AN INTERDISCIPLINARY MODEL FOR THE DEVELOPMENT OF ALABAMA OIL SANDS
by
DANIEL EDWARD SMITH III
RICHARD A. ESPOSITO, COMMITTEE CHAIR BENNETT L. BEARDEN SCOTT BRANDE MICHELLE V. FANUCCHI BERRY H. (NICK) TEW, JR.
A DISSERTATION
Submitted to the graduate faculty of The University of Alabama at Birmingham, in partial fulfillment of the requirements for the degree of Doctor of Philosophy
BIRMINGHAM, ALABAMA
2018
Copyright by Daniel Edward Smith III 2018
AN INTERDISCIPLINARY MODEL FOR THE DEVELOPMENT OF ALABAMA OIL SANDS
DANIEL EDWARD SMITH III
INTERDISCIPLINARY ENGINEERING
ABSTRACT
In July 2013, a memorandum of understanding (MOU) was signed by the
Governors of the states of Alabama and Mississippi to jointly conduct a comprehensive geologic, engineering, and legal assessment of oil sands resources associated with the
Hartselle Sandstone formation including the identification of environmental best practices associated with developing these resources. Pursuant to the MOU, the
Geological Survey of Alabama (GSA) began a limited geological evaluation of the potential development of Alabama’s oil sand resources. This dissertation compliments those GSA efforts by identifying and assessing environmental and social sustainability risks associated with the potential development of Alabama’s oil sands within the
International Organization for Standardization (ISO) 31010 risk management standard framework to provide an interdisciplinary sustainability risk management strategy that considers the inter-related disciplinary aspects of regulation, technology, and sustainability to address the environmental best practices component of the MOU. The bitumen extraction technologies currently being used to recover bitumen from geological formations that are most like the Hartselle Sandstone are proprietary and confidential.
Furthermore, currently available bitumen extraction technologies have not been tested on
Hartselle Sandstone oil sand deposits.
iii In 2013 when the MOU was signed, West Texas Intermediate (WTI) oil prices exceeded $100 per barrel. Since the MOU was signed, WTI oil prices dropped below $30 per barrel and are now around $60 per barrel. While the economic aspect of oil sands development is not the focus of this dissertation, it is important to point out that interest in the potential development of Alabama’s oil sands has diminished with the price of oil.
Nonetheless, this dissertation provides an interdisciplinary model for the sustainable development of Alabama’s oil sands when and if oil prices rise to incentivize such development. The interdisciplinary approach provided within this dissertation can be applied to the sustainable development of other oil and gas formations.
Keywords: Hartselle sandstone, oil sands, sustainability, risk management
iv
DEDICATION
This dissertation is dedicated to my wife, Elizabeth Perry Smith, without whose encouragement I would not have been able to complete this project.
v
ACKNOWLEDGEMENTS
I am especially thankful to Cumberland School of Law and Samford University student Mary-Thomas Hart who provided the dissertation section on the regulation of
Canadian Oil Sands Development as an independent research project under my supervision towards the completion of her joint Juris Doctor – Master of Science in
Environmental Management degree.
I am thankful to Auburn University Geology student (now recent graduate)
Benjamin D. Smith, my son, who accompanied and assisted me with the field observations of Hartselle Sandstone outcrops with bitumen deposits in Alabama.
I am also thankful to have been blessed with an outstanding PhD Committee that can be appropriately referred to as “The Dream Team”. I decided to embark on this path to purse a PhD because my Committee Chair, Dr. Richard Esposito, recommended I do so and he provided wise counsel and encouragement throughout the process. Committee member and State Geologist, Dr. Nick Tew, helped me understand oil sand development issues and focus my work to best support state efforts under his oversight to evaluate the potential development of Alabama’s oil sand deposits. Dr. Bennett Bearden is a world- renowned expert in water policy and his wisdom on the interplay of potential oil sands development and state water policy issues was invaluable. Many of the top environmental consultants in our region were trained by Dr. Scott Brande. His influence on the
vi environmental quality of Alabama cannot be overstated and I was honored that he brought that expertise to my committee. Lastly, but certainly not least, I want to thank Dr.
Michelle Fanucchi who balanced out the geologists on my committee with her public health experience and leadership. I am indebted to each of you.
Finally, I am thankful to the American National Standards Institute (ANSI) who provided me with access to ISO standards via their University Outreach Program.
vii
TABLE OF CONTENTS
Page
ABSTRACT ...... iii
DEDICATION ...... v
ACKNOWLEDGEMENTS ...... vi
LIST OF TABLES ...... xi
LIST OF FIGURES ...... xii
LIST OF ABBREVIATIONS ...... xiii
INTRODUCTION ...... 1
GEOLOGIC FRAMEWORK OF OIL SANDS DEVELOPMENT ...... 3
ALABAMA OIL SANDS GEOLOGIC SETTING ...... 3
CANADA OIL SANDS GEOLOGIC SETTING ...... 7
UTAH OIL SANDS GEOLOGIC SETTING ...... 10
BITUMEN EXTRACTION AND TRANSPORTATION TECHNOLOGIES ...... 16
CURRENT OIL SANDS DEVELOPMENT TECHNOLOGIES IN CANADA ...... 16
CURRENT OIL SANDS DEVELOPMENT TECHNOLOGIES IN UTAH ...... 17
POTENTIAL OIL SANDS DEVELOPMENT TECHNOLOGIES IN ALABAMA ...... 19
AN OVERVIEW OF SUSTAINABLE DEVELOPMENT ...... 22
WHAT IS SUSTAINABLE DEVELOPMENT AND WHY IS IT IMPORTANT? ...... 22
GREEN IMAGING ...... 24
viii AN APPROACH TO BUSINESS SUSTAINABILITY ...... 25
STRATEGIC PLANNING ...... 26
SUSTAINABILITY INFORMATION MANAGEMENT SYSTEMS ...... 27
SUSTAINABILITY PERFORMANCE FOOTPRINTS ...... 28
SOCIAL SUSTAINABILITY PERFORMANCE ...... 30
THE INTERNATIONAL ORGANIZATION FOR STANDARDIZATION (ISO) ENVIRONMENTAL MANAGEMENT SYSTEM STANDARD ...... 31
THE INTERNATIONAL ORGANIZATION FOR STANDARDIZATION (ISO) RISK MANAGEMENT STANDARD ...... 35
RISK MANAGEMENT FUNDAMENTALS ...... 35
RISK MANAGEMENT FRAMEWORK ...... 36
RISK MANAGEMENT PROCESS ...... 36
RISK MANAGEMENT CONTEXT AND CRITERIA ...... 37
RISK ASSESSMENT ...... 37
RISK IDENTIFICATION ...... 37
RISK ANALYSIS ...... 38
RISK EVALUATION ...... 39
RISK TREATMENT ...... 40
ASSESSMENT OF SUSTAINABILITY RISKS FROM OIL SANDS DEVELOPMENT ...... 42
DEFINITION OF RISK MANAGEMENT CONTEXT AND RISK EVALUATION CRITERIA ...... 43
RISK ASSESSMENT SCORING INDICES ...... 57
SUSTAINABILITY RISKS ASSOCIATED WITH CANADIAN OIL SANDS DEVELOPMENT ...... 60
ix SUSTAINABILITY RISKS ASSOCIATED WITH UTAH OIL SANDS DEVELOPMENT ...... 72
SUSTAINABILITY RISKS ASSOCIATED WITH ALABAMA OIL SANDS DEVELOPMENT ...... 72
REGULATION OF OIL SANDS DEVELOPMENT AS A RISK MANAGEMENT STRATEGY ...... 77
REGULATION OF CANADA OIL SANDS DEVELOPMENT ...... 77
REGULATION OF UTAH OIL SANDS DEVELOPMENT ...... 94
REGULATION OF ALABAMA OIL SANDS DEVELOPMENT ...... 97
STATE ENVIRONMENTAL POLICY ACTS ...... 102
SUSTAINABILITY RISK MANAGEMENT MODEL FOR POTENTIAL ALABAMA OIL SANDS DEVELOPMENT ...... 105
CONCLUSIONS AND IMPLICATIONS FOR REGULATORY POLICY AND FURTHER RESEARCH ...... 153
LIST OF REFERENCES ...... 157
APPENDICES
APPENDIX - A: MEMORANDUM OF UNDERSTANDING BETWEEN ALABAMA AND MISSISSIPPI TO STUDY THE POTENTIAL DEVELOPMENT OF OIL SANDS ...... 164
APPENDIX - B: FIELD OBSERVATIONS OF HARTSELLE SANDSTONE OUTCROPS WITH BITUMEN DEPOSITS IN ALABAMA ...... 166
x
LIST OF TABLES
Table Page
1 Risk Evaluation Criteria ...... 55
2 Risk Impact Scoring Index ...... 58
3 Risk Probability Scoring Index ...... 59
4 Risk Detectability Scoring Index ...... 59
5 Pre-Treatment Risk Analysis ...... 112
6 Risk Evaluation ...... 117
7 Post-Treatment Risk Analysis ...... 141
8 Risk Treatment Effectiveness ...... 148
xi
LIST OF FIGURES
Figure Page
1 Areal extent of the Hartselle Sandstone and outline of the Bulletin 111 study area ...... 4
2 Locations of outcrops of asphaltic rocks in Lawrence and Morgan Counties, Alabama ...... 5
3 Locations of outcrops of asphaltic rocks in Colbert and Franklin Counties, Alabama ...... 6
4 Distribution of water and bitumen in Canadian oil sand pore systems ...... 8
5 Table of Formations Illustrating the Primary Oil Sands and Heavy Oil Horizons in Alberta ...... 9
6 Primary Oil Sand Deposits Within the Uinta Basin ...... 11
7 Secondary (smaller and/or difficult to access) Oil Sand Deposits (names underlined) Within the Uinta Basin ...... 12
8 Geologic Cross-Section of the Asphalt Ridge Deposit ...... 13
9 ADEM 305(b) 2016 Ambient Surface Water Quality Monitoring Trend Stations in the Tennessee River Basin ...... 130
xii
LIST OF ABBREVIATIONS
ADEM Alabama Department of Environmental Management
AMSE American Sands Energy Corporation
ANSI American National Standards Institute
AQMS Air Quality Management System
AWAWG Alabama Water Agencies Working Group bbl Barrel
BGEPA Bald and Golden Eagle Protection Act
BLIER Base-level Industrial Emission Requirements
CAA Clean Air Act
CAAQS Canadian Ambient Air Quality Standards
CBM Coal Bed Methane
CEPA Canadian Energy Pipeline Association
CERCLA Comprehensive Environmental Response, Compensation, and Liability Act
CERI Canadian Energy Research Institute
CFR Code of Federal Regulations
CWA Clean Water Act
DBT Dibenzothiophenes
DOGM Division of Oil, Gas and Mining of the Utah State Department of Natural Resources
xiii EIS Environmental Impact Statement
EJ Environmental Justice
EPA Environmental Protection Agency
ESA Endangered Species Act
FMEA Failure Mode Effects Analysis
FTC Federal Trade Commission
GHG Green House Gas
GPS Global Positioning System
GRI Global Reporting Initiative
GSA Geological Survey of Alabama
IEC International Electrotechnical Commission
IS&Up In Situ Extraction and Upgrading
ISO International Organization for Standardization
LARP Lower Athabasca Regional Plan
LED Light Emitting Diode
MARPOL International Convention for the Prevention of Pollution from Ships
MBTA Migratory Bird Treaty Act
MOU Memorandum of Understanding
NA Napthenic Acids
NAAQS National Ambient Air Quality Standards
NEPA National Environmental Policy Act
NOI Notice of Intention or Notice of Intent
NPDES National Pollutant Discharge Elimination System
xiv OGB Alabama Oil and Gas Board
OSLTF Oil Spill Liability Trust Fund
PAH Polycyclic Aromatic Hydrocarbons
RBS Risk Breakdown Structure
RCRA Resource Conservation and Recovery Act
RFG Reformulated Gasoline
SAGD Steam Assisted Gravity Drainage
SCO Synthetic Crude Oil
SDWA Safe Drinking Water Act
SEPA State Environmental Policy Act
SHPO State Historic Preservation Officer
SIP State Implementation Plan
SM&Up Surface Mining and Upgrading
SOR Steam to Oil Ratio
SPCC Spill Prevention, Countermeasure, and Control Plan
SWOT Strengths, Weaknesses, Opportunities, and Threats
TBL Triple Bottom Line
THPO Tribal Historic Preservation Officer
TMDL Total Maximum Daily Load
TMF Tailings Management Framework for the Mineable Athabasca Oil Sands
UIC Underground Injection Control
U.S.C. United States Code
WTR Well to Refinery
xv WTW Well to Wheel
xvi
INTRODUCTION
In July 2013, a memorandum of understanding (MOU) was signed by the
Governors of the states of Alabama and Mississippi to jointly conduct a comprehensive geologic, engineering, and legal assessment of oil sands resources associated with the
Hartselle Sandstone formation including the identification of environmental best practices associated with developing these resources. A copy of the MOU is provided in
Appendix A. Pursuant to the MOU, the Geological Survey of Alabama (GSA) began a limited geological evaluation of the potential development of Alabama’s oil sand resources. A primary objective of this dissertation is to compliment the efforts of the
Geological Survey of Alabama (GSA) in its comprehensive assessment of the potential development of oil sand resources in Alabama. While the GSA assessment is primarily focused on geological aspects, this dissertation focuses on the assessment of environmental and social sustainability risks from the perspective of identifying regulatory strategies that the state of Alabama could use to treat those risks. To that end, significant environmental and social sustainability risks are identified and assessed for current oil sand developments in Canada and Utah, and potential oil sand development in
Alabama using the same risk scoring indices and evaluation criteria to generate relative risk scores. After current regulatory risk treatments are applied, the risks are re-scored to determine a relative percentage reduction in the risk scores. Potential regulatory risk
1 treatments are then applied to identified environmental and social sustainability risks associated with the potential development of Alabama oil sands to determine regulatory risk treatments that would effectively reduce these risks. The state of Alabama is contemplating the promulgation of Alabama oil sands development regulations and the findings of this dissertation are intended to provide guidance in the rulemaking process in the form of a regulatory model to support and compliment the GSA oil sands assessment and any forthcoming state oil sands rulemaking.
This dissertation is interdisciplinary in many significant ways because the regulatory models for oil sands development that are generated represent an intersection of technology, law, geology, sociology, and ecology or environmental science. The term
“sustainability” encompasses the last two disciplines – sociology and ecology or environmental science. This dissertation also brings the process of risk assessment into the interdisciplinary mix to provide a unique, interdisciplinary, risk-based approach to the regulatory treatment of a potential energy development. The dissertation deliverables are not overly complex, yet they are powerfully effective in their simplicity. This dissertation provides an overview of sustainability fundamentals, risk assessment fundamentals, and the geologic and legal setting of current oil sands development in Utah and Canada, and potential oil sands development in Alabama. These overviews provide the context for developing a regulatory risk treatment model for the potential development of Alabama oil sands.
2
GEOLOGIC FRAMEWORK OF OIL SANDS DEVELOPMENT
Alabama Oil Sands Geological Setting
The Geological Survey of Alabama issued Bulletin 111 “Characteristics and
Resource Evaluation of the Asphalt and Bitumen Deposits of Northern Alabama” in
1987. The stated purpose of Bulletin 111 was “to provide information on the occurrence, physical characteristics, and chemical properties of the asphalt and bitumen deposits of northern Alabama and, in particular, those deposits that are found in the Hartselle
Sandstone.” In a June 4, 1987 cover letter to Alabama Governor Guy Hunt within
Bulletin 111, Alabama State Geologist Ernest A. Mancini states “The asphalt and bitumen deposits of northern Alabama contain huge reserves of petroleum that may one day be tapped to supplement conventional oil production. This report provides information that will be useful to future research efforts and development planning for this potentially important natural resource.” The presence of bituminous sandstone, asphaltic seeps and/or tar springs in Northern Alabama was recorded as early as 1896.
The areal extent of Hartselle Sandstone in Alabama is depicted in Figure 1 and Hartselle
Sandstone outcrop areas are depicted in Figures 2 and 3. The only commercial development of these materials to date has been relatively small-scale surface mining for paving material. [1]
3 Figure 1. Areal extent of the Hartselle Sandstone and outline of the Bulletin 111 study
area [1]
4 Figure 2. Locations of outcrops of asphaltic rocks in Lawrence and Morgan Counties,
Alabama from Bulletin 111 [1]
5 Figure 3. Locations of outcrops of asphaltic rocks in Colbert and Franklin Counties,
Alabama from Bulletin 111 [1]
The findings of Gary V. Wilson in Bulletin 111 indicate that core samples of the
Hartselle Sandstone formation show wide ranges of porosity, permeability, and oil saturation. Some locations contain as much as 12,000 barrels of bitumen per acre.
Shallow reserves within 50 feet of the surface are estimated at 350 million barrels and deeper reserves are estimated at 7.5 billion barrels. Bitumen deposits are relatively immobile because of their high viscosities, low temperatures, and lack of reservoir pressure. The sulfur content of Alabama bitumen is significantly lower than the average sulfur content of Canadian bitumen.[1] Bulletin 111 speculates that any recovery of these bitumen reserves would involve surface mining in some areas and require in situ techniques in other areas; however, the report states “The potential for the development of a particular deposit by surface mining is dependent not only upon the thickness, grade,
6 and lateral extent of that deposit, but also upon topographic and overburden conditions, the availability of water, the available access and proximity to transportation routes, and any potential adverse socioeconomic effects that may result from surface mining operations.” Based upon earlier laboratory experiments that found increased bitumen mobility from steam injection within Hartselle Sandstone core samples, the report concludes that in situ recovery using thermal energy is the most feasible recovery option; however, pilot projects are needed to test these theories. [1]
A summary of field observations on June 26, 2017 of potential bitumen bearing sandstone outcrops in Alabama is provided in Appendix – B.
Canada Oil Sands Geologic Setting
The primary oil sands deposits in Alberta, Canada are the Athabasca, Wabascsa,
Peace River, Cold Lake, and Lloydminster deposits. With the exception of the Peace
River deposits in northwestern Alberta, the oil sands deposits of eastern Alberta are found in various reservoirs within the Mannville Group of Lower Cretaceous age. [2] There is a profound angular unconformity between the Mannville group and underlying rocks in each of the eastern Alberta oil sands production areas. At Peace River, the underlying rocks are of Mississippian, Permian, and Jurassic age. At Athabasca, Cold Lake, and
Lloydminster, the underlying rock formations are of Devonian age. [3] The Mannville group was deposited unconformably upon karstic and highly eroded Devonian carbonates. The reservoir sands within the Mannville group are “mainly fluvial braided river and fluvio-estuarine, sinuous, incised valley fills, capped by brackish bay-fill and marine shales.” [4] These reservoir formations have relatively high porosity. Canada’s oil sands are hydrophytic or water-wet where the grains of sand are surrounded by a thin
7 film of water and the remainder of the pore space is bitumen. The sand is angular in shape and very abrasive. [2] The bitumen-saturated Grosmont carbonate formation in
Alberta has received significant recent attention as an additional large reserve of
Canadian bitumen. The Grosmont formation consists of limestone and dolomite characterized by large vugs, open fractures and above average porosity. These formations lie beneath the oil sands formations. [5]
Figure 4. Distribution of water and bitumen in Canadian oil sand pore systems [2]
8 There are several theories regarding the potential sources of Alberta’s oil sands deposits and those theories fall within two origin categories: in-situ and ex-situ. Under the in-situ origin theory the bitumen was derived from organic material deposited within the sand – this theory is not widely held. [6] Under the ex-situ origin theory the bitumen began as light oil to the west and/or southwest and migrated from marine shale source rock to its present locations due to tectonic pressures during the orogenic events associated with the uplift of the Rocky Mountains and was then transformed into bitumen via water and bacteria contact. This is the most prominent source theory. [7] An alternate ex-situ source theory holds that these oil sand deposits originated from coal within the
Lower Cretaceous strata of Western Alberta during the coalification process; however, this is not a widely-held theory. [6]
Figure 5. Table of Formations Illustrating the Primary Oil Sands and Heavy Oil Horizons in Alberta [2]
9 Utah Oil Sands Geologic Setting
Utah’s oil sands have historically been referred to as “bituminous sandstones,”
“oil-impregnated rock,” or “tar sands.” The Uinta Basin contains about ½ of Utah’s oil sand resources. The Uinta Basin is also one of the nation’s most hydrocarbon-rich basins producing oil, non-associated gas, native asphalt, and other unique hydrocarbons. An origin theory for bitumen impregnating the rock mass is that crude oil accumulated within conventional petroleum reservoirs near the land surface. These reservoirs were eventually breached via erosion processes allowing the volatile components to escape.
Ground water, air, and bacteria then altered the remaining material via biodegradation over time to create tar sands within the host formation. Oil sands are found in strata that range in age from Pennsylvanian to Oligocene. Most of the oil sands are found in Tertiary stratigraphic and structural sandstone traps. Bitumen distribution varies depending on the permeability and porosity of the host rock. Large accumulations of oil sands occur in sandstone of Eocene age, deposited in a fluvial-deltaic environment. The petroleum that biodegraded to form bitumen is believed to have originated in a lacustrine basin where fresh-water algae and bacteria accumulated within sediment layers on lake bottoms. Over time the generated crude oil migrated upward out of the fine-grained lacustrine source rocks, through more permeable carrier beds, and finally into porous traps where it was transformed into bitumen via biodegradation and water-washing. There are four principal oil sand deposits in the Uinta Basin: Asphalt Ridge, P.R. Springs, Hill Creek, and
Sunnyside. [8]
10 Figure 6. Primary Oil Sand Deposits Within the Uinta Basin [8]
11
Figure 7. Secondary (smaller and/or difficult to access) Oil Sand Deposits (names underlined) Within the Uinta Basin [8]
12
Figure 8. Geologic Cross-Section of the Asphalt Ridge Deposit [8]
The State of Utah Office of Energy Development states “Most of the United
States’ oil sand resources are concentrated in Eastern Utah in the Uintah Basin. Utah’s oil sands are estimated by the Utah Geologic survey to contain 15 billion barrels of recoverable oil. While Canada’s oil sands industry has demonstrated the economic viability of large-scale oil sand’s development, new projects in Utah aim to greatly reduce the environmental impact of commercial-scale oil sands development. Utah’s oil sands contain an estimated 15 billion barrels of measured in-place oil, with an additional estimated resource of 23-28 billion barrels.” [9] Oil sands resources in Utah are distinctly different from Canadian Athabasca oil sands both in nature and extraction methodologies due to physical differences such as composition and geologic setting. While Utah’s oil sand deposits are only about 2% of the size as the vast Canadian oil sand deposits, they are nonetheless, a significant U.S. resource and represent approximately 55% of total
13 U.S. oil sand resources. Utah oil sands are classified as “oil wet” where bitumen adheres directly to sand grains within the pore space of host sandstone. In contrast, Canadian oil sands are classified as “water-wet” with an intervening water film known as “connate water”. Canadian oil sands typically have water contents in the 3-5% range. Because of this difference, the Clark extraction process used in Canada will not work with Utah oil sands. Unlike Canadian oil sands, Utah’s oil sands cannot be mined by truck and shovel methods because their compressive strengths are 3 to 4 times greater than Athabasca ores.
These consolidated Utah beds must be mined using hard rock techniques. [10]
U.S. Oil Sands, Inc. describes the geology of Utah Uinta Basin Oil Sands as follows: “The Uinta Basin is a major structural basin that formed in the Early Tertiary when tectonic events resulted in dramatic topographic elevation of surrounding highlands. The Basin was and is flanked by the Uinta Mountains on the north, Douglas
Creek Arch along the eastern margin, southwest and southeast highlands in the form of the San Rafael Swell and Uncompahgre Plateau, respectively. It is bounded along the west by the Wasatch Plateau and mountains. (Covington, 1964). Contemporaneous with the Uinta Basin, the Piceance Creek Basin, rich in oil shale deposits, formed in northwestern Colorado. Sediments eroding from surrounding highlands flowed into the
Lake Uinta basin forming a thick sequence of organic-rich shale, limestone, and sandstone, providing all the elements necessary for the oil shale and oil sand present today in the southern part of the Uinta Basin. Rocks range from Cretaceous age Mancos shale, Mesa Verde Group, and Tuscher Formation, to Tertiary age Wasatch Formation
Paleocene-Eocene, and Green River Formation (Eocene).
14 The Green River Formation is composed of marlstone, oil shale, shale, mudstone, sandstone, siltstone, limestone, and tuff. It has been divided into four units (Gwynn, 1970) with the youngest to oldest as follows: Evacuation Creek Member, Parachute Creek
Member, Garden Gulch Member, and Douglas Creek Member. Bitumen saturation is found in five distinct oil sand zones, lettered “A” (lowest) to “E” (highest). The “E” zone is in the Parachute Creek Member and “A” through “D” zones are in the Douglas Creek
Member. The Mahogany Oil Shale, a major stratigraphic marker in the area, divides these two Members.” [11]
A U.S. Department of Energy report indicates that Utah contains more oil sand reserves that all other states combined with over 11.5 billion barrels of proven oil reserves and 20.7 billion barrels of oil equivalent. The Uinta Basin contains 24 individual oil sand deposits. There are also 50 additional deposits scattered throughout southeastern
Utah. Oil sands are found in 13 pay zones with a gross thickness of 10 feet to over 1,000 feet. The overburden thickness varies from zero to 500 feet. [12]
A brief Comparison of Utah and Alabama Oil Sand Deposits
Alabama’s oil sands deposits are similar to Utah’s oil sands deposits in that they are both oil-wet. Therefore, it is logical to assume that one or more of the solvent-based extraction methods being used in Utah would also be the optimal extraction methods for
Alabama’s oil sands. [13]
Alabama’s Hartselle sandstone is characterized as tightly cemented and therefore assumed to exhibit relatively high compressive strengths similar to Utah’s oil sands to warrant hard rock mining techniques for surface mining. [1].
15
BITUMEN EXTRACTION AND TRANSPORTATION TECHNOLOGIES
Current Oil Sands Development Technologies in Canada
There are two main methods for Canadian oil sands recovery: Surface Mining and
In Situ Extraction. Both of these methods are water and energy intensive. Significant amounts of natural gas are typically required. Surface mining is used for relatively shallow oil sand deposits that are less than 75 meters (approximately 236 feet) below the surface. After surface mining, the bitumen is extracted from excavated oil sands in a separator using hot water. Deeper oil sand deposits utilize in situ extraction techniques where the bitumen is pumped to the surface after being heated or diluted underground.
