Study No. 147 June 2015 - CERI · Process Efficiencies of Unconventional Oil and Gas ix June 2015 Executive Summary The oil and gas sector in Canada provides considerable economic

CANADIAN ENERGY RESEARCH INSTITUTE

PROCESS EFFICIENCIES OF

UNCONVENTIONAL OIL AND GAS

Study No. 147 June 2015

Canadian Energy Research Institute | Relevant • Independent • Objective

PROCESS EFFICIENCIES OF UNCONVENTIONAL OIL AND GAS

Process Efficiencies of Unconventional Oil and Gas

Author: Rob McWhinney ISBN 1-927037-32-4 Copyright © Canadian Energy Research Institute, 2015 Sections of this study may be reproduced in magazines and newspapers with acknowledgement to the Canadian Energy Research Institute

June 2015

Printed in Canada Front Photo Courtesy of http://www.arcresources.com/images/sized/assets/gallery/photos/dawson_frac-

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Acknowledgements: The author of this report would like to extend his thanks and sincere gratitude to all CERI staff that provided insightful comments and essential data inputs required for the completion of this report, as well as those involved in the production, reviewing, and editing of the material, including but not limited to Allan Fogwill and Megan Murphy

ABOUT THE CANADIAN ENERGY RESEARCH INSTITUTE The Canadian Energy Research Institute is an independent, not-for-profit research establishment created through a partnership of industry, academia, and government in 1975. Our mission is to provide relevant, independent, objective economic research in energy and environmental issues to benefit business, government, academia and the public. We strive to build bridges between scholarship and policy, combining the insights of scientific research, economic analysis, and practical experience. For more information about CERI, visit www.ceri.ca CANADIAN ENERGY RESEARCH INSTITUTE 150, 3512 – 33 Street NW Calgary, Alberta T2L 2A6 Email: [email protected] Phone: 403-282-1231

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Table of Contents LIST OF FIGURES ............................................................................................................. v

LIST OF TABLES ............................................................................................................... vii

EXECUTIVE SUMMARY .................................................................................................... ix

CHAPTER 1 INTRODUCTION ........................................................................................ 1

CHAPTER 2 CURRENT BEST PRACTICES ........................................................................ 9

Conventional Oil and Gas Production ................................................................................ 9 Oil Sands – Thermal ........................................................................................................... 12 Oil Sands – Mining and Upgrading ..................................................................................... 18

CHAPTER 3 SHALE GAS ............................................................................................... 21

Production Process ............................................................................................................ 21 Water Use and Wastewater Management ........................................................................ 22 Drilling and Fracturing Materials ....................................................................................... 28 Energy Use ......................................................................................................................... 30

CHAPTER 4 OIL SANDS ................................................................................................ 33

Oil Sands Mining: Paraffinic Froth Treatment .................................................................. 34 Oil Sands In Situ: Steam-Solvent Extraction ...................................................................... 37 Physical Process ........................................................................................................... 37 Solvent Choice .............................................................................................................. 41 Operating Costs of Hybrid Steam-Solvent Technology ................................................ 42 Oil Sands In Situ: Solvent-based Extraction ...................................................................... 46 In Situ Modular Design ....................................................................................................... 49

CHAPTER 5 CONCLUSIONS .......................................................................................... 53

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Process Efficiencies of Unconventional Oil and Gas v

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List of Figures 1.1 Oil Sands Regions in Alberta ........................................................................................ 2 1.2 Shale Gas Regions of Northeastern British Columbia .................................................. 3 1.3 Breakdown of 2005, 2012 and 202 Oil and Gas Emissions in Canada ......................... 5 2.1 Typical Energy Loss in SAGD Operations Compared to the Theoretical Minimum Energy Loss per Hour of Operation ............................................................. 15 2.2 A Schematic of Cenovus’ Wedge Well Technology ..................................................... 17 3.1 A Simplified Graphic of the Shale Gas Hydraulic Fracturing Process .......................... 22 4.1 Refining and Upgrading Emissions for SCO Production by Coker or Hydrocracking, Bitumen, or Dilbit................................................................................ 36 4.2 Vapour Pressure Curves for Five Hydrocarbon Solvents and Water as a Function of Temperature ............................................................................................. 39 4.3 Steam and Solvent Operating Costs for Traditional SAGD and Steam Butane Co-injection ..................................................................................................... 43 4.4 Steam and Solvent Operating Costs for Traditional SAGD and Steam Pentane Co-injection.................................................................................................... 44 4.5 Sensitivity of Cost per Barrel with Butane Added to Steam ........................................ 45 4.6 Sensitivity of Cost per Barrel with Pentane Added to Steam ...................................... 45

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Process Efficiencies of Unconventional Oil and Gas vii

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List of Tables E.1 Summary of Upstream Oil and Gas Efficiency Opportunities ....................................... xii

3.1 Sources of Water Used for Hydraulic Fracturing in British Columbia, 2013 ............... 23 4.1 Temperature and Mole Fraction of Solvent in Condensing Liquid at the Edge of the Vapour Chamber at 3000kPa.................................................................... 40 4.2 Values Used for Estimating per Barrel Costs of Steam-solvent Extraction ................. 42 5.1 Summary of Upstream Oil and Gas Efficiency Opportunities ....................................... 54

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Process Efficiencies of Unconventional Oil and Gas ix

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Executive Summary The oil and gas sector in Canada provides considerable economic benefits. It is also a resource-intensive sector, requiring large amounts of energy, natural resources, capital, and labour inputs to produce crude oil and natural gas outputs. Growth in this sector can place strain in the following areas:

Increased consumption of fossil fuels, consequently increasing greenhouse gas (GHG) and air pollutant emissions;

Increased consumption of fresh surface and groundwater resources;

Disturbances and fragmentation of the natural environment;

Increased demand on scarce raw materials required for construction, drilling, and well operation; and

Demand for skilled labour that outpaces local supply.

As the sector grows, this strain can result in increased costs for the sector, including monetary costs, such as increased capital cost intensity due to limited labour supplies and construction materials, and environmental costs, such as consumptive use of fresh water and emissions of GHGs.

Finding more efficient ways to construct and operate an upstream oil and gas facility is one way to combat these costs. While efficiency is often used to describe energy efficiency (reducing overall energy consumption per unit of output), this report considers both energy efficiency and operational efficiencies, such as those that decrease the amount of a resource required for operation, decrease construction costs and delays, and

make for more efficient use of limited labour and equipment. Many efficiency gains in one area often result in gains in another, so there can be considerable overlap in these categories.

In terms of energy efficiency, the first options are to use readily available, economically viable technologies that reduce overall energy consumption. These best practices may not be in current use due to the age of a facility or slow adoption of new technologies. Strategies range from optimizing the operations of existing equipment to replacement of outdated equipment with more modern, energy efficient versions. The cost of the new technology and the residual cost of the old one can often be quickly recovered through lower operating costs from fuel savings. Other readily available technologies require a change in techniques; for example, significant energy savings can be obtained in steam

assisted gravity drainage (SAGD) oil sands operations by adding mechanical down-hole pumps rather than using reservoir pressure to retrieve bitumen from the well. For oil sands mining, use of paraffinic froth treatment to partially upgrade bitumen through asphaltene removal can remove the need for an on-site upgrader, which reduces the overall life cycle emissions of mined oil sands bitumen.

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Estimated energy savings based on adopting best practices are on the order of about a

ten percent reduction in energy consumed per unit of production. Advantages are gained in lower GHG intensity, lower air emissions, and lower operating costs.

While increasing the operating efficiency of existing upstream oil and gas facilities is important, future growth of the industry presents unique challenges. Growth is anticipated in both natural gas production from shale resources and expansion of in situ bitumen production from oil sands. Expansion of these resources places pressure on the construction industry and often draws from a constrained labour force, which can lead to inflated costs.

Shale gas resources in the Montney and Horn River basins of Northeast British Columbia are located in regions with relatively little previous drilling. As such, services tend to be

located in areas distant to the location of drilling. Construction delays due to transport or scarcity of materials can be avoided using strategies such as:

Locating drill rig storage and servicing equipment in municipalities closer to British Columbia shale development;

Coordinating drilling activity on a large scale to achieve savings from economies of scale; and

Developing local sales points of important hydraulic fracturing materials such as chemical additives and sand for proppant.

For in situ oil sands growth, one of the most promising ways of reducing construction costs is to increase the degree of modularization used in the facility design. This allows

much of the facility to be produced off-site in areas with higher labour productivity, shipped to the well site, and constructed in a short period of time. Modularization prevents cost escalation from the overshooting of construction timelines, and allows for the equipment to be quickly taken down and moved to a new well site at the end of a project’s lifetime.

The growth of production also exerts upward pressure on Canadian GHG emissions at a time when overall reductions have been committed to the international community. Shale gas production has the additional challenge of using large volumes of water, and the main shale gas basins of British Columbia often experience low availability of surface fresh water.

To overcome these challenges of growth, larger impact changes to operations must be

adopted, as incremental reductions in fuel or resource use are low enough in magnitude to be overshadowed by projected growth in production. Shale gas resources can reduce reliance on local freshwater by using municipal or industrial wastewater, using fracturing additives that are compatible with lower water purity, or increasing the rate of recycling of flowback water from previously fractured wells. Switching from diesel rigs to those operating with natural gas can reduce energy costs and GHG emissions.

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For in situ bitumen production, use of hydrocarbon solvents may increase the energy and

operating cost efficiency of a project compared to steam-only thermal extraction while reducing water usage. In steam-solvent hybrid methods, a small amount of light hydrocarbon solvent can reduce steam-oil ratios by approximately half, reducing the amount of water needed per barrel of oil and, consequently, the amount of fuel needed to generate steam. Solvent methods without steam can eliminate the need for water, operate at much lower temperatures and pressures and thus require less natural gas for heat, and produce a partially upgraded bitumen product by removing asphaltenes in the reservoir. The major barrier to solvent methods is the rate of recovery of solvent from the reservoir. Substantial loss of solvent to the reservoir could represent a major increase in operating costs that counter savings from fuel use reduction. Waterless solvent processes would likely have significant capital cost reduction compared with SAGD variations as facilities can be much simpler in scope and design.

A summary of efficiency strategies discussed herein along with a brief outline of the major efficiency gains from each is shown in Table E.1.

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Table E.1: Summary of Upstream Oil and Gas Efficiency Opportunities

Sector Strategy Advantages

Conventional oil and gas Adoption of technical and management best practices

- Technologies are currently available

- Cost recovery through fuel savings

- Potential energy savings on the order of 10 percent

- Reduced GHG intensity - Reduced operating costs

In situ oil sands Mechanical lift Wedge Wells Modular construction Solvent-based extraction

- Lower steam pressures - Reduced SOR (approx. 18

percent reduction) - Approx. 24 percent

reduction in energy loss - Improved heat recovery at

surface - Reduced GHG intensity - Reduced water use - Improved bitumen

recovery rates (12 percent increase)

- Fewer construction delays - Reduced capital cost

(estimated 53 – 61 percent lower per barrel of production than traditional SAGD)

- More efficient use of labour

- Easy to move to new sites - Reduced SOR; pilot projects

have demonstrated over 50 percent reduction

- Improved bitumen recovery rates

- Reduced water use - Reduced GHG intensity - Potential for partial

bitumen upgrading

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Mined oil sands Adoption of current best practices Improved tailings management Paraffinic froth treatment

- Reduced need for heating process water

- Reduced coke usage - Reduced air emissions - Reduced GHG intensity - Reduced fresh water

requirements - Reduced land footprint - Partially upgraded bitumen

product - Product may be shipped as

dilbit rather than requiring on-site upgrading

- Reduced on-site and life cycle GHG intensity (15 percent reduction in refining and upgrading related emissions)

- Reduced capital costs

Shale gas Improved water management Improved drilling rig and material management Fuel replacement

- Reduced fresh water usage by using waste water sources

- Less requirement for additional fracturing additives

- Reduced cost of treatment and transport of water

- Lower risk of well drilling delays in times of drought

- Reduced energy requirements for water treatment

- Reduced cost of transport of rigs or drilling and fracturing material

- Lower risk of delay due to equipment or material availability

- Lower fuel cost (2014 natural gas cost 84 percent lower than equivalent energy in diesel fuel)

- Reduced air emissions - Reduced GHG intensity

Source: CERI

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Overall, there are many existing ways to increase efficiency of upstream oil and gas

production through best practices; although these tend to be small enough gains that projected growth in the industry will outstrip the advantages gained, particularly in areas such as GHG emissions. For the projected growth to be obtainable simultaneously with reductions in emissions, much larger scale changes in technology must be adopted to increase the energy efficiency dramatically.

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Chapter 1: Introduction When discussing efficiency in the upstream oil and gas sector, it can be thought of as a goal to be achieved in a number of operational areas: energy use, natural resource use, and process efficiencies. As more efficient processes are adopted, the industry can increase economic benefits and reduce environmental impacts of resource extraction. There is considerable overlap in these areas in improvement, and improving one can often lead to improvements in another; for example, reducing water use can also reduce energy use due to requirements for heating or treatment of fresh water. This report approaches efficiency from this broader scope, rather than focusing on energy efficiency alone.

The oil and gas sector plays a key role in the Canadian economy. In 2013, the energy

industry in Canada directly and indirectly accounted for 13.4 percent of Canada’s GDP,

with the direct effects of the oil and gas sector contributing $133 billion, or 7.5 percent of GDP.1 The oil and gas sector employed 190,170 people in 2013, accounting for 1.1 percent of Canada’s workforce.

As conventional resources are depleted, the production in Canada is shifting to unconventional sources of oil and gas, in the form of oil sands and natural gas from tight and shale reservoirs (see Figures 1.1 and 1.2). The National Energy Board (NEB) reports2 that as of the beginning of 2013, 98 percent of Canada’s 171.3 billion barrels (bbl) of crude oil reserves are in the form of bitumen in oil sands. As of the more recent Energy Future report, by 2035, the NEB projects that 5 million barrels per day (MMbpd) will be produced as bitumen from oil sands, where conventional oil production will be less than 1 MMbpd.

In light of recent declines in oil prices, this projection is likely to grow at a slower pace, but bitumen from oil sands is still expected to be a prominent oil source in the future. The same energy outlook projects that natural gas production will fall until approximately 2017-2018 before slowly increasing to the early 2000s level of production of approximately 17.4 billion cubic feet per day (Bcf/d), with 62 percent of production coming from tight gas and 28 percent coming from shale gas. Production in the Montney Basin in British Columbia and Alberta is expected to be particularly important in coming years, as the gas deposits contain high levels of liquids and are thus of higher value. Total Montney production is expected to be 7.7 Bcf/d by 2035, with 6.1 Bcf/d coming from British Columbia. The Horn River Basin in northern British Columbia is also expected to be a more dominant contributor, increasing to 3.6 Bcf/d by 2035. Ultimate production rates will depend on the future of planned liquefied natural gas export terminals on the Pacific

coast.

