OIL & GAS PRODUCTION PROTOCOL€¦ · Stirling Bates, British Columbia ... 4.2 Option 1: Reporting...

THE CLIMATE REGISTRY

OIL & GAS PRODUCTION PROTOCOL

VERSION 1.1

JUNE 2009

The Climate Registry –Oil & Gas Production Protocol DRAFT

The Climate Registry 2 O&GP Protocol – DRAFT

ABOUT THIS PROTOCOL

The Oil and Gas Production (O&GP) protocol was developed to provide guidance to Members of The Climate Registry (The Registry) for calculating and reporting greenhouse gas (GHG) emissions from sources in the Oil and Gas (O&G) Exploration and Production (E&P) sector. The (O&GP) protocol is an appendix of The Registry’s General Reporting Protocol (GRP), and as such it specifies additional reporting requirements and options for Members in the O&G E&P sector. It also provides clarification of some of the GRP concepts and requirements and how they should be applied to this sector, as well as additional calculation methodologies for sources unique to the sector. However, O&G E&P Members will still need to use the GRP as their primary source document for understanding The Registry’s basic reporting requirements and for quantifying emissions from many of their sources. In order to facilitate coordinated use of the GRP and this protocol, the organization of the O&GP protocol closely mirrors that of the GRP. The development of this draft was sponsored by the Western Governors Association’s (WGA) Western Regional Air Partnership (WRAP), and it benefitted from the substantial input provided by WRAP’s O&G E&P sector Technical Workgroup. Oil and Gas Sector Technical Workgroup

Bob Savage, Alberta Environment Ministry Karin Ritter, American Petroleum Institute Reid Smith, BP Petroleum Stirling Bates, British Columbia Petroleum Ministry Byard Mosher, California Air Resources Board Bill Winkler, California Department of Conservation Rock Zierman, California Independent Petroleum Association Krista Phillips, Canadian Association of Petroleum Producers Coleen West, Canadian Association of Petroleum Producers Mark Nordheim, Chevron – Texaco Craig Bock, El Paso Exploration & Production Tim O’Connor, Environmental Defense Roger Fernandez, EPA – Natural Gas STAR Alberto Cruzado, Mexico: SEMARNAT Air Quality Tom Singer, Natural Resource Defense Council Mike Schneider, New Mexico Air Quality Bureau Mark Fesmire, New Mexico Oil Conservation Commission Terry Snyder, Santa Barbara County APCD Arun Naik, Shell Oil & Gas Company Jill Gravender, The Climate Registry Sam Hitz, The Climate Registry Jim Tangeman, Williams Production Stephen Russell, World Resources Institute Jennifer Knowlton, Yates Petroleum



CONTENTS

ABOUT THIS PROTOCOL ...........................................................................................................2 CONTENTS ..................................................................................................................................3 ABBREVIATIONS AND ACRONYMS...........................................................................................6 LIST OF FIGURES .......................................................................................................................8 LIST OF TABLES..........................................................................................................................8 LIST OF EQUATIONS ..................................................................................................................9 LIST OF EXAMPLES ..................................................................................................................10 PART I: INTRODUCTION...........................................................................................................12 PART II: DETERMINING WHAT YOU SHOULD REPORT........................................................16

Chapter 1: Introduction.....................................................................................................16 1.1 GHG Accounting and Reporting Principles....................................................................16 1.2 Origin of The Registry’s GRP ........................................................................................16 1.3 Reporting Requirements................................................................................................16 1.4 Annual Emissions Reporting..........................................................................................16

Chapter 2: Geographic Boundaries..................................................................................17 2.1 Required Geographic Boundaries .................................................................................17 2.2 Optional Reporting: Worldwide Emissions.....................................................................18

Chapter 3: Gases to Be Reported....................................................................................19 3.1 Required Reporting of All Six Internationally-Recognized Greenhouse Gases.............19 3.2 Optional Reporting: Additional Greenhouse Gases.......................................................19

Chapter 4: Organizational Boundaries .............................................................................20 4.1 Two Approaches to Organizational Boundaries: Control and Equity Share ..................20 4.2 Option 1: Reporting Based on Both Equity Share and Control ......................................20 4.3 Option 2: Reporting Using the Control Consolidation ....................................................21 4.4 Corporate Reporting: Parent Companies & Subsidiaries ..............................................22 4.5 Government Agency Reporting .....................................................................................22 4.6 Leased Facilities/Tenants and Landlord/Tenant Agreements .......................................23 4.7 Further Examples of Control versus Equity Share Reporting ........................................25

Chapter 5: Operational Boundaries..................................................................................29 5.1 Required Emission Reporting ........................................................................................29 5.2 Direct Emissions: Scope 1.............................................................................................29 5.3 Indirect Emissions: Scope 2 ..........................................................................................29 5.4 Reporting Emissions from Biomass Combustion...........................................................30 5.5 Scope 3 Emissions ........................................................................................................30

Chapter 6: Facility-Level Reporting..................................................................................32 6.1 Required Facility-Level Reporting..................................................................................32 6.2 Defining Facility Boundaries ..........................................................................................32 6.3 Optional Aggregation of Emissions from Certain Types of Facilities .............................34 6.4 Categorizing Mobile Source Emissions .........................................................................34 6.5 Optional Reporting: Unit Level Data ..............................................................................34 6.6. Aggregation of Data to Entity Level ..............................................................................34



Chapter 7: Establishing and Updating the Base Year......................................................35 7.1 Required Base Year ......................................................................................................35 7.2 Updating Your Base Year Emissions.............................................................................35 7.3 Optional Reporting: Updating Intervening Years ...........................................................37

Chapter 8: Transitional Reporting (Optional) ...................................................................38 8.1 Reporting Transitional Data ...........................................................................................38 8.2 Minimum Reporting Requirements for Transitional Reporting.......................................38 8.3 Public Disclosure of Transitional Data ...........................................................................38

Chapter 9: Historical Reporting (Optional) .......................................................................39 9.1 Reporting Historical Data...............................................................................................39 9.2 Minimum Reporting Requirements for Historical Data...................................................39 9.3 Importing Historical Data ...............................................................................................39 9.4 Public Disclosure of Historical Data...............................................................................39

PART III: QUANTIFYING YOUR EMISSIONS ...........................................................................40 Chapter 10: Introduction to Quantifying Your Emissions .................................................40 Chapter 11: Simplified Estimation Methods .....................................................................43 Chapter 12: Direct Emissions from Stationary Combustion .............................................46

12.1 Measurement Using Continuous Emissions Monitoring System Data.........................46 12.2 Calculating Emissions from Stationary Combustion Using Fuel Use Data ..................46 12.3 Allocating Emissions from Combined Heat and Power (Optional)...............................46 12.4 Calculating Emissions for Stationary Combustion Devices Lacking Fuel Use Data ....46

Chapter 13: Direct Emissions from Mobile Combustion...................................................57 13.1 Calculating Carbon Dioxide Emissions from Mobile Combustion................................57 13.2 Calculating Methane and Nitrous Oxide Emissions from Mobile Combustion.............57 13.3 Example: Direct Emissions from Mobile Combustion ..................................................57

Chapter 14: Indirect Emissions from Electricity Use ........................................................58 14.1 Quantifying Indirect Emissions from Electricity Use ....................................................58

Chapter 15 Indirect Emissions from Imported Steam, District Heating, Cooling and Electricity from a CHP Plant ....................................................................................................59

15.1 Calculating Indirect Emissions from Heat and Power Produced at a CHP Facility......59 15.2 Calculating Indirect Emissions from Imported Steam or District Heating from a Conventional Boiler Plant ....................................................................................................59 15.3 Calculating Indirect Emissions from District Cooling ...................................................59

Chapter 16 Direct Fugitive Emissions ..............................................................................60 16.1 Calculating Direct Fugitive Emissions from Refrigeration Systems .............................60

PART IV: REPORTING YOUR EMISSIONS ..............................................................................61 Chapter 17: Completing Your Annual Emissions Report .................................................61

17.1 Additional Reporting Requirements .............................................................................61 17.2 Optional Data...............................................................................................................61

Chapter 18: Reporting Your Data Using CRIS.................................................................63 18.1 CRIS Overview ............................................................................................................63 18.2 Help with CRIS ............................................................................................................63

Chapter 19: Third-Party Verification.................................................................................64 19.1 Background: The Purpose of The Registry’s Verification Process ..............................64



19.2 Activities To Be Completed by the Member in Preparation for Verification .................64 19.3 Batch Verification Option .............................................................................................64 19.4 Verification Concepts...................................................................................................64 19.5 Verification Cycle .........................................................................................................65 19.6 Conducting Verification Activities.................................................................................65 19.7 Activities To Be Completed After the Verification Body Reports Its Findings ..............65 19.8 Unverified Emission Reports .......................................................................................65

Chapter 20: Public Emission Reports ..............................................................................66 20.1 Required Public Disclosure..........................................................................................66 20.2 Confidential Business Information ...............................................................................66

PART V: ADDITIONAL EMISSION CALCULATION METHODOLOGIES FOR SOURCES UNIQUE TO THE OIL AND GAS E&P SECTOR........................................................................68

Chapter 21: Fugitive Emissions .......................................................................................68 21.1 Flashing Losses from Tanks........................................................................................68 21.2 Working/Breathing Losses from Tanks........................................................................79 21.3 Vented Emissions from Pneumatic Devices ................................................................79 21.4 Vented Emissions from Natural Gas-Driven Chemical Injection Pumps .....................84 21.5 Wellhead and Facility Fugitive Losses.........................................................................88 21.6 Surface Collection Ponds ............................................................................................97 21.7 Transportation Sector - Gas Compressor Station........................................................98

Chapter 22: Vented Emissions.........................................................................................99 22.1 Amine Plant Process Venting ......................................................................................99 22.2 Dehydrators ...............................................................................................................102 22.3 Well Completions, Underbalanced Drilling, and Drilling Mud Degassing...................109 22.4 Well Blowdowns.........................................................................................................111 22.5 Vessel and Facility Upsets/Blowdowns and Compressor Engine Start-Ups and Shutdowns .........................................................................................................................112 22.6 Transportation Sector - Truck, Tanker, Rail Loading.................................................118 22.7 Transportation Sector - Pipeline Blowdowns and Pigging .........................................118

Chapter 23: Flaring Emissions .......................................................................................119 Chapter 24: Oil Sands and Oil Shale specific sources...................................................124

24.1 Oil Sands and Heavy Oil Upgrading Industry (OS/HOU)...........................................124 24.2 Hydrogen Unit............................................................................................................125 24.3 Upgrader Facilities.....................................................................................................128 24.4 Flue Gas Desulphurization ........................................................................................130 24.5 Oil Sands Mines and Ponds Emissions .....................................................................131

ATTACHMENT 1: GLOSSARY OF TERMS .............................................................................132 ATTACHMENT 2: CONVERSION TABLES .............................................................................141 ATTACHMENT 3: COMBUSTION EMISSION FACTORS .......................................................143

The Climate Registry –Oil & Gas Production Protocol

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ABBREVIATIONS AND ACRONYMS

AEUB Alberta Energy and Utilities Board API American Petroleum Institute bbl Barrels BTU British Thermal Unit(s) C Carbon CAC Criteria Air Contaminant CaCO3 Calcium Carbonate; Limestone CAPP Canadian Association of Petroleum Producers CEM Continuous Emissions Monitoring CHP Combined Heat and Power CH4 Methane COP Coefficient Of Performance CO2 Carbon Dioxide EOS Equation of State EUB Energy Utility Board EU-ETS European Union Emission Trading Scheme EF Emission Factor FGD Flue Gas Desulphurization ft3 Cubic Feet GC/MS Gas Chromatography-Mass Spectrometry GHG Greenhouse Gas GOR Gas to Oil Ratio GWP Global Warming Potential H2 Hydrogen H2O Water HFC Hydrofluorocarbon HHV Higher Heating Value IPCC Intergovernmental Panel On Climate Change kg Kilogram(S) lb Pound m Meter m3 Cubic Meter MW Molecular Weight N Nitrogen N2 Nitrogen Gas NOx Oxides Of Nitrogen N2O Nitrous Oxide O2 Oxygen OS/HOU Oil Sands and Heavy Oil Upgrading PFC Perfluorocarbon RVP Reid Vapor Pressure SF6 Sulfur Hexafluoride


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t Tonne THC Total Hydrocarbon U.S. EPA United States Environmental Protection Agency VBE Vasquez-Beggs Equation VOC Volatile Organic Compound WBCSD World Business Council For Sustainable Development WRI World Resources Institute


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LIST OF FIGURES

Figure 1.1 - Overview of the Oil and Natural Gas Industry Sectors ............................................13

LIST OF TABLES

Table 4.1 - ACME Oil Company’s Reporting Responsibilities Under The Registry’s Two Main Reporting Options .......................................................................................................................21 Table 4.2 - Reporting Responsibilities for Two Members of a Consortium.................................22 Table 4.3 - Required Treatment of Emissions from Assets Covered by an Operating Lease by the Lessor and Lessee................................................................................................................23 Table 4.4 - Required Treatment of Emissions from Assets Covered by a Capital Lease by the Lessor and Lessee Under TCR’s Four Options ..........................................................................24 Table 4.5 – Beta Oil’s Reporting Responsibilities .......................................................................25 Table 4.6 – Alpha Oil’s Reporting Responsibilities .....................................................................26 Table 4.7 – JV Oil Reporting Responsibilities.............................................................................27 Table 4.8 – Reporting Responsibilities for Alpha ........................................................................27 Table 4.9 – Reporting Responsibilities for Beta..........................................................................28 Table 10.1 - Cross Reference of Oil and Gas Source Categories ..............................................40 Table 21.1 - CH4 Flashing Loss Emission Factors for Crude Oil Storage Tanks .......................78 Table 21.2 - Default Bleed Rates for Various Pneumatic Device Types by Manufacturer and Model ..........................................................................................................................................81 Table 21.3 - Default Bleed Rates for Various Pneumatic Device Types by Natural Gas Industry Segment......................................................................................................................................82 Table 21.4 - Default Molar Fraction Values of CH4 Used in Pneumatic Devices .......................84 Table 21.5 - Default CH4 Emission Rates for Various CIPs by Type and Operating Pressure...86 Table 21.6 – Component Level TOC Emission Rates by Industry and Facility Type .................90 Table 21.7 – Equipment Level CH4 Emission Rates by Industry and Facility Type ....................93 Table 21.8 – Equipment Level CH4 Emission Rates by Facility Type.........................................96 Table 22.1 - CH4 Emission Rates for Glycol Dehydrators by Natural Gas Industry Segment ..105 Table 22.2 - CH4 Emission Rates for Natural Gas-Driven Glycol Pumps by Natural Gas Industry Segment....................................................................................................................................106 Table 22.3 - Generalized CH4 Emission Rates for Glycol Dehydrators by Dehydrator Mode of Operation ..................................................................................................................................108 Table 22.4 - Mud Degassing Emission Factors ........................................................................110 Table 22.5 - Equipment Level CH4 Emission Rates by Facility Type.......................................116 Table 23.1 – GHG Emissions for Gas Flares............................................................................121 Table 23.2 - GHG Emission Factors for Liquid Flares ..............................................................122 Table 24.1 - Composition of U.S. Pipeline-Quality Natural Gas ...............................................127 Table 24.2 - Hydrogen Unit Simplified Emission Factors..........................................................127


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LIST OF EQUATIONS

Equation 12-1: Calculating CO2 Emissions from Compressors ..................................................47 Equation 12-2: Calculating CH4 Emissions from Compressors ..................................................47 Equation 12-3: Calculating N2O Emissions from Compressors ..................................................48 Equation 12-4: Calculating CO2 Emissions from Natural Gas Turbine Generators ....................49 Equation 12-5: Calculating CH4 Emissions from Natural Gas Turbine Generators ....................49 Equation 12-6: Calculating N2O Emissions from Natural Gas Turbine Generators ....................49 Equation 12-7: Calculating CO2 Emissions from Drill Rig and Workover Rig Engines ...............50 Equation 12-8: Calculating CH4 Emissions from Drill Rig and Workover Rig Engines ...............51 Equation 12-9: Calculating N2O Emissions from Drill Rig and Workover Rig Engines ...............51 Equation 12-10: Calculating CO2 Emissions from Heaters and Boilers ......................................52 Equation 12-11: Calculating CH4 Emissions from Heaters and Boilers ......................................52 Equation 12-12: Calculating N2O Emissions from Heaters and Boilers ......................................53 Equation 21-1: Annual Hydrocarbon Vapor Fugitive Emissions .................................................69 Equation 21-2: Hydrocarbon Vapor Volumetric Fugitive Emissions ...........................................70 Equation 21-3: CH4 and CO2 Emissions From Volumetric Fugitive Emissions...........................70 Equation 21-4: Specific Gravity of Gas .......................................................................................72 Equation 21-5: Flash GOR..........................................................................................................73 Equation 21-6: Standing Correlation...........................................................................................75 Equation 21-7: Standing Correlation – Crude Flash Occurring from Separator..........................75 Equation 21-8: EUB Rule of Thumb............................................................................................77 Equation 21-9: Calculating CH4 Emissions from Natural Gas-Driven Pneumatic Devices based on Bleed Rates ...........................................................................................................................80 Equation 21-10: CH4 and CO2 Emissions from Natural Gas-Driven Chemical Injection Pumps based on Emissions Factors.......................................................................................................85 Equation 21-11: CO2 and CH4 Emissions from Exploration and Production Facilities Based on Component Level Emission Factors ...........................................................................................88 Equation 21-12: CO2 and CH4 Emissions from Exploration and Production Facilities Based on Equipment Level Emission Factors.............................................................................................92 Equation 21-13: Correcting Default CH4 Emission Factors to Reflect Site-Specific CH4 Content....................................................................................................................................................94 Equation 21-14: CH4 to CO2 Emission Factor Conversion..........................................................94 Equation 21-15: CO2 and CH4 Emissions from Exploration and Production Facilities Based on Facility Level Emission Factors...................................................................................................95 Equation 21-16: Correcting Default CH4 Emission Factors to Reflect Site-Specific CH4 Content....................................................................................................................................................96 Equation 21-17: CH4 to CO2 Emission Factor Conversion..........................................................97 Equation 21-18: Gas Emitted from Non Re-injected Produced Waters ......................................98 Equation 22-1: CO2 and CH4 Emissions from Amine Units Based on Tests of Amine Unit Vent Emissions....................................................................................................................................99 Equation 22-2: CO2 and CH4 Emissions from Amine Units Using API’s AMINECalc Software 101 Equation 22-3: CO2 Emissions from Amine Units Using Mass Balance ...................................102


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Equation 22-4: CO2 and CH4 Emissions from Glycol Dehydrators Based on Tests of Dehydrator Vent Emissions .........................................................................................................................103 Equation 22-5: CO2 and CH4 Emissions from Glycol Dehydrators Based on Industry Segment Specific Emissions Factors .......................................................................................................104 Equation 22-6: Correcting Default Dehydrator CH4 Emission Factors to Account for Glycol Pumps, Flash Tank Separators, and Site-Specific CH4 Content Values ..................................107 Equation 22-7: CH4 to CO2 Emission Factor Conversion..........................................................107 Equation 22-8: CH4 Emissions from Glycol Dehydrators Using General Emissions Factors....108 Equation 22-9: Well Completion (Underbalanced Drilling) Emissions Estimation.....................110 Equation 22-10: Well Completion Emissions Estimation ..........................................................111 Equation 22-11: Emissions from Well Blowdowns....................................................................112 Equation 22-12: Alternative to Estimating Vented Gas Volume................................................112 Equation 22-13: Calculation of the Quantity of Gas Released From Non-Routine Activities ....114 Equation 22-14: Conversion From Moles of Gas to Mass of Gas Released from Non-routine Activities....................................................................................................................................114 Equation 22-15: CO2 and CH4 Emissions from Non-Routine Activities.....................................115 Equation 22-16: Correcting Default CH4 Emission Factors to Reflect Site-Specific CH4 Content..................................................................................................................................................117 Equation 22-17: CH4 to CO2 Emission Factor Conversion........................................................117 Equation 23-1: Flared Emissions Estimation 1 .........................................................................120 Equation 23-2: Flared Emissions Estimation 2 .........................................................................120 Equation 23-3: Flared Emissions - Simplified Emissions Factors.............................................121 Equation 24-1: Extrapolation Model..........................................................................................124 Equation 24-2: Chemical Reaction to Obtain Hydrogen ...........................................................125 Equation 24-3:Material Balance Emissions Estimation.............................................................125 Equation 24-4: Stoichiometric Ratio Approach .........................................................................126 Equation 24-5: Emissions from Coker Units .............................................................................129 Equation 24-6: Emissions from Hydroprocessing Units............................................................129 Equation 24-7: CO2 Emissions from Flue Gas Desulphurization Using Mass Balance............130

LIST OF EXAMPLES

Example 2-1: Jurisdictional Boundaries......................................................................................17 Example 4-1: Reporting Based on Both Equity Share and Control ............................................20 Example 4-2: Reporting Under Financial Control .......................................................................22 Example 4-3: Treatment of Leased Assets under an Operating Lease ......................................23 Example 4-4: Treatment of Leased Assets under a Financial or Capital Lease .........................24 Example 11-1: Application of the 5 Percent Threshold for the Use of Simplified Estimation Methods to an Oil and Gas Leaseholder ....................................................................................44 Example 12-1: Direct Emissions from Stationary Combustion ...................................................46 Example 12-2: Calculating Emissions for a Stationary Combustion Device Lacking Fuel Consumption Data ......................................................................................................................53 Example 14-1: Indirect Emissions from Electricity Use...............................................................58


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Example 21-1: Flashing Loss Emissions Calculation using the Vasquez-Beggs Equation (VBE)....................................................................................................................................................73 Example 21-2: Flashing Loss Emissions Calculation using Standing Correlation ......................75 Example 21-3: Flashing Loss Emissions Calculation using the EUB Rule-of-Thumb Correlation....................................................................................................................................................77 Example 21-4: Flashing Loss Emissions Calculation using the Emission Factor .......................78 Example 23-1: Calculation of Combustion Emissions from a Gas Flare ..................................122


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PART I: INTRODUCTION

The Climate Registry (The Registry) has developed this document as a supplemental appendix to the General Reporting Protocol (GRP) for the Oil and Gas Production (OG&P) sector (See text box at the end of this introduction for a description of organizations that are required to use this appendix). While the GRP describes The Registry’s voluntary reporting program and provides the basic framework for all Registry Members to report their emissions of greenhouse gases (GHGs), this protocol is focused specifically on emissions from the Oil and Gas (O&G) Exploration and Production (E&P) sector. The GRP is designed to support the complete, transparent, and accurate reporting of a Member’s GHG emissions in a fashion that minimizes the reporting burden and maximizes the benefits associated with understanding the connection between fossil fuel consumption, energy production, and GHG emissions in a quantifiable manner. By joining The Registry, Members agree to report their GHG emissions according to the guidelines in the GRP and its appendices. The reporting requirements of the GRP are the governing requirements for all Members1 and as such, Members in the O&G sector must also follow the GRP. This appendix (here after referred to as the OG&P Protocol) defines the additional reporting requirements for O&G entities reporting to The Registry’s voluntary program and in some instances provides alternative provisions to those of the GRP. It also provides specific interpretation of the GRP reporting requirements, as deemed necessary, for the O&G E&P sector’s unique operations, including drilling and completions, workovers, and natural gas processing. Refining, transportation, storage and distribution of petroleum products, storage and distribution of natural gas productions are not addressed in the OG&P Protocol. A reporting protocol for natural gas transmission and distribution is also currently in the process of being developed. Traditionally, and for the purposes of this protocol, the definition of where E&P is completed and the next stage (transportation) begins has been defined as the point where custody of the oil or gas is transferred to a common carrier transportation pipeline or licensed carrier vessel. This point of custody transfer is a defining boundary for E&P and is used in a variety of federal regulations such as National Emissions Standards for Hazardous Pollutants (NESHAPS) and Title V air pollution permitting. Figure 1.1 shows an overview of the sector processes of the O&G industry.

1 The Registry changed its nomenclature from “Reporters” to “Members” in the fall of 2008 to reflect the leadership Members demonstrate by reporting their emissions to The Registry and to highlight that its Members are part of a group of organizations committed to the application of best practices in GHG reporting.


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Figure 1.1 - Overview of the Oil and Natural Gas Industry Sectors

Oil Industry Sectors

Note that this protocol does not address oil industry operations shown in the shaded area. The oil transportation sector (pipelines, trucks and crude oil tankers) will, pending Steering Committee approval, be added to the protocol.

Natural Gas Industry Sectors

Note that this protocol does not address natural gas operations shown in the shaded area. Straddle plants in the natural gas transportation sector will, pending Steering Committee approval, be added to the protocol.

In the case of oil production, the point of custody transfer is to a pipeline in many cases, but sometimes to a truck or offshore tanker that transports the oil for processing at a refinery. Refining activities, which are downstream of the custody transfer point, are outside of the boundary of E&P operations covered in the O&GP Protocol. In the case of natural gas production, the point of custody transfer is normally from a natural gas processing plant into a gas transmission pipeline. If natural gas processing to meet pipeline

Distribution Engine

Compressor Stations

Separator Gas Plant

Liquids Liquids LNG

Underground Well

C

C

Compressor Stations

Gas

Production Processing Transmission, Storage & Distribution

Drilling &

Exploration

Water Handling Including Steam

Gathering Separation & Distribution

Gas Treating Facilities

Gas Exporting Facilities

Injection (Water, Steam,

Oil & Gas Distribution

Oil Treating Facilities

Oil Exporting Facilities

Pumpjack

Production Transmission Storage

& Distribution

Processing

Drilling &


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transportation specifications is not required, the point of custody transfer occurs immediately after the production facilities.


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Applicability: Who Must Use the OG&P Protocol?

The OG&P Protocol must be used by Members that own or control oil or natural gas exploration and production operations. As defined by NAICS industry code 21111,2 this industry comprises establishments primarily engaged in operating and/or developing oil and gas field properties and recovering liquid hydrocarbons from oil and gas field gases. Such activities may include exploration for crude petroleum and natural gas; drilling, completing, and equipping wells; operation of separators, emulsion breakers, desilting equipment, and field gathering lines for crude petroleum and natural gas; and all other activities in the preparation of oil and gas up to the point of shipment from the producing property. This industry includes the production of crude petroleum, the mining and extraction of oil from oil shale and oil sands, the production of natural gas, sulfur recovery from natural gas, and the recovery of hydrocarbon liquids from oil and gas field gases. Specific components of NAICS industry 21111 include Crude Petroleum and Natural Gas Extraction (NAICS Code 211111) and Natural Gas Liquid Extraction (NAICS Code 211112). These can be described as follows:

Crude Petroleum and Natural Gas Extraction (NAICS Code 211111) This industry comprises establishments primarily engaged in (1) the exploration, development and/or the production of petroleum or natural gas from wells in which the hydrocarbons will initially flow or can be produced using normal pumping techniques; or (2) the production of crude petroleum from surface shales or tar sands or from reservoirs in which the hydrocarbons are semisolids. Establishments in this industry operate oil and gas wells on their own account or for others on a contract or fee basis.

Natural Gas Liquid Extraction (NAICS Code 211112) This industry comprises establishments primarily engaged in the recovery of liquid hydrocarbons from oil and gas field gases. Establishments primarily engaged in sulfur recovery from natural gas are included in this industry. A single entity may have operations that are represented in more than one of the above categories. These entities will need to meet the reporting requirements for all of the categories in which they have operations. Similarly, a single entity, such as a vertically integrated oil producer, refiner, and distributor, may own or control some emission sources falling within the scope of the OG&P Protocol, and some that fall outside this protocol’s scope. Such vertically integrated entities are required to use this protocol in conjunction with the GRP for reporting emissions from their upstream activities. Members that refine and/or distribute oil and gas products, but that are not involved in E&P activities (e.g., retail distributors and transportation companies) are not required to use this protocol. These Members should report using the GRP.

2 http://www.census.gov/epcd/naics02/def/NDEF211.HTM#N211


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PART II: DETERMINING WHAT YOU SHOULD REPORT

Chapter 1: Introduction

1.1 GHG Accounting and Reporting Principles REFER TO GRP.

1.2 Origin of The Registry’s GRP REFER TO GRP.

1.3 Reporting Requirements REFER TO GRP.

1.4 Annual Emissions Reporting REFER TO GRP.


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Chapter 2: Geographic Boundaries

2.1 Required Geographic Boundaries The Registry requires that all emissions from sources located in Canada, Mexico and the U.S. be reported and that emissions that occur on lands designated to Native Sovereign Nations be explicitly identified. The reporting of emissions from sources outside of North America is encouraged but not required. Emissions must be reported at the facility level by the address of the facility and not by the state. For more information, please refer to the GRP.

