The focus of the NRTEE?s review of water use by the oil and gas sector is on the upstream industryj with particular attention given to the unconventional development and operations. The main oil and gas activities considered here include oil development using water for enhanced oil recovery (EOR); oil sands development including both mining and in situ methods; and natural gas, focused on the shale gas development.
Water is an essential component of the sector. For example, in 2007, three-quarters of all Alberta?s oil production was water-assisted. All types of oil and gas developments use water but vary considerably in the sources, volumes, production uses, recycling and reuse, and treatment. The oil and gas sector uses small volumes of water in comparison to the other natural resource sectors.k In 2005, in Alberta, the oil and gas sector accounted for approximately seven per cent of the province?s total allocations, and in many cases companies reportedly used much less than the amount they were allocated.46 The key difference with the other energy sectors is that much of the water use for oil and gas production could be considered to be consumptive as it is either injected into oil reserves or stored in tailings ponds, and is not returned to the environment.
Even though the oil and gas sector uses relatively small volumes of water on a national scale, the anticipated strong growth for the sector will have important consequences for regional water resources.
The sector?s impacts on water quality and ecosystems will continue to be a challenge for the sector to manage.
Key issues facing the oil and gas sector include:
- Water quality with respect to both oil sands and future shale gas developments
- Water availability
- Unknown impacts on groundwater sources
Economic Importance of the Oil and Gas Sector to Canada In 2008, the oil and gas extraction sector contributed approximately $40 billion to Canada?s GDP. While it is a critical sector for the provinces of British Columbia, Saskatchewan, and Newfoundland and Labrador offshore, Alberta accounts for approximately 75% of the Canadian oil and gas production (Figure 11). Alberta enjoys the second largest oil reserves in the world with its oil sands reserves, containing an estimated 1.7 trillion barrels of (volume-in-place) bitumen of which approximately 11% is recoverable.47 In absolute terms, according to the Canadian Energy Research Institute (CERI), Canada produced 2.7 million barrels per day (Mbd) of oil in 2008. Of that amount, 2.4 Mbd came from Western Canada and of that, 1.2 Mbd from the oil sands. Oil sands production could grow to 1.7 Mbd in 2015 and 4.5 Mbd in 2030. The recent global economic recession resulted in decreased demand for oil, and, on average, current oil prices are lower than in recent years. Furthermore, the economic downturn has hindered the ability of companies to acquire investment capital.48 Closer to home, the recession has slowed the rate of expansion of oil sands with many projects being put on hold. Over the medium term, the oil and gas sector is predicted to see moderate growth, and much larger growth over the longer term. At a provincial level, the growth is concentrated in Alberta, Saskatchewan, and British Columbia. Oil Production Forecasts indicate that Canadian oil production mix will tend increasingly toward nonconventional oil production from the oil sands in the coming years, with conventional oil production expected to decline. Table 4 shows three medium-term oil production forecasts; all forecasts concur that conventional oil production will decrease more than 10% in the next five years and that oil sands will increase by at least 50%. The National Energy Board predicts oil production growth in Canada to be moderate over the medium term for the reference case, with larger increases over the longer term. The low price scenario sees very little growth over both the medium- and longer-term forecasts, whereas the high price scenario sees larger growth over both time horizons.49 A provincial analysis indicates that Alberta represents the main driver in the growth of oil production, with a small contribution coming from the Northwest Territories and Atlantic Canada for the longer-term reference case and high price scenarios. Overall these forecasts align with those of the Canadian Association of Petroleum Producers (CAPP).50
Conventional natural gas currently supplies two-thirds of the Canadian production but this is expected to decline to only one-third by 2020 due to declining reserves. Increasing demand for natural gas, both domestically and internationally, will likely result in future development of unconventional gas production.53 Unconventional gases include coal bed methane (natural gas embedded in coal deposits), tight gas (natural gas within low permeability, usually sandstones), and shale gas (natural gas within relatively low permeable organic shale beds). Estimates suggest that shale and tight gas in Canada and the United States could contribute up to one-third of all North American production by 2020. Estimates of shale gas in western Canada vary significantly from 86 trillion cubic feet (Tcf ) to over 1000 Tcf.54 While there is huge potential in British Columbia and some in a few other regions of Canada (Alberta, Saskatchewan, Qubec) (Figure 11), shale gas production is in very early stages and commercial development is not likely to occur in the short term due to current market prices and technical challenges.55
Water is a component of all oil and gas developments and operations. However the types of water uses, volumes required, and water sources all vary considerably within the sector. The NRTEE research considered the following sub-sectors: oil sands, shale gas, and enhanced oil recovery.