1 Natural Resources Canada (2014). Energy Markets Fact Book 2014-2015. http://www.nrcan.gc.ca/sites/www.nrcan.gc.ca/files/energy/files/pdf/2014/14-0173EnergyMarketFacts_e.pdf 2 National Energy Board (2013). Canada’s Energy Future 2013. http://www.neb-one.gc.ca/nrg/ntgrtd/ftr/2013/2013nrgftr-eng.pdf

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Figure 1.1: Oil Sands Regions in Alberta

Source: Government of Alberta


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Figure 1.2: Shale Gas Regions of Northeastern British Columbia

Source: BC Oil and Gas Commission

The development of these resources does present challenges in the coming years. The first is how to accommodate the growth of these resources in an environmentally responsible manner. All energy extraction requires some amount of input energy, which is currently supplied mostly by fossil fuels. The burning of fossil fuels releases carbon


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dioxide to the atmosphere, a greenhouse gas (GHG) that is partially responsible for

climate change. Gas development can also, through fugitive emissions or venting, release methane to the atmosphere, and methane is currently estimated as 28 to 34 times stronger as a GHG as the same mass of carbon dioxide over a 100-year period.3,4

Environment Canada projects emissions to be nearly equal to 2005 levels even though Canada’s current international commitment is 17 percent below 2005 levels.5 Emissions from the oil and gas sector are expected to grow from 159 megatonnes (Mt) of carbon dioxide equivalent (CO2e) to 204 Mt CO2e by 2020, an increase of 45 Mt that counters the 50 Mt CO2e reduction projected in the electricity sector. The growth in emissions in oil and gas, shown in Figure 1.3, is the result of growth in the oil sands sector; emissions grow from 34 Mt to 103 Mt CO2e between 2005 and 2020, with the majority coming from in situ oil sands production. Natural gas production, projected to be lower in 2020 than

2005, actually decreases emissions from 54 Mt to 40 Mt CO2e over this time period, although this will likely increase as production picks up in later years.

3 For further details, consult the IPCC Fifth Assessment Report, available at http://www.ipcc.ch/report/ar5/ 4 The factors of 28 and 34 are the global warming potentials (GWPs) of methane as published in the most recent IPCC assessment report, without and with the inclusion of climate-carbon feedback, respectively. GWPs are used to convert non-CO2 GHGs to an equivalent of CO2 emissions and are dependent on a number of factors, including infrared absorptivity of the molecule, lifetime in the atmosphere, and potential feedback mechanisms that can change the potency of a GHG. Most regulations currently use a GWP of 25 for methane based on the IPCC Fourth Assessment Report. The most current fifth version of the report updated this value to 28, with a new GWP of 34 introduced that introduces climate-carbon feedback mechanisms that can increase the potency of methane as a GHG. These feedback mechanisms are considerably more complex and uncertain than the factors that contribute to the GWP of 28. 5 Environment Canada (2014). Canada’s Emissions Trends. http://www.ec.gc.ca/ges-ghg/E0533893-A985-4640-B3A2-008D8083D17D/ETR_E%202014.pdf


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Figure 1.3: Breakdown of 2005, 2012 and 2020 Oil and Gas Emissions in Canada

Source: Environment Canada, Canada’s Emissions Trends 2014

Bitumen extraction is more energy-intensive and more emissions-intensive than conventional oil production, as at reservoir temperatures bitumen is highly resistant to flow, and thus must be mobilized from the surrounding sand. In the minable region north of Fort McMurray and close to the Athabasca River, the oil sands resource is close enough to the surface to be mined. The oil sands ore is retrieved from the ground using truck and shovel mining and mixed with hot water and caustic soda. This slurry is sent to a central extraction plant and mixed with a hydrocarbon solvent, forming a bitumen-solvent froth that floats to the surface of the mixture and is separated from the water. In most cases, the solvent is then recovered for further froth treatment, and the bitumen is sent to an upgrader. Upgrading is a partial refining technique, which uses a coker or hydrotreating unit to break the bitumen hydrocarbons into smaller molecules and removes impurities such as metals and sulphur. The final product is synthetic crude oil (SCO), which can be

transported via pipeline to be refined into final saleable products. Energy is required for the operations of the truck and shovel, the heating of the water in the extraction process, the transport of water and mine tailings, and the upgrading of bitumen into SCO.

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2005 2012 2020

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LNG Production

Downstream Oil and Gas

Transmission

Oil Sand Upgrading

Oil Sands Mining

Oil Sands In Situ

Conventional Oil Production

Natural Gas Production andProcessing


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In situ bitumen extraction, on the other hand, involves oil sands too deep to be mined,

and represents 80 percent of the 2013 remaining oil sands reserves.6 To mobilize the bitumen in situ (Latin for “in position”), the bitumen is heated by injecting steam into the reservoir by either cyclic steam stimulation (CSS) or steam assisted gravity drainage (SAGD). In CSS, a single vertical well acts as an injection well and a production well, undergoing a cycle where high pressure steam is injected into the reservoir, allowed to sit for a period of time on the order of several weeks, and then the heated, mobilized oil is pumped out of the ground through the same well. In SAGD, two parallel horizontal wells are drilled, with the top well placed about 5 metres above the bottom well. The top well, or injection well, is used to inject high quality steam into the reservoir. The steam transfers heat to the surrounding bitumen, which then drains into the bottom producing well. In both techniques, the hot bitumen has a much lower viscosity (that is, it flows much more easily under gravity) and can be pumped to the surface as an oil-water

emulsion. Once at the surface, the oil is separated from the water and the produced water is sent through treatment to be recycled back to steam generators (about 80 to 90 percent recycled). The produced bitumen, in the majority of projects, is typically diluted with condensate (typically referred to as diluent) and sent to market by pipeline as a mixture called dilbit (diluted bitumen) containing approximately 30 percent diluent and 70 percent bitumen. In this case, the generation of steam is a particularly energy-intensive process, and further energy is needed to treat water to a sufficient purity to generate steam.

Shale gas does differ from conventional gas development in ways that make it a more energy-intensive process. Shale is a low permeability reservoir, and as such gas will not flow to a well through rock pores at a high enough rate for a typical vertical well to be

effective. Instead, a horizontal well is drilled through the shale reservoir with lengths up to several kilometres. Fluid is then pumped into the well at high pressures to induce fractures in the rock through which the gas can flow through – a process known as hydraulic fracturing (or, colloquially, fracking). The additional drilling and the energy required for pumping high-pressure fluid make the overall production process more energy-intensive than conventional gas production, although unlike bitumen, the processing of gas from shale gas reservoirs does not have processing requirements that are unique to the resource compared to conventional gas.

Water use is another environmental concern for unconventional oil and gas for both the extraction process and hydraulic fracturing. Oil sands mining and extraction requires a considerable amount of water and generates a considerable amount of liquid tailings in

the process. Likewise, in situ bitumen extraction requires a large amount of water for steam generation.

6 AER ST98. https://www.aer.ca/data-and-publications/statistical-reports/st98


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Water use for hydraulic fracturing has been particularly contentious, with several

jurisdictions placing moratoriums on fracturing out of concerns partially for water use, but mostly for the concerns of the effects of fracturing and the chemical additives added to water to make fracturing fluid. In some locations, the volumes of water can place demands on limited surface fresh water resources, and wastewater management can become a limiting factor when developing shale resources.

The environmental impacts have also generated public controversy that has directly impacted the industry. Public perception of the oil sands as “dirty oil” has led to wide protests and delays over pipelines such as TransCanada’s Keystone XL and Enbridge’s Northern Gateway,7 both aimed at increasing transport and export capacity for projected bitumen growth. Hydraulic fracturing has a similar image problem, with New Brunswick,8 Quebec,9 and Nova Scotia10 all currently banning the practice in Canada.

There is incentive, then, for the industry to improve its environmental performance, not only for the environmental benefits and the potential to improve public perception, but to perform better economically as well. Increasing the efficiency of the processes in the upstream oil and gas industry can reduce the amount of resources used, such as fuel and water, and often provide savings in operating costs that outweigh the upfront costs of adopting new technologies and practices.

Increased oil production activity has also led to challenges beyond the environmental impacts. During times of high oil prices, there is a high demand for construction and operating labour as projects try to get installed while economic conditions are favourable. Coupled with the relatively large scale of projects in the oil sands region, the result can

tend towards inflation of capital costs. Capital costs, coupled with higher energy needs and thus higher operating costs, mean that even the most economic method of oil sands production, in situ, requires West Texas Intermediate prices of $50 to $80 (US 2012) per barrel to be economically viable.11 With WTI prices at times dropping to levels below $50 per barrel in 2015, oil sands projects are riskier and more exposed to delays and cancellations. Shale gas development, on the other hand, is a relatively new resource in Canada, and as such takes place in a less developed environment with minimal infrastructure than historical gas production. In addition, developers must compete with

7 Numerous resources can be found on these pipelines, but for overviews of media coverage, the Globe and Mail has a special section on Keystone XL (http://www.theglobeandmail.com/report-on-business/industry-news/energy-and-resources/topic/Keystone-XL-Pipeline) and CBC has a special section on Northern Gateway (http://www.cbc.ca/calgary/features/northerngateway/). 8 http://www2.gnb.ca/content/gnb/en/news/news_release.2014.12.1404.html 9 http://montrealgazette.com/news/quebec/couillard-rules-out-fracking 10 http://thechronicleherald.ca/novascotia/1251197-fracking-bill-becomes-law 11 National Energy Board (2013). Canada’s Energy Future 2013. http://www.neb-one.gc.ca/nrg/ntgrtd/ftr/2013/2013nrgftr-eng.pdf

http://www.theglobeandmail.com/report-on-business/industry-news/energy-and-resources/topic/Keystone-XL-Pipeline

http://www.theglobeandmail.com/report-on-business/industry-news/energy-and-resources/topic/Keystone-XL-Pipeline


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other segments of the oil and gas sector for drilling rigs, particularly in times when energy

prices are high.

This report looks at some of the options available for the industry to increase the efficiency in their operations, whether that is energy efficiency, resource efficiency (such as water use and waste management), or efficiency in other areas including construction and materials management. Chapter 2 will look primarily at available practices that can improve the energy efficiency of typical oil and gas development, while the remaining chapters will examine potential methods for achieving more efficient operations in the expanding shale gas and in situ bitumen developments.


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Chapter 2: Current Best Practices In order to obtain usable end products from oil and gas, there must be some expenditure of energy, and typically, this energy also comes from the use of fossil fuels. The more fuels used in these upstream processes, such as extraction, processing, or refining, the less efficient the overall energy production becomes. This leads to both increased overall costs, either via the purchase of outside fuel or reduction of the amount of final fuel that may be sold to market, and increases emissions in the form of GHGs and air pollutants depending on the type of fuel used.

Often when discussing ways to cut back on emissions and fuel use in the upstream oil and gas sector, particularly in very energy-intensive methods such as in situ oil sands

production, the discussion tends towards large, game changing extractive technologies.

For example, finding in situ oil sands extraction processes that can extract bitumen without having to produce large volumes of steam. Some of these potential technologies will be discussed later in the report, but there are also viable methods of increasing energy efficiency simply by adopting currently available and economically viable technology that improves on what is most commonly used today. In many cases, facilities can easily recoup the capital cost of maintaining or replacing equipment through savings in energy costs and reduce overall emissions.

This chapter will discuss currently available methods of increasing efficiency of the upstream oil and gas sector.

Conventional Oil and Gas Production Stantec Consulting and Marbek Resource Consultants prepared a report for Natural Resources Canada on the potential for greater energy efficiency in the Canadian upstream oil and gas sector.1 When considering the results of that study, there are a number of factors that should be kept in mind with respect to how the cost savings are quantified.

The cost savings are referred to as the economic potential. This is calculated based on a total resource cost (TRC) methodology. Using this methodology may overstate the cost benefits of adopting a technology at a particular facility, as costs avoided external to the facility are included in the cost savings. These costs may not be borne by the producer so the financial cost savings differ from this TRC estimate (i.e., financial savings will be lower). In addition, some of the assumptions used are based on the Ontario Market (e.g., electricity price) which will differ from the oil sands environment in Alberta and

Saskatchewan. Additionally, the TRC method does not include costs for writing off the

1 Stantec Consulting Ltd. and Marbek Resource Consultants Ltd. Energy efficiency potential in Canada’s upstream oil and gas sector. Project 115301592. Prepared for Natural Resources Canada (NRCan).


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replaced equipment that is not yet at the end of its life cycle at the time of replacement.

Other considerations include:

The baseline scenario does not account for regulations in place, such as carbon emission costs, that would encourage the adoption of energy efficient processes.

The baseline year of 2005 precedes the increase in shale gas production, and thus does not accurately capture the current gas industry.

As such, the potential energy savings is overestimated from this source. However, the report does offer a number of strategies to improve energy efficiency in the sector, and the findings can at least be examined to look at areas of improvement even if the quantitative findings are overstated.

A survey of 30 facilities of 15 companies, spanning natural gas producers, sweet and sour gas processors, and light, medium, and heavy oil and bitumen producers, was conducted to determine current conformance with technical and management best practices currently identified within the sector. Based on a baseline year of 2005, each best practice was assessed and screened for economic cost vs. benefits from energy savings. Once economically-viable best practices were determined, the rate of current compliance was determined and the energy savings achieved by year 2030 were calculated. The report examines all upstream oil and gas production but stops at refining, and thus does not include upgrading facilities.

Some major energy savings strategies identified in the report include:

Improving performance monitoring, optimization and servicing on engines and gas turbines for natural gas producers;

Improving engine operation for natural gas producers;

Improving performance monitoring, optimization and servicing on engines and gas turbines for sweet natural gas processing;

Optimizing gas compressor operation for light and medium oil producers;

Optimizing power quality in sour natural gas processing;

Implementing power factor improvements in sour natural gas processing; and

Right sizing gas compressors to minimize recycling and matching the volume of inlet gas for light and medium oil producers.

The report notes that of all facility components, direct fired heaters and steam boilers used the largest fraction of the energy in the upstream oil and gas industry (65 percent of

total energy used) and tended to have lower rates of adoption of best practices. As a result, greater use of best practices in this area will provide the largest impact in energy use reduction within the sector. None of the aforementioned techniques require any new development of unproven technology, some only require changes in operation and servicing on existing equipment, and yet the opportunities for energy savings are considerable. In many cases, savings of more than 10 percent can be achieved.


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Although these best practices are currently viable, the study notes a number of barriers

to a wider adoption within the upstream oil and gas industry:

The focus of the sector tends to be on short-term financial return, and the implementation of new projects can be seen as an interruption on production and revenue. As a result, planned outages tend to focus on preventative maintenance rather than implementation of energy efficiency measures or technologies.

Fuel gas is considered a free resource due to the need to harness and manage it, and royalty structures do not encourage its conservation, although industry organizations including the Canadian Association of Petroleum Producers (CAPP) have promoted the efficient use of fuel gas.2

There are currently few governmental policies aimed at promoting the adoption of energy efficiency measures.

There is often a high perception of financial and operational risk involved in adopting new efficiency measures.

Education, information and resources are limited even within large organizations when it comes to energy efficiency measures, and there may not be the measurement instruments in place to measure the efficacy if new technologies or techniques are adopted.

While many of the technologies are readily available, companies often have a large number of small facilities across different segments of the upstream oil and gas sector, and there may not be a one-size-fits-all approach available across all facilities. As a result, large scale facilities with sufficient staff and resources and with large enough energy use that the outcomes are immediately evident tend to be the most likely to adopt energy efficiency techniques.

