The combined mining/extraction and upgrading operations of Canada’s oil sands industry has made considerable use of cogeneration plant. However, a modern trend to separate upgrading from mining and extraction operations has complicated the case for continuing to build new cogeneration plant. Jeremy Moorhouse and Bruce Peachey report.
The International Energy Agency (IEA) projects a 60% increase in world oil demand between 2000 and 2030. Unconventional oil supplies such as bitumen and heavy oil resources are anticipated to supply a growing percentage of this demand. Bitumen and heavy oil resources are huge, the United States Geological Survey (USGS) estimates that globally there are 434 billion barrels (BBO) of technically recoverable heavy oil and 651 BBO of technically recoverable bitumen (in places volumes are estimated to be roughly ten times these values) – see Figure 1. The sum of these values is approximately equal to global estimates of remaining light crude reserves.
Figure 1. Distribution of recoverable conventional natural bitumen and heavy oil resources – units in BBO.
Although heavy oil and bitumen deposits exist all over the world (see Table 1), a few large deposits account for the majority of recoverable reserves. Alberta, Canada contains roughly 80% of the recoverable bitumen reserves and South America, most notably the Orinoco heavy oil belt in Venezuela, accounts for approximately 60% of the recoverable heavy oil.
For the most part, heavy oil and bitumen resources continue to be undeveloped, accounting for only three of the 25 BBO produced annually worldwide. In Canada, a combination of advances in technology, higher oil prices and government support is leading to significant growth in Alberta’s oil sands. Current production stands at approximately a million barrels/day (BPD) of bitumen which could reach six million BPD by 2025 if all listed projects are developed (includes all operating, approved, applied for, disclosed and announced projects).
Oil sands operations are made up of essentially two processes: extraction, through mining (shallow bitumen extraction) or in-situ (deep bitumen extraction); and upgrading (the conversion of bitumen into something similar to crude oil).
COGENERATION MAKES MOST SENSE
All of the above processes are technically challenging, energy and resource intensive and environmentally damaging. The rapid adoption of cogeneration continues to be successful in increasing energy efficiency and reducing greenhouse gas emissions. Cogeneration makes most sense when designed into integrated mining, extraction and upgrading oil sands projects, as discussed in more detail below, as they have a need for both power and heat energy. In the current deregulated energy market, cogeneration offers clear benefits such as increased reliability and efficiency, as well as reduced energy costs and greenhouse gas emissions.
However, changing dynamics in the oil sands sector make it more compelling for operators to geographically separate the extraction and upgrading components of their operations. Although, operators of large standalone mining and in-situ projects can often realize the benefits mentioned above, the benefits of incorporating cogeneration into a standalone upgrader are less obvious from an individual operator’s perspective. Cogeneration may still provide regional benefits but these are likely to need the support of government initiatives.
OIL SANDS RECOVERY PROCESSES
In general there are two steps that must be performed before the bitumen can be converted into gasoline, diesel or other petroleum products. Firstly, the bitumen is extracted from the oil sands, using either mining or in-situ techniques. Secondly, the bitumen is converted or upgraded into a product known as synthetic crude oil (SCO). SCO is similar to crude oil in composition and can be processed at modified refineries. These energy intensive processes rely primarily on natural gas combustion to produce heat, hydrogen for upgrading and, in most cases, electricity through cogeneration.
Mining is the primary technique for extracting bitumen from the oil sands in Alberta. Large truck and shovel operations are used to transport the bitumen laden oil sands to a central processing facility. Here the oil sands are crushed and the bitumen is extracted from the bulk sand with warm water to produce a bitumen froth. The froth is then treated with solvents for the final separation of bitumen. At this point the bitumen is delivered to an upgrader to be converted into SCO. This entire process requires roughly two to five barrels of extracted fresh water (i.e. this is the net amount of water required per barrel as some water is recycled), 7.08 m3 (250 cubic feet) of natural gas and roughly 30 kWh of electricity. It also produces 30-40 kg of CO2eq/barrel.
Mining operations account for 60% or 600,000 BPD of bitumen production in Alberta and are expected to expand to three million BPD by 2025 if all listed projects go forward. However, the Alberta Energy and Utilities Board estimates that mineable reserves account for only 3.5% of the total bitumen in place, and 20% of total recoverable reserves in Alberta.
