Greenhouse Gas Emissions from Natural Gas Development in Western Canada: A Gap Analysis

Transcription

1 UNIVERSITY OF CALGARY Greenhouse Gas Emissions from Natural Gas Development in Western Canada: A Gap Analysis by Elnaz Senobari Vayghan A THESIS SUBMITTED TO THE FACULTY OF GRADUATE STUDIES IN PARTIAL FULFILMENT OF THE REQUIREMENTS FOR THE DEGREE OF MASTER OF SCIENCE GRADUATE PROGRAM IN CHEMICAL AND PETROLEUM ENGINEERING CALGARY, ALBERTA JULY, 2016 Elnaz Senobari Vayghan 2016

2 Abstract The greenhouse gas (GHG) emissions of conventional and unconventional natural gas are primarily methane and carbon dioxide that are released in natural gas development activities. Addressing these emissions have gained attention because of recent climate commitments. Life Cycle Assessment (LCA) can help to compare different pathways of gas development considering all life cycle stages. The objective of this thesis is to conduct a LCA of GHG emissions of natural gas in western Canada, with a focus on BC`s Montney and Horn River. This thesis presents a gap analysis demonstrating that current public data in Canada is insufficient to characterize the life cycle emissions and highlighted where the data is needed. Preliminary estimates suggest that the average US unconventional gas life cycle emissions are higher than those in Canada but significant variability exists between and within regions of Canada. Future investigation and data collection is required to confirm these preliminary results. ii

3 Acknowledgements Foremost, I would like to express my sincere gratitude to my supervisor, Dr. Joule Bergerson for the continuous support of M.Sc. research, for her patience, motivation, enthusiasm, and immense knowledge. Her guidance helped me in all the time of research and writing of this thesis. Besides my supervisor, I would like to thank Dr. Eduard Cubi for his continuous support and understanding throughout the course of my program. His fruitful advices have always helped and encouraged me through different stages of work. I am also grateful to my committee members Dr. Nashaat Nassar and Dr. Sathish Ponnurangam for accepting to be in my defense committee. I gratefully acknowledge the financial support received from Alberta Energy and the Department of Chemical and Petroleum Engineering at the University of Calgary. Finally, I must express my very profound gratitude to my dear parents, sisters and my beloved husband, Moein, for providing me with unfailing support and continuous encouragement throughout my years of study and through the process of researching and writing this thesis. This accomplishment would not have been possible without them. iii

4 Dedication Dedicated to my husband, my parents, my sisters and my beautiful niece, Parmida iv

5 Table of Contents Abstract... ii Acknowledgement... iii Dedication... iv Table of Contents...v List of Tables... vii List of Figures and Illustrations... viii List of Symbols, Abbreviations and Nomenclature...x INTRODUCTION Problem Statement and Motivation Thesis objectives and Scope Objectives Thesis scope Contributions Thesis outline...11 LITERATURE REVIEW Overview of activities across supply chain of natural gas development Preproduction Production Processing Transmission End use of natural gas Estimates of methane leaks from EDF studies...44 EDF studies production stage...44 EDF studies gathering and processing stages...46 EDF studies transmission stage...47 METHODS Top-down analysis Available data sources in Western Canada Top-down analysis based on publicly available BC data...53 Facility level emission factors...53 Company level emission factors...62 Province level emission factors Bottom-up analysis Preproduction Production Processing Transmission Populating the model Sensitivity analysis in Bottom-up analysis...79 RESULTS AND DISCUSSION...81 v

6 4.1 Top-down results Facility level emission factors...81 Relationship between facility level emission factors and well configuration Company level emission factors...98 Company level emission factors based on individual facilities...98 Company level emission factors based on aggregated format emissions Provincial level emission factors Bottom-up results and discussion Bottom-up results (for BC) Comparison of bottom-up results with top-down and other studies Sensitivity analysis for from a life cycle perspective CONCLUSIONS Considerations for future work REFERENCES APPENDIX A: TABLE OF PARAMETERS USED IN BOTTOM-UP ANALYSIS APPENDIX B: SENSITIVITY ANALYSIS APPENDIX C: COPYRIGHT PERMISSIONS vi

7 List of Tables Table 1-1 Remaining oil and gas resources in Canada... 2 Table 2-1 General characteristics of shale gas studies Table 2-2 Parameters considered in preproduction stage of shale gas studies/reports Table 2-3 Parameter considered in production stage of shale gas studies/reports Table 2-4 Parameter considered in processing stage of shale gas studies/reports Table 2-5 Parameter considered in transmission stage of shale gas studies/reports Table 2-6 Parameter considered in end use stage of natural gas studies/reports Table 2-7 Comparison between EDF study and EPA emission factors Table 3-1 ARC Resources 2013 production data from Montney formation using different sources and methods Table 3-2 Comparison of AltaGas facilities the oil and gas codes data and the facility emissions data Table 3-3 Emissions for the different segments of the oil and gas industry (BC, 2013) Table 4-1 Gas production and rig release dates based on 2013 the well level production data in BC Table A-1 Parameters that were used in Preproduction stage of Horn River formation Table A-2 Parameters that were used in Preproduction stage of Montney formation Table A-3 Parameters that were used in Preproduction stage of BC conventional gas Table A-4 Parameters that were used in Production stage Table A-5 Parameters that were used in Processing stage Table A-6 Parameters that were used in Transmission stage vii

8 List of Figures and Illustrations Figure 1-1 Canadian natural gas production pathways forecast Figure 1-2 System boundaries of stages included in life cycle assessment of natural gas development... 6 Figure 2-1 Normalized Comparison of US LCA Studies on shale gas Figure 2 2 Summarized description of study methods (bottom-up compared with top-down approaches) and emissions estimates methods of US and Canadian LCA studies Figure 2-3 Primary Natural Gas Demand in Canada Figure 3-1 Method C, connection between emissions data and production data on a facility level Figure 3-2 Natural gas Bottom-up emissions estimator model structure used in this thesis Figure 4-1 Central Dehydration facilities emission factors in BC in Figure 4-2 Compressor Station facilities emission factors in BC in Figure 4-3 Gas Plant facilities emission factors in BC in Figure 4-4 Sour Gas Plant facilities emission factors in BC in Figure 4-5 Sweet Gas Plant facilities emission factors in BC in Figure 4-6 Range of emission factors for different facility types in BC in Figure 4-7 Level of emissions in amounts and types of facilities in BC in Figure 4-8 Dispersion of different configurations of wells and their 2013 annual production in northeastern BC Figure 4-9 Range of emission factors for different facilities based on well configuration linked to that facility in BC in Figure 4-10 Company level emission factors for BC natural gas companies Figure 4-11 Emission factors for facilities with emissions reported in an aggregated format Figure 4-12 BC provincial level average emission factor for natural gas in Figure 4-13 BC provincial level emissions intensity from natural gas in viii

9 Figure 4-14 Bottom up results for Horn River, Montney, and BC conventional gas Figure 4-15 Comparison of results from different analyses in this thesis and other studies Figure 4-16 Top six most important parameters for preproduction, production, processing and transmission of natural gas produced in Horn River Figure 4-17 Top six most important parameters for preproduction, production, processing and transmission of natural gas produced in Montney Figure 4-18 Top six most important parameters for preproduction, production, processing and transmission of natural gas produced in BC conventional Figure B-1 Sensitivity analysis of preproduction stage in Horn River Figure B-2 Sensitivity analysis of Production stage in Horn River Figure B-3 Sensitivity analysis of Processing stage in Horn River Figure B-4 Sensitivity analysis of Transmission stage in Horn River. (Same results for Montney and BC conventional gas) Figure B-6 Sensitivity analysis of Production stage in Montney Figure B-7 Sensitivity analysis of Processing stage in Montney Figure B-8 Sensitivity analysis of Preproduction stage in BC conventional Figure B-9 Sensitivity analysis of Production stage in BC conventional Figure B-10 Sensitivity analysis of Processing stage in BC conventional ix

10 Symbol AB AGR BC Bcf CBM CEPEI CH4 CO2 CO2e Comp Stn DOE EIA EPA EUR EF ft GHG G gal GWP H2S hp-hr HR Hr IPCC kg km kwh LCA LNG m m 3 Mg M MJ MMcf NETL NG NPRI N2O US List of Symbols, Abbreviations and Nomenclature Definition Alberta Acid Gas Removal British Columbia Billion cubic foot Coal Bed Methane Canadian Energy Partnership for Environmental Innovation Methane Carbon Dioxide Carbon Dioxide equivalent Compressor Station Department of Energy Energy Information Administration Environmental Protection Agency Estimated Ultimate Recovery Emission Factor Feet Greenhouse Gas Gram Gallon Global warming potential Hydrogen sulfide Horsepower-hour Horn River Hour Intergovernmental Panel on Climate Change Kilogram Kilometer Kilowatt-hour Life Cycle Assessment Liquefied natural gas Meter Cubic meter Milligrams Montney Mega Joule Million cubic feet National Energy Technology Laboratory Natural Gas National Pollutant Release Inventory Nitrogen United States x

11 INTRODUCTION 1.1 Problem Statement and Motivation Natural gas accounted for 33% of total energy produced in Canada in 2014 [1]. Among different production pathways of natural gas, two unconventional alternatives, shale and tight gas 1 are satisfying a growing fraction of Canada s gas production. According to the National Energy Board s (NEB) 2013 forecast [2], shale and tight gas production will grow faster than conventional gas or coalbed methane, largely due to the increase in production in western Canada 2. As shown in Figure 1.1, NEB projects shale gas and tight gas production to account for approximately 28% and 62%, respectively, of total Canadian marketable natural gas by Figure 1-1 Canadian natural gas production pathways forecast 3. CBM: Coal Bed Methane [2] The reasons for the forecasted growth include several factors such as the recent shift from coal to gas for power generation throughout North America and the anticipated increased export 1 For the purpose of this thesis, unconventional gas refers to tight and shale gas only. Other unconventional types, such as coalbed methane, have little production in Canada as compared with these two sources. 2 Since this forecast was released in 2013, it does not include recent changes of gas price that will change this outlook. 3 Copyright permission is attached in appendix C. 1

12 of gas to satisfy increasing demands for energy in the US (for industrial, commercial, and residential needs) 4. However, the ratios of developing conventional and unconventional gas will depend on the costs of production associated with each production type. Comparison between the amounts of remaining types of natural gas and oil (heavy and light oil) in Canada, presented in Table 1-1, shows that the amount of remaining gas in Canada are comparable to those of oil and therefore have the potential bring significant economic revenue to the country. Table 1-1 Remaining oil and gas resources in Canada [4], [5] Resource type TJ Conventional gas Natural gas from coal/coalbed methane Tight gas Shale gas Oil Despite progress in measurements of water use [6], [7] and seismic events [8] [10] (operations have been suspected of causing earthquakes), GHG emissions have received less attention. Understanding and managing these GHG emissions can help researchers in many areas such as scientists and policy makers studying recent climate change commitments [11]. Currently, GHG emissions from the oil and gas industry in British Columbia (BC) are tonnes of CO2e, accounting for 50% of the total GHG emissions in the province. Recent US studies [12] [14], however, have identified activities and emissions levels that challenge our understanding of the source and magnitude of GHG emissions throughout the supply 4 Based on Canada s recent regulations, there will likely be a shift from coal-fired power plants to lower- or nonemitting types of generation, such as high-efficiency natural gas, etc.[3] 2

13 chain of natural gas development. For example, overall emissions estimates of the production stage (i.e. the activities that occur during a producing well s operating lifetime) in these studies are close to EPA (Environmental Protection Agency) estimates, whereas the breakdown of emissions from different activities of production stage differs between EDF and EPA reports (e.g. equipment s fugitive emissions, pneumatic devices emissions etc.). These different emissions estimates and measurements are discussed further in section While these recent measurements have improved the data quality to characterize emissions from US operations, nothing comparable has been developed in Canada. The nature of gas production operations in Canada and US are different. For example, the fate of the dissolved gas in flowback water is different in US and Canada [15]. Flowback water is a portion of injected water in hydraulic fracturing, which is a stimulation process in unconventional gas production. Due to more strict venting and flaring regulations in Canada [16], operators tend to capture these dissolved gases and route them for sale through pipelines instead of venting them to the atmosphere. In addition, the fate of this flowback water (e.g. recycle, reuse, water treatment facilities, injection in deep wells) can be different. The composition of the produced gas differs from region to region as well. For example, higher concentrations of CO2, with an average of 12% in the Horn River formation in northeastern British Columbia, can lead to higher energy consumption in gas processing and thus higher GHG emissions [15]. Natural gas production in the provinces of BC and Alberta (AB) are the focus of this thesis as they make up more than 94% of Canada s gas production (AB and BC produced 4,200 and 1,600 billion cubic feet (Bcf), respectively, out of a total 6,300 Bcf of Canadian natural gas production in 2014) [17]. According to NEB s 2013 forecast [2], over the next two decades, 99% of Canada s total natural gas is expected to be produced in BC and AB. In BC, more than 85% of 3

14 natural gas is produced by unconventional methods and less than 14% is from conventional production 5 [18]. Most of the natural gas in AB is produced from conventional sources, with less than 1% from shale formations [17], [19], [20]. A key difference between shale gas, trapped in shale formations, and tight gas, trapped in sandstone or limestone, is their permeability. Tight gas permeability is approximately 1000 times higher than that of shale gas. However, in general, both have relatively low permeability overall. That is, any trapped natural gas cannot easily move through their respective shale and sandstone/limestone formations. The key difference between unconventional and conventional gas production is in the preproduction stage. Hydraulic fracturing, the technology that led to the shale gas boom in North America, is only deployed to access unconventional resources [21]. In this well stimulation technique, fracking fluid (primarily water with sand and chemicals) is injected at high pressure into a wellbore, creating extensive artificial fractures around the targeted well bores. This method helps trapped gas to flow to the well, thereby increasing production. The second significant difference between unconventional and conventional production is horizontal drilling, as opposed to conventional vertical drilling. Advances in horizontal drilling technology allow a single well to access greater volumes of unconventional gas. Based on a Petroleum Services Association of Canada (PSAC) report, more than 70% of all wells drilled in Canada in 2013 are horizontal wells [22]. Operators inject water and chemicals into wells to create fractures with pumps in fracturing. While less than 1,000 m 3 water per well is used for conventional gas extraction 5 Data is gathered from BC oil and Gas Commission. Copyright permission is attached in appendix C. 4

15 (primarily for drilling activities that use drilling fluid to bring rock cuttings to the surface as well as cooling purposes), 10,000-35,000 m 3 water per well is used and injected in hydraulic fracturing for unconventional wells [7], [23]. This amount of water is associated with additional activities such as transporting water from its typical lake and river source to well sites, in unconventional gas production than conventional. In addition, a fraction of this injected water flowback water flows back up the well during or after the completion of fracturing. Flowback water usually contains dissolved natural gas when coming to the surface; operators vent, flare or capture the gas and send it through the pipeline system. The fate of the dissolved gas is dependent on the regulations and availability of infrastructure in the jurisdiction in which it is produced. Venting and flaring natural gas is highly controlled across Canada. Based on a Canadian Association of Petroleum Producers (CAPP) report, as a result of environmental regulations, Alberta has cut the amount of natural gas flared by 80%, which reduced GHG emissions by more than 8 million tonnes of carbon dioxide equivalent (CO2e) from 1996 to [22]. British Columbia has committed to eliminate all routine flaring at oil and gas producing wells by 2016, replacing it with flaring alternative options such as capturing the gas at the well sites [24]. Of note is that flowback water needs to be treated and reused on site or injected into water injection wells (abandoned wells that are no longer producing). The activities associated with flowback water management bring additional activities for unconventional gas production and are needed to be considered when comparing conventional and unconventional gas productions. The previously discussed elements can lead to different GHG emissions estimates and associated environmental impacts for unconventional (shale and tight gas) and conventional gas production. And different data requirements exist to characterize and differentiate between these natural gas production pathways. 5