Government support and incentivization may increase the rate of adoption of best practices to improve energy efficiency. One of the core responsibilities of the Climate Change Emission Management Corporation (CCEMC) is to fund energy efficiency projects,3 including support of a company-wide adoption of energy efficiency measures for ConocoPhillips.4 Alberta has lagged on other areas of support, and has been identified as the only province or state in Canada and the United States to have no consumer energy efficiency funding.5 To examine the efficacy of regulation, one metric to look at is the

2 CAPP: Fuel gas best management practices. http://www.capp.ca/publications-and-statistics/fuel-gas-best-management 3 http://ccemc.ca/projects/energy-efficiency/ 4 http://ccemc.ca/project/energy-efficiency-program-leading-to-ghg-reductions-oil-and-gas-industry/ 5 Alberta Energy Efficiency Alliance. Jurisdictional review of funding for energy efficiency programs in Canada and the United States. http://www.aeea.ca/pdf/jurisdictional-review-of-funding-for-ee-programs.pdf


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relatively high rate of adoption for waste reduction practices compared to energy

efficiency identified in the Stantec efficiency report.

Waste reduction practices, which are primarily aimed at loss of gas through either flaring or venting, are governed by the Alberta Energy Regulator’s Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting.6 This Directive requires any facility producing more than 900 cubic metres (m3) of solution gas per day to perform an economic evaluation on gas capture and requires capture if the net present value of the recovered solution gas is in excess of -55 000 CAD or if the facility is within 500 m of a residence, regardless of economics. In addition to resulting in a high rate of adoption of best practices, flaring and venting have been substantially reduced in Alberta. As of 2013, solution gas conservation stands at 95.3 percent, up from 94.2 percent the previous year; flared gas from crude oil and bitumen batteries fell from 547 million m3 to 495 million m3,

while vented gas fell from 430 million m3 to 403 million m3.7 This represents not only an increase in usable energy from required gas, but also a significant decrease in GHG emissions, particularly when vented gas contains methane, a particularly potent GHG.

The successes of Directive 060 and others such as Directive 081 mandating water disposal limits for thermal in situ bitumen production8 (thus increasing water recycling rates for thermal oil sands facilities) show that in some cases, the regulatory environment can encourage the wide-scale adoption of practices that reduce the environmental impact of the upstream oil and gas sector. Similar government regulations or incentives could encourage the further adoption of the technical best practices on a wider scale in the conventional upstream oil and gas industry.

Oil Sands - Thermal While conventional oil and gas production still constitutes a considerable portion of the upstream oil and gas industry, most of the projected growth overall in the oil and gas sector in Canada is expected to come from the oil sands, particularly thermal in situ projects.

Thermal in situ bitumen production has the highest rates of adoption of efficiency best practices.9 The larger scale of these facilities coupled with the lower economic margins of the resource due to the high energy requirements and the relatively low value of bitumen are likely reasons why energy efficiency technologies and practices are adopted at a greater rate. However, there are still areas in which best practices are not fully adopted,

6 Alberta Energy Regulator Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting. http://www.aer.ca/rules-and-regulations/directives/directive-060 7 Alberta Energy Regulator (2014). ST60B-2014: Upstream petroleum industry flaring and venting report. http://www.aer.ca/documents/sts/ST60B-2014.pdf 8 Alberta Energy Regulator Directive 081: Water Disposal Limits and Reporting Requirements for Thermal In Situ Oil Sands Schemes. http://www.aer.ca/rules-and-regulations/directives/directive-081 9 Stantec Consulting Ltd. In addition, Marbek Resource Consultants Ltd. Energy efficiency potential in Canada’s upstream oil and gas sector. Project 115301592. Prepared for NRCan.


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and the projected energy use of 603 petajoules (PJ) by year 2030 is estimated to be

reduced by 10 percent if economic best practices are adopted. The majority reduction is achievable by implementing the use of up-to-date distributed control systems (DCS) or programmable logic controllers (PLC) to ensure the equipment operations at a facility are optimized.

As one of the CCEMC’s energy efficiency projects, Jacobs Consultancy and Suncor Energy prepared an energy efficiency study with the end goal of determining GHG reduction potential in the oil sands.10 The reported baseline energy intensity of 8.6 gigajoules (GJ) per m3 of bitumen produced for a steam-to-oil ratio (SOR) of 3.2 could be reduced by 8 percent to 7.9 GJ per m3 of bitumen using currently available, economically viable technologies (economic viability was defined as having a payback period of less than 5 years). The two major areas where improvements could be made were heat exchange

and efficiency of fired heaters; and utilities, including steam production and greater use of electricity cogeneration. This report does not elaborate beyond these categories regarding the techniques contributing to that reduction in energy usage, but the improvement ideas that are suggested fall under these major categories:

Operational improvements, including maximizing fuel gas temperature, using low energy water treatment processes, and maximizing steam quality;

Improving existing heat exchangers and adding heat exchangers where they are currently unused, thus maximizing the recovery of waste heat from sources such as stacks, flue gases, and produced well fluids; and

Recovering more energy from high-pressure sources such as natural gas, boiler blowdown, and steam.

As the report is concerned with GHG reductions, the proposed energy efficiency measurements also reduce overall emissions by 12 percent. As will be discussed in a later chapter, some of the energy saving measures, namely the use of lime softening over evaporators to treat boiler feed water, are at odds with potential measures to make SAGD

projects more economically efficient in terms of capital cost and labour required for site construction. Further energy efficient processes can result in the need for equipment that is more customized and more capital-intensive.

An earlier Jacobs Consultancy report prepared for the Alberta Energy Research Institute to specifically address the efficiency of the SAGD process more explicitly details specific techniques to reduce the energy consumption of the process.11 The basis of the report

was to examine the potential areas of lost energy; that is, energy that cannot be

10 Jacobs Consultancy and Suncor Energy (2012). A Greenhouse Gas Reduction Roadmap for Oil Sands. Prepared CCEMC. http://ccemc.ca/wp-content/uploads/2012/12/C101221-CCEMC-GHG-Reduction-Roadmap-Final-Report.pdf 11 Jacobs Consultancy (2009). SAGD Energy Efficiency Study. Prepared for Alberta Energy Research Institute. http://www.ai-ees.ca/media/12516/aeri-jacobs_consultancy_sagd_study-1009c-jg_final_rev1.pdf


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recovered to further process bitumen. These areas include: heat lost to the ground within

the reservoir; heat lost through the use of air coolers; heat lost through flue gas; heat lost from disposal of water; and consumption of electricity. The report helps identify a baseline ideal energy loss rate, defined as the energy lost when all energy recovery systems are working to their maximum capacity. The vast majority of this lost energy, more than 98 percent, is lost to heating the ground within the reservoir. Of course, the ideal scenario cannot be physically achieved, as it assumes unrealistic achievements such as 100 percent recovery of waste heat and zero energy requirements for boiler feed water treatment, but it allows for a good comparison for typical operations at SAGD facilities and the efficacy of alternative scenarios.

A typical SAGD facility was defined as operating under the following characteristics:

An operating pressure of 3,400 kPa and an SOR of 3.3;

Gas lift for fluid production from the reservoir;

Glycol circuits for heat recovery and transfer; and

Warm lime softening for water treatment and once-through-steam generator (OTSG) for generating steam.

Under these typical conditions, energy losses were 63 percent higher than the ideal minimum energy scenario. The major effective alternative scenarios were as follows:

Use of mechanical lift (energy loss reduction of 395 GJ per hour): using a mechanical process to pump produced fluids to the surface, such as the use of downhole pumps, made a very large difference in energy loss, and was only 24 percent higher in energy loss

than an ideal SAGD operation. Gas lift, which uses a high reservoir pressure to push produced reservoir fluid to the surface, results in both higher losses of heat to the earth within the reservoir and requires higher SOR (3.3 compared to 2.7). Additionally, the high pressure fluids produced tend to flash vapours when brought to the surface, which removes recoverable heat from oil emulsion and requires more capital expenditures to deal with the produced gases. Downhole pumps allow the reservoir to be operated at a lower pressure, reducing the energy required for steam generation and the amount of energy lost to the earth.

Eliminate glycol use (energy loss reduction of 28 GJ per hour): while this has a smaller effect, replacing a glycol energy recovery system with direct heat exchangers to preheat the combustion air and boiler feed water reduces energy loss within the system.

Reduce stack heat losses (energy loss reduction of 67 GJ per hour): this involves using both boiler blowdown (the liquid water left after steam generation) and flue gases from the boiler to preheat combustion gases, and reducing the stack temperature to 130 °C.

The available reductions due to downhole pumps/mechanical lift, minimizing glycol use through direct heat exchange, and reducing the amount of boiler blowdown are shown


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in Figure 2.1. The typical and ideal energy losses and the potential gains from these three

techniques are also illustrated.

Figure 2.1: Typical Energy Loss in SAGD Operations Compared to the Theoretical Minimum Energy Loss per Hour of Operation

Source: Jacobs 2009

What was not effective in reducing energy consumption further was minimizing boiler blowdown by using drum boilers instead of OTSGs to generate steam. Drum boilers

generate a higher quality steam, but necessitate a higher quality feed water through the use of evaporators rather than warm lime softening. Evaporators are more energy-intensive than lime softening for water treatment, and thus this increases the overall energy use.

Although the Jacobs consultancy report presents gas lift as “typical,” mechanical lift is being increasingly adopted by the industry. Cenovus’ Christina Lake12 and Foster Creek13, and Statoil’s Leismer14 projects use entirely mechanical lift as of 2013. Others, including

12 Cenovus Christina Lake In-situ Oil Sands Update for 2013. http://www.aer.ca/documents/oilsands/insitu-presentations/2014AthabascaCenovusChristinaSAGD8591.pdf 13 Cenovus Foster Creek In-situ Oil Sands Update for 2013. http://www.aer.ca/documents/oilsands/insitu-presentations/2014AthabascaCenovusFosterCreekSAGD8623.pdf 14 Statoil Leismer SAGD 2014 Performance presentation. http://www.aer.ca/documents/oilsands/insitu-presentations/2014AthabascaStatoilLeismerSAGD10935.pdf

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Suncor’s Firebag,15 Shell’s Orion,16 CNOOC/Nexen’s Long Lake,17 MEG’s Christina Lake,18

ConocoPhillips’ Surmont, 19 and Connacher’s Great Divide 20 projects have made considerable progress towards installing downhole pumps. There are still locations, however, at which this technology has yet to be fully adopted, and represents an area in which improvements may still be made. Although there are additional capital costs with the installation of downhole pumps, and the advantages are slightly lower for projects with the existing infrastructure to handle gas lift, energy savings can be substantial enough due to reduced operating pressure to incentivize the installation.

Another existing production strategy called Wedge Wells has been used by Cenovus to increase bitumen production.21 The process involves drilling an additional production well between two producing SAGD well pairs. Pockets of bitumen can exist between well pairs that do not efficiently drain to the existing producing wells. This increases recovered

bitumen without the use of additional steam or water, reducing the overall impact per barrel of produced bitumen for the project. At Cenovus’ Foster Creek project, since 2010 typically in excess of 12 percent of total bitumen production (or approximately 2,000-2,500 m3 of production per day) comes from Wedge Well production.22 The Wedge Well uses an additional production well placed between producing well pairs to increase the area of the reservoir from which mobilized bitumen may be recovered. The process is illustrated in Figure 2.2.

15 Suncor Firebag 2014 AER Performance Presentation. http://www.aer.ca/documents/oilsands/insitu-presentations/2014AthabascaSuncorFirebagSAGD8870.pdf 16 Shell In Situ Oil Sands Progress update 2014. http://www.aer.ca/documents/oilsands/insitu-presentations/2014ColdLakeShellOrionSAGD10103.pdf 17 CNOOC/Nexen Long Lake 2013 Performance Presentation http://www.aer.ca/documents/oilsands/insitu-presentations/2014AthabascaNexenLongLakeSAGD9485.pdf 18 MEG Energy Christina Lake 2013/2014 Performance Presentation. http://www.aer.ca/documents/oilsands/insitu-presentations/2014AthabascaMEGChristinaLakeSAGD10773.pdf 19 ConcoPhillips Annual Surmont SAGD Performance Review 2014. http://www.aer.ca/documents/oilsands/insitu-presentations/2014AthabascaConocoSurmontSAGD94609426.pdf 20 Connacher Performance Presentation 2014. http://www.aer.ca/documents/oilsands/insitu-presentations/2014AthabascaConnacherGreatDivideSAGD10587.pdf 21 Cenovus Energy: Wedge Well technology. http://www.cenovus.com/operations/technology/wedge-well-tm-technology.html 22 Cenovus Foster Creek In-situ Oil Sands Update for 2013. Inhttp://www.aer.ca/documents/oilsands/insitu-presentations/2014AthabascaCenovusFosterCreekSAGD8623.pdf


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Figure 2.2: A Schematic of Cenovus’ Wedge Well Technology

Source: Cenovus Energy

Finally, cogeneration is an effective way of increasing the overall efficiency of a project, although part of this is indirect. Thermal in situ processes require both steam and electricity to operate, and cogeneration plants use natural gas to generate both in a manner more efficient than producing steam and electricity in isolation. This is primarily driven by the relative inefficiency of stand-alone electricity generation. Much of the

energy is lost as heat; a conventional coal-fired power plant, which provides 39 percent of installed electricity generation in Alberta,23 operates with an efficiency rate of about 33 percent, compared to 40 percent efficiency rate for a typical natural gas power plant and over 80 percent for a natural gas-fired cogeneration plant. 24 , 25 A SAGD project typically requires steam more than electricity, and so a cogeneration plant at a SAGD facility will typically sell excess electricity back to the grid.26

The overall efficiency of producing electricity and steam in tandem is better than using grid electricity (where waste heat is less likely to be recovered for industrial use) and

23 www.aeso.ca 24 https://ec.gc.ca/energie-energy/default.asp?lang=En&n=7ED2A11B-1 25 Zhang et al. (2014). Key factors for assessing climate benefits of natural gas versus coal electricity generation. Environmental Research Letters 9, 114022. 26 CIEEDAC (2012). A review of existing cogeneration facilities in Canada. Prepared for Natural Resources Canada, Environment Canada, and CIEEDAC Supporters. http://www.cga.ca/wp-content/uploads/2013/04/Cogeneration_Report_2012_Final.pdf


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stand-alone OTSGs. The advantage is even greater when the gas cogeneration unit sells

electricity into a grid that is primarily coal-fired. Coal produces more GHGs per unit energy than natural gas (96 kg and 52 kg CO2 per million Btu, respectively),27 and so the gas-fired electricity lowers the overall carbon intensity of the produced electricity on the province’s grid. Where plausible, use of cogeneration can be an effective tool for increasing efficient use of natural gas.

The in situ oil sands producers have been particularly successful at reducing reliance on fresh water and achieving high recycle rates. Water usage is regulated through the AER’s Directive 80: Water Disposal Limits and Reporting Requirements for Thermal In Situ Oil Sands Schemes, 28 which sets disposal limits on the amount of fresh, brackish, and produced water taken in by a SAGD operator. Despite growth in SAGD production, fresh water use has stayed nearly constant between 2002 and 2013, with brackish water being

used as a water source instead.29 For each barrel of bitumen produced in 2002, more than one barrel of water, almost entirely composed of fresh water, was required; recycle rates near 95 percent now mean that just over half a barrel of water is needed to produce a barrel of oil, brackish water accounts for half of this volume. There may yet be room to improve this performance, but substantial progress has been made to improve the efficiency of water recycling over the past decade.