The remaining 80% of reserves are assumed to be economically recoverable only by in-situ techniques. Unlike conventional crude oil, the thick and viscous properties of bitumen prevent it from being recovered using conventional well drilling techniques. Special recovery methods, most commonly the injection of pressurized steam, are needed to separate the bitumen from the oil sands so it can be pumped to the surface. With existing in-situ plants, the water is recovered, treated and reused at recycle rates around 90%. Natural gas is the primary fuel source used to generate steam. An average in-situ project requires 28.3 m3 (1000 cubic feet) of natural gas, less than barrel of water and less than a kWh of electricity and generates 50-60 kg CO2eq/barrel of bitumen. In-situ operations are thus, on average, three to four times more energy intensive than mining operations but require less water and electricity.
For in-situ thermal schemes, cogeneration is suitable for larger operations (over 25,000 BPD). However, the heating load is much larger than the power demand unless large amounts of power can be exported off-site. Current in-situ production is 400,000 BPD and accounts for 40% of total bitumen production in Alberta. It is expected to increase to three million BPD by 2025 if all listed projects go forward.
After being extracted, either through mining or in-situ techniques, the bitumen must be upgraded into SCO before it can be refined. The process of upgrading involves breaking the long, heavy molecules of bitumen into smaller ones and removing impurities, including sulphur, nitrogen and carbon. This is done in two stages. The first stage, which involves cracking the large bitumen hydrocarbons, is accomplished using coking, hydrocracking or both. The second stage of upgrading is called hydrotreating, whereby high pressures and temperatures are used to remove nitrogen and sulphur.
Regardless of the process used, upgrading requires significant amounts of electricity, between 14 and 55 kWh, natural gas, between 1.1-8.5 m3 (40-300 ft3) and water, between 0.5 and one barrel (BBL). It also emits 20 to 200 kg of CO2eq/BBL of bitumen produced. Natural gas is currently used for hydrogen production, through methane reformation and heat. However, future upgraders plan to gasify waste products to produce hydrogen and supply heat. Alberta currently has an upgrading capacity of 700,000 BPD of bitumen, which is projected to expand to 4.3 million BPD of bitumen by 2025. Table 2 shows the water, natural gas and electricity requirements, as well as greenhouse gas (GHG) emissions for the primary oil sands processes.
COGENERATION IN OIL SANDS PROJECTS
The rapid adoption of cogeneration in the oil sands sector, in both mining and in-situ operations, has been very successful in improving environmental, economic and emissions results for the oil sands producers. The dramatic history and results of this shift toward cogeneration illustrate what can be achieved in a rapidly growing and energy intensive sector in a very short time. This is especially impressive when compared to the development of stationary power developments.
Suncor oil sands processing facility by Athabasca
Between 1996 and 2006, a paradigm shift occurred in a rapid move from centralized coal-fired thermal generation (30% thermal efficiency generation) to natural gas fired cogeneration (60-80% overall thermal efficiency) – see Figure 2. The start of the shift occurred when the provincial government decided to deregulate the power industry in the province. Alberta was simply following trends in other jurisdictions, but the change effectively allowed large energy users to implement cogeneration technologies in their new developments.
Figure 2. Alberta power generation capacity mix. Source: Alberta Dept of Energy
With deregulation, the oil and gas producers in the province began to see the potential of becoming ‘energy companies’ with assets expanding into traditional utility markets. Deregulation had the largest impact on the development of major oil sands projects, where there are large heating and power loads that can be effectively integrated to generate significant efficiencies and economic benefits.
In 1996, Natural Resources Canada prepared ‘Canada’s Energy Outlook: 1996-2020’ which looked at all energy supplies and demands for that period. For oil sands, it was assumed that production would grow at a modest rate, and that the oil sands producers would continue past practices of using power from remote coal-fired generation to meet their electrical demands. Deregulation of the power industry, and royalty incentives to increase oil sands production, resulted in both a more rapid growth in production, and an almost complete transition to cogeneration for the oil sands power supply.
As a result, the energy demands of oil sands extraction and the value of the energy sources for the sector did not increase in proportion to the production increases, mainly because of savings through cogeneration. Instead, the over 100% increase in production, compared to the original growth estimates, required only an estimated 56% increase in energy input and only a 42% increase in the value of the energy used.