16 perspective: As presented in Figure 1-2, natural gas activities fall into five main stages from a life cycle Preproduction Production Processing Transmission Distribution and End Use Upstream Downstream Figure 1-2 System boundaries of stages included in life cycle assessment of natural gas development (for shale, tight, and conventional gas) Preproduction: the activities that occur prior to production from natural gas wells, including well drilling and casing, hydraulic fracturing (for shale and tight gas formations), through to well completion. The GHG emissions from this stage include emissions from the production and transportation of material involved in preproduction (i.e. drilling and casing materials such as carbon steel and cement); emissions from fuel consumption for powering the drilling and fracturing equipment (diesel or natural gas); emissions associated with water delivery trucks and water treatment activities; emissions associated with well completion (flowback fate: vented, flared or captured). Production: the activities that occur during a producing well s operating lifetime, including liquid unloading (removing liquids that impede natural gas flow), workover (occasional maintenance of unconventional wells for re-fracturing formations that improve production rates), the use of pneumatic device such as pneumatic controllers or pumps in gathering systems to control pressure, temperature, liquid level, injecting chemicals, and other activities. The GHG emissions from this stage includes emissions from re-fracturing and 6

17 workover activities; emissions associated with pneumatic devices used to control natural gas levels and flow in the gathering system; emissions from liquid unloading operations; emissions related to fugitive emissions as well as operating and maintenance leakages from all equipment that might be captured and flared. Processing: the operations required to remove impurities from raw natural gas (i.e. natural gas as it is produced from a well) that can cause problems such as corrosion in pipelines. Impurities such as H2S, CO2, water, and condensate are removed from natural gas to meet pipeline quality specifications. For example, TransCanada Corporation allows a maximum of 23 and 65 mg/m 3 of H2S and water in their pipeline, respectively [25]. Acid gas removal (AGR) units (removing H2S and CO2 from natural gas) and dehydration units are examples of process units. The GHG emissions from this stage include emissions from AGR (also called sweetening) operations; emissions from gas dehydration operations; emissions related to fugitive emissions and operating and maintenance leakages from all equipment that may or may not be captured and flared in the gas processing activities; emissions from compressor stations (both fugitive emissions and the combustion of fuel). In this thesis, preproduction, production and processing stages are considered upstream stages. Transmission: the activities to transport natural gas from producing regions to the entrance gate of large industrial customers, such as power plants. Compressor stations (compressing natural gas to enhance its flow over long distances) and pipeline systems are the key transmission components. The GHG emissions from this stage includes fugitive emissions from the pipeline across the pipeline network; emissions from fuel use in the transmission system (gas combusted to fuel the compressor stations); emissions related to pipeline construction (e.g., diesel use). 7

18 Distribution and end use: the stage in which natural gas is distributed and is consumed by final end users (called downstream operations; operations after transmitting gas to the entrance gate of large industrial customers, such as power plants). These operations are mostly associated with electric power generation for industrial, commercial and residential use in North America [26]; all involve combusting or processing natural gas for different services (e.g. power generation, fuel for steam generation, feedstock in production of petrochemicals, space heating, hydrogen production etc.). In the focus of this thesis is on understanding the GHG emissions of upstream and transmission stages, as they have not been explored in detail for western Canadian gas development. Emissions from downstream operations have been discussed extensively in other studies [27] [32]. 1.2 Thesis objectives and Scope Objectives The key objective of this thesis is to provide insights about the GHG emissions emitted as a consequence of natural gas development across the supply chain, with a focus on development in British Columbia and Alberta. Three specific goals help to achieve this objective. First, a gap analysis identifies data needs by identifying the gaps in both the knowledge and data necessary to assess the full life cycle GHG impact of western Canadian natural gas. Second, a top-down analysis is performed, matching publicly reported GHG emissions data and production data in western Canada to estimate the emissions intensities on the facility, company and provincial levels. Third, a bottom-up analysis is conducted, using a model adapted from the US Department of Energy s (DOE) National Energy Technology Laboratory (NETL) GHG emissions model for natural gas 8

19 production in the US [33]. With assistance from this model, GHG emissions are estimated using a first principles approach and data from actual operations within western Canada Thesis scope A full life cycle assessment, including all sources of GHG emissions associated with the preproduction, production, processing, transmission, and end use, is necessary to estimate the GHG footprint of natural gas. In this thesis, the greenhouse gases considered are methane (CH4), carbon dioxide (CO2), and nitrous oxide (N2O). The largest shale and tight gas producing regions in Canada are chosen as the targets of this thesis: Horn River, a shale-only formation located in northeastern BC and Montney, a shale, tight and conventional gas region, spanning northeastern BC and western AB. The sources of GHG emissions considered in this thesis for upstream and transmission are mentioned in problem statement (1.1) where different stages of supply chain of natural gas are discussed. The GHG emissions associated with producing cement and steel (used in natural gas wells and pipelines) are considered in this thesis, while emissions related to building equipment such as boilers or compressors along with the emissions related to constructing gas plants are out of this thesis scope. During natural gas processing, water evaporation to the atmosphere will happen, which can be assumed as another environmental impact of natural gas. However, comparing the amount of water released in natural gas processing with the water that is released to the atmosphere on the global scale shows that the evaporated water does not have an impact on climate and can be assumed insignificant and is out of this thesis scope. 9

20 It should be mentioned that among all impact categories that fall within a typical life cycle assessment scope (such as global warming potential (GWP), acidification potential, eutrophication potential, and photochemical oxidant creation potential [35]), this thesis only includes global warming potential associated with GHG emissions. The other impacts, however, could be determined in future research. 1.3 Contributions This thesis provides insights about the GHG emissions of natural gas development in Canada. Gap analysis results help to explore the gaps in both literature and public datasets to analyze natural gas GHG emissions in the western Canadian context. The top-down analysis contributes to more informed estimates of GHG emissions on a facility, company and province levels that can be used for future performance evaluations for individual industry members in Canada and the US for benchmarking purposes. The bottom-up analysis developed in this thesis, adapted from a NETL model, is the first attempt to characterize GHG emissions of Canadian natural gas in a detailed way. This can be used as guidance for future analysis once data gaps have been addressed. The top six most important parameters, based on the stages of preproduction, production, processing, and transmission on GHG emissions of natural gas development, are gathered as the result of a sensitivity analysis. These results can further guide future studies by prioritizing parameters that need more reliable values. These parameters can affect the variability and uncertainty of GHG emissions across different projects/companies and over time. 10

21 1.4 Thesis outline Chapter 2 of this thesis includes background on previous LCA studies with respect to natural gas production. A comprehensive literature review is also provided in chapter 2. Chapter 3 describes the methods developed and used in this thesis. Chapter 4 presents the results, discussion and sensitivity analysis. Chapter 5 discusses the conclusions and provides recommendations on data needs and future research on the life cycle impacts of gas development. 11

22 LITERATURE REVIEW Several studies have been conducted in the US, over the past 10 years, to assess GHG emissions from unconventional gas using a life cycle perspective, including: Howarth et al. [36], Jiang et al. [37], Venkatesh et al. [38], Hultman et al., Skone et al. [33], [39] (two reports in 2011 and 2014), Stephenson et al.[31], Burnham et al.[40], and Laurenzi et al. [41]. Since the focus of the unconventional gas in these studies was shale gas (except for one study [36], no other LCA study on tight gas were found) this chapter reviews shale gas studies across the US and Canada. The motivation for most of these US studies is the significant growth of shale gas in the past ten years, the potential for changes to climate policies at a national and international level, understanding the uncertainty and variability of life cycle GHG emissions of US shale gas compared to conventional gas and life cycle emissions for power generation. Hultman et al. argued that the exploitation of unconventional gas resources, such as shale, can affect several contexts: change energy security, shift trend in GHG emissions, and change the economics of energy investment decisions [29]. The studies include GHG emissions estimates associated with production, processing, transmission, and end use (e.g. combustion stage) of natural gas, while the preproduction stage is discussed in all but Howarth et al. [36] and Hultman et al. [29]. The level of detail of activities included for each life cycle stage varied across the studies. Howarth et al. [36] and Hultman et al. [29] only investigated GHG emissions as one of the environmental impacts of shale gas production, while other studies included both GHG emissions and water consumption as implications of shale gas development. 12

23 g CO2e / MJ Natural gas Analyzing large scale energy systems, such as shale gas development, that includes comparison between previous and current LCA studies, is challenging. The LCA studies can differ in terms of their goal and scope, system boundaries, inclusion or exclusion of specific activities, geographic location of the studied reservoir, types of extraction methods, gas composition, modeling approaches, and data sources used. The effect of these parameters on the differences across US studies results are not the same (e.g. extraction methods had greater impact on differences compared with gas composition). Figure 2-1 presents a summary of the results from these US LCA studies. Note that Skone et al. published two individual reports, in 2011 and 2014, and both of their results are presented in this figure. The differences between the studies is related to the production activities considered, specific assumptions and data used. For example, assumptions about workover emissions differed greatly from study to study (workover frequency per well lifetime was assumed to be 3 in 2011 study, compared with 0.3 in 2014 study 6 ) preproduction production and processing transmission Figure 2-1 Normalized Comparison of US LCA Studies on shale gas Normalized means considering consistent boundary conditions between studies (i.e. not all the activities within each stage are exactly the same across all studies). Sources: Howarth et al. [36], Jiang et al. [37], Venkatesh et al. [42], 6 A frequency of 0.3 means only one out of three wells will have a workover once in its lifetime. 13

24 Hultman et al. [29], Skone et al. (2011) [39], Stephenson et al. [31], Burnham et al. [40], Laurenzi et al. [41], Skone et al. (2014) [33], and ICF [43]) While figure 2-1 shows a range of estimates of 8.4 to 26.7 g CO2e per MJ natural gas, five of these studies (Jiang et al., Hultman et al., Skone et al. (2011), Burnham et al., and Laurenzi et al.) have GHG emissions estimates that are within 19% of each other (from g CO2e per MJ natural gas). The key difference between these studies is in the assumptions regarding study boundaries. The lower estimates of Stephenson et al. and Skone et al. (2014) are due to smaller emissions estimates related to workover activities. Stephenson et al. did not consider workover emissions in their base case 7 result and Skone et al. lowered the number of times that wells were assumed to require workovers during their lifetime compared to their 2011 report. Weber et al. [44] concluded that most of the data used by many of these studies came either from the same source, such as the US EPA [45], or specific operational values for different basins, such as the Marcellus or Barnett shale gas formations. Another reason for differences stems from combining EPA values with actual operation data for different regions and at different times. The US studies also drew varying conclusions about the climate implications from the use of different pathways of natural gas and coal. These conclusions, discussed in different reviewed US studies, include: Shale and conventional gas having higher life cycle GHG emissions than coal [36], Shale gas having less GHG emissions than coal but greater GHG emissions than conventional gas [37], [29], [31], [41], [33], 7 Base case in this thesis refers to the expected case of the model using the assumptions that management deems most likely to occur. The results for your base case should be better than those for your worst (conservative) case but worse than those for your best case. 14

25 Conventional gas having higher GHG emissions than shale gas, while both have less than coal [40]. Below is a brief description of these LCA studies with regard to the conclusions they drew. Only one study suggested the first conclusion: a controversial study (claimed to be controversial by [46], [47]) published by Howarth et al. of Cornell University [36], concluding that shale gas can have a larger climate impact than coal. In this study, the authors claimed that shale gas has % higher life cycle GHG emissions than coal on a 20-year time horizon. The difference between the Howarth et al. study and the remaining US studies can be explained considering the following notes. First, using a 20-year time horizon (which is the period during which the impacts are considered (i.e. a molecule of methane will have a larger impact over the first 20 years after emissions compared to 100 years after it is emitted)). is one important reason why the values of Howarth et al. differ from the rest of the US studies. This is due to the fact that the global warming potential (GWP that are based on comparing the amount of heat that is trapped by a certain mass of GHG emissions in relation to the same mass of CO2) of Methane is 72 on the 20-year time horizon as compared with 25 in the 100-year time horizon (which is assumed in the US studies). It should be noted, however, both of these GWPs are relevant and many other studies also used 72 as the GWP of methane [13]. The most updated IPCC (Intergovernmental Panel on Climate Change) report updated GWP of methane to be 86 on the 20-year and 34 on the 100-year time horizons [48]. Second, methane emissions during the extraction process, especially the amount of methane that is vented during well completion in flowback activities, are overestimates, based on other US studies [30], [33]. Howarth et al. calculations lead to an overestimate since they did not assume any flaring or industry control technologies in well completion emissions. Also, in transmission emissions, they used Russian pipeline data which is not applicable for most of the 15

26 US transmission system as discussed by Ridley [49]. In addition, the authors fail to consider the greater generating efficiency of gas than coal. This study initiated debates about whether natural gas from shale resources is a cleaner source of energy than coal when their full life cycle emissions are taken into account [46]. Hultman et al.[29] and Skone et al. [33] claimed to be motivated to assess these conclusions. Five different studies suggested the second conclusion. Jiang et al. [37], Hultman et al. [29], Stephenson et al. [31], Laurenzi et al. [41], and Skone et al. [33] estimated that shale gas has life cycle GHG emissions approximately 3%, 11%, %, 1.2%, and 3.3% higher than conventional gas, respectively. Except for Hultman et al., the others discussed that this difference is within the uncertainty associated with the LCA studies. The five studies concluded that the GHG footprint of shale gas is approximately 35-50% lower than that of coal and replacing coal-fired power generation with gas fired power generation can substantially reduce GHG emissions. One study drew the third conclusion: Burnham et al. [40] found that the emissions from conventional gas production were 6% higher than for shale gas production. It should be noted that Burnham et al. indicated that the difference between shale gas and conventional gas emissions fell within the study s uncertainties. This study concluded that shale gas has 33% lower emissions when compared with coal. The Environmental Defense Fund (EDF) coordinated and funded a group of researchers to investigate the magnitude and sources of methane emissions across the supply chain of natural gas [50]. By using both bottom-up (measuring emissions from the source of specific activities and adding all the emissions from different sources to estimate the total emissions) and top-down techniques (using ambient methane concentration measurements to estimate emissions for different stages), the studies, while not considered comprehensive from a LCA perspective, 16

27 provided insight for improving data quality that can, in turn, be incorporated into LCAs. Due to the differences in the scope, boundaries and the structure of presenting the results between these studies and previous US studies, EDF studies are discussed in a separate section (Section 2.1.6). As discussed by Tyner and Johnson [51], while many operations and activities are likely to be similar in US and Canadian industries, some specific activities and operations vary by region. Thus, natural gas GHG emissions in a Canadian context are likely to be different from US. Only a few reports are available that assess unconventional (mostly shale) gas GHG emissions in Canada. Natural Resources Canada used the GHGenius model [15] to estimate the GHG impacts of shale gas production and compare it to conventional gas. This model considered the high concentration of CO2 (with an average of 12%) in Horn River and estimated nearly double the emissions per MJ of gas produced from that locale as compared with Montney in the upstream stages (13.2 for Horn River compared with 6.8 for Montney both in g CO2e / MJ natural gas). Tyner and Johnson evaluated GHG emissions associated with all unconventional gas wells (drilled and completed in 2011), in Alberta, that used hydraulic fracturing as the well stimulation method [51]. This study was limited to preproduction and a fraction of production stages of the natural gas life cycle. In addition, ICF International prepared a Canadian analysis in 2015 for Pembina Institute that highlighted the opportunities to reduce the methane emissions from oil and gas industries [52]. This study focuses on the cost analysis associated with several emissions reduction opportunities. They looked at emissions in 2020 and concluded that 45% of methane emissions reduction is achievable with existing technologies and techniques. This study however, used EPA values for parts of their analysis, for example completion and workover emissions, which were challenged by recent EDF studies. Canadian literature still suffers from the lack of 17

28 sufficient data on GHG implications of unconventional gas development as compared with what has been reported in the US. 2.1 Overview of activities across supply chain of natural gas development In the following section, all of the activities and parameters considered in different studies are discussed. Most of the studies conducting LCA on natural gas GHG footprint address: preproduction, production, processing, transmission, and distribution/end use. Not all studies discussed all of these stages in their analysis since each study had a unique boundary and scope. In this thesis, all assumptions and boundaries were used to construct the best estimate of the data available in US studies. Different attempts are made to reconcile the available data. For example, the average Estimated Ultimate Recovery (EUR) of the wells, across the US studies, is used for those studies that do not include production rates such as Hultman et al. or Tyner and Johnson study [29], [51]. Average well lifetime is used to estimate emissions per well lifetime for those studies that present results on an annual basis. Another example is considering an average US gas composition for those studies that stated their result in volume of natural gas (not methane or carbon dioxide). Some of the studies included the distribution stage and others did not, given their different scopes. The distribution stage in all upstream calculations is removed to create an even comparison for the end use of power plant combustion. Canadian related data are gathered and reviewed along with US data to show which parameters are missing or which are inadequately described compared what has been done in US. The forthcoming tables (Tables 2-1 to 2-6) summarize these studies. Figure 2-2, presents the schematic of life cycle stages and the methods that were used in US and Canadian LCA studies. As seen in this figure, different approaches were used by different studies such as top-down 18