Oil Sands – Mining and Upgrading Stantec’s report also addresses the mining and extraction portion of the integrated mining and bitumen sector.30 Mining and extraction was reported to have a baseline energy use of 1.55 GJ per m3 of bitumen produced. A reduction of energy intensity of 13 percent was identified, primarily through the adoption of improved control systems, heat

exchange improvements, and better monitoring and management of energy use. The report does not elaborate on which potential strategies lead to the greatest reduction in energy use, but the potential strategies include:

Decreasing diesel use by reducing idle time, introducing fuel monitoring for equipment, changing road design, and adopting fuel efficient mine shovels;

Examine and modify standard operating procedures to reduce hot water use, reduce reliance on multiple hydrotransport lines, improve tailings management and improve maintenance and operations of heat exchangers;

27 http://www.epa.gov/climateleadership/documents/emission-factors.pdf 28 http://www.aer.ca/rules-and-regulations/directives/directive-081 29 CERI Study 143 (2014). Oil Sands Environmental Impacts. http://www.ceri.ca/images/stories/2014-09-18_CERI_Study_143.pdf 30 Stantec Consulting Ltd. And Marbek Resource Consultants Ltd. Energy efficiency potential in Canada’s upstream oil and gas sector. Project 115301592. Prepared for NRCan.


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Add controllers to optimize line flushes, steam use in naphtha recovery units and tailings lines; and

Investigate methods to better make use of heat recovery.

Most mining projects, with the exception of Imperial Oil’s Kearl mine, also make use of upgrading to convert low-value bitumen to synthetic crude oil. The upgrading process is quite energy-intensive itself, more so than the mining and extraction process, requiring 2.7 GJ per m3 of bitumen produced. 31 Available and economically viable efficiency technologies can reduce energy consumption by 13 percent to 2.35 GJ per m3 of bitumen. The measures span a number of classes of project improvements, including:

Optimizing operations such as adopting improved energy management systems, managing use of fuel gas, improving steam use, and reduction of flaring;

Increasing furnace efficiency;

Improving use of hot process water by using higher-grade heat sources and improving insulation on hot water process lines;

Improving boiler usage by allowing boilers to operate on fuel gas or converting to higher efficiency cogeneration units; and

Installing systems to recover flare gas.

Overall GHG emissions for mining, extraction, and upgrading, reported as 0.46 MT CO2e per m3 of bitumen, are reduced by approximately 9 percent to 0.42 MT CO2e per m3 of bitumen based on the currently available improvements in technology.

One particular concern for mining and extraction use is the use of water, as the

production of a barrel of synthetic crude oil from mining projects requires, on average, 3.2 barrels of fresh makeup water, primarily due to the inability to separate solids from liquids in mature fine tailings (MFT) produced in the extraction process.32 MFT represent a large source of water that cannot be easily recycled in the extraction process, in addition to taking up a large amount of land space for storage.

Directive 074 from the AER addressed tailings management issues by requiring mines to present tailings management plans and minimum disposal rates of tailings in order to prevent the proliferation of tailings ponds.33 Industry has made large investments and responded with a number of new technologies to separate the solids from the water in

31 Jacobs Consultancy and Suncor Energy (2012). A Greenhouse Gas Reduction Roadmap for Oil Sands. Prepared CCEMC. http://ccemc.ca/wp-content/uploads/2012/12/C101221-CCEMC-GHG-Reduction-Roadmap-Final-Report.pdf 32 CERI Study 143 (2014). Oil Sands Environmental Impacts. http://www.ceri.ca/images/stories/2014-09-18_CERI_Study_143.pdf 33 AER Directive 074: Tailings Performance Criteria and Requirements for Oils Sands Mining Schemes. http://www.aer.ca/rules-and-regulations/directives/directive-074


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mine tailings, but projects have been unable to meet the standards set for tailings disposal

rates,34 and currently the directive has been suspended. Water and tailings management is an ongoing challenge in the oil sands mining and extraction sector, and perhaps with more time the tailings disposal techniques will be honed to the point that higher water recycle rates can be achieved and fewer tailings ponds will need to be constructed.

While the upgrading process generates a higher value synthetic crude oil product that does not require diluent for pipeline shipments, it is a very energy- and capital-intensive process that is difficult to undertake in an economically viable manner. Most planned new upgraders have been cancelled because full integrated mining projects are among the most difficult projects to gain a return on investment. Imperial Oil’s Kearl mining project is an example of a new oil sands mine that does not have an integrated upgrader.

34 2012 Tailings Management Assessment Report: Oil Sands Mining Industry (2013), Energy Resources Conservation Board. http://www.aer.ca/documents/oilsands/tailings-plans/TailingsManagementAssessmentReport2011-2012.pdf


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Chapter 3: Shale Gas Shale reservoirs have been historically underused as natural gas resources. Unlike conventional gas reservoirs, shale beds have a very low porosity. A typical conventional vertical well, then, will yield very small volumes of gas, as it does not naturally flow through the reservoir. Hydraulic fracturing, however, has allowed for the development of this resource on a larger scale, and opened up previously unattainable resources – such as those in the Montney and Horn River basins in northeastern British Columbia – for new development. Despite current low gas prices, shale resources are being developed in BC; 80 percent of rigs released in 2012 in the province have targeted the Montney play. Unconventional gas makes up 69 percent of the total gas reserves in the province, with 33 percent of total reserves in the Montney Basin and 28 percent in the Horn River basin.1

Production Process Shale gas wells use horizontal drilling to maximize the amount of the resource that is exposed to a single well and minimize the number of wells needed. Once the well is drilled, the fracturing process begins (an illustration from the BC OGC is shown in Figure 3.1). Due to the length of the horizontal well, which can be several kilometres, it is exceedingly difficult to have high enough pressure to fracture an entire well in one step. Rather, the process is staged, working from the toe to the heel of the horizontal well portion. A segment of the well lining close to the toe (i.e., the end of the well) is perforated, and fracturing fluid is pumped into the well at a high pressure. This high-pressure fluid is forced through the well perforations and into the shale, where the high pressure induces fractures within the shale, allowing channels through which gas can

more readily flow.

The first injection typically uses slickwater, which is water with additives to reduce the fluid viscosity. The lower viscosity reduces pressure lost within the well and allows for more efficient fracturing. Following this, fluid containing a proppant, usually sand, is injected into the well. Gelling additives are typically added to this fluid to push the proppant into the fractures. The purpose of the proppant is to hold the fractures open and allow for unimpeded gas flow once the well is completed. Following the fracturing, a drillable well plug is placed behind the newly fractured stage of the well, and the process continues from toe to heel until the whole horizontal length of the well has been fractured. At this point, the plugs separating the stages are drilled out, the well is completed, and production begins.

1 BCOGC (2012). Hydrocarbon and By-Product Reserves in British Columbia. http://www.bcogc.ca/node/11111/download


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Figure 3.1: A Simplified Graphic of the Shale Gas Hydraulic Fracturing Process


After production begins, there is very little that differentiates shale gas developments from conventional gas developments. Adopting the appropriate best practices for the above ground part of the well should make the process as efficient as possible. However,

there are some unique challenges to shale gas development, particularly as it relates to the northeastern BC context and the relative lack of existing gas development infrastructure in the region. Some of the challenges and potential for increased efficiency in the development of this region are the focus of this chapter.

Water Use and Wastewater Management The injection of high volumes of hydraulic fracturing fluid into the reservoir is the key difference between a typical shale gas well and conventional gas wells. In 2013, British Columbia saw 433 hydraulically fractured wells drilled with an average water use of approximately 12,300 m3 per well.2 The majority (403) of these wells were in the Montney Basin, taking an average of 9600 m3 of water per well. The Horn River Basin, which has much tighter shale formations, saw only 18 wells drilled, but an average volume of

approximately 79,100 m3 was required per well. The breakdown of water use is given in Table 3.1. Section 8 allowances are unlicensed water withdrawals issued at the discretion of a comptroller or regional water manager for water used on a temporary basis lasting less than 24 months. Although this water use is not formally licensed, oil and gas

2 BC Oil and Gas Commission. Water Use for Oil and Gas Activity 2013 Annual Report. http://www.bcogc.ca/node/11263/download


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companies must report monthly water use under a BC Oil and Gas Commission (BCOGC)

directive.

Table 3.1: Sources of Water Used for Hydraulic Fracturing in British Columbia, 2013

Source Percentage

Section 8 allowances 48.8

Water licenses 13.5

Fresh water wells 7.0

Saline water wells 0.8

Reuse of flowback (estimated) 15.0

Municipal wastewater 4.3

Private acquisition/produced water 10.6


Surface fresh water accounts for 62.3 percent of all water used and 7 percent comes from fresh water wells, with the remaining 30.7 percent coming from non-freshwater sources, including saline water, flowback reuse, and municipal wastewater. While some of the injected water remains in the reservoir after fracturing is complete, there will be flowback of injected fluids containing additional dissolved and suspended solids from the reservoir. It is against regulations to dispose of flowback to the environment, so produced water must be stored until it is either treated or sent for disposal.

Water management is an important aspect of the unconventional drilling process, as it accomplishes a number of goals:

Reducing reliance on makeup water can save money and resources by reducing the required transport of water on-site, and has positive environmental effects by reducing pressure on the local watershed;

Reuse of produced water may reduce operating costs by decreasing the need for additional chemical additives to the fracturing fluid; and

Reducing the final volume of wastewater will reduce costs with transport and disposal of flowback water after wells are completed.

Watersheds in northeastern BC have experienced severe enough water shortages that as recently as August 2014, the government suspended most of the water use from rivers, creeks, streams and lakes with the exception of 8 large rivers and two lakes.3 Part of this

suspension remains in place for the Liard River basin as of December 2014.4 Similar suspensions of water use were in place in 20125 and 2010.6 To have certainty moving

3 BCOGC Directive 2014-01 2nd Update. https://www.bcogc.ca/node/11287/download 4 BCOGC Directive 2014-01 4th Update. https://www.bcogc.ca/node/12274/download 5 BCOGC Directive 2012-01. https://www.bcogc.ca/node/8026/download 6 BCOGC Directive 2010-05. https://www.bcogc.ca/node/5839/download


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forward in the development of shale gas resources in this region, ways to work within the

sometimes-limited water resources in the region must be found.

One method is to store water on-site in dugouts during times when surface water is not limited. Typically, BCOGC directives that have limited the use of surface water is confined to lakes, streams, and rivers in a particular watershed, while dugout water use is allowed (although, if lack of rain has led to low water levels in lakes and streams, it may also be difficult to keep sufficient water quantities in dugouts). Another option is to source water from larger rivers and lakes that are less likely to experience low flow events. However, the ability to do this may be limited by the location of the well and the economics of water transport from water sources further from the drilling site.

Another option to increase reliability of water sourcing and reduce the environmental

impact of water use is to reduce reliance on surface fresh water. One such method is to find ways to reuse wastewater from other sources. Shell and the city of Dawson Creek struck a partnership to build a wastewater treatment plant in the city that opened in 2012.7 Prior to this, Dawson Creek had its own issues meeting water demand in times of drought while industry was using up to 20 percent of the municipal water draw. Lack of appropriate water treatment meant that wastewater could not be reused. Shell invested 81 percent of the total facility cost. Now treated wastewater is up to the standard of industrial and municipal use, and Shell retains use of 85 percent of the wastewater for use in their shale gas development.8 The arrangement gives Shell a reliable source of water for industrial use, gives the city of Dawson Creek a lasting piece of water treatment infrastructure, and reduces the reliance of both on fresh surface water from the region.

The shale gas industry can continue to look for more opportunities to situate themselves downstream from large, non-consumptive water users as the number of wells expand in northeast BC. The major advantages of using outside wastewater include:

Decreased reliance on freshwater from a local watershed that could be constrained by lack of rainfall;

Shared costs of water transport, treatment, and disposal for the initial water user and the wastewater user; and

A continuous and reliable source of water that is of high enough quality for use as hydraulic fracturing fluid.

While use of wastewater from other municipal or industrial processes should continue to

be explored as this resource is expanded, the shale gas industry has to deal with its own wastewater production as well. While the process is at least partly consumptive (that is, some of the fracturing fluid is inevitably lost to the reservoir), flowback water, and

7 http://www.shell.ca/en/aboutshell/media-centre/news-and-media-releases/2012/0907dawson-creek.html 8 http://watercanada.net/2013/dawson-creekshell-canada-water-treatment-project/


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improvements to the fracturing process mean that up to half of the fracturing fluid can

be recovered from the well. The fluid contains the original water and chemical additives, but also can contain very high concentrations of dissolved solids from the shale reservoir. In addition to suspended solids, dissolved natural gas, and, in some cases, low to high levels of naturally occurring radioactive matter/material are present. This flowback presents several challenges and opportunities:

How should the flowback fluid be managed during well completion and early stages of production?

Can flowback water be effectively reused during the fracturing of future wells?

How should produced flowback be treated and/or disposed of following the completion stage of the well?

The first question on what to do with flowback water has relatively little implications for the overall fate of reuse or disposal. The regulations are such that fracturing fluid cannot be released to the environment, and as such there must be on-site storage for the fluid to be held prior to transport for treatment or disposal. However, the well completion process requires the simultaneous handling of liquid and gas production. The way that the gas portion is handled during this process can have major implications to the life cycle greenhouse gas emissions of natural gas produced from shale reservoirs.

In an ideal scenario, well completion is performed as a “green completion.” In a green completion, the produced fluid and gas are separated and the gas is sent to the collection system and sold to market for processing. This requires that the gas well be tied-in, or connected, to an existing gas collection system. The next best alternative is to flare gas

during completion. Carbon dioxide is created when gas is flared. This option has a lower global warming potential than venting the natural gas. Concern has been raised by some research organizations that methane loss during well completion could make shale gas production more GHG-intensive than conventional gas. One outlier study found that if gas produced during well completion is entirely vented (counter to common practice and regulations in some jurisdictions), shale gas can be approximately 14 to 19 percent more GHG-intensive than conventional gas on a 100-year period.9 Typically, however, large-scale venting of gas is not the norm in the industry, and life cycle analyses report that GHG emissions are similar for shale gas and conventional natural gas (according to one meta study, emissions are nearly identical at 465 and 461 g CO2e/MWh, respectively, for electricity generation).10 This is an important factor, given that one of the drivers of shale

9 Howarth et al. (2011). Methane and the greenhouse-gas footprint of natural gas from shale formations. Climatic Change 106, 679-690. 10 Heath et al. (2014). Harmonization of initial estimates of shale gas life cycle greenhouse gas emissions for electric power generation. PNAS 111, E3167-E3176.


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gas development is the push to find cost-effective fuel sources to replace coal, which has

higher GHG emissions per unit of energy than natural gas.

The technology exists to allow for green well completions that recover produced gas for sale rather than flaring or venting, and regulations requiring the conservation of produced gas during well completion are effective at reducing these activities. Analysis of hydraulically fractured gas wells in Alberta,11 with relatively mature flaring regulations through the Alberta Energy Regulator Directive 060, found that of 1,579 wells, 643 were green completions compared to 544 with flaring or venting (371 could not be classified due to confidential data). Of the 407 tight gas wells reporting venting and flaring, 99.5 percent of released natural gas volume was flared rather than vented.

The United States Environmental Protection Agency has likewise required that emissions

reduction measures be used to reduce methane and volatile organic compound emissions from all new wells.12 The BCOGC has a venting and flaring guideline with nearly identical requirements to the AER Directive 060,13 and so gas conservation should be considered the norm for wells in this region. This does require tie-ins to a commercial collection line, but for wells already intended for commercial production this is unlikely to be a problem.

