The world has a huge appetite for energy. In its recent publication 2012 The Outlook for Energy: A View to 2040, ExxonMobil forecasts global energy demand to increase by about 30 percent between 2010 and 2040. While nuclear and renewable energy production will grow to meet some of this demand, the vast majority will continue to be met from fossil fuels. As opportunities for ‘easy’ conventional petroleum deposits dwindle, the challenges and costs of meeting this expanding energy demand will only increase.
An improved understanding of unconventional resources, and further advances in applicable technology, have increased and should continue to increase the proportion of unconventional reserves that may be economically recovered. These developments will further enhance the viability of these projects and help provide the critical mass required to underpin large scale ventures. Unconventional resources are destined to contribute a far greater share of future energy supplies. Oil sands production alone is estimated to account for 25 per cent of the total liquids fuel supply in North and South America by 2040.
‘Unconventional’ petroleum is a dynamic concept - what constitutes unconventional shifts as new technologies render a previously ‘unconventional’ deposit more accessible. In this series of papers we look at unconventional petroleum such as coal bed methane, oil sands, shale, tight reservoirs, underground coal gasification and hydrates. We also discuss unconventional means of developing conventional reserves, including floating LNG and projects in extreme conditions such as the Arctic.
Our energy team works with clients around the world in developing and financing unconventional petroleum projects, and on unconventional means of developing conventional reserves. We know the issues and understand the industry. For further information, please ask your usual Norton Rose Group contact or any person listed on the back page.
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What is it?
The term 'oil sands' refers to sand which, in addition to water, clay and other substances, is mixed with bitumen. Bitumen, also referred to as tar (and hence oil sands are also often referred to as ‘tar sands’), comprises heavy molecules that remain behind in the sands after lighter molecules are released following degradation. The distinction between bitumen and extra-heavy crude oil is somewhat blurred. They are both very dense, with an API gravity of less than 10 degrees, but extra-heavy oil is less viscous and so can generally flow somewhat easier than bitumen.
Conventional oil is ordinarily produced by driling wells into high pressure accumulations, with the oil then flowing according to Darcy's law towards the low pressure area created by the drill bit. As bitumen is too heavy and viscous to flow towards the low pressure area, at least at a rate that would make production economic, it cannot be recovered through conventional means. There are two primary methods used for producing bitumen:
- Deeper sands, typically below 225 feet, are usually less viscous and so can be produced by injecting steam, solvents, hot air or lighter hydrocarbons into the well to improve viscosity further and enable recovery
- In shallower sands, the bitumen ore may be recovered by strip mining with huge shovels and trucks capable of hauling up to 360 tonnes of mixed sand and bitumen. This mix is taken to a crusher, which breaks up the ore so that it can be transported to an extraction plant. During extraction, the bitumen is separated from water, sand and other materials.
Currently most of the production from oil sands projects is from surface open pit mines. This will soon change however. At the present time, only Canada has a large-scale commercial oil sands industry, and the majority of that is in Alberta. About 80 per cent of Alberta’s bitumen deposits are too deep underground to be reached by open pit mining. In situ recovery is better suited for the production of these deeper bitumen deposits. Cyclic steam stimulation (CSS) and steam assisted gravity drainage (SAGD) are the two predominant commercial methods of in situ bitumen production. Of the two methods, SAGD is the one that is most used in the rapidly developing Athabasca oil sands in Alberta.
In the SAGD process, two parallel (top and bottom) horizontal wells (called “well pairs”) are drilled into the bitumen reservoir from well pads at the surface. One well is drilled near the top of the bitumen reservoir and the other is drilled near its bottom. Steam is generated at a field plant and it is injected into the reservoir through the top well (the “injection well”). Over time a steam chamber is formed underground within the bitumen zone and maintained by the addition of further steam. Within that steam chamber the bitumen is heated so that it separates from the surrounding sand and can move. The mobilized bitumen can then flow via gravity toward the bottom of the reservoir where it is captured in the lower well pair (the “producing well”) and pumped to the surface.
