bargain. Catalyst and refining technologies in the last decade have improved so the refiners now get about as much yield from a barrel of heavy oil as they do from lighter feedstocks.

Heavy oil can be produced in limited amounts by "cold" production, with typical recovery factors in the range of 5% to 8%. The most common way to produce heavy oil is to heat the reservoir, usually by injecting steam, which typically boosts recovery rates to well over 20%, and in some cases as high as 70%. Operators in California use steam-drives the way others might use water. Rows of up to 10 steam generators, each the size of a diesel locomotive, are a common sight.

Thermal recovery, however, is hugely expensive. In addition to the wells, there is the equipment and fuel to generate steam. Just one 50-million-Btu-per-hour gas-fired steam generator consumes the energy equivalent of more than 80,000 barrels of oil a year. Each bank of generators needs scrubbers to clean the exhaust, pipelines and injection wells to get steam into the ground, insulated pipelines to keep the produced-oil warm, and experienced operators to keep everything running.

In 2005, typical lifting costs for heavy oil in Kern County ran $12 to $14 per barrel, compared with $3 to $5 per barrel for lighter crudes from conventional land wells.

About 60% of the increased lifting cost is the expense of generating steam, but other economic factors may influence development. In California, for instance, individual wells are relatively cheap to drill, since they are seldom deeper than 3,000 feet. Some of these savings are eliminated, however, because heavy oil requires more wells on a relatively tight spacing.



Role of technology

Technology is boosting the recovery rate for heavy oil. Producers in Canada have been successful with a thermal technique called steam-assisted gravity drainage (SAGD), which is quite different from traditional steam flooding or cyclic steam stimulation (CSS). With SAGD (pronounced sag-dee), pairs of horizontal wells are drilled into the producing zone, one about five meters above the other. When steam is injected into the top well to heat the formation, gravity pushes the warm oil toward the producing well below.

The trick with this and any thermal recovery process is to minimize the steam-to-oil ratio (SOR), since steam is the largest single expense. Even a small shift in the SOR can have a significant impact on a field's overall economics. In 2005, Canada's National Energy Board estimated that operating costs of cyclical steam and SAGD processes ranged from C$10 to C$14 per barrel, compared with cold recovery processes at C$6 to C$10 per barrel. Operating expenses do not include the cost of capital, taxes or royalties.

One of the largest producers of unconventional oil and gas in North America notes that its oil-sand developments in Canada require an initial capital investment of about US$100 million for each 10,000 barrels of daily production, and sustaining capital of US$150 million over the project's life, which is estimated at 25 to 30 years.

Much of Venezuela's heavy oil is produced with a mix of cold and thermal recovery processes. Solvents or lighter crudes are then blended with the heavy crude to lighten and transport the oil. Other heavy-oil producers have tried-with limited economic success-systems that combine steam and solvents.

Operators in Alaska are producing heavy oil from the West Sak and Schrader Bluff formations by injecting slugs of water alternating with gas (WAG). The gas acts as a solvent to reduce viscosity and the water helps push the thinner oil toward producing wells. The process, although not as effective as thermal, will recover more oil than primary recovery alone. It is also less expensive than generating steam, which would be particularly challenging in such a remote area.

In an effort to optimize WAG flood designs, the DOE has funded additional research at the University of Houston.



Managing, monitoring wells

High-temperature well completions and artificial-lift systems are available to help manage and optimize the various thermal recovery systems. There are also new ways to monitor and control steam in the reservoir, both for steam floods and SAGD wells.

Techniques available include temperature, pressure and deep resistivity measurement; high-temperature pressure gauges; and instruments for cross-well resistivity and microseismic measurements. The economic realities of heavy-oil developments make some operators wary of investing in additional well-monitoring equipment, but the payoff in increased production and reliability often justifies the expense.

One major advance has been the introduction of downhole fiber-optic distributed-temperature sensors (DTS) that can monitor the temperature continuously at one-meter intervals throughout the well. With DTS, operators can see where steam chambers are developing along the entire length of a horizontal run, then use the information to increase or decrease the steam rates from nearby injection wells.

Not yet a commodity

Regardless of the technology used in the field, the important matter for portfolio managers to remember is that, unlike lighter crudes, heavy oil is not a commodity. Although the amount of heavy oil being produced each year is growing, it is unmarketable as it comes from the ground.

Like natural gas, heavy oil becomes what the industry calls a "stranded resource" when it is discovered far from the infrastructure to transport and refine it. Today, for example, there is the capacity to produce at least 2 million barrels of heavy oil per day from the Middle East, but there is no market for it.

Heavy oil is a long-term asset that is more like liquefied natural gas (LNG) than conventional oil. Adding heavy-oil reserves to a portfolio will not bring a rapid increase in production. The upfront capital expense can be far greater than the cost of developing a conventional field, and the payout takes much longer. The portfolio manager's goal, thus, is not for a high rate of return short term, but to secure long-term cash flow.

The high cost of production is just part of the story. Heavy-oil producers in North America have had to become part of the supply chain by investing in pipelines to deliver, and refineries to process their oil. That makes financing a problem. Bankers are used to paybacks of 10 or 15 years, not 30 to 50 years.



What producers can do

To make heavy oil a commodity on par with lighter crude, producers must transform the resource into something customers can use. They need to consider the entire value chain rather than the extraction process alone. With heavy oil, the goal is not to simply maximize recovery from the field, but to optimize recovery to achieve the maximum project economics. There are several options, using available technology, and more opportunities on the way.

Producers in Venezuela, for example, are upgrading most of the production from the prolific Faja del Orinoco ultra-heavy-oil region at a large upgrader facility on the coast. The upgrader was built as an integral part of the field development. While the upgraded oil is still considered heavy, there are refineries along the U.S. Gulf Coast that can handle it. This downstream solution, although expensive, is working well, given the size of the resource and its estimated longevity.

Technology, however, increases both the recovery factor and the cost. That works as long as oil prices are high, but what if they go down? The cost of production will remain high, reducing profit margins. The pressure, therefore, is on the upstream to reduce production costs.



Midsize producers

Multinational companies with deep pockets can afford the integrated upstream and downstream solutions that are typically applied to heavy-oil developments. They can build upgraders and modify their refineries to process heavy oil. Does that mean midsize producers will be left out? Not necessarily.

Using existing technology, some types of heavy oil can be processed in the field, converting perhaps one-third of the heavy oil into a commodity that is light enough to sell to any refinery. The remaining two-thirds can be reinjected. Although that means a lower recovery factor overall, it may improve the field economics enough to make the project a financial success.

Another possibility for midsize producers is a technology called "in situ" processing. It is a promising experimental technique that is not yet commercial. The idea is to install downhole heaters capable of raising the local reservoir temperature enough to begin breaking down the heavy oil into lighter components. The lighter ends could then be produced and sold as conventional light crude, while the heavier components would remain in the reservoir.

In early tests, in-situ processing appears to be competitive, both economically and in terms of energy balance. The downside is that more of the oil is left behind, but in some cases, in-situ processing could mean the difference between some production and none at all. Technology, however, is continually improving, and no one knows what will be available in 15 or 20 years. By that time, it is likely that new techniques could recover more of the oil being left in the ground today.

The fact remains that heavy oil is not a commodity. To develop a new resource, it is important to consider the downstream side. Producers must transform their heavy crude into something they can sell at an attractive margin. That is the strategic decision companies have to make, and it is the most difficult part of the game.



Jean Paul Chalot is a senior advisor with Schlumberger. He has 25 years of experience with majors, national oil companies and governments in originating, developing, financing and implementing energy projects.

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