Now that the well has been completed and flowback has been collected, there is a decision to be made with the produced water. As highlighted in a document prepared for the Petroleum Technology Alliance of Canada and the Science and Community Environmental Knowledge Fund,14 the options for produced water range from reuse of water as is to total disposal. The problem with the former is that the flowback water is often very high in additional dissolved contaminants from the reservoir. In a report

prepared by PennWest for PTAC,15 flowback water from fracturing of tight oil reservoirs showed very wide ranges in total dissolved solids, ranging from about 3,300 milligrams per litre (mg/L) to 116,000 mg/L, and some contained high levels of metal ions that can lead to formation of solids within water. Direct reuse without treatment can lead to scaling of equipment and possible equipment failures.

In addition, chemical constituents may interfere with the efficacy of chemical additives aimed at changing the physical properties of the fracturing fluid. This may lead to poorer fracturing, unplanned shutdowns of fracturing equipment, or requirements for use of

11 Tyner and Johnson (2014). Emission factors for hydraulically fractures gas wells derived using well- and battery-level reported data for Alberta, Canada. Environmental Science and Technology 48, 14772-14781. 12 http://www.epa.gov/airquality/oilandgas/pdfs/20120417fs.pdf 13 BCOGC Flaring and Venting Reduction Guideline Version 4.4. http://www.bcogc.ca/node/5916/download 14 M-I SWACO (2012). Fracturing Fluid Flowback Reuse Project: Decision Tree and Guidance Manual. Prepared for PTAC and SCEK. http://www.scek.ca/sites/default/files/documents/scek-ra2011-02-fracturing-fluid-flowback-reuse-report-final.pdf 15 PennWest Exploration (2012). Reuse of Flowback and Produced Water for Hydraulic Fracturing in Tight Oil. Prepared for PTAC. http://www.ptac.org/projects/151.


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more expensive fracturing chemicals. Knowledge of the flowback water chemistry is

crucial before direct reuse is considered.

Given the problems that can arise with reusing fracturing fluid, straight disposal may be tempting. However, even considering up to 50 percent recovery, this represents about 4,500 m3 for the average 2013 Montney well and nearly 40,000 m3 for the average 2013 Horn River well. This water must typically be trucked for disposal in underground wells if not reused, which can be an expensive option (and doubly so if an operation is relying on trucked water for drilling future wells). The cost disadvantage of disposal often depends on the availability of disposal wells; in the Marcellus Shale, with few disposal wells nearby, water reuse saves on the order of $370,000 US per well, while abundance of disposal wells near Eagle Ford Shale developments make recycling vs. disposal roughly cost neutral.16

The most inexpensive “treatment” option for flowback water is to simply dilute with fresh water. For example, flowback water with chloride content higher than 60,000 mg/L necessitates the use of higher cost fracturing additives, but diluting with low-chloride fresh water can allow for less expensive additives to be utilized.17 This may be necessary in any case, since water is typically partially lost to the reservoir. Dilution may also be used to make saline groundwater suitable to be used as part of the fracturing fluid.

The next options for treatment are chemical conditioning and physical or chemical treatment. Chemical conditioning involves chemical additives such as scale inhibitors or biocides to prevent equipment scaling or microbial growth. Physical or chemical treatment increases the purity of the water using some treatment method such as

precipitation of ions that result in scaling, softening, reverse osmosis, crystallization, or evaporation. Chemical conditioning may be necessary for water reuse, particularly for inhibiting scale generation. Adoption of water treatment is perhaps less likely to happen on an industry-wide scale.

One problem with these techniques is that because the total dissolved solids are so high, these technologies end up being prohibitively expensive on a project level scale. Since fracturing additives exist that can work in high salinities, these water treatment techniques can often work to provide a much higher quality of water than is necessary and require significant additional energy use.

A case study of flowback from the Montney basin suggests that dilution and chemical

conditioning may be well suited to meet the needs of this region.18 With average flowback volumes of 50 percent, flowback must be diluted by half. This brings salinity to an

16 http://www.reuters.com/article/2013/07/15/us-fracking-water-analysis-idUSBRE96E0ML20130715 17 M-I SWACO (2012). Fracturing Fluid Flowback Reuse Project: Decision Tree and Guidance Manual. Prepared for PTAC and SCEK. http://www.scek.ca/sites/default/files/documents/scek-ra2011-02-fracturing-fluid-flowback-reuse-report-final.pdf 18 Ibid.


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appropriate concentration, and while there are potential problems with scaling at the

typical flowback water chemistry, this can be dealt with cost-effectively using scaling reduction additives. The one unknown factor is the effect of residual fracturing additives such as gelling agents that may be incompatible with the slickwater additives, and may require ozonation prior to reuse.

While current practices may not require water treatment, this option could be further examined as the resource continues to grow in British Columbia. Continual development may allow for the economies of scale and water demands to reach a point were collective water treatment may become an option. There are also options for smaller-scale treatment that are more cost-effective than traditional techniques, including an evaporation process that requires approximately 5 percent of the energy of traditional evaporators that has been used for water treatment for both oil and shale gas

wastewater.19

Drilling and Fracturing Materials Drilling and materials are some of the major factors that contribute to capital cost escalation in the shale gas sector. The actual drilling and hydraulic stimulation procedures for shale gas development involve a concentration of heavy equipment on-site. Transportation of these drilling supplies and materials for the multiple wells is often handled by stockpiling at the well site in advance.

The most cost-effective process is drilling of multiple wells from a single pad location to reduce the footprint of shale gas operations. By utilizing economies of scale, strategic alliances, materials management efficiencies, and service sector and footprint sharing,

this concentration of equipment and materials can lead to significant savings in operations.20 Coordination of drilling activities and use of drilling equipment storage closer to British Columbia shale development can reduce the cost of transporting rigs and supplies as new wells are developed. Additionally, this will reduce the amount of transit-related downtime once drilling rig utilization rates once again increase.

Each stage of drilling requires significant equipment that in many cases is mobilized from the service center that may be far away. In order to cut these substantial mobilization costs, multiple wells may be drilled at the same time resulting in costs being defrayed over the total number of wells. Economies of scale can be applied to all stages of drilling required. One such example is the Encana Corporation Resource Play Hub model, which has bundled services and constructed a large multi-well drilling pad from a single location

to allow for significant savings during the drilling to hydraulic fracturing stages of development. Specifically in the Montney play, efficiencies and economies of scale have resulted in savings of $0.16/mcf, which has improved competitiveness of the project. Through this process, improved efficiency in the number of fracture stimulations per

19 http://www.aqua-pure.com/technology/evaporation/evaporation.html 20 Michael Dawson, et al, Improved Productivity in the Development of Unconventional Gas, May 2012


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month per crew has tripled the productivity of the fracture stimulation crews from 2008

to 2012.

In addition to these benefits, other advantages include:

reduced cumulative footprint

reduced total time for development

minimized need for large cranes and crews for rig moves

minimized spills, reduction in road building

reduction in length of surface or buried gathering lines

simplified installation of spill containment berms and leak prevention liners

reduction in truck traffic

ease of inspection at one site

the ability to use low profile wellheads

the ability to concentrate on development activities

the ability to handle produced water at a centralized location

reduced drilling days per well, and

cost savings.21

A number of chemicals may be added to the fluid-proppant mixture (sand, resin coated sand, or ceramic particles) to ensure that the proppant is being carried as far into the fractures as possible. These fracturing fluids contain several different chemical additives mixed in different proportions, depending on the operator and reservoir. Companies are increasingly supporting the development of fracturing fluid additives with the least environmental risk.22 In addition, support has been expressed for disclosing fracturing

fluid additives, with some chemical suppliers developing less toxic “green chemicals” for use in hydraulic fracturing operations or reducing chemical usage overall.23

Another pollutant is crystalline silica dust usually generated from the sand proppant, which can be reduced by product substitutions, engineering controls and improved personal protective equipment.24 Concern over the additives used in hydraulic fracturing has led the BC OGC to develop regulations on fracturing fluid composition disclosure through the Frac Focus chemical disclosure registry.25

21 For more details and case studies, please see the CERI Report: Improved Productivity in the Development of Unconventional Gas May 2012 22 CAPP Guiding Principles of Hydraulic Fracturing January 2012 23 The Modern Practices of Hydraulic Fracturing: A Focus on Canadian Resources: PTAC June 2012 24 Hydraulic Fracturing and Shale Gas Production: Technologies, Impacts and Regulations April 2013 25 http://fracfocus.ca


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In 2013, the NEB announced their intention to require all companies regulated under the

Canada Oil and Gas Operations Act to publicly disclose hydraulic fracturing fluid information on Frac Focus.26

A range of waste fluids are generated at shale gas wells. These drilling wastes can be managed on-site in pits that are designed to keep liquids from infiltrating water resources. Specifically, Alberta and British Columbia are geologically suited to massive deep wastewater disposal because thick permeable saline aquifers are available at reasonable depth.27 During the flowback stage, as much as half of the fluid is recovered, but is considered to be consumed water, and cannot be returned to the environment without additional treatment. Therefore, to reduce their environmental impact, the industry goal is to treat and recycle the fluids used for fracturing. Furthermore, the quality and quantity of regional surface and groundwater resources can be protected through sound wellbore

construction practices and sourcing freshwater alternatives where appropriate.28

Transportation of materials to remote locations adds to the cost of materials. Proactive communication between suppliers of materials and producers is a key element for improved efficiencies from a reliability and accuracy standpoint. Local suppliers of fracturing additives and materials can help to reduce the cost of transport and provide additional economic opportunities to the communities near shale gas plays.

Another process known as the vertical integration model,29 which is more applicable to larger projects where economies of scale are possible, involves natural gas operators in the region acquiring or creating specific support businesses to provide key equipment or material supplies for the project development. By owning and operating these services or

suppliers, operators can ensure access to equipment and materials, as well as provide stability in the supply chain management of those services and supplies.

Energy Use Both drilling rigs and fracturing fluid pumps require considerable amount of energy to operate. This fuel typically comes in the form of diesel, which as a liquid fuel is easily

transported by truck to the well site.

This choice of fuel, however, can add to the operating costs of drilling, fracturing, and completing a shale gas well. Switching to a less expensive fuel, such as natural gas, can reduce the price paid for fuel making the well. The average reference price of natural gas

26 http://www.neb-one.gc.ca/bts/nws/nr/archive/2013/nr32-eng.html 27 Council of Canadian Academies, 2014. Environmental Impacts of Shale Gas Extraction in Canada. Ottawa (ON): The Expert Panel on Harnessing Science and Technology to Understand the Environmental Impacts of Shale Gas Extraction, Council of Canadian Academies. 28 CAPP Guiding Principles of Hydraulic Fracturing January 2012 29 CERI Report: Improved Productivity in the Development of Unconventional Gas May 2012


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in Alberta was $4.00 per GJ in 2014,30 compared to the average Edmonton wholesale

diesel price of $24.45 per GJ.31 The average estimated amount of diesel used during shale gas well drilling in Alberta in 2011 was 47.5 m3 per unique well identifier.32 By using natural gas instead of diesel, cost reduction can be in the range of 40 percent.33 Around 5-6 percent of Alberta’s drilling rig fleet is equipped with dual-fuel engines that handle both natural gas and diesel, and are estimated to use natural gas fuel 80 percent of the time. Typical dual-fuel rigs can achieve 40-60 percent substitution of natural gas for diesel.34 Therefore, industry is working to cut down drilling and transportation costs by switching engines from diesel to natural gas where possible.

In addition, this switch also comes with a major environmental benefit: for each liter of diesel displaced by burning natural gas, CO2 emissions are reduced significantly. For example, CO2 emissions from a rig operated on dual-fuel would be reduced by about 15.5

percent.35 Some solutions such as dual-fuel service in fracking pumps or using large trucks, which transport compressed natural gas for use as a fuel to drilling rigs,36 allow for higher efficiency and lower emissions.

Using natural gas over diesel during the fracking process in either pumps or ancillary equipment can significantly reduce emissions because it is less chemically complex, and its combustion generally results in less emissions of pollutants such as nitrogen oxides and particulate matter.37 Subsequently, environmental controls on gas equipment, if required, tend to cost less than those for other fuels due to the inherent cleanliness of gas. Tailpipe CO2 emissions from burning natural gas in heavy-duty trucking applications are less than a quarter of those from burning diesel. However, research suggests that exhaust treatment technology, which is more important than the type of fuel used, must

be taken into account to obtain the optimal emissions gains from a shift to natural gas in trucks.38

30 Alberta Energy Natural Gas Reference Price History. http://www.energy.alberta.ca/NaturalGas/1322.asp 31 Calculated based on an average price of 94.4 cents per litre (http://www2.nrcan.gc.ca/eneene/sources/pripri/wholesale_bycity_e.cfm) and a heating value of 138 490 Btu per gallon (http://www.afdc.energy.gov/fuels/fuel_comparison_chart.pdf). 32 Evaluation of Emissions related to hydraulic fracturing, Carleton University, David R. Tyner and Matthew Johnson, March 20, 2014 33 FuelFix. 2013. Fracking with natural gas to trim fuel costs 40%. http://fuelfix.com/blog/2013/01/07/fracking-with-natural-gas-to-trim-fuel-costs-40/ 34 Scott, K. (2013). Dual-fuel systems power up. Drilling Contractor 35 Evaluation of Emissions related to hydraulic fracturing, Carleton University, David R. Tyner and Matthew Johnson, March 20, 2014 36 Cangas solutions “Pipeline on Wheels” service: http://cangassolutions.com/services/natural-gas-transport 37 American gas association: https://www.aga.org/environmental-benefits-natural-gas 38 Amy Myers Jaffe, Rosa Dominguez-Faus, Allen Lee, Kenneth Medlock, Nathan Parker, Daniel Scheitrum, Andrew Burke, Hengbing Zhao, Yueyue Fan (2015) “Exploring the Role of Natural Gas in U.S. Trucking”


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June 2015

Chapter 4: Oil Sands The oil sands already comprise a considerable portion of Canada’s oil production. As of 2013, oil sands production totaled 2.1 million bpd, with SCO and non-upgraded bitumen accounting for 54 percent of Canadian crude oil production.1 The NEB projected in 2012 that by 2035, oil sands would make up 86 percent of Canada’s 5.8 million bpd production, with the largest growth coming from in situ bitumen production.2

The capital cost of building an integrated oil sands mine is in the range of $100,000 to $120,000 in 2012 Canadian dollars per barrel and the economics require a WTI price of $80 to $100 per barrel. This is not to say that mining projects are not being considered, as Imperial recently started production on the Kearl mine project, although without the

presence of an upgrader. Paraffinic froth treatment allows the project to operate without

the use of upgrading; this will be discussed in the first section of this chapter. Few new mines are expected to be developed (although expansions of existing mines continues), as the better economics and reserves that are more extensive have shifted focus to SAGD projects.

The fundamental unit of a SAGD operation consists of a horizontal well pair spaced approximately 5 metres apart vertically. The upper well, or the injection well, is used to inject high-quality, high-temperature steam into the oil sands reservoir. The steam condenses in the reservoir, heating the surrounding bitumen and decreasing its viscosity (that is, it makes it easier for the bitumen to flow). The bitumen is able to drain down the reservoir with the force of gravity, into the lower production well. The bitumen and water

mixture is brought to the surface where the bitumen is separated from the water, diluted, and sent to market for refining.

