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Academic year 2015/2016
THE WATER-ENERGY-FOOD NEXUS OF PRODUCTION
FROM SHALE OIL, SHALE GAS AND OIL SANDS
By
Lorenzo Rosa
Supervisor: Maria Cristina Rulli
Co-supervisor: Paolo D’Odorico
Co-supervisor: Kyle Frankel Davis
September 2016
Abstract Unconventional fossil fuel resources have recently emerged as new important energy sources and they
are expected to play a fundamental role in meeting energy demand in the near future. We consider global
shale oil, shale gas and oil sands assessing consequences on the Water-Energy-Food security Nexus.
Shale resources are globally abundant and widespread. Extraction of shale oil and natural gas is
performed through hydraulic fracturing, a water intensive process that is not free from environmental
and social impacts. It is unclear to what extent and where the development of shale resources could
compete with water and food security. Here we consider the global distribution of known shale deposits
suitable for oil and gas production and evaluate the impacts on water resources for food production and
other human and environmental uses in the same region. We find that 39% of world’s high quality shale
deposits is located in areas affected by water stress and 7% is situated in regions where irrigation is
expected to meet the growing food demand. In these regions shale oil and gas production would likely
threaten water and food security. These results highlight the need for adequate policies to avert social,
economic, and ecological consequences of shale resource extraction.
Oil sands deposits account for a third of globally proven oil reserves, extend over large natural areas, and
have extraction methods requiring large volumes of freshwater. Little work has been done to quantify
some of the environmental impacts of oil sands operations. Here we examine forest loss and water use
for the world’s major oil sands deposits. We calculate rates of water use and forest loss both in Canadian
deposits where oil sand extraction is already taking place and in other major deposits worldwide
accounting for ≈93% of global oil sand reserves. We estimated that their full exploitation could result in
1.31 km3 yr-1 of freshwater, 8700 km2 of forest loss, and 383 Mtonne CO2eq yr-1 in greenhouse emissions.
The expected escalation in oil sands extraction thus portends extensive environmental impacts.
While unconventional fossil fuels extraction have multiple environmental impacts, there have however
been substantial economic benefits that bring to an ever-evolving technological innovation, which is
lowering environmental impacts. Furthermore, energy security of some countries has been strengthen.
Thus there are clear and ongoing tradeoffs between economic development, energy, and the environment.
Lorenzo Rosa
Department of Civil and Environmental Engineering, Politecnico di Milano, Milan I-20133 Italy
Prof. Maria Cristina Rulli, Thesis Supervisor
Department of Civil and Environmental Engineering, Politecnico di Milano, Milan I-20133 Italy
Prof. Paolo D’Odorico, Thesis Co-Supervisor
Department of Environmental Sciences, University of Virginia, Charlottesville, VA 22904
Dr. Kyle Frankel Davis, Thesis Co-Supervisor
Department of Environmental Sciences, University of Virginia, Charlottesville, VA 22904
Acknowledgements
First of all, I would like to thank my thesis committee, Prof. Maria Cristina Rulli (chair), Prof. Paolo
D’Odorico, Dr. Kyle Frankel Davis. They have provided me a tremendous challenge and support, and
each has been an outstanding mentor.
I would like to thank my parents, Manuela and Marco, for all the support and for all the opportunities
that have given during these years of study. I would like to thanks my brother, Andrea, for being a great
mate in all these years.
I would like to thank all my Italian friends and all the amazing people that I met in the past few years in
Stockholm and Charlottesville. A great thanks to Matteo and Marco.
I would like to thank Madagascar Oil for providing information about Madagascar oil sand concession
areas and Chris W. Baynard (Baynard Geospatial Consulting: http://www.baynard-geospatial.com) for
sharing the shapefile of Orinoco Heavy Oil Belt in Venezuela.
CONTENTS INTRODUCTION ......................................................................................................................................... 5
WATER-ENERGY-FOOD NEXUS .................................................................................................................. 9
DEFINITIONS ........................................................................................................................................ 11
PART 1: SHALE GAS AND SHALE OIL ........................................................................................................ 13
HISTORY ............................................................................................................................................... 17
EXTRACTION ............................................................................................................................................ 17
EXPLORATION/PLANNING ................................................................................................................... 18
DIRECTIONAL DRILLING ....................................................................................................................... 18
HYDRAULIC FRACTURING .................................................................................................................... 20
PRODUCTION ...................................................................................................................................... 21
METHODS ................................................................................................................................................ 24
SHALE DEPOSITS IN WATER STRESSED REGIONS .................................................................................... 28
SHALE DEPOSITS OVER IRRIGATED AREAS .............................................................................................. 31
WATER FOR FRACKING OR WATER FOR IRRIGATION? ........................................................................... 40
BALANCING ENERGY AND FOOD SECURITY ............................................................................................ 41
REFERENCES ............................................................................................................................................ 43
PART 2: OIL SANDS .................................................................................................................................. 52
CANADA................................................................................................................................................... 55
RECOVERING THE OIL .......................................................................................................................... 57
UPGRADING ........................................................................................................................................ 69
OIL SANDS IN THE WORLD .................................................................................................................. 71
METHODS ................................................................................................................................................ 77
ENVIRONMENTAL IMPACTS OF OIL SANDS PRODUCTION ..................................................................... 84
TRADEOFFS BETWEEN ECONOMY, ENERGY, AND THE ENVIRONMENT ................................................. 95
REFERENCES ............................................................................................................................................ 99
CONCLUSIONS ....................................................................................................................................... 105
DISCUSSION ........................................................................................................................................... 109
INTRODUCTION
In recent years oil and gas corporations have shown a rising interest in unconventional fossil fuels,
likely in response to the increasing global energy demand (U.S. EIA, 2013; Exxon Mobil, 2016), its
predominant reliance of fossil fuels (U.S. EIA, 2013; Exxon Mobil, 2016; British Petroleum, 2016),
scarcity of conventional fossil fuel resources (Gordon, 2012), and technological innovations that have
substantially reduced extraction and processing costs (Speight, 2013). Unconventional fossil fuels are
hydrocarbons found in deposits that cannot be tapped with standard production methods (i.e., based the
extraction of hydrocarbons that naturally flow into production wells) (Rogner, 2007) but require more
complex and advanced technology (Chew, 2014). These fossil fuels exist both as oil (oil sands, tight/shale
oil, deep-sea oil, heavy and extra-heavy crude oil) and natural gas (tight/shale gas, coal bed gas and gas
hydrates) (Rogner, 2007). Reliance on unconventional fossil fuels is dramatically transforming the
exploration and production industries (Gordon, 2012). While the global oil demand is projected to rise
by about 20% from 2014 to 2040 (Exxon Mobil, 2016), it is expected that within the same time period
the contribution of unconventional oil will increase from 25% to about 40% (Exxon Mobil, 2016). By
2040, 10% of world oil production will come from oil sand deposits (U.S. EIA, 2013; Exxon Mobil,
2016), which are bigger by an order of magnitude than conventional crude oil deposits (Mossop, 1980).
Moreover, shale oil production (also known as tight oil) is expected to more than double contributing
from 4% in 2015 to 10% in 2040 of world oil demand (U.S. EIA, 2016 a-b; British Petroleum, 2016;
Exxon Mobil, 2016). Natural gas consumption is expected to rise of 40% from 2014 to 2040 (British
Petroleum, 2016; Exxon Mobil, 2016). Unconventional gas will cover a big share of this increase, shale
gas production will surge from 10% in 2014 to 30% in 2040 of world natural gas supply (U.S. EIA, 2016
a-b; British Petroleum, 2016; Exxon Mobil, 2016).
Figure 1. Hydrocarbon resources pyramid.
This work is separated in two different parts. Part 1 focuses on world shale resources and their
consequences on the water-energy-food nexus. Part 2 mainly focuses on world oil sands deposits and
their environmental implications on water use and forest loss related to oil sands extraction and
processing, with a little focus on the water-energy-food nexus.
Shale are low permeability sedimentary rocks containing high quantities of hydrocarbons
(Holditch, 2007). The oil and natural gas contained in these shale deposits can then be tapped using a
water-intensive process known as hydraulic fracturing (Jiang, 2013; U.S. DOE, 2013; Vidic, 2013), a
method not free from environmental and social impacts (Vidic, 2013). Indeed, various studies have
shown how hydraulic fracturing is associated with the use of substantial amounts of water (Nicot, 2012;
Clark, 2013; Godwin, 2014; Scanlon, 2014; Gallegos, 2015; Chen, 2016) as well as declines in regional
water quality (Osborn, 2011; Warner, 2012; Vidic, 2013; Stokstad, 2014). Other related consequences
are methane migration from faulty seals around well casings (Jiang, 2011; Howarth, 2011; Vidic, 2013;
Brandt, 2014), health hazards (i.e., groundwater contamination), impacts on regional air quality (Kargbo,
2010; McKenzie, 2012; Bunch, 2014), seismic triggering (Rutqvist, 2013), forest cover loss, habitat
fragmentation (Droham, 2012; Kiviat, 2013; Brittingham, 2014), and biodiversity loss (Kiviat, 2013;
Souther, 2014; Brittingham, 2014).
Of the various socio-environmental consequences of shale deposit development, its impacts on
water availability or accessibility are arguably the most profound yet poorly understood (Kargbo, 2010;
Moniz, 2011; Nicot, 2012; Reig, 2014; Mauter, 2014). In some regions, the relatively high rates of water
use for horizontal drilling and hydraulic fracturing could lead to a competition between water
appropriation for shale rock stimulation and other human and environmental needs (e.g., food production,
environmental flows) (Nicot, 2012; Mauter, 2014; Freyman, 2014). Therefore the withdrawal and
depletion of water resources for shale deposit development is a significant challenge situated at the water-
energy-food nexus (Howells, 2013; Rulli, 2016).
Meeting humanity’s increasing water demand for food and energy production, while protecting
ecosystem needs (Hoekstra, 2014) is expected to be a major task of this century. Despite growing interest
in shale resources, there is only a limited understanding of the pressure that their extraction could place
on local water resources. It remains unclear to what extent the water requirements of shale gas and shale
oil production would compete with other uses by ecosystems and society and contribute to unsustainable
water use (World Economic Forum, 2015). Such a trade-off is especially worrisome for regions prone
to water stress, where additional water will already be needed to enhance food production and prevent
crop water stress induced by climate change (Hoekstra, 2014; Haddeland, 2014). Further, in areas with
an active water market (Debaere et al, 2014), hydraulic fracturing could contribute to an increase in water
prices, as already observed in the case of South Texas (Nicot, 2012; Mauter, 2014). The limited
understanding of the water demands of shale deposit development thus prevents the implementation of a
sound management plan for the use of these energy sources (Mauter, 2014). There is therefore a pressing
need for a quantitative assessment and mapping of where shale resource development could induce or
exacerbate water stress as well as intensify the competition for water between food and energy production
(Ayensu, 1999; Fiksel, 2006; Bazilian, 2011).
Here we examine the global distribution of known shale deposits suitable for oil and gas production
(Kuustra, 2013) and identify the regions in which water use for hydraulic fracturing could compete with
agriculture. We analyze the average annual surface water stress at 0.5° degrees resolution (~ 50 km at
the Equator) for the world’s high-quality shale deposits (also known as “shale plays”); unlike previous
studies (Reig et al., 2014), we account for the water needed for shale oil and gas development, agriculture,
industry, as well as environmental flows required to maintain key ecosystem functions. We
contextualized shale development impacts on water resources considering other human and
environmental uses in the same region, while also considering local groundwater stress (Gleeson et al.,
2012) and expected increase in water demand for irrigation (Muller et al., 2012).
Little is known about the environmental implications of oil sands extraction and processing. For
the case of Alberta (Humphries, 2008), previous investigations have focused on GHG emissions
(Charpentier, 2009) and the human health effects resulting from oil sands production (Kelly, 2010). There
are also other important environmental impacts associated with these extraction and treatment processes.
First, the total water footprint of oil sand extraction remains poorly understood to date, except for some
values of freshwater withdrawal reported in Alberta (Alberta Environment and Parks, 2015). It is also
unclear whether these deposits and extraction operations occur in areas of relative water scarcity and
whether they may enhance water stress. Moreover, the effects of oil sand extraction on vegetation cover
have yet to be quantified despite conspicuous losses of forest during the excavation of shallow deposits
and habitat fragmentation from in situ infrastructure and exploration (Schneider, 2006). With all of these
apparent environmental impacts in mind, we examined five countries whose deposits account for 93%
of the global reserves of recoverable crude oil from oil sands and cover 162,750 km2 – equal to the size
of Tunisia. Specifically, the aim of this study was to estimate the amount of water required for the
extraction process, the ongoing and expected loss in forest cover, associated GHG emissions due to
extraction and processing, and the number of people that could be potentially affected by the development
of oil sand deposits.
WATER-ENERGY-FOOD NEXUS Renewed debate over food security has emerged after 2007-2008 and 2011 food crises (Howells,
2013). In response commercial pressures on land and water are increasing worldwide (Rulli, 2012).
Furthermore, access to water is a concern, with an increasing number of people living in water stressed
areas (Mekonnen and Hoekstra, 2016). Moreover, global energy demand is expected to increase of 25%
by 2040 (U.S. EIA, 2016 a-b; British Petroleum, 2016; Exxon Mobil, 2016). At the same time water,
energy and food are three pillars fundamental to preserve security, prosperity and equity (Bazillian,
2011). Water, energy and food are also important to reach the Eight Millennium Goals (United Nations,
2005) and the Seventeen Sustainable Development Goals, such as: eradicate malnutrition bringing food
to 1 billion people actually malnourished, ensure safe and constant water supply to 1.2 billion people
facing water shortages, bringing access to electric energy to 1.3 billion people. Hence, an efficient
management of these resources needs to be taken in the coming decades (Bazillian, 2011). The Seventeen
Sustainable Development Goals commit subscribing countries to new action targets aimed at achieving
sustainable water use, energy use and agricultural practices, as well as promoting more inclusive
economic development (United Nations, 2014).
The Water-Energy-Food Nexus describes the complex and inter-related nature of our global
resources systems (Biggs, 2015). It has emerged as a useful concept to describe and address the complex
and interrelated nature of our global resource systems, on which we depend to achieve different social,
economic and environmental goals. In practical terms, it presents a conceptual approach to better
understand and systematically analyze the interactions between the natural environment and human
activities, and to work towards a more coordinated management and use of natural resources across
sectors and scales (FAO, 2014). This can help us to identify and manage trade-offs and to build synergies
through our responses, allowing for more integrated and cost-effective planning, decision-making,
implementation, monitoring and evaluation. A Nexus approach helps us to better understand the complex
and dynamic interrelationships between water, energy and food, so that we can use and manage our
limited resources sustainably (Biggs, 2015). It forces us to think of the impacts a decision in one sector
can have not only on that sector, but on others. Anticipating potential trade-offs and synergies, we can
then design, appraise and prioritize response options that are viable across different sectors (FAO, 2014).
Energy, water and food are valuable resources that are interdependent and determine human well-
being. Water is used in power generation; in extraction, transport and processing of fossil fuels; in
irrigation to grow crops used to produce biofuels. Energy is necessary to water provision, to power
systems that collect, transport, distribute and treat water. Energy is needed to produce fertilizers and to
prepare land, harvest crops and process agriculture products.
Water-energy-food nexus has and will have greatest consequences (IEA, 2012). Energy and water
will have a rising demand due to global population and economy growth, climate change effects, higher
standard of living and higher food demand, particularly a dietary shift to more water intensive food (i.e.,
from a plant towards a meat based diet) (World Water Assessment Programme, 2012). All these drivers
will create a more water-constrained future, which will amplify the mutual vulnerability of energy, food
production and water (IEA, 2012).
For the energy sector, constraints on water can challenge the reliability of existing operations as
well as the physical, economic and environmental viability of future projects. Water constraints can occur
naturally (i.e., droughts and heat waves), or be human-induced (i.e., growing competition among users
or regulations that limit access to water). Equally important to water-related risks confronted by the
energy sector, the use of water for energy production can impact freshwater resources, affecting both
availability (the amount downstream) and quality (their physical and chemical properties).
Water is becoming so important that is used as a criterion for assessing the viability of energy
projects. The availability and the access to water could become an issue for shale gas, shale oil and oil
sands expansion and development. Understanding energy-water stressed areas is of fundamental
importance for future planning action of development of unconventional fossil fuels resources. This, on
the one hand, will create less environmental issues, less risked capital expenditures and less failures. On
the other hand, it will require the use of better technologies and a better integration between water and
energy policies.
Agenda 21 highlighted the need for an integrated assessment of water, energy and food
management to support the decision making process and help to reach the Eight Millennium Goals
(Howells, 2013). Here we consider an integrated regional assessment of water, energy and food for global
shale resources and oil sands. While, extraction of fossil fuels from unconventional fossil fuels has
environmental impacts, the issues generated from an insecurity of access to water, energy and food
suggest that the economic and security related issues may be a stronger motivators to change in future
planning actions (Bazilian, 2011).
