Oils Sands, Gas Shales & Oil...

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Table of Contents

Executive Summary ................................................................................................................. 9

Section 1: Analysis of Oil Sands......................................................................................... 11

Introduction to Oil Sands .................................................................................................... 12

What are Oil Sands? ........................................................................................................................... 12 History of Oil Sands ........................................................................................................................... 13 Extraction of Oil Sands ..................................................................................................................... 14 Surface Mining ................................................................................................................................ 14 Cold Flow .......................................................................................................................................... 15 Combustion Overhead Gravity Drainage ............................................................................ 16 Cyclic Steam Stimulation ............................................................................................................ 16 Steam Assisted Gravity Drainage ........................................................................................... 16 Vapor Extraction Process ........................................................................................................... 17 Toe to Heel Air Injection ............................................................................................................ 18

Environmental Issues Facing Oil Sands ......................................................................... 19

Overview ................................................................................................................................................ 19 Air Pollution .......................................................................................................................................... 19 Impact of Mining on Land ............................................................................................................... 20 Impact on Water Resources ........................................................................................................... 20 Emission of Greenhouse Gases ..................................................................................................... 21 Impact on Aquatic Life ..................................................................................................................... 23 Other Environmental Concerns ................................................................................................... 23

Energy Requirement for Oil Sand Extraction .............................................................. 24

Analysis of Canada’s Oil Sands Industry ........................................................................ 25

Industry Overview ............................................................................................................................. 25 Global Impact of the Industry ....................................................................................................... 28 Make‐up of the Bitumen Resources ........................................................................................... 30

Oil Sands, Gas and Oil Shales © EnergyBusinessReports.com

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Executive Summary

Challenges Facing the Industry .................................................................................................... 31 Market Opportunities ....................................................................................................................... 33 Mining the Oil Sands ......................................................................................................................... 35 Extraction ......................................................................................................................................... 37 In‐situ Bitumen ............................................................................................................................... 38 Cyclic Steam Stimulation ............................................................................................................ 39 Steam Assisted Gravity Drainage ........................................................................................... 40 Generating Steam .......................................................................................................................... 42 VAPEX ................................................................................................................................................. 42 Firefloods .......................................................................................................................................... 42 “Cold” Production .......................................................................................................................... 43 Processing ......................................................................................................................................... 44 Upgrading ......................................................................................................................................... 44 Transportation ............................................................................................................................... 46

Economics of the Industry .............................................................................................................. 47 Energy Balance for Oil Sands Mining‐Upgrading Projects ............................................... 49 Products of the Industry ................................................................................................................. 50 Sustaining the Environment .......................................................................................................... 51 Regulatory Framework .................................................................................................................... 52 Ongoing R&D ........................................................................................................................................ 54 Oil Sands Production Primer ......................................................................................................... 55 Future of the Industry ...................................................................................................................... 56

Analysis of the Athabasca Oil Sands ................................................................................ 59

Introduction .......................................................................................................................................... 59 History of the Athabasca Oil Sands ............................................................................................. 59 Development of the Athabasca Deposits .................................................................................. 60 Extracting Bitumen from the Deposits ..................................................................................... 61 Commercial Production from Athabasca Oil Sands ............................................................. 63 Production Forecast from Athabasca Oil Sands .................................................................... 63 Overall Estimation of Oil Reserves in the Athabasca Deposits ....................................... 64 Economics of Oil Extraction from the Athabasca Deposits .............................................. 65 Political Significance of the Deposit ........................................................................................... 67 Environmental Issues with the Athabasca Oil Sands .......................................................... 68 Impact on Land ............................................................................................................................... 68 Impact on Water Resources ...................................................................................................... 69 Use of Natural Gas and Greenhouse Gases Emissions ................................................... 69

Company ProfilesAthabasca Oil Sands ......................................................................... 71

Overview ................................................................................................................................................ 71 Canadian Natural Resources Limited (CNRL) ........................................................................ 71


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Executive Summary

Imperial Oil ........................................................................................................................................... 72 Nexen Inc ............................................................................................................................................... 75 etro Canada ........................................................................................................................................... 76 Shell Canada.......................................................................................................................................... 78 Sinopec (China Petroleum & Chemical Corporation) ......................................................... 81 Statoil ....................................................................................................................................................... 85 Suncor Energy ...................................................................................................................................... 89 Syncrude Canada ................................................................................................................................ 93 Teck Resources .................................................................................................................................... 95 Total SA ................................................................................................................................................... 97

Analysis of the Utah Oil Sands ......................................................................................... 103

Introduction ....................................................................................................................................... 103 History of the Utah Oil Sands ..................................................................................................... 103 Production Sites ............................................................................................................................... 103 Utah Oil Sands Joint Venture ...................................................................................................... 103

Case Study: Mackay River inSitu Oil Sands Projects .............................................. 106

Case Study: Kearl Oil Sands Project ............................................................................... 108

Section 2: Analysis of Gas Shales .................................................................................... 111

Introduction to Gas Shales ................................................................................................ 112

Overview ............................................................................................................................................. 112 Role of Fracturing ........................................................................................................................... 113 Flow Rates .......................................................................................................................................... 114 Process of Unlocking ...................................................................................................................... 115 Shale Gas Economics ...................................................................................................................... 116 Environmental Considerations ................................................................................................. 116 Processes in Extracting Gas Shales .......................................................................................... 117 Hydraulic Fracturing ................................................................................................................. 117 Horizontal Drilling ..................................................................................................................... 121 Fluid Management ..................................................................................................................... 123

Shale Gas in the United States ......................................................................................... 125

Overview ............................................................................................................................................. 125 History of the Industry .................................................................................................................. 127 Shale Gas Production & Reserves ............................................................................................. 127 Major Shale Gas Production Regions ...................................................................................... 128 Antrim Shale, Michigan ............................................................................................................ 128


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Executive Summary

Barnett Shale, Texas .................................................................................................................. 130 Caney Shale, Oklahoma ............................................................................................................ 130 Conesauga Shale, Alabama ..................................................................................................... 130 Devonian Shales, Appalachian Basin ................................................................................. 131 Fayetteville Shale, Arkansas .................................................................................................. 134 Floyd Shale, Alabama ................................................................................................................ 134 Gothic Shale, Colorado ............................................................................................................. 134 Haynesville Shale, Louisiana ................................................................................................. 134 New Albany Shale, Illinois Basin .......................................................................................... 134 Pearsall Shale, Texas ................................................................................................................. 135 Utica Shale, New York ............................................................................................................... 135 Woodford Shale, Oklahoma ................................................................................................... 135

DOE/NETL Research Program .................................................................................................. 135 Role of Shale Gas in Unconventional Gas in the U.S.......................................................... 137 Regulatory Framework ................................................................................................................. 138 Quality of Surface Water ......................................................................................................... 139 Surface Water Quality Issues................................................................................................. 142 Protecting the Groundwater .................................................................................................. 143 Safe Drinking Water Act Authority ..................................................................................... 143 Underground Injection of Waste Fluids ........................................................................... 145 State Water Quality Laws ........................................................................................................ 147 State Water Supply Management ........................................................................................ 148

Shale Gas in Canada ............................................................................................................ 151

Overview ............................................................................................................................................. 151 Major Shale Gas Production Regions ...................................................................................... 151 Frederick Brook Shale, New Brunswick ........................................................................... 151 Horton Bluff Shale, Nova Scotia............................................................................................ 151 Montney Shale, British Columbia ........................................................................................ 151 Muskwa Shale, British Columbia ......................................................................................... 151 Utica Shale, Quebec .................................................................................................................... 152

Impact of Gas Shales on the LNG Industry .................................................................. 153

Introduction ....................................................................................................................................... 153 Comparing the LNG Market with Gas Shale Market ......................................................... 153 Investment Boom in LNG Facilities ......................................................................................... 155 LNG versus Shale Gas..................................................................................................................... 156 Changing Industry Perception ................................................................................................... 157 Dealing with Market Shortage ................................................................................................... 157 Understanding the Cost Structure ........................................................................................... 158 Understanding the Cost Curve ................................................................................................... 159


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Executive Summary

Impact of Shale Gas on LNG Markets ...................................................................................... 161 Impact on New LNG Projects ...................................................................................................... 162 Cost of New Projects ...................................................................................................................... 163 Conclusion .......................................................................................................................................... 163

Impact of Shale Gas on the Global Energy Industry ................................................. 165

Water Issues Facing Shale Gas Production ................................................................. 168

Stormwater Runoff ......................................................................................................................... 168 Water Supply for Drilling and Other Processes ................................................................. 172 Water Flowing to the Surface ..................................................................................................... 173

Major Players in Gas Shales ............................................................................................. 175

Anadarko Petroleum ...................................................................................................................... 175 Apache Corporation ....................................................................................................................... 178 Bill Barrett Corporation ............................................................................................................... 181 Chesapeake Energy ........................................................................................................................ 183 Devon Energy .................................................................................................................................... 185 EnCana ................................................................................................................................................. 188 EOG Resources .................................................................................................................................. 190 Newfield Exploration ..................................................................................................................... 193 Range Resources .............................................................................................................................. 196 Talisman Energy .............................................................................................................................. 198 XTO Energy ........................................................................................................................................ 202

Section 3: Analysis of Oil Shales ..................................................................................... 205

Introduction to Oil Shales ................................................................................................. 206

Overview ............................................................................................................................................. 206 History of the Industry .................................................................................................................. 206 Oil Shale Geology ............................................................................................................................. 207 Shale Oil Extraction ........................................................................................................................ 209 Applications of Shale Oil ............................................................................................................... 210

Global Oil Shale Reserves .................................................................................................. 211

Overview ............................................................................................................................................. 211 Estimating Shale Oil Reserves ................................................................................................... 211 Regional Analysis ............................................................................................................................ 212 Global Overview .......................................................................................................................... 212 Africa ................................................................................................................................................ 212


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Executive Summary

Asia ................................................................................................................................................... 213 Europe ............................................................................................................................................. 213 Middle East .................................................................................................................................... 214 North America ............................................................................................................................. 214 Australia ......................................................................................................................................... 214 South America .............................................................................................................................. 214

Analysis of the Oil Shale Industry .................................................................................. 215

Overview ............................................................................................................................................. 215 Power Generation with Shale Oil.............................................................................................. 215 Major Producers of Shale Oil ...................................................................................................... 216 Industrial Uses of Shale Oil ......................................................................................................... 217

Economics of Oil Shale ....................................................................................................... 218

Overview ............................................................................................................................................. 218 Competing with Oil Prices ........................................................................................................... 218 Energy Use & Water Requirement ........................................................................................... 219 Investment in the Industry ......................................................................................................... 221

Environmental Impact of Shale Oil Mining ................................................................. 222

Major Players in Shale Oil ................................................................................................. 224

Ambre Energy ................................................................................................................................... 224 American Shale Oil Corporation ............................................................................................... 225 Eesti Energia ...................................................................................................................................... 226 Exxon Mobil Corporation ............................................................................................................. 227 Fushun Mining Group .................................................................................................................... 229 Hom Tov .............................................................................................................................................. 230 Independent Energy Partners ................................................................................................... 230 Mountain West Energy ................................................................................................................. 231 Oil Shale Exploration Company ................................................................................................. 233 Petrobras ............................................................................................................................................ 234 Queensland Energy Resources .................................................................................................. 237 Red Leaf Resources ........................................................................................................................ 238 Shale Technologies LLC ................................................................................................................ 239

Section 4: Conclusion .......................................................................................................... 241

Appendix ................................................................................................................................. 242

Glossary ................................................................................................................................... 260


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Executive Summary

Figures & Tables

Figures

Figure 1: Alberta's Oil Sands Projects ........................................................................................ 28 Figure 2: Western Canada Sedimentary Basin Cross‐Section .................................................. 30 Figure 3: Cyclic Steam Stimulation ............................................................................................. 39 Figure 4: SAGD ............................................................................................................................. 41 Figure 5: Toe‐to‐Heel Air Injection ............................................................................................. 43 Figure 6: Geology of Natural Gas Resources ............................................................................ 113 Figure 7: Output of Hydraulic Fracture Simulation Model ..................................................... 117 Figure 8: Micro Seismic Mapping of Fractures in a Treatment .............................................. 119 Figure 9: Volumetric Composition of a Shale Gas Fracture Fluid .......................................... 121 Figure 10: U.S. Shale Gas Plays .................................................................................................. 126 Figure 11: Major Shale Basins in the Conterminous United States ....................................... 128 Figure 12: Devonian Shale Cross Section ................................................................................. 131 Figure 13: Devonian Shale Undiscovered Resource Potential ............................................... 132 Figure 14: Marcellus Shale Formation Thickness ................................................................... 133 Figure 15: U.S. Unconventional Gas Outlook ........................................................................... 137 Figure 16: U.S. Natural Gas Supply Outlook ............................................................................. 155 Figure 17: U.S. LNG Imports ...................................................................................................... 161 Figure 18: Well Pad Showing Drilling Rig ................................................................................ 168 Figure 19: Well Pad Showing Equipment Used for Frac Job .................................................. 169 Figure 20: Well Pad Showing Completed Wellhead ................................................................ 169 Figure 21: Access Road at Recently Completed Well .............................................................. 170 Figure 22: Stormwater Diversion Ditch to Collect Offsite Water ........................................... 171 Figure 23: Lower End of Stormwater Diversion Ditch ........................................................... 171 Figure 24: Stormwater Control Structure ................................................................................ 172 Figure 25: Hydraulic Fracture Job at Marcellus Shale Well .................................................... 242 Figure 26: Rotary Drilling Rig ................................................................................................... 243 Figure 27: Directional Drilling .................................................................................................. 244 Figure 28: Hypothetical Well Casing ........................................................................................ 245 Figure 29: Idealized Hydraulic Fracture .................................................................................. 246 Figure 30: Methane in Gas Shales Occurs as the following: .................................................... 247 Figure 31: Estimated Recovery from Barnett Shale ................................................................ 247 Figure 32: Athabasca Oil Sands ................................................................................................. 248 Figure 33: Syncrude Mine at Athabasca Oil Sands .................................................................. 249 Figure 34: Marcellus Shale ........................................................................................................ 250 Figure 35: Trends in Shale Gas Production (MMcf/Day) ........................................................ 251 Figure 36: Barnett Shale in the Fort Worth Basin ................................................................... 253 Figure 37: Fayetteville Shale in the Arkoma Basin ................................................................. 255 Figure 38: Haynesville Shale in the Texas & Louisiana Basin ................................................ 257 Figure 39: Comparison of Target Shale Depth and Base of Treatable Groundwater ........... 259


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Executive Summary

Tables Table 1: Recovery Rates for Various Types of Production ....................................................... 38 Table 2: Comparison of Data for the Gas Shales in the United States .................................... 252 Table 3: Stratigraphy of the Barnett Shale ............................................................................... 254 Table 4: Stratigraphy of the Fayetteville Shale ........................................................................ 256 Table 5: Stratigraphy of the Haynesville Shale ........................................................................ 258


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Executive Summary

Executive Summary Oil Sands, also known as tar sands and bituminous sands, have emerged as a source of unconventional petroleum resources. Oil sands are being used all over the world these days as an alternative to petroleum. While Canada is a leader in the oil sands industry, the United States and other countries are also catching up fast and are developing oil sands in a bid to upgrade the bitumen source to synthetic crude oil. Gas shales are a type of natural gas that is produced from shales. With the rising demands for energy in the world today, shale gas has become an important source of natural gas in not only the United States, but all over the world. In fact, many analysts are predicting that shale gas will supply nearly half of the natural gas supply in North American by the year 2020. Meanwhile, oil shales are organic sedimentary rocks that contain a large amount of kerogen that can be converted into liquid hydrocarbons. While these are three different forms of unconventional energy sources, what is common amongst these them is that the world is starting to use them more and more as the energy crunch hits major countries who's need for energy is never ending. Now comes a research report that explores the tremendous possibilities offered by these three unconventional sources of energy ‐ Oil Sands, Gas Shales, and Oil Shales. The report analyzes these sources of energy in three sections and each analysis contains an overview of the energy source, the technology involved in extracting these forms of energy, the industry status of the energy source, and the major players involved in making these alternative forms of energy a major success today. The economics of each energy form is also analyzed as well as the environmental impact of extracting energy from these three forms. Never before have these three energy sources been analyzed together in one research report. The report is perfectly suited for investors and researchers alike who are interested in finding out more about Oil Sands, Gas Shales, and Oil Shales.


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Executive Summary


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Section 1: Analysis of Oil Sands

Section 1: Analysis of Oil Sands


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Introduction to Oil Sands

Introduction to Oil Sands What are Oil Sands? Bituminous sands ‐ colloquially known as oil sands (and sometimes referred to as tar sands) ‐ are a type of unconventional petroleum deposit. The sands contain naturally occurring mixtures of sand, clay, water, and a dense and extremely viscous form of petroleum technically referred to as bitumen (or colloquially "tar" due to its similar appearance, odor, and color). Oil sands are found in large amounts in many countries throughout the world, but are found in extremely large quantities in Canada and Venezuela. The crude bitumen contained in the Canadian oil sands is described by Canadian authorities as petroleum that exists in the semi‐solid or solid phase in natural deposits. Bitumen is a thick, sticky form of crude oil, so heavy and viscous (thick) that it will not flow unless heated or diluted with lighter hydrocarbons. At room temperature, it is much like cold molasses. Venezuelan authorities often refer to similar types of crude oil as extra‐heavy oil, because Venezuelan reservoirs are warmer and the oil is somewhat less viscous, allowing it to flow more easily. Oil sands reserves have only recently been considered to be part of the world's oil reserves, as higher oil prices and new technology enable them to be profitably extracted and upgraded to usable products. They are often referred to as unconventional oil or crude bitumen, in order to distinguish the bitumen extracted from oil sands from the free‐flowing hydrocarbon mixtures known as crude oil traditionally produced from oil wells. Making liquid fuels from oil sands requires energy for steam injection and refining. This process generates two to four times the amount of greenhouse gases per barrel of final product as the production of conventional oil. If combustion of the final products is included, the so‐called "Well to Wheels" approach, oil sands extraction, upgrade and use emits 10 to 45% more greenhouse gases than conventional crude.


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History of Oil Sands The exploitation of bituminous deposits and seeps dates back to Paleolithic times. The earliest known use of bitumen was by Neanderthals, some 40,000 years ago. Bitumen has been found adhering to stone tools used by Neanderthals at sites in Syria. After the arrival of Homo sapiens, humans used bitumen for construction of buildings and water proofing of reed boats, among other uses. In ancient Egypt, the use of bitumen was important in creating Egyptian mummies. In ancient times, bitumen was primarily a Mesopotamian commodity used by the Sumerians and Babylonians, although it was also found in the Levant and Persia. Along the Tigris and Euphrates rivers, the area was littered with hundreds of pure bitumen seepages. The Mesopotamians used the bitumen for waterproofing boats and buildings. In North America, the early European fur traders found Canadian First Nations using bitumen from the vast Athabasca oil sands to waterproof their birch bark canoes. In Europe, they were extensively mined near the European city of Pechelbronn, where the vapor separation process was in use in 1742. The name tar sands was applied to bituminous sands in the late 19th and early 20th century. People who saw the bituminous sands during this period were familiar with the large amounts of tar residue produced in urban areas as a by‐product of the manufacture of coal gas for urban heating and lighting. The word "tar" to describe these natural bitumen deposits is really a misnomer, since, chemically speaking, tar is a man‐made substance produced by the destructive distillation of organic material, usually coal. Since then, coal gas has almost completely been replaced by natural gas as a fuel, and coal tar as a material for paving roads has been replaced by the petroleum product asphalt. Naturally occurring bitumen is chemically more similar to asphalt than to tar, and the term oil sands (or oil sands) is more commonly used in the producing areas than tar sands because synthetic oil is what is manufactured from the bitumen. Oil sands are now considered a serious alternative to conventional crude oil, since crude oil is becoming scarce. Oil sands and oil shale have the potential to generate oil for centuries.


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Extraction of Oil Sands Surface Mining Since Great Canadian Oil Sands (now Suncor) started operation of its mine in 1967, bitumen has been extracted on a commercial scale from the Athabasca Oil Sands by surface mining. In the Athabasca sands there are very large amounts of bitumen covered by little overburden, making surface mining the most efficient method of extracting it. The overburden consists of water‐laden muskeg (peat bog) over top of clay and barren sand. The oil sands themselves are typically 40 to 60 meters deep, sitting on top of flat limestone rock. Originally, the sands were mined with draglines and bucket‐wheel excavators and moved to the processing plants by conveyor belts. In recent years companies such as Syncrude and Suncor have switched to much cheaper shovel‐and‐truck operations using the biggest power shovels (100 or more tons) and dump trucks (400 tons) in the world. This has held production costs to around $27 per barrel of synthetic crude oil despite rising energy and labor costs. After excavation, hot water and caustic soda (NaOH) is added to the sand, and the resulting slurry is piped to the extraction plant where it is agitated and the oil skimmed from the top. Provided that the water chemistry is appropriate to allow bitumen to separate from sand and clay, the combination of hot water and agitation releases bitumen from the oil sand, and allows small air bubbles to attach to the bitumen droplets. The bitumen froth floats to the top of separation vessels, and is further treated to remove residual water and fine solids. Bitumen is much thicker than traditional crude oil, so it must be either mixed with lighter petroleum (either liquid or gas) or chemically split before it can be transported by pipeline for upgrading into synthetic crude oil. The bitumen is then transported and eventually upgraded into synthetic crude oil. About two tons of oil sands are required to produce one barrel (roughly 1/8 of a ton) of oil. Originally, roughly 75% of the bitumen was recovered from the sand. However, recent enhancements to this method include Tailings Oil Recovery (TOR) units which recover oil from the tailings, Diluent Recovery Units to recover naphtha from the froth, Inclined Plate Settlers (IPS) and disc centrifuges. These allow the extraction plants to recover well over 90% of the bitumen in the sand. After oil extraction, the spent sand and other materials are then returned to the mine, which is eventually reclaimed.


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Alberta Taciuk Process technology extracts bitumen from oil sands through a dry‐retorting. During this process, oil sand is moved through a rotating drum, cracking the bitumen with heat and producing lighter hydrocarbons. Although tested, this technology is not in commercial use yet. Four oil sands mines are currently in operation and two more (Jackpine and Kearl) are in the initial stages of development. The original Suncor mine opened in 1967, while the Syncrude mine started in 1978, Shell Canada opened its Muskeg River mine (Albian Sands) in 2003 and Canadian Natural Resources Ltd opened its Horizon Project in 2009. New mines under construction or undergoing approval include Shell Canada's Jackpine mine, Imperial Oil's Kearl Oil Sands Project, Synenco Energy's Northern Lights mine, and Suncor's Fort Hills mine. It is estimated that approximately 90% of the Alberta oil sands and nearly all of Venezuelan sands are too far below the surface to use open‐pit mining. Several in‐situ techniques have been developed to extract this oil. Cold Flow In this technique, also known as cold heavy oil production with sand (CHOPS), the oil is simply pumped out of the sands, often using progressive cavity pumps. This only works well in areas where the oil is fluid enough. It is commonly used in Venezuela (where the extra‐heavy oil is at 50 degrees Celsius), and also in the Wabasca, Alberta Oil Sands, the southern part of the Cold Lake, Alberta Oil Sands and the Peace River Oil Sands. It has the advantage of being cheap and the disadvantage that it recovers only 5‐6% of the oil in place. Some years ago Canadian oil companies discovered that if they removed the sand filters from the wells and produced as much sand as possible with the oil, production rates improved remarkably. This technique became known as Cold Heavy Oil Production with Sand (CHOPS). Further research disclosed that pumping out sand opened "wormholes" in the sand formation which allowed more oil to reach the wellbore. The advantage of this method is better production rates and recovery (around 10%) and the disadvantage that disposing of the produced sand is a problem. A novel way to do this was spreading it on rural roads, which rural governments liked because the oily sand reduced dust and the oil companies did their road maintenance for them. However, governments have become concerned


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about the large volume and composition of oil spread on roads, so in recent years disposing of oily sand in underground salt caverns has become more common. Combustion Overhead Gravity Drainage This is an experimental method that employs a number of vertical air injection wells above a horizontal production well located at the base of the bitumen pay zone. An initial Steam Cycle similar to CSS is used to prepare the bitumen for ignition and mobility. Following that cycle, air is injected into the vertical wells, igniting the upper bitumen and mobilizing (through heating) the lower bitumen to flow into the production well. It is expected that COGD will result in water savings of 80% compared to SAGD. Cyclic Steam Stimulation The use of steam injection to recover heavy oil has been in use in the oil fields of California since the 1950s. The Cyclic Steam Stimulation or "huff‐and‐puff" method has been in use by Imperial Oil at Cold Lake since 1985 and is also used by Canadian Natural Resources at Primrose and Wolf Lake and by Shell Canada at Peace River. In this method, the well is put through cycles of steam injection, soak, and oil production. First, steam is injected into a well at a temperature of 300 to 340 degrees Celsius for a period of weeks to months; then, the well is allowed to sit for days to weeks to allow heat to soak into the formation; and, later, the hot oil is pumped out of the well for a period of weeks or months. Once the production rate falls off, the well is put through another cycle of injection, soak and production. This process is repeated until the cost of injecting steam becomes higher than the money made from producing oil. The CSS method has the advantage that recovery factors are around 20 to 25% and the disadvantage that the cost to inject steam is high. Steam Assisted Gravity Drainage Steam assisted gravity drainage was developed in the 1980s by the Alberta Oil Sands Technology and Research Authority and fortuitously coincided with improvements in directional drilling technology that made it quick and inexpensive to do by the mid 1990s. In SAGD, two horizontal wells are drilled in the oil sands, one at the bottom of the formation and another about 5 meters above it. These wells are typically drilled in groups off central pads and can extend for miles in all directions. In each well pair, steam is injected into the upper well, the heat melts the


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bitumen, which allows it to flow into the lower well, where it is pumped to the surface. SAGD has proved to be a major breakthrough in production technology since it is cheaper than CSS, allows very high oil production rates, and recovers up to 60% of the oil in place. Because of its very favorable economics and applicability to a vast area of oil sands, this method alone quadrupled North American oil reserves and allowed Canada to move to second place in world oil reserves after Saudi Arabia. Most major Canadian oil companies now have SAGD projects in production or under construction in Alberta's oil sands areas and in Wyoming. Examples include Japan Canada Oil Sands Ltd's (JACOS) project, Suncor’s Firebag project, Nexen's Long Lake project, Suncor's (formerly Petro‐Canada's) MacKay River project, Husky Energy's Tucker Lake and Sunrise projects, Shell Canada's Peace River project, Cenovus Energy's Foster Creek and Christina Lake developments, ConocoPhillips' Surmont project, Devon Canada's Jackfish project, and Derek Oil & Gas's LAK Ranch project. Alberta's OSUM Corp has combined proven underground mining technology with SAGD to enable higher recovery rates by running wells underground from within the oil sands deposit, thus also reducing energy requirements compared to traditional SAGD. This particular technology application is in its testing phase. Vapor Extraction Process VAPEX is similar to SAGD but instead of steam, hydrocarbon solvents are injected into the upper well to dilute the bitumen and allow it to flow into the lower well. It has the advantage of much better energy efficiency than steam injection and it does some partial upgrading of bitumen to oil right in the formation. It is very new but has attracted much attention from oil companies, who are beginning to experiment with it. The above three methods are not mutually exclusive. It is becoming common for wells to be put through one CSS injection‐soak‐production cycle to condition the formation prior to going to SAGD production, and companies are experimenting with combining VAPEX with SAGD to improve recovery rates and lower energy costs.


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Toe to Heel Air Injection This is a very new and experimental method that combines a vertical air injection well with a horizontal production well. The process ignites oil in the reservoir and creates a vertical wall of fire moving from the "toe" of the horizontal well toward the "heel", which burns the heavier oil components and upgrades some of the heavy bitumen into lighter oil right in the formation. Historically fireflood projects have not worked out well because of difficulty in controlling the flame front and a propensity to set the producing wells on fire. However, some oil companies feel the THAI method will be more controllable and practical, and have the advantage of not requiring energy to create steam. Advocates of this method of extraction state that it uses less freshwater, produces 50% less greenhouse gases, and has a smaller footprint than other production techniques. Petrobank Energy and Resources Ltd. has reported encouraging results from their test wells in Alberta, with production rates of up to 400 barrels per day (64 m3/d) per well, and the oil upgraded from 8 to 12 API degrees. The company hopes to get a further 7‐degree upgrade from its CAPRI (controlled atmospheric pressure resin infusion) system, which pulls the oil through a catalyst lining the lower pipe.


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Environmental Issues Facing Oil Sands

Environmental Issues Facing Oil Sands Overview Like all mining and non‐renewable resource development projects, oil sands operations have an adverse effect on the environment. Oil sands projects affect: the land when the bitumen is initially mined and with large deposits of toxic chemicals; the water during the separation process and through the drainage of rivers; and the air due to the release of carbon dioxide and other emissions, as well as deforestation. Additional indirect environmental effects are that the petroleum products produced are mostly burned, releasing carbon dioxide into the atmosphere. Heavy metals such as vanadium, nickel, lead, cobalt, mercury, chromium, cadmium, arsenic, selenium, copper, manganese, iron and zinc are present in oil sands. Air Pollution The Wood Buffalo Environmental Association (WBEA) monitors the air in the Regional Municipality of Wood Buffalo continuously. This is done through a variety of air, land and human monitoring programs. The information collected is openly shared with stakeholders and the public. Since 1995, monitoring in the oil sands region shows improved or no change in long term air quality for the five key air quality pollutants — carbon monoxide, nitrogen dioxide, ozone, fine particulate matter (PM2.5) and sulphur dioxide — used to calculate the Air Quality Index. Air monitoring has shown significant increases in exceedances of hydrogen sulfide (H2S) both in the Fort McMurray area and near the oil sands upgraders. Hydrogen sulfide is the chemical compound with the formula H2S. This colorless, toxic and flammable gas is responsible for the foul odor of rotten eggs. Hydrogen sulfide gas occurs naturally in crude petroleum, natural gas, volcanic gases and hot springs. It also can result from bacterial breakdown of organic matter and be produced by human and animal wastes. In 2007, the Alberta government issued an Environmental Protection Order to Suncor Energy Inc. The order comes in response to numerous occasions when


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ground level concentration (GLC) for H2S exceeded acceptable standards. Environmental Protection Orders are issued under the authority of Alberta’s Environmental Protection and Enhancement Act. Alberta Environment can issue Environmental Protection Orders to remedy environmental problems where there has been a release of a substance that has caused or may cause an adverse effect to the environment. Impact of Mining on Land A large part of oil sands mining operations involves clearing trees and brush from a site and removing the "overburden" — the topsoil, muskeg, sand, clay and gravel — that sits atop the oil sands deposit. Approximately two tons of oil sands are needed to produce one barrel of oil (roughly 1/8 of a ton). As a condition of licensing, projects are required to implement a reclamation plan. The mining industry asserts that the boreal forest will eventually colonize the reclaimed lands, but that their operations are massive and work on long‐term timeframes. As of 2006/2007 (the most recent data available), about 420 km2 (160 sq mi) of land in the oil sands region have been disturbed, and 65 km2 (25 sq mi) of that land is under reclamation. In March 2008, Alberta issued the first‐ever oil sands land reclamation certificate to Syncrude Canada Ltd. for the 1.04 km2 (0.40 sq mi) parcel of land known as Gateway Hill approximately 35 km (22 mi) north of Fort McMurray. Several reclamation certificate applications for oil sands projects are expected within the next 10 years. Impact on Water Resources Between 2 to 4.5 volume units of water are used to produce each volume unit of synthetic crude oil (SCO) in an ex‐situ mining operation. Despite recycling, almost all of it ends up in tailings ponds, which, as of 2007, covered an area of approximately 50 km2 (19 sq mi). In SAGD operations, 90 to 95% of the water is recycled and only about 0.2 volume units of water is used per volume unit of bitumen produced. Large amounts of water are used for oil sands operations – Greenpeace gives the number as 349 million cubic meters per year, twice the amount of water used by the city of Calgary. It is unclear if this is the amount of water they are licensed to remove from the Athabasca or the actual use and how up to date the statistic is. The Athabasca River is also much larger than Bow and Elbow rivers that flow through Calgary.


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The Athabasca River is the ninth longest river in Canada running 1,231 km (765 mi) from the Athabasca Glacier in west‐central Alberta to Lake Athabasca in northeastern Alberta. The average annual flow just downstream of Fort McMurray is 633 cubic meters per second with its highest daily average measuring 1200 cubic meters per second. Current water license allocations totals about 1.8% of the Athabasca river flow. Actual use in 2006 was about 0.4%. In addition, the Alberta government sets strict limits on how much water oil sands companies can remove from the Athabasca River. According to the Water Management Framework for the Lower Athabasca River, during periods of low river flow water consumption from the Athabasca River is limited to 1.3% of annual average flow. The province of Alberta is also looking into cooperative withdrawal agreements between oil sands operators. In October 2009, Suncor Energy announced it was seeking government approval for a new process to recover tailings called Tailings Reduction Operations (TRO), which accelerates the settling of fine clay, sand, water, and residual bitumen in ponds after oil sands extraction. The technology involves dredging mature tailings from a pond bottom, mixing the suspension with a polymer flocculent, and spreading the sludge‐like mixture over a “beach” with a shallow grade. According to the company, the process could reduce the time for water reclamation from tailings to weeks rather than years, with the recovered water being recycled into the oil sands plant. In addition to reducing the number of tailing ponds, Suncor claims TRO could reduce the time to reclaim a tailing pond from 40 years at present to 7–10 years, with land rehabilitation continuously following 7 to 10 years behind the mining operations. In December 2010, the Oil Sands Advisory Panel, commissioned by former environment minister Jim Prentice, found that Canada has "no system" for monitoring the potential impacts of Alberta's oil sands projects on local waterways. Emission of Greenhouse Gases The production of bitumen and synthetic crude oil emits more greenhouse gas (GHG) than the production of conventional crude oil, and has been identified as the largest contributor to GHG emissions growth in Canada, as it accounts for 40 million tons of CO2 emissions per year. Environment Canada claims the oil sands make up 5% of Canada's greenhouse gas emissions, or 0.1% of global greenhouse gas emissions. It predicts the oil sands will grow to make up 8% of Canada's greenhouse


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gas emissions by 2015. Environmentalists argue that the availability of more oil for the world made possible by oil sands production in itself raises global emissions of CO2. While the emissions per barrel of bitumen produced decreased 26% over the decade 1992–2002, total emissions were expected to increase due to higher production levels. As of 2006, to produce one barrel of oil from the oil sands released almost 75 kg (170 lb) of GHG with total emissions estimated to be 67 megatons (66,000,000 LT; 74,000,000 ST) per year by 2015. In January 2008, the Alberta government released Alberta’s 2008 Climate Change Strategy. Alberta’s emissions are projected to grow to 400 megatons (Mt) by 2050, largely due to forecast growth in the oil sands sector. The new plan aims to cut the projected 400 Mt in half by 2050, with a 139 Mt reduction coming from carbon capture and storage — the bulk of those reductions (100 Mt) will come from activities related to oil sands production. A federal court of Canada ruling on March 6, 2008, found the approval of Imperial Oil Ltd.'s $8‐billion oil sands mine insufficient on climate change and greenhouse gas emissions. Proposals in the regulatory system at that date included mines by Total SA of France, by Anglo‐Dutch Royal Dutch Shell and by Petro‐Canada, as well as steam‐injection projects by EnCana of Calgary. A 2009 study by CERA estimated that production from Canada's oil sands emits "about 5% to 15% more carbon dioxide, over the "well‐to‐wheels" lifetime analysis of the fuel, than average crude oil." Author and investigative journalist David Strahan that same year stated that IEA figures show that carbon dioxide emissions from the tar sands are 20% higher than average emissions from oil. With coal's CO2 emissions about one‐third higher than convention oil's , this would make the tar sands' emissions equal to about 90% of the CO2 released from coal. On September 21, 2010, a study by "IHS (Information Handling Services) Cambridge Energy Research Associates (IHS CERA)" found that fuels made from Canadian oil sands "result in significantly lower greenhouse gas (GHG) emissions than many commonly cited estimates... Oil sands products imported to the United States result in GHG emissions that are, on average, six percent higher than the average crude consumed in the country. This level places oil sands on par with other sources of


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U.S. crude imports, including crudes from Nigeria, Venezuela and some domestically produced oil, the report finds." Impact on Aquatic Life There is conflicting research on the effects of the oil sands on aquatic life in the Canadian oil sands development. In 2007, Environment Canada completed a study that shows high deformity rates in fish embryos exposed to the oil sands. David W. Schindler, a limnologist from the University of Alberta, published a study on Alberta's oil sands' contribution of aromatic polycyclic compounds, some of which are known carcinogens, to the Athabasca River and its tributaries. Scientists, local doctors, and residents supported a letter sent to the Prime Minister in September 2010 calling for an independent study of Lake Athabasca (which is downstream of the oil sands) to be initiated due to the rise of deformities and tumors found in fish caught there. The bulk of the research that defends the oil sands development is done by the Regional Aquatics Monitoring Program, RAMP. RAMP studies show that deformity rates are normal compared to historical data and the deformity rates in rivers upstream of the oil sands. It should be noted that RAMP is affiliated with the oil industry and its research data is submitted to environmental government agencies but unlike academia where peer review happens on a per study basis, RAMP does a peer review of the entire organization only once every five years. Other Environmental Concerns The environmental impact caused by oil sand extraction is frequently criticized by environmental groups such as Greenpeace. Environmentalists state that their main concerns with oil sands are land damage, including the substantial degradation in the land's ability to support forestry and farming, greenhouse gas emissions, and water use. Oil sands extraction is generally held to be more environmentally damaging than conventional crude oil — carbon dioxide "well‐to‐pump" emissions, for example, are estimated to be about 1.3‐1.7 times that of conventional crude.


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Energy Requirement for Oil Sand Extraction

Energy Requirement for Oil Sand Extraction Approximately 1.0 – 1.25 gigajoule of energy is needed to extract a barrel of bitumen and upgrade it to synthetic crude. As of 2006, most of this is produced by burning natural gas. Since a barrel of oil equivalent is about 6.117 gigajoules, this extracts about 5 or 6 times as much energy as is consumed. Energy efficiency is expected to improve to 0.7 gigajoules of energy per barrel by 2015, giving an EROEI of about 9. However, since natural gas production in Alberta peaked in 2001 and has been static ever since, it is likely oil sands requirements will be met by cutting back natural gas exports to the U.S. Alternatives to natural gas exist and are available in the oil sands area. Bitumen can itself be used as the fuel, consuming about 30‐35% of the raw bitumen per produced unit of synthetic crude. Nexen's Long Lake project will use a proprietary deasphalting technology to upgrade the bitumen, using asphaltene residue fed to a gasifier whose syngas will be used by a cogeneration turbine and a hydrogen producing unit, providing all the energy needs of the project: steam, hydrogen, and electricity. Thus, it will produce syncrude without consuming natural gas, but the capital cost is very high. Coal is widely available in Alberta and is inexpensive, but produces large amounts of greenhouse gases. Nuclear power is another option which has been proposed, but did not appear to be economic as of 2005. In early 2007 the Canadian House of Commons Standing Committee on Industry, Science and Technology considered that the use of nuclear power to process oil sands could reduce CO2 emissions and help Canada meet its Kyoto commitments, as it would require nearly 12 GW to meet production growth to 2015, but the implications of building reactors in northern Alberta were not yet well understood. Energy Alberta Corporation announced in 2007 that they had applied for a license to build a new nuclear plant at Lac Cardinal, 30 km west of the town of Peace River. The application would see an initial twin AECL Advanced CANDU Reactor ACR‐1000 plant go online in 2017, producing 2.2 GW (electric). At 6.117 GJ/barrel, this is equivalent to conserving 31,074 barrels per day (4,940.4 m3/d). On November 30, 2007 Bruce Power, which operates eight CANDU reactors in Ontario, signed a letter of intent to acquire Energy Alberta and take over the project.


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Analysis of Canada’s Oil Sands Industry

Analysis of Canada’s Oil Sands Industry Industry Overview As of January 2009, there were 91 active mining and in‐situ oil sands projects in Alberta that produced more than 1.5 million barrels per day in 2009, which represented about 1.8% of world oil supply – and more projects are proposed or under construction. The National Energy Board estimates that production could exceed 2.8 million barrels per day in 2020 if all the current and proposed projects go ahead. The Alberta government envisions oil sands production as high as 3.2 million barrels per day by 2019; that would be equivalent to about 13.2% of the North American daily oil consumption in 2009 (2.2 million barrels in Canada, 18.7 million barrels in the United States, 2.1 million barrels in Mexico and 1.2 million barrels elsewhere in North America.) Canada also produced 434,727 barrels of conventional heavy oil per day in 2009. Upgraded and non‐upgraded bitumen and heavy oil thus accounted for more than half of Canada’s crude oil production. Without this production, Canada would have been a net importer of crude oil. With it, Canada had substantial positive energy trade balance of $46.0 billion (including natural gas and coal as well as oil) and was the largest single supplier of crude oil to the United States. Although Canada is a net oil exporter, it imported approximately 807,751 million barrels of crude oil and refined products per day in 2009. Many factors have converged to make the Alberta oil sands such an important resource in the 21st century:

• Experience gained through more than a century of research and four decades of commercial production;

• Continuing development of technologies to reduce costs and environmental

impacts;

• High demand, and therefore high prices, for crude oil and refined petroleum products;


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• Taxes and royalties that are adapted to the high capital costs and long lead times of oil sands development;

• An infrastructure of roads, pipelines and electrical power lines;

• Managerial talent, technical expertise and skilled labor;

• Scientific research to address the many issues arising from development and

improve development processes;

• Regulatory and consultative processes to facilitate. Oil sands development has created many opportunities:

• A large new source of petroleum to meet North American and global demand;

• Employment for Albertans and other Canadians;

• Revenues for energy companies and governments;

• Economic benefits for Aboriginal people and other residents of northeastern Alberta;

• Investments in education, training, scientific research and technological

development. But there are also challenges arising from development:

• Greenhouse gases and other air emissions, water use and land disturbance;

• Consumption of natural gas to extract and upgrade bitumen;

• Strain on infrastructure and labor markets due to rapid growth;

• Inflation and delays due to high demand for crucial goods and services;

• Effects on Aboriginal communities and traditional land uses.


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Oil sands deposits underlie 142,000 square kilometers of Alberta, an area larger than the island of Newfoundland or the state of North Carolina. The Athabasca oil sands area, by far the largest, is the site of all surface mining projects and most in‐situ extraction projects. There are also large in‐situ projects in the Cold Lake oil sands area. Development has been slower in the Peace River, Wabasca and Buffalo Head Hills deposits. The Carbonate Triangle is an area where bitumen is trapped in limestone rocks as well as sands or sandstones. Production from the Carbonate Triangle has not been considered technologically or economically feasible to date, but companies have acquired large leases there and presumably see prospects for future development. Approximately 8,000 square kilometers of bitumen resources are being evaluated in northwest and east‐central Saskatchewan, and there are significant bitumen deposits on Melville Island in the Canadian Arctic. Conventional heavy oil deposits in Canada are concentrated around Lloydminster on the Alberta‐Saskatchewan border, but heavy oil has also been found in British Columbia, offshore Newfoundland and Labrador, and in the Arctic Islands.


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Figure 1: Alberta's Oil Sands Projects

Source: EIA

Global Impact of the Industry The Canadian oil sands resource – the total amount of bitumen in the ground – is estimated at 1.7 trillion barrels, of which 170 billion barrels are considered recoverable reserves, based on current economics and technology. Eighty percent of these reserves, approximately 138 billion barrels, can only be recovered through in‐situ processes. Reserves currently under development, through both mining and in‐situ methods, total 15.8 billion barrels. The recoverable oil sands reserves in northern Alberta represent a potential supply larger than the conventional crude oil reserves of Iran, Iraq or Kuwait, and are second only to those of Saudi Arabia.


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Bitumen and heavy oil resources are found in many other parts of the world, including off Canada’s East Coast and in the Arctic Islands, but none of the known deposits come close to the scale of Alberta’s oil sands and the Orinoco heavy oil region of Venezuela. In addition, there are numerous deposits of oil shales around the world, but extracting hydrocarbons economically from oil shales has proved very difficult. However, new technologies and processes are improving the economical viability of these resources. Relatively abundant coal resources also can be gasified or converted into liquid fuels, but this poses major economic and environmental challenges. Crude oil plays a central role in the North American and world economies. Nearly all motorized transportation (except electric rail) currently depends on gasoline, diesel, jet and marine fuels refined from crude oil. Transportation fuels account for about three‐quarters of current crude oil consumption. Many other products, from asphalt paving and roofing to synthetic rubber, are manufactured economically from by‐products of crude oil. While alternatives such as ethanol and biodiesel can fill some of the mobile fuel demand, it would take much of the world’s cropland to supply all the transportation energy now obtained from crude oil. Conservation, efficiency gains and economic recessions can also reduce consumption, but demand for crude oil is likely to remain high well into the 21st century.