GHG emissions were also significantly reduced by the conversion to natural gas cogeneration. Including indirect emissions from coal power, the net GHG emissions from oil sands production dropped by an estimated 7 MtCO2e / year between 1996 and 2006, compared to what they would have been under the ‘business as usual’ case of coal fired power supply – see Figure 3. Overall, this represented a 30% drop in GHG emissions vs. the business as usual case (total oil sands emissions from mining/upgrading operations = 20 MT / year, thermal in-situ oilsands emissions were about nine MT / year).
Figure 3. GHG emissions to supply heat and power to oil sands in 2005
Almost 80% of the reduction resulted from conversion to natural gas for electrical energy from the more carbon intensive Alberta grid that uses primarily coal generation, with the additional 20% resulting from increased efficiency through onsite cogeneration.
Mining operations at the Syncrude mine
The implementation of cogeneration was most pronounced in the integrated mining, extraction and upgrading operations, which generally have a matched need for both power and heat energy. The Husky Upgrader in Lloydminster, which is an offsite upgrader mainly processing locally produced conventional heavy oil and some in-situ Cold Lake bitumen, was the first to be in operation with 220 MW in 1999, followed by Syncrude Mildred Lake (2000) at 80 MW, Suncor (2001) at 356 MW and TransAlta MacKay River at 165 MW. Imperial Oil was one of the first to include an integrated cogeneration facility for an in-situ thermal oilsands operation with a 170 MW project in 2002. Since then, other upgrader additions, expansions and in-situ operations have incorporated cogeneration in their planning to the point where the oilsands operations are net exporters of electrical power – roughly 25%-30% (500 MW) of generated cogeneration electricity is exported to the grid.
The Suncor oil sands processing and upgrader facility uses a 356 MW cogeneration plant (All photos: David Dodge/The Pembina Institute)
TransCanada estimates that there could be 3500 MW of cogeneration potential for the oil sands region by 2015. However this could be limited because of a lack of transmission lines out of the oilsands regions.
COGENERATION OPPORTUNITIES FOR OFF-SITE BITUMEN UPGRADERS
Traditionally, upgraders have been integrated with oil sands mining operations. In this environment, operators installed cogeneration units in order to capitalize on clear increases in energy efficiency and economics. However, current pressures to locate upgraders further from the oil sands and to reduce natural gas dependence, are altering the arguments for the incorporation of onsite power generation. Hemson Consulting determined that over 40% of Alberta’s projected upgrading capacity is to be located in the Edmonton area, more than 700 km from the oil sands region. If all of these projects are developed, this could result in additional power requirements of around 1000 MWe based on the average electricity intensity of Edmonton area upgraders.
This region offers synergies with other industries, infrastructure (roads, electricity, natural gas, water) and a sizeable labour force. Here, the decision to incorporate cogeneration can only be made on a case-by-case basis with individual projects largely influenced by economic drivers, environmental and government requirements, and corporate culture.
Given that the most economic activity of an upgrader is to maximize SCO production, this may compete with the desire to produce electricity from available upgrader by-products. In addition, in the desire to reduce natural gas dependence, natural gas prices have tripled over the past ten years, so that most upgrader operators are planning to use available waste products for heat and hydrogen production. Onsite electricity generation is therefore produced at the expense of other marketable products such as hydrogen, fuel gas (a byproduct of certain upgrading processes that can be cleaned and burned in a gas turbine) and SCO.
This is not necessarily a simple decision given that different companies have come to different conclusions. For example, the Synenco upgrader, which is temporarily on hold, had two operation scenarios: to maximize power production or maximize hydrogen production. Synenco was able to find clients for its hydrogen so decided not produce its own electricity. Similarly, North West Upgrading Corporation stated in its environmental impact assessment (EIA) that ‘the end products of the upgrader provide more value than power produced by a cogen unit’. The organization is, however, ‘continuing to evaluate plans for cogeneration’.
Other organizations have determined that cogeneration is a worthy investment. For example, Petro-Canada’s Sturgeon Upgrader planned cogeneration facility is to supply all the upgrader’s internal electrical load and will export 176 MWe of electricity. This provides increased reliability of power supply when coordinated with a grid connection; particularly important when considering the high cost of suspending operations through loss of grid electricity. The Husky Lloydminister upgrader, a currently operating offsite upgrader, also chose to incorporate a 215 MWe cogeneration unit into its facility.
Further, The Bitumen Upgrading Integration Study – conducted by the Alberta Energy Research Institute – came to the same conclusion in the design of a conceptual integrated upgrader. This study chose combined heat and power production to ‘obtain lower cost power, higher thermal efficiency and higher reliability’ in its conceptual design.