DEFINITIONS from Kuustra, 2013
Remaining oil and natural gas in-place. Original oil and gas in-place minus cumulative production.
Technically recoverable resources. The volumes of oil and natural gas that could be produced with
current technology, regardless of oil and natural gas prices and production costs.
Economically recoverable resources. Resources that can be profitably produced under current market
conditions and under current technological development.
Proved reserves. The most certain oil and gas resource category, but with the smallest volume, is proved
oil and gas reserves. Proved reserves are volumes of oil and natural gas that geologic and engineering
data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under
existing economic and operating conditions. Proved reserves generally increase when new production
wells are drilled and decrease when existing wells are produced.
Figure 2. Stylized representation of oil and natural gas resource categorizations (Kuustra, 2013).
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PART 1: SHALE GAS AND SHALE OIL Shale is a fine-grained sedimentary rock formed from the compaction of silt and clay (Ridley, 2011).
Shale deposits typically contain organic material (Speight, 2013), which is usually transformed in natural
gas and oil and stored in the relatively high porosities. Shale has very low permeability; in other words,
the degree to which a fluid or gas will flow through a rock is very low, oil and gas can only be removed
and produced economically if the permeability is increased fracturing the rock (U.S. DOE, 2013). Shale
rocks are not only the source of the oil and natural gas, but also the reservoir and seals for conventional
oil and gas accumulations (Denney, 2009). Interstitial spaces in shale formations are very tiny. However,
these spaces can occupy a significant volume of the rock. This allow shale to hold a great amount of oil
and gas that cannot flow due to low permeability. Oil and gas industries discovered new methods to
create artificial porosity and permeability within the rock (Speight, 2013).
SHALE GAS
Shale gas is gas that remains tightly trapped in shale and consists mostly of dry gas with 60%-90% v/v
of methane, but some formation produce wet gas (i.e., ethane, propane, butane and pentane) (Speight,
2013). Gas generated is stored in situ and can be found in three forms:
Free gas in the pore spaces and fractures;
Adsorbed gas, where gas is electrically stuck to the organic matter and clay;
Dissolved in the organic matter.
TIGHT GAS
It is used to indicate natural gas produced from low-permeability sandstone and carbonate reservoir (U.S.
EIA, 2016), it can be extracted fracturing the rock. The difference between tight gas and shale gas is the
higher amount of sandstone in the tight gas reservoir (Speight, 2013).
COAL BED METHANE
Coal bed methane can be found in every coal seam (Al-Jubori, 2009). Historically was considered a
nuisance during coal mining extraction. Nowadays, development in technologies let to exploit this
resource of natural gas using similar methods used for shale gas (Ridley, 2011). Deep coal seams
undevelopable for mining operations can be exploited for the extraction of coal bed methane (Al-Jubori,
2009). Generated gas is adsorbed by the organic material that forms coal. Large volumes of stored gas
are possible because the internal surface area of the micro porosity where the gas is adsorbed is very
large (Al-Jubori, 2009).
TIGHT/SHALE OIL
Tight oil is oil produced from low permeability sandstones, carbonates and shale formations (U.S. EIA,
2016 a). Tight oil production is a term used by oil and gas industry rather than shale oil production (U.S.
EIA, 2015). Tight oil production is a more encompassing term with respect to different geologic
formations producing oil at any particular well.
Figure 3. Illustration of conventional and unconventional oil and natural gas reservoirs. Source:
U.S. EIA.
As other unconventional resources, also shale accumulations tent to be distributed over a larger area than
conventional accumulations and usually require advanced technology to be economically productive.
Technological advances in horizontal drilling, hydraulic fracturing and 3D mapping has yielded
substantial cost reductions making unlocking huge quantity of shale resources (shale gas, shale oil) in
USA and Canada. This commercial success has opened up the possibility to produce oil and natural gas
from shale resources in other parts of the world. However, commercial shale development of the type
demonstrated in the United States requires the ability to rapidly drill and complete a large number of
wells in a single productive geologic formation. The logistics and infrastructure necessary to support this
level of activity, including the drilling and completion processes, the manufacturing of drilling
equipment, and the distribution of the final product to market are not yet evident in countries other than
the United States, Canada, China, and to some extent, Argentina. Other above the ground factors such as
ownership of mineral rights, taxation regimes, and social acceptance also play a role in decisions
regarding the development of shale and tight resources.
Although the shale resource estimates will likely change over time as additional information becomes
available, it is evident that shale resources constitute a substantial share of overall global technically
recoverable oil and natural gas resources (Kuustra, 2013). Two-thirds of the assessed, technically
recoverable shale gas resource is concentrated in six countries: USA, China, Argentina, Algeria, Canada
and Mexico (Figure 4). Similarly, two-thirds of the assessed, technically recoverable shale oil resource
is concentrated in six countries: Russia, U.S., China, Argentina, Libya and Venezuela (Figure 5)
(Kuustra, 2013). The portion of technically recoverable resource which is translated into reserves in each
of these plays will depend on economic decision made by companies (U.S. National Energy Technology
Laboratory, 2013).
Figure 4. World technically recoverable resources of shale gas expressed in trillion cubic meters
of natural gas. Source: Kuustra, 2013.
05
101520253035404550
Technically recoverable resources of shale gas (Trillion cubic meters)
Figure 5. World technically recoverable resources of shale oil expressed in billion barrels of oil.
1 barrel =0.159 m3. Source: Kuustra, 2013.
0
10
20
30
40
50
60
70
80
Technically recoverable resources of shale oil (Billion barrels)
HISTORY Shale gas and shale oil extraction come through a combination of existing technologies:
The knowledge that shale rock contains gas and oil;
Hydraulic fracturing of rock to open the pores and allow the extraction of hydrocarbons.
Hydraulic fracturing dates 1949;
Horizontal drilling, which is in use in the oil industry from 1970s;
Seismic exploration and growing computer power led to the development of 3D reconstruction
of rock strata in 2000s.
In 1990s George Mitchell brought these four elements together in Texas and discovered that large
quantity of natural gas could be extracted from deep shale. This make shale permeable enough for oil or
gas to escape. Indeed shale often forms the cap that holds in place the profitable oil and gas reservoirs
that have migrated into permeable sandstones beneath. In 2000s shale gas extraction developed quickly
in the USA starting from Texas and then to North Dakota, Pennsylvania and Ohio thanks to a rapid
increase in natural gas prices between 1998 and 2008 (from 2$/Mcf to 10$/Mcf) (U.S. DOE, 2013).
These technological breakthroughs have made commercially viable to recover gas trapped in tight
formations, such as shale or coal and at the same time to recover oil from shale oil reservoirs.
EXTRACTION Extraction is performed stimulating the reservoir by creating a fracturing network to give enough surface
area to allow sufficient production from the additional enhanced reservoir permeability (Speight, 2013).
All shale and tight reservoirs require fracture stimulation to connect the natural fracture network to the
wellbore (Gale, 2007). The use of horizontal drilling in conjunction with hydraulic fracturing has greatly
expanded the ability of producers to profitably recover natural gas and oil from low permeability geologic
plays.
Basic steps of shale gas and shale oil production are (Ridley, 2011):
1. Seismic exploration. Underground rock formations are mapped using sound waves and 3D
reconstruction to identify the depth and thickness of appropriate shale.
2. Well pad construction: a platform for the drilling rig is levelled and hard-cored. Roads and
infrastructures needed are built.
3. Horizontal drilling: a drilling derrick drills up to 12 holes down to the shale rock.
4. Hydraulic fracturing: the casing of the horizontal pipe is perforated with small explosive charges
and water mixed with sand is pumped through the hole at high pressure to fracture the rock.
5. Slick water fracturing: is a method of hydro-fracturing which involves adding chemicals to
increase the fluid flow.
6. Water disposal: tanks collect water that flows back out of the well the water is generally reused
for future fracking or disposed as waste.
7. Production: a ‘Christmas tree’ valve assembly and a tank remain on site to collect gas, which then
flows through pipeline. While a Pump Jack is installed to lift oil to the surface and storage tank
facilities.
EXPLORATION/PLANNING The realization of shale oil and shale gas extraction is more expensive and labor intensive than
conventional reservoirs. Since the construction of a well pad is very expensive and intensive activities of
exploration with highly specialized expertise are needed to characterize the reservoir and plan future
eventual extraction.
Characterization of shale gas and shale oil resources using geophysical methods has increase in
importance (Chopra, 2012). Prior to recovery a number of vertical wells (usually two or three) are drilled
and fractured to determine if shale gas is present and can be extracted. After more wells (10 to 15) are
drilled and fractured to: characterize the shale, examine how fractures will tend to propagate and establish
if the shale could produce gas economically. Moreover, other wells are drilled (up to 30) to verify long
term viability of the shale (Speight, 2013). Once the reservoir proprieties and contents have been defined,
the drilling program and recovery operations will start.
DIRECTIONAL DRILLING Most wells drilled for oil and gas are vertical wells drilled straight into the earth. Drilling at an angle
other than vertical can stimulate reservoir in a way that cannot be achieved using vertical wells.
Horizontal wells begin at the surface as a vertical well. Drilling progresses until the drill bit is a few
meters above the target. At that point the pipe is pulled from the well and a hydraulic motor is attached
between the drill bit and the drill pipe. The drill bit can drill with the desired inclination. The hydraulic
motor is powered by a flow of drilling mud down the drill pipe and drill it with the desired direction.
Directional and horizontal drilling have been used to reduce the footprint of oil and gas field and increase
the length of the pay zone in a well. Horizontal trajectory length is up to 4 km (U.S DOE, 2013). This let
the reservoir to be exposed as much as possible to the wellbore.
Horizontal wells are created to intersect a greater number of naturally existing fractures in the reservoir.
The direction of the drill path is chosen based on the known fracture trends in each area.
Drilling for shale gas can penetrate the water table. A proper casing of shale gas wells is fundamental to
preserve groundwater contaminations and to guarantee a proper functionality of the well during
production. Casing and cementing is done to prevent leakage. The casing in the horizontal section is then
perforated using explosive charges to enable the flow of hydraulic fracturing fluids out of the well into
the shale and the flow of natural gas out of the shale into the well.
6 to 8 horizontal wells can be originate from the same pad. Typical well pad area is rectangular with an
area of 15,000 to 20,000 m2 (Speight, 2013). This area is cleared leveled and cemented. Stacked wells
and multilateral drilling can be used to increase area developed and production. Stacked horizontal wells
are drilled when shale is sufficiently thick. One vertical wellbore can be used to produce gas from
horizontal wells at different depths. Multilateral drilling involves the drilling of two or more horizontal
wells from the same vertical wellbore. Horizontal wells access different areas of the shale at the same
depth, but in different directions.
Figure 6. Well pad during drilling operation. Photo courtesy: Nick Price.
HYDRAULIC FRACTURING Low permeable rocks requires extensive fractures (natural or induced) to produce commercial quantities
of gas and oil (Speight, 2013). Massive hydraulic fractures are created to effectively connect a huge
reservoir area to the wellbore (Speight, 2013). Maximizing the total stimulated reservoir volume plays a
major role in successful economic production.
Hydraulic fracturing is a procedure that pump liquids down a well into subsurface rock units under
pressure that are high enough to fracture the rock. The goal is to create a network of interconnected
fractures that will serve as pore spaces for the movement of oil and natural gas to the well bore. This
method increase well production rates of oil and gas (Speight, 2013).
In this process water and sand are pumped at high pressure into the well. Water is the driving fluid used
in the hydraulic fracturing process. Sand, named also proppant, is used to prop the fractured shale, prevent
its closure and allow the flow of natural gas into the well. Chemicals are added improving hydraulic
fracturing performances. The chemicals used are proprietary. The fissures created in the fracking process
are held open by the sand particles so that natural gas in the shale can flow up through the well. Once
released through the well, natural gas is captured, stored and transported to the relevant site processing
unit.
Approximately 30 meters of wellbore is hydraulically fractured at a time, so each well must be
hydraulically fractured in multiple stages, beginning at the furthest end of the wellbore. Cement plugs
are used to isolate each hydraulic fracture stage and must be drilled out to enable the flow of natural gas
up the well after all hydraulic fracturing is complete. When the water is pumped into the well the entire
length of the well is not pressurized. Instead, plugs are inserted to isolate the portion of well where the
fractures are desired. Only this section of the well receives the full force of pumping. As pressure builds
up in this portion of the well, water opens fractures, and the driving pressure extends the fractures deep
into the rock unit. Once pressure is released fluid flows back out through the top of the well. Flowback
water not only contain proprietary blend but also chemicals naturally present in the reservoir. In many
cases flowback water can be reused in subsequent hydraulic fracturing operations, this depends on the
quality of the flowback and on the economies of other management alternatives (disposal). Disposal in
injection wells place the flowback water in underground formations isolated from drinking water
resources.
Re-fracturing the reservoir is an option that is becoming more and more commonplace (Cramer, 2008)
and can yield additional recoverable reserves.
Following the hydraulic fracturing process the well is flowed back and tested using a controlled flaring
process. In some areas a pipeline ready to take the gas to market will be in place and flaring will not be
necessary (U.S DOE, 2013).
Figure 7. Well site during hydraulic fracturing stimulation. Source: Kansas Geological Society.
PRODUCTION After all of the wells on a pad have been drilled, completed (hydraulically fractured), and prepared for
production (well heads, piping and surface equipment installed, flowback period completed) the wells
are ready for production. The water and hydrocarbons (oil or condensate) produced along with the
natural gas from multiple wells on a pad is separated and stored in tanks on the pad.
Wells are connected to the production facilities and production can start. Most recoverable oil and gas is
usually extracted after few years. Approximately 25% of a shale gas well’s gas production emerges in
the first year and 50% within four years. After the output falls very slowly and wells are expected to
continue supplying gas for about 30-50 years (Ridley, 2013).
Conventional well production last 30 years or more with a smooth production over time. Because shale
gas production has been occurring recently, the production lifetime of shale gas wells is not fully
established. Although it is observed that shale gas decline quicker than conventional natural gas
production. Once a well no longer produces in an economic way, the well head is removed, wellbore is
filled with cement to prevent leakage of gas into the air, surface is reclaimed and the site is abandoned
to the holder of the land surface rights.
Figure 8. A shale gas well pad with multiple adjacent tress. Source: GoMarcellusshale.com
Figure 9. A shale oil well pad with a Pump Jack. Source: AllEagleFord.com
Figure 10. Schematic representation of well pad facilities. Source: Chesapeake Energy.
METHODS World shale deposits
Global maps of shale deposits were acquired from Advanced Resources International, Inc., who have
developed the most updated internationally recognized geo-referenced dataset of the spatial extent of
high quality shale areas (Kuustra, 2013). In the case of the United States the map of high quality shale
areas came from the U.S. National Energy Technology Laboratory (U.S. NETL, 2016).
These geo-databases provide information on 228 shale basins in 96 countries and classify shale
deposits depending on their ability to yield oil, dry gas or wet gas. In this study we focus on high quality
shale areas (or “shale plays”) that contain high quality shale gas and shale oil deposit, and therefore offer
the most profitable opportunities for oil and natural gas extraction in the near future. Other lower quality
and less explored areas within these basins are not included in this assessment.
Figure 11. World shale basins and high quality shale areas (shale play).
Assessing water for shale development
To identify the shale deposits in which oil and gas extraction could be limited by water availability and
compete with water uses for agriculture and other uses, we overlaid maps of major shale basins (Kuustra,
2013) with the global distribution of water stress areas (Mekonnen and Hoekstra, 2016). We then
calculated the water footprint of shale deposit development.
The amount of water required to stimulate a horizontal well through hydraulic fracturing (WW) depends
greatly on local geology, technology used and operational factors applied (Nicot, 2012; Scanlon, 2014;
Gallegos, 2015). Chen et al. (2016) calculated that 80,047 wells were drilled in the U.S. from 2008 to
2014, accounting for an average water use (W) of 11,259 m3 per well, in agreement with previous work
(Jiang et al., 2014). Interestingly, shale oil and shale gas wells drilled in the same area use the same
amount of water (Scanlon et al., 2014).
In the calculation of the water footprint of shale deposit extraction we assume that only one
stimulation is performed during the lifespan of a well. Therefore our estimate of the water footprint of
shale gas and oil is conservative because in some cases, to increase production, hydraulic fracturing may
be performed a few times over the lifetime of the well, provided that it is necessary and economically
profitable (Gregory, 2011). Additional water is required to drill a well. We assume that 1000 m3 of water
are used for drilling and “cementing” each well, based on previous studies (Scanlon et al. (2014), Clark
et al. (2013)).