OFFSHORE OIL AND GAS FACILITIES Offshore oil and gas facilities present some unique geographic boundary issues, particularly with respect to their location. When reporting to The Registry, Members are required to report emissions from offshore facilities according to the jurisdiction with leasing and regulatory authority over each facility. For example, in the U.S. most coastal states control the territory extending 3.45 statute miles from the shore (measured at mean low tide), and have jurisdiction to decide whether or not, and under what terms, to lease this territory for oil and gas E&P. Exceptions to the 3.45-mile limit apply to Texas and to the Florida Gulf coast, where state waters extend to three marine leagues (approximately 10.5 statute miles). Under international law, national control generally extends 200 nautical miles from the shoreline; the area enclosed within this 200-mile boundary is referred to as a nation’s Exclusive Economic Zone (EEZ). However, the EEZ may extend beyond 200 miles if the outer limits of the coastal margin go past that boundary. For the U.S. the EEZ extends beyond 200 miles north of Alaska, and along the Atlantic and Gulf Coasts. Along the Pacific Coast the standard 200-mile boundary applies. In the Gulf of Mexico, a small area, referred to as the “doughnut hole,” that lies beyond the EEZ’s of both Mexico and the U.S., has been divided between these two countries by treaty; hence the mineral resources of the Gulf of Mexico have been completely claimed. Example 2-1: Jurisdictional Boundaries

As an example of the application of these jurisdictional boundaries, let us suppose that at some point in the future a Member has five drilling platforms operating off the pacific coast. Two of these platforms, A and B, are located one mile and two miles, respectively, from the shoreline of California (as defined at mean low tide). Two more platforms, C and D, are each located approximately 50 miles from California’s shore. Finally, the fifth platform (platform E) is located in deep water 250 miles from California’s shoreline. In this case, emissions from A and B should be reported as California facilities. Emissions from offshore platforms C and D should be reported as U.S. emissions. Finally, the Member is not required to report emissions from platform E, as this platform lies in international waters. However, the Member does have the


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option of reporting platform E emissions as part of its worldwide emissions report (see Section 2.2 of the GRP).

2.2 Optional Reporting: Worldwide Emissions REFER TO GRP.


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Chapter 3: Gases to Be Reported

3.1 Required Reporting of All Six Internationally-Recognized Greenhouse Gases REFER TO GRP.

3.2 Optional Reporting: Additional Greenhouse Gases REFER TO GRP.


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Chapter 4: Organizational Boundaries

4.1 Two Approaches to Organizational Boundaries: Control and Equity Share The GRP provides two main options for defining organizational boundaries:

Option 1: Reporting based on both a control approach and the equity share approach; or Option 2: Reporting based exclusively on a control approach.

Please refer to the GRP for a basic definition and explanation of these two reporting options. Sections 4.2 and 4.3 below provide examples on how to apply these two options to situations common in the O&G E&P sector.

4.2 Option 1: Reporting Based on Both Equity Share and Control Under the control approach, the Member is required to report 100 percent of the emission from sources under its control, including both wholly owned and partially owned sources. The Registry has adopted the control approach as its minimum standard for defining organizational boundaries; thus both options require that, at a minimum, the sources under the Member’s control be included within the Member’s boundary. However, under Option 1 (reporting based on both equity share and control), in addition to reporting 100 percent of the emissions from sources under its control, the Member is also required to report emissions from those sources outside its control in proportion to its ownership share in those sources (unless the Member has no financial control or significant influence over a partially owned source, as would be the case for fixed asset investments and associated organizations not consolidated in the Member’s financial accounts). Example 4-1: Reporting Based on Both Equity Share and Control

An example will help to illustrate the application of Option 1 to an E&P company. ACME Oil Company is currently producing oil in three separate fields scattered throughout North America. ACME wholly owns and controls its production operations in Field A, while it has a 12-percent ownership stake in the operation controlled by Best Oil Company on behalf of a consortium of companies in Field B. Finally, as a partner of Best Oil Company with a 50-percent stake in a joint venture, ACME controls the drilling and production operations in Field C. Given this situation, ACME must report all of the emissions from its operations in Field A, as well as all of the emissions from the joint venture in Field C. The Field A and C emissions must be reported in their entirety regardless of whether ACME chooses to report using Option 1 or Option 2, because ACME controls the operations in these two fields. Conversely, if ACME and


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Best have formed a separate JV company in Field C with separate policies and management, ACME would not be required to report the emissions in Field C. However, under Option 1 (Control plus Equity Share reporting), ACME is also required to report 12 percent of the emissions of the consortium (i.e., its share of the consortium producing oil in Field B). Table 4.1 illustrates ACME’s Registry reporting responsibilities under each of the two main options for defining organizational boundaries. Table 4.1 - ACME Oil Company’s Reporting Responsibilities Under The Registry’s Two Main Reporting Options

ACME’s Reporting Responsibilities Under:

Operation ACME’s Ownership Stake

Does ACME Control the Operation? Option 1

(Control & Equity)

Option 2 (Control Only)

Field A 100% Wholly-Owned

Yes 100% of Emissions

100% of Emissions

Field B 12% of Consortium

No 12% of Emissions

No Reporting Responsibility

Field C 50% of Joint Venture (Partnership)

Yes 100% of Emissions

100% of Emissions

4.3 Option 2: Reporting Using the Control Consolidation In addition to providing Members with the option of including or excluding equity-share based emissions, the GRP also provides two different options for defining “control.” The two options are a follows:

Operational Control: Defined as the full authority to introduce and implement operating, health, safety, and environmental policies. Typically the entity that holds the operating license for an operation has operational control. In the case of the E&P sector, the entity with the authority to decide matters such as where and when to drill would have operational control.

Financial Control: Defined as the ability to direct the financial policies of the operation

with an interest in gaining economic benefits from its activities. Typically the entity holding the majority of the financial risks and benefits in an operation exercises financial control over the operation. In particular, an entity has financial control over an operation or subsidiary if the operation is fully consolidated in the entity’s financial accounts. Thus the activities of a wholly-owned subsidiary of an oil company would be under the financial control of the oil company.


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Under the GRP’s rules, if a company has full financial control over an operation, and is using financial control as its approach to defining its organizational boundary, then the company is required to report 100 percent of the operation’s emissions. However, if the company has joint financial control over the operation, then the company is required to report a percentage of the operation’s emissions equal to the company’s equity share in the operation. Example 4-2: Reporting Under Financial Control

To illustrate these reporting rules, consider the example presented in Table 4.2 below. In this example, ACME is a five percent shareholder, and Best Oil a 51 percent shareholder, in a consortium formed to develop the oil reserves in Field B. As the majority shareholder, Best Oil has been given operational control over the consortium’s activities. However, it shares joint financial control with another consortium member. ACME, on the other hand, has neither operational nor financial control over the consortium. Furthermore, as a minority shareholder, ACME does not have significant influence over the operating and financial policies of the consortium. In this situation, Best Oil must report 100 percent of the emissions from Field B (the consortium operation) if it chooses to use the operational control or operational control plus equity share option(s). However, because it exercises joint as opposed to full financial control, it would report only 51 percent of the emissions (i.e., its equity share—see Table 4.2) under the financial control option. ACME, on the other hand, would not report any emissions from the consortium under the financial control option, despite its 12 percent ownership stake, because it does not have any financial control or significant influence over the consortium. Under the control consolidation approach, a company is required to report its equity share of an operation only if it has significant influence over the financial policies of a consortium or joint venture. Table 4.2 - Reporting Responsibilities for Two Members of a Consortium

Item ACME Best Oil Ownership and Control of Field B Consortium

Percent Ownership 5% 51% Operational Control? No Yes Financial Control? No Shared (Joint)

4.4 Corporate Reporting: Parent Companies & Subsidiaries REFER TO GRP.

4.5 Government Agency Reporting REFER TO GRP.


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4.6 Leased Facilities/Tenants and Landlord/Tenant Agreements The treatment of a leased asset parallels that of owned assets, and depends on the type of lease governing control of the asset. The GRP identifies the two main types of leases: operating leases and finance or capital leases. All emissions from assets leased under a finance or capital lease must be reported by the lessee regardless of whether the operational or financial control approach is being used. Such leases grant the lessee both operational and financial control of the asset. In contrast, emissions from assets covered by an operating lease must be reported in full only when the lessee is using the operational control option. If the lessee is using the financial control option none of the emissions from assets covered by operating leases have to be reported, because the lessee does not possess financial control over these assets. However, in this circumstance, the lessee does have the option of reporting these emissions as Scope 3 (indirect emissions). In the O&G sector, it is often the mineral rights themselves that are leased. A situation unique to this sector arises when the mineral rights are leased and the hydrocarbons are themselves emitted. This situation occurs, for example, when a leaseholder vents or flares a portion of the gas under lease as part of the normal production process. In such cases, reporting of GHGs from venting, leakage and flaring will generally be the leaseholder’s responsibility since it is the control of the source of the emissions (i.e., the well, pipeline, or other equipment) that determines reporting responsibility. This follows from the fact that the leaseholder usually exercises both operational and financial control over the various emissions sources (wells, pipelines, etc.). However, there are exceptions to this general rule, particularly overseas, as the first example below illustrates. Example 4-3: Treatment of Leased Assets under an Operating Lease

A few E&P sector examples should help to illustrate the treatment of leased assets. First let us assume that Black Gold Oil Company has leased a property for production from a foreign government’s state operating company– say Molvenia Oil. Black Gold has operational control over the equipment and personnel on the property, but under the terms of the lease does not have the right to sub-lease or otherwise gain additional profit from the production beyond specified rates of return in the operating contract or production sharing contract. Table 4.3 shows the reporting responsibilities for Black Gold and Molvenia Oil under the control organizational boundary options. Table 4.3 - Required Treatment of Emissions from Assets Covered by an Operating Lease by the Lessor and Lessee

Registry Option Black Gold (Lessee) Molvenia Oil (Lessor) Operating Control 100% 0% (May opt to report 100%

as Scope 3) Financial Control 0% Required (May opt to

report 100% as Scope 3) 100%


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Under the operating control option, Black Gold would be required to report 100 percent of the emissions, because Black Gold has operational control under the terms of its lease. However, Black Gold would not be required to report any of the emissions under the financial control option, because Black Gold neither owns nor has financial control over the field. Black Gold could choose to report the emissions from the field as indirect, Scope 3 emissions. Molvenia Oil, as the lessor in this example, would be required to report 100 percent of the emissions from the field under the financial control option, because it has retained financial control over the field. Molvenia Oil would not be required to report any emissions if it chooses to use the operational control option, because Molvenia has transferred operational control of the field to Black Gold under the terms of the lease. It may, nonetheless, choose to report the emissions from the field as optional Scope 3 emissions, because its action in leasing the field to an operating E&P company will indirectly cause the emission of GHGs. Note that if Molvenia Oil chooses to report according to Option 1 using the operating control plus equity share option it must report 100 percent of the emissions from the field, because even though it no longer retains operational control, it still owns the field and must report 100 percent of the emissions under the equity share consolidation methodology. The preceding example illustrates reporting responsibilities of the lessor and lessee under an operating lease; now let us consider an example involving a finance or capital lease. Although this terminology is not often used in the O&G E&P Industry, it fits the leasing arrangements where a landowner leases both the operational rights and mineral rights in exchange for a stream of royalty payments. Example 4-4: Treatment of Leased Assets under a Financial or Capital Lease

Suppose that John Brown, a landowner, owns a 640 acre property along with the mineral rights. Under the terms of one of Mr. Brown’s capital leases, O&G Corp. has the full rights to explore, produce and profit from the property. Table 4.4 shows the reporting responsibilities of both Mr. Brown and O&G Contracting in this situation. As the table indicates, O&G Corp. is required to report 100 percent of the emissions from the property, regardless of the particular option it chooses to use. This follows from the fact that O&G Corp. leases the property under the terms of a capital lease, and hence exercises both operational and financial control over the field. In contrast, John Brown, the lessor, is not required to report any of the emissions associated with the field under any of the options. Note that if Mr. Brown chose to report according to Option 1, he would not be responsible for reporting these emissions, because assets leased under a financial or capital lease are considered to be wholly owned by the lessee. Mr. Brown may, however, opt to report the emissions as his indirect (Scope 3) emissions. Table 4.4 - Required Treatment of Emissions from Assets Covered by a Capital Lease by the Lessor and Lessee Under TCR’s Four Options Registry Option O&G Corp. (Lessee) John Brown (Lessor) Operating Control 100% 0% (May opt to report 100%

as Scope 3) Financial Control 100% 0% (May opt to report 100%

as Scope 3)


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4.7 Further Examples of Control versus Equity Share Reporting The O&G sector is often characterized by complex, multi-layered ownership and leasing patterns. The following examples are provided to clarify how The Registry’s reporting rules should be applied to these complex arrangements. Suppose that Alpha Oil Company has been assigned operational and financial control of a consortium in which it holds a 60 percent equity share, and Beta Oil Corp., a member of the consortium, is planning to report its equity share (equal to 25 percent) of the emissions from the consortium. Alpha has financial control over the consortium, but Beta has significant influence over the consortium’s financial decisions. Alpha is leasing equipment from another company under an operating lease to work the field. Beta plans to report to The Registry using the operational control plus equity share option. In such a situation, should Beta report its equity share of the consortium’s total emissions, regardless of the leasing patterns for the individual equipment used by the consortium? Or do separate rules apply to each emitting asset depending on the asset’s relationship to Beta? The answer, in this case, depends on the reporting option used. Under the control options, it is control of the individual emitting sources that determines reporting responsibilities. However, under the equity share approach it is ownership of the entire collective entity—in this case, the consortium—that determines reporting responsibilities. Table 4.5 below shows the results of this separate application of the rules for each group of emitting sources and for the four reporting. Note, first, that under either the operational control or financial control options Beta would not be responsible for reporting emissions from any of the sources, because it does not have operational or financial control over any of the individual sources. Table 4.5 – Beta Oil’s Reporting Responsibilities

Emission Sources Registry Option

Wells Leased Equipment

Operational Control

0% 0%

Operational Control & Equity Share

25% 25%

Financial Control 0% 0% Financial Control & Equity Share

25% 25%

Under the two control and equity share reporting options, Beta would have responsibility for reporting its equity share of the entire consortium’s emissions. Thus Beta would need to report 25 percent of the emissions from each source within the consortium. Having considered Beta’s reporting responsibilities Table 4.6 presents Alpha’s responsibilities for the same sets of sources and reporting options. Note, first, that Alpha would have


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responsibility for reporting 100 percent of the emissions from all sources under the operational control and operational control plus equity share options. This follows from the fact that Alpha, as the operator of the consortium, has operating control over all of the consortium’s individual emission sources, including the leased sources. Alpha also has financial control over the consortium, and as a result would be responsible for reporting 100 percent of the emissions from the wells and from its own equipment under the financial control and financial control plus equity share options. However, Alpha would not be responsible for reporting the emissions associated with the leased equipment under the financial control option. Again, under the control options, it is the control of each individual emitting source that determines which entity has responsibility for reporting emissions from the source. Even though Alpha has financial control over the consortium as a whole, and therefore control over some of the consortium’s emissions sources (including the wells), it does not have financial control over the leased equipment (that control remains with the lessor). Hence Alpha would not be responsible for reporting the emissions associated with this equipment under the financial control option. Finally, under the financial control and equity share option, Alpha would be required to report its ownership share (60 percent) of the consortium on top of 100 percent of the emissions from those individual sources under its financial control. Thus, under this option Alpha would need to report 100 percent of the emissions from all sources under its financial control (including the wells), and 60 percent of the emissions from all consortium sources not under its financial control—including the leased equipment. Again, under the equity share approach, the reporting entity is responsible for reporting its ownership share of the collective enterprise (in this case the consortium) and all of the emission sources comprising that enterprise, regardless of the reporting entity’s ownership relationship to each individual source. Thus even though Alpha does not own the leased equipment, it’s 60 percent ownership share in the consortium makes it responsible for reporting 60 percent of the emissions from the leased equipment, because that equipment is being used by the consortium. Table 4.6 – Alpha Oil’s Reporting Responsibilities


Wells

Leased Equipment

Operational Control

100% 100%


100%

100%

Financial Control 100% 0% Financial Control & Equity Share

100% 60%

How might the reporting rules and options change if, instead of Alpha controlling the consortium’s operations, a separate operating company jointly owned by the consortium members were set up to work the oil field? The operating company, JV Oil Corporation, is


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granted operational control over the consortium’s activities, but financial control is exercised jointly by the two primary consortium members, Alpha (with a 60 percent equity share) and Beta (with a 25 percent share). JV Oil has no input on financial decisions, nor does it have an equity share in the consortium; it is strictly an operating company. In addition to using its own equipment, JV Oil leases equipment from a separate (non-consortium member) company. First, let us consider JV Oil’s reporting responsibilities (shown in Table 4.7). As the consortium operator, JV Oil would have responsibility for reporting 100 percent of the emissions from all sources under both the operational and operational plus equity share reporting options. In contrast, JV Oil would not be responsible for reporting the emissions from any sources under the two financial control options, except for the emissions from the equipment directly owned by JV Oil. Here, even though JV Oil does not have financial control over the consortium, it still has financial control over its own equipment—and under the control options, reporting responsibilities must be determined based on control over each individual emitting source comprising the consortium. Table 4.7 – JV Oil Reporting Responsibilities


Wells JV Oil’s Equipment

Leased Equipment

Operational Control

100% 100% 100%


100% 100% 100%

Financial Control 0% 100% 0% Financial Control & Equity Share

0% 100% 0%

Table 4.8 shows Alpha’s reporting responsibilities. Since operational control of the consortium has been given to JV Oil, Alpha would not have responsibility for reporting emissions from any of the sources under the operational control option. However, using operational control with equity share, Alpha would have responsibility for reporting its equity share of the entire consortium’s emissions (60 percent), and hence would report 60 percent of the emissions from each and every one of the consortium’s sources—regardless of ownership relationship to these individual sources. Table 4.8 – Reporting Responsibilities for Alpha


Wells JV Oil’s Equipment Leased Equipment

Operational Control

0% 0% 0%

Operational 60% 60% 60%


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Control & Equity Share Financial Control 60% 0% 0% Financial Control & Equity Share

60% 60% 60%

Alpha’s reporting responsibilities under the financial control option would need to be assessed on an individual source basis. First, as a consortium member with joint financial control, Alpha would be required to report 60 percent of the emissions from the wells. But it would not report emissions from any of JV Oil’s equipment or the equipment leased from the non-consortium member, as Alpha does not have financial control over this equipment. Finally, under the financial control and equity share option, Alpha would be required to report its ownership share over those sources over which it exercises joint financial control (including the wells). And for those sources over which it does not exercise joint financial control (i.e., the leased equipment), Alpha would still report 60 percent of the emissions (because, under the equity share approach, it must report 60 percent of all consortium emissions). Beta’s reporting responsibilities (shown in Table 4.9) echo those of Alpha, with the exception that Beta would report its own equity share of 25 percent (rather than Alpha’s 60 percent) where appropriate. Table 4.9 – Reporting Responsibilities for Beta



Operational Control

0% 0% 0%


25% 25% 25%

Financial Control 25% 0% 0% Financial Control & Equity Share

25% 25% 25%


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Chapter 5: Operational Boundaries

5.1 Required Emission Reporting As stated in the GRP, The Registry requires the reporting of Scope 1 and Scope 2 emissions data. Scope 1 sources specific to the E&P sector that are covered in the OG&P Protocol are described in Section 5.2 below. Scope 2 sources are described in Section 5.3 below. The GRP states that the reporting of Scope 3 emissions is optional. While this optional reporting holds true for most Scope 3 emissions associated with the oil & gas E&P sector, there are certain exceptions. Specifically, emissions arising from three activities—drilling, completions, and workovers—must be reported by the Member holding the oil and gas lease, even when these activities are contracted out (as is usually the case). The reporting requirements for Scope 3 emissions are further detailed in Section 5.5 below. Section 5.5 also provides some examples of these emission sources specific to the E&P sector.

5.2 Direct Emissions: Scope 1 The GRP defines direct (Scope 1) emissions as emissions from sources within the entity’s organizational boundaries. You are required to report all of your organization’s Scope 1 emissions. For oil and gas leaseholders, Scope 1 emissions will generally include, e.g., flaring and venting emissions from oil and gas wells, as well as combustion, fugitive, venting and flaring emissions from stationary and mobile equipment inside the leaseholder’s organizational boundary (see Chapter 4 of the OG&P Protocol and Chapter 4 of the GRP for more information on organizational boundaries). While the GRP itself provides emission calculation methodologies for many of these emission sources, some of them, such as venting and flaring emissions from wells and specialized equipment, are unique to the E&P sector. Emission calculation methodologies for sources unique to this sector are provided in Part V, Chapters 21 through 24, of this O&GP Protocol. Please refer to Section 5.2 of the GRP for more information on Scope 1 emissions.

5.3 Indirect Emissions: Scope 2 The GRP defines indirect emissions as emissions that are a consequence of activities that take place within the organizational boundaries of the reporting entity, but that occur at sources owned or controlled by another entity. Scope 2 emissions are a special category of indirect emissions consisting exclusively of those emissions associated with the consumption of purchased or acquired electricity, steam, heating, or cooling. For oil and gas leaseholders, Scope 2 emissions will include, e.g., emissions associated with outside suppliers of electricity and steam (such as CHP plants not owned/operated by the leaseholder).


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None of the various sources of Scope 2 emissions, such as power plants and CHP plants, are unique to the E&P sector. Emission calculation methodologies for Scope 2 sources are provided in the GRP (see specifically Chapters 14 and 15 of the GRP). Please refer to Section 5.3 of the GRP for more information on indirect Scope 2 emissions.

5.4 Reporting Emissions from Biomass Combustion REFER TO GRP.

5.5 Scope 3 Emissions As discussed in Section 5.1 above, O&G leaseholders are required to report Scope 3 contractor emissions associated with drilling, completion, and workover activities. Specifically, O&G leaseholders are required to report the emissions from the contractors’ equipment used to perform these three activities. It should be emphasized that the leaseholder is not required to report all contractor emissions; only those contractor emissions resulting from drilling, completions, and workovers are required. These required Scope 3 emissions are limited to the engine and electric motor emissions from the contractors’ equipment used in the activities of drilling, completions, and workovers. Engine/motor emissions to be reported include emissions of CO2, CH4, and N2O. Both the Scope 1 and Scope 2 emissions of drilling, completion, and workover contractors must be reported. Vented and flared methane emissions that occur during drilling, completion and workover activities are considered the direct, Scope 1 emissions of the leaseholder, and must be reported as Scope 1 emissions under the GRP’s requirement that all Scope 1 emissions be reported. Emissions from contractor equipment (e.g., drilling rigs and workover rigs) used in drilling, completions, and workovers must be classified and reported as Scope 3 emissions. The Registry requires the reporting of Scope 3 contractor emissions in the case of drilling, completions and workovers for a number of reasons, including the following:

These emissions can be significant at some fields; The activities of drilling, completions and workovers are integral and, indeed, central to

the E&P process; and

Based on feedback solicited by The Registry from O&G company stakeholders, the leaseholder should be able to obtain the data needed to estimate these emissions from its contractors.

However, The Registry does not require the reporting of contractor emissions resulting from ancillary activities such as supply transportation and general maintenance. Unlike the emissions associated with drilling, completions, and workovers, the emissions associated with


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other, ancillary contractor activities tend to represent a small percentage of total emissions. Furthermore, based on feedback from O&G company stakeholders, obtaining emissions-related data from contractors involved in these latter types of activities would be extremely difficult if not impossible. A key distinction here is that drilling, completions and workovers tend to be performed by just a few contracting companies, whereas numerous contractors are involved in other ancillary activities. Also, because the contractors involved in the latter activities are often shared by more than one leaseholder in a given field, it is not clear that these contractors would be able to provide data correctly apportioned to their different clients. The Registry is sensitive to imposing an unreasonable reporting burden on its Members in an effort to obtain data on a small percentage of total E&P emissions, and for this reason has limited the requirement to report Scope 3 contractor emissions to those emissions associated with the three activities of drilling, completions and workovers. Questions for the TWG: should we be requiring the reporting of contractor emissions for drilling, completions and workovers? (Please explain your answer). Do you agree leaseholders will be able to obtain the necessary data from the contractors? The reporting of all Scope 3 emissions other than contractor emissions associated with drilling, completions, and workovers, is optional. Examples of Scope 3 emissions you may opt to report include the following:

Contractor emissions associated with ancillary support services such as general maintenance;

Emissions from gathering lines, in those cases when the lines are owned or controlled by a company other than your own;

Upstream emissions from the transportation of equipment, personnel and supplies to and from the field, when such transportation activities are contracted out to other companies (transportation performed using your company’s own vehicles or vessels must be reported as part of entity wide Scope 1 emissions);

Downstream emissions from the refining of crude oil produced by your company and sold to another company (emissions from refineries owned or controlled by your company must be reported as part of entity wide Scope 1 emissions);

Downstream emissions from the transmission and distribution of your company’s produced natural gas, when the transmission and distribution pipelines are owned or controlled by another company;

Downstream emissions from the combustion of natural gas and/or petroleum products produced by your company and sold to end users; and

Downstream emissions from the disposal of waste generated during the E&P process.


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Chapter 6: Facility-Level Reporting

6.1 Required Facility-Level Reporting REFER TO GRP.

6.2 Defining Facility Boundaries The Registry requires Members to report their emissions at the facility level. Specifically, Members must report their emissions by types of source (stationary combustion, mobile combustion, process and fugitive) and gas (CO2, CH4, N2O, HFCs, PFCs and SF6) within each facility. However, as noted in the GRP, some emission sources cannot be easily associated with a traditionally defined facility (i.e., a “single physical premises”). The emission sources characteristic of the O&G E&P sector are a prime example of a set of sources that cannot be distinguished or grouped using the standard notion of a facility. Instead, field operations within the E&P sector are typically characterized by hundreds, or even thousands, of sources spread out over the area of operation. In recognition of unique geographic realities in the O&G E&P sector, The Registry requires that distributed emission sources be aggregated and reported by oil or gas field, while facilities that conform to the traditional definition of a facility continue to be reported as separate facilities. In general, a “field” is defined as a surface area which is underlain, or appears to be underlain, by one more pools. A pool, in turn, is an underground reservoir containing, or appearing to contain, a common accumulation of crude oil and/or natural gas. Each zone of a general structure which is separated from any other zone in the structure forms a separate pool.3 The reader will note that the general definition of a field is ambiguous. From a practical standpoint, each nation, state or province has named and delineated the specific oil and gas fields under its own jurisdiction. The definition of a field is defined by one entity, for example U.S. states and Canadian provinces have jurisdiction to define a field, whereas Mexico defines fields nationally. The Registry requires that these established definitions be used as the basis for aggregating emission sources in the O&G E&P sector. Emissions from fields that cross state, provincial, or national boundaries must be disaggregated and reported separately by jurisdiction within the field; e.g., a single field straddling a state line must be treated as two separate fields, divided by the state line, for reporting purposes. Specific emissions that should be included in your aggregated field-level emission totals include emissions from all of your organization’s wells in a given field. Processing plants, natural gas

3 California Dept. or Conservation, Division of Oil, Gas and Geothermal Resources, California Laws for Conservation of Petroleum & Gas, January 2009.