SAGD is an effective production method, but does suffer from some distinct drawbacks:

Generation of high quality steam requires a great deal of energy, which is primarily supplied by the burning of natural gas. This makes SAGD a fairly GHG-intensive process, and can lead to high operational costs when gas prices are high. As steam-to-oil ratios rise, both GHGs and operational costs will rise accordingly.

Large volumes of sufficiently pure water are needed to supply continuous steam. While mandated recycle rates through Directive 81 have reduced reliance on fresh water sources for steam generation, the purification process itself, through warm lime softening or evaporators, is an energy-intensive process.

1 CERI Study 141 (2014). Canadian Oil Sands Supply Costs and Development Projects (2014-2048). http://www.ceri.ca/images/stories/2014-07-17_CERI_Study_141_Oil_Sands_Supply_Cost_Update_2014-2048.pdf 2 National Energy Board (2013). Canada’s Energy Future 2013. http://www.neb-one.gc.ca/nrg/ntgrtd/ftr/2013/2013nrgftr-eng.pdf


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Traditional SAGD setups have used once-through steam generators (OTSGs) to generate steam, as these can tolerate the higher levels of impurities that result from the warm-lime softening treatment method. OTSGs are less widely used than boilers, and the lime softening/OTSG setup tends to require a large amount of on-site construction compared to evaporator/boiler setups. However, evaporators can be subject to considerable fouling due to the feedwater quality.

SAGD projects have been subject to capital cost inflation, often due to limited manufacturing and construction resources. Increasing capital costs can limit SAGD growth to only very ideal reservoirs and to times of high oil prices when anticipated returns are higher.

One major change that is currently being explored is to use hydrocarbon solvents as an addition to or replacement for steam. The idea is to rely less on heat provided by steam

and more on the dissolution of bitumen components in a low-viscosity solvent, and thus relying less on the use of gas to heat water. On the construction front, designs using modular construction have been proposed to minimize the amount of on-site construction required for a SAGD installation.

Oil Sands Mining: Paraffinic Froth Treatment The mining sector of the oil sands is, at this point, quite mature. As such, there aren’t many game-changing technologies available or likely to be developed. One of the major changes to oil sands processing available is not actually new, and is currently in use, but can greatly increase the overall efficiency of the mining and extraction process. This technique, paraffinic froth treatment, is relatively straightforward, and involves using a paraffinic solvent instead of a naphthenic solvent for the extraction of bitumen from the

mined oil sands ore.3

The technique itself is straightforward, but the advantages can have large-scale impacts on the economics of a new mining project and results in rather significant efficiencies downstream in terms of energy required for refining into final fuels, capital requirements for a mining project, and in some cases, waste management. Paraffins, which are composed of straight chain hydrocarbon molecules, will dissolve most constituents of bitumen, but do not readily dissolve asphaltenes. Asphaltenes are large molecules, carbon-rich and tend to be high in sulphur and heavy metal contaminants. They can make up a significant fraction (16 to 25 percent by weight4) of the bitumen, but are low in value and can contribute to corrosive properties of the bitumen in pipelines. As such, bitumen produced using naphthenic solvent, which does extract asphaltenes, requires upgrading

prior to shipment.

3 Rao and Liu (2013). Froth Treatment in Athabasca Oil Sands Bitumen Recovery Process: A Review. Energy and Fuels 27, 7199 – 7207. 4 Strausz. Chemistry of the Alberta Oil Sand Bitumen. https://web.anl.gov/PCS/acsfuel/preprint%20archive/Files/22_3_MONTREAL_06-77_0171.pdf


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While upgrading does have its advantages, namely that the product of synthetic crude oil

is significantly more valuable than raw bitumen, the process is very intensive in capital and operating costs. Capital expenditures are in the order of 1.3 times as high for an integrated oil sands mine compared to a mine built without an upgrader, which has the possibility of outweighing the added benefit of producing a higher value SCO product. There are other issues that arise as part of the upgrading process. The overall refining process aims to convert large molecules into lighter molecules, and to do so requires increasing the overall ratio of hydrogen to carbon in the bitumen.

One way to do this is through coking, which removes carbon in the form of petroleum coke. This decreases the overall volume of the final product and adds an additional problem of what to do with the petroleum coke. One solution is to use the coke as fuel for the extraction and upgrading process. The downside to this is that coke, comparable

in composition to coal, is high in GHG emissions per unit of energy, and this increases the overall emissions relative to using a fuel such as natural gas or fuel gas. If not using the coke for fuel, then it must be stockpiled on-site until it can be used either on- or off-site. Coke is not produced when hydrogenation is used in the upgrading process, such as at the Shell Scotford upgrader.

The second problem that arises from the use of upgrading results from the overall life cycle emissions for end use fuels in the integrated mining pathway. The upgrading process is essentially a refining process, and while some end products can arise from upgrading (for example, diesel fuel is produced for local use at the Suncor integrated mining project), the major product is synthetic crude oil, which still requires refining before end use. This overall process results in some redundant refining, which increases the overall energy use

and thus GHG emissions in the final project compared to a route without the upgrading process.5

As illustrated in Figure 4.1, emissions for upgrading and refining using a coker, the most common SCO delivery method, is modeled to produce about 33 percent more GHG emissions per unit energy in the final fuel compared to refining dilbit, the most common bitumen delivery method. Eliminating the separate upgrading step and instead performing coking or hydrotreatment in conjunction with refining to the final use product can significantly reduce overall emissions.

5 Jacobs Consultancy (2009). Life cycle assessment comparison of North American and imported crudes. Prepared for Alberta Energy Research Institute.


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Figure 4.1: Refining and Upgrading Emissions for SCO Produced by Coker or Hydrocracking (Eb-Bed), Bitumen, or Dilbit

Note: data is based on production of ultra-low Sulphur diesel at a PADD II refinery

Source: Jacobs 2009

Paraffinic froth treatment, by removing asphaltenes rather than refining them, reduces the overall environmental impact of the mining and upgrading process. Of the current integrated projects, Suncor, Syncrude, and CNRL use naphthenic froth treatment and Shell uses paraffinic treatment. Overall, Shell’s GHG emissions per unit of SCO are considerably lower than the other techniques due to relatively lower emissions at the

upgrading stage (although due to the disaggregation of emissions across different facilities, direct comparison of reported emissions is complex).6

Finally, removing the upgrader may be the only option for any mining projects to proceed

today. Planned upgraders have mostly been cancelled in recent years. Imperial Oil’s Kearl project is the only mine that has been successfully opened in recent years, and part of this success has been due to the lack of a required upgrader. Due to a lack of upgrading, the reported GHG intensity for the project of 40 kg CO2e/bbl7 is considerably lower than existing mines, and while the dilbit product does require more energy-intensive refining than SCO, overall the emissions for refining dilbit are lower than those for upgrading bitumen to SCO and subsequently refining SCO.

For existing projects, while it may not be appropriate to consider shutting down upgraders already in operation, paraffinic froth treatment might be a technique worth considering. This will prevent asphaltenes from having to go through the upgrading process, increasing

6 CERI Study 143 (2014). Oil Sands Environmental Impacts. http://www.ceri.ca/images/stories/2014-09-18_CERI_Study_143.pdf 7 http://www.imperialoil.ca/Canada-English/Files/ThisIs/EUB_Kearl_Application_Feb_2007-013.pdf

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the throughput of bitumen, and reducing the amount of petroleum coke generated

during the process.

Oil Sands In Situ: Steam-Solvent Extraction The idea behind using solvents rather than steam is rather simple. Unlike water, many low-viscosity organic solvents can easily mix with bitumen components. A mixture of bitumen and solvent can flow easily without requiring the same high temperatures, which reduces natural gas requirements. This has the potential to reduce both operating costs and greenhouse gas emissions, as well as reduce reliance on local water sources.

Solvent-steam hybrid methods involve the co-injection of an organic solvent along with steam. Bitumen is mobilized by two main mechanisms: first, similar to solvent-free SAGD or CSS, the bitumen temperature is raised, increasing the mobility of the bitumen in the

reservoir; second, the low-viscosity solvent condenses and mixes with the mobilized bitumen, further increasing the mobility.

While steam-solvent extraction has not been used on a commercial scale to date, the technique has been proposed and field tests have been carried out to determine the efficacy of the technique. While the technique has been proposed under several names by different oil sands players – including SAP (solvent assisted process, Cenovus), ES-SAGD (expanding solvent SAGD), and LASER (liquid addition to steam to enhance recovery, a CSS technique used by Imperial Oil) – the basic concept remains the same. A large volume of steam is injected into the reservoir with a smaller volume of a light, hydrocarbon-based solvent that is condensable and miscible with bitumen.

Physical Process

A brief overview of the physical process involved in steam-solvent co-injection follows. A more detailed discussion may be found in technical papers that model the technique. 8,9

While there are certainly many complexities that must be addressed when starting a SAGD project, the process is quite simple conceptually. With typical SAGD, high quality steam (that is, steam containing very minimal liquid water) is injected into the reservoir. The chamber of steam expands until it cools to the water saturation temperature at the reservoir pressure. The pressure within the reservoir dictates at which temperature this occurs, as the equilibrium temperature between water and steam is higher at higher pressures. For example, at a pressure of 3,000 kPa, the steam is in equilibrium with liquid

8 Jha et al. (2013). New insights into steam/solvent-coinjection-process mechanism. SPE Journal 18, 867-877. 9 Keshavarz et al. (2015). Optimal application conditions for steam/solvent coinjection. SPE Reservoir Evaluation & Engineering 18 (1), 20-38.


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water at a temperature of about 234 ˚C.10 At this point, steam condenses into liquid

water, and in doing so releases a large amount of latent heat energy to the surrounding reservoir, including sand, existing water, and, most importantly since this process is being used to produce oil, bitumen. Bitumen viscosity has a strong temperature dependence, with typical Athabasca bitumen having a viscosity about 800,000 centipoise (cP) at a temperature of 13 ˚C and about 6 cP at the steam condensation temperature of 234 ˚C.11 The heated bitumen, is now much less resistant to flow, can drain to the producing well and may be pumped to the surface.

If steam is instead injected as a mixture with an organic solvent, the system behaves quite differently, with the end result of a temperature at the chamber edge that may be substantially lower than the steam-only scenario. Consider a reservoir that is being injected with steam, pentane (a linear, five-carbon alkane with the chemical formula

C5H12), or a mixture of both vapours. At a pressure of 3000 kPa in the reservoir, steam alone condenses at 234 ˚C, while pentane alone will condense at 193 ˚C, as calculated using the vapour pressure curve for pentane.12

A mixture of steam and a hydrocarbon vapour, when treated as an ideal mixture where the gases behave independently of each other, will end up condensing in the chamber at different temperatures. The concept of partial pressures becomes important when looking at co-injecting steam. The partial pressure is defined based on the mole ratio (i.e., the fraction of the molecules in the gas phase that are made up of a particular component, such as water). For a two-component system, such as steam and pentane, the total pressure is the sum of the partial pressures of the two components:

𝑃 = 𝑥H2O𝑃H2O + 𝑥C5H12𝑃C5H12

Mole fractions will always add to 1, so a mixture that is 5 mol% pentane (i.e., 5 percent of the gas molecules are pentane molecules) will be 95 mol% water vapour. If gases behave ideally, this is equal to the ratio of the volume of each vapour (i.e., 20 m3 of vapour injected will contain 19 m3 of steam and 1 m3 of water).

In an ideal mixture of gases, each vapour will physically behave according to the partial pressure rather than the total pressure in the system. Thus, the 95 mol% steam in the chamber, at 3000 kPa total pressure, will act as though the pressure is 2850 kPa. Rather than 234 ˚C, water will start to condense at a slightly lower temperature of 231 ˚C. In steam-only injection, all water should ideally condense at this temperature, assuming a

high-purity steam. With a co-injection of pentane, the condensation of water reduces the

10 Water – Antoine equation parameters. NIST Chemistry Webbook, National Institute of Standards and Technology. http://webbook.nist.gov/cgi/cbook.cgi?Name=water&Units=SI 11 Mehrotra and Svrcek (1987). Corresponding states method for calculating bitumen viscosity. Journal of Canadian Petroleum Technology 26 (5), 60-66. 12 Pentane – Antoine equation parameters. NIST Chemistry Webbook, National Institute of Standards and Technology. http://webbook.nist.gov/cgi/cbook.cgi?ID=C109660


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fraction of water in the vapour, which in turn increases the partial pressure of pentane,

and further lowers the temperature at which water condenses. As a result, there will be a region within the vapour chamber when, moving from the inside to the outside of the chamber, is characterized by gradually falling temperatures, increasing vapour concentrations of pentane, and condensing water.

Eventually, the temperature will fall low enough and the pentane partial pressure will be high enough that the pentane will reach saturation and condense. In a steam-solvent hybrid method, this is the true vapour chamber edge. When in a mixture with steam at 3000 kPa, the pentane condenses at a temperature of about 170 ˚C. Thus, the temperature at the edge of the vapour chamber is about 64 ˚C lower than in steam-only injection. Bitumen viscosity is also higher at this temperature, approximately 17 cP.

The lighter the solvent the lower the temperature is at the edge of the vapour chamber. Figure 4.2 shows the vapour pressure of five different alkane solvents with between four and eight carbons (i.e., butane, pentane, hexane, heptane, and octane). The dotted line shows the partial pressure of the hydrocarbon solvent that is co-injected with steam as a function of temperature at an injection pressure of 3000 kPa. As the partial pressure depends on how much steam has condensed out of the vapour phase, this curve is independent of the type of solvent used. The point at which the dotted line intersects with the vapour pressure curve is the point at which solvent condenses within the chamber, which determines the temperature at the edge of the chamber.

Figure 4.2: Vapour Pressure Curves for Five Hydrocarbon Solvents and Water as a Function of Temperature

Note: the intersection of the black dotted line and the hydrocarbon vapour pressure curve indicates the temperature at which the solvent will condense at a reservoir pressure of 3,000 kPa.

Source: calculated data

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While the temperature at the vapour chamber edge is lower for lighter hydrocarbon

solvents, and lower overall than for steam injection, the low-viscosity solvent is miscible with bitumen, and this can compensate for the higher viscosity at higher temperatures. The lower temperatures achieved by lighter solvents can also be offset by the fact that the condensing fluid at the chamber edge is more hydrocarbon-rich with lighter solvents, a consequence of their higher saturation pressure.

The vapour chamber edge temperatures for five solvents, butane through octane, are listed in Table 4.1, along with the mole fraction of the condensing fluid at this edge of the chamber, for a reservoir pressure of 3000 kPa. Although it may be somewhat counterintuitive, these numbers depend only on pressure and are unaffected by the amount of solvent co-injected with steam (provided that water is the first fluid to condense in the reservoir).

Table 4.1: Temperature and Mole Fraction of Solvent (Xsol) in Condensing Liquid at the Edge of the Vapour Chamber at 3000 kPa

Temperature at Chamber Edge (°C)

Xsol at Edge

Butane 131 0.9

Pentane 170 0.71

Hexane 193 0.52

Heptane 207 0.36

Octane 217 0.24

Source: calculated data

To summarize, the co-injection of small amounts of hydrocarbon solvents with steam results in a chamber edge that is cooler than in normal SAGD, but deposits a hydrocarbon-rich fluid that is able to mix with the bitumen and further reduce the viscosity beyond

what may be achieved by heat alone. How does this change the productivity of a well pair in comparison to regular SAGD?