Once recovered, bitumen must be upgraded, irrespective of whether it is produced through strip-mining or in-situ methods. Upgrading is the final stage of the process where bitumen is converted into refinery-ready synthetic crude oil and, in some cases, other petroleum products like diesel. Upgrading may be performed on-site, or the bitumen product may be mixed with a diluent (such as gas condensate, NGLs or light crude) and shipped by pipeline to an upgrading facility. Key components of upgrading are:
- removal of water, sand, physical waste, and lighter products;
- catalytic purification by hydrodemetallisation (HDM), hydrodesulfurization (HDS) and hydrodenitrogenation (HDN); and
- hydrogenation through carbon rejection or catalytic hydrocracking (HCR).
As carbon rejection is typically inefficient and wasteful, catalytic hydrocracking is preferred in most cases. All these processes take large amounts of energy and water, while emitting more carbon dioxide than conventional oil production processes.
Extra-heavy oil on the other hand cannot be developed by open pit mines, due to its lower viscosity. As with in-situ methods for producing bitumen from oil sands, extra-heavy oil resources require enhanced recovery techniques either by heating the oil or introducing solvents, further reducing viscosity and enabling recovery through conventional methods.
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Projects and opportunities
Although the energy potential of bitumen has been known for a long time, it is only in recent times that a combination of higher oil prices and technological advances has allowed them to be widely considered part of the world's recoverable oil reserves. Several countries have known oil sands or extra-heavy oil resources. The vast majority is found in Canada and Venezuela. Other countries which might develop an industry include the United States, the Democratic Republic of Congo, Madagascar, and the Russian Federation.
In 1998 Scientific American brought to the world’s attention, for the first time in a prominent way, the promise of Canada’s oil sands situated in the province of Alberta. The magazine announced to the world what Canadian oil & gas companies had known for decades: the Alberta oil sands hold a tremendous amount of producible oil. It is estimated that Canada has about 175 billion barrels of oil that can be recovered with today’s technology. That represents the third largest oil reserves in the world after Venezuela and Saudi Arabia (rankings as of January 2011). The volume of recoverable reserves may further increase as advances in technology improve the recovery ratio. This underscores the importance of the oil sands resource in both Canada and in the world.
Over 97 per cent of Canada's reserves are located in the Alberta oil sands, with the majority of the remaining deposits being located in Saskatchewan. The Alberta oil sands constitute the world’s largest formation of bitumen. With an estimated total potential oil reserve value of 315 billion barrels, there remains a substantial opportunity for development of the three major Alberta oil sands deposits found in the Athabasca, Cold Lake and Peace River regions of Alberta. These resources represent significant long-term oil production within a politically stable country currently linked through existing infrastructure to markets in the United States. The growth of oil sands development has also prompted new proposals to expand the existing TransMountain (TMX) pipeline and to build the proposed Northern Gateway pipeline in order to facilitate the export of oil to Asia from Canada's west coast.
In 2010, Canada was the number one exporter of oil to the U.S. supplying an average 1.9 million barrels a day, compared with 1.2 million from Mexico and 1.1 million from Saudi Arabia. Oil production from the oil sands is expected to more than double in the next 10 years, making Alberta one of the few places in the world where oil production is increasing. Along with this growth opportunity, however, there are also environmental and social challenges that will have to be faced and overcome, as discussed later in this paper.
For further detailed information on the regulatory environment for oil sands projects in Canada, please refer to our separate publication Canada's oil sands: The opportunities and challenges for foreign investors
Canadian and foreign companies are increasingly combining through formal partnerships, strategic alliances and joint ventures to contribute the technology, expertise and capital necessary to execute a successful oil sands project. In its recent publication The rise of Asian investment in Western Canada, Ernst & Young reviewed the level of foreign investment in unconventional oil and gas assets in Canada, including oil sands, and concluded that during 2010 “… the number of inbound oil sands-focused transactions from Asia tripled, as countries like China, Japan, Thailand and South Korea actively sought to secure natural resources around the world and completed several major deals in Western Canada.” In total, Asian investment accounted for US$9.2 billion during 2010 (compared to US$5.9 billion in 2009 and almost nothing in 2008).
This increasing investment from Asia comes on the heels of significant and continuing investment from the United States by companies such as Exxon Mobil, ConocoPhillips, Chevron and Devon as well as investment from European-based companies such as Total and Statoil.
Continuing oil sand investment is evident from the number of significant oil sands and associated investments made in 2010 and 2011. These include the following:
- The acquisition by Sinopec International Petroleum Exploration and Production Company of ConocoPhillips’ 9.03 percent interest in Syncrude Canada Ltd.’s oil sands operation for US$4.65 billion, and subsequent acquisition of Daylight Energy for C$2.2 billion.