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processing plants, refineries, and other facilities that conform to traditional definition of a facility should be treated as separate, individual facilities in accordance with the general instructions for facility-level reporting provided in the GRP, even when these facilities lie within the boundaries of a field. Question for the TWG: An alternative to the above requirement would be to allow Members to aggregate emissions from natural gas processing plants and other standard facilities located within a field with emissions from dispersed sources within the same field. For example, EPA allows the lumping together of all existing stationary source emissions in this manner—although this may change in the future. Do you agree with the requirement to keep emissions from plants meeting the standard definition of a facility separate from other (dispersed-source) field emissions, or do you prefer the current EPA approach? Also, TCR could require that facilities located within a field be associated with the field in the TCR’s software system. Would such a field-facility association provide useful information to data users, keeping in mind it will only cover corporate entities voluntarily reporting to The Registry? Further Questions for the TWG: some consideration was given to requiring the aggregation of emissions by state permit within each field (i.e., having two levels of aggregation—by permit, and then by field). Disadvantages of this approach are that it increases complexity, since not all emission sources are covered by a permit. However, this approach would have the potential advantage of increasing the consistency, and facilitating the comparison, of voluntary emissions data collected by The Registry with GHG data obtained from mandatory reporting programs. However, this advantage would be gained only if the mandatory programs also require reporting by permit. Do you anticipate or expect that your state’s mandatory reporting program will require reporting of emissions by permit? Do you see other advantages/disadvantages of requiring reporting by permit? Emissions from mobile sources are a special case; these emissions are discussed in Section 6.4 below. One other special case is emissions from a pipeline(s) or pipeline network used to transport natural gas or crude oil out of the field. In general, a portion of a pipeline or network of pipelines will lie inside the field’s boundaries (including, e.g., the gathering lines used to gather the oil or natural gas from individual wells to a central point), while the remainder of the pipeline/pipeline network lies outside the field (e.g., the transmission lines used to move the product to market or to a refinery). It is not necessary to distinguish, and report separately, the pipeline emissions that occur inside and outside the field boundary (although you may take this approach if you have the data necessary to make a distinction between emissions inside versus outside the field). Instead, as described in Section 6.2 of the GRP, you may treat each pipeline or pipeline system as a single facility, and aggregate the emissions from the portion of the pipeline lying inside the field with the emissions that occur outside the field boundary. Question for TWG: will a member ever want to aggregate emissions from the pipelines inside a field with emissions from pipelines further downstream? Should we allow the


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option to aggregate emissions in this way, or should we require separate reporting of in-field pipeline emissions from out-of-field pipeline emissions?

6.3 Optional Aggregation of Emissions from Certain Types of Facilities REFER TO GRP.

6.4 Categorizing Mobile Source Emissions The GRP makes a distinction between ground-based mobile sources that operate exclusively on the grounds of a single facility, and ground-based mobile sources that operate at least some of the time beyond a single facility. The former mobile sources are treated as part of the facility, and are included in the emissions totals reported for the facility, whereas the latter sources are aggregated separately (e.g., by state, province, or country, according to the aggregation rules specified in Section 6.4 of the GRP). Although in the O&G E&P sector distributed emission sources are grouped and aggregated by field instead of by facility, a similar distinction applies. In addition, offshore E&P includes water-based mobile emission sources (supply and crew vessels) and air-based mobile sources (helicopters). Specifically, mobile emission sources that operated exclusively within the boundaries of a single field during a given reporting year are considered to be part of that field-facility’s emission sources. The emissions from such sources must be included in the field’s aggregate emission totals, along with the emissions from the stationary sources located inside the field. Mobile emission sources that travel beyond the boundaries of a single field or offshore facility during the reporting year should not be assigned to any particular field-facility or facility for reporting purposes, but should instead be reported separately. For example, dedicated vessels and helicopters that serve offshore platforms should not be included in the emissions for the offshore field, because these vessels travel beyond the boundaries of the field (e.g., when they return to shore). Hence these vessels and helicopters should be aggregated and reported separately from your field emissions. Please refer to Section 6.4 of the GRP for a description of the rules governing the aggregation of ground-based mobile sources that operate beyond the confines of a specific facility (or field), as well as an explanation of the reporting rules governing air- and marine-based mobile sources such as those serving offshore platforms.

6.5 Optional Reporting: Unit Level Data REFER TO GRP.

6.6. Aggregation of Data to Entity Level REFER TO GRP.


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Chapter 7: Establishing and Updating the Base Year

7.1 Required Base Year REFER TO GRP.

7.2 Updating Your Base Year Emissions As Section 7.2 of the GRP explains, you are required to adjust your base year emissions report to reflect structural changes in your entity’s boundaries (e.g., mergers or divestitures) or your emission calculation methodologies (including the correction of errors), if the resulting cumulative change in base year emissions would be equal to or greater than five percent. The GRP also explains the five percent threshold is to be measured relative to your total reported base year emissions; i.e., the sum of your Scope 1 and Scope 2 emissions, along with any Scope 3 emissions included in your base year report. Because the OG&P Protocol requires the reporting of Scope 3 contractor emissions associated with the activities of drilling, completion and workovers, you should be sure to include these (and any optionally-reported GHGs) Scope 3 emissions when determining whether or not the five percent threshold has been exceeded. Suppose, for example, that ACME Oil Company reported its emissions in the base year as follows:

Total Scope 1 emissions of 1 million tonnes CO2-e; Total Scope 2 emissions of 100,000 tonnes CO2-e; and Total Scope 3 (contractor) emissions associated with drilling, completions and workovers

of 100,000 tonnes CO2-e. Suppose, further, that ACME acquires J.D. Little Oil Company subsequent to the base year. ACME determines that J.D. Little’s emissions in ACME’s base year were as follows:

Total Scope 1 emissions of 40,000 tonnes CO2-e; Total Scope 2 emissions of 5,000 tonnes CO2-e; and Total Scope 3 (contractor) emissions associated with drilling, completions and workovers

of 20,000 tonnes CO2-e. In this case, the total increase in ACME’s base year emissions resulting from the acquisition would be the sum of J.D. Little’s Scope 1, Scope 2, and required Scope 3 emissions, or 65,000 tonnes CO2-e. This total in turn represents 5.4 percent of the sum of ACME’s Scope 1, Scope and Scope 3 emissions as reported in the base year (1,200,000 tonnes CO2-e). Because 5.4 percent exceeds the five percent threshold, ACME is required to adjust its base year report to reflect the acquisition of J.D. Little. Note that in determining whether or not the five percent


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significance threshold has been exceeded, ACME must include both J.D. Little’s and its own Scope 3 (contractor) drilling, completion, and workover emissions in the calculation. Clarifications to Examples 7.4 (Outsourcing) and 7.5 (Insourcing) in the GRP are required for O&G leaseholders. As Example 7.4 on outsourcing explains, if your organization contracts out activities previously included in your base year emissions report, you may need to adjust your base year report to reflect the outsourcing. However, the shifting of emissions from one scope to another does not trigger a requirement to revise your base year emissions report as long as you reported the shifted emissions in your base year report, and as long as you continue to report these emissions in subsequent years. Therefore, because you are required to report the emissions associated with drilling, completions and workovers regardless of whether these activities are performed in-house or outsourced, changes in the organization(s) performing these activities will not trigger a requirement to adjust your base year emissions report. Suppose, for example, that an oil and gas leaseholder performed all workovers internally, using its own personnel and equipment, in the base year. This leaseholder would report the emissions associated with workovers as part of its own direct, Scope 1 emissions in the base year. Suppose, further, that this same leaseholder subsequently contracts out its workover activities. Subsequent to the contracting out of workovers, the leaseholder would continue to report the emissions associated with workovers, but it would report these emissions as part of its indirect Scope 3 emissions. Since the workover emissions would be included in both the base year report and the emissions reports filed in subsequent years, there would be no need for this leaseholder to adjust the base year report to reflect the outsourcing of workovers. Note, however, that the outsourcing of other activities besides drilling, completions and workovers, might require adjustment to the base year report. Example 7.4 in the GRP still applies to outsourced activities other than drilling, completions, and workovers. Example 7.5 provides general instructions on handling adjustments to base year reports to reflect insourcing. Insourcing is the converse of outsourcing. As Example 7.5 explains, if you did not include the emissions associated with insourced activities as Scope 3 emissions in your base year report, then you must adjust your base year emissions to reflect the insourced activities. However, because O&G leaseholders are required to report the Scope 3 contractor emissions associated with drilling, completions and workovers, you would not need to adjust your base year emissions if you subsequently insourced any or all of these three activities. However, the subsequent insourcing of other activities performed by contractors in the base year would necessitate an adjustment to your base year emissions report if the adjustment would result in a change of 5 percent or larger in your entity’s total base year emissions (Scope 1 plus Scope 2 as well as reported Scope 3 emissions). Again, the shifting of emissions from one scope to another does not necessitate a revision to your base year report as long as the shifted emissions are included in the base year report and in the current reporting year emissions report. Suppose, for example, that an oil and gas leaseholder decided to insource all of its drilling activities, replacing its drilling contractors with its own personnel and drilling rigs. This leaseholder would have reported the emissions associated with drilling as part of its Scope 3


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(contractor) emissions in the base year. Upon insourcing this activity, the leaseholder would continue to report the emissions associated with drilling as its direct Scope 1 emissions. Since the drilling emissions would be included in both the base year report and the emissions reports filed in subsequent years, there would be no need for this leaseholder to adjust the base year report to reflect the insourcing of the drilling activity. Note, however, that the insourcing of other activities besides drilling, completions and workovers, might require adjustment to the base year report. Example 7.5 in the GRP still applies to insourced activities other than drilling, completions, and workovers. Please refer to the GRP for general instructions on updating your base year emissions.

7.3 Optional Reporting: Updating Intervening Years REFER TO GRP.


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Chapter 8: Transitional Reporting (Optional)

8.1 Reporting Transitional Data REFER TO GRP.

8.2 Minimum Reporting Requirements for Transitional Reporting As is discussed in Chapter 5, oil and gas leaseholders are required to report all Scope 3 contractor emissions associated with the three activities of drilling, completions, and workovers. However, this requirement is waived for Transitional Members. The reporting of Scope 3 contractor emissions associated with drilling, completions, and workovers is allowed but optional for Transitional Members; it does not become required until Members begin reporting on a comprehensive (non-transitional) basis. Please refer to the GRP for additional information on the reporting requirements for transitional reporting.

8.3 Public Disclosure of Transitional Data REFER TO GRP.


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Chapter 9: Historical Reporting (Optional)

9.1 Reporting Historical Data REFER TO GRP.

9.2 Minimum Reporting Requirements for Historical Data As is discussed in Chapter 5, oil and gas leaseholders are required to report all Scope 3 contractor emissions associated with the three activities of drilling, completions, and workovers. However, this requirement is waived for historical data reporting. The reporting of historical Scope 3 contractor emissions associated with drilling, completions, and workovers is allowed but optional. Please refer to the GRP for additional information on the reporting requirements for historical data reporting.

9.3 Importing Historical Data REFER TO GRP.

9.4 Public Disclosure of Historical Data REFER TO GRP.


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PART III: QUANTIFYING YOUR EMISSIONS

Chapter 10: Introduction to Quantifying Your Emissions

Methodologies for estimating emissions from stationary combustion, mobile combustion, electricity use, imported steam, and refrigeration and air conditioning equipment are provided in Chapters 12 through 16 of the GRP. These methodologies apply to many of the emission sources found in the E&P sector, such as mobile equipment and stationary engines, boilers, steam generators, gas turbines, imported electricity and steam, etc. However, the E&P sector also includes many emissions sources that are unique to the sector and that are not covered in the GRP. These unique sources include, e.g., many of the process and fugitive emissions (venting, flaring, and leakage) associated with E&P activities. Calculation methodologies for these unique sector sources are provided in this OG&P Protocol—specifically, in PART V: ADDITIONAL EMISSION CALCULATION METHODOLOGIES FOR SOURCES UNIQUE TO THE OIL AND GAS E&P SECTOR (Chapters 21 through 24). Table 10.1 below provides a list of the various emission sources found in the O&G E&P sector, along with an indication of the specific document (GRP or OG&P Protocol) and chapter(s) providing Registry-approved emission calculation methodologies for each source. Please refer to this table to help you find approved calculation methodologies for each of your emission sources. For more general information on quantifying your emissions, please refer to Chapter 10 of the GRP. Table 10.1 - Cross Reference of Oil and Gas Source Categories Source Category Refer to: Well testing (flaring) OG&P, Chapter 23 Exploratory drilling engines GRP, Chapter 13 Well testing and completion activities (non-venting)

GRP, Chapters 12-15

Well testing and Completion venting OG&P, Chapter 22 Drill mud degassing OG&P, Chapter 22 Drill rig engines GRP, Chapter 13 Workover rig engines GRP, Chapter 13 Miscellaneous I.C engines GRP, Chapters 12 and 13 Glycol dehydrators OG&P, Chapter 22 Flares/incinerators OG&P, Chapter 23 Heavy-duty trucks GRP, Chapter 13 Medium-duty trucks GRP, Chapter 13 Light-duty trucks GRP, Chapter 13 Light-duty automobiles GRP, Chapter 13 Offshore Support and Seismic Vessels (OSV) GRP, Chapter 13 Helicopters (Offshore) GRP, Chapter 13


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Source Category Refer to: Artificial lift engines (pumpjacks) GRP, Chapter 12 Oil well tanks OG&P, Chapter 21 Oil well truck loading OG&P, Chapter 22 Pneumatic devices OG&P, Chapter 21 Oil well fugitives OG&P, Chapter 21 Chemical injection pumps OG&P, Chapter 21 Vapor recovery unit (VRU) engines GRP, Chapter 12 Heaters GRP, Chapter 12 Boilers GRP, Chapter 12 Cogeneration Units (EOR) GRP, Chapter 12 Imported electricity GRP, Chapter 14 Process heat/steam imports GRP, Chapter 15 Salt-water disposal (SWD) engines GRP, Chapter 12 Gas actuated pumps OG&P, Chapter 21 Central power plant turbines (offshore) GRP, Chapter 12 Central power plant IC Engines (offshore) GRP, Chapter 12 Converted Diesel ship engines (offshore) GRP, Chapter 13 Tankers in Floating Production, Storage, and Offloading Systems – FPSO (Offshore)

OG&P, Chapter 22

Coke gasification unit OG&P, Chapter 24 Hydrogen production unit OG&P, Chapter 24 Primary upgrading coke unit OG&P, Chapter 24 Gas well condensate tanks OG&P, Chapter 21 Gas well, NGL plant truck loading OG&P, Chapter 22 Gas well fugitives OG&P, Chapter 21 Compressor start-ups and shutdowns OG&P, Chapter 21 Amine units OG&P, Chapter 22 Well blowdowns OG&P, Chapter 22 Compressor blowdowns OG&P, Chapter 22 Lateral/wellhead compressor engines GRP, Chapter 12 CBM pump engines GRP, Chapter 12 Gas well and plant truck loading OG&P, Chapter 22 Gas pipeline fugitives OG&P, Chapter 21 Water treatment facilities (evaporative ponds) OG&P, Chapter 21 Gas processing plant fugitives OG&P, Chapter 21 Acid gas removal systems OG&P, Chapter 22 Boilers/Steam generators GRP, Chapter 12 Gas turbines GRP, Chapter 12 Vessel blowdowns OG&P, Chapter 22 Pipeline blowdowns OG&P, Chapter 22 Haulers and dumptrucks GRP, Chapter 13 Bulldozers GRP, Chapter 13 Scrapers GRP, Chapter 13 Blasthole Drills GRP, Chapter 13 Explosive loading trucks GRP, Chapter 13 Front end loaders GRP, Chapter 13


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Source Category Refer to: Hydraulic excavators GRP, Chapter 13 Mobile cranes, forklifts, maintenance and supply trucks, road graders, etc.

GRP, Chapter 13


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Chapter 11: Simplified Estimation Methods

The Registry requires that 100 percent of your organization’s emissions be accounted for in your emissions report. In the case of an oil and gas leaseholder, 100 percent of the Scope 3 contractor emissions from drilling, completions, and workovers must be reported, along with 100 percent of the leaseholder’s Scope 1 and Scope 2 emissions. In general, Members must use the Registry-approved calculation methodologies presented in the GRP, and in the Oil & Gas Production Protocol, to compute their Scope 1, Scope 2 and required Scope 3 emissions. However, as is discussed in Chapter 11 of the GRP, Members may use alternative, simplified estimation methods to compute up to 5 percent of their total entity emissions. For O&G leaseholders, the 5 percent threshold should be based on the sum of total Scope 1, Scope 2, and Scope 3 contractor emissions associated with drilling, completions and workovers. Furthermore, O&G leaseholders may choose to use simplified estimation methods to compute all or a portion of their required Scope 3 contractor emissions, as well as selected Scope 1 and Scope 2 emissions, as long as the total quantity of emissions computed using simplified methods does not exceed 5 percent of total entity Scope 1, Scope 2 and required Scope 3 emissions (summed on a CO2 equivalency basis). The Registry recognizes that in certain cases, it may not be possible to obtain the data from contractors necessary to apply the Registry-approved calculation methods specified in the GRP and in the Oil & Gas Production Protocol. In addition, the Registry recognizes that for some emission sources in the O&G E&P sector, there are significant obstacles in any attempt to apply generic, “one size fits all” estimation methodologies. For example, there are currently no generally accepted, standardized approaches to estimating gas volumes sent to a flare and the resulting emissions. Gas volumes sent to a flare and emissions from flaring can vary by orders of magnitude for different platforms in the same field, due to differences in the platform facility design, process upsets, etc. As a result generic emission factors often cannot be applied to site-specific conditions. Furthermore, many leaseholders may lack the data needed to apply any standard, default methods that might be developed. Given these circumstances, the Registry recognizes that accuracy may be enhanced by allowing operators to develop their own site-specific methods, rather than requiring the use of generic methods that may yield wildly inaccurate results when applied to specific sites. These observations and conclusions apply to emissions from water ponds as well as flaring emissions. Question for TWG: can you provide acceptable emission factors for water ponds (if not, we believe we will need to allow the use of simplified methods for the estimation of water pond emissions)? In recognition of the potential inaccuracies arising from the application of generic emission calculation methods to flaring and water ponds, the Registry explicitly exempts these two sources from the 5-percent threshold for the use of alternative, simplified estimation methods. In addition, the Registry exempts required Scope 3 (contractor) drilling, completion and workover emissions from the 5 percent threshold when the leaseholder cannot obtain the data


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needed to apply Registry-approved methods to these emission sources. However, the Registry requires Members to attempt to obtain the data needed to apply Registry-approved calculation methods from all drilling, completion and workover contractors and to use these methods for all sources for which data are available. An O&G sector Member can apply simplified methods over and above the 5 percent threshold to estimate Scope 3 drilling, completion and workover emissions only when unsuccessful attempts have been made to obtain the data needed to apply Registry-approved methods to these sources. If use of the exemptions to the threshold for flaring, water pond and/or contractor emissions results in the utilization of simplified methods to estimate more than 5 percent of an entity’s total emissions, then the further application of simplified methods to additional emissions sources is not allowed. If the sum of the emissions estimated using simplified methods from flaring, water ponds and/or contractors is less than 5 percent of the entity’s total emissions (i.e., the exemption from the 5 percent threshold was not used), then simplified methods may be used to estimate emissions from additional sources, up to the 5 percent threshold. Example 11.1 illustrates the application of the 5-percent threshold, and the limited exemptions to this threshold, for an oil and gas leaseholder. Please refer to the GRP for additional general guidance on the application of simplified methods to the estimation of emissions. Questions for TWG: do you agree we should exempt flaring and water pond emissions from the 5% threshold? Should we instead attempt to provide generic guidance for estimating these emissions? If so, how can we make this guidance flexible enough to capture the site-specific conditions that result in wide variations in emissions from these sources? Also, for flaring, how would companies estimate volume flows? Do you agree with exempting from the 5% threshold scope 3 emissions for contractors that are unwilling to provide the needed data? What alternatives could/should be pursued if the contractors refuse to provide the data? Example 11-1: Application of the 5 Percent Threshold for the Use of Simplified Estimation Methods to an Oil and Gas Leaseholder

Triple A Oil and Gas Corp., a Registry Member, holds oil and gas leases in three fields in California. It contracts out all of its drilling, completion and workover activities to three separate contractors in each of the three fields. Two of these three contractors are providing Triple A with the data needed to estimate engine emissions associated with these activities. However, the third contractor, Joe Best’s Drilling Company, refuses to provide the needed data, citing confidentiality concerns. Flaring operations are ongoing in all three fields. Triple A may use alternative, simplified estimation methods to calculate its Scope 1 emissions from flaring, as well as its Scope 3 emissions from Joe Best’s drilling rigs. However, Triple A must use Registry-approved methods to calculate the drilling, completion, and workover


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emissions from the other two contractors. Let us suppose that Triple A estimates its emissions as follows:

Emissions from flaring (estimated using simplified methods): 2000 tonnes CO2-e; Emissions from Joe Best’s (estimated using simplified methods): 4000 tonnes CO2-e; Emissions from the other two drilling/completion/workover contractors (estimated using

Registry-approved methods): 10,000 tonnes CO2-e; and Emissions from all other sources: 84,000 tonnes CO2-e.

In this case, Triple A has total emissions of 100,000 tonnes CO2-e. Since it has already used simplified methods to estimate 6,000 of these total emissions, or 6 percent, it has already exceeded the 5 percent threshold. Because it has limited its use of simplified methods to exempt sources—namely, flaring and emissions from a contractor unwilling to provide Triple A with its emissions-related data--Triple A is allowed to exceed the 5 percent threshold. However, because it has exceeded the threshold, it may not apply simplified estimation methods to any of its other emissions sources. If Triple A used alternative, simplified methods to estimate any of its 84,000 tonnes of emissions from other sources, it would need to re-calculate these emissions using Registry-approved methods. If, instead of emissions of 4000 tonnes CO2-e, Triple A had instead estimated Joe Best’s emissions at 1000 tonnes CO2-e, its total emissions would have been 97,000 tonnes CO2-e, and only 3000 tonnes of this total, or 3.1 percent, would have been estimated using simplified methods. In this case Triple A could have applied simplified methods to additional sources, of its own choosing comprising up to 1.9 percent of its total emissions.


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Chapter 12: Direct Emissions from Stationary Combustion

Please refer to the GRP for emission calculation methodologies covering most stationary combustion devices. However, for methodologies for combustion devices unique to the E&P sector, including, hydrogen units, and coker upgraders, please refer to Chapters 23 and 24 of this OG&P Protocol.

12.1 Measurement Using Continuous Emissions Monitoring System Data REFER TO GRP.

12.2 Calculating Emissions from Stationary Combustion Using Fuel Use Data The GRP provides a number of methodologies for estimating the emissions from stationary combustion devices based on fuel consumption data. You should use the methodologies provided in the GRP to calculate emissions for those stationary combustion devices for which you have fuel consumption data. If you do not have fuel consumption data for some stationary combustion devices, please refer to Section 12.4 of this OG&P protocol for emissions calculation guidance.

12.3 Allocating Emissions from Combined Heat and Power (Optional) REFER TO GRP. Example 12-1: Direct Emissions from Stationary Combustion

REFER TO GRP.

12.4 Calculating Emissions for Stationary Combustion Devices Lacking Fuel Use Data You must use the calculation methodologies provided in Sections 12.1 and/or 12.2 of the GRP for all stationary combustion devices for which you have either CEMS or fuel consumption data. However, The Registry recognizes that the E&P sector utilizes some stationary combustion devices—particularly smaller compression engines, natural gas turbines and other devices—that are not metered for fuel consumption. The Registry provides the additional methodologies described below to calculate emissions for those stationary combustion devices for which fuel consumption data are not available.

METHOD 01


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METHODOLOGY FOR COMPRESSOR ENGINES AND NATURAL GAS TURBINE COMPRESSORS

The following equations may be used to estimate emissions from compressors using either reciprocating internal combustion engines or natural gas turbines for which fuel consumption data are lacking.

Equation 12-1: Calculating CO2 Emissions from Compressors

ECO2 = HP × LF × fe × EFCO2 × tannual

where: ECO2 = the annual emissions of CO2 per engine or turbine [tonne/yr] HP = the rated horsepower of the engine or turbine [hp] LF = the load factor of the engine or turbine Fe, the energy-basis conversion factor for the engine = 0.007858 for a natural gas internal combustion engine or 0.010379 for a natural gas turbine [MMBTU/hp-hr] EFCO2 = the emissions factor of CO2 on an energy basis assuming the higher heating value (HHV) of the fuel [tonne/MMBTU] tannual = the annual hours of usage of the engine (hr/yr)

Equation 12-2: Calculating CH4 Emissions from Compressors

ECH4 = HP × LF × fe × EFCH4 × tannual

where: ECH4 = the annual emissions of CH4 per engine or turbine [tonne/yr] HP = the rated horsepower of the engine or turbine [hp] LF = the load factor of the engine or turbine Fe, the energy-basis conversion factor for the engine = 0.007858 for a natural gas internal combustion engine or 0.010379 for a natural gas turbine [MMBTU/hp-hr] EFCH4 = the emissions factor of CH4 on an energy basis assuming the higher heating

value (HHV) of the fuel [tonne/MMBTU]

tannual = the annual hours of usage of the engine (hr/yr)


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Equation 12-3: Calculating N2O Emissions from Compressors

EN2O = HP × LF × fe × EFN2O × tannual

where: EN2O = the annual emissions of N2O per engine or turbine [tonne/yr] HP = the rated horsepower of the engine or turbine [hp] LF = the load factor of the engine or turbine Fe, the energy-basis conversion factor for the engine = 0.007858 for a natural gas internal combustion engine or 0.010379 for a natural gas turbine [MMBTU/hp-hr] EFN2O = the emissions factor of N2O on an energy basis assuming the higher heating value (HHV) of the fuel [tonne/MMBTU] tannual = the annual hours of usage of the engine (hr/yr)

Please refer to Tables 12.1 through 12.9 of the GRP to find the emission factors (EFCO2, EFCH4, and EFN2O) needed to solve Equation 12-1, Equation 12-2 and Equation 12-3. The value of the load factor (LF) in the equations should be based on compressor-specific data or engineering estimates (derived from field pressures) whenever possible. However, when compressor-specific data or engineering estimates are not available, the following default values for the load factor may be used:

For permitted compressors, LF = 0.75; and For unpermitted compressors, LF = 0.5.

Natural gas-fired turbines used as compressors in gas processing facilities and large compressor stations are generally considered permitted sources, in that they exceed emissions thresholds requiring permits in most U.S. states. Compressors using internal combustion engines may be either permitted or unpermitted. Permitted compressor engines typically include large engines located at central gas processing plants or large compressor stations. Unpermitted compressors are generally small, distributed devices located at the wellhead or at lateral compressor stations.

METHOD 02

METHODOLOGY FOR NATURAL GAS TURBINE GENERATORS

In addition to their application to compressors, natural gas turbines are also sometimes used to drive electricity generators in the E&P sector. For example, natural gas turbines are often used to supply electricity to offshore platforms. You should use the methodologies provided in Section 12.2 of the GRP to calculate emissions from all gas turbine generators for which fuel


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consumption data are available. However, the following equations may be used when fuel consumption data are lacking.

Equation 12-4: Calculating CO2 Emissions from Natural Gas Turbine Generators

ECO2 = (P × HR × EFCO2 × tannual) / 1000

where: ECO2 = the annual emissions of CO2 per turbine [tonne/yr] P = the rated capacity of the turbine [MW] HR = the heat rate of the turbine [BTU/kWh] EFCO2 = the emissions factor of CO2 on an energy basis [tonne/MMBTU]

tannual = the annual hours of usage of the turbine (hr/yr)

Equation 12-5: Calculating CH4 Emissions from Natural Gas Turbine Generators

ECH4 = (P × HR × EFCH4 × tannual) / 1000

where: ECH4 = the annual emissions of CH4 per turbine [tonne/yr] P = the rated capacity of the turbine [MW] HR = the heat rate of the turbine [BTU/kWh] EFCH4 = the emissions factor of CH4 on an energy basis [tonne/MMBTU] tannual = the annual hours of usage of the turbine (hr/yr)

Equation 12-6: Calculating N2O Emissions from Natural Gas Turbine Generators

EN2O = P × HR × EFN2O × tannual) / 1000

where: EN2O = the annual emissions of N2O per turbine [tonne/yr] P = the rated capacity of the turbine [MW] HR = the heat rate of the turbine [BTU/kWh] EFN2O = the emissions factor of N2O on an energy basis [tonne/MMBTU]


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Equation 12-6: Calculating N2O Emissions from Natural Gas Turbine Generators

tannual = the annual hours of usage of the turbine (hr/yr)

Please refer to Tables 12.1 through 12.9 of the GRP to find the emission factors (EFCO2, EFCH4, and EFN2O) needed to solve Equation 12-4, Equation 12-5 and Equation 12-6.

METHOD 02

METHODOLOGY FOR DRILL RIG AND WORKOVER RIG ENGINES

A single drill rig may include three to seven or more engines, including draw works, mud pumps, and generator engines. Workover rigs, used to perform major maintenance on wells, including removing and replacing the tubing string, as well as well re-completions, typically have fewer and smaller engines than drill rigs, but they will include at least one engine and in some cases multiple engines. You should use the methodologies provided in Section 12.2 of the GRP to calculate emissions from all drill rig and workover rig engines for which fuel consumption data are available. However, the following equations may be used when fuel consumption data are lacking.