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Figure 2: Western Canada Sedimentary Basin Cross‐Section

Source: NRCan

Makeup of the Bitumen Resources Like all crude oil, Canada’s bitumen resources started as living material. Hundreds of millions of years ago, the remains of tiny plants and animals, mainly algae, were buried in sea beds. As the organic materials became more deeply buried, they slowly “cooked” at temperatures between 50 and 150 degrees Celsius. Eventually, this process converted the materials into liquid hydrocarbons, as well as sulphur compounds, carbon dioxide and water. The liquid hydrocarbons included both “light” compounds – those with only a few atoms of carbon surrounded by hydrogen atoms – and large “heavy” molecules composed of many more carbon atoms and relatively fewer hydrogen atoms. Light hydrocarbons are similar to those found in gasoline, diesel and jet fuel. Heavy hydrocarbons are like those found in grease and tar. The hydrocarbons then migrated through rocks until they reached the surface or something blocked their progress. Conventional light crude oil is usually trapped in porous rocks under a layer of impermeable (non‐porous) rock. In such reservoirs,


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the oil is not in an underground lake but rather held in the pores and fractures of rock, like water in a sponge. Oil sands are different. Geologists believe that about 50 million years ago, huge volumes of oil migrated eastward and upward through more than 100 kilometers of rock until they reached and saturated large areas of sand and sandstones at or near the surface. Bacteria then feasted on the hydrocarbons, degrading the simplest hydrocarbons first, converting them into carbon dioxide and water, and leaving behind the big hydrocarbon molecules and other substances, such as trace metals, that cannot be digested. The bacteria may also modify some of the simpler sulphur molecules, leaving complex sulphur compounds. As a result, there are more heavy hydrocarbons, complex sulphur compounds and metals in bitumen than in conventional crude oil. This makes extraction and processing more difficult and expensive. While the Athabasca oil sands are one of world’s largest known hydrocarbon resources, the volume of original crude oil digested by the micro‐organisms is believed to have been at least two or three times greater than what now remains as bitumen. While bacteria were the major agent in forming Canada’s oil sands bitumen, crude oil can also be degraded or altered by other factors such as oxidation, evaporation, underground water flows and loss of light hydrocarbons that migrate more easily through pores and fractures in rocks. Various combinations of such factors create the many kinds of bitumen and heavy oil deposits found around the world. In the Alberta oil sands, each grain of sand is surrounded by a layer of water and a film of bitumen. The water layer prevents the bitumen from being absorbed directly onto the sand surface, which allows for relatively simple extraction. In contrast, in oil shales the hydrocarbon is in direct contact with the mineral making extraction more difficult. Challenges Facing the Industry The economic, environmental and social challenges of oil sands arise from the nature of the resource, its location, its vast scale and rapid acceleration of development since the late 1990s. The resource is different from light crude oil and


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requires different methods and facilities to produce transportation fuels and other commodities previously obtained from conventional crude oil. Until recently, the main producing region had a small population and modest infrastructure. The resource is so large that almost everything about its development has occurred on a huge and often unprecedented scale, although smaller in‐situ projects are now becoming more common. Among some stakeholders, the recent pace of development has raised questions about sustainability. Economic challenges include inflation, shortages and delays caused by the high demand for labor, equipment and other key goods and services as multiple projects are under construction. Once production begins, labor requirements and the energy requirements in the production process have been major concerns. Projects need continual maintenance to avoid unscheduled production interruptions. As in other high‐growth areas, rapid growth has put heavy burdens on infrastructure such as roads and water treatment, and new construction has had trouble keeping pace. Environmental challenges involve both the impacts of individual projects and the cumulative effects of development. Greenhouse gas emissions from production and upgrading are about 10% higher than from conventional crude; however, if cogeneration is taken into consideration, oil sands crudes would have a carbon footprint similar to conventional crudes. There are also emissions of gases that can cause acid deposition and ground‐level ozone or smog. Use and disposal of water are significant issues. Impacts on soils, vegetation and wildlife of the boreal forest – not just from mining but also from wells, plants, roads, pipelines, electric power lines and seismic cutlines – raise questions about how ecosystems can be protected during operations and reclaimed after production ceases. The soaring demand for labor and services to support the projects and the effects on the existing Aboriginal and non‐Aboriginal communities are among the social challenges. The population of the Regional Municipality of Wood Buffalo, which includes Fort McMurray and most of the Athabasca oil sands region, soared by 108% between 1999 and 2007 to more than 89,100. Traffic multiplied on the main highway and through the airport. Local government officials, Aboriginal communities and non‐government organizations sought greater input into decisions affecting them.


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Market Opportunities The challenges represent opportunities for those who can find more effective and sustainable ways to do things. Lessons from four decades of commercial oil sands operations have already been incorporated into the existing projects and those under development, and new approaches are continually being introduced. As a result, Canadians have become world leaders in unconventional crude oil production, and Canadian expertise is now being applied to other bitumen resources in places such as California and Egypt. The economic opportunities – employment, regional development, government revenues and export earnings – are numerous. Only about 10% of the Alberta bitumen resource is considered economically recoverable with current technologies, yet those reserves would be sufficient to sustain production of three million barrels per day for more than 150 years. New methods could unlock the resources currently beyond reach, including the deposits in the Carbonate Triangle. Innovation could also make existing projects much more cost effective, productive and environmentally sustainable, for both existing and new projects. Creative solutions are being found to the labor shortages and supply bottlenecks that slowed projects as oil sands development accelerated. Companies have built camps to house construction workers, and some workers fly in from other provinces and fly home for rest days. With support from industry and government, community colleges and technical schools have expanded programs to train workers, and companies have stepped up in‐house training. Companies have also collaborated in efforts to maximize employment opportunities, minimize competition for labor and ensure an adequate supply of skilled trades throughout construction. Construction schedules have been altered and some work postponed to avoid conflicts with other projects. Wherever possible, assembly and fabrication work is done in the Edmonton area or elsewhere outside the oil sands region. Some new upgrading facilities are located in the industrial area near Edmonton, and upgrading capacity has been built at the project sites. New pipelines are planned to carry diluted bitumen from producing


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areas to upgraders, and upgraded crude oil to refineries. Meanwhile, work has begun on twinning the main highway between Edmonton and the oil sands project area north of Fort McMurray, and a second highway to the Fort McMurray area was paved in 2006. The provincial government has also stepped up support for other infrastructure, water and wastewater treatment, housing, schools and health facilities in Fort McMurray. While existing projects use natural gas to provide most of the energy for operations as well as the hydrogen for upgrading, companies are developing and implementing technologies that reduce or eliminate the need for natural gas. Upgraders already capture much of the energy used for extraction as waste heat and obtain considerable energy from bitumen residues during processing, and this is expected to increase. One project obtains substantially all its heat energy from coke and bitumen combustion and gasification. Technologies are also being tested to extract bitumen underground without the need for steam heat. Other possible energy sources include Alberta’s large coal resources and nuclear reactors. One project has been proposed to gasify coal in central Alberta as a source of fuel and hydrogen, and there have been preliminary discussions about nuclear power options. Each project undergoes environmental assessment before approval, and regulatory authorities also consider the cumulative effects of multiple projects on regional ecosystems. Many research and development projects are underway to reduce environmental impacts. Several methods have been suggested to reduce greenhouse gas emissions. One possibility would be to inject emissions underground, known as carbon capture and storage or carbon sequestration; some of the carbon dioxide might be used to enhance production from conventional oil fields. On a per‐barrel basis, greenhouse gases have been reduced 38% and other emissions have been reduced substantially since the 1990s, but the recent rapid expansion of production has made further emissions reductions a high priority for companies and government authorities. Water recycling and use of non‐potable groundwater already reduce impacts on freshwater resources, and new technologies may reduce the large water requirements for current oil sands production methods. Companies are also working with scientists, government authorities and forestry companies to reduce


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cumulative impacts on soils, vegetation and wildlife. On a per‐barrel basis, most in‐situ oil sands operations disturb less land than conventional oil operations. There are opportunities for people across Canada – and internationally – in responsible development of oil sands bitumen resources. Production reduces North America’s dependence on imports of crude oil from other parts of the world, and it makes more oil available to meet global demand. A favorable trade balance benefits Canadians. According to a study by the Canadian Energy Research Institute, over the next 25 years 9.4% of total GDP impacts and 22.8% of total employment from oil sands investment and operations in Alberta occurs in provinces outside Alberta. The study also indicates the federal tax impact on Alberta will be $166 billion compared to $22.4 billion for the other provinces. Mining the Oil Sands About 20% of Alberta’s economically recoverable oil sands bitumen reserves are close enough to the surface to make mining feasible. These are all located in the Athabasca oil sands area north of Fort McMurray. An advantage of mining is that nearly all of the bitumen is extracted from the ore, while in‐situ methods leave a substantial amount of the resource underground. A disadvantage is that a great deal of earth and ore must be moved, disturbing significant areas of landscape. To achieve economies of scale, the projects are very large. Each of the operating mining projects also has an upgrader on site or is connected to an upgrader by pipeline. The ore in the current projects’ lease areas averages about 10 to 12% bitumen by weight. Thus nearly two tons of oil sands are dug up, moved and processed to make one 159‐litre barrel of upgraded crude oil. The processed sand is then returned to the pit, and the site reclaimed. A big part of the mining operation involves clearing trees and brush from the site and removing the overburden – the topsoil, muskeg, sand, clay and gravel – that sits atop the oil sands deposit. This can amount to more than two tons of additional material that needs to be moved in the course of producing one barrel of upgraded crude oil. The topsoil and muskeg are stockpiled so they can be replaced as sections of the mined‐out area are reclaimed. The rest of the overburden is used to reconstruct the landscape.


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The oil sands are highly abrasive and very hard on machinery. Literally tons of steel are worn away from the equipment each year. Regular maintenance is expensive but vital to a profitable operation. When the Suncor and Syncrude projects were built in the 1960s and 1970s, they used giant excavators called bucket wheels and draglines to dig up the oil sands ore and kilometers long conveyor belts to move it to bitumen extraction facilities. They used this system because, at that time, the largest mining trucks carried less than 60 tons in a load. However, the excavators and conveyors were expensive to operate and suffered frequent breakdowns, especially in cold weather. In the mid‐1980s, Syncrude started using trucks and power shovels for a portion of its oil sands mining. In 1993, Suncor switched its entire operation to a system that used the world’s largest trucks and power shovels. Each truck by then could carry up to 240 tons in a single load. Syncrude began phasing out its draglines and bucket wheels a few years later and retired the last of its draglines in 2006. By the late 1990s, the trucks in use were carrying as much as 360 tons, and the largest trucks today carry about 400 tons. The truck‐and‐shovel system has proven much more flexible and energy‐efficient than the draglines and bucket wheels of yesteryear. The other big innovation in the 1990s was a system called hydrotransport, which uses pipelines instead of conveyors to carry oil sands to the processing plant. The trucks dump the sand into a machine that breaks up lumps and removes rocks, then mixes the sand with warm water. The resulting slurry of oil sands and hot water is transported by pipeline to the extraction plant. As an added benefit, bitumen begins to separate from sand, water and minerals as it travels from the mine to the plant. In the mid‐1990s, Syncrude began lowering extraction process temperatures from the 80°C that was then the customary temperature. The move to hydrotransport facilitated a reduction in process temperature to 40°C, which is currently the norm. As a result, the energy requirement for bitumen extraction has been essentially halved.


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A new system was tested in 2006 and is expected to make ore transportation even more efficient. A mobile crusher, connected to a slurry pipeline, is located next to the power shovel so that the ore can be dumped in directly. Trucks would still be needed to carry overburden and to reach less accessible parts of the mines, but this system could considerably reduce the trucking requirement and related air emissions. Extraction At the processing plant, the mixture of oil, sand and water goes first to a large separation vessel. Tiny air bubbles, which are trapped in the bitumen as it separates from the sand granules, float the bitumen to the surface where it forms a thick froth at the top of the vessel. This froth is skimmed off, mixed with a solvent and spun in a centrifuge to remove remaining solids, water and dissolved salts from the bitumen. The solvent is recycled. The sand and water, known as tailings, fall to the bottom of the separation vessel. The sand is eventually sent back to the mine site to fill in mined‐out areas. Water from the extraction process, containing sand, fine clay particles and traces of bitumen, goes into settling ponds. Some bitumen may be skimmed off the ponds if it floats to the surface. The sand sinks to the bottom and bacteria digest the remaining bitumen, but the fine clay particles stay suspended for some time before slowly settling. Adding gypsum helps to speed the settling process and produces a slurry called consolidated tailings (CT) for disposal in mined‐out areas. Water is recycled back to the extraction plant for use in the separation process. As mining operations move further away from the main upgrading plants, some companies have started building satellite extraction facilities. The bitumen froth is then sent to the upgrader by pipeline. This reduces the round‐trip distance for moving sand between the mine pit and the extraction equipment.


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Table 1: Recovery Rates for Various Types of Production

Source: NRCan

Insitu Bitumen More than 80% of the economically recoverable oil sands bitumen is buried too deeply for surface mining. Most of this cannot be produced from a well unless it is heated or diluted. Today’s major commercial in‐situ projects use steam to heat and dilute the bitumen, although several other methods are being tested or deployed. Current in‐situ production technologies recover between 25 and 50% of the bitumen in the reservoir. This is higher recovery than most conventional light crude oil wells. Research to improve the in‐situ recovery rates continues. Excluding the use of diesel as fuel for the mining equipment and trucks, mining operations may use less energy and water than in‐situ operations on a per barrel basis. In‐situ does use substantially less surface area, is reclaimed faster and requires far less reclamation after operations cease. Research and pilot operations are currently underway which will dramatically reduce the energy and water consumption for in‐situ oil sands development. There are two principal in‐situ steam injection methods used in Canada today. The choice between them depends on the characteristics of the reservoir.


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Cyclic Steam Stimulation

Figure 3: Cyclic Steam Stimulation

Source: U.S. DOE


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Cyclic steam stimulation is used at Imperial Oil’s Cold Lake project, Canada’s largest in‐situ bitumen producer, and at Canadian Natural Resources Limited’s Wolf Lake Primrose project. In this method, high‐pressure steam is injected into the oil sands formation for several weeks. The heat softens the bitumen, while the water helps to dilute and separate the bitumen from the sand grains. The pressure also creates channels and cracks through which the bitumen can flow to the well. When a portion of the reservoir is thoroughly saturated, the steam injection ceases and the reservoir “soaks” for several weeks. This is followed by the production phase, when the bitumen is pumped up the same wells to the surface. When production rates decline, another cycle of steam injection begins. This process uses vertical, deviated and horizontal wells and is sometimes called “huff‐and‐puff” recovery. Shell Canada uses a similar method, with horizontal wells, in the Peace River oil sands area. Steam Assisted Gravity Drainage Most of the other current in‐situ projects, particularly in the Athabasca oil sands area, use steam‐assisted gravity drainage (SAGD). In this method, pairs of horizontal wells, one above the other, are drilled into an oil sands formation, and steam is injected continuously into the upper well. As the steam heats the oil sands formation, the bitumen softens and drains into the lower well. Pumps then bring the bitumen to the surface.


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Figure 4: SAGD

Source: U.S. DOE


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Generating Steam Existing in‐situ projects use natural gas‐fired boilers to generate steam, consuming between 1,000 and 1,200 cubic feet of natural gas to produce each barrel of bitumen or about twice as much as the mining‐upgrading projects use to produce a barrel of synthetic crude oil. In 2009, natural gas consumed by oil sands producers was 681.5 Bcf, up 17.1% from 2008. This represents 13% of total Canadian gas demand. This gas use includes natural gas required for electricity generation. However, in‐situ developments do not require the use of diesel fuel to run equipment in their operations, like typical mining development and therefore do not have that energy requirement or the associated emissions. Technologies have been developed to use crude bitumen as a fuel if needed for steam generation. Additionally, some projects are using by‐products of bitumen upgrading, such as asphaltenes and carbon residue or coke. Most of these methods would increase emissions of air contaminants, such as particulates, oxides of sulphur and nitrogen, and greenhouse gases compared to natural gas; however, new technologies are being developed to capture and store carbon dioxide and manage the other air contaminants. VAPEX One technology that could reduce energy requirements is called “vapor extraction” or VAPEX. In this method, pairs of parallel horizontal wells are drilled as in SAGD, but instead of steam, natural gas liquids such as ethane, propane or butane are injected into the upper well to act as solvents so the bitumen or heavy oil can flow to the lower well. An industry government consortium is currently evaluating a VAPEX pilot project at the Dover lease northwest of Fort McMurray, and the technology is also being tested by several operators on their own leases. A number of other in‐situ production systems, including solvents, electric currents, microwaves and even ultrasound, have been tried on an experimental scale. Firefloods


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There has been some production of heavy oil and oil sands bitumen with “firefloods” in which air or oxygen is injected and part of the resource is ignited to heat the reservoir. Petrobank Energy and Resources Ltd. is using a variation on the fireflood method near Christina Lake, south of Fort McMurray in the Athabasca oil sands region; the system is called “toe‐to‐heel air injection” or THAITM. This process uses no natural gas for production and very little water, thereby substantially reducing the GHG emissions and overall environmental footprint of in‐situ production.

Figure 5: Toe‐to‐Heel Air Injection

Source: U.S. DOE “Cold” Production Conventional production methods using vertical and horizontal wells have also been used, primarily in the Cold Lake oil sands but also in the Athabasca and Peace River oil sands, where deposits are considered too thin to make steam injection economic. This production method is also known as CHOPS (cold heavy oil production with


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sand). Technologies such as progressive cavity pumps have improved the effectiveness of these “cold” production methods. Processing In‐situ bitumen processing involves using water to separate the bitumen from water and sand. In‐situ use of surface water has remained relatively constant, but the total volume of groundwater allocated and used is increasing substantially, doubling between 2002 and 2007, with saline ground water use growing and expected to meet up to 40% of total in‐situ water requirements in the future. Devon’s Jackfish project currently uses 100% saline water. In‐situ projects that use saline water from deep formations also treat the water after use and then re‐inject it into these same formations, so as to not impact the surface or groundwater systems. Up to 90% of the water is recycled, with the remainder injected underground if it cannot be used in operations. Solids may be landfilled, injected underground or used to surface roads. After processing, the bitumen is diluted with condensate (pentanes and heavier hydrocarbons obtained from natural gas processing) and the mixture is shipped by pipeline to an upgrader or refinery. Upgrading Compared to conventional light crude oil, bitumen typically contains more sulphur and a much higher proportion of large, carbon‐rich hydrocarbon molecules. All operating mines have integral upgraders and 100% of mineable production is upgraded within Alberta. In 2008, about eight percent of in‐situ production was upgraded in Alberta, with most of the rest being upgraded elsewhere in Canada or shipped to the U.S. for upgrading. Currently only a very small portion of bitumen is shipped to Asian markets. Upgrading is the process that converts bitumen into a product with a density and viscosity similar to conventional light crude oil. This is accomplished by using heat to “crack” the big molecules into smaller fragments. Adding high‐pressure hydrogen and/or removing carbon can also create smaller hydrocarbon molecules. Most of the energy for upgrading is obtained from byproducts of the process. Upgrading is usually a two‐stage process. In the first stage, coking, hydro‐processing, or both, are used to break up the molecules. Coking removes carbon, while hydro‐processing adds hydrogen. In the second stage, a process called


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hydrotreating is used to stabilize the products and to remove impurities such as sulphur and nitrogen. The hydrogen used for hydro‐processing and hydrotreating is produced from natural gas and steam. Upgrading produces various hydrocarbon products that can be blended together into a custom‐made crude oil equivalent, or they can be sold or used separately. The Syncrude and Suncor mining projects use some of their production to fuel the diesel engines in trucks and other equipment at their operations. Suncor also ships diesel fuel by pipeline to Edmonton for sale in the marketplace. Upgraders in Canada remove most of the sulphur from bitumen. Since sulphur may be about five percent of the raw resource, large volumes of this by‐product are produced, Natural Resources Canada expects annual sulphur production from oil sands projects to rise from about 1.6 million tons in 2009 to about 3.3 million tons in 2018. Sulphur is used in the manufacture of fertilizers, pharmaceuticals and other products. Unsold sulphur is stockpiled. Those operations that use coking also market or stockpile the coke, which contains some sulphur as well as carbon. Co‐generation is the simultaneous production of electricity and heat energy from a single facility. All of the oil sands mining operations, and several of the larger in‐situ projects, include natural gas or synthetic gas‐fired co‐generation. The electricity is used to meet the projects’ own energy needs, such as operating mine machinery and in‐situ well pumps, and any excess power is sold to the provincial power grid. The heat energy is used to separate bitumen from sand – whether at the extraction plants in the mining operations or by steam injection at the in‐situ projects. Co‐generation produces fewer air emissions per unit of energy produced compared to other thermal‐electric generating facilities. Upgrading can occur at the producing site, adjacent to a refinery or anywhere in between. The choice of location for upgrading depends on several factors:

• Capital and operating costs of the upgrader at one location relative to another;

• Potential synergies of locating an upgrader near to or in association with

other corporate assets such as a refinery; • Transportation costs


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o Diluent cost and availability – crude bitumen has to be diluted to flow through pipelines

o Pumping costs – diluted bitumen requires more energy to pump than conventional or upgraded crude

• Marketing Conditions Transportation Pipelines are the least expensive and most efficient way to move petroleum products over land. Upgraded synthetic crude oil has a density of about 850 kilograms per cubic meter (about 34 degrees on the America Petroleum Institute gravity scale), similar to the vegetable oil in our kitchens, and is shipped through pipelines just like the conventional light crude oil it resembles. Moving bitumen by pipeline is a challenge due to its high viscosity (resistance to flow, or stickiness). Large‐diameter pipelines with powerful pumps help, but producers also lower the density and viscosity of the bitumen by diluting it with a light, low‐viscosity petroleum product such as condensate, conventional light crude oil or synthetic crude oil. Some bitumen must be diluted by as much as 40% to flow through a pipeline. The most common diluents for oil sands bitumen is condensate, a mixture of pentanes and heavier hydrocarbons obtained from natural gas processing. Supplies of condensate in Western Canada are limited. Some pipeline systems already include return lines to carry condensate back upstream for re‐use. A recent alternative uses synthetic crude to dilute bitumen for shipment; the two fluids are separated before processing at the downstream end. Other proposed solutions involve pipelining imported condensate from the U.S. Midwest or Canada’s West Coast for use as diluent. As bitumen production has increased, there have been periodic shortages of condensate and light oil available for dilution. This is one reason why upgraders in Western Canada increased their processing capacity. Bitumen can also be shipped by truck, but again it must be diluted or heated first. Trucks are used mainly to carry production from small or experimental operations to the nearest upgrader or pipeline terminal.


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Economics of the Industry Oil sands development depends mainly on two factors: the cost of producing and transporting the products, and the price buyers are willing to pay. Crude oil prices are determined by global supply and demand and change with the weather, politics and other factors. For Western Canadian producers, refining capacity and competition in the midcontinental U.S. and Canadian markets are also key considerations. Operating costs – the labor, natural gas and other goods and services needed to produce a barrel – comprise about half of the supply cost for producers. In addition, companies have to earn enough to repay the capital they invested in the project, pay royalties and taxes to government, reclaim the sites and set aside funds for research, maintenance and new developments. The developers have invested billions of dollars in the projects, and they must attempt to earn a competitive return on this investment. Judging by the scale of current and proposed activity, companies generally believe that oil sands projects are worthwhile long‐term investments. A number of factors affect the profitability of oil sands projects. Major influences include the exchange rate of the Canadian dollar, fiscal terms and operating expenses such as initial capital costs, crude prices and natural gas, material and labor costs. As well, because of unique challenges, different projects will have differing operating costs. The operating costs for conventional light oil in Western Canada are considerably lower than for upgraded oil sands bitumen, but conventional producers also have to invest continually in exploration for new reserves, which can add substantially to their costs. After a few years of production, the volume produced from a conventional well begins to decline and the operating costs start to rise, whereas this is not the case with oil sands mining. Operating costs in the oil sands mining projects are partly dependent on the price of natural gas used to generate steam and electricity and to produce hydrogen in associated upgrading facilities. If ways can be found to reduce or eliminate natural gas use, then costs could be reduced significantly. Wages and salaries are another major component of operating costs for mines and upgraders as they employ large


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numbers of skilled workers. The operating costs to produce in‐situ bitumen vary considerably. In a 2008 study, the Canadian Energy Research Institute estimated plant gate supply costs of about $42 per barrel for cyclic steam stimulation projects and $38 per barrel for steam‐assisted gravity drainage projects, compared to almost $63 per barrel for mining projects. The amount of natural gas used to generate steam and the recovery rate are the key factors. The availability of condensate and light oil to dilute bitumen can also affect markets for these products. The price of bitumen generally increases in the spring and summer when a lot of road‐building and construction activity requiring asphalt is under way. The spread between the price of heavy and light oils is called the differential. The provincial government, which owns the mineral rights to virtually all of the oil sands resources, has recognized the long‐term benefits of development in shaping royalty arrangements for their “owner’s share” of revenues from oil sands. Alberta established a stable “generic” oil sands royalty system in 1997 after decades of negotiating project‐by project arrangements. Under the generic system, the province collected one percent of gross sales revenues on all production and a 25% share of net project revenues after the operator recovered capital costs to build the project. In 2009, the government introduced its New Royalty Framework, consisting of price‐sensitive royalty rates linked to the price of West Texas Intermediate crude oil in Canadian dollars. For projects that haven’t recovered capital costs incurred to construct the project, gross royalty rates start at one percent when oil is priced at $55 per barrel or less, and increase to a maximum of nine percent when oil is priced at $120 per barrel or more. For projects that have recovered start‐up costs, net royalty rates start at 25% when oil is priced at $55 per barrel or less, and increase to a maximum of 40% when oil is priced at $120 or more. The goals of the new Royalty Regime are as follows:

• Support sustainable economic development that contributes to a high quality of life for all Albertans now and into the future;

• Support a fair, predictable and transparent royalty regime;


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• Align Alberta’s royalty regime with overall government objectives.

One economic benefit of oil sands development is the ongoing stable employment and significant maintenance capital expended throughout the entire life of the project, in contrast to the ups and downs of conventional oil operations. This was an important consideration cited by the governments when they implemented the generic royalty and tax regimes. Though the economic effects of oil sands development are concentrated in Alberta, they also spread across the country and internationally through purchases of equipment, materials and services. Companies and workers pay taxes to the federal government, and Alberta is a major contributor to equalization payments that aid poorer provinces. According to a study by the Canadian Energy Research Institute, oil sands tax revenue across the country will total $307 billion over the next 25 years, $187 billion of which will go to the federal government. The high demand for labor in the oil sands region has also alleviated unemployment across the country. People from Atlantic Canada, for example, now account for more than one‐quarter of the population in Fort McMurray. Energy Balance for Oil Sands MiningUpgrading Projects The energy balance is simply the ratio between energy inputs and outputs for a given type of energy production. Energy balances are used as indicators of efficiency when comparing energy types and production methods. Based on National Energy Board data for natural gas inputs and petroleum outputs, the energy balance for oil sands mining‐upgrading projects is about 1:12 and it is about 1:6 for in‐situ bitumen production. In addition, about 14% of the raw bitumen is consumed to produce energy during upgrading or is converted into by‐products such as coke and sulphur. As a result if the raw bitumen from in‐situ projects is then upgraded into synthetic crude oil, the energy balance is as low as 1:4. The energy balance for oil sands is roughly comparable to that for ethanol produced from sugar cane in Brazil – where one unit of energy input produces about eight units of ethanol fuel energy – and it is much better than ethanol produced from corn in North America, where one unit of energy input only produces about 1.3 units of


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ethanol fuel energy. Since the early 1990s, energy use per barrel in oil sands mining and extraction has been reduced about 45% through the use of new technologies such as hydrotransport, which is more efficient than conveyors or truck transport. New, low‐temperature extraction processes further reduce energy use. Products of the Industry Upgraded synthetic crude oil is a conventional light oil equivalent. The most common products made from upgraded synthetic crude oil are transportation fuels such as gasoline, diesel and jet fuel. Others include petrochemicals used in making synthetic rubber and polystyrene. When bitumen is processed in refineries, it also produces transportation fuels and some petrochemicals, as well as the asphalt needed for road paving and roofing. Sulphur, which comprises about five percent of oil sands bitumen, is a major by‐product of oil sands upgrading. The decision to sell or stockpile sulphur for future sale is dependent on world sulphur markets and the availability of storage space. Until recently, Syncrude stockpiled most of its sulphur at the upgrader site, but in 2005 Syncrude sold sulphur from its stockpile for the first time in 10 years, and the company is now producing fertilizer from its sulphur. Suncor and other companies have sold most of their sulphur production on international markets despite low prices and high transportation costs for the commodity. Canada is the world’s largest producer and exporter of elemental sulphur, which is also obtained from sour gas production. By 2018, however, upgraders could generate as much as 3.3 million tons of sulphur per year. To address this issue, China and India have been identified as potential markets since sulphur can be used to make fertilizer. Canadian supply to China has increased 16% in 2009 over 2008, following a 33.8% decline in 2008 over 2007. Canada’s share of exports into the China market has dropped, while competitive supplies from the Middle East have increased. Sulphur is also used in other industries such as pharmaceuticals and synthetic rubber. Some sulphur is currently used in road asphalt and potentially could be used in concrete or other construction materials.


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Sustaining the Environment The Alberta and federal governments and the petroleum industry generally subscribe to the concept of sustainable development, defined as “development that meets today’s needs without compromising the ability of future generations to meet their needs.” As the pace of oil sands development began to accelerate in 1999, the Alberta government announced the Regional Sustainable Development Strategy for the oil sands area of northeastern Alberta. The strategy defined sustainable development this way: "Under sustainable development, renewable resources are managed to ensure their longterm viability and potential future use. Nonrenewable resources are managed to maximize their benefits. Sustainable development takes into account the interdependence of trees, minerals, wildlife, water, fish, range lands, public lands, plants and other similar resources... It considers the economic effects of environmental decisions, and the environmental effects of economic decisions." To implement the strategy, multi‐stakeholder task forces brought together industry, different levels of government, non‐governmental organizations, Aboriginal communities and local businesses and other interests. They sought coordinated approaches to issues such as health care, infrastructure and air quality as well as the cumulative effects from so much development occurring so rapidly, most of it in one geographical area. In 2006, the Alberta government conducted public consultation through the oil sands Multi‐Stakeholder Committee (MSC), to consider economic, social, environmental and First Nations and Métis issues associated with oil sands development. Phase I of the process set out a vision and principles for oil sands development. Phase II sought public input on implementing the vision and principles, and included separate, parallel First Nations and Métis consultation focusing on potential adverse impacts of oil sands development on constitutionally protected rights and traditional land uses. Information gathered by the MSC supplemented previous public and interest‐group input that has been ongoing since commercial oil sands operations began.


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The MSC reached consensus on 96 of 120 recommendations regarding Aboriginal consultation, minimizing the impact of oil sands on biodiversity, improving land reclamation, the need for protected areas, planning and monitoring processes, and retention of a larger share of related, value‐added processing. It failed to reach consensus on the pace of development, water use, targets for greenhouse gas emissions, limiting the amount of land available for oil sands projects, and royalties and taxes. Aboriginal people, who have inhabited the oil sands region for thousands of years, have a special interest in how development proceeds. While they have gained many opportunities through direct employment and the creation of Aboriginal‐owned businesses, they have also expressed concern about the impacts of development on their communities, the environment and traditional land uses. In December 2008, the Alberta government released the Land‐use Framework, which sets out an approach on how to better manage public and private lands and natural resources in light of achieving Alberta’s long‐term economic, environmental and social goals. The Lower Athabasca Regional Plan will identify and set resource and environmental management outcomes for air, land, water and biodiversity, and guide future resource decisions while considering social and economic impacts. In February 2009, Alberta released Responsible Actions, a 20‐year strategic plan for Alberta’s oil sands, which addresses the economic, social, environmental, research and innovation, and governance needs of Alberta’s oil sands regions. The plan will form a new provincial and regional approach to managing the oil sands regions. Regulatory Framework The Alberta Resources Conservation Board and Alberta Environment are the principal regulators of oil sands operations in the province. Alberta Energy and Alberta Sustainable Resource Development also have direct roles in oil sands regulation. The National Energy Board regulates interprovincial and international aspects such as pipelines and exports. Large projects affecting interprovincial air and water resources, and related issues such as fisheries, are typically subject to joint federal‐provincial environmental assessment.


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Provincial and federal energy, environment, health and safety authorities are also involved in many aspects of oil sands regulation. Through the Aboriginal Policy Framework released in 2000, Alberta committed to consult with First Nations when land management and resource development decisions may infringe their existing treaty or other constitutional rights. Beginning in September 2003, Alberta engaged in dialogue with industry and First Nations about consultation and the focus of consultation policy. The province’s First Nations Consultation Policy on Land Management and Resource Development was approved on May 16, 2005. It reinforced the commitment for consultation that was identified in the Aboriginal Policy Framework. The policy outlines the province’s expectations of First Nations and resource companies in striving for increased certainty for all parties with respect to land management and resource development activities. In addition, it outlines the province’s approach to meeting its consultation responsibilities. Following the release of the policy, the province worked with First Nations and industry to develop a Framework for Consultation Guidelines and sector‐specific consultation guidelines. The framework was released on May 19, 2006 and the guidelines were implemented on September 1, 2006. In addition, the Athabasca Tribal Council began working with the government to develop specific consultation guidelines for the Athabasca oil sands area where development has been most intense. In 2000, two groups were created to address traditional environmental knowledge in the Athabasca oil sands region. The Cumulative Environmental Management Association formed a standing committee, the Traditional Environmental Knowledge Committee, to provide guidance on how to incorporate Aboriginal expertise into their knowledge base. The Reclamation Advisory Committee meanwhile created a sub‐group to address traditional knowledge. Much of the science and understanding used in reclamation and environmental activities previously were based on Western knowledge. The members of the two bodies were aware of the needs and desires of the people indigenous to the Athabasca area, and wanted to incorporate their knowledge to have a greater understanding of what environmental protection and reclamation should encompass.


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Traditional ecological knowledge includes information from people with an understanding of how past generations lived off of the land. This includes many First Nations people, Métis and historians of local culture. Ongoing R&D The National Energy Board estimates that only about 10% of Canada’s oil sands resource can be recovered economically with current technology. The future of this resource will be decided in the laboratory. Government and industry have invested heavily in oil sands and in‐situ research and development for decades, and much more will undoubtedly be spent in the future to improve the technological, environmental and economic performance of oil sands developments. To date, the Alberta government and private industry have each invested more than $1 billion in research to reduce the environmental footprint of oil sands development and increase economic recoveries. Several hundred researchers work in industry, university and government laboratories, primarily in the Calgary and Edmonton areas, to find solutions to the scientific and technological challenges facing the oil sands industry. Employees and contractors throughout the industry constantly seek more efficient, cost‐effective and environmentally sensitive ways to do things. Some of the immediate challenges facing the scientists and technologists include: reducing emissions of oxides of nitrogen and greenhouse gases; reducing water use and natural gas consumption; improving the efficiency of oil sands mining, bitumen extraction and in‐situ recovery; obtaining a higher yield of desirable products from upgrading; reducing equipment maintenance requirements; reducing the need to dilute bitumen for pipeline transportation; and improving tailings management and reclamation methods. Research partners from industry, the academic community and government co‐ordinate their efforts through associations such as the Petroleum Technology Alliance Canada (PTAC), Canadian Oil Sands Network for Research and Development (CONRAD), the Alberta Chamber of Resources’ Oil Sands Task Force, Black Oil Pipeline Network Steering Committee, the CO2 Synergies Research


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Network, and Co‐ordination of University Research for Synergy and Effectiveness (COURSE). The Alberta Energy Research Institute's research priorities with regard to oil sands include improving bitumen upgrading; demonstrating clean carbon/coal is a viable fuel for producing electricity; improving oil recovery technologies; developing technologies that reduce greenhouse gas emissions; supporting new technology to reduce fresh water use by the energy industry and advancing and adapting technology for alternative energy sources. Oil Sands Production Primer Canadian oil sands deposits are a mixture of sand (73%), clay and silt (13%), bitumen (10%), and water (4%). The ore lies above limestone and below the non‐oil bearing layer of earth called overburden, which is covered by muskeg (an acidic type of soil common in boreal forests). The deposits are found primarily in Central Alberta in three main fields: Athabasca, Peace River and Cold Lake. Bitumen is a heavy crude oil that cannot be recovered through a well in its natural state and hence needs enhanced recovery in the extraction process. The two main extraction methods are conventional surface mining and in‐situ recovery using heat (steam). Approximately 20% of Alberta’s oil sands are deposited close enough to the surface to be mined; the remaining 80% of the resource lies deeper underground and can only be recovered through in‐situ processes. The mining reserves are concentrated in only 2.5% of the oil sands land area; in‐situ reserves are spread over the remaining 97.5%. In 2008, 55% of Alberta’s total 1.3 million bbls/d oil sands production came from mining, and 45% from in‐situ projects. Open pit mining includes excavation of the ore, initial transport of the ore by diesel‐powered trucks and secondary transport, or hydrotransport (ore dissolved in water) to the primary extraction facility. There the bitumen is separated from sand and other compounds, using Dr. Clark’s hot water process, whereby the sand is essentially combined with hot water to become a slurry. As a result, the bitumen froth fl oats to the top of the separation vessel, where it is collected. The residual mixture then undergoes secondary recovery, whereby smaller quantities of bitumen are further separated from the slurry. While 50‐80% of water is recycled in this operation, the remaining mixture of sand, clay and water along with residual


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bitumen and other toxic compounds, is deposited into the waste containment areas, known as tailing ponds. In‐situ recovery can be achieved through a variety of technologies, including steam assisted gravity drainage (SAGD), cyclic steam stimulation (CSS), vapor extraction (VAPEX), and toe‐to‐heel‐air‐injection (THAI). The most commonly used technique is SAGD, whereby a series of horizontal well pairs are drilled and steam is generated by a natural gas‐fired furnace using water from nearby aquifers. The steam is then injected into the upper well, which heats up the ore and reduces the viscosity of the bitumen, enabling it to gravitate towards the lower well and flow towards the surface. A large portion of the used water (70‐90%) is recycled into the operation; however, the remaining amount remains underground, where it persists as a mixture of produced wastewater, clay and sand. Bitumen extracted through either mining or in‐situ methods is then piped to a so‐called upgrader, which is essentially an oil processing facility, where it is further processed (i.e., upgraded) into the equivalent of conventional crude oil, or synthetic crude oil (SCO). The reason for this intermediary step is to reduce the high viscosity of the recovered bitumen, which cannot be handled by a conventional oil refinery. At the upgrader stage, bitumen – a complex, heavy hydrocarbon that is rich in carbon and poor in hydrogen – is coked (stripped of a portion of carbon), distilled (processed into various grades), catalytically converted (transformed into more valuable petroleum forms), and hydrotreated (stripped of a portion of sulfur and nitrogen molecules and enhanced with hydrogen). Once the bitumen has been upgraded into synthetic crude oil, it is piped to an oil refinery, where it is processed into final petroleum products, such as gasoline, diesel, jet fuel, petrochemicals, etc. Future of the Industry The ongoing controversy and unresolved questions surrounding oil sands development in Alberta have led to calls for a moratorium on new projects. A number of Aboriginal leaders in the region want project approvals put on hold until strategic watershed and land use planning is completed, and they receive


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assurances that they will be properly consulted with their constitutional rights respected. Some Canadian investor groups, such as Northwest & Ethical Investments, based in Vancouver, British Columbia, support this call for a new‐project moratorium. Meanwhile, a group of investors, with backing from some major U.S., European and Australian institutions, has filed shareholder resolutions with four major oil sands producers in 2010 asking for better disclosure of the economic and environmental risks associated with oil sands development. A similar resolution filed with ConocoPhillips in 2009 received strong investor support—30.3% in favor, representing $12.8 billion in share value. Falling oil prices in late 2008 prompted a de facto moratorium for some oil sands producers that have canceled or indefinitely deferred many new projects. However, global oil prices have since rebounded, and prospects for new oil sands development have improved. Several prominent players, including Cenovus and Suncor (which merged with Petro‐Canada in summer 2009 to create Canada’s biggest oil company), have signaled their intent to maintain oil sands development as a core business activity. Imperial Oil has also received a corporate go‐ahead to launch a giant new mining project, and in April 2010 PetroChina International Investment launched a public offering of its 60% stake in Athabasca Oil Sands Corp.’s in‐situ projects. In effect, these companies are betting that demand for higher‐priced oil is here to stay. To justify investments in new oil sands development, oil needs to maintain a global price of at least $65/bbl and possibly as high as $95/bbl. A recent forecast from the U.S. Energy Information Administration (EIA) projects that oil prices will continue to rise and reach $130/bbl by 2030 (in constant 2009 dollars). This would raise oil sands production volume up to 4.2 mbbl/d by 2030 under a high economic growth forecast, according to EIA. This is more than double the volume of existing operating capacity and projects under construction. This EIA estimate is also 500,000 bbl/d above the Growth scenario of 3.7 mbbl/d that has been presented in this report. At $200/bbl, the EIA estimates that oil sands production could reach as high as 6.5 mbbl/d by 2030—far above any of the scenarios presented. However, we regard


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this is as a highly unrealistic and economically and environmentally unsustainable scenario, for reasons outlined earlier. Oil sands producers are operating in a narrow financial window that may be shrinking over time. They want to avoid reaching an oil price ceiling, like the one at $147/barrel in July 2008 that contributed to the oil price collapse below $40/barrel by the end of that year. But they also want to be confident of an oil price floor ‐ now estimated at $65–$95 per barrel—to justify such long‐term, capital‐intensive investments. Oil markets have rarely maintained such stability and orderly price movements; this is one of the inherent risks in investing in this volatile commodity. Beyond global market conditions, oil sands producers must also be wary of their own rising production costs. A combination of growing demand for natural gas, onset of carbon pricing and low carbon fuel standards will effectively raise the floor price for production of synthetic crude oil. Growing water requirements and land reclamation regulations will add on another layer of additional costs. The biggest wild card, however, may be relations with First Nations and other Aboriginal communities whose exercise of constitutional rights has the potential to stop some oil sands projects and pipelines dead in their tracks.


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Analysis of the Athabasca Oil Sands

Analysis of the Athabasca Oil Sands Introduction The Athabasca oil sands (also known as the Athabasca tar sands) are large deposits of bitumen, or extremely heavy crude oil, located in northeastern Alberta, Canada ‐ roughly centered around the boomtown of Fort McMurray. These oil sands, hosted in the McMurray Formation, consist of a mixture of crude bitumen (a semi‐solid form of crude oil), silica sand, clay minerals, and water. The Athabasca deposit is the largest reservoir of crude bitumen in the world and the largest of three major oil sands deposits in Alberta, along with the nearby Peace River and Cold Lake deposits. Together, these oil sand deposits lie under 141,000 square kilometers (54,000 sq mi) of sparsely populated boreal forest and muskeg (peat bogs) and contain about 1.7 trillion barrels (270×10^9 m3) of bitumen in‐place, comparable in magnitude to the world's total proven reserves of conventional petroleum. With modern unconventional oil production technology, at least 10% of these deposits, or about 170 billion barrels (27×10^9 m3) were considered to be economically recoverable at 2006 prices, making Canada's total oil reserves the second largest in the world, after Saudi Arabia's. The Athabasca deposit is the only large oil sands reservoir in the world which is suitable for large‐scale surface mining, although most of it can only be produced using more recently developed in‐situ technology. History of the Athabasca Oil Sands The Athabasca oil sands are named after the Athabasca River which cuts through the heart of the deposit, and traces of the heavy oil are readily observed on the river banks. Historically, the bitumen was used by the indigenous Cree and Dene Aboriginal peoples to waterproof their canoes. The oil deposits are located within the boundaries of Treaty 8, and several First Nations of the area are involved with the sands. The Athabasca oil sands first came to the attention of European fur traders in 1719 when Wa‐pa‐su, a Cree trader, brought a sample of bituminous sands to the Hudson's Bay Company post at York Factory on Hudson Bay where Henry Kelsey


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was the manager. In 1778, Peter Pond, another fur trader and a founder of the rival North West Company, became the first European to see the Athabasca deposits after discovering the Methye Portage which allowed access to the rich fur resources of the Athabasca River system from the Hudson Bay watershed. In 1788, fur trader Alexander MacKenzie (who later discovered routes to both the Arctic and Pacific Oceans from this area) wrote: "At about 24 miles (39 km) from the fork (of the Athabasca and Clearwater Rivers) are some bituminous fountains into which a pole of 20 feet (6.1 m) long may be inserted without the least resistance. The bitumen is in a fluid state and when mixed with gum, the resinous substance collected from the spruce fir, it serves to gum the Indians' canoes." He was followed in 1799 by map maker David Thompson and in 1819 by British Naval officer Sir John Franklin. Sir John Richardson did the first geological assessment of the oil sands in 1848 on his way north to search for Franklin's lost expedition. The first government‐sponsored survey of the oil sands was initiated in 1875 by John Macoun, and in 1883, G.C. Hoffman of the Geological Survey of Canada tried separating the bitumen from oil sand with the use of water and reported that it separated readily. In 1888, Dr. Robert Bell, the director of the Geological Survey of Canada, reported to a Senate Committee that "The evidence ... points to the existence in the Athabasca and Mackenzie valleys of the most extensive petroleum field in America, if not the world." In 1926, Dr. Karl Clark of the University of Alberta perfected a hot water separation process which became the basis of today's thermal extraction process. Several attempts to implement it had varying degrees of success, but it was 1967 before the first commercially viable operation began with the opening of the Great Canadian Oil Sands (now Suncor) plant using surfactants in the separation process developed by Dr. Earl W. Malmberg of Sun Oil Company. Development of the Athabasca Deposits The key characteristic of the Athabasca deposit is that it is the only one shallow enough to be suitable for surface mining. About 10% of the Athabasca oil sands are covered by less than 75 meters (246 ft) of overburden. Until 2009, the surface mineable area (SMA) was defined by the ERCB, an agency of the Alberta


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government, to cover 37 contiguous townships (about 3,400 km2/1,300 sq mi) north of the city of Fort McMurray. In June 2009, the SMA was expanded to 51.5 townships, or about 4,700 km2/1,800 sq mi. This expansion pushes the northern limit of the SMA to within 12 miles (19 km) of Wood Buffalo National Park, a UNESCO World Heritage Site. The overburden consists of 1 to 3 meters of water‐logged muskeg on top of 0 to 75 meters of clay and barren sand, while the underlying oil sands are typically 40 to 60 meters thick and sit on top of relatively flat limestone rock. As a result of the easy accessibility, the world's first oil sands mine was started by Great Canadian Oil Sands Limited (a predecessor company of Suncor Energy) in 1967. The Syncrude mine followed in 1978 and is now the largest mine (by area) in the world at 191 km2. The Albian Sands mine (operated by Shell Canada) opened in 2003. All three of these mines are associated with bitumen upgraders that convert the unusable bitumen into synthetic crude oil for shipment to refineries in Canada and the United States. For Albian, the upgrader is located at Scotford, 439 km south. The bitumen, diluted with a solvent is transferred there in a 610 millimeters (24 in) corridor pipeline. Extracting Bitumen from the Deposits The original process for extraction of bitumen from the sands was developed by Dr. Karl Clark, working with Alberta Research Council in the 1920s. Today, all of the producers doing surface mining, such as Syncrude Canada, Suncor Energy and Albian Sands Energy etc., use a variation of the Clark Hot Water Extraction (CHWE) process. In this process, the ores are mined using open‐pit mining technology. The mined ore is then crushed for size reduction. Hot water at 50 — 80 °C is added to the ore and the formed slurry is transported using hydrotransport line to a primary separation vessel (PSV) where bitumen is recovered by flotation as bitumen froth. The recovered bitumen froth consists of 60% bitumen, 30% water and 10% solids by weight. The recovered bitumen froth needs to be cleaned to reject the contained solids and water to meet the requirement of downstream upgrading processes. Depending on the bitumen content in the ore, between 90 and 100% of the bitumen can be recovered using modern hot water extraction techniques. After oil extraction, the spent sand and other materials are then returned to the mine, which is eventually reclaimed.