Jha et al. examined the mechanism of steam-solvent extraction using a numerical model of a homogeneous reservoir.13 In their study, steam-to-solvent ratio of 5 percent w/w was modeled using paraffinic solvents ranging from propane to decane, as well as diluent and synthetic crude oil. As discussed, within the modeled reservoir water begins to condense and the temperature falls until the hydrocarbon solvent reaches saturation. Within this

liquid stream, as the solvent blends with the heated bitumen, the viscosity drops to levels below 1 cP, with the midpoint of the liquid stream having a viscosity of approximately 1 cP. As a result, oil mobility in the steam-solvent liquid stream is considerably higher than in the steam-only model, increasing the oil production rate. The addition of solvent in the

13 Jha et al. (2013). New insights into steam/solvent-coinjection-process mechanism. SPE Journal 18, 867-877.


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model both reduces the viscosity of the oil mixture in the liquid bitumen stream,

increasing the oil production rate, and reduces the residual oil saturation in the reservoir, which increases the overall recovery.

Solvent Choice

The effect of solvent addition in the modeled reservoir is greater overall oil production and reduced average steam oil ratios. The greatest modeled benefits come as the solvent becomes lighter and less viscous, down to butane. The benefits are lost somewhat using propane as a solvent, as it does not condense as readily in the reservoir. Non-condensing gases interfere with heat transfer, as a considerable portion of heat transfer comes from the release of latent heat when gases condense.

A few field trials have been conducted to test the efficacy of the process. Encana has

performed trials at the Senlac and Christina Lake SAGD projects, which yielded promising results. Addition of butane to an operational well increased oil production rates from 1,900 b/d to 3,000 b/d, reduced the average SOR from 2.6 to 1.6, and reduced the energy intensity of production from about 1 GJ/bbl to 0.7 GJ/bbl.14

Likewise, the Christina Lake field test showed an increase in production from 100 t/d immediately before butane injection to 300 t/d immediately following injection, with a reduction in SOR from 3.3 to 1.6, and a minor improvement in bitumen quality by roughly 0.7 to 1 degree API gravity.15 The Christina Lake pilot, while planned for a longer term, was stopped after two months after a drop in reservoir pressure indicated that reservoir containment was no longer achieved. More than 70 percent of the injected solvent was recovered through the producing well.

The basic operating costs of steam-solvent injection include typical SAGD costs – steam generation and water treatment – as well as solvent related costs, the largest of which is the cost of solvent retained in the reservoir. As the use of solvent lowers the overall SOR, the cost of unrecovered solvent will be balanced by the reduction in steam requirements.

Keshavarz et al. present an economic analysis of their model in terms of net present value (NPV) achieved with time. Based on costs from a 2005 study by Deng et al.,16 co-injection of pentane at 2 mol% is estimated to increase maximum NPV by 15 percent over traditional SAGD, and the maximum NPV is reached in roughly 5.4 years as opposed to 8.8 years. The solvent costs, in this model, however, are based on a price equivalent to heating value of natural gas. While this does match somewhat closely for 2005 Canadian

14 Gupta et al. (2005). Field implementation of solvent aided process. Journal of Canadian Petroleum Technology 44 (11), 8-13. 15 Gupta and Gittens (2006). Christina Lake solvent aided process pilot. Journal of Canadian Petroleum Technology 45 (9), 15-18. 16 Deng (2005). Recovery performance and economics of steam/propane hybrid process. SPE International Thermal Operations and Heavy Oil Symposium, 1-3 Nov 2005. SPE-97760-MS.


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solvent costs (the estimated pentane cost is $76.37 CAD/bbl compared to actual

Edmonton pentanes plus cost of $69.57 CAD/bbl in 2005 dollars), the cost of gas and hydrocarbon solvents have not scaled together over the past decade.

Operating Costs of Hybrid Steam-Solvent Technology

In the absence of detailed modeled production data, per barrel operating costs related to steam and solvent use are estimated for pentane and butane. These solvents have been shown as effective in modeled reservoirs (although Keshavarz et al. note that butane co-injection does not accelerate oil production to the same degree as pentane) or successfully used in pilot projects. The degree of SOR reduction demonstrated has varied.

The Senlac pilot project resulted in an SOR 62 percent of the SAGD baseline, while the Christina Lake pilot showed an SOR 48 percent of the SAGD baseline. Model results from

Keshavarz et al. did not report SOR values, but injected water volumes at 65 percent production for the pentane co-injection model yielded an SOR 51 percent of the SAGD only simulation. To stay on the conservative side, the cost comparison is based on an SOR reduction to 60 percent of SAGD baseline. For a baseline SOR of 3.0, this means an SOR of 1.8 with solvent co-injection.

Solvent is injected with steam at 2 mol%, and baseline recovery of solvent from the reservoir is 75.5 percent based on the modeled recovery with a constant injection. Natural gas requirements are set at 0.47 GJ per barrel of water for steam, to match the CERI natural gas requirements for a model SAGD operation (35,910 GJ/d for a 30,000 barrel per day facility with an SOR of 2.8). Costs of operating the steam generator and to treat the water are taken from Deng.17

Table 4.2: Values Used for Estimating per Barrel Costs of Steam-solvent Extraction

Parameter Value Range for Sensitivity

Energy required for steam 0.47 GJ/bbl CWE

Solvent injection volume 2 mol%

Water treatment cost 0.31 CAD (2005)/bbl CWE

Steam generator cost 0.45 CAD (2005)/bbl CWE

Baseline SOR 3.0

Reduced SOR 1.8 1.5 – 2.1

Solvent recovery 75.5% 67 – 89.2%

*CWE = cold water equivalent

Source: CERI

17 Deng (2005). Recovery performance and economics of steam/propane hybrid process. SPE International Thermal Operations and Heavy Oil Symposium, 1-3 Nov 2005. SPE-97760-MS.


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Per barrel cost estimates are calculated for each year from 2005 through 2014 in then-

current dollars, based on average costs of natural gas, butane, and pentanes plus for that year (Figures 4.3 and 4.4).18,19 Under the assumption that butane and pentane perform equally well per barrel of oil produced, the ideal choice of solvent is butane, given its lower cost; butane prices were, on average, 73 percent of the cost of pentanes plus in this time frame. As a result, butane tends to have slightly lower operating costs in steam-solvent co-injection compared to the SAGD case under baseline conditions. Pentane, on the other hand, tends to be comparable or higher in cost on a per barrel basis due to the higher cost of unrecovered solvent, except for 2005 when pentanes plus and natural gas prices were comparatively low and high, respectively.

Figure 4.3: Steam and Solvent Operating Costs for Traditional SAGD and Steam Butane Co-injection (in nominal CDN dollars)

Source: CERI analysis

18 Alberta Energy Natural Gas Reference Price History. http://www.energy.alberta.ca/NaturalGas/1322.asp 19 GLJ Petroleum Consultants Commodity Price Library. https://www.gljpc.com/commodity-price-library

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Figure 4.4: Steam and Solvent Operating Costs for Traditional SAGD and Steam Pentane Co-injection (in nominal CDN dollars).


Sensitivity to changes in natural gas price, solvent price, degree of SOR reduction and solvent recovery was examined using 2014 prices (natural gas: $3.35 CAD/GJ, butane: $69.29 CAD/bbl, pentane: $102.92 CAD/bbl). Unsurprisingly, using the more expensive pentane as a solvent makes the steam and solvent recovery slightly more sensitive to

solvent-related variables than butane. A change of 30 percent in the price of pentane will affect the cost per barrel of oil more than a 30 percent change in natural gas price. A high solvent recovery of 89.2 percent, which was demonstrated in the model with the modified injection procedure, results in a per barrel cost almost 30 percent lower than the 75.5

percent recovery.

Butane, being a less expensive solvent, is not as sensitive to the solvent recovery, but increasing the recovery by the same amount also decreases the per barrel cost by a little more than 20 percent (Figure 4.5). In both cases, a less efficient lowering of the SOR to 2.1 instead of 1.8 results in little change in the cost per barrel, but lowering the SOR to 1.5 (half of the SAGD baseline of 3.0 used here) results in a significant drop in the per barrel cost. This degree of SOR reduction was demonstrated for both Senlac and Christina

Lake pilot studies, so this may not be unrealistic.

2005 2006 2007 2008 2009 2010 2011 2012 2013 2014

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Figure 4.5: Sensitivity of Cost per Barrel with Butane Added to Steam


Figure 4.6: Sensitivity of Cost per Barrel with Pentane Added to Steam


A per barrel operating cost does not capture all the advantages of solvent co-injection,

however. As mentioned, both reservoir models and pilots show increases in bitumen production rates and a lowering of the residual oil saturation, which work in concert to reduce the amount of time it takes to recover bitumen from a reservoir and increase overall recovery. This reduces time-dependent operating costs such as labour and increases gross revenue from bitumen sales.

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While an increase in revenue would be the driving factor behind adoption of this

technique, the reduction in energy use would also lead to lower GHG emissions from SAGD production. Natural gas usage for steam generation is the main driver of emissions for SAGD, and lowering the SOR by 40 to 50 percent would result in GHG emission reductions of approximately the same magnitude. Given the GHG emissions of the oil sands and the recent development of low carbon fuel standards, this could improve the marketability of SAGD bitumen. Carbon price savings, however, would be minimal. Even assuming a $15 per tonne charge on all emissions rather than those in excess of a 12 percent reduction in intensity as per Alberta’s Specified Gas Emitters Regulation would only result in a reduction of operating costs on the order of 50 cents per barrel.

It should be noted that at this point, solvent co-injection has yet to be developed on a commercial scale and pilot studies, although promising, have been somewhat limited.

More successful pilots will likely be necessary for oil sands developers to incorporate solvent injection into their projects, considering the risk that arises from additional capital cost and loss of expensive solvent.

Oil Sands In Situ: Solvent-based Extraction Solvent-based extraction, while seemingly simple in concept, has some unique challenges not encountered with steam-based processes. One potential concern of solvent-based extraction is that asphaltenes, which are large aromatic molecules present in bitumen, do not readily dissolve in paraffinic solvents. Asphaltenes themselves are of low value, are rich in non-hydrocarbon impurities, and must be limited in pipeline-ready bitumen. In fact, use of paraffinic solvents when extracting oil sands mining ore can eliminate the need for upgrading due to the rejection of asphaltenes. As such, eliminating the

asphaltenes in the reservoir is somewhat desirable.

The problem comes if the bitumen-solvent mixture migrates in the reservoir prior to asphaltene precipitation. This can result in accumulation of insoluble bitumen components within the reservoir and impede proper flow of diluted bitumen and prevent the well from being productive. Much of the early work used solvent mixtures injected at

the reservoir dew point, or the point where solvent vapour just begins to condense in the reservoir. The goal is to prevent large amounts of solvent from entering the bitumen phase and avoid the approximately 50 vol% conditions at which asphaltenes precipitate in the reservoir. This process, which typically uses a mixture of either propane or butane and methane, is referred to as VAPEX (vapour extraction). The cold and dry process (that is, it is not heated and does not use steam) has been applied in some pilot projects

including DOVAP at Suncor’s Dover site,20 but little information on production results can be found. Unfortunately, processes like Vapex that use a blend of solvent and methane have an inherently unstable mass balance as the solvent is carried out in the oil and the methane is retained in the chamber. After injecting a few pore volumes, the chamber gas 20 https://www.aer.ca/documents/oilsands/insitu-presentations/2011AthabascaSuncorDoverSAGD9044.pdf


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completely fills with inert methane and there is no ability to inject solvent without

exceeding safe operating pressures. Currently, there is little evidence of success for cold solvent extraction on a pilot scale.

A competing solvent-based technique called N-Solv has been developed. The patented process was developed by N-Solv Corporation, which is co-owned by Hatch, Enbridge, and Nenniger.21 In a paper discussing the physical processes of the N-Solv technique, Nenniger and Dunn address some of the reasons why VAPEX has, thus far been relatively unsuccessful.22

The rate limiting process in a solvent-based extraction has historically been assumed to be analogous to heat transfer in SAGD. To match lab data, this analogy requires diffusion coefficients that were two or three orders of magnitude too high to be physically correct

and these unphysical coefficients imply deep penetration (10’s of meters) of the solvent into the bitumen. However, simple lab experiments reveal a sharp solvent-bitumen interface and bitumen dissolution behavior which resembles a melting ice cube.

This unexpected dissolution mechanism has many important consequences: effectively there is a solvent shock front at the bitumen interface which dissolves the valuable components at the same time as immobilizing the asphaltenes. Consequently, the asphaltenes are uniformly dispersed in the sand matrix, which avoids permeability damage. The extremely steep concentration gradient (less than 100 microns instead of 10’s of meters) eliminates the need to invoke unphysical diffusion coefficients.

The solvent drainage rate correlation developed by Nenniger only has one fluid property,

the bitumen viscosity, which suggests that the rate limiting step in the extraction mechanism is set by the bitumen dissolution rate. The physics of the correlation are not understood yet but it seems likely that the rate limiting step for solvent extraction is physically disentangling the individual bitumen molecules from each other. As the viscosity of bitumen is reduced 1,000 fold with a 30˚C temperature rise, the bitumen dissolution rate increases by a factor of 30 fold.

Since the permeability and void space within the reservoir cannot be physically changed in any manner, the only control that can be exercised is over the initial viscosity of the bitumen. With a well pair 500 metres long in a 20 metre pay thickness and a permeability of 5 Darcies, Nenniger and Dunn note that with a bitumen viscosity of 8 million cP, production rates will only be on the order of 30 barrels per day. This yields depletion times

of longer than 100 years and makes commercial application uneconomic. However, injection of heated solvent vapour into the reservoir under condensing conditions could increase production rates by heating the bitumen in the reservoir and decreasing the

21 http://www.n-solv.com/profile.php 22 Nenniger and Dunn (2008). How Fast is Solvent Based Gravity Drainage? Canadian International Petroleum Conference Paper 2008-139.


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initial viscosity of the bitumen. They estimate that the same reservoir could produce

nearly 900 barrels per day by increasing the reservoir extraction temperature to just 40 °C, and only require about 15 percent of the energy of a SAGD well pair.

To achieve stable operation and avoid the accumulation of non-condensable gases in the reservoir, the N-Solv extraction process requires the use of a pure hydrocarbon solvent, typically propane or butane. The process is somewhat analogous to the SAGD process, where heated solvent vapour is injected through the upper well. In the reservoir, the solvent condenses and passes the latent heat of vaporization to the surrounding bitumen, raising the temperature of the solvent-reservoir interface, in addition to dissolving the in situ bitumen. The solvent-bitumen mixture drains to the lower production well and is pumped to the surface to recover solvent and send de-asphalted bitumen to market.

N-Solv is currently operating the Bitumen Extraction Solvent Technology (BEST) pilot at Suncor’s Dover site, partially funded by Sustainable Technology Development Canada and Alberta’s Climate Change and Emissions Management Corporation.23 The plant consists of one 300 meter-long well pair in a thin payzone for a 500 barrel per day production design.24 N-Solv began preconditioning its well pair in the summer of 2013. While detailed production data does not appear publicly available at the still-operational pilot plant, N-Solv is reported to have reached cumulative production of 25,000 barrels as of October 2014, just a few months after first solvent injection, with no significant disruption in the production schedule, and has received requests for projects of a larger scale.25 The plant has now produced over 50,000 barrels of oil.