The most common in situ extraction method is the Steam Assisted Gravity Drainage
(SAGD) process. The recovered bitumen from either recovery method is too viscous (like molasses) to transport within a pipeline. Therefore, the bitumen must be diluted with a diluent to lower its viscosity for pipeline transportation to either an upgrading facility, where it is upgraded into synthetic crude oil (SCO), or directly to a refinery. Bitumen has a density of 960 to 1,020 kg/m3 and a viscosity of 760,000 cSt at 15˚C. The viscosity must be reduced to at least 350 cSt for pipeline transport. Bitumen is typically diluted with naphtha or natural gas liquids to create “Dilbit” at a 30:70 diluent to bitumen ratio to achieve a viscosity of 350 cSt at 15˚C. Bitumen can also be diluted with synthetic crude to create “Synbit” at a 50:50 diluent to bitumen ratio to achieve a viscosity of 128 cSt at
16 15˚C. The choice of diluents depends on diluent availability, operational logistics, and economic factors. Most of the Canadian oil sands production is transported to the United
States to be upgraded and refined. This is because upgrading and refining facilities are very expensive and there is excess refining capacity in the United States. It is more economical to transport diluted bitumen to these existing facilities rather than construct new bitumen upgrading and refining facilities in Canada. Diluted Canadian bitumen is currently being transported via railways and pipelines. [14], [15], [16].
Current Oil Sands Development Technologies in Utah
All the current Utah oil sands development involves surface mining techniques and proprietary solvents that use either zero water or minimal water. Unlike Canadian oil sand operations, none of these processes require tailing ponds. On October 1, 2014 MCW
Energy Group unveiled its proprietary oil sands extraction technology using benign solvents in a proprietary closed-loop system that requires no water, pressure, or high temperatures in the extraction process. MCW claims that 99% of the solvents are recovered and recycled. They have described their process as “environmentally friendly.”
[17] In an October 14, 2014 press release American Sands Energy Corporation (AMSE) indicates that they also use a water-free extraction process to minimize their environmental footprint. They report a production cost of less than $49/bbl. [18] Their process utilizes surface mining to extract the oil sands which are mixed with a proprietary solvent used to extract the bitumen. The bitumen/solvent mixture is then heated to separate the solvent from the bitumen. The bitumen will then be shipped by rail 150 miles to a refinery in Salt Lake City. [19] U.S. Oil Sands uses D-limonene, a citrus bio-solvent made from orange peels, to extract bitumen from sand grains at their PR Spring project in
17 Utah to recover 96-98% of the bitumen. They claim that there is no process on earth that achieves that high a rate of recovery. D-limonene works the same as a clothing stain remover or hand cleanser. It is also a non-toxic supplement found in many health food stores. It biodegrades rapidly. With their process the same truck that delivers a load of ore takes a load of clean sand to deposit for reclamation on the same day. [20] Unlike surface extraction methods utilized in Canada, there are no tailings ponds associated with this process. With this process, the ore is slurried with hot water and solvent and the solvent dissolves the bitumen. The water, solvent and sand are then separated over a 30- minute period. The solids are then thickened and returned as backfill. The water is recycled, and the solvent is recovered by distillation and reused in the process. “The company claims recycling rates of 98% for solvent and 95% for water, with the process using around half the energy needed for conventional hot-water bitumen extraction.” [21]
Any use of water by these extraction processes is problematic because water availability is a significant issue in Utah. Under Utah’s prior appropriation water law system, essentially all of the water rights available in Eastern Utah have already been appropriated. The amount of water available for appropriation is limited by interstate water pacts and federal Endangered Species Act requirements. Therefore, any water demands must be satisfied by purchasing water rights from others and/or alternative water supply options. Formation or produced water is often managed for disposal as poor-quality wastewater during extraction processes. In light of Utah’s significant water resource limitations, produced water might serve as a source of extraction process water.
This would also serve to lower wastewater disposal costs. The produced water could come from other non-oil sands related oil production within the Uinta Basin. However,
18 once the water ceases to be a wastewater and begins to serve a beneficial use, state prior appropriation water law requirements are presumed to apply, as water is public property under Utah law. These issues have not been fully settled in the Utah courts. [22]
While some literature reports that only a small percentage of Utah oil sands, similar to Canadian oil sands, can be exploited via surface mining, with the remainder to be recovered via in situ methods, the literature suggests that current industry efforts are focused on surface mining with no literature identified on industry attempts at in situ recovery in Utah. Nonetheless, the University of Utah has created conceptual reservoir models of Utah oil sand deposits to determine which in situ recovery techniques are the most promising. [23] A 2009 paper published by the Utah Geological Survey discusses the potential application of various in situ techniques with Utah oil sands and also mentions a lack of data from any actual experience with in situ oil sands recovery in
Utah. [24] MCW Oil Sands Recovery, LLC claims that the Steam Assisted Gravity
Drainage (SAGD) method of in situ recovery using steam and pressure in Canada will not work for in situ recovery in Utah because the Canadian oil sands are water-wet whereas the Utah oil sands are oil-wet. [25]
Potential Oil Sands Development Technologies in Alabama
In 1987 Wilson provided the following status of Alabama oil sands development:
“With the exception of small-scale surface mining for paving material, interest in the development of the asphaltic deposits of northern Alabama has never gone beyond the stage of the leasing of mineral rights and the drilling of a few shallow test wells or the opening of small test pits or quarries. Companies and investors have displayed more of a
“wait and see” attitude, and this has been due primarily to the uncertainties in the
19 reserves at any given locality and the recoverability of those reserves by available technology. Individuals and small companies have dug some test pits and drilled a number of shallow test wells at scattered locations within the outcrop area of the
Hartselle sandstone, the formation to which are attributed most of the reserves present in north Alabama. Debris-filled pits and small, abandoned quarries, most of which were excavated between 1890 and 1925, can still be found throughout the area.” [1] This status has more or less remained unchanged until recent years at high oil prices when a company explored the possibility of surface mining operations to extract bitumen from these oil sand deposits using an undisclosed technology. Any surface mining of Alabama oil sands would require the promulgation of new regulations by the Alabama Oil and Gas
Board. [26]
Wilson speculates that any recovery of these bitumen reserves would involve surface mining in some areas and require in situ techniques in other areas; however, the report states “The potential for the development of a particular deposit by surface mining is dependent not only upon the thickness, grade, and lateral extent of that deposit, but also upon topographic and overburden conditions, the availability of water, the available access and proximity to transportation routes, and any potential adverse socioeconomic effects that may result from surface mining operations.” Based upon earlier laboratory experiments that found increased bitumen mobility from steam injection within Hartselle
Sandstone core samples, the report concludes that in situ recovery using thermal energy is the most feasible recovery option; however, pilot projects are needed to test these theories. [1]
20 Canadian oil sands are hydrophilic or water-wet where each grain of sand is covered by a film of water, which is then surrounded by bitumen. However, the oil sands in Alabama are oil wet and the bitumen adheres directly to the sand grains; therefore, different extraction techniques will be required in Alabama than are used in Canada. Oil- wet sands do not respond as well to water/steam extraction processes used in Canada.
Any surface mining in Alabama will likely use technologies similar to those used in Utah because Alabama’s oil sand deposits are similar to deposits found in Utah. The technologies most suited to Alabama and Utah surface mining operations are closed-loop solvent-based systems which are suited to small to medium-sized deposits. Some of the solvents being developed are biodegradable and non-toxic. These technologies do not require tailing ponds and require reduced amounts of water. [13]
Given that Canadian oil sand deposits are water-wet and relatively unconsolidated in comparison to Alabama and Utah deposits, Alabama and Utah must look to one another for viable in situ technologies that work well with oil-wet consolidated sandstone deposits. While surface extraction methods are being developed in Utah that are presumably adaptable to Alabama, no attention is currently being given to the development of in situ extraction methods for Utah and Alabama oil sand deposits. In light of the consolidated nature of these deposits, some sort of hydraulic fracturing technique might be required before using thermal and/or solvent-based methods to extract bitumen from wells drilled along the dip angle of Hartselle sandstone deposits. These are all speculative thoughts warranting further research.
21
AN OVERVIEW OF SUSTAINABLE DEVELOPMENT
Sustainable development, products, and business practices are important factors to investors, customers, and public stakeholders. In today’s world, there are stock market sustainability indexes and sustainable investment options for the growing socially responsible investor market. In addition, consumers now prefer products and services they deem to be more sustainable than others and shareholders demand sustainability performance reporting in addition to financial reporting. These factors indicate that companies able to distinguish themselves from their competitors by their sustainability performance will have an advantage. The sustainability or “green” image of a company is certainly important; however, that should not be the end-goal or primary driver for business sustainability initiatives. Sustainability performance can provide a company with far more strategic business value and risk mitigation than simply an improved image.
What is Sustainable Development and Why is it Important?
The 1987 World Commission on Environment and Development, also known as the Brundtland Commission, defined sustainable development as “development that meets the needs of the present without compromising the ability of future generations to meet their own needs.” To that end, the Bruntland Commission’s report emphasized “the need to integrate economic and ecological considerations in decision making” and the need to identify alternative or appropriate technologies that are more sustainable. The
22 report further states that “the development of environmentally appropriate technologies is closely related to questions of risk management.” [27] The Bruntland Commission’s sustainable development concept was fleshed out further in1994 when John Elkington coined the phrase “the triple bottom line”.[28] Business sustainability performance is currently evaluated using this Triple Bottom Line (TBL) approach to assess a company’s overall performance in three categories: economic, environmental, and social. The conventional approach to gauging the success of a company is to look at its economic sustainability alone to know whether it is making a profit. However, it could be making a profit while causing significant adverse environmental and social impacts. While an organization’s economic bottom line can be measured quantitatively using universally accepted accounting standards, there are no universally recognized quantitative standards for measuring environmental and social performance. Economic performance is an objective evaluation, whereas, social and environmental performance tend to be subjective evaluations. A company’s Social Bottom Line considers its responsibility to employees, investors, customers, nearby communities, and other stakeholders. The
Environmental Bottom Line considers performance with respect to environmental compliance, resource conservation, waste management, environmental risk management, ecosystem impacts, and supply chain impacts. In addition to an organization’s direct impacts, it also has indirect impacts along its supply chain that may need to be considered when evaluating sustainability performance.
The Global Reporting Initiative (GRI) provides sustainability reporting standards that have become the accepted international standard for environmental and social sustainability performance reporting. [29] Nonetheless, it remains difficult to compare the
23 sustainability performance of one company against another in the same way that economic performance can be compared. While publicly traded corporations issue annual reports of their economic performance, annual integrated reporting of both economic and sustainability performance together is not a universal requirement; therefore, sustainability performance reporting is mostly voluntary.
In defining sustainability, we have only discussed external drivers for sustainability performance; namely, the expectations of investors, customers, and public stakeholders. It could be argued that an internal driver, profit, ultimately drives business attention to satisfy these external expectations. One important internal driver of sustainability performance is that significant cost savings can be achieved when practices are identified to reduce energy and water consumption and minimize or eliminate waste streams. In a similar manner, practices to eliminate hazardous substances and minimize ecosystem impacts also serve as risk management strategies to address potential non- compliance and public opposition scenarios that present significant financial risks.
Sustainability performance that reduces operating expenses means increased profit.
Another internal driver of sustainability performance could be the mission or governing principles of a business. Some businesses are created or operated in a way to achieve certain levels of sustainability performance.
Green Imaging
Green imaging or green messaging can now be commonly found associated with products and services offered to consumers in the market place. These communications include all sorts of sustainability claims and certifications. Whether a product or service is perceived to be “green” is now an important factor in consumer purchasing decisions.
24 Socially responsible investors are also looking for “green” investment options. In response, the market now provides green and sustainable mutual funds tied to sustainability indexes. Many analysts now consider a company’s sustainability performance in addition to its financial performance believing that the two are integrally related. Yet, a company’s green imaging efforts can turn out negatively for them. The
Federal Trade Commission (FTC) is empowered to take enforcement actions against companies who make illegal green marketing claims. Green claims and certifications that are misleading, false, or unsubstantiated can present serious green imaging compliance problems. There are also a host of nonprofit environmental organizations that monitor green claims and quickly label green imaging efforts as “green washing” when they believe these green messages are disingenuous. Company branding efforts and choice of logos, certifications, labels, and green/sustainability claims must be scrutinized to avoid these potential problems. Seeking to demonstrate sustainability performance through a green image can be problematic if true sustainability performance does not undergird that image. [30]
An Approach to Business Sustainability
I have taught a graduate level course on sustainability in Samford University’s
Master of Science in Environmental Management program for many years. In teaching this course I have selected volunteer clients where my students have acted as a consulting firm to evaluate all aspects of the client’s sustainability performance and benchmark the client’s performance against their peers. These sustainability assessments have typically included an evaluation of the client’s strategic planning, green imaging, management systems, environmental footprints, supply chains, social sustainability, sustainability
25 performance metrics, and sustainability reporting. We have learned that positive sustainability performance usually correlates with positive economic performance. Over the years, we have evaluated a broad spectrum of organizations and provided them with sustainability findings and recommendations that produced impressive results.
Strategic Planning
Strategic planning enables a company to be intentional in its sustainability performance efforts. Business sustainability begins with a Mission Statement and a
Statement of Principles. A Mission Statement tells everyone what the organization does.
It is the most fundamental reason why the organization exists. It should ideally be one or two sentences and no longer. It is a succinct statement that anyone in the organization should be able to memorize and recite when asked. The mission statement is the initial
“litmus” test for everything that you do. If you are spending resources on something that does not support the Mission Statement it should be scrutinized and possibly eliminated.
It is very important for everyone in your organization to know the mission with clarity. It is possible to incorporate sustainability performance within the Mission Statement.
An organization’s values set forth within a Statement of Principles is the second most important component of a strategic plan. The organization’s Mission Statement and
Statement of Principles should be relatively static documents that rarely change over many years. The organizational values memorialized within a Statement of Principles are the lenses through which decisions are filtered. These principles define the character of the organization and should guide “how you do what you do” daily. Organizational principles might address specific ethical standards for how it conducts business, how it relates to its employees, investors, customers, public stakeholders, and how it addresses
26 various environmental and sustainability issues, etc. Perhaps the organization’s sole reason for existence is not just to make a profit, but to serve various societal needs – this would be a place in its strategic planning to address that. The Statement of Principles should be limited to a few pages to ensure that it is referenced in the routine operation of the organization. The articulation of these principles should be as specific as possible.
The next aspect to strategic planning should be an annual SWOT analysis to identify and list internal Strengths & Weaknesses and external Opportunities & Threats.
This should be done annually by the organization’s leadership team. This critical analysis is essential. Annual organizational objectives are created to address SWOT analysis results considering the organization’s Mission Statement and Statement of Principles.
With limited resources, most organizations need to rank and prioritize the list of proposed objectives and only include those most highly ranked within available resource limits. A simple ranking matrix can be used to score each objective using criteria such as net present value, conformity to the Statement of Principles and the Mission Statement. If certain criteria are more important than others, weightings can be used to reflect the relative importance of each.
Sustainability Information Management Systems
It can be difficult for a company to achieve sustainability performance goals without having a sustainability management information system in place to manage all aspects of sustainability performance including environmental and safety compliance. For many companies, environmental compliance is a daunting task considering the complexities of environmental regulation involving three different jurisdictional levels of government: federal, state, and local. The problem can be compounded with limited staff
27 resources and competing duties where important tasks can sometimes “fall between the cracks” and lead to non-compliance situations or enforcement actions. Some organizations turn to spreadsheets to provide a management solution; however, spreadsheets are a “duct tape and bailing wire” type of solution. Spreadsheets can become unwieldy and are prone to user errors as various people attempt to share the spreadsheet.
They may even cease to function altogether if the person maintaining the spreadsheet leaves the organization. Spreadsheet management systems might be compared to using a slide rule instead of a calculator. Powerful cloud-based and enterprise-based software solutions are now offered by several companies to effectively manage sustainability performance and environmental and safety compliance responsibilities in place of those antiquated spreadsheets. Many organizations track their sustainability performance against certain metrics including their carbon footprint, water footprint, waste footprint, social performance, etc. To track these criteria, the organization’s management information system must include the appropriate functionality.
Sustainability Performance Footprints
The measurement of an aspect of sustainability performance is usually referred to as a “footprint.” Footprints consider direct and indirect impacts along the supply chain of an organization.
Water Footprints: Many are familiar with carbon footprints; however, companies are increasingly evaluating their water footprints also based on the work of
Arjen Y. Hoekstra of the University of Twente in the Netherlands. The water footprint of a product, commodity, service, or consumer is the total volume of freshwater used.
Hoekstra divides a water footprint into three components. He calls the volume of
28 rainwater used the “Green water footprint;” the volume of surface and groundwater consumed the “Blue water footprint;” and the volume of freshwater that is required to assimilate the load of pollutants based on natural background concentrations and existing ambient water quality standards the “Grey water footprint.” As freshwater supplies become increasingly scarce, water footprints are of strategic importance to the sustainability performance of industries that are water-intensive. [31]
Energy Footprints: Solar energy and LED lighting often provide excellent opportunities to achieve sustainability performance goals allowing a company to save significant energy cost and improve its “green image” to potential customers or investors.
Solar energy systems paired with LED lighting typically have fast payback periods because of displaced energy from the grid, enhanced energy efficiency, and tax incentives. An energy audit can be used to identify opportunities to reduce energy consumption and save operating expenses.
Carbon Footprints: Many companies track and report their annual carbon footprint for various purposes. In some jurisdictions, it is a legal requirement for certain industries. Some companies purchase credits to offset their carbon emissions. Companies that include their carbon footprint within an annual sustainability performance report typically compare their carbon performance against a baseline year.
Waste Footprints: There is a Zero Waste business movement that seeks to implement waste diversion practices that reduce and, when possible, eliminate sending wastes to landfills or incinerators. The focus of these efforts is on managing processes rather than end-of-process waste management. Companies can be very creative in finding ways to eliminate or reduce their waste streams. Some companies have saved millions of
29 dollars through their waste diversion practices. Waste Stream Audits can be used to characterize and quantify waste streams. Waste tracking systems provide important information about the quantities of each type of waste generated per month, and the quantities of waste recycled, incinerated, and sent to landfills. [32][33]
Social Sustainability Performance
A company’s social sustainability considers how it treats its employees, investors, customers, nearby communities, and other stakeholders. ISO 26000 is an International
Standard giving guidance and recommendations about how any organization can improve its social responsibility. [34]
30
THE INTERNATIONAL ORGANIZATION FOR STANDARDIZATION (ISO)
ENVIRONMENTAL MANAGEMENT SYSTEM STANDARD
The Bruntland Commission definition of “Sustainable Development” as well as the Triple Bottom Line concept are reflected in the introduction language of the ISO
14001:2015 Environmental Management System standard as follows: “Achieving a balance between the environment, society, and the economy is considered essential to meet the needs of the present without compromising the ability of future generations to meet their needs. Sustainable development as a goal is achieved by balancing the three pillars of sustainability.” The purpose of the ISO 14001:2015 standard is to provide organizations with an environmental management system framework “to protect the environment and respond to changing environmental conditions in balance with socio- economic needs.” ISO 14001:2015 is a risk-based approach to managing the environmental pillar of sustainable development or said in another way, the environmental portion of an organization’s sustainability performance. [35]
From a triple bottom line perspective, an environmental management system can be a subset of an organization’s sustainability management system which can be a subset of the organization’s overall management system. An organization may have many different management systems. The common elements to most management systems are:
(a) a written policy stating the organization’s commitments; (b) assigned responsibilities and authorities; (c) monitoring, measurement, and analysis; (d) documentation including
31 operating procedures and instructions; (e) internal audit of the management system; and
(f) management review to evaluate performance, management system effectiveness, and ensure continuous improvement. [36] Viewed in a more simplistic manner, the essential components of a management system are: (1) identify the performance requirements; (2) develop compliance procedures and contingency plans to achieve those requirements; (3) train employees on how to implement those plans and procedures; and (4) management system audits. ISO 14001:2015 defines “management system” as a “set of interrelated or interacting elements of an organization to establish policies and objectives and processes to achieve those objectives.” “Environmental policy” is defined as the “intentions and direction of an organization related to environmental performance, as formally expressed by its top management” and “environmental management system” is defined as “part of the management system used to manage environmental aspects, fulfil compliance obligations, and address risks and opportunities.” Therefore, under ISO 14001:2015, performance requirements could include the organization’s mission, written management policies, strategic objectives, and government regulations. Written procedures are developed to comply with the identified management system performance requirements, and employees are trained to implement these procedures. Finally, periodic audits are conducted to evaluate the management system. [35]
To determine an organization’s environmental management system performance requirements under ISO 14001:2015, it must first “determine the environmental aspects of its activities, products and services that it can control and those that it can influence, and their associated environmental impacts, considering a life cycle perspective.”
“Environmental aspect” is defined as an “element of an organization’s activities or
32 products or services that interacts or can interact with the environment” and an
“environmental impact” is “change to the environment, whether adverse or beneficial, wholly or partially resulting from an organization’s environmental aspects.” While some environmental aspects and impacts may be subject to legal compliance requirements in the form of government regulations, others may be subject to voluntary internal compliance requirements set forth in the organization’s policies. ISO 14001:2015 specifies that “the organization shall establish environmental objectives at relevant functions and levels, taking into account the organization’s significant environmental aspects and associated compliance obligations, and considering its risks and opportunities.” “Objective” is defined as a “result to be achieved.” The scope of the environmental management system must also address potential emergency situations that can have an environmental impact and be prepared to respond to those emergency situations. [35]
The ISO 14001:2015 environmental management system standard provides a framework for the sustainable development of fossil energy resources such as oil sands, namely with respect to the establishment of environmental policy and the identification of environmental aspects and impacts. The standard specifies three basic commitments for an environmental policy: “(a) to protect the environment; (b) to fulfil the organization’s compliance obligations; and (c) to continually improve the environmental management system to enhance environmental performance.” Potential environmental aspects may include: (a) emissions or releases to air, water, or land; (b) use of raw materials and natural resources; (c) use of energy; (d) the use of space; and (e) the generation of waste.
Environmental aspects are identified from a life cycle perspective that includes the
33 organization’s supply chain. Only those aspects that are determined to be significant are addressed by the management system. Environmental impacts are changes to the environment resulting from environmental aspects. The “environment” is defined as
“surroundings in which the organization operates, including air, water, land, natural resources, flora, fauna, humans and their interrelationships.” [35]
34
THE INTERNATIONAL ORGANIZATION FOR STANDARDIZATION (ISO)
RISK MANAGEMENT STANDARD
Risk Management Fundamentals
The ISO 31000:2009(E) standard provides generic principles and guidelines on risk management that can be applied to any type of risk associated with a wide range of activities, processes, and projects. This standard is intended for use with other ISO standards such as the ISO 14001 Environmental Management System standard; however, unlike ISO 14001, ISO 31000 is not intended for certification purposes. Under the risk management standard, “risk” is defined as “effect of uncertainty on objectives” and “risk management” is “coordinated activities to direct and control an organization with regard to risk.” The management of risk in accordance with the ISO risk management standard increases the likelihood of achieving sustainability performance objectives including environmental objectives established within an environmental management system. The
ISO standard further explains that “risk management helps decision makers make informed choices, prioritize actions and distinguish among alternative courses of action.”
Whether an energy development achieves sustainability performance targets can depend upon whether risk management is an integral part of organizational processes. [37]
35 Risk Management Framework
ISO 31000:2009(E) defines “risk management framework” as a “set of components that provide the foundations and organizational arrangements for designing, implementing, monitoring, reviewing and continually improving risk management throughout the organization” and risk management success depends on this framework.
The components of a risk management framework include: (a) a risk management policy that defines, mandates, and expresses the organization’s commitment to risk management; (b) assigns risk management responsibilities; (c) establishes accountability;
(d) integrates or embeds risk management effectively and efficiently within the organization’s practices and processes; (e) provides internal and external communication plans; (f) monitors risk management performance against indicators; and (g) continuously improves the risk management framework. The organization’s risk management framework is implemented by applying the risk management process through a risk management plan. [37]
Risk Management Process
ISO 31000:2009(E) specifies that stakeholder communication and consultation along with monitoring and review should take place throughout the risk management process. Communications and consultations at an early stage “help ensure that risks are adequately identified” and “ensure that the interests of stakeholders are understood and considered.” The stages of the risk management process are: (a) establishing the risk management context; (b) risk identification; (c) risk analysis; (d) risk evaluation; and (e) risk treatment. [37]
36 Risk Management Context and Criteria
Establishing the risk management context includes consideration of external and internal factors including, but not limited to the following: stakeholder values and perceptions, political factors, legal requirements, and organizational culture and processes. Part of establishing the context is to define criteria to be used to evaluate the significance of risk. Criteria should be derived from organizational objectives, legal requirements, and organizational policies. [37] ISO/TR 31004:2013(E) defines “risk criteria” as “the parameters established by the organization to allow it to describe risk and make decisions about the significance of risk that take into account the organization’s attitude to risk. These decisions enable risk to be assessed and treatment to be selected.”
[38] The IEC/ISO 31010:2009 standard on risk management techniques further explains the purpose of defining risk criteria as necessary to decide: (a) how a level of risk will be determined; (b) when a risk needs treatment; (c) when a risk is acceptable and/or tolerable; and (d) whether and how combinations of risks will be considered. [39]
Risk Assessment
“Risk assessment” is the risk management process stages of risk identification, risk analysis and risk evaluation. [39]
Risk Identification
“Risk identification is the process of finding, recognizing, and recording risks”.