- The C$2.1 billion acquisition by China National Offshore Oil Corporation Ltd (CNOOC) of OPTI Canada Inc., a company holding a 35 percent working interest in the Long Lake oil sands project.
- The purchase by Thailand’s PTT Exploration and Production Company of 40 percent of the Kai Kos Dehseh oil sands project from Statoil ASA for US$2.28 billion.
- The investment by the China Investment Corporation, a Chinese sovereign wealth fund, of C$1.25 billion into the Penn West Trust to develop Penn West’s Peace River oil sands assets.
- A new joint venture between Suncor Energy Inc. and Total S.A., which included a C$1.75 billion payment by Total to Suncor as a result of the balancing of portfolio interests, and reportedly will result in Total spending $20 billion on Canadian oil sands projects by 2020.
China in particular appears to be investing significantly in oil sands. In addition to the transactions undertaken in 2010 and 2011 outlined above, PetroChina invested $1.9 billion in 2009 in oil sands developer Athabasca Oil Sands Corporation, Sinopec owns a 50 percent interest in the Northern Lights oil sands project in conjunction with Total and CNOOC originally purchased a 16.7 percent interest in MEG Energy, a small but growing oil sands developer that plans to eventually produce up to 500,000 barrels per day.
Venezuela follows Canada as the second largest commercial oil sands developer in the world. Its reserves can be principally found in the east of the country, north of the Orinoco River, in the Orinoco oil belt. They are not technically bitumen reserves, but rather extra-heavy oil deposits, still with a very low API gravity but which have not been subject to the same degree of degradation as oil sands. The Venezuelan deposits are at a much higher temperature than those in Canada (upwards of 40 to 50 degrees Celsius versus freezing for northern Canada), which improves their viscosity and means they are easier to extract using modern horizontal drilling techniques.
Although the deposits are easier to produce, they are still too heavy to transport by pipeline or to process in standard refineries. In the early 1980s, Venezuela’s state oil company, PDVSA, developed a method to enable the resources to flow in pipelines by emulsifying 70 per cent extra-heavy oil with water. This process produces Orimulsion, which can be burned in boilers as a replacement for coal and heavy fuel oil with only minor modifications. However, the Venezuelan government made a decision not to market Orimulsion any further since it considered that the prices obtained for such boiler fuel were to low when compared to market prices for syncrude.
The Orinoco oil sands belt in Venezuela is now thought to contain 513 billion barrels of ‘technically recoverable’ oil; this is more than double what was previously estimated (235 billion barrels). Although this represents almost double the 264 billion Saudi Arabian recoverable barrels, the heavy Orinoco oil requires a huge amount of refining to turn it into useful fuel, in comparison to Saudi light oil which is very easily refined.
Venezuela, unlike Canada, has not had the resources to harvest its supplies. It has not been able to optimise the design and construction of upgraders and heavy oil refineries due to a lack of capital and technological skill. The Venezuelan government has attempted to attract foreign investment to the industry. This met with initial success and leading international oil companies such as Phillips, Texaco, Conoco, TotalFinaElf (as they were all then known), ExxonMobil and Statoil, partnered with the state-owned PDVSA for four major heavy oil projects in the Orinoco belt. However, progress was partially suspended, due largely to the re-nationalization of the oil industry in 2007. Two leading companies involved in the extra heavy oil projects, ExxonMobil and ConocoPhillips, were expropriated after failing to agree terms for a new joint venture under the nationalization laws which gave PDVSA a minimum 60 percent stake. Chevron, Total and Statoil agreed to the new nationalization terms, and have continued to develop their projects with PDVSA.
The government’s policy to invite further foreign participation and the discovery of new resources, have resulted in increased interest in the area. In 2010, the China Development Bank agreed a US$20 billion facility with Venezuela's state oil company PDVSA to finance infrastructure projects: representing the largest ever financing in the area. Investments in the four key areas in the Orinoco belt – the Carabobo, Junin, Ayacucho and Boyaca areas – have continued since 2007. Numerous MOUs, study agreements and general agreements have been struck, but activity peaked in early 2010 when companies including Chevron, CNPC, Eni, Gazprom, Inpex, Lukoil, Mitsubishi, OIL, ONGC, Petronas, Repsol and Rosneft obtained contracts to develop large blocks and associated upgraders. Two of those new projects were awarded in a bid process and the rest were directly awarded, mainly based on State-to-State accords entered into by Venezuela over the past decade.