Oil can be extracted from oil sands using two methods: mining and in situ. Mining techniques are used where the oil sands are close to the surface and in situ techniques are used for deeper deposits. Currently 20% of Alberta?s total oil sands recoverable reserves are deemed to be mineable, the remaining 80% must be accessed through in situ techniques. In 2007, Alberta produced approximately 55% of its oil from the mineable oil sands, and 45% from the in situ areas. These proportions are expected to shift as future oil sands production moves to extraction from the deeper deposits using in situ methods.
The water use in an oil sands mine is technically complex. In simple terms, water use in oil sands mining is similar to water use in metal mining and can be divided into three categories: mine water and groundwater inflow, process water (includes recycled and make-up water), and tailings pond water. As in other mining operations, mine water and ground water flowing into the mine pits must be managed so as to ensure it does not contaminate surrounding ecosystems. A key difference with oil sands mines is there is a ?no discharge? policy in place, which doesn?t permit water to be discharged into surface water bodies. Water is either treated and recycled or reused, or it is held in long-term tailings ponds. In some operations, process water is re-injected into deep geological formations as an acceptable means of disposal. The focus of the rest of the discussion is related to the process water and the tailings pond water.
?Process water? is critical to the separation process ? it is essential in order to separate bitumen from the sand. The process water is a combination of make-up water, both from surface water or groundwater sources, and recycled water from the tailings ponds. A common misconception is that the water requirements involve only water from surface or groundwater sources. In fact, a substantial amount of process water is recycled. For example, a mature mine can use about 80% recycled water from its tailings ponds for the process water. Surface-mining oil sands production uses from 2.0 to 4.0 barrels of water (net) per barrel of bitumen produced.
The production of bitumen from mining results in significant volumes of fluid tailings that include sand, fine clays, and residual amounts of bitumen mixed with water. They are held in long-term containment ponds called tailings ponds. While a substantial proportion of water from the tailings ponds can be recycled and used in process water, a significant volume of contaminated water remains in the tailings ponds, possibly indefinitely. Tailings management is a critical component of mining operations and is also one of the greatest concerns of the local community and environmental advocacy groups. As such, significant research and efforts by industry and government bodies has been ongoing since the early days of oil sands development to figure out how best to manage the tailings. Over the years, the industry has invested heavily in new tailings technology. It continues to try to achieve ?dry tailings? technologies where, essentially, the water in the tailings is minimal and the tailings are solid enough to be incorporated into a sustainable reclaimed landscape. The provincial regulators are cognizant of this issue, and recently initiated a more comprehensive regulatory framework for tailings management with the objective of minimizing and eventually eliminating long-term storage of fluid tailings in the reclamation landscape.
Most oil sands deposits will need to be developed by drilling wells (in situ) and injecting steam into the reservoir. The two most common thermal in situ production processes are cyclical steam stimulation and steam-assisted gravity drainage, both of which inject steam into the reservoir to liquefy the oil and separate it from the sand so that it can be pumped to the surface. The steam condenses in the reservoir and is pumped back to the surface with the liquid bitumen. This is called ?produced water? and is often treated and reused. Three types of water can be used in thermal in situ operations: fresh (from either surface or groundwater sources), brackish or saline groundwater, and produced water.