The purpose is to identify “what situations might exist that might affect the achievement of objectives.” A question that might be asked is “what could go wrong?” As previously discussed, management system compliance objectives typically include government regulatory requirements and performance requirements derived from organizational
37 policies. When risks are identified, the organization should identify any existing controls affecting the risks. These controls might include design provisions or organizational processes. Risks can be identified using evidence-based methods such as checklists and historical information. Risks can also be identified using systematic team approaches that rely upon subject matter experts. Brainstorming is a technique that is often used to improve the accuracy and completeness of risk identification. [39] Larson and Gray describe a project management approach to risk identification where risks are identified by creating a risk breakdown structure. [40] The Project Management Institute Project
Management Book of Knowledge defines “risk breakdown structure” as “a hierarchically organized depiction of the identified project risks arranged by risk category.” [41] The
Project Management Book of Knowledge is now provided as International Organization for Standardization (ISO) Standard 21500:2012. [42]
Risk Analysis
In the Risk analysis stage of the risk management process, the consequences and probabilities of risk events are determined for identified risks. Existing controls are considered in this determination. The consequences and probabilities of risk events are combined to determine a level of risk. The methods used for analyzing risks can be qualitative, semi-qualitative or quantitative depending on the application, data availability, and decision-making needs of the organization. Qualitative assessments typically define risks using terms such as “high, medium, or low.” Semi-quantitative assessments often use numerical scales for consequence and probability and combine them to produce a level of risk using a formula. Quantitative assessments estimate practical values for consequence and their probabilities. When insufficient information is
38 available to perform quantitative assessments, comparative semi-quantitative or qualitative ranking of risks by specialists knowledgeable in their respective field may be effective. [39]
The comparative semi-quantitative approach to ranking risks is often used for project management and it is well-suited for oil sand development projects. Larson and
Gray describe a semi-quantitative approach for project risks using a version of the Failure
Mode and Effects Analysis (FMEA) technique to assess risks where the probability of a risk event, the impact of the risk event, and the ability to detect an occurrence of the risk event are each scored on a five-point scale and each risk is scored using the following equation:
Impact x Probability x Detection = Risk Value
They point out that the quality and credibility of the risk analysis process requires that the different levels of risk probabilities, impacts, and detection abilities need to be defined for each point on the scoring scales. [40] Under the IEC/ISO 31010:2009 standard on risk management techniques, this approach is described as the use of risk indices. This standard defines the use of “risk indices” for risk analysis as “a semi-quantitative measure of risk which is an estimate derived using a scoring approach using ordinal scales. Risk indices can be used to rate a series of risks using similar criteria so that they can be compared.” The standard further states “risk indices are essentially a qualitative approach to ranking and comparing risks.” [39]
Risk Evaluation
The ISO 31000:2009(E) standard states that “risk evaluation involves comparing the level of risk found during the analysis process with risk criteria established when the
39 context was considered. Based upon this comparison, the need for treatment can be considered.” [37] In the evaluation of risks, some of the decisions to be made are: (a) whether a risk needs treatment; (b) priorities for treatment; and (c) whether an activity should be undertaken. The cost and benefits of accepting the risk verses treating the risk may be a decision factor. Risks are often placed into one of the following three categories: (1) risks that are intolerable and risk avoidance or treatment is essential; (2) risks where the cost and benefit of taking the risk are balanced against the cost and benefits of risk treatment; and (3) risks that are negligible or so small that no treatment is needed. [39]
Risk Treatment
The ISO 31000:2009(E) standard states that “risk treatment involves selecting one or more options for modifying risks, and implementing those options.” Whether the residual risk levels are tolerable following treatment is a factor. Potential risk treatment options include the following: (a) avoiding the risk; (b) retaining or taking the risk; (c) removing the risk source; (d) changing the likelihood; (e) changing the consequences; and (f) sharing the risk with others. “Selecting the most appropriate risk treatment option involves balancing the costs and efforts of implementation against the benefits derived, with regard to legal, regulatory, and other requirements such as social responsibility and the protection of the natural environment.” [37] Larson and Gray organize risk treatment options into four categories that encompass the previously discussed ISO 31000:2009(E) list: (a) mitigating risk; (b) avoiding risk; (c) transferring risk; and (d) retaining risk.
There are two basic strategies for mitigating risks; the first is to reduce the likelihood that the event will occur, and the second is to reduce the impact of the potential adverse event.
40 Risk avoidance is changing the project plan to eliminate the risk. Transferring risk to another party usually occurs via a contract, insurance, performance bonds, or warranties.
Retaining risk is a conscious decision to accept the risk of an event occurring. Larson and
Gray distinguish between a risk treatment and a risk contingency plan. Risk treatment occurs before a risk event can occur and a risk contingency plan goes into effect after a risk event occurrence has been detected. [40]
41
ASSESSMENT OF SUSTAINABILITY RISKS FROM OIL SANDS
DEVELOPMENT
The following risk assessment process for sustainability risks from oil sands development is derived from the ISO standards discussed in previous chapters:
Step #1: Define the risk management context and risk evaluation criteria according to
IEC/ISO 31010:2009.
Step #2: Identify risks in a risk breakdown structure format according to the Project
Management Institute Project Management Book of Knowledge/ISO 21500:2012.
Environmental risk categories within the risk breakdown structure will correspond to significant environmental aspects according to ISO 14001:2015
Step #3: Analyze Risks according to ISO 31000:2009(E) in a semi-quantitative approach using risk indices and a modified FMEA technique where the probability of a risk event, the impact of the risk event, and the ability to detect an occurrence of the risk event are each scored on a five-point scale and each risk is scored using the following equation:
Impact x Probability x Detection = Risk Value
Step #4: Evaluate risks using criteria from Step #1 according to ISO 31000:2009(E)
Step #5: Treat risks according to ISO 31000:2009(E).
Significant environmental and social sustainability risks are identified and assessed for current oil sand developments in Canada and Utah, and potential oil sand
42 development in Alabama using the same risk scoring indices and evaluation criteria to generate relative risk scores. After current regulatory risk treatments are applied, the risks are re-scored to determine a relative percentage reduction in the risk scores. Potential regulatory risk treatments are then applied to identified environmental and social sustainability risks associated with the potential development of Alabama oil sands to determine regulatory risk treatments that would effectively reduce these risks.
In the risk management process described above, one or more subject matter experts are typically utilized to identify environmental aspects, identify risks, score risks, and evaluate risks. I am a qualified subject matter expert in these areas having managed all aspects of environmental policy and compliance in the energy field and teaching graduate level environmental law, sustainability, and project management courses dealing with environmental and sustainability risk management for many years. Therefore, 3rd party subject matter experts are not utilized to identify, analyze, and evaluate oil sands development risks in this dissertation.
Definition of Risk Management Context and Risk Evaluation Criteria
The organizational participants within the scope of this assessment of oil sands development sustainability risks are any companies conducting or proposing oil sand developments and the governments that regulate those developments. Company activities to develop oil sands are the causation of identified risks and the governments having jurisdiction over these developments act to treat these risks through statutes and regulations. Given that the end goal of this dissertation is to generate a regulatory risk treatment model for the potential development of Alabama oil sands, the risk scoring indices used to assess identified risks, and the risk evaluation criteria that will be applied
43 to each risk will reflect an Alabama regulatory context; therefore, oil sand development risks in Utah, Canada, and Alabama will be scored using the same indices and evaluated using the same criteria to identify and apply the best regulatory practices to oil sand development risks presented in Alabama.
From an Alabama regulatory context, the following sustainability criteria are gleaned from federal and state regulatory requirements and policy:
Government Regulation and Protection of Biodiversity: The Public Trust
Doctrine establishes a trustee relationship of government to hold and manage wildlife, fish, and waterways for the benefit of the resources and the public. [43] Elements of the
Public Trust Doctrine are codified within Alabama statutory law. Ala. Code § 9-11-230
(1975) states “the title and ownership to all wild birds and wild animals in the State of
Alabama or within the territorial jurisdiction of the state are vested in the state for the purpose of regulating the use and disposition of the same in accordance with the laws of the state.” Ala. Code § 9-11-81 (1975) states “the title ownership to all fish in the public fresh waters of the State of Alabama is vested in the state for the purpose of regulating the use and disposition of the same in accordance with the provisions of the laws of this state and regulations based thereon.” Section 9 the federal Endangered Species Act
(ESA) prohibits adverse impacts to listed threatened or endangered species or their designated critical habitat under the act. There are also other federal biodiversity protection laws like the Migratory Bird Treaty Act (MBTA) and the Bald and Golden
Eagle Protection Act (BGEPA). These government biodiversity interests collectively provide a risk management biodiversity context supportive of the risk evaluation criteria in the table below.
44 Government Regulation and Protection of Surface Water Quality: As previously stated, the Public Trust Doctrine establishes a trustee relationship of government to hold and manage waterways for the benefit of the resources and the public. [43] That doctrine is reflected in the federal Clean Water Act (CWA) Section 402
NPDES program that requires permits for the discharge of “pollutants” from any “point source” into “waters of the United States.” 40 CFR 122.1(b)(1). The National Pollutant
Discharge Elimination System (NPDES) means the national program for issuing, modifying, revoking and reissuing, terminating, monitoring and enforcing permits, and imposing and enforcing pretreatment requirements, under sections 307, 402, 318, and 405 of CWA. 40 CFR 122.2. Permits are also required for the discharge of fill or dredged material into waters of the United States under CWA Section 404. The term “waters of the United States” is lengthy and complex and includes a wide range of rivers, perennial streams, intermittent streams, creeks, and wetlands. 40 CFR 122.2. The Public Trust
Doctrine is also reflected in the designation and enforcement of state water quality standards under Section 303(c) of the CWA. 40 Part 131. Under Section 303(d) of the
CWA, states prepare a list of impaired waters that do not meet state water quality standards and Total Maximum Daily Loads (TMDLs) are created to determine the maximum amount of a pollutant that should be allowed to enter the waterbody so that the water body will meet and continue to meet the water quality standard for that pollutant.
40 CFR 130.7. These government surface water quality interests provide a risk management surface water quality context supportive of the risk evaluation criteria in the table below.
45 Government Regulation and Protection of Surface Water Quantity: Surface water rights are allocated under two different systems in the United States. In the eastern part of the country surface water rights belong to the owners of property abutting a stream. A property owner abutting a stream is called a riparian and the riparian owner’s surface water right is called a riparian water right. Riparian landowners do not own the surface water, but have a right to reasonable use of the abutting surface water. If the riparian owner sells his/her land, the riparian owner loses his/her riparian water rights.
Non-riparian land owners do not possess surface water rights under a riparian water rights system. In the western part of the country surface water rights are allocated under a system based upon prior appropriation which rewards the first user in time to put the water to beneficial use. Senior appropriators possess superior rights to junior appropriators. Under the prior appropriation doctrine water rights are not associated with riparian land ownership. Prior appropriation water rights can be sold and lost because of non-use. Both the riparian and prior appropriation systems have evolved over time and some states have surface water use permitting systems that contain elements of both systems. [44] The addition of state permitting systems as surface water rights have evolved over time finds support in the Public Trust Doctrine that establishes a trustee relationship of government to hold and manage waterways for the benefit of the resources and the public. [43] University of Alabama School of Law professor Heather Elliott demonstrates that Alabama faces a major water crisis because of droughts, the increasing water demands of population growth and development, and inadequacies with current water resources law. There are also significant ongoing interstate conflicts between
Alabama, Georgia, and Florida over water because of increasing regional demands and
46 decreasing regional water availability. Elliott wants to see significant changes to
Alabama’s water resources law with a permitting system for surface and ground water diversions that specifies where, when, and how water may be diverted, how much may be diverted, and what the water may be used for. [45] An Alabama Water Agencies Working
Group (AWAWG) report to Governor Robert Bentley in 2013 describes the importance of naturally varying stream flows to support healthy ecosystems. In addition to ecological minimum stream flow requirements, adequate instream flows are also important to other water users including NPDES permit holders who rely on sufficient stream flows for pollutant assimilative capacity to remain within permit limits and state water quality standards, public water supplies, outdoor recreational water users, and power generation water users. The AWAWG report states “Instream flow management approaches vary widely from state to state, and there are few national standardized methods for linking flow quantity and duration to state and local water needs and requirements while considering stream ecology, riparian areas, and floodplain habitats.” Alabama has no law prescribing instream flow standards. [46] The AWAWG Instream Flow Focus Panel has defined “instream flow” as “the amount of water that supports instream uses including: waste assimilation and maintaining water quality standards; protection of freshwater and estuarine fish and wildlife habitat, migration, and propagation; outdoor recreational activities; downstream uses; navigation, power generation, and commerce; ecosystem maintenance, which includes recruitment of freshwater to estuaries, riparian areas, floodplain wetlands and maintenance of channel geomorphology; and future needs.” [47]
In 2017 the Alabama Office of Water Resources issued a statewide surface water assessment report showing “that for a very large part of the state, consumptive use is
47 equal to a very low percentage of streamflow and considerable increases in consumptive use can be sustained.” [48] These government surface water quantity interests provide a risk management surface water quantity context supportive of the risk evaluation criteria in the table below.
Government Regulation and Protection of Groundwater Quality: Most public water systems rely on groundwater as a source of drinking water. The federal Safe
Drinking Water Act (SDWA) protects underground sources of drinking water by regulating and/or prohibiting the underground injection of wastes that may affect groundwater sources. EPA regulations contain the minimum requirements for state
Underground Injection Control (UIC) programs. There are six classes of UIC wells. If an approved state UIC program is not in place, EPA implements the program. [49] In 1997, the U.S. Court of Appeals for the 11th Circuit held that hydraulic fracturing of coal bed methane (CBM) wells in Alabama must be regulated under the SDWA. In 2004 EPA reported that the CBM risk was small unless diesel fuel was used in the hydraulic fracturing process. The federal Energy Policy Act of 2005 revised the SDWA to explicitly exclude the injection of hydraulic fracturing fluids and propping agents except for fluids containing diesel fuels. Therefore, hydraulic fracturing is only regulated when diesel fuels are used. Injection wells that are used for the disposal of produced brines associated with oil and gas production wells and injection wells for enhanced oil and gas recovery are regulated as Class II wells under the SDWA. [50] The term “enhanced oil recovery” is not defined in the SDWA or implementing regulations. It is generally understood to mean secondary and tertiary recovery techniques where various fluids such as water and CO2 are injected through well bores to stimulate oil and gas production
48 from existing wells. [51] Alabama’s State Oil and Gas Board regulates SDWA Class II
UIC wells through its regulations at Ala. Admin. Code r. 400-4-1 (2017) et. seq. Under
Alabama Oil and Gas Board regulations a “Class II injection well shall mean an injection well which is used (1) to inject brine or other fluids which are brought to the surface in connection with natural gas storage operations or oil or natural gas production and which may be commingled with waste waters from gas plants which are an integral part of production operations, unless those waters are classified as a hazardous waste at the time of injection; (2) for enhanced recovery of oil or natural gas; or (3) for storage of hydrocarbons which are liquid at standard temperature and pressure.” “Fluid shall mean a material or substance which flows or moves whether in a semi-solid, liquid, sludge, gaseous or any other form or state.” Ala. Admin. Code r. 400-4-2-.01(1) (2017).
“Enhanced recovery shall mean the increased recovery from a pool achieved by flooding, pressuring, cycling, or pressure maintenance and which may include the injection into the pool of a substance or a form of energy extrinsic to the pool.” Ala. Admin. Code r. 400-1-
1-.05(25) (2017). Techniques for in situ bitumen recovery from Alabama oil sand deposits have not be developed and tested. Considering the consolidated hard rock nature of Alabama oil sand deposits, it is foreseeable that in situ recovery techniques might include hydraulic fracturing and the operational injection of steam and/or solvents. Given that Alabama’s oil sand deposits are relatively shallow and potentially within underground sources of drinking water, the Alabama Oil and Gas Board may need to develop new UIC Class II injection well regulations for oil sand development. These government ground water quality interests provide a risk management ground water quantity context supportive of the risk evaluation criteria in the table below.
49 Government Regulation and Protection of Groundwater Quantity: Alabama follows the “American reasonable use rule” where overlying owners have a right to use the water on the overlying tract. [45] Unlike Alabama’s riparian water rights doctrine,
Alabama’s groundwater doctrine does not prohibit off-tract use of water. According
Heather Elliott, “It is possible to export groundwater for use on a non-overlying tract if one purchases an overlying parcel from which to export or, presumably, if one bargains with an overlying landowner for access to her tract for pumping. Export of water for use on a non-overlying tract will be enjoined, however, if that export harms the water rights of an overlying landowner.” [52] The Geological Survey of Alabama (GSA) is conducting a comprehensive statewide assessment of groundwater resources to determine groundwater use and availability. The initial groundwater assessment began in southeast
Alabama and research is being conducted throughout the state to complete a statewide groundwater assessment. [53] These government ground water quantity interests provide a risk management ground water quantity context supportive of the risk evaluation criteria in the table below.
Government Regulation and Protection of Cultural Resources: Under the
National Historic Preservation Act “it is the policy of the Federal Government, in cooperation with other nations and in partnership with States, local governments, Indian tribes, Native Hawaiian organizations, and private organizations, and individuals, to – (4) contribute to the preservation of nonfederally owned historic property and give maximum encouragement to organizations and individuals undertaking preservation by private means.” 54 U.S.C. § 300101. “Historic property” means “any prehistoric or historic district, site, building, structure, or object included on, or eligible for inclusion on, the
50 National Register, including artifacts, records, and material remains relating to the district, site, building, structure, or object.” 54 U.S.C. § 300308. The “National Register” means “the National Register of Historic Places Maintained under [the National Historic
Preservation Act.]” 54 U.S.C. § 300311. A State Historic Preservation Officer (SHPO) is responsible for administering a state Historic Preservation Program under the National
Historic Preservation Act. The SHPO identifies and nominates eligible property to the
National Register. 54 U.S.C. § 302303. Under Section 106 of the Act, federal agencies are required to take effects on any historic property into account before taking certain federal actions such as the issuance of a permit or license. 54 U.S.C. § 306108. To comply with the Section 106 requirements, the U.S. Army Corps of Engineers requires that private permittees conducting activities within waters of the United States under its
Nationwide Permits must notify the Corps if the activity might have the potential to cause effects to any historic properties listed on, or potentially eligible for listing on the
National Register of Historic Places. 82 Fed. Reg. 2000 (January 6, 2017) and 33 CFR §
330.4(g)(3). These government cultural resource interests provide a risk management cultural resource context supportive of the risk evaluation criteria in the table below.
Government Regulation of the Release of Toxic Chemicals and Waste
Disposal: Under the federal Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA), if there is a release equal to or greater than a designated reportable quantity of a hazardous substance within a 24-hour period, a notification must be made to the National Response Center, State or Tribal Emergency Response
Commission, and Local Emergency Planning Committee. The United States
Environmental Protection Agency has established a list of reportable quantities for
51 various hazardous substances. 42 U.S.C. § 9601 et seq. (1980). The federal Resource
Conservation and Recovery Act (RCRA) regulates the management of hazardous and non-hazardous wastes. There are different management requirements under RCRA for hazardous and non-hazardous wastes. Whether a waste is hazardous depends upon whether it is on one of several lists of designated hazardous wastes or if it exhibits one or more of the defined characteristics of a hazardous waste. 42 U.S.C. § 6901 et seq. (1976).
These government hazardous substance release and waste management interests provide a risk management hazardous substance and waste management context supportive of the risk evaluation criteria in the table below.
Government Regulation and Protection of Air Quality: The federal Clean Air
Act (CAA) of 1970 regulates air emissions from stationary and mobile sources. Under the
CAA, EPA has established National Ambient Air Quality Standards (NAAQS) for a short list of relatively ubiquitous Criteria Air Pollutants and emission standards for a long list of hazardous air pollutants. CAA permits are required for Major Sources of these pollutants. With respect to areas determined to be in nonattainment of the NAAQS, state governments may establish a State Implementation Plan (SIP) for achieving NAAQS compliance. 42 U.S.C. § 7401 et seq. (1970). These government air quality interests provide a risk management hazardous air quality context supportive of the risk evaluation criteria in the table below.
Government Interest in Environmental Justice: EPA has defined
“environmental justice” as “the fair treatment and meaningful involvement of all people regardless of race, color, national origin, or income, with respect to the development, implementation, and enforcement of environmental laws, regulations, and policies. Fair
52 treatment means no group of people should bear a disproportionate share of the negative environmental consequences resulting from industrial, governmental and commercial operations or policies. Meaningful involvement means: People have an opportunity to participate in decisions about activities that may affect their environment and/or health;
The public's contribution can influence the regulatory agency's decision; Community concerns will be considered in the decision making process; Decision makers will seek out and facilitate the involvement of those potentially affected.” [54] Presidential
Executive Order 12898 directs federal agencies to address environmental justice in their missions. Section 1-101 of the Executive Order states: “To the greatest extent practicable and permitted by law, and consistent with the principles set forth in the report on the
National Performance Review, each Federal agency shall make achieving environmental justice part of its mission by identifying and addressing, as appropriate, disproportionately high and adverse human health or environmental effects of its programs, policies, and activities on minority populations and low-income populations in the United States and its territories and possessions, the District of Columbia, the
Commonwealth of Puerto Rico, and the Commonwealth of the Mariana Islands.”
Accompanying the Executive Order was a Presidential Memorandum stating in part: “In accordance with Title VI of the Civil [R]ights Act of 1964, each Federal agency shall ensure that all programs or activities receiving Federal financial assistance that affect human health or the environment do not directly, or through contractual or other arrangements, use criteria, methods, or practices that discriminate on the basis of race, color, or national origin. Each Federal agency shall analyze the environmental effects, including human health, economic and social effects, of Federal actions, including effects
53 on minority communities and low-income communities, when such analysis is required by the National Environmental Policy Act of 1969 (NEPA), 42 U.S.C. section #321 et seq. Mitigation measures outlined or analyzed in an environmental assessment, environmental impact statement, or record of decision, whenever feasible, should address significant and adverse environmental effects of proposed Federal actions on minority communities and low-income communities.” 59 Fed. Reg. 7629 (Feb. 11, 1994). Title VI of the Civil Rights Act of 1964 prohibits discrimination on the basis of race, color, and national origin in programs and activities receiving federal financial assistance. 42 U.S.
C. § 2000d et seq. These government environmental justice interests provide a risk management environmental justice context supportive of the risk evaluation criteria in the table below.
54 Table 1
Risk Evaluation Criteria
Category 1: Risks that are Category 2: Risks Category 3: intolerable and risk where the cost Risks that are Risk Criteria avoidance or treatment is and benefit of negligible or essential taking the risk are so small that balanced against no treatment the cost and is needed. benefits of risk treatment Protection of Adverse Impacts to: (a) Minor, temporary, Negligible Biodiversity Listed Threatened or impacts to fish & impacts to Endangered Species or wildlife protected species and Designated Critical Habitat by a state or nation habitats will under the federal ESA; (b) under the Public occur birds protected under the Trust Doctrine that federal MBTA or BGEPA; are not protected or (c) laws like (a) or (b) for under federal ESA, developments within another MBTA, BGEPA, nation. Significant and/or or similar laws long-term impacts to fish & within another wildlife protected by a state nation. or nation under the Public Trust Doctrine. Protection of Unpermitted pollutant Minor and Negligible Surface Water discharges or fill to a water temporary non- water quality Quality of the United States. compliance with impacts to Significant violation of a CWA permits, state waters of the state water quality standards. water quality United States Significant non-compliance standards, or with a CWA Section 402 or TMDLs Section 404 permit. Significant noncompliance with a TMDL
55 Category 1: Risks that are Category 2: Risks Category 3: intolerable and risk where the cost Risks that are Risk Criteria avoidance or treatment is and benefit of negligible or essential taking the risk are so small that balanced against no treatment the cost and is needed. benefits of risk treatment Protection of A surface water diversion or Minor and Negligible Surface Water consumptive use that is not temporary surface surface water Quantity based upon a valid water water rights rights impacts. right or violates the water conflicts. Minor Negligible rights of another. A surface and temporary exceedances of water use that significantly exceedances of minimum exceeds minimum stream minimum stream stream flows flows needed for: (a) waste flows needed for: needed for: (a) assimilation; (b) public water (a) waste waste supplies; (c) outdoor assimilation; (b) assimilation; recreational activities; (d) public water (b) public navigation; (e) power supplies; (c) water supplies; generation & commerce; (f) outdoor (c) outdoor ecosystem maintenance recreational recreational activities; (d) activities; (d) navigation; (e) navigation; (e) power generation power & commerce; (f) generation & ecosystem commerce; (f) maintenance ecosystem maintenance Protection of Adverse hydraulic fracturing Minor and Negligible Groundwater impacts to underground temporary impacts to Quality sources of drinking water. groundwater groundwater Adverse Class II UIC impacts that do not injection well impacts to involve an underground sources of underground drinking water from the source of drinking injection of steam or solvents water for in situ bitumen recovery Protection of A groundwater use that Groundwater use Negligible Groundwater significantly harms the water that results in impacts to the Quantity rights of another minor and water rights of groundwater rights holder temporary harm to another the water rights of groundwater another rights holder groundwater rights holder
56 Category 1: Risks that are Category 2: Risks Category 3: intolerable and risk where the cost Risks that are Risk Criteria avoidance or treatment is and benefit of negligible or essential taking the risk are so small that balanced against no treatment the cost and is needed. benefits of risk treatment Protection of Impacts to cultural resources Impacts to cultural Negligible Cultural from activities that are resources from impacts to Resources subject to federal approvals activities that are cultural and the NHPA Section 106 not subject to resources requirements; Impacts to federal approvals human remains and the NHPA Section 106 requirements Prevention of Release of a reportable Minor and No CERCLA Toxic quantity of a CERCLA temporary hazardous Chemical hazardous substance or violations of substance or Releases and significant RCRA waste RCRA waste hazardous Improper management violations management waste risks are Waste requirements presented Disposal Protection of Air emissions that Minor and Negligible air Air Quality substantially violate the temporary air emissions will CAA emissions occur Environmental Violation of Title VI of the Minor and No Justice Civil Rights Act of 1964 or temporary effects environmental significant adverse impacts to environmental justice to environmental justice justice communities communities communities affected
Risk Assessment Scoring Indices
Identified Risks are assessed according to ISO 31000:2009(E) in a semi- quantitative approach using risk indices and a modified FMEA technique where the probability of a risk event, the impact of the risk event, and the ability to detect an occurrence of the risk event are each scored on a five-point scale and each risk is scored using the following equation:
Impact x Probability x Detectability = Risk Score
57 Each risk impact is scored using the scoring index provided in the table below.
Table 2
Risk Impact Scoring Index
Risk Impact Score Sustainability Regulatory Organizational Effects Compliance Status Policy Compliance Status 1 Temporary, minor, No regulatory Insignificant or insignificant reporting required. deviation from impacts that No government organizational quickly dissipate enforcement action policy with no remedial will occur. No action required regulatory violation. 2 Temporary, minor, Minor regulatory Minor deviation or insignificant violation with no from organizational impacts that require self-reporting policy minimal short-term required remedial action 3 Moderate impacts Moderate non- Moderate deviation that will require compliance, self- from an significant remedial reporting may be organizational work required. policy that may Government require internal enforcement action reporting. unlikely if problem addressed. Potential government warning letter if found via government inspection. 4 Significant long- Significant non- Significant term impacts compliance that deviation from an requiring may result in a organizational significant remedial government Notice policy that should work of Violation and require internal penalty reporting
58 Risk Impact Score Sustainability Regulatory Organizational Effects Compliance Status Policy Compliance Status 5 Major long-term Significant non- Failure to achieve a adverse impacts to compliance that significant biodiversity, water could result in organizational quality, water significant civil objective or quantity, air penalty, significant failure quality, or major administrative to comply with an spills or releases of order, or criminal important hazardous enforcement action organizational substances causing policy major harm to the environment or stakeholders
Each risk probability is scored using the scoring index provided in the table below.
Table 3
Risk Probability Scoring Index
Risk Probability Score Subjective Probability Range 1 Greater than 0% to 20% 2 21% to 40% 3 41% to 60% 4 61% to 80% 5 81% to 100%
The detectability of each risk is scored using the scoring index provided in the table below.