With dwindling resources in North America, and rising oil prices, it looks likely that the Venezuelan oil sands industry could follow that of Canada, provided the political environment facilitates the necessary investment. One of the biggest challenges as well is the fact that PDVSA is mandated to take at least 60 per cent in each project and therefore the need for their share of the capital increases exponentially.
Bitumen from oil sands is currently not produced on a significant commercial level in the United States. Oil sand resources are primarily found in the Uinta Basin in Eastern Utah, mostly on public lands. Resources in the area are estimated to be at between 12 and 19 billion barrels, representing about 90 per cent of all US resources, although not all of that would be accessible. Several projects were attempted in the 1980s, but they have all since been abandoned, due largely to stagnating oil prices at the time.
However, in September 2009, the Division of Oil, Gas and Mining of the Utah Department of Natural Resources gave its conditional approval to a notice of intention to commence large mining operations by Earth Energy Resources. The company, which was acquired by International LMM Ventures Corp in April 2011 and renamed US Oil Sands Inc (USO), has obtained a permit to construct a bitumen mining project at PR Spring in Utah, targeting first production in 2013. It also has bitumen leases covering over 32,000 acres of Utah state land for exploration, and has estimated that its current holdings have around 177.8 million barrels of discovered bitumen initially in place.
In the period since November 2009, the granting of permits to USO was appealed several times by two environmental groups in an attempt to prevent the USO project proceeding and setting a precedent for the industry. USO, meanwhile, maintains that its citrus-based solvent is capable of removing over 96 percent of hydrocarbons from oil sands while leaving no toxins or tailings ponds. The appeal process is ongoing with the Division of Oil, Gas and Mining and the Division of Water Resources.
Currently the USA imports around 20 per cent of its oil and refined products from Canada, and over 50 per cent of Canadian oil production is from oil sands. With oil prices rising, there are significant economic reasons for the United States to look to develop its own bitumen resources. However any proposed development of oil sands projects in the United States is likely to attract acute opposition from environmental groups, judging by the active resistance to the development of new pipelines to import Canadian oil sands crude, such as the Keystone XL pipeline. The outcome of the challenge to USO’s permits will have a significant impact on whether, and when, these resources are able to be developed.
Republic of Congo
In 2008, Eni discovered a large oil sands deposit in the Republic of Congo (Congo-Brazzaville) that was estimated to hold several billion barrels of recoverable oil. While the reserves may not be as large as the oil sands discovered in other countries, they are nonetheless substantial. Eni was granted an exclusive license to explore and develop two oil sands fields, Tchikatanga and Tchikatanga-Makola, covering around 1,800 square kilometres in Kouilou department, near the coast.
The resource discovered in Eni’s permits are reportedly deep, and less viscous than the average oil sands in Canada, which suggests that production is likely to be via in situ means rather than strip mining with subsequent water treatment. According to statements released by Eni, the company plans to use the Eni Slurry Technology (EST), a hydroconversion process employing a slurry nano catalyst and a particular process scheme to convert the bitumen into low environmental impact distillates without producing by-products. The EST plant will also utilise feedgas from the nearby Eni-operated M'Boundi gas field.
It is estimated that oil sands and extra-heavy oil lie beneath a substantial portion of Madagascar’s surface. The two most explored fields are Bemolanga (oil sands) and Tsimiroro (heavy oil).
The Tsimiroro field is wholly owned and operated by private company Madagascar Oil. It is located in the onshore Morondava basin, and as of September 2011 is estimated to hold between 1.1 billion barrels to 2.5 billion barrels. The field has been tested and will be produced using "in-situ" steam-flood methods, which the company expects to have a 70 per cent recovery factor. According to releases by Madagascar Oil, the steam flood pilot is expected to reach first production in the second half of 2012, and the national authorities estimate commercial production to commence in 2015.
The Bemolanga field is 60 per cent owned and operated by Total SA, with the balance owned by Madagascar Oil. Exploration activities commenced in 2009, and in mid-July the companies received a one year extension to the licence. However, the companies have deferred the bitumen mining project and the new work programme will focus on deeper conventional hydrocarbons. Accordingly, no production of bitumen is expected in the near term.