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More recently, in situ methods like steam‐assisted gravity‐drainage (SAGD) and cyclic steam stimulation (CSS) have been developed to extract bitumen from deep deposits by injecting steam to heat the sands and reduce the bitumen viscosity so that it can be pumped out like conventional crude oil. The standard extraction process requires huge amounts of natural gas. Currently, the oil sands industry uses about 4% of the Western Canada Sedimentary Basin natural gas production. By 2015, this may increase 2.5 fold. According to the National Energy Board, it requires about 1,200 cubic feet (34 m3) of natural gas to produce one barrel of bitumen from in situ projects and about 700 cubic feet (20 m3) for integrated projects. Since a barrel of oil equivalent is about 6,000 cubic feet (170 m3) of gas, this represents a large gain in energy. That being the case, it is likely that Alberta regulators will reduce exports of natural gas to the United States in order to provide fuel to the oil sands plants. As gas reserves are exhausted, however, oil upgraders will probably turn to bitumen gasification to generate their own fuel. In much the same way the bitumen can be converted into synthetic crude oil, it can also be converted into synthetic natural gas. In‐situ extraction on a commercial scale is just beginning. A project nearing completion, the Long Lake Project, is designed to provide its own fuel, by on‐site hydrocracking of the bitumen extracted. Long Lake Phase 1 is extracting 13,000 barrels/day of bitumen as of July 2008, ramping towards a target of 72,000 in late 2009, and "upgrading" of bitumen to liquid oil in 2007, producing 60,000 bbl/day of usable oil. The hydrocracker is scheduled to complete commissioning by September 2008.


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Commercial Production from Athabasca Oil Sands Commercial production of oil from the Athabasca oil sands began in 1967, when Great Canadian Oil Sands Limited (then a subsidiary of Sun Oil Company but now an independent company known as Suncor Energy) opened its first mine, producing 30,000 barrels per day (4,800 m3/d) of synthetic crude oil. Development was inhibited by declining world oil prices, and the second mine, operated by the Syncrude consortium, did not begin operating until 1978, after the 1973 oil crisis sparked investor interest. However, the price of oil subsided afterwards, and although the 1979 energy crisis caused oil prices to peak again, introduction of the National Energy Program by Pierre Trudeau discouraged foreign investment in the Canadian oil industry. During the 1980s, oil prices declined to very low levels, causing considerable retrenchment in the oil industry, and the third mine, operated by Shell Canada, did not begin operating until 2003. However, as a result of oil price increases since 2003, the existing mines have been greatly expanded and new ones are being planned. Oil sands were the source of 62% of Alberta's total oil production and 47% of all oil produced in Canada. The Alberta government believes this level of production could reach 3 Mbbl/d (480,000 m3/d) by 2020 and possibly 5 Mbbl/d (790,000 m3/d) by 2030. Production Forecast from Athabasca Oil Sands As of December 2008, the Canadian Association of Petroleum Producers revised its 2008‐2020 crude oil forecasts to account for project cancellations and cutbacks as a result of the price declines in the second half of 2008. The revised forecast predicted that Canadian oil sands production would continue to grow, but at a slower rate than previously predicted. There would be minimal changes to 2008‐2012 production, but by 2020 production could be 300,000 barrels per day (48,000 m3/d) less than its prior predictions. This would mean that Canadian oil sands production would grow from 1.2 million barrels per day (190,000 m3/d) in 2008 to 3.3 million barrels per day (520,000 m3/d) in 2020, and that total Canadian oil production would grow from 2.7 to 4.1 million barrels per day (430,000 to 650,000 m3/d) in 2020. Even accounting for project cancellations, this would place Canada among the four or five largest oil‐producing countries in the world by 2020.


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In early December 2007, London based BP and Calgary based Husky Energy announced a 50/50 joint venture to produce and refine bitumen from the Athabasca oil sands. BP would contribute its Toledo, Ohio refinery to the joint venture, while Husky would contribute its Sunrise oil sands project. Sunrise was planned to start producing 60,000 barrels per day (9,500 m3/d) of bitumen in 2012 and may reach 200,000 bbl/d (30,000 m3/d) by 2015‐2020. BP would modify its Toledo refinery to process 170,000 bbl/d (27,000 m3/d) of bitumen directly to refined products. The joint venture would solve problems for both companies, since Husky was short of refining capacity, and BP had no presence in the oil sands. It was a change of strategy for BP, since the company historically has downplayed the importance of oil sands. In mid December 2007, ConocoPhillips announced its intention to increase its oil sands production from 60,000 barrels per day (9,500 m3/d) to 1 million barrels per day (160,000 m3/d) over the next 20 years, which would make it the largest private sector oil sands producer in the world. ConocoPhillips currently holds the largest position in the Canadian oil sands with over 1 million acres (4000 km2) under lease. Other major oil sands producers planning to increase their production include Royal Dutch Shell (to 770,000 bbl/d (122,000 m3/d); Syncrude Canada (to 550,000 bbl/d (87,000 m3/d); Suncor Energy (to 500,000 bbl/d (79,000 m3/d) and Canadian Natural Resources (to 500,000 bbl/d (79,000 m3/d). If all these plans come to fruition, these five companies will be producing over 3.3 million bbl/d (500,000 m3/d) of oil from oil sands by 2028. Overall Estimation of Oil Reserves in the Athabasca Deposits The Alberta government's Energy and Utilities Board (EUB) estimated in 2007 that about 173 billion barrels (27.5×10^9 m3) of crude bitumen are economically recoverable from the three Alberta oil sands areas based on benchmark WTI market prices of $62 per barrel in 2006, rising to a projected $69 per barrel in 2016 using current technology. This was equivalent to about 10% of the estimated 1,700 billion barrels (270×10^9 m3) of bitumen‐in‐place. In fact WTI prices topped $133 in May 2008. Alberta estimated that the Athabasca deposits alone contain 35 billion barrels (5.6×10^9 m3) of surface mineable bitumen and 98 billion barrels (15.6×10^9 m3) of bitumen recoverable by in‐situ methods. These estimates of Canada's reserves were doubted when they were first published but are now largely accepted by the


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international oil industry. This volume placed Canadian proven reserves second in the world behind those of Saudi Arabia. The method of calculating economically recoverable reserves that produced these estimates was adopted because conventional methods of accounting for reserves gave increasingly meaningless numbers. They made it appear that Alberta was running out of oil at a time when rapid increases in oil sands production were more than offsetting declines in conventional oil, and in fact most of Alberta's oil production is now unconventional oil. Conventional estimates of oil reserves are really calculations of the geological risk of drilling for oil, but in the oil sands there is very little geological risk because they outcrop on the surface and are easy to locate. With the oil price increases since 2003, the economic risk of low oil prices was reduced. The Alberta estimates only assume a recovery rate of around 20% of bitumen‐in‐place, whereas oil companies using the steam assisted gravity drainage (SAGD) method of extracting bitumen report that they can recover over 60% with little effort. Only 3% of the initial established crude bitumen reserves have been produced since commercial production started in 1967. At rate of production projected for 2015, about 3 million barrels per day (480×10^3 m3/d), the Athabasca oil sands reserves would last over 170 years. However those production levels require an influx of workers into an area that until recently was largely uninhabited. By 2007 this need in northern Alberta drove unemployment rates in Alberta and adjacent British Columbia to the lowest levels in history. As far away as the Atlantic Provinces, where workers were leaving to work in Alberta, unemployment rates fell to levels not seen for over one hundred years. The Venezuelan Orinoco Oil Sands site may contain more oil sands than Athabasca. However, while the Orinoco deposits are less viscous and more easily produced using conventional techniques (the Venezuelan government prefers to call them "extra‐heavy oil"), they are too deep to access by surface mining. Economics of Oil Extraction from the Athabasca Deposits


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Despite the large reserves, the cost of extracting the oil from bituminous sands has historically made production of the oil sands unprofitable—the cost of selling the extracted crude would not cover the direct costs of recovery; labor to mine the sands and fuel to extract the crude. In mid‐2006, the National Energy Board of Canada estimated the operating cost of a new mining operation in the Athabasca oil sands to be C$9 to C$12 per barrel, while the cost of an in‐situ SAGD operation (using dual horizontal wells) would be C$10 to C$14 per barrel. This compares to operating costs for conventional oil wells which can range from less than one dollar per barrel in Iraq and Saudi Arabia to over six in the United States and Canada's conventional oil reserves. The capital cost of the equipment required to mine the sands and haul it to processing is a major consideration in starting production. The NEB estimates that capital costs raise the total cost of production to C$18 to C$20 per barrel for a new mining operation and C$18 to C$22 per barrel for a SAGD operation. This does not include the cost of upgrading the crude bitumen to synthetic crude oil, which makes the final costs C$36 to C$40 per barrel for a new mining operation. Therefore, although high crude prices make the cost of production very attractive, sudden drops in price leaves producers unable to recover their capital costs—although the companies are well financed and can tolerate long periods of low prices since the capital has already been spent and they can typically cover incremental operating costs. However, the development of commercial production is made easier by the fact that exploration costs are very low. Such costs are a major factor when assessing the economics of drilling in a traditional oil field. The location of the oil deposits in the oil sands are well known, and an estimate of recovery costs can usually be made easily. There is not another region in the world with energy deposits of comparable magnitude where it would be less likely that the installations would be confiscated by a hostile national government, or be endangered by a war or revolution. As a result of the oil price increases since 2003, the economics of oil sands have improved dramatically. At a world price of US$50 per barrel, the NEB estimated an integrated mining operation would make a rate return of 16 to 23%, while a SAGD operation would return 16 to 27%. Prices since 2006 have risen, exceeding US$145


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in mid 2008. As a result, capital expenditures in the oil sands announced for the period 2006 to 2015 are expected to exceed C$100 billion, which is twice the amount projected as recently as 2004. However, because of an acute labor shortage which has developed in Alberta, it is not likely that all these projects can be completed. At present the area around Fort McMurray has seen the most effect from the increased activity in the oil sands. Although jobs are plentiful, housing is in short supply and expensive. People seeking work often arrive in the area without arranging accommodation, driving up the price of temporary accommodation. The area is isolated, with only a two‐lane road connecting it to the rest of the province, and there is pressure on the government of Alberta to improve road links as well as hospitals and other infrastructure. Despite the best efforts of companies to move as much of the construction work as possible out of the Fort McMurray area, and even out of Alberta, the shortage of skilled workers is spreading to the rest of the province. Even without the oil sands, the Alberta economy would be very strong, but development of the oil sands has resulted in the strongest period of economic growth ever recorded by a Canadian province. Political Significance of the Deposit The Athabasca oil sands are often a topic in international trade talks, with energy rivals China and the United States negotiating with Canada for a bigger share of the rapidly increasing output. Production is expected to quadruple between 2005 and 2015, reaching 4 million barrels a day, with increasing political and economic importance. Currently, most of the oil sands production is exported to the United States. An agreement has been signed between PetroChina and Enbridge to build a 400,000 barrels per day (64,000 m3/d) pipeline from Edmonton, Alberta, to the west coast port of Kitimat, British Columbia. The pipeline will help export synthetic crude oil from the oil sands to China and elsewhere in the Pacific. A smaller pipeline will also be built alongside to import condensate to dilute the bitumen. Sinopec, the largest refining and chemical company in China, and China National Petroleum Corporation have bought or are planning to buy shares in major oil sands development.


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On August 20, 2009, the U.S. State Department issued a presidential permit for an Alberta Clipper Pipeline that will run from Hardisty, Alberta to Superior, Wisconsin. The pipeline will be capable of carrying up to 450,000 barrels of crude oil a day to refineries in the U.S. Environmental Issues with the Athabasca Oil Sands Critics contend that government and industry measures taken to minimize environmental and health risks posed by large‐scale mining operations are inadequate, causing damage to the natural environment. Objective discussion of the environmental impacts has often been clouded by polarized arguments from industry and from advocacy groups. Impact on Land Approximately 20% of Alberta's oil sands are recoverable through open‐pit mining, while 80% require in situ extraction technologies (largely because of their depth). Open pit mining destroys the boreal forest and muskeg. The Alberta government requires companies to restore the land to "equivalent land capability". This means that the ability of the land to support various land uses after reclamation is similar to what existed, but that the individual land uses may not necessarily be identical. In some particular circumstances the government considers agricultural land to be equivalent to forest land. Oil sands companies have reclaimed mined land to use as pasture for wood bison instead of restoring it to the original boreal forest and muskeg. Syncrude asserts they have reclaimed 22% of their disturbed land.


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Impact on Water Resources A Pembina Institute report stated "To produce one cubic meter (m3) of synthetic crude oil (SCO) (upgraded bitumen) in a mining operation requires about 2–4.5 m3 of water (net figures). Approved oil sands mining operations are currently licensed to divert 359 million m3 from the Athabasca River, or more than twice the volume of water required to meet the annual municipal needs of the City of Calgary," and went on to say "...the net water requirement to produce a cubic meter of oil with in situ production may be as little as 0.2 m3, depending on how much is recycled". Jeffrey Simpson of the Globe and Mail paraphrased this report, saying: "A cubic meter of oil, mined from the tar sands, needs two to 4.5 cubic meters of water." Though actual water withdrawals for conventional production run at even less than the 0.2 m3 needed for in situ production. The Athabasca River runs 1,231 kilometers from the Athabasca Glacier in west‐central Alberta to Lake Athabasca in northeastern Alberta. The average annual flow just downstream of Fort McMurray is 633 cubic meters per second with its highest daily average measuring 1,200 cubic meters per second. Water license allocations total about 1% of the Athabasca River average annual flow, though actual withdrawals for all uses, in 2008, amount to about 0.4%. In addition, the Alberta government sets strict limits on how much water oil sands companies can remove from the Athabasca River. According to the Water Management Framework for the Lower Athabasca River, during periods of low river flow water consumption from the Athabasca River is limited to 1.3% of annual average flow. The province of Alberta is also looking into cooperative withdrawal agreements between oil sands operators. Use of Natural Gas and Greenhouse Gases Emissions The processing of bitumen into synthetic crude requires energy, and currently this energy is generated by burning natural gas, which releases carbon dioxide. In 2008, the oil sands used around 1 billion cubic feet of natural gas per day, around 40% of Alberta's total usage. Based on gas purchases, natural gas requirements are given by the Canadian Energy Resource Institute as 2.14 GJ (2.04 mcf) per barrel for cyclic steam stimulation projects, 1.08 GJ (1.03 mcf) per barrel for SAGD projects, 0.55 GJ (0.52 mcf) per barrel for bitumen extraction in mining operations not including


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upgrading or 1.54 GJ (1.47 mcf) per barrel for extraction and upgrading in mining operations. A 2009 study by CERA estimated that production from Canada's oil sands emits "about 5% to 15% more carbon dioxide, over the "well‐to‐wheels" lifetime analysis of the fuel, than average crude oil." Author and investigative journalist David Strahan that same year stated that IEA figures show that carbon dioxide emissions from the tar sands are 20% higher than average emissions from oil. With coal's CO2 emissions about one‐third higher than convention oil's , this would make the tar sands' emissions equal to about 90% of the CO2 released from coal. The forecast growth in synthetic oil production in Alberta also threatens Canada's international commitments. In ratifying the Kyoto Protocol, Canada agreed to reduce, by 2012, its greenhouse gas emissions by 6% with respect to 1990. In 2002, Canada's total greenhouse gas emissions had increased by 24% since 1990. Oil Sands production contributed 3.4% of Canada's greenhouse gas emissions in 2003. Ranked as the world's eighth largest emitter of greenhouse gases, Canada is a relatively large emitter given its population and is missing its Kyoto targets. A major Canadian initiative called the Integrated CO2 Network (ICO2N) has proposed a system for the large scale capture, transport and storage of carbon dioxide (CO2). ICO2N members represent a group of industry participants providing a framework for carbon capture and storage development in Canada, initially using it to enhance oil recovery. Nuclear power has also been proposed as a means of generating the required energy without releasing green house gases.


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Company Profiles-Athabasca Oil Sands

Company ProfilesAthabasca Oil Sands Overview There are currently three large oil sands mining operations in the area run by Syncrude Canada Limited, Suncor Energy and Albian Sands owned by Shell Canada, Chevron, and Marathon Oil Corp. Canadian Natural Resources Limited (CNRL) Canadian Natural Resources Limited is an oil and natural gas exploration, development and production company centered in Calgary, Alberta. Operations are focused in western Canada, the North Sea and offshore West Africa. It ranks number 251 on the Forbes Global 2000 list for 2009. Corporate Headquarters resides in Calgary, Alberta. It operates field offices in Alberta, British Columbia, Saskatchewan as well as international offices in Gabon, Côte d'Ivoire and Aberdeen, Scotland. CNR is currently completing an Oilsands upgrading plant north of Fort McMurray, Alberta, named the Horizon project. Contact Details: Canadian Natural Resources Limited 2500, 855 ‐ 2 Street S.W. Calgary, AB T2P 4J8 Canada Tel: (403) 517‐6700 Fax: (403) 517‐7350 Website: www.cnrl.com


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Imperial Oil Imperial Oil is a producer of crude oil, natural gas liquids, and natural gas, and a refiner and marketer of petroleum products. It is also a supplier of petrochemicals. Exxon Mobil Corporation owns approximately 69.6% of the outstanding shares of Imperial Oil. The company operates in Canada. Imperial Oil's operations are conducted through three main segments: upstream; downstream; and chemicals. The upstream operations include the exploration and production of conventional crude oil, natural gas, upgraded crude oil, and heavy oil. It is a major developer of Canada's vast reserves of oil sands through its operation at Cold Lake, Alberta, and its participation in Syncrude Canada. The company produces natural gas from a large number of gas fields located in the Western Provinces, primarily in Alberta. The company holds about 194,000 net acres of heavy oil leases near Cold Lake, Alberta. The company has interests in other heavy oil leases in the Athabasca and Peace River areas of northern Alberta, totaling about 170,000 net acres. Imperial Oil holds a 25% participating interest in Syncrude, a joint venture established to recover shallow deposits of oil sands using open‐pit mining methods to extract the crude bitumen, and to produce a high‐quality, light (32 degree API), sweet, synthetic crude oil. In FY2009, average net production at Cold Lake was about 120,000 barrels per day and gross production was about 141,000 barrels per day. Most of the production from Cold Lake is sold to refineries in the northern U.S. The majority of the remainder of Cold Lake production is shipped to certain of the company's refineries and to a third‐party crude bitumen upgrader in Lloydminster, Saskatchewan. The company has been involved in the exploration and development of petroleum and natural gas in the Western Provinces, in the Canada Lands, and in the Atlantic Offshore. It has interest in 16 significant discovery licenses and one production license granted by the Government of Canada in the Arctic Islands. The company manages five discovery licenses granted by the Government of Canada in the Atlantic offshore. The company also has minority interests in 27 significant discovery licenses, and six production licenses, managed by others.


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The company's largest conventional oil producing asset is the Norman Wells oil field in the Northwest Territories, which currently accounts for approximately 56% of the company's net production of conventional crude oil (approximately 60% of gross production). In FY2009, net production of crude oil was about 11,000 barrels per day and gross production was about 15,000 barrels per day. The downstream segment handles the transportation, refinement, and blending of crude oil into petroleum products, and the marketing of these products. The company carries out its petroleum research and technical support through its center in Sarnia, Ontario. Imperial Oil owns and operates four refineries. Two of these, the Sarnia refinery and the Strathcona refinery, have lubricating oil production facilities. The Strathcona refinery processes Canadian crude oil, and the Dartmouth, Sarnia, and Nanticoke refineries process a combination of Canadian and foreign crude oil. In addition to crude oil, the company purchases finished products to supplement its refinery production. The company maintains a nation‐wide distribution system, including 24 primary terminals, to handle bulk and packaged petroleum products moving from refineries to market by pipeline, tanker, rail, and road transport. The company owns and operates crude oil, natural gas liquids, and products pipelines in Alberta, Manitoba, and Ontario and has interests in the capital stock of two products and one crude oil pipeline companies. Imperial Oil markets more than 650 petroleum products throughout Canada under various brand names, most notably Esso and Mobil, to all types of customers. At the end of FY2009, the company operated about 1,850 retail stores, of which about 540 were company owned or leased. Imperial Oil's chemical segment manufactures and markets various petrochemicals including: ethylene, benzene, aromatic and aliphatic solvents, plasticizer intermediates, and polyethylene resin. Its major petrochemical and polyethylene manufacturing operations are located in Sarnia, Ontario. There is also a heptene and octene plant located in Dartmouth, Nova Scotia. The company offers the following products:


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Petroleum Products:

• Gasoline • Diesel fuel • Heating oil • Jet fuel • Heavy fuel oil • Lubricants • Bitumen

Chemical Products:

• Hydrocarbon solvents • Plasticizers • Olefins and alcohols • Ethylene • Benzene • Aromatic and aliphatic solvents • Plasticizer intermediates • Polyethylene resin

Brands:

• Esso • Mobil

Contact Details: Imperial Oil Limited 237 Fourth Avenue South West Station M Calgary Alberta T2P 3M9 Canada Tel: +1‐800‐567‐3776 Fax: +1‐800‐367‐0585 Website: http://www.imperialoil.ca


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Nexen Inc Nexen is an independent energy company. It focuses on three strategies which include: oil sands; conventional exploration and development of properties; and unconventional gas which is focused on the company's shale gas play. The company operates in the U.S., the UK, Middle East, Africa and Asia Pacific. Nexen operates through three segments which include: oil and gas, energy marketing and chemicals. The company has its oil and gas in operations in the UK North Sea, U.S. Gulf of Mexico, western Canada, Yemen, offshore West Africa, Colombia and Norway. It also operates in Canada's Athabasca oil sands which produce synthetic crude oil. The Syncrude includes a 7.23% joint venture interest in the Syncrude Joint Venture and it was established to mine shallow oil sands deposits using open‐pit mining methods, extract the bitumen from the oil sands, and upgrade the bitumen to produce a good quality, light, sweet, synthetic crude oil. Nexen also has interests in numerous oil sands leases in the Athabasca region of northern Alberta. The company's energy marketing group currently sells proprietary and third‐party natural gas, crude oil, natural gas liquids, and power in certain regional global markets. It focuses on crude oil marketing, gas marketing and power marketing in North America. The chemicals segment manufactures sodium chlorate and chlor‐alkali products which include: chlorine, caustic soda and muriatic acid in Canada and Brazil. Its operates in North and South America and some sodium chlorate is distributed in Asia. The company's key products and services include the following: Products:

• Crude oil • Natural gas • Natural gas liquids


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• Electricity • Sodium chlorate • Chlor‐alkali

Services:

• Gas marketing services • Oil marketing services • Power marketing services

Contact Details: Nexen Inc. 801 7th Avenue South West Calgary Alberta T2P 3P7 Canada Tel: +1‐403‐699‐4000 Fax: +1‐403‐699‐5800 Website: http://www.nexeninc.com etro Canada Petro‐Canada was a crown corporation of Canada in the field of oil and natural gas. It was headquartered in the Petro‐Canada Centre in Calgary, Alberta. In August, 2009, Petro‐Canada was merged with Suncor Energy, which took approximately 60% ownership of Petro‐Canada. However, the Petro‐Canada brand for fuels, petrochemical products and service stations, and the loyalty program are retained by Suncor Energy along with Suncor's Sunoco brand. As of 2008, Petro‐Canada was Canada's 11th largest company and second‐largest downstream company with important interests in such projects as Hibernia, Terra Nova, and White Rose; its gas stations remained a presence in most Canadian cities. It owned refineries in Edmonton, Alberta (135,000 bpd) and Montreal, Quebec (160,000 bpd), accounting for 16% of the Canadian industry's total refining capacity. Its lubricants plant in Mississauga, Ontario (15,600 bpd) refined crude oil


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feedstock to produce lubricating oil‐based stocks (13,600 bpd of API Group II capacity and 2,000 bpd of API Group III capacity) and other specialized products. All these facilities are currently run by Suncor. The company had operations in Algeria, the Netherlands, Tunisia, the United Kingdom, Syria, Italy, Libya, Trinidad and Tobago, Venezuela, Morocco and Norway. The main assets United Kingdom (North Sea), Netherlands (North Sea), Libya, Syria and Trinidad and Tobago. These and all the other sites outside of North America were run by the International and Offshore Business Unit of Petro‐Canada with its headquarters in London. This was the largest business unit, and much of its assets were part of the former Veba Oel company based in Essen, Germany. In 2006, the company entered the mobile phone market with a prepaid service called Petro‐Canada Mobility. In recent years, Petro‐Canada has been opening a new fast‐food oriented branded convenience store called Neighbors. Some of these locations include drive‐thrus and a new “Touchless” Glide car wash. Many of these new stores are in the GTA with a new store slated for Stittsville in Ottawa. Contact Details: Website: www.petro‐canada.ca


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Shell Canada Shell Canada is engaged in the production of natural gas, natural gas liquids, and bitumen. It also manufactures, distributes, and markets refined petroleum products and is the largest producer of sulfur in Canada. The company primarily operates in Canada. Shell produces natural gas, natural gas liquids (NGL), bitumen, synthetic crude oil, and sulfur mainly in Alberta and British Columbia where the main leases/assets are held. Shell Canada operates through five business segments: exploration and production (E&P); gas and power; oil sands; chemicals; and oil products. The E&P segment is engaged in exploration and production of natural gas and natural gas liquids. It also produces sulfur. E&P operations of the company also include shell's unconventional oil business, in situ oil sands operations, that use wells to extract bitumen too deep to be surface mined. Shell holds over 2,100 leases in Canada. The majority of Shell's gas production in Canada comes from the Foothills region of Alberta. Shell also owns and operates four natural gas processing and sulfur extraction plants in southern and south‐central Alberta. In addition, it holds a 31.3% interest in the Sable Offshore Energy Project, a natural gas complex offshore eastern Canada, and has a non‐operating 20% interest in an early stage deepwater exploration asset off the east coast of Newfoundland. It is a joint venture participant in the Mackenzie Gas Pipeline proposal in northern Canada. In FY2009, Shell Canada continued unconventional gas development in west central Alberta and east‐central British Columbia through drilling programs and investment in infrastructure facilitating new production. Shell holds approximately 600,000 tight gas acres (2,400 square kilometers) in these areas. The gas and power segment of the company explores for and produces natural gas, processes it, and transports it to markets. It is also involved in wind energy and solar power technology. Shell Canada's oil sands business extracts bitumen at its Athabasca Oil Sands Project in Alberta, Western Canada (Shell Canada's share 60%), and converts it to synthetic crude oil. The company's oil sands segment has operations in each of Alberta's three main oil sands deposits. The Athabasca Oil Sands Project (AOSP) in northeast


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Alberta mines bitumen‐saturated sand from which synthetic crude oil is produced. Shell's AOSP includes the Muskeg River Mine, Scotford Upgrader, and supporting facilities. The Muskeg River Mine is a joint venture between Shell Canada (60%), Chevron Canada (20%), and Marathon Oil Sands (20%). It extracts heavy oil (bitumen) from the oil sands of northern Alberta. The Muskeg River Mine has a design capacity of 155,000 barrels per day (bpd) of bitumen. The Scotford Upgrader is a part of the joint venture project between Shell Canada, Chevron Canada, and Marathon Oil Sands. It is operated by Shell Canada. The Scotford Upgrader is located next to Shell Canada's Scotford Refinery, north of Fort Saskatchewan, Alberta. The Scotford Upgrader upgrades the high viscosity crude oil (bitumen) from the Muskeg River Mine into a range of synthetic crude oils. Shell Canada also holds a number of other minable oil sands leases in the Athabasca region with expiry dates ranging from 2010 to 2020. The chemicals segment produces petrochemicals for industrial customers. These products include the raw materials for plastics, coatings, and detergents. Petrochemicals are used to manufacture many products such as paints, detergents, computers, mobile phones, medicines, waterproof clothing, adhesive tape, and refrigerators. The oil products segment manufactures, distributes, and markets refined petroleum products. This segment also procures crude oil and feedstocks for Shell Canada's refineries in Montreal (Quebec), Sarnia (Ontario), and Fort Saskatchewan (Alberta). These refineries convert crude oil into gasoline, diesel fuel, aviation fuels, solvents, lubricants, asphalt, and heavy fuel oils. Shell Canada operates Montreal East Refinery, the company's largest, with a refining capacity of approximately 130,000 barrels per day of crude oil. It produces liquefied petroleum gasoline, distillates, heavy oils, lubricating oils, waxes, and bitumen. The company's Scotford refinery operates with a capacity of 100,000 barrels of synthetic crude oil daily. It produces gasoline, jet fuel, diesel, propane, butane, and extracted sulfur.


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The Brockville Lubricants Plant is Shell's only lubricant oil blending and packaging facility in Canada. It blends and packages retail passenger‐car motor oils in Canada, manufactures multiple lubricant products resulting in the production of over 2,500 finished goods. Shell's Sarnia Manufacturing Centre, with a capacity of 75,000 barrels of crude oil daily, produces gasoline, distillates, liquid petroleum gas, heavy oils, pure chemicals, and solvents. Shell operates the only grease manufacturing facility in Canada, Calgary Lube & Grease Plant. It consists of a grease manufacturing plant, a packaging department and a distribution warehouse. The plant produces grease in about 30 different formulations and 14 different colors. The company's key products include the following:

• Natural gas • Natural gas liquids • Bitumen • Sulfur • Petrochemicals • Synthetic crude oil • Gasoline • Diesel • Aviation fuel • Solvents • Lubricants • Asphalt • Heavy fuel oils • Propane • Butane • Liquid petroleum gas


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Contact Details: Shell Canada Limited 400 ‐ 4th Avenue South West Calgary Alberta T2P 0J4 Canada Tel: +1‐403‐691‐3111 Fax: +1‐403‐269‐7462 Website: http://www.shell.ca/ Sinopec (China Petroleum & Chemical Corporation) China Petroleum & Chemical Corporation (Sinopec) is a producer and marketer of oil products and petrochemical products. It is a vertically integrated energy and chemical company. The principal operations of Sinopec and its subsidiaries include exploration, development, production, and marketing of crude oil and natural gas, oil refining and marketing, and production and sales of petrochemicals, chemical fibers, chemical fertilizers, and other chemicals. The company's business activities also include storage and pipeline transportation of crude oil and natural gas, and import and export of petroleum products. Sinopec operates through five principal business segments: exploration and production; refining; marketing and distribution; chemicals; and others. The exploration and production segment of Sinopec explores and develops oil fields, produces crude oil and natural gas, and sells products to the refining segment of the company and external customers. As of December 31, 2009, the company held 193 production licenses with an aggregate acreage of 19,136 square kilometers and 318 exploration licenses for various blocks in which the company is engaged in exploration activities. At the end of 2009, Sinopec had proved oil and gas reserves of 3,943 million barrels of oil equivalent (mmboe), including 2,820 million barrels (mmbbls) of proved reserve of crude oil, and 6,739 billion cubic feet (bcf) of proved reserve of natural gas. In FY2009, the company produced an average of 962 thousand barrels of oil equivalent (boe) per day, of which approximately 85.8% was crude oil and 14.2% was natural gas.


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Sinopec's refining business segment processes and purifies crude oil, which is sourced from the exploration and production segment of the company and external suppliers. It also manufactures and sells petroleum products to the chemicals and marketing and distribution segments of the company and external customers. Sinopec is the largest refiner of petroleum and oil producer in China, with its refining capacity ranking third in the world. The company's major oil products include gasoline, kerosene, diesel, lube oil, chemical light feedstock, fuel oil, solvent oil, petroleum wax, asphalt, petroleum coke, liquefied petroleum gas (LPG), propylene, and benzene products. The company's refineries are mainly located in China's southeast coastal area, middle, and lower reaches of Yangtze River and North China. At the end of FY2009, the company's total processing capacity was 210 million tons per annum. In FY2009, the output of gasoline, kerosene, and diesel reached 113.69 million tons. The company also produced 26.87 million tons of chemical light feedstock in FY2009. The marketing and distribution segment of Sinopec owns and operates oil depots and service stations in China, and distributes and sells refined petroleum products (mainly gasoline and diesel) in China through wholesale and retail sales networks. The company operates the largest sales and distribution network for refined petroleum products in China. In FY2009, in China, it distributed and sold approximately 124.02 million tons of gasoline, diesel, and kerosene including jet fuel, representing a market share of approximately 60% in China. All of Sinopec's retail sales are made through a network of service stations and petroleum shops operated under the Sinopec brand. At the end of FY2009, the company owned 29,698 retail stations, among which 643 sites were under franchise agreement. In FY2009, Sinopec sold approximately 78.9 million tons of refined petroleum products through its retail network, representing approximately 63.6% of its total refined petroleum products sales volume. Sinopec's retail market share in FY2009 was approximately 76.7% in its principal market. Moreover, in FY2009, the company sold approximately 25.61 million tons of refined petroleum products, including 2.42 million tons of gasoline, 23.06 million tons of diesel, and 0.13 million tons of kerosene, through direct sales to commercial customers such as industrial enterprises, hotels, restaurants, and agricultural producers.


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In FY2009, Sinopec sold approximately 19.52 million tons of refined petroleum products through wholesale channels, representing approximately 15.7% of its total sales volume of refined petroleum products. Its wholesale sales include sales to large commercial or industrial customers and independent distributors as well as sales to certain long‐term customers such as railway, airlines, shipping, and public utilities. Through its wholesale centers, Sinopec operates 410 storage facilities with a total capacity of approximately 14.0 million cubic meters, substantially all of which are wholly‐owned by Sinopec. The company's wholesale centers are connected to its refineries by railway, waterway and, in some cases, by pipelines. The company also owns some dedicated railways, oil wharfs, and oil barges, as well as a number of rail tankers and oil trucks. The chemicals segment of Sinopec manufactures and markets petrochemical products, derivative petrochemical products, and other chemical products mainly to external customers. Sinopec is the largest petrochemicals producer in China. It produces a range of petrochemical products, including intermediate petrochemicals, synthetic resin, synthetic fiber monomers and polymers, synthetic fibers, synthetic rubber, and chemical fertilizer. At the end of FY2009, the company had 11 ethylene plants (including three joint venture companies), 29 synthetic resin plants, 13 producers of synthetic fiber monomers and polymers, eight synthetic fiber plants, five synthetic rubber plants, and six urea plants. Sinopec's others segment consists principally of trading activities of the import and export subsidiaries and research and development activities undertaken by the company's other subsidiaries. The company's key products and services include the following: Products: Exploration and production:

• Crude oil • Natural gas


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Refined petroleum products:

• Gasoline • Kerosene • Diesel • Lube oil • Chemical light feedstock • Fuel oil • Solvent oil • Petroleum wax • Asphalt • Petroleum coke • Liquefied petroleum gas (LPG) • Propylene • Benzene

Chemicals:

• Intermediate petrochemicals • Synthetic resin • Synthetic fiber monomers and polymers • Synthetic fibers • Synthetic rubber • Chemical fertilizers • Ethylene

Services:

• Marketing of refined products • Storage and transportation services

Contact Details: China Petroleum & Chemical Corporation (Sinopec) No.22 Chaoyangmen North Street Chaoyang District Beijing


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100728 China Tel: +86‐10‐5996‐0028 Fax: +86‐10‐5996‐0386 Website: http://english.sinopec.com/ Statoil Statoil is an integrated oil and gas company. The company is present in approximately 40 countries worldwide and is engaged in exploration and production activities in 22 of these countries. The company is among the world's largest net sellers of crude oil and condensate and is the second largest supplier of natural gas to the European market. The company has its operations in North America; Latin America; Africa; the European, Caspian, and Russian area; and Middle East and Asia. Statoil operates through four business segments: exploration and production Norway; international exploration and production; natural gas; and manufacturing and marketing. The exploration and production Norway (EPN) segment includes exploration, field development, and production operations on the Norwegian Continental Shelf (NCS). NCS portfolio consists of licenses in the North Sea, the Norwegian Sea, and the Barents Sea. EPN is the operator of 42 developed fields on the NCS. Statoil's total entitlement liquids and gas production in FY2009 was 1,450 million barrels of oil equivalent (mmboe) per day, which represented about 75% of the total production from the NCS. In FY2009, the company's average daily oil and natural gas liquid (NGL) production was 784 thousands of barrels of oil equivalent (mboe) and its daily gas production was 105.9 million cubic meters (mmcm). EPN had proved reserves of 1,351 million barrels (mmbbls) of crude oil and 480 billion cubic meters (bcm) of natural gas, which represents an aggregate of 4,369 mmboe. Statoil has ownership interests in exploration acreage throughout the licensed parts of the NCS, both within and outside its core production areas. In FY2009, EPN had a high level of exploration activity, and discovered 31 of 39 exploration wells.


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The international exploration and production (INT) segment is responsible for exploration, development, and production of oil and gas outside the NCS. The company was engaged in production in 12 countries in FY2009 which include Canada, the U.S., Venezuela, Algeria, Angola, Libya, Nigeria, the UK, Azerbaijan, Russia, Iran ,and China. Statoil has exploration licenses in North America (Canada and the U.S.), Latin America (Brazil, Cuba, and Venezuela), Africa (Algeria, Angola, Egypt, Libya, Mozambique, Nigeria, and Tanzania), the European and Caspian area (the Faroes, Ireland, the UK ,and Azerbaijan), and the Middle East and Asia (Iran, India, and Indonesia). The main development projects that the company is involved are in Canada, the U.S., Brazil, and Angola, Further, in January 2010 Statoil and Lukoil signed the development and production contract for West Qurna 2 with Iraqi authorities. In FY2009, INT produced about 26% of Statoil's total equity production of oil and gas. The natural gas segment of the company is responsible for Statoil's transportation, processing, and marketing of pipeline gas and liquefied natural gas (LNG) worldwide, including the development of sufficient processing, transportation, and storage capacity. The natural gas segment is also responsible for marketing gas supplies originating from the Norwegian state's direct financial interest (SDFI). In total, the company accounts for approximately 80% of all Norwegian gas exports and is responsible for technical operation of the majority of export pipelines and onshore plants in the processing and transportation systems for Norwegian gas (Gassled). The natural gas segment's business is conducted from three locations in Norway (Stavanger, Karsto, and Kollsnes) and from offices in Belgium, the UK, Germany, Turkey, Singapore, Azerbaijan, and the U.S. (Houston and Stamford). In FY2009, the company sold 38.7 bcm of natural gas from the NCS on its own behalf, in addition to approximately 35.3 bcm NCS gas on behalf of the Norwegian State. Statoil 's total European gas sales, including third party gas, were 79.5 bcm in FY2009. This makes the company the second largest gas supplier in Europe with a market share of around 15% in the European gas market. From its international positions (mainly Azerbaijan and the U.S.), the company sold 5.3 bcm of gas in FY2009, of which 3.2 bcm was entitlement gas.


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Statoil has a significant interest in the NCS pipeline system (owned by Gassled), which is the world's largest offshore gas pipeline transportation system and is approximately 7,800 kilometers long. This network links gas fields on the NCS with gas processing plants on the Norwegian mainland and terminals at six landing points located in France, Germany, Belgium, and the UK. The manufacturing and marketing segment (M&M) segment is responsible for the company's combined operations in the transportation of oil, processing, the sale of crude oil and refined products, retail activities, and marketing of natural gas in Scandinavia. M&M operates in approximately 13 countries, has two refineries, one methanol plant, and three crude oil terminals and has international trading activities and a distribution network for businesses and private customers. More than one million customers visit M&M's approximately 2,000 service stations daily. Besides these segments, the company also generates revenue through its other operations, which consists of the activities of corporate services, corporate center, group finance, technology and new energy (TNE), and projects (PRO). TNE is responsible for ensuring that that Statoil has capacity and competence in the field of technology, in addition to creating distinct technological solutions for global growth. This includes delivering innovative and competitive technological solutions for exploration, increased recovery, field development solutions, and safe, efficient, and environmentally‐friendly operations. The research and development department, which has research centers in Trondheim, Bergen, and Porsgrunn in Norway and in Calgary in Canada, is engaged in research into and the development, piloting, implementation and commercialization of new technology. The new energy business unit is responsible for company's business effort within renewable energy. The activities are grouped under renewable energy production, new options, and carbon dioxide management. PRO is responsible for planning and executing all development and modification projects, as well as project and operational procurement, including securing rig capacity based on a corporate rig strategy. The current portfolio consists of more than 120 modification and development projects in the execution phase, with a total expected investment cost of more than NOK200 billion (approximately $36 billion).


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The company's key products and services include the following:

• Exploration and production of oil and natural gas • Transportation, processing, and marketing of gas and liquefied natural gas

(LNG) • Transportation, processing, and marketing of oil and refined products

Contact Details: Statoil ASA Forusbeen 50 4035 Stavanger Norway Tel: +47‐51‐990‐000 Fax: +47‐51‐990‐050 Website: http://www.statoilhydro.com/en


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Suncor Energy Suncor Energy (Suncor) is an integrated Canadian energy company. The company is engaged in acquisition, exploration, development, production, and marketing of crude oil and natural gas. It also transports and refines crude oil and markets petroleum and petrochemicals. The company primarily operates in Canada and the U.S.. Suncor's operations are divided into three business segments: oils sands, natural gas, and refining and marketing. The company's oil sands segment, based near Fort McMurray (Alberta), recovers bitumen, primarily through oil sands mining and in‐situ development, and upgrades it into refinery feedstock, diesel fuel, and by‐products. It produces light sweet and light sour crude oil, diesel fuel, and various custom blends from oil sands in the Athabasca region of northeastern Alberta. Suncor markets these products in Canada and the U.S., and periodically to its offshore markets. Oil sands' production is sold to and marketed by Suncor Energy Marketing. The markets for its crude oil products include refining operations in Alberta, Ontario, the U.S. Midwest, and the U.S. rocky mountain regions. Diesel products are sold primarily in Western Canada. The company also owns and operates a pipeline (having a capacity of approximately 110,000 barrels per day or bpd) that transports synthetic crude oil from Fort McMurray (Alberta) to Edmonton (Alberta). The company's natural gas segment, based in Calgary (Alberta), explores for, acquires, develops, and produces natural gas and natural gas liquids from reserves in Western Alberta and Northeastern British Columbia. In addition, the company's indirectly wholly‐owned U.S. subsidiary, Suncor Energy (Natural Gas) America, acquires land and explores for coal bed methane in the U.S.. Suncor operates natural gas processing plants at South Rosevear, Pine Creek, Progress and Simonette with a total design capacity of approximately 265 million cubic feet per day (mmcf/d). Their capacity interest in these gas processing plants is approximately 115 mmcf/d. Suncor also has varying undivided percentage ownership interests in natural gas processing plants operated by other companies


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and processing agreements in facilities where it does not hold an ownership interest. Approximately 93% of its natural gas production is sold to Suncor Energy Marketing and then marketed to customers in Alberta, British Columbia, Eastern Canada, and the U.S. Suncor's refining and marketing (R&M) segment refines crude oil at its refineries in Sarnia, Ontario, and Commerce City (Colorado) into a range of petroleum, petrochemical, and biofuel products. These products are marketed to industrial, wholesale, and commercial customers principally in Ontario, Quebec, and Colorado. In Ontario, the company's retail businesses are managed through Sunoco‐branded and joint venture operated retail networks. In Colorado, the company's retail businesses are managed through Phillips 66‐branded sites. The company also transports crude oil on its pipelines in Wyoming and Colorado. The company's refinery in Sarnia, Ontario, has a crude oil capacity of 85,000 bpd and refines petroleum feedstock from oil sands and other sources into gasoline, distillates, and petrochemicals with the majority of these refined products being distributed in Ontario. This refinery produces transportation fuels (gasoline, diesel, propane, and jet fuel), heating fuels, liquefied petroleum gases (LPG), residual fuel oil, asphalt feedstock, benzene, toluene, mixed xylenes, and orthoxylene. In the, Suncor's refining units include two fluidized catalytic crackers, distillate hydrotreater, and a gas oil hydrotreater. The refined gasoline products from the Commerce City refinery primarily supply R&M's marketing operations in Colorado. The Commerce City refining operation produces a range of products including gasoline, jet fuels, diesel, and asphalt. The refinery utilizes a crude slate containing approximately one‐third heavy, high sulphur crude oil. In Canada, R&M's products are marketed through retail networks, including the Sunoco‐branded retail network, joint‐venture owned retail stations, and cardlock operations. These products are sold to its industrial, commercial, wholesale, and refining customers, primarily in Ontario and Quebec. R&M Canadian operations market toluene, mixed xylenes, orthoxylene, and other petrochemicals, primarily in Canada and the U.S. through Sun Petrochemicals Company (in which Suncor has a 50% interest). In the U.S., R&M's products are marketed through Phillips 66‐branded retail outlets.