29 compared with bottom-up. Also, this figure presents emissions estimates methods such as using first principle estimates (i.e. estimating emissions based on processed based approach using engineering calculations), sample data or process stimulations methods (i.e. engineering software). Life cycle stage Jiang et al. Skone et al. (NETL) US studies (all LCA studies) Burnham et al. Laurenzi et al. Howarth et al. Hultman et al. Stephenson et al. Canadian LCA studies Tyner and Johnson GHGenius model Bottom-up / Top-down Topdown Bottomup Bottomup Topdown Bottom-up Bottomup Topdown Topdown Bottomup Bottomup Bottomup Preproduction EIO-LCA First Principle estimates First Principle estimates First Principle estimates First Principle estimates Sampling data First Principle estimates First Principle estimates First Principle estimates Sampling data First Principle estimates Sampling data First Principle estimates Sampling data Production First Principle estimates First Principle estimates Sampling data First Principle estimates First Principle estimates Sampling data First Principle estimates First Principle estimates First Principle estimates First Principle estimates Sampling data First Principle estimates Processing First Principle estimates First Principle estimates Sampling data First Principle estimates First Principle estimates Process simulation First Principle estimates First Principle estimates First Principle estimates - First Principle estimates Transmission First Principle estimates First Principle estimates First Principle estimates First Principle estimates Process simulation First Principle estimates First Principle estimates First Principle estimates - First Principle estimates End use First Principle estimates First Principle estimates First Principle estimates First Principle estimates First Principle estimates First Principle estimates First Principle estimates - First Principle estimates Figure 2-2 Summarized description of study methods (bottom-up compared with top-down approaches) and emissions estimates methods of US and Canadian LCA studies Table 2-1 summarizes the unconventional gas types (shale or tight gas) and studied reservoir (if applicable) that were considered in different studies, as well as their EUR, key data 19

30 sources, and methane content assumed. Methane content and EUR are the two important parameters that can greatly vary from one reservoir to another and affect the life cycle emissions results (two of the reasons for discrepancies in US studies). The following tables present activities of each stage of the life cycle (preproduction, production, processing, transmission, and end use) for seven US LCA studies [29] [33], [36], [41], [42] and two Canadian LCA reports/studies [15], [53]. 20

31 Table 2-1 General characteristics of shale gas studies Parameter Unconventional gas type Estimated Ultimate Recovery (EUR) Methane content of raw gas Unit - Bcf /well molar percent Key data source - Jiang et al. a Marcellus shale Skone et al. (NETL) Marcellus shale US studies (all LCA studies) Burnham et al. b EUR: well-weighted average of Marcellus, Barnett, Haynesville, Fayetteville shales; emission factors for generic unconventional B M F H Base case 3.5 Laurenzi et al. Marcellus shale Howarth et al. Production: shale (Haynesville, Barnett)and tight (Piceance, Uinta); indirect emissions : Marcellus Hultman et al National average unconvention al Stephenso n et al. US shale gas Canadian studies/reports Non LCA LCA studies studies Other Canadian reports c Tyner and Johnson Tight, shales and CBM gas that were drilled in 2011 in Alberta GHGenius model Not clear d N/A e 2 N/A 25 f 2-6 M g 3-19 HR h N/A HR i EPA[57] Primary data collection EPA[57] Primary data collection EPA[57] EPA[57] Primary data from XTO operations EPA[57], GAO[58] EPA[57] EPA[57] Primary data collection Primary data collection CAPP [59] - a Jiang et al. covered preproduction phase and for the rest of the stages they used Venkatesh et al. values [42] b In the Burnham et al. report values please note: B stands for Barnett, M stands for Marcellus, F stands for Fayetteville, H stands for Haynesville formation c The Values are not read from a single Canadian LCA report. Every value contains the source that was read from. d Some of their analyses are based on two drilling operations in Horn River and most of their values are based on conventional production in Canada e Not available in the study f Based on two drilling operations, not any discussion on how representative these data assumed g M stand for Montney. Reference: Terra energy report, Montney asset [54] h HR stands for Horn River. The range was reported from two separate reports: Terra energy report, Montney asset [54] and Horn River & Greater Sierra [55] i HR stands for Horn River. Reference: Horn River Atlas [56] 21

32 Table 2-1 shows that not all of the US studies considered similar gas types. Marcellus shale gas was the focus of three of the US studies. Other studies focused on different unconventional gas resources: Howarth et al. included both tight and shale gas and Hultman et al. studied unconventional gas. Different shale formations across the US were considered in Burnham et al. and Howarth et al. studies. Burnham et al. evaluated emissions for Marcellus, Barnett, Haynesville, and Fayetteville formations, and Howarth et al. focused on Barnett and Haynesville shale gas formations. On the other hand, Stephenson et al. used US shale gas without specifying any shale formation. Different plays or sets of plays affected two important characteristics of the basins: EUR and gas compositions, as shown in Table 2-1. The table also illustrates the key data sources for each study: EPA values were the main data sources for all of the US studies, however, four of the studies supplemented the EPA values with primary data collection. In Canada, Tyner and Johnson reviewed emissions from tight, shale and coalbed methane gas wells drilled in Alberta in 2011 (data of tight gas and shale gas from this report were considered since they are more relevant to this thesis). This study used well level emissions data from different companies in Alberta, which are not public. It, however, did not provide emissions estimates for all of these well types on a similar level. For example, because Tyner and Johnson evaluated emission factors based on primary data collected from 1334 tight gas wells, 580 coalbed methane gas wells, and 20 shale gas wells (all in AB); tight gas wells received more detailed discussion than did the other two. Production estimates associated with the wells studied were not included; therefore, the EUR of the wells studied is not clear in this report. This study only investigated emissions associated with preproduction and a fraction of production stages, as opposed to the overall upstream and transmission stages which are the focus of this thesis. 22

33 The GHGenius model relied on information from two drilling operations, without explicitly stating details, such as the type and number of wells. These two drilling operations also provided production rates 17. Some of their analysis, such as EUR estimates, are based on these two operations in Horn River. The EUR estimates in Canada, especially in Horn River, are considered to be greater than those in the US (Table 2-1 s footnotes show the references for the Canadian studies). Assumptions about flaring and venting without clear calculation or data to support these assumptions were also evident. This model relies primarily on data from a CAPP (Canadian Association of Petroleum Producers) 2004 report [59] which considered emission factors for the oil and natural gas industry based on data from Therefore, CAPP estimates (and some values used in GHGenius model) are for conventional natural gas production rather than shale gas, since shale gas production in Canada did not start to grow significantly until after 2007 (Figure 1-1). The energy consumption associated with processing the natural gas is estimated to range from 1% to 4% of produced gas in the model. For shale gas, they assumed 3.5% of produced gas was used for energy demands on site which is close to their conventional gas production value (3.2%) Preproduction The preproduction stage includes all the activities that should be completed before natural gas wells start producing. These activities include: well drilling and well construction (include well casing), hydraulic fracturing, water treatment/disposal (water used for fracturing), flowback treatment (depending on the fate of the dissolved gas in the flowback water during hydraulic 17 As discussed by GHGenius, these 2 production rates were much higher than the average production used in their conventional model (eight times higher than the 2000 production rate and eighteen times higher than the average 2010 production rate). 23

34 fracturing), and completion. Completion encompasses emissions occurring during the development of a well, before natural gas recovery, and other equipment being installed at the wellhead (mostly emissions related to adjusting the reservoir s pressure). Table 2.2 summarizes the parameters included or missing in reports that are relevant to shale gas GHG emissions [15], [29], [31] [33], [36], [37], [41], [42], [53]. This table categorizes individual activities in the preproduction stage that were discussed in relevant reports by using seven sub stages. These sub stages are separated with dash lines in Table 2-2. Each sub stage is further broken down by individual parameters discussed in at least one study. 24

35 Table 2-2 Parameters considered in preproduction stage of shale gas studies/reports Sub stage name Parameters included in the sub stage Unit Jiang et al. a Skone et al. (NETL) US studies (all LCA studies) Burnham et al. b Laurenzi et al. Howarth et al. Hultman et al. Stephen son et al. Canadian studies/reports Tyner and Johnson LCA studies GHGenius model Non LCA studies Other Canadian reports c 1. Well pad d construction Cost $/well pad 3 million 3.5 million N/A e N/A N/A 2. Well drilling Vertical Depth ft N/A f N/A Lateral Depth ft N/A N/A Total Depth ft Penetration Rate ft./hr Drilling Rig Capacity N/A hp N/A Shale gas Tight gas N/A g h i N/A Drilling Time hr hr. to several month N/A a Jiang et al. covered preproduction phase and for the rest of the stages they used Venkatesh et al. values [30], [42] b In the Burnham et al. report values please note: B stands for Barnett, M stands for Marcellus, F stands for Fayetteville, and H stands for Haynesville formations c The Values are not read from a single Canadian LCA report. Every value contains the source that it was read from. d Well pad is the area that has been cleared for drilling rig. Well pad can include one or more individual wells. e Not available: parameter was not included in the report f Values are for Montney source: Annex B: Shale Resources Compendium, Responsible Shale Development: Enhancing the Knowledge Base on Shale Oil and Gas in Canada, Energy and Mines Ministers Conference, Yellowknife, Northwest Territories August 2013 [60] g Data based on one drilling activity h Values for Horn River, source: A Primer for Understanding Canadian Shale Gas. Calgary by National Energy Board [61] i Values for Montney, source: A Primer for Understanding Canadian Shale Gas. Calgary by National Energy Board [61] 25

36 Sub stage name Parameters included in the sub stage Unit Jiang et al. a Skone et al. (NETL) US studies (all LCA studies) Burnham et al. b Laurenzi et al. Howarth et al. Hultman et al. Stephen son et al. Canadian studies/reports Tyner and Johnson LCA studies GHGenius model Non LCA studies Other Canadian reports c 2. Well drilling (continued) 3. Drilling mud production 4. Pumping in hydraulic fracturing 5. Water manageme nt (water used in hydraulic fracturing) Diesel use for drilling Diesel Emissions Factor Liter diesel/well g CO 2 e /hp-hr B j k M l F H N/A m N/A Cost $/well 1100 N/A Hydraulic Equipment Horsepower Duration of Fracturing Water Consumption hp 34,150 n N/A N/A o N/A hr 10 to MM litre p /well B M F H N/A 4 N/A N/A N/A N/A N/A N/A 83 HR qr 8.3 M HR s M j In the Burnham et al. report values please note: B stands for Barnett, M stands for Marcellus, F stands for Fayetteville, and H stands for Haynesville formations k Includes diesel fuel requirements for on-site activities and transportation burdens for diesel and water for all four formations in the Burnham et al. study l Data are based on 26 wells that were drilled and produced by XTO energy (a subsidiary of ExxonMobil). The range is: gallon per well (30000 is their average point) m Based on applying the diesel usage factor of m 3 diesel / m-drilled that was used in this report n Stewart & Stevenson and MTT are the fracturing equipment providers in Jiang et al. report o Burnham et al. provided total energy consumption for pumping in the form of electricity consumption from kwh/well p MM litre is million litre q A presentation by Kevin Heffernan, Hydraulic Fracturing and Oil and Gas Development November, 2013 [62] r HR stands for Horn River and M stands for Montney. s Johnson et al.[7] 26

37 Sub stage name 5. Water Management (water used in hydraulic fracturing) - continued Parameters included in the sub stage Recycle Factor (RF) Flowback Fraction Distance that tracks use for water management Load of transportation Unit Jiang et al. a Skone et al. (NETL) % % km Litre-km 426 million 390 million US studies (all LCA studies) Burnham et al. b B t 20 M 95 F 20 H 0 B 275 M 20 F 25 H 90 B 27 M 100 F 65 H B million 18 M million 225 F million H 628 million Laurenzi et al. 30 Howarth et al. N/A Hultman et al. Stephen son et al N/A million Canadian studies/reports Tyner and Johnson LCA studies N/A GHGenius model Non LCA studies Other Canadian reports c 20 u N/A Diesel used for hydraulic fracturing (both transportation and pumps) Litre diesel /well N/A B M F H v Tight gas Shale gas w t In the Burnham et al. report values please note: B stands for Barnett, M stands for Marcellus, F stands for Fayetteville, and H stands for Haynesville formations u Johnson et al. [7] v Data are based on 26 wells that were drilled and produced by XTO energy (a subsidiary of ExxonMobil). The range is : gallon per well (24000 is their average point) w Data based on just one drilling; the high amount is due to long drilling depth 27

38 Sub stage name Parameters included in the sub stage Unit Jiang et al. a Skone et al. (NETL) US studies (all LCA studies) Burnham et al. b Laurenzi et al. Howarth et al. Hultman et al. Stephen son et al. Canadian studies/reports Tyner and Johnson LCA studies GHGenius model Non LCA studies Other Canadian reports c 6.Fracturing additives Cost of additives $ per well 630,000 N/A N/A N/A 7.Well completion Methane emissions x Flaring rate at well sight Tonnes of methane /completion of a well 11 With Pipeline in Place 140 Without Pipeline in Place (177) y ( ) Tight gas z N/Aaa 14 bb % 15 N/A N/A N/A x This is the amount assumed to be vented, some of the studies used a flaring rate at the well sites that can affect overall GHG emissions (since flaring produces CO 2 instead of CH 4, and because CH 4 has greater global warming potential on the environment, flaring instead of venting would decrease overall emissions over time) y This value was read from their sensitivity analysis result from Figure S9 in their supplemental information report z This value is for tight gas; no value was specified for shale gas. However, since both shale gas and tight gas were stimulated in this report with hydraulic fracturing, I present their estimates for well completion emissions for tight gas to give a range of this parameter in Alberta aa This report discussed that US EPA estimates are not applicable to Canada but no specific value is defined for Canadian operations. bb Canadian Association of Petroleum Producers (CAPP) report (2004) [59] 28

39 A review of Table 2-2 illustrates the following key points about the preproduction stage in the available US and Canadian literature. First, not all the US studies considered this stage to the same degree of detail. Four of the studies (Jiang et al., Skone et al., Burnham et al., and Laurenzi et al.) used a very detailed approach to represent this stage. For instance, while all of these studies considered well completion emissions, activities associated with hydraulic fracturing did not gain similar attention across all US studies. Three main activities contribute the most to total preproduction emissions: diesel use for drilling, diesel use for hydraulic fracturing (both pumping and water management transportations), and completion emissions. All of these activities are particularly site specific. For example, if the values of diesel use for drilling are compared across the US studies, a broad range, from 30,000 to 325,000 litres of diesel/well is observed. This broad range can have several explanations: different assumptions for depth of drilling, different formations assumed for each study, and different boundaries of activity in one of the studies (see footnote k of Table 2-2). The US and Canadian values are comparable in diesel use for drilling (available Canadian range is within the US range), but they are different in diesel use for hydraulic fracturing and well completion emissions. For diesel use in hydraulic fracturing, Canadian reports included a broad range of ,000 litres diesel/well. The corresponding GHGenius value, of 520,000 litre/well, is based on one operation in Horn River and is associated with a well-length of nearly 20,000 ft. Tyner and Johnson did not state the length of the shale gas wells. Furthermore, well completion methane emissions are the only parameter discussed in all of the studies. Most of the US studies rely on EPA values from a 2010 report [57]. This report provided emission factors for completions of both conventional and unconventional wells. Some notes to consider when comparing this activity across different studies are discussed as follows: 29