Table 4
Risk Detectability Scoring Index
Risk Detectability Score Detectability Characteristics 1 Would be immediately detected 2 Would be detected within 24 hours 3 Would be detected within one week 4 Would be detected within one month
59 Risk Detectability Score Detectability Characteristics 5 Would not be easily detected. The impact may not be detected for a long period of time (i.e. many months or years)
Sustainability Risks Associated with Canadian Oil Sands Development
The following sustainability issues have been associated with oil sands production in Canada:
• Water Consumption and Water Availability
• Waste Water Management and Potential Water Pollution
• Potential Air Pollutants
• Green House Gas (GHG) Footprint
• Potential Ecosystem and Biodiversity Impacts
• Potential loss of Streams and Wetlands
• Bitumen and/or Synthetic Crude Oil (SCO) Transportation Spill Risks
• Reclamation of Surface Extraction Mines and Tailing Ponds
• Potential Social Impacts
Water Consumption and Water Availability: Oil sands development presents serious risks to Canada’s water security because of insufficient local water supply and inappropriate water disposal methods. Less than 10% of water withdrawals associated with oil sands production is returned to the source resulting in the prediction of future water supply shortages. Alberta water quality is being affected not only by oil sands development discharges, but also by oil sands development water consumption. [55] A
2013 report issued by the Pembina Institute indicates that large amounts of water are required to extract and process bitumen into SCO with a water recycle rate between 40%
60 to 90%, depending on the bitumen extraction process. The production of one barrel of
SCO from surface mining uses at least three times as much fresh water as one barrel of conventional oil. They report the following water requirements to produce one barrel of
SCO:
• Two to four barrels of freshwater are required when the bitumen is extracted via
surface mining.
• Approximately O.8 to 1.7 barrels of freshwater are required when the bitumen is
extracted via in situ methods.
Surface water flows in the Athabasca River are highly variable throughout the year.
Pembina argues that these water withdrawals are not adequately limited to ensure the availability of minimum stream flow requirements for aquatic ecosystems in light of seasonal stream flow variability. Reducing the water demand and increasing water returns are major challenges for Canadian oil sands development. [56], [55]
Waste Water Management and Potential Water Pollution: Impacts on lake ecosystems associated with Canadian oil sands development are primarily related to surface mining bitumen extraction, in-situ bitumen extraction, and the upgrading of bitumen into synthetic crude oil (SCO). Various carcinogenic and toxic ecosystem contaminants are associated with oil sands surface mining and bitumen upgrading operations; however, pre-development background levels of these contaminants were not determined before Athabasca oil sands development began. Athabasca contaminants of concern include polycyclic aromatic hydrocarbons (PAHs) and dibenzothiophenes
(DBTs). A regional aquatics monitoring program to measure contaminant levels was not established until 1997, many years after Athabasca oil sands development began. The
61 establishment of pre-development background concentrations and historic loadings of these contaminants is needed to understand the ecosystem impacts of oil sands development in relation to natural sources. Natural sources of these contaminants include atmospheric deposition from forest fires and erosion and transport of naturally occurring bitumen-rich sediments.
Kurek et al used paleolimnological techniques to reconstruct pre-development background concentrations and natural pollutant loadings. They found that oil sands development has increased the delivery of PAHs and DBTs in the Athabasca oil sands region to well-above “natural” predevelopment levels. Total PAH concentrations in sediment cores from five lakes within a 35-km radius of major bitumen upgrading facilities all increased from mid-20th century levels. Increased PAH concentrations in lake sediments were found to have begun in 1966 +/- 5.7 years. Increased DBT concentrations in lake sediments were found to have begun in 1972 +/- 5.3 years.
Modern sediments were found to have PAH levels between approximately 2.5 and 23 times historic background levels. Modern sediments were found to have DBT levels between approximately 2.6 and 57 times historic background levels. In comparison, natural PAH deposition measured in remote lakes experienced maximum PAH levels during the mid-20th century with declining levels toward modern times; however, the lakes associated with Athabasca oil sands development showed an exponential-like increase in total PAH concentrations with time.
PAHs found within pre-1960 lake sediments were found to have characteristics of grass or wood combustion; however, PAHs found within modern lake sediments were found to have characteristics of petrogenic sources, coinciding with four decades of oil
62 sands development in the region. Atmospheric deposition of PAHs from upgrading facility emissions and dust particles from surface-mining areas are the likely sources of modern PAH measurements within regional aquatic ecosystems. The results show that
PAH levels have increased within lakes around Athabasca oil sands development and that
PAHs in modern lake sediments are characteristic of petrogenic sources. [57]
Notwithstanding the creation of a Canadian oil sands regional aquatics monitoring program in 1997, the Pembina Institute suggests that Canada lacks adequate water monitoring systems to detect water any water quality changes associated with oil sands development. [56]
In addition to potential water contamination from airborne sources, the large volume of process water associated with Canadian oil sands processing is a significant potential source of water pollution. This water is typically stored within tailings ponds.
Four cubic meters of process water are generated for each cubic meter of oil sands processed. Because Canadian environmental regulations impose a zero-discharge policy, this water must be held on site. This has resulted in over a billion cubic meters of tailings water being held in containment systems. All of the process water must eventually be treated and released. These process waters typically contain polycyclic aromatic hydrocarbons (PAHs) and napthenic acids (NAs). [58] The Pembina Institute describes these process waters as follows: “Tailings contain elevated concentrations of salts and toxic compounds such as metals, polycyclic aromatic hydrocarbons (PAHs), naphthenic acids and solvents that are added to the bitumen during the separation process. Metals detected in tailings lakes include arsenic, cadmium, chromium, copper, lead and zinc, all of which are labeled as priority pollutants under the United States Clean Water Act.
63 Heavy metals, such as arsenic, cadmium and lead, are very toxic and can build up in biological systems and become a significant health hazard.” [56] A 2011 study issued by the Green Party of Canada suggests that tailings ponds are leaking 4 billion liters per year
(11 million liters per day) of contaminated water into the environment and predicts that this volume could reach 25 billion liters per year within a decade in light of proposed projects. [15] This is supported by a study issued by the Pembina Institute that states:
“Toxic wastewater seeps out of tailing lakes at an estimated rate of more than 11 million litres per day” [56] However, in contrast to these two studies, a study by Miall, published in 2013 finds that this is not happening – “Much concern has been expressed regarding contamination of surface waters by seepage from tailings ponds, but hydrogeological studies indicate that this is not happening; that seepage capture design is effective.” [59]
The primary lessons to be gleaned from these studies are: (1) pre-development water quality testing should be performed to establish water quality baselines for oil sands- related pollutants; (2) on-going water quality testing should be performed to detect any adverse impacts relative to baseline assessments; (3) any tailings ponds or process water management systems warrant appropriate design standards and regulation; and (4) effective process water treatment systems must be in place for process water pollutants.
Potential Air Pollutants: Studies on the life-cycle GHG emissions associated with oil sands derived fuel production can be divided into two categories:
1. Well-To-Refinery (WTR) Entrance Gate Studies
2. Well-To-Wheel (WTW) Studies
WTR studies focus primarily on GHG emissions associated with bitumen extraction and
SCO production. WTW studies expand the WTR to also include refining, transportation
64 from refining to distribution, and end use of reformulated gasoline (RFG) fuel in light- duty vehicles.
The following oil sands production pathways are included in these studies:
1. Oil Sands Surface Mining and Upgrading (SM&Up)
2. Oil Sands In Situ Extraction and Upgrading (IS&Up)
3. Oil Sands In Situ Extraction Without Upgrading
The following metrics were used to compare past studies:
• For WTR comparisons, (kg) of CO2eq per barrel (bbl) of marketable product
(SCO for SM&Up and IS&Up; and bitumen for in situ without upgrading) -
kgCO2eq/bbl
• For WTW comparisons, gram (g) CO2eq per kilometer (km) driven in a gasoline
powered light duty vehicle – gCO2eq/km
On a WTR basis, the range of GHG emissions associated with SCO from oil sands was found to be higher than the GHG emissions range associated with conventional crude oil:
• 62 to 164 kgCO2eq/bbl for SCO from SM&Up
• 99 to 176 kgCO2eq/bbl for SCO from IS&Up
• 27 to 58 kgCO2eq/bbl for conventional crude oil
The higher GHG emissions intensity associated with SCO is due to the energy required to extract bitumen and upgrade it into SCO. With respect to SCO produced through IS&Up, steam-to-oil ratios (SOR) are an important factor in GHG emission calculations as they reflect energy consumption. The SOR is a measure of the efficiency
65 of oil production from steam injection. It is the volume of steam required to produce one unit volume of oil.
On a WTW basis, the range of GHG emissions associated with SCO from oil sands is higher than the GHG emissions range associated with conventional crude oil:
• 260 to 320 gCO2eq/km for RFG produced using SCO from SM&Up
• 320 to 350 gCO2eq/km for RFG produced using SCO from IS&Up
• 270 to 340 gCO2eq/km for RFG produced using In Situ without upgrading
• 250 to 280 gCO2eq/km for RFG produced using conventional crude oil
The GHG emission differences between SCO from oil sands and conventional oil is smaller on a WTW basis than on a WTR basis. This is because vehicle-use GHG emissions account for 60% to 80% of WTW emissions. Most of the WTW GHG emissions occur from the vehicle’s internal combustion engine.
These studies suggest: (a) that the range of GHG emissions associated with SCO from oil sands is higher than the GHG emissions range associated with conventional crude oil on both a WTR and WTW basis; and (b) that GHG emission differences between SCO from oil sands and conventional oil is smaller on a WTW basis than on a
WTR basis. Nonetheless, further study was recommended because definitive conclusions about the relative GHG emissions performance of the different oil sands pathways could not be drawn from the broad ranges of results found in these studies. Accurate GHG emissions data for the full fuel life cycle of oil sands-derived fuel production is required to understand GHG emissions from oil sands development. [14]
66 Following the study by Charpentier, et al, the Congressional Research Service
(CRS) also surveyed published literature on the life-cycle GHG emissions associated with Canadian oil sands production and found the following: [60]
• “Canadian oil sands crudes are on average somewhat more GHG emission
intensive than the crudes they may displace in U.S. refineries, as Well-to-Wheel
GHG emissions are, on average, 14%-20% higher for Canadian oil sands crudes
than for the weighted average of transportation fuels sold or distributed in the
United States”
• “Discounting the final consumption phase of the life-cycle assessment (which can
contribute up to 70%-80% of Well-to-Wheel emissions), Well-to-Tank (i.e.,
“production”) GHG emissions are, on average, 70%-110% higher for Canadian
oil sands crudes than for the weighted average of transportation fuels sold or
distributed in the United States”
• “Compared to selected imports, Canadian oil sands crudes range from 9% to 19%
more emission-intensive than Middle Eastern Sour, 5% to 13% more emission
intensive than Mexican Maya, and 2% to 18% more emission-intensive than
various Venezuelan crudes, on a Well-to-Wheel basis.”
• “Compared to selected energy- and resource-intensive crudes, Well-to-Wheel
GHG emissions for Canadian oil sands crudes are within range of heavier crudes
such as Venezuelan Bachaquero and Californian Kern River, as well as lighter
crudes that are produced from operations that flare associated gas (e.g., Nigerian
Bonny Light).”
67 The lessons to be learned from analysis of Canadian oil sands GHG footprints are:
(1) full fuel cycle (i.e. WTW or life-cycle) should be used when comparing GHG footprints of competing types of fuel; (2) there are many complex variables effecting the
GHG footprints of oil sands derived fuels.
Potential Ecosystem and Biodiversity Impacts: Very little analysis of broader ecosystem and biodiversity impacts from oil sands development was identified in academic literature; however, the Green Party of Canada published a paper by Michelle
Mech in 2011 that reviews literature and identifies known and potential ecosystem and biodiversity impacts associated with Canadian oil sands development. In addition to potential air and water pollution, Mech identified habitat fragmentation as a significant adverse impact. In particular, Mech concluded that woodland caribou herds could be lost from northeastern Alberta as a result of cumulative range disturbances. Mech also found that oil sands development could present a significant adverse impact on the habitat and migratory route of North American ducks and other waterfowl. Mech indicates that thousands of acres of diverse bird habitats have already been destroyed. A cumulative impact study projects that millions of birds could be lost due to loss of breeding and staging areas, and from birds landing in tailing ponds of waste. As an indicator of ecosystem impacts, Mech found from a review of other studies that fish embryos exposed to oil sands waste water and sediments have high rates of deformities and mortality. The
Canadian government has established some conservation areas where oil sands development will not be allowed and is now conducting biodiversity-monitoring. [15]
The broader ecosystem and/or biodiversity lessons to be learned are: (1) pre- development biodiversity assessments should be performed to establish baseline
68 conditions; (2) regular biodiversity monitoring should be performed during oil sands development; and (3) appropriate habitat/biodiversity conservation areas should be identified and protected from oil sands development.
Potential Loss of Streams and Wetlands: Academic studies of stream and wetland impacts from oil sands development were not found in a literature review.
Nonetheless, the Pembina Institute’s 2013 report indicates that wetland ecosystems dominate 65% of the Alberta oil sands active surface mining area. Peatlands are the primary type of wetland habitat encountered. Grant, et al, indicate that it is not possible to restore these peatlands after surface mining. [56]
With respect to potential stream and wetland losses associated with oils sands development, the following lessons can be learned: (1) pre-development characterization, delineation, and inventory of streams and wetlands should be performed as a baseline; and (2) stream and wetland losses should be monitored and regulated via appropriate regulatory programs.
Bitumen and/or SCO Transportation Spill Risks: The majority of Canadian oil sands production is transported as diluted bitumen via railway and/or pipeline. When spills occur, this material behaves differently than conventional crude oil. With a diluted bitumen spill, various by-products off-gas quickly, posing serious health risks to those near the spill, and the remaining bitumen typically sinks within aquatic ecosystems. In comparison, lighter conventional crude oil, typically stays on the surface where it can be skimmed off. [61] This difference in spill behavior can be explained by analyzing the composition of diluted bitumen which is formed by diluting bitumen with a diluent such as natural gas condensate to lower its viscosity for transportation. Diluted bitumen is
69 approximately 30% diluent and 70% bitumen. Bitumen itself is heavier than water and will sink; however, diluents are lighter than water and will float. If a spill occurs, it is possible that some of the spilled materials will sink and others will float. Planning for a response can be difficult. [62]
The lesson to be learned from the identification of potential risks associated with bitumen and/or SCO spills is that spill response plans must be developed and implemented that consider the unique characteristics of bitumen and/or SCO.
Reclamation of Surface Extraction Mines and Tailings Ponds: A review of academic literature did not reveal any significant attention to the reclamation of surface extraction mines and tailings ponds; nonetheless, there are numerous websites and papers discussing environmental issues associated with the operation and eventual reclamation of tailings ponds and surface mines. The portions of Canada’s oil sands that are extracted via surface mining techniques generate leftover materials known as “tailings’ after the bitumen has been extracted. Oil sands tailings contain a mixture of solvent, clay, sand, fine silt, water, residual bitumen, salts, metals and organic compounds. Various organizations in Canada have expressed concerns about spillage, leakage, and the long- term viability of reclaiming oil sands tailings ponds; however, the Canadian government requires a security deposit to ensure that long-term reclamation occurs. [63], [56], [15]
The lesson to be learned on environmental issues associated with the reclamation of tailings ponds are: (1) adequate regulation of tailing pond design, operation, and reclamation is important; (2) long-term financial assurance requirements are necessary to ensure that reclamation goals are attained and (3) life-cycle environmental impact
70 analysis and feasibility studies of tailings pond design, site selection, operation, and eventual reclamation are warranted.
Potential Social Impacts: While there are, potential social impacts associated with the development of Canada’s oil sands, there is little scientific research into those concerns. There are some concerns that First Nations people near or downstream of
Canadian oil sands development may be experiencing adverse health effects suspected to be caused by oil sands contaminants. Many of these individuals consume wild game that could be affected by oil sands-related contaminants and there are reports that tumors, mutations, and elevated levels of various oil sands contaminants have been found in fish, waterfowl, and mammal tissue samples in these areas. There are reports of suspected drinking water contamination. Social impacts on First Nation people include social disruption associated with the sudden influx of workers into relatively isolated communities. Disruption in another form occurs when First Nations people are less able to travel within the region by boat due to lower water levels caused by oil sands development activities. Another adverse social impact of concern is that First Nations people may not be adequately involved in government actions to establish oil sands development policies and approve specific developments. [15]
The lessons to be learned regarding potential social impacts are that pre- development demographic studies of areas surrounding and downstream of oil sands development areas should be performed to identify sensitive populations and potential adverse impacts and the meaningful involvement of all stakeholders is essential in government permitting and policymaking actions.
71 Sustainability Risks Associated with Utah Oil Sands Development
Significantly fewer sustainability risks were identified for current surface mining oil sands development in Utah compared to current oil sands development in Canada.
Potential environmental concerns include physical damage to land, ecosystem impacts, over use of water, and water contamination. U.S. Oil Sands indicates that they will consume about a barrel and a half of groundwater for every barrel of oil they produce.
Opposition to U.S. Oil Sands PR Springs project is concerned about potential watershed impacts from project drainage. [64] To the extent that any Utah oil sands development processes present significant water demands or produce significant wastewater discharges, water-related environmental concerns are presented in light of the scarcity of water in eastern Utah. [22] While the U.S. Oil Sands process requires water, neither the
American Oil Sands nor the MCW processes require process water. [65], [25] Utah’s oil sands contain 1/10 the sulfur of Canadian oil sands. [66]. Sustainability risks presented by Utah oil sands development are also addressed in the dissertation chapter discussing the current oil sands development technologies in Utah.
Sustainability Risks Associated with Alabama Oil Sands Development
Given that Alabama’s oil sands are not actively being developed now, sustainability risks associated with the potential development of Alabama oil sands must be gleaned from oil sand development experience in Utah and Canada considering the
Sustainability Risk Context for the potential Alabama development of Alabama oil sands realizing that Alabama’s oil sand deposits are most like those found in Utah. Guided by the factors, the following risks are identified for the potential development of Alabama oil sands:
72 • Risk of Adverse Biodiversity Impacts
o Federal Endangered Species Act Takings/Violations
o Migratory Bird Treaty Act Violations
o Bald and Golden Eagle Protection Act Violations
o Adverse impacts to State protected fish and wildlife
• Risk of Adverse Impacts to Surface Water Quality
o Unpermitted pollutant discharges to a Water of the United States
o Violation of a State Water Quality Standard
o Violation of an NPDES Water Pollutant Discharge Permit
o Noncompliance with a TMDL
• Risk of Adverse Impacts to Surface Water Quantity
o Surface water diversion or consumptive use that not based upon a valid
water right or violates the water rights of another
o Surface water use that exceeds minimum stream flows needed for: (a)
waste assimilation; (b) public water supplies; (c) outdoor recreational
activities; (d) navigation; (e) power generation & commerce; or (f)
ecosystem maintenance
• Risk of Adverse Impacts to Groundwater Quality
o Adverse impacts to underground drinking water sources from hydraulic
fracturing for in situ bitumen recovery
o Adverse impacts to underground sources of drinking water from
operational injection of steam, hot water, or solvents for in situ bitumen
recovery
73 o Adverse impacts to underground sources of drinking water from surface
contaminant infiltration via karst groundwater systems that include caves,
sinks, and springs in this area.
• Risk of Adverse Impacts to Groundwater Quantity
o Groundwater use that harms the water rights of another groundwater rights
holder
• Risk of Adverse Impacts to Cultural Resources
o Adverse impacts to cultural resources that are eligible or potentially
eligible for listing on the federal National Register of Historic places
o Adverse impacts to human remains
• Risk of Toxic Chemical Releases and Improper Waste Disposal
o Release of a CERCLA Reportable Quantity of a Hazardous Substance
o RCRA waste management violation
• Risk of Adverse Impacts to Air Quality in violation of CAA
• Risk of Adverse Environmental Justice Impacts
o Violation of Title VI of the Civil Rights Act of 1964
o Adverse impacts to Environmental Justice Communities
As previously discussed, Alabama’s Hartselle sandstone oil sand deposits are relatively consolidated suggesting that some form of hydraulic fracturing might be required for in-situ recovery. Potential environmental issues associated with hydraulic fracturing are identified in a September 11, 2013 paper by Steven L. Leifer, Thomas
Jackson, And Christine G. Wyman as follows: “Hydraulic fracturing requires significant amounts of water and produces large volumes of wastewater that could require treatment
74 before disposal or reuse. There are also concerns that chemicals used in the hydraulic fracturing process could contaminate groundwater either through surface spills or through the hydraulic fracturing process itself (although there is no evidence that the hydraulic fracturing process has ever caused such contamination). In addition, pumping of fluids deep underground as part of the injection of wastewater into disposal wells— and in one instance the hydraulic fracturing process itself—has been linked to minor cases of seismic activity.” [67] The International Gas Union (Union Internationale Du Gaz), in its
2009-2012 Triennium Work Report dated June, 2012 identified the following environmental concerns and recommended best practices associated with hydraulic fracturing:[68]
Concern: Potential Adverse Effects on Drinking Water. Recommended Best
Practices:
• Study local geology to identify subsurface drinking water sources within 250
meters of a well site before drilling
• Test any water sources within 250 meters of a well before, during, and after
drilling
• Utilize quality assurance programs to ensure proper well bore design,
construction practices, subcontractor oversight, and testing
• Set minimum well depths
Concern: Large Quantities of Water Used in Hydraulic Fracturing. Recommended
Best Practices:
• Collect and disclose water usage data
• Reduce, Re-Use, and Recycle water to mitigate water requirements
75 • Invest in viable technologies to reduce water usage
Concern: Potential Harm from Chemical Additives Within Hydraulic Fracturing
Fluids. Recommended Best Practices:
• Fully disclose fracturing fluid additives
• Invest in “green” or non-toxic alternatives to current additives
Concern: Adverse Seismic Activity from Hydraulic Fracturing and/or Underground
Injection of Wastewater. Recommended Best Practices:
• Review local geology for potential fault lines prior to drilling wells for gas
production and wastewater disposal.
• Monitoring drilling process with sensitive seismic instruments.
Concern: Adverse Impacts from Wastewater Disposal. Recommend Best Practices:
• Use deep underground injection wells or treat wastewater at a proper
wastewater treatment facility.
• Use “closed-loop” or “covered containment systems” to minimize
environmental impacts
• Develop wastewater management policies/procedures to ensure proper
wastewater management and compliance with applicable regulations.
Concern: Harmful Air Emissions. Recommended Best Practice:
• Mitigate fugitive emissions via green-completion systems to maximize
resource recovery and to minimize methane releases.
76
REGULATION OF OIL SANDS DEVELOPMENT AS A RISK MANAGEMENT
STRATEGY
Regulation of Canadian Oil Sands Development
Canadian Federalism: To understand Canadian environmental regulations, it is first key to gain a working knowledge of Canadian law and intergovernmental affairs.
Most importantly, this includes understanding Canadian federalism, the methods by which provinces and the national government work together. Although it is founded on the traditional foundation of federalism, the Canadian government is largely decentralized. The Constitution Act of 1867 recognizes each province as autonomous, meaning that the federal government cannot change a provincial law as it pleases.
Constitution Act, 1867, 30 & 31 Vict., c. 3 (U.K.). Additionally, the Act sets out a division of federal powers, provincial powers, as well as stating which powers are to be shared by both governments. Id. Direct taxation, administration of justice, transportation, public works, and anything of a local or private nature are all under the jurisdiction of provincial legislatures. Id. at §92. Additionally, provinces are given the exclusive power to make laws related to the exploration, development, conservation, and management of non-renewable natural resources. Id. Because oil sands are considered non-renewable natural resources, with rights owned by the British Crown, extraction practices are largely regulated by the Government of Alberta. However, there are many aspects of the industry
77 that fall under federal regulation, including the need for environmental assessment, air regulation, water regulation, well spacing, and transportation. Put simply, bitumen extraction and development practices are heavily regulated, both federally and provincially.
Mineral Rights: While private citizens may hold the surface rights to real property in Canada, over 90% of the nation’s mineral rights are held by the federal government and British Crown (“the Crown”). These rights cannot be purchased, but may be leased. Nationwide, mineral developers lease rights from the Crown, then pay royalties, as determined by provincial statutes. Because natural resources are governed provincially, the primary authorities on the Athabasca Oil Sands are Alberta’s Mines and
Minerals Act and Mines and Minerals Administration Regulation. Mines and Minerals
Act, R.S.A. 2000, c. M-17; Mines and Minerals Administration Regulation, A. Reg.
262/97 (Can.). Eighty-one percent of Alberta’s mineral rights are owned by the Crown and are available for lease. The other nineteen percent are owned by the Canadian government in the form of national parks. Of the 14 million hectares that make up the
Athabasca region and surrounding areas, nine million hectares are under lease. Currently,
76,700 hectares are being and mined in the Athabasca, region.
Well Spacing: The two most common types of bitumen extraction are open pit mining, also known as surface mining, and in situ (in place) mining. In situ mining is done through the placement of wells. In the oil sands development industry, well spacing practices are imperative to ensure prolonged environmental integrity of the Athabasca region for generations to come. Well spacing is regulated provincially under Alberta’s
Oil and Gas Conservation Rules:
78 [T]he drilling spacing unit for a well is the surface area of the drilling spacing unit
and (a) the subsurface vertically beneath that area, or (b) where the drilling
spacing unit is prescribed with respect to a specified pool, geological formation,
member or zone, the pool, geological formation, member or zone vertically
beneath that area.
Oil and Gas Conservation Rules, A. Reg. 151/71 (Can.) (§4.010(1)). Drilling spacing units set requirement for the distance between wells drilled into individual reservoirs for extracting bituminous sand. This regulates production rates, thus ensuring efficient and safe drainage of the resource. The standard spacing unit for oil sands is one well per quarter section. Id. at §4.010(3). The Mines and Minerals Act defines a Section as an area of land containing 256 hectares, while a quarter section is a 64-hectare area of land.
R.S.A. 2000, c. M-17 (§28). However, according to Alberta Energy Regulator Directive
056, it is common for oil sands developers to gain approval for closer well spacing.
Alberta Energy Regulator, Energy Development Application and Schedules (2011). A developer may gain special permission to increase the number of wells in a spacing unit by applying with the Energy Regulator. A. Reg. 151/71 (Can.) (§4.040(1)).
Royalties and Taxes: The Athabasca Oil Sands are an extremely valuable resource, not only to developers but to all Canadian citizens. The extraction of bitumen generates Crown Royalties, as well as provincial and municipal taxes that create significant economic growth. According to the Canadian Energy Research Institute
(CERI), Alberta can expect $350 billion in royalties and $122 billion in provincial and municipal tax revenue from the oil sands over the next 25 years. [69]
79 Following the Mines and Minerals Act, the Crown holds the right to collect royalties on all minerals extracted from Crown land. R.S.A. 2000, c. M-17 (§§33-43).
This collection power is further expanded in the Oil Sands Royalty Regulation. Oil Sands
Royalty Regulation, A. Reg 223/08 (Can.). Royalties vary based on a number of factors, and are determined differently for each mineral. Id. at §29. When determining royalty rates for bitumen, base royalties start at 1% and increase for every dollar the world oil price, as reflected by West Texas Intermediate, is priced above $55 per barrel, to a maximum of 9% when barrels are $120 or higher. Id. Developers pay royalties in two payments- a pre-payout of 1-9% and a post-payout of 25-40%. Id. This allows developers to earn enough revenue to recover all allowed costs for the project plus a return allowance. Id. In addition to Crown Royalties, oil sands developers will pay approximately $122 billion over the next 25 years in provincial and municipal taxes. [69].