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Apart from operating in these segments, Suncor also has an ethanol facility in St. Clair, Ontario. This facility produces ethanol from corn, which is used for blending into the company's fuels and is also sold to third parties. The company is also investing in renewable energy opportunities and is a partner in four wind power projects. They are SunBridge in southwestern Saskatchewan, Magrath and Chin Chute in southern Alberta, and Ripley in Ontario. In addition to these operating segments, the company reports financial data for activities not directly attributable to an operating business under the results of Suncor's 'corporate and eliminations' segment. This includes the activity of its self‐insurance entity, as well as investments in wind energy. The company's key products and services include the following: Products:

• Light sweet and light sour crude oil • Natural gas • Natural gas liquids (NGLs) • Coal bed methane • Gasoline • Diesel • Propane • Jet fuel • Heating fuels • Liquefied petroleum gas (LPG) • Residual fuel oil • Asphalt feedstock • Benzene • Toluene • Mixed xylenes and orthoxylene • Petrochemical • Ethanol production


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Services:

• Refining and marketing of crude oil • Wind power generation • Prospect Generation Services

Brands:

• Sunoco • Phillips 66

Contact Details: Suncor Energy 112 ‐ 4 Avenue S.W. Calgary Alberta T2P 2V5 Canada Tel: +1‐403‐269‐8100 Fax: +1‐403‐269‐6200 Website: http://www.suncor.com


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Syncrude Canada Syncrude Canada Ltd. is the world's largest producer of synthetic crude oil from oil sands and the largest single source producer in Canada. It is located just outside Fort McMurray in the Athabasca Oil Sands, and has a nameplate capacity of 350,000 barrels per day (56,000 m3/d) of oil, equivalent to about 13% of Canada's consumption. It has approximately 5.1 billion barrels of proven and probable reserves (11.9 billion when including contingent and prospective resources) situated on 8 leases over 3 contiguous sites. By 2020, Syncrude expects to extract the equivalent to 525,000 barrels per day (83,500 m3/d). Including fully realized prospective reserves, said production level could be sustained for well over the next 60 years. The company is a joint venture between seven partners. As a result, Syncrude is not traded directly, but rather through the individual owners. As of August 2010, the partners (by percentage): Canadian Oil Sands Limited (36.74%), Imperial Oil (25%), Suncor Energy (12%), Sinopec (9.03%), Nexen (7.23%), Mocal Energy (a subsidiary of Nippon Oil Exploration) (5%), and Murphy Oil (5%). The ownership board must approve all annual operating budgets and proposed capital spending projects, and are required to provide the funding for said activities based on their ownership share. The company's key product and activities include the following: Product:

• Crude oil Activities:

• Crude oil production • Operation of oil sand mine, utilities plant, bitumen extraction plant and

upgrading facility


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Brand:

• Syncrude Crude Oil Contact Details: Syncrude Canada Ltd. Fort McMurray Alberta T9H 3H5 Canada Tel: +1‐780‐790‐5911 Website: http://www.syncrude.ca/


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Teck Resources Teck Resources (formerly known as Teck Cominco) is engaged in mining and related activities including exploration, development, processing, smelting and refining. Its major products are zinc, copper and metallurgical coal. The company also produce precious metals, lead, molybdenum, electrical power, fertilizers and various specialty metals. Teck Cominco also owns an interest in certain oil sands leases and have a partnership interest in an oil sands development project. The company operates through four divisions: copper, zinc, coal and energy. The copper division includes interests in the Highland Valley Copper mine located in south central British Columbia, the Antamina mine in north central Peru, the Quebrada Blanca and Carmen de Andacollo mines located in Chile, the Duck Pond copper‐zinc mine located in central Newfoundland, and the Galore Creek mine located in northwestern British Columbia. The zinc division includes Trail refining and smelting complex located in south central British Columbia; the Red Dog mine located in the northwest Alaska; and the Pend Oreille mine in Washington State. The major products produced at these operations are zinc and lead concentrates at mines and refined zinc and lead at Trail metallurgical complex. Trail also produces various precious and specialty metals, fertilizers and chemicals. It also produces electricity for the metallurgical facilities, selling any that is surplus to the company's internal needs to various customers in Canada and the U.S.. The coal division includes six metallurgical coal mines in British Columbia and Alberta and is the world's second largest exporter of seaborne hard coking coal. The Coal Mountain, Elkview, Fording River, Greenhills, and Line Creek mines are located in southeastern British Columbia, approximately 1,100 kilometers from the ports near Vancouver, British Columbia. Cardinal River is located in west‐central Alberta, near the town of Hinton. All these coal mines produce primarily hard coking coal, which is used in the production of steel, and small amounts of thermal coal. The energy division consists of investments in oils sands projects. It includes 20% interest in the Fort Hills Energy Limited Partnership, which is developing the Fort Hills oil sands project located in northern Alberta; and 50% interest in various oil


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sands leases that the company jointly owns with UTS Energy Corporation (UTS). The company also have a 50% interest in various other oil sands leases, including the Lease 421 Area, which are in the exploration phase. All of these properties are located in the Athabasca region of northeastern Alberta, Canada. The company's key products and services include the following: Products:

• Concentrates • Metals and base metals • Specialty metals • Precious metals • Advanced materials • Industrial chemicals

Services:

• Recycling • Galvanizing technology sales • Battery technology • Geochemical analysis services • Technical and marketing services

Contact Details: Teck Resources Limited Suite 3300 Bentall 5 550 Burrard Street Vancouver British Columbia V6C 0B3 Canada Tel: +1‐604‐699‐4000 Fax: +1‐604‐699‐4750 Website: http://www.teck.com


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Total SA TOTAL is engaged in the exploration and production of oil and gas, as well as transportation, refining, petroleum product marketing, and international crude oil and product trading. The company operates in more than 130 countries. TOTAL operates through three business segments: upstream, downstream, and chemicals. The upstream segment includes the company's exploration, development, and production activities, as well as its gas and power operations. TOTAL has exploration and production activities in over 40 countries and produces oil or gas in 30 countries. TOTAL's gas and power division conducts activities downstream from production related to natural gas, liquefied natural gas (LNG), and liquefied petroleum gas (LPG), as well as power generation and trading, and other activities. The company's consolidated exploration and production subsidiaries' development expenditures amounted to E7 billion (approximately $10.3 billion) in FY2008. The investments were made primarily in Angola, Nigeria, Norway, Kazakhstan, Indonesia, the Republic of Congo, the UK, Gabon, Canada, the U.S., and Qatar.. In FY2008, TOTAL's combined proved reserves of crude oil and natural gas was 10,458 million barrels of oil equivalent (Mboe), 50% of which were proved developed reserves. Liquids represented approximately 54% of these reserves and natural gas the remaining 46%. These reserves were located for the most part in Europe (Norway, the UK, the Netherlands, Italy, and France), and Africa (Nigeria, Angola, the Republic of Congo, Gabon, Libya, Algeria, and Cameroon). The reserves were also located in Asia/Far East (Indonesia, Myanmar, Thailand, and Brunei), North America (Canada and the U.S.), and the Middle East (Qatar, United Arab Emirates, Yemen, Oman, Iran, and Syria). These reserves were also located in South America (Venezuela, Argentina, Bolivia, Trinidad & Tobago, and Colombia) and the Commonwealth of Independent States or CIS (Kazakhstan, Azerbaijan, and Russia). The upstream business segment also includes the gas and power division which encompasses the marketing, trading, and transport of natural gas and liquefied natural gas (LNG), LNG re‐gasification and natural gas storage, and LPG shipping and trading. It also includes power generation from gas‐fired combined‐cycle plants and renewable energies; the trading and marketing of electricity; and the


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production, marketing, and trading of coal and solar power systems (through its subsidiaries Tenesol and Photovoltech). In FY2008, TOTAL traded and sold 5.2 million metric ton (Mt) of LPG (butane and propane) worldwide. As a refiner and petrochemicals producer, TOTAL has interests in several cogeneration facilities. TOTAL also participates in another type of cogeneration, which combines power generation with water desalination and gas‐fired electricity generation. One such example is the Taweelah A1 cogeneration plant in Abu Dhabi, in which TOTAL has a 20% interest. TOTAL has also entered into a partnership agreement in FY2008 with GDF Suez and Areva to propose the development of a nuclear power plant project, based on third generation EPR technology, to the local authorities in Abu Dhabi at the appropriate time. In Thailand, TOTAL owns 28% of Eastern Power and Electric Company (EPEC), which operates the combined cycle gas power plant of Bang Bo, with a capacity of 350 megawatt (MW). In Nigeria, TOTAL and its partner, the state‐owned Nigerian National Petroleum Corporation, are participating in two projects to construct gas‐fired power generation units. TOTAL is also engaged in renewable energies, with a particular focus on solar‐photovoltaic power. In solar‐photovoltaic power (silicon‐crystal technology), TOTAL is involved in upstream activities, with the manufacturing of photovoltaic cells, and, in downstream activities, with the marketing of solar panels. In partnership with GDF Suez and IMEC (Interuniversity MicroElectronics Centre), TOTAL owns 47.8% of Photovoltech, a company specializing in manufacturing photovoltaic cells. In addition, TOTAL holds a 50% interest in Tenesol, in partnership with Electricite de France (EDF). Tenesol designs, manufactures, markets and operates solar‐photovoltaic power systems. TOTAL also operates a wind farm in Mardyck (near its Flanders refinery, located in Dunkirk, France). Mardyck has a capacity of 12 MW and produced approximately 29.5 gigawatt‐hours (GWh) of electricity in FY2008. TOTAL has decided to dispose of certain of its wind farm projects. In marine energy, TOTAL acquired a 10% interest in a pilot project located offshore Santona, on the northern coast of Spain, in 2005. The construction of a first buoy,


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with a capacity of 40 kilowatt (kW), was completed and the buoy was put into the water in September 2008. TOTAL also exports steam coal from its mines located in South Africa, primarily to Europe and Asia. TOTAL owns and operates three mines. A fourth mine is under construction and several mining development projects are being reviewed. TOTAL also trades and markets steam coal through its subsidiaries Total Gas & Power, Total Energy Resources (Pacific Basin), and CDF Energie (France). TOTAL sold approximately 8.4 Mt of coal worldwide in FY2008, of which 4.0 Mt was South African steam coal. Approximately 50% of TOTAL's South African coal production was sold to European utility companies and approximately 40% was sold in Asia. The downstream segment is engaged in refining, marketing, trading, and shipping activities. TOTAL is the largest refiner/marketer in Western Europe, and the largest marketer in Africa, with a market share of 11%. TOTAL's refining business has interests in 25 refineries and it directly operates 12 of these refineries. These refineries are located in Europe, the U.S., the French West Indies, Africa, and China. The company's refineries produce a broad range of specialty products, such as lubricants, LPG, jet fuel, special fluids, bitumen, and petrochemical feedstock. As of December 31, 2008, TOTAL's worldwide refining capacity was 2,604 thousand barrels per day (kb/d) and its refined products sales worldwide stood at 3,658,kb/d (including trading activities). The company markets a wide range of specialty products, produced from refined oil at its refineries and other facilities. TOTAL is among the leading companies in the specialty products market, in particular for the bitumen, jet fuel, LPG, and lubricants markets. Through its specialty products, TOTAL is present in approximately 150 countries. As of December 31, 2008, TOTAL's worldwide marketing network comprised 16,425 retail stations, with more than 50% owned by the company. TOTAL is also active in the biodiesel and biogasoline biofuel sectors. In 2008, TOTAL consolidated its position as a leading oil and gas company in the European biofuels market by producing and incorporating 790 kilotons (kt) of ethyl‐tertio‐buthyl‐ether (ETBE) at ten refineries and incorporating 1,470 kt of VOME (vegetable‐oil‐methyl‐ester) at fourteen European refineries and several storage sites. TOTAL, in partnership with the companies in this area, is developing second generation


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biofuels derived from biomass. The company is also participating in French, European, and international bioenergy development programs. The trading and shipping activities of the downstream segment of TOTAL sell and market the company's crude oil production; and provides a supply of crude oil for the company's refineries. It also imports and exports the appropriate petroleum products for TOTAL, charters appropriate ships for these activities, and undertakes trading on various derivatives markets. In FY2008, the shipping division of the company chartered 3,182 voyages to transport approximately 128 million metric ton (Mt) of oil. As of December 31, 2008, TOTAL employed a fleet of 62 vessels chartered under long‐term or medium‐term agreements (including six LPG carriers). The fleet, consisting entirely of double‐hulled vessels, has an average age of approximately five years. The chemicals segment is organized into the base chemicals (petrochemicals and fertilizers) and the specialties chemicals (including rubber processing, resins, adhesives, and electroplating activities). TOTAL is one of the world's largest integrated chemical producers. TOTAL's petrochemicals activities include base petrochemicals (olefins and aromatics) and their derivatives (polyethylene, polypropylene, and styrenics). TOTAL's main petrochemicals sites are located in Belgium, France, the U.S., Singapore, and China. TOTAL holds a 50% interest in an integrated petrochemicals site located in Daesan, South Korea in partnership with Samsung. The company also holds a 20% interest in a site with a steam cracker and two polyethylene units in Mesaieed, Qatar. Through its subsidiary GPN, TOTAL manufactures and markets nitrogen fertilizers made from natural gas. TOTAL's specialties chemicals division includes its business in rubber processing, resins, adhesives, and electroplating. Hutchinson manufactures and markets products derived from rubber processing for the automotive, aerospace, and defense industries and consumer markets. TOTAL produces and markets resins for adhesives, inks, paints, coatings and structural materials through three subsidiaries: Cray Valley, Sartomer, and Cook Composites & Polymers. TOTAL, through its subsidiary Bostik, is engaged in manufacturing


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adhesives for the industrial, hygiene, construction, and consumer and professional distribution markets. Atotech, which encompasses TOTAL's electroplating activities, is the second largest company in this sector, based on worldwide sales. It is engaged in both the electronics and general metal finishing markets. The company's key products and services include the following: Products:

• Aviation gas and fuel • Bitumen • Crude Oil • Fuel oils and heating oils • Kerosene and diesel fuel • Liquefied petroleum gas (LPG) • Lubricants • Motor gasoline • Natural gas • Solvents • Biofuels

Chemicals:

• Olefins • Aromatics • Polyethylene • Polypropylene • Styrenics • Commodity polymers • Vinyl products • Industrial chemicals • Fertilizers • Resins • Adhesives • Electroplating


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Services:

• Power generation • Gas transportation and transmission • Gas and power distribution

Brands:

• TOTAL • Elf • Elan • Orgasol • Pebax • Kynar • Evatane • Lotryl • Lotader • Orevac • TOTAL EXCELLIUM • AS24

Contact Details: TOTAL S.A. 2 place Jean Millier La Defense 6 92400 Courbevoie France Tel: +33‐147‐444546 Fax: +33‐147‐444944 Website: http://www.total.com


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Analysis of the Utah Oil Sands

Analysis of the Utah Oil Sands Introduction In the United States a large supply of oil sands are found in Eastern Utah. These deposits of bitumen or heavy crude oil have the ability to generate about 12 to 19 billion barrels from a number of prominent sites. History of the Utah Oil Sands Since the early 1900's the oil sand deposits have been extracted mainly for the use of road pavement. Later, in the 1970's, oil companies began to experiment with the deposits in the hope of using it for their benefit. These experiments ended in the late 1980's when the technologies being used were concluded inefficient and too expensive. Recently, oil companies have again become interested in Utah's oil sands. Now that conventional oil is becoming harder to find, oil sands have become an alternative fuel source. Production Sites Utah's oil sands are made up of several different deposits all consisting of different amounts of heavy or crude oil. These sites are mostly found on public lands. They are mainly close together and many are found within the Uintah Basin of Utah, which is a section of the Colorado Plateaus province. Some of these sites include Sunnyside, P.R. Spring, Asphalt Ridge, Hill Creek, Circle Ridge, Circle Cliffs, White Rocks, and the Tar Sand Triangle, the highest deposit. Utah Oil Sands Joint Venture The Utah Oil Sands Joint Venture is a joint venture between Nevtah Capital Management, Inc., and Black Sands Energy Corp. to develop oil sands resources at the Uintah Basin in Utah. Oil‐sands extraction in Utah started in the 1960's when two extraction plants were constructed. Western Industries opened a strip‐mine and built a pilot plant along the east side of the Whiterocks River and Major Oil Company opened a strip‐mine


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and built a pilot plant on the west side off the Whiterocks River. In 2005, Nevtah Capital Management and Cassandra Energy (now: Black Sands Energy) formed a joint venture to develop Utah's oil sands and opened a pilot plant at the Asphalt Ridge lease location. The pilot plant became in operation in November 2005. The joint venture uses closed‐loop solvent extraction process originally proven by X‐TRAC Energy in Wyoming in 1998, with a full scale production plant. Black Sands Energy has exclusive rights to a technology. The above‐ground extraction process dissolute crushed, 1" minus oil sands materials through contact with a benign non‐toxic solvent in an enclosed extractor vessel at temperatures up to 300 °F (149 °C) at near‐atmospheric pressures. As the material dissolves, it is passed to a wash chamber where any remaining oil is removed. The oil‐free sand is then desolventized with heat, which converts the liquid solvent to a gas, leaving dry solids suitable for mine backfill. The solvent‐oil mixture is pumped into a critical unit for the removal of asphalt and oil from the solvent through heating and cooling. The recovered solvent is compressed back to a liquid, cooled and re‐circulated to the extractor vessel in an endless loop. The system consists of only few moving parts and it operates on a gravity principle. Since the process does not use water to recover the oil, energy requirements are minimal. The partnership holds the rights to 13 oil sands leases in Utah consisting of 11,535 acres (46.68 km2) containing over 650,000,000 bbl of recoverable oil. The joint venture owns a 200 bbl per day mobile pilot plant and preparing a 2,000 bbl per day commercial production unit. The production capacity is expected to increase up 50,000 bbl per day by the end of 2009. The system has been improved to maintain processing levels at cold temperatures. A steam jacket has been installed which creates drier sand and keeps the pumps, plumbing and the extraction chamber warmer during standby time, minimizing warm‐up time. System performance has improved with the installation of more powerful pumps and additional sensors for better indications of mass flow, temperature and material levels. The upgraded process control provides more precise data required in order to measure the system's performance.


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The partnership is between Nevtah Capital Management, Inc., and Black Sands Energy Corp. The extraction technology is provided by development by Black Sands Energy and the financing is provided by Nevtah Capital Management. On 12 January 2007, Nevtah Capital Management and Black Sands Energy announced a joint venture agreement with Korea Technology Industry. According to the agreement, Korea Technology Industry provides $19 million for the development of the Whiterocks Deposit, in exchange of 50% of net profit. The joint venture agreement is limited to 100 million barrels of oil.


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Case Study: Mackay River in-Situ Oil Sands Projects

Case Study: Mackay River inSitu Oil Sands Projects Petro‐Canada has been a leader in in‐situ oil sands research and development since its inception over a quarter century ago. Today this investment is paying off with the commercial development of the Mackay River Oil Sands lease, northwest of Ft. McMurray, Alberta. This project will build on Petro‐Canada’s investment in SAGD technology, developed through membership in the former UTF consortium (now known as the Dover Project), along with various other SAGD projects. The fact that the Dover project area sits immediately adjacent to the MacKay River site is viewed as a distinct advantage in understanding the eventual performance of the MacKay River reservoir, since Dover has the longest history of application of SAGD technology of any oil sands or heavy oil project anywhere in the world. Currently, MacKay River is one of several SAGD projects within the general area of the Athabasca Oil Sands which have either been announced as being under consideration for development or have actually been granted approval for development. The resource base at MacKay River was discovered nearly 40 years ago by one of Petro‐Canada’s predecessor companies, Arco Canada. It was not until 1997, however, that full‐scale evaluation of the property was undertaken. Since that time, over 200 delineation core holes have been drilled and evaluated, and over 150km of seismic coverage has been shot. Two main pools have been identified, which Petro‐Canada refers to as Mackay River North and Mackay River South. Both reservoirs have been extensively drilled, with up to 16 delineation wells per section. At this time Petro‐Canada is only choosing to develop the MacKay River North reservoir, which will alone support a 30,000 bbl/d development for the next 25 years. Reservoir characteristics of the McMurray Formation at MacKay River are excellent, with up to 34 m net pay, porosities averaging 33%, permeabilities of as much as 10D, and oil saturations in excess of 80%. The reservoir at MacKay River is quite shallow, with depths to the top of the McMurray Formation averaging only 115m TVD. Because of this last fact, horizontal SAGD wells are being spudded at a angle of 45 degrees in order to build angle fast enough to achieve horizontal trajectories at these shallow depths.


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Projects

Prior to proceeding with commercial development of this project, extensive studies were undertaken in order to determine expected reservoir characteristics and performance once production was initiated. A 3‐D geostatistical model was developed for the MacKay River North reservoir based on log and core data from over 150 wells. This model was used to develop both thermal models of reservoir performance (steam chamber growth and reservoir depletion, production rates, steam‐oil ratios), as well as aiding in the planning of horizontal wellbores. Initial development plans call for the drilling of 25 horizontal pairs in order to meet the planned production volumes. These wells are being drilled from pads, and have been planned in such a way as to minimize surface land use. Over 200 SAGD well pairs will have to be drilled over the 25‐year life of the project in order to fully exploit the reservoir.


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Case Study: Kearl Oil Sands Project

Case Study: Kearl Oil Sands Project Mobil Oil Canada, Ltd. (Mobil), a wholly owned subsidiary of Mobil Oil Corporation, has substantial holdings of heavy oil and oil sands in Alberta, Canada. One such holding, 70 kilometers north of Fort McMurray, contains approximately 1.5 billion barrels of 8 API gravity recoverable bitumen and is shallow enough to be surface mineable. In early 1997, Mobil announced plans to develop the Kearl Oil Sands project (Kearl) and construct associated extraction and upgrading facilities which could produce 130,000 barrels per day of synthetic crude oil (SCO) from this lease in 2003. The latest in truck and shovel technology and extraction processes will be utilized to optimize economics and mitigate environmental effects. The building of processing facilities in Alberta to upgrade the bitumen to higher value marketable SCO provides an opportunity to produce a product optimized for marketability and costs. The potential development of Kearl, at an estimated capital cost of C$2.5 billion, supports Mobil’s vision to become the largest, most profitable and most respected energy company in Canada. A commitment of this magnitude could follow completion of Mobil’s current major developments offshore Canada’s East Coast. These include: a. The recent start up of a 33.1% working interest in the C$6 billion Hibernia light oil project which could, with some debottlenecking, possibly reach a production rate of 180,000 barrels per day; b. A 50.8% working interest in the C$2 billion Sable Offshore Energy gas and gas liquids project with an estimated 103,000 barrels of oil equivalent production per day starting in November 1999; c. A 22% working interest in the C$2 billion Terra Nova light oil project with a production rate of an estimated 115,000 barrels per day starting in early 2001. Mobil thus has the basis for undertaking the development of Kearl, and based on work to date, this opportunity is competitive with Mobil’s other global


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opportunities. Some of Mobil’s key drivers for participation in oil sands development follow. 1. The Alberta oil sands is one of the largest resource bases in the world, highly concentrated in a relatively small area, and capable of sustaining production rates for a very long time. Additionally, there are essentially no exploration and associated finding costs or risks normally associated with the conventional oil and gas business. 2. Improved generic fiscal terms from the federal and provincial governments provide more fiscal certainty and a level playing field for all investors. An attractive feature of the new terms provides for a low 1% gross royalty until payout of invested capital and a return allowance. These terms remove much of the investor’s front end risk associated with capital intensive projects while providing a substantial share of project profits to the Crown over the lifetime of the project. 3. Major technological advances have resulted in dramatically lower capital and operating costs and higher bitumen recoveries. These advances include the introduction of large, reliable trucks and shovels to substantially lower mining costs, more energy efficient lower temperature extraction processes, new pipeline slurry transportation systems from the mine pits, improved tailings management and emissions control systems and upgrading catalyst improvements. 4. The relative proximity of a large and efficient pipeline transportation network to a large market in the U.S. Midwest, the continued decline of conventional North American light oil production that serves this market, and some supply displacement capability in the U.S. Midwest provides some basis for reasonable market placement. 5. The pioneering efforts of the existing operators, Syncrude Canada Ltd. and Suncor Energy Inc., have resulted in the development and availability of substantial technical and industrial expertise in Alberta to engineer, procure and construct oil sands mining projects.


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Section 2: Analysis of Gas Shales


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Introduction to Gas Shales

Introduction to Gas Shales Overview Shale gas is natural gas produced from shale. Shale gas has become an increasingly important source of natural gas in the United States over the past decade, and interest has spread to potential gas shales in Canada, Europe, Asia, and Australia. One analyst expects shale gas to supply as much as half the natural gas production in North America by 2020. Some analysts expect that shale gas will greatly expand worldwide energy supply. A study by the Baker Institute of Public Policy at Rice University concluded that increased shale gas production in the U.S. and Canada could help prevent Russia and Persian Gulf countries from dictating higher prices for the gas it exports to European countries. The Obama administration believes that increased shale gas development will help reduce greenhouse gas emissions. Because shales ordinarily have insufficient permeability to allow significant fluid flow to a well bore, most shales are not commercial sources of natural gas. Shale gas is one of a number of “unconventional” sources of natural gas; other unconventional sources of natural gas include coalbed methane, tight sandstones, and methane hydrates. Shale gas areas are often known as resource plays (as opposed to exploration plays). The geological risk of not finding gas is low in resource plays, but the potential profits per successful well are usually also lower. Shale has low matrix permeability, so gas production in commercial quantities requires fractures to provide permeability. Shale gas has been produced for years from shales with natural fractures; the shale gas boom in recent years has been due to modern technology in hydraulic fracturing to create extensive artificial fractures around well bores. Horizontal drilling is often used with shale gas wells, with lateral lengths up to 10,000 feet (3,000 m) within the shale, to create maximum borehole surface area in contact with the shale.


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Shales that host economic quantities of gas have a number of common properties. They are rich in organic material (0.5% to 25%), and are usually mature petroleum source rocks in the thermogenic gas window, where high heat and pressure have converted petroleum to natural gas. They are sufficiently brittle and rigid enough to maintain open fractures. In some areas, shale intervals with high natural gamma radiation are the most productive, as high gamma radiation is often correlated with high organic carbon content. Some of the gas produced is held in natural fractures, some in pore spaces, and some is adsorbed onto the organic material. The gas in the fractures is produced immediately; the gas adsorbed onto organic material is released as the formation pressure is drawn down by the well.

Figure 6: Geology of Natural Gas Resources

Source: EIA

Role of Fracturing Natural or induced fracturing of the reservoir is required in order to allow gas to migrate through the low permeability matrix to the well.


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Induced fracturing is achieved via a hydraulic process commonly referred to as “fracing”, which involves pumping a liquid into the borehole under high pressure to fracture the rock. So that the fractures remain open after the injection stops a solid “proppant” such as sand or ceramic beads is added to the fluid. As the name suggests, when in place, these prop open the induced fractures to produce a high permeability conduit to the well. In “shale” some of the gas is typically held in natural fractures and pore spaces (free gas), while some is adsorbed onto the surface of the organic material (adsorbed gas). The free gas is produced immediately, while the deadsorbed gas is released as the formation pressure is drawn down by the well. A well‐fractured shale that contains an abundance of mature organic matter and is under high pressure will generally yield a high initial flow rate. Flow Rates However, the initial flow rates decline rapidly, usually by about 50% to 60% after the first year. Thereafter gas flow is dominated by the rate of diffusion from the matrix to the induced fractures. Hence matrix permeability and the extent of induced fracturing are both key parameters in determining the economics of a development. The former determines the sustainability of gas production, while the latter determines the effective drainage area of a well and hence the density of wells required to produce a play. The drainage area of low‐matrix‐permeability reservoirs is presently thought to be restricted to a relatively small area beyond the extent of the individual fracture. Innovation in drilling and completion techniques has improved the economics of shale development considerably in recent years. Horizontal drilling increases the drainage area of shale gas wells, while new completion techniques, including


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“staged fracs” and simultaneous “fracs” have further improved economics and added substantial reserves to otherwise uneconomic areas. Nonetheless shale gas reservoirs still generally recover less gas (from <5% to 20%) than conventional reservoirs (~50% to 90%), although more recently there have been suggestions that the Haynesville shale in Louisiana may have a recovery factor as high as 50% to 60%. In summary, finding an organic‐rich gas prone shale in the U.S. is generally not difficult. Rather, the challenge is finding the combination of permeable “sweet spots”, the most brittle and easily fractured strata and the most gas‐saturated sediment to make production economic. As the broad range of reservoir lithologies listed previously suggests, each reservoir may have distinct geochemical and geological characteristics that may require equally unique methods of drilling, completion, production and resource and reserve evaluation. Once the sweet spots are identified and the best ways to drill and complete the play have been identified (usually through a process of trial and error) operational efficiency becomes key. Particularly as the operations are relatively capital intensive with full‐scale development requiring drilling several thousand wells with multiple fractures. Process of Unlocking Indeed the process becomes more akin to “gas manufacturing” than traditional exploration and production, leading some to speculate that we will see the return of vertical integration in the sector in order to guarantee the control over the process necessary to generate scale and scheduling efficiencies, as well as protect the “intellectual” property of knowing how to best “unlock” a play. Potential shale gas plays are relatively abundant in North America. Around 20 shale formations were shown in American Association of Petroleum Geologists (AAPG) documentation and listed as current plays in 2006. This had increased to more than 40 by 2008. The Barnett Shale in North Texas, which has been producing since 1999, was the proving ground for many of the techniques responsible for the growing success of shale gas. With Barnett Shale production reaching almost 5 billion cubic feet per day in 2009 (from 11,000 wells) focus has now shifted to other shale plays such as the


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Haynesville, Fayetteville, Woodford, Marcellus, Horn River and Montney among others. Shale Gas Economics Although shale gas has been produced for more than 100 years in the Appalachian Basin and the Illinois Basin of the United States, the wells were often marginally economical. Higher natural gas prices in recent years and advances in hydraulic fracturing and horizontal completions have made shale gas wells more profitable. Shale gas tends to cost more to produce than gas from conventional wells, because of the expense of massive hydraulic fracturing treatments required to produce shale gas, and of horizontal drilling. However, this is often offset by the low risk of shale gas wells. To date, all successful shale gas wells have been in rocks of Paleozoic and Mesozoic age. North America has been the leader in developing and producing shale gas. The great economic success of the Barnett Shale play in Texas in particular has spurred the search for other sources of shale gas across the United States and Canada. Environmental Considerations The development of shale gas resources has been dependent on several concomitant improvements n technology. These improvements directly affect the environmental considerations associated with shale gas development. Hydraulic fracturing techniques have grown to be carefully engineered processes employed to generate a more extensive network of fractures and thereby produce a larger portion of the in‐place natural gas. This innovation has transformed shale gas into a bona fide economic resource play and has led to the drilling of many more shale gas wells and to increased attention on potential environmental effects.


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Figure 7: Output of Hydraulic Fracture Simulation Model

Source: Chesapeake Energy

At the same time, horizontal drilling has become more economical, faster, more accurate, and more wide‐spread. With horizontal drilling, operators can access and drain larger volumes of the shale reservoir from a single well. The combination of opening up larger volumes of the reservoir and being able to reach out long distances means that only a fraction of the wells are needed to drain the gas from a given field area. Fewer wells translate into fewer impacts from land disturbance, noise, water use, traffic, and air emissions. Fluid handling techniques have also evolved to make routine drilling and stimulation work less impactful on the local environment and especially less prone to accidental releases to land, water, and air. Processes in Extracting Gas Shales Hydraulic Fracturing Fracturing is a formation stimulation technique used to create additional permeability in a producing reservoir, thus allowing gas to flow more readily to the wellbore. Fracturing has become the industry standard. Recent developments in


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hydraulic fracturing include pumping large volumes of low‐viscosity; nearly pure water/sand slurry into the shale to induce new fractures and augment existing fractures in the shale. Modern refinements in hydraulic fracturing technology make it an extremely sophisticated engineering process designed to emplace fracture networks into specific reservoir units. Hydraulic fracturing treatments are carefully tailored to the specific parameters of the target shale including thickness, local stress conditions, compressibility, and rigidity. Local conditions are used in computer models to design site‐specific hydraulic fracturing treatments and optimize the new fractures as shown in Exhibit 9. Both shale gas reservoirs and the intervals to be fractured are typically thick, so it is often more effective to separate the hydraulic fracturing process into several stages, each focused on a consistent portion of the reservoir. Each stage of the job will be isolated within the borehole so that the full capacity of the fracturing equipment can be applied to the single reservoir unit. This can be done in vertical or horizontal wells to great effect. Before operators or service companies perform a hydraulic fracture treatment of a well (either vertical or horizontal), they conduct a series of tests to ensure that the well, well‐head equipment, and fracturing equipment are in proper working order and will safely withstand the fracture treatment pressures and pump rates. It should be noted that minimum construction requirements are typically mandated by state oil and gas regulatory agencies to make sure that the well construction and fracture treatment design are protective of environmental resources and are safe for operation. After testing surface equipment, the hydraulic fracturing process begins with the pumping of a “rock‐acid”—often hydrochloric acid (HCl)—treatment to clean the near‐wellbore area which may have become plugged with drilling mud and cement. The next step is a slug of “slickwater” which combines water with a friction‐reducing chemical additive allowing the water to be pumped faster into the formation. Slickwater hydraulic fractures treatments work best in low‐permeability reservoirs, and have been the primary instrument in opening up unconventional plays like the Texas Barnett Shale. In addition to the cost advantage, slickwater hydraulic fractures treatments require less cleanup, provide longer fractures, and carry proppant farther into the fracture network. After the first water slug, the operator begins the fracturing process by pumping a large volume of slickwater with fine sand at a low volume. Subsequent steps include


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the application of slickwater volumes with coarser sand proppant that keep fractures closer to the well‐bore open. The last step is a flush to remove proppant from the equipment and well‐bore. After the flush, the next treatment stage is begun on a new portion of the bore‐hole that contains its own specific reservoir parameters including thickness, local stress conditions, compressibility, and rigidity. The staged fracturing treatments are closely monitored by technicians from service and operating companies. By fracturing discrete intervals of the wellbore (either horizontal or vertical), the operator is able to make modifications to accommodate local changes in the shale reservoir including lithology, natural splitting, rigidity, and changes in the stress regime.

Figure 8: Micro Seismic Mapping of Fractures in a Treatment

Source: Oilfield Service Company


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Fracturing stages are determined with the help of numerical simulators to predict fracture performance in the shale reservoir. Engineers and geologists can manipulate the simulator and evaluate the effect on fissure height, length, and orientation. Predictions from the simulator can be used to monitor and evaluate the results of the fracture job. Monitoring can also be done in real‐time at the well by way of micro‐seismic mapping. This technology can locate the fracture tips in an east‐west and north‐south direction from the bore‐hole and track their growth as the job proceeds and more steps are completed. Of particular importance is the growth of fractures in the vertical direction. Operators take particular care to ensure that they do not migrate out of the shale reservoir and extend into adjacent water‐bearing units. Such fissures can ruin the economics of a shale gas well. During the fracturing treatment, a number of chemicals are added to the water‐sand mix. Each chemical compound serves a specifically engineered purpose such as reducing viscosity or bacterial growth or bio‐fouling reservoir surfaces. The make‐up of fracturing fluid will vary from one basin to another and from one contractor to another. The figure below graphically demonstrates the relative amounts of the components in a fracture fluid used recently on the Fayetteville Shale; this fluid is 99.5% water with less than 0.5% other compounds. Any toxicity of the components, such as acid, is greatly reduced by dilution in the pumped fluid and by the reaction of the acid with the rock in the subsurface that converts the acid into salts.


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Figure 9: Volumetric Composition of a Shale Gas Fracture Fluid

Source: Data Collected at Fayetteville Shale Fracture Stimulation by ALL Consulting,

2008 Horizontal Drilling Modern drilling technology has progressed to the point of allowing the driller to turn corners by making the drill bit progress on a horizontal track while accurately staying within a narrow directional and vertical window. Because the horizontal portion is easily controlled, the well is able to drain shale gas resources from a geographical area that is much larger than a single vertical well in the same shale formation. Using the Marcellus Shale play in Pennsylvania as an example, a vertical well may only drain a cylinder of shale 1,320 feet in diameter and as little as 50 feet high . By comparison, a horizontal well may extend from 2,000 to 6,000 feet in length and drain a volume up to 6,000 feet by 1,320 feet by 50 feet in thickness, an area about 4,000 times greater than that drained by a vertical well. The increase in drainage creates a number of important advantages for horizontal over vertical wells, particularly in terms of environmental concerns. Using the similar Fayetteville Shale as an example, analysis performed for the U. S. Department of the Interior60 estimated that a shallow vertical shale gas well in Arkansas would have a 2.0 acre well pad and 0.10 miles of road and 0.55 miles of


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utility corridor resulting in a total of 4.8 acres of disturbance per well. The same study identified a horizontal shale gas well that occupies a well‐pad of approximately 3.5 acres plus roads and utilities resulting in a total of 6.9 acres. The horizontal well has the ability to drain at least four times the acreage of a vertical well, meaning that horizontal shale gas development results in roughly one‐third (19.2 acres versus 6.9 acres) the disturbed acres. This means less landscaping and vegetation destroyed, wildlife habitat disturbed, soil erosion and compaction done, and general construction needed. Co‐locating several horizontal wells on a single pad will further shrink the number of disturbed acres. Reducing the number of producing wells in a field will also reduce the need for field personnel and routine truck traffic within the field. Fewer wells will require fewer maintenance crews traveling county roads. Produced water will still need to be transported to central management facilities but if there are fewer well sites with more production, it may become economical to transport the water to the facility by pipeline rather than by truck. Pipelines require ground disturbance but the total amount is small and the time of disturbance is short until the trenches can be filled and re‐vegetated. Furthermore, pipelines can be built with an assortment of safety features such as automatic cutoff valves along the pipeline to isolate the line if pressures drop (indicating a leak) and trip‐wires laid on top of the pipelines that will break if the pipeline is severed by earth‐moving equipment. Like traffic, noise can be reduced by use of these fewer horizontal wells. If a shale gas field only has one‐quarter the number of wells, noise and dust from drilling and equipment will be much less. These impacts can be further reduced as required by mitigation strategies such as sound walls and praying gravel roads with dust‐suppressant during dry periods. Then again, dust and noise are not issues in most rural locations, and mitigation may not be needed. Other potential environment impacts from drilling can also be alleviated. Wastes such as used mud and produced water are managed by routine, on‐site containment of these fluids as described in the next section. Refuse volume and other possible impacts can be further cut by reducing the number of wells and locating the wells on the same pad or nearby pads. Co‐locating multiple wells on the same pad will encourage the use of closed mud systems to maintain mud quality from well to well and cut down on waste by re‐using mud. The use of steel tanks for mud management allows the operator to segregate specialty


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muds that might only be used over short intervals and then the tank can be moved to another well. Because the shale contains few water zones and is prone to damage during mud‐drilling, some Marcellus wells are drilled with air; in addition, air drilling is considerably faster. Air drilling is not appropriate in all locations, but when it is, it generates a low volume of dry drilling wastes that can be more easily managed than wet refuse. Fluid Management A variety of waste fluids are generated on site at shale gas wells. During drilling, used mud and saturated cuttings are produced and must be managed. The volume of mud roughly correlates with the size of the well drilled, so a horizontal Marcellus well may generate twice as much drilling waste as a single vertical well; however, as discussed above, it will replace four such holes. Drilling wastes can be managed onsite either in pits or in steel tanks. Each pit is designed to keep liquids from infiltrating vulnerable water resources. On‐site pits are a standard in the oil and gas industry but are not appropriate everywhere; they can be large and they disturb the land for an extended period of time. Steel tanks may be required to store drilling mud in some environments to minimize the size of the well site “footprint” or to provide extra protection for a sensitive environment. Steel tanks are not, of course, appropriate in every setting either. In rural areas where space is available at the well site for pits or ponds, steel tanks are usually not needed. Horizontal drilling development has the power to reduce the number of well sites and to group them so that management facilities such as storage ponds can be used for several wells. Make‐up water is used throughout the development process to drill the well and to form the basis of the hydraulic fracturing fluid. Large volumes of water may be needed and are often stored at the well site in pits or tanks. For example, surface water can be piped into the pit during high‐water runoff periods and used during the year for drilling and fracture treatments in nearby wells. After a hydraulic fracture treatment, when the pumping pressure has been relieved from the well, the water‐based fracturing fluids begin to flow back through the well casing to the wellhead. This water is referred to as flowback water and consists of spent fracturing fluids and, in some cases, dissolved constituents from the formation itself (minerals present in the shales as well as brine waters that may be present within any natural pore space contained in the shale). The majority of flowback water is produced in a range of time from several hours to a couple of weeks. In


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various basins and shale gas plays, the extent of this volume of flowback water may account for less than 30% to more than 70% of the original fracture fluid volume. In some cases, production of flowback water can continue for several months after gas production has begun. Natural formation waters that flow to the well are known as produced water. Regardless of the source of water, flowback or formation water, these waters that are produced back through the wellhead with the gas represent a production stream that must be managed and are collectively referred to as produced water. Gas shale operators manage produced water through a variety of mechanisms including: underground injection, treatment and discharge, and recycling. Underground injection is not possible in every play area as suitable injection zones may not be available. Similar to a producing reservoir, there must be a porous and permeable formation capable of receiving injected fluids near the play area. If such is not locally available, it may be possible to transport the produced water to a more distant injection site. Treatment of produced waters may be feasible through either self‐contained systems at well sites or fields or through municipal waste water treatment plants or commercial treatment facilities. The availability of municipal or commercial treatment plants may be limited to larger urban areas where treatment facilities with sufficient available capacity already exist; as in underground injection, transportation to treatment facilities may or may not be practical.


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Shale Gas in the United States

Shale Gas in the United States Overview Shale gas in the United States is rapidly increasing as a source of natural gas. Led by new applications of hydraulic fracturing technology and horizontal drilling, development of new sources of shale gas has offset declines in production from conventional gas reservoirs, and has led to major increases in reserves of U.S. natural gas. Largely due to shale gas discoveries, estimated reserves of natural gas in the United States in 2008 were 35% higher than in 2006. In 2008, shale gas fields included the #2 (Barnett/Newark East) and #13 (Antrim) sources of natural gas in the United States in terms of gas volumes produced. The economic success of shale gas in the United States since 2000 has led to rapid development of shale gas in Canada, and, more recently, has spurred interest in shale gas possibilities in Europe, Asia, and Australia.


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Figure 10: U.S. Shale Gas Plays

Source: U.S. DOE


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History of the Industry The first commercial gas well drilled in the U.S., in 1821 in Fredonia, New York, was a shale gas well producing from the Devonian Fredonia Shale. Soon many shale gas wells were drilled in the area, and the gas used for domestic use and for street lamps. After the Drake Oil Well in 1859, however, shale gas production was overshadowed by much larger volumes produced from conventional gas reservoirs. In 1996, shale gas wells in the United States produced 0.3 TCF (trillion cubic feet), 1.6% of U.S. gas production; by 2006, production had more than tripled to 1.1 TCF per year, 5.9% of U.S. gas production. By 2005 there were 14,990 shale gas wells in the U.S.. A record 4,185 shale gas wells were completed in the U.S. in 2007. Shale Gas Production & Reserves U.S. shale gas production has grown rapidly in recent years as the natural gas industry has improved drilling and extraction methods while increasing exploration efforts. U.S. shale production was 2.02 trillion cubic feet (TCF) in 2008, a jump of 71% over the previous year. In 2009, U.S. shale gas production grew 54% to 3.11 Tcf, while remaining proved U.S. shale reserves at year‐end 2009 increased 76% to 60.6 TCF. In its Annual Energy Outlook for 2011, the U.S. Energy Information Administration (EIA) more than doubled its estimate of technically recoverable shale gas reserves in the U.S., to 827 Tcf from 353 Tcf, by including data from drilling results in new shale fields such as the Marcellus, Haynesville and Eagle Ford shales. Shale production is projected to increase from 14% of total U.S. gas production in 2009 to 45% by 2035. The top shale‐gas sources of production in 2009 were (in descending order) the Barnett Shale (1,745 billion cubic feet (BCF)), the Fayetteville Shale (527 BCF), the Haynesville Shale (321 BCF), the Woodford Shale (249 BCF) and Antrim Shale (132 BCF). The availability of large shale gas reserves in the U.S. has led some to propose natural gas‐fired power plants as lower‐carbon emission replacements for coal plants, and as backup power sources for wind energy.


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Major Shale Gas Production Regions

Figure 11: Major Shale Basins in the Conterminous United States

Source: U.S. DOE

Antrim Shale, Michigan The Antrim Shale of Upper Devonian age produces along a belt across the northern part of the Michigan Basin. Although the Antrim Shale has produced gas since the 1940s, the play was not active until the late 1980s. During the 1990s, the Antrim became the most actively drilled shale gas play in the U.S., with thousands of wells drilled. To date, the shale has produced more than 2.5 TCF from more than 9 thousand wells. Antrim Shale wells produced almost 140×10^9 cu ft (4.0×109 m3) in 2006. The shale appears to be most economic at depths of 1,000‐2,000 feet. Wells are developed on 80‐acre (320,000 m2) units. Horizontal drilling is not widely used. Unlike other shale gas plays such as the Barnett Shale, the natural gas from the Antrim appears to be biogenic gas generated by the action of bacteria on the organic‐rich rock.


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In 2008, the Antrim gas field produced 136 billion cubic feet of gas, making it the 13th largest source of natural gas in the United States.


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Barnett Shale, Texas The Barnett Shale of the Fort Worth Basin is the most active shale gas play in the United States. The first Barnett Shale well was completed in 1981 in Wise County. Drilling expanded greatly in the past several years due to higher natural gas prices and use of horizontal wells to increase production. In contrast to older shale gas plays, such as the Antrim Shale, the New Albany Shale, and the Ohio Shale, the Barnett Shale completions are much deeper (up to 8,000 feet). The thickness of the Barnett varies from 100 to 1,000 feet (300 m), but most economic wells are located where the shale is between 300 and 600 feet (180 m) thick. The success of the Barnett has spurred exploration of other deep shales. In 2008, the Barnett shale (Newark East) gas field produced 1.11 trillion cubic feet of gas, making it the second‐largest source of natural gas in the United States. The Barnett shale currently produces more than 6% of U.S. natural gas production. Caney Shale, Oklahoma The Caney Shale in the Arkoma Basin is the stratigraphic equivalent of the Barnett Shale in the Ft. Worth Basin. The formation has become a gas producer since the large success of the Barnett play. Conesauga Shale, Alabama Wells are currently being drilled to produce gas from the Cambrian Conasauga shale in northern Alabama. Activity is in St. Clair, Etowah, and Cullman counties.