40 o Howarth et al. s high emissions estimates for this activity are due to the assumption that all of the reported released methane is vented directly to atmosphere. o Jiang et al. is the only study that developed emission factors based on the scenario of having required infrastructure and the ability to capture the gas on the well site, compared with the scenario of only venting (with a portion being flared) in well completion. o When comparing US and Canadian values, it should be noted that based on the GHGenius model, the EPA emission factors do not appear to present current practices of Canadian gas production. GHGenius claims that no venting occurs during well completions in the Horn River area. If gas exists in the flowback, it will be either captured and flared or transmitted to the processing facilities. This claim is consistent with the regulations in BC, which prevents venting in this province. The GHGenius model, however, does not include any specific values for the case that gas is flared, although flaring operations generate GHG (mainly CO2) emissions. Yet, flaring activity is not a common practice in BC. o The reason for the discrepancy in methane values emitted during well completions for Hultman et al. and other studies (i.e. Skone et al., Burnham et al., Laurenzi et al., and Stephenson et al.) is that Hultman et al. assumes EPA factors represent natural gas rather than methane. This means that Hultman et al. incorporated a methane mass fraction in the EPA estimates. o Canada is lacking updated numbers for well completion emissions. CAPP s values for well completion are based on 2000 data, which are related to conventional gas operations. While Tyner and Johnson developed estimates for tight gas wells (not shale gas wells), completion emissions from shale gas wells in Canada remains one of the gaps in available data. 30

41 Furthermore, Jiang et al. is the only study that included cost estimates. They used a hybrid combination of process activity emissions estimates and economic input output LCA (called EIO- LCA) in their report. This economic input-out model was developed in the US and includes approximately 490 sectors (industry input-output model) of the US economy. Relevant components of EIO- LCA model with regards to unconventional gas production is not available in Canada. Additionally, water treatment activities are not treated at the same level of detail in all of the US and Canadian studies. Some key points to consider when comparing this activity across different studies are: Howarth et al. and Hultman et al. s studies did not include any parameters associated with this sub stage. According to Johnson et al., water that is needed for hydraulic fracturing differs in Horn River and Montney [7], due to the different hydraulic fracturing techniques in these two regions. The common practice in Horn River is slick water, which needs a larger amount ( million gallons per well) of water in hydraulic fracturing than other techniques. Energized treatments, which use less water ( million gallons per well) and are aided by compressed gases, such as N2 in fracturing, are widely used in Montney [7]. No data about transportation associated with water management (e.g. distance, truck loads, truck fuel efficiency, etc.) were found in Canada. It is not clear whether assuming similar distances in Canada and US for all of the transportation activities in the preproduction stage would be fair and therefore, this is another gap in Canadian data. 31

42 Variations in equipment types in the US and Canada need further investigation. For instance, the types of pumps and trucks and their fuel types (diesel vs. gas), used in Canada, should be carefully studied. The most important conclusion drawn from Table 2-2 is that preproduction emissions estimates are largely site specific, depending on the jurisdiction and formation Production The production stage of natural gas includes several activities: liquid unloading, gathering equipment, and workover operations, which are necessary when wells need to be cleaned (mostly of sand) or to increase production. The stage also presents varying emissions sources, from fugitive emissions that cannot be captured (fugitive emissions from wellheads, heaters, separators, etc.), to venting (such as pneumatic devices), flaring and combustion emissions from equipment. Workover operations are an episodic emissions source and, depending on the corresponding well, they can occur from zero to several times in the well s lifetime. In the case of shale gas formations, hydraulic fracturing is used in workover activities to re-stimulate natural gas formations. Liquid unloading, one of the most variable parameters determining production emissions, is the process of removing fluids, such as water or other liquids (natural gas liquids) that have accumulated over the lifetime of a gas well and lead to reduced production. Well cleanup procedures, such as beam lifts, plunger lifts, or well blowdowns, can be used to remove accumulated fluids [51]. Table 2-3 summarizes parameters used in the production stage of shale gas development. Similar to Table 2-2, sub stage components of the production stage are separated with dash lines. 32

43 Table 2-3 Parameter considered in production stage of shale gas studies/reports Sub stage name Parameters included in the sub stage Unit Jiang /Venkatesh et al. Skone et al. (NETL) Burnham et al. US studies Laurenzi et al. Howarth et al. Hultman et al. Steph enson et al. Canadian studies/reports Tyner and Johnson GHGenius model 1. Methane venting, leaking or fugitive emissions 2.Emission from flaring Includes emissions from Pneumatic devices and equipment leaks All GHG emissions (CO2,CH4, N2O) Tonnes of CH4 / well lifetime Tonnes of CO2e / well lifetime 787 a b negligible c 1625 N/A 1490 N/A d N/A e 3 Fuel combustions CO2 from equipment Tonnes ofco2 / well lifetime 362 N/A N/A f 4. Workover 5. Liquid Unloading CH4 venting Number of workovers during the lifetime of well Venting natural gas Tonnes of CH4 N/A negligible / workover N/A N/A # / well lifetime N/A 3.5 g 2 N/A 1 N/A N/A Tonnes of CO2e /well-month h N/A 1.2 N/A N/A a Please note that the high rate for this value is due to the fact that Venkatesh et al. consider workover emissions in total methane emissions in production and the values for workover emissions are not stated b 28% methane reductions are considered in this report c Venting rate for production in this report is assumed to be the same in conventional and shale gas (0.316% loss rate). In order to make this parameter comparable to other studies with the same units, I considered the range of the GHGenius model for the lifetime production of a well, which is between 40 million cubic meter to 725 million cubic meter (725 million cubic meter is based on two drilling operations and may not be a good representative for Canadian operations) d Not Available: parameter was not included in the report e Flaring rate in production is assumed to be the same in conventional and shale gas (29758 kj/tonne gas produced). To make this parameter comparable to other studies with the same units, I considered the range of the GHGenius model for the lifetime production of a well, which is between 40 million cubic meters to 725 million cubic meters (725 million cubic meters is based on two drilling operations and may not be a good representative for Canadian operations). f Flaring rate in production is assumed to be the same in conventional and shale gas ( kj/tonne gas produced). To make this parameter comparable to other studies with the same units, I considered the range of the GHGenius model for the lifetime production of a well, which is between 40 million cubic meter to 725 million cubic meter (725 million cubic meter is based on two drilling operations and may not be a good representative for Canadian operations) g This value was reported in the 2012 report. In their latest report (2014), they changed this parameter to 0.3, which means only one out of 3 wells will have a workover once in its lifetime h Because Laurenzi et al. included both emissions per well lifetime and the assumed specific well lifetime in their reports, and Tyner and Johnson did not include assumed well lifetime and presented emissions per month for this activity, I used emissions per well per month. 33

44 A review of Table 2-3 illustrates the following key points about the production stage in the available US and Canadian reports. First, methane emissions from venting, leaking, or fugitive emissions from production, are one of the largest emissions sources and values for these activities are not consistent within the US studies, due to different boundaries and assumptions used in the individual studies. The following notes illustrate this issue: Since the breakdown of production emissions are not stated by Jiang et al., comparing their values with other studies is not possible. The great difference in production methane emissions in this study with the rest of US studies, can be associated with the fact that they considered workovers, without stating the number of workover activities per well lifetime (the greater the assumed number of workovers is, the greater the overall GHG emissions would be). Skone et al. provides the only study with an actual breakdown of the aggregated methane emissions by different activities (NETL) such as different equipment emissions (e.g. heaters, valves, etc.). Therefore, investigating the actual boundaries and specific activities imbedded in this aggregated number across the other US studies is not possible. Some studies only included methane emissions as a percentage of lost methane over gross production. Since these studies have different EUR values (presented in Table 1-1), the amount of gas that is released differs for each study. Methane emissions for production in Canada lack reliable estimates. The only value available is based on the GHGenius model. Similar to some of the US studies, this report discussed emissions as a percentage of lost methane over gross production (0.316% loss 34

45 rate based on CAPP 2000 data). The venting rate during production is assumed to be the same for conventional and shale gas operations. The Prasino group report, related to production venting emissions and, specifically, the use of pneumatic devices in BC, was not included in Table 2-3, [63]. Prasino group s report updated average bleed rates (in m 3 natural gas vented /hr. of operation) for different pneumatic controllers and pumps. The data to make improved assessments applicable in LCA studies is still missing and further Canadian specific data is needed. Numbers and types of pneumatic devices per well and the hours of operation over a well s lifetime in Canada are two examples of required data. Liquid unloading is another important production stage activity. Most of the current studies assumed that only conventional natural gas wells require liquid unloading [30], [31], [33], [40], [45], while other reports discussed that both shale and conventional gas operators perform liquid unloading [41], [51]. According to Allen et al. and Tyner and Johnson [41], [51], depending on the liquid richness of the formations (wet gas are more liquid rich than dry gas), liquid unloading can take place in shale gas sites. Tyner and Johnson developed emission factors for liquid unloading of wells that had been hydraulically fractured (both tight and shale gas) in Alberta, and their results are lower than the US range. The reason is not clear but can be related to the differences between the regulations and operations in the US and Canada. As the EPA assumed similar emission factors for workovers and completion activities, Skone et al., Burnham et al., Stephenson et al., and Hultman et al. also used similar values for these two operations. The different values in the Hultman et al. study and the rest of the US studies were explained in the preproduction section. They assumed EPA values to be natural gas, not methane. Flaring emissions have a broad range, from 47 to 1625 ton CO2/well lifetime, across US and Canadian values. This is due to the wide range that GHGenius assumed for EUR per well 35

46 lifetime (see footnote d of Table 2-3). Fuel combustion emissions values have also discrepancies across the US studies. This can be attributed to different boundaries and assumptions between different studies (e.g. the types of equipment considered in each study) Processing The processing stage includes activities necessary to prepare natural gas for transmission in a pipeline system. Processing activities can vary based on gas conditions, such as, the amount of natural gas condensate and water in the raw natural gas, and gas composition. CO2 and H2S levels are crucial because of the corrosion problems they can generate if they enter pipelines. Similar to the production stage, processing can include different operations. Key operations include acid gas removal (AGR), to remove H2S and CO2 from natural gas with amine based processes, and dehydration, to remove water from raw gas with a glycol solution. Other operations can potentially include condensate removals, natural gas liquid (NGL) removal, etc. Compressor stations are sometimes used at this stage as well [33]. There are different categories of emissions sources, from fugitive emissions that cannot be captured (such as fugitive emissions from heaters, separators, etc.) to venting and flaring activities (from different sources such as the AGR or dehydration units) and combustion emissions in different equipment (mostly compressors and reboilers used in the AGR and dehydration units). Table 2-4 summarizes the parameters used in the processing stage of shale gas in different studies. As in the other tables, dash lines separate differentiate components of the processing stage. 36

47 Table 2-4 Parameter considered in processing stage of shale gas studies/reports Sub stage name 1. Methane fugitive and venting emissions (CH4) Parameters included in the sub stage CH4 from gas plants and equipment and valves Unit Tonnes of CH4 / well lifetime Jiang /Venkatesh et al. Skone et al. (NETL) Burnham et al. US studies Laurenzi et al. Howarth et al. Hultman et al. Stephenson et al. Canadian studies/reports Tyner and Johnson GHGenius model N/A Carbon dioxide Fugitive emissions(co2) CO2 from gas plants a and equipment Tonnes of CO2/well lifetime N/A b 2880 N/A 5600 N/A 3. Vents (CO2) CO2 from processing the gas Tonnes of CO2/ well lifetime N/A N/A 4. Fuel combustion in processing (CO2) CO2 in the exhausted gas Tonnes of CO2/ well lifetime N/A 733 c N/A N/A Flaring (CO2) CO2 from flaring in processing Tonnes of CO2/ well lifetime N/A 35 N/A N/A a Please note fugitive emissions from gas plants are different than vent activities. Fugitive emissions cannot be captured or flared but vent flows can b Not available: parameter was not included in the report c This value in the study is combustion emissions associated with dehydration reboiler and compressors based on XTO Energy Company. Most of the compressor emissions were included in the transmission stage (not processing) for this study 37

48 Two key parameters to consider when comparing emissions values in the processing stage are inclusion or exclusion of compressor stations and the concentration of CO2. The differences in the values of fuel combustion emissions and methane fugitive emissions between Laurenzi et al. and Skone et al. is due to the exclusion and inclusion of compressors in the processing stage of these studies, respectively. Laurenzi et al. include compressors in gathering systems in their production stage. Higher levels of CO2 in natural gas composition result in greater energy consumed to remove it. Horn River, with a high concentration of CO2 (12%) and one of the GHGenius model s studied formation, reveals that higher fuel use (approximately 25% higher) in processing can be observed in some regions of Canada. The lower range of fuel use in the GHGenius model is related to formations like Montney, with a lower concentration of CO2 (1%). CO2 removed in acid gas removal operations, however, is often vented to the atmosphere; no specific Canadian value is reported for this activity in the GHGenius model. Similar to the production stage, another source of discrepancies across the US studies is the assumed EUR per well lifetime since some of the studies included emissions rates per cubic feet of natural gas produced. It means these studies did not include emissions per well lifetime, so depending on the assumed amount of natural gas that is produced, emissions can vary. For studies with clear EUR, emissions are calculated based on the well lifetime Transmission The transmission stage includes natural gas pipeline networks that connect producers and end users. Two main sources of emissions were investigated in different studies: total natural gas fugitive emissions from pipelines and compressor stations, which are necessary to boost the 38

49 pressure of gas to flow in the pipeline system, and CO2 emissions from burning natural gas in compressor stations. These parameters are shown for different studies in Table 1-5. Skone et al. is the only study that stated the assumed distance for a transmission pipeline, at 971 km. They stated: The total natural gas combustion and fugitive emissions is a function of pipeline distance, which was estimated at an average distance of 971 km. This distance is based on the characteristics of the entire transmission network and delivery rate for natural gas in the US It is possible that some natural gas sources are located significantly closer to their final markets than other sources of natural gas. To account for this uncertainty, this analysis varies the average pipeline distance by +/- 20 percent, which is an uncertainty range based on professional judgment [33] Transmission distances can have an impact on both the fugitive emissions estimates and the number of compressor stations (and their corresponding fugitive and combustion emissions) needed in the transmission system. Based on the GHGenius model [12], a linear relationship exists between emissions estimates from transmission and the distance of transmission pipeline. Therefore, an economic cut off would likely exist for each project. 39

50 Table 2-5 Parameter considered in transmission stage of shale gas studies/reports Sub stage name Parameters included in the sub stage Unit Jiang/ Venkatesh et al. Skone et al. (NETL) US studies Burnham Laurenzi Howarth et al. et al. et al. Hultman et al. Stephenson et al. Canadian studies/reports Tyner and GHGenius model Johnson 1. Fugitive Pipeline and emissions and vents (CH4) compressor methane emissions Tonnes of CH4 / well lifetime N/A Fuel combustion (CO2) Natural gas use in compressor stations Tonnes of CO2/well lifetime N/A 3180 N/A Includes methane fugitive emissions from transmission, storage and distribution 40

51 2.1.5 End use of natural gas Natural gas is used for multiple purposes, including electric power generation, industry use, commercial use, residential use, and transportation. Based on a NEB report, the two primary uses of natural gas in Canada are in power generation and industry, as shown in Figure 2-3 [2]. Canada is one of the unique countries that the industrial use of natural gas is higher than power generation. In US, natural gas is largely consumed for power generation [64]. As all of the LCA studies 58 in the US considered power generation in their analysis as the downstream stage of natural gas use, only this purpose was included in the literature review. Figure 2-3 Primary Natural Gas Demand in Canada [2] Based on the Energy Information Administration s (EIA) data in the US, in 2012 [64], 39% of the total natural gas delivery to consumers was used for electric power generation. This is why most of the US studies considered power generation as the primary end use of natural gas. 58 EDF studies, which are not LCA studies, assumed vehicle transportation as another major end use of natural gas. 41