Estimated water use for in situ oil sands production can vary from 0.4 to 5.5 barrels of water per barrel of bitumen.56 The average use is about one barrel of water (net) per barrel of bitumen produced.57 The water use varies between facilities due to technology, use of recycling, and the phase of development. The start up phase of an operation requires more water, however this usually decreases as the project matures. In some in situ operations, saline groundwater replaces some or all of the freshwater requirements for extraction. In the case of those operations located within the Athabasca region, no water is withdrawn from the Athabasca River for in situ production. In situ oil sands projects can recycle more than 90% of water produced. Thus, for freshwater only, the average net value is 0.5 barrels of water per barrel of bitumen produced. All recent in situ projects are required to recycle a minimum of 90% of their produced water.
In Alberta, the Energy Resources Conservation Board (ERCB) and Alberta Environment are taking steps to enhance the conservation and encourage the efficient use of water sources for new in situ schemes.58 ERCB?s new Directive, which builds upon existing water conservation policies in the province,59 will require in situ operations to limit the sector?s use of fresh and brackish water, and maximize the recycling/reuse of produced water. Freshwater use will be limited to a maximum of 10% of total make-up water; brackish groundwater will be no more than 25% of the total make-up water (less if freshwater is used as well). In addition it will also require operators to improve their measurement and reporting of all major water streams at thermal in situ oil sands schemes.
Shale gas merits some attention as a potential unique area of development for the oil and gas sector in Canada, both in terms of potential for expansion and the unique water requirements that are associated with this type of gas production. Shale gas resources in Canada are estimated to be in the order of 1500 Tcf of gas in place, with the most significant known play located in Horn River in Northeastern British Columbia.
Gas from shale requires fracturing of the rock in order to allow the natural gas to flow out ? known as hydraulic fracturing (or ?fracing?) ? which involves the injection of fluids into the gas wells at very high pressure. These pressurized fracing fluids are used to crack open the underground formation to allow oil or gas to flow more freely and increase production. While some of the injected fluids are returned to the surface, some remain underground and may eventually seep into the groundwater aquifers. The fracing fluids often contain many additives such as friction reducers, biocides, surfactants, and scale inhibitors.
Shale gas development requires the drilling of multiple horizontal wells for the purpose of fracturing the shale beds to extract the natural gas. Thousands of wells are required for shale gas production to be commercially viable, and this requires significant volumes of water. Much of the water is not returned to source in the short term and so is considered a consumptive use. As the shale gas developments of Northern British Columbia and Qubec are in their initial development stage, it is hard to predict how much water will be required, how it will be managed, and what effects it may have on the water resources and the surrounding ecosystems.
Enhanced oil recovery is the process of increasing the amount of oil that can be recovered from a reservoir. EOR is used to increase the productivity from conventional oil wells that would otherwise no longer be in production, and it can employ a number of different methods such as water flooding and thermal methods, involving the injection of either water or steam (with solvents) into the reservoir to force the oil out. Water flooding relies on the availability of freshwater, but it can also use saline, recycled, or treated produced water. Steam injected recovery largely uses freshwater or non-saline sources, including recycled water. In comparison with conventional oil recovery, EOR can increase recovery from approximately 15% to 25?30%. Relatively small volumes of water are used for EOR in comparison with other users. Of the total water allocated in Alberta in 2001, the oil and gas sector actually used less than half of one per cent for EOR processes.* The volume of freshwater being diverted for injection has declined significantly over the past 30 years.60
One of the most prevalent water issues facing the oil sands industry is its impact on water quality rather than quantity. Water recycling and reuse is high in this industry, the result of intensive research and development over the years, driven more recently by increasingly stringent policy directives.? However, unanswered questions remain regarding the potential for oil sands mining and in situ production to adversely affect water quality in the region. The complexity of these questions is reflected in the significant effort put forward by the industry and governments to find answers. Since the late 1990s the Athabasca oil sands region has been the focus of substantial monitoring and research, much of it led by the Cumulative Environmental Management Association (CEMA). A number of sub-committees exist in this association, such as the Surface Water and Reclamation Working Groups. In addition to this association, there is the Regional Aquatics Monitoring Program (RAMP), a multi-stakeholder monitoring program that assesses the health of rivers and lakes in the region. To date RAMP has concluded that there has been no significant impact from oil sands development on the Athabasca River;? however, this is contested by many scientists, stakeholders, and environmental groups. Therefore, the potential impacts of oil sands operations on water quality in the Athabasca region continues to be one of the most important issues for the oil sands industry.