Equation 12-7: Calculating CO2 Emissions from Drill Rig and Workover Rig Engines

ECO2 = Σ HPi × LFi × BSFCi × HHV × EFCO2 × ti,annual

where: ECO2 = the emissions of CO2 for a drilling or workover rig [tonne/yr]

HPi = the horsepower of engine i on the drilling or workover rig [hp]

LFi = the load factor of engine i on the drilling or workover rig

BSFCi = the brake specific fuel consumption of engine i on the drilling or workover rig [lb-fuel/hp-hr] HHV = the higher heating value of the diesel fuel [BTU/lb]

EFCO2 = the emissions factor of CO2 on an energy basis assuming the higher heating value (HHV) of the fuel [tonne/BTU] Ti,annual = the hours of operation of engine i on the drilling or workover rig [hr/yr]


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Equation 12-8: Calculating CH4 Emissions from Drill Rig and Workover Rig Engines

ECH4 = Σ HPi × LFi × BSFCi × HHV × EFCH4 × ti,annual

where: ECH4 = the emissions of CH4 for a drilling or workover rig [tonne/yr] HPi = the horsepower of engine i on the drilling or workover rig [hp] LFi = the load factor of engine i on the drilling or workover rig BSFCi = the brake specific fuel consumption of engine i on the drilling or workover rig [lb-fuel/hp-hr]

HHV = the higher heating value of the diesel fuel [BTU/lb]

EFCH4 = the emissions factor of CH4 on an energy basis assuming the higher heating value (HHV) of the fuel [tonne/BTU]

Ti,annual = the hours of operation of engine i on the drilling or workover rig [hr/yr]

Equation 12-9: Calculating N2O Emissions from Drill Rig and Workover Rig Engines

EN2O = Σ HPi × LFi × BSFCi × HHV × EFN2O × ti,annual

where: EN2O = the emissions of N2O for a drilling or workover rig [tonne/yr] HPi = the horsepower of engine i on the drilling or workover rig [hp] LFi = the load factor of engine i on the drilling or workover rig BSFCi = the brake specific fuel consumption of engine i on the drilling or workover rig [lb-fuel/hp-hr] HHV = the higher heating value of the diesel fuel [BTU/lb] EFN2O = the emissions factor of N2O on an energy basis assuming the higher heating value (HHV) of the fuel [tonne/BTU] Ti,annual = the hours of operation of engine i on the drilling or workover rig [hr/yr]

Please refer to Tables 12.1 through 12.9 of the GRP to find the emission factors (EFCO2, EFCH4, and EFN2O) needed to solve Equation 12-7, Equation 12-8 and Equation 12-9.

METHOD O3


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METHODOLOGY FOR HEATERS AND BOILERS

Heaters and boilers used in the E&P sector may include external combustion devices at gas processing plants, large compressor stations and gas and oil wellheads. Examples of such devices include steam boilers, heaters used in a variety of gas processing steps, reboilers used in dehydration and acid gas removal, and separator and tank heaters. You should use the methodologies provided in Section 12.2 of the GRP to calculate emissions from all heaters and boiler for which fuel consumption data are available. However, the following equations may be used when fuel consumption data are lacking.

Equation 12-10: Calculating CO2 Emissions from Heaters and Boilers

ECO2 = {(Qfiring/HHV) × [(1.0 lb-mole)/379.3 scf] × MWgas × fc × fo × (44 g CO2/12 g

C) × tannual × c}/2200

where: ECO2 = the annual emissions of CO2 for a heater/boiler [tonne/yr] Qfiring = the specified firing rate of the heater/boiler [MMBTU/hr] HHV = the higher heating value of the fuel [MMBTU/scf] MWgas = the molecular weight of the natural gas (which may be assumed to be 17.4 lb/lb-mole where a specific fuel composition is not known) [lb/lb-mole] Fc = the mass fraction of carbon in the fuel Fo = the fraction of fuel carbon oxidized to CO2 (which may be assumed to be 1.0) tannual = the annual hours of usage of the heater/boiler [hr/yr] c = the cycling fraction of the heater/boiler (if it uses cycling to maintain a set point temperature)

Equation 12-11: Calculating CH4 Emissions from Heaters and Boilers

ECH4 = [(Qfiring/HHV) × EFCH4 × tannual × c]/(2200 × 106)

where: ECH4 = the annual emissions of CH4 for a heater/boiler [tonne/yr] Qfiring = the specified firing rate of the heater/boiler [MMBTU/hr] EFCH4 = the emissions factor of CH4 on a volumetric basis [lb/MMSCF]


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Equation 12-11: Calculating CH4 Emissions from Heaters and Boilers

tannual = the annual hours of usage of the heater/boiler [hr/yr] c = the cycling fraction of the heater/boiler (if it uses cycling to maintain a set point temperature)

Equation 12-12: Calculating N2O Emissions from Heaters and Boilers

EN2O = [(Qfiring/HHV) × EFN2O × tannual × c]/(2200 × 106)

where: EN2O = the annual emissions of N2O for a heater/boiler [tonne/yr] Qfiring = the specified firing rate of the heater/boiler [MMBTU/hr] EFN2O = the emissions factor of N2O on a volumetric basis [lb/MMSCF] tannual = the annual hours of usage of the heater/boiler [hr/yr] c = the cycling fraction of the heater/boiler (if it uses cycling to maintain a set point temperature)

Please refer to Tables 12.1 through 12.9 of the GRP to find the emission factors (EFCO2, EFCH4, and EFN2O) needed to solve Equation 12-10, Equation 12-11 and Equation 12-12. Example 12-2: Calculating Emissions for a Stationary Combustion Device Lacking Fuel Consumption Data

An E&P Member of The Registry has a 5-MW natural gas turbine, used to generate electricity on an offshore oil platform located in U.S. waters. The turbine has a heat rate of 16,000 BTUs/kWh. This same Member also has a small, 150 horsepower, and two-stroke natural gas-fired reciprocating engine used to drive an unpermitted compressor at a remote location in the U.S. Because neither the gas turbine nor the engine are metered, fuel consumption data are lacking. However, it is known that the engine was in operation 50 percent of the time during the reporting year, while the gas turbine operated 80 percent of the time. The first step in calculating the emissions for these two combustion devices is to select an appropriate methodology(ies), based on the type of devices and the available data. Since fuel consumption data are not available, the calculation methodologies provided in the GRP are not applicable, and one of the methodologies presented in this section must instead be used. Equations 12.1, 12.2, and 12.3 are applicable to engines and turbines used to drive compressors, and therefore can be applied to the compressor engine. Emissions from the natural gas turbine, on the other hand, should be calculated using the methodology for gas turbine generators— Equation 12-4, Equation 12-5 and Equation 12-6 above.


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Turning first to the compressor engine, emission factors on a per unit of energy basis for CO2 must be obtained for the fuel (natural gas) used to run the engine. The second to last column of Table 12.1 in the GRP (Tier C Method) provides CO2 emission factors on a per unit energy basis for various fuel types, including natural gas. This table provides separate emission factors for natural gas by heat content category. However, since the heat content of the natural gas used by the engine is unknown, the “Unspecified (Weighted U.S. Average)” emissions factor of 53.06 kg CO2/MMBTU should be used. Since Equation 12-1 requires an emission factor specified in tonnes/MMBTU, the emission factor from Table 12.1 of the GRP must be converted into the correct units, as follows:

EFCO2 = (53.06 kg CO2/MMBTU)(1 tonne/1000 kgs) = 0.0536 tonnes CO2/MMBTU. Table 12.7 of the GRP provides a CH4 emissions factor of 658 grams/MMBTU for a 2-stroke, natural gas-fired reciprocating engine. Converting to the units required in Equation 12-2:

EFCH4 = (658 g CH4/MMBTU)(1 tonne/1,000,000 g) = 0.000658 tonnes CH4/MMBTU. Table 12.7 of the GRP indicates that there are no N2O emission factors available for natural gas- fired reciprocating engines. However, Table 12.9 of the GRP provides a generic N2O emission factor of 0.1 g/MMBTU for natural gas applications in the industrial sector. Converting to the units required in Equation 12-3:

EFN2O = (0.1 g CH4/MMBTU)(1 tonne/1,000,000 g) = 0.0000001 tonnes CH4/MMBTU. Equation 12-1, Equation 12-2and Equation 12-3 also require a load factor (LF), but as data on the engine’s load factor is unavailable it is necessary to use the default load factor of 0.5 for unpermitted compressor engines. Finally, an estimate of the number of hours the engine was in operation during the year is needed. This can be computed based on the information, provided above, that the engine was in operation 50 percent of the time, as follows:

tannual = (0.5)(8760 total hours in a year) = 4380 hrs of operation With the above-determined default values for the emission and load factors, and the hours of operation of the engine, Equation 12-1, Equation 12-2 and Equation 12-3 can now be solved. First, CO2 emissions from the engine are calculated using Equation 12-1 as follows:

ECO2 = HP × LF × fe × EFCO2 × tannual

ECO2 = (150 hp) × 0.5 × (0.007858 MMBTUs/hp-hr) × 0.0536 tonnes CO2/MMBTU ×

4380 hrs

ECO2 = 138.36 tonnes CO2


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The engine’s CH4 emissions are calculated using Equation 12-2 as follows:

ECH4 = HP × LF × fe × EFCH4 × tannual

ECO2 = (150 hp) × 0.5 × (0.007858 MMBTUs/hp-hr) × 0.000658 tonnes CH4/MMBTU ×

4380 hrs

ECO2 = 1.70 tonnes CH4

The engine’s N2O emissions are calculated using Equation 12-3 as follows:

EN2O = HP × LF × fe × EFN2O × tannual

EN2O = (150 hp) × 0.5 × (0.007858 MMBTUs/hp-hr) ×0.0000001 tonnes N2O/MMBTU ×

4380 hrs

EN2O = 0.000258 tonnes N2O Finally, the total emissions of the engine on a CO2 equivalent can be computed by applying the GWPs for CO2, CH4 and N2O (1, 21 and 310, respectively, from Appendix B of the GRP) to the emissions for these gases, and then summing across gases, as follows:

Total emissions of engine = (138.36 tonnes CO2 × 1) + (1.70 tonnes CH4 × 21)

(0.000258 tonnes N2O × 310)

Total emissions of engine = 138.36 tonnes CO2-e + 35.70 tonnes CO2-e + 0.080 tonnes CO2-e = 174.14 tonnes CO2-e

Turning now to the natural gas turbine generator on the offshore platform, it is first necessary to obtain appropriate emission factors from Tables 12.1 to 12.9 of the GRP. CO2 emission factors for combustion devices vary depending on the fuel type but not the technology. Therefore, since the turbine uses the same fuel type (natural gas) as the compressor engine, the CO2 emission factor will be the same for both devices (i.e., 0.0536 tonnes CO2/MMBTU). However, CH4 and N2O emission factors vary depending on technology type, and hence the emission factors developed above for the compressor engine cannot be applied to the gas turbine. Instead, turning to Table 12.7 of the GRP, we find that the appropriate emission factors for a gas-fired gas turbine with a rated capacity in excess of 3 MWs are:

3.8 g CH4/MMBTU, or 0.0000038 tonnes CH4/MMBTU; and 0.9 g N2O/MMBTU, or 0.0000009 tonnes N2O/MMBTU.


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Total hours of operation for the gas turbine, given its 80 percent utilization rate, can be computed as follows:

tannual = (0.8)(8760 total hours in a year) = 7008 hrs of operation Solving Equation 12-4 for CO2 emissions, we obtain:

ECO2 = (P × HR × EFCO2 × tannual) / 1000

ECO2 = 5 Mws × 16,000 BTUs/kWh ×0.0536 tonnes CO2/MMBTU × 7008 hrs) / 1000

ECO2 = 30,050.3 tonnes CO2

Solving Equation 12-5 for CH4 emissions, we obtain:

ECH4 = (P × HR × EFCH4 × tannual) / 1000

ECH4 = 5 Mws × 16,000 BTUs/kWh ×0.0000038 tonnes CH4/MMBTU × 7008 hrs) / 1000

ECH4 = 2.13 tonnes CH4

Solving Equation 12-6 for N2O emissions, we obtain:

EN2O = (P × HR × EFN2O × tannual) / 1000

EN2O = 5 Mws × 16,000 BTUs/kWh ×0.0000009 tonnes N2O/MMBTU × 7008 hrs) / 1000

EN2O = 0.50 tonnes N2O

Finally, the total emissions of the turbine on a CO2 equivalent can be computed by applying the GWPs for CO2, CH4 and N2O (1, 21 and 310, respectively, from Appendix B of the GRP) to the emissions for these gases, and then summing across gases, as follows:

Total emissions of turbine = (30,050.3 tonnes CO2 × 1) + (2.13 tonnes CH4 × 21) (0.50

tonnes N2O × 310)

Total emissions of engine = 30,050.3 tonnes CO2-e + 44.73 tonnes CO2-e + 155 tonnes CO2-e = 30,250.03 tonnes CO2-e


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Chapter 13: Direct Emissions from Mobile Combustion

13.1 Calculating Carbon Dioxide Emissions from Mobile Combustion REFER TO GRP.

13.2 Calculating Methane and Nitrous Oxide Emissions from Mobile Combustion REFER TO GRP.

13.3 Example: Direct Emissions from Mobile Combustion REFER TO GRP.


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Chapter 14: Indirect Emissions from Electricity Use

REFER TO GRP

14.1 Quantifying Indirect Emissions from Electricity Use Example 14-1: Indirect Emissions from Electricity Use

REFER TO GRP


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Chapter 15 Indirect Emissions from Imported Steam, District Heating, Cooling and Electricity from a CHP Plant

15.1 Calculating Indirect Emissions from Heat and Power Produced at a CHP Facility Refer to GRP. Please note that Section 15.1 of the GRP also applies to CHP facilities operated by one entity and transferred to another for steam flood and cyclic steam wells.

15.2 Calculating Indirect Emissions from Imported Steam or District Heating from a Conventional Boiler Plant Refer to GRP. Please note that Section 15.2 of the GRP also applies to steam generators operated by one entity and transferred to another for steam flood and cyclic steam wells.

15.3 Calculating Indirect Emissions from District Cooling Refer to GRP

15.4 EXAMPLE: INDIRECT EMISSIONS FROM DISTRICT HEATING Refer to GRP


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Chapter 16 Direct Fugitive Emissions

REFER TO GRP.

16.1 Calculating Direct Fugitive Emissions from Refrigeration Systems REFER TO GRP.

EXAMPLE: DIRECT FUGITIVE EMISSIONS FROM REFRIGERATION SYSTEMS REFER TO GRP.


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PART IV: REPORTING YOUR EMISSIONS

Chapter 17: Completing Your Annual Emissions Report

17.1 Additional Reporting Requirements Refer to GRP

17.2 Optional Data As discussed in Section 17.2 of the GRP, The Registry encourages you to exceed its reporting requirements by providing optional data along with your required data. There is a wide array of optional data you may report, including, e.g., your entity’s worldwide emissions, historical emissions, and emissions of GHGs beyond the six Kyoto gases. For a more comprehensive list of optional data, please refer to Section 17.2 of the GRP. One set of optional data that can be particularly useful is performance metrics, or GHG intensity ratios. Intensity ratios measure GHG emissions per unit of physical activity (e.g., barrels of oil produced) or economic unit (e.g., total sales in dollars). As noted in the GRP, tracking and reporting intensity ratios can serve a variety of purposes, including:

Evaluation of emissions over time in relation to targets or industry benchmarks; Facilitation of comparisons between similar businesses, processes or products; and

Improving public understanding of your entity’s emissions profile over time, even as your

business activity changes, expands or decreases. E&P companies have reported GHG intensity data to a variety of programs, including, e.g., the California Climate Action Registry and the Carbon Disclosure Project. Based on the data collected under these programs, the most common efficiency metric that is currently reported is GHG emissions on a per unit of production basis. A number of companies are also starting to provide regional information on emissions per unit of production. This metric can provide a useful basis for comparing similar fields in the same region or producing basin. Within the same basin, there is usually uniformity in important parameters such as oil vs. gas, oil quality, and depth. As just one example of the type of intra-basin analysis that might be performed given sufficient GHG field-level intensity data, the emissions performance of various fields might be assessed by field age. Older fields within a basin would typically be expected to be more energy and emissions intensive on a unit of production basis due to declining oil/gas volumes, secondary recovery operations, or increased compression needs. However, field-level information on GHG emissions per unit of production is just one example of the type of performance metrics you might choose to provide to The Registry. Again, the


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submission of performance metrics data, although strongly encouraged, is optional; and the specific metrics you decide to provide, along with the level of detail at which you provide this data (e.g., field-level, basin-level, etc.), is up to you.


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Chapter 18: Reporting Your Data Using CRIS

To be provided by TCR

18.1 CRIS Overview Modifications to CRIS are currently being considered.

18.2 Help with CRIS Modifications to CRIS are currently being considered.


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Chapter 19: Third-Party Verification

19.1 Background: The Purpose of The Registry’s Verification Process REFER TO GRP.

19.2 Activities To Be Completed by the Member in Preparation for Verification REFER TO GRP. QUESTION FOR TWG and TCR: DO THE STANDARD COI RULES IN THE GVP NEED TO BE EXPANDED TO ADDRESS THE COMPLEX OWNERSHIP AND OPERATING PATTERNS CHARACTERIZING THIS SECTOR? SPECIFICALLY, IF A VERIFIER IS HIRED TO VERIFY THE EMISSIONS OF THE OPERATING COMPANY OF A CONSORTIUM, SHOULD THE VERIFIER’S RELATIONSHIPS WITH OTHER CONSORTIUM MEMBERS BE RELEVANT TO THE DETERMINATION OF CASE SPECIFIC COI? IF SO, HOW WOULD THE COI RULES NEED TO BE CHANGED? WOULD EXPANSIONS OF THE DEFINITION OF COI STILL LEAVE A SUFFICIENT POOL OF QUALIFIED VERIFIERS FOR THIS SECTOR, OR WOULD O&G COMPANIES BE UNABLE TO FIND ANY VERIFIERS WITHOUT CONFLICTS OF INTEREST?

19.3 Batch Verification Option REFER TO GRP.

19.4 Verification Concepts As discussed in Chapter 5 of this OG&P Protocol, Registry Members operating in the E&P sector are required to report all Scope 3 contractor emissions associated with the three activities of drilling, completions, and workovers. Furthermore, all Scope 3 contractor emissions associated with drilling, completions, and workovers must be verified. Other optional Scope 3 emissions should not be verified; only the Scope 3 emissions that leaseholders are required to report must be verified. The Scope 3 contractor emissions associated with drilling, completions, and workovers should be combined with the Member’s Scope 1 emissions for the purpose of determining whether or not the 5 percent materiality threshold has been exceeded. In other words, the Scope 1 materiality threshold must be expanded to include the mandatory Scope 3 sources (again, optional Scope 3 sources are excluded from the verification requirements). Scope 2 emissions should continue to be assessed separately against the 5 percent materiality threshold, as described in the Registry’s General Verification Protocol (GVP).


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The GVP requires Verification Bodies to confirm that not more than 5 percent of total emissions have been estimated using simplified methods not prescribed in the GRP. However, as discussed in Chapter 11 of this OG&P Protocol, the Registry exempts certain E&P emission sources from the 5-percent threshold. Specifically, the Registry exempts emissions from flaring and water ponds from the 5-percent threshold. In addition, the Registry exempts required Scope 3 (contractor) drilling, completion, and workover emissions, along with emissions from small combustion devices, when the leaseholder cannot obtain the data needed to apply Registry-approved methods to these emission sources. If the Member chooses to use the latter exemptions, the Verification Body should confirm that the Member attempted to obtain the data needed to apply Registry-approved methods but was unable to do so. Furthermore, if the 5-percent threshold has been exceeded, the Verification Body must verify that simplified methods were used exclusively to estimate emissions from sources meeting the Registry’s criteria for exemption from the threshold. The 5-percent threshold can be exceeded only when emissions from exempt sources exceed 5 percent of the Member’s total emissions; if exempt sources total less than 5 percent of the entity’s emissions then the 5-percent threshold remains in effect.

19.5 Verification Cycle REFER TO GRP.

19.6 Conducting Verification Activities As discussed in Chapter 6 of this OG&P Protocol, a field is considered to be the equivalent of a facility for purposes of aggregating emissions from E&P activities. Section 4.4.4 of the GVP, and in particular Table 4.2, provides Verification Bodies some guidance on determining the number of facilities to be visited during the verification process. The Verification Body should treat each field a Member has operations in as equivalent to a single facility when selecting the sample of sites to visit. More specifically, the Verification Body should understand the term “facility” in Table 4.2 of the GVP to refer to either a standard facility (i.e., a single physical premises) or a field. question for the TWG: is the generic guidance for selecting an appropriate sample size provided in table 4.2 of the GVP applicable to the O&G E&P sector, or should the ratio between the sample size and the total number of facilities (fields) be adjusted up or down for the E&P sector?

19.7 Activities To Be Completed After the Verification Body Reports Its Findings REFER TO GRP.

19.8 Unverified Emission Reports REFER TO GRP.


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Chapter 20: Public Emission Reports

20.1 Required Public Disclosure As described in the GRP, your verified annual emission reports are accessible to the public through the Registry’s website. Your required Scope 3 contractor emissions data, along with your own organization’s data, will be disclosed at the facility-, or field-, level, by gas and emissions category. Your contractor emissions data will not be released by individual contractor. You may apply to the Registry for an exemption from the public release of your organization’s, and/or your contractor’s, facility-level emissions data. Section 20.2 in the GRP describes the general procedure for applying for an exemption, while Section 20.2 describes how to limit an exemption request to Scope 3 contractor emissions data. Please refer to Section 20.1 of the GRP for other information on the required public disclosure of your emissions data. Question for TCR: is it true to say contractor emissions data will not be released at the contractor level?

20.2 Confidential Business Information As described in Section 20.2 of the GRP, The Registry provides a process for applying for an exemption to the public release of your organization’s facility-level emissions data, if such a public release will jeopardize your organization’s confidential business information. In addition, oil and gas leaseholders are provided the option of applying for a more limited exemption to the release of their Scope 3 contractor emissions data at the facility (i.e., field) level. Note that if you apply for an exemption from the release of your own organization’s facility-level data, and the Registry grants the exemption, your Scope 3 contractor emissions data will be protected from release along with your own organization’s data. The separate option for protecting contractor emissions data only is offered to Members that wish to release their own organization’s data to the public, while protecting the data provided by their contractors from public release. Even if you are granted an exemption your Scope 3 contractor emissions data will still be publicly released in aggregate form (specifically, by gas and emissions category as well as by state/province); exemptions apply only to the release of emissions data at the facility (i.e., field) level. Your contractor emissions data will not be released by individual contractor. However, you should be aware that if you use one (or in some cases just a few) contractor(s) to perform drilling, completion, and workover activities in a given field, it may be possible for a data user to identify the contractor(s) to which your reported Scope 3 emissions data apply, depending on the public availability of data identifying your contractors by field. The procedure for applying for an exemption from the field-level release of your contractor emissions data is essentially the same as that described in the GRP in Section 20.2.


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Specifically, you should download the Public Disclosure Exemption Request Form from the Registry’s website: www.theclimateregistry.org, and either mail or email the completed form to the Registry. If you are requesting an exemption exclusively for your Scope 3 contractor emissions data and not your own organization’s data, be sure to indicate that your request applies only to your Scope 3 contractor data in your answer to the question “What kinds of information are you concerned about disclosing?” (the second question on the Public Disclosure Exemption Request Form). Please refer to Section 20.2 of the GRP for additional information on requesting an exemption from the public release of facility- (field-) level data. Question for TCR: can CRIS handle a request to exempt scope 3 contractor emissions data, or would it be necessary to exempt all scope 3 emissions?


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PART V: ADDITIONAL EMISSION CALCULATION METHODOLOGIES FOR SOURCES UNIQUE TO THE OIL AND GAS E&P SECTOR

The following topics are included in these additional chapters of the E&P Protocol because they are not addressed within the GRP structure:

Fugitive Emissions – Flashing and working/breathing losses from tanks, pneumatic devices and pumps operating with natural gas, wellhead and facility fugitive losses, and surface collection ponds.

Vented Emissions – Amine plant process venting, dehydrators, well testing and completions, well blowdowns, underbalanced drilling, drilling mud degassing, vessel and facility upsets/blowdowns and compressor engine start-ups and shutdowns.

Flaring Emissions Oil Sands and Oil Shales Specific Emission Sources – upgrader facilities, hydrogen unit,

flue gas desulphurization, oil sands mines and ponds emissions. These additional chapters will need to be used by oil & gas fields, gas plants, and straddle plants to develop their emission inventories. Members will need to cross check the types of equipment in use at their fields and facilities against the chapters presented here. Almost any of the chapters could apply to any particular oil or gas field. For gas plants and straddle plants, the sections of most relevance are:

21.3 Vented Emissions from Pneumatic Devices 21.4 Vented Emissions from Natural Gas-Driven Chemical Injection Pumps 21.5 Wellhead and Facility Fugitive Losses 22.1 Amine Plant Process Venting 22.2 Dehydrators 22.5 Vessel and Facility Upsets/Blowdowns and Compressor Engine Start-Ups and

Shutdowns 23 Flaring Emissions

(NOTE: A similar explanatory paragraph will be written when the oil transportation sector is included)

Chapter 21: Fugitive Emissions

21.1 Flashing Losses from Tanks Crude oil production tanks emit CH4 (and potentially CO2 for a CO2 rich stream) through flashing losses, which occur as the crude oil pressure decreases from the separator conditions to atmospheric pressure in the storage tank. Flashing emissions can be significant where there is a significant reduction in pressure. This primarily occurs during production operations. Liquid


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petroleum storage tanks can also produce emissions through working and breathing losses; these methodologies are described in Section 21.2. Tanks can be used extensively across oil fields, or their usage may be very minimal if there is significant pipeline infrastructure installed and the crude oil produced is sent to refinery facilities through pipelines. A variety of calculation methods, described below, can be used to estimate flashing losses from production storage tanks.

METHOD 01 Tank fugitive emissions can be measured directly (volume flow rate measurements and gas chromatography-mass spectrometry (GC/MS) analysis of CO2 and CH4 concentration if present in the gas), providing accurate emissions estimates for the measured tanks. Members can measure hydrocarbon emissions from tanks using a flow meter (i.e. high volume samplers, calibrated bags, rotameters, turbine meters, etc) for a test period that represents normal operation conditions throughout the year. Members may maintain records of: gross input of the storage tank during the test period, and temperature and pressure of hydrocarbon vapors emitted during the test period. Samples of hydrocarbon vapors should be collected for composition analysis. Calculate emissions from tanks as follows4:

1. Total annual hydrocarbon vapor fugitive emissions are calculated using Equation 21-1

Equation 21-1: Annual Hydrocarbon Vapor Fugitive Emissions

Es,n = [Ea,n x (460 + Ts) x Pa]/ (460 + Ts) x Ps where,

Es,n = Natural gas volumetric fugitive emissions at standard temperature and pressure conditions.

Ea,n = Natural gas volumetric fugitive emissions at actual conditions.

Ts = Temperature at standard conditions (ºF)

Ta = Temperature at actual emission conditions (ºF)

Ps = Absolute pressure at standard conditions (inches of Hg)

4 EPA Mandatory GHG Reporting Rule, 2009.


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Equation 21-1: Annual Hydrocarbon Vapor Fugitive Emissions

Pa = Absolute pressure at ambient conditions (inches of Hg)

2. The hydrocarbon vapor volumetric fugitive emissions are calculated using the Equation 21-2

Equation 21-2: Hydrocarbon Vapor Volumetric Fugitive Emissions

Es,n = [Ea,n x (460 + Ts) x Pa]/ (460 + Ts) x Ps where,

Es,n = Natural gas volumetric fugitive emissions at standard temperature and pressure conditions.

Ea,n = Natural gas volumetric fugitive emissions at actual conditions.

Ts = Temperature at standard conditions (ºF)

Ta = Temperature at actual emission conditions (ºF)

Ps = Absolute pressure at standard conditions (inches of Hg)

Pa = Absolute pressure at ambient conditions (inches of Hg)

3. Estimate CH4 and CO2 mass emissions from GHG volumetric fugitive emissions using Equation 21-3

Equation 21-3: CH4 and CO2 Emissions From Volumetric Fugitive Emissions

Masss,i = Es,i x i where,

Masss,i = GHGi (either CH4 and CO2) mass emissions at standard conditions.

Es,i = GHGi (either CH4 and CO2) volumetric emissions at standard conditions.

i = Density of GHGi; 1.87 kg/m3 for CO2 and 0.68 kg/m3 for CH4.