Based on existing North American technology and the assessed recoverable shale resources, the
number of potential wells (n) in each shale high quality area was calculated according to criteria
developed by the U.S. Energy Information Administration (U.S. EIA, 2014) as:
𝑛𝑗 = 𝑇𝑅𝑅𝑗
𝐸𝑈𝑅𝑗
where TRR is the technically recoverable resources of oil or natural gas (i.e. oil and natural gas that can
be extracted, based on current technology, but without accounting for economic profitability) (Kuustra,
2013) and EUR is the average estimated ultimate recovery for oil or natural gas during the lifetime of a
well, which is assumed to be equal to 30 years (U.S. EIA, 2014). The subscript j indicates whether the
well is used to produce oil or natural gas. TRR values came from Kuustra et al., 2013. EUR values came
from existing estimates for the United States in 2014, namely, 108.7∙103 bbl/well and 52.63∙106 m3/well
for oil and gas, respectively (U.S. EIA, 2014). We assumed that wells are uniformly distributed within
shale plays. Depending on the geology, the returning hydraulic fracturing fluid can be up to 70% of the
injected water (Gregory, 2015). This water is returned as a brine rich of chemicals and heavy metals. It
can be recycled and reused on site, transported to wastewater treatment facilities, or injected in disposal
wells (Gregory, 2011; Warner, 2012; Mauter, 2014; Gregory, 2015). As part of the industry’s efforts to
reduce freshwater use, an economical production of shale resources will require a management of this
fracturing return fluid (Gregory, 2011). Here, three management scenarios for fracturing return fluid (rf)
were analyzed: no recycling, 50% recycling, and 100% recycling.
The number of drilled and stimulated wells depends also on the extent to which machinery and
infrastructures needed for drilling and production (e.g., drilling rigs, trucks, pumps, water tanks, roads,
and pipelines) are available (Kuustra, 2013). Therefore the wells are not drilled and stimulated all at once
but within a timeframe of a few decades, here assumed to be 30 years. Thus every year the number of
drilled wells is assumed to be constant and equal to n/30. Thus the annual water footprint of well drilling
and stimulation is:
WFfrac( m3
year) =
W ∙ n ∙ rf
30
Water is usually withdrawn from nearby water sources (Gregory, 2011). We assumed that the water
used for fracturing stimulations (WFfrac) is extracted within the same 0.5 degree grid cell where drilling
takes place because oil and gas companies will likely try to minimize the transport costs of water
(Vandecasteele, 2015).
Generation of surface water stress map
The global distribution of annual surface water stress was calculated as in Mekonnen and Hoekstra, 2016
but accounting also for the consumptive use of water for hydraulic fracturing in high quality shale areas.
Surface water stress (WS) is defined as the ratio of the blue water footprint (WF) of human activities (i.e.,
municipal, agriculture, mining, and other industries) and the total blue water availability (WAtot) in a grid
cell (Mekonnen, 2016). We calculate WS in grid cells at a 0.5° resolution (i.e., ~ 50 km at the equator),
the local blue water footprint (WFloc) in each grid cell and total water availability (WAtot) in each grid
cell.
The blue water availability in a grid cell (WAtot) is the sum of the local blue water generated in that
cell (WAloc) and the net blue water availability from the upstream grid cells (WAnet,up).
WAtot,j = WA loc,j + WAnet,up,j
where j denotes the cell under consideration. Upstream blue water availability is defined as the blue water
generated in the upstream cells minus the blue water footprint in the upstream cells (WFup).
WAnet,up,j = ∑(WAup,i − WFup,i)
n
i=1
where the subscript i denotes the cells upstream from the cell j under consideration.
The blue water footprint is the volume of surface and ground water that is withdrawn and not returned
back to the environment as liquid water (i.e., consumptive use). This value is calculated by adding the
blue water footprint by Mekonnen and Hoekstra, (2012) (aggregated at a 0.5° resolution) — which
accounts for agricultural, industrial and municipal water uses — with the amount of water required for
well drilling and hydraulic fracking (WFfrac). Runoff data at 0.5° resolution were obtained from the
Composite Runoff V1.0 database of Fekete et al. (2002).
To account for environmental flow requirements, we assumed that 80% of the natural runoff is
allocated to environmental flows and the remaining 20% is considered blue water available for human
needs (Aldaya, 2012; Richter, 2012). To calculate the upstream water availability we used the flow
direction raster (0.5° resolution) from the World Water Development Report II
(http://www.grdc.sr.unh.edu/index.html) (Vorosmarty, 2000a; 2000b).
Assessing other water related impacts
Water used for shale gas and oil extraction can be withdrawn either from surface water bodies, or
the groundwater. The latter can be more ubiquitous and therefore more likely available close to the
production wells (Nicot, 2012). To identify areas in which hydraulic fracturing is expected to place
additional pressure on stressed groundwater resources, we overlaid a groundwater stress map (Gleeson
et al., 2012) with the global distribution of high quality shale areas.
To identify shale deposits in which the extraction of oil and gas is expected to strongly compete
with food production in the near future, we examined areas in which the increase in agricultural
production by closing the yield gap of major crops (i.e., wheat, maize and rice) to 75% of attainable yield
requires an increase in irrigation. To that end, we rely on the global assessment of irrigation-controlled
yield gaps by Muller et al., (2012).
The number of people living in affected areas was estimated using population distribution data
taken from CIESIN’s Gridded Population of the World map (GPWv4) for the year 2010.
The economic evaluation of water use for energy and food production was calculated using data of
water use and average world commodities prices in 2015 (World Bank, 2016) (Table 2).
SHALE DEPOSITS IN WATER STRESSED REGIONS The global analysis of surface water stress potentially generated by shale deposit exploitation (Fig.
12) shows that 39% of the area of high quality shale deposits are located in areas affected by surface
water stress and where 171 million people live. Some of the deposits in stressed areas occur in the south-
central United States, Argentina, South Africa, Saharan Africa, China, India, and Australia. Water stress
is particularly high in areas that are highly populated, irrigated, or with low water availability (Mekonnen,
2016). In these regions an increase in human appropriation of freshwater resources for shale gas or shale
oil extraction would markedly increase competition with the existing water uses for agriculture and
environmental flows. Water stress in Australia, Argentina (in the Vaca Muerta shale deposit) and Algeria
is particularly severe and worse than in any other shale deposit around the world, due to a combination
of high volumes of extractable shale resources and lower water availability.
Figure 12. Map of surface water stress within high quality shale deposits. Pixels with water stress
indexes greater than 1are subjected to unsustainable water withdrawals (i.e., water use for human
activities exceeds the limit imposed by environmental flow requirements). Bottom panels show some
notable water stressed high quality shale deposits in which production has either started or is expected to
take place in the near future. Nowadays, the United States, Canada, China and Argentina have
commercial shale gas production. Development of shale gas resources is also expected in Algeria and
Mexico. Shale oil production is practiced in the United States and Canada, future commercial extraction
is mainly expected in Russia, Argentina, Colombia, Mexico and Australia (U.S. E.I.A., 2016 a-b).
The extraction of shale deposits is expected to affect not only surface water resources but also
groundwater (e.g., Freyman, 2014). Our analysis (Fig. 13) shows that 8% of high quality shale deposits
are located in regions affected by groundwater stress across the United States, Argentina, South Africa,
China, India and home to 118 million people. About 6% of the world’s high quality shale areas are
affected by both surface and groundwater stresses (Fig. 14). To cope with strong limitations on both
surface and groundwater resources, one such area - southern Texas - developed a water market. However,
the recent emergence of hydraulic fracturing in the region has driven higher water prices (Nicot 2012)
and enhanced the competition between water for food production through irrigation and water for oil and
natural gas production from shale resources. Thus while water markets may offer an effective solution
for allocating water rights within water-limited systems (Debaere et al. 2014), the ultimate result may be
the displacement of agriculture if shale energy companies are willing to pay a higher price for water use.
Figure 13. Groundwater stress over high quality shale deposits. Groundwater stress is defined as the
ratio of the groundwater footprint and the aquifer area (Gleeson, 2012). Pixels with water stress indexes
greater than 1are subjected to unsustainable water withdrawals (i.e., water use for human activities
exceeds the limit imposed by environmental flow requirements).
Figure 14. Surface and groundwater stress over high quality shale deposits. High quality shale areas
(countries) facing these combined stresses are: Mississippian Lime, Niobrara, Permian and Eagle Ford
(U.S.), Eagle Ford deposit (Mexico), Vaca Muerta and Aguada Bandera (Argentina), Collingham (South
Africa), Tannezuft and Frasnian (Algeria), Tannezuft (Lybia), Khatatba (Egypt), Etropole (Romania),
Wufeng/Gaobiajian, Longmaxi, Keuter and Qingshankou (China), Sembar (Pakistan) and Sembar,
Cambay and Permian Triassic (India).
Our analysis shows that water stress levels are not sensitive to different degrees of water recycling in the
hydraulic fracturing process. With the assumption to recycle 50% and 100% of water there is no major
change in the spatial extent of water stressed areas. A similar finding was also reported by other authors
who noticed that the geographic distribution and size of water stressed areas was not sensitive to changes
in crop water footprint (Brauman et al., 2016). Interestingly, we find water stress to substantially vary
within each high quality shale area, consistent with the observation of small-scale heterogeneity in the
global distribution of water stress (Vorosmarty et al., 2005 and Perveen et al., 2011). The results of our
analysis are sensitive to the uncertainty in water footprint for hydraulic fracturing, agriculture, and water
availability.
SHALE DEPOSITS OVER IRRIGATED AREAS To better evaluate possible future competition for water resources between shale deposit
development and agriculture, we examined the global distribution of areas in which irrigation is expected
to increase to accommodate growing demand for food products (Figure 15). We find that 25% of high
quality shale areas worldwide are in irrigated areas where about 220 million people live. About 7% of
the high quality shale areas are located in regions where water use for irrigation has been projected to
increase in order to close the crop yield gap – the difference between actual and attainable yields. Thus,
competition for water use in these areas will not only increase due to shale energy production but also be
exacerbated by a greater need for irrigation water.
Figure 15. Irrigated areas overlying high quality shale deposits. Projected increase in irrigation to
close maize, rice and wheat yield gaps to 75% of attainable yields is expected to affect several shale
deposits. Bottom panels show twelve high quality shale areas - Bakken (Canada), Bakken, Heath,
Gammon, Mississippian Lime, Barnett, Eagle Ford (U.S.), Eagle Ford (Mexico), Lower Silurian
(Morocco), Sembar (Pakistan), Sembar and Cambay Shale (India), Keuter and Quingshankou (China),
Nam Duk Fm (Thailand) - where we predict the occurrence of future competition between water for
shale resource development and food production. Other high quality shale areas threatening water-
energy-food security are: Collingham (South Africa), Etropole (Romania and Bulgaria), Hamitabat
(Turkey), Barren Measure (India), Longmaxi and Qiongzhusi (China), Carynginia (Australia).
By far the most substantial human appropriation of water, consumptive freshwater use for irrigation
is 899 Gm3 annually (Hoekstra, 2012). We estimated that a total volume of 58.7 Gm3 of water is required
to extract the global shale oil and shale gas reserves using current technology. This water is expected to
be withdrawn from the local surface and groundwater reserves within a timeframe of a few decades.
Detailed volumes of water required for the development of each high quality shale area are shown in
Table 1 of the supplementary materials. These estimates are based on current technology and estimated
size of extractable hydrocarbon deposits. Many of the assessed high quality shale areas, however, are not
likely to be put under commercial production for economic, social and technical reasons. The countries
in which commercial production is expected to occur (U.S. EIA, 2016 a-b) (Fig. 12) account for 92%
and 57% of world technically recoverable shale gas and oil, respectively. In these countries, the extraction
of shale gas and oil will require a total volume of 36.07 Gm3 of water. While our results show that large
volumes of water will be required, it is worth noting that future technological development and water
management improvements will likely minimize fresh water appropriation using brackish water - a
globally abundant and underutilized resource - and maximizing the reuse of returning hydraulic
fracturing water (Mauter, 2014; Nicot, 2012).
Presently, in the United States only 11% of returning hydraulic fracturing fluid water is recycled
(Chen, 2016), while 89% is injected into disposal wells. This water is therefore removed from the water
cycle and becomes unavailable for other uses on an annual scale (Gregory, 2011; Warner, 2012; Mauter,
2014; Gregory, 2015). Though the volume of water for shale oil and gas production is an order of
magnitude less than that required for crop irrigation globally, we find that the effect of hydraulic
fracturing on water resources could be profound at local scales (Nicot, 2012) with potentially stronger
impacts on other societal uses and the environment than irrigated agriculture.
Table 1. List of world high quality shale areas and total volume of water required to extract
technically recoverable resources of shale gas and shale oil.