Through royalties and taxes, every Canadian citizen benefits positively from the
Athabasca Region Oil Sands industry.
Federal Environmental Assessment Act: Canada’s Environmental Assessment
Act provides federal jurisdiction to assess projects that will have potentially adverse effects on the environment. Environmental Assessment Act, S.C. 2012, c. 19. This includes the impact that potential developments will have on fish and fish habitats, as well as migratory bird populations. Environmental Assessment Act, Id. at §5(1)(a).
Additionally, any issue that occurs on federal land, crosses provincial or international boundaries, or affects aboriginal populations fall under the jurisdiction of the statute. Id. at §5(1)(b). Finally, a change to the environment that is linked (directly or indirectly) to a
80 federal agency’s decision on a proposed project is subject to the jurisdiction of the
Canadian government. Id. at §5(2)(a).
One key aspect of the statute is the Canadian government’s ability to conduct
Environmental Assessments. Canadian Environmental Assessments should not be confused with American Environmental Assessments. While the United States uses
Assessments as the first step in a larger process, Canada considers their entire decision- making process the “Environmental Assessment.” Assessments are conducted by one of three agencies, dependent on the nature of the project. The Nuclear Safety Commission conducts assessments on nuclear projects, the National Energy board conducts assessments on pipelines and transmission lines, and the Environmental Assessment
Agency conducts assessment on any other proposed project. Id. at §15.
Typically, Committees have 365 days to conduct an assessment. Id. at §27. If a proposed project is expected to have a substantial impact on the environment, the
Minister of the Environment may refer the issue to assessment by a review panel rather than review by a government agency. Id. at §38. Review panels are composed of experts in the area related to the project in question. Id. at §42. Like the government agency, panel experts must also consider questions from the public. Id. at §45(3). This is a lengthier process than the traditional method, taking up to 24 months. Id. at §38(3). In both assessment methods, the Canadian government looks to integrate First Nations consultation to the greatest extent possible. Id. at §4(d).
When committees are considering the potential impact of a proposed project, they are required to consider 10 factors:
81 (a) The environmental effects of the designated project, including […] effects of
malfunctions or accidents that may occur in connection with the designated
project and any cumulative environmental effects that are likely to result from the
designated project in combination with other physical activities that have been or
will be carried out; (b) the significance of the[se] effects […]; (c) comments from
the public […](d) mitigation measures that are technically and economically
feasible […] (e) the requirements of the follow-up program in respect of the
designated project; (f) the purpose of the designated project; (g) alternative means
of carrying out the designated project that are technically and economically
feasible and the environmental effects of any such alternative means; (h) any
change to the designated project that may be caused by the environment; (i) the
results of any relevant study conducted by a committee established under section
73 or 74; and (j) any other matter relevant to the environmental assessment that
the responsible authority, or — if the environmental assessment is referred to a
review panel — the Minister, requires to be taken into account.
Id. at §19. From the listed factors, one general rule can be taken away: the Canadian government works hard to balance economic growth with environmental responsibility.
This characteristic is not only evident in the Environmental Assessment Act, is a common thread that is apparent in many federal and provincial environmental statutes. In this sense, Canada’s environmental policy is very similar that found in the United States.
Provincial Environmental Protection and Enhancement Act: Alberta’s
Environmental Protection and Enhancement Act was passed in 2000 to promote a view of balanced environmental protection, economic development, and government policy.
82 Environmental Protection and Enhancement Act, R.S.A. 2000, c. E-12. Similar to the previous federal act, project proponents are subject to an Environmental Assessment.
R.S.A. 2000, c. E-12 (pt. 2). The Environmental Assessment Regulation provides specific requirements and procedures for proposed projects. Environmental Assessment
Regulation, A.R. 112/93. When both a federal and provincial Environmental Assessment are required, they are processed efficiently under the Canada-Alberta Agreement for
Environmental Assessment Cooperation. Passed in 2005, this agreement highlights the need by both governments to conduct assessments, the similar objectives desired by both
Alberta and Canada, and established methods to increase efficiency for all interested parties.
Air Emissions Regulation: In May 2013, the Ministers of the Environment implemented a nationwide Air Quality Management System (AQMS). Environment
Canada, AQMS: Federal Provincial and Territorial Roles and Responsibilities (2012).
The System is driven by Canadian Ambient Air Quality Standards (CAAQS), established as objectives under the Canadian Environmental Protection Act. Canadian
Environmental Protection Act, S.C. 1999, c. 33. CAAQS seek to regulate air quality through four key mechanisms. Air zones regulate local air quality in provinces and territories. AQMS at 3. Airshed management allows broad geographic management of areas that encompass a number of air zones, thus reducing transboundary pollution flows.
Id. Base-level Industrial Emission Requirements (BLIERs) are intended to ensure that all significant industrial sources meet a set base-level performance that focuses on nitrogen oxides, sulphur dioxide, volatile organic compounds, and particulate matter emissions. Id.
Finally, regulation of mobile sources though advanced transportation technologies and
83 proper vehicle maintenance will build on existing federal, provincial, and territorial initiatives aimed at reducing emissions from the transportation sector. Id. at 4.
As an industrial polluter, oil sands developers follow the strict guidelines set by the CAAQS. It is difficult to directly compare CAAQS to NAAQS because both standards account for population size, which vary greatly. See generally 40 C.F.R. § 50
(2015). Due to original passage over 40 years ago, American air quality laws are more advanced than Canadian standards, and already cover industrial polluters. Any American
Oil Sands mine or refinery would be subject to the National Ambient Air Quality
Standards set by the Clean Air Act. Id.
In addition to federal guidelines, the Alberta Ambient Air Quality Objectives, developed under the Environmental Protection and Enhancement Act, set strict standards for industrial facilities. R.S.A. 2000, c. E-12 (§14). These requirements are used “to determine the adequacy of facility design, establish required stack heights and other release conditions, and assess compliance and evaluate facility performance.” Alberta
Environment and Parks, Ambient Air Quality Objectives and Guidelines Summary
(August 2013). As industrial facilities, oil sands mines will be required to comply with these additional guidelines.
On August 12, 2012, the Government of Alberta approved the Lower Athabasca
Regional Plan (LARP), which sets air, land, water, and biodiversity management standards. Alberta Environment and Parks, Lower Alberta Regional Plan (2012). The
Plan presents a comprehensive approach to environmental management, while setting the stage for significant economic growth in northwest Alberta. One way to maintain the increasingly industrialized Athabasca region is though heightened air quality standards.
84 The Lower Athabasca Region Air Quality Management Framework was written as an integral park of the LARP, and presents a specific strategy for managing nitrogen dioxide and sulpher dioxide levels in this region, in accordance with the Clean Air Strategic
Alliance (an Alberta policy group that acts in an advisory position under the
Environmental Protection and Enhancement Act) and the Air Quality Management
System. R.S.A. 2000, c. E-12.
Water Use Regulation: Water management and regulation is one of Canada’s most historical legal issues. Passed in 1894, the Northwest Irrigation Act ended Canada’s traditional system of riparian rights, which provided landowners close to a body of a water first right to make “reasonable use” of the water. In revoking these rights, the law declares that all water in Canada belongs to the Crown, and defines the conditions that must be met if a company wishes to apply for a water use license. The Northwest
Irrigation Act continued in effect until the western provinces passed laws of their own.
The Alberta Water Act contains a clause stating, “[t]he property in and the right to the diversion and use of all water in the Province is vested in Her Majesty in right of
Alberta.” Water Act, R.S.A. 2000 c. W-3 (§3).
Water Pollution Regulation: Similar to the United States’ Clean Water Act, the
Canada Water Act provides for the management of aquatic resources through the research, planning, and implementation of programs necessary for the conservation of
Canadian water resources. Canada Water Act, R.S.C., 1985, c. C-11. There are a number of focuses, including pollution, water quality improvement, and the protection of federal water. Federal jurisdiction includes border waters, national land water, and provincial waters where provinces have failed.
85 Because water falls into the “public land” classification, its use is also regulated provincially. According to section two of the statute, the purpose of the Alberta Water
Act is “to support and promote the conservation and management of water, including the wise allocation and use of water, while recognizing … (a) the need to manage and conserve the need for ... (b) Alberta’s economic growth and prosperity.” R.S.A. 2000, c.
W-3 (§2). The Alberta Water Act focuses on three types of uses: household uses, licensable uses, and traditional agricultural uses. Id. Therefore, every developer who wishes to mine in the Athabasca region must first apply for and obtain a license to use water commercially under the this statute, following the process under Part 4, Division 2.
Id. at §§46-61. One requirement under the licensure requirement is a provincial
Environmental Assessment. Id. at §16. In cases where both a federal and provincial
Environmental Assessment are required, joint assessments are conducted under the
Canada-Alberta Agreement on Environmental Assessment Cooperation.
One key aspect of water regulation is the protection of wetlands. The Alberta
Wetland Policy is a relatively new program, being put in place to “conserve, restore, protect and manage Alberta’s wetlands.” Alberta Wetland Policy, Sept. 2013 (Can.) (p.
2). In order to set specific criteria in achieving this goal, the Alberta Wetland Mitigation
Directive provides a three-stage approach to reduce development impacts. Alberta
Environment and Parks, Alberta Wetland Mitigation Directive (2015). When planning new projects, the first objective is to avoid adverse effects on wetlands altogether. Id.
However, if this is impossible, project proponents are expected to minimize negative effects. Id. Finally, if avoidance and minimization of negative effects are ineffective or not feasible, proponents will be required to replace the wetland area. Id. This is very
86 similar to the United States’ compensatory mitigation wetland policy, also known as “no net loss.”
Fluid Tailings: One of the largest challenges in the oil sands extraction process is fluid tailings management. Fluid tailings are made up of water, silts, residual bitumen, soluble organic compounds, and solvents that are added to oil sands during the separation process. Following separation, tailings are kept in ponds while they settle. The government of Alberta sets strict regulations for management application and plans, tailings investing, and overall management performance of ponds. However, because tailings ponds are open and can contain harmful substances, all Alberta regulations must fall within Canada’s Environmental Assessment Act, Fisheries Act, and Migratory Birds
Convention Act. See generally Environmental Assessment Act, S.C. 2012, c. 19, s. 52;
Fisheries Act, R.S.C., 1985, c. F-14; Migratory Birds Convention Act, S.C. 1994, c. 22.
Prior to 2013, parties who wished to mine oil sands complied with Directive 074 of Alberta’s Oil Sands Conservation Rules. Alberta Energy Regulator, Tailings
Performance Criteria and Requirements for Oil Sands Mining Schemes (2009)
(Suspended); Oil Sands Conservation Rules, A.R. 76/88. Directive 074’s primary objective was to reduce the inventory of fine fluid tailings across various leases, but provided no guidance on obtaining such a reduction. This lead to significant variation in the tailings measurement methods implemented by mine operators. To create greater consistency in reporting, the government of Alberta issued the Tailings Management
Framework for the Mineable Athabasca Oil Sands (TMF) as a component of the LARP.
Alberta Environment and Parks, Tailings Management Framework for the Mineable
Athabasca Oil Sands (2015); Lower Alberta Regional Plan (2012). This regulation aims
87 to “provide direction to manage fluid tailings volumes during and after mine operation in order to manage and decrease liability and environmental risk resulting from the accumulation of fluid tailings.” Id. at §1. The Alberta Energy Regulator has the duty of creating individualized fluid tailings thresholds for each developer. Id. at §5.2.3.
Thresholds will be determined based on “rate of growth, approved volume, and a five- year rolling average to account for year-over-year variability.” Id. Custom thresholds are designed to ensure that new tailings are not accumulated at a volume that cannot meet the reclamation goal. Id. The ultimate purpose of the TMF is to ensure that tailings accumulation is minimized and all tailings are accurately treated so that projects are
“ready-to-reclaim within 10 years of the end of mine life of that project […] while balancing environmental, social, and economic needs.” Id. at §3.4.
Species Protection: Passed in 2002, Canada’s Species at Risk Act works to protect endangered plant and animal species. Species at Risk Act, S.C. 2002, c. 29. Under the Species at Risk Act, a single committee makes decisions regarding whether species should be added to the endangered list. Id. at §14. Prohibitions apply to aquatic species, birds, and animals on federal lands. Id. at §58. Federally listed species on private and provincial lands are subject to provincial law; however, the federal government reserves the right to intervene if it feels that a province is not doing enough. While there are some similarities to the United States’ Endangered Species’ Act, The procedure that Canada follows to add a plant or animal to the list considers socioeconomic conditions throughout the entire selection process, while the American process only takes scientific information into consideration.
88 In order to ensure both environmental preservation and economic growth, Canada considers the protection of its migratory bird populations a top priority. In 1994, Canada enacted the Migratory Birds Convention Act, providing protection through the Migratory
Birds Regulations and the Migratory Birds Sanctuary Regulations. S.C. 1994, c. 22;
Migratory Birds Regulations, C.R.C., c. 1035; Migratory Birds Sanctuary Regulations,
C.R.C. c. 1036. The Migratory Birds Convention Act and Regulations must be taken into consideration throughout the oil sands extraction and transportation process. See S.C.
1994, c. 22. Because developers could potentially face criminal penalties for any offense, they are particularly cautious when designing fluid tailings ponds and pipelines.
Maintaining Canada’s fish population is vital to insuring the growth of its economy. Therefore, protection through the Fisheries Act is necessary. R.S.C., 1985, c.
F-14. This act protects not only fish, but also the habitats where they thrive. Id. at §2(1).
Under the statute, it is unlawful to “carry on any work, undertaking or activity that results in serious harm to fish that are part of a commercial, recreational, or aboriginal fishery, or to fish that support such a fishery.” Id. at §35(1).
The Alberta Biodiversity Monitoring Institute: In addition to federal statutes that work to protect plant and animal species, the Alberta Biodiversity Monitoring
Institute is focused on protecting the integrity of Alberta’s wildlife. The institute is funded in equal parts by the provincial government, forestry industry, and energy industry. As states begin to consider oil sands development, it is important to consider regional biodiversity. Alberta has taken extensive measures to protect the wild species of their province. The Alberta Biodiversity Monitoring Institute can serve as a model for
89 states that wish to conserve their state’s wildlife, while holding private parties accountable.
Bitumen Transport Regulation: All aspects of oil transportation, including the transportation of bitumen, are highly regulated, both domestically and internationally.
Regulations are put in place to protect the environment as well as mitigate public health concerns. Unlike most aspects of the bitumen development process, transportation is regulated federally and internationally, rather than under Alberta law.
Train Transport: In Canada, Rail transportation is regulated generally under the
Railway Safety Act. However, the transportation of bitumen is more strictly regulated under the Transportation of Dangerous Goods Act. Transportation of Dangerous Goods
Act, S.C. 1992, c. 34. For a substance or product to fall into the “dangerous goods” category, it must satisfy at least one of nine requirements:
(1) Explosives, including explosives within the meaning of the Explosives Act; (2)
Gases: compressed, deeply refrigerated, liquefied or dissolved under pressure; (3)
Flammable and combustible liquids; (4) Flammable solids, substances liable to
spontaneous combustion, [or] substances that on contact with water emit
flammable gases; (5) Poisonous (toxic) and infectious substances; (6) Oxidizing
substances, organic peroxides; (7) Nuclear substances, within the meaning of the
Nuclear Safety and Control Act, that are radioactive; (8) Corrosives; (9)
Miscellaneous products, substances or organisms considered by the Governor in
Council to be dangerous to life, health, property or the environment when
handled, offered for transport or transported and prescribed to be included in this
class.
90 Id. at §27. The statute sets strict emergency plan requirements, containment standards, and inspection designations. Id. at §§7,8,10.
Marine Transport: The marine transportation of bitumen allows the Canadian
Oil Sands industry to grow exponentially. The Canada Shipping Act includes environmental response regulations including specific provisions for all oil handling facilities. Canada Shippping Act, S.C. 2001, c. 26. A key aspect of these regulations is the requirement that all facilities have an oil pollution prevention plan, an oil pollution emergency plan, and the means necessary to implement these plans. Id. at §168. The pollution provisions of the Shipping Act generally apply to all Canadian and foreign vessels in Canadian waters. Id. at §166. However, there is an exception for ships engaged in oil and gas exploration in the Northwest Territories, Nunavut and Sable Island, submarine areas, and in the Arctic. Id. These circumstances are under the jurisdiction of the Arctic Waters Pollution Prevention Act. Arctic Waters Pollution Prevention Act,
R.S.C., 1985, c. A-12.
The Arctic Waters Pollution Prevention Act is a zero-discharge statute; meaning that no pollution is allowed and no license to pollute will be granted:
[N]o person or ship shall deposit or permit the deposit of waste of any type in the
arctic waters or in any place on the mainland or islands of the Canadian arctic
under any conditions where the waste or any other waste that results from the
deposit of the waste may enter the arctic waters.
Id. at §4. The Arctic Waters Pollution Prevention Regulations apply to waste deposits in
Arctic waters and the liability associated with these deposits. Arctic Waters Pollution
91 Prevention Regulation, C.R.C. c. 354. Because the United States is active in global trade and arctic research, it already likely complies with these statutes.
The marine transportation of oil is not only regulated federally but on an international level as well. Under the United Nations, the International Maritime
Organization sets guidelines for tanker safety and accidental pollution prevention. The
International Convention for the Prevention of Pollution from Ships (MARPOL) Annex I
Regulation 13G bans the carriage of heavy-grade oil (including bitumen) in single-hull tankers of 5,000 tons deadweight and above.
Pipeline Transport: Pipelines are considered a more economically efficient oil transportation method than rail or tanker trucks. For example, the Canadian Energy
Pipeline Association (CEPA) pipelines transport nearly three million barrels of oil every day. Transporting the same amount of oil would require 4,200 rail cars or 15,000 tanker trucks. Because pipelines transport such a significant amount of oil, their regulation is imperative. All aspects of a pipeline’s lifespan, design, construction, operation, discontinuation, and abandonment, are highly regulated. Canada’s federal jurisdiction to regulate all pipeline transportation falls under the National Energy Board Onshore
Pipeline Regulations. National Energy Board Onshore Pipeline Regulations, SOR/99-294
(Can.); See also National Energy Board Act, R.S.C., 1985, c. N-7.
Not only are pipelines one of the most heavily regulated methods of bitumen transportation, pipelines are perhaps the most politically sensitive. In September 2008,
TransCanada, a little-known Calgary-based energy company, applied for a permit to build a pipeline that would allow the transportation of diluted bitumen into the United
States. The Keystone XL pipeline has since become one of the most central controversies
92 in American environmental policy. If approved, the pipeline will span 1,179 miles and will transport 800,000 barrels of oil daily from Alberta to Houston, Texas.
The Oil Spill Liability Trust Fund (OSLTF) requires that oil companies pay an 8- cent-per-barrel fee that serves as a clean up fee in the event of an oil spill in the United
States. However, oil sands developers are not required to pay into the OSLTF. Jonathan
Ramseur, Cong. Research Serv., R43128, Oil Sands and the Oil Spill Liability Trust
Fund: The Definition of “Oil” and Related Issues for Congress 7-5700 (2015). This has become highly controversial, with concerned parties arguing that companies that transport oil sands into the United States do not assume full responsibility through contribution to the fund. In U.S. et al v. Exxon, an Exxon Mobile pipeline carrying bitumen through Arkansas ruptured, spilling 80,000 gallons. Exxon did not previously contribute to the Oil Spill Liability Trust Fund though the Pegasus Pipeline and paid over five million dollars in settlements. [70]
Canadian Oil Sands Regulatory Conclusions: As the United States considers oil sands extraction and production, it is imperative to study, consider, and plan for the potential environmental consequences, primarily in fluid tailings and pipeline regulation.
Many of Canada’s environmental laws mirror American statutes. Additionally, the United
States and Canada are similar in the way they attempt to regulate a balance between environmental consciousness and economic growth.
Some of the most valuable steps that Alberta has taken to mitigate the negative effects of oil sands development have been to develop programs that apply specifically to the Athabasca region. For example, the Lower Athabasca Regional Plan was designed to ensure that Alberta’s water quality, air quality, and biodiversity remained stable, even
93 with a growing oil sands industry. Another example is the Alberta Biodiversity
Monitoring Institute, which is focused specifically on species in the oil sands region. As states begin to consider the possibility of oil sands mining, Canada can serve as an example in many respects.
Regulation of Utah Oil Sands Development
Oil sands development in Utah is currently all via surface mining techniques and is better characterized as mining rather than traditional oil extraction; therefore, oil sands development is regulated as a mining activity subject to regulatory requirements typical for mining including, but not limited to, environmental, safety, and reclamation requirements. [10]
The primary state statutes regulating mineral development in Utah are:
• The Utah Oil and Gas Act
• The Utah Mined Lands Reclamation Act
Both of these statutes are administered by the Division of Oil, Gas and Mining of the
Utah State Department of Natural Resources (DOGM). The Oil and Gas Act promotes the efficient and coordinated development of oil and gas while preventing the waste of oil and gas resources. The act created the Utah Board of Oil, Gas, and Mining with authority to regulate oil and gas. The board exercises that authority to ensure that wells are properly drilled, cased, completed, operated, and plugged; however, this jurisdiction does not extend to the development of oil sands. There is an express exclusion for any gaseous or liquid substances produced from “tar sands;” nonetheless, DOGM approval is required under the Utah Mined Lands Reclamation Act before operations can begin. Certain development plans and bonding are required. [12]
94 Access to landlocked private oil sand deposits could be problematic. The State of
Utah possesses broad eminent domain powers, which may be exercised for various
“public” purposes. While access to mineral deposits may be a public purpose, there is some uncertainty as to whether oil sands are included. The question of whether access to oil sands is a permissible public purpose for the exercise of eminent domain remains to be tested. [12]
With respect to conventional oil and gas development, unitization is the practice of combining royalty and working interests over a producing formation to facilitate production over the entire reservoir in the most efficient manner. However, unitization is typically not required for solid mineral development because solid minerals are non- migratory and extraction can be tailored to those resources legally available to the operator. Whether a particular oil sands development warrants unitization should depend on certain site-specific factors. Conflicts can sometimes be avoided by using un-mined buffers. [12]
A surface ownership map shows that the vast majority of land is owned by the federal government, followed by state and tribal ownership, with very little private ownership. Only about 10.2% of Utah’s oil sands are privately owned. [12]
Rule R647-1-106. Utah Minerals Regulatory Program Definitions: [71]
• "Deposit" or "mineral deposit" means an accumulation of mineral matter in the
form of consolidated rock, unconsolidated materials, solutions, or otherwise
occurring on the surface, beneath the surface, or in the waters of the land from
which any useful product may be produced, extracted or obtained, or which is
extracted by underground mining methods for underground storage. "Deposit" or
95 "mineral deposit" excludes sand, gravel, rock aggregate, water, geothermal steam,
and oil and gas, but includes oil shale and bituminous sands extracted by mining
operations.
• "Mining operations" means those activities conducted on the surface of the land
for the exploration for, development of, or extraction of a mineral deposit,
including, but not limited to, surface mining and the surface effects of
underground and in situ mining; on-site transportation, concentrating, milling,
evaporation, and other primary processing. "Mining operation" does not include:
the extraction of sand, gravel, and rock aggregate; the extraction of oil and gas;
the extraction of geothermal steam; smelting or refining operations; off-site
operations and transportation; reconnaissance activities; or activities which will
not cause significant surface resource disturbance and do not involve the use of
mechanized earth-moving equipment, such as bulldozers or backhoes.
• "Notice of Intention" means a notice of intention to commence mining operations,
that provide the complete information required for authorization to conduct
mining operations, and includes any amendments or revisions thereto.
• "Permit" means a notice to conduct mining operations issued by the Division. A
notice to conduct mining operations is issued by the Division when either a notice
of intention for a small mining operation or exploration is determined to be
complete and includes a surety approved by the Division, or a notice of intention
for a large mining operation or exploration with a plan of operations and surety
approved by the Division.
96 The Utah oil sands exploitation permitting process is briefly described in a news release issued by American Sands Energy Corporation (AMSE) on October 13, 2014.
AMSE submitted a Notice of Intention to Commence Large Mining Operations ("NOI") on March 5, 2014 to the Utah Division of Oil, Gas & Mining ("DOGM") and has been working with the state regulators through the permitting process. [18]
Regulation of Alabama Oil Sands Development
A Brief Comparison of Utah and Alabama Oil Sands Regulation: The Utah
Oil and Gas Act created the Utah Board of Oil, Gas, and Mining with authority to regulate oil and gas; however, Utah’s oil sands are exempt from that act as there is an express exclusion for any gaseous or liquid substances produced from “tar sands”. The development of Utah’s oil sands is regulated under the Utah Mined Lands Reclamation
Act. The Division of Oil, Gas and Mining of the Utah State Department of Natural
Resources (DOGM) administers both of these statutes. DOGM approval is required for surface mining of oil sands. [12]. In contrast to the State of Utah, oil sands development in Alabama (both surface mining and in situ extraction) will be regulated under state oil and gas laws rather than surface mining laws. In the 2013 regular session, the Alabama
Legislature passed HB503 modifying sections 9-17-6 and 9-17-24 of the Code of
Alabama of 1975 to grant authority to the State Oil and Gas Board to regulate surface mining operations to recover oil from oil sand deposits in Alabama. [72] The Alabama
Oil and Gas Board (OGB) has not promulgated oil sand surface mining regulations to date.
Statutory Authority for State Oil and Gas Board Regulation of Oil Sands
Development: Any in situ recovery of oil from oil sands would be regulated under
97 existing law by the OGB. Under Alabama law the following statutory definition of oil includes oil from oil sands: “OIL. Crude petroleum oil and other hydrocarbons, regardless of gravity, which are produced at the well in liquid form by ordinary production methods and which are not the result of a condensation of gas after it leaves the pool.” Ala. Code § 9-17-1(11). The Alabama Legislature has granted the OGB with authority to create regulations to prevent the pollution of fresh water supplies by oil or other contaminants resulting from oil and gas operations including surface mining operations to recover oil from oil sands. Ala. Code § 9-17-6(c). The OGB also possess authority to require performance bonds from oil and gas operators. Ala. Code § 9-17-
6(c)(5). The OGB must be notified of proposed oil wells under Ala. Code § 9-17-24(a) and proposed surface mining operations to recover oil from oil sands under Ala. Code §
9-17-24(d). The OGB has promulgated regulations based upon these statutory authorities that cover any in situ oil sand wells. OGB regulations require a permit to drill an in situ oil sands well. Ala. ADMIN. Code r. 400-1-2-.01.
Alabama Oil and Gas Board Regulations Covering In Situ Oil Sands
Development: OGB regulations specifically address the protection of freshwater resources with oil operations: “An operator shall conduct all oil and gas operations in a manner so as to prevent the pollution of all freshwater resources. All fresh waters and waters of present or probable future value for domestic, municipal, commercial, stock, or agricultural purposes shall be confined to their respective strata and shall be adequately protected. Special precautions shall be taken to guard against any loss of artesian water from the strata in which it occurs, and the contamination of fresh water by objectionable
98 water, oil, condensate, gas, or other deleterious substance to such fresh water.” Ala.