METHOD 02


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COMPUTER MODELING METHODOLOGY

Members may use API's E&P TANKS software (API, 1997) to estimate flashing losses. This program is based on Peng-Robinson (PR) Equation of State (EOS)5. This approach requires the following input parameters: tank configuration, API gravity and Reid Vapor Pressure (RVP) of the sales oil, oil composition, separator atmospheric pressure and temperature, and production rate of liquid to tanks. If the oil composition is unknown, the program contains a fluid composition database of more than one hundred oil analyses. Members can sort the database by geographic region, sales oil physical properties, and separator pressure and temperature. Parameters should be selected so that they are similar to the conditions of the particular facility. The E&P TANKS model is valid for liquids with API gravity ranging from 16 to 68 degrees. Once the appropriate data have been entered, flashing losses are calculated by flashing the upstream oil stream to atmospheric pressure. Normal evaporation losses are then inferred by matching the oil properties obtained from the flash calculations to the specified API gravity and RVP of the sales oil. QUESTION FOR TWG: CAN THEY PROVIDE MORE DETAILS ABOUT THE ACTUAL PROCESS THE SOFTWARE USES? MAYBE AN EXAMPLE OF THE CALCULATION AND SOME SCREEN SHOTS.

METHOD 03

PROCESS SIMULATORS METHODOLOGY

Members may estimate flashing losses using professional process simulators, these are computer models that use EOS and mass and energy balance equations to simulate a variety of processes. There are a variety of process simulators that can be used to calculate flashing losses (HYSYS, HYSIM, PROSIM, etc); these simulators utilize similar basic principles. Required input data includes: an extended pressurized condensate analysis; temperature, pressure and flow rates for the process being simulated, etc. These simulators are not constrained by API gravity. The use of a simulation model involves the following steps:

Selection of components. Selection of a thermodynamics property package. Construction of a flow sheet. Specification of known streams, unit compositions and conditions. Running the simulation program.

5 EOS is a mathematical equation, which represents the relationship between thermodynamic variables such as pressure, temperature, and volume of a specific material in thermodynamic equilibrium.


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Analysis of the results. -------------------------------------- ----------------- PLACEHOLDER: BP's approach to model flashing emissions (HYSIS) --------------------------------- Question for TWG: Could the BP case presented during the Denver meeting be used as an example for this method?

METHOD 04

CORRELATION EQUATIONS METHODOLOGY

Members may use the Vasquez-Beggs Equation (VBE), standing correlation, or the Alberta Energy Utility Board (EUB) rule-of-thumb methods to estimate tank flashing losses when limited input data are available. The decision of using VBE or standing correlation versus EUB depends on the data available; the EUB approach requires less data input. If sufficient data is available to use VBE or standing correlation, then the choice of using one over the other is left to the discretion of the Member.

VASQUEZ-BEGGS EQUATION (VBE)

The Vasquez-Beggs Equation (VBE) estimates the gas to oil ratio (GOR) of a hydrocarbon as a function of the separator pressure, temperature, gas specific gravity, and the API gravity of the oil. Flashing losses are then calculated by multiplying the GOR by the tank throughput, the weight fraction of VOC in the gas, and the stock tank gas molecular weight. This method was designed for gases dissolved in crude oils, and is most appropriate for use in upstream operations. This equation requires eight input parameters: API gravity, separator pressure, separator temperature, gas specific gravity, volume of produced oil, molecular weight of the stock tank gas, VOC fraction of tank emissions, and atmospheric pressure. The first step in calculating flashing emissions is to estimate the specific gravity of the gas at 100psig using Equation 21-4

Equation 21-4: Specific Gravity of Gas

SGx = SGi x {1.0 + 0.00005912 x API x Ti x log [(Pi + 14.7)/114.7]} where,

SGx= Dissolved gas gravity, adjusted to 100psig


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Equation 21-4: Specific Gravity of Gas

SGi = Dissolved gas gravity at initial conditions, where air = 1. A suggested default value

for SGi is 0.90 (OK DEQ, 2004) API = API gravity of liquid hydrocarbon at final condition

Pi = Pressure of initial conditions, in psig

Ti = Temperature of initial conditions, in °F Then, the flash GOR is calculated using Equation 21-5.

Equation 21-5: Flash GOR

GOR =A x SGx x (Pi + 14.7)B x exp [(C x Goil)/(Ti + 460)]

where, GOR = Ratio of flash gas production to standard stock tank barrels of oil produced, in scf/bbl oil (barrels of oil corrected to 60°F)

SGx= Dissolved gas gravity, adjusted to 100psig

Goil = API gravity of stock tank oil at 60°F

Pi = Pressure in separator, in psig

Ti = Temperature in separator, °F

For Goil ≤ 30°API: A = 0.0362; B = 1.0937; and C = 25.724

For Goil > 30°API: A = 0.0178; B = 1.187; and C = 23.931 The flash gas emissions estimated by the VBE are in terms of total hydrocarbon. Thus, the last step is to estimate the CH4 content in the tank flash gas vent. In the absence of site-specific data, the recommended tank vent CH4 content is 27.4 volume %6. A sample calculation illustrating the use of the VBE applied to flashing loss emissions is provided below. Example 21-1: Flashing Loss Emissions Calculation using the Vasquez-Beggs Equation (VBE)7

6 This value is the average tank vent gas composition from two published studies that measured flashing loss emissions from tanks (Ogle, March 1997/ Ogle, May 1997; Picard, Vol. III, 1992). 7 Source: API Compendium of Greenhouse Gas Emissions Estimation Methodologies for the Oil and Gas Industry. Section 5 - Process and Vented Emission Estimation Methods, May 2009. DRAFT Version.


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An oil and gas production facility produces 71.70 m3/day (451 bbl/day) of crude oil with an API gravity of 48.8°. The separator pressure (immediately upstream of the tank) is 197.2 kPa gauge (28.6 psig), and the separator temperature is 44.4°C (112°F). Neither the tank vent CH4 content nor the tank vent gas specific gravity is known. Flashing losses are not controlled by a vapor recovery system. Calculate flashing loss emissions using the VBE approach. The Member must calculate the flash gas specific gravity adjusted to 100 psig, using Equation

21-4. The flash gas specific gravity at initial conditions, SGi, is not known, so the recommended

default value of 0.90 will be used. SGx = 0.90 x {1.0 + 0.00005912 x 48.8 x 112 x log [(28.6 + 14.7)/114.7]} SGx = 0.78 The Member has to use Equation 21-5 to calculate the flash gas vent flow rate (GOR), using the A, B, and C parameters for an API gravity less than 30. GOR = 0.0178 x (0.78) x (28.6 + 14.7)1.187 x exp [(23.931 x 48.8)/(112 + 460)] GOR = 9.33 scf/bbl oil The output from this equation is in units of scf/bbl oil. The conversion tables in Attachment 2 can be used to convert to SI units. GOR = (9.33 scf gas/bbl crude) x (m3 gas/ 35.3147 scf gas) x (bbl crude/ 0.1589873 m3 crude) GOR = 1.66 m3 gas/ m3 crude The flash gas contains gases besides CH4 and thus the GOR must be multiplied by the tank vent CH4 content. The tank vent CH4 content is not known, so the recommended default concentration of 27.4 volume % CH4 will be used. Thus, the CH4 emissions are estimated as: E (CH4) = (1.66 m3 gas/m3 oil) x (71.70 m3 oil/day) x (365 day/yr) x (kgmole gas/23.685 m3) x (27.4 kgmole CH4/100 kgmole gas) x (16 kg CH4/kgmole CH4) x (tonne/1000 kg) E (CH4) = 8.04 tonnes CH4/yr Question for TWG: Could this example from the API compendium be used in this protocol?

STANDING CORRELATION


DRAFT


As in the case of VBE, this correlation is based on the regression of experimentally determined bubble point pressures for variety of crude oil systems. This equation requires the following input parameters: API gravity, separator absolute pressure, separator temperature, gas specific gravity, and water specific gravity.

Equation 21-6: Standing Correlation

GOR = Gflash gas x (P/ 519.7 x 10yg )

1.204

where,

GOR = Ratio of flash gas production to oil produced, m3/m

3 oil

Gflash gas = Specific gravity of the tank flash gas, where air = 1. A suggested

default value for Gflash gas is 1.22 (TNRCC; Vasquez, 1980) P = Absolute pressure in vessel, kPa

Yg = 1.225 + 0.00164x T – (1.769/SGoil)

SGoil = specific gravity of oil with respect to water = 141.5/(131.5 + Goil)

Goil = API gravity of stock tank oil at 60°F For the situation where the crude flash occurs from a separator to an atmospheric tank, the term in parenthesis must be evaluated separately for the separator and the oil storage tank. In this case, the Member should use Equation 21-7.

Equation 21-7: Standing Correlation – Crude Flash Occurring from Separator8

GOR = Gflash gas x [{(P/ 519.7 x 10yg )

1.204}Separator - {(P/ 519.7 x 10

yg )1.204

} Tank]

As in the case of the VBE approach, the CH4 content must be estimated using the recommended tank vent CH4 content is 27.4 volume %9. Example 21-2: Flashing Loss Emissions Calculation using Standing Correlation

The facility is the same oil and gas production facility described in Example 21-1. Crude oil production per day is 451 bbl (71.7 m3 oil/day), API gravity is 48.8°, and flashing losses occur

8 Note that the units for the standing correlation variables are different than the units for the VBE. 9 Average tank vent gas composition from Ogle, March 1997/ Ogle, May 1997; Picard, Vol. III, 1992.


DRAFT


as the oil flows from a separator at 28.6 psig and 112°F to an atmospheric tank. The atmospheric temperature (and thus the storage tank temperature) is assumed to be 80°F (299.8 K). Flashing losses are not controlled by a vapor recovery system. The Member has to calculate flashing loss emissions using Equation 21-7 First, the input parameters must be converted to the proper SI units for use in the equation, using the conversion factors presented in Attachment 2. Note that the separator absolute pressure is 43.3 psia (28.6 psig + 14.7 psia) while the tank pressure is 1 atm. Thus, the pressures in kPa are: Psep = (43.3 psi) x (6.894757 kPa/psi) = 298.5 kPa Ptank = (1 atm) x (101.325 kPa/atm) = 101.3 kPa Next, the oil API gravity (Goil) is converted to a specific gravity: SGoil = 141.5/(131.5 + Goil) = 141.5/(131.5 + 48.8) = 0.785 Next, the parameter, yg, can be calculated for both the separator and tank using the oil-specific gravity and temperatures in the separator (112°F or 317.6 K) and the tank (80°F or 299.8 K): yg,sep = 1.225 + (0.00164) x (317.6) – (1.769/0.785) = -0.5076 yg,tank = 1.225 + (0.00164) x (299.8) – (1.769/0.785) = -0.5368 The flash gas vent flow rate (GOR) is calculated below: GOR = 0.90 x [{(298.5/ 519.7 x 10-0.5076)1.204} Sep - {(101.3/ 519.7 x 10-0.5368)1.204} Tank] GOR = 1.329 m3 gas/m3 oil Similar to Example 21-1, the flash gas contains gases besides CH4 and must be multiplied by the tank vent CH4 content. The Member must follow the same procedure presented in the previous example to calculate the CH4 content. Thus, the CH4 emissions are: E (CH4) = 6.44 tonnes CH4/yr Question for TWG: Could this example from the API compendium be used in this protocol?

EUB RULE-OF-THUMB

This is a simple correlation that relates the gas volume to the oil production volume and the amount of pressure drop in the tank. This approach tends to yield conservatively high flashing


DRAFT


loss estimates and is recommended for facilities with low oil volumes, established pools, mature pools with declining GOR’s, and some heavy oil production facilities.

Equation 21-8: EUB Rule of Thumb

Vs = 0.0257 x Vo x ∆P

where,

Vs = volume of gas released, m3

Vo = oil production volume, m3

∆P = pressure drop to atmospheric tank, KPa The flash gas emissions estimated using the EUB rule-of-thumb approach must be converted to a CH4 emissions basis. As noted earlier, a default of 27.4 volume % CH4 is assumed in the absence of site-specific data10. An example illustrating the calculations is presented below. Example 21-3: Flashing Loss Emissions Calculation using the EUB Rule-of-Thumb Correlation11

The facility is the same one described in Example 21-1 and Example 21-2. For illustrative purposes, this exhibit shows how CO2 emissions would be estimated as well. For this facility, the CO2 tank vent concentration is assumed to be approximately 4.5 volume %. The Member can calculate the flashing loss emissions using Equation 21-8. Crude oil production = 451 bbl/day (71.70 m3/day) First, the input parameters must be converted to the proper SI units for use in the equation, using the conversion factors presented in Attachment 2. The separator gauge pressure, 28.6 psig, is equal to the pressure drop from the separator to the atmospheric storage tank (i.e., 43.3 psia - 14.7 psia = 28.6 psi). Thus, the pressure drop in kPa is: ∆P = (28.6 psi) x (6.894757 kPa/psi) = 197.2 kPa The flash gas vent flow rate is calculated below: Vs = 0.0257 x (71.7) x (197.2) = 363.4 m3/day

10 Average tank vent gas composition from Ogle, March 1997/ Ogle, May 1997; Picard, Vol. III, 1992. 11 Source: API Compendium of Greenhouse Gas Emissions Estimation Methodologies for the Oil and Gas Industry. Section 5 - Process and Vented Emission Estimation Methods, May 2009. DRAFT Version.


DRAFT


As in Example 21-1 and Example 21-2, the flash gas contains gases besides CH4 and must be multiplied by the tank vent CH4 content. The tank vent CH4 content is not known so the recommended default concentration of 27.4 volume % CH4 will be used. Thus, the CH4 emissions are: E (CH4) = 24.56 tonnes CH4/yr Question for TWG: Could this example from the API compendium be used in this protocol?

METHOD 05

EMISSION FACTOR METHODOLOGY

This approach uses data from two published studies, API/GRI (Ogle, March 1997; Ogle, May 1997) and the Canadian Petroleum Association (Picard, Vol. III, 1992), to derive emission factors for production crude oil storage tanks. The measurement programs included gas streams with varying CH4 contents. In order to combine the measurements, each was converted to a common production segment CH4 concentration of 78.8%. This approach should be used only if very limited data are available. CH4 emission factors are presented in the table below. Table 21.1 - CH4 Flashing Loss Emission Factors for Crude Oil Storage Tanks12

Source CH4 Flashing Loss Emission Factor Combined API/GRI and CPA data 46.18

1.954 8.86E-04 5.57E-03

Scf/bbl lb/bbl crude tonnes/bbl crude tonnes/m3 crude

Example 21-4: Flashing Loss Emissions Calculation using the Emission Factor13

An oil and gas production facility produces 451 bbl/day of crude oil (same as the examples). The separator gas (to sales pipeline) CH4 content is 58 volume %. The Member has to calculate the CH4 emissions using the emission factors Table 21.1 Note that the emission factor from the table is based on 78.8 mole % CH4 in the separator gas, so this emission factor must be corrected to 58 mole % based on the composition for this example. E (CH4) = (451bbl oil/day) x (365 day/yr) x (8.86 x 10-4 tonnes CH4/bbl oil) x (58 mole % CH4/ 78 mole % CH4)

12 API Compendium of Greenhouse Gas Emissions Estimation Methodologies for the Oil and Gas Industry. Appendix B, 2004. 13 Source: API Compendium of Greenhouse Gas Emissions Estimation Methodologies for the Oil and Gas Industry. Section 5 - Process and Vented Emission Estimation Methods, May 2009. DRAFT Version.


DRAFT


E (CH4) = 107.4 tonnes CH4/yr Question for TWG: Could this example from the API compendium be used in this protocol?

21.2 Working/Breathing Losses from Tanks Working loss emissions occur because of evaporative losses of the liquid as a result of changes in liquid level in the tank (emptying and filling activities). Standing or breathing losses occur during storage of the liquid, and can result from diurnal temperature changes. Most of the CH4 and CO2 emissions from crude storage tanks occur as a result of flashing (Section 21.1), working and breathing loss emissions are very small in production activities and virtually non-existent in the downstream segments. EPA provides a methodology to estimate tank hydrocarbon emissions due to tank working and standing losses. This methodology can be found in Chapter 7 of AP-4214. This methodology forms the basis for the TANKS software program (EPA, 1999)15. EPA’s methodology primarily estimates total hydrocarbon (THC) or volatile organic compound (VOC). Members would have to estimate the total emissions from the tank and then multiply the total emissions by the concentration of CH4 and CO2 in the tank vent stream. CH4 and CO2 concentrations should be based on site data if they are available. Question for API: The emission estimation equations in Chapter 7 of AP-42 were developed by API (API retains the copyright of the equations but has granted EPA permission to publish them). Can we include the equations in this protocol?

21.3 Vented Emissions from Pneumatic Devices This section provides a method for calculating vented emissions from pneumatically-powered devices at oil and natural gas wells and facilities that utilize natural gas as a pressurized fluid. These devices are used in a variety of applications, including compressor motor starters, isolation shutoff valves, small pneumatic motors, and for controlling and monitoring gas and liquid flows, temperature in dehydrator regenerators and pressure in flash tanks. While such devices can be pneumatic, electric or mechanical, this guidance applies only to those that utilize natural gas as a pressurized fluid; these tend to be more commonly employed where access to grid-supplied electricity is limited, but natural gas is plentiful, including wellheads and remote pipeline locations.

14 The emission estimation equations in Chapter 7 of AP-42 were developed by API (API retains the copyright of the equations but has granted EPA permission to publish them). 15 The TANKS software available at: http://www.epa.gov/ttn/chief/software/tanks/index.html


DRAFT


As part of normal operation, natural gas powered pneumatic control devices release (or “bleed”) gas to the atmosphere and, consequently, can be a significant source of methane emissions. If the natural gas used by the devices has a naturally occurring CO2 content, CO2 emissions can also be significant. Methods for calculating CH4 and CO2 emissions from pneumatic devices are provided below. Emissions from gas-driven pneumatic pumps are not included in this section, and are described in Section 21.4.

METHOD O1

METHOD FOR CALCULATING CH4 EMISSIONS FROM NATURAL GAS-DRIVEN PNEUMATIC DEVICES BASED ON BLEED RATES

This method relies on estimates of device bleed rates, usage information, the CH4 content of the natural gas, and device counts for each natural gas production segment considered in order to calculate CH4 emissions using Equation 21-9, below.

Equation 21-9: Calculating CH4 Emissions from Natural Gas-Driven Pneumatic Devices based on Bleed Rates

22003.379

0.1444 , annualCHCH

iibleediCH tfMW

scf

molelbNE

where: E CH4/CO2 = the total pneumatic device venting emissions of CH4/CO2 from each production segment [tonne/yr] Ni = the number of devices of type i in the basin or region Q bleed = the bleed rate of gas from device type i [scfd] MW CH4 = the molecular weight of methane (16 lb/lb-mole) f CH4/CO2 = is the molar fraction of CH4/CO2 in the gas t annual = the annual usage of the pneumatic device (hr/yr)

This approach involves six steps:

1. Identify the type and number of each pneumatic device employed in a given basin or region;

2. Identify the hours of annual usage of each device type; 3. Determine the appropriate bleed rate for each device type – if the gas system serving

the device is pressurized, the device can be assumed to be “bleeding”;


DRAFT


4. Obtain the molar fractions of CH4 and CO2 for the natural gas used in each device; 5. Calculate CH4 and CO2 emissions for each device; and 6. Convert CH4 emissions to units of CO2 equivalent and sum to determine total

emissions.

STEP 1: IDENTIFY THE TYPE AND NUMBER OF EACH PNEUMATIC DEVICE EMPLOYED IN A GIVEN BASIN OR REGION.

If it is available, use a count that represents the actual inventory of all of the natural gas-driven pneumatic devices that are in operation at the all of the facilities throughout the region in question. This should provide an estimate of the number of devices by type.

STEP 2: IDENTIFY THE HOURS OF ANNUAL USAGE OF EACH DEVICE TYPE

Obtain an estimate of the number of hours each device is used over the course of the reporting year from service records, maintenance logs or other relevant records pertaining to equipment usage. If an actual inventory of the number of hours each device type is used is not available, a default usage rate of 8760 hours per year per device can be assumed, as many production systems and wells are operational and pressurized year round.

STEP 3: DETERMINE THE APPROPRIATE BLEED RATE FOR EACH DEVICE.

A direct measurement of the bleed rate of each device can be accomplished by installing gas flow meters upstream and downstream of each device. The difference between the upstream and downstream flow rate is equal to the bleed rate for that device. In some cases, an individual meter can be used when there is adequate space in the line. Bleed rates should be measured in standard cubic feet per day. Guidance on converting units can be found in Attachment 2 If it is not possible to directly measure the bleed rate for each device, many manufacturers can provide measured bleed rates for their devices. This information may be provided directly on the device, or you can obtain it directly from the manufacturer. Alternatively, Table 21.2and Table 21.3 provide default bleed rates for a variety of devices; Table 21.3 provides rates for general device types typically used in the production, processing, transmission and storage, and distribution segments of the natural gas industry, while Table 21.2 provides rates for a number of devices by manufacturer and model type. Table 21.2 - Default Bleed Rates for Various Pneumatic Device Types by Manufacturer and Model16

Device Type Emission Factor (scf/device/day)

16 http://www.wrapair.org/ClimateChange/GHGProtocol/meetings/090504m/


DRAFT


Device Type Emission Factor (scf/device/day)

Production

Snap Acting Bleed Level Controllers 30.00

Kimray T-12 Temperature Controllers 0.00

Fischer 4660 Hi-Lo Pilots 24.00

Fischer 4195 KB Intermittant 24.00

Fischer 4195 KB Continuous 102.00

Fischer 4160 K Pressure 0.00

Fischer 4102 ZR Pressure 600.00

Automation I/P 0.00

Trerice Temp Controller 0.00

Invalco Pilot Guard 0.00

Cemco Tank Level Continuous 840.00

Cemco Tank Level Snap 24.00

Norriseal Tank Level Intermittant 412.00

Norriseal Tank Level Snap 0.00

Mallard Tank Level 0.00

Well Mark - Level 840.00 Cemco Dump Snap 24.00

Cemco Dump Continuous 840.00

Engleman General Dump Snap 24.00

Engleman General Dump Continuous 840.00

Fischer Dump 840.00

Flextube Invalco CTC 4155 Dump Controller 360.00 Kimray Dump Snap 24.00

Kimray Dump Continuous 840.00

MacAfee Machine Dump 24.00

Murphy Matic Dump 0.00

Norriseal 2" Dump Controller 0.00

Table 21.3 - Default Bleed Rates for Various Pneumatic Device Types by Natural Gas Industry Segment

Device Type Emission Factor a,

Original Units17 Production

Continuous bleed a 654 scfd gas/device

Continuous bleed, low/no-bleed d 33.4 scfd gas/device

Continuous bleed, high-bleed d 896 scfd gas/device

Intermittent bleed a 323 scfd gas/device

Production averagea (if device type is unknown)

345 scfd CH4/device

17 Equation specifies bleed rate in scfd, but then multiplies by hours/year


DRAFT


Device Type Emission Factor a,

Original Units17 Transmitter (140 kPag) e 0.12 m3 gas/hr/device

Transmitter (240 kPag) e 0.2 m3 gas/hr/device

Controller (140 kPag) e 0.6 m3 gas/hr/device

Controller (240 kPag) e 0.8 m3 gas/hr/device

Controller (pressure not specified) f

0.1996 m3 gas/hr/device

I/P Transducer (140 kPag) e 0.6 m3 gas/hr/device

I/P Transducer (240 kPag) e 0.8 m3 gas/hr/device

P/P Positioner (140 kPag) e 0.32 m3 gas/hr/device

P/P Positioner (240 kPag) e 0.5 m3 gas/hr/device

I/P Positioner (140 kPag) e 0.4 m3 gas/hr/device

I/P Positioner (240 kPag) e 0.6 m3 gas/hr/device

Processing Continuous bleed 497,584 scf gas/device-yr

Piston valve operator 48 scf gas/device-yr

Pneumatic/hydraulic valve operator 5,627 scf gas/device-yr

Turbine valve operator 67,599 scf gas/device-yr

164,949 scf CH4/plant-yr Processing average (if device type is unknown)7.431 g scf CH4/MMscf processed

Transmission and Storage Continuous bleed 497,584 scf gas/device-yr

Pneumatic/hydraulic valve operator 5,627 scf gas/device-yr

Turbine valve operator 67,599 scf gas/device-yr

Transmission or Storage average (if device type is unknown)

162,197 scf CH4/device-yr

STEP 4: OBTAIN THE MOLAR FRACTIONS OF CH4 AND CO2 FOR THE NATURAL GAS USED IN EACH DEVICE.

You must determine the CH4 and CO2 content of the natural gas, as a molar fraction, that is used in the pneumatic devices. Fuel data should be collected and analyzed according to applicable industry-approved, national, or international technical standards regarding sampling frequency, procedures, and preparation. For additional resources on gas composition analysis methods, refer to:

ASTM D1945-03: Standard Test Method for Analysis of Natural Gas by Gas Chromatography;

ASTM D4984 - 06 Standard Test Method for Carbon Dioxide in Natural Gas Using Length-of-Stain Detector Tubes


DRAFT


If measured data on the CH4 content of the natural gas are not available, default methane content values for production, processing, transmission and storage, and distribution segments of the natural gas industry are provided in Table 21.4. Table 21.4 - Default Molar Fraction Values of CH4 Used in Pneumatic Devices18

Industry Segment Molar Fraction of CH4 Production 0.788 Processing 0.868 Transmission and Storage 0.934 Distribution 0.949

STEP 5: CALCULATE CH4 AND CO2 EMISSIONS FOR EACH DEVICE.

Using the values obtained in steps 1-4, above, calculate CH4 and CO2 emissions from all pneumatic devices using Equation 21-9.

STEP 6: CONVERT CH4 EMISSIONS TO UNITS OF CO2 EQUIVALENT.

To convert CH4 emissions to metric tons of CO2-equivalent, multiply the quantity of CH4 calculated in Step 5 by 21. Sum all values to come up with total emissions from pneumatic devices in metric tons CO2-equivalent. -------------------------------------------------------- PLACEHOLDER- EXAMPLE – Calculating Vented Emissions from Pneumatic Devices -------------------------------

21.4 Vented Emissions from Natural Gas-Driven Chemical Injection Pumps This section provides a method for calculating vented emissions from chemical injection pumps (CIPs) at oil and natural gas wells and facilities that utilize natural gas to act on a diaphragm or piston. These pumps are used to inject precise amounts of chemicals into process equipment lines. Typical chemicals injected into the process lines include anti-foam agents, methanol, biocides, demulsifiers, clarifiers, corrosion inhibitors, scale inhibitors, hydrate inhibitors, paraffin dewaxers, surfactants, oxygen scavengers, and hydrogen sulfide (H2S) scavengers. While CIPs can be pneumatic, electric or mechanical, this guidance applies only to those that utilize natural gas as a pressurized fluid; these tend to be more commonly employed where access to grid-supplied electricity is limited, but natural gas is plentiful, including wellheads and remote pipeline locations. CIPs are typically piston or diaphragm types, and operate across a range of pressures. As part of normal operation, natural gas-driven CIPs a small amount of natural gas is vented to the atmosphere during the actuation of the pump’s piston or diaphragm, and, consequently, can 18 Source: API. DRAFT 2008 Compendium of Greenhouse Gas Emissions Estimation Methodologies for the Oil and Gas Industry. Table 5-15. 2009.


DRAFT


be a significant source of CH4 emissions. If the natural gas used by the CIPs has a naturally occurring CO2 content, CO2 emissions can also be significant. Methods for calculating CH4 and CO2 emissions from natural gas-driven CIPs are provided below. Emissions from other gas-driven pneumatic devices are not included in this section, and are described in Section 21.3.

METHOD 01

METHOD FOR CALCULATING CH4 AND CO2 EMISSIONS FROM NATURAL GAS-DRIVEN CHEMICAL INJECTION PUMPS BASED ON EMISSION FACTORS

This method relies on estimates of the quantity of gas processed, utilization rates of the CIPs, and natural gas composition information in order to calculate CH4 and CO2 emissions using Equation 12-11 below.