Country Basin High quality shale
area
Total potential
shale gas water
use (Gm3)
Total potential
shale oil water
use (Gm3)
Canada Horn River Muskwa/Otter Park 0.6195 0.0000
Evie/Klua 0.2542 0.0000
Cordova Muskwa/Otter Park 0.1335 0.0000
Liard Lower Besa River 1.0414 0.0000
Deep Basin Doig Phosphate 0.1660 0.0000
Alberta Basin Banff/Exshaw 0.0000 0.0106
East and West
Shale Basin
Duvernay 0.7450 0.1345
Deep Basin North Nordegg 0.0876 0.0265
NW Alberta Area Muskwa 0.0000 0.0711
Southern Alberta
Basin
Colorado Group 0.2825 0.0000
Williston Basin Bakken 0.0000 0.0528
Appalachian Fold
Belt
Utica 0.2049 0.0000
Windsor Basin Horton Bluff 0.0224 0.0000
Mexico Burgos Eagle Ford Shale 2.2609 0.2128
Tithonian Shales 0.3325 0.0000
Sabinas Eagle Ford Shale 0.6609 0.0000
Tithonian La Casita 0.1557 0.0000
Tampico Pimienta 0.1532 0.1852
Tuxpan Tamaulipas 0.0000 0.0170
Pimienta 0.0000 0.0155
Veracruz Maltrata 0.0228 0.0092
Australia Cooper Roseneath-Epsilon-
Murteree
(Nappamerri)
0.5887 0.0333
Roseneath-Epsilon-
Murteree
(Patchawarra)
0.0238 0.0148
Roseneath-Epsilon-
Murteree (Tenappera)
0.0000 0.0044
Maryborough Goodwood/Cherwell
Mudstone
0.1264 0.0000
Perth Carynginia 0.1637 0.0000
Kockatea 0.0000 0.0181
Canning Goldwyer 1.5528 0.3273
Georgina L. Arthur Shale
(Dulcie Trough)
0.0536 0.0039
L. Arthur Shale
(Toko Trough)
0.0306 0.0289
Beetaloo M. Velkerri Shale 0.1460 0.0466
L. Kyalla Shale 0.0930 0.0446
Colombia Middle Magdalena
Valley
La Luna/Tablazo 0.0000 0.1597
Llanos Gacheta 0.0000 0.0211
Colombia/
Venezuela
Maracaibo Basin La Luna/Capacho 1.3313 0.4982
Argentina Neuquen Los Molles 1.8164 0.1230
Vaca Muerta 2.0300 0.5450
San Jorge Basin Aguada Bandera 0.3353 0.0000
Pozo D-129 0.229 0.0168
Austral-
Magallanes Basin
L. Inoceramus-
Magnas Verdes
0.8539 0.2203
Parana Basin Ponta Grossa 0.0211 0.0003
Brazil Parana Basin Ponta Grossa 0.5309 0.1439
Solimoes Basin Jandiatuba 0.4255 0.0095
Amazonas Basin Barreirinha 0.6591 0.0260
Paraguay Parana Basin Ponta Grossa 0.0541 0.0183
Uruguay Cordobes 0.0301 0.0191
Paraguay/
Bolivia
Chaco Basin Los Monos 0.6826 0.1261
Chile Austral-
Magallanes Basin
Estratos con Favrella 0.3196 0.0788
Poland Baltic
Basin/Warsaw
Trough
Llandovery 0.6940 0.0413
Lublin Llandovery 0.0000 0.3022
Podlasie Llandovery 0.0663 0.0194
Fore Sudetic Carboniferous 0.1407 0.0000
Lithuania/
Kaliningrad
Baltic Basin Llandovery 0.0161 0.0485
Russia West Siberian
Central
Bazhenov Central 0.0000 1.9442
West Siberian
North
Bazhenov North 0.9300 0.5608
Ukraine/
Romania
Carpathian
Foreland Basin
L. Silurian 0.4781 0.0000
Ukraine Dniepr-Donets L. Carboniferous 0.5010 0.0384
Ukraine/
Romania
Moesian Platform L. Silurian 0.0637 0.0027
Romania/
Bulgaria
Etropole 0.0000 0.0133
UK N. UK
Carboniferous
Shale Region
Carboniferous Shale 0.1656 0.0000
S. UK Jurassic
Shale Region
Lias Shale 0.0000 0.0230
Spain Cantabrian Jurassic 0.0000 0.0048
France Paris Basin Lias Shale 0.0000 0.0511
Permian-
Carboniferous
0.8400 0.1067
Southeast Basin Lias Shale 0.0488 0.0000
Germany Lower Saxony Posidonia 0.1113 0.0177
Wealden 0.0000 0.0042
Netherlands West Netherlands
Basin
Epen 0.0000 0.0790
Geverik Member 0.0000 0.0106
Posidonia 0.0000 0.0089
Sweden Scandinavia
Region
Alum Shale - Sweden 0.0644 0.0000
Denmark Alum Shale -
Denmark
0.2092 0.0000
Morocco (and
Wetern
Sahara)
Tindouf L. Silurian 0.1149 0.0079
Tadla L. Silurian 0.0202 0.0000
Algeria Ghadames/Berkin
e
Frasnian 0.6992 0.1311
Tannezuft 1.1629 0.0159
Illizi Tannezuft 0.3675 0.0171
Mouydir Tannezuft 0.0627 0.0000
Ahnet Frasnian 0.0581 0.0000
Tannezuft 0.3372 0.0000
Timimoun Frasnian 0.6162 0.0000
Tannezuft 0.3898 0.0000
Reggane Frasnian 0.1070 0.0078
Tannezuft 0.6898 0.0107
Tindouf Tannezuft 0.1719 0.0023
Tunisia Ghadames Tannezuft 0.0699 0.0014
Frasnian 0.0799 0.0477
Libya Ghadames Tannezuft 0.2756 0.1745
Frasnian 0.0349 0.0434
Sirte Sirte/Rachmat Fms 0.0000 0.5452
Etel Fm 0.0000 0.0678
Murzuq Tannezuft 0.0000 0.0451
Egypt Shoushan/Matruh Khatatba 0.0000 0.0225
Abu Gharadig Khatatba 0.0000 0.0632
Alamein Khatatba 0.0000 0.0193
Natrun Khatatba 0.0000 0.0481
South Africa Karoo Basin Prince Albert 0.6354 0.0000
Whitehill 1.3940 0.0000
Collingham 0.5407 0.0000
China Sichuan Basin Qiongzhusi 0.8239 0.0000
Longmaxi 1.8899 0.0000
Permian 1.4151 0.0000
Yangtze Platform L. Cambrian 0.2984 0.0000
L. Silurian 0.0000 0.0000
Jianghan Basin Niutitang/Shuijintuo 0.0754 0.0000
Longmaxi 0.0434 0.0013
Qixia/Maokou 0.0644 0.0083
Greater Subei Mufushan 0.0478 0.0000
Wufeng/Gaobiajian 0.2373 0.0075
U. Permian 0.0127 0.0016
Tarim Basin L. Cambrian 0.2901 0.0000
L. Ordovician 0.6224 0.0000
M.-U. Ordovician 0.4047 0.0522
Ketuer 0.0000 0.2174
Junggar Basin Pingdiquan/Lucaogou 0.0000 0.1827
Triassic 0.0000 0.2251
Songliao Basin Qingshankou 0.0000 0.3848
Mongolia East Gobi Tsagaantsav 0.0000 0.0573
Tamtsag Tsagaantsav 0.0000 0.0573
Thailand Khorat Basin Nam Duk Fm 0.0359 0.0000
Indonesia C. Sumatra Brown Shale 0.0000 0.0931
S. Sumatra Talang Akar 0.0000 0.1372
Tarakan Naintupo 0.0000 0.1679
Meliat 0.0247 0.0000
Tabul 0.0000 0.0106
Kutei Balikpapan 0.0000 0.0226
Bintuni Aifam Group 0.1884 0.0000
India Cambay Basin Cambay Shale 0.1947 0.0910
Krishna-Godavari Permian-Triassic 0.3751 0.0203
Cauvery Basin Sattapadi-
Andimadam
0.0000 0.0076
Damodar Valley Barren Measure 0.0000 0.0070
Pakistan Lower Indus Sembar 0.6647 0.1951
Ranikot 0.0289 0.1097
Turkey SE Anatolian Dadas 0.0000 0.1534
Thrace Hamitabat 0.0427 0.0032
Jordan Hamad Batra 0.0441 0.0000
Wadi Sirhan Batra 0.0008 0.0000
USA Michigan Antrim 0.1266 0.0000
Permian Avalon-Bone Spring 0.0593 0.0974
Williston Bakken 0.0798 0.7624
Ft. Worth Barnett 0.1154 0.0067
Marfa Barnett-Woodford 0.0098 0.0235
Permian Barnett-Woodford 0.0817 0.0000
Greater Green
River
Baxter 0.0006 0.0302
Greater Green
River
Baxter/HIllard 0.0026 0.0201
Powder River Baxter/HIllard 0.0158 0.0705
Appalachian Big Sandy 0.0817 0.0134
Black Warrior Chattanooga 0.0105 0.0000
Appalachian Chattanooga 0.0290 0.0000
Appalachian Cleveland 0.0065 0.0033
Permian Cline 0.0718 0.0302
Valley and Ridge
(APB)
Conasauga 0.0283 0.0000
Appalachian Devonian (Ohio) 0.1563 0.0000
Burgos Eagle Ford 0.3654 0.3459
Western Gulf Eagle Ford Gas Play 0.1688 0.1679
Western Gulf Eagle Ford Oil Play 0.1965 0.1780
Cherokee Excello-Mulky 0.0098 0.0235
Arkoma Fayetteville 0.17611 0.0000
Black Warrior Floyd-Chattanooga 0.0105 0.0000
Black Warrior Floyd-Neal 0.0211 0.0201
Williston Gammon 0.0000 0.1108
TX-LA-MS Salt
(APB)
Haynesville-Bossier 1.4023 0.0268
Williston Heath 0.0481 0.0033
Pardox Hermosa 0.0065 0.0268
San Juan Lewis 0.1352 0.0000
Montana Thrust
Belt
Lombard 0.0006 0.0000
Uinta Mancos 0.2796 0.0235
Uinta-Piceance Mancos 0.0639 0.0067
Uinta Manning Canyon 0.0072 0.0033
Appalachian Marcellus 0.9808 0.0100
Anadarko Mississippian Lime 0.2711 0.0302
Los Angeles Monterey 0.01978 0.0201
Santa Maria Monterey 0.0804 0.0000
Powder River Mowry 0.0699 0.0302
Illinois New Albany 0.1919 0.0000
North Park Niobrara 0.0178 0.0134
Denver Niobrara 0.0758 0.0033
Uinta-Piceance Niobrara 0.2658 0.0302
Maverick Pearsall-Eagle Ford 0.0323 0.0000
Raton Pierre - Niobrara 0.0039 0.0134
TX-LA-MS Salt Tuscaloosa 0.0936 0.2351
Appalachian Utica 0.3601 0.0302
Permian Wolfcamp/Wolfbone 0.1642 0.2048
Ardmore Woodford 0.0639 0.0201
Anadarko Woodford 0.1517 0.0302
Arkoma Woodford-Caney 0.1517 0.0000
WATER FOR FRACKING OR WATER FOR IRRIGATION? The increasing food and energy needs of humanity (e.g., Suweis, 2013) and the possible local
decline in water availability as an effect of climate change (IPCC, 2013) are expected to increase pressure
on freshwater resources (Muller, 2012; Davis, 2014). As a result, regions affected by increasing water
stress will face not only environmental and social challenges, but also see the emergence of financial
obstacles both for the food and energy industries. In some water constrained areas where shale resources
are present a rush for water appropriation by oil and gas companies has surged, leaving the agricultural
sector with limited water supply (Nicot, 2012; Mauter, 2014). This pattern is expected to occur in many
other water stressed agricultural regions in which shale deposits are going to be developed because of
the higher profits of water use for energy than for food production. In fact, despite the current low price
of oil and natural gas, the use of water for energy production generates greater profits than agriculture
(Table 2). Oil production from hydraulic fracturing is also less water intensive than oil from oil sands
and conventional oil through secondary recovery (i.e., water flooding of the reservoir) and therefore more
economically convenient. Only conventional oil from primary recovery (i.e., using lift pump) and
conventional gas, which has a zero water footprint in extraction, exhibits a higher economic yield of
water use than shale oil and shale gas. Interestingly, bioethanol and biodiesel are less profitable - in terms
of economic yield of water - than fossil oil and gas, but are more economical than the production of
certain food crops. Moreover, our analysis shows that, despite their similar water requirements per unit
of energy produced, shale oil and shale gas strongly differ in the economic yields of the water used in
their production processes. Because of the higher price of shale oil with respect to shale gas, the economic
yield of water used in shale oil extraction is higher than in the case of shale gas. Oil and gas prices are
currently driving investors to target the more lucrative high quality shale areas where the more profitable
oil and natural gas liquids (i.e., ethane, propane, butane and isobutene) are known to exist (U.S. DOE,
2013).
Table 2. Economic yield of water for energy and food production. 1 bbl (barrel) = 0.159 m3
Water footprint of
major food and fuel
products
Water per unit
of energy
(L/GJ)
Average global price
(year 2015) ¶¶
Economic
yield of water
($/m3)
Shale gas 0.20-0.55 L/m3 * 5.69-15.54 2.47-6.88 $/GJ 159-434
Shale oil 57.08-65.86 L/bbl * 9.85-11.37 50.75 $/bbl 771-889
Conventional gas 0 ** 0 2.47-6.88 $/GJ -
Conventional oil:
primary recovery
31 L/bbl ** 5.31 50.75 $/bbl 1651
Conventional oil:
secondary recovery
1361 L/bbl ** 235 50.75 $/bbl 37
Oil from oil sands 95-906 L/bbl † 16.15-154.05 50.75 $/bbl 56-532
Maize 1222 L/kg ¶ 800157 0.169 $/kg 0.14
Rice 1830 L/kg ¶ 336459 0.351-0.386 $/kg 0.14
Wheat 2497 L/kg ¶ 176043 0.205 $/kg 0.11
Bioethanol 2107-2854 L/L ¶ 51000-121000 0.38 $/L 0.19-0.32
Biodiesel 11400 L/L ¶ 343000 0.76 $/L 0.07
* Scanlon, 2014; ** Mielke, 2010; † this work; ¶ Mekonnen, 2011; ¶¶ The World Bank, 2016
BALANCING ENERGY AND FOOD SECURITY A number of shale deposits are situated in countries lacking conventional hydrocarbon deposits
such as South Africa, Jordan, Chile, and European countries (Kuustra, 2013). Their potential future
exploitation will create a new geography of oil and natural gas production, with important implications
for the global geopolitical landscape (IEA, 2016 a-b). Shale resources are an opportunity for these
countries to increase their energy security, while reducing costs of fossil fuel imports and potentially
changing their import-export balance (Vidic, 2013; Mauter, 2014). Should they choose to exploit their
shale deposits, these countries will need to develop responsible water management plans to ensure that
other sectors are not impacted.
Nowadays, the United States, Canada, China and Argentina have commercial shale gas production.
Development of shale gas resources is also expected in Algeria and Mexico. Shale oil production is
practiced in the United States and Canada, future commercial extraction is mainly expected in Russia,
Argentina, Colombia, Mexico and Australia (U.S. E.I.A., 2016 a-b). Shale oil production is expected to
more than double in the near future from 4% of the world’s oil demand in 2015 to about 10% by 2040
(U.S. EIA, 2016 a-b; British Petroleum, 2016; Exxon Mobil, 2016); likewise, shale gas production is
predicted to surge from 10% of the global natural gas supply in 2014 to 30% by 2040 (U.S. EIA, 2016
a-b; British Petroleum, 2016; Exxon Mobil, 2016). The shale revolution has created new jobs and
economic benefits in North America, supporting economic growth also in some rural and less developed
areas. For example, in the U.S. the shale industry employed about 1.7 million people in 2015, a trend
that is expected to grow to 3.5 million jobs by 2035 (U.S Chamber of commerce, 2013). Thus, with
adequate policies and regulations, shale extraction has the potential to enhance the economic growth and
energy security of some regions.
Despite these benefits, in many regions of the world shale deposits development will be
problematic because of water limitations and will likely exacerbate a competition with water for food
and other human needs. Particularly critical appears to be the case of some high quality shale areas in
water stressed regions of the United States, Mexico, South Africa, China, South Asia, and Australia
(Figure 15). In some of these regions oil and gas production from shale rocks is expected to threaten the
local water and food security. In these water stressed areas where shale resources are present adequate
policies need to be put in place in order to avert social, economic, and ecological consequences.
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PART 2: OIL SANDS
Also known as tar sands, oil sand deposits differ from conventional oil fields in two ways. First,
oil sands are orders of magnitude larger respect to conventional oil pools. Second, oil sands have different
physical characteristics from conventional crude oil (Mossop, 1980). Oil sands are a natural occurring
mixture of sand, clay, water, other minerals and bitumen (Dai, 1996). Oil sands contain a highly viscous
crude oil in an unconsolidated sand matrix.
Bitumen is a heavy oil with API gravity − a measure of how heavy a petroleum is compared to
water (U.S. EIA, 2016) − less than 10° (Meyer, 2007). Bitumen is too heavy and viscous to flow or be
pumped in natural conditions, but undergoes a substantial reduction in viscosity when subjected to
elevated temperatures (Dai, 1996). Bitumen must be treated before it can be used by refineries to produce
usable fuels such as gasoline and diesel. Bitumen chemical composition has a low hydrogen to carbon
ratio and is composed by carbon, hydrogen, oxygen, nitrogen, sulfur1 (Alberta Energy, 2016).
Figure 1. Composition of oil sands.
1 Chemical composition of bitumen varies among different deposits.
Oil sand deposits have been discovered in a few region around the world and account for about
30% of the proved reserves of global crude oil. Because of their oil sand deposits, Venezuela and Canada
have the first and third largest recoverable oil reserves in the world, respectively, while Saudi Arabia is
at the second place with its endowment of conventional oil (Figure 2) (U.S. Central Intelligence Agency,
2016). Presently, oil sand deposits are intensively exploited only in Alberta and Venezuela (in the
“Orinoco’s Heavy Oil Belt”, which encompasses both oil sand and heavy oil deposits). In Madagascar
and Utah commercial extraction has just started, while the development of other deposits around the
world is still at the exploration or planning stage.
Figure 11. World crude oil proved reserves. Source: U.S. Central Intelligence Agency, 2016.
The Athabasca deposit in Alberta is the most developed in the world. In Alberta, best available
technologies are used in the exploration and production processes. Although oil sands are found in many
countries, the availability of water in Alberta, make water-based bitumen extraction feasible.
Furthermore, Alberta’s oil sands are considered unique since are water-wet, meaning that a layer of water
cover the sand particles and bitumen. This water facilitates the separation of bitumen from sand (Oil
sands magazine, 2015). While, oil sands in Venezuela and USA (Utah) are oil-wet and therefore cannot
be separated in a water-based process (Oil sands magazine, 2015). Deposits in Venezuela and Utah
require solvents and chemicals to separate bitumen from the sand.
0
50
100
150
200
250
300
350
Bill
ion
Bar
rels
Crude Oil proved reserves
Historically, oil sands was incorrectly referred to as tar sands. The name tar derives from the now
outdated and largely ineffective practice of using oil sands for roofing and paving tar. Oil sands and tar
appear to be visibly similar, but they are different.
Oil sands are a naturally occurring petrochemical that can be upgraded into crude oil and
other petroleum products.
Tar is synthetically produced from coal, wood, petroleum or peat through destructive
distillation. Tar is generally used to seal against moisture.
Furthermore, oil sands can be refined to make oil, while tar cannot. Tar has historically been used to seal
wood and rope against moisture (Alberta Energy, 2016).
Figure 4. Tar (left) and oil sands (right). Source: Tar sands basic.
Figure 12. Water-wet and oil-wet oil sands. Source: U.S. Oil Sands, 2015
CANADA Canada has about 173 billion barrels of oil that can be recovered with today’s technology (Canada
Association of Petroleum Producers, 2016). Of that number, the 97 per cent are located in the oil sands
(Canada Association of Petroleum Producers, 2016). However, with new technologies this reserve
estimates could be significantly increased. In fact, Canada’s total oil sands reserves are estimated at 1.8
trillion barrels (Alberta Oil sands industry, 2016). Today more than a half of Canada’s oil production
comes from the oil sands. Canada is the largest supplier of oil to USA (Alberta’s oil sands, 2016).
Figure 5. Location and extensions of Alberta’s oil sand deposits (red). Oil sands are located in three
main regions within the province of Alberta: the Athabasca, Cold Lake and Peace River regions (Alberta
Energy, 2016).
United States
Formation of oil sands
Alberta’s oil sands were formed in Early Cretaceous age, about 110 millions of years ago when the
province was covered by a warm tropical sea (Government of Alberta, 2016). Oil began forming in
southern Alberta when tiny marine creatures died and were drifted to the seafloor. Over time their body
were compressed by heat and pressure and formed liquid rock oil.