Related to the water quality effects is the issue of tailings management. The production of oil sands mining results in significant volumes of tailings. While up to 80% of the water from tailings ponds can be recycled and reused in the processing, a substantial volume of contaminated water remains in the tailings ponds. The lifespan and long-term implications of the tailings facilities is the subject of significant research by the industry and governments, and continues to be a focal point of their efforts. A key concern of tailings ponds is related to the risks of contaminated water seeping into the aquatic ecosystems (surface and groundwater), particularly the Athabasca River. The main toxics found in the tailings include naphthenic acids and polycyclic aromatic hydrocarbons (PAHs) and are of high concern for the communities in the region, particularly those downstream of the oil sands operations. Stakeholders continue to engage in an intensive debate regarding the potential effects of the tailings ponds on the ecosystems within the vicinity of the Athabasca oil sands. In July, 2009, Environment Canada indicated it would conduct an independent study of leakage from the tailings ponds.61
As shale gas developments in Canada are in their infancy, it is difficult to say exactly what water quality issues the industry will face. However there may be some merit in looking south to the United States where shale gas operations are well developed. Their main operational issue is potential groundwater contamination due to fracing fluids and their possible impact on drinking water supplies. This has been of particular concern where fracturing operations have contaminated groundwater due to seepage of the fracing fluids or migration of natural gas into drinking water aquifers. This is not to say the same will happen in Canada, but a cautionary approach to regulating this new industry should include protective measures to address such possibilities. Industry and government should pay special attention to investigating and understanding the potential impacts to groundwater as the industry develops further in our country.
There is a perception that the water use from oil sands activities is high and unsustainable and many call into question the volumes of water that are allowed to be withdrawn under existing licences. While gross volumes taken from the river are substantial, the levels should be viewed with some perspective relative to other river systems in the province. The Athabasca River has one of the smallest water allocations of any river in Alberta and yet one of the largest flows. The total annual allocation of water from the Athabasca River for all uses (municipal, industrial, and oil sands) is less than 3.2% of flow. This is low in comparison with allocations in other rivers in Alberta: 37% for the North Saskatchewan River, 60% for the Oldman River and 65% for the Bow River.62 All existing and approved oil sands projects will withdraw less than three per cent of the average annual flow of the Athabasca River. During periods of low river flow, water consumption is limited to the equivalent of 1.3% of annual flow.63 Therefore it does not readily appear that water availability is currently an issue in the northern region of Alberta and particularly for this sector. That said, stakeholders involved in the oil sands region, who have been working together for a number of years under CEMA, have substantial concerns about future water withdrawals and uses. Most recently CEMA undertook a three-year study that resulted in a comprehensive report that addresses many issues associated with oil sands developments including water withdrawals from the Athabasca River. As a result of this study, CEMA?s Phase II Water Management Framework recommended to the Alberta government that oil sands operators be allowed to withdraw only 4.4 cubic metres per second during low flow conditions of the river ? almost half the current allowable rate of 8 cubic metres per second.64 Clearly, this recommendation strongly suggests serious concerns with current water allocation in the Athabasca River. The Alberta government is currently reviewing the report and taking its recommendation into consideration. Given the potential substantial growth of the oil sands, future water requirements will need to be considered carefully, and not just project by project, but from a cumulative, watershed basis.
The question of future water use and availability for shale gas developments remains unanswered. The natural gas resource is significant, and under the right economic circumstances (i.e., higher gas prices) supported by further innovation and technology in fracturing, the potential for this resource development seems very plausible. This current situation presents an opportunity for regulators and decision makers to put in place a framework under which the resources can be sustainably developed.