Equation 21-10: CH4 and CO2 Emissions from Natural Gas-Driven Chemical Injection Pumps based on Emissions Factors

22003.379

0.1444 ,4 annualCHCH

iibleedCH tfMW

scf

molelbNE

where: E CH4/CO2 = the total CIP emissions of CH4/CO2 [tonne/yr] Ni = the number of CIPs of type i in the basin or region Q bleed = the emission rate of gas from CIP type i [scfd] MW CH4 = the molecular weight of methane (16 lb/lb-mole) f CH4/CO2 = is the molar fraction of CH4/CO2 in the gas t annual = the annual usage of the CIP (hr/yr)

This approach involves six steps:

1. Identify the type and number of each CIPs employed in a given basin or region; 2. Identify the hours of annual usage of each CIP; 3. Determine the appropriate emission rate for each device type; 4. Obtain the molar fractions of CH4 and CO2 for the natural gas used in each CIP; 5. Calculate CH4 and CO2 emissions for each CIP; and 6. Convert CH4 emissions to units of CO2 equivalent and sum to determine total

emissions.


DRAFT


STEP 1: IDENTIFY THE TYPE AND NUMBER OF EACH CIP EMPLOYED IN A GIVEN BASIN OR REGION.

If it is available, use a count that represents the actual inventory of all of the natural gas-driven CIPs that are in operation at the all of the facilities throughout the region in question. This should provide an estimate of the number of CIPs by type.

STEP 2: IDENTIFY THE HOURS OF ANNUAL USAGE OF EACH DEVICE TYPE

Obtain an estimate of the number of hours each CIP is used over the course of the reporting year from service records, maintenance logs or other relevant records pertaining to equipment usage. If an actual inventory of the number of hours each CIP type is used is not available, a default usage rate of 8760 hours per year per CIP can be assumed, as many production systems and wells are operational and pressurized year round.

STEP 3: DETERMINE THE APPROPRIATE EMISSION RATE FOR EACH DEVICE.

A direct measurement of the emission rate of each CIP can be accomplished by installing gas flow meters upstream and downstream of each pump. The difference between the upstream and downstream flow rate is equal to the emission rate for that pump. In some cases, an individual meter can be used when there is adequate space in the line. Emission rates should be measured in standard cubic feet per day. Guidance on converting units can be found in ATTACHMENT 2: CONVERSION TABLES If it is not possible to directly measure the emission rate for each CIPs, many manufacturers can provide measured emission rates for their pumps. This information may be provided directly on the device, or you can obtain it directly from the manufacturer. Alternatively, Table 21.5 provides default CH4 emission rates for a variety of CIPs; emission rates are provided by pump type, and operating pressure. If information about the pump is not known, a default, averaged rate is also provided. Table 21.5 - Default CH4 Emission Rates for Various CIPs by Type and Operating Pressure19

Pump Type / Operating Pressure Emission Factor

Piston

Piston pumps / 207 kPag 48.9 scfd

Piston pumps / 140 kPag 0.04 m3/hour

Piston pumps / 240 kPag 0.06 m3/hour

19 Source: API. DRAFT 2008 Compendium of Greenhouse Gas Emissions Estimation Methodologies for the Oil and Gas Industry. Table 5-16. 2009.


DRAFT


Pump Type / Operating Pressure Emission Factor

Diaphragm pumps / pressure unspecified 446 scfd Diaphragm pumps / 140 kPag 0.4 m3/hour Diaphragm pumps / 240 kPag 0.06 m3/hour

Average (if pump type unknown) 248 scfd

Do these values represent methane (as noted in the API Compendium) or natural gas? The emission factors are in gas volumes, implying that these are overall emission rates and not methane.

STEP 4: OBTAIN THE MOLAR FRACTIONS OF CH4 AND CO2 FOR THE NATURAL GAS USED IN EACH CIP.

You must determine the CH4 and CO2 content of the natural gas, as a molar fraction, that is used in the CIPs. Fuel data should be collected and analyzed according to applicable industry-approved, national, or international technical standards regarding sampling frequency, procedures, and preparation. For additional resources on gas composition analysis methods, refer to:



If measured data on the CH4 and CO2 of the natural gas are not available, a default methane molar fraction value of 0.788 can be used. Is there information available for default CO2 content values by region or by basin? Or is the variation too great?

STEP 5: CALCULATE CH4 AND CO2 EMISSIONS FOR EACH CIP AND SUM TO OBTAIN TOTAL EMISSIONS

Using the values obtained in steps 1-4, above, calculate CH4 and CO2 emissions from all pneumatic devices using Equation 21-10.


To convert CH4 emissions to metric tons of CO2-equivalent, multiply the quantity of CH4 calculated in Step 5 by 21. Sum all values to come up with total emissions from pneumatic devices in metric tons CO2-equivalent. ------------------------


DRAFT


PLACEHOLDER- EXAMPLE – Calculating Vented Emissions from Chemical Injection Pumps -----------------------

21.5 Wellhead and Facility Fugitive Losses This section provides methods for calculating fugitive emissions from equipment in oil and gas exploration and production facilities. Fugitive emissions result from leaks in equipment and components that carry pressurized gases, including, but not limited to wellheads, gathering pipelines, valves, flanges, seals, fittings, and open ended lines. CH4 from natural gas is the primary greenhouse gas associated with fugitive emissions in E&P facilities, but CO2 emissions can also be significant at sites where the natural gas has a naturally occurring CO2 content. When considering fugitive emissions from E&P facilities, it is necessary to distinguish between primary oil and gas production, as the distribution of components will vary between the two; oil production tends to utilize more heavy liquid components, while gas production typically utilize more gas/vapor and light liquid components. It is worth noting that for some larger central compressor stations and gas processing plants are required to estimate their fugitive emissions as a part of the permitting process for the facility. While these permits do not require estimates of methane emissions, the permits can provide information that is useful for estimating GHG emissions. This section addresses both fugitive emissions that would be identified under a permitting process, and those “unpermitted” fugitive emissions that occur at smaller facilities and components that are not subjected to a permitting process. Thus, an estimate of fugitive emissions should include both “permitted” and “unpermitted” sources. Fugitive emissions are typically calculated by applying an emission rate to site-specific equipment, activity and gas composition data. The availability of these data will vary from facility to facility, and will determine the level at which emissions are estimated. The methods in this section provide options for estimating fugitive emissions from E&P facilities on a facility-wide level, an equipment level, and a component level.

METHOD 01

COMPONENT LEVEL ESTIMATE OF FUGITIVE EMISSIONS FROM E&P FACILITIES

Equation 21-11 relies on estimates of the mass emissions rate of gas from all of the individual components in a facility, gas composition information and component usage data to calculate fugitive emissions from individual components in E&P facilities. These are then summed to calculate total emissions from a facility. The mass emission rate can be directly measured, correlated, or based on default values, as described in Step 3, below.

Equation 21-11: CO2 and CH4 Emissions from Exploration and Production Facilities Based on Component Level Emission Factors


DRAFT


Equation 21-11: CO2 and CH4 Emissions from Exploration and Production Facilities Based on Component Level Emission Factors

annualTOC

CH

jifugitivejiCH t

f

fE

4

4

..

where: E CH4/CO2 = the total fugitive emissions of CH4/CO2 from each facility [tonne/yr]

jfugitivei. = is the measured or estimated fugitive mass emissions rate of gas from

component i in service type j [tonne-TOC/hr]

4CHf = is the mass fraction of CH4/CO2 in the gas stream

TOCf = is the mass fraction of total organic carbon species in the gas stream

t annual = the annual usage of the component [hr/yr]

This approach involves five steps:

1. Identify the number and types of components employed throughout the facility; 2. Determine the composition of the natural gas stream; 3. Determine the appropriate mass emission rate of gas for each component; 4. Calculate CH4 and CO2 emissions for each component; and 5. Convert CH4 emissions to units of CO2 equivalent and sum to determine total emissions.

STEP 1: IDENTIFY THE NUMBER AND TYPES OF COMPONENTS EMPLOYED THROUGHOUT THE FACILITY.

If it is available, use a count that represents the actual inventory of all of the individual components that are in operation at the facility in question. This will include pumps, valves, pressure relief valves, flanges, agitators, and compressors, seals, sampling connections and open ended lines.

STEP 2: DETERMINE THE COMPOSITION OF THE NATURAL GAS STREAM

Determine the mass fractions of CH4, CO2, and total organic compound species (TOCs) for the natural gas stream that is passing through the components. For additional resources on gas composition analysis methods, refer to:

ASTM D 2650: Standard Test Method for Chemical Composition of Gases by Mass Spectrometry



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STEP 3: DETERMINE THE APPROPRIATE MASS EMISSION RATE OF GAS FOR EACH COMPONENT

Selecting mass emission rates for each component is determined by data availability. Members can select from three options when selecting mass emission rates for their facility’s components- directly measured “bagged” rates, source screened rates, and default rates. “Bagging” is a type of mass emissions sampling, and involves enclosing individual components in an impermeable bag, and measuring the vapors that are leaked into it. Bagged sample measurements can provide a direct estimate of the fugitive mass emissions rate of gas from the component sampled. Additional information on bag sampling methods and techniques can be found in Appendix C of EPA’s “Preferred and Alternative Methods for Estimating Fugitive Emissions from Equipment Leaks.”20 High volume samplers are another device type that can be used to establish a mass emissions rate for leaking components. High volume samplers pull a large volume of air and leaked gas into a hydrocarbon detector unit, which measures the concentration of hydrocarbons in both the ambient air and in the sampled air. A mass hydrocarbon emission rate can then be calculated by multiplying the flow rate of the measured sample by the difference in the hydrocarbon concentration in the sampled and ambient air. Source screened rates are calculated by measuring the concentration of leaking organic compounds from a component’s leak interface using a portable organic compound analyzer (screening device). This concentration level is then converted into a mass emission rate by use of a equipment-specific correlation equation. The following EPA documents provide guidance on performing screen measurements and correlating them into mass emission rates:

Preferred and Alternative Methods for Estimating Fugitive Emissions from Equipment Leaks,21 and;

1995 Protocol for Equipment Leak Emission Estimates.22

In the absence of the measured approaches described above, Members can use the default mass emission rates provided in Table 21.6, which are broken down by facility type. The averaged values therein reflect all of the gas types handled by different facility types, e.g. a heavy oil processing facility should always use values designated as “heavy oil”. Table 21.6 – Component Level TOC Emission Rates by Industry and Facility Type 23

20 USEPA. “Preferred and Alternative Methods for Estimating Fugitive Emissions from Equipment Leaks.” 1996. http://www.epa.gov/ttn/chief/eiip/techreport/volume02/ii04.pdf Accessed 6/9/09. 21 http://www.epa.gov/ttn/chief/eiip/techreport/volume02/ii04.pdf 22 http://www.epa.gov/ttnchie1/efdocs/equiplks.pdf


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Facility Type / Component Type Emission Factor

(tonne TOC / component-hr) Offshore Facilities

Valves 5.14E-07

Pump seals 1.95E-07

Others 6.94E-06

Connectors 1.08E-07

Flanges 1.97E-07

Open-ended lines 1.01E-06

Oil and Gas Production Facilities

Valves – gas production 2.63E-06

Valves – heavy crude production 1.30E-08

Valves – light crude production 1.32E-06

Connectors – gas production 3.21E-07

Connectors – heavy crude production 7.98E-09

Connectors – light crude production 1.64E-07

Flanges – gas production 1.18E-07

Flanges – heavy crude production 2.19E-08

Flanges – light crude production 7.69E-08

Open-ended lines – gas production 6.86E-07

Open-ended lines – heavy crude production 1.55E-07

Open-ended lines – light crude production 1.21E-06

Pump Seals – gas production 1.95E-07

Pump Seals – light crude production 3.18E-07

Others – gas production 9.19E-06

Others – heavy crude production 6.99E-08

Others – light crude production 7.50E-06

Gas Plants

Valves 3.86E-06

Pump seals 1.15E-05

Others 4.86E-06

Connectors 2.74E-07

Flanges 4.38E-07

Open-ended lines 1.03E-06

STEP 4: CALCULATE CH4 AND CO2 EMISSIONS FOR EACH COMPONENT.

Using the values obtained in steps 1-3, above, calculate total CH4 and CO2 emissions from all components using Equation 21-11.


23 Source: API. DRAFT 2008 Compendium of Greenhouse Gas Emissions Estimation Methodologies for the Oil and Gas Industry, Tabls 6-13 – 6-15. 2009.


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To convert CH4 emissions to metric tons of CO2-equivalent, multiply the quantity of CH4 calculated in Step 4 by 21. Sum all values to come up with total emissions from components in metric tons CO2-equivalent.

METHOD 02

EQUIPMENT LEVEL ESTIMATE OF FUGITIVE EMISSIONS FROM E&P FACILITIES

This method is similar to Method 01, above, but uses emission rates for large pieces of equipment rather than for their individual components. Equation 21-12 relies on emission factors for all of the equipment types in a facility, gas composition information and equipment usage data to calculate fugitive emissions from individual pieces of equipment in E&P facilities. These are then summed to calculate total emissions from a facility.

Equation 21-12: CO2 and CH4 Emissions from Exploration and Production Facilities Based on Equipment Level Emission Factors

ECH4/CO2 = ∑ ER CH4/CO2 i * t annual i

where: E CH4/CO2 = the total fugitive emissions of CH4/CO2 from each facility [tonne/yr] ER CH4/CO2 i = CH4/CO2 emission factor from equipment type i (tonnes/hr) t annual i = the annual usage of equipment type i (hr/yr)

This approach involves four steps:

1. Identify the number and types of equipment employed throughout the facility; 2. Determine the appropriate mass emission factor for each piece of equipment; 3. Calculate CH4 and CO2 emissions for each piece of equipment; and 4. Convert CH4 emissions to units of CO2 equivalent and sum to determine total emissions.

STEP 1: IDENTIFY THE NUMBER AND TYPES OF EQUIPMENT EMPLOYED THROUGHOUT THE FACILITY.

Use a count that represents the actual inventory of all of the pieces of equipment that are in operation at the facility in question. This will include wellheads, pump stations, separators, heater treaters, headers, tanks, and small compressors.

STEP 2: DETERMINE THE APPROPRIATE MASS EMISSION FACTOR FOR EACH PIECE OF EQUIPMENT


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Table 21.7 provides a list of CH4 emission factors for a variety of equipment types by E&P facility type. Table 21.7 – Equipment Level CH4 Emission Rates by Industry and Facility Type24

Facility Type / Equipment Type Assumed CH4

Content (molar %)

Emission Factor

Units

Onshore Crude Production Facilities

Oil wellheads – heavy crude 78.8 6.63E-07 tonne/well-hr

Oil wellheads – light crude 78.8 1.56E-05 tonne/well-hr

Oil pump stations d 78.8 5.49E-08 tonne CH4/mile-hr

Separators – heavy crude 78.8 6.79E-07 tonne/separator-hr

Separators – light crude 78.8 4.10E-05 tonne/separator-hr

Heater treaters – light crude 78.8 4.77E-05 tonne/heater-hr

Headers – heavy crude 78.8 4.72E-07 tonne/header-hr

Headers – light crude 78.8 1.62E-04 tonne/header-hr

Tanks – light crude 78.8 2.75E-05 tonne/tank-hr

Small compressors – light crude 78.8 3.69E-05 tonne/compressor-hr

Large compressors e – light crude 78.8 1.31E-02 tonne/compressor-hr

Sales areas 78.8 3.24E-05 tonne/area-hr

Onshore Natural Gas Production Facilities

Gas wellheads 78.8 1.80E-05 tonne CH4/well-hr

Separators 78.8 4.42E-05 tonne CH4/separator-hr

Gas heaters 78.8 4.60E-05 tonne CH4/heater-hr

Small reciprocating gas compressor 78.8 2.12E-04 tonne CH4/compressor-hr

Large reciprocating gas compressor 78.8 1.22E-02 tonne CH4/compressor-hr

Large reciprocating gas compressor stations 78.8 6.59E-03 tonne CH4/station-hr

Meters/piping 78.8 3.52E-05 tonne CH4/meter-hr

Dehydrators 78.8 7.13E-05 tonne CH4/dehydrator-hr

Gathering pipelines 78.8 4.28E-05 tonne CH4/mile-hr

CO2 from oxidation 78.8 4.38E-06 tonne CO2/mile-hr

CO2 from pipeline leaks 78.8 5.84E-06 tonne CO2/mile-hr

Gas Processing Facilities

Gas processing volume 86.8 2.50E-03 tonne/MMscf processed

Reciprocating compressors 86.8 8.95E-03 tonne/compressor-hr

Centrifugal compressors 86.8 1.70E-02 tonne/compressor-hr

If you have site-specific information on the methane content of the natural gas being processed, you can adjust the emission factors provided in Table 21.7 to reflect your own natural gas composition. This is done by multiplying the emission factors from Table 21.7 by the ratio of methane content of your own gas to the default methane content values also provided in Table 21.7, as shown in Equation 21-13. Natural gas composition data should be collected and 24 Source: API. DRAFT 2008 Compendium of Greenhouse Gas Emissions Estimation Methodologies for the Oil and Gas Industry, Tables 6-3 – 6-5. 2009.


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analyzed according to applicable industry-approved, national, or international technical standards regarding sampling frequency, procedures, and preparation. For additional resources on gas composition analysis methods, refer to:

ASTM D 2650: Standard Test Method for Chemical Composition of Gases by Mass

Spectrometry ASTM D1945-03: Standard Test Method for Analysis of Natural Gas by Gas

Chromatography; ASTM D4984 - 06 Standard Test Method for Carbon Dioxide in Natural Gas Using

Length-of-Stain Detector Tubes

Equation 21-13: Correcting Default CH4 Emission Factors to Reflect Site-Specific CH4 Content

EFCH4site = (EF CH4 GD default ) * (CH4 site / CH4 default )

where: EF CH4 site = Updated CH4 emission factor, adjusted for site-specific CH4 content of

natural gas [tonnes/activity unit] EF CH4GD default = Industry-specific CH4 emission factor provided in Table 21.7

[tonnes/activity unit] CH4 site = Site-specific CH4 content provided by Member [molar %] CH4 default = Segment-specific CH4 content provided in Table 21.7 [molar %]

Generally, CO2 emission factors are less commonly available than CH4 emission factors. An equivalent CO2 emission factor can, however, be calculated from a CH4 emission factor based on the relative concentrations of CO2 and CH4 in the natural gas stream in question. This conversion is shown in Equation 21-14, below.

Equation 21-14: CH4 to CO2 Emission Factor Conversion

EFCO2 = EF CH4 * (44/16) * (mol % C02 / mol % CH4 )

where: EF CO2 = CO2 emission factor EF CH4 = CH4 emission factor 44 = Molecular weight of CO2 (g/mole) 16 = Molecular weight of CH4 (g/mole) mol % C02 = Concentration of CO2 in the natural gas stream [molar %] mol % CH4 = Concentration of CH4 in the natural gas stream [molar %]


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STEP 3: CALCULATE CH4 AND CO2 EMISSIONS FOR EACH PIECE OF EQUIPMENT

Using the values obtained in steps 1-2, above, calculate total CH4 and CO2 emissions from all pieces of equipment using Equation 21-14.


To convert CH4 emissions to metric tons of CO2-equivalent, multiply the quantity of CH4 calculated in Step 3 by 21. Sum all values to come up with total emissions from facilities in metric tons CO2-equivalent.

METHOD 03

FACILITY LEVEL ESTIMATE OF FUGITIVE EMISSIONS FROM E&P FACILITIES

This method is similar to Method 02, above, but uses emission rates for entire facilities rather than for their individual components or pieces of equipment. Equation 21-15 relies on emission factors for the facility type, gas composition information and production data to calculate fugitive emissions from E&P facilities.

Equation 21-15: CO2 and CH4 Emissions from Exploration and Production Facilities Based on Facility Level Emission Factors

ECH4/CO2 = ER CH4/CO2 i * t annual i

where: E CH4/CO2 = the total fugitive emissions of CH4/CO2 from each facility [tonne/yr] ER CH4/CO2 i = CH4/CO2 emission factor from facility type i (tonnes/bbl produced) t annual i = Facility production data (bbl/yr)

This approach involves three steps:

1. Determine the appropriate mass emission factor for each facility type; 2. Calculate CH4 and CO2 emissions for each facility; and 3. Convert CH4 emissions to units of CO2 equivalent and sum to determine total emissions.

STEP 1: DETERMINE THE APPROPRIATE MASS EMISSION FACTOR FOR EACH FACILITY TYPE

Table 21.8 provides a list of CH4 emission factors for different E&P facility types.


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Table 21.8 – Equipment Level CH4 Emission Rates by Facility Type25

Facility Type Assumed CH4

Content (molar %)

Emission Factor (tones CH4 / bbl

produced)

Onshore Oil Production 78.8 2.346E-04 Offshore Oil Production 78.8 9.386E-05 Onshore Gas Production 78.8 2.601E-02 Offshore Gas Production 78.8 1.040E-02 Gas Processing 86.8 2.922E-02

If you have site-specific information on the methane content of the natural gas being processed, you can adjust the emission factors provided in Table 21.8 to reflect your own natural gas composition. This is done by multiplying the emission factors from Table 21.8 by the ratio of methane content of your own gas to the default methane content values also provided in Table 21.8, as shown in Equation 21-16. Natural gas composition data should be collected and analyzed according to applicable industry-approved, national, or international technical standards regarding sampling frequency, procedures, and preparation. For additional resources on gas composition analysis methods, refer to:

ASTM D 2650: Standard Test Method for Chemical Composition of Gases by Mass

Spectrometry ASTM D1945-03: Standard Test Method for Analysis of Natural Gas by Gas

Chromatography; ASTM D4984 - 06 Standard Test Method for Carbon Dioxide in Natural Gas Using

Length-of-Stain Detector Tubes

Equation 21-16: Correcting Default CH4 Emission Factors to Reflect Site-Specific CH4 Content





Generally, CO2 emission factors are less commonly available than CH4 emission factors. An equivalent CO2 emission factor can, however, be calculated from a CH4 emission factor based 25 Source: API. DRAFT 2008 Compendium of Greenhouse Gas Emissions Estimation Methodologies for the Oil and Gas Industry, Tables 6-3 – 6-5. 2009.


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on the relative concentrations of CO2 and CH4 in the natural gas stream in question. This conversion is shown in Equation 22-7, below.




STEP 2: CALCULATE CH4 AND CO2 EMISSIONS FOR EACH FACILITY

Using the emission factor obtained in step 1, above, calculate total CH4 and CO2 emissions from each facility using Equation 21-17.

STEP3: CONVERT CH4 EMISSIONS TO UNITS OF CO2 EQUIVALENT.


21.6 Surface Collection Ponds Water disposal pits are used to store and dispose of produced water, or fluids from drilling and completion operations. The water in these pits may contain small amounts of hydrocarbons that may volatilize into the atmosphere if no other control measures are taken. These pits have GHG emissions of CH4 but can also have emissions of CO2 if it is present in the water. Varying amounts of the produced water is not re-injected, however, and any gases remaining dissolved in it, including CO2 and CH4, can be expected to evaporate into the atmosphere.

METHOD 01

MASS FRACTION CALCULATION


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Members may use Equation 21-18 to calculate the quantities of CO2 and CH4 that are released from produced water that is left to evaporate in disposal pits. It should be noted that all of the gas dissolved in this water is assumed to be released into the atmosphere.

Equation 21-18: Gas Emitted from Non Re-injected Produced Waters26

E CO2/CH4 = f CO2/CH4 * Q water

Where E CO2/CH4 = Emissions of CO2/CH4 from the non re-injected water (tonnes) f CH4/CO2 = mass fraction of CH4/CO2 in the water (%) Q water = mass of non-reinjected water (tonnes)

It should be noted that all of the gas dissolved in this water is assumed to be released into the atmosphere. For additional guidance on measuring the CO2 content of the water, refer to:

ASTM D513 - 06 Standard Test Methods for Total and Dissolved Carbon Dioxide in Water

21.7 Transportation Sector - Gas Compressor Station

26 “Greenhouse Gas Emission Reduction Protocol for the Salt Creek Enhanced Oil Recovery (EOR) Project”. Howell Petroleum Corporation. August, 2004


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Chapter 22: Vented Emissions

22.1 Amine Plant Process Venting This section provides a method for calculating CH4 and CO2 emissions from amine units. In addition to water, oil, and NGL removal, one of the most important parts of gas processing involves the removal of so-called “acid gases” from natural gas streams is one of the most important parts of gas processing. Amine units are often employed to remove the acid gases hydrogen sulfide and carbon dioxide through the “amine process”, in which a stream of natural gas is passed through an amine solution, which absorbs the gases. The amine solution is then directed to an amine regenerator, where a reboiler supplies the necessary heat to strip H2S and CO2 from the rich amine. Elemental sulfur is often recovered in a separate sulfur recovery unit. This section addresses CH4 emissions from uncontrolled amine unit vents, and CO2 from amine unit and sulfur recovery vents. Combustion emissions from reboiler units and emissions associated with flared or captured and utilized vented emissions are addressed in Chapter 12 Direct Emissions from Stationary Combustion. CO2 emissions that are captured and utilized in enhanced oil recovery operations are discussed in Section 22.2 Dehydrators

METHOD 01

CALCULATING CH4 AND CO2 EMISSIONS FROM AMINE UNITS BASED ON TESTS OF AMINE UNIT VENT EMISSIONS

This method relies on a direct measurement of the CH4 and CO2 content of the gas stream released from the amine unit vent. Amine unit vent emissions should be analyzed for CH4 and CO2 content, measured in scfd. Emissions should be collected and analyzed according to applicable industry-approved, national, or international technical standards regarding sampling frequency, procedures, and preparation. For additional resources on measuring the emissions from amine units, refer to:

ASTM D 2650 – Standard Test Method for Chemical Composition of Gases by Mass Spectrometry

CH4 and CO2 emissions from each measured amine unit can then be calculated using Equation 22-1 below.

Equation 22-1: CO2 and CH4 Emissions from Amine Units Based on Tests of Amine Unit Vent Emissions

ECH4/CO2 = ER CH4/CO2 * t annual

where:


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Equation 22-1: CO2 and CH4 Emissions from Amine Units Based on Tests of Amine Unit Vent Emissions

E CH4/CO2 = the total venting emissions of CH4/CO2 from each amine unit [tonne/yr] ER CH4/CO2 = measured CH4/CO2 emission rate from each amine unit (scfd) t annual = the annual usage of each amine unit (day/yr)

To convert CH4 emissions to metric tons of CO2-equivalent, multiply the quantity of CH4 calculated by 21. Sum all values to come up with total emissions from all amine units in metric tons CO2-equivalent.

METHOD 02

METHOD FOR CALCULATING CH4 EMISSIONS FROM AMINE UNITS USING API’S AMINECALC SOFTWARE

If measured test data from amine units are not available, Members can use a software program, such as API’s AMINECalc Software to calculate organic compound emissions from amine units. AMINECalc is a software tool designed to estimate hydrocarbon emissions from amine and other natural gas sweetening units. Data required to run the software includes information on ??? More information on using the AMINECalc model can be found on API’s website27. QUESTION FOR THE WORKING GROUP: IS THERE ANYONE AT API WE CAN GET MORE INFORMATION ABOUT THIS PROGRAM FROM? THERE IS VERY LITTLE INFO ON THEIR WEBPAGE. An estimate of VOC mass emission rate is one of AMINECalc’s outputs. Provided knowledge of the CH4 content of the natural gas being processed, this can be converted to a mass emission rate for CH4. This is done by ??? If you do not have access to the CH4 content of the input gas, you can assume a default molar fraction value of 0.86828. QUESTION FOR THE WORKING GROUP: IN KEEPING WITH THE PREVIOUS QUESTION, DOES AMINECALC A) REQUIRE AN INPUT GAS CH4 COMPOSITION VALUE AS AN INPUT, AND B) DOES IT PROVIDE A CH4 MASS EMISSION RATE?

METHOD 03

27 www.api.org. AMINECalc software and documentation can be found by searching for publication number 4679. 28 Source: API. DRAFT 2008 Compendium of Greenhouse Gas Emissions Estimation Methodologies for the Oil and Gas Industry. Table 5-15. 2009.


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METHOD FOR CALCULATING CH4 EMISSIONS FROM AMINE UNITS USING GENERAL EMISSION FACTORS

If the data required to use the methods provided above are unavailable, Members can use a general emission factor of 0.0185 tonnes CH4 /106 scf treated gas produced, as shown in Equation 22-2. This factor is based on an uncontrolled, diethanol amine unit, and does not include any emissions of CO2

29.