Meanwhile, in the north, rivers flowing away from the sea deposited sand and sediment. When
tectonic plates shifted to form the Rocky Mountains, the pressure squeezed the oil northward causing it
to seep into the sand and transporting with it oxygenated water (Alberta Energy, 2016). Aerobic microbe
bacteria fed off the lighter hydrocarbon molecules in a biodegradation process. Heavy and complex
hydrocarbons were left behind to form Alberta’s oil sands (Oil sands magazine, 2015).
History of oil sands
Bitumen appears in the first writings about the Athabasca region that immediately identifying it as
a resource. The primary use was not related to energy, but was used to waterproof canoes mixing bitumen
and spruce gum.
Efforts to tap the oil sands resources began in the early 20th century. The production of oil from oil
sands has been conducted commercially for almost five decades. Canada’s first large scale oil sands mine
started in 1967. Initially oil sands were primarily accessed through large open pit mining operation. While
oil sands mining is on the commercial scale since the 1980s, in situ drilling is a more recent technology.
In situ technologies have played a growing role in oil sands production (Alberta Energy, 2016). Since
2012 in situ oil sands production exceed mined oil sands production in Alberta (Alberta Oil sands
industry 2016).
Figure 6. Bitumen production from Canada’s oil sands. Source: Alberta Environment and Parks,
2016.
RECOVERING THE OIL Oil sands are recovered using two main methods: surface mining and in situ drilling. The method
used depends on how deep the reserves are located. Bitumen that is close to the surface is mined. While,
bitumen that is deep within the ground is extracted in situ using specialized techniques. Approximately
80 per cent of Alberta’s oil sands are recoverable through in situ production, with only 20 per cent
recoverable using mine extraction (Alberta Energy, 2016).
SURFACE MINING
Oil sands mines are one of the largest earth moving operation in the world (Oil sands magazine,
2015). The principal requirements for a viable mine are that there is a sufficient reserves to support a
plant life for at least 20 years and that there are oil sands with more than 8% bitumen by weight (Mossop,
1980).
Surface mining is economically feasible when oil sands are close to the surface. Surface mining
collects deposits less than 75 m deep. It is practiced in the Athabasca region, near Fort McMurray,
adjacent to the Athabasca River (Oil sands magazine, 2015).
0
100
200
300
400
500
600
700
800
900
Pro
du
ctio
n [
mill
ion
bar
rels
]
Canada oil sands production
Mining bitumen Thermal in situ bitumen
Figure 7. Oil sands mineable and in situ drilling areas. Source: Peak oil, 2016.
A typical oil sands mining facility has the following units (Oil sands magazine, 2015):
A surface mine;
A bitumen production plant, where bitumen is separated from sand and water;
A tailings storage facility, known as tailings pond;
An utility plant, which supplies steam, power and hot water;
A storage facility for bitumen and diluents.
Anatomy of an oil sands deposit
A layer of topsoil, containing trees, shrubs normally covers the deposit. An oil sands deposit consist of
four distinct layers (Oil sands magazine, 2015):
Muskeg: A wet top layer of peatland, muskeg has a limited use as construction material. Once
removed is typically sent to a waste dump.
Overburden: a layer that consists of glacial drift composed by sand, gravel and a little amount of
bitumen. Sections of deposit containing less than 7% bitumen are considered overburden as
defined by Alberta Energy Regulator. Overburden has a high sand content and is used as building
material. The overburden average thickness is 15 meters.
Oil sands: a zone of bitumen rich sand. Oil sands deposit are an unconsolidated deposit of mainly
sand, bitumen and water. The oil sands layer is typically 50 meter in thickness.
Rock: a layer of rock that sits below the oil sands.
Clearing of the forest: black spruce2 is cleared during winter period, when frost penetration into
the underlying muskeg is sufficient to allow the movement of heavy trucks. The trees are
harvested and sold to forestry companies.
Remove the muskeg layer: the muskeg layer is a peatland that needs hydraulic remediation.
Drainage trenches are excavated and after muskeg is dewatered, it is removed and it is stored in
a waste dump for subsequent use in future reclamation of the mines.
Dewater the mining area: some areas can be very wet. Water is collected and pumped to a water
collection pond in order to lower the groundwater table.
Remove the overburden: overburden is removed and is used on site to build dikes for the
containment of tailings3 and muskeg or is used as building material.
Excavate the opening cut: the opening cut is the very first excavation of the oil sands deposit.
The techniques uses shovels and trucks4. Mining shovels dig into sand and load it into trucks. The
mined material is transferred to the Bitumen Production processing plant. It is very common for
2 Black spruce, Picea Mariana, is a North American species of spruce tree in the pine family. It is frequent part of
the biome known as taiga or boreal forest. 3 Tailings are a combination of water, sand, silt and clay that are a by-product of the bitumen extraction from the
oil sands. 4 The oil sands mining truck is the Caterpillar 797. This truck is one of the world’s largest trucks with the capacity
to haul up to 400 tons per load.
Figure 8. Anatomy of an oil sands deposit. Source: Oil sands magazine, 2015.
new oil sand mines to have a below average performance for the first few months of operation
due to the low grade of bitumen in the oil sands.
Figure 9. Overview of an oil sands mines during the opening cut phase. Source: Oil sands
magazine, 2015 .
Mine out the oil sands following the mine plan: the sequence and sections of mine to be excavated
are outlined in a mine plan provided by geologists in order to ensure constant bitumen input and
optimal performances of the plant. Mining continues until the pit is depleted or become
uneconomical.
Backfill the mined out pit: once the pit is mined out, the empty pit is backfilled with tailings,
overburden and waste material that was excavated out of the mine.
Reclaim the mine site: once the mine is backfilled, it needs by law to be reclaimed. Reclamation
is completed when the area is capable of sustaining wildlife or vegetation.
Figure 10. Former oil sands mine backfilled and reclaimed. Source: Oil sands magazine, 2015.
Ore Preparation Plant
Oil sands is haul from the mine to the Ore Preparation Plant (OPP). OPP is the first step in any Bitumen
Production facility. Here mined oil sands ore are crushed and mixed with hot water to form a slurry that
is pumped to the processing plant. A correct functionality of the OPP is of fundamental importance for
bitumen extraction (Oil sands magazine, 2015):
Large debris are removed in the OPP stage. These materials can damage downstream equipment.
The oil sands are crushed to make more effective the blending with water.
The mixing of hot water with oil sands ore allows the slurry mixture to aerate and entrain air
bubbles. These air bubbles then attach on the surface of the liberate bitumen particles allowing
the separation by gravity with sand. In addition to hot water, it is also used caustic soda in order
to increase the PH of the slurry facilitating the following separation process.
Extraction
The slurry is transported through pipelines to the Bitumen Extraction facility. Here, primary separation
occurs. The slurries goes through a separation frothing process. Injection air forms tiny bubbles that
separate bitumen from sand. Sand and water are settled at the bottom, while tiny air bubbles trapped in
the bitumen cause it to form into froth and rise to the surface, where it is skimmed out and diluted.
Figure 11. Gravity separation of oil sands slurry. Source: Oil sands magazine, 2015.
The objectives of the Bitumen Extraction facility are (Oil sands magazine, 2015):
Maximize the recovery of bitumen;
Produce a good quality bitumen, minimizing fines and water content;
Sent as much of the solids as possible to the tailings plant.
The froth separated has a lot of impurities. The composition is only 50 to 60% bitumen with water up to
30% and 10% of fine solids (Oil sands magazine, 2015). This low quality froth is further processed.
Water and fine solids are removed using a solvent. The solvent used is a light hydrocarbon that reduces
the viscosity of the bitumen and enables a gravity separation of the various phases in the froth. The final
product is a good quality bitumen that can be sent to an upgrader for conversion to Synthetic Crude Oil
and then sent to refineries to obtain marketable products.
Bitumen is too viscous to flow through pipelines. Pipeline users dilute bitumen with a hydrocarbon
solvent (usually refinery naphtha) before it could be transported. Once mixed with a hydrocarbon diluent
is sent to upgrading (Oil sands magazine, 2015).
Tailings ponds
Tailing ponds or tailing storage facilities are made up of:
water and sand from the Bitumen Extraction facilities;
residual hydrocarbons and fine clays from froth separation;
unrecovered bitumen;
Tailings streams are normally about 50% water (Oil sands magazine, 2015). Tailings are the leftover
liquid mixture of mostly water and clay, some sand and residual oil.
Tailings ponds are large engineered dam and dyke systems designed for store tailings. These large
volume of water cannot be readily returned to the environment because of suspended clay particles, heavy
metals and other contaminants. While sand can be easily separated by gravity and recycled for backfill
the mined out areas. Tailings ponds are harmful, since they contain chemicals that are present in the oil
sands and solvents used in the extraction process. There is also always some residual oil floating the
surface of the pond. For these reasons tailings ponds are dangerous for wildlife, and have to be provided
by wildlife deterrent systems.
Tailings ponds act as a settling basin. Once the solids have settled, clarified water is recovered and
recycled back to the processing plant for reuse. Tailings ponds are considered temporary storage
facilities. The solids in the ponds are returned to the mine site to rebuild the mined out areas.
Tailings ponds are built using compacted clay. Clay has low permeability rate which helps prevent water
leachate into the groundwater. Furthermore, vertical water pumps are installed around the tailings dyke.
These wells serve to monitor the quality of the groundwater. The leachate are pumped back into the
tailings pond (Oil sands magazine, 2015).
Figure 12. Oil sands water storage facilities. Source: Oil sands magazine, 2015.
Reclamation
By law all mines must be fully reclaimed. Reclamation process begin in mined out areas while mining
continues in other areas. The replaced topsoil has muskeg peat and plant seeds, so that the re-growth can
begin. Native plant and grasses are used to recreate productive landscapes. The first government
reclamation certificate for an oil sands mine was issued in 2008 (Canada’s oil sands, 2016). Furthermore,
tailings ponds have to be reclaimed. Re-vegetation of tailing ponds has proved difficulties. The sand is
sterile having been subjected to boiling and with a high concentration of chemicals and solvent.
Figure 13. Oil sands mining trucks and shovels. Photo courtesy: Caterpillar
IN SITU DRILLING
80% of Alberta’s oil sand reserves are too deep to be mined, so they are recovered in situ (in place) by
drilling wells (Oil sands magazine, 2016). This techniques recover oil from unconsolidated oil sands
within the earth. All of the in situ technologies are based on concepts originally developed for recovery
in conventional oil field. An in situ technology methods is not suitable for all geological conditions.
What works in a deposit, may not work in another deposit.
An in situ commercial facilities consists of the following operations (Oil sands magazine, 2015):
A series of well are drilled throughout the oil sands deposit;
A steam and power generation plant , which provides power for the facility and high-pressure
steam for injection into the wells;
A central processing plant, where bitumen and water emulsion produced at the injection wells are
separated;
A water treatment plant , where the recovered water is cleaned and recycled back into the process;
A bitumen storage facilities, where bitumen is diluted with a hydrocarbon solvent for
transportation via pipeline to the upgrading and/or refining plant.
A commercial project operates almost 20 years. From a geological point of view obstacles are from the
geometry of the reservoir sand bodies. Internal discontinuities and permeability barriers in the reservoir
control the pattern of bitumen. In situ methods depend on the resolution of two main issues:
Reducing the viscosity of the bitumen;
Recovering the bitumen from deep within the earth.
These challenges are overcame using energy and water. In situ methods are more expensive respect
to mining, but are smaller and simpler plant than a mining bitumen production plant. In situ techniques
are different depending on the flowing capacity of bitumen. Recovering methods are divided in thermal
recovery and non-thermal recovery. In situ production involves only the mobilization of the target
product, while sand remains in the place.
In thermal recovery, indirect heating is employed for winning bitumen from formations of oil
sands. Thermal recovery methods require to heat hydrocarbons so as to reduce their viscosity sufficiently
to cause mobility. Thus, a heat transfer from a heat source to the heavy oils is required. The principal and
more efficient method of heat transfer is convection (U.S. Patent No 3,338,306, 1967). Convection has
economic efficiency in transferring heat energy underground from a source to the heavy oil to reduce its
viscosity. As temperature is raised to 150° C, bitumen is fluid enough to flow through the pore holes in
the earth and be pumped to the surface through recovery wells.
Projects that have been conducted to date are based on steam, hot water or combustion. Advances
in technology, such as directional drilling, enable in situ operations to drill multiple wells (sometimes
more than 20) from a single location, further reducing surface disturbance.
Thermal in situ recovery are:
Steam Assisted Gravity Drainage (SAGD): the majority of the in situ operations use SAGD
recovery. It is a well-recognized and proven commercial in situ thermal recovery process. Two
horizontal wells are drilled five meter apart, one above the other. SAGD uses directional drilling
technology, which let to drill wells also in the horizontal direction. Well depth can be up to 450
meters, while the horizontal length of a well can be 1000 meters long. Steam at high pressure is
injected into the upper well and into the oil sands through the steam injection well. Heat mobilizes
the bitumen allowing it to flow to the production well located beneath the steam injection well.
Bitumen along with condensed water from the steam then flows to the surface. The bitumen is
sent to a central process facility by an above ground pipeline, where water gas and impurities are
removed before the product is shipped to the upgrader. More than the 90 per cent of water is
recycled and reused in the process (Oil sands magazine, 2015).
Figure 14. SAGD recovery methods. Source: RAMP, 2016.
Cyclic Steam Stimulation (CSS): CSS is also known as steam soak. It is a form of well stimulation
that heats the reservoir by periodically injecting steam into a production well for a period of weeks
to months. The high pressure steam injected fractures the oil sands deposit. Furthermore, heat is
injected to reduce oil viscosity. This injection continues until the reservoir is fully saturated. Then
soak phase starts, the well is closed allowing the heat to penetrate a considerable zone around the
well. Following the well is put on production to pump off the bitumen that has become mobile.
Each cycle of this process can take from four months to four years, and several cycles can be
completed in a formation. Water is treated and recycled back into the process at the processing
plant. Bitumen is sent to an upgrader for further processing. Recently directional drilling has been
applied also to CSS allowing a less surface disturbance (Oil sands magazine, 2015).
Figure 15. CSS recovery stages. Source: Canada’s oil sands, 2016.
Toe to Hell Air Injection (THAI): THAI is still in its infancy, but very promising. This method is
a new combustion process that combines a vertical air injection well with a horizontal production
well. First, steam is pumped down to the vertical well to heat the bitumen beneath the surface.
When the reservoir reaches a certain temperature, air is injected down through the vertical well.
Here, bitumen auto ignites. Air is supplied continuously to keep the combustion going. A portion
of bitumen is consumed in the combustion zone. Bitumen outside the combustion zone is
mobilized and is moved toward the recovery well. The recovery well pump to the surface
bitumen. By burning the bitumen underground, THAI creates an upgraded crude oil. It also saves
on steam and on energy use as noted by the company Petrobank Energy and Resources Ltd.
According to Petrobank THAI can be used in area where CSS and SAGD cannot (The Oil Drum,
2007).
Figure 16. THAI well. Source: Petrobank Energy and resources Ltd.
A small number of in situ methods are based on non-thermal processes. Non-thermal recovery is applied
when the flux of bitumen does not require heat.
Cold production: cold production can be used in areas of the reservoir where the heavy oil is
mobile enough to be pumped to the surface without the use of steam. The cold production concept
uses long horizontal wells to pump the product to the surface without the use of heat.
BEST-Bitumen Extraction Solvent Technology: reduction of viscosity of bitumen is achieved
using an addition of diluents or emulsifier. Solvent can also be used for reservoir preconditioning
before a thermal process.
Once extracted the bitumen is diluted with a hydrocarbon solvent and is sent to an upgrading facilities.
Figure 17. In situ oil sands plants. Source: The oil sands project, 2016.
Open pit mine vs. in situ drilling
Advantages from in situ drilling are (Oil sands magazine, 2016):
Smaller land use: the surface area occupied by wellheads is smaller respect to the
mine areas.
Less water use: in situ facilities use water for steam production, which is mostly
recovered and recycled in the waste water processing plant. Open pit mine require
large amount of fresh water for the gravity water -based separation process.
No tailings ponds: in situ operations do not require tailings ponds, since much of
the sand is left in the ground.
Disadvantages from in situ drilling are (Oil sands magazine, 2016):
Lower bitumen recovery rates : recovery rate percentages of bitumen depend on the
method of extraction:
i. 20-40% from average world recovery of conventional oil (Muggeridge, 2014);
ii. Up to 35-40% bitumen using cyclic steam simulation;
iii. Up to 50-60% using steam assisted gravity drainage;
iv. Up to 75-80% using Toe to Hell Air Injection 5;
v. Up to 90% of bitumen from mining;
Great uncertainty: there is a degree of uncertainty in the positioning of the
wellheads and expected recovery rates.
Intensive exploration activities for the positioning of the extraction wells.