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Devonian Shales, Appalachian Basin

Figure 12: Devonian Shale Cross Section

Source: USGS


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Figure 13: Devonian Shale Undiscovered Resource Potential

Source: USGS

Chattanooga and Ohio Shales The upper Devonian shales of the Appalachian Basin, which are known by different names in different areas have produced gas since the early 20th century. The main producing area straddles the state lines of Virginia, West Virginia, and Kentucky, but extends through central Ohio and along Lake Erie into the panhandle of Pennsylvania. More than 20,000 wells produce gas from Devonian shales in the basin. The wells are commonly 3,000 to 5,000 feet (1,500 m) deep. The shale most commonly produced is the Chattanooga Shale, also called the Ohio Shale. The U.S.


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Geological Survey estimated a total resource of 12.2 trillion cubic feet (350 km3) of natural gas in Devonian black shales from Kentucky to New York. Marcellus Shale The Marcellus shale in West Virginia, Pennsylvania, and New York, once thought to be played out, is now estimated to hold 168‐516 TCF still available with horizontal drilling. It has been suggested that the Marcellus shale and other Devonian shales of the Appalachian Basin, could supply the northeast U.S. with natural gas. In November 2008, Chesapeake Energy, which held 1.8 million net acres of oil and gas leases in the Marcellus trend, sold a 32.5% interest in its leases to Statoil of Norway, for $3.375 billion.

Figure 14: Marcellus Shale Formation Thickness

Source: USGS


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Fayetteville Shale, Arkansas The Mississippian Fayetteville Shale produces gas in the Arkansas part of the Arkoma Basin. The productive section varies in thickness from 50 to 550 feet (170 m), and in depth from 1500 to 6,500 feet (2,000 m). The shale gas was originally produced through vertical wells, but operators are increasingly going to horizontal wells in the Fayetteville. Producers include SEECO a subsidiary of Southwestern Energy Co. who discovered the play, Chesapeake Energy, Noble Energy Corp., XTO Energy Inc., Contango Oil & Gas Co., Edge Petroleum Corp., Triangle Petroleum Corp., and Kerogen Resources Inc. Floyd Shale, Alabama The Floyd Shale of Mississippian age is a current gas exploration target in the Black Warrior Basin of northern Alabama and Mississippi. Gothic Shale, Colorado Bill Barrett Corporation has drilled and completed several gas wells in the Gothic Shale. The wells are in Montezuma County, Colorado, in the southeast part of the Paradox basin. A horizontal well in the Gothic flowed 5,700 MCF per day. Haynesville Shale, Louisiana Although the Jurassic Haynesville Shale of northwest Louisiana has produced gas since 1905, it has been the focus of modern shale gas activity only since a gas discovery drilled by Cubic Energy in November 2007. The Cubic Energy discovery was followed by a March 2008 announcement by Chesapeake Energy that it had completed a Haynesville Shale gas well. Haynesville shale wells have also been drilled in northeast Texas, where it is also known as the Bossier Shale. New Albany Shale, Illinois Basin The Devonian‐Mississippian New Albany Shale produces gas in the southeast Illinois Basin in Illinois, Indiana, and Kentucky. The New Albany has been a gas producer in this area for more than 100 years, but recent higher gas prices and improved well completion technology have increased drilling activity. Wells are 250 to 2,000 feet


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(610 m) deep. The gas is described as having a mixed biogenic and thermogenic origin. Pearsall Shale, Texas Operators have completed approximately 50 wells in the Pearsall Shale in the Maverick Basin of south Texas. The most active company in the play has been TXCO Resources, although EnCana and Anadarko Petroleum have also acquired large land positions in the basin. The gas wells had all been vertical until 2008, when TXCO drilled and completed a number of horizontal wells. Utica Shale, New York In October 2009, the Canadian company Gastem, which has been drilling gas wells into the Ordivician Utica Shale in Quebec, drilled the first of its three state‐permitted Utica Shale wells in New York. The first well drilled was in Otsego County. Woodford Shale, Oklahoma The Devonian Woodford Shale in Oklahoma is from 50 to 300 feet (91 m) thick. Although the first gas production was recorded in 1939, by late 2004, there were only 24 Woodford Shale gas wells. By early 2008, there were more than 750 Woodford gas wells. Like many shale gas plays, the Woodford started with vertical wells, then became dominantly a play of horizontal wells. The play is mostly in the Arkoma Basin of southeast Oklahoma, but some drilling has extended the play west into the Anadarko Basin and south into the Ardmore Basin. The largest gas producer from the Woodford is Newfield Exploration; other operators include Devon Energy, Chesapeake Energy, Cimarex Energy, Antero Resources, St. Mary Land and Exploration, XTO Energy, Pablo Energy, Petroquest Energy, Continental Resources, and Range Resources. DOE/NETL Research Program DOE’s National Energy Technology Laboratory (NETL) administers an Environmental Program that aims to find solutions to environmental concerns by focusing on the following program elements:


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1. Produced water and fracture flowback water management, particularly in gas shale development areas; 2. Water resource management in oil and gas basins; 3. Air quality issues associated with oil and gas exploration and production (E&P) activities; 4. Surface impact issues associated with E&P activities; 5. Water resource management in Arctic oil and gas development areas; 6. Decision making tools that help operators balance resource development and environmental protection; and 7. Online information and data exchange systems that support regulatory streamlining. There are currently 27 extramural projects in the Environmental Program, with a total value of roughly $32 million (not including participant cost‐share). Approximately $10 million of this total is directed toward projects led by industry, $9 million to projects led by universities, $11 million to state agencies and national non‐profit organizations, and $2 million to national laboratories for technical support to other project partners. The project portfolio is balanced between projects focused on technology development, data gathering, and development of data management software and decision support tools.


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Role of Shale Gas in Unconventional Gas in the U.S. A key factor in this increase in production from unconventional resources has been the development of shale gas. The lower forty‐eight states have a wide distribution of highly organic shales capable of containing vast resources of natural gas. This potential for production in the twenty‐one known onshore shale basins, coupled with other unconventional gas plays, is expected to contribute significantly to the U.S. domestic energy outlook.

Figure 15: U.S. Unconventional Gas Outlook

Source: ALL Consulting

Three factors have come together in recent years to make shale gas production economically viable: technological advances in 1) horizontal drilling and 2) hydraulic fracturing, plus 3) rapid increases in natural gas prices as a result of


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significant supply and demand pressures. Horizontal drilling and hydraulic fracturing have not only dramatically improved daily production rates, but have increased the total ultimate recovery potential of individual wells to as high as 54% in one experimental case in Texas. Without these advances in the pre‐existing technology, many unconventional natural gas plays would not be economical. As recently as the late 1990s, only 40 drilling rigs (6%) in the U.S. were capable of onshore horizontal drilling; that number grew to 519 rigs (28%) by May of 2008. Since 1998, annual production has consistently exceeded EIA’s forecasts of unconventional gas production. A great deal of this increase is attributable to shale gas production, particularly from the Barnett Shale in Texas. Already, the fledgling Barnett Shale play in Texas produces 6% of all natural gas produced in the lower forty‐eight states.24 The potential for most other shale gas plays in the U.S. is just emerging. Taking this into consideration, Navigant (2008) has projected that the U.S. total natural gas resources (proven plus unproven technically recoverable) are 1,680 Tcf to 2,247 Tcf, or 88 to 118 years of production at 2008 production levels. Of that, shale gas is expected to provide 28%, or more of the estimated production. Analysts have estimated that by 2011 most new reserves growth (50 to 60% or approximately 3 Bcf/d) will come from unconventional shale gas reservoirs. Total annual production volumes of 3 to 4 Tcf may be sustainable for decades. An additional benefit of shale gas plays is that many exist in areas previously developed for natural gas production and, therefore, much of the necessary pipeline infrastructure is already in place. Many of these areas are also near the nation’s population centers thus facilitating transportation to consumers. Regulatory Framework Development of the Marcellus Shale will be subject to regulation under several federal and state laws. In particular, the large volumes of water needed to drill and hydraulically fracture the shale, and the disposal of this water and other wastewater associated with gas extraction may pose significant water quality and quantity challenges that trigger regulatory attention. As the U.S. Geological Survey noted in a recent publication, “Concerns about the availability of water supplies needed for gas production, and questions about wastewater disposal have been raised by water‐resource agencies and citizens through the Marcellus Shale gas development region.” The following sections review key provisions of two relevant federal laws,


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the Safe Drinking Water Act (SDWA) and the Clean Water Act (CWA), and related state requirements. Quality of Surface Water As previously described, hydraulic fracturing involves injecting water, sand, and chemicals into the shale layer at extremely high pressures in order to release the trapped natural gas. It is a water‐intensive practice. Typical projects use 1‐3 million gallons of water for each well and 0.5 million pounds of sand. Large projects may require up to 5 million gallons of water. The Texas Railroad Commission estimates that fracturing a vertical well in the Barnett Shale in Texas can use more than 1.2 million gallons of water, while fracturing a horizontal well can use more than 3.5 million gallons. Moreover, the wells may be re‐fractured several times, thus requiring additional water. Fracturing operations use an estimated 5 or more million gallons of water each day in the Barnett Shale, a smaller natural gas field in Texas. Regarding the Marcellus Shale region, the USGS observed “many regional and local water management agencies are concerned about where such large volumes of water will be obtained, and what the possible consequences might be for local water supplies.” Some of the injected fluids remain trapped underground, but the majority of the injected water— 60% to 80%—returns to the surface as “flowback” after the frac treatment. It typically contains proppant (sand), chemical residue, and trace amounts of radioactive elements that naturally occur in many geologic formations. USGS notes that because the quantity of fluid used is so large, the additives in a three million gallon frac job would yield about 15,000 gallons of chemicals in the waste. The well service company may temporarily retain the flowback and brine in open‐air, lined retention ponds before reusing it (if possible), or disposing it. The drilling operator must reclaim the temporary storage pits when the drilling and fracturing operations end. In addition, the well operator must separate, treat, and dispose the natural brine co‐produced with gas. As noted below, where feasible, the produced water may be disposed through underground injection. The oil and gas industry uses this disposal method in some western states and in Ohio. The industry has not yet begun using it as a disposal alternative for gas production in eastern Marcellus Shale.


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In the event that underground injection is not feasible in the area of the Marcellus Shale, the well service company may discharge the flowback to surface waters if the discharge does not violate a stream or lake’s water quality standards. Standards established by states under Section 303 of the Clean Water Act (CWA) protect designated beneficial uses of surface waters, such as recreation or public water supply. If contaminants present in the flowback prevent discharge to surface water without further treatment, it is likely that the service company will have to transfer the wastewater off‐site to an industrial treatment facility or a municipal sewage treatment plant that is capable of handling and processing the wastewater. In this case, the operator of the publicly owned treatment works (POTW) or industrial treatment facility would assume responsibility for treating the waste before discharging it into nearby receiving water in compliance with effluent limits contained in the facility’s discharge permit. The chemical frac additives returned in flowback and the produced brine could cause problems for POTWs. Contaminants in industrial process wastewaters can kill off the biota essential to a POTW’s operation. If contaminants pass through the POTW without adequate treatment, the discharge could violate the facility’s discharge permit and could cause a violation of water quality standards. A standard POTW’s effective treatment of flowback and brine is uncertain. It could require upgrading, but the cost of such an upgrade is also uncertain. In the fall of 2008, water samples from the mid‐Monongahela River valley of Pennsylvania showed high levels of total dissolved solids (TDS), which indicate salinity. Although the TDS was determined to pose little threat to health or safety, preliminary analysis suggested that the principal source was large truck deliveries of wastewater from gas well drilling sites in the Marcellus Shale to POTWs discharging, directly or indirectly, into the Monongahela River. In October 2008, state officials ordered nine sewage treatment plants to reduce their volumes of gas well drilling water, which contains high concentrations of TDS. Subsequent analysis concluded that discharge from abandoned mines was more responsible for the high TDS than drilling wastewater discharges from municipal wastewater treatment plants.


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However, state officials remain concerned about the projected need for treatment of wastewater (both initial flowback water from fracturing and longer term production brines) from gas well development—projected to be as much as 20 million gallons per day in 2011—and the capacity of the state’s surface waters to assimilate associated wastewaters. In April 2009, the Pennsylvania Department of Environmental Protection issued a permitting strategy document for gas development wastewaters, requiring that any discharges will be subject to the most stringent treatment or water quality standards needed to protect aquatic life in the state’s streams. Their goal is prohibiting new sources of high‐TDS wastewaters from discharging into Pennsylvania’s waters by January 1, 2011. Brine storage and transport are major issues in developing the Barnett Shale in Texas, and are likely to be key issues in development of the Marcellus Shale, as well. Currently, permitted treatment facilities capable of treating such wastes are not adequate. In Pennsylvania, there are five facilities designed to treat the type of industrial wastewater that is involved in producing shale gas. Most of the well sites are located in northeast Pennsylvania, while the closest treatment facilities are nearly 250 miles away. West Virginia, too, recognizes that wastewater disposal is “perhaps the greatest challenge regarding these operations.” State officials say that underground injection control may be the best option for wastewater disposal, but the state has only permitted two commercial underground injection control (UIC) wells. The state has no centralized commercial treatment facilities available, and state officials are cautious about the capability of POTWs to handle the flow and quality of waste that they might receive. The West Virginia Department of Environmental Protection has proposed both changes to the state’s oil and gas drilling rules (which the state legislature must approve) and an industry guidance document to assist operators in planning for the water issues associated with drilling and operating these wells. However, local groups have criticized the proposed rules and draft non‐binding guidance for failing to address disposal of wastewater, disclosure of chemicals used in hydraulic fracturing, and where the additional quantities of water required for drilling will come from. One potential solution to off‐site disposal may be on‐site treatment and reuse; that is, treating and reusing flowback and produced water on‐site. Some companies are reportedly considering on‐site treatment options such as advanced oxidation and


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membrane filtration processes. On‐site treatment technologies may be capable of recovering 70%‐80% of the initial water to potable water standards, thus making the water immediately available for reuse. The remaining 20%‐30% is very brackish and considered brine water. A portion may be further recoverable as process water, but not to achieve potable water standards. In other cases, companies send the brine water off‐site for treatment and disposal. The economics of any such options are critical, and site factors such as available power and final water quality are often the determinant in treatment selection. Surface Water Quality Issues Another potential source of water pollution from oil and gas drilling sites is runoff that occurs after a rainstorm. The storm water runoff can transport sediment to nearby surface water bodies. Provisions of the CWA generally regulate storm water discharges from industrial and municipal facilities by requiring implementation of pollution prevention plans and, in some cases, remediation or treatment of runoff. Industries that manufacture, process, or store raw materials and that collect or convey storm water associated with those activities are subject to the act’s requirements. Furthermore, fracturing fluid chemicals and wastewater can leak or spill from injection wells, flow lines, trucks, tanks or holding pits and thus may contaminate soil, air, and water resources. However, the act specifically exempts the oil and gas industry from these storm water management regulatory provisions. CWA Section 402(l)(2) exempts mining operations or oil and gas exploration, production, processing, or treatment operations or transmission facilities from federal storm water regulations, and Section 502(24) extends the exemption to construction activities, as well. Thus, federal law contains no requirements to minimize uncontaminated sediment pollution from the construction or operation of oil and gas operations. However, the federal exemption does not hinder states from requiring erosion and sedimentation controls at well sites, under authority of non‐federal law. Pennsylvania, for example, requires well drill operators to obtain a permit for implementation of erosion and sedimentation controls, including storm water management, if the site disturbance area is more than five acres in size. If the site is less than five acres, a plan for erosion and sediment control is required. Storm water requirements are part of this permit. New York has similar requirements for erosion and sedimentation controls at well sites, regardless of site area. The Delaware River Basin Commission, which


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has jurisdiction over water quality in a portion of the area underlain by the Marcellus Shale also has similar requirements regardless of site area. Protecting the Groundwater Because development of the Marcellus Shale is dependent on the use of hydraulic fracturing, some fear it could potentially contaminate underground aquifers that provide water supplies to private wells and public water systems. The Safe Drinking Water Act in 2005 broadly excluded the underground injection of fluids used in hydraulic fracturing for oil and gas development. However, the SDWA does not preempt states from imposing their own laws and regulations, and the states have long been responsible for protecting groundwater resources during oil and gas production activities. For example, in New York, the Department of Environmental Conservation (DEC) has authority over oil and gas development in the state, including oversight of hydraulic fracturing activities to ensure protection of groundwater resources. Although federal laws do not regulate the injection of hydraulic fracturing fluids, states such as Pennsylvania and New York do require submission of information on hydraulic fracturing fluid composition prior to issuing a well permit. Moreover, other injection wells related to oil and gas development may be subject to federal requirements. Safe Drinking Water Act Authority The underground injection control provisions of the SDWA require the Environmental Protection Agency (EPA) to regulate the underground injection of fluids (including solids, liquids, and gases) to protect underground sources of drinking water. UIC program regulations specify sitting, construction, operation, closure, financial responsibility, and other requirements for owners and operators of injection wells. West Virginia, Ohio, and Texas are among the states that have assumed primacy and have lead implementation and enforcement authority for the UIC program, including primacy for injection wells associated with oil and gas development. EPA implements the programs directly for New York and Pennsylvania.77 Most states, including Ohio and West Virginia, have received primacy for Class II oil and gas wells under Section 1425.


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The Safe Drinking Water Act specifies that the UIC regulations may not interfere with the underground injection of brine or other fluids brought to the surface in connection with oil and gas production or any underground injection for the secondary or tertiary recovery of oil or natural gas. Additionally, the Energy Policy Act of 2005 amended SDWA UIC provisions to specify further that the definition of “underground injection” excludes the injection of fluids or propping agents (other than diesel fuels) used in hydraulic fracturing operations related to oil, gas, or geothermal production activities. The key statutory provisions are:

• SDWA Section 1421 directs EPA to promulgate regulations for state underground injection control (UIC) programs, and mandates that the regulations contain minimum requirements for programs to prevent underground injection that endangers drinking water sources;

• Section 1422 authorizes EPA to delegate primary enforcement authority

(primacy) for UIC programs to the states, provided that state programs prohibit any underground injection that is not authorized by a state permit;

• Section 1425 provides separate authority for states to attain primacy

specifically for oil and gas (i.e., Class II) wells. The provision allows states to demonstrate that their existing programs for oil and gas wells are effective in preventing endangerment of underground sources of drinking water, providing an alternative to meeting many of the detailed requirements promulgated to implement the UIC program under Section 1421;

• Section 1431 grants the EPA Administrator emergency powers to issue

orders and commence civil action to protect public water systems or underground sources of drinking water. The Administrator may take action when (1) a contaminant present in or likely to enter a public drinking water supply system or underground drinking water source poses a substantial threat to public health, and (2) state or local officials have not taken adequate action.


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Underground Injection of Waste Fluids As noted, nearly all of the water injected for hydraulic fracturing must come back out of the well for gas to flow out of the shale. A key issue related to Marcellus Shale gas production is safely disposing large quantities of potentially contaminated fluids recovered from the gas wells. EPA generally categorizes injection wells associated with oil and gas production as Class II wells under its UIC regulatory program. These are wells used to inject brines and other waste fluids associated with oil and natural gas production. Given the expense of treating and transporting large volumes of wastewater for disposal, it is possible that the production of gas from the Marcellus Shale will increasingly involve the use of injection wells to dispose of poor‐quality formation water, flowback water resulting from hydraulic fracturing, and other waste fluids associated with gas production. EPA reports that most of the fluid injected into Class II wells has been brine brought to the surface in producing oil and gas. This brine, a naturally occurring formation fluid, is often very saline and may contain toxic metals and naturally occurring radioactive substances. According to EPA, the brine “can be very damaging to the environment and public health if it is discharged to surface water or the land surface.” To prevent contamination of land and surface water, Class II wells provide a means for disposing brines by re‐injecting them back into their source formation or into similar formations. Injection wells also serve as disposal means for residual water from drilling and hydraulic fracturing operations. As states have adopted rules to prevent the disposal of saline water to surface water and soil, injection has become the preferred way to dispose of this waste fluid, where the local geology permits. In New York and Pennsylvania, both EPA and the state environmental agency must issue permits if the disposal method for fracturing wastewater is deep well injection. Pennsylvania law provides that “a well operator who affects a public or private water supply by pollution or diminution shall restore or replace the affected supply with an alternate source of water adequate in quantity and quality for the purposes served by the supply.” Additionally, it requires a permit application for a disposal well or enhanced recovery well to include an erosion and sedimentation plan for the well site.


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As of now, it is unknown how much water the gas wells in the Marcellus Shale formation will produce. The amount of water produced could vary across the region. Because shale gas formations generally are impermeable, they typically produce much less water than traditional oil and gas fields or coalfields. The impermeability of the shale also indicates that reinjection of wastewater from fracturing into the shale formation may not be feasible in many locations. Consequently, it is uncertain whether Class II disposal wells will find wide use in the Marcellus Shale formation. Currently, only four injection wells operate for this purpose in Pennsylvania. Wastewater injection into the permeable Cambrian sandstones that lie beneath the Marcellus Shale appears feasible. The Cambrian Mt. Simon Sandstone, considered an ideal geologic unit in Ohio for disposal and long‐term storage of liquid wastes, is relatively deep, and underlain and overlain by impervious confining layers that prevent migration of injected fluids. Although underground injection of wastewater may not be practical or economic in all areas across the Marcellus region because of the lack of suitable injection zones, the cost and environmental concerns associated with surface disposal may make Class II injection wells the preferred disposal option for flowback and other wastewater from hydraulic fracturing operations where feasible. This appears to be the trend in other shale areas. In the Fayetteville Shale in Arkansas, trucks have typically collected wastewater and hauled it to disposal wells distant from the producing areas. However, with more intense shale development, the high cost of transporting, treating, and disposing water offsite, injection well use has increased. In the Barnett Shale in Texas, flowback water has been primarily disposed in Class II injection wells. Both Class II injection and municipal and industrial water treatment facilities are under consideration for the Marcellus Shale, and more than 60 permit applications for such wells are pending in New York for Marcellus Shale development. One firm active in Marcellus Shale development has been disposing of flowback water and produced water using three UIC disposal wells and two commercial water treatment facilities, but reportedly plans to use only disposal wells in the future. Based on leases already held, the firm plans to drill between 13,500 and 17,000 gas wells. Technical and practical questions regarding the development of the Marcellus Shale remain unanswered. USGS researchers have noted that while drilling and hydraulic


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fracturing technologies have improved over the past several decades, “the knowledge of how this extraction might affect water resources has not kept pace.” Consequently, environmental regulators and gas developers face new challenges and some uncertainties as the Marcellus Shale is developed. State Water Quality Laws State laws addressing the quality of surface water and groundwater also appear to apply to Marcellus Shale development. For example, in New York various aspects of such development would require a permit under the State Pollutant Discharge Elimination System (SPDES).94 SPDES is an “approved,” rather than delegated, version of the federal National Pollutant Discharge Elimination System (NPDES) permit program because, while the federal NPDES covers only discharges to surface water, SPDES covers discharges to groundwater also. The SPDES permit requirement could apply to hydraulic fracturing by meeting four conditions:

• Most importantly, the state must determine that injection will not degrade groundwater;

• A wastewater treatment plant would likely dispose of the fluids produced

from the well, in which case the plant’s SPDES permit would apply;

• SPDES permits would also cover treatment facilities built specially for disposing of flowback water, if there would be discharges into a water body; and

• Applicable state water‐quality standards would control, in part, the permit’s

discharge limits. New York State’s Environmental Quality Review Act (SEQRA) is also relevant. As with its federal counterpart, the National Environmental Policy Act, a requirement of an environmental impact statement preparation lies at the heart of the statute. New York has been evaluating the environmental impact of the drilling and hydraulic fracturing activities for more than 15 years through a Generic Environmental Impact Statement (GEIS) that sets parameters that apply statewide for SEQRA review of gas well permitting. In February 2009, the state’s Bureau of Oil and Gas Regulation, in the Department of Environmental Conservation, released the final scoping document under SEQRA for a Supplemental Generic Environmental


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Impact Statement (SGEIS) on developing the Marcellus and other gas shale regions in the state using high‐volume hydraulic fracturing. On September 30, New York DEC released for comment the draft SGEIS which proposes additional parameters for SEQRA review and focuses on water supply protection and wastewater management as major issues. Until New York finalizes the supplemental GEIS, the state will only accept, but not process, permit applications for gas wells involving horizontal drilling and high‐volume hydraulic fracturing. As another example, West Virginia’s NPDES permit program would apply to wastewater treatment plants to which flowback from Marcellus Shale production sites was taken and to treatment facilities built specially for the frac water that discharge into a water body. Applicable state water‐quality standards would control the permit’s discharge limits, in part. However, this program applies to surface water only, not groundwater, and the state’s Groundwater Protection Act exempts “groundwater within geologic formations which are site specific to ... [t]he production ... of ... natural gas.... ” The state’s underground injection control program would regulate frac water re‐injected at a second or subsequent production site. In addition to state water‐quality laws, the interstate Delaware River Basin Commission (36% of whose jurisdictional land area in Pennsylvania and New York overlies the Marcellus Shale formation) would also impose water quality requirements. The Commission’s water quality (and other) requirements are legally separate from those of the affected states—that is, obtaining state approval does not excuse an applicant from seeking Commission approval—though in some cases the two requirements may be substantively identical. Another interstate‐compact‐created commission within the Marcellus region, the Susquehanna River Basin Commission, regulates only water quantity, not water quality. State Water Supply Management Gas producers must arrange to procure the large volumes of water required for hydraulic fracturing in advance of their drilling and development activity. Generally, water rights and water supply regulation differ among the states. Depending on individual state resources and historic development, states may use one of two water rights doctrines, riparian or prior appropriation, or a hybrid of the two. Under


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the riparian doctrine, a person who owns land that borders a watercourse has the right to make reasonable use of the water on that land. Traditionally, the only limit to users under the riparian system is the requirement of reasonableness in comparison to other users. Under the prior appropriation doctrine, a person who diverts water from a watercourse (regardless of his location relative thereto) and makes reasonable and beneficial use of the water may acquire a right to use of the water. The prior appropriation system limits users to the quantified amount of water the user secured under a state permitting process with a priority based on the date the state conferred the water right. Because of this priority system, the phrase “first in time, first in right” has sometimes substituted for appropriative rights. Some states have implemented a dual system of water rights, assigning rights under both doctrines. Generally, states east of the Mississippi River follow a riparian doctrine of water rights, while western states follow the appropriation doctrine. The system of water rights allocation in a particular state with shale resources may affect the development process, particularly in times when shortages in water supply affect the area of shale development. In areas where the Marcellus Shale is located, which are generally riparian states, water rights may not be as big a concern as in other areas of the country with shale development, such as the Barnett Shale in Texas. That is, even in times of shortage, shale development may be able to continue in the Marcellus Shale region because riparian users reduce water usage proportionally and may still receive enough for supply requirements of the development process. On the other hand, appropriative rights users in the Barnett Shale region may not be able to fill their water rights at all if other senior rights take all the water, and thus would have to postpone development. In addition, interstate compacts may apply and affect water supply for shale development processes. In the case of Marcellus Shale development, several interstate compacts are relevant. New York’s SPDES permit program (discussed above) governs water quality only, not water quantity. With a limited exception for pumping water on Long Island, there is no proactive regulatory scheme in New York for extracting water from streams, lakes, groundwater, etc. In the case of drawing water from a public drinking water supplier, however, the state does have limited authority to make sure that the public water supplier stays within its permit terms. Otherwise, however, the state can only respond to water flow problems—e.g., if a fish kill


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occurs, it can prosecute the responsible entity for violating the flow standard that is a component of the state’s water quality standards. There is no requirement to notify the state in advance of a water extraction. West Virginia passed the Water Resources Protection and Management Act in 2003. It requires users of water resources whose withdrawals exceed 750,000 gallons in any given month for one facility to register with the Division of Water and Waste Management in the Department of Environmental Protection. To protect both ground and surface waters, the state proposes to require operators to provide information about the sources of withdrawals, anticipated volumes, and the time of year of withdrawals prior to start‐up.112 State officials believe it is likely that some oil and gas industry operations in the Marcellus Shale region will exceed this threshold and will be required to submit withdrawal information. The goal is to ensure that water withdrawal from ground or surface waters does not exceed volumes beyond what the waters can sustain. Texas is another relevant example, because of similarities between the Barnett Shale there and the Marcellus Shale. Texas has codified the public trust doctrine regarding ownership of state water resources. That is, water in any of the various water bodies ‐ including rivers, streams, lakes, etc.—within the state is the property of the state of Texas. Individuals or entities may divert the state’s waters for their own use only after acquiring a permit (water right) from the state through its Commission on Environmental Quality. Texas does provide for the possibility of temporary water permits for a period of up to three years, if a temporary permit would not adversely affect senior rights. Other states apply surface and groundwater regulations similarly, and gas producers using fresh water for drilling and development must comply with state and local administration of water rights. As for interstate constraints in the Marcellus Shale region and vicinity, the Delaware River Basin Commission and the Susquehanna River Basin Commission impose limits on the quantity of water extracted. In addition, the Great Lakes‐St. Lawrence River Basin Water Resources Compact prohibits inter‐basin transfers of water.


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Shale Gas in Canada

Shale Gas in Canada Overview Recent discoveries of shale gas in Canada have caused a sharp increase in estimated recoverable natural gas in Canada. There are a number of prospective shale gas targets in various stages of exploration and exploitation across the country, from British Columbia to Nova Scotia. Major Shale Gas Production Regions Frederick Brook Shale, New Brunswick In June 2010, Apache Canada began drilling a horizontal well to tap the Lower Carboniferous Frederick Brook Shale, near Sussex, New Brunswick. Apache is in a joint venture with Halifax‐based Corridor Resources Inc., which has extensive leasehold in the province. Corridor has drilled two vertical wells that tested gas from the Frederick Brook. Horton Bluff Shale, Nova Scotia In 2009, Triangle Petroleum Corporation completed two gas wells in the Horton Bluff Shale, of the Windsor Basin, Nova Scotia. Montney Shale, British Columbia The Montney Shale play is in east‐central British Columbia. Muskwa Shale, British Columbia The Devonian Muskwa Shale of the Horn River Basin in northeast British Columbia is said to contain 6×10^12 cu ft (170 km3) of recoverable gas. Major leaseholders in the play are EOG Resources, EnCana Corp., and Apache Corp. The government of British Columbia announced lease proceeds for 2008 to be in excess of CDN$2.2 billion, a record high for the province, with the majority of the proceeds coming from shale gas prospects. The British Columbia government has


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Shale Gas in Canada

granted royalty credits to companies for drilling and infrastructure development in the area. Muskwa formation shale gas contains between 10% to 12% carbon dioxide, which must be removed before the gas is marketed. Utica Shale, Quebec The Ordovician Utica Shale in Quebec potentially holds 4×10^12 cu ft (110 km3) at production rates of 1 MMCF per day. From 2006 through 2009 24 wells, both vertical and horizontal, were drilled to test the Utica. Positive gas flow test results have been reported, although none of the wells had been put on production at the end of 2009. Gastem, one of the Utica shale producers, has announced plans to explore for Utica Shale gas across the border in New York state. The Utica shale is a black calcareous shale, from 150 to 700 feet (210 m) thick, with from 3.5% to 5% by weight total organic carbon. The Utica Shale play focuses on an area south of the St. Lawrence River between Montreal and Quebec City. Interest has grown in the region since Denver‐based Forest Oil Corp. announced a significant discovery there after testing two vertical wells. Forest Oil said its Quebec assets may hold as much as four trillion cubic feet of gas reserves, and that the Utica shale has similar rock properties to the Barnett shale in Texas. Quebec has been known to have natural gas reserves, but advanced horizontal drilling techniques and higher gas prices are only now making the play potentially economically viable, observers say. Forest Oil, which has several junior partners in the region, has drilled both vertical and horizontal wells. Calgary‐based Talisman Energy has drilled five vertical Utica wells, and began drilling two horizontal Utica wells in late 2009 with its partner Questerre Energy, which holds under lease more than 1 million gross acres of land in the region. Other companies in the play are Quebec‐based Gastem and Calgary‐based Canbriam Energy.


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Impact of Gas Shales on the LNG Industry

Impact of Gas Shales on the LNG Industry Introduction The year 2008 marked an important turning point in the U.S. natural gas market. Formerly obscure resources such as the Haynesville and Marcellus shales have come to the forefront of the global natural gas industry and look set to become a transformational resource for the market. BG Group, from its position as a leading importer of LNG into the U.S. market over the period 2002 to the present, a leading global LNG player and as a recent entrant into U.S. unconventional gas production is uniquely placed to comment on both sides of this emerging “competition”. Comparing the LNG Market with Gas Shale Market The LNG industry has in recent years been undergoing a structural evolution. Based on recent trade figures the evolution of the LNG industry has clearly continued apace over the past three years. Based on recent industry data the industry has witnessed:

• A continued trend towards globalization of LNG trade with cargoes moving over increasing distances.;

• We have seen spot and short‐term trades grow to just over 30 million tons in

2008, representing 18% of total trade;

• We have seen trade between the Atlantic and Pacific Basins reach all time highs in 2008 at just below 15 MTPA;

• We have seen the emergence of numerous new trades and markets in the

past three years – most notably China, but also in South America and the Middle East. Some of these markets have emerged more rapidly than we had previously envisioned via fast‐track regasification solutions;


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• We have seen an increasing use of hub‐related pricing for LNG volumes, both in the U.S. and in Northern Europe;

• We have seen increasing flexibility of LNG volumes at the margin of the trade

‐ both in respect of commercial terms, as Master Sales Agreements (MSA) become widely established, and availability of infrastructure and shipping.

However just when everything seemed to be progressing as forecast by industry analysts, the emergence of a potential “game‐changer” for the LNG industry ‐ “unconventional gas” has come forth in North America, or more particularly shale gas, which has over the past few years been undergoing what has been called its own “quiet revolution” in the North American market‐place. After a decade of steady growth, U.S. natural gas production started a period of steady decline in 2002, decreasing by two percent per annum on average over the period to 2006. It was generally accepted that the U.S. upstream industry was “running faster to stand still” as new production wells from conventional sources showed an increasing rate of decline. By 2006 the annual decline rate of U.S. gas production was 20% to 30% (depending upon method of calculation). This meant that the U.S. had to drill enough wells to replace almost one third of its gas production each and every year just to maintain supplies at a constant level. The decline in production was brought to the attention of the nation as early as mid‐2003 when Alan Greenspan highlighted it in testimony to the Committee on Energy and Commerce at the U.S. House of Representatives In his speech he suggested that “improving technologies have also increased the depletion rate of newly discovered gas reservoirs, placing a strain on supply that has required increasingly larger gross additions from drilling to maintain any given level of dry gas production” and that “if North American natural gas markets are to function with the flexibility exhibited by oil, unlimited access to the vast world reserves of gas is required.”


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Figure 16: U.S. Natural Gas Supply Outlook

Source: EIA

Investment Boom in LNG Facilities This unleashed an investment boom in U.S. LNG import facilities in the subsequent years. The first indications of the “quiet revolution” underway in the U.S. gas market came in 2006, when contrary to expectations dry natural gas production figures started to show modest growth (2.5% year‐on‐year). A 3.2% increase in growth was seen in 2007, but the main increment was seen in 2008 with a 6.7% jump in annual production. So quickly was the rate changing that the Energy Information Administration (EIA) had to revise its production figures upwards between its Annual Energy Outlook in June 2008 and its Short‐term Energy Outlook in October 2008. Much of the increase in production was noted to have come from unconventional production, mainly shale gas, which had clearly started to more than balance the reduction from conventional sources and was expected to increase significantly over time.


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LNG versus Shale Gas Although there are still some aspects of shale gas production yet to be fully resolved, primarily the extent to which it is environmentally regulated, there is now general consensus that its impact on the North American market will be significant. CERA argued in a recent market commentary that the “shale gale” is a game changer for the U.S. fuel market which “transforms the debate over generating electricity”. They observe that “the U.S. electric power industry faces very big questions about fuel choice and what kind of new generating capacity to build” and that “some areas such as Pennsylvania and New York, traditionally importers of the bulk of their energy from elsewhere, will instead become energy producers.” They also hypothesize that “it could also mean that more buses and truck fleets will be converted to natural gas” and that “energy‐intensive manufacturing companies, which have been moving overseas in search of cheaper energy in order to remain globally competitive, may now stay home”. In addition to being a transformational resource for the U.S. energy market, the emergence of shale gas will also be a game‐changer for global LNG.


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Changing Industry Perception It is probably fair to say that there has been a changing perception of the U.S. market by LNG suppliers in the past three years. A number of shifting elements have, in combination, moved it from being perceived as an “engine of growth” to what has been termed a “market of last resort.” In 2004 many new projects were being underpinned wholly, or in part, by the U.S. market. These included: Atlantic LNG Train 4, Equatorial Guinea LNG, Tangguh LNG in Indonesia, RasGas (2 Trains), Qatargas (2 Trains), Norway’s Snohvit LNG, Sakhalin LNG in Russia, Angola LNG, and Nigeria’s Brass LNG ‐ in short North America was playing an important role in pulling through almost all new supply projects at that time. With the start of the rapid rise in commodity prices in 2006 there were two concurrent effects take place which impacted this status. New LNG supply projects under construction started to delay as engineering, procurement and construction contractor tightness and a changing cost base weighed heavily on delivery schedules. Dealing with Market Shortage This tightened the market as LNG buyers, particularly those in Asia, sought replacement volumes. At the same time rapidly rising crude oil prices caused oil‐linked LNG prices in Asia and Europe to rise to record levels in relation to U.S. Henry Hub prices, thus increasing the pull of these markets on U.S. volumes. The growing market tightness was exacerbated by the shut‐down of the Tokyo Electric Power Co.’s Kashiwazaki‐Kariwa nuclear facility in mid‐2007 following an earthquake in the region. In theory the sudden flow of LNG out of the U.S. market (~2.0 Bcf/d equivalent) during what was a period of extreme global supply tightness should have moved the U.S. market price upwards. However, the Henry Hub price instead moved downwards in relation to U.S. Gulf Coast (USCG) 1% Residual Fuel Oil (1% FO) which many at the time thought had become a representative pricing point for LNG in the U.S. market, and has subsequently traded at an on‐going discount to USGC 1%FO since that date.


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In retrospect what we were probably seeing in 2007 was the impact of increasing shale production on the market, allowing the U.S. market to start to de‐link from the impacts of global pricing. Despite the significant volume withdrawal LNG was not missed by the market ‐ which did not send the price signals necessary to attract LNG volumes back. These changing fundamentals led to a period of industry speculation as to how LNG and shale would impact each other, particularly once the global economic recession of 2008 started to erode industrial gas demand worldwide and it became apparent that LNG would once again likely have to find its way back into the U.S. market in meaningful quantities. The industry was rife with speculation that the “tsunami” of LNG that was about to hit the U.S. market would either cause shale gas producers to have to shut‐in, or LNG producers to have to mothball production. The Zeitgeist of late 2008 was summed up one commentator who said that although “the U.S. no longer needed LNG, LNG needed the U.S..” Although the much heralded LNG wave was in fact delayed into 2010, it is unlikely that even had it arrived in 2009 the majority of either shale‐gas or LNG producers would have been forced to shut‐in. Understanding the Cost Structure This misconception comes from a lack of understanding of the cost structure of both supplies ‐ leading many to believe that LNG and shale gas are mutually exclusive solutions for the North American market. Existing LNG producers, who can consider the capital cost of their facilities sunk, will judge the market opportunity on the basis of whether their short‐run marginal revenue covers their short‐run marginal or variable cost. CERA has calculated the variable cost for LNG delivered to either the U.S. or Europe ranges between around $0.50 to $2.00 per MMBtu, and observes that although this range is relatively wide, the volumes at the top end are small. LNG costs would have to fall to $1.00 per MMBtu before 3.0 Bcf per day might be shut in, in their view. Gas Matters concurred in June 2009 indicating that “unless gas prices in the U.S. and


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Europe fall well below $2.00/MMBtu for an extended period, an LNG production shut‐in does not appear to be on the horizon.” Recent speculation in the press has suggested that one of the more distant suppliers, Qatar, would even continue to operate at zero netback rather than forego the revenue from its associated liquids sales. For shale gas the new and rapidly evolving cost base, plus limited track record, has led many to become confused by the cost figures. However, just as in the case of conventional production there is no single meaningful figure for the cost of shale production. Some shales are advantaged versus others, both in terms of geographical relationship to market, but also terms of reservoir characteristics, thickness and organic content. Hence a single basin can be expected to show a range of production costs, from the low cost “sweet spots” to higher cost “tier 2” and “tier 3” locations. Understanding the Cost Curve As a result one should expect not only different shale basins to be distributed throughout the North American supply cost curve, but also different areas within the basin to also be likewise distributed. The best protection a shale gas player can have against reducing prices is to ensure that they are at the right end of the cost curve, making capture of high quality assets and subsequent efficient execution critical components in ensuring long‐term success. Based on the knowledge of the North American market place, we speculate that some of the higher cost conventional sources are in fact the marginal price setting gas resources in the present market, and that most shales and all existing LNG supplies are intra‐marginal (i.e. not the price setter). It has been hard to definitively test this thesis in the market place of 2009, despite relatively low prices ($3.81/MMBtu average year to date as of November 30 2009) as the market place has been in contango for much of the year, allowing gas producers to hedge production forward and access higher prices. In addition it has not been clear whether increasing shale gas production can be attributed to a continued improvement in productivity and hence a reducing cost‐


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base, or a back‐log of well completions that were only later hooked up and brought into production. Finally, as already indicated, the expected wave of LNG volumes was deferred into 2010 and so has not pressured or stress‐tested the market.


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Impact of Shale Gas on LNG Markets

Figure 17: U.S. LNG Imports

Source: Wood Mackenzie

However, despite this uncertainty, the resilience of shale gas production in the current demand downturn, coupled with well data and in some cases economic data reported by the producers, plus the magnitude of the resource, appears to be wholly consistent with the view that U.S. gas market pricing will be set by its own cost curve, and that it has effectively delinked from the impacts of global pricing. So how will the present evolution of the U.S. market impact the LNG industry? On the one hand there is clearly a reduced expectation that the market will ever reach the size (in terms of LNG imports) that many once speculated. This is illustrated by the evolution of Wood Mackenzie’s forecast for U.S. LNG imports shown in the figure above. Conversely however, the industry will not return to its former “inflexible self.” The U.S. market can still be accessed via abundant import infrastructure (a total of 15 Bcf/d is presently operational as of October 2009, equivalent to 60% of total global trade in 2009) while the nature of the U.S. market still allows for LNG trade


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flexibility (albeit under somewhat changed circumstances ‐ as a supply‐push rather than market‐pull function). That said there will still undoubtedly be times when the U.S. market does pull LNG volumes due to price spikes driven by exogenous factors. Our industry is well known for these, is very price reactive to them and it is unlikely that such instances will cease to occur in future. Broad industry consensus presently appears to be that shale‐gas will result in a U.S. gas market priced between $6.00 and $8.00/MMBtu (real 2009 $) at the Henry Hub and that LNG will be a price‐taker in this market (i.e. will not set the price). There are already indications that the short‐run marginal cost of existing LNG should be comfortably within an intramarginal position in the North American cost curve, however this is far from certain for new LNG investments for which project sponsors will have to judge whether their long‐run full cycle project costs give an acceptable rate‐of‐return at forecast long‐range Henry Hub prices. Impact on New LNG Projects If new LNG projects are able to clear the Henry Hub price, then we will continue to see the U.S. market used to sanction new projects effectively taking market timing issues off of project sanction agendas. A continued high spread of oil price versus Henry Hub would clearly incentivize a decanting of the U.S. volumes into higher value markets if and when they are able to accommodate the volumes. Economic theory would suggest that this arbitrage should lead to closure of the spread between Henry Hub and oil prices ‐ with the competition to supply the oil‐indexed markets pushing the oil indexed prices downwards. However, this is far from certain as an outcome in the scenario for two key reasons: firstly geopolitical constraints may limit the number and timing of new projects, giving buyers uncertainty over which projects will develop and when. Secondly, the ownership of flexible volumes, though increasing, is still not widely spread, which may act as an inhibitor to competition between these volumes.


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Cost of New Projects A second alternate outcome is possible if the long‐run cost of new projects does not clear the long term HH price outlook. In this case projects will have to wait for premium markets in Asia and Europe to grow demand for incremental LNG. Although this scenario suggests that a buyers’ market will develop, again this is not a foregone conclusion for the same reasons as before. In addition a lower limit to LNG prices will be set by the cost of new projects, which by definition in this scenario will be high (as they don’t clear the Henry Hub). In this scenario the decanting of existing U.S. back‐stopped LNG into other higher value markets is likely to result in a reducing quantity of flexible volumes available to the industry over time as these are locked into non‐flexible or semi‐flexible markets. However, the U.S. LNG import infrastructure will still be available to the industry, and will continue to underpin flexible trading in the industry providing a put option with which Asian and European markets can handle volume uncertainty. In addition analysts believe that exogenous factors and the differing market fundamentals (now including a U.S. cost curve underpinned by shale gas) will continue to create arbitrage opportunities for the flexible trader. The U.S. market may no longer need LNG, but it can still provide a meaningful balancing role to the industry – that genie is out of the bottle, to the extent of 15 Bcf/d of import capacity. Conclusion Based on this analysis and our market knowledge we observe that:

• There is now wide consensus that shale gas in North America has been a transformative resource for the market, effectively restocking the North American reserves base. As a result the U.S. natural gas market will no longer need LNG imports to meet long‐term demand and the long‐run U.S. natural gas price will be set by the cost‐curve for domestic production;

• Although LNG will influence U.S. prices over the short‐term as it is pushed

into or pulled from the market, it now seems unlikely to achieve anywhere close to the market share required for LNG to become the marginal price‐setter over the long term. As a result LNG will remain a price‐taker in the U.S.


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natural gas market and will not (as previously expected) be the conduit through which global prices are transmitted into the U.S. market place;

• Given that LNG is unlikely to be able to significantly influence the long‐run

U.S. gas price the future growth of LNG in the Atlantic Basin will be very dependent upon the future evolution of LNG project costs in the region. The future LNG industry will look different if projects are able to clear the long‐run Henry Hub outlook, than if they are not;

• LNG and shale gas are not in conceptual competition in the U.S. market place.