Equation 22-2: CO2 and CH4 Emissions from Amine Units Using API’s AMINECalc Software

ECH4 = ER CH4 * Gas annual where: E CH4 = the total venting emissions of CH4 from each amine unit [tonne/yr] ER CH4 = default CH4 emission rate from each amine unit (0.0185 tonnes CH4/ 106

treated gas produced annually) Gas annual = quantity of treated gas produced annually (106 scf)

METHOD 04

METHOD FOR CALCULATING CO2 EMISSIONS FROM AMINE UNITS USING A MATERIAL BALANCE APPROACH

CO2 emissions from amine and sulfur recovery units that vent their emissions directly to the atmosphere can be measured through a material balance method that measures the concentration of CO2 in both the inlet stream into the unit, and the outlet gas stream coming out of it. This approach is outlined in Equation 22-3, below. For additional resources on measuring the CO2 content of the inlet and outlet streams, refer to:

ASTM D 2650 – Standard Test Method for Chemical Composition of Gases by Mass Spectrometry

29 Source: API. DRAFT 2008 Compendium of Greenhouse Gas Emissions Estimation Methodologies for the Oil and Gas Industry. Table 5-5. 2009


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Equation 22-3: CO2 Emissions from Amine Units Using Mass Balance

ECO2 = [(V inlet * CCO2 inlet ) - (V outlet * CCO2 outlet)] * (44/23.685m3/kgmole) * 1/2000

where: E CO2 = the total venting emissions of CO2 from each amine unit [tonne/yr] Vinlet = volume of untreated inlet gas (m3) Voutlet = volume of treated outlet gas (m3) C CO2 inlet = CO2 concentration of untreated inlet gas (molar %) C CO2 outlet = CO2 concentration of treated outlet gas (molar %) 44 = molecular weight of CO2

23.685 = molecular weight of CO2

22.2 Dehydrators This section provides methods for calculating vented emissions from liquid desiccant dehydrators, primarily glycol dehydrators, in use at wellheads and at central gas processing facilities. Dehydrators are used to remove the water contained in produced natural gas, which can condense and/or freeze in gathering, transmission and distribution piping causing plugging, pressure surges and corrosion. This is done by passing the natural gas through a dewatering agent such as triethylene glycol (TEG), diethylene glycol (DEG) or propylene carbonate. The glycol stream is then passed through a glycol reboiler/regenerator, where water and hydrocarbons are boiled off. Some systems also utilize a stripping gas in the regenerator to facilitate removal of water and methane from the glycol stream. Some systems also use flash separators to vaporize light hydrocarbons from the glycol stream. Factors that affect emission rates include the gas flow rate, the inlet and outlet water content, glycol-to-water ratios, the percent over circulation and the methane entrainment rate. In uncontrolled systems, CH4 that is stripped from the glycol stream, contained in the stripping gas (if used) and vented from natural gas driven glycol pumps (if used) are all vented to the atmosphere from the glycol regenerator. In some systems, these emissions are flared, or directed to an alternative controlled combustion device and utilized. Similarly, emissions from flash separators may also either be vented to the atmosphere or collected for use or flaring. Considerations for accounting for stripping gases, natural gas driven glycol pumps and gas capture are discussed as appropriate to each method below. At sites where the natural gas has a naturally occurring CO2 content, CO2 emissions from these sources might also be significant. Combustion emissions from the glycol regenerators and emissions associated with flared or


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captured and utilized vented emissions are addressed in Chapter 12 Direct Emissions from Stationary Combustion.

METHOD 01

METHOD FOR CALCULATING CH4 AND CO2 EMISSIONS FROM GLYCOL DEHYDRATORS BASED ON TESTS OF DEHYDRATOR VENT EMISSIONS

This method relies on a direct measurement of the CH4 and CO2 content of the gas stream released from the glycol dehydrator vent. Amine unit vent emissions should be analyzed for CH4 and CO2 content, measured in scfd. Emissions should be collected and analyzed according to applicable industry-approved, national, or international technical standards regarding sampling frequency, procedures, and preparation. For additional resources on measuring the emissions from glycol dehydrators, refer to:


CH4 and CO2 emissions from each measured glycol dehydrator can then be calculated using Equation 22-4, below.

Equation 22-4: CO2 and CH4 Emissions from Glycol Dehydrators Based on Tests of Dehydrator Vent Emissions

ECH4/CO2 = ER CH4/CO2 * t annual

where: E CH4/CO2 = the total venting emissions of CH4/CO2 from each glycol dehydrator

[tonne/yr] ER CH4/CO2 = measured CH4/CO2 emission rate from each glycol dehydrator (scfd) t annual = the annual usage of each glycol dehydrator (day/yr)

To convert CH4 emissions to metric tons of CO2-equivalent, multiply the quantity of CH4 calculated by 21. Sum all values to come up with total emissions from glycol dehydrators in metric tons CO2-equivalent.

METHOD 02

METHOD FOR CALCULATING CH4 AND CO2 EMISSIONS FROM GLYCOL DEHYDRATORS USING GTI’S GRI-GLYCALC SOFTWARE

If measured test data from each dehydrator are not available, Members can use a software program, such as GTI’s GRI-GLYCalc Software to calculate emissions of CH4, CO2 and other organic compounds. GRI-GLYCalc requires detailed information about each dehydrator for


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which emissions are calculated, including gas composition and flow rate, wet gas temperature, pressure, and water content, glycol circulation rate, temperature and pressure in the absorber column, the type of glycol pump used, the operating pressure of the flash tank (if used), the amount of flash gas used by the process (if used), the type of glycol (TEG or DEG) used, and stripping gas usage (if used). More information on using the GRI-GLYCalc model can be found on GTI’s website30. QUESTION FOR THE WORKING GROUP- DOES ANYONE HAVE ANY ADDITIONAL INFORMATION ABOUT THE LOGIC/OPERATING PARAMETERS BEHIND THE GRI-GLYCALC MODEL THAT WE CAN INCLUDE HERE?

METHOD 03

METHOD FOR CALCULATING CH4 AND CO2 EMISSIONS FROM GLYCOL DEHYDRATORS USING INDUSTRY SEGMENT SPECIFIC EMISSION FACTORS

Equation 22-5 relies on emission factors for dehydrators, total natural gas processing estimates, CH4 and CO2 content estimates, and dehydrator counts to calculate CH4 and CO2 emissions from glycol dehydrators in the production, processing, transmission and storage segments of the natural gas industry. Some dehydrator systems will include a flash tank separator and/or a natural gas-driven glycol pump. If either of these items are present, the emission factor for the dehydrator must be adjusted accordingly. These adjustments are outlined in Step 3, below.

Equation 22-5: CO2 and CH4 Emissions from Glycol Dehydrators Based on Industry Segment Specific Emissions Factors

E CH4/CO2 = Ni * Q vent i * (1.0 lb – mole / 379.3 scf) * MW CH4/CO2 * f CH4/CO2 * t annual i

/2200 where: E CH4/CO2 = the total glycol dehydrator venting emissions of CH4/CO2 from each industry

segment [tonne/yr] Ni = the number of dehydrators for production segment i in the basin or region Q vent i = the emission rate of gas from dehydrator type i [tonnes / 106 scf gas processed] MW CH4/CO2 = the molecular weight of CH4 (16 lb/lb-mole) / /CO2 (44 lb/lb-mole) f CH4/CO2= is the molar fraction of CH4/CO2 in the gas t annual = quantity of natural gas processed annually (106 scf / yr) This approach involves five steps:

30 http://www.gastechnology.org/webroot/app/xn/xd.aspx?it=enweb&xd=10abstractpage\12352.xml


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6. Identify the number of dehydrators employed; 7. Identify the total quantity of natural gas processed; 8. Determine the appropriate emission rate for each dehydrator; 9. Calculate CH4 and CO2 emissions for each dehydrator; and 10. Convert CH4 emissions to units of CO2 equivalent and sum to determine total

emissions.

STEP 1: IDENTIFY THE NUMBER OF DEHYDRATORS EMPLOYED.

If it is available, use a count that represents the actual inventory of all of the glycol dehydrators that are in operation at the all of the facilities throughout the region in question. This should provide an estimate of the number of dehydrators by industry segment.

STEP 2: IDENTIFY THE TOTAL QUANTITY OF NATURAL GAS PROCESSED

Obtain an estimate for the total quantity of natural gas that is processed in each industry segment, in 106 scf/year. For assistance in converting units, refer to ATTACHMENT 2: CONVERSION TABLES

STEP 3: DETERMINE THE APPROPRIATE EMISSION RATE FOR EACH DEHYDRATOR

Calculating emission rates for dehydrators is a one to three step process, depending on the type of dehydrator in question, and on data availability. For each dehydrator type, you must a) select an emission factor from the appropriate industry segment, correct the emissions factor by adding an emissions factor for a natural-gas driven glycol pump, if present, and c) correct the resulting emissions factor to reflect the composition of the natural gas being processed, if data availability allows. This is illustrated in Equation 22-6, at the bottom of this step. Table 22.1 provides a list of emission factors for a variety of dehydrators by industry segment, and does not include emissions from natural gas-driven glycol pumps. For each segment, the assumed methane content used to generate the segment-specific emission factor is provided. Table 22.1 - CH4 Emission Rates for Glycol Dehydrators by Natural Gas Industry Segment31

Industry Segment CH4 Emission Factor (tonnes / 106 scf gas processed annually)

CH4 Content Basis for Industry Segment

(molar %) Production 0.0052589 78.8

Processing 0.0023315 86.8

Transmission 0.001798 93.4

Storage 0.0022477 93.4

31 Source: API. DRAFT 2008 Compendium of Greenhouse Gas Emissions Estimation Methodologies for the Oil and Gas Industry, Table 5-2. 2009.


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For dehydrators that use natural gas-driven glycol circulator pumps, you must adjust the emissions rates from Table 22.1, above, to reflect the additional CH4 emissions from the pump. If you know the emissions rate of your specific glycol pump, use that. If you do not have information about the specific pumps you are using, Table 22.2 provides emission factors for glycol pumps in dehydrators in the production and processing segments based on pumps produced by Kimray, Inc, a leading manufacturer of glycol pumps. Table 22.2 - CH4 Emission Rates for Natural Gas-Driven Glycol Pumps by Natural Gas Industry Segment32

Industry Segment CH4 Emission Factor (tonnes / 106 scf gas processed annually)

CH4 Content Basis for Industry Segment

(molar %) Production 0.01903 78.8

Processing 0.0034096 86.8

If a flash tank is in use, you must also adjust the emission rate to account for that. All emissions that are vented to the atmosphere from the flash tank must be added to the emission rates provided in Table 22.2. To calculate emissions from flash tanks on a comparable basis, divide the total quantity of methane emitted from the flash tank by the total quantity of natural gas processed on an annual basis to convert to a tonnes CH4 / 106 scf processed annually basis. If the emissions from the flash tank are collected and flared or rerouted for use as a fuel in the glycol regenerator boiler or elsewhere, they must be accounted for separately using the methods provided in Chapter 12. These emissions will not count towards total emissions from glycol dehydrators. If you have site-specific information on the methane content of the natural gas being processed, you can adjust the emission factors provided in Table 22.1 and Table 22.2 to reflect your own natural gas composition. This is done by multiplying the emission factors from Table 22.1 and Table 22.2 by the ratio of methane content of your own gas to the default methane content values also provided in Table 22.1 and Table 22.2, as shown in Equation 22-6. Natural gas composition data should be collected and analyzed according to applicable industry-approved, national, or international technical standards regarding sampling frequency, procedures, and preparation. For additional resources on gas composition analysis methods, refer to:



32 Source: API. DRAFT 2008 Compendium of Greenhouse Gas Emissions Estimation Methodologies for the Oil and Gas Industry, Table 5-4. 2009.


DRAFT


Equation 22-6: Correcting Default Dehydrator CH4 Emission Factors to Account for Glycol Pumps, Flash Tank Separators, and Site-Specific CH4 Content Values

EFCH4site = (EF CH4 GD default + EF CH4 GP + EF CH4 FS ) * (CH4 site / CH4 default )

where: EF CH4 site = Updated CH4 emission factor for dehydrators, adjusted for site-specific

CH4 content of natural gas [tonnes/scf processed] EF CH4GD default = Segment-specific glycol dehydrator CH4 emission factor provided in

Table 22.2 [tonnes/scf processed] EF CH4GP = Natural gas-driven glycol pump CH4 emission factor, either site-specific,

or provided in Table 22.2 (if used) [tonnes/scf processed] EF CH4FS = Flash Tank Separator CH4 emission factor (if used) [tonnes/scf

processed] CH4 site = Site-specific CH4 content provided by Member [molar %] CH4 default = Segment-specific CH4 content provided in Table 22.2 [molar %]





STEP 4: CALCULATE CH4 EMISSIONS FOR EACH DEVICE AND SUM TO OBTAIN TOTAL CH4 EMISSIONS


DRAFT


Using the values obtained in steps 1-3, above, calculate total CH4 and CO2 emissions from all dehydrators using Equation 22-7.


To convert CH4 emissions to metric tons of CO2-equivalent, multiply the quantity of CH4 calculated in Step 4 by 21. Sum all values to come up with total emissions from dehydrators in metric tons CO2-equivalent.

METHOD 04

METHOD FOR CALCULATING CH4 EMISSIONS FROM GLYCOL DEHYDRATORS USING GENERAL EMISSION FACTORS

If the data required to use the methods provided above are unavailable, Members can use the general emission factors provided in Table 22.3 to estimate CH4 emissions from glycol dehydrators. These generalized emission factors were calculated using GTI”s GRI-GLYCalc software described above, and include emissions from natural gas-driven glycol pumps, and account for the presence or absence of a flash tank separator that collects and utilizes vented emissions. CH4 emissions from each dehydrator can be calculated using Equation 22-8.

Equation 22-8: CH4 Emissions from Glycol Dehydrators Using General Emissions Factors

ECH4 = ER CH4 * t annual

where: E CH4 = the total venting emissions of CH4 from each glycol dehydrator [tonne/yr] ER CH4 = measured CH4 emission rate from each glycol dehydrator (scfd) t annual = the annual usage of each glycol dehydrator (day/yr)

Table 22.3 - Generalized CH4 Emission Rates for Glycol Dehydrators by Dehydrator Mode of Operation33

Mode of Operation CH4 Emission Factor

(tonnes / 106 scf gas processed annually) Gas pump without a flash separator 0.006410

Gas pump with a flash separator 0.000154

Electric pump without a flash separator 0.001665

Electric pump with a flash separator 0.000127

CH4 emissions must be calculated for all dehydrators in use, and summed to calculate total CH4 emissions. 33 Source: API. DRAFT 2008 Compendium of Greenhouse Gas Emissions Estimation Methodologies for the Oil and Gas Industry, Table 5-3. 2009.


DRAFT


------------------------------------------------------------------------------------------------------------------ PLACEHOLDER- EXAMPLE – Calculating Vented Emissions from Glycol Dehydrators -----------

22.3 Well Completions, Underbalanced Drilling, and Drilling Mud Degassing Well completion refers to the process of finishing a well so that it is ready to produce oil or natural gas. This process includes strengthening the well hole with casing, evaluating the pressure and temperature of the formation, and then installing the proper equipment to ensure an efficient flow of natural gas out of the well. This methodology can also be applied to calculate vented emissions from underbalanced drilling operations. Part of a well drilling operation is to keep the drilling mud free of entrained gas that enters the mud as it circulates downhole. This gas can reduce the drilling mud density causing the pressure in the well hole to drop and allowing the oil and/or gas to flow from the reservoir to the surface before the well completion is finished. Drilling mud degassing units extract the entrained gas from the mud at the surface. During this process CH4 emissions are vented to the atmosphere. This section addresses methodologies to calculate GHG emissions from well completion, underbalanced drilling and drilling mud degassing activities.

METHOD 01

WELL COMPLETION AND UNDERBALANCED DRILLING EMISSIONS ESTIMATION METHODOLOGY

CO2 and CH4 emissions from well completion are calculated using the volume of gas vented and the methane fraction of the gas using Equation 22-9


DRAFT


Equation 22-9: Well Completion (Underbalanced Drilling) Emissions Estimation

Ei = Q x (lbmole/379.3scf) x MWi x fi/ 2200

where, Ei = emissions of the GHG (either CO2 or CH4) from the completion (or drilling) of a single well, in tonne/well Q = total volume of gas vented during a well completion (or drilling), in scf/well

MWi = molecular weight of GHG, in lb/lbmole f i = molar fraction of the GHG 2200 = conversion factor from lbs to tonnes

This methodology relies on an estimated volume of gas vented during the completion or underbalanced drilling operation. This volume is determined using engineering estimates based factors such as the dimensions of the well bore and downhole pressure and the duration of the completion venting. This protocol recommends Members to keep proper records of their completions and drilling activities. -------------------------------------------------------- PLACEHOLDER- EXAMPLE – Calculating Vented Emissions from Well Completion Operations -------------------------------

METHOD 02

DRILLING MUD DEGASSING EMISSIONS ESTIMATION METHODOLOGY

CH4 emissions from mud drilling degassing operations are calculated using the emission factors presented in the table below and Equation 22-10. Table 22.4 - Mud Degassing Emission Factors Emission Source Emission Factor Units34 Mud degassing – water-based mud 881.84 lbs THC / drilling day Mud degassing – oil-based mud 198.41 lbs THC / drilling day Mud degassing – synthetic mud 198.41 lbs THC / drilling day Note: Assume synthetic mud has similar emission characteristics to oil-based mud. Apply the appropriate mass or volume percentage methane to the mud degassing emission factors. The factors emission factors presented in Table 22.4 estimate THC emissions and should be converted to CH4 emissions using the gas composition. 34 “Atmospheric Emissions from Offshore Oil and Gas Development and Production,” EPA, 1977.


DRAFT


Equation 22-10: Well Completion Emissions Estimation

E(CH4) = VM x EFi

where, E(CH4) = emissions of CH4, in units of mass per day VM = total volume of mud, in units of mass per day

EFi = emission factor of the source, in units of mass per day -------------------------------------------------------- PLACEHOLDER- EXAMPLE – Calculating Vented Emissions from Drill Mud Degassing -------------------------------

22.4 Well Blowdowns A well blowdown is performed to clean or unload a gas well in order to remove liquid buildup that reduces production rates. During a well blowdown, the well is opened to atmosphere so the downhole pressures may blow water from the tubing to an atmospheric storage tank. This process is used in shallow, low-pressure gas wells where downhole pressure may not be sufficient to overcome a liquid buildup. The volume of gas released during a well blowdown depends on the duration of the event, wellhead temperature and pressure, size of the vent line, the properties of the gas and the quantity of water produced.

METHOD 01

WELL BLOWDOWNS EMISSIONS ESTIMATION METHODOLOGY

To estimate CH4 and CO2 emissions from well blowdowns, Members should use the molar fraction of the gas and volume of the gas vented. Equation 21-10 presents the calculation method.


DRAFT


Equation 22-11: Emissions from Well Blowdowns

Ei = Q x (lbmole/379.3scf) x MWi x fi/ 2200

where, Ei = emissions of GHG (either CO2 or CH4) from a single blowdown event, in tonne/blowdown Q = total volume of gas vented during a well blowdown event, in scf/blowdown

MWi = molecular weight of GHG, in lb/lbmole f i = molar fraction of GHG 2200 = conversion factor from lbs to tonnes

If the vented gas volume is unknown, Equation 22-12 presents an alternative to estimate this volume.

Equation 22-12: Alternative to Estimating Vented Gas Volume

Q = 0.37 x 10-6x Cd x Wd x Pshut-in

where, Q = total volume of gas vented during a well blowdown event, in units of mass per blowdown

Cd = casing diameter, in inches Wd = well depth, in feet Pshut-in = Shut-in pressure, in psia

NOTE: The above equation was taken from EPA Natural Gas STAR and is still being reviewed. -------------------------------------------------------- PLACEHOLDER- EXAMPLE – Calculating Vented Emissions from Well Blowdowns -------------------------------

22.5 Vessel and Facility Upsets/Blowdowns and Compressor Engine Start-Ups and Shutdowns This section provides methods for calculating fugitive emissions of CH4 and CO2 from non-routine activities that release natural gas from processing equipment, including vessels,


DRAFT


compressors, well tubing and oil pump stations. These types of activities can be categorized as either planned or unplanned. Planned activities refer to scheduled maintenance and turnaround activities, including vessel and gathering pipeline blowdowns, compressor starts and blowdowns, oil and gas well workovers, on and offshore gas well completions. Unplanned events refer to emergency or upset events that result in gas venting from equipment, such as pressure relief valve releases, gathering gas pipeline mishaps and emergency shutdowns. Many types of equipment must be purged of oxygen prior to re-pressurization, and this is often accomplished with natural gas, some of which may be vented to the atmosphere in the process. This section does not include emissions from CO2 well stimulation, well unloading or well blowouts. Emissions from these non-routine activities can be estimated in two ways. An engineering approach considers the volume and composition of the gas released. A simplified emission factor approach estimates emissions on a per-unit or production basis. Emission factors are tailored for the production and processing segments. The methods below can also be used to estimate volumes of gas that are sent to a flare during these procedures, and not vented into the atmosphere. Where these gas are captured and sent to a flare, or other control device, emissions should be calculated using the methods in Chapter 23.

METHOD 01

METHOD FOR CALCULATING FUGITIVE EMISSIONS NON-ROUTINE EVENTS USING ENGINEERING CALCULATIONS

In order to calculate the quantity of the gas released, it is necessary to know the temperature, volume and pressure of that gas before it was released. The volume of the gas is determined by the dimensions of the equipment from which it was released, which can be measured or discerned from product specifications and/or design data. For more information on estimating the volumes of vessels and other equipment, refer to CAPP’s Estimation of Flaring and Venting Volumes from Upstream Oil and Gas Facilities35. The pressure and temperature are dependent on the operating conditions prior to the release. Using this information, the quantity, in moles, of gas can be calculated using Equation 22-13.

35 www.capp.ca/raw.asp?x=1&dt=PDF&dn=38234


DRAFT


Equation 22-13: Calculation of the Quantity of Gas Released From Non-Routine Activities

n = PV/zRT

where: n = number of moles of gas P = pressure (atm or psi) R = gas constant (value depends on volume, temperature and pressure units

used) V = volume (m3 or scf) z = compressibility factor36 T = absolute temperature (°R or K)

Once the number of moles of the gas is calculated, it can be converted to mass using Equation 22-14.

Equation 22-14: Conversion From Moles of Gas to Mass of Gas Released from Non-routine Activities

ECH4/CO2 = n/event * mole % CH4/CO2 * MW CH4/CO2 * events

where: E CH4/CO2 = the total emissions of CH4/CO2 from each glycol dehydrator [tonne/yr] n/event = number of moles of gas released during each event mole % CH4/CO2=molar fraction of CH4/CO2 in the gas released MW CH4/CO2 = molecular weight of CH4 (16) / CO2 (44) events = number of events per year

If it is available, use CH4 and CO2 composition data specific to the gas stream used in the equipment. Natural gas composition data should be collected and analyzed according to applicable industry-approved, national, or international technical standards regarding sampling frequency, procedures, and preparation. For additional resources on gas composition analysis methods, refer to:

36 Compressibility factor values for CH4 and CO2 can be found in a chemical engineering reference, such as “Perry’s Chemical Engineer’s Handbook.” ISBN 978-0-07-049841-9


DRAFT





If you do not have access to site-specific gas composition data, you can assume CH4 content (molar %) of 78.8 for natural gas in the production segment, and 86.8 in the processing segment. Once you have calculated total CH4 and CO2 emissions, convert CH4 emissions to metric tons of CO2-equivalent, by multiplying the quantity of CH4 calculated by 21. Sum all values to come up with total emissions from non-routine activities in metric tons CO2-equivalent.

METHOD 02

METHOD FOR CALCULATING FUGITIVE EMISSIONS NON-ROUTINE EVENTS USING EMISSION FACTORS

This method uses emission rates for non-routine events for the production and processing segments. Equation 22-15 relies on emission factors for the event type, gas composition information and activity data to calculate fugitive emissions from non-routine activities

Equation 22-15: CO2 and CH4 Emissions from Non-Routine Activities

ECH4/CO2 = ER CH4/CO2 i * t annual i

where: E CH4/CO2 = the total fugitive emissions of CH4/CO2 from non-routine events [tonne/yr] ER CH4/CO2 i = CH4/CO2 emission factor from event type i (tonnes/activity unit) t annual i = Annual event occurrences, or production data (activity unit)

This approach involves three steps:

1. Determine the emission factor for each non-routine event; 2. Calculate CH4 and CO2 emissions for each non-routine event; and 3. Convert CH4 emissions to units of CO2 equivalent and sum to determine total

emissions.

STEP 1: DETERMINE THE APPROPRIATE MASS EMISSION FACTOR FOR EACH NON-ROUTINE TYPE


DRAFT


Table 22.5 provides a list of CH4 emission factors for different E&P facility types. Note that the emission factors are given on a unit production basis in some cases, and on a production bases in others. Table 22.5 - Equipment Level CH4 Emission Rates by Facility Type37

Source CH4 Emission

Factor Emission Factor Unit

Basis CH4 Content (mole

%)

Production Segment Planned Activities

Vessel blowdowns 0.0015 tonnes/vessel-yr 78.8

Compressor starts 0.1620 tonnes/ compressor-yr

78.8

Compressor blowdowns 0.07239 tonnes/ compressor-yr

78.8

Gas well workovers (tubing maintenance) 0.04707 tonnes/workover Not given

Oil well workovers (tubing maintenance)

0.0018 tonnes/workover Not given

Gathering gas pipeline blowdowns 0.00593 tonnes/mile-yr 78.8

Onshore gas well completion 25.9 tonne/completion-day 78.8

Offshore gas well completion 131.5 tonne/completion-day 78.8

Oil pump stations (maintenance) 7.076E-04 tonnes/station-yr Not given

Production Segment Unplanned Activities

Pressure relief valves releases 0.00065 tonnes/PRV-yr 78.8

Gathering gas pipeline mishaps (dig-ins) 0.0128 tonnes/mile-yr 78.8

Offshore emergency shutdown (ESD) 4.9276 tonnes/platform-yr 78.8

Processing Segment, All Non-Routine Activities

Gas Processing Non-Routine Activities 3.254E-03 tonnes/106 scf processed 86.8

If you have site-specific information on the methane content of the natural gas being processed, you can adjust the emission factors provided in Table 22.5 to reflect your own natural gas composition. This is done by multiplying the emission factors from Table 22.5 by the ratio of methane content of your own gas to the default methane content values also provided in Table 22.5, as shown in Equation 22-16.Natural gas composition data should be collected and analyzed according to applicable industry-approved, national, or international technical standards regarding sampling frequency, procedures, and preparation. For additional resources on gas composition analysis methods, refer to:




37 Source: API. DRAFT 2008 Compendium of Greenhouse Gas Emissions Estimation Methodologies for the Oil and Gas Industry, Tables 6-3 – 6-5. 2009.


DRAFT


Equation 22-16: Correcting Default CH4 Emission Factors to Reflect Site-Specific CH4

Content









STEP 2: CALCULATE CH4 AND CO2 EMISSIONS FROM EACH EVENT

Using the emission factor obtained in step 1, above, calculate total CH4 and CO2 emissions from each event using Equation 22-17.

STEP3: CONVERT CH4 EMISSIONS TO UNITS OF CO2 EQUIVALENT.


DRAFT



22.6 Transportation Sector - Truck, Tanker, Rail Loading

22.7 Transportation Sector - Pipeline Blowdowns and Pigging


DRAFT


Chapter 23: Flaring Emissions

Flaring is used to consume waste gases in a safe and reliable manner through combustion in an open flame. In the petroleum industry, flaring occurs during well testing and production operations, its primary purpose is to act as a safety device to protect vessels or pipes from over-pressuring due to unplanned upsets. Flares are routinely used to dispose of flammable gases that are either unusable or uneconomical to recover. Flaring can also be used to depressurize gas-processing equipment during routine maintenance. There are different types of flares, from small open-ended pipes used on wells during activities such as workovers and well completions, to large horizontal or vertical flares with pilots used at refineries. Flares can be used either temporary or permanently depending on the type of operation. CO2 and N2O emissions are products of the combustion process. In cases when the combustion is incomplete, or when there are operational problems, CH4 emissions can also be produced. The combustion efficiency is variable, primarily dependent on the flame stability which in turn depends on the gas velocity, heat content, and wind conditions. Many unplanned activities input gas volumes into flares and as such the volumes are difficult to quantify. Determining volumes during well completion and/or workover activities can be particularly challenging. This protocol recommends Members to keep proper logs and documentation of flaring activities and to perform gas analysis (GC/MS) when possible. Members should use the methods presented below to estimate emissions. These methods require the estimation of the flare gas flow rate and composition.