More GHG emissions: in situ extraction requires large volume of steam to heat the
bitumen in the ground. This steam is produced mainly burning natural gas. In situ
extraction generates more GHG emissions per barrel of bitumen produced respect to
mining.
UPGRADING
Bitumen recovered from the oil sands is a mixture of heavy hydrocarbons and contains impurities of
water and solid particles and trace metals. These compounds cannot be handled by conventional
refineries (Oil sands magazine, 2015). Bitumen before needs to be upgraded.
Upgrading is the process of separating the components of bitumen into different petroleum products for
further processing. Synthetic Crude Oil (SCO) is the main product of upgrading. SCO is usually low
sulfur and contains no residue or very heavy components and can be refined into commercial products.
Upgrading uses temperature, pressure and catalyst to crack the big molecules of bitumen into smaller
ones. Adding hydrogen and removing carbon from oil creates hydrocarbon molecules like those in light
oil. Upgraded oil is used as a replacement for conventional crude oil to make marketable products such
as gasoline, fuel oil, ethylene and propylene. Different combinations or variations of these processes are
used by different companies to produce the desired end product. Upgrading is usually divided in two
main stage processes (Oil sands magazine, 2015):
5 Nowadays THAI technology is not at the commercial scale, it is present only in pilot plants.
Coking or hydrocracking: the bitumen is separated from the diluent-naphtha, which is sent back
to the extraction facilities and reused. While, bitumen is transported to the cooker unit. Here,
bitumen is heated to high temperatures. Heat breaks the long chain of carbon-carbon bonds.
Smaller molecules are formed. Hydrogen is added to stabilize the hydrocarbon molecules. The
superheated hydrocarbon vapors from the cooker units are sent to the fractionating tower where,
using different boiling points, vapor condenses into naphtha, kerosene and gas oil. Excess of
carbon, in the form of petroleum coke is a byproduct that is used as a fuel to generate the heat
needed for this process.
Hydrotreating: this process stabilize the oil adding hydrogen at high temperatures to the
unsaturated molecules. Moreover, hydrotreating remove impurities such as sulfur, nitrogen and
trace metals. The output is a mixture called Synthetic Crude Oil.
Currently about 50% of Alberta’s bitumen is upgraded to crude oil, the remaining 50% is diluted and is
sold directly to the market (Oil sands magazine, 2015). Bitumen from oil sands mine has to be
upgraded, while bitumen from in situ technology can also be sold to the market without
upgrading. SCO is sent to refineries through pipelines across the USA and Canada to be refined.
OIL SANDS IN THE WORLD Alberta is today the main producer of bitumen from oil sands. But, investments of different corporations
are expanding also in other countries.
The viability of a commercial oil sands operation does not only require the presence of an exploitable
deposit, but also a network of infrastructures. This network of infrastructures could be a challenge in
some areas. In general an oil sands project requires (Unconventional series, 2016):
Water;
Natural gas feed or an alternative energy source for the production of steam, hot water and
hydrogen;
Diluents and solvent for piping bitumen;
Pipes transportation system;
Large trucks, in the case bitumen is mined out.
VENEZUELA
Venezuela has the largest oil deposit on the planet. The vast Orinoco Heavy Oil Belt contains 300·109
barrels of recoverable oil with actual technology (USGS, 2012). In Venezuela operations for recovery
bitumen from oil sands are not developed as in Alberta. However, there are many similarities between
Alberta and Venezuela’s oil sands. There are not barriers for the implementation of Canadian technology
to Orinoco oil sands. Venezuelan deposits are located in a more favorable climate area without harsh
winters. The oil in Orinoco oil belt is more mobile, with thicker reservoir and higher permeability values
respect to Alberta’s oil sands. 88-92% of oil sands deposits is too deep to be mined out (Wykes, 2010).
The other 8-12% is mineable. For this reason mining is not implemented at a commercial scale, but could
be done in the future. Deposits in Venezuela are at higher temperature respect to Alberta. The higher
temperature improves the viscosity of oil and this means that it is easier to extract bitumen. Venezuela
unlike Alberta has not had resources to invest in oil sands extraction due to lack of capital and technical
skills.
The reservoir contains heavy oil with a range of API gravity from 4 to 16 degrees (USGS, 2010). This
oil has a high sulfur content and needs to be upgraded before refining. Oil sands in the Orinoco Belt are
largely unconsolidated sandstone. Unconsolidated means that reservoir have high porosity with no
significant grain to grain cementification. Nowadays, Venezuela extract heavy-oil with a technology
similar to in situ drilling for oil sands. This oil is the more profitable respect to extraction of bitumen
from oil sands, since requires less technology and less operating costs. However, investment in
exploration and in the creation of a network for oil sands extraction is ongoing.
Figure 18. Venezuela’s Orinoco heavy oil belt and concessions to different corporations. Source:
Caracaschronicles.com
USA
USA oil sands deposits are present in the following states: Alaska, Utah, Alabama, California, Texas,
Colorado, Wyoming, and Oklahoma (USGS, 1988).
Table 1. Location of the oil sands deposits by United States of America. The reserves are expressed
in known reserves, while the recoverable reserves with the actual technology is unknown. As a rule of
thumb 10% of the reserves could be recoverable using Canadian technology. Source: USGS, 1988.
State Proved reserves
(Barrels)
Utah 18.7·109
Alaska 15·109
Alabama 6.4·109
Texas 4.9·109
California 4.5·109
Kentucky 3.4·109
Oklahoma 0.8·109
New Mexico 0.35·109
Wyoming 0.15·109
Diffusion of oil sand industries in USA have many obstacles including:
Remote and difficult topography of oil sand deposits;
USA oil sand deposits are more scattered and smaller respect to Alberta or Venezuela’s deposits;
Deposits are present mainly in regions with lack of water.
All these have resulted in an uneconomic oil resource. However, many companies are significant
investing in R&D to bring oil sands extraction at the commercial scale in the USA (Humphries, 2008).
Any recovery of oil sands in USA can be mainly done using mine technique (USGS, 1988).
Nowadays, exploration is done almost in every of these state. While, extraction is done in California and
Utah. There are some in situ extraction facilities of extra-heavy-oil in California in the Pleasant Valley.
The production is of about 1000 barrels per day (Try Valley Corp, 2016). In the state of Utah there are
more than half of the USA oil sand deposits (U.S. Oil Sands, 2015). The deposits are located in the area
of Uinta Basin in the Eastern Utah. This region rich of oil and natural gas has been exploited for decades
also for the extraction of conventional oil and natural gas. Hence, the implementation of oil sands
extraction at a commercial scale will be supported by the network of infrastructures constructed from
conventional oil and gas fields.
The Uinta Basin was formed about 66 millions of year ago. Oil shale and oil sands nowadays present
were formed with the following geological process. Sediments eroded from high mountains that at that
time surrounded the Uinta Basin, flowed into Lake Uinta. This formed a sequence of organic-rich shale
and sandstone. Bitumen resources are present in Green River formation which is composed by oil sands
and oil shale. Here, bitumen is not present as a continuous layer, but is present with lenticular beds with
a bitumen saturation up to 16% w/w (U.S. Oil Sands, 2016). Utah’s bitumen is of higher quality respect
to Alberta’s bitumen, since it is lighter and low sulfur content. The main advantage of Utah’s bitumen is
the proximity to the markets and the operating environment is not as complicated as in Alberta.
While Alberta’s oil sands are water-wet, Utah’s oil sands are oil-wet. This is of fundamental importance
for the separation process. Water-wet means that the sand grains are surrounded by water and then by
oil. In Utah, the sand grains are directly surrounded by oil. Hot water separation process is not effective
since gives low recovery rates of bitumen and leave a high amount of bitumen leftover. Bitumen
separation is achieved using a solvent.
Figure 19. An oil sands seep at a Utah’s oil sands mine. Photo credit: U.S. Argonne National
Laboratory.
A Canadian company, U.S. Oil Sands, in 2005 has leased an area of 130 km2 in the Uinta Basin. Since
2005 this company invested in developing a new extraction process suitable for Utah’s environmental
conditions in order to extract bitumen from mining operations. The deepest oil sands excavated is 200
meters. If it is too deep too much solids have to be mined. Another factor to make viable the extraction
is the bitumen content. In order to have an economical viable production, 14% w/w of bitumen content
is required (U.S. Oil Sands, 2015). U.S. Oil Sands patented an extraction process which doesn’t require
large amounts of water (U.S. Patent No. US20130062258 A1, 2014). The process produce bitumen and
dry tailings. The extraction process is based on the use of a solvent. The solvent is citrus base. 95% of
water and 98% of solvent are recycled and reused (U.S. Oil Sands, 2016). Nowadays, the production is
at the first stage of the commercial scale with a production of 2000 barrels of bitumen per day (U.S. Oil
Sands, 2016). This plant requires 1.5 barrels of water per barrels of bitumen produced (U.S. Oil Sands,
2015). Water used come from deep wells. However, this value of water does not account for water use
for crop citrus and for solvent production.
TRINIDAD & TOBAGO
Oil sands are located in South-west of Trinidad & Tobago. Deposit are too shallow for in situ recovery.
Deposits outcrops from the surface to 200 meters in depth (Petrotrin, 2011). Mining is required for the
vast majority of deposits. Bitumen has been mined on a small scale quarry for pavement, but no
conversion to oil is done at a commercial scale (Tar sands in T&T, 2010). Exploration and studies about
economic feasibility are done. Corporations are investing in order to create a network of infrastructures
needed for bitumen extraction, upgrading and refining (Tar sands in T&T, 2010). T&T is a region with
lack of freshwater. Water for processing will be provided by a desalination plant in construction, which
will convert water from ocean into fresh water. Furthermore, construction of an upgrader has been
proposed.
NIGERIA
Nigeria is well known for its conventional oil and natural gas fields. This country has also deposits of oil
sands. Starting from the 20th experiments has been done on Nigeria’s oil sands. In 2000 a Canadian
corporation operated exploration of Nigerian oil sands. Deposits are shallow. Hence, extraction could be
mainly done using mining operations.
REPUBLIC OF CONGO
There are two main oil sands deposits on Congo Basin near Brazzaville. Plan for extraction has been
proposed by Italian corporation ENI. The resources are deep in the range of 100 to 200 meters. Extraction
requires in situ technology to develop (Wykes, 2010).
DEMOCRATIC REPUBLIC OF CONGO
Deposit are present near Brazzaville along Congo River and the East part of the country near Uganda.
This country has also great reserves of shale oil. Mining of oil sands in the east part of the country has
taken place on a small scale for decades to produce asphalt. No extraction plans for oil sands or shale oil
are currently present. However, corporations are exploring these deposits (Wykes, 2010)
MAGADASCAR
There are two deposit of oil sands in Madagascar: Tsimiroro and Bemolanga. While Tsimiroro’s oil sands
can be recovered via in situ drilling, Bemolanga requires mining extraction. Bitumen is present with an
average content of 6% (Andrianasolo, 1987). Small level of production of bitumen are active. The aim
is to establish a bitumen production of 15000 barrels/day but the potentiality of a massive commercial
operation can be 100000 barrels/day (Andrianasolo, 1987). Recovery is done using hot water extraction
Canadian process. Bemolanga is one of the most arid part of the country. Tsimoro deposit is too deep for
mining. An in situ extraction facility is being built to achieve a production of 31500 barrels/day.
RUSSIA
Russia has four main deposits of oil sands. The largest is Tunguska in Siberia. This deposit has extensive
resources, the location in Siberia let this resources unrecoverable in the near future. The three other small
deposits are in the Caucasus: Volga-Ural, Timan-Pechora, and North Caucasus-Mangyshlak.
Corporations are experimenting feasibility of extraction both with in situ and mining techniques (Wykes,
2010).
METHODS Description and data
We assessed current and potential impacts of oil sand extraction in terms of forest loss, water use,
GHG emissions, and population potentially affected for the five countries – Canada, Venezuela, the
United States, Republic of Congo, and Madagascar – whose deposits account for 93% of the oil sand
deposits discovered worldwide. Alberta has the most extensive oil sand deposit, followed by Venezuela
(Table 2). However, Venezuela’s deposits are larger (in terms of recoverable heavy oil) than those of
Alberta (Table 3). These deposits have an area that is about 16% and 14% of the land areas of Alberta
and Venezuela, respectively. Madagascar, the Republic of Congo and Utah have deposit and concession
areas that are much smaller than those of Venezuela and Alberta. The oil sand deposits of Alberta and
the Republic of Congo occur in major primary forests that so far have undergone relatively low rates of
forest clearing (Potapov, 2008). In Venezuela heavy oil deposits are found in a region where forest
vegetation has been more heavily affected by human activities and land use change (e.g., forestry and
agriculture) (Vera, 2006), while the forest loss observed in Utah since the year 2000 was due to forest
fire (UtahFireInfo, 2016). In Madagascar no forest cover is present over concessions areas.
Table 2. Areas of oil sand deposits and concession areas. Forested area in year 2000 and net
forest changes over the five countries studied.
Area deposit (km2)
Forested area 2000
(km2)
Net forest change 2000-
2014 (%)
Canada 107,680 75,540 10
Venezuela 49,963 6,293 37
Rep. of Congo 1,800 1,732 8
Madagascar 352 no forest cover according to the classification used in this
study USA 2,953 292 26
Table 3. Oil sand deposits in the world. Actual production and projected production from
surface mining and in situ extraction (Alberta Oil sands industry, 2016), remaining oil in place
and proved oil reserves. Zero values are used for areas where no extraction is expected to occur;
missing data are reported as “-”. The deposit in Venezuela contains both oil sands and heavy oil, no
geological surveys have been done to define the boundaries of oil sand deposits.
Remaining oil in-place is the volume of oil within a formation before the start of production. Proved
reserves are volumes of oil that geologic and engineering data demonstrate with reasonable certainty to
be recoverable in future years under existing economic conditions and technology.
Production
surface mining (barrels/day)
Production in-situ
(barrels/day)
Projected production
(2025) surface mining
(barrels/day)
Projected production (2025) in-
situ (barrels/day)
Remaining oil in-place
(billion barrels)
Proved reserves (billion barrels)
Canada 1.38∙106 1.43∙106 1.84∙106 2.96∙106 315 175
Dem. Rep. of Congo 0 0 - - 0.30 0.03
Madagascar 1.5∙104 1.5∙104 1.8∙105 2.0∙105 200 25
Nigeria 0 0 - - 30 4
Rep. of Congo 0 0 0 3.00∙104 25 2.5
Russia 0 0 0 1.00∙105 245 34
Trinidad & Tobago 0 0 4.00∙104 0 2 1.50
USA 5.00∙103 0 3.50∙104 0 55 10
Venezuela 0 6.00∙105 0 2.10∙106 2500 300
Georeferenced data on the spatial extent of oil sand deposits and existing concession areas for oil
sands extraction were acquired from various government and private institutions and agencies. Data on
tree cover in the year 2000, annual forest loss between 2000 and 2015, and cumulative forest gain came
from a recent high resolution (30m) satellite-based dataset produced by Hansen et al. (2013).
Forest loss and fragmentation
Following Hansen et al. (2013), we defined forested pixels as areas with at least 50% vegetation
cover of 5 meters or higher. For oil sands areas where exploration and production have already started,
historical net changes in forest cover were calculated simply as the difference between cumulative forest
loss and cumulative forest gain. Potential forest losses were then calculated over entire deposit and
concession areas, assuming that the entire area is cleared in mining operations and that the clear area
needed for in situ extraction is the same as in the case of deposits that are currently under production in
Alberta (i.e., ≈ 6 % of the land area). This is because the removal of forest vegetation associated with
extraction technologies, exploration activities, and infrastructure construction (e.g., roads, pipelines) is
likely to be similar across regions in order for the enterprise to be globally competitive. Net forest change
(i.e., ((forest loss + gain)/forested area in year 2000) × 100), in Alberta was calculated separately for
operational mines and in-situ facilities. Because forest fires cause substantial forest loss in this region,
the effect of fire on deforestation was removed using Alberta’s historical spatial wildfire data (Alberta
Agriculture and Forestry, 2015), assuming that forest loss by fire would occur even in the absence of oil
sand extraction. Hansen forest maps was validated using the methods from Carlson et al. (2013) by
randomly selecting x points for each country or region considered. Points were classified as forested or
not forested area based on land cover maps. We generated confusion matrices to calculate accuracy (po),
the proportion of the total number of predictions that were correct, and the kappa coefficient (k), which
takes into account the agreement occurring by chance, from a total of y validation points. The comparison
yielded to the results shown in Table 4.
Table 4. Validation of forest map for Alberta, Venezuela, Republic of Congo and Utah. Using x
randomly selected points for each country or state we calculated accuracy (po) and kappa coefficient (k)
from a total of y validation points.