ADMIN. Code r. 400-1-4—02.
If in situ oil sands recovery in Alabama were to require hydraulic fracturing or chemical treatment, OGB approval is required: “Wells shall not be chemically treated or fractured until the approval of the Supervisor is obtained. Each well shall be treated or fractured in such manner as will not cause damage to the formation, result in water encroachment into the oil- or gas-bearing formation, or endanger freshwater-bearing strata. Necessary precautions shall be taken to prevent damage to the casing. Routine chemical treatments for corrosion control shall be excluded from this notice requirement.
If chemical treating or fracturing results in irreparable damage to the well, the oil or gas- bearing formation or freshwater-bearing strata, then the well shall be properly plugged and abandoned.” Ala. ADMIN. Code r. 400-1-4-.07. OGB hydraulic fracturing regulations require “an inventory prepared by the operator identifying all fresh water supply wells within a one quarter- (1/4-) mile radius of the well to be fractured. Records of fresh water supply wells shall be used by the operator in delineating the construction and completion depths of such supply wells. The records of the Geological Survey of
Alabama (GSA) shall be the primary source of information used in this evaluation process. Additionally, the operator shall conduct a field reconnaissance within a one quarter- (1/4-) mile radius of the subject well to determine the location of any additional fresh water supply wells that may not be identified in the previously described documents. If possible, construction information for such additional fresh water supply wells must be obtained. Consideration shall be given to the records of all fresh water supply wells available and the operator shall report the results of his findings to the
99 Supervisor. Fracturing operations shall not be conducted if it is determined that any fresh water resources or any fresh water supply well located within a one quarter- (1/4-) mile radius of the subject well could be adversely impacted as a result of the fracturing operation.” Ala. ADMIN. Code r. 400-1-9-.04(3)(d). One of the factors that the OGB must consider in reviewing hydraulic fracturing proposals is “whether the proposed hydraulic fracturing operation ensures that the formation to be fractured lies beneath an impervious stratum.” Ala. ADMIN. Code r. 400-1-9-.04(3)(e)(1). If in situ oil sands recovery in Alabama were to require hydraulic fracturing, relatively shallow oil sand deposits above impervious stratums could be problematic under these regulatory requirements. The OGB regulations also require that information on hydraulic fracturing fluids be posted on the Frac Focus website within thirty days after fracturing a well. Ala.
ADMIN. Code r. 1-9-.04(7(b).
OGB regulations require the proper management of oil and gas site wastes as follows: “All wastes and other material including petroleum contaminated soil shall be removed from the location and disposed of in a lawfully approved facility, or recycled or disposed of in accordance with appropriate permit(s) or regulation(s); provided, however, that petroleum contaminated soil may be approved by the Supervisor for on-site remediation. All wastes being removed from location shall comply with the requirements of Rule 400-1-9-.03, Transportation of Wastes Associated with Oil and Gas Operations.”
Ala. ADMIN. Code r. 400-1-6-.10(4).
The transportation of any oil from a production facility requires OGB approval as follows: “No transporter shall transport oil, gas, or condensate from any production facility or plant products from any plant, until the operator thereof shall furnish to the
100 transporter an approved Operator's Certificate of Compliance and Authorization to
Transport Oil, Gas, or Condensate from Well, Form OGB-12, and, if required, an approved Operator's Certificate of Compliance and Authorization to Transport Products from Plant, Form OGB-13. If oil, gas, or condensate is being transported from multiple wells, and there is a common transporter and a common purchaser for each of the wells, then an operator may submit a single Operator's Certificate of Compliance and
Authorization to Transport Oil, Gas, or Condensate from Well, Form OGB-12, listing the permit number, well name and number, and field name for each well. Such certificates shall certify that the conservation laws of the State have been complied with, and that such transporter is authorized by the operator to transport oil, gas, or condensate from such facility or plant products from any plant. Unless otherwise authorized by the
Supervisor, Form OGB-12 or OGB-13 must be approved prior to transporting first production.” Ala. ADMIN. Code r. 400-1-8—01.
The OGB must be notified immediately if a spill or leak occurs at an oil operation and the operator must take immediate actions to repair and clean up leaks. Ala. ADMIN.
Code r. 400-1-9-.01.
The OGB also requires performance bonds from oil and gas operators: “Before any person(s) shall commence drilling, completing, converting, operating, or producing any oil, gas, or Class II injection well, including production facilities, processing facilities, injection facilities, underground storage facilities in reservoirs, plants, pipelines, and other equipment associated with such well, said person(s) shall file with the Board a single well bond on Form OGB-3.” Ala. ADMIN. Code r. 400-1-2-.03.
101 Alabama Oil and Gas Board Regulations Covering Surface Mining Oil Sands
Development: While the Alabama Legislature modified sections 9-17-6 and 9-17-24 of the Code of Alabama of 1975 to grant authority to the State Oil and Gas Board to regulate surface mining operations to recover oil from oil sand deposits in Alabama, regulations have not been promulgated to date.
State Environmental Policy Acts
Oil sands development in the United States is still immature and the only significant attempts at development have been in Utah and limited to surface mining exploitation methods using proprietary solvents. As discussed in the previous section, any in-situ oil sands recovery within Alabama would be regulated under existing state oil and gas law; however, any surface mining recovery would be regulated under state regulations that have not yet been created. Various State Environmental Policy Acts
(SEPAs) around the country might provide potential policy strategies for consideration as any new oil sands regulations are developed. An overview of SEPAs and discussion of how SEPAs could be used to address oil sands development sustainability risks follows.
Given that most SEPAs are modeled after the National Environmental Policy Act
(NEPA) a brief overview of NEPA is warranted. The National Environmental Policy Act of 1969 is a federal statute that can be found at 42 U.S.C. § 4321 et seq. Under NEPA federal government agencies are required to prepare an Environmental Impact Statement
(EIS) for major federal actions significantly affecting the quality of the human environment. An EIS must include:
• The environmental impact of the proposed action
102 • Any adverse environmental effects which cannot be avoided should the proposal
be implemented
• Alternatives to the proposed action
• The relationship between local short-term uses of man's environment and the
maintenance and enhancement of long-term productivity
• Any irreversible and irretrievable commitments of resources which would be
involved in the proposed action should it be implemented.
In preparing the EIS, the responsible federal official must consult with and obtain the comments of any federal agency which has special expertise or jurisdiction by law with respect to any environmental impact involved. NEPA only forces federal agencies to make environmentally informed decisions; however, NEPA does not prohibit federal agencies from taking actions that harm the environment and NEPA does not elevate environmental factors over other factors when federal agencies are making decisions.
A few states have enacted State Environmental Policy Acts (SEPAs) that function in a similar manner to NEPA but on a state level. Each SEPA can be different from one state to another; however, they typically require that state agencies and local governments consider potential environmental impacts and alternatives before making permitting decisions. The State of Washington’s SEPA empowers local governments to deny projects or conditionally approve projects if significant environmental impacts are identified that cannot be mitigated through an alternative action. Wash. Rev. Code §
43.21C (1989). “The State Environmental Policy Act of 1971 is the State of
Washington's most pervasive environmental law. In fact, a strong case can be made that
SEPA is Washington's most pervasive law of any kind because SEPA authority overlays
103 and supplements all other state statutory authority.” [73] The Washington SEPA requires all policies, regulations, and laws of the State to be interpreted in accordance with the policies of SEPA and potentially affects everything done by local governments and state agencies. The Washington SEPA requires government agencies to determine and analyze the probable significant impacts of proposed actions. The term “agency” includes almost every unit of state or local government that makes decisions or takes actions that might significantly affect the environment. When the probable impacts of a proposed major action are significant, SEPA requires the agency to prepare an Environmental Impact
Statement (EIS) that provides the agency with information that can be the basis for an agency to deny a proposed action. An action significantly affects the environment whenever a greater than moderate effect on the quality of the environment is a reasonably probable result of the action. [73]
104
SUSTAINABILITY RISK MANAGEMENT MODEL FOR THE POTENTIAL
DEVELOPMENT OF ALABAMA OIL SANDS
Pursuant to Step #1 of the risk management process set forth in a previous dissertation chapter, the risk management context and risk evaluation criteria were developed according to IEC/ISO 31010:2009.
Pursuant to Step #2 of the risk management process set forth in a previous dissertation chapter, potential oil sand development sustainability risks presented by surface mining and in situ extraction methods are identified in the following Risk
Breakdown Structure according to ISO 21500:2012 and organized by significant sustainability aspects according to ISO 14001:2015. This Risk Breakdown Structure is based upon the sustainability risks presented in a previous dissertation section for oil sands development in Canada, Utah, and Alabama; as such, it can serve as the basis for a sustainability risk management model for oil sands development in Canada, Utah, and other jurisdictions. In this model, it is being applied to potential Alabama oil sands development. Here are the previously identified significant sustainability aspects which serve as the Risk Breakdown Structure categories:
1. Surface Water Quality
2. Surface Water Quantity
3. Ground Water Quality
105 4. Groundwater Quantity
5. Air Quality
6. Ecosystem Health and Biodiversity Protection
7. Land, Stream, and Wetland Losses, Mitigation, and Reclamation
8. Waste Management
9. Social Impacts
Here is the resulting Risk Breakdown Structure:
1. Oil Sands Development Sustainability Risk Breakdown Structure
1.1. Sustainability Aspect: Surface Water Quality
1.1.1. Surface Mining Risks
1.1.1.1. Adverse Surface Water Quality Impacts from Erosional Discharges
1.1.1.2. Adverse Surface Water Quality Impacts from Tailing Pond
Discharges
1.1.1.3. Adverse Surface Water Quality Impacts from Surface Mining
Process Effluent Discharges
1.1.1.4. Adverse Surface Water Quality Impacts from Spills and Releases
Associated with Bitumen Recovery Operations and Bitumen Transport
1.1.2. In Situ Risks
1.1.2.1. Adverse Surface Water Quality Impacts from Hydraulic Fracturing
Processes, Flow Back, and Produced Water Discharges
1.1.2.2. Adverse Surface Water Quality Impacts from In Situ Process
Effluent Discharges
106 1.1.2.3. Adverse Surface Water Quality Impacts from Erosional Discharges
Associated with Above Ground Land Disturbances
1.1.2.4. Adverse Surface Water Quality Impacts from Spills and Releases
Associated with Bitumen Recovery Operations and Bitumen Transport
1.2. Sustainability Aspect: Surface Water Quantity
1.2.1. Surface Mining Risks
1.2.1.1. Surface Water Withdrawals Exceed Surface Water Ecological
Availability
1.2.1.2. Surface Water Withdrawals Violate Water Rights
1.2.2. In Situ Risks
1.2.2.1. Surface Water Withdrawals Exceed Surface Water Ecological
Availability
1.2.2.2. Surface Water Withdrawals Violate Water Rights
1.3. Sustainability Aspect: Ground Water Quality
1.3.1. Surface Mining Risks
1.3.1.1. Adverse Impacts to Groundwater Quality from Surface Mining
Process Effluent Discharges
1.3.1.2. Adverse Impacts to Groundwater Quality from Surface Mining
Excavations
1.3.1.3. Adverse Impacts to Ground Water Quality from Spills and
Releases Associated with Bitumen Recovery Operations and Bitumen
Transport
1.3.2. In Situ Risks
107 1.3.2.1. Adverse Impacts to Groundwater Quality from In Situ Process
Effluent Discharges
1.3.2.2. Adverse Impacts to Groundwater Quality from In Situ Extraction
Processes including the Injection of Steam, Hot Water, Heat, or
Solvents
1.3.2.3. Adverse Ground Water Quality Impacts from Hydraulic Fracturing
Processes, Flow Back, and Produced Water Discharges
1.3.2.4. Adverse Impacts to Ground Water Quality from Spills and
Releases Associated with Bitumen Recovery Operations and Bitumen
Transport
1.4. Sustainability Aspect: Ground Water Quantity
1.4.1. Surface Mining Risks
1.4.1.1. Water Withdrawals Violate Water Rights
1.4.1.2. Water Withdrawals Deplete Ground Water Resources
1.4.2. In Situ Risks
1.4.2.1. Water Withdrawals Violate Water Rights
1.4.2.2. Water Withdrawals Deplete Ground Water Resources
1.5. Sustainability Aspect: Air Quality
1.5.1. Surface Mining Risks
1.5.1.1. Adverse Air Quality Impacts from Air Emissions Associated with
Equipment and Operational Processes
108 1.5.1.2. Adverse Full Fuel Cycle (i.e. life cycle) Carbon Footprints
Associated with Bitumen Extraction, Processing, Transportation, and
End Use
1.5.1.3. Exposure of Surface Mining Excavations to Air Results in Adverse
Air Quality Impacts
1.5.2. In Situ Risks
1.5.2.1. Adverse Air Quality Impacts from Air Emissions Associated with
Equipment and Operational Processes
1.5.2.2. Adverse Full Fuel Cycle (i.e. life cycle) Carbon Footprints
Associated with Bitumen Extraction, Processing, Transportation, and
End Use
1.6. Sustainability Aspect: Ecosystem Health and Biodiversity Protection
1.6.1. Surface Mining Risks
1.6.1.1. Adverse Impacts to Threatened, Endangered, or Protected Species
or their Habitats in Violation of Federal, State, or International Law
1.6.2. In Situ Risks
1.6.2.1. Adverse Impacts to Threatened, Endangered, or Protected Species
or their Habitats in Violation of Federal, State, or International Law
1.7. Sustainability Aspect: Land, Stream, and Wetland Losses, Mitigation, and
Reclamation
1.7.1. Surface Mining Risks
109 1.7.1.1. Loss of Wetlands or Streams from the Siting of Bitumen
Extraction Facilities and Associated Operational, Processing, and
Transportation Infrastructure
1.7.1.2. Surface Mining and Tailing Pond Impacts Warranting Reclamation
1.7.2. In Situ Risks
1.7.2.1. Loss of Wetlands or Streams from the Siting of Bitumen
Extraction Facilities and Associated Operational, Processing, and
Transportation Infrastructure
1.8. Sustainability Aspect: Waste Management
1.8.1. Surface Mining Risks
1.8.1.1. Illegal Waste Disposal Practices
1.8.1.2. Spill or Release of Reportable Quantities of Oil or Hazardous
Substances
1.8.1.3. Relatively High Waste Generation Rates
1.8.2. In Situ Risks
1.8.2.1. Illegal Waste Disposal Practices
1.8.2.2. Spill or Release of Reportable Quantities of Oil or Hazardous
Substances
1.8.2.3. Relatively High Waste Generation Rates
1.9. Sustainability Aspect: Social Impacts
1.9.1. Surface Mining Risks
1.9.1.1. Adverse Impacts to External Stakeholders
1.9.1.2. Adverse Impacts to Environmental Justice Communities
110 1.9.1.3. Adverse Cultural Resource Impacts
1.9.2. In Situ Risks
1.9.2.1. Adverse Impacts to External Stakeholders
1.9.2.2. Adverse Impacts to Environmental Justice Communities
1.9.2.3. Adverse Cultural Resource Impacts
Pursuant to Step # 3 of the risk management process set forth in a previous dissertation chapter, each of the risks identified in Step #2 are analyzed according to ISO
31000:2009(E) in a semi-quantitative approach using risk indices and a modified FMEA technique where the probability of a risk event, the impact of the risk event, and the ability to detect an occurrence of the risk event are each scored on a five-point scale and each risk is scored using the following equation:
Impact x Probability x Detection = Risk Value
The Risk indices were established in a previous dissertation chapter. The untreated risk analysis scores for the predominant categories of sustainability risk identified in the Risk
Breakdown Structure (RBS) follows below. While each individual risk could be analyzed individually, a categorical analysis is used here because the close similarities of many of the RBS elements did not justify individual analysis. Please note that most of the risk category analyses scored the maximum value of 125 because the risks were scored before any risk treatments are applied to reduce risk indices scores.
111 Table 5
Pre-Treatment Risk Analysis
Sustainability Risk Impact Probability Detectability Untreated Category and Score Score Score Risk Associated RBS Score Element Identification numbers 1. Adverse Surface Water Quality 5 5 5 125 Impacts from Erosional Discharges 1.1.1.1, 1.1.2.3 2. Adverse Surface Water Quality 5 5 5 125 Impacts from Tailing Pond Discharges 1.1.1.2 3. Adverse Surface Water Quality 5 5 5 125 Impacts from Bitumen Extraction Process Effluent Discharges 1.1.1.3, 1.1.2.2 4. Adverse Surface Water Quality 5 3 5 75 Impacts from Spills (assumed 50% & Releases 1.1.1.4, chance of spill 1.1.2.4 with no controls in place) 5. Adverse Surface Water Quality 5 5 5 125 Impacts from Hydraulic Fracturing 1.1.2.1 6. Surface Water Withdrawals 5 5 5 125 Exceed Surface Water Ecological Availability 1.2.1.1, 1.2.2.1
112 Sustainability Risk Impact Probability Detectability Untreated Category and Score Score Score Risk Associated RBS Score Element Identification numbers 7. Surface Water Withdrawals 5 5 5 125 Violate Water Rights 1.2.1.2, 1.2.2.2 8. Adverse Groundwater 5 5 5 125 Quality Impacts from Extraction Process Effluent Discharges 1.3.1.1, 1.3.2.1 9. Adverse Groundwater 5 3 5 75 Quality Impacts (assumed 50% from Surface chance of Mining Excavations occurrence with 1.3.1.2 no controls in place) 10. Adverse Groundwater 5 5 5 125 Quality Impacts from In Situ Extraction Processes Including the Injection of Steam, Hot Water, Heat, or Solvents 1.3.2.2 11. Adverse Groundwater 5 5 5 125 Quality Impacts from Hydraulic Fracturing 1.3.2.3 12. Adverse Groundwater 5 3 5 75 Quality Impacts (assumed 50% from Spills & chance of spill Releases 1.3.1.3, with no controls 1.3.2.4 in place)
113 Sustainability Risk Impact Probability Detectability Untreated Category and Score Score Score Risk Associated RBS Score Element Identification numbers 13. Groundwater Withdrawals that 5 5 5 125 Violate Water Rights 1.4.1.1, 1.4.2.1 14. Groundwater Withdrawals that 5 5 5 125 Deplete Groundwater Resources 1.4.1.2, 1.4.2.2 15. Adverse Air Quality Impacts 5 5 5 125 from Air Emissions Associated with Equipment and Operational Processes 1.5.1.1, 1.5.2.1 16. Carbon Footprint in Excess 5 5 5 125 of Organizational or Regulatory Requirements 1.5.1.2, 1.5.2.2 17. Adverse Air Quality Impacts 5 5 5 125 from Surface Mining Excavations 1.5.1.3 18. Adverse Impacts to 5 5 5 125 Threatened, Endangered, or Protected Species or their Habitats 1.6.1.1, 1.6.2.1
114 Sustainability Risk Impact Probability Detectability Untreated Category and Score Score Score Risk Associated RBS Score Element Identification numbers 19. Loss of Wetlands or 5 5 5 125 Streams from the Siting of Bitumen Extraction Facilities and Associated Infrastructure 1.7.1.1, 1.7.2.1 20. Adverse Surface Mining and Tailing 5 5 5 125 Pond Impacts Warranting Reclamation 1.7.1.2 21. Illegal Waste Disposal Practices 5 5 5 125 1.8.1.1, 1.8.2.1 22. Spill or Release of Reportable 5 5 5 125 Quantities of Oil or Hazardous Substances 1.8.1.3, 1.8.2.2 23. Waste Generation Rates in 5 5 5 125 Excess of Organizational or Regulatory Requirements 1.8.1.3, 1.8.2.3 24. Adverse Impacts to External 5 5 5 125 Stakeholders 1.9.1.1, 1.9.2.1 25. Adverse Impacts to 5 5 5 125 Environmental Justice Communities 1.9.1.2, 1.9.2.2
115 Sustainability Risk Impact Probability Detectability Untreated Category and Score Score Score Risk Associated RBS Score Element Identification numbers 26. Adverse Impacts to Cultural 5 5 5 125 Resources 1.9.1.3, 1.9.2.3
Pursuant to Step # 4 of the risk management process set forth in a previous dissertation chapter, each of the risk categories analyzed in Step #3 are evaluated using the risk evaluation criteria from Step #1 according to ISO 31000:2009(E). The Step #4
Risk Evaluation follows below. The risk evaluation table demonstrates that each of the risk categories could fall under any one of three risk evaluation results depending upon the characteristics of each risk according to the risk criteria. The Risk Treatments identified in Step #5 address risk categories when they are intolerable and where risk avoidance or treatment is essential. Regulatory policy options are identified in Step #5 to address risks that are of that degree. Lesser degree risks that warrant a cost benefit analysis to balance taking the risk against treating the risk are left to the subjective determination of individual oil sands developers.
116 Table 6
Risk Evaluation
Sustainability Risk Untreated Risks that are Risks where the Risks Category and Risk intolerable and cost and benefit that are Associated RBS Score risk avoidance of taking the risk negligible Element or treatment is are balanced or so Identification essential against the cost small numbers and benefits of that no risk treatment treatment is needed 1. Adverse Surface Water Quality 125 X X X Impacts from Erosional Discharges 1.1.1.1, 1.1.2.3 2. Adverse Surface Water Quality 125 X X X Impacts from Tailing Pond Discharges 1.1.1.2 3. Adverse Surface Water Quality 125 X X X Impacts from Bitumen Extraction Process Effluent Discharges 1.1.1.3, 1.1.2.2 4. Adverse Surface Water Quality 75 X X X Impacts from Spills & Releases 1.1.1.4, 1.1.2.4 5. Adverse Surface Water Quality 125 X X X Impacts from Hydraulic Fracturing 1.1.2.1 6. Surface Water Withdrawals 125 X X X Exceed Surface Water Ecological Availability 1.2.1.1, 1.2.2.1
117 Sustainability Risk Untreated Risks that are Risks where the Risks Category and Risk intolerable and cost and benefit that are Associated RBS Score risk avoidance of taking the risk negligible Element or treatment is are balanced or so Identification essential against the cost small numbers and benefits of that no risk treatment treatment is needed 7. Surface Water Withdrawals 125 X X X Violate Water Rights 1.2.1.2, 1.2.2.2 8. Adverse Groundwater 125 X X X Quality Impacts from Extraction Process Effluent Discharges 1.3.1.1, 1.3.2.1 9. Adverse Groundwater 75 X X X Quality Impacts from Surface Mining Excavations 1.3.1.2 10. Adverse Groundwater 125 X X X Quality Impacts from In Situ Extraction Processes Including the Injection of Steam, Hot Water, Heat, or Solvents 1.3.2.2 11. Adverse Groundwater 125 X X X Quality Impacts from Hydraulic Fracturing 1.3.2.3
118 Sustainability Risk Untreated Risks that are Risks where the Risks Category and Risk intolerable and cost and benefit that are Associated RBS Score risk avoidance of taking the risk negligible Element or treatment is are balanced or so Identification essential against the cost small numbers and benefits of that no risk treatment treatment is needed 12. Adverse Groundwater 75 X X X Quality Impacts from Spills & Releases 1.3.1.3, 1.3.2.4 13. Groundwater Withdrawals that 125 X X X Violate Water Rights 1.4.1.1, 1.4.2.1 14. Groundwater Withdrawals that 125 X X X Deplete Groundwater Resources 1.4.1.2, 1.4.2.2 15. Adverse Air Quality Impacts 125 X X X from Air Emissions Associated with Equipment and Operational Processes 1.5.1.1, 1.5.2.1 16. Carbon Footprint in Excess 125 X X X of Organizational or Regulatory Requirements 1.5.1.2, 1.5.2.2 17. Adverse Air Quality Impacts 125 X X X from Surface Mining Excavations 1.5.1.3
119 Sustainability Risk Untreated Risks that are Risks where the Risks Category and Risk intolerable and cost and benefit that are Associated RBS Score risk avoidance of taking the risk negligible Element or treatment is are balanced or so Identification essential against the cost small numbers and benefits of that no risk treatment treatment is needed 18. Adverse Impacts to Threatened, 125 X X X Endangered, or Protected Species or their Habitats 1.6.1.1, 1.6.2.1 19. Loss of Wetlands or 125 X X X Streams from the Siting of Bitumen Extraction Facilities and Associated Infrastructure 1.7.1.1, 1.7.2.1 20. Adverse Surface Mining and Tailing 125 X X X Pond Impacts Warranting Reclamation 1.7.1.2 21. Illegal Waste Disposal Practices 125 X X X 1.8.1.1, 1.8.2.1 22. Spill or Release of Reportable 125 X X X Quantities of Oil or Hazardous Substances 1.8.1.3, 1.8.2.2 23. Waste Generation Rates in 125 X X X Excess of Organizational or Regulatory Requirements 1.8.1.3, 1.8.2.3
120 Sustainability Risk Untreated Risks that are Risks where the Risks Category and Risk intolerable and cost and benefit that are Associated RBS Score risk avoidance of taking the risk negligible Element or treatment is are balanced or so Identification essential against the cost small numbers and benefits of that no risk treatment treatment is needed 24. Adverse Impacts to External 125 X X X Stakeholders 1.9.1.1, 1.9.2.1 25. Adverse Impacts to Environmental 125 X X X Justice Communities 1.9.1.2, 1.9.2.2 26. Adverse Impacts to Cultural 125 X X X Resources 1.9.1.3, 1.9.2.3
Pursuant to Step # 5 of the risk management process set forth in a previous dissertation chapter, risk treatments in the form of regulatory policy options according to
ISO 31000.2009(E) are identified for each of the risk categories analyzed in Step #3 and evaluated under Step #4. Risk treatment options fall under one of the following categories:
• Mitigating the risk
• Avoiding the risk
• Transferring the risk
• Retaining the risk with a risk contingency plan
The following potential risk treatments are identified from previous dissertation findings, in no particular order of priority, for the risk categories listed in the Risk
Evaluation table above.
121 Risk Treatment No. 1: Adopt a State Environmental Policy Act: State
Environmental Policy Acts (SEPAs) are introduced in a previous chapter of the dissertation. A SEPA could be adopted by the state Legislature that requires an evaluation and consideration of potential sustainability impacts before the state Oil and Gas Board
(OGB) authorizes any type of oil sands development including surface mining and in situ extraction methods. A SEPA could be written to address all of the sustainability risks listed in the Risk Evaluation table. Required assessments or determinations under a SEPA before OGB project approval might include the following:
• Determination of minimum stream flow requirements and water availability for
any surface waters where water withdrawals are required for the proposed
development with minimum stream flows based upon ecological requirements,
and the water needs of other users for both consumptive and pollutant assimilation
uses, all based upon variable flows and variable requirements. Demonstrate that
any surface water withdrawals will not exceed minimum stream flow
requirements.