52 According to the literature, natural gas power plants are considered to be competitors to coal-fired power plants, mainly due to lower environmental impacts associated with natural gas in the combustion stage. Three main types of power plants generate electricity from gas: a) steam generation or natural gas boiler, in which natural gas is burned in a boiler to heat water that transforms it into steam to spin a generator; b) single cycle gas turbines, where natural gas is burned inside an internal combustion chamber, then flows to spin the turbine s blade to generate electricity; and c) natural gas combined cycle, which is a combination of a and b, steam and turbines. In the third type, gas is first burned in a gas turbine and, after escaping, it is piped to a steam-generating tank to heat water which, in turn, spins its own turbine. One of the key parameters needed to determine the GHG emissions in the end use stage of natural gas is power plant energy efficiencies. Steam generation units typically have an energy efficiency around 33-35%, while single gas turbines are slightly less efficient (less than 30%) [65]. The most efficient form of fossil fuel power generation is the Natural Gas Combined Cycle (NGCC) units with a range of 50-60% efficiency [65]. Table 2-6 summarizes the US and Canadian emission factors used for natural gas power generation in different studies and reports. Three other US studies were added to this table and, in comparison with Tables 2-2 to 2-5, support the literature in terms of combustion emissions of natural gas. As mentioned previously, the downstream stages occurring after transmission were not the focus of this thesis. 42

53 Table 2-6 Parameter considered in end use stage of natural gas studies/reports Sub stage name Parameters included in the sub stage Unit Jiang / Vanketash et al. Skone et al. (NETL) Burnham et al. Laurenzi et al. US studies Howarth et al. Hultman et al. Stephenson et al. Spath et al. 59 Odeh et al. 60 Singh et al. 61 Canadian studies/reports Tyner and Johnson GHGenius model 1. Power plant emissions Final emission factors Types of gas power plant considered in study g of CO2e / kwh of electricity generated from natural gas - NGCC NGCC SCGT 64 NGCC NGB 65 NGCC N/A SCGT NGCC Not clear 499 (without CCS 62 ) 495 (without CCS) 425 (without CCS) (with CCS) (with CCS) (with CCS) N/A 485 NGCC NGCC NGCC N/A Efficiency % N/A N/A 59 Reference: [66] 60 Reference: [67] 61 Reference: [68] 62 CCS: Carbon Capture and Storage 63 NGCC: Natural Gas Combined Cycle 64 SCGT: Single Cycle Gas Turbines 65 NGB: Natural Gas Boiler 43

54 Also, Singh et al. [68] reviewed seven other studies (not stated in Table 2-6) about natural gas emissions intensities for electricity generation with very similar results Estimates of methane leaks from EDF studies Improved methane emissions measurements and estimates have been the focus of much recent research in the US. In 2012, EDF lead an extensive research program to quantify methane leaks across the entire supply chain of the US natural gas industry. A series of 16 independent projects were designed to investigate how much and from where methane is escaping to the atmosphere through the entire life cycle of natural gas. Out of the 16 studies, the data from 12 have been published to date and the rest is expected to be published or submitted soon [50]. Almost 100 researchers and industry experts participated and collaborated in this research 66. Findings from three modules (out of five 67.) investigated in EDF studies are relevant to this thesis. These three modules include a) Production, b) Gathering and Processing, and c) Transmission and Storage. Key parameters for the mentioned modules are provided below. EDF studies production stage Researchers in the Allen et al. [69] study performed direct measurements of methane emissions at 150 production sites, 27 well completion flowback events, 9 well liquid unloadings, 66 the University of Texas, Houston Advanced Research Center (HARC), US Environmental Protection Agency (EPA), Colorado State University, Carnegie Mellon University, Purdue University, Aerodyne Research Centre, Washington State University, Harvard University, Boston University, Duke University, Atmospheric and Environmental Research, National Oceanic Atmospheric Administration, University of Michigan, West Virginia University, Coordinating Research Council, Inc., Picarro, Conestoga-Rovers & Associates, URS Corporation, Conestoga-Rovers & Associates, Clearstone Engineering, Pipeline Research Council, St. Croix Research, Council on Foreign Relations and Innovative Environmental Solutions 67 Local distribution and vehicle transportations are not reviewed in this thesis as they are out of the scope of this thesis. 44

55 and 4 workovers in the US over 6 month. Summaries of their findings are compared with the EPA values in Table 2-7. Please note that the values are at a national level (i.e. total US emissions). Table 2-7 Comparison between EDF study and EPA emission factors 68 [69] Emissions category EDF project emissions estimates (Gg of methane/yr.) EPA GHG Inventory net emissions (Gg of methane/yr.) Completion flowback from wells with hydraulic 18 (5-27) 654 fracturing Chemical pumps 68 (35-100) 34 Pneumatic controllers 580 ( ) 335 Equipment leaks 291 ( ) Unloading (no plunger lift) (25-206) 149 Although this study s total methane emissions in the production stage (0.53% of gross gas produced, based on Allen et al.) are similar to those of the EPA s (0.59% of gross gas produced), the emissions estimates for individual categories between these two reports are significantly different. Allen et al. estimated lower national emissions for completion activities from wells with hydraulic fracturing compared with the EPA values. On the other hand, their results show greater national emissions for chemical pumps, pneumatic controllers, and equipment leaks than do the EPA results. The largest discrepancies in the EPA values and Allen et al. findings are in well completions, due to three main reasons. First, average potential emissions rates in the EDF studies are lower than the EPA results. Average potential emissions is defined as the emissions that would be released if all of the methane flowing from the well during the completion flowback was emitted to the atmosphere. The second reason is that more than 60% of the wells in the EDF study are 68 Copyright permission is attached in appendix C. 45

56 assumed to send methane to sales or control devices (such as flares). Third, 99% of potential emissions were assumed to be capture and controlled in the wells that have this ability [70]. The results from Table 2-7 can affect decisions about opportunities to reduce GHG emissions in the US. For instance, investments in equipment (such as pumps and controllers) with lower emission factors than equipment currently in place can both reduce GHG emissions and save money by providing more gas to sell and reduce escaped gas. With respect to liquid unloading activities, Allen s team argued that national emission factors should be derived with caution. The characteristics of the sampled activities in their work were highly variable and the number of events sampled was small. Overall, they concluded that national emissions from well liquid unloading are bound to have large uncertainties. EDF studies gathering and processing stages This study includes facility level methane measurements at 114 gathering facilities and 16 processing plants in the US natural gas system [71]. The gathering pipeline network that connects these facilities was not studied. Six different types of facilities were sampled, including: Compression only (C); Compression and Dehydration (C/D); Compression, Dehydration, and Treatment (C/D/T); Dehydration only (D); Dehydration and Treatment (D/T); and Processing (P). Authors used tracer flux measurements, which can measure concentrations of specific gases, such as methane in the gas flow, with consideration of wind directions. They revealed that gathering facilities emit methane at a rate roughly eight times higher than EPA estimates for this segment. Processing facilities emissions rates, however, were reported to be lower than the EPA inventory. In this study, however, contributions of different sources of emissions are not presented. For instance, methane emissions from equipment leaks are not distinguished from other types of 46

57 vents and flares. Also, activities in the processing plants, like AGR compared with other types of processes such as Natural Gas Liquid (NGL) removal, are not considered in this report. In Canada, where CO2 rates can be high (12% in Horn River compared with an average of 1% in the US) understanding emissions based on activity and source can help operators find cost effective ways to reduce emissions. EDF studies transmission stage In this study [72], Subramanian et a.l measured both equipment and site level methane emissions from 45 compressor stations in the transmissions and storage sector of the US natural gas system. Direct measurements of fugitive and vented sources, as well as downwind-tracer-flux techniques, were used to produce methane emissions estimates. They argued that compressor vents, leaky isolation valves, reciprocating engine exhaust, and equipment leaks were major sources at both operating and standby compressor stations. As discussed in this study, 10% of the sites, including two super emitters (emitters with the range of emissions significantly higher, approximately 7 and 20 times greater than the average emissions rate for the rest of emitters), contributed to half of the total aggregated methane emissions. Study findings were comparable or lower than the corresponding EPA emissions factors if these two super emitters were excluded. In the presence of the two super emitters in the analysis, average emission factors based on this study exceeded the EPA GHG inventory emission factors. This highlighted the potentially important contributions from super emitters to national emissions. They argued that quantification of this contribution requires knowledge of the magnitude and frequency of super emitters across the entire transmission and storage sector. Again, the results of this study can be used in Canada to motivate both policy makers and industry to establish broad-based monitoring and maintenance 47

58 requirements. The main conclusion from the EDF studies is that EPA factors may need to be updated. Since EPA emission factors were the data source for most of the LCA studies discussed in previous sections, further investigation, with the help of natural gas industry partners, is needed. The conclusion that can be drawn from the entire literature review is that US studies have addressed GHG emissions associated with the development of natural gas, in a more detailed way than what has been done in Canada. Although lack of data is not consistent through individual stages of life cycle of natural gas (i.e. preproduction stage has gained less attention for data collection compared to other stages), each stage still needs accurate and reliable data to let decision makers find the best opportunities to manage and reduce GHG emissions. Canadian literature suffers from insufficient data that are needed to calculate life cycle GHG emissions of different types of natural gas. 48

59 METHODS The primary objective of this thesis is to provide insights about the GHG emissions emitted as a consequence of natural gas development across the supply chain, using public data. To achieve this objective with the focus of natural gas development in western Canada, two methods are used: 1) Top-down analysis: matching publicly available emissions data reported by natural gas companies to publicly available production data. 2) Bottom-up analysis: adapting a life cycle model developed by the US DOE NETL (Department of Energy s National Energy Technology Laboratory [33]) to estimate emissions using a first principle approach and substituting US data with data from actual operations within BC where it exists publicly. The objective of applying a top-down analysis is to estimate emission factors for natural gas development for each life cycle stage (i.e. preproduction, production, processing, and transmission) in BC and AB. Emission factors are the amount of GHG emissions released into the atmosphere due to operations in the natural gas supply chain divided by the quantity of gas produced (i.e. emission factor = GHG emissions/production volume). Results from the top-down analysis can help to compare emission factors from activities related to natural gas development in western Canada with other jurisdictions (e.g. US). However, the activities are aggregated to life cycle stages so cannot provide detailed information about the types of activities that contribute significantly to overall GHG emissions. This means that it cannot be used to determine opportunities to reduce GHG emissions at an activity level. The bottom-up analysis complements the top-down analysis and enables decision-makers to see the effect of changing parameters throughout the supply chain of natural gas on the GHG emissions. When compared across jurisdictions, this analysis can also identify the impact of 49

60 different operating practices, reservoirs, and other characteristics that can change the overall GHG emissions profile of natural gas. 3.1 Top-down analysis The top-down analysis is used as one approach to assess GHG emissions from natural gas development in western Canada. A top-down estimate begins with annual GHG emissions reported to government agencies at the facility level. These facility level emissions data can be different for different provinces based on their reporting regulations and threshold. A reporting threshold refers to the volume of GHG emissions for an individual facility on an annual basis. Above this volume the facility is required to report their annual emissions. In this thesis, whenever possible the GHG emissions are disaggregated to a life cycle stage level (preproduction, production, processing, and transmission). The ultimate goal of this analysis is to estimate emission factors on a facility/stage level. To estimate emission factors, GHG emissions and production data are needed to be matched as they represent the numerator and denominator. Ideally, GHG emissions and production data would be collected with consistent geographic, time, and activity boundaries. For example, GHG emissions from the production stage of shale gas operations in region A would be linked to production data from the same region s shale gas production Available data sources in Western Canada The Greenhouse Gas Reduction Target Act (GGRTA) in BC requires the province s industrial emitters to submit facility GHG emissions data [24]. The regulation (effective Jan 1, 2010) sets out requirements for reporting GHG emissions from BC facilities emitting 10,000 50

61 tonnes of CO2e emissions or more per year [73]. In AB, the Specified Gas Reporting Program (SGRP) has collected facility GHG emissions data since Until 2010, the threshold for a facility to report their emissions was 100,000 tonnes of CO2e or more (10 times higher than BC s threshold). After 2010, due to the Specified Gas Emitters Regulation (SGER) and to improve the value of data collected through the reporting program, AB lowered this threshold to 50,000 tonnes of carbon dioxide equivalent [74]. In the top-down analysis, only BC facility level emissions are used for the following reasons: The higher threshold level for AB compared with BC leads to higher aggregation in data for GHG emissions on a facility level in AB. Consequently, GHG emissions from fewer facilities in AB are reported individually compared to BC. No public data are available for GHG emissions of facilities in AB that emitted less than the threshold in an aggregated format. Emissions in an aggregated format include the aggregated amount of GHG emissions of all facilities owned by a company that, individually, emitted less than the threshold in a year. In contrast to AB, BC GHG emissions data includes both individual facilities that emitted more than 10,000 tonnes of CO2e along with an aggregation of the rest of the facilities owned by that company. Approximately 28% of oil and gas industry GHG emissions in BC in 2013 are reported in an aggregated format. Aggregated format emissions data can help calculate company and province levels emission factors. Unlike BC, AB public emissions reports do not include emissions source type, such as flaring or venting on a facility level. The AB reports break down the facility level emissions by gas type only (CO2, CH4, N2O, etc.). 51

62 The most recent public report of GHG emissions in AB is for 2011 as compared with BC where reported GHG emissions up to 2013 (which is the base case year in this thesis for the top-down analysis). Because shale and tight gas production have experienced rapid growth over the past ten years (Figure1-1 in Chapter 1), the more recent GHG emissions data is more relevant for emissions estimates of unconventional gas development. Both BC and AB report GHG emissions for conventional oil and gas extraction. While approximately 2% (on an energy basis) of BC s total oil and gas production was attributed to oil production in 2013, in AB, conventional oil accounted nearly 20% (on an energy basis) of AB s total oil and gas production (sources: calculations from BC and AB public production reports [18], [75]). Therefore, the AB data would be more affected by the allocation required to separate and attribute GHG emissions to oil and gas separately. Having said this, the BC emissions data cannot be used to distinguish between unconventional and conventional natural gas. The most important difference between AB and BC data is that production on a well level (i.e. production per well), which is essential to estimate emission factors, is not public in AB. BC has the well level production data,however, the list of fractured wells is not public and was shared with this researcher through a personal communication with the BC Oil and Gas Commission [76]. In addition, based on public well level data including their geographical locations, different configurations of wells (vertical or horizontal) can be distinguished. 52

63 3.1.2 Top-down analysis based on publicly available BC data The most recent public BC emissions data is called Industrial Facility GHG Emissions Report Summaries: Province of British Columbia and is associated with annual GHG emissions for oil and gas facilities in BC in 2013 [77]. This data is provided by the BC government (Ministry of Environment) and is referred to as facility emissions data in this thesis. It provides emissions data for both facilities that emitted more (individually) than 10,000 tonnes of CO2e as well as aggregated emissions that individually are smaller than 10,000 tonnes. The emissions are broken down by specific activities (i.e., stationary fuel combustion, flaring, venting, and fugitives ) as well as GHG emissions types (i.e. CO2, CH4, N2O, CF4, C2F6, and SF6) on a facility level. In this report, only CO2, CH4, and N2O are presented for oil and gas facilities and the rest of the GHG emissions are not included in the dataset. However, greenhouse gases other than CO2, CH4 and N2O are less prevalent in oil and gas industry [78]. In the top-down analysis, emission factors are explored at three levels of aggregation: 1) Facility level emission factors 2) Company level emission factors 3) Province level emission factors The method used to calculate these emission factors are described in the following sections. Facility level emission factors To develop facility level emission factors, production data are needed to be matched to GHG emissions at these facilities. The facility level emission factors include the amount of annual GHG emissions as the numerator (collected from the facility emissions data [77]) and volume of annual natural gas production as the denominator (collected from the BC Oil and Gas Commission 53

64 Web Application/Data Downloads search tool/ Production Data for all wells in BC [18]). The data source for natural gas production is referred to as well level production data in this thesis and includes 2013 data. In 2013, 102 facilities were above the 10,000 tonnes of CO2e threshold based on the facility emissions data and therefore reported individual GHG emissions. The facility emissions data includes the company names but the well level production data does not. The well level production data includes the following information: monthly production of gas, oil, condensate, and water (volume/month), area code, formation code, and production days (i.e. number of days in a month that natural gas is produced) on a well level. In addition, this data contains the Unique Well Identifier (UWI). However, these UWIs are not linked to the company that operates them. In order to assign the production from a well to the appropriate company and then link this production to the facility emissions data, several methods are explored. These analyses are better illustrated with an example. Facilities operated by ARC Resources Ltd. are used as the examples to describe the challenges and limitations for facility level emission factors in a top-down analysis. ARC Resources Ltd. reported 255 MMcf/day in natural gas production in the Montney formation in January 2013 and was ranked the 4 th largest BC natural gas producer [17]. In the 2013 facility emissions data [77], 5 separate emissions estimates are attributed to ARC Resources. The first four are related to specific facilities (with locations) that each emitted more than 10,000 tonnes of CO2e. The fifth emissions estimate is the aggregation of emissions from all other ARC Resources facilities that emitted less than 10,000 tonnes of CO2e each. The names are: Dawson Comp Stn (compressor station) Dawson Sour Gas Plant Parkland Comp Stn (compressor station) 54