Validation for Utah has been done removing tree classes of Junipers and Pinyon since they are less than
five meters high. For Alberta the kappa value is not so high since the land cover map used has as
definition of forest a treed areas with at least a 10% ground cover of trees.
Source of land cover map used po k x y
Alberta A.B.M.I., 2000 0.66 0.42 1500 732
Venezuela Arino, 2010 0.85 0.69 1500 761
Rep. of Congo Arino, 2010 0.72 0.45 1500 726
Utah USGS, 2004 0.95 0.67 1500 142
Forest fragmentation was assessed over the deposits and concessions designated as in situ
exploration and extraction areas (Alberta, Venezuela, and Republic of Congo) following the approach
by Vogt et al. (2007). Using binary land cover maps, this methodology classified each pixel of the area
of interest into one of four forest cover categories - core, patch, perforation, or edge. Cores were defined
as forested pixels having all adjacent pixels as forested. Core pixels were also further classified into 3
sub-categories, based on the size of the contiguous forest core they belong to (<100 ha, 100 ha to 200 ha,
or >200 ha). Patches were defined as forested pixels not containing core forest pixels. Edges were defined
as forested pixels having at least one adjacent non-forested pixel. Perforations were defined as edge
pixels surrounding a non-forested area with a maximum width of 100 m.
To summarize the extent of fragmentation within an area, we used a composite fragmentation index
(CFI), defined as the ratio between the sum of number of pixels classified as “edges”, “perforated”,
“patches”, or smaller core areas (i.e., those <200 ha), and the total number of pixels in that area. CFI
varies between 0 and 1; CFI=1 in areas with extremely fragmented forest cover, while CFI=0 in areas
with no fragmented forest cores or no forest cover at all. Changes in fragmentation between 2000 and
2014 were expressed in terms of two indices, namely, CCFI (changes in CFI) and CPFI (changes in the
number of patch pixels).
Water footprint of extraction
To calculate the amount of water used to extract and treat one liter of mined bitumen, we considered
the amount of water required to attain the two process target densities starting from mined oil sand ore.
Details about the calculations of water use for extraction and preparation can be found in Figure 20 and
Figure 21. The typical composition of mined oil sand ore is reported in Table 5.
Table 5. Typical composition and density of mined oil sands. Source: Oil sands magazine, 2016.
We calculated the recoverable bitumen (𝑏𝑟𝑒𝑐%) from 1 m3 of mined oil sands ore according to the
Alberta Energy Regulator Directive 082 formula (Alberta Energy Regulator, 2013) (Alberta Energy
Regulator, 2013):
𝑏𝑟𝑒𝑐(%) = −202.7 + 54.1 ∙ 𝑤𝑡% − 2.5 ∙ 𝑤𝑡%2
where wt% is the average bitumen content, that ranges from 8% to 12% (Oil sands magazine, 2015),
of the mined oil sands ore reported as weight percent.
In Alberta 78% of mined oil sands were also upgraded in year 2015, a process requiring additional
water. Data on upgrading water requirements are sparse, but detailed values have been reported by one
of the upgraders – Scotford Upgrader – involved in the treatment of bitumen from Alberta’s oil sands
(Canada Patent number 2004352). In this study we assumed that all other upgraders used roughly same
amount of water per liter of Synthetic Crude Oil (SCO), the product of upgrading from bitumen.
Estimates of the total amount of water needed to treat mined oil sands are based on data of production
from mines and upgrading facilities in 2015 (Table 6, 7).
Composition [% v/v]
Density [kg/m3]
Water 5 1000 Sand 85 2650
Bitumen 10 1050
Table 6. Barrels of bitumen produced per day from Alberta’s oil sands mine facilities in 2015.
Source: Oil sands magazine, 2016.
Project name (Company) BarrelsBitumen/day
Horizon (Canadian Natural Resources LTD) 1.52·105 Kearl (Imperial Oil) 1.10·105
Kearl Expansion (Imperial oil) 1.10·105 Muskeg (Shell Canada) 1.55·105 Jackpine (Shell Canada) 1.00·105
Steepbank (Suncor Energy) 1.50·105 Millenium (Suncor Energy) 1.80·105 Mildred Lake (Syncrude) 2.00·105
Aurora North (Syncrude) 2.25·105 Total 1.38·106
Table 7. Barrels of Synthetic Crude Oil produced from Alberta’s upgraders in 2015. Source:
Alberta Oil Sands Industry, 2016.
Upgrader (Company) BarrelsSCO/day
Horizon (Canadian Natural Resources) 1.27·105 Millennium (Suncor Energy) 3.57·105
Mildred Lake (Syncrude) 3.50·105 Scotford Upgrader (Shell) 2.55·105
Total 1.09·106
The volume of water used to produce one liter of bitumen from in situ operations was calculated
using data from annual facility performances expressed in terms of steam to oil ratio (m3 water / m3
produced bitumen) (Alberta Energy Regulator, 2015; Oil sands magazine, 2016)(Table 8). In situ plant
performances are measured through steam to oil ratio (SOR). SOR is a measure of how efficiently energy
is used in bitumen recovery from oil sands. SOR is the volume of water transformed into steam required
to produce one cubic meter of bitumen (Alberta Energy, 2016). The lower the SOR value the higher the
efficiency of water and energy usage.
Table 8. Data for each in situ operating project in terms of barrel of bitumen produced per day,
Steam to Oil Ratio and technology of extraction used in year 2015.
Commercial operating facilities use Steam Assisted Gravity Drainage (SAGD) and Cyclic Steam
Simulation (CSS) extraction technologies. In situ plant performances are measured through Steam to Oil
Ratio (SOR). SOR is a measure of how efficiently energy is used in bitumen recovery from oil sands.
SOR is the volume of water transformed into steam required to produce one cubic meter of bitumen
(Alberta Energy, 2016). The lower the SOR value the higher the efficiency of water and energy usage.
Source: Alberta Energy Regulator, 2015; Oil sands magazine, 2016.
Project name (company) Production
(BarrelsBitumen/day) SOR
(m3Water/m3
bitumen) Techology
Cold Lake (Imperial Oil) 1.80·105 3.40 CSS
Wolf lake (Canadian Natural Resources) 0.13·105 3.90 CSS Primrose (Canadian Natural Resources) 1.07·105 3.90 CSS
Christina lake (Cenovus) 2.10·105 1.70 SAGD Foster creek (Cenovus) 1.50·105 2.50 SAGD
Long lake (CNOOC) 0.92·105 4.10 SAGD Great Divide ( Connacher) 0.20·105 4.50 SAGD Surmont (ConocoPhillips) 1.49·105 2.50 SAGD Jackfish (Devon Energy) 1.05·105 2.00 SAGD Sunrise (Husky Energy) 0.60·105 3.00 SAGD
Kirby South (Canadian Natural Resources) 0.40·105 2.50 SAGD Christina lake (Meg Energy) 0.60·105 2.50 SAGD
Firebag (Suncor) 1.80·105 2.70 SAGD MacKay river (Suncor) 0.38·105 3.00 SAGD
Leismer (Statoil) 0.20·105 2.97 SAGD Total 1.43·106
20% of the water used in the processes is new fresh water, while the other 80% is recycled (Wu,
2009; Jacobs Consultancy, 2012; Oil sands magazine, 2016). To convert from barrels of bitumen to cubic
meters of bitumen, we considered an API gravity of bitumen equal to 8°.
Similar to our calculations for potential forest loss, the potential water use for oil sands extraction
and processing in deposits that are not yet under production was estimated assuming that the technology
currently used in Alberta will be adopted also in the other regions. Rates of actual and projected
production of major oil sand deposits in the world are in Table 3. In the calculation of water use the
projected production rates are multiplied by the water footprint of bitumen extraction and processing
determined for Alberta.
Net water consumption from mining and in situ was assessed considering that 80% of the total
water footprint is recycled, and adding the water required to upgrade and refine bitumen.
Assessing other impacts
GHG emissions from oil sands extraction were calculated considering projected production rates
of bitumen from in situ or mine operations (Table 3), assuming an 80% bitumen yield to SCO (Canada
Patent number CN 105339469 A) and using for mine and in situ the mean values of GHG emissions
provided by a previous study (Charpentier, 2009). The number of people potentially affected was
assessed using data on population distribution taken from CIESIN’s Gridded Population of the World
map (GPWv4) for the year 2010 and calculating the number of people living within the perimeters of oil
sand deposits and concessions. Water stress areas were assessed overlaying the five oil sands deposit and
concessions areas with a water depletion map Brauman et al. (2016). Water depletion was calculated as
the fraction of renewable water consumptively used for human activities.
ENVIRONMENTAL IMPACTS OF OIL SANDS PRODUCTION The total water footprint of bitumen extraction and processing from oil sand deposits in Alberta
differed greatly depending on the extraction method. We found that 2.8 liters of water were required to
obtain a liter of bitumen using in situ drilling.
Figure 20. Volume of water required to extract 1 barrel of bitumen from in-situ drilling. 1 barrel
=0.159 m3
Bitumen that is too deep to be mined is extracted using thermal in-situ technologies. In-situ facilities
use horizontal drilling technology. High pressure and temperature steam is injected into the reservoir to
reduce bitumen viscosity. An emulsion of bitumen and condensed steam (produced water) is pumped
out to the ground surface. Approximately 10% of the injected steam is retained into the reservoir and
another 10% of steam is disposed or lost in disposal and blowdown processes at the cogeneration
power plant (Jacobs Consultancy, 2012). Make-up fresh water is required to compensate these losses
and maintain the water balance required by this process. This water is usually withdrawn from fresh or
saline groundwater reservoirs. Water from saline aquifers has to be transformed into fresh water
(desalination) before it can be used in this process.
Conversely, the water footprint of surface mining was 28.5 l H2O per l bitumen. Net fresh water
consumed is the 20% of the total water footprint, since the 80% was recycled in both extraction methods
recycled (Wu, 2009; Jacobs Consultancy, 2012; Oil sands magazine, 2016). Where information was
available, these values agreed well with previous studies that determined the net water footprint of
bitumen extraction (Wu, 2009; World Energy Outlook 2012, 2012).
Figure 21. Volume of water required to extract 1 barrel of bitumen from mined oil sands in
Canada. 1 barrel =0.159 m3
Oil sands close to the ground surface (<75m in depth) are mined (Oil sands magazine, 2016). Bitumen
is extracted from mined oil sands using a water intensive process known as hot water extraction (Oil
sands magazine, 2016). First, at the slurry preparation plant water is added to the mined oil sand ore to
obtain a slurry with a density of 1500 kg/m3 (Oil sands magazine, 2016). Second, the produced slurry
is sent to the bitumen extraction plant, where more water is added to reach a density of 1400 kg/m3
(Oil sands magazine, 2016). Bitumen is separated by gravity from tailings. Bitumen is usually
upgraded into Synthetic Crude Oil (SCO) before being sent to refineries. Tailings are one of the by-
products from mining operations. They are made of water, sand, clay, left-over bitumen and trace
amounts of chemicals used in the extraction process. Tailings are stored in large dykes named tailing
ponds from 3 to 5 years (Government of Alberta, 2011). In 2013 the tailing pond area in Alberta was
about 220 km2 with a volume of fine fluid tailings stored of 0.975 km (Alberta Environment and Parks,
2015). Approximately 80% of water used in the extraction process is recycled. The other 20% of water
is freshwater withdrawn from Athabasca River.
Where information was available, these values agreed well with previous studies that determined the net
water footprint of bitumen extraction (Wu, 2009; IEA, 2012). At current rates of production, we estimate
that extraction from Canadian oil sands requires 0.49 km3 H2O yr-1.
Figure 22. Forest fire in Alberta from 2000 to 2014. The boxed area in the main map are shown in
the corresponding local map to the right.
About 1476 km2 of Alberta’s forests – 15% of forests covering Alberta’s oil sands concession areas
in year 2000 – have been removed since the start of the century. In addition 6% of “natural” forest loss
is due to fire (unrelated to extraction activities) in oil sand concession areas since the beginning of the
century. Forest fragmentation has also increased – both in terms of cumulative fragmentation index (CFI,
the areal fraction of sites located at the edges of forested areas, small forest patches, and smaller forest
cores; see Methods) and in the number of forest patches. This is especially true for in situ operations
where CFI and the number of forest patches increased by 7% and 81%, respectively, since the year 2000.
It should also be noted that our estimate of forest loss for in situ concessions is likely conservative as
typical exploration lines are 4 meters wide– narrower than the 30m resolution of the dataset (Hansen,
2013) – with 60 meters spacing between lines (Figure 23, 24).
Figure 23. Exploration seismic lines used for in situ extraction in Alberta. It is also visible a typical
configuration of an in situ extraction facilities. Source: Google Earth, 2016.
Figure 24. Exploration seismic lines used for in situ extraction in Venezuela over Orinoco Heavy
Oil Belt area. Source: Google Earth, 2016.
While multiple environmental impacts are apparent, there have however been substantial
economic benefits with affordable and secure energy to U.S. and Canadian market, more than 478,000
jobs created in Canada in year 2012 (3% of all jobs in the country) (PetroLMI, 2016), and tax revenues
and royalties paid to the governments (Exxon Mobil, 2016). Thus there are clear and ongoing tradeoffs
between economic development, energy, and the environment.
The effect of oil sand extraction from undeveloped deposits in Alberta and other study countries
was estimated assuming that the water use and the land footprint (i.e., fraction of deposit area that needs
to be clear of vegetation) of mining or drilling operations were the same as those calculated for
operational concessions in Alberta (Table 9).
Table 9. Impacts from oil sands extraction and processing in Alberta: in-situ versus surface
mining impacts on water, forest loss, GHG emissions (in mass of equivalent CO2 per barrel of
Synthetic Crude Oil, SCO), and number of jobs directly created by the oil sand industry.
Surface mining In-situ drilling Source
Water (l water / l bitumen) 28.52 2.77 This study
Net forest loss (%) 100 6 This study
GHG emissions (kg CO2eq/barrel SCO) 113 138 Charpentier (2009)
Direct job creation (#workers) 14,750 11,274 PetroLMI (2016)
The impact on water resources and forest cover was then evaluated using site specific water stress and
forest cover data (see Methods Section). We estimate that full exploitation of oil sands deposits will
have profound environmental consequences, with the greatest impacts by far expected in Canada and
Venezuela (Table 10).
Table 10. Future potential impacts from extraction and processing of oil sands. Only relatively
shallow deposits can be mined, while bitumen extraction from deeper deposits requires in situ
technology. In Alberta only 4.5% of the deposit area is mineable, while in Venezuela mining can
potentially take place in 12% of the deposit area. Deposits in Rep. of Congo are too deep to be mined,
while Utah has only shallow deposits. In Madagascar 50% of the deposit is mineable and the other 50%
is suitable for in situ extraction.
Actual water stress over oil sand deposits expressed as in Brauman et al. (2016). Water depletion is
calculated as the fraction of renewable water consumptively used for human activities.
Country
(source)
GHG emissions
(Mtonne CO2 eq yr-1)
Freshwater use
(km3 yr-1)
Deforestation
(km2)
Population
potentially affected
Actual water
stress
Canada actual
(Alberta Environment and
Parks, 2015)
102.81 0.486 1,476
696 <5%
Canada potential
(Alberta Energy Regulator,
2016; ArcGIS, 2014)
179.35 0.680 7,482 162,000 <5%
Venezuela potential
(acknowledgements)
84.32 0.065 871 455,916 <5%
Rep. of Congo potential
(Global Forest Watch, 2016)
1.20 0.001 97 20,476 <5%
Madagascar potential
(acknowledgements)
13.97 0.064 - 1,796 <5%
USA (Utah) potential
(USGS, 2005)
1.15 0.011 215 59 Dry year
Specifically, cumulative forest loss across these studied oil sand deposits (Figure 25, 26, 27, 30)
may eventually reach 8,665 km2, an area equal to 5% of global forest loss in the year 2014 (Hansen,
2013). In addition, fresh water use may nearly triple to 1.31 km3 H2O yr-1 with important impacts on the
local freshwater resources, as the case of Utah where the deposits are located in a potentially water-
stressed areas. Moreover, projected annual GHG emissions (383 Mtonne CO2 eq yr-1) – due in large part
to growth in energy-intensive in situ production – would be commensurate with those from land use and
land cover change for all of Indonesia (Carlson, 2013), and as many as many as 640,000 people could
potentially be affected by the complete development of these five world’s oil sands deposits (Table 10).
Figure 25. Map of forest cover, forest loss, oil sand concession boundaries in year 2013 and deposits
in Alberta. The boxed area in the main map are shown in the corresponding local map to the right. Map
1 shows the typical forest loss over an oil sand mining area; map 2 shows forest loss and fragmentation
over situ drilling extraction areas. In-situ concession areas exhibit also a massive network of exploration
lines (with a typical width of 4 meters) that cannot be detected by the 30m resolution forest cover dataset
used in this study. Source: Alberta Environment and Parks, 2015; Alberta Energy Regulator, 2016;
ArcGIS, 2014.