There are many wide and diverse ranges of estimates for oil sands in Russia, including up to as much as 250 billion barrels of bitumen resources. As there has been little exploration activity, and there is no real transparency on reserves reporting, it is difficult to estimate the resources with any degree of confidence. Recoverability is another factor to consider. While the Tunguska basin is expected to hold extensive resources, its location in the Krasnoyarsk Krai and Sakha Republic in Eastern Siberia means those resources are unlikely to be economically recoverable in the near future. Estimates of technically recoverable reserves are therefore more modest, including an estimate by the U.S. Geological Survey (USGS) of 33.7 billion technically recoverable barrels of bitumen, primarily in the Melekess oil sands in the Volga-Ural Basin in the Republic of Tatarstan.
There has been little in the way of oil sands development in Russia to date. Since 2006, OAO Tatneft has been operating a pilot project at the Ashalchinskoye field in the Volga-Ural basin to test a modified heat stimulation technology through dual wellhead horizontal wells. OAO Tatneft, whose largest shareholder is the Republic of Tatarstan, essentially has control over the oil sands in the Republic. The Volga-Ural area has also attracted international interest, and in September 2007, Royal Dutch Shell signed an agreement with OAO Tatneft to explore the heavy bituminous fields in Tatarstan.
As production of conventional oil resources declines in the traditional ‘workhorses’ of the Volga-Ural and Western Siberia basins, and the pilot SAGD project for recovering Melekess bitumen advances, there may be an increased push to develop bitumen in Tatarstan and across wider parts of Russia.
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What are the issues?
The differences in the resource characteristics and production methods for developing extra-heavy oil and oil sands generate a new set of risks for project sponsors, offtakers and lenders compared to conventional oil projects. A brief summary of some of these are set out below – the following discussion is not comprehensive and must not be relied upon as legal advice We would be happy to have a more detailed discussion on these and other issues affecting extra-heavy oil and oil sands projects.
Both extra-heavy oil and bitumen from oil sands require substantial upgrading and refining before they become consumer-ready petroleum products. In general, additional processing or upgrading is required prior to the transportation of bitumen because of its lower hydrogen to carbon ratio, higher molecular weight and the increased concentrations of impurities such as sulphur, nitrogen and heavy metals (including lead, nickel, mercury, and arsenic) that are associated with the production.
The increased concentrations of impurities and molecular weight of bitumen necessitate that production undergo catalytic purification and hydrocracking, which together are known as hydroprocessing. Hydroprocessing removes or reduces impurity concentrations and adds hydrogen to the bitumen molecules.
One of the primary challenges with hydroprocessing is the degradation or poisoning of catalysts over time, as a result of the impurities. Many efforts have been made to deal with this to ensure high activity and long life of a catalyst. Catalyst materials and pore size distributions are key parameters that need to be optimized to deal with these challenges and this varies from place to place, depending on the kind of feedstock present.
Hydroprocessing increases the value of the bitumen and prevents the degradation of pipelines, decreases the viscosity of the bitumen allowing it to be transported and allows downstream refineries, which are designed for conventional crudes, to accept the upgraded bitumen. However, this increases the capital intensity of oil sands projects which require significant upfront capital investment and increased operating expenditures throughout the life cycle of the project.
Whether investing in new or existing areas, oil sands projects present investors with some unique infrastructure challenges. In general, these projects require access to:
- gas feeds (or alternate energy sources if gas is not in sufficient supply) for the production steam and hydrogen, used to assisted production and upgrading;
- water, where it is not an abundant supply or if access is restricted;
- diluents or solvents to aid in the recovery of bitumen and enable piping;
- piping or transportation systems; and
- large trucking, where mining bitumen.
Alberta has specific infrastructure challenges because its oil sands industry has been developing since the 1950s. As oil sands production increases, demand for transportation of the crude oil to key markets must also be considered. Oil pipeline capacity out of Western Canada is currently close to full utilization. Additional pipeline capacity will be required and, in response, plans are being presented to expand existing capacity and to create new pipelines. These proposals all face routing, environmental impact and other challenges. This likely means that, in many cases, the regulatory review process will be extensive and lengthy. Knowing the methods and availability of transportation is an important aspect of an oil sands project.