• Establish a water quality baseline for all surface waters that might be impacted
from both point-source and non-point-source pollutant discharges from oil sand
development activities by sampling and analyzing the potentially effected surface
water segments with respect to pollutants associated with oil sands developing
including polycyclic aromatic hydrocarbons (PAHs). This baseline could be
compared to any sampling and analysis performed later during or after oil sands
development activities to determine whether adverse surface water quality
impacts have occurred.
122 • Demonstrate that proposed pollutant discharges from potential oil sand
development activities will not violate state water quality standards or any
established TMDLs for potentially effected surface waters.
• Determine groundwater availability and demonstrate that any proposed
groundwater withdrawals will not deplete groundwater resources or violate water
rights of others.
• Establish a groundwater quality baseline by sampling and analysis and
demonstrate that potential oil sands development activities will have no adverse
effects on groundwater quality. This baseline could be compared to any sampling
and analysis performed later during or after oil sands development activities to
determine whether adverse groundwater quality impacts have occurred.
• Provide a locational inventory of all public drinking water surface and
groundwater sources within a specified distance of proposed oil sands
development activities and related infrastructure.
• Perform an assessment and locational inventory of threatened, endangered,
protected, and regulated species throughout the areas that would be impacted by
oil sands development including associated infrastructure for bitumen processing
and transport. Determine in consultation with both the U.S. Fish & Wildlife
Service and the State Department of Conservation and Natural Resources whether
the proposed oil sands development activities will result in adverse impacts to
these species or their habitats.
• Perform an assessment and locational inventory of cultural resources and
archeological sites throughout the areas that would be impacted by oil sands
123 development including associated infrastructure for bitumen processing and
transport. Determine in consultation with the State Historic Preservation Officer
(SHPO) and relevant Tribal Historic Preservation Officers (THPOs) whether any
of the identified cultural resources or archeological sites are potentially eligible
for listing on the National Register of Historic Places and whether the proposed
oil sands development activities will result in adverse impacts to these resources
or sites.
• Provide an inventory of any CERCLA Hazardous Substances that will be
associated with the oil sands development along with the CERCLA Reportable
Quantity for any releases and a proposed management plan for each substance
that is designed to prevent releases and provides a contingency plan should a
release occur.
• Provide an inventory of proposed oil storage and transport infrastructure and a
Spill Prevention, Countermeasure, and Control Plan (SPCC) for storing and
transporting oil.
• Provide an initial inventory, characterization, and projected generation rates of
wastes streams associated with oil sands development and a proposed waste
management plan for these wastes.
• Establish a regional air quality baseline by sampling and analysis and demonstrate
that potential oil sands development activities will have no adverse effects on
regional air quality. This baseline could be compared to any sampling and
analysis performed later during or after oil sands development activities to
determine whether adverse regional air quality impacts have occurred.
124 • Provide a preliminary inventory of wetlands, streams, and Waters of the United
States that the proposed oil sands development and associated infrastructure
would impact and proposed mitigation plans for those impacts where mitigation
will likely be required by the U.S. Army Corps of Engineers.
• Provide preliminary reclamation plans for any proposed surface mining
excavations and tailing ponds.
• Provide a locational inventory of communities within the proposed oil sands
development area that could be considered Environmental Justice (EJ)
communities that are either predominately minority communities and/or
communities with poverty rates that exceed national average based upon U.S.
Census data.
• Conduct one or more public meetings to explain the proposed oil sands
development to community stakeholders and determine their concerns. Develop
and provide a stakeholder concerns management plan that addresses the
stakeholder issues identified. The stakeholder concerns management plan should
provide for ongoing stakeholder engagement throughout the project.
It is important to remember that most SEPAs, like the National Environmental
Policy Act (NEPA), do not mandate a certain level of environmental or sustainability performance and do not elevate environmental or sustainability concerns over other factors and public interests. A SEPA would only help ensure that a government agency makes an informed decision when issuing project approvals, licenses, or permits. An informed decision by an agency might mean that other factors support an agency’s
125 decision notwithstanding known adverse environmental or sustainability impacts that will occur because of that decision.
From a risk treatment perspective, a SEPA would significantly reduce untreated oil sands development risk scores by improving the detectability, lowering the probability, and lessening the impact of the sustainability risks listed in the Risk
Evaluation table. Some of the SEPA assessments could enable decision makers to avoid risks altogether – for example, seasonal species impacts might be avoided through scheduling certain project activities. In addition to the benefit of ensuring informed governmental decision making, the assessments required under a SEPA provide baselines for either voluntary or regulatory monitoring going forward to be able to quickly detect adverse environmental or sustainability impacts in comparison to those baselines.
Risk Treatment No. 2: Sediment and Erosion Control Permits: Under the federal Clean Water Act NPDES permits are required for stormwater discharges from construction activities that disturb one or more acres of land. [74] Under EPA regulations at 40 CFR 122.26(b)(14)(iii) NPDES permits are also required for specific categories of industrial activity including coal and mineral mining and oil and gas exploration and processing. Many states, including the state of Alabama have been authorized by EPA, pursuant to federal Clean Water Act authority, to administer these NPDES permitting programs. [75] Federal Clean Water Act section 402(l)(2) exempts from NPDES permitting “discharges of stormwater runoff from oil and gas exploration, production, processing or treatment operations, or transmissions facilities, composed entirely of flows that are from conveyances or systems of conveyances used for collecting and conveying precipitation runoff, and that are not ‘contaminated by contact with any overburden, raw
126 material, intermediate products, finished product, byproduct or waste products located on the site of such operations.’ This exemption applies to both construction and industrial activities associated with oil and gas exploration, production, processing or treatment operations, or transmission facilities.” This exemption could include in situ well sites and drilling pads and associated infrastructure. In those states where EPA has not delegated
NPDES permitting authority to the state, EPA uses a construction stormwater General
Permit to regulate construction activities and a multi-sector General Permit to regulate stormwater discharges from non-exempt industrial activities that are subject to permitting. [76]
In the state of Utah, oil sand surface mining activities must be permitted under the state’s General Multi-Sector Storm Water Permit for Discharges Associated with
Industrial Activity, Permit No. UTR000000 from the Utah Department of Environmental
Quality. This Utah General Permit imposes a number of requirements including monitoring and the development of a Storm Water Pollution Prevention Plan. [77]
In the state of Alabama, under ADEM Admin. Code r. 335-6-9-.05(1), “[a]ll surface mining operations must have an NPDES permit issued by the Department …”
ADEM Admin. Code r. 335-6-9-.02(j) states that “’surface mining’ shall not be interpreted to include … advance prospecting” and under ADEM Admin. Code r. 335-6-
9-.02(a) “’[a]dvance prospecting’ shall mean the removal of overburden for the purpose of determining the location, quality or quantity of a natural deposit in an area not to exceed two acres per forty acre tract.” Alabama’s General Permit No. ALG850000 is for
“Discharges from the Mining and Processing (Wet or Dry) of Construction Sand and
Gravel, Chert, Dirt, and/or Red Clay, and Areas Associated with these Activities.”
127 However, Part I, Section B of this permit indicates that “stormwater discharges from industrial sand mines” and “discharges from crushed or dimension stone mines” are prohibited discharges that are not authorized by this permit. [78] Given that surface mining of oil sand deposits could be characterized as either an “industrial sand mine” or a
“crushed stone mine”, it is foreseeable that surface mining would not be covered under
ALG850000 thus requiring an Individual NPDES permit. An Alabama Department of
Environmental Management (ADEM) Consent Order noticed on July 9, 2015 for a surface mining operation in North Alabama describes a situation where ADEM had determined that proposed surface mining activities were not eligible for coverage under
NPDES General Permit ALG850000 and the permittee therefore applied for an
Individual NPDES permit, No. AL0082759. [79] These permits contain a wide range of discharge limitations and monitoring, reporting, inspection, and operation requirements.
NPDES permits are submit to public notice and comment requirements.
ADEM General Permit No. ALR100000 authorizes “Discharges from
Construction Activities that Result in a Total Land Disturbance of One Acre or Greater and Sites Less than One Acre but are Part of a Common Plan of Development of Sale.”
The construction of in situ well sites and associated infrastructure disturbing one or more acres of land would require coverage under this General Permit. [78]
From a risk perspective, an NPDES permit of some type will be required for surface mining and in situ land disturbances and the NPDES permit requirements will serve to significantly mitigate risk impacts and occurrence probabilities associated with these activities. These NPDES permits also serve to improve the detectability of these risk events via monitoring, inspection, and reporting requirements. If wide spread oil
128 sands development was to occur in Alabama, ADEM may wish to create one or two new
General Permits for stormwater discharges that are specifically designed to address the previously identified risks associated with potential surface mining and in situ oil sands development in Alabama.
Risk Treatment No. 3: Enhanced Surface Water Quality Monitoring: Under
Section 305(b) of the federal Clean Water Act states are required to submit to EPA on
April 1 of every even numbered year a report on the water quality of all navigable waters in the state during the previous year. 33 U.S.C, § 1313. The state of Alabama’s 2016
305(b) report indicates that ADEM performs ambient surface water monitoring at Active
Trend Stations to identify long-term water quality trends. Most of the trend stations are sampled three times per year during the months of June, August, and October and certain sites are sampled more frequently. There are 99 trend stations that are sampled annually.
“The data summaries are based on nine parameters for each station. Parameters for each station include Temperature (˚C), pH (su), Dissolved Oxygen (mg/L), Specific
Conductance (µmhos), Turbidity (NTU), Total Suspended Solids (mg/L), Nitrate +
Nitrite Nitrogen (mg/L), Total Nitrogen (mg/L), and Total Phosphorus (mg/L). The time frame varies for each trend station, but each dataset contains the entire life of that station.
Older stations include data from 1978, and most stations include data through 2015. The statistics for each trend station include the number of samples (N), the minimum (Min) and maximum (Max) values, the median (Med), the average (Avg), and the standard deviation (SD).” There are eight ambient monitoring stations within Tennessee River
Basin covering a 6,820 square mile area. Within the counties along the updip erosional limit of Hartselle sandstone deposits, there are no ambient monitoring stations in Colbert
129 County or Franklin County, and there is only one ambient monitoring station in Lawrence
County and one in Morgan County. These Tennessee River Basin ambient monitoring stations are shown in the following figure. [80]
Figure 9. ADEM 305(b) 2016 Ambient Surface Water Quality Monitoring Trend Stations in the Tennessee River Basin [80]
ADEM’s current surface water quality monitoring program is not designed to provide water quality data that could be used to quickly detect adverse water quality impacts from oil sands development as a risk treatment tool. Oil sands development contaminants of concern such as PAHs are not monitored in ADEM’s ambient surface water quality monitoring and there are no ambient monitoring trend stations in most of the areas where potential oil sands surface mining could foreseeably occur. It is unlikely
130 that any adverse surface water quality impacts could be readily detected in a timely manner without a larger network of ambient monitoring stations in many sub-watersheds throughout potential oil sands development areas. Therefore, enhanced surface water quality monitoring should be considered as a risk treatment strategy for potential oil sands development. Given that oil sands surface mining is considered a higher surface water quality risk that in situ recovery, ADEM’s Surface Mining Rules in Chapter 335-6-
9 of ADEM’s regulations could foreseeably be amended for oil sands surface mining activities to require an enhanced surface water quality monitoring system within oil sand development sub-watersheds focused on oil sand development pollutants of concern. The monitoring system could foreseeably be paid for via fees imposed by ADEM upon permittees with ADEM operating the monitoring system. Potential statutory authority for
ADEM to require an oil sands development surface water quality monitoring system may be found in ALA. Code §§ 22-22-9 and 22-22A-5 and other Alabama statutes. An enhanced surface water quality monitoring system could substantially increase the detectability of adverse surface water quality impacts.
Risk Treatment #4: Surface Water and Groundwater Withdrawal
Permitting: In a previous chapter of the dissertation, the Alabama Water Agencies
Working Group (AWAWG) report to Governor Robert Bentley in 2013 was discussed that describes the importance of naturally varying stream flows to support healthy ecosystems. In addition to ecological minimum stream flow requirements, adequate instream flows are also important to other water users including NPDES permit holders who rely on sufficient stream flows for pollutant assimilative capacity to remain within permit limits and state water quality standards, public water supplies, outdoor
131 recreational water users, and power generation water users. “Instream flow management approaches vary widely from state to state, and there are few national standardized methods for linking flow quantity and duration to state and local water needs and requirements while considering stream ecology, riparian areas, and floodplain habitats.”
Alabama has no law prescribing instream flow standards. [46] Alabama School of Law
Professor Heather Elliott wants to see significant changes to Alabama’s water resources law with a permitting system for surface and ground water diversions that specifies where, when, and how water may be diverted, how much may be diverted, and what the water may be used for. [45]
Elliott would like to see the Alabama state Legislature adopt the Regulated
Riparian Model Water Code or a similar statute that would create a water use permitting system under which a state agency would assess the reasonableness of a proposed water use before issuing a permit. She says that any legislation must recognize the hydrologic connections between surface and groundwater. “If groundwater pumping affects surface flows, and surface water diversions affect groundwater levels, continuing to treat the two as separate resources means that permits for surface water could allow harm to groundwater and vice versa.” A permitting system could be used to protect instream flows needed by ecosystems. [52]
If any proposed oil sands development would utilize significant amounts of surface water or groundwater, state adoption of a water withdrawal permitting system that is designed to protect minimum stream flow needs of ecosystems and other water users would serve to mitigate risks by lowering or eliminating potential adverse water withdrawal risk impacts and reducing the likelihood of their occurrence.
132 Risk Treatment #5: Voluntary GHG Emission Limits: Climate change regulation through the control of greenhouse gas emissions has been a primary focus of many governmental jurisdictions around the world in recent years. Under Alabama law,
ADEM is prohibited from creating new greenhouse gas regulations under the following two paragraphs of ALA. Code § 22-28A-3
Section 22-28A-3:
(a) Effective immediately, the Director of the Alabama Department of
Environmental Management shall refrain from proposing or promulgating any
new regulations intended in whole or in part to reduce emissions of greenhouse
gases, as such gases are defined by the Kyoto Protocol, from the residential,
commercial, industrial, electric utility, or transportation sectors unless such
reductions are required under existing statutes.
(b) In the absence of a resolution or other act of the Legislature of the State of
Alabama approving same, the Director of the Alabama Department of
Environmental Management shall not submit to the U.S. Environmental
Protection Agency or to any other agency of the federal government any legally
enforceable commitments related to the reduction of greenhouse gases, as such
gases are defined by the Kyoto Protocol unless such reductions are required
under existing statutes.
Therefore, notwithstanding existing EPA greenhouse gas regulatory requirements that
ADEM implements under delegated authority, additional state greenhouse gas regulations are not recommended. Nonetheless, oil sand developers could choose to voluntarily
133 monitor and reduce or limit greenhouse gas emissions from oil sand development projects to satisfy organizational carbon footprint objectives.
Risk Treatment No. 6: Public Involvement Plans: In 2000 EPA issued its Draft
Title VI Guidance for EPA Assistance Recipients Administering Environmental
Permitting Programs which explains how to effectively deal with the types of public concerns that often lead to complaints of discrimination. See 65 Fed. Reg. 39650 (June
27, 2000) This guidance document is primarily directed to state agencies that are recipients of financial assistance from EPA to comply with Title VI of the Civil Rights
Act of 1964 in their implementation of environmental permitting programs. Financial aid recipients must administer their programs in a nondiscriminatory manner. This document provides useful guidance that non-federally funded state agencies could also follow to address public concerns in their regulation of oil sands development. EPA’s guidance is based upon the following guiding principles:
• All persons regardless of race, color, or national origin are entitled to a safe and
healthful environment.
• Strong civil rights enforcement is essential.
• Enforcement of civil rights laws and environmental laws are complementary, and
can be achieved in a manner consistent with sustainable economic development.
• Potential adverse cumulative impacts from stressors should be assessed, and
reduced or eliminated wherever possible.
• Research efforts by EPA and state and local environmental agencies into the
nature and magnitude of exposures, stressor hazards, and risks are important and
should be continued.
134 • Decreases in environmental impacts through applied pollution prevention and
technological innovation should be encouraged to prevent, reduce, or eliminate
adverse disparate impacts.
• Meaningful public participation early and throughout the decision-making process
is critical to identify and resolve issues, and to assure proper consideration of
public concerns.
• Early, preventive steps, whether under the auspices of state and local
governments, in the context of voluntary initiatives by industry, or at the initiative
of community advocates, are strongly encouraged to prevent potential Title VI
violations and complaints.
• Use of informal resolution techniques in disputes involving civil rights or
environmental issues yield the most desirable results for all involved.
• Intergovernmental and innovative problem-solving provide the most
comprehensive response to many concerns raised in Title VI complaints.
EPA recommends that the following activities be integrated into permitting programs to identify and resolve issues:
1. Staff training;
2. Encourage effective public participation and outreach—to provide permitting and
public participation processes that occur early, and are inclusive and meaningful;
3. Conduct adverse impact and demographic analyses—to analyze new and existing
sources, stressors, and adverse impacts with relevant demographic information,
especially potential cumulative adverse impacts, to provide confidence that Title
VI concerns are identified and appropriately addressed;
135 4. Encourage intergovernmental involvement—to bring together all agencies and
parties that may contribute to identifying and addressing stakeholder concerns to
reach innovative and comprehensive resolutions;
5. Participate in alternative dispute resolution—to involve both the community and
recipient in an informal process to resolve Title VI concerns;
6. Reduce or eliminate the alleged adverse disparate impact(s)—to reduce or
eliminate identified or potential adverse human health or environmental impacts;
and
7. Evaluate Title VI activities—to identify progress and areas in need of
improvement.
Most these recommendations could be utilized by any state agency regulating oil sands development to address broad public concerns and not just those concerns that might relate to Title VI. The primary risk treatments to glean are the following:
• Provide meaningful public participation early and throughout the regulatory
process
• Conduct adverse impact and demographic analyses to analyze new and existing
sources, stressors, and adverse impacts with relevant demographic information,
especially potential cumulative adverse impacts
• Reduce or eliminate the alleged adverse disparate impact(s)—to reduce or
eliminate identified or potential adverse human health or environmental impacts
This risk treatment would significantly lower the probability of adverse impacts to external stakeholders and adverse impacts to environmental justice communities.
136 Risk Treatment No. 7: Groundwater Quality Monitoring: The Geological
Survey of Alabama (GSA) manages a real-time groundwater monitoring program that measures real-time groundwater levels in 25 wells and 2 springs. The GSA also has a periodic groundwater monitoring program that monitors water levels in 369 wells and 49 springs throughout the state. [81] With state funding to do so, the expansion of GSA groundwater monitoring programs within potential oil sands development areas to include groundwater quality monitoring in addition to water level monitoring would provide a useful tool for detecting adverse impacts to groundwater from any oil sands development. It is unlikely that any adverse groundwater quality impacts could be readily detected in a timely manner without a network of monitoring wells throughout potential oil sands development areas. The monitoring system could foreseeably be paid for via fees imposed by Oil & Gas Board (OGB) upon permittees with GSA operating the monitoring system. One of the statutory powers of the OGB is “[t]o prevent the pollution of fresh water supplies by oil, gas, salt water, or other contaminants resulting from oil and gas operations, including surface mining operations to recover oil from oil sands.” ALA.
Code § 9-17-6(c)(3). The OGB is also empowered to collect fees: “Any person proposing a surface mining operation to recover oil from oil sands shall notify the State Oil and Gas
Supervisor. The notification shall be in a form prescribed by the State Oil and Gas
Supervisor and shall be accompanied by a fee paid to the State Treasurer in an amount based on acreage of the operation. The acreage fees for surface mining operations to recover oil from oil sands shall be set by rule of the State Oil and Gas Board. All fees for a proposal to conduct surface mining operations to recover oil from oil sands paid pursuant to this section shall be deposited into the State Oil and Gas Board Special Fund
137 and disbursed by the State Treasurer upon warrants drawn by the state Comptroller for the purpose of defraying the expenses incurred by the State Oil and Gas Board in the performance of its duties pursuant to this subsection.” ALA. Code § 9-17-24(d). “All well permit fees, filing fees for petitions, and other fees paid to the State Treasurer pursuant to this section shall be paid into the Alabama State Oil and Gas Board Special Fund and disbursed by the State Treasurer upon warrants drawn by the state Comptroller for the purpose of defraying expenses incurred by the State Oil and Gas Board in the performance of its duties.” ALA. Code § 9-17-24(e).
An oil sands development area groundwater monitoring system, whether paid for by permittees or the state General Fund, would significantly improve the detectability of adverse impacts to groundwater from oil sands development.
Risk Treatment No. 8: Aquifer Contamination Vulnerability Assessment within Potential Oil Sands Development Areas: The U.S. Geological Survey issued a report in 1987 that delineates and describes the geohydrology and susceptibility of major aquifers to contamination in Colbert, Franklin, Lauderdale, Lawrence, Limestone,
Madison, and Morgan Counties of Alabama. This report indicates that the Bangor aquifer is a significant source of groundwater and includes the Bangor Limestone and the underlying Hartselle Sandstone. This aquifer is recharged throughout its outcrop and is susceptible to contamination within the outcrop. However, the report indicates that “The
Hartselle Sandstone is a significant source of water in only a small part of the study area.” Nonetheless, the report adds that the Bangor Aquifer “is capable of supplying large quantities of groundwater but currently is not being used extensively.” [82] In light of recent attention to groundwater availability and long-term water needs, careful attention
138 must be given to potential oil sands development impacts to the Bangor Aquifer and whether it will be looked to as a long-term source of freshwater supply.
If in situ oil sand wells require hydraulic fracturing, OGB regulations specify that
“Each well shall be treated or fractured in such manner as will not … endanger freshwater-bearing strata.” Ala. ADMIN. Code r. 400-1-4-.07. Fracturing operations shall not be conducted if it is determined that any fresh water resources or any fresh water supply well located within a one quarter- (1/4-) mile radius of the subject well could be adversely impacted as a result of the fracturing operation.” Ala. ADMIN. Code r. 400-1-
9-.04(3)(d). One of the factors that the OGB must consider in reviewing hydraulic fracturing proposals is “whether the proposed hydraulic fracturing operation ensures that the formation to be fractured lies beneath an impervious stratum.” Ala. ADMIN. Code r.
400-1-9-.04(3)(e)(1). Any in situ oil sands recovery in Alabama that requires hydraulic fracturing within the Bangor Aquifer could be problematic under these regulatory requirements without a detailed assessment of freshwater aquifers within potential oil sands development areas.
A detailed assessment of the aquifer vulnerability and hydrogeology is needed in the potential oil sands area and the Geological Survey of Alabama would be the appropriate agency to undertake such a study.
Risk Treatment No. 9: Reclamation and Financial Assurance Requirements to Ensure Reclamation of Surface Extraction Mines and/or Tailings Ponds: In a previous dissertation chapter on the regulation of Canadian oil sands development, the following practices were identified with respect to the long-term reclamation of surface extraction mines and tailing ponds: (1) adequate regulation of tailing pond design,
139 operation, and reclamation is important; (2) long-term financial assurance requirements are necessary to ensure that reclamation goals are attained; and (3) life-cycle environmental impact analysis and feasibility studies of tailings pond design, site selection, operation, and eventual reclamation are warranted. The Canadian government requires financial assurance to ensure that long-term reclamation occurs with any surface extraction mines or any tailings ponds associated with oil sands development. [63], [56],
[15]
In the 2013 regular session, the Alabama Legislature passed HB503 modifying sections 9-17-6 of the Code of Alabama of 1975 to grant authority to the State Oil and
Gas Board to “[t]o require reasonable bond, with good and sufficient surety, or other financial security … for the duty to … reclaim all surfaces disturbed during surface mining operations for the recovery of oil from oil sands.” [72] Forthcoming OGB regulations for oil sands mining and tailing ponds along with long-term financial assurance requirements to ensure adequate reclamation occurs will serve to significantly reduce the likelihood of long-term reclamation risks.