Figure 26. Map of forest cover, forest loss and oil sand deposits in Venezuela. The boxed area shows
the typical trend of exploration lines over an oil sands area suitable for in situ drilling extraction.
Figure 27. Map of forest cover, forest loss and oil sand concessions in Republic of Congo. Source:
Global Forest Watch, 2016
Figure 28 Oil sand concessions in Madagascar. No forest is present inside the concession areas
according to the methods used in this study.
Figure 29. Madagascar's concessions areas.
Figure 30. Map of forest cover, forest loss over oil sand deposits in Utah. Source: USGS, 2005.
TRADEOFFS BETWEEN ECONOMY, ENERGY, AND THE ENVIRONMENT In Alberta the amount of water required to extract and process bitumen from oil sands is of the
same order of magnitude as the province’s water consumption for irrigated agriculture. Thus, it can be
argued that in this state the oil sand industry was able to develop because the region is relatively rich of
water resources. The projected growth by 2025 in oil sand production is expected to lead to a 40%
increase in freshwater appropriations by oil sand operations. This could threaten Alberta’s water
resources, with important ecological and societal impacts, especially in the Athabasca watershed, where
most of the deposits and production are located. The development of oil sand extraction in countries with
drier climates is expected to exert a stronger pressure on the local water resources, likely competing with
other water uses such as crop production and flows for aquatic ecosystems. Thus the increasing reliance
on oil sand extraction may raise new water security concerns in countries where deposits are located in
water stressed watersheds (Utah), thereby further sustaining ongoing debates on competing water uses
within the context of the water-energy nexus (Rulli, 2016).
This study demonstrates that mining operations and in situ drilling differ significantly in their
environmental impacts. While in-situ technology is more energy intensive, the process requires less
water, does not produce tailings, and has less extensive impacts on overall forest cover. For in situ
concessions, forest loss tends to be more scattered, limited to areas of intensive exploration activities for
the positioning of the extraction wells, and construction of infrastructures (e.g., roads, pipelines). Even
though in-situ drilling entails a smaller net change in forest cover than surface mining, its impact on
wildlife habitat and landscape fragmentation should not be underappreciated. Conversely, forest
vegetation is completely cleared within mining operations. In addition, while oil sand extraction is not
expected to displace a large number of people – as these deposits are located in remote forested areas –
these operations are likely to have important impacts on carbon sequestration, because of carbon
emissions associated with land use change and deforestation. Overall, in situ drilling is more expensive
(Muggeridge, 2014) and has less environmental impacts in terms of water use and forest loss; however
it requires more energy and has a bitumen recovery rate lower than mining (up to 60% for in situ vs. 90%
for mining) (Oil sands magazine, 2015). For this reason the current trend, with low oil price, is to increase
mining production instead of in situ extraction (PetroLMI, 2016). This choice, likely driven by economic
factors, is in disagreement with the previous trend of increasing investments in situ production
(PetroLMI, 2016) and does not account for the big difference in environmental impacts highlighted by
this study.
Ongoing technological innovation is trying to reduce the environmental impacts of oil sands
production. GHG emissions per barrel have already decreased by 25-40% in the last 25 years (The Oxford
Institute for Energy studies, 2016). Nevertheless, oil sand extraction and processing still requires a large
amount of energy, which corresponds to emitting about three times more GHGs than the production of
conventional oil. The water required to upgrade bitumen has decreased by 40% since 2005 (Table 11).
Likewise, the amount of water needed to extract bitumen using in situ techniques has, while we found
that more water is required to win bitumen from mined oil sands than what was reported by previous
studies. Our results show that the gasoline produced from secondary conventional oil recovery techniques
(i.e., water flooding) requires almost the same amount of water used to produce gasoline from mined oil
sands.
Progress in technology, proximity to the markets and high prices of crude oil have favored the
proliferation of the oil sand industry in Alberta. Though this study has focused on the major
environmental impacts of oil sand extraction, this source of energy also offers some advantages compared
to conventional oil. First, the recovery rate of bitumen from oil sands is greater than for conventional oil.
The average recovery rates for conventional oil range from 20 to 40% of the deposit, while the recovery
rate of bitumen from oil sand extraction varies from 50-60% (in-situ drilling) to 90% (surface mining)
(Oil sands magazine, 2016; Muggeridge, 2014)). Second, oil sand deposits decline more slowly (4%
decline per year) than those of conventional oil (20% per year), allowing these deposits to last longer
(e.g., 30 years in the case of Alberta) (Oil sands magazine, 2016). Because of their long lifespan, oil sand
deposits are drawing increasing interest and investments from oil and gas corporations. Moreover, oil
sand industries have led to considerable job creation. For example, in 2012, the oil sands industry in
Canada and U.S. employed – directly and indirectly – almost 558,000 people (80,000 in U.S.) (IHS
CERA, 2014; Canadian Energy Research Institute, 2011). Employment is expected to grow in the most
positive scenario of oil sands development to 2.2 million jobs in the U.S. and Canada by 2035 (Canadian
Energy Research Institute, 2011). By 2020 direct job creation in the oil sand industry in Alberta is
expected to add about 5,170 new jobs to the existing workforce for a total of 35,070 (PetroLMI, 2016).
As a result of this oil sands ‘boom’, Alberta has become one of the richest regions in the world, with a
GDP per capita in year 2014 (91,000 U.S. dollar) among the top five countries in the world (Alberta
Government, 2016; The World Bank, 2014). Thus, pairing oil sands extraction with responsible policies
can ultimately enhance economic growth and create employment opportunities. Yet despite these obvious
benefits, our study clearly demonstrates that environmental considerations need to be incorporated into
decision-making surrounding oil sands.
Table 11. Net water consumption and GHG emissions from extraction and processing of petroleum
products.
GHG emissions are obtained from a review of seven publicly available studies that account for: recovery
& extraction, upgrading, electricity supply chain, natural gas supply chain, venting & flaring, fugitive
leaks and fugitive tailings ponds (Charpentier, 2009). Net water consumed Source GHG emissions from well-
to-tank
Source
Bitumen upgrading to SCO 0.6 l water/ l SCO This study 36.9 – 66.6 kg CO2eq./ bbl
BITUMEN
Nimana, 2015
Bitumen upgrading to SCO 1.0 l water/ l SCO Peachey, 2005
Oil refining ( U.S. average) 1.4 l water/ l refined Wu, 2009 46.3 – 92.1 kg CO2eq./ bbl
REFINED
Nimana, 2015
Gasoline (Alberta oil sands
mining)
7.7 l water/ l gasoline This study 62 – 164 kg CO2eq./ bbl SCO Charpentier,
2009
Gasoline (Alberta oil sands
mining)
5.2 l water/ l gasoline Wu, 2009
Gasoline (Alberta oil sands
in situ)a
2.0 l water/ l gasoline This study
99 – 176 kg CO2eq./ bbl SCO Charpentier,
2009
Gasoline (Alberta oil sands
in situ)
2.6 – 6.2 l water/ l
gasoline
Wu, 2009
Gasoline (U.S. conventional
crude-primary recovery)
0.2 l water/ l gasoline Wu, 2009
27 – 58 kg CO2eq./ bbl
GASOLINE
Charpentier,
2009
Gasoline (U.S. conventional
crude-secondary recovery) b
3.4 – 6.6 l water/ l
gasoline Wu, 2009
Gasoline (Saudi
conventional crude)
2.8 – 5.8 l water/ l
gasoline Wu, 2009
a Bitumen extracted from in situ drilling is not upgraded to SCO, but it is sent directly to refineries.
b Secondary recovery via water flooding.
Most global oil sand reserves are expected to be put under production and exploited in the near
future (U.S. EIA, 2016). While low oil prices (in year 2014 and 2015) have presently slowed extraction
from oil sand deposits, investments are ongoing, with massive extraction for commercial production
likely to take place as soon as oil prices become higher again. Production is expected to increase from
the current 3.5 million barrels a day to 7.5 million barrels a day by 2025. The environmental impacts of
oil sands extraction are already apparent in places where production is already occurring. Thus areas
containing oil sands can expect marked changes in terms of land cover and freshwater appropriations in
the near future. This expected escalation in oil sand extraction may therefore alter the existing equilibria
in the water-energy system and reshape patterns of water allocations, governance strategies, and
associated institutional arrangements.
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CONCLUSIONS 39% of the area of world high quality shale deposits is located in areas affected by surface water
stress and where 171 million people live. Water stress is particularly high in areas that are highly
populated, irrigated, or with low water availability (Mekonnen, 2016). In these regions an increase in
human appropriation of freshwater resources for shale gas or shale oil extraction would markedly
increase competition with the existing water uses for agriculture and environmental flows. The extraction
of shale deposits is expected to affect not only surface water resources but also groundwater (e.g.,
Freyman, 2014). Our analysis shows that 8% of high quality shale deposits are located in regions affected
by groundwater stress. About 6% of the world’s high quality shale areas are affected by both surface and
groundwater stresses. In these water constrained areas a water market could be developed increasing
water prices and enhancing the competition between water for food production through irrigation and
water for oil and natural gas production from shale resources. Thus while water markets may offer an
effective solution for allocating water rights within water-limited systems (Debaere et al. 2014), the
ultimate result may be the displacement of agriculture if shale energy companies are willing to pay a
higher price for water use. We find that 25% of high quality shale areas worldwide are in irrigated areas
where about 220 million people live. About 7% of the high quality shale areas are located in regions
where water use for irrigation has been projected to increase in order to close the crop yield gap – the
difference between actual and attainable yields. Thus, competition for water use in these areas will not
only increase due to shale energy production but also be exacerbated by a greater need for irrigation
water.
The increasing food and energy needs of humanity (e.g., Suweis, 2013) and the possible local
decline in water availability as an effect of climate change (IPCC, 2013) are expected to increase pressure
on freshwater resources (Muller, 2012; Davis, 2014). As a result, regions affected by increasing water
stress will face not only environmental and social challenges, but also see the emergence of financial
obstacles both for the food and energy industries. In some water constrained areas where shale resources
are present a rush for water appropriation by oil and gas companies has surged, leaving the agricultural
sector with limited water supply (Nicot, 2012; Mauter, 2014). This pattern is expected to occur in many
water stressed agricultural regions in which shale deposits are going to be developed because of the
higher profits of water use for energy than for food production. In fact, despite the current low price of
oil and natural gas, the use of water for energy production generates greater profits than agriculture. Oil
production from hydraulic fracturing is also less water intensive than oil from oil sands and conventional
oil through secondary recovery (i.e., water flooding of the reservoir) and therefore more economically
convenient. Only conventional oil from primary recovery (i.e., using lift pump) and conventional gas,
which has a zero water footprint in extraction, exhibits a higher economic yield of water use than shale
oil and shale gas. Interestingly, bioethanol and biodiesel are less profitable - in terms of economic yield
of water - than fossil oil and gas, but are more economical than the production of certain food crops.
Moreover, our analysis shows that, despite their similar water requirements per unit of energy produced,
shale oil and shale gas strongly differ in the economic yields of the water used in their production
processes.
The total water footprint of bitumen extraction and processing from oil sand deposits in Alberta
differed greatly depending on the extraction method. We found that 2.8 liters of water were required to
obtain a liter of bitumen using in situ drilling. Conversely, the water footprint of surface mining was 28.5
l H2O per l bitumen. At current rates of production, we estimate that extraction from Canadian oil sands
requires 0.49 km3 H2O yr-1. Substantial GHG emissions (from well-to- refinery entrance gate) have also
been associated with this production. Currently, oil sands production accounts for 103 Mtonne CO2 eq
yr-1 (14% of Canada’s GHG emission in year 2014).
About 1476 km2 of Alberta’s forests – 15% of forests covering Alberta’s oil sands concession areas in
year 2000 – have been removed since the start of the century. Forest fragmentation has also increased.
We estimate that full exploitation of oil sands deposits will have profound environmental consequences,
with the greatest impacts by far expected in Canada and Venezuela. Specifically, cumulative forest loss
across these studied oil sand deposits may eventually reach 8,665 km2, an area equal to 5% of global
forest loss in the year 2014. In addition, fresh water use may nearly triple to 1.31 km3 H2O yr-1 with
important impacts on the local freshwater resources, as the case of Utah where the deposits are located
in a potentially water-stressed areas. Moreover, projected annual GHG emissions (383 Mtonne CO2 eq
yr-1) – due in large part to growth in energy-intensive in situ production – would be commensurate with
those from land use and land cover change for all of Indonesia, and as many as many as 640,000 people
could potentially be affected by the complete development of these five world’s oil sands deposits.
While multiple environmental impacts are apparent, there have however been substantial
economic benefits with affordable and secure energy to U.S. and Canadian market, more than 478,000
jobs created in Canada in year 2012 (3% of all jobs in the country) (PetroLMI, 2016), and tax revenues
and royalties paid to the governments. Thus there are clear and ongoing tradeoffs between economic
development, energy, and the environment. The development of oil sand extraction in countries with dry
climates is expected to exert a stronger pressure on the local water resources, likely competing with other
water uses such as crop production and flows for aquatic ecosystems. Thus the increasing reliance on oil
sand extraction may raise new water security concerns in countries where deposits are located in water
stressed watersheds (Utah), thereby further sustaining ongoing debates on competing water uses within
the context of the water-energy nexus (Rulli, 2016).
This study demonstrates that mining operations and in situ drilling differ significantly in their
environmental impacts. While in-situ technology is more energy intensive, the process requires less
water, does not produce tailings, and has less extensive impacts on overall forest cover. For in situ
concessions, forest loss tends to be more scattered, limited to areas of intensive exploration activities for
the positioning of the extraction wells, and construction of infrastructures (e.g., roads, pipelines). Even
though in-situ drilling entails a smaller net change in forest cover than surface mining, its impact on
wildlife habitat and landscape fragmentation should not be underappreciated. Conversely, forest
vegetation is completely cleared within mining operations. In addition, while oil sand extraction is not
expected to displace a large number of people – as these deposits are located in remote forested areas –
these operations are likely to have important impacts on carbon sequestration, because of carbon
emissions associated with land use change and deforestation.
Progress in technology, proximity to the markets and high prices of crude oil have favored the
proliferation of the oil sand industry in Alberta. Though this study has focused on the major
environmental impacts of oil sand extraction, this source of energy also offers some advantages compared
to conventional oil. First, the recovery rate of bitumen from oil sands is greater than for conventional oil.
Second, oil sand deposits decline more slowly (4% decline per year) than those of conventional oil (20%
per year), allowing these deposits to last longer (e.g., 30 years in the case of Alberta) (Oil sands magazine,
2016). Because of their long lifespan, oil sand deposits are drawing increasing interest and investments
from oil and gas corporations. Moreover, oil sand industries have led to considerable job creation. For
example, in 2012, the oil sands industry in Canada and U.S. employed – directly and indirectly – almost
558,000 people (80,000 in U.S.) (IHS CERA, 2014; Canadian Energy Research Institute, 2011).
Employment is expected to grow in the most positive scenario of oil sands development to 2.2 million
jobs in the U.S. and Canada by 2035 (Canadian Energy Research Institute, 2011As a result of this oil
sands ‘boom’, Alberta has become one of the richest regions in the world, with a GDP per capita in year
2014 among the top five countries in the world (Alberta Government, 2016; The World Bank, 2014).
Thus, pairing oil sands extraction with responsible policies can ultimately enhance economic growth and
create employment opportunities. Yet despite these obvious benefits, our study clearly demonstrates that
environmental considerations need to be incorporated into decision-making surrounding oil sands.
DISCUSSION Potential exploitation of unconventional fossil fuels will create a new geography of oil and natural
gas production, with important implications for the global geopolitical landscape. Their projected growth
by 2040 will meet 30% of world natural gas demand and 18% of global oil production. Shale resources
and oil sands are an opportunity for some countries to increase their energy security, while reducing costs
of fossil fuel imports and potentially changing their import-export balance. The high amount of water
required to extract these resources requires that countries that decide to exploit their unconventional
resources will need to develop responsible water management plans to ensure that other sectors are not
impacted.
The shale revolution and oil sands boom have created million of new jobs and economic benefits
in North America, supporting economic growth also in some rural and less developed areas. Thus, with
adequate policies and regulations, unconventional fossil fuels extraction has the potential to enhance the
economic growth and energy security of some regions.
Despite these benefits, in many regions of the world unconventional fossil fuels development will
be problematic because of water limitations and will likely exacerbate a competition with water for food
and other human needs. Particularly critical appears to be the case of some high quality shale areas in
water stressed regions of the United States, Mexico, South Africa, China, South Asia, and Australia and
in the United States (Utah deposit) for the case of oil sands. In some of these regions oil and gas
production from unconventional fossil fuels is expected to threaten the local water and food security. In
these water stressed areas where shale resources are present adequate policies need to be put in place in
order to avert social, economic, and ecological consequences.