65 Parkland Gas Plant ARC Resources BC Aggregated Facilities (Emissions less than 10,000 t CO2e at each) To attribute production from the individual wells to their companies (such as ARC Resources in this example) and specifically to individual facilities (such as ARC Resources facilities), three different methods are used. Method A - Match 2013 producing UWIs with well names to identify ARC Resources wells: In this method, the well level production data from the BC Oil and Gas Commission [18] is used to find natural gas producing wells in The production data is provided on a well level without mentioning the company name. Based on this data, 9300 wells were producing natural gas, oil and/or condensate in 2013 in BC. The first step to find company names is to use the Well Index by Name file (available at the BC Oil and Gas Commission Web Application/Data Downloads search tool/ Well Index by Name [18]). The well index by name file contains UWIs and their current company owners in BC, rather than the 2013 owners which is the year associated with the facility emissions data and was not useful for those UWIs where the owner changed during or after To overcome this issue, company names in 2013 are used that were shared through personal communication with the BC Oil and Gas Commission [76]. Method B - Use well look-up by well operator search tool available on the BC Oil and Commission Web Application [79]: In this method, the Well Lookup Using Location, Well Operator or Well Name search tool is used. ARC Resources is entered as an operator to obtain all the UWIs associated with this company. Then, these UWIs are matched with the well level production data in As seen in 55

66 Table 3-1, the numbers of ARC Resources producing wells in 2013 found with this method are similar to method A. Method C - Use the oil and gas codes data (e.g. client code, facility code, etc.) in the tax and royalties section of the BC Government (Ministry of Finance) [80]. This data source is referred to as oil and gas codes data in this thesis: In this method, the oil and gas codes data (i.e. client codes ) are used to obtain a client code for each company. Once the ARC Resources client code is known, the facilities and their types (facility types show the purpose of the facility such as dehydration facility ) owned by ARC Resources are identified through the Facility Codes tool. Then, the Facility/UWI Linkage Codes tool is used to connect the ARC Resources facilities and UWIs. After finding the UWIs assigned to ARC Resources facilities with this method (that do not include any production data), the UWIs are matched with the well level production data of 2013 (used in method A) to obtain the production of each well. Table 3-1 compares different production data associated with ARC Resources in 2013 by applying different methods and sources. Their 2013 public annual report is included in Table 3-1 for comparison. Table 3-1 ARC Resources 2013 production data from Montney formation using different sources and methods Parameter ARC Resources 2013 annual report [81] Method A Method B Method C Gas (m 3 /d) 6,670,000 6,640,000 6,640,000 6,680,000 Oil (m 3 /d) Condensate (m 3 /d) Number of total UWI owned by ARC Resources Not Available

67 In Table 3-1, the results of methods A, B, and C show similar amounts of gas estimated to be produced by ARC Resources in 2013 (less than a 1% difference compared with ARC Resources annual report value [81]). In addition, the number of ARC Resources UWIs that match producing wells in 2013 are close when different methods are used ( wells). The discrepancies in oil and condensate values obtained by different methods are not investigated as they are out of scope for this thesis 69. Because the facility emissions data is on a facility level and the well level production data is not, the connection between facilities and UWIs is also needed. Method C was the only method connecting UWIs to facilities (i.e. the only method that allows matching emissions data with production data). The procedure used in method C to estimate emission factors for ARC Resources operations is shown in Figure The oil and condensate quantities are included to show that ARC Resources produced these products, however, these values are not used anywhere in this thesis. 57

68 Emission factors per facility= (g CO2e / MJ NG linked to each facility) Annual GHG emissions emitted per facility (g CO2e per facility) Annual amount of natural gas linked to facility (MJ NG per facility) Emissions per facility [72] (4 individual facilities for ARC Resources) Facility codes for each facility name UWIs linked to facilities 2013 production data based on matching UWIs Production per facility Based on facility names and/or facility type and/ or NTS or DLS systems (see footnote at the bottom of this page) Oil and Gas codes ( Facility/UWI Linkage Codes tool [75]) Well level production data [15] Summing up the total natural gas linked to a facility Figure 3-1 Method C, connection between emissions data and production data on a facility level By using method C, 3 out of the 4 individual facilities can be matched to production data (missing the Dawson Sour Gas Plant 05-35) for ARC Resources. Method C is used to calculate facility level emission factors. However, two challenges meant that emission factors for all 102 individual facilities that emitted more than 10,000 tonnes of CO2e in BC in 2013 can not be estimated. These challenges include: 1) Not all the facilities in the facility emissions data have a name and/or enough information about the NTS (National Topographic System) or DLS (Dominion Land Survey) location system 70. As shown in Figure 3-1, in order to find facility codes to match facilities in the facility emissions data and facilities obtained from the oil and gas codes 70 NTS and DLS are methods utilized for finding locations such as latitude and longitude system. 58

69 data (i.e. Facility/UWI Linkage Codes), facility names and locations are needed. For example, AltaGas reported two individual facilities in the facilities emissions data, while this company owns 5 dissimilar facilities in the oil and gas codes data (available at Table 3-2). Table 3-2 Comparison of AltaGas facilities the oil and gas codes data and the facility emissions data. Terms in bold font show the name of facilities List of AltaGas facilities in the oil and gas codes data (facilities that were obtained via facility code tool for AltaGas)[80] List of AltaGas facilities in the facility emissions data (emitted more than 10,000 tonnes of CO 2 e in 2013)[77] AltaGas Mica AltaGas Roger c-079-j/094-j-10 AltaGas Sunrise AltaGas Town d-058-f/094-b-16 AltaGas Town d-058-f/094-b-16 Blair Creek Comp Stn d-058-f Younger NGL Extraction Plant As it is shown in Table 3-2, AltaGas facilities that emitted more than 10,000 tonnes of CO2e in 2013 cannot be matched to this company s facilities using the oil and gas codes data. Therefore, no facility codes are identified for these facilities and as a result, no UWI is linked to find the volume of production from that well. Consequently, no emission factor can be calculated for these facilities. Out of 102 facilities reported in the emissions data, 12 have this challenge and therefore their emission factors cannot be calculated. Concerns about inconsistencies in facility types within the remaining 90 facilities are identified and treated separately. For those facilities where the facility types are not stated in the facility emissions data, the oil and gas codes data is used to fill the gap by matching facility names, company names, and location in the two data sets [80]. 20 facilities have this challenge and are shown with a * in the results section. In addition, if facility names and/or facility 59

70 locations are similar in both data sources (i.e. the facility emissions data and the oil and gas codes data) and facility types were different, the researcher use the facility types from the facility emissions data. For example, Endurance Energy s Gunnell facility is called a compressor station in the facility emissions data, while this facility is considered as a central dehydration facility in the oil and gas codes data. In this thesis, Endurance Energy s Gunnell facility is considered a compressor station. Eight facilities have this challenge are shown with a ** in the results section. 2) For some of facilities in the facility emissions data, even with finding their facility codes in the oil and gas codes data, no UWI is linked to them when using the Facility/UWI Linkage Codes tool. So, as no production data can be matched to these facilities, no emission factor is calculated. 44 facilities have this limitation in developing facility level emission factors. However, based on information from experienced people in the BC government, these links are evolving with more updated data expected in the near future [82]. Out of 102 facilities, 46 facilities (that correspond to 15% of total BC GHG emissions in 2013 for oil and gas industry), are matched with their associated UWIs in this thesis. Three out of 46 facilities are categorized as battery in one of the data sources. For those 3, a more descriptive facility type is used. For instance, the Bonavista s Rigel facility is called battery in the facility emissions data, but it is categorized as a compressor station facility in the oil and gas codes data. In this example, compressor station shows a more clear description of the purpose of the facility compared to battery and is used in this thesis. Emission factors for these 46 facilities are categorized into five individual facility types (after matching emissions and production data using method C): 60

71 1. Central dehydration facilities - removes water from produced natural gas. 2. Compressor station facilities - increases pressure of natural gas for transport. 3. Gas plant facilities - treats natural gas to meet the gas concentrations required by pipeline operators. Detailed characteristics (i.e. whether these facilities are before, after or instead of compression and sourness/sweetness of the gas that these facilities treat) are not clear with the current public data. 4. Sour gas plant facilities - removes impurities such as H2S from natural gas with more than 4 ppm of H2S [83]. 5. Sweet gas plant facilities - removes impurities such as H2S from natural gas with less than 4 ppm of H2S [83] Relationship between facility level emission factors and well configurations To explore the relationship between well configurations (i.e. fractured horizontal wells, fractured vertical wells, not fractured horizontal wells, not fractured vertical wells) and emission factors, results are presented for the facilities in BC where all of the UWIs linked to them (via method C) produced natural gas from a certain well configuration. This means 100% of the UWIs connected to a certain facility are assumed to be similar. Since not all the UWIs link to a certain facility are similar (e.g. a facility is linked to UWIs where 60% of those UWIs produced gas from fractured horizontal wells, while the rest produced gas from fractured vertical wells), only a portion of UWIs and their corresponding facilities are used in this analysis. 25% (based on number of wells linked to 46 facilities) and 55% (based on the MJ of natural gas production linked to 46 facilities) of the UWIs, which are linked to 19 facilities through method C, are relevant and therefore are used in this method. 61

72 Company level emission factors Company level emission factors can be broken down into two categories: 1. Company level emission factors based on individual facilities, which are the aggregated values across both emissions and production, considering their individual facilities in the facility emissions data 2. Company level emission factors based on aggregated format emissions, which are the aggregated values across both emissions and production, considering company s emissions in the aggregated format in the facility emissions data The first company level emission factor is basically the summation of the facility level emission factors that were obtained via method C (explained in ) owned by the same company. In ARC Resources example, emission factors for Dawson compressor station (with 20,900 tonnes of CO2e emitted per year), Parkland compressor station (with 16,300 tonnes of CO2e/year) and Parkland gas plant with (11,400 tonnes of CO2e/year) were obtained via method C for ARC Resources company. The summation of their GHG emissions is equal to 48,600 tonnes of CO2e/year. ARC Resources, however, emitted 132,500 tonnes of CO2e in 2013 (48,600 from mentioned facilities + 15,700 from Dawson sour gas plant (missing due to challenges in method C) + 68,200 from aggregated format emissions, all annual emissions in tonnes of CO2e). Since the company level emission factors should represent all operations of a certain company, a criterion was used to reflect the representativeness of company level emission factors. For example, the representativeness of ARC Resources emission factor is 37% (48, ,500 = 37%). This means, this company`s emission factor which is based on summation across its facility level emission factors (obtained via method C) is based on 37% of their total emissions in Only 62

73 15% of the emissions from all of the BC facilities are accounted for in this analysis to represent company level emission factors. The second company level emission factor is for those companies that only reported their emissions in the aggregated format (i.e. none of their facilities emitted more than 10,000 tonnes of CO2e in 2013 individually). The reported annual GHG emissions are divided by their total production in 2013 that is obtained via method A (explained in ) to develop company level emission factors. 24% of emissions data from total aggregated format emissions are linked to their corresponding production data in this type of company level emission factor. Province level emission factors The emission factor on a provincial level includes an average annual provincial emission factor broken down by natural gas life cycle stages (i.e. preproduction, production, processing, and transmission). All emissions data used in this analysis are reported as conventional oil and gas extraction in the facility emissions data [77]. It is assumed that all of these emissions can be attributed to natural gas production since only 2% of total oil and gas production in BC in 2013 was oil [18]. To break down the province level emission factor into life cycle stages two challenges exist: 1) Not all the facilities in the province (i.e. BC) can be linked to their production to develop the facility level emission factors. These facility emission factors are needed to be added to each other to develop the BC average annual emission factor. This was due to limitations in method C (explained in ) and 30% of BC total emissions in the facility emissions data being reported in aggregated format. 63

74 Although approximately a quarter of this 30% can be matched to production data, no production data can be matched to the remaining aggregated emissions. 2) Even with a perfect match between all of the emissions in the facility emissions data and the well level production data, emission factors are calculated based on the facility types. However, allocation required to separate and attribute these facility types emission factors to life cycle stages was not possible. Two main reasons for this challenge include the fact that most of the facilities in the facility emissions data stated compressor station as their facility type. However, compressor stations can potentially be used in production, processing, transmission, or a combination of all stages. Therefore, it is not clear where in the life cycle stages these facilities and their corresponding emission factors should be considered. In addition, facilities that can be considered in preproduction stage such as drilling or hydraulic fracturing are not stated in the available public data. To overcome these challenges, raw data from the question and answer section presented the facility emissions data available on the BC government website (Industrial Facility GHG Emissions Report Summaries Province of British Columbia [84]) is used to develop the province level emission factor. This data is shown in Table 3-3. It is important to note that this data is not broken down by the natural gas types (i.e. shale, tight, conventional gas). Therefore, it is not possible to calculate emission factors specific to shale and tight gas or conventional gas on a province level. 64

75 Table 3-3 Emissions for the different segments of the oil and gas industry (BC, 2013) [84] Oil and Gas Industry Segment (not broken down by natural gas types) Stage name in BC government Stage name in this thesis Total BC emissions from oil and gas in 2013 (tonnes CO 2 e) Percentage of total upstream emissions Well drilling and completions Preproduction Upstream & Gathering Production Processing Processing Transmission Transmission Total Upstream and Transmission Because the amount of total BC emissions from oil and gas in this raw data ( tonnes of CO2e) is the same amount of the summation of all facilities emissions (both individual and aggregated format) in the facility emissions data, data in Table 3-3 is used to create the province level emission factor. To calculate BC emission factor, BC total emissions are divided by total BC production, collected from the well level production data. Then this emission factor is multiplied by percentages of each life cycle stage, presented at the right column of Table 3-3, to break down the aggregated emission factor into life cycle stages. While the result cannot be broken down by region (i.e. Montney versus Horn River) or by natural gas type (i.e. shale and tight gas versus conventional gas), it is known that less than 14% of natural gas production is produced by conventional methods in 2013 [17]. It is important to note that the format of the data presented in Table 3-3 suggests that the BC government has access to the emissions data separated by stages, which is not public at the time that this thesis is written. Another provincial level emissions intensity (i.e. emissions per year, as opposed to emission factor that is emissions per production) is calculated in this thesis. This emissions 65

76 intensity is based on facility names in the facility emissions data and is divided by activity types (such as gas plants or dehydration stations) on the province level [77]. 66

77 3.2 Bottom-up analysis In this thesis, a life cycle model adapted from the US DOE NETL model, presented in several Excel spreadsheets in the report titled Life Cycle Analysis of Natural Gas Extraction and Power Generation [33] is used to estimate GHG emissions from actual operations in Western Canada, with a focus on BC operations. The first draft of the NETL report was published in 2011 (without any spreadsheets included) [39], and the second report updated their results including the release of spreadsheets representing the data and calculations summarized in the report in 2014 [33]. The justification for choosing the NETL model as a reference to assess the emissions from Canadian gas development over other US studies such as Jiang et al. [30] is that the NETL individual Excel spreadsheets include all the key inputs and outputs of each activity. Each spreadsheet represents a unit process and their model can be re-created using these spreadsheets. The NETL natural gas modeling structure is presented in a schematic figure (Figure 2-2 of NETL 2014 report [33]) and is broken down by the following stages: raw material 71 acquisition (including both extraction and processing stages), raw material transport, energy conversion facility 72, product 73 transport (i.e. distribution) and end use. The NETL adapted-model used in this thesis include only raw material acquisition and raw material transport because the rest of the activities (i.e. energy conversion facility, product transport and end use) are beyond the thesis scope. The activities in the upstream and transmission operations are adapted from the NETL model, with only a few changes and modifications. The main modification is to break down the 71 Raw material in NETL report refers to natural gas. 72 Power plants that convert natural gas to other products such as electricity. 73 Product in NETL report refers to electricity. 67