Both are just natural gas once they are in the market place and both have low‐cost and high‐cost examples. Over the long‐term both low‐cost LNG and low‐cost shale supplies will be advantaged in the U.S. market. LNG will have the flexibility to seek other markets as well;

• Analysts remain optimistic about the evolution of the LNG industry despite

the recent market developments in North America; global demand for LNG remains strong; new projects will be developed in the Atlantic Basin and at least some (those best able to control costs) will be based on Henry Hub pricing; U.S. LNG infrastructure will continue to underpin flexible trading in the industry providing a ‘put‐option’ with which Asian and European markets can handle volume uncertainty, while exogenous factors and the differing market fundamentals (now including a U.S. cost curve underpinned by ‘shale gas’) will continue to create arbitrage opportunities for the flexible LNG supplier;

• It is too early to assess the impact of shale gas in other global locations,

however it is clear that unconventional gas in general is already having an impact on the LNG industry in the form of Coal Bed Methane (CBM) based projects in Australia and it is clearly possible that additional resource developments will be seen elsewhere ‐ on both the market and supply sides of the LNG industry.


165 Impact of Shale Gas on the Global Energy

Industry

Impact of Shale Gas on the Global Energy Industry Shale gas – natural gas from rock formations – has become an important resource for energy industry. Earlier its extracting was considered too difficult and expensive but recent technological advances have made the exploitation of shale gas easier and more cost‐effective. The shale gas revolution has already been spreading in the United States and profoundly transforming the North American natural gas market. Now some are expecting shale gas boom to hit Europe as well. The exploitation of the so called unconventional natural gas sources – gas shales, coalbed methane and tight gas sands – began in North America approximately a decade ago. The existence of natural gas trapped in shale formations was nothing new but the break‐through in technology – horizontal drilling and hydraulic fracturing – made shale gas exploitation highly productive. The gas shale resources in North America are huge and the production from shale formations is expected to be the fastest‐growing source of unconventional natural gas production. According to the U.S. Energy Information Administration (EIA), natural gas production from shale formations will increase from 0.03 trillion cubic meters per year in 2006 to 0.12 trillion cubic meters – 18% of total U.S. production – in 2030. Some analysts estimate the production to grow even faster, up to 50% of total U.S. natural gas production in 2020. Resource estimates made by different organizations vary widely and are likely to change over time as new information and technology become available. According to the International Energy Agency’s (IEA) recent estimate, Europe’s unconventional gas reserves could reach 35 trillion cubic meters, of which almost half in shale. Although amounting far less than in North America, the IEA estimates that these reserves would be enough to substitute natural gas imports for 40 years at current levels. It’s not a surprise that the idea of indigenous natural gas reserves sound particularly appealing to Europeans that aim to decrease their dependence on imported energy. The shale gas resource base is global and large shale gas reserves are likely to exist for example in China and Central Asia, North Africa, Latin America and Australia. It is possible that unconventional gas could change the global geopolitics of natural gas when new supplier countries emerge and reliance on only a few suppliers decreases.


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Impact of Shale Gas on the Global Energy Industry

However, the unconventional gas exploration in Europe is in embryonic stage and both the size and the exploitability of the European unconventional gas reserves remain highly uncertain. Some experts see great potential in European shale gas resources whereas others regard the early estimates as highly exaggerated. There are also several factors that can slow down or complicate the shale gas production in Europe. To begin with, there are considerable geological differences with North America, and European shale formations aren’t expected to have as much gas trapped in them. Therefore the technology developed in the U.S. can’t just be transferred to Europe as such. Second, the building up of the required infrastructure takes some time, and certainly a lot of money. In addition, drilling is a large operation which can cause problems in densely populated Europe where wide open space is hard to find. Finally, the environmental impact of the shale gas exploitation has raised concerns in the U.S. and this will likely be brought on the agenda in Europe as well. Hence, whatever the size and recoverability of European shale gas reserves, it will certainly take a long time before any significant shale gas production can take place in Europe. It is expected to take at least a decade before shale gas can have a significant effect on European natural gas supply – before 2020 only minimal production volumes are predicted. Despite all the uncertainties concerning the potential of Europe’s shale gas reserves, several oil and gas companies are already exploring on European soil. Countries, where exploration projects are taking place, include at least Austria, France, Germany, Hungary, Poland, Sweden and the U.K., and the results are still pending. However, for example the Alum Shale of Sweden, the Silurian Shales of Poland and the Mikulov Shale of Austria are already considered to have high shale gas potential – according to some estimates the recoverable shale gas resources of the three basins combined range up to 4 trillion cubic meters. On the research front, the 6‐year Gas Shales in Europe (GASH) project was launched in 2009 by the German Research Centre for Geosciences. The aim of the oil industry funded project is to predict shale gas formation and occurrence in time and space, focusing on the potential gas shales of Europe. It is still worth mentioning that even though shale gas production in Europe will require years to start, Europe can benefit from shale gas before that in the form of


167 Impact of Shale Gas on the Global Energy

Industry

decreasing natural gas prices and growing liquefied natural gas (LNG) supply. The North American shale gas boom has already led to oversupply of natural gas in the U.S., which has driven prices down and forced companies to temporarily cut back drilling. Before the new technological advances in the shale gas production, energy companies were investing billions of dollars in LNG facilities in the U.S. Now LNG import terminals run at very low capacity and there has even been discussion about turning them into export terminals instead. Due to the growing natural gas supply imported LNG will no longer be needed in the U.S., which will probably free LNG shipments to other destinations. This could cause a slump in natural gas prices even on a global scale and increase LNG affordability. The IEA expects a large growth in LNG production during the next few years. On the flipside, it warns that plummeting natural gas prices and weakening demand together with the current economic situation could jeopardize future investments. This could lead to re‐tightening natural gas markets after a few years, when the demand for natural gas supplies recovers. On the other hand, if the shale gas exploitation becomes more common and spreads outside North America, the amount of natural gas in the global markets may well increase. Natural gas fits in well with the targets to reduce carbon emissions because it causes lower carbon emissions than other fossil fuels. It can be seen as a bridge between oil and coal, and renewable fuels, and unconventional gas could indeed drive a transformation in the energy sector. Another important energy issue, focal for Europeans, is security of supply. If European – and worldwide – shale gas reserves proved to be wide and their extraction cost‐effective, shale gas could really turn out to be a game changer.


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Water Issues Facing Shale Gas Production

Water Issues Facing Shale Gas Production Stormwater Runoff In order to create an area for drilling a new well, the operator clears and grades an area that can accommodate one or more wellheads; several pits for holding water, drill cuttings, and used drilling fluids; and space for the many trucks used to complete a frac job. Typically, this space will be 3 to 5 acres in size, plus any area disturbed to create an access road from the nearest public road to the well pad. Most of the figures in this chapter are photos taken by the author at several different Marcellus Shale well sites in southwestern Pennsylvania on a rainy day in May 2009 (photos from other locations are identified).

Figure 18: Well Pad Showing Drilling Rig

Source: U.S. DOE


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Figure 19: Well Pad Showing Equipment Used for Frac Job

Source: U.S. DOE

Figure 20: Well Pad Showing Completed Wellhead

Source: U.S. DOE


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Figure 21: Access Road at Recently Completed Well

Source: U.S. DOE These photos give an idea of the amount of disturbed land there is at a well site. Most operators employ appropriate management practices to control stormwater runoff. The figures below show some of the stormwater management structures that are used to capture offsite stormwater and divert it around the disturbed well pad area. This reduces the amount of water that carries sediment. The water falling on disturbed areas of the site can be controlled through the application of gravel to the well pad and road surfaces or through onsite collection pits.


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Figure 22: Stormwater Diversion Ditch to Collect Offsite Water

Source: U.S. EPA

Figure 23: Lower End of Stormwater Diversion Ditch


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Source: U.S. EPA

Figure 24: Stormwater Control Structure

Source: U.S. EPA

Water Supply for Drilling and Other Processes The second important water issue involves finding an adequate and dependable supply of water to support well drilling and completion activities. Water used for drilling and making up frac fluids can come from several sources: surface water bodies, groundwater, municipal potable water supplies, or reused water from some other water source (most commonly this is flowback water from a previously fractured well). GWPC and ALL (2009) provide estimates of water requirements for four of the major shale gas plays. The water required for drilling a typical shale gas well ranges from 1,000,000 gallons in the Haynesville Shale to 60,000 gallons in the Fayetteville Shale, depending on the types of drilling fluids used and the depth and horizontal extent of the wells. The Marcellus Shale drilling volume falls near the lower end of this range at 80,000 gallons per well. The volume needed to fracture a well is considerably larger. According to GWPC and ALL (2009), the frac fluid volume


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ranges from 3,800,000 gallons per well in the Marcellus Shale to 2,300,000 gallons per well in the Barnett Shale. Another source of information on the amount of water used per well is a presentation given by a representative of the Susquehanna River Basin Commission (SRBC) on volumes of water withdrawn for Marcellus Shale gas well development. A large portion of the Marcellus Shale underlies the Susquehanna River basin watershed. Any water usage within the watershed is subject to oversight by the SRBC. Hoffman (2010) notes, that as of January 2010, the SRBC had data for 131 wells. The total volume of water withdrawn through that date is 262 million gallons, with 45% coming from public water supplies and the other 55% coming from surface water sources. The average total volume of fluid used per well is 2.7 million gallons, with 2.2 million gallons of that coming from freshwater sources and 0.5 million gallons coming from recycled flowback water. No information was provided by Hoffman (2010) concerning whether the wells in the SRBC data set were vertical or horizontal wells (a vertical well requires much less water for a frac job than does a horizontal well). Water can be brought to the site by numerous tank trucks or, where another source of water is available within a mile or so, it can be piped to the site. Water Flowing to the Surface The third important water issue involves managing the water that comes to the surface from the gas well. During the frac job, the operator injects a large volume of water into the formation. Once the frac job is finished, the pressure is released, and a portion of the injected water flows back to the surface in the first few days to weeks. This water is referred to as flowback or flowback water. Over a much longer period of time, additional water that is naturally present in the formation (i.e., produced water) continues to flow from the well. While some authors consider flowback to be just one part of the produced water, this report distinguishes flowback from the ongoing produced water. Both flowback and produced water typically contain very high levels of total dissolved solids (TDS) and many other constituents. Over an extended period of time, the volume of produced water from a given well decreases. Not all of the injected frac fluid returns to the surface. GWPC and ALL (2009) report that from 30% to 70% of the original frac fluid volume returns as flowback. However, anecdotal reports from Marcellus operators suggest that the actual


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percentage is at or below the lower end of that range. The rest of the water remains in pores within the formation. The SRBC data set described in the previous section shows that about 13.5% of the injected frac fluid is recovered. Operators must manage the flowback and produced water in a cost‐effective manner that complies with state regulatory requirements. The primary options are: Inject underground through a disposal well (onsite or offsite), Discharge to a nearby surface water body, Haul to a municipal wastewater treatment plant (often referred to as a publicly owned treatment works or POTW), Haul to a commercial industrial wastewater treatment facility, and Reuse for a future frac job either with or without treatment.

• Inject underground through a disposal well (onsite or offsite); • Discharge to a nearby surface water body; • Haul to a municipal wastewater treatment plant (often referred to as a

publicly owned treatment works or POTW); • Haul to a commercial industrial wastewater treatment facility, and Reuse for

a future frac job either with or without treatment.


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Major Players in Gas Shales

Major Players in Gas Shales Anadarko Petroleum Anadarko Petroleum Corporation (Anadarko) is an independent oil and gas exploration and production company, with 2.3 billion barrels of oil equivalent (BOE) of proved reserves as of December 2009. The company also markets natural gas, oil, and natural gas liquids (NGLs); and owns and operates gas gathering and processing systems. The company is also engaged in the hard minerals business. The company operates in the U.S., Algeria, Brazil, China, Cote d'Ivoire, Ghana, Indonesia, Mozambique, and Sierra Leone. Anadarko operates through three segments: oil and gas exploration and production; midstream; and marketing. The oil and gas exploration and production segment explores for and produces natural gas, crude oil, condensate, and NGLs. The company's major areas of operation are located onshore in the U.S., the deepwater of the Gulf of Mexico, as well as in Algeria, Brazil, China, Cote d'Ivoire, Ghana, Indonesia, Mozambique, and Sierra Leone, among other countries. Anadarko had proved reserves of 7,764 billion cubic feet (Bcf) of natural gas and 1,010 millions of barrels (MMBbls) of crude oil, condensate and, NGLs, as of December 31, 2009. Anadarko had proved developed reserves of 5,884 Bcf of natural gas and 499 million barrels (MMBbls) of crude oil, condensate, and NGLs, as of December 31, 2009. The company's oil and gas exploration and production business in the U.S. includes the Lower 48 states, Alaska, and the deepwater Gulf of Mexico. Reserves in the U.S. comprised 89% of Anadarko's total proved reserves at year‐end 2009. The company's drilling efforts in the U.S. resulted in 979 natural gas wells, 40 oil wells, and 21 dry holes, during FY2009. At the end of FY2009, about 75% of the company's proved reserves were located onshore in the Lower 48 states. Anadarko's operation in Alaska is concentrated primarily on the North Slope. Anadarko owns an average 66% working interest in 575 blocks in the deepwater Gulf of Mexico and has access to an additional six blocks through participation agreements. The company holds interests in 26 producing fields and is in the process of developing seven additional fields in the area.


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The company is also engaged in oil and gas exploration and production in the Sahara desert of Algeria in Blocks 404 and 208. During FY2009, six development wells were drilled in Blocks 404 and 208; and during FY2010 the company expects to drill approximately 10 development wells in the two blocks The company's other international oil and gas production and/or development operations are located primarily in China. The company has exploration acreage in China, Brazil, Ghana, Indonesia, and other areas. Around 11% of the company's proved reserves were located in these other international locations in FY2009. Anadarko drilled 44 wells in international areas in FY2009.


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The midstream segment engages in gathering, processing, treating, and transporting Anadarko's and third party oil and gas production. The company owns and operates natural gas gathering, treating and processing systems in the U.S.. The company invests in midstream (gathering and processing) facilities to complement its oil and gas operations in regions where the company has natural gas production. In addition, Anadarko's midstream business provides gathering, treating, and processing services for third‐party customers, including major and independent producers. The company also processes a portion of its gas at various third‐party plants. Anadarko has 28 systems in seven states (Wyoming, Colorado, Utah, New Mexico, Kansas, Oklahoma, and Texas) located in major onshore producing basins. The marketing segment sells most of Anadarko's production, as well as commodities purchased from third parties. The company markets natural gas, oil, and NGLs in the U.S., and markets oil from Algeria and China. Under this segment, the company manages the sales of Anadarko's natural gas, crude oil, and NGLs. The company also purchases natural gas, crude oil, condensate, and NGLs for resale primarily from partners and producers near Anadarko's production. It sells natural gas under various contracts. The company is also engaged in sales of greenhouse gas emission reduction credits (ERCs) derived from carbon dioxide (CO2) injection operations in Wyoming. The company's key products and services include the following: Oil and gas exploration and production:

• Natural gas • Crude oil • Condensates • Natural gas liquids (NGLs)

Midstream:

• Gathering, processing, treating, and transporting oil and gas production • Gas processing

Marketing:


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• Selling natural gas, crude oil, and NGLs • Reselling natural gas, crude oil, condensate, and NGLs • Selling greenhouse gas emission reduction credits (ERCs)

Contact Details: Anadarko Petroleum Corporation 1201 Lake Robbins Drive The Woodlands, TX 77380 United States of America Tel: +1‐832‐636‐1000 Fax: +1‐832‐636‐8220 Website: http://www.anadarko.com Apache Corporation Apache Corporation (Apache) is an independent energy company that explores for, develops, and produces natural gas, crude oil, and natural gas liquids. In North America, the company's exploration and production interests are focused in the Gulf of Mexico, the Gulf Coast, East Texas, the Permian basin, the Anadarko basin, and the Western Sedimentary basin of Canada. Outside of North America, Apache has exploration and production interests onshore Egypt, offshore Western Australia, offshore UK in the North Sea (North Sea), and onshore Argentina. The company also has exploration interests on the Chilean side of the island of Tierra del Fuego. Apache's reportable segments are managed based on their geographic locations. In the U.S., Apache's exploration and production activities are spread between two regions: Gulf Coast and Central. The Gulf Coast region comprises the company's interests in and along the Gulf of Mexico, in the areas on‐and offshore Louisiana and Texas. Apache is the largest held‐by‐production acreage holder and the second largest producer in Gulf waters less than 1,200 feet deep. The region also holds 1.2 million gross acres along the Gulf Coast of Louisiana and Texas. As of year‐end 2009, the Gulf Coast region accounted for approximately 20% of Apache's worldwide production, about 21% of its revenues, and held 13% of its estimated proved reserves. In FY2009, the region


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drilled or participated in 26 wells and performed 217 workovers and recompletions. The Central region includes assets in the Permian basin of West Texas and New Mexico and the Anadarko basin of western Oklahoma and the Texas Panhandle. Over the past decade, the region has grown from approximately 3,000 wells to over 10,000; and for the year end 2009, represents 27% of Apache's proved reserves. During FYZ2009 Apache operated or participated in drilling 135 wells; 99% were completed as producers. The region also performed 810 workovers and recompletions. Apache's exploration and development activity in the Canadian region has 4.4 million net acres across the provinces of British Columbia, Alberta, and Saskatchewan. The region comprises 22% of the company's estimated proved reserves. In addition Apache and EnCana, as 50% partners, control more than 400,000 acres in the Horn River Basin shale‐gas play in northeast British Columbia. To appraise and develop oil and natural gas resources in the province of New Brunswick, Apache entered into a farm‐in agreement with Corridor Resources, in December 2009. In FY2009, Apache drilled or participated in 201 wells in Canada, 41 of which were in the Horn River Basin. In Egypt, the company holds more than 11 million gross acres in 21 separate concessions (18 producing concessions) in the Cretaceous Upper Bahariya formations and in deeper intervals from Lower Cretaceous to Jurassic. In addition, the company also produces liquid hydrocarbons and natural gas in the Western Desert. In FY2009, the company's Egypt region contributed 30% of Apache's production revenue, 26% of total production, and 13% of total estimated proved reserves. In FY2009, Apache had an active drilling program in Egypt, drilling 164 wells, including nine new field discoveries, and conducted 792 workovers and recompletions. Apache's exploration activity in Australia is focused in the offshore Carnarvon, Gippsland, and Browse basins where it holds 4.3 million net acres in 31 exploration permits, 14 production licenses, and 3 retention leases. In FY2009, the region increased equivalent production 40% and accounted for approximately 7% of its total production. During the year, the region participated in drilling 33 wells, which generated 28 productive wells.


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Apache's North Sea operations are concentrated at the Forties Field. In FY2009, the North Sea region produced 22.4 million barrel of oil equivalent (MMboe), approximately 11% of the company's total production. In Argentina, Apache's oil and gas assets are located in the Neuquen, Rio Negro, and Tierra del Fuego. In FY2009, the company had 16.6 MMboe of production, drilled 29.6 net wells (32 gross), and performed 57 additional capital projects. Argentina holds approximately 5% of the company's total estimated proved reserves. In Chile, Apache has the exploration rights on two blocks comprising one million net acres in Tierra del Fuego. This acreage is adjacent to its 552,000 net acres on the Argentinean side of Tierra del Fuego. The company holds interests in many of its U.S., Canadian, and other international properties through subsidiaries, including Apache Canada, DEK Energy Company (DEKALB), Apache Energy (AEL), Apache North America, and Apache Overseas. As of December 2009, Apache had total estimated proved reserves of 1,067 million barrels (MMbbls) of crude oil, condensate, and NGLs and 7.8 trillion cubic feet (Tcf) of natural gas. Combined, these total estimated proved reserves are equivalent to 2.4 billion barrels of oil equivalent or 14.2 Tcf of natural gas. The company's key products include the following:

• Liquefied natural gas (LNG) • Natural gas • Crude oil

Contact Details: Apache Corporation 2000 Post Oak Boulevard Suite 100 Houston, TX 77056 4400 United States of America Tel: +1‐713‐296‐6000 Website: http://www.apachecorp.com


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Bill Barrett Corporation Bill Barrett Corporation (Bill Barrett) is engaged in the exploration, development and production of natural gas and crude oil. The company primarily operates in the U.S.. The company has exploration and development projects in seven basins and a regional over thrust belt in the Rocky Mountains region. These basins are the Piceance, the Wind River, the Uinta, the Powder River, Montana Overthrust Belt, the Paradox and the Big Horn. Bill Barrett's Piceance basin is located in northwestern Colorado, and includes 106 million cubic feet equivalent per day (MMcfe/d) net production, 532 billion cubic feet (Bcfe) of estimated net proved reserves, 490 net producing wells and 46,653 net undeveloped acres. The company's Wind River Basin is located in central Wyoming and operations in the basin include field expansion programs, recompletions, as well as exploration projects. It includes 9.6 Bcfe net production, 165 gross producing wells and 226,636 net undeveloped acres. Bill Barrett's Uinta Basin is located in northeastern Utah and development operations are conducted primarily in West Tavaputs. It includes 198,800 net undeveloped acres, 24.8 MMcfe/d net production and 29.7 Bcfe proved reserves. The company's Powder River Basin is located in northeastern Wyoming. Its operations are focused on the development drilling of coalbed methane wells, typically to a depth of 1,200 feet. It includes 62,025 net undeveloped acres, 39.3 MMcfe/d net production and 63.5 Bcfe proved reserves. Bill Barrett's Montana Overthrust Belt is a linear structural feature that runs from southern Utah through the Canadian Rockies. It includes 165,667 net undeveloped acres. The company's Paradox Basin is located in southwestern Colorado and southeastern Utah. The company is testing a shale gas concept and plan to test a structure play along the flanks of large salt diapirs. It includes 295,276 net undeveloped acres.


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Bill Barrett's Big Horn Basin is located in north central Wyoming. It includes 58,367 net undeveloped acres. The company's subsidiaries include the following: Bill Barrett CBM Corporation, and Circle B Land Co. The company's key products and activities include the following: Products:

• Oil • Natural gas

Activities:

• Exploration and development of oil and natural gas Contact Details: Bill Barrett Corporation 1099 18th Street Suite 2300 Denver, CO 80202 United States of America Tel: +1‐303‐293‐9100 Fax: +1‐303‐291‐0420 Website: http://www.billbarrettcorp.com


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Chesapeake Energy Chesapeake Energy Corporation (Chesapeake) is engaged in the exploration and production of natural gas and oil. It is the second largest producer of natural gas in the U.S.. The company owns interests in approximately 44,100 producing natural gas and oil wells that produce approximately 2.4 billion cubic feet equivalent (bcfe) per day, 93% of which is natural gas. Chesapeake operates through three business segments: natural gas and oil; marketing, gathering, and compression (midstream); and service operations. Under its natural gas and oil segment, the company focuses on its natural gas exploration, development, and acquisition efforts in eight operating areas. These operating areas are: Barnett Shale; Fayetteville Shale; Haynesville Shale (including the Bossier Shale); Marcellus Shale; Mid‐Continent; Permian and Delaware Basins; South Texas/Gulf Coast/Ark‐La‐Tex (including the Eagle Ford Shale); and Appalachian Basin (excluding the Marcellus Shale). Chesapeake's Barnett Shale proved reserves represented 3.434 trillion cubic feet equivalent (tcfe), or 24%, of the company's total proved reserves as of December 31, 2009. During FY2009, the Barnett Shale assets produced 238 bcfe, or 26%, of the company's total production. Chesapeake's Fayetteville Shale proved reserves represented 2.167 tcfe, or 15%, of the company's total proved reserves as of December 31, 2009. During FY2009, the Fayetteville Shale assets produced 91 bcfe, or 10%, of the company's total production. Chesapeake's Haynesville Shale proved reserves represented 1.834 tcfe, or 13%, of its total proved reserves as of December 31, 2009. During FY2009, the Haynesville Shale assets produced 85 bcfe, or 10%, of the company's total production. Chesapeake's Marcellus Shale proved reserves represented 259 bcfe, or 2%, of the company's total proved reserves as of December 31, 2009. During FY2009, the Marcellus Shale assets produced 15 bcfe, or 2%, of the company's total production. Chesapeake's Mid‐Continent proved reserves of 4.098 tcfe represented 29% of its total proved reserves as of December 31, 2009. During FY2009, this area produced 305 bcfe, or 34%, of the company's total production. Chesapeake's Permian and Delaware Basin proved reserves represented 741 bcfe, or 5%, of its total proved


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reserves as of December 31, 2009. During FY2009, the Permian assets produced 75 bcfe, or 8%, of the company's total production. The proved reserves of the company's South Texas/Texas Gulf Coast/Ark‐La‐Tex regions represented 565 bcfe, or 4%, of its total proved reserves as of December 31, 2009. During FY2009, these assets produced 67 bcfe, or 7%, of the company's total production. Chesapeake's Appalachian Basin proved reserves represented 1.156 tcfe, or 8%, of its total proved reserves as of December 31, 2009. During FY2009, the Appalachian assets produced 30 bcfe, or 3%, of the company's total production. In FY2009, the company had interests in approximately 44,100 productive wells, of which 36,950 were classified as primarily natural gas productive wells and 7,150 were classified as primarily oil productive wells. Chesapeake operates approximately 25,150 of its 44,100 productive wells. During FY2009, the company drilled 1,212 wells and participated in another 994 wells operated by other companies. The company operates approximately 80% of its current daily production volumes. Further, in FY2009, the company had 13,510 billion cubic feet (bcf) of total proved natural gas reserves and 124 million barrels (mmbbl) of total proved oil reserves. Under its midstream segment, the company is engaged in marketing, gathering, and compression activities. Chesapeake Energy Marketing, Chesapeake's marketing subsidiary, provides natural gas and oil marketing services. These services include commodity price structuring, contract administration, and nomination services for Chesapeake, its partners, and other producers. Through its gathering operations, Chesapeake invests in gathering systems and processing facilities to complement its natural gas operations in regions where it has significant production and additional infrastructure is required. Under its compression business, Chesapeake's wholly‐owned subsidiary, MidCon Compression, operates wellhead and system compressors to facilitate the transportation of the company's natural gas production. The service operations segment of Chesapeake is engaged in drilling activities and trucking business. Chesapeake is engaged in drilling activities through its wholly‐owned drilling subsidiary, Nomac Drilling Corporation. The company is the fourth


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largest drilling rig contractor in the U.S.. The company's drilling rigs are currently operating in Oklahoma, Texas, Arkansas, Louisiana, and Appalachian regions. Chesapeake's trucking business is utilized primarily to transport drilling rigs for both Chesapeake and third parties. As of December 2009, the company's fleet included 255 trucks and 19 cranes, which mainly service the Mid‐Continent, Barnett Shale, and Appalachian regions. The company's key products and activities include the following: Products:

• Natural gas • Oil

Activities:

• Exploration and production of oil and natural gas • Discovery, acquisition, and development of conventional and unconventional

natural gas reserves Contact Details: Chesapeake Energy Corporation 6100 North Western Avenue Oklahoma City, OK 73118 United States of America Tel: +1‐405‐848‐8000 Fax: +1‐405‐843‐0573 Website: http://www.chk.com Devon Energy Devon Energy is an independent oil and gas producer in the U.S. and one of the largest independent processors of natural gas and natural gas liquids (NGL), such as propane, butane, and ethane, in North America. The company also owns natural gas


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pipelines and processing and treatment facilities in many of its producing areas, making it one of North America's larger processors of NGLs. Devon Energy's revenue mix is about 52.5% from natural gas, 35% from oil, and 12.5% from NGLs. The company's major operations are concentrated in the U.S. and Canada. Devon Energy also has offshore operations that are situated principally in the Gulf of Mexico and regions located offshore Azerbaijan, Brazil, and China. Devon Energy is in process of divesting its offshore assets. The decision to monetize offshore assets is to utilize the capital and human resources in a more productive manner. As a result, the focus is going to be more on the assets onshore in the U.S. and Canada. The company identifies its segments based on geographic areas: the U.S. and Canada. The company's operations in the U.S. are focused in Barnett Shale, Carthage, Washakie, Groesbeck, Woodford Shale, and the Permian Basin. The company also has certain midstream assets like natural gas and NGL processing plants and pipeline systems. These assets include approximately 3,100 miles of pipeline, two natural gas processing plants with 750 million cubic feet (mmcf) per day of total capacity, and 15 thousand barrels (MBbls) per day NGL fractionators. These assets serve the Barnett Shale region in north Texas. To support its production in the Woodford Shale, located in southeastern Oklahoma, the company has constructed the Northridge natural gas processing plant that has a capacity of 200 mmcf per day. Its midstream assets also include its 50% ownership interest in the Access Pipeline transportation system in Canada. This is a 220‐mile dual pipeline system which extends from the company's Jackfish operations in northern Alberta to a 350 MBbls storage terminal in Edmonton. The dual pipeline system allows the company to blend the Jackfish heavy oil production with condensate and transport the combined product to the Edmonton crude oil market. Devon Energy's Canadian deep basin operations include portions of west central Alberta, east central British Columbia, and Peace River Arch operations. In Northeast British Columbia, the company's assets are located primarily in British Columbia and to a lesser extent in northwestern Alberta, which produce principally


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natural gas from conventional reservoirs. These centers primarily produce natural gas and NGLs from conventional reservoirs. Devon Energy has also assembled an asset base offshore Brazil, including the Polvo oil field and two oil discoveries in the Campos Basin that await development. The company's key products and services include the following:

• Exploration, production, processing, and marketing of oil • Exploration, production, processing, and marketing of natural gas • Exploration, production, processing, and marketing of natural gas liquids

(NGLs) Contact Details: Devon Energy Corporation 20 North Broadway Oklahoma City, OK 73102 8260 United States of America Tel: +1‐405‐235‐3611 Fax: +1‐405‐552‐4550 Website: http://www.devonenergy.com


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EnCana EnCana Corporation (EnCana) is one of North America's leading natural gas producers. It is among the largest holders of natural gas and oil resource lands onshore North America and is a technical and cost leader in the in‐situ recovery of oil sands bitumen. In November 2009, EnCana completed a corporate reorganization to split into two independent publicly traded energy companies: EnCana Corporation, a natural gas company, and Cenovus Energy (Cenovus), an integrated oil company. EnCana holds a diversified portfolio of prolific shale and other gas resource plays in key basins stretching from northeast British Columbia to Louisiana. Its operations are primarily located in Canada and the U.S.. EnCana through the following segments: Canada, the U.S., market optimization, and corporate and others. The Canada segment is engaged in the exploration, development, and production of natural gas, crude oil, and natural gas liquids (NGLs) and other related activities within the Canadian cost centre. The segment comprises the Canadian plains division and the Canadian foothills division. In conjunction with the split transaction, the upstream assets formerly included in EnCana's Canadian Plains division and integrated oil division has been transferred to Cenovus. The Canadian plains division encompasses the majority of EnCana's legacy natural gas production activities in southern Alberta and Saskatchewan as well as the corporation's crude oil (excluding in‐situ bitumen) development and production activities in Alberta and Saskatchewan. Three key resource plays are located in the Canadian Plains Division: Shallow Gas, Pelican Lake, and Weyburn. The Shallow Gas key resource play is contained within the Suffield, Brooks North, and Langevin areas. The Canadian (formerly the Canadian foothills division) division includes EnCana's key natural gas growth assets in British Columbia and Alberta. Four key resource plays are located in the Canadian division: Greater Sierra, Cutbank Ridge, Bighorn in west central Alberta, and CBM. The CBM key resource play (Horseshoe Canyon CBM, and commingled shallow gas) is located within the Clearwater business unit. In addition, EnCana has established a land position in the Horn River Devonian shale, located adjacent to the Greater Sierra key resource play.


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The company's U.S. segment includes the development and production of natural gas within the U.S. cost centre. The U.S. downstream refining assets were transferred to Cenovus which were formerly included in the company's U.S. segment. EnCana's operations in the U.S. segment are focused on exploiting long‐life unconventional natural gas formations in the Jonah field in southwest Wyoming, the Piceance Basin in northwest Colorado, and the East Texas and Fort Worth basins in Texas. The segment is also focused on the development of the Haynesville shale play located in Louisiana and Texas and the recent entrance into the Marcellus shale play located in Pennsylvania. The U.S. segment also has interests in natural gas gathering and processing assets, primarily in Colorado, Wyoming, Texas, and Utah. The company sells its production through the market optimization segment. Market optimization activities are managed by EnCana's business development, Canadian gas marketing, and power corporate group and by divisional marketing groups. The market optimization segment is focused on enhancing the netback price of the company's proprietary production. Market optimization activities include third party purchases and sales of product to provide operational flexibility for transportation commitments, product type, delivery points, and customer diversification. The corporate and others segment mainly includes unrealized gains or losses recorded on derivative financial instruments. The company's key operation includes the following:

• Natural gas exploration, production, and processing Contact Details: EnCana Corporation 1800 855 2nd Street South West Calgary Alberta T2P 2S5 Canada Tel: +1‐403‐645‐2000


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Fax: +1‐403‐645‐3400 Website: http://www.encana.com EOG Resources EOG Resources (EOG), once part of the energy company Enron, became an independent entity in 1999 and changed its name from Enron Oil & Gas to EOG Resources. EOG, together with its subsidiaries, explores, develops, produces, and markets natural gas and crude oil primarily in major producing basins in the U.S., Canada, offshore Trinidad, the UK, and China. It is one of the largest independent (non‐integrated) oil and natural gas companies in the U.S. with proved reserves in the U.S., Canada, Trinidad, the UK, and China. All of EOG's operations are related to natural gas and crude oil exploration and production and its operations are grouped into two reportable segments: exploration and production operations in the U.S. and Canada; and exploration and production operations outside the U.S. and Canada. As on December 31, 2009, EOG's total estimated net proved reserves were 10,776 billion cubic feet equivalent (Bcfe), of which 8,898 billion cubic feet (Bcf) were natural gas reserves and 220 million barrels (MMBbl), or 1,317 Bcfe, were crude oil and condensate reserves and 93 MMBbl, or 561 Bcfe, were natural gas liquids reserves Approximately 75% of EOG's reserves on a natural gas equivalent basis were located in the U.S., 16% in Canada, and 9% in Trinidad. The U.S. operations are grouped into independent business units with each unit focusing on certain basins in a particular geographic region. The independent business units are Midland (Texas), Denver (Colorado), Oklahoma City/Mid‐Continent, Tyler (Texas), Corpus Christi (Texas), Pittsburgh (Pennsylvania), and Houston Texas/Offshore, in the U.S.; and Calgary in Canada. Other producing areas in the U.S. are in Wyoming, Utah, South and East Texas, the Mississippi Salt Basin, the offshore Gulf of Mexico, New Mexico, Val Verde, and Midland Basins of West Texas. The company's other U.S. natural gas and crude oil producing properties are located primarily in other areas of Texas, Utah, Oklahoma, California, and Kansas. As of FY2009, approximately 81% of the company's proved U.S. and Canada reserves are of natural gas while the remaining 19% are crude oil, condensate, and natural


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gas liquids. As of December 2009, EOG held approximately 4,185,000 net undeveloped acres in the U.S.. EOG's Canadian operations are carried out through its subsidiary EOG Resources Canada (EOGRC). The company's offices are located in Calgary and Alberta. During FY2009, EOGRC drilled or participated in 98 net wells and net crude oil and condensate and natural gas liquids production increased by 41% to 5,200 barrels per day (MBbld) and natural gas production increased 1% to 224 million cubic feet per day (MMcfd). As of December 2009, EOGRC held approximately 1.66 million net undeveloped acres in Canada. Apart from North America, the company also has operations in offshore Trinidad, in the UK North Sea, East Irish Sea, and the China Sichuan Basin; and is evaluating additional exploration, development, and exploitation opportunities. In FY2009, EOG's average net production from Trinidad was 273 MMcfd of natural gas and 3.1 MBbld of crude oil and condensate. As of December 2009, EOG held approximately 156,000 net undeveloped acres in Trinidad. In FY2009, EOG delivered net average production of seven MMcfd of natural gas in the UK; and held approximately 277,000 net undeveloped acres in the UK. EOG also has exploration rights in the Chuanzhong Block exploration area in the Sichuan Basin, Sichuan Province, China, which it acquired from ConocoPhillips in July 2008. The acquisition includes net production of approximately eight million cubic feet equivalent per day (MMcfed) of natural gas, on approximately 130,000 acres. In addition, EOG continues to evaluate other select natural gas and crude oil opportunities outside the U.S. and Canada primarily by pursuing exploitation opportunities in countries where indigenous natural gas and crude oil reserves have been identified. The company's key products and services include: Products:

• Natural gas • Natural gas liquids


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• Crude oil Services:

• Exploration and production of crude oil, natural gas, and natural gas liquids Contact Details: EOG Resources, Inc. 1111 Bagby Sky Lobby 2 Houston, TX 77002 United States of America Tel: +1‐713‐651‐7000 Fax: +1‐713‐651‐6995 Website: http://www.eogresources.com


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Newfield Exploration Newfield Exploration Company (Newfield Exploration), an independent oil and gas company, is engaged in the exploration, development, and acquisition of natural gas and crude oil properties. The company has operations in the following resource plays: Mid‐Continent, Rocky Mountains, Appalachia basin, onshore Texas, the Gulf of Mexico, and offshore Malaysia and China. Newfield Exploration is engaged in the production activities in Anadarko and Arkoma Basins of the Mid‐Continent region. At the end of December 2009, the company had a working interest in approximately 725,000 gross acres (approximately 400,000 net acres) and approximately 2,300 gross producing wells. Newfield Exploration owns approximately 166,500 net acres in the Woodford Shale, located in the Arkoma Basin of southeast Oklahoma. The company has an average working interest of approximately 60% in Woodford Shale. As of February 15, 2010, the company's operated production in the Woodford Shale was approximately 190 million cubic feet equivalent (MMcfe/d) net. Newfield Exploration also owns more than 44,000 net acres in the Granite Wash play located in the Anadarko Basin of northern Texas and western Oklahoma. The company has an average 75% working interest in Stiles/Britt Ranch, the largest producing field in the Granite Wash. As of February 15, 2010, the company's operated production in the Granite Wash was approximately 130 MMcfe/d net. The company has an interest in approximately 1.4 million gross acres (1 million net acres) and more than 2,400 gross producing wells in the Rocky Mountains. Its assets in the Rocky Mountains are more than 70% oil and have long‐lived production. Newfield Exploration's working interest in the Monument Butte oil field, its largest asset in the Rocky Mountains, averages about 80%. The Monument Butte oil field is located in the Uinta Basin of Utah. The company operates the field, which is substantially held‐by‐production. Newfield Exploration has approximately 1,300 productive oil wells in Monument Butte and its acreage is approximately 180,000 net acres. The gross production from the Monument Butte field area totaled 17,000 barrels of oil per day (BOPD) gross as of February 15, 2010.


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The company also owns acreage in the Williston Basin/Southern Alberta Basin and Green River Basin in the Rocky Mountains. Newfield Exploration has approximately 150,000 net acres in the Williston Basin, excluding approximately 54,000 net acres in the mature Elm Coulee field. The production from the Williston Basin at the end of FY2009 was approximately 2,500 barrels of oil equivalent per day (BOEPD) net. The company owns interests in 4,000 net acres in the Pinedale Field, located in Sublette County, Wyoming and operate activities in Pinedale. Additionally, Newfield Exploration has an interest in the Jonah field, located in Sublette County, Wyoming, where it has identified about 35 development locations on 10 and 5‐acre well spacing. In the Appalachia basin, Newfield Exploration signed a joint exploration agreement with Hess Corporation covering up to 140,000 gross acres in the Marcellus Shale play, primarily in Wayne County, Pennsylvania. The agreement was signed in mid‐2009. Newfield Exploration is the operator of this venture with a 50% working interest. At the end of FY2009, the company had leased about 35,000 net acres. At the end of December 2009, the company owned an interest in approximately 375,000 gross acres (224,000 net) and about 750 gross producing wells onshore Texas. It produced 170 MMcfe/d net from its onshore Texas assets, as of December 31, 2009. The company's operations in the Gulf of Mexico are focused on the deepwater. At the end of FY2009, the company's daily production from the Gulf of Mexico was approximately 90 MMcfe/d net. As of December 31, 2009, Newfield Exploration owned interests in 86 deepwater leases and approximately 370,000 net acres. Newfield Exploration's international production at the end of FY2009 was approximately 17,000 BOPD net. The company has an interest in approximately three million acres gross (1.1 million net) offshore Malaysia and approximately 1.7 million acres gross (1.6 million net) offshore China. At the end of FY2009, the company's proved reserves totaled 3.6 trillion cubic feet equivalent (Tcfe) and consisted of 1,505 thousand cubic feet equivalent (Bcfe) proved developed producing, 403 Bcfe proved developed non‐producing, and 1,708 Bcfe proved undeveloped reserves.


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The company's key products include the following:

• Crude oil • Natural gas

Contact Details: Newfield Exploration Company 363 North Sam Houston Parkway East Texas United States of America Tel: +1‐281‐847‐6000 Fax: 1 281 405 4242 Website: http://www.newfield.com


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Range Resources Range Resources Corporation (Range Resources) is engaged in the exploration, development and acquisition of oil and gas properties primarily in the Southwestern and Appalachian regions of the U.S.. The company operates in two regions: the Southwestern (which includes the Barnett Shale of North Central Texas, the Permian Basin of West Texas and eastern New Mexico, the East Texas Basin, the Texas Panhandle and the Anadarko Basin of Western Oklahoma) and Appalachian (which includes tight‐gas, shale, coal bed methane and conventional oil and gas production in Pennsylvania, Virginia, Ohio, New York and West Virginia). Range Resources has over 11,500 identified drilling locations in inventory, both proven and unproven. The Southwestern region includes drilling, production and field operations in the Barnett Shale of North Central Texas, the Permian Basin of West Texas and eastern New Mexico, and the East Texas Basin, as well as in the Texas Panhandle, Anadarko Basin of western Oklahoma and Louisiana and Mississippi. In the Southwestern region, the company owns 1,854 net producing wells. The company's properties in Appalachian region are located in the Appalachian Basin in the northeastern U.S., principally in Pennsylvania, Ohio, West Virginia and Virginia. The reserves principally produce from the Pennsylvanian (coalbed formation), Upper Devonian, Medina, Clinton, Big Lime and Marcellus Shale formations at depths ranging from 2,500 to 9,000 feet. The company owns 8,052 net producing wells and approximately 4,000 miles of gas gathering lines. It has approximately 2.3 million gross (1.9 million net) acres under lease, which include 289,000 acres where the company also owns a royalty interest. The company's subsidiaries include Energy Assets Operating Company, Range Resources Appalachia, Mountain Front Partners, Range Resources Pine Mountain, Range Energy I, Range Energy Services Company, Range Gathering & Processing Company, Range Holdco, Range Operating New Mexico, Range Operating Texas, Range Production Company, Range Resources Midcontinent, Range Texas


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Production, WCR/Range GP, Oil and Gas Title Abstracting, American Energy Systems. The company's key products and activities include the following: Products:

• Oil • Natural gas

Activities:

• Exploration and development of oil and gas resource properties Contact Details: Range Resources Corporation 100 Throckmorton Street Suite 1200 Fort Worth, TX 76102 United States of America Tel: +1‐817‐870‐2601 Fax: +1‐817‐869‐9100 Website: http://www.rangeresources.com


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Talisman Energy Talisman Energy (Talisman) is one of the largest independent oil and gas producers in Canada. Its main business activities include exploration, development, production, transportation, and marketing of crude oil, natural gas, and NGLs. Talisman has ongoing production, development, and exploration operations in North America, the North Sea, Southeast Asia Australia, and North Africa. Talisman's operations are conducted principally in five geographic segments: North America, the UK, Scandinavia, Southeast Asia, and other. Talisman's aggregate production for FY2009 was approximately 425,000 barrels of oil equivalent per day (boe/d). Talisman's aggregate production for the year ended December 31, 2009 was 425,000 boe/d (including discontinued operations), comprised of 168,000 boe/d from North America, 89,000 boe/d from the UK, 44,000 boe/d from Scandinavia, 108,000 boe/d from Southeast Asia, and 16,000 boe/d from other areas. The North America segment includes operations in Canada and the U.S.. Talisman has organized its North American operations into two distinct businesses: shale and conventional. As a result, certain lands prospective for shale gas in British Columbia, Alberta, and Quebec have been transferred from Talisman Energy Canada to Talisman Energy Inc. The new organizational structure has been designed to allow Talisman effectively operate its new shale gas business model. Talisman intends to focus its spending in North America on shale gas plays where Talisman has built significant landholdings. Talisman's Marcellus shale play is located in New York and Pennsylvania, The main area of focus will be in Pennsylvania. The company holds 218,000 Tier 1 net acres with approximately 1,800 net drilling locations. In Montney shale, Talisman holds 168,000 Tier 1 net acres with approximately 3,000 net drilling locations. Talisman's Lorraine/Utica lands are located in the Quebec lowlands along the St. Lawrence River, where it holds a total of 756,000 net acres. Talisman's conventional assets in North America are focused in the following areas: tight gas in the Outer Foothills and the Edson/Bigstone/Wild River/WestWhitecourt areas; deep gas in the Foothills of Monkman in British Columbia and Alberta Foothills; and oil operations in Alberta/Saskatchewan in the Chauvin and


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Shaunavon fields. The net sales production for FY2009 was 976 million cubic feet equivalent per day (mmcfe/d), or 163 million barrels oil equivalent per day (mboe/d). Talisman's remaining operations in North America include approximately 700 kilometers (kms) of gathering systems in Western Canada including Central Foothills, Erith, Lynx; and Palliser, plus three operated gas plants (Edson, Berland West, and Boundary Lake). The company's midstream assets support many areas in the company's conventional division, including Alberta Foothills, Bigstone/Wild River, and greater Edson. The company's UK assets are principally held by Talisman Energy (UK) and Talisman North Sea, which include producing fields and exploration acreage in the UK and the Netherlands sectors of the North Sea. Talisman has two core operating areas in the UK: the Northern Business Area (NBA) and the Central Business Area (CBA). Talisman's principal operating areas in the NBA include Claymore, Piper (including Tweedsmuir), Tartan, and Quad 16. These four principal operating areas encompass a total of 23 fields. Talisman currently holds interests ranging from 5% to 100% in the NBA fields, as well as in a number of production facilities and pipelines, including an 80% interest in the Flotta Terminal. Of the 23 fields, 16 are operated (with interests ranging from 37% to 100%) and seven are non‐operated (with interests ranging from 5% to 15%). In FY2009, production from the NBA averaged 49,000 barrels oil equivalent per day (boe/d), which accounted for 55% of the total UK production of the company. Talisman's principal operating areas in the CBA include Montrose/Arbroath, Fulmar, Auk, Clyde, Ross/Blake, and Buchan. These principal operating areas encompass a total of 23 fields. Talisman currently holds interests ranging from 7% to 100% in the CBA fields, as well as in a number of production facilities and pipelines. Of the 23 fields, 18 are operated (with interests ranging from 25% to 100%) and five are non‐operated (with interests ranging from 7% to 54%). In FY2009, production from the CBA averaged 40,000 boe/d. Talisman's Scandinavian assets are held by Talisman Energy Norge, including producing fields and exploration acreage in the Norwegian sector of the North Sea.