The N-Solv BEST process purports to have several distinct advantages over SAGD including

much lower capital requirements; greatly reduced energy consumption yielding lower operating costs; de-asphalted produced oil yielding higher product value; and no water use. The process is water-free, and as such avoids challenges related to water use: finding large sources of water, fresh or saline, is unnecessary; water treatment for recycle is no longer an issue; and water disposal is no longer necessary except for minor reservoir in situ water production.

As discussed in the N-Solv process, asphaltenes do not dissolve in the solvent, and thus remain in the reservoir. Asphaltenes reduce the value of bitumen and are expensive to remove via cokers. If asphaltenes are left in the reservoir, the produced oil is not only of higher value due to partial upgrading but also diluent requirements are significantly

23 N-Solv BEST Pilot Plant at Suncor Dover. Climate Change and Emissions Management Corporation. http://ccemc.ca/project/n-solv-best-pilot-plant-at-suncor-dover/ 24 N-Solv Overview. 2013 PTAC Oil Sands Forum, November 6, 2013. www.ptac.org/attachments/1200/download 25 N-Solve Corporation announces 25,000 barrels of oil production from its BEST Pilot. http://www.newswire.ca/en/story/1436519/n-solv-corporation-announces-25-000-barrels-of-oil-production-from-its-best-pilot


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reduced along with pipeline tariffs. This results in a higher refined product yield, and

there is less need to store or dispose of asphaltenes downstream.

The N-Solv process has been demonstrated to operate at low to medium pressures or about native reservoir pressure. This may allow development of shallow depth reservoirs currently challenged by low allowable maximum operating pressure as well as intermediate depth reservoirs.

The requirements for solvent purification and heating are much less complex than for steam generation, which should reduce upfront capital expenditures, and the lower temperatures and pressures require substantially less energy than steam generation, which should reduce both operating costs and GHG emissions.

The economic benefits of the technique have been touted as well. Upfront capital costs are purported to be 40 percent lower than SAGD since water treatment and steam generation plants are unnecessary. Operating costs can be significantly lower because of an expected 80 percent reduction in input energy. In addition, the partial upgrading from asphaltene precipitation yields a higher value product at 13 API gravity or more compared to 8 API for SAGD.26

A potential Achilles heel to a solvent-based method is the loss of solvent to the reservoir. Unlike water, solvent has a direct per-barrel cost, and if considerable amounts are lost in the reservoir, the extra makeup solvent may be a significant operating cost. N-Solv claims to recycle over 90 percent of their injected solvent at their pilot facility with further solvent recovery anticipated in a blowdown phase of operation.

N-Solv notes that the high viscosity of bitumen causes a natural seal around the solvent injection chamber, which minimizes solvent loss, especially since the process typically operates in a pressure balance with the native reservoir pressure. The performance of the BEST pilot development should help to identify whether or not solvent recovery rates are high enough for this technique to be viable. With more solvent coming on stream with expanding gas production, solvent costs are currently very low reducing sensitivity to solvent loss.

In Situ Modular Design While the development of the oil sands has been beneficial to the economy of Alberta and Canada, the pace of growth in the industry has led to substantial challenges in

keeping up with demand in terms of construction of capital projects and finding labour. In a report prepared for Alberta Energy and the Construction Owners Association of Alberta, the Construction Industry Institute (CII) indicated that compared to similar

26 https://www.nsolv.ca/benefits/


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projects in the United States, heavy industry construction projects in Alberta experienced

over 5 times the amount of growth in capital cost and almost 2 times as much growth in scheduled time for construction.27 The total peak construction workforce was highly correlated to the degree of cost overruns, indicating that labour costs are a major factor in these overruns. Indeed, the most important factor in cost overruns in a construction project in Alberta was reported to be the amount of unplanned overtime. Another major contributor to cost escalations, scheduling, and productivity was the amount of engineering complete prior to the start of construction; it was the most important factor leading to schedule and productivity overruns, and the second most important factor leading to cost overruns.

Despite being developed quite recently on a commercial scale, SAGD has reached a degree of maturity as a technique relatively quickly. There is also a great deal of overlap

between the technologies required for each development. This does not discount the amount of effort that must go into understanding the unique geological constraints and requirements for a new project, but at the heart of each SAGD project, the elements are common: steam generation equipment, bitumen recovery, and water treatment. These common elements allow for considerable opportunity to use modular equipment that can be manufactured off-site and quickly assembled in the field.

However, this modular construction has not translated into practice. Part of the reason for this is the typical use of once-through steam generators (OTSG) as a steam source. While this has been a reasonably effective method thus far, projects tend not to be very scalable or portable. A project is designed for a particular steam capacity, and once bitumen production declines, the equipment cannot easily be used at other sites.

An alternative approach is to use a modularized, portable design for SAGD projects that can be installed in parallel to scale with the amount of bitumen production at a site. This approach has been developed by Oak Point Energy.28 The technology developed by Oak Point consists of a modular design that is constructed primarily off-site and requires considerable less on-site construction than the traditional SAGD design.

A key difference between this modular design and the traditional SAGD design is in the water handling technologies used. Oak Point uses an evaporator design 29 that has improvements compared to previous evaporator designs.

Typical projects use lime softening and OTSGs for treatment and steam generation.

Produced SAGD water tends to have high silica concentrations and residual hydrocarbons, which tend to lead to problems with scaling and fouling when used in evaporators. Due

27 CII (2009). The Alberta Report: COAA Major Projects Benchmarking Study. 28 http://www.oakpointenergy.ca 29 Oak Point Energy (2013). Evolution of Evaporators as Successor for Warm Lime Softeners. http://www.oakpointenergy.ca/upload/media_element/25/01/evolving-sagd-water-treatment-technology.pdf


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to these challenges, lime softening with ion exchange tends to be the method of choice

for water treatment. The equipment required is large and requires a large amount of on-site construction compared to evaporators. This setup also precludes the use of boilers, which are more common for industrial steam generation and typically are of lower capital cost, but cannot be used with the levels of dissolved solids resulting from lime softening systems.

The evaporators developed by Oak Point are more resistant to fouling due to patented alterations to the design to remove floating hydrocarbons and a control system designed to reduce silica scaling. Additionally, the evaporator uses two exchangers that can be isolated from one another, allowing maintenance on one while the evaporator still operates at 80 percent capacity. The higher water quality afforded by evaporators allows for the use of cheaper drum boilers to deliver steam.

The technologies allow for a design that is much more modularized and portable than traditional SAGD design.30 Coupled with a simplified bitumen separation train, the whole surface segment of the SAGD project is reduced to one of three scaled applications:

UltraLite: for pilot applications of 1 to 2 well pairs and 1,260 bpd production, with total capital intensity of $33,600-$48,100 per barrel per day installed (the range is based on two quoted costs from Oak Point Energy31);

1nSite: for small fields or production ramp up with 8 to 12 well pairs and 7,200 bpd production, with total capital intensity of $17,600 – $21,200 per barrel per day installed; and

MultiSite: for large resources of 2 to 4 well pads and 21,600 bpd production, with total capital intensity of $13,800 – $16,500 per barrel per day installed.

A caveat should be added that these are numbers reported by the company itself and have not been tested by a third party. If these capital costs are realized, this puts the capital intensity of a project considerably lower than CERI’s estimate for a typical capital intensity of a SAGD project of approximately $35,000 per barrel per day.32 Even a pilot project is in the range of the capital intensity for a typical large-scale SAGD project.

Modularization allows for most of the construction to be accomplished off-site, and can be located in areas with lower costs and higher productivities and less susceptible to labour shortages. Assembling and disassembling on-site is reduced to 30 days. Scenarios

30 Oak Point Energy (2014). Exploring an Improved SAGD Facility Design and Execution Strategy for In Situ Oil Sands to Significantly Improve the Economics, Minimize Environmental Footprint and Reduce Scheduling Times. http://www.oakpointenergy.ca/upload/media_element/28/01/optimizing-sagd-facility-design.pdf 31 Ibid 32 CERI Study 141 (2014). Canadian Oil Sands Supply Costs and Development Projects (2014-2048). http://www.ceri.ca/images/stories/2014-07-17_CERI_Study_141_Oil_Sands_Supply_Cost_Update_2014-2048.pdf


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with low completion of engineering prior to construction and large amounts of unplanned

overtime that lead to cost and schedule overruns are more easily avoided. In addition, if most of the manufacturing and construction can be completed off-site, it is more realistic to outsource construction to other regions of the country that have fewer labour constraints than Alberta.

One potential drawback to this type of design is that while the evaporator-boiler setup allows for lower upfront costs and ease of installation, evaporators require more energy to operate than lime softening units.33 As the oil sands sector is already under scrutiny for GHG emissions, this may potentially be an issue depending on how emissions from the sector are addressed in the future. However, the modular nature also allows for close integration in the design, and Oak Point claims that high levels of heat integration incorporated into the design allows for the lowest energy intensity in the oil sands.

33 New SAGD Technologies Show Promise in Reducing Environmental Impact of Oil Sand Production. http://albertainnovates.ca/media/20420/sagd_technologies_ogm_lightbown.pdf


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Chapter 5: Conclusions Efficiency in upstream oil and gas can be thought of in a number of ways; efficient use of energy, efficient use of natural resources, and efficient use of labour and capital are all important to consider, and there are opportunities to improve in each area. There is also considerable overlap in these areas, as improving one area can often have ripple effects in another. For example, lowering the steam-oil ratio of a SAGD project increases the energy efficiency of a project, but also reduces a project’s reliance on water and potentially requires smaller steam and water treatment infrastructure, thus lowering the capital requirements for a project. Processes that are more efficient are desirable to reduce the environmental impact of the industry and to maximize the economic benefits from resource extraction. A summary of efficiency strategies discussed herein along with

a brief outline of the major efficiency gains from each is shown in Table 5.1.


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Table 5.1: Summary of Upstream Oil and Gas Efficiency Opportunities


Conventional oil and gas Adoption of technical and management best practices

- Technologies are currently available

- Cost recovery through fuel savings

- Potential energy savings on the order of 10 percent

- Reduced GHG intensity - Reduced operating costs

In situ oil sands Mechanical lift Wedge Wells Modular construction Solvent-based extraction

- Lower steam pressures - Reduced SOR (approx. 18

percent reduction) - Approx. 24 percent

reduction in energy loss - Improved heat recovery at

surface - Reduced GHG intensity - Reduced water use - Improved bitumen

recovery rates (12 percent increase)

- Fewer construction delays - Reduced capital cost

(estimated 53 – 61 percent lower per barrel of production than traditional SAGD)

- More efficient use of labour

- Easy to move to new sites - Reduced SOR; pilot projects

have demonstrated over 50 percent reduction

- Improved bitumen recovery rates

- Reduced water use - Reduced GHG intensity - Potential for partial

bitumen upgrading


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Mined oil sands Adoption of current best practices Improved tailings management Paraffinic froth treatment

- Reduced need for heating process water

- Reduced coke usage - Reduced air emissions - Reduced GHG intensity - Reduced fresh water

requirements - Reduced land footprint - Partially upgraded bitumen

product - Product may be shipped as

dilbit rather than requiring on-site upgrading

- Reduced on-site and life cycle GHG intensity (15 percent reduction in refining and upgrading related emissions)

- Reduced capital costs

Shale gas Improved water management Improved drilling rig and material management Fuel replacement

- Reduced fresh water usage by using waste water sources

- Less requirement for additional fracturing additives

- Reduced cost of treatment and transport of water

- Lower risk of well drilling delays in times of drought

- Reduced energy requirements for water treatment

- Reduced cost of transport of rigs or drilling and fracturing material

- Lower risk of delay due to equipment or material availability

- Lower fuel cost (2014 natural gas cost 84 percent lower than equivalent energy in diesel fuel)

- Reduced air emissions - Reduced GHG intensity


June 2015

While there is a certain mystique surrounding new, game-changing techniques and

technologies to drastically reduce the impact of oil and gas technology, there are still many available ways to improve the efficiency of the industry simply by adopting currently available and economically favourable technologies and practices. This may be as simple as adopting a more rigorous maintenance process or swapping out some outdated equipment for newer, more efficient models. In more economically marginal projects such as in situ bitumen extraction, the adoption rate of more efficient processes is naturally high, as the incentives are strong to overcome the short-term challenges involved in the change. A good example is the use of downhole pumps, which allow for SAGD to operate at lower reservoir pressures and reduce operating SOR considerably, and are already used at a considerable number of projects.

However, there are still a number of best practices that have yet to be adopted on a broad

scale. There are numerous reasons for this, ranging from simple inertia to the risk involved with interrupting production to install equipment expected to only provide marginal gains in efficiency. As has been shown in the successful water recycle rates in the in situ oil sands sector or the reduction in flaring in Alberta, government regulation can also be effective at fostering change.

In the upstream gas sector, shale gas, particularly out of northeastern British Columbia, is poised to become a more prominent source of Canadian produced natural gas. The province has alleviated some concerns that are often associated with shale gas by creating a fracturing fluid registry, but practical concerns associated with the large water use require consideration when the resource pushes forward. Responsible use, and re-use, of flowback water could be pursued, and the frequent surface water shortages in the region

may signal to producers to consider alternative sources such as municipal or industrial wastewater. While it is less of a problem currently, considering the lower activity in the oil and gas sector due to low energy prices, the industry could consider coordination of activities and drilling materials to alleviate pressures and schedule overruns resulting from constraints in drilling infrastructure. Additional cost savings could be realized by using natural gas rather than diesel for drilling and fracturing, whenever practical.

For upstream oil, bitumen production will continue to dominate Canadian oil production. Mining, being capital-intensive and a mature industry, has comparatively few opportunities for drastically changing techniques to improve efficiency. However, strategies to reduce reliance on upgrading, which is energy- and capital-intensive and tends to increase overall life cycle emissions, can help to reduce the environmental

footprint of the sector. Paraffinic froth treatment, which reduces the extraction of low value and corrosive components of crude bitumen, could be considered on a wider scale, as it eliminates requirements for upgrading and allows mined bitumen to be sold to market as dilbit.


June 2015

In situ techniques will be the main growth driver in the sector, due to a larger resource

base and lower capital costs than mining. As steam generation and the accompanying water treatment are the main drivers in costs and energy use, strategies to reduce reliance on steam can greatly increase the efficiency of this process. Solvent techniques have been proposed, both as pure solvent extraction and steam-solvent techniques. Field application of steam-solvent processes have been successful at reducing SOR and increasing production with relatively small solvent additions, but have yet to be adopted on a commercial scale and are primarily limited if solvent loss to the reservoir is high. VAPEX is challenging due to low oil rates and non-condensable gas poisoning. Early indications are that N-Solv, as a waterless extraction technique, can reduce heat requirements and produce a partially upgraded bitumen product, and it is currently being field tested. N-Solve has a capex advantage over SAGD (because it is a waterless process) and solvent prices have collapsed to less than $10/bbl.

Modular construction is another strategy to improve the efficiency of the construction aspect of in situ projects. The majority of the construction can be moved off-site to areas with higher construction efficiency, and the short set-up time will reduce the likelihood of project delays and associated cost overruns. The compact design can allow for better heat integration, and potentially offset the increased energy requirements for the evaporator-drum boiler steam delivery process compared to traditional lime softening and once-through steam generators.

In all cases, the specific cost or energy savings will be unique to a particular operation. Realized savings will be as much dependent on the process or technology change itself as its effective implementation.

Documents

Study No. 147 June 2015 - CERI · Process Efficiencies of Unconventional Oil and Gas ix June 2015 Executive Summary The oil and gas sector in Canada provides considerable economic