78 extraction stage to preproduction and production activities. The rest of the modifications and key parameters and inputs that differentiated the models are described in the following section. The main reason for modifying the NETL model is to capture differences between Canadian and US operations and gas formations. The thesis model involves four individual stages: preproduction, production, processing, and transmission. Figure 3-3 presents the schematic of the bottom-up model used to estimate the emissions from the natural gas produced in western Canadian formations. Gray boxes in Figure 3-3 show venting, flaring, and fugitive emissions. Orange boxes show energy and material sources that result in the release of GHG emissions (mostly combustion emissions). Similar to the assumptions made in the NETL model, the difference between other point source emissions and other fugitive emissions in production and processing is that other point source emissions can be captured and flared, whereas other fugitive emissions are vented directly into atmosphere (e.g. emissions from blowdown vessels, heaters, etc.). Other fugitive emissions cannot be captured by operator and is lost into air because capturing them is very costly (e.g. fugitive emissions from separators, meters/piping, pipeline leaks, etc.). 68

79 Preproduction Production Processing Transmission CO2/N2 for Fracturing Sand and Propants for Hydraulic Fracturing Transportation of needed material for fracking by trucks Well Workovers Venting /Flaring Acid Gas Removal Dehydration Natural Gas (as Fuel) Steel Pipeline Construction Water for Hydraulic Fracturing Venting/ Flaring Liquid Unloading Other Point Source Emissions Diesel Steel Concrete Natural Gas (as Fuel) Well Construction & Hydraulic Fracturing Other Point Source Emissions Fugitives Other Fugitive Emissions Valve Fugitives Emissions Electricity Natural Gas (as Fuel) Pipeline Operation (Energy & Combustion Emissions) Flowback Water Treatment Diesel Electricity Venting/Flaring Flowback Water Injection to Water Disposal Wells Well Completion Fugitives Other Fugitive Emissions Pneumatic devices &Valve Fugitives Emissions Venting /Flaring Gas Centrifugal Compressors Reciprocating Compressors Electrical Centrifugal Compressors Natural Gas (as Fuel) Electricity Fugitives Pipeline Operation Boundary of this thesis analysis 69 Energy Conversion Facilities Downstream activities Figure 3-2 Natural gas Bottom-up emissions estimator model structure used in this thesis (adapted from NETL study [33]) Gray boxes show venting, flaring and fugitive emissions. Orange boxes show energy and material sources that result in the release of GHG emissions. White boxes show thesis model activities in each life cycle stage. In the boundary of this analysis, red text shows the data source for default values are from Canadian data, black text shows the data source for default values are from US data, and blue text shows the data source for default values are from a combination of Canadian and US data (except for text shown in Gray boxes).

80 3.2.1 Preproduction The key difference between unconventional and conventional gas production is in the preproduction stage. This stage includes well construction and hydraulic fracturing, flowback water management, and well completion. Water management may include recycling, treatment in water treatment facilities, injection in water injection wells, etc. The thesis-specific modifications in the NETL model are discussed as follows: The energy consumed in fracturing (mostly energy consumed by pumps that inject fracturing fluid into the well) was not considered in the NETL model. Based on the Jiang et al. model and their method to estimate shale gas emissions, which is the most comprehensive study for calculating preproduction stage emissions among all reviewed US studies [30], this activity is considered in the thesis model. The Jiang et al. model, however, assumed only diesel was used to pump during fracturing. In Canada, both natural gas fueled pumps and diesel pumps can help operators in fracturing operations therefore, both are considered in the thesis model [85]. The NETL model only used water as the requisite material for fracturing, a process known as slickwater treatment. In Canada, however, other methods, such as energized fracturing or energized slickwater, are used in the industry [7]. The frequency of each of these methods is not clear, but most of the energized fracturing are within the Montney formation [7]. For these methods, N2 and/or CO2 are also injected during fracturing as a part of the stimulation. In the thesis model, the diesel used in transportation trucks for water, proppants such as sand, and energized gases (i.e. CO2 and N2) are considered. 70

81 The flowback water can have different fates. In the NETL model, three destinies were assumed for this water: o o o Recycle and reuse for other well fracturing operations Sent to water treatment facilities Sent to crystallization facilities In this thesis model, water disposal wells is added as another fate. Crystallization facilities are assumed a part of treatment facilities. So this thesis model considers water treatment facilities as one of the fatse of flowback water, which can process water in different ways (e.g. crystalize, removing dissolves salt and other contaminant, etc.). This modification is made since water disposal wells is more common in Canada than crystallization facilities [86]. Using different types of pumps (i.e. gas fuel and diesel fuel [85]) for injecting flowback water into water disposal wells (mostly abandoned wells) and transporting flowback water to water disposal wells can lead to energy consumption and result in additional emissions. Gas composition can have an effect on the volume of CO2 and methane venting and flaring emissions. While in the US the range of CO2 concentration in the gas produced is between 0.1% and 1.5%, Horn River has higher ranges than the US with 4% to 22% (average of 12%) of CO2 concentration and must be taken into account when venting and flaring emissions are modeled. This model is modified to consider this variable in the upstream stages. 71

82 3.2.2 Production Activities included in the production stage include workover activities, liquid unloading, pneumatic devices (e.g. controllers and pumps) and other operations that lead to venting, flaring or fugitive emissions. The modifications made to create the thesis model from the NETL model for the production stage are: In the thesis model, workover operations have been separated into two sub sections: a) re-fracturing shale gas wells to increase production, b) activities other than re-fracturing (e.g. shutting down the well for a period of time for maintenance, replacing production tubing, etc.). This modification makes it easier to separate the frequencies of these two sets of activities. Since they do not have similar emission factors and, may have different frequencies, they are treated separately. The liquid unloading operation removes water or condensates from the well to increase production. In the NETL model, liquid unloading is assumed to be necessary only for conventional wells. The thesis model assumes the operation is optional in shale gas operations, especially in the Montney region where a portion of the formation has liquid rich products [87]. Given the absence of frequency of liquid unloading data in Canada, the most updated US values from EDF study are used as the base case [13]. Liquid unloading events can be separated as plunger lift unloading and non-plunger-lift unloading. Plunger lift helps to remove the accumulated water and other condensate from the wellbore by shutting, then reopening the well bore. If the plunger returns to the surface as expected, no vent or flare is required and the gas in the separator is routed for sale. In some cases, if the plunger does not return to the surface as expected, the plunger controller may direct the 72

83 flow to an atmospheric pressure vent, such as a vented tank [13]. In the absence of plunger lifts, most of the flow in liquid unloading operations is either vented or flared (based on venting/flaring regulation in that jurisdiction). The thesis model assumes that all liquid unloading operations are without plunger lifts in the base case. This is a conservative assumption considering that no Canadian public data were found regarding these activities. As discussed by Allen et al. [14], however, liquid unloading operations are one of the most variable parameters from well to well. Therefore, further investigation into liquid unloading operations in the Canadian context is needed. Pneumatic devices were not a separate unit in the NETL model. In the thesis model, these devices are modeled based on the Prasino group report [63]. They estimated individual pneumatic devices (different controllers and pumps) emission factors in cubic meters of natural gas vented per hour. For example, a generic piston pump has a 0.6 (m 3 /hr) average bleed rate in Prasino group report. To implement the Prasino group method, activity data (activities such as types and number of the pneumatic devices in the facilities and their operating times) are needed. Because, none of these activity data are public, this thesis model cannot use Prasino s values. However, thesis model allows future researchers to use Prasino s method when activity data are public. Pneumatic emissions in this thesis are read from the most updated US values in Allen et al. (one of the EDF studies[14]) because of gap in Canadian data. Allen et al. average national emissions are used considering natural gas production rates in BC and US. 73

84 3.2.3 Processing Processing activities included in the NETL and thesis models differ only slightly. Both include acid gas removal, dehydration and compressor stations; the rest of the emissions that are not accounted for anywhere else in the model are grouped as other point source emissions, other fugitive emissions and valve fugitive emissions. It is assumed that acid gas removal operations in both models used amine-based chemical absorption processes. However, emissions from different natural gas processing operations (e.g. physical absorption, physical adsorption, permeation (membrane), etc. [88]) are available and should be explored in future studies. The main differences in the processing stage between the NETL and thesis models are in two sections: Dehydration is necessary to remove water from raw natural gas, to make it suitable for pipeline transport and increase its heating value. The configuration of a typical dehydration process includes an absorber vessel in which a glycol-based solution comes into contact with a raw natural gas stream (and absorbs its water content), followed by a stripping column in which the rich glycol solution (water) is heated to drive off the water and regenerate the glycol solution. The regenerated ( water-free ) glycol solution (the lean solvent) is recirculated to the absorber vessel. Some systems have flash separators to capture most of the natural gas in the water rich glycol solution before regeneration. The NETL did not model these separators, whereas for this thesis, separators are modeled and potential fates (i.e. vent, flare or use elsewhere) for the subsequently captured natural gas were considered. 74

85 Compressors are used to increase the gas pressure for pipeline transmission and distribution. NETL assumed three types of compressors: o o o Reciprocating compressors (the most common) Gas-powered centrifugal compressors (mostly used in offshore extraction) Electrically powered centrifugal compressors (used in extraction sites near sources of electricity) The same types of compressors are duplicated in the thesis model. NETL used shares (e.g. amount of natural gas compressed with reciprocating compressors on a national level over total natural gas produced in US) of each compressor type on the national level. In this thesis, the actual amount of natural gas being compressed with different types of compressors (i.e. reciprocating, centrifugal, and electrical) are considered on a facility level. The bottom-up analysis for Horn River and Montney use formation level data (i.e. data associated with specific formations as opposed to province level data that does not differentiate between activities among formations) in natural gas sweetening [15], [84]. This means that all the activities assumed in the processing stage are considered to be similar for Horn River, Montney, and BC conventional except for sweetening in this thesis. Gas composition data, especially CO2 concentrations, are taken into account when modeling sweetening [56] Transmission Transmission is very similar in both the NETL and thesis models, including emissions from pipeline construction (installation and de-installation) and transmission operations (both fuel use emissions and fugitive emissions). It should be mentioned that in the transportation stage, estimates for the rate of fugitive emissions from pipelines are obtained from the most updated values in the 75

86 US from EDF study in 2015 [72]. However, Canadian specific fugitive emissions from transmission are needed to improve the applicability of these estimates Populating the model In order to run the bottom-up analysis, formation specific data are used to populate the model whenever possible. Therefore, the base case estimates emissions for an average MJ of natural gas produced in 2013 (where possible, Montney/Horn River and BC conventional specific data is used; when not available, BC, Canadian or US data were selected). Parameters used in this thesis model and the data sources of the default value include: Formation data (i.e. Montney/Horn River data [7], [15], [54], [56], [89]): o Diesel use for drilling o Estimated Ultimate Recovery factor (EUR) per well o Water needed for hydraulic fracturing o Amount of flowback water (produced water) o Gas composition of Horn River o Annual natural gas that is sweetened BC or Canadian data [15], [18], [59]: o Total depth of well o Diesel use for fracturing (for pumping fluids) o Annual production o Other point source emissions vented (annually) o Other point source emissions flared (annually) 76

87 o Other fugitive emissions from production (annually) o Annual methane vented during amine regeneration o Annual carbon dioxide vented during amine regeneration (considering gas composition in each formation) o Annual natural gas that is dehydrated o Annual methane vented during glycol regeneration o Annual methane flared during glycol regeneration o Other point source emissions vented in processing o Other fugitive emissions released in processing o Annual natural gas released from reciprocating compressors o Length of transmission pipeline o Natural gas consumption rate in transmission o Transmission flow rate US data (NETL as well as Wood et al. values[33], [90]): o Well Diameter o Thickness of well casing o Well Lifetime o Diesel use in trucks for water delivery to well site o Diesel use in trucks for sand/proppants delivery to well site o Diesel use in trucks for CO2/N2 delivery to well site o % of flowback water that is recycled o % of flowback water that is sent to a wastewater treatment plant o Diesel use in trucks for flowback water management 77

88 o Emissions intensity from waste water treatment plant o Electricity use for water treatment o Gas composition of Montney and BC conventional o Frequency of workover episodes o Annual natural gas used in reboiler as fuel (Sweetening) o Annual natural gas used in reboiler as fuel (Dehydration) o Annual methane vented after capturing in separators o Annual methane flared after capturing in separators o Annual natural gas compressed with reciprocating compressors o Annual natural gas used as fuel in gas powered compressors o % of compressors using gas VS electricity in transmission system o Annual electricity use in centrifugal compressors o Diameter of pipeline o Average thickness of pipe wall o Estimated lifetime of pipeline o Diesel use in equipment o Diesel use in delivery trucks In the case of four parameters, data from US EDF studies, the most recent values in this context in North America, are used as the data source [69], [72]. These values are determined to be appropriate since they are based on direct measurements and reliable updated emissions estimates, considering that no relevant Canadian data were found (except for fugitive emissions from pipelines available in GHGenius model which is based on 2004 activities). This GHGenuis 78

89 data is considered outdated, and effect of using US data for this parameter is investigated in sensitivity analysis. These four parameters include: o Well completion emissions in the preproduction stage (assumed to be similar with workover emissions) o The amount of gas that is emitted during liquid unloading in the production stage, annually o Volume of gas vented by Pneumatic devices o Fugitive emissions rates from pipelines in transmission stage Appendix A presents the values and the ranges for all parameters used in the thesis model Sensitivity analysis in Bottom-up analysis The results for the bottom-up analysis are uncertain because the data used are not gathered from a unique source and there is uncertainty associated with all data. Uncertainty such as measurement errors and variability such as different formation characteristics or different times are contributing to overall uncertain results. Appendix A shows the details of the data sources and the ranges for each parameter in characterizing emissions from Montney and Horn River, as well as conventional natural gas development in western Canada. A sensitivity analysis is conducted to show which parameters can affect the emissions estimates of the final results. A range of plus and minus 50% variations are used for most of the parameters, unless a reasonable range of data was found in the relevant literatures and data sources. Plus and minus 50% is assumed an average estimate since it is approximately covers most of the other ranges found in data sources. Six of the most influential parameters from each stage are presented to illustrate the parameters that should be prioritized in future data collection exercises. 79

90 80

91 RESULTS AND DISCUSSION The life cycle GHG emission factors of natural gas development in western Canada are explored and presented in this chapter. 4.1 Top-down results Results from the top-down analysis in this section are broken down into the following subsections: 1. Facility level emission factor 2. Company level emission factor 3. Provincial level emission factor Facility level emission factors Facility level emission factors are for different facility types and show the range of emission factors for each type. Figures 4-1 to 4-5 show the facility emission factors of five different facility types (central dehydration, compressor station, gas plant, sour gas plant, and sweet gas plant). According to the well level production data, more than 99% of the production associated with these facilities was natural gas rather than oil. As presented in Figure 4-1, the facility emissions data from 12 individual central dehydration facilities was linked to the well level production data and helped to estimate emission factors for this facility type. 81

92 Emission factors (g CO2e/MJ NG linked to facility) Total Stationary Combusion Total Flaring Total Venting Total Fugitive Figure 4-1 Central Dehydration facilities emission factors in BC in (The facility names are stated in parenthesis, after the company name)- A * shows that the facility types were not stated in the facility emissions data and the oil and gas codes data (data source for production linked to each facility) was used to find facility types. Results are presented as emission factors in units of g CO 2 e/mj natural gas linked to each facility. According to Figure 4-1, emissions from stationary fuel combustion were responsible for more than 95% of the total emissions in every facility, except for Penn West s Firebird Central Dehydration Facility. Venting activities from this facility contributed 37% of its total emissions in Considering strict venting/flaring regulations in BC [16], which enforces flaring instead of venting where possible, this facility may have had several situations/incidents in 2013 where flaring was not possible and gas was vented instead. Given the current public data, however, no reliable reason for this extreme venting activity is available for this facility. Yet comparing this extreme value with their previous years emissions, would clarify whether this large emissions was associated with an accident or it was related to facility's performance during