Natural gas requirements for Alberta oil sands operations are projected to increase substantially from 0.7 billion cubic feet per day in 2005 to 2.1 billion cubic feet per day in 2015. Lower natural gas prices are currently spurring the oil sands industry to progress with current plans while investigating more efficient and less carbon intensive measures such as vapour extraction.
The development of oil sands resources is best fostered by a regime which is designed to be cognisant of the investment environment. These projects often have significantly longer payback periods as a result of large upfront and ongoing capital expenditure, slower production rates and a less attractive product. Differential royalty schemes, which have a lower royalty rate for projects that have not reached payout and a higher royalty for projects that have reached payout, recognize the considerable capital intensity of oil sands projects. They ensure that project proponents are not unreasonably burdened with a high royalty while they are getting started and allows for increased royalty recovery once the initial investment is recovered.
In Alberta for example, the royalty amount is established not only based on the world price of oil but also on the project's status vis-à-vis "payout". The term "payout" refers to the point where the oil sands developer has earned enough revenue to recover all of the allowed costs for the project plus a pre-determined return on investment. The other factor used in calculating the royalty amount is the world oil price as measured by the price of West Texas Intermediate (WTI) oil quoted in U.S. dollars. A sliding royalty amount of 1 per cent to 9 per cent is assessed on gross revenues from oil sands projects that have not yet reached payout, with the base royalty starting at 1 per cent and increasing for every dollar that the world price of oil exceeds $55 per barrel up to a maximum royalty of 9 per cent when oil is priced at $120 or higher. For post-payout projects, the net royalty starts at 25 per cent and increases for every dollar that oil is priced above $55 to a maximum royalty amount of 40 per cent when the world oil price reaches $120 or higher.
Due to the scale and nature of oil sands operations they have the potential to impact the environment to a greater degree, when compared to conventional operations. The associated processes can be more water intensive and require larger amounts of energy than conventional extraction. Although many conventional oil fields also require large amounts of water and energy to achieve good rates of production.
The development of oil sands has not been without controversy. Environmental groups have campaigned against oil sands development on many fronts expressing concerns including:
- the destruction of the boreal forest;
- the generation of greenhouse gases;
- the cost and need to remediate mined areas;
- the reclamation of tailings ponds;
- the industrial use of water; and
- the environmental and health impacts of water and air emissions.
For many years the industry did not respond well to these concerns and failed to act in a cooperative and co-ordinated manner to address them effectively. However, the oil sands industry has, in the past few years, become more responsive to the environmental concerns and has been working co-operatively as well as with government to demonstrate that it is acting to deal responsibly with those concerns.
In 2010 the Royal Society of Canada undertook an independent review of the environmental impacts of the oil sands that cut through much of the rhetoric on both sides of the issue. Through its peer-reviewed study the expert panel concluded that, although much should be done to improve operations at oil sands facilities, development of the oil sands did not deserve the destructive reputation that had been advanced by many environmental groups and criticized them and the media for sensationalizing the extent of industry impacts. Most importantly the study found “no credible evidence” of elevated cancer rates due to oil sands operations.
Although many of the findings were either neutral or positive regarding many important aspects of oil sands development, the report was critical of some issues, including:
- the slow pace of mine reclamation;
- the nature and accuracy of aquatic monitoring in the region;
- the improved but still insufficient progress in tailings management; and
- the difficulty for Canada to meet its international commitments for overall GHG emissions reductions despite progress in reducing GHG emissions because of growing bitumen production.
Nevertheless, with respect to emissions in general, and greenhouse gases in particular, there have been improvements. The oil sands industry has been actively addressing emissions by using improved technology such as low nitrogen oxides burners, sour water treaters and flue gas desulphurization. Overall there have been significant reductions in greenhouse gas emissions even though there has been an increase in production over the last ten years due to investment by oil sands operators in new technologies.
The current environmental emphasis is on building a credible monitoring system for oil sands operations, to ensure that there is accurate data to inform planning decisions. The need to improve monitoring was forcefully argued in the Royal Society report and both the Federal and Provincial governments have taken steps to improve monitoring and environmental oversight. In March 2010 the Federal Government announced its new monitoring plan for the Athabasca oil sands area which will include more frequent and widespread sampling and will form a part of a broader system that will also monitor air quality and the impact of development on the region's wildlife. The cost of the new program is estimated C$20 million ($20.4 US million) a year and will be paid for by the oil industry.