A very important unknown cumulative effect of oil sands operations may be that of the impact to groundwater aquifers. The significant groundwater use by in situ operations could potentially affect drawdown of fresh or shallow saline aquifers, change groundwater levels, and allow freshwater to infiltrate voids created by bitumen removal.65 The aquifers in the regions are currently not accurately mapped and so the potential impact is very uncertain. The provincial and federal governments recognize this information gap and are now mapping some of the most significant aquifers in the region.
The relatively abundant supply and low cost of water have traditionally supported the development of water-intensive technologies for the oil and gas sector. This is now changing as public pressure and government policies require industry to improve its water efficiency. The most obvious example of this is the Alberta Government?s Water for Life Strategy, which sets a target of 30% for improving water efficiency for all industrial activities in the province by 2015.
There are many technologies that exist, and many more that could be further developed that would improve the sector?s water use. The challenge is that there is no one-size-fits-all solution, and so many solutions need to be pursued. Not unlike other natural resource sectors, the capital costs and risks associated with moving from bench-scale technology to pilot-scale ? let alone full-scale implementation ? present a barrier to full technology deployment. A second challenge is that of competitiveness: a competitive edge that reduces costs is not something that companies necessarily will share openly.
Several technologies exist to reduce water use for in situ recovery. Some technologies involve the use of solvents that are vaporized and injected into the bitumen to liquefy the oil. Other technologies being developed replace traditional steam injection with combustion or gasification, thus reducing water requirements. Further, methods are being pursued that use more recycling of produced water in the recovery process.
EOR is moving toward the use of carbon dioxide instead of water. Notable examples can be found in Weyburn, Saskatchewan, and Joffre, Alberta, where CO2 is injected into depleting oil formations to increase production and lengthen the life of the fields.
On the tailings management side, current efforts are underway in Alberta to develop dry tailings technologies that use little or no water for extraction. As an example, Natural Resources Canada (CanmetENERGY) is working with oil sands mining companies to develop technology that may reduce the water in tailings ponds, possibly resulting in dry tailings. Research such as this ? in combination with other advancements on reclamation approaches for tailings ? holds promise for addressing one of the most significant problems facing the oil sands industry.
Private-Public Approach to Water Innovation
The Alberta Water Research Institute and General Electric (GE) Water & Process Technologies have combined forces in a multi-million dollar research agreement focusing on technology to improve the treatment and re-use of water in some oil sands operations. The initial investment is cost-shared by GE, The Water Institute, and its research funding partners. Any solutions and learnings from the project will be publicly available. These innovative partnerships are good examples of how public agencies and industry can work together to develop programs that benefit the environment and the economy.
Overall, the oil and gas sector has made significant improvements in water use, particularly over the last 20 years within the oil sands industry, with improved recycling rates and reduced water intensity (consumption per barrel of bitumen). However, the oil sands is one of the world?s most important oil resources and therefore the pressure on the use of water will continue to grow. The potential for substantial oil sands and shale gas developments may mean significant water requirement within the provinces of Alberta and British Columbia, and so this potential expansion needs to be taken into account. Governments and industry both have important roles to determine the potential impacts of the withdrawals on the aquifers and surrounding areas, and to establish measures that ensure the effects are not long term or irreversible. Further research is necessary to ensure that not only is the water use sustainable, but that the surrounding ecosystems are not irreparably damaged.
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(j) The downstream production of the oil and gas sector is an important component of the Canadian economy; however, it was not considered within the scope of this research. ? Oil and gas water use is unknown on a national level as it has not historically been part of Statistics Canada?s Industrial Water Survey.
(k) For detailed description of water use in enhance oil recovery see Water Use for Injection Purposes in Alberta. Geowa Information Technologies Ltd. March, 2003. ? The oil sands regulator, the Alberta Energy Resources Conservation Board (ERCB), must be satisfied with operator?s plans for water use and disposal. Provincial regulations require operators to minimize the use of fresh make-up water and the disposal of waste water, as well as to maximize the recycling of produced water. ? RAMP?s information and technical reports may be reviewed on its website www.ramp-alberta.org/RAMP.aspx.