93 Generally, 95% of the emissions associated with stationary fuel combustion appears high (compared with the US range of 60% to 90% [33]). However, since a large portion of emissions from dehydration facilities could not be linked to their production data. Therefore, while generally informative of the range of emission factors possible, the associated uncertainties with these emissions factors should be investigated further prior to confirming their representativeness. Dehydrating one MJ of natural gas in these facilities emitted from less than 0.6 to nearly 8.7 grams of CO2e, with an average, median, and standard deviation of 2.6, 1.8, and 2.1 grams of CO2e, respectively. This variability can be explained as follows. First, considering that roughly 95% of the GHG emissions for these facilities are emitted from stationary fuel combustion, different energy and fuel efficiencies (e.g., related to age of the equipment) across these facilities would cause variability in stationary fuel combustion emissions. Second, based on currently available public data, the boundaries of each facility and respective activities are not clear. This means that it is not clear if the facilities with highest and lowest emission factors have the same equipment within their boundaries. For instance, for facilities with higher emission factors, other equipment, such as compressors (which could increase facility emissions), could exist within their boundary. But the company may categorize that facility as part of central dehydration since the primary purpose is to remove water from the natural gas. Third, the water content of raw natural gas in each region is variable and can affect the dehydration emission factors (i.e. the higher the water content in raw natural gas, the more energy is required for its removal which results in more emissions). Emission factors from 17 individual compressor station facilities are presented in Figure 4-2. This figure includes only the compressor stations that were disaggregated from other activities, and where emissions and production data could be matched at a facility level. 83

94 Emission factors (g CO2e/MJ NG linked to facility) Total Stationary Combusion Total Flaring Total Venting Total Fugitive Figure 4-2 Compressor Station facilities emission factors in BC in (The facility names are stated in parenthesis, after the company name)- A * shows that the facility types were not stated in the facility emissions data and the oil and gas codes data (data source for production linked to each facility) was used to find facility types. A ** shows that there were inconstancies in facility types in facility emissions data and the oil and gas codes data, and the facility types in facility emissions data were used in this thesis. Results are presented as emission factors in units of g CO 2 e/mj natural gas linked to each facility. According to Figure 4-2, the emission factors span more than one order of magnitude for different compressor station facilities in BC. The average, median, and standard deviation for these results are 4.1, 2.7, and 3.5 g CO2e/ MJ natural gas, respectively. One of the most important reasons for the variability in these emission factors (from 0.3 to 12.8 g CO2e per MJ natural gas) is likely the variability in the distance between each natural gas compressor station. Compressing natural gas for transport across small distances requires less fuel than longer distances. The destination of the gas after it leaves the compressor station is not available in the public data. 84

95 The highest emission factor across all of compressor facilities is Conoco Philips s Hiding Creek 2 compressor station, with a significant amount of venting activities compared with other compressor stations. Similar to Penn West s Firebird Central Dehydration Facility, no explanation for this is provided in public data. Another important note from this figure is that Conoco Philips s compressor station facilities (Hiding Creek 1&2) reported no flaring activities. The breakdown of emissions by types shows stationary fuel combustion, on average, contributed 85% of the total emissions of compressor stations. Compared with central dehydration, this value seems more reasonable. Because no processing procedure (e.g. processing activities that aim to remove specific components from natural gas) that need energy in forms of fuel combustion is used in compressor stations. Emission factors from 11 gas plant facilities in BC are presented in Figure 4-3. Similar to the other facility types discussed to this point, these are not all the gas plants that operated in BC during

96 Emission factors (g CO2e/MJ NG linked to facility) Total Stationary Combusion Total Flaring Total Venting Total Fugitive Figure 4-3 Gas Plant facilities emission factors in BC in (The facility names are stated in parenthesis, after the company name)- A * shows that the facility types were not stated in the facility emissions data and the oil and gas codes data (data source for production linked to each facility) was used to find facility types. A ** shows that there were inconstancies in facility types in facility emissions data and the oil and gas codes data, and the facility types in facility emissions data were used in this thesis. Results are presented as emission factors in units of g CO 2 e/mj natural gas linked to each facility. As shown in Figure 4-3, the highest and lowest emission factors for gas plant facilities are from Penn West s Wildboy and ARC Resources Parkland, with 5.7 and 0.7 g CO2e / MJ natural gas, respectively. The average, median, and standard deviations for gas plant emission factors are 2.7, 2.8, and 1.6 g CO2e per MJ natural gas produced, respectively. A lower standard deviation compared with compressor stations and central dehydration shows the data were closer to the average point and is spread over a narrower range of values. The smaller amount of standard deviation shows that most of these facilities have similar emissions ranges. This suggests that gas plants in BC have similar operations and processes (e.g. acid gas removals) which leads to closer emissions ranges compared to variabilities in compressor stations and dehydration facilities. 86

97 No outlier activity for venting or flaring can be seen in the emission factors of these gas plants in Figure 4-3 compared with central dehydration and compressor stations. This suggests that similar procedures for venting and flaring activities were used in these gas plants. These procedures can include removing H2S and CO2 from natural gas with amine based processes in AGR facilities. In this process, a portion of methane is absorbed in amine solutions and is vented (or flared) to atmosphere in gas plants. Most of the variability in emission factors for gas plants came from the combustion activities. Gas plants facilities are used to process the gas and, based on the gas composition and reservoir characteristics of the producing wells linked to them etc., they can be associated with different operations. This variability in operations, for example gas plants that only remove the H2S from natural gas compared with gas plants that remove both H2S and CO2 from natural gas - can cause variability in emission factors. In addition, more energy efficient facilities have lower emission factors associated with burning fuel to operate gas plants. Also, similar to central dehydration facilities, details about the boundaries and operations associated with each gas plant facility can be useful to explore the variability in emission factors. For example, some gas plants may include only sweetening operations while others include both sweetening and removing nonmethane hydrocarbons (e.g. ethane, propane, etc.). Current public data does not include detailed descriptions of the activities and operations for gas plant facilities and future investigation is needed.five gas plant facilities in the facility emissions data, however, included the type of gas (i.e. sour vs sweet) they treated. Emission factors of these facilities are shown in Figure 4-4 for sour gas, and in Figure 4-5 for sweet gas. 87

98 Emission factors (g CO2e/MJ NG linked to facility) Emission factors (g CO2e/MJ NG linked to facility) Total Stationary Combusion Total Flaring Total Venting Total Fugitive Endurance Energy Ltd. (Sierra) Canadian Natural Resources Limited (Cypress) Figure 4-4 Sour Gas Plant facilities emission factors in BC in (The facility names are stated in parenthesis, after the company name). Results are presented as emission factors in units of g CO 2 e/mj natural gas linked to each facility. 2.5 Total Stationary Combusion Total Flaring Total Venting Total Fugitive Aux Sable Canada L.P. (Septimus) ConocoPhillips Canada Resources Corp. (Noel) Endurance Energy Ltd. (Elleh)** Figure 4-5 Sweet Gas Plant facilities emission factors in BC in (The facility names are stated in parenthesis, after the company name)- A ** shows that there were inconstancies in facility types in facility emissions data and the oil and gas codes data, and the facility types in facility emissions data were used in this thesis. Results are presented as emission factors in units of g CO 2 e/mj natural gas linked to each facility. Figure 4-4 shows that only two gas plant facilities stated sour gas as the type of gas they processed. Ranges of the emission factors are from 2.9 to 19.8 g CO2e per one MJ of natural gas that was processed in these two facilities. This is a significant range in emission factors which needs to be addressed. In the facility emissions data four sweet gas plant facilities emitted more than 10,000 tonnes of CO2e in Emissions of three of them could be matched to production and their emission factors as shown in Figure 4-5. The emission factors for these facilities have the lowest variability 88

99 compared with other facility types discussed, with a standard deviation of 0.3 g CO2e per MJ natural gas produced (average and median are the same and equal to 1.8). By comparing Figures 4-4 and 4-5, it can be seen that the minimum value of the sour gas plant emission factor is still higher than the maximum value of the sweet gas plant emission factor (2.9 compared with 2.1 g CO2e per one MJ of natural gas). This was expected since the sweet gas plants have to remove lower level of H2S or CO2 from natural gas. Figure 4-12 shows the range of emission factors for different facility types in BC, as well as the distribution of MJ of natural gas linked to each facility type. Results are based on 46 facilities: In Montney: 10 central dehydration facilities, 14 compressor station facilities, 1 gas plant, 1 sour gas plant and 2 sweet gas plants. In Horn River: 2 central dehydration facilities, 3 compressor station facilities, 1 gas plant, 1 sour gas plant and 1 sweet gas plant. 89

100 5.00E E E E E E E E E+10 >4.50E E E E E E E E E E E E E+10 >6.00E E E E E E E E E E+10 >4.50E E E E E+10 >3.50E E E E+10 >2.50E+10 # of facilities # of facilities # of facilities # of facilities # of facilities Emission Factors (g CO2e / MJ NG linked to facility) Central Dehydration Compressor Station Gas Plant Sour Gas Plant Sweet Gas Plant 6 4 Frequency of MJ natural gas linked to Central Dehydration facilities 6 4 Frequency of MJ natural gas linked to Compressor Station facilities 6 4 Frequency of MJ natural gas linked to Gas Plant facilities 6 4 Frequency of MJ natural gas linked to Sour Gas Plant facilities 6 4 Frequency of MJ natural gas linked to Sweet Gas Plant facilities MJ Natural Gas MJ Natural Gas MJ Natural Gas MJ Natural Gas MJ Natural Gas Figure 4-6 Range of emission factors for different facility types in BC in 2013 (upper figure presented in g CO 2 e / MJ natural gas linked to facilities) and the frequencies of MJ natural gas linked to each facility type. Please note that the Y axis of lower figures is not presented in the same range. The box-and-whisker plots in the upper figure are based on six statistical numbers: 1. Minimum emission factor, presented by the lower point of vertical lines; 2. The first quartile or Q1 (is the middle (the median) of the lower half of the data) of emission factors, presented in dark gray boxes; 3. The median of emission factors, presented with the black line in the box (the line between dark and light gray boxes); 4.The third quartile or Q3 (is the middle (the median) of the upper half of the data) of emission factors, presented in light gray boxes; 5.Maximum emission factor, presented by the upper point of vertical lines; 6. Outlier data (outlier = any data bigger or smaller than 1.5*(third quartile first quartile)) that falls outside of the range of other values, presented with X. 90

101 As presented in Figure 4-6, compressor stations have the largest range for emission factors compared to other types of facilities in BC, excluding sour gas plants (excluded due to small and highly variable data, as discussed after Figure 4-4). Exploring operational activities, specifically the type of compressors and the transport distances of each facility, can help to explain these variations, which is not possible with current public data. If the emission factor from the sour gas plants is excluded from the results in Figure 4-6, the median value of emission factors for the four remaining facility types are close; 50% of the emission factors are between 1.2 and 2.8 g CO2e per MJ natural gas. The difference is associated with the upper half of the data (third quartile) and the maximums that are not outliers (outlier is defined as a number which is less than Q1 or greater than Q3 by more than 1.5 times the interquartile range, IQR (IQR = Q3 Q1)). The caption of Figure 4-6 includes the definition of all statistical parameters used in this figure. Compressor stations emission factors have a higher third quartile as well as maximum values (excluding the outlier) compared with the rest of the facilities. As shown in this figure, however, the outlier emission factors of central dehydration facilities has higher emission factors than 75% of the compressor station s emission factors. To investigate emission factors of facilities between Horn River and Montney, it is necessary to bear in mind the number of each facility type in each region. Horn River is a newer natural gas field with, as expected, fewer number of facilities. The average emission factor for each facility type between Montney and Horn River is discussed as follows: Central dehydration: On an average basis, this facility type had an 11% higher emission factor in Montney than in Horn River. Montney, however, seems to have more wet gas than Horn River and the results shown in this thesis support this fact. 91

102 Compressor stations: On an average basis, this facility type had an 11% lower emission factor in Montney than in Horn River. Geographical differences in the formations explain this; since Horn River is in the northern part of northeastern BC, transmitting the gas to the mainline transmission and distribution systems results in more emissions when compared with Montney. Gas plant: On an average basis, this facility type had a 52% lower emission factor in Montney than in Horn River. Ten gas plants in this data are situated in Montney compared with only one in Horn River, suggesting this is not a fair comparison. The result was expected, however, as the gas composition in Horn River, especially the CO2 concentration, affect processing operations that could result in higher emissions. Sour gas plant: Only two facilities were used to develop sour gas plant emission factors, one in each region. The emission factor in Montney is nearly 7 times higher than that in Horn River however, no conclusion can be drawn from this result given the small sample size. Sweet gas plant: On an average basis, this facility type had 15% lower emission factor in Montney than in Horn River. Similar to what has been discussed in gas plants discussion, this result was expected. In the lower figures of Figure 4-6, frequencies of MJ of the natural gas linked to each facility type are shown. Gas plant facilities had a relatively normal distribution of production with the majority linked to wells with higher than 1.00E+10 MJ of natural gas production. For compressor stations and central dehydration facilities, however, the distribution is skewed to the left. This means that these facility types were linked to lower MJ of natural gas more frequently (when linking emissions and production data) than higher MJ of natural gas. This result suggests 92

103 Number of facilities that compressor stations and central dehydration facilities are typically smaller (in terms of production) compared with gas plants and, consequently, processed fewer amounts of natural gas. This is consistent with the fact that the level of reporting threshold for facilities in the facility emissions data (i.e. 10,000 tonnes of CO2e) affects compressor stations and central dehydration facilities rather than gas plants. For example, if the threshold was 5,000 tonnes of CO2e, the number of compressor stations and central dehydration facilities that report individual emissions estimates, would increase more than gas plants. So, one can argue that there are more compressor station and dehydration facilities sin aggregated emission format than gas plants and therefore, results emission factors associated with gas plants are fairly reliable. This fact is investigated in Figure 4-7, as well. This figure shows the distribution of facility types versus the amount of annual emissions. These results are based on the facility emissions data and not emission factors. Booster Station Central Dehydration Compressor Station 24 Gas Plant Sour Gas Plant Sweet Gas Plant Annual emissions (tones of CO2e / yr) Figure 4-7 Level of emissions in amounts and types of facilities in BC in Results are presented in number of facilities for each type of facility. 93

104 According to Figure 4-7, compressor stations emitted lower amounts of emissions (10,000 to 20,000 tonnes of CO2e) with the highest frequency, followed by central dehydration facilities. Gas plants are distributed within several ranges of emissions values. The data limitations led to using only 15% of BC s total GHG emissions to perform the facility level emission factors, and made this result less representative of the actual range of facilities GHG emissions. Linking remaining BC s total GHG emissions can help to develop more reliable ranges of facility emission factors and allow investigating variability in the emissions estimates more accurately. Relationship between facility level emission factors and well configuration Table 4-1 summarizes production from different well configurations in BC in 2013 based on the well level production data. Approximately 76% of natural gas production in BC was from fractured wells (there was not enough information to separate this between shale and tight gas). Assuming that the vertical wells that were not fractured were conventional reservoirs, 13% of BC's total natural gas was from conventional reservoirs in In addition, the rig release dates (the date that wells start to produce), presented in Table 4-1, are consistent with the fact that the production from shale and tight gas reservoirs is the most recent and common production method in BC; fractured wells were rig released more recently (on average 2010) than the other configurations. 94

105 Table 4-1 Gas production and rig release dates based on 2013 the well level production data in BC [18] Well configuration Horizontal Fractured Vertical Fractured Horizontal Not Fractured Vertical Not Fractured # of wells producing in 2013 Total production in 2013 (MJ) % of total Production in BC in 2013 Average Rig release date of wells E+12 62% E+11 14% E+11 12% E+11 13% 1987 The majority (62%) of total natural gas production in BC in 2013, was from horizontally fractured wells, followed by vertical fractured wells with 14% of production. Figure 4-8 shows the amount of production associated with different configurations of wells in northeastern BC. It should be noted that the height of the bars in this figure is relative to the amount of natural gas produced in each region. 95

106 Figure 4-8 Dispersion of different configurations of wells and their 2013 annual production in northeastern BC. Presented in cubic meter per year (i.e. 2013).F, H: Fractured Horizontal wells, F, V: Fractured Vertical wells, NF, H: Not Fractured Horizontal wells, NF, V: Not Fractured Vertical wells. Height of the bars shows the amount of production in each region. Map is adapted from Montney formation atlas, provide by BC oil and gas commission [89] 96