Some environmental groups that see grave danger in developing the oil sands have popularized the label “dirty oil”. The label comes from the assertion that oil sands production results in substantially more GHG than normal oil operations. A "wells-to-wheels" study of greenhouse gas emissions from fuels made with Alberta oil sands crude, however, shows that they are not as "dirty" as this label might suggest.
IHS Cambridge Energy Research Associates (CERA) released a report entitled "Oil Sands, Greenhouse Gases, and the U.S. Oil Supply" that reviewed thirteen primary studies and estimates of GHG emissions from fuels produced from the oil sands on a lifecycle basis. The CERA report provides a range of 5 per cent to 15 per cent in increased emissions for oil sands versus the U.S. average crude oil baseline on a lifecycle (or well-to-wheels) basis.
CERA states furthermore that oil sands products imported to the United States result in GHG emissions that are, on average, only 6 percent higher than the average crude consumed in the country. Their analysis was drawn from the results of 13 publicly available studies from government, academic, and industry sources.
Until renewable or "green energy" technology reaches the stage where it can substitute oil on a large-scale and economic basis, oil sands will continue to represent a secure source of oil, developed within a strong and transparent regulated framework that can serve as a bridge to the future use of renewable energy resources.
Indigenous rights and empowerment
Aboriginal peoples in Canada comprise the First Nations, Inuit and Métis. Many of the oil sands reserves exist on or near lands which have been traditionally used by First Nations. The Canadian government currently does not have an express regulatory process specifically designed to address oil sands mining, activities that have an impact on lands traditionally used by First Nations. While the Province of Alberta has a comprehensive regulatory structure to address oil sands mining the regime does not expressly apply to the use of traditional lands for oil sands activities. As a result, the issue of First Nation rights has been resolved through negotiated agreements with the First Nations. These agreements are often complex, covering issues such as local benefits, compensation for land use, development of local skills and capacity, sharing business opportunities, and the mitigation of social impacts associated with a project. Companies developing and investing in oil sands projects should be aware that negotiations with First Nations entities will be an issue in developing the project.
The considerations detailed above primarily relate to Canada and are of less significance for countries where extra-heavy oil and oil sands have not yet been commercially developed. However, as other countries with these resources begin to develop their reserves indigenous rights and empowerment concerns may well arise.
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The production of extra-heavy oil and of bitumen through oil sands projects can and will play a critical role in the future global energy supply. Although the increase of renewable energy is important, it is still in its early stages of development and, in the short and medium term, it is likely to be only a small energy contributor. Liquid fuels made from oil are required for transportation, and so far they have been difficult to replace successfully with commercially viable alternative forms of energy. As a result, extra-heavy oil and oil sands will play an important role in the foreseeable future, even if only to bridge the world from current technology and economy to the future.
The projects are however very capital intensive due to the need for production, upgrading, refining and transportation facilities, and have large operating costs due to the continual need for steam and/or solvents and diluents. Combining the cost profile with a slower rate of production compared to conventional oil projects, projects are typically characterised by long payback periods, and so require a stable facilitating regulatory regime and confidence on oil prices in order to attract the necessary long-term investment.
The responsible production of extra-heavy oils and bitumen will go a substantial way to meeting the need for safe and responsibly developed oil. That responsibility should be shared by all stakeholders.
Governments need to be, and be seen to be, developing, implementing and enforcing a framework of laws, regulations and policies that will maintain energy and economic security in a manner that ensures the environment is properly protected and the public interest is best served. Industry proponents should also respond by implementing environmental best practices, adopting a cooperative approach to development and continuing to advance technologies to reduce potential impacts on the environment and nearby populations. Finally, interested members of society can continue to monitor developments and impacts, and contribute to the educated debate on the merits of development plans and processes, as this role of ‘safe-keeper’ of the social and cultural values of the local community and the environment will help ensure the safe and reliable development of energy resources and reduce the risk of harmful incidents.
If investors and all stakeholders are properly aware of, and well-advised on, the various commercial, environmental and regulatory issues involved, investments in extra-heavy oil and oil sands could significantly contribute towards meeting the world’s ever-increasing demand for energy while providing an attractive investment.
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