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Talisman's principal operating areas in Scandinavia are the Southern North Sea Area and the Mid North Sea Area, which encompass a total of 10 fields. In FY2009, Scandinavian production averaged 44,000 boe/d. In the Southern North Sea Area, Talisman holds interests of 18%, 61%, and 60% in the Blane, Gyda, and Yme operated fields, respectively, as well as a 10% interest in the non‐operated Tambar East field. In the Mid North Sea Area, Talisman holds interests of 65% and 70% in the operated Varg and Rev Fields, respectively, and interests in four non‐operated fields (with interest ranging between 1% and 35%) as well as a number of production facilities and pipelines in other areas of the Norwegian Continental Shelf. In FY2009, production from this area averaged 36,000 boe/d, which accounted for 82% of total Scandinavian production of the company. Talisman's interests in Southeast Asia include operations and exploration acreage in Indonesia, Malaysia, Vietnam, Papua New Guinea, and Australia. In FY2009, Southeast Asia production averaged 108,000 boe/d. Talisman's Indonesian assets include onshore interests at Corridor and Ogan Komering as well as offshore interests in Southeast Sumatra, offshore Northwest Java, Tangguh, and extensive exploration acreage at Pasangkayu and Sageri. It also has an indirect 6% interest in the Grissik to Duri pipeline and in the Grissik to Singapore pipeline. In Malaysia, Talisman holds a 41% operated interest in Block PM‐3 commercial arrangement area (CAA) between Malaysia and Vietnam and associated production facilities. In addition, Talisman holds interests in Block 46‐Cai Nuoc adjacent to PM‐3 CAA, Block PM‐305, and Block PM‐314. In Vietnam, Talisman holds a 30% interest in Block 46/02 and in the joint operating company which operates that block. Block 46/02 lies adjacent to PM‐3 CAA/46‐Cai Nuoc. Talisman also holds a 60% interest in Block 15‐2/01 and in the joint operating company which operates that block. Block 15‐2/01 lies in the Cuu Long Basin, the predominant oil producing basin in Vietnam.


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Offshore Papua New Guinea, Talisman has interests in 12 blocks in Papua New Guinea with an area extent covering in excess of 8 million net acres. In Australia, Talisman holds non‐operated interests in the Laminaria and Corallina fields and the Joint Petroleum Development Area 06‐105 (JPDA 06‐105) in Australia/East Timor. In FY2009, production in Australia averaged 5,000 barrels per day (bbls/d), which accounted for 5% of total Southeast Asia production of the company. The other segment includes operations in Algeria and Tunisia. In Algeria, Talisman holds a 35% non‐operated interest in Block 405a under a PSC with Algeria's national oil company. Through its participation in Block 405a, Talisman currently holds a 35% interest in the Greater Menzel Lejmat North fields and the Menzel Lejmat Southeast field, a 2% interest in the unitized Ourhoud field, and a 9% interest in the EMK field. In Tunisia, Talisman holds a 5% non‐operated interest in the Adam concession portion of the Borj El Khadra permit and a 10% interest in the remainder of the permit. Talisman is also engaged in exploration activities in Colombia, Peru, the Kurdistan region of northern Iraq, Poland, and Alaska. The company's products and services include: Products:

• Crude oil • Natural gas • Natural gas liquids

Services:

• Exploration • Development • Production


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• Transportation Contact Details: Talisman Energy Suite 2000 888 3rd Street South West Calgary Alberta T2P 5C5 Canada Tel: +1‐403‐237‐1234 Fax: +1‐403‐237‐1902 Website: http://www.talisman‐energy.com XTO Energy XTO Energy is an American Fortune 500 energy producing company. Its primary products are oil and natural gas. It is based in Downtown Fort Worth, Texas. In 2007, it paid Dominion Resources US$2.5 billion for 1 trillion cubic feet (28×10^9 m3) of oil and gas reserves in the Rocky Mountains, Texas and southern Louisiana, In 2008 XTO acquired Hunt Petroleum Corporation for $4.2 billion. At the end of the second quarter of 2009 XTO Energy became the largest producer of natural gas in the United States. In 2009, XTO entered into an agreement with ExxonMobil to be acquired for $31 billion in stock. The deal was approved by XTO's shareholders on June 25, 2010. As a subsidiary of ExxonMobil, the company will be named XTO Energy Incorporated and it will focus on global development and production of unconventional resources. Contact Details: XTO Energy Inc. 810 Houston St. Fort Worth, Texas 76102‐6298


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United States of America Tel: +1‐817‐870‐2800 Fax: +1‐817‐870‐1671 Website: www.xtoenergy.com


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Section 3: Analysis of Oil Shales


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Introduction to Oil Shales

Introduction to Oil Shales Overview Oil shale, an organic‐rich fine‐grained sedimentary rock, contains significant amounts of kerogen (a solid mixture of organic chemical compounds) from which liquid hydrocarbons can be extracted. Kerogen requires more processing to use than crude oil, which increases its cost as a crude‐oil substitute both financially and in terms of its environmental impact. Deposits of oil shale occur around the world, including major deposits in the United States of America. Estimates of global deposits range from 2.8 trillion to 3.3 trillion barrels (450×109 to 520×109 m3) of recoverable oil. The chemical process of pyrolysis can convert the kerogen in oil shale into synthetic crude oil. Heating oil shale to a sufficiently high temperature will drive off a vapor which processing can distill (retort) to yield a petroleum‐like shale oil—a form of unconventional oil—and combustible oil‐shale gas (the term shale gas can also refer to gas occurring naturally in shales). Industry can also burn oil shale directly as a low‐grade fuel for power generation and heating purposes and can use it as a raw material in chemical and construction‐materials processing. Oil shale has gained attention as an energy resource as the price of conventional sources of petroleum has risen and as a way for some areas to secure independence from external suppliers of energy. At the same time, oil‐shale mining and processing raise a number of environmental concerns, such as land use, waste disposal, water use, waste‐water management, greenhouse‐gas emissions and air pollution. Estonia and China have well‐established oil shale industries, and Brazil, Germany, Israel and Russia also utilize oil shale. History of the Industry Humans have used oil shale as a fuel since prehistoric times, since it generally burns without any processing. Britons of the Iron Age also used to polish it and form it into ornaments. Modern industrial mining of oil shale began in 1837 in Autun, France, followed by exploitation in Scotland, Germany, and several other countries. Operations during the 19th century focused on the production of kerosene, lamp oil,


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and paraffin; these products helped supply the growing demand for lighting that arose during the Industrial Revolution. Fuel oil, lubricating oil and grease, and ammonium sulfate were also produced. The European oil‐shale industry expanded immediately before World War I due to limited access to conventional petroleum resources and to the mass production of automobiles and trucks, which accompanied an increase in gasoline consumption. Although the Estonian and Chinese oil‐shale industries continued to grow after World War II, most other countries abandoned their projects due to high processing costs and the availability of cheaper petroleum. Following the 1973 oil crisis, world production of oil shale reached a peak of 46 million tons in 1980 before falling to about 16 million tons in 2000, due to competition from cheap conventional petroleum in the 1980s. On 2 May 1982, known in some circles as "Black Sunday", Exxon canceled its US$5 billion Colony Shale Oil Project near Parachute, Colorado because of low oil‐prices and increased expenses, laying off more than 2,000 workers and leaving a trail of home‐foreclosures and small‐business bankruptcies. In 1986, President Ronald Reagan signed into law the Consolidated Omnibus Budget Reconciliation Act of 1985 which among other things abolished the United States' Synthetic Liquid Fuels Program. The global oil‐shale industry began to revive at the beginning of the 21st century. In 2003, an oil‐shale development program restarted in the United States. Authorities introduced a commercial leasing program permitting the extraction of oil shale and oil sands on federal lands in 2005, in accordance with the Energy Policy Act of 2005. Oil Shale Geology Oil shale, an organic‐rich sedimentary rock, belongs to the group of sapropel fuels. It does not have a definite geological definition nor a specific chemical formula, and its seams do not always have discrete boundaries. Oil shales vary considerably in their mineral content, chemical composition, age, type of kerogen, and depositional history and not all oil shales would necessarily be classified as shales in the strict sense. Oil shale differs from bitumen‐impregnated rocks (oil sands and petroleum reservoir rocks), humic coals and carbonaceous shale. While oil sands originate from the biodegradation of oil, heat and pressure have not (yet) transformed the kerogen in oil shale into petroleum.


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Oil shale contains a lower percentage of organic matter than coal. In commercial grades of oil shale the ratio of organic matter to mineral matter lies approximately between 0.75:5 and 1.5:5. At the same time, the organic matter in oil shale has an atomic ratio of hydrogen to carbon (H/C) approximately 1.2 to 1.8 times lower than for crude oil and about 1.5 to 3 times higher than for coals. The organic components of oil shale derive from a variety of organisms, such as the remains of algae, spores, pollen, plant cuticles and corky fragments of herbaceous and woody plants, and cellular debris from other aquatic and land plants. Some deposits contain significant fossils; Germany's Messel Pit has the status of a Unesco World Heritage Site. The mineral matter in oil shale includes various fine‐grained silicates and carbonates. Geologists can classify oil shales on the basis of their composition as carbonate‐rich shales, siliceous shales, or cannel shales. Another classification, known as the van Krevelen diagram, assigns kerogen types, depending on the hydrogen, carbon, and oxygen content of oil shales' original organic matter. The most commonly used classification of oil shales, developed between 1987 and 1991 by Adrian C. Hutton of the University of Wollongong, adapts petrographic terms from coal terminology. This classification designates oil shales as terrestrial, lacustrine (lake‐bottom‐deposited), or marine (ocean bottom‐deposited), based on the environment of the initial biomass deposit. Hutton's classification scheme has proven useful in estimating the yield and composition of the extracted oil.


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Shale Oil Extraction Most exploitation of oil shale involves mining followed by shipping elsewhere, after which one can burn the shale directly to generate electricity, or undertake further processing. The most common methods of surface mining involve open pit mining and strip mining. These procedures remove most of the overlying material to expose the deposits of oil shale, and become practical when the deposits occur near the surface. Underground mining of oil shale, which removes less of the overlying material, employs the room‐and‐pillar method. The extraction of the useful components of oil shale usually takes place above ground (ex‐situ processing), although several newer technologies perform this underground (on‐site or in‐situ processing). In either case, the chemical process of pyrolysis converts the kerogen in the oil shale to shale oil (synthetic crude oil) and oil shale gas. Most conversion technologies involve heating shale in the absence of oxygen to a temperature at which kerogen decomposes (pyrolyses) into gas, condensable oil, and a solid residue. This usually takes place between 450 °C (842 °F) and 500 °C (932 °F). The process of decomposition begins at relatively low temperatures (300 °C/570 °F), but proceeds more rapidly and more completely at higher temperatures. In‐situ processing involves heating the oil shale underground. Such technologies can potentially extract more oil from a given area of land than ex‐situ processes, since they can access the material at greater depths than surface mines can. Several companies have patented methods for in‐situ retorting. However, most of these methods remain in the experimental phase. One can distinguish true in‐situ processes (TIS) and modified in‐situ processes (MIS). True in‐situ processes do not involve mining the oil shale. Modified in‐situ processes involve removing part of the oil shale and bringing it to the surface for modified in‐situ retorting in order to create permeability for gas flow in a rubble chimney. Explosives rubblize the oil‐shale deposit. Hundreds of patents for oil shale retorting technologies exist; however, only a few dozen have undergone testing. As of 2006, only four technologies remained in commercial use: Kiviter, Galoter, Fushun, and Petrosix.


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Applications of Shale Oil Industry can use oil shale as a fuel for thermal power‐plants, burning it (like coal) to drive steam turbines; some of these plants employ the resulting heat for district heating of homes and businesses. Sizable oil‐shale‐fired power plants occur in Estonia, which has an installed capacity of 2,967 megawatts (MW), Israel (12.5 MW), China (12 MW), and Germany (9.9 MW). In addition to its use as a fuel, oil shale may also serve in the production of specialty carbon fibers, adsorbent carbons, carbon black, phenols, resins, glues, tanning agents, mastic, road bitumen, cement, bricks, construction and decorative blocks, soil‐additives, fertilizers, rock‐wool insulation, glass, and pharmaceutical products. However, oil shale use for production of these items remains small or only in its experimental stages. Some oil shales yield sulfur, ammonia, alumina, soda ash, uranium, and nahcolite as shale‐oil extraction byproducts. Between 1946 and 1952, a marine type of Dictyonema shale served for uranium production in Sillamäe, Estonia, and between 1950 and 1989 Sweden used alum shale for the same purposes. Oil shale gas has served as a substitute for natural gas, but as of 2009, producing oil shale gas as a natural‐gas substitute remained economically infeasible. The shale oil derived from oil shale does not directly substitute for crude oil in all applications. It may contain higher concentrations of olefins, oxygen, and nitrogen than conventional crude oil. Some shale oils may have higher sulfur or arsenic content. By comparison with West Texas Intermediate, the benchmark standard for crude oil in the futures‐contract market, the Green River shale oil sulfur content ranges from near 0% to 4.9% (in average 0.76%), where West Texas Intermediate's sulfur content has a maximum of 0.42%. The sulfur content in shale oil from Jordan's oil shales may rise even up to 9.5%. The arsenic content, for example, becomes an issue for Green River formation oil shale. The higher concentrations of these materials means that the oil must undergo considerable upgrading (hydrotreating) before serving as oil‐refinery feedstock. Above‐ground retorting processes tended to yield a lower API gravity shale oil than the in situ processes. Shale oil serves best for producing middle‐distillates such as kerosene, jet fuel, and diesel fuel. Worldwide demand for these middle distillates, particularly for diesel fuels, increased rapidly in the 1990s and 2000s. However, appropriate refining processes equivalent to hydrocracking can transform shale oil into a lighter‐range hydrocarbon (gasoline).


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Global Oil Shale Reserves

Global Oil Shale Reserves Overview Oil shale reserves refers to oil shale resources that are recoverable under given economic restraints and technological abilities. Oil shale deposits range from small presently non‐economic occurrences to large presently commercially exploitable reserves. Defining oil shale reserves is difficult, as the chemical composition of different oil shales, as well as their kerogen content and extraction technologies, vary significantly. The economic feasibility of shale oil extraction is highly dependent on the price of conventional oil; if the price of crude oil per barrel is less than the production price per barrel of shale oil, it is uneconomic. There are around 600 known oil shale deposits. Many deposits need more exploration to determine their potential as reserves. However, worldwide technically recoverable reserves have recently been estimated at about 2.8–3.3 trillion barrels (450×10^9–520×10^9 m3) of shale oil, with the largest reserves in the United States, which is thought to have 1.5–2.6 trillion barrels (240×10^9–410×10^9 m3). Well‐explored deposits, which could be classified as reserves, include the Green River deposits in the western United States, the Tertiary deposits in Queensland, Australia, deposits in Sweden and Estonia, the El‐Lajjun deposit in Jordan, and deposits in France, Germany, Brazil, China, and Russia. It is expected that these deposits would yield at least 40 liters (0.25 bbl) of shale oil per metric ton of shale, using the Fischer Assay. Estimating Shale Oil Reserves Estimating shale oil reserves is complicated by several factors. Firstly, the amount of kerogen contained in oil shale deposits varies considerably. Secondly, some nations report as reserves the total amount of kerogen in place, including all kerogen regardless of technical or economic constraints; these estimates do not consider the amount of kerogen that may be extracted from identified and assayed oil shale rock using available technology and under given economic conditions. By most definitions, "reserves" refers only to the amount of resource which is technically exploitable and economically feasible under current economic conditions. The term "resources", on the other hand, may refer to all deposits containing kerogen. Thirdly,


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shale oil extraction technologies are still developing, so the amount of recoverable kerogen can only be estimated. There are a wide variety of extraction methods, which yield significantly different quantities of useful oil. As a result, the estimated amounts of resources and reserves display wide variance. The kerogen content of oil shale formations differs widely, and the economic feasibility of its extraction is highly dependent on international and local costs of oil. Several methods are used to determine the quantity and quality of the products extracted from shale oil. At their best, these methods give an approximate value to its energy potential. One standard method is the Fischer Assay, which yields a heating value, that is, a measure of caloric output. This is generally considered a good overall measure of usefulness. The Fischer Assay has been modified, standardized, and adapted by the American Petroleum Institute. It does not, however, indicate how much oil could be extracted from the sample. Some processing methods yield considerably more useful product than the Fischer Assay would indicate. The Tosco II method yields over 100% more oil, and the Hytort process yields between 300% to 400% more oil. Regional Analysis Global Overview There is no comprehensive overview of oil shales geographical allocation around the world. Around 600 known oil shale deposits are diversely spread throughout the earth, and are found on every continent with the possible exception of Antarctica, which has not yet been explored for oil shale. Oil shale resources can be concentrated in a large confined deposit such as the Green River formations, which were formed by a large inland lake. These can be many meters thick but limited by the size of the original lake. They may also resemble the deposits found along the eastern American seaboard, which were the product of a shallow sea, in that they may be quite thin but laterally expansive, covering thousands of square kilometers. Africa Major oil shale deposits are located in the Democratic Republic of Congo (equal to 14.31 billion metric tons of shale oil) and Morocco (12.3 billion metric tons or 8.16 billion metric tons of shale oil). Deposits in Congo are not properly explored yet. In Morocco, oil shale deposits have been identified at ten localities with the largest


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deposits in Tarfaya and Timahdit. Although reserves in Tarfaya and Timahdit are well explored, the commercial exploitation has not started yet and only a limited program of laboratory and pilot‐plant research has been undertaken. There are also oil shale reserves in Egypt, South Africa, Madagascar, and Nigeria. The main deposits of Egypt are located in Safaga‐Al‐Qusair and Abu Tartour areas. Asia Major oil shale deposits are located in China, which has an estimated total of 32 billion metric tons, of which 4.4 billion metric tons are technically exploitable and economically feasible; Thailand (18.7 billion metric tons), Kazakhstan (several deposits; major deposit at Kenderlyk Field with 4 billion metric tons), and Turkey (2.2 billion metric tons). Smaller oil shale reserves have also been found in Assam (India), Pakistan, Uzbekistan, Turkmenistan, Myanmar, Armenia, and Mongolia. The principle Chinese oil shale deposits and production lie in Fushun and Liaoning; others are located in Maoming in Guangdong, Huadian in Jilin, Heilongjiang, and Shandong. In 2002, China produced more than 90,000 metric tons of shale oil. Thailand's oil shale deposits are near Mae Sot, Tak Province, and at Li, Lamphun Province. Deposits in Turkey are found mainly in middle and western Anatolia. Professor Alan R. Carroll of University of Wisconsin–Madison estimates that Upper Permian lacustrine oil shale deposits of northwest China, absent from previous global oil shale assessments, are comparable to the Green River Formation. Europe The biggest oil shale reserves in Europe are located in Russia (equal to 35.47 billion metric tons of shale oil). Major deposits are located in the Volga‐Petchyorsk province and in the Baltic Oil Shale Basin. Other major oil shale deposits in Europe are located in Italy (10.45 billion metric tons of shale oil), Estonia (2.49 billion metric tons of shale oil), France (1 billion metric tons of shale oil), Belarus (1 billion metric tons of shale oil), Sweden (875 million metric tons of shale oil), Ukraine (600 million metric tons of shale oil) and the United Kingdom (500 million metric tons of shale oil). There are oil shale reserves also in Germany, Luxembourg, Spain, Bulgaria, Hungary, Poland, Austria, Albania, and Romania.


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Middle East Significant oil shale deposits are located in Jordan (5.242 billion metric tons of shale oil or 65 billion metric tons of oil shale) and Israel (550 million metric tons of shale oil or 6.5 billion metric tons of oil shale). Jordanian oil shales are high quality, comparable to western U.S. oil shale, although their sulfur content is high. The best‐explored deposits are El Lajjun, Sultani, and the Juref ed Darawishare located in west‐central Jordan, while the Yarmouk deposit, close to its northern border, extends into Syria. Most of Israel's deposits are located in the Rotem Basin region of the northern Negev desert near the Dead Sea. Israeli oil shale is relatively low in heating value and oil yield. North America At 380 billion metric tons, the oil shale deposits in the United States are easily the largest in the world. There are two major deposits: the eastern U.S. deposits, in Devonian‐Mississippian shales, cover 250,000 square miles (650,000 km2); the western U.S. deposits of the Green River Formation in Colorado, Wyoming, and Utah, are among the richest oil shale deposits in the world. In Canada 19 deposits have been identified. The best‐examined deposits are in Nova Scotia and New Brunswick. Australia Australia's oil shale resource is estimated at about 58 billion metric tons or 4.531 billion metric tons of shale oil, of which about 24 billion barrels (3.8 km3) is recoverable. The deposits are located in the eastern and southern states with the biggest potential in the eastern Queensland deposits. South America Brazil has the world's second‐largest known oil shale resources (the Irati shale and lacustrine deposits) and is currently the world's second largest shale oil producer, after Estonia. Oil shale resources occur in São Mateus do Sul, Paraná, and in Vale do Paraíba. Brazil has developed the world’s largest surface oil shale pyrolysis retort at Petrosix, with a 11‐meter (36 ft)‐diameter vertical shaft. Brazilian production in 1999 was about 200,000 metric tons. Small resources are also found in Argentina, Chile, Paraguay, Peru, Uruguay, and Venezuela.


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Analysis of the Oil Shale Industry

Analysis of the Oil Shale Industry Overview Oil shale industry is an industry of mining and processing of oil shale—a fine‐grained sedimentary rock, containing significant amounts of kerogen (a solid mixture of organic chemical compounds), from which liquid hydrocarbons can be manufactured. The industry has developed in Brazil, China, Estonia and to some extent in Germany, Israel and Russia. Several other countries are currently conducting research on their oil shale reserves and production methods to improve efficiency and recovery. However, Australia has halted their pilot projects due to environmental concerns. Estonia accounts for about 70% of the world's oil shale production. Oil shale has been used for industrial purposes since the early 17th century, when it was mined for its minerals. Since the late 19th century, shale oil has also been used for its oil content and as a low grade fuel for power generation. However, barring countries having significant oil shale deposits, its use for power generation is not particularly widespread. Similarly, oil shale is a source for production of synthetic crude oil and it is seen as a solution towards increasing domestic production of oil in countries that are reliant on imports. Power Generation with Shale Oil Oil shale can be used as a fuel in thermal power plants, wherein oil shale is burnt like coal to drive the steam turbines. As of 2008, there are oil shale‐fired power plants in Estonia with a generating capacity of 2,967 megawatts (MW), Israel (12.5 MW), China (12 MW), and Germany (9.9 MW). Also Romania and Russia have run oil shale‐fired power plants, but have shut them down or switched to other fuels like natural gas. Jordan and Egypt have announced their plans to construct oil shale‐fired power plants, while Canada and Turkey plan to burn oil shale at the power plants along with coal. Thermal power plants which use oil shale as a fuel mostly employ two types of combustion methods. The traditional method is Pulverized combustion (PC) which is used in the older units of oil shale‐fired power plants in Estonia, while the more


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advanced method is Fluidized bed combustion (FBC), which is used by Holcim cement factory in Dotternhausen, Germany, and in PAMA power plant at Mishor Rotem in Israel. The main FBC technologies are Bubbling fluidized bed combustion (BFBC) and Circulating fluidized bed combustion (CFBC). There are more than 60 power plants around the world, which are using CFBC technology for combustion of coal and lignite, but only two new units at Narva Power Plants in Estonia, and one at Huadian Power Plant in China use CFBC technology for combustion of oil shale. The most advanced and efficient oil shale combustion technology is Pressurized fluidized‐bed combustion (PFBC). However, this technology is still premature and is in its nascent stage. Major Producers of Shale Oil As of 2008, the major shale oil producers are Estonia, Brazil and China, while Australia, USA, Canada and Jordan have planned to setup or restart shale oil production. In 2005, the global oil shale production was 684,000 tons. Although the largest shale oil producer in 2005 was Estonia, it is expected that as of 2007, China has overtaken the position of the largest producer in the world. Although there are several oil shale retorting technologies, only four technologies are currently in commercial use. These are Kiviter, Galoter, Fushun, and Petrosix. The two main methods of extracting oil from shale are ex‐situ and in‐situ. In ex‐situ method, the oil shale is mined and transported to the retort facility in order to extract the oil. The in‐situ method converts the kerogen while it is still in the form of an oil shale deposit, and then extracts it via a well, where it rises up as normal petroleum.


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Industrial Uses of Shale Oil Oil shale is used for cement production by Kunda Nordic Cement in Estonia, by Holcim in Germany, and by Fushun cement factory in China. Oil shale can also be used for production of different chemical products, construction materials, and pharmaceutical products. However, use of oil shale for production of these products is still very rare and in experimental stages only. Some oil shales are suitable source for sulfur, ammonia, alumina, soda ash, and nahcolite which occur as shale oil extraction byproducts. Some oil shales can also be used for uranium and other rare chemical element production. During 1946–1952, a marine variety of Dictyonema shale was used for uranium production in Sillamäe, Estonia, and during 1950–1989 alum shale was used in Sweden for the same purpose. Oil shale gas can also be used as a substitute for natural gas. After World War II, Estonian‐produced oil shale gas was used in Leningrad and the cities in North Estonia. However, at the current price level of natural gas, this is not economically feasible.


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Economics of Oil Shale

Economics of Oil Shale Overview Oil shale economics deals with the economic feasibility of oil shale extraction and processing. The economic feasibility of oil shale is highly dependent on the price of conventional oil, and the assumption that the price will remain at a certain level for some time to come. As a developing fuel source the production and processing costs for oil shale are high due to the small nature of the projects and the specialist technology involved. A full‐scale project to develop oil shale would require heavy investment and could potentially leave businesses vulnerable should the oil price drop, as the cost of producing the oil would exceed the price they could obtain for the oil. Oil shale deposits in the USA, Estonia, China, and Brazil have been important over the past hundred years. Presently few deposits can be exploited economically without subsidies. However, some countries, such as Estonia, Brazil, and China, operate oil‐shale industries, while others, including Australia, USA, Canada, Jordan, and Egypt, are contemplating establishing or re‐establishing this industry. The production cost of a barrel of shale oil ranges from as high as US$95 per barrel to as low US$12 per barrel. The industry is proceeding cautiously, due to the losses incurred during the last major investment into oil shale in the early 1980s, when a subsequent collapse in the oil price left the projects uneconomical. Competing with Oil Prices The various attempts to develop oil shale deposits have succeeded only when the cost of shale‐oil production in a given region comes in below the price of crude oil or its other substitutes. According to a survey conducted by the RAND Corporation, the cost of producing a barrel of oil at a surface retorting complex in the United States (comprising a mine, retorting plant, upgrading plant, supporting utilities, and spent shale reclamation), would range between US$70–95 ($440–600/m3, adjusted to 2005 values). This estimate considers varying levels of kerogen quality and extraction efficiency. In order for the operation to be profitable, the price of crude oil would need to remain above these levels. The analysis also discusses the


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expectation that processing costs would drop after the complex was established. The hypothetical unit would see a cost reduction of 35–70% after its first 500 million barrels (79×10^6 m3) were produced. Assuming an increase in output of 25 thousand barrels per day (4.0×10^3 m3/d) during each year after the start of commercial production, the costs would then be expected to decline to $35–48 per barrel ($220–300/m3) within 12 years. After achieving the milestone of 1 billion barrels (160×10^6 m3), its costs would decline further to $30–40 per barrel ($190–250/m3). A comparison of the proposed American oil shale industry to the Alberta oil‐sands industry has been drawn (the latter enterprise generated over one million barrels of oil per day in late 2007), stating that "the first‐generation facility is the hardest, both technically and economically". In 2005, Royal Dutch Shell has announced that its in situ extraction technology in Colorado could become competitive at prices over $30 per barrel ($190/m3). However, it is possible that the real competitive price level will be higher as the costs for building an underground wall of frozen water to contain melted shale have significantly escalated. At full‐scale production, the production costs for one barrel of light crude oil of the Australia's Stuart plant were projected to be in the range of US$11.3 to $12.4 per barrel, including capital costs and operation costs over a projected 30‐year lifetime. However, the project has been suspended due to environmental concerns. Israel's AFSK Hom Tov process, which produces oil from a mixture of oil refinery residue (in the form of bitumen) and oil shale, claims to be profitable at US$16‐US$17 per barrel. This technology is still being tested. The project of a new Alberta Taciuk Processor, planned by VKG Oil, is estimated to achieve break‐even financial feasibility operating at 30% capacity, assuming a crude oil price of US$21 per barrel or higher. At 50% utilization, the project is economic at a price of US$18 per barrel, while at full capacity, it could be economic at a price of US$13 per barrel. Energy Use & Water Requirement


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A critical measure of the viability of oil shale is the ratio of energy used to produce the oil, compared to the energy returned (Energy Returned on Energy Invested ‐ EROEI). This is because the extraction process is energy intensive, and so the increased cost of oil, or energy generally, will raise the cost of extracting oil from shale oil. Generally, for ex‐situ processes the oil shale has to be mined, transported, and retorted, and the waste materials must be disposed of, so at least 40% of the energy value is consumed in production. A 1984 study estimated the EROEI of the different oil shale deposits to vary between 0.7‐13.3. Royal Dutch Shell has reported an EROEI about three to four on its in‐situ development, Mahogany Research Project, which uses electric heating of the shale up to 500 °F (260 °C). This compares to a figure of typically 5:1 for conventional oil extraction. EROEI will be less important to the extent that lower‐cost energy sources are used to fuel the extraction process. Development of oil shale resources will require significant quantities of water for mine and plant operations, reclamation, supporting infrastructure, and associated economic growth. In 1980, the U.S. Office of strategic assessment estimated water requirements of 2.3 to 5.7 barrels of water per barrel of oil. More current estimates based on updated oil shale industry water budgets suggest that requirements for new retorting methods will be 1 to 3 barrels of water per barrel of oil. For an oil shale industry producing 2.5 million barrels per day, this equates to between 105 and 315 million U.S. gallons of water per day. These numbers include water requirements for power generation for in‐situ heating processes, retorting, refining, reclamation, dust control and on‐site worker demands. Municipal and other water requirements related to population growth associated with industry development will require an additional 58 million gallons per day. Hence, a 2.5 MMBbl/d oil shale industry would require 180,000 acre feet (220,000,000 m3) to 420,000 acre feet (520,000,000 m3) of water per year, depending on location and processes used.


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The largest deposit of oil shale in the United States is in the Green River basin. Though scarce, water in the western United States is treated as a commodity which can be bought and sold in a competitive market. Royal Dutch Shell has been reported to be buying groundwater rights in Colorado as it prepares to drill for oil in the shale deposits there. In the Colorado Big‐Thompson project, average prices per share (0.7 acre feet/share) increased from some $2,000 in 1990 to more than $12,000 in mid‐2003 (constant 2001 dollars). CBT Prices from 2001 to 2006 has had a range of $10,000 to $14,000 per share, or $14,000 to $20,000 per acre foot. In August 2009 asking prices in Utah (ex‐salt lake city) ranged from $8,000‐$15,000/AF. At $10,000 per acre foot, capital costs for water rights to produce 2.5m bbls/day would range between $1.8 bn‐$4.2 bn. Investment in the Industry In the second half of the 20th century, oil shale production ceased in Canada, Scotland, Sweden, France, Australia, Romania, and South Africa due to the low price of oil and other competitive fuels. In the United States, during the 1973 oil crisis businesses expected oil prices to stay as high as US$70 a barrel, and invested considerable sums in the oil shale industry. World production of oil shale reached a peak of 46 million tons in 1980. Due to competition from cheap conventional petroleum in the 1980s, several investments became economically unfeasible. On 2 May 1982, known as "Black Sunday", Exxon canceled its US$5 billion Colony Shale Oil Project near Parachute, Colorado because of low oil‐prices and increased expenses. Because of the losses in 1980s, companies were reluctant to make new invests in shale oil production. However, in the early 21st century, USA, Canada and Jordan were planning or had started shale oil production test projects, and Australia was considering restarting oil shale production. In a 1972 publication by the journal Pétrole Informations (ISSN 0755‐561X), shale oil production was unfavorably compared to the liquefaction of coal. The article stated that coal liquefaction was less expensive, generated more oil, and created fewer environmental impacts than oil shale extraction. It cited a conversion ratio of 650 liters (170 U.S. gal; 140 imp gal) of oil per one ton of coal, as against 150 liters (40 U.S. gal; 33 imp gal) per one ton of shale oil.


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Environmental Impact of Shale Oil Mining

Environmental Impact of Shale Oil Mining Mining oil shale involves a number of environmental impacts, more pronounced in surface mining than in underground mining. They include acid drainage induced by the sudden rapid exposure and subsequent oxidation of formerly buried materials, the introduction of metals into surface‐water and groundwater, increased erosion, sulfur‐gas emissions, and air pollution caused by the production of particulates during processing, transport, and support activities. In 2002, about 97% of air pollution, 86% of total waste and 23% of water pollution in Estonia came from the power industry, which uses oil shale as the main resource for its power production. Oil‐shale extraction can damage the biological and recreational value of land and the ecosystem in the mining area. Combustion and thermal processing generate waste material. In addition, the atmospheric emissions from oil shale processing and combustion include carbon dioxide, a greenhouse gas. Environmentalists oppose production and usage of oil shale, as it creates even more greenhouse gases than conventional fossil fuels. Section 526 of the Energy Independence And Security Act prohibits United States government agencies from buying oil produced by processes that produce more greenhouse gas emissions than would traditional petroleum. Experimental in situ conversion processes and carbon capture and storage technologies may reduce some of these concerns in the future, but at the same time they may cause other problems, including groundwater pollution. Among the water contaminants commonly associated with oil shale processing are oxygen and nitrogen heterocyclic hydrocarbons. Commonly detected examples include quinoline derivatives, pyridine, and various alkyl homologues of pyridine (picoline, lutidine). Some commentators have expressed concerns over the oil shale industry's use of water. In 2002, the oil shale‐fired power industry used 91% of the water consumed in Estonia. Depending on technology, above‐ground retorting uses between one and five barrels of water per barrel of produced shale‐oil. A 2008 programmatic environmental impact statement issued by the U.S. Bureau of Land Management stated that surface mining and retort operations produce 2 to 10 U.S. gallons (7.6 to 38 l; 1.7 to 8.3 imp gal) of waste water per 1 short ton (0.91 t) of processed oil shale. In situ processing, according to one estimate, uses about one‐tenth as much water.


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Environmental Impact of Shale Oil Mining

Water concerns become particularly sensitive issues in arid regions, such as the western U.S. and Israel's Negev Desert, where plans exist to expand oil‐shale extraction despite a water shortage. Environmental activists, including members of Greenpeace, have organized strong protests against the oil shale industry. In one result, Queensland Energy Resources put the proposed Stuart Oil Shale Project in Australia on hold in 2004.


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Major Players in Shale Oil

Major Players in Shale Oil Ambre Energy Ambre Energy Limited is an Australian coal and oil shale company. It has offices in Brisbane and Salt Lake City. Ambre Energy was founded in June 2005 by Edek Choros, a geologist and mining engineer. In September 2005, Ambre Energy filed a patent for the Hybrid Energy System, a method for processing low value coal and other carbonaceous materials. In April 2006, Ambre Energy started negotiations with American oil shale technology company Oil‐Tech, Inc., incorporated in February 2000 in Utah. Oil‐Tech, Inc. was a developer of the Oil‐Tech staged electrically heated retort process for the oil shale pyrolysis. In October 2006, Ambre Energy and Oil‐Tech established Millennium Synfuels, LLC, which take over property rights of the retorting technology. By 30 June 2007 Ambre Energy acquired 6% of Oil Tech and 17 October 2007 it acquired 35%. Further Oil Tech become a wholly owned subsidiary of Ambre Energy and as of 21 July 2008 was merged into Ambre Energy. Ambre Energy is planning to build and operate a clean coal gasification plant at Felton Valley, 30 kilometers (19 mi) south west of Toowoomba, Queensland. The plan includes construction of an open‐pit coal mine, and carbon capture facility. At the final stage, the plant is expected to produce enough gas for production of 2.8 million tons per year of dimethyl ether and generate 650 MW of electricity. It is also expected to produce by‐products for fertilizer production, and olefins and plastics manufacturing. Ambre Energy operates a small Oil‐Tech‐type of shale oil extraction pilot plant and 34,000 acres (140 km2) of oil shale leases, approximately 40 miles (64 km) southeast of Vernal, Utah. In Oil‐Tech process, crushed oil shale is lifted by a conveyor system to the vertical retort, and is loaded into the retort from the top. The retort consists of a series of connected individual heating chambers, stacked atop each other. Heating rods extend into the centers of each of these chambers. The feed oil shale is heated to increasingly‐higher temperatures as it moves down the retort, attaining a temperature of 1,000 °F (540 °C) in the lowest chamber. The


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gases and vapors are vacuumed into a condensing unit. The spent shale is used for pre‐heating feed oil shale. The advantages of this technology are its modular design, which enhances its portability and adaptability, its low water requirements, its heating efficiency, and the relatively high quality of the resulting product. Contact Details: Ambre Energy Ltd Level 27 AMP Place 10 Eagle St Brisbane Qld 4000 Australia Website: http://ambreenergy.com/ American Shale Oil Corporation The American Shale Oil, LLC (AMSO), formerly known as EGL Oil Shale, LLC, is a developer of in‐situ shale oil extraction technology. It is owned 50% each by affiliates of IDT Corporation and Total S.A.. AMSO is based in Rifle, Colorado with offices in Newark, New Jersey and Livermore, California. American Shale Oil develops the "Conduction, Convection, Reflux" or CCR oil shale conversion process (formerly known as the EGL Resources Process). The process combines horizontal wells, which are heated by either recirculating hot fluid, such as steam, or a downhole burner, and other horizontal or vertical wells, which provide both heat transfer through refluxing of generated oil and a means to collect and produce the oil. In contrast to the Equity process, the steam circulates through a closed loop, and no fluids are injected into the formation. Heat transfer by the refluxing oil is expected to be somewhat faster than in the Shell ICP due to permeability generated by thermomechanical fracturing, but a similar quality of oil is expected. AMSO is leasing a 160 acres (650,000 m2) test tract in the Piceance Basin from the Bureau of Land Management. AMSO is currently preparing for a pilot test of its process in 2010. The pilot test aims to demonstrate recovery of shale oil from the illitic oil shale in Garden Gulch member at the bottom of the Green River formation, which is isolated from usable water in the upper part of the formation by the saline mineral zone.


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Contact Details: American Shale Oil, LLC PO Box 1370 Rifle, CO 81650 United States of America Website: www.amso.net Eesti Energia Eesti Energia AS is a state‐owned energy company in Estonia with its headquarters in Tallinn. The company operates in Estonia, Latvia, Lithuania, Finland and Jordan. In Estonia the company operates under the name Eesti Energia, while using the brand name Enefit for international operations. The main raw material for energy production – oil shale – is extracted from mines owned by the company. The government considered the initial public offering of shares of the company. Eesti Energia produces and sales electricity, heat and fuel (oil shale and shale oil) and provides customer and consulting services. On 5 November 2006, Eesti Energia signed a memorandum of understanding with the Government of Jordan being awarded with the exclusive right to study about one third of the resources of the El Lajjun oil shale deposit. Later this right was transferred to cover the Attarat Umm Ghudran oil shale deposit as the shallow aquifer that underlies the El Lajjun deposit provides fresh water to Amman and other municipalities in central Jordan. On 29 April 2008, Eesti Energia present a feasibility study to the Government of Jordan. According to the feasibility study, the company will establish a shale oil plant with capacity of 36,000 barrels per day. The shale oil plant will use a Galoter processing technology; the construction is slated to begin by 2015. On 30 April 2008, Eesti Energia signed an agreement with the Ministry of Energy and Mineral Resources of Jordan and the National Electricity Power Company of Jordan to develop the construction of an oil shale‐fired power station with capacity of 600‐900 MW in the country. The power station is expected to be operational by 2015.


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In Lithuania Eesti Energia is negotiating its participation in the Visaginas Nuclear Power Plant project. Contact Details: Eesti Energia AS Laki tn. 24, 12915 Tallinn Estonia Tel: +715‐2222 Fax: +715‐2200 Website: https://www.energia.ee Exxon Mobil Corporation Exxon Mobil Corporation (Exxon Mobil) is an integrated oil and gas company engaged in exploration and production, refining, and marketing of oil and natural gas. The company is also a major manufacturer and marketer of commodity petrochemicals, including olefins, aromatics, polyethylene, and polypropylene plastics, and a wide variety of specialty products. It also has interests in electric power generation facilities. The company conducts its business activities across the globe. Exxon Mobil operates through three segments: upstream, downstream, and chemicals. The upstream segment explores for and produces crude oil and natural gas. The company's upstream business has operations in 36 countries and includes five global companies. These companies are responsible for the corporation's exploration, development, production, gas and power marketing, and upstream‐research activities. The company's upstream portfolio includes operations in the U.S., Canada, South America, Europe, the Asia‐Pacific, Australia, the Middle East, Russia, the Caspian region, and Africa. At the end of FY2009, the company had liquid proved reserves of 11,651 million barrels and 68,007 billion cubic feet of natural gas. The company had 16,556 of crude oil and 9,760 of natural gas net production wells at the end of FY2009. Further, the company's net production of liquids, which include crude oil, natural


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gas liquids, synthetic oil, and bitumen for FY2009, was 2.4 million barrels/day. The company's production of natural gas and oil‐equivalent for FY2009 was 9,273 million cubic feet and 3.9 million barrels/day, respectively. Moreover, for FY2009, Exxon Mobil's net exploration acreage totaled 72 million acres in 33 countries. During the same year, the company replaced 133% of reserves produced, including asset sales, by adding two billion oil‐equivalent barrels to proved reserves while producing 1.5 billion net oil‐equivalent barrels. Further, Exxon's proved reserves of oil and gas during FY2009 was 23 million barrels. The company is also engaged in power generation. Exxon Mobil has interests in about 16,000 megawatts of power generation capacity worldwide. This includes a majority interest in the Castle Peak Power Company that generates electricity for consumers in Hong Kong and mainland China. The company's downstream activities include refining, supply, and fuels marketing. The company's refining and supply business focuses on providing fuel products and feedstock. Exxon Mobil manufactures clean fuels, lubes, and other high‐valued products. The refining and supply operations encompass a global network of manufacturing plants, transportation systems, and distribution centers that provide a range of fuels, lubricants, and other products and feedstocks to its customers around the world. At the end of FY2009, the company had interests in 37 refineries across 21 countries, with distillation capacity of 6.3 million barrels per day and lubricant basestock manufacturing capacity of 143 thousand barrels per day. In FY2009, Exxon Mobil's refinery throughput was 5.4 million barrels per day. The fuels marketing business operates throughout the world. The Exxon, Mobil, Esso, and On the Run brands serve motorists at nearly 28,000 service stations and provide over one million industrial and wholesale customers with fuel products. The company supplies lube base stocks and markets finished lubricants and specialty products. The chemicals division manufactures and sells petrochemicals. Exxon Mobil Chemical is an integrated manufacturer and global marketer of olefins, aromatics, fluids, synthetic rubber, polyethylene, polypropylene, oriented polypropylene packaging films, plasticizers, synthetic lubricant base stocks, additives for fuels and lubricants, zeolite catalysts, and other petrochemical products.


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Contact Details: Exxon Mobil Corporation 5959 Las Colinas Boulevard Irving, TX 75039 2298 United States of America Tel: +1‐972‐444‐1000 Fax: +1‐972‐444‐1348 Website: http://www.exxonmobil.com Fushun Mining Group The Fushun Mining Group is a large state‐owned coal and oil shale company in Fushun, Liaoning Province, China. The corporation consists of 35 companies with more than 40,000 employees. It operates in four business areas: coal mining, oil shale processing, machinery and services. FMG is one of the world's largest shale oil producers. The corporation consists of 35 companies with more than 40,000 employees. It operates mainly in four business areas: coal mining, oil shale processing, machinery and service industry. FMG is one of the world's largest shale oil producers. Commercial retorting of oil shale in FMG started in 1991 with an oil shale retorting plant was established as a part of Fushun Mining Group. Fushun Mining Group owns geological reserve for high grade oil shale about 3.5 billion tons, of which exploitable reserve is 920 million tons. Reserves are divided between East Open Pit (760 million tons) and West Open Pit (160 million tons). At the end of 2008, the company operated the largest oil shale plant in the world consisting eleven retorting units with 20 retorts in each unit, total 220 sets of Fushun‐type retort. Annual oil shale processing capacity is designed to be 11 million tons of oil shale, and annual shale oil yields to be 330,000 tons. Now FMG are constructing Alberta Taciuk processor (ATP) to treat small size oil shale (particulate oil shale) which can't be processed in Fushun retort. The 250 tons per hour ATP processor, scheduled to start operation at the end of 2010, is engineered and provided by Canadian company UMATAC Industrial Processes, a subsidiary of UMA Engineering Ltd of AECOM, as well as Polysius AG, a subsidiary of ThyssenKrupp AG.