Risk Treatment No. 10: Air Quality Modeling, Inventory, and Permitting:
ADEM has a robust air permitting program in place. If air emissions from oil sands development exceed certain emission thresholds or fall under specific source categories, an air permit from ADEM may be required. ADEM uses emissions modeling and emissions inventories to analyze emission trends. ADEM’s current air regulatory programs sufficiently mitigate the likelihood of potential adverse air emissions from oil sands development activities. [83]
140 Each of the identified risk categories were re-scored after applying the risk treatments in the following table.
Table 7
Post-Treatment Risk Analysis
Sustainability Risk Treatments Impact Probability Detectability Treated Risk Score Score Score Risk Category and Score Associated RBS Element Identification numbers 1. Adverse RT1: SEPA Surface Water RT2: Sediment & 5 2 4 40 Quality Erosion Control via minimum Impacts from Permits permitting monthly Erosional RT3: Enhanced requirements monitoring Discharges Surface Water 1.1.1.1, Quality 1.1.2.3 Monitoring 2. Adverse RT1: SEPA Surface Water RT3: Enhanced 5 2 4 40 Quality Surface Water via new OGB minimum Impacts from Quality surface monthly Tailing Pond Monitoring mining monitoring Discharges RT9: requirements 1.1.1.2 Reclamation and Financial Assurance Requirements 3. Adverse RT1: SEPA Surface Water RT3: Enhanced 5 2 4 40 Quality Surface Water via NPDES minimum Impacts from Quality permit monthly Bitumen Monitoring requirements monitoring Extraction Process Effluent Discharges 1.1.1.3, 1.1.2.2
141 Sustainability Risk Treatments Impact Probability Detectability Treated Risk Score Score Score Risk Category and Score Associated RBS Element Identification numbers 4. Adverse RT1: SEPA Surface Water RT3: Enhanced 5 2 4 40 Quality Surface Water via SPCC minimum Impacts from Quality plans and monthly Spills & Monitoring permit monitoring Releases requirements 1.1.1.4, 1.1.2.4 5. Adverse RT1: SEPA Surface Water RT3: Enhanced 5 2 4 40 Quality Surface Water via OGB minimum Impacts from Quality permitting monthly Hydraulic Monitoring requirements monitoring Fracturing 1.1.2.1 6. Surface RT1: SEPA Water RT4: Surface 5 1 2 10 Withdrawals Water & via permit via permit Exceed Groundwater requirements requirements Surface Water Withdrawal Ecological Permitting Availability 1.2.1.1, 1.2.2.1 7. Surface RT1: SEPA Water RT4: Surface 5 1 2 10 Withdrawals Water & via permit via permit Violate Water Groundwater requirements requirements Rights 1.2.1.2, Withdrawal 1.2.2.2 Permitting
142 Sustainability Risk Treatments Impact Probability Detectability Treated Risk Score Score Score Risk Category and Score Associated RBS Element Identification numbers 8. Adverse RT1: SEPA Groundwater RT7: 5 1 5 25 Quality Groundwater Impacts from Quality Extraction Monitoring Process RT8: Aquifer Effluent Contamination Discharges Vulnerability 1.3.1.1, Assessment 1.3.2.1 9. Adverse RT1: SEPA Groundwater RT7: 5 1 5 25 Quality Groundwater Impacts from Quality Surface Monitoring Mining RT8: Aquifer Excavations Contamination 1.3.1.2 Vulnerability Assessment 10. Adverse RT1: SEPA Groundwater RT7: 5 1 5 25 Quality Groundwater Impacts from Quality In Situ Monitoring Extraction RT8: Aquifer Processes Contamination Including the Vulnerability Injection of Assessment Steam, Hot Water, Heat, or Solvents 1.3.2.2
143 Sustainability Risk Treatments Impact Probability Detectability Treated Risk Score Score Score Risk Category and Score Associated RBS Element Identification numbers 11. Adverse RT1: SEPA Groundwater RT7: 5 1 5 25 Quality Groundwater Impacts from Quality Hydraulic Monitoring Fracturing RT8: Aquifer 1.3.2.3 Contamination Vulnerability Assessment 12. Adverse RT1: SEPA Groundwater RT7: 5 1 5 25 Quality Groundwater Impacts from Quality Spills & Monitoring Releases RT8: Aquifer 1.3.1.3, Contamination 1.3.2.4 Vulnerability Assessment 13. RT1: SEPA Groundwater RT4: Surface 5 1 2 10 Withdrawals Water & via via that Violate Groundwater permitting permitting Water Rights Withdrawal 1.4.1.1, Permitting 1.4.2.1 14. RT1: SEPA Groundwater RT4: Surface 5 1 2 10 Withdrawals Water & via permit via permit that Deplete Groundwater requirements requirements Groundwater Withdrawal Resources Permitting 1.4.1.2, 1.4.2.2
144 Sustainability Risk Treatments Impact Probability Detectability Treated Risk Score Score Score Risk Category and Score Associated RBS Element Identification numbers 15. Adverse RT1: SEPA Air Quality RT10: Air 5 1 5 25 Impacts from Quality Air Emissions Modeling, Associated Inventory, and with Permitting Equipment and Operational Processes 1.5.1.1, 1.5.2.1 16. Carbon RT5: Voluntary Footprint in GHG Emission 5 1 1 5 Excess of Limits Organizational or Regulatory Requirements 1.5.1.2, 1.5.2.2 17. Adverse RT1: SEPA Air Quality RT10: Air 5 1 4 20 Impacts from Quality via OGB Surface Modeling, permit Mining Inventory, and requirements Excavations Permitting 1.5.1.3 18. Adverse RT1: SEPA Impacts to 5 1 5 25 Threatened, Endangered, or Protected Species or their Habitats 1.6.1.1, 1.6.2.1
145 Sustainability Risk Treatments Impact Probability Detectability Treated Risk Score Score Score Risk Category and Score Associated RBS Element Identification numbers 19. Loss of RT1: SEPA Wetlands or 5 1 1 5 Streams from via U.S. via pre- the Siting of Army Corps construction Bitumen of Engineer assessments Extraction Permitting Facilities and Requirements Associated Infrastructure 1.7.1.1, 1.7.2.1 20. Adverse RT1: SEPA Surface RT9: 5 1 5 25 Mining and Reclamation and via OGB Tailing Pond Financial permitting Impacts Assurance requirements Warranting Requirements Reclamation 1.7.1.2 21. Illegal RT1: SEPA Waste 5 1 5 25 Disposal via Practices regulatory 1.8.1.1, requirements 1.8.2.1 22. Spill or RT1: SEPA Release of 5 1 2 10 Reportable via Quantities of regulatory Oil or requirements Hazardous Substances 1.8.1.3, 1.8.2.2
146 Sustainability Risk Treatments Impact Probability Detectability Treated Risk Score Score Score Risk Category and Score Associated RBS Element Identification numbers 23. Waste RT1: SEPA Generation 5 1 1 5 Rates in Excess of Organizational or Regulatory Requirements 1.8.1.3, 1.8.2.3 24. Adverse RT1: SEPA Impacts to RT6: Public 5 2 4 40 External Involvement Stakeholders Plans 1.9.1.1, 1.9.2.1 25. Adverse RT1: SEPA Impacts to RT6: Public 5 2 4 40 Environmental Involvement Justice Plans Communities 1.9.1.2, 1.9.2.2 26. Adverse RT1: SEPA Impacts to 5 1 1 5 Cultural Resources 1.9.1.3, 1.9.2.3
The following table demonstrates the effectiveness of the various risk treatment options that were applied to the identified risk categories.
147 Table 8
Risk Treatment Effectiveness
Sustainability Risk Untreated Risk Treatment Treated Risk Risk Category and Risk Score Score Associated RBS Score Change Element Identification numbers 1. Adverse Surface RT1: SEPA Water Quality 125 RT2: Sediment 40 -85 Impacts from & Erosion -68% Erosional Control Permits Discharges 1.1.1.1, RT3: Enhanced 1.1.2.3 Surface Water Quality Monitoring 2. Adverse Surface RT1: SEPA Water Quality 125 RT3: Enhanced 40 -85 Impacts from Surface Water -68% Tailing Pond Quality Discharges 1.1.1.2 Monitoring RT9: Reclamation and Financial Assurance Requirements 3. Adverse Surface RT1: SEPA Water Quality 125 RT3: Enhanced 40 -85 Impacts from Surface Water -68% Bitumen Extraction Quality Process Effluent Monitoring Discharges 1.1.1.3, 1.1.2.2 4. Adverse Surface RT1: SEPA Water Quality 75 RT3: Enhanced 40 -35 Impacts from Spills Surface Water -47% & Releases 1.1.1.4, Quality 1.1.2.4 Monitoring 5. Adverse Surface RT1: SEPA Water Quality 125 RT3: Enhanced 40 -85 Impacts from Surface Water -68% Hydraulic Quality Fracturing 1.1.2.1 Monitoring
148 Sustainability Risk Untreated Risk Treatment Treated Risk Risk Category and Risk Score Score Associated RBS Score Change Element Identification numbers 6. Surface Water RT1: SEPA Withdrawals Exceed 125 RT4: Surface 10 -115 Surface Water Water & -92% Ecological Groundwater Availability 1.2.1.1, Withdrawal 1.2.2.1 Permitting 7. Surface Water RT1: SEPA Withdrawals Violate 125 RT4: Surface 10 -115 Water Rights Water & -92% 1.2.1.2, 1.2.2.2 Groundwater Withdrawal Permitting 8. Adverse RT1: SEPA Groundwater 125 RT7: 25 -100 Quality Impacts Groundwater -80% from Extraction Quality Process Effluent Monitoring Discharges 1.3.1.1, RT8: Aquifer 1.3.2.1 Contamination Vulnerability Assessment 9. Adverse RT1: SEPA Groundwater 75 RT7: 25 -50 Quality Impacts Groundwater -67% from Surface Quality Mining Excavations Monitoring 1.3.1.2 RT8: Aquifer Contamination Vulnerability Assessment 10. Adverse RT1: SEPA Groundwater 125 RT7: 25 -100 Quality Impacts Groundwater -80% from In Situ Quality Extraction Processes Monitoring Including the RT8: Aquifer Injection of Steam, Contamination Hot Water, Heat, or Vulnerability Solvents 1.3.2.2 Assessment
149 Sustainability Risk Untreated Risk Treatment Treated Risk Risk Category and Risk Score Score Associated RBS Score Change Element Identification numbers 11. Adverse RT1: SEPA Groundwater 125 RT7: 25 -100 Quality Impacts Groundwater -80% from Hydraulic Quality Fracturing 1.3.2.3 Monitoring RT8: Aquifer Contamination Vulnerability Assessment 12. Adverse RT1: SEPA Groundwater 75 RT7: 25 -50 Quality Impacts Groundwater -67% from Spills & Quality Releases 1.3.1.3, Monitoring 1.3.2.4 RT8: Aquifer Contamination Vulnerability Assessment 13. Groundwater RT1: SEPA Withdrawals that 125 RT4: Surface 10 -115 Violate Water Water & -92% Rights 1.4.1.1, Groundwater 1.4.2.1 Withdrawal Permitting 14. Groundwater RT1: SEPA Withdrawals that 125 RT4: Surface 10 -115 Deplete Water & -92% Groundwater Groundwater Resources 1.4.1.2, Withdrawal 1.4.2.2 Permitting 15. Adverse Air RT1: SEPA -100 Quality Impacts 125 RT10: Air 25 -80% from Air Emissions Quality Associated with Modeling, Equipment and Inventory, and Operational Permitting Processes 1.5.1.1, 1.5.2.1
150 Sustainability Risk Untreated Risk Treatment Treated Risk Risk Category and Risk Score Score Associated RBS Score Change Element Identification numbers 16. Carbon RT5: Voluntary Footprint in Excess 125 GHG Emission 5 -120 of Organizational or Limits -96% Regulatory Requirements 1.5.1.2, 1.5.2.2 17. Adverse Air RT1: SEPA Quality Impacts 125 RT10: Air 20 -105 from Surface Quality -84% Mining Excavations Modeling, 1.5.1.3 Inventory, and Permitting 18. Adverse Impacts to Threatened, 125 RT1: SEPA 25 -100 Endangered, or -80% Protected Species or their Habitats 1.6.1.1, 1.6.2.1 19. Loss of Wetlands or Streams 125 RT1: SEPA 5 -120 from the Siting of -96% Bitumen Extraction Facilities and Associated Infrastructure 1.7.1.1, 1.7.2.1 20. Adverse Surface RT1: SEPA Mining and Tailing 125 RT9: 25 -100 Pond Impacts Reclamation and -80% Warranting Financial Reclamation 1.7.1.2 Assurance Requirements 21. Illegal Waste Disposal Practices 125 RT1: SEPA 10 -115 1.8.1.1, 1.8.2.1 -92%
151 Sustainability Risk Untreated Risk Treatment Treated Risk Risk Category and Risk Score Score Associated RBS Score Change Element Identification numbers 22. Spill or Release of Reportable 125 RT1: SEPA 10 -115 Quantities of Oil or -92% Hazardous Substances 1.8.1.3, 1.8.2.2 23. Waste Generation Rates in 125 RT1: SEPA 5 -120 Excess of -96% Organizational or Regulatory Requirements 1.8.1.3, 1.8.2.3 24. Adverse Impacts RT1: SEPA to External 125 RT6: Public 40 -85 Stakeholders Involvement -68% 1.9.1.1, 1.9.2.1 Plans 25. Adverse Impacts RT1: SEPA to Environmental 125 RT6: Public 40 85 Justice Communities Involvement -68% 1.9.1.2, 1.9.2.2 Plans 26. Adverse Impacts to Cultural 125 RT1: SEPA 5 -120 Resources 1.9.1.3, -96% 1.9.2.3
152
CONCLUSIONS AND IMPLICATIONS FOR REGULATORY POLICY, OIL
SANDS DEVELOPMENT STRATEGIES, AND FURTHER RESEARCH
Conclusions: This dissertation demonstrates that International Organization for
Standardization (ISO) standards provide an effective framework for creating an oil sands development sustainability risk management strategy. The findings of this dissertation compliment the efforts of the Geological Survey of Alabama in its charge to conduct a comprehensive geologic, engineering, and legal assessment of oil sands resources associated with the Hartselle Sandstone formation including the identification of environmental best practices associated with developing these resources. This dissertation provides an interdisciplinary model for the sustainable development of Alabama’s oil sands. The interdisciplinary approach provided within this dissertation can be applied to the sustainable development of other oil and gas formations.
This dissertation is delivered in a user-friendly and practical format to be readily applied by a wide variety of disciplines in developing policy strategies for the potential development of Alabama’s oil sand deposits.
Implications for Regulatory Policy and Oil Sands Development Strategies:
The following primary risk treatments were identified to address potential oil sands development risks via the risk assessment process set forth in this dissertation. These risk treatments are in the form of proposed regulatory policies:
153 • The adoption of a State Environmental Policy Act (SEPA) could require the
evaluation and consideration of potential sustainability impacts by and before the
OGB authorizes any oil sands development. A SEPA would ensure that potential
sustainability issues are identified, assessed, and considered before state agency
decisions are made to issue authorizations, licenses, permits, or approvals for
proposed oil sand development activities.
• If wide spread oil sands development was to occur in Alabama, ADEM should
consider creating one or two new General Permits for stormwater discharges that
are specifically designed to address risks associated with potential surface mining
and in situ oil sands development.
• Oil sands development in Alabama warrants the creation of an enhanced surface
water quality monitoring system within sub-watersheds where oil sands
development would occur that is focused on oil sand development pollutants of
concern. This system would facilitate timely detection of any adverse surface
water impacts from oil sands development.
• The establishment of a surface water and groundwater withdrawal permitting
system for any significant oil sands development water needs could be used to
protect minimum stream flow needs of ecosystems and other water users.
• State agencies regulating oil sands development should develop public
involvement plans to identify stakeholder issues and provide meaningful public
participation early and throughout regulatory processes.
• State agencies regulating oil sands development should conduct demographic
analyses to avoid potential environmental justice issues.
154 • Oil sands development in Alabama warrants the creation of an enhanced
groundwater quality monitoring system within sub-watersheds where oil sands
development would occur that is focused on oil sand development pollutants of
concern. This system would facilitate timely detection of any adverse
groundwater impacts from oil sands development.
• A detailed assessment of the aquifer vulnerability and hydrogeology is needed in
the potential oil sands area and the Geological Survey of Alabama would be the
appropriate agency to undertake such a study.
• Any forthcoming OGB regulations for potential oil sands surface mining should
include excavation and tailing pond design requirements, reclamation
requirements, and long-term financial assurance requirements to ensure that
adverse surface and groundwater impacts do not occur and that adequate
reclamation occurs.
Further Research: Existing core samples of the Hartselle Sandstone formation show wide ranges of porosity, permeability, and oil saturation. Gaining a better understanding of these factors through the completion of the current GSA geological assessment of oil sand deposits is essential before any development of Alabama’s oil sands can be considered.
Considering the similarities between Alabama’s Hartselle Sandstone and oil sand deposits in Utah, there is speculation that any surface mining of oil sand deposits in
Alabama would utilize the same technologies as in Utah (i.e. hard rock mining techniques using proprietary solvents to extract bitumen via closed loop systems); however, unlike
Utah, the vast amount of Alabama’s oil sand deposits are too deep for surface mining and
155 would require in situ extraction methods. In situ methods for the potential recovery of
Alabama oil sands have not been developed or tested in Utah or Alabama. Research is needed to develop and evaluate in situ bitumen recovery methods for the Hartselle
Sandstone. Research is also warranted to confirm whether Utah’s surface mining technologies are applicable to surface mining Alabama’s Hartselle Sandstone.
156
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[66] “Activists camp out in protest vigil at Utah tar sands site,” The Salt Lake Tribune. [Online]. Available: http://www.sltrib.com/sltrib/news/58089815-78/sands-utah-oil- tar.html.csp. [Accessed: 23-Jul-2014].
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APPENDIX - A: MEMORANDUM OF UNDERSTANDING BETWEEN ALABAMA AND MISSISSIPPI TO STUDY THE POTENTIAL DEVELOPMENT OF OIL SANDS
164
Memorandum of Understanding
This Memorandum of Understanding (MOU) describes a coordinated effort between the Governors of the states of Alabama and Mississippi (States) and their designees to explore emerging energy resources in the States. The Governors recognize the need for a comprehensive geologic and engineering assessment of the States oil sands resources and an analysis of the legal and regulatory frameworks applicable to resource development. The Governors understand the significance of the potential oil production from these resources and recognize the employment and economic development opportunities that development presents for the people of the States and the Southern States Energy Board region.
Oil sands generally occur as natural mixtures of sand, clay, water, and bitumen, a heavy oil. When extracted from the subsurface, the bitumen is separated from the sand and upgraded to a refinery-ready crude oil. The State of Alabama has the third largest oil sands resource in the United States, which may extend into the State of Mississippi. The Hartselle Sandstone exists from north-central and northwest Alabama into northeastern Mississippi. The potential for future oil extraction operations of this formation’s surface and subsurface hydrocarbons have been the focus of attention for many years. Based on evaluations in the 1980s, the total subsurface reserves are estimated to be 7.5 billion barrels, 350 million barrels of which are located within 50 feet of the surface.
The Governors support a comprehensive geologic and engineering assessment of the oil sands resources in the States to be conducted as a joint effort between the Geological Survey of Alabama/State Oil and Gas Board, the Mississippi State Oil and Gas Board, the Mississippi Development Authority, the Mississippi Office of Geology, and the Southern States Energy Board. This assessment may include, but is not limited to, an inventory of existing core and well logs for data collection; identification of data gaps; acquisition and interpretation of additional data; detailed geologic reservoir modeling; a refined estimate of oil reserves; and an inventory of existing and new infrastructure needed to support the industry. Further, the Governors support a thorough analysis and comparison of the existing legal and regulatory frameworks applicable to oil sands resource development in the States and request recommendations for resolving any legal or regulatory barriers to commercial deployment across the geographical boundary between the States. As necessary and within their authority, the Governors hereby agree to work cooperatively to address the recommendations and resolve any identified barriers.
Forty-seven percent of non-OPEC imports of crude to the United States originate in Canada. The largest commercial oil sands operations are ongoing in the Canadian Province of Alberta, which supplied the United States with 15 percent of its crude imports in 2011. Over 906 U.S. companies supply equipment, parts, and services to companies in Alberta, and 40 percent of these suppliers are located within Alabama, Mississippi, and other jurisdictions within the Southern States Energy Board region. The Canadian Consulate General in Atlanta, Georgia, and the Government of Alberta hosted Southern States Energy Board members and geologists from Alabama and Mississippi in Alberta in 2012 for a series of meetings and tours highlighting the oil sands operations in the Province. The Governors encourage continued collaboration and knowledge-sharing on technical, legal, regulatory, and environmental best practices between the Geological Survey of Alabama/State Oil and Gas Board, the Mississippi State Oil and Gas Board, the Mississippi Development Authority, the Mississippi Office of Geology, and the Southern States Energy Board and the Canadian Consulate General in Atlanta, Georgia, the Government of Alberta, and Canadian universities and research facilities.
The Governors recognize that a partnership between the States, the energy industry, and major utilities can have a positive impact on the successful exploration for, and development of, these resources. To the extent practicable, the Governors will call on industry, in cooperation with state officials, to provide scientific assessment, technical expertise, and environmental stewardship to foster the potential for oil sands development.
This MOU demonstrates the Governors’ willingness to explore the potential for oil sands resource development in the States and asserts the Governors’ support of conducting the work outlined herein. This MOU shall not create any obligations or legal relationships that are binding or enforceable at law or in equity.
Set forth this 27th day of July, 2013 by:
State of Alabama State of Mississippi
Robert Bentley, Governor Phil Bryant, Governor
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APPENDIX – B: FIELD OBSERVATIONS OF HARTSELLE SANDSTONE OUTCROPS WITH BITUMEN DEPOSITS IN ALABAMA
166 The following outcrops were visited on June 26, 2017 by Benjamin D. Smith and Daniel E. Smith III:
No. Proximate Field Approximate Sample and Field Notes Outcrop Measured GPS Address from Photograph Observations Identified Coordinates iPhone Label Name in GSA Mapping Bulletin Software 111 Table A 1 A-3.3 34˚26’22.8”N 613 Cedar A_3_3 Weathered 86˚55’20.9”W Cove Road SE A-3.3 sandstone. No asphaltic content observed in fresh surface of sample 2 34˚30’15.1”N 2026 County Moulton #1 Sandstone Moulton 87˚09’34.3”W Road 434 Moulton #2 outcrop. No #1 on Moulton, Al asphaltic material South observed in side of Moulton #1 creek sample fresh along surface. Moulton county #2 sample fresh road 434. surface was Moulton darker inside and #2 on potentially North asphaltic. side of creek along county road 434. Both samples on east side of road. 3 A-5.2 34˚32’22.9”N 269 County A_5_2 Sandstone. No 87˚09’01.1”W Road 325 A-5.2 asphaltic material Moulton, Al observed in sample fresh surface; notwithstanding darker weathered surface.
167 No. Proximate Field Approximate Sample and Field Notes Outcrop Measured GPS Address from Photograph Observations Identified Coordinates iPhone Label Name in GSA Mapping Bulletin Software 111 Table A 4 A-8.1 34˚34’39.9”N On Colborn A_8_1 Sandstone 87˚39’12.8”W Mill Road A-8.1 outcrops. No asphaltic material observed within upland sample fresh surface from east side of road side. Fresh surface of sample from outcrop within Rocky Branch stream bed on west side of the road was darker and potentially asphaltic material. 5 A-8.2 34˚34’46.2”N 700 George A_8_2 Sandstone 87˚40’53.7”W Wallace Hwy, A-8.2 outcrop with Russellville, slight AL 35654 discoloring. No significant asphaltic material, if any, observed within fresh surface of sample. 6 34˚36’32.9”N US Hwy #43 Hwy 43 Large sandstone 87˚39’43.2”W George outcrop with a Wallace Hwy few dark spots in fresh surfaces and fossils. 7 A-2.1 34˚44’27.0”N Along Sutton A_2_1 Sandstone 88˚03’12.0”W Hill Road A-2.1 outcrop. Asphaltic material observed in sample fresh surfaces. Only small traces of potential asphaltic material observed in fresh surface of sample.
168 No. Proximate Field Approximate Sample and Field Notes Outcrop Measured GPS Address from Photograph Observations Identified Coordinates iPhone Label Name in GSA Mapping Bulletin Software 111 Table A 8 34˚44’10.0”N Along Asphalt AR1 Sandstone 88˚04’38.9”W Rock Road outcrop with tree roots. Poor induration. Weathered. 9 34˚44’23.9”N Abandoned AR2 Fresh surfaces of 88˚03’29.9”W quarry at sandstone intersection of samples from Sutton Hill edge of quarry Road and closest to Sutton Asphalt Rock Hill Road were Road dark and had strong bituminous smell. 10 34˚45’41.9”N Along US Hwy 72_1 Large limestone 88˚02’27.1”W Hwy #72 on outcrop. Possibly southern edge Bangor limestone of right-of- way 11 34˚36’57.1”N Along US Hwy 72_2 Possibly Observed 87˚27’47.1”W Hwy #72 (Lee limestone on from Hwy) on bottom of opposite northern edge highway cut (or (south) of right-of- covered with side of 4 way concrete façade) lane with sandstone highway on top. On North side of highway west bound lane.
169 Asphaltic Outcrops Identified in GSA Bulletin 1111
Number GSA Description Approximate Township USGS 7.5’ Notes Bulletin Coordinates Range Topo 111 Section Map Table No. 1 A-1.1 Near 34˚43’57.43”N T4S Barton, Al 845 feet south Cherokee, 87˚57’25.63”W R14W of Cove Alabama in S12 Road. Don’t Colbert see access County 2 A-1.2 Near 34˚43’27.82”N T4S Barton, Al 1,689 feet SW Cherokee, 87˚57’5.53”W R14W of Cove Road Alabama in S12 around Colbert hunting green County fields. No access. 3 A-2.1 Near 34˚44’29.78”N T4S Bishop, AL Looks like Margerum, 88˚3’20.42”W R15W access Alabama in S1 available on Colbert south side of County Asphalt Rock Road 4 A-2.2 Near 34˚44’10.71”N T4S Bishop, Al End of what Margerum, 88˚3’24.99”W R15W appears to be Alabama in S12 a dirt road Colbert heading south County at the intersection of Sutton Hill Road and Hwy #3 (Asphalt Rock Rd.) Can’t tell whether the dirt road is private. Looks like old water-filled mining quarries all around the spot. 5 A-3.1 Hartselle, 34˚26’29.77”N T7S Hartselle, Access Alabama in 86˚55’52.16”W R4W Ala doubtful. Morgan S11 Behind County commercial
1 GSA Bulletin 111 did not provide coordinates or USGS 7.5’ series map names. Google Earth used to identify coordinates for GSA Bulletin 111 outcrop location plots and https://ngmdb.usgs.gov/topoview/viewer/#4/40.01/-100.06 used to identify 7.5’ series 1:24,000 scale map names
170 Number GSA Description Approximate Township USGS 7.5’ Notes Bulletin Coordinates Range Topo 111 Section Map Table No. facilities across railroad tracks 6 A-3.2 Hartselle, 34˚26’34.60”N T7S Hartselle, Access Alabama in 86˚55’0.40”W R4W Ala doubtful. Morgan S11 Along a dirt County road at end of Michael Drive SE 7 A-3.3 Hartselle, 34˚26’19.46”N T7S Hartselle, Potential but Alabama in 86˚55’17.89”W R4W Ala questionable Morgan S14 Access. 150 County feet west of McClanahan St. 8 A-4.1 Chestnut 34˚31’50.20”N T6S Trinity, Ala No Access. Grove 87˚0’26.01”W R5W On private Mountain S13 land behind near Flint residential City, areas Alabama in Morgan County 9 A-4.2 Chestnut 34˚31’51.84”N T6S Trinity, Ala No Access. Grove 87˚0’21.73”W R5W On private Mountain S12 land behind near Flint residential City, areas Alabama in Morgan County 10 A-5.1 Caddo, 34˚32’51.92”N T6S Caddo, Ala No access. Alabama in 87˚9’17.19”W R6W Private Lawrence S3 Property County 11 A-5.2 Caddo, 34˚32’21.91”N T6S Caddo, Ala Looks like the Alabama in 87˚9’14.42”W R6W outcrop Lawrence S10 follows the County south side of Hwy #24 right-of-way for a good ways providing some access. 12 A-6.1 Black Wax 34˚37’1.32”N T5S Hatton, Ala A hill top at Hill, Alabama 87˚28’49.26”W R9W end of dirt in Lawrence S16 road that may County be private off Bradford
171 Number GSA Description Approximate Township USGS 7.5’ Notes Bulletin Coordinates Range Topo 111 Section Map Table No. Road. Access unsure. 13 A-6.2 Wolf Springs, 34˚35’47.86”N T5S Hatton, Ala No access. Alabama in 87˚28’46.97”W R9W Looks like Lawrence S21 private County property. 14 A-7.1 Doss Hollow, 34˚36’12.86”N T5S Old Bethel, No access. Alabama in 87˚34’34.15”W R10W Ala Private Colbert S22 property. County 15 A-7.2 Spring Creek, 34˚35’2.37”N T5S Old Bethel, About 1,000 Alabama in 87˚36’15.72”W R10W Ala feet south of Colbert S29 the end of County Bull Skull Hollow Road. Appears to be private property with no access. 16 A-8.1 Rocky 34˚34’39.40”N T5S Russellville, Possible view Branch, 87˚39’14.10”W R11W Ala along Colburn Alabama in S35 Mountain Colbert Road; County however, access may be on private property off the road 17 A-8.2 Littleville, 34˚34’49.35”N T5S Russellville, Possible Alabama in 87˚40’53.35”W R11W Ala Access off Colbert S34 Hwy Right- County of-way 18 A-9 Frankfort, 34˚33’3.65”N T6S Frankfort, No access. Alabama in 87˚50’19.90”W R12W Ala Private Franklin S7 Property County
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