An additional influencing economic factor is the exposure of an individual upgrader operator to market fluctuations in the price of bitumen and SCO. The profitability of an upgrader is largely determined by the spread between the economic value of these two products. An organization that owns both the upstream bitumen production and the downstream SCO production, such as Petro-Canada, is less vulnerable to fluctuations in the price of bitumen as its bitumen price will be determined primarily by the production costs.
An independent upgrader, on the other hand, is exposed to both the fluctuating price of SCO and bitumen. This exposure makes independent upgraders, such as North West Upgrading, higher risk ventures that are less likely to invest in more capital intensive processes, such as cogeneration units.
From an environmental point of view, facility-based provincial and federal regulations can act as a disincentive to the production of on-site electricity. These regulations encourage facilities to lower onsite emissions, which can encourage companies to purchase electricity from the grid. For example, Synenco noted that on-site air emissions would increase if the organization incorporated an onsite cogeneration facility.
On the other hand, Government requirements for facility operators to consider cogeneration can also encourage companies to consider cogeneration. All proposed projects are required to describe ‘the options considered for supplying thermal energy and electric power for the project, and their environmental implications, including opportunities to increase the energy efficiency of the project with the use of waste heat or cogeneration of heat and electrical power’. The direct impact of this requirement is unclear. However, the Manager of the National Center for Upgrading Technology, formed by the Canadian Federal and Alberta Provincial government in 1995, noted that companies are sensitive to Government concerns and this provision requires project proponents to consider cogeneration as an option.
It is difficult to clearly correlate corporate culture with certain actions. However, it is worth noting that both Shell Canada and Petro-Canada have had experience with onsite power generation and currently have, or are planning to, incorporate cogeneration into their new operations. The Director of Project Development for Petro-Canada’s Sturgeon Upgrader noted that: ‘It is quite common [for oil and gas companies] to form these types of relationships with power producers’. Other groups without this experience, such as North West Upgrading, did not include plans for a cogeneration unit.
In summary, the decision to incorporate a cogeneration unit into an offsite upgrader is influenced by economic considerations, as well as environmental and government requirements and corporate culture. It is unknown at this point as to whether cogeneration will play as important a role in this region as it has it the oil sands. What is known is that it is, at a minimum, being considered by every company and cogeneration could supply this region with over 1000 MWe of electricity. Moreover, oil sands operations overall could be exporting up to 3500 MW of power if transmission capacity allowed cogeneration to be developed to the maximum extent.
As global demand for oil increases and conventional resources decrease, unconventional resources are expected to supply an increasing percentage of this demand. However, developing heavy oil and bitumen resources is extremely energy and resource-intensive as well as environmentally damaging. Under the right conditions, cogeneration can economically increase energy efficiency while reducing environmental impact.
Deregulation of the electricity market in Alberta, Canada resulted in extensive adoption of cogeneration in the oil sands region. The implementation of cogeneration was most pronounced in the integrated mining, extraction and upgrading operations, which generally have a matched need for both power and heat energy. Cogeneration facilitated oil sands production to grow by 100% while reducing projected energy requirements by 45% and electricity generation related GHG emissions by 50% between 1996 and 2006.
However, in response to changing dynamics in the oil sands sector, operators are beginning to separate upgraders geographically from oil sands production. From an individual operator’s perspective, the benefits of incorporating a cogeneration unit are less obvious when the unit is not integrated with mining and in-situ operations. Furthermore, the benefits depend on careful consideration of several economic factors as well as environmental regulations, government requirements and corporate culture. Nonetheless, there are likely systemic benefits that the Alberta Government is encouraging by requiring that all upgrader proponents to explore the option of cogeneration.
As the oil sands example demonstrates, the primary benefits of cogeneration are realized when viewed from a systems perspective, such as the integration of extraction and upgrading systems in the oil sands. However, when not integrated, the optimization of individual operations could result in decreased efficiency of the entire system, as may result in the Edmonton area. Government encouragement to consider cogeneration from a systems perspective is sometimes necessary to ensure that environmental and economic benefits are realized.
Jeremy Moorhouse is with Pembina Corporate Consulting, Calgary, Alberta, Canada.
Fax: +1 403 269 3377
Bruce Peachey is the President of New Paradigm Engineering Ltd., Edmonton, Alberta, Canada.