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Contact Details: Website: http://english.fkjt.com.cn/index.aspx Hom Tov A.F.S.K. Hom Tov is a spin‐off of the A.F.S.K. Industries Group in Haifa, Israel. The company was founded by Shimon Kazanskyhas and Israel Feldman, the current managing director. A.F.S.K. Hom Tov has patented a shale oil extraction method, first presented at the end of 2006, whereby 6 megatons of oil shale is coated with 2 Mt of refinery waste bitumen and retorted to produce 3 Mt of oil (all per year). The company claims this technology to be more efficient and environmentally friendly than classical shale oil producing methods, but so far it has only been tested on a laboratory scale. The technology was developed by Moshe Gvirtz in the 1990s. The company plans to build a small (1‐2 ton/h) test plant in Haifa before building a full scale production plant in the Negev Desert south of Beer Sheba at Mishor Rotem, where the oil shale reserves are estimated at 1.25 gigatons. The Mishor Rotem plant would bring bitumen 80 kilometers (50 mi) by a new pipeline from the Ashdod refinery and return product along the same corridor. Contact Details: Unavailable Independent Energy Partners Independent Energy Partners, Inc. (IEP) is an American oil shale company Based in Denver, Colorado. It is a developer of the Geothermic Fuels Cells Process, an in‐situ shale oil extraction process. IEP owns the patents to the Geothermic Fuel Cell technology (U.S. Patent Nos. 6,684,948 B1‐Apparatus and Method For Heating Subterranean Formations Using Fuel Cells and 7,182,132 B2‐Linearly Scalable Geothermic Fuel Cells). It owns


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mineral interests in the oil shale reserves within the Green River Formation, including in Rio Blanco County, Colorado. In the Independent Energy Partners' Geothermic Fuels Cells Process (IEP GFC), a high‐temperature stack of fuel cells is placed in the formation. During an initial warm‐up period, the cells are fueled by an external source of natural gas. Afterwards, the process is able to fuel itself using oil shale gas generated by its own waste heat. The formation is fractured by rising fluid pressure in the heated zone. Alternatively, the formation can be pre‐fractured to enhance the shale oil flow between heating and producing wells. The company asserts a ratio of approximately 7 units of energy produced per unit used, when primary recovery is combined with gasification of the residual char and use of the resulting oil shale gas. The company asserts a ratio of approximately 18 units of energy produced per unit used, cause primary recovery is combined with gasification of the residual char and use of the resulting oil shale gas. IEP together with Petro Probe, Inc. and Phoenix Wyoming, Inc have formed the Oil Shale Alliance, Inc., a Delaware corporation for the purpose of commercialization of in‐situ oil shale technologies. Contact Details: Independent Energy Partners, Inc. TEC Building ‐ 11479 S. Pine Dr. Parker, CO 80134 United States of America Website: www.iepm.com Mountain West Energy Mountain West Energy, LLC is an American unconventional oil recovery technology research and development company based in Orem, Utah. It is a developer of the In‐situ Vapor Extraction Technology, an in‐situ shale oil extraction technology. The company owns 880 acres (3.6 km2) oil shale leases in the Uintah Basin, Uintah County, Utah. In 2008, Mountain West Energy won the Clean Technology and Energy Utah Innovation Award.


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In‐Situ Vapor Extraction technology is an experimental technology proposed for the in‐situ shale oil extraction. In addition, it is suitable for enhanced oil recovery and for extraction of heavy oil and oil sands. For conversion the kerogen in oil shale into shale oil, a high‐temperature gas is used. Gas is injected into the oil shale formation through an injection well. In the oil shale formation, gas transfers its heat to oil shale causing pyrolysis. As a result, shale oil vapors are generated. Resulted oil vapors are swept to the surface through an extraction well by the process gas. In the surface the condensation of oil vapors and separation of oil and gas conducted in a separator. After separation the gas is re‐heated and re‐circulated. In 2009, Mountain West Energy concluded an exclusive agreement with San Leon Energy granting the right of usage of the technology for a three year pilot project on the Tarfaya oil shale deposit of Morocco. San Leon signed a memorandum of understanding with the National Office of Hydrocarbon and Mining of Morocco on the Tarfaya oil shale deposit in May 2009. Contact Details: Mountain West Energy LLC PO Box 1313 American Fork, UT 84003 United States of America Fax: 801‐437‐1250 Website: www.mtnwestenergy.com


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Oil Shale Exploration Company Oil Shale Exploration Company (OSEC) is a Utah based oil shale exploration and development company. It has been involved in the development of oil shale since 2005. OSEC owns or leases more than 30,000 acres (120 km2) of oil shale property in the Green River Basin in Utah, containing more than 3‐4 billion barrels of shale oil. It also lease from the United States Bureau of Land Management the abandoned White River Oil Shale Mine 45 miles (72 km) southeast of Vernal, Utah. The White River Mine was developed by the White River Shale Corporation in the early 1980s. In 1986, after termination of operations, the mine and surface facilities were turned over to the Bureau of Land Management. OSEC intends to reopen the mine to supply oil shale for testing, development, and operation of a surface‐based 50,000 bbl/day RD&D oil shale retort facility. Originally OSEC planned to use the Alberta Taciuk Process (ATP). To use the ATP retort technology, OSEC entered in to a license agreement with AECOM, an owner of the ATP property rights. However, on 9 June 2008, OSEC announced it has signed an agreement with Petrobras and Mitsui according to which Petrobras agreed to undertake a technical, economic and environmental commercial feasibility study of Petrosix shale oil extraction technology for oil shale owned or leased by OSEC in Utah. Mitsui will provide advice the project management. Contact Details: Oil Shale Exploration Company 3601 Spring Hill Business Park Suite #201 Mobile, AL 36608 United States of America Tel: +1‐251‐380‐1100 Website: www.oilshaleexplorationcompany.com


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Petrobras Petroleo Brasileiro (Petrobras) is an integrated oil and gas company. It is one of the largest corporations in Brazil and one of the largest companies in Latin America in terms of oil and gas production and reserves. The company operates substantially all the refining capacity in Brazil. Most of the company's refineries are located in Southeastern Brazil. The company is also involved in the production of petrochemicals and fertilizers. Petrobras operates through five business segments: exploration and production; refining, transportation, and marketing; distribution; gas and power; and international. The exploration and production segment includes the company's oil and gas exploration, development, and production operations in Brazil. Production of crude oil and natural gas in Brazil is divided into onshore and offshore production, comprising 11% and 89% of total production in Brazil, respectively. The company's domestic oil and gas exploration and production efforts are primarily focused on three major basins offshore southeastern Brazil: Campos, Espirito Santo, and Santos. In FY2009, the company's oil and gas production from Brazil was 2,339.6 thousand barrels of oil equivalent per day (mboe/d) of which 86% was oil and 14% was natural gas. Brazil provided 90% of the company's worldwide production in FY2009 and accounted for 95% of the company's worldwide reserves at December 2009 on barrels of oil‐equivalent basis. Historically, approximately 85% of the company's total Brazilian production has been oil. As of December 31, 2009, Petrobras had 147 exploration agreements covering 225 blocks, and 33 evaluation plans. The company is exclusively responsible for conducting the exploration activities in 66 of the 147 exploration agreements. As of December 31, 2009, it had partnerships in exploration with 23 foreign and domestic companies, for 81 agreements. Petrobras undertakes exploration activities under 57 of its 81 partnership agreements. As of December 31, 2009, Petrobras' estimated reserves of crude oil and natural gas in Brazil totaled 11.56 billion barrels of oil equivalent (bboe), including 9.92 billion barrels of crude oil and natural gas liquids and 261.24 billion cubic meters (bnm3) of natural gas.


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The refining, transportation, and marketing segment undertakes activities related to refining, import, and export of oil products and crude oil, and petrochemicals and fertilizers in Brazil. The domestic refining capacity of Petrobras constitutes 92% of Brazil's total refining capacity. The company supplies almost all of the refined product needs of third‐party wholesalers, exporters, and petrochemical companies in addition to the needs of Petrobras' distribution segment. Petrobras owns and operates eleven refineries in Brazil; with a total net distillation capacity of 1,942 thousand barrels per day (mbbl/d), which makes it the world's eighth largest refiner among publicly traded companies. Petrobras operates a large and complex infrastructure of pipelines and terminals and a shipping fleet to transport oil products and crude oil to domestic and export markets. Most of its refineries are located near its crude oil pipelines, storage facilities, refined product pipelines, and major petrochemical facilities, facilitating access to crude oil supplies and end‐users. The company owns and operates an extensive network of crude oil and oil products pipelines in Brazil that connect its terminals, refineries, and other primary distribution points. As of December 31, 2009, the company's onshore and offshore crude oil and oil products pipelines extended 13,996 kilometers (km). Petrobras operates 27 marine storage terminals and 20 other tank farms with nominal aggregate storage capacity of 65 million barrels. The company's marine terminals handle an average 10,000 tankers annually. Petrobras also imports and exports crude oil and oil products. It imports certain oil products, particularly diesel. The company's supply segment also includes petrochemical and fertilizer operations. The distribution segment is engaged in the distribution of company's oil products to wholesalers and through its Petrobras Distribuidora retail network in Brazil. The company supplies and operates Brazil's leading service station network, Petrobras Distribuidora, which accounts for about 38% of the total Brazilian distribution market. Petrobras Distribuidora distributes oil products, ethanol, and biodiesel, and vehicular natural gas to retail, commercial, and industrial customers. As of December 31, 2009, Petrobras Distribuidora network included 7,221 service stations. In FY2009, Petrobras Distribuidora sold the equivalent of 767.4 mbbl/d of oil products to wholesale and retail customers, of which the largest portion (40.7%) was diesel.


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The gas and power segment is engaged in gas transmission and distribution, electric power generation using natural gas and renewable energy sources, and biofuels operations in Brazil. The company's natural gas business comprises three activities: transportation (building and operating the Brazilian natural gas pipeline network); commercialization (purchase and resale); and equity participation in distribution companies that sell natural gas to end‐users. The company's natural gas transportation system in Brazil comprises two main pipeline networks as well as Urucu‐Coari pipeline. The 5,030 km Malha Sudeste (Southeast Network) connects the company's main offshore natural gas producing fields in the Campos and Espirito Santo basins to the markets of the Southeast Region, including Rio de Janeiro and Sao Paulo. This network includes the 2,593 km Brazilian portion of the Bolivia‐Brazil natural gas pipeline. The 1,968 km Malha Nordeste (Northeast Network) transmits gas from onshore and offshore natural gas fields in the Northeast to consumers in that region. In the Northern region, the 661 km Urucu‐Coari pipeline connects the Solimoes basin to Coari. The company's gas and power segment supplied an average 46.1 million cubic meters per day (mmm3/d) of natural gas in FY2009. The company also develops and operates gas‐fired thermoelectric power generation plants. Petrobras currently owns stakes in 26 thermoelectric power plants, and controls 16 of them. Petrobras also aims to produce biodiesel in Brazil and actively participates in Brazil's growing ethanol industry, particularly the transportation and exportation of ethanol to other countries. The company does not produce ethanol, but distributes it through its distribution business segment. The company's gas and power segment plans to expand its participation in the ethanol business through partnerships with ethanol producers and international customers where the company's role would primarily be as a transporter and exporter of Brazilian ethanol. The company owns three biodiesel plants located in Northeastern Brazil at Candeias and Quixada and in Southeastern Brazil at Montes Claros with a combined capacity of 2.9 million barrels per day (bbl/d). In FY2009, Petrobras acquired 40.4% of Total Agroindustria Canavieira (Total). Total owns a plant with ethanol production capacity of 1.7 mbbl/d.


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The international segment comprises exploration and production, supply (refining, petrochemicals, and fertilizers), distribution, and natural gas and energy operations in 24 countries outside of Brazil. In Latin America, the company's operations extend from exploration and production to refining, marketing, retail services, and natural gas pipelines. In North America, the company produces oil and gas and has refining operations in the U.S.. In Africa, the company produces oil in Angola; and in Asia, the company has refining operations in Japan. In other countries, the company is engaged only in oil and gas exploration. Contact Details: Petroleo Brasileiro S.A. (Petrobras) Avenida Republica do Chile 65 Centro CEP 20031 912 Rio de Janeiro Brazil Tel: +55‐21‐3224‐4477 Fax: +55‐21‐3224‐6055 Website: http://www2.petrobras.com.br/ingles/index.asp Queensland Energy Resources Queensland Energy Resources Limited (QERL) is an Australian oil shale mining and shale oil extraction company with the headquarter in Brisbane. It is a developer of the Stuart and McFarlane oil shale projects. Queensland Energy Resources holds mining tenement rights to several oil shale deposits in Queensland, Australia. Two major resources are Stuart, located near Gladstone, and McFarlane, located near Proserpine. It owns also pilot plant facility in Rifle, Colorado, used for testing oil shale from its deposits. On 10 May 2010, the company announced a plan for construction of a small‐scale shale‐oil demonstration plant at Yarwun. The McFarlane oil shale resource is one of Australia's largest. However, on 24 August 2008, the Queensland Government announced an oil‐shale mining moratorium over the McFarlane deposit for 20 years.


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Contact Details: QER GPO Box 5214 Brisbane Qld 4001 Australia Tel: +61‐7‐3222‐0600 Fax: +61‐7‐3222‐0611 Website: http://www.qer.com.au Red Leaf Resources Red Leaf Resources, Inc, is a developer of the EcoShale In‐Capsule Process, a shale oil extraction technology. It has its headquarters in Salt Lake City, Utah. Red Leaf Resources is a developer of the shale oil extraction technology EcoShale In‐Capsule Process. In the Red‐Leaf Resources EcoShale In‐Capsule Process a hot gas is generated by burning natural gas or pyrolysis gas. Generated hot gas is then circulated through oil shale rubble using sets of parallel pipes. The heat is transferred to the shale through the pipe walls rather than being injected directly into the rubble, thereby avoiding dilution of the product hydrocarbons with the heating gas. The oil shale rubble is enclosed by a low‐cost earthen impoundment structure to prevent environmental contamination and to provide easier and more rapid reclamation after the extraction process is finished. Heat from the spent shale is recovered for enhancing the process's energy efficiency by passing cool gas through pipes and then using it for preheating adjacent capsules. Red Leaf Resources controls oil shale leases of about 17,000 acres (69 km2) on state land in Utah. The acreage represents about 1.1 billion barrels (170×10^6 m3) of shale oil. The company is progressing through front‐end engineering design and plans to commence commercial production in 2011. Contact Details: Red Leaf Resources, Inc.


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200 W. Civic Center Dr., Suite 190 Sandy, UT 84070 United States of America Website: www.redleafinc.com Shale Technologies LLC Shale Technologies, LLC is an American privately held oil shale company with the headquarter in Rifle, Colorado. It is an owner of the proprietary information relating to the Paraho oil shale retorting technologies (Paraho Direct and Paraho Indirect). The Paraho Direct is an American version of a vertical shaft retort similar to the Kiviter and Fushun retorts. This technology is used in the company's pilot plant facility in Rifle. Contact Details: Shale Technologies, LLC 1354 County Road 246 Rifle, Colorado 81650 United States of America Phone: +1‐970‐625‐3193 Fax: +1‐970‐625‐9898 Website: www.shaletechnologies.com


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Section 4: Conclusion


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Appendix

Appendix

Figure 25: Hydraulic Fracture Job at Marcellus Shale Well

Source: Chesapeake Energy


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Appendix

Figure 26: Rotary Drilling Rig

Source: Bureau of Land Management


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Appendix

Figure 27: Directional Drilling

Source: Schlumberger


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Appendix

Figure 28: Hypothetical Well Casing

Source: CRS


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Appendix

Figure 29: Idealized Hydraulic Fracture

Source: CRS


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Appendix

Figure 30: Methane in Gas Shales Occurs as the following:

Source: EIA

Figure 31: Estimated Recovery from Barnett Shale

Source: EIA


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Appendix

Figure 32: Athabasca Oil Sands

Source: NRCan


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Appendix

Figure 33: Syncrude Mine at Athabasca Oil Sands

Source: Syncrude


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Appendix

Figure 34: Marcellus Shale

Source: Misc.


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Appendix

Figure 35: Trends in Shale Gas Production (MMcf/Day)

Source: Navigant


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Appendix

Table 2: Comparison of Data for the Gas Shales in the United States

Source: EIA


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Appendix

Figure 36: Barnett Shale in the Fort Worth Basin

Source: U.S. DOE


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Appendix

Table 3: Stratigraphy of the Barnett Shale

Source: U.S. DOE


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Appendix

Figure 37: Fayetteville Shale in the Arkoma Basin

Source: U.S. DOE


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Appendix

Table 4: Stratigraphy of the Fayetteville Shale

Source: U.S. DOE


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Appendix

Figure 38: Haynesville Shale in the Texas & Louisiana Basin

Source: U.S. DOE


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Appendix

Table 5: Stratigraphy of the Haynesville Shale

Source: U.S. DOE


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Appendix

Figure 39: Comparison of Target Shale Depth and Base of Treatable Groundwater

Source: NREL


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Glossary

Glossary Absorptance: The ratio of the radiation absorbed by a surface to the total energy falling on that surface described as a percentage. Access Charge: A charge paid by all market participants withdrawing energy from the ISO controlled grid. The access charge will recover the portion of a utility's transmission revenue requirement not recovered through the variable usage charge. Active Solar Energy: Solar radiation used by special equipment to provide space heating, hot water or electricity. Active Solar Energy System: A system designed to convert solar radiation into usable energy for space, water heating, or other uses. It requires a mechanical device, usually a pump or fan, to collect the sun's energy. ACOP (Adjusted Coefficient of Performance): A standard rating term that was used to rate the efficiency of heat pumps in California. ACOP was replaced by Heating Seasonal Performance Factor (HSPF) in 1988. Addition: An alteration to an existing building that increases conditioned space. Adjustment Bid: A bid that is used by the ISO to adjust supply or demand when congestion is anticipated. Adverse Hydro: Water conditions limiting the production of hydroelectric power. In years having below‐normal levels of rain and snow, and in seasons having less‐than‐usual runoff from mountain snow pack, there is then less water available for hydro energy production. After‐Market: broad term that applies to any change after the original purchase, such as adding equipment not a part of the original purchase. As applied to alternative fuel vehicles, it refers to conversion devices or kits for conventional fuel vehicles.


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Glossary

Aggregator: An entity responsible for planning, scheduling, accounting, billing, and settlement for energy deliveries from the aggregator's portfolio of sellers and/or buyers. Aggregators seek to bring together customers or generators so they can buy or sell power in bulk, making a profit on the transaction. Air Change: The replacement of a quantity of air in a space within a given period of time, typically expressed as air changes per hour. If a building has one air change per hour, this is equivalent to all of the air in the building being replaced in a one‐hour period. Air Conditioner: An assembly of equipment for air treatment consisting of a means for ventilation, air circulation, air cleaning, and heat transfer (either heating or cooling). The unit usually consists of an evaporator or cooling coil, and an electrically‐driven compressor and condenser combination. Air Film: A layer of still air adjacent to a surface which provides some thermal resistance. Air Film Coefficient: A measure of the heat transfer through an air film. Air‐To‐Air Heat Exchanger: A device with separate air chambers that transfers heat between the conditioned air being exhausted and the outside air being supplied to a building. Air Pollution: Unwanted particles, mist or gases put into the atmosphere as a result of motor vehicle exhaust, the operation of industrial facilities or other human activity. Alteration: Any change or modification to a building's construction. Ambient Air Temperature: Surrounding temperature, such as the outdoor air temperature around a building. Alcohol Fuels: A class of liquid chemicals that have certain combinations of hydrogen, carbon and oxygen, and that are capable of being used as fuel.


262

Glossary

Alternating Current: (AC) Flow of electricity that constantly changes direction between positive and negative sides. Almost all power produced by electric utilities in the United States moves in current that shifts direction at a rate of 60 times per second. Alternative (transportation) Fuels: as defined by the National Energy Policy Act (EPAct) the fuels are: methanol, denatured ethanol and other alcohols, separately or in mixtures of 85% by volume or more (or other percentage not less than 70% as determined by U.S. Department of Energy rule) with gasoline or other fuels; CNG; LNG; LPG; hydrogen; "coal‐derived liquid fuels;" fuels "other than alcohols" derived from "biological materials;" electricity, or any other fuel determined to be "substantially not petroleum" and yielding "substantial energy security benefits and substantial environmental benefits." Alternative Fuel Vehicle (AFV): motor vehicles that run on fuels other than petroleum‐based fuels. As defined by the National Energy Policy Act (EPAct), this excludes reformulated gasoline as an alternative fuel. Ambient: The surrounding atmosphere; encompassing on all sides; the environment surrounding a body but undisturbed or unaffected by it. ANSI: American National Standards Institute is the national organization that coordinates development and maintenance of consensus standards and sets rules for fairness in their development. ANSI also represents the USA in developing international standards. Ancillary Services: The services other than scheduled energy that are required to maintain system reliability and meet WSCC/NERC operating criteria. Such services include spinning, non‐spinning, and replacement reserves, voltage control, and black start capability. Ampere (Amp): The unit of measure that tells how much electricity flows through a conductor. It is like using cubic feet per second to measure the flow of water. For example, a 1,200 watt, 120‐volt hair dryer pulls 10 amperes of electric current (watts divided by volts).


263

Glossary

Angle of Incidence: The angle that the sun's rays make with a line perpendicular to a surface. The angle of incidence determines the percentage of direct sunshine intercepted by a surface. Annual Maximum Demand: The greatest of all demands of the electrical load which occurred during a prescribed interval in a calendar year. Animal Waste Conversion: Process of obtaining energy from animal wastes. This is a type of biomass energy. AFUE (Annual Fuel Utilization Efficiency): A measure of heating efficiency, in consistent units, determined by applying the federal test method for furnaces. This value is intended to represent the ratio of heat transferred to the conditioned space by the fuel energy supplied over one year. Anthracite: Hard coal, found deep in the earth. It burns very hot, with little flame. It usually has a heating value of 12,000‐15,000 British thermal units (Btus) per pound. Appliance Efficiency Standards: California Code of Regulations, Title 20, Chapter 2, Subchapter 4: Energy Conservation, Article 4: Appliance Efficiency Standards. Appliance Efficiency Standards regulate the minimum performance requirements for appliances sold in California and apply to refrigerators, freezers, room air conditioners, central air conditioners, gas space heaters, water heaters, plumbing fittings, fluorescent lamp ballasts and luminaires, and ignition devices for gas cooking appliances and gas pool heaters. New National Appliance Standards are in place for some of these appliances and will become effective for others at a future date. Appliance Saturation: A percentage telling what proportion of all households in a given geographical area have a certain appliance. Applicant: Applicant means any person who submits an application for certification pursuant to the provisions of this division, including, but not limited to, any person who explores for or develops geothermal resources. Application: Application means any request for certification of any site and related facility filed in accordance with the procedures established pursuant to this division.


264

Glossary

An applicant for a geothermal power‐plant and related facilities may propose more than one site and related geothermal facilities in the same application. Area Load: The total amount of electricity being used at a given point in time by all consumers in a utility's service territory. ASHRAE: Acronym for American Society of Heating, Refrigerating and Air‐ Conditioning Engineers. Ash: Non‐organic, non‐flammable substance left over after combustible material has been completely burned. Associated Gas: Natural gas that can be developed for commercial use, and which is found in contact with oil in naturally occurring underground formations. Atgas: Synthetic gas produced by dissolving coal in a bath of molten iron. The process was developed by Applied Technology, Inc. Synthetic gas may be used as a substitute for natural gas in industrial and home uses. Atomic Energy Commission: The independent civilian agency of the federal government with statutory responsibility to supervise and promote use of nuclear energy. Functions were taken over in 1974 by the Energy Research and Development Administration (now part of the U.S. Department of Energy) and the Nuclear Regulatory Commission. Atomic Nucleus: The positively charged core of an atom. Auxiliary Energy Subsystem: Equipment using conventional fuel to supplement the energy output of a solar system. This might be, for example, an oil‐ fueled generator that adds to the electrical output of a substitutes for the solar system during long overcast periods when there is not enough sunlight. Auxiliary Equipment: Extra machinery needed to support the operation of a power plant or other large facility. Average Cost: The revenue requirement of a utility divided by the utility's sales. Average cost typically includes the costs of existing power plants, transmission, and


265

Glossary

distribution lines, and other facilities used by a utility to serve its customers. It also included operating and maintenance, tax, and fuel expenses. Average Demand: The energy demand in a given geographical area over a period of time. For example, the number of kilowatt‐hours used in a 24‐hour period, divided by 24, tells the average demand for that period. Average Hydro: Rain, snow and runoff conditions that provide water for hydroelectric generation equal to the most commonly occurring levels. Average hydro usually is a mean indicating the levels experienced most often in a 104‐year period. Avoided Cost: (Regulatory) The amount of money that an electric utility would need to spend for the next increment of electric generation to produce or purchase elsewhere the power that it instead buys from a co‐generator or small‐power producer. Federal law establishes broad guidelines for determining how much a qualifying facility (QF) gets paid for power sold to the utility. Avoided Cost: The cost the utility would incur but for the existence of an independent generator or other energy service option. Avoided cost rates have been used as the power purchase price utilities offer independent suppliers (see Qualifying Facilities). Azimuth: The angular distance between true south and the point on the horizon directly below the sun. Typically used as an input for opaque surfaces and windows in computer programs for calculating the energy performance of buildings. Balanced Schedule: A Scheduling Coordinator's schedule is balanced when generation, adjusted for transmission losses, equals demand. Ballast: A device that provides starting voltage and limits the current during normal operation in electrical discharge lamps (such as fluorescent lamps). Barrel: In the petroleum industry, a barrel is 42 U.S. gallons. One barrel of oil has an energy content of 6 million British thermal units. It takes one barrel of oil to make enough gasoline to drive an average car from Los Angeles to San Francisco and back (at 18 miles per gallon over the 700‐mile round trip).


266

Glossary

Barrels Per Day Equivalent (BPD‐Equivalent): A unit of measure that tells how much oil would have to be burned to produce the same amount of energy. For example, California's hydroelectric generation in 1983 was 58,000 barrels per day equivalent. Base Load: The lowest level of power production needs during a season or year. Biodiesel: Biodiesel is a type of biofuel made by combining animal fat or vegetable oil (such as soybean oil or recycled restaurant grease) with alcohol and can be directly substituted for diesel as a stand‐alone fuel (called B100, for 100% biodiesel) or be used as an additive (called B20, for 20% bio‐diesel). Biodiesel can be used in vehicles (newer cars, usually 1994 or later, are required for B100) and is beginning to be used in on‐site electricity generation and heating applications. Biofuel: Biofuels are renewable liquid fuels made from plant matter rather than fossil fuels. Today’s primary biofuels are ethanol and biodiesel. Biofuels can help reduce air toxics emissions, greenhouse gas buildup, and dependence on imported oil, while supporting United States agriculture. Biomass: A type of renewable fuels that includes trees and other crops and residues, solid waste, sewage, and liquid fuels derived from agricultural products. Some of the common energy sources derived from biomass are landfill gas, anaerobic digester gas, methane, and biofuels including biodiesel, bio‐oil, and ethanol. Biomass gasification is an emerging clean energy technology. See the Bioenergy section of the MTC website for more details. Biomass Gasification: This is a highly efficient process for converting woody biomass (wood chips, pellets, and other wood residues) into energy that can then be converted into electricity. Bio‐oil: Solid biomass can be converted into a carbon‐rich liquid which can be used to produce chemicals and fuels. This liquid, or bio‐oil, is produced through a process called pyrolysis, in which the biomass is broken down into liquid in an oxygen‐free, high‐temperature environment. Carbon Dioxide (CO2): Carbon dioxide is one of the most common greenhouse gases in the atmosphere and is regulated through the natural carbon cycle, where carbon


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dioxide is emitted into the air and reabsorbed by vegetation and water. This cycle is upset by the emission of additional carbon dioxide from human activities. Because natural cycles cannot absorb these additional emissions, a large portion of carbon dioxide remains in the atmosphere and increases climate change. The primary human source of carbon dioxide is the burning of fossil fuels for electricity, heat, and transportation. Carbon Monoxide (CO): This gas is created when the carbon in fossil fuels is not entirely burned during combustion and can have serious impacts on human health. The majority of carbon monoxide emissions come from the use of fossil fuels in transportation. Lesser quantities come from electricity production and natural events like forest fires. Improperly‐adjusted gas stoves can also release high levels of indoor carbon monoxide. When released into the air, carbon monoxide can exacerbate heart disease and damage the human nervous system. Carbon monoxide also has an indirect effect on global climate change, and is a criteria pollutant. Chemical Energy: Chemical energy is generated from chemical reactions in which the chemical bonds of a substance are broken and rearranged to form new molecules that can provide energy. Chemical energy can be transformed into thermal energy, mechanical energy, and electrical energy. Respective examples of these conversions include burning wood, digestion of food, and the chemical process used in nuclear power plants. Clean Energy: Clean energy can be generally defined as energy from renewable sources such as biomass, wind, or solar power. The goal of clean energy is to have a low environmental impact, with low or zero emissions, and a minimal impact on the physical surroundings. Hydropower can be defined as clean energy due to zero emissions, but today's hydropower still often has substantial impacts on aquatic ecosystems. Waste‐burning and wood‐burning plants that capture emissions can be clean energy generators. Fossil fuels do not provide clean energy because of their emissions and environmental impacts. Learn more about clean energy technologies. Coal: Coal is a fossil fuel that currently provides about half of the country’s electricity. Coal power plants create more emissions per unit of generated electricity than other fuels, and are required to install pollution control devices to curb pollution. Like natural gas and oil, coal is a nonrenewable resource because it cannot be replenished on a human time scale.


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Concentrating Solar Power (CSP): Concentrating solar power plants collect the sun’s energy through different mirror configurations, converting the high‐temperature heat collected into electricity through use of a generator. There are three different types of CSP systems: trough systems, power tower systems, and solar dish/engine systems. Each system uses a different method for collecting solar energy. Criteria Pollutants: These are man‐made pollutants such as carbon monoxide, nitrogen oxides, nonmethane volatile organic compounds (NMVOCs), and sulfur dioxide that have indirect effects on global warming. They are primarily emitted as byproducts of fossil fuel and biomass combustion. Lead and particulates are also criteria pollutants. Although these pollutants only remain in the atmosphere for a short time, the chemical reactions that remove carbon monoxide, NMVOCs, and nitrogen oxides from the atmosphere promote the formation of ozone, which is harmful to people and animals at ground level. Daylighting (Natural Lighting): Daylighting is the use of various design techniques to enhance the use of natural light in a building. Daylighting decreases reliance on electric lights and mechanical systems through the use of windows, skylights, light shelves, and other techniques that maximize sunlight while minimizing glare and excess heat. Green buildings often use daylighting. Direct Current (DC): A direct current means that electrical current flows in a single direction through a conductor. DC must be converted to alternating current (AC) to be used for a typical 120‐volt or 220‐volt household appliance. DC is used directly in industrial applications and appliances that use battery power. Electric Utility: An entity that owns and operates transmission and/or distribution facilities and delivers electric energy to customers. It may be an investor‐owned, municipal, state, or federal electric utility, or a rural electric cooperative. Find your local Massachusetts utility. Electrical Circuit: The path followed by electrons from a power source such as a photovoltaic (solar) panel, through an electrical system to create light, motion, battery power, and other power. The circuit is completed when the electrons return to the power source, creating a continuous flow of electricity.


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Electrical Current: The flow of electrons through an electrical wire, or transmission or distribution line. Current is measured in amperes. Electrical Energy: Electrical energy is the flow of electrons along a circuit. The movement of electrons creates an electric current which can be connected to an end use like lighting or appliances. Electrical energy can also be transformed into mechanical energy (using an elevator) or thermal energy (by using a space heater). Conversely, mechanical, thermal, and other forms of energy can be converted to create electricity, as in wind turbines and biomass facilities respectively. Electrical energy is usually measured in kilowatt‐hours (kWh) or megawatt‐hours (MW). Electrical Grid (Electric Grid): The grid can most easily be understood as a web of connections between power plants and the consumer of electricity. This web transfers electricity from power plants through transmission substations, high voltage transmission lines, distribution substations, and distribution lines to the consumer. Emissions: Emissions are gases and particles released into the air as byproducts of a natural or man‐made process. One of these processes is the burning of fuels to create electricity and other forms of energy. The emissions from burning fossil fuels contribute significantly to global warming and poor air quality. A small set of emissions are responsible for the majority of human impacts on global climate change and health. These gases and particulates come from a variety of sources and can be categorized as greenhouse gas emissions (which affect climate change) and air quality emissions (which affect health as well as the environment). Energy: The ability to do work or the ability to move an object. Energy occurs in two primary states, potential and kinetic. This energy can occur in a number of forms including electrical, thermal (heat), chemical, radiant, and mechanical energy. Energy Efficiency: Energy efficiency refers to products or systems designed to use less energy for the same or higher performance than regular products or systems. Energy‐efficient buildings are designed to use less energy than traditional buildings; see green buildings for details. Saving energy through efficiency also saves money on utility bills and protects the environment by reducing fossil fuel consumption and emissions. Combining energy efficiency with renewable energy is even better for the environment.


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Ethanol: A biofuel derived from grain and corn that can be used instead of or as an additive to gasoline. Ethanol is primarily used in transportation applications. Fossil Fuels: Fossil fuels (oil, coal, and natural gas) come from the long‐term decomposition of plant and animal matter from millions of years ago. These fossil fuels are the main sources of energy used by Americans today to generate electricity, heat, and fuel for transportation. Because fossil fuels cannot be replenished on a human time scale once they are extracted and burned, they are a non‐renewable resource. The byproducts of fossil fuel combustion, including carbon dioxide (CO2) and methane, are emissions that increase the “greenhouse” effect that causes global climate change. Fuel Cells: A fuel cell is an electrochemical device used to create electricity. Much like a battery, it converts chemical energy to electrical energy. But unlike a typical battery, which holds a limited fuel supply in a sealed container, a fuel cell uses an ongoing supply of fuel to create a continuous flow of electricity. Fuels like natural gas and methane gas are used to produce hydrogen and oxygen. The hydrogen and oxygen are then fed to two terminals in the fuel cell to cause a chemical reaction that produces electricity with heat and water as byproducts. Learn more about fuel cells. Global Climate Change (GCC): Global climate change is a significant alteration from one climatic condition to another, beyond the usual alterations in various climates throughout the globe, as the result of human activities. The greatest of these is fossil fuel combustion, which traps greenhouse gases in the atmosphere that cause gradual changes in Earth’s temperatures over hundreds of years. The term “global warming” may also be used but refers more specifically to temperature, whereas global climate change encompasses the broader changes associated with elevated greenhouse gas levels, such as dryer deserts, increased numbers of hurricanes, and warmer oceans. Greenhouse Gases: While gases like carbon dioxide, methane, nitrous oxide, ozone, and water vapor naturally occur in earth’s atmosphere, human activities can artificially increase concentrations, notably through fossil fuel combustion to produce heat and electricity. These gases are dubbed greenhouse gases because they remain in the atmosphere and intensify the sun’s heat as it radiates to the earth, similar to a greenhouse’s glass walls heating and moisturizing the air inside of


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it. Greenhouse gases are the primary source of global climate change (GCC). Learn more about greenhouse gases and GCC. Hydropower (Hydroelectricity): Hydropower, or hydroelectricity, is a clean energy technology that uses moving water to produce electricity. In a hydroelectric system, water flows downstream through a hydraulic turbine that spins and in turn rotates adjacent generators to transform the rotational energy into electricity. When the water exits the turbine it is returned to the stream or riverbed. Hydraulic turbines are generally located near dams that increase the height from which water falls to increase the potential for energy generation. Learn more about hydropower. Investor‐Owned Utility: A publicly held utility that typically serves multiple towns or regions and often combines transmission and distribution services. Standards, rates, and other aspects of investor‐owned utilities are regulated by the Massachusetts DTE. These utilities are also required under the Massachusetts Electric Restructuring Act of 1997 to collect energy efficiency and renewable energy funding for use in public funds. Joule (J): A unit of electrical energy equal to the work done when a current of one ampere passes through a resistance of one ohm for one second (synonymous with watt‐second). Kilowatt (kW): A standard unit of electrical power equal to 1000 watts. The term “kilowatt” (in addition to the measurements of “watt” and “megawatt”) is commonly used to describe the capacity of an electric generator, particularly in reference to small solar photovoltaic and other generating systems. Kilowatt‐hour (kWh): 1,000 watts or 1 kilowatt acting over a period of 1 hour. One kilowatt‐hour is equal to 1,000 watt‐hours and is equal to 3600 kJ. The primary difference between a kilowatt and a kilowatt‐hour is that “kilowatt” measures the capacity of an electric generator and “kilowatt‐hour” measures the actual amount of electricity it produces over a certain period of time. Kinetic Energy: Kinetic energy is the release of potential energy to create motion, ultimately to do work. An example of kinetic energy is the energy carried by wind.


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Landfill Gas: Landfill gas is created when food, wood, and other organic waste in a landfill decomposes under anaerobic – or oxygen‐free – conditions. Because landfill gas is about 50% methane, it can be used as a source of energy similar to natural gas (which is about 90% methane). Carbon dioxide (CO2) is the other primary component of landfill gas. Since landfill gas is generated continuously, it provides a reliable fuel for a range of energy applications, including heating and electric power generation. Mechanical Energy: Mechanical energy refers to an object that is doing work by being in motion. Mechanical energy can be transformed into electrical energy or thermal energy. Examples include wind turbines and refrigerators, respectively. Megawatt (MW): A standard unit of electrical power equal to 1,000 kilowatts, or 1 million watts. Like watts and kilowatts, the term “megawatt” is used as a standard measure of electric power plant generating capacity. It is most commonly used for large systems like wind turbines, biomass plants, and coal, natural gas, and nuclear plants. Megawatt‐hour (MWh): 1 megawatt acting over a period of 1 hour. One megawatt‐hour is equal to 1,000 kilowatt‐hours or 1 million watt‐hours. The primary difference between a megawatt and a megawatt‐hour is that “megawatt” measures the capacity of an electric generator and “megawatt‐hour” measures the actual amount of electricity it produces over a certain period of time. Methane Gas: Methane is a common, naturally occurring and human‐produced gas that can have serious climate change impacts when it is not captured. When captured, it can be used as a fuel. Methane produced by decomposition in landfills and through other human activities can be burned to produce energy for turbines and even fuel cells. Municipal Utility: Municipally owned utilities are owned and operated by the individual towns and cities they serve. These utilities are responsible for customer billing, wire, pole, and meter maintenance, connecting new customers, distribution of electricity, and restoring power after an outage. These utilities are not required to collect energy efficiency and renewable energy funding for use in public funds, but some have elected to establish their own energy efficiency funds and install clean energy in their local service areas.


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Natural Gas: Natural gas is a fossil fuel made of about 50% methane, a potent greenhouse gas. Like coal and oil, natural gas is a nonrenewable resource because it cannot be replenished on a human time scale. According to the U.S. EPA, natural gas power plants provide about 14% of the electricity produced in the United States, ranking third behind coal and nuclear power. Nitrogen Oxides (NOx): Nitrogen oxides are byproducts of nitrous oxide from fossil fuel combustion. They are called criteria pollutants (along with carbon monoxide, sulfur dioxide, nonmethane volatile organic compounds, lead, and particulates). They contribute to acid rain, smog, and respiratory problems, and have an indirect impact on global climate change. Nitrous Oxides (N2O): Nitrous oxides are greenhouse gases. The natural sources and cycles of nitrous oxides are not as well understood as those of carbon dioxide and methane, but their primary natural source appears to be bacterial breakdown of chemicals in soil. Human activities that increase nitrous oxide levels in the atmosphere (and the corresponding risk of climate change) include fossil fuel burning, use of nitrogen‐based fertilizers in farming, and emissions from industrial processes. Nuclear Energy: Nuclear energy relies on the splitting of uranium atoms in a process called fission, which generates heat for producing steam that then turns a turbine to produce electricity. While nuclear power plants do not emit air pollutants, nuclear wastes and abandoned uranium mines pose health risks from radiation for as long as 250,000 years if not contained properly. Ohm: A measure of the electrical resistance of a material equal to the resistance of a circuit in which the potential difference of 1 volt produces a current of 1 ampere. Ohms are used by utilities and electrical engineers to measure the resistance of wires conducting electricity. Oil: Oil, a liquid fossil fuel, is used in enormous quantities worldwide. Oil contains carbon, nitrogen, sulfur, mercury, lead, and arsenic, all of which are emitted when oil is burned to produce energy. Advancements have been made in producing cleaner‐burning oil; however, its emissions are still significant. Oil is a


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nonrenewable resource, like coal and natural gas, and oil spills have caused severe damage to natural environments. Ozone (O3): Ozone is a unique emission because it is not directly produced by human sources. Instead, it is created as a result of chemical reactions between human‐produced emissions and other gases in the atmosphere. Ozone is also unique because it is considered beneficial in some places and detrimental in others. When ozone is in the earth's upper atmosphere it is considered good because it protects the earth from the sun's radiation. But when ozone is created in the lower atmosphere, it creates smog which can cause respiratory problems and damage to plant and animal life. In the lower atmosphere, ozone is typically created when volatile organic compounds (VOCs) or nitrogen oxides react with other atmospheric gases. Particulates: Particulates are criteria pollutants that include dust, dirt, soot, smoke and other miniscule solids released into the air and can affect heart and respiratory health. Particulates can be composed of many different chemicals. Their human sources vary but come largely from construction activities like road building. Particulates can also form when emissions from fossil fuels react with sunlight and water vapor to create solid particles in the air. Potential Energy: Potential energy is stored energy, waiting to be released. An example of potential energy is the energy embodied in ocean waves, which can be captured through ocean energy technologies to produce kinetic energy. Power: Power is the rate at which work is done. The ratio of work and time determines the amount of power used. For example, imagine that two people start at the bottom of a mountain with the goal of reaching the top. The first person hikes to the top in a short amount of time. The second person scales the rocks to the top which takes a much longer amount of time. The same amount of work was done by both (they reached the top of the mountain), but the hiker has more power since the distance traveled was completed in a shorter amount of time. Power is expressed in Watts. Radiant Energy: Radiant energy comes from a light source, such as the sun. Energy released from the sun is in the form of photons. These tiny particles, invisible to the


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human eye, move in a way similar to a wave. Radiant energy can be transformed into electrical energy using solar panels. Renewable Energy: Renewable energy comes from sources that can be replenished on a human time scale, such as biomass (wood), or that are essentially inexhaustible, such as waste and geothermal, wind, and solar energy. Fossil fuels are non‐renewable energy sources; there is a finite supply of them. Renewable energy is also often clean energy; it can be generated with few or zero emissions and little to no environmental damage. Smog: Smog is air pollution mainly consisting of ozone and nitrogen oxides, which creates a visible brownish haze (particularly in cities in the summer). Smog can cause breathing problems and greatly reduces visibility in the air. Power plants and vehicles are major causes of smog. Solar Heating: Solar heating converts the sun’s power into heat for hot water, space heating, and swimming pools. Passive solar heating uses large windows to let in more light and warmth, while active solar heating uses specially designed mechanical systems to intensify the sun’s heat for use indoors. Solar Photovoltaics (PV): PV converts sunlight directly into electricity. PV is made from semiconductor materials, and does not create any pollution, noise, or other impacts on the environment. Homes and businesses may incorporate solar panels and arrays as a source of clean energy. Solar Photovoltaic Cell: A PV cell is the most basic element of a solar photovoltaic system. Each cell is made from semiconductor materials, and creates an electrical charge in reaction to sunlight that can be transformed into a current of electricity. Solar Power: The sun's energy can be used to generate electricity, provide hot water, and to heat, cool, and light buildings. This can be achieved using solar photovoltaic panels, concentrating solar power, and passive solar design. Sulfur Dioxide (SO2): Sulfur dioxide is a criteria pollutant that contributes to respiratory problems and the creation of acid rain. Sulfur dioxide is created by burning fossil fuels with trace amounts of sulfur, like coal and oil. Smaller amounts


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can be created during industrial metal processing. The major source of sulfur dioxide is the use of fossil fuels in electricity production. Thermal Energy: Thermal energy is the use of heat as a source of energy. Thermal energy can be used directly or can be transformed into mechanical energy (using a steam engine) which can then be transformed into electrical energy. Thermal energy is usually measured in British thermal units (Btu). Volt: A unit of electrical force equal to the amount of electromotive force that will cause a steady current of one ampere to flow through a resistance of one ohm. High‐voltage electricity moves faster than low‐voltage electricity, as seen in the difference between high‐voltage transmission lines used to move electricity quickly throughout a region and lower‐voltage distribution lines used to move electricity directly to customers. Voltage: The amount of electromotive force, measured in volts that exists between two points. Voltage is used to describe the amount of power produced by a generator. Water Efficiency: Water efficiency refers to practices, products, or systems that use less water than traditional products or systems without sacrificing performance. Water‐efficient products can include graywater use and low‐flow water fixtures (such as toilets or faucets). Water‐efficient practices can include landscaping with plants that require less water, use of rainwater for irrigation, and stormwater management. Watt (W): The rate of energy transfer equivalent to one ampere under an electrical pressure of one volt. One watt equals 1/746 horsepower, or one joule per second. It is the product of voltage and current (amperage). The term "watt" (in addition to the larger measurements of kilowatt and megawatt) is commonly used to describe the capacity of an electric generator. For example, a 1,000‐watt photovoltaic system has the capacity to produce 1,000 watts of power at any given time, though it may not consistently produce this much. Watt‐second (Ws): One Joule equals one watt‐second.


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Watt‐hour (Wh): The energy produced by 1 watt of power acting over a period of 1 hour. The Wh is the basis for the more commonly used measurements kilowatt‐hour and megawatt‐hour. Wind Power: Wind power uses the kinetic energy of flowing air to create mechanical energy in a wind turbine that can be transformed into pollution‐free electricity. Learn more about wind power and wind turbines. Work: Work is the transfer of energy to move an object a certain distance, such as a horse pulling a plow from one side of a field to another. Work is expressed in Joules. The rate at which work is performed is power.

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