METHOD O1

FLARE EMISSIONS ESTIMATION METHODOLOGY

In cases where flared volume and gas composition data are available, the Member can estimate flared gas volumes based on the vented volume estimates for the source categories that were flared. CO2 and CH4 emissions can be calculated using the volume of gas flared, and the flare gas carbon fraction using Equation 23-1and Equation 23-2.


DRAFT


Equation 23-1: Flared Emissions Estimation 1

E(CO2) = Qfuel x (lbmole/379.3scf) x MWgas x fC x fflare x fO x [(44g-CO2)/(12g-C)]/2200

where; E(CO2) = emissions of CO2 from flaring, in tonne/yr Qfuel = flare inlet gas volume, in scf/yr MWgas = molecular weight of the natural gas (assumed to be 17.4 lb/lb-mole where a specific fuel composition is not known), in lb/lb-mole fC = mass fraction of carbon in the fuel fO = fraction of fuel carbon oxidized to CO2 (assumed to be 1.0 for all combustion emissions estimates) fflare = combustion efficiency of the flaring (assumed to be 0.98)

When vendor data information about combustion efficiency is not available, Members should use a default combustion efficiency value of 98 percent (EPA, AP-42 Section 13.5.2, September 1991). Question for TWG: Can you provide a combustion efficiency for non-engineered flares

Equation 23-2: Flared Emissions Estimation 2

E (CH4) = Qfuel x M(CH4) x R(CH4) x Vm x MW(CH4)

where; E (CH4) = emissions of CO2 from flaring, in tonne/yr Qfuel = flare inlet gas volume, in scf/yr M(CH4) = molar fraction of CH4

R(CH4) = % residual of CH4 Vm = molar volume MW(CH4) = molecular weight of CH4

METHOD 02


DRAFT


SIMPLIFIED EMISSION FACTORS METHODOLOGY

When gas composition is unknown, Members can use Equation 23-3 to estimate CO2, CH4 and N2O emissions. Table 23.1 presents the list of GHG emission factors for gas flares.

Equation 23-3: Flared Emissions - Simplified Emissions Factors

Ei = Vf x EFi where; Ei = emissions of CO2, CH4 or N2O from flaring, in tonne/yr

Vf = Volume flared, in MMSCF-gas/yr or 1000bbl-oil/yr EF = emissions factor of GHG per unit production, in tonne/MMSCF-gas or tonne/1000bbl

Table 23.1 – GHG Emissions for Gas Flares38

Emission Factors Flare Source CO2 CH4 N2O

Units

Original Units Flaring - gas productiona 1.8E-03 1.1E-05 2.1E-08 Gg/106 m3 gas production Flaring - sweet gas processinga

2.1E-03 1.3E-05 2.5E-08 Gg/106 m3 gas receipts

Flaring - sour gas processinga

4.6E-03 2.9E-05 5.4E-08 Gg/106 m3 gas receipts

Flaring - conventional oil productiona

6.7E-02 5.0E-06 -2.7E-04

6.4E-07

Gg/1000 m3 conventional oil production

Flaring - heavy oil productiona

4.9E-02 5.0E-05 -2.0E-04

4.6E-07

Gg/1000 m3 heavy oil production

Flaring - crude bitumen productiona

2.2E-02 8.8E-05 2.4E-07 Gg/1000 m3 crude bitumen production

Flaring - Refiningb,c No data 0.189 No data scf/1000 bbl refinery feed Units Converted to tonnes/106 scf or tonnes/1000 bbl Flaring - gas productiona 5.1E-02 3.1E-04 5.9E-07 tonnes/106 scf gas production Flaring - sweet gas processinga

5.9E-02 3.7E-04 7.1E-07 tonnes/106 scf gas receipts


0.13 8.2E-04 1.5E-06 tonnes/106 scf gas receipts


10.7 7.9E-04 -4.3E-02

1.0E-04

tonnes/1000 bbl conventional oil production


7.8 7.9E-03 -3.2E-02

7.3E-05

tonnes/1000 bbl heavy oil production

38 Source: API Compendium of Greenhouse Gas Emissions Estimation Methodologies for the Oil and Gas Industry. Section 4 – Combustion Emission Estimation Methods, 2004.


DRAFT


Emission Factors Flare Source CO2 CH4 N2O

Units


3.5 1.4E-02 3.8E-05 tonnes/1000 bbl crude bitumen production

Flaring - Refiningb,c No data 3.62E-06 No data tonnes/1000 bbl refinery feed Units Converted to tonnes/106 m3 or tonnes/1000 m3 Flaring - gas productiona 1.8 1.1E-02 2.1E-05 tonnes/106 m3 gas production Flaring - sweet gas processinga

2.1 1.3E-02 2.5E-05 tonnes/106m3 gas receipts


4.6 2.9E-02 5.4E-05 tonnes/106m3 gas receipts


67.0 5.0E-03 2.7E-01

6.4E-04 tonnes/1000 m3 conventional oil production


49.0 5.0E-02 -2.0E-01

4.6E-04

tonnes/1000 m3 heavy oil production


22.0 8.8E-02 2.4E-04 tonnes/1000 m3 crude bitumen production

Flaring - Refiningb,c No data 2.28E-05 No data tonnes/1000 m3 refinery feed Sources: a IPCC, IPCC Good Practice Guidance and Uncertainty Management in National Greenhouse Gas Inventories, Chapter 2 (Energy), Table 2.16, May 2000. b US Environmental Protection Agency (EPA). Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990- 2001. EPA-430-R-03-004, U.S. Environmental Protection Agency, Washington D.C., April 15, 2003, Annex H, Table H-3. c CH4 emission factors converted from scf or m3 are based on 60°F and 14.7 psia.

When calculating flared emissions from well testing activities, Members should use the fuel-based emission factors from Attachment 3 to estimate emissions, or the average emission factor shown below. Table 23.2 - GHG Emission Factors for Liquid Flares39

Original Units Emission Factors

Flare Source CO2 CH4 N2O

Units

Upstream liquid flares 3.2 x 0.95 = 3.04a 0.00033 0.00022 Tones/tonne oil flared

Example 23-1: Calculation of Combustion Emissions from a Gas Flare

A facility produces 3 million scf of natural gas per day. In a given year, 20 million scf of field gas is flared at the facility. The flare gas composition is: 80% of CH4, 15% of C2H6 and 5% of C3H8 Since vendor data on combustion efficiency is not available, CO2 emissions are estimated assuming 98% combustion efficiency and 2% of uncombusted CH4. 39 Source: API Compendium of Greenhouse Gas Emissions Estimation Methodologies for the Oil and Gas Industry. Section 4 – Combustion Emission Estimation Methods, 2004.


DRAFT


CO2 emissions are calculated using Equation 23-1 as follows. E(CO2) = (20 x 106scf gas/yr) x (lbmole gas/379.3scf gas) x [(0.80 lbmole CH4/lbmole gas x

lbmole C/lbmole CH4) + (0.50 lbmole C2H6/lbmole gas x 2 lbmole C/lbmole C2H6) + (0.05 lbmole

C3H8/lbmole gas x 3 lbmole C/lbmole C3H8)] x (0.98 lbmole CO2/lbmole Ccombusted) x (44 lb

CO2/lbmole CO2) x (tonne/2204.62 lb)

E(CO2) = 1,289 tonnes CO2/yr Equation 23-2 is used to estimate CH4 emissions. E(CH4) = (20 x 106scf gas/yr) x (0.80 scf CH4/scf gas) x (0.02 scf CH4/scf CH4 total) x (lbmole

CH4/379.3 scf CH4) x (16lb CH4/lbmole CH4) x (tonne/2204.62 lb)

E(CH4) = 6.1 tonnes CH4/yr N2O emissions are calculated using Equation 23-3 and the emission factors from Table 23.2, as shown below. E(N2O) = (3 x 106scf gas/day) x (365 days/yr) x (5.9 x 10-7 tonnes N2O/106 scf gas) E(N2O) = 6.46 x 10-4 tonnes N2O/yr


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Chapter 24: Oil Sands and Oil Shale specific sources

24.1 Oil Sands and Heavy Oil Upgrading Industry (OS/HOU) The main GHG emission sources from Oil Sands and Heavy Oil Upgrading Industry (OS/HOU) are:

Process emissions hydrogen units; CH4 present in the oil sands deposits that is released during mining activities; volatilization of hydrocarbons from the exposed oil sands; biogenic gas formation (primarily CH4) in some tailings ponds; volatilization and decomposition of residual bitumen, which carry through to the tailings

ponds; fugitive equipment leaks, venting, flaring, storage losses at ore preparation, extraction,

and upgrader plants. GHG emissions from the Oil Sands and Heavy Oil Upgrading Industry (OS/HOU) can be estimated using an extrapolation model created by Clearstone Engineering Ltd. for Environment Canada’s Bitumen-Oilsands Extrapolation Model - Rev 3 in 2007. This model is based on results from the Bitumen Report: 1990 – 2003 Emission Estimates (CAPP 2006), annual production data reported by the Alberta Energy and Utilities Board (AEUB) and the National Energy Board (NEB). The model also uses source specific emission factors. This section presents details about this model.

METHOD 01

EXTRAPOLATION MODEL

This model applies custom emission factors and prorating factors derived from the facility base inventories (1990–2003) to publicly available activity data collected every year, to provide emission estimates for the OS/HOU industry from the years 2004 to the present. The equation used by the model to extrapolate emissions is presented below.

Equation 24-1: Extrapolation Model

ERi = EFi x (A1 + A2)

where; ERi = emissions of substance i, in t/year EFi = emission factor for substance i A1,A2 = activity values applicable to the emission factor


DRAFT


In Alberta and Saskatchewan, source-specific factors were developed for each facility by correlating the most recent 3–4 years of emission data from the bitumen report (CAPP, 2006a) with available site-specific production accounting data. This is a high-level emissions factor approach that relates present activity levels with past performances. This methodology may not take into account facility changes when applied to current emissions. Question for CAPP: Can you provide more details about this model? Which emission factors are being used?

24.2 Hydrogen Unit This section presents methodologies to calculate GHG emissions from hydrogen units operations. These units are used to generate hydrogen (H2) and synthesis gas as a product of the reaction between hydrocarbons and steam (H2O). Equation 24-2 presents the chemical reaction that has to occur in order to obtain H2.

Equation 24-2: Chemical Reaction to Obtain Hydrogen

C x H(2x+2) + 2 x H2O (3x+1)H2 + xCO2

The quantity of H2 generated depends on the carbon-to-hydrogen ratio of the feed gas. In most cases, H2 is made from natural gas, but there are some cases where naphtha or refinery fuel gas is used as feedstock. The CO2 generated during this process doesn’t include CO2 emissions from process heater(s) associated with the hydrogen unit. These emissions should be treated like the combustion sources described in Chapter 12 of this protocol.

METHOD 01

MATERIAL BALANCE EMISSIONS ESTIMATION

Members can use the specific feed gas composition to estimate vented CO2 emissions from hydrogen units. This methodology can be based on either the volume of feedstock used or the hydrogen production rate. Both calculation methods are presented below. This method is based on a material balance equation (Equation 24-3), the feedstock rate and the carbon content are needed as input.

Equation 24-3:Material Balance Emissions Estimation

E(CO2) = FR x CF [(44 mass units CO2/mole)/(12mass units C/mole)

where,


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Equation 24-3:Material Balance Emissions Estimation

E(CO2) = emissions of CO2, in units of mass per year (i.e. tonnes/year) FR = feedstock rate, in units of mass per year (excluding H2O fed) CF = weight fraction of carbon in feedstock 44 = molecular weight of CO2

12 = molecular weight of carbon -------------------------------------------------------- PLACEHOLDER- EXAMPLE – Calculating Hydrogen unit Emissions using the Material Balance Approach ---------------------------------

STOICHIOMETRIC RATIO APPROACH

In this approach, Members need to have the H2 production rate rather than the feedstock rate. This equation applies the stoichiometric ratio of H2 formed to CO2 formed and it is derived from Equation 24-3 presented above.

Equation 24-4: Stoichiometric Ratio Approach

E(CO2) = H2R x [(xmole CO2/(3x + 1)mole H2 )/(44/molar volume conversion)]

where, E(CO2) = emissions of CO2, in units of mass per year (i.e. tonnes/year) H2R = rate of hydrogen production, in units of volume per year (i.e. scf/yr) CR = weight fraction of carbon in feedstock 44 = molecular weight of CO2

x = stoichiometry from Equation 24-2 Molar volume conversion = see Attachment 2 for conversion factors -------------------------------------------------------- PLACEHOLDER- EXAMPLE – Calculating Hydrogen unit Emissions using the Stoichiometric Ratio Approach -------------------------------

METHOD 02


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SIMPLIFIED EMISSION FACTORS

Members can use default emission factors based on either feedstock consumption or hydrogen production to estimate CO2 emissions from hydrogen unit processes. These emission factors are based on a stoichiometric conversion for a feed gas with an average natural gas composition. The following table provides the average natural gas composition40 used to derive these factors. Table 24.141 - Composition of U.S. Pipeline-Quality Natural Gas

Compound Average Volume % a,b CH4 93.07 C2H6 3.21 C3H8 0.59

Higher hydrocarbons c 0.32 Non-hydrocarbons d 2.81

Footnotes and Sources: a Gas Technology Institute (GTI). Database as documented in W.E. Liss, W.H. Thrasher, G.F. Steinmetz, P. Chowdiah, and A. Atari, "Variability of Natural Gas Composition in Select Major Metropolitan Areas of the United States", GRI-92/0123, March 1992. b Perry and Green. Perry’s Chemical Engineer’s Handbook, Sixth Edition, Table 9-14, 1984. c Higher molecular weight hydrocarbons were represented by C5 in calculating the CO2 and H2 production rates. d The non-hydrocarbons are assumed to contain 0.565 volume % CO2 based on an average natural gas composition from Perry’s Chemical Engineers Handbook.

Members should only use this methodology if the feedstock is pipeline-quality natural. Otherwise, CO2 emissions will be overestimated. This methodology is based on an emission factor of 32,721 pounds of carbon per million standard cubic feet of feedstock (excluding H2O) or 8,064 pounds of carbon per million standard cubic feet of H2 produced. Table 24.2 presents the emission factors. Table 24.242 - Hydrogen Unit Simplified Emission Factors

Process Feedstock Hydrogen Production Rate

119,976 lb CO2/106 scf feedstock 29,568 lb CO2/106 scf H2 produced

54.42 tonnes CO2/106 scf feedstock 13.41 tonnes CO2/106 scf H2 produced

1,922 tonnes CO2/106 m3 feedstock 473.6 tonnes CO2/106 m3 H2 produced

-------------------------------------------------------- PLACEHOLDER- EXAMPLE – Calculating Hydrogen Unit Emissions using Simplified Emission Factors -------------------------------

40 This natural gas composition is based on measurements from pipeline-quality gas from 26 U.S. cities (GTI, 1992). 41 API Compendium of Greenhouse Gas Emissions Estimation Methodologies for the Oil and Gas Industry. Section 5 - Process and Vented Emission Estimation Methods, May 2009. DRAFT Version. 42 API Compendium of Greenhouse Gas Emissions Estimation Methodologies for the Oil and Gas Industry. Section 5 - Process and Vented Emission Estimation Methods, May 2009. DRAFT Version.


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Question for CAPP: The Greenhouse Gas Emission Estimation Methodologies for the Oil Sands / Heavy Oil Upgrader Industry Report (May 2004) present the following deviations from guidelines: Emission calculations associated with the production of hydrogen by steam methane reforming need to take into consideration several factors, including:

The composition of the natural gas The efficiency of the conversion process. The hydrogen purification process downstream of the steam methane reformation

process. Two processes are utilized: Catacarb absorption and regeneration, and pressure swing absorption (PSA). Catacarb units vent carbon dioxide directly to atmosphere. The product hydrogen stream which contains unconverted hydrocarbon gases and carbon monoxide is utilized in hydrotreating processes. These components end up in the process gas stream as fuel components along with light gases produced during the Upgrading process. In comparison, PSA units extract a very high purity hydrogen product. The remaining PSA offgases are utilized directly as fuel for the endothermic reforming process.

Can CAPP provide examples that illustrate how companies deal with these deviations (i.e. development of emission factors, etc)? If there are other emission factors that are being used, could we include them in this protocol?

24.3 Upgrader Facilities Upgrading is a conversion process used during unconventional oil production operations to change the characteristics of the crude bitumen to create synthetic crude oil. This process has two phases. During the first step, the crude bitumen enters an upgrading unit where the hydrocarbon molecules are broken down using a coker unit. In the second step, the lighter portion of the upgraded bitumen obtained during the coking process goes through a hydroprocessing unit where hydrogen is added to remove nitrogen, sulphur and metals from the crude bitumen. This section presents methodologies to estimate CO2 emissions associated with these two processes.

METHOD 01

EMISSIONS FROM COKER UNITS

There are different types of coker units that can be used such as delayed cokers, flexi-cokers, and fluid cokers. CO2 emissions from delayed coker units come from the unit’s heaters; these emissions should be calculated using the equations presented in Chapter 12 of this protocol. Flexicoker unit vent CO2 emissions from the coke burner. There are some flexicokers that can


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have vents that produce flexigas, which is used as a fuel; emissions from these units should be calculated using the combustion emissions calculation methods presented in Chapter 12. In order to estimate CO2 emissions from the coker units, Members should assume that all of the carbon in the coke is oxidized to CO2. The calculation methodology is presented below.

Equation 24-5: Emissions from Coker Units

E(CO2) = FR x CF [(44 mass units CO2/mole)/(12mass units C/mole)]

where, E(CO2) = emissions of CO2, in units of mass per year (i.e. tonnes/year) FR = feedstock rate, in units of mass per year CF = weight fraction of carbon in feedstock 44 = molecular weight of CO2

12 = molecular weight of carbon

-------------------------------------------------------- PLACEHOLDER- EXAMPLE – Calculating Emissions from Coker Units ---------------------------------

METHOD 02

EMISSIONS FROM HYDROPROCESSING UNITS

Hydroprocessing units employ catalysts that require regeneration (e.g., naphtha reformers). Most of these are regenerated intermittently, although a few have continuous regeneration systems. CO2 emissions can be produced from the combustion of coke to regenerate catalysts. CO2 emissions from intermittent regeneration are not likely to be significant when compared to combustion sources and continuous regeneration. There are no significant CH4 emissions from these operations. Members should apply the principle of complete stoichiometric combustion to estimate CO2 emissions from catalyst regeneration using Equation 24-6.

Equation 24-6: Emissions from Hydroprocessing Units

E(CO2) = CRR x H x (FCspent – FCregen) x [(44 mass units CO2/mole)/( 12mass units

C/mole)] where,


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Equation 24-6: Emissions from Hydroprocessing Units

E(CO2) = emissions of CO2, in units of mass per year (i.e. tonnes/year) CRR = catalyst regeneration rate, in units of mass per hour (i.e. tones/hr) H = hours of operation of the regenerator per year (or number of regeneration cycles per year when estimating emissions from an intermittent regeneration operation FCspent = weight fraction of carbon on spent catalyst FCregen = weight fraction of carbon on regenerated catalyst 44 = molecular weight of CO2

12 = molecular weight of carbon

-------------------------------------------------------- PLACEHOLDER- EXAMPLE – Calculating Emissions from Hydroprocessing Units --------------------------------- Question for CAPP: The Greenhouse Gas Emission Estimation Methodologies for the Oil Sands / Heavy Oil Upgrader Industry report mentions that the compositions of some of the streams processed in facilities that operate with unconventional oil are different than from convention oil and gas streams. Thus, some calculations need to be modified . These methodologies present basic mass balance equations, do you have more information about how the differences in composition affect these equations?

24.4 Flue Gas Desulphurization Fossil Fuels such as oil contain significant amounts of sulfur. When fossil fuels are burned, about 95 percent or more of the sulfur is generally converted to sulfur dioxide (SO2). This happens under normal conditions of temperature and of oxygen present in the flue gas. The flue gas desulphurization (FGD) process removes the sulfur dioxide (SO2) produced from burning fossil fuels by using limestone to scrub the gases (this process is called wet scrubber), calcium sulfate dehydrate (gypsum- CaSO4) and CO2 are produced as a result of this reaction. Members can use a mass balance approach to estimate CO2 emissions from the process. The overall accuracy of this approach depends on the degree to which the input materials are measured. The calculation method is based on the mass of limestone, the limestone %CaCO3, and the conversion factor for CO2 equivalency.

Equation 24-7: CO2 Emissions from Flue Gas Desulphurization Using Mass Balance

CaCO3 + SO2 +1/2O2 CaSO4 + CO2


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Question for CAPP: Here we have a mass balance approach. Do you have a different approach to calculate these emissions?

24.5 Oil Sands Mines and Ponds Emissions Question for CAPP: Do you have information that you can provide about the methodologies that Syncrude and Suncor use to estimate their emissions from these sources and the emission factor they’ve developed?


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ATTACHMENT 1: GLOSSARY OF TERMS43

These definitions are from the emission factors source documents: GRI GHGCalc, API Compendium, and GRI/EPA "Methane Emissions from the Natural Gas Industry" Term Definition

Activity Data Set An Activity Data Set is what is used to store activity values for a facility. A facility can have more than one Activity Data Set; for example, Activity Data Sets can be defined to represent the following scenarios:

Multiple years of a given facility's operations (such as 1990 baseline conditions and current year operations);

Different seasons of operation in a given year (such as summer versus winter operations at a storage facility); or

Different sites within a facility (such as each pipeline in a transmission company or each production field for a production company).

Activity Data The activity data of a particular source is a measure of the annual "usage" of that source which can be an equipment count, production rate, or the frequency of an emissions-generating event. It is multiplied by an emission factor, which is an estimate of the emissions per unit "usage" from that source, to obtain the annual emission rate. For example, to estimate combustion emissions from an engine, the emission factor is given in lb/MMhp-hr (in customary US units), and the activity data are in units of MMhp-hr/yr, to give an emission rate of lb/yr.

AGR Abbreviation for acid gas recovery processes. AGRs remove sulfur compounds and CO2 from natural gas streams.

Anthropogenic Emissions/Removals

Greenhouse gas emissions and greenhouse gas removals that are the result of human activities, either directly or indirectly through natural processes that have been affected by human activities.

Associated Gas Natural gas that is in contact with crude oil in the subsurface reservoir. Associated gas is wet gas; that is, it typically contains significant amounts of condensate and/or liquid hydrocarbons. Associated gas occupies a separate portion of the reservoir from dissolved or non-associated gas.

Barrel One barrel is defined as 42 U.S. gallons. bbl/yr Abbreviation for barrels per year. Blanket gas A gas phase maintained above a liquid in a vessel to protect the liquid against air

contamination, to reduce the hazard of detonation, or to pressurize the liquid. The gas source is located outside the vessel.

Blowdown The venting of natural gas contained inside a pressure vessel, pipeline, compressor, or other equipment for emergency or maintenance purposes. The gas may be vented to the atmosphere or to a control system (e.g. flare or lower pressure gas system (if available)).

Boiler An indirect-fired water heater that produces steam and/or hot water. Btu/scf Abbreviation for British Thermal Units per standard cubic foot. Calculation Tier Three calculation tiers offer a range of detail for estimating emissions.

Successively higher tiers require more specific user inputs, but generate more accurate results. Tier 1 is the simplest approach and requires only very general information on the facility or operations - Tier 1 will not be used for this inventory. Tier 2 requires slightly more detailed information to calculate emissions (and provides slightly better accuracy), while Tier 3 starts to account for emissions from

43 Note that the terms included in this Glossary are sector-specific terms used in the OG&P protocol. Other terms applicable to GHG reporting for The Registry are included in the General Reporting Protocol.


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Term Definition

individual equipment sources.

Carbon Equivalent The concept of carbon equivalents has been developed to compare the capacity of different greenhouse gases to trap heat relative to a base gas, CO2 . The carbon equivalent of a particular greenhouse gas is determined by first multiplying the concentration of the gas by the global warming potential (GWP) for that gas. Then the mass units of CO2 are converted to mass units of carbon based on the molecular weight ratio of carbon to CO2. This is shown in the following equation: mass units C = mass units CO2 x 12/44 The GWP is an index used to relate the level of emissions of various greenhouse gases to a common measure. It is defined as the ratio of global warming from one mass unit (kilogram or pound) of the greenhouse gas to one mass unit of carbon dioxide over a period of time. While any period of time can be selected, the GWP for a period of 100 years is recommended by the Intergovernmental Panel on Climate Change (IPCC) and the U.S. Department of Energy [U.S. Department of Energy, 1995]. On this basis, one mass unit of methane released into the atmosphere has the same impact on global warming as 21 mass units of CO2 over a 100-year time period. Likewise, one mass unit of N2O has the same impact of 310 mass units of CO2 . Because CO2 is chosen as the reference gas, the GWP of CO2 is 1 [U.S. Environmental Protection Agency, 1998].

Casinghead Gas Casinghead gas is natural gas that effuses out of crude oil on the well surface due to the pressure difference between the surface and the reservoir. A casinghead is the top of the casing at the surface of a well, and can be a heavy steel flange bolted to the top of the surface casing as part of the wellhead. The casinghead has a hanger packer that suspends the smaller diameter production string in the well. Casinghead valves are used to relieve gas pressure built up in the casing annular space; this gas is usually either vented or recovered to sales.

Cast Iron Pipeline Pipelines constructed of cast iron. Cast iron pipes are prone to leakage because of bell and spigot design and frequency of the fittings

Centrifugal Compressor

A compressor that uses blades or impellers to accelerate gas radially, thus imparting kinetic energy to the gas. Centrifugal compressors are common in gas transmission, and are sometimes used in gas gathering. Centrifugal compressors are generally driven by gas turbines.

CH4 Methane (CH4) is a naturally occurring greenhouse gas produced through anaerobic decomposition of organic matter in biological systems. Methane is also emitted during the production and distribution of natural gas and petroleum, and through incomplete combustion of fossil fuels. Methane is the primary component of natural gas.

Chemical Injection Pump

Chemical Injection Pumps are small positive displacement units designed to inject precise amounts of chemicals into process streams to control processing problems and protect equipment. Gas-driven CIPs, which use gas pressure to drive a plunger that drives other fluids (i.e. the chemicals), are commonly used in applications where electricity is not readily available. The motive gas is vented to atmosphere. The vented gas volume depends on the pump size, operating frequency, and supply gas pressure.

Chemical Injection Pump - Diaphragm Pump

Chemical Injection Pumps that use a diaphragm to drive the Chemical Injection Pump plunger.

Chemical Injection Pump - Piston Pump

Chemical Injection Pumps that use a piston to drive the Chemical Injection Pump plunger.


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Term Definition

CO2 Carbon dioxide (CO2) is a naturally occurring greenhouse gas formed by the oxidation of atmospheric carbon. It is part of the natural carbon cycle, where carbon is transferred between the atmosphere, land, oceans, living biomass, and mineral reservoirs. Carbon dioxide is also formed through the combustion of carbon-containing fuels.

CO2 Equivalent The concept of CO2 equivalents has been developed to compare the capacity of different greenhouse gases to trap heat relative to a base gas, CO2 . The CO2 equivalent of a particular greenhouse gas is determined by multiplying the concentration of the gas by the global warming potential (GWP) for that gas. The GWP of a greenhouse gas is the ratio of global warming from one mass unit (kilogram or pound) of the greenhouse gas to one mass unit of carbon dioxide over a period of time. While any period of time can be selected, the GWP for a period of 100 years is recommended by the Intergovernmental Panel on Climate Change (IPCC) and the U.S. Department of Energy [U.S. Department of Energy, 1995]. On this basis, one mass unit of methane released into the atmosphere has the same impact on global warming as 21 mass units of carbon dioxide (over a 100-year time period). Likewise, one mass unit of N2O has the same impact of 310 mass units of CO2 . Since CO2 is chosen as the reference gas, the GWP of CO2 is 1 [U.S. Environmental Protection Agency, 1998].

Combined Cycle Technology for electricity generation that uses both a combustion turbine and a steam turbine.

Combustion Emissions

Combustion emissions include exhaust from combustion sources such as compressor engines, burners, and flares. Typical combustion products are CO2, CO, and NOx; methane is usually emitted as a result of incomplete combustion. Trace levels of N2O are also emitted.

Component Counts (Fugitive Emissions)

The number of parts at a site from which fugitive emissions may escape. The EPA has developed six different categories of components: connections, flanges, open-ended lines, pumps, valves, and "others".

Compressor Blowdown

Compressor blowdowns can be partial or full blowdowns. Partial blowdowns either depressurize the compressor to a lower-pressure recovery system or to atmosphere, and leave the compressor at that lower pressure. Full blowdowns depressurize the compressor from full operating pressure to the atmosphere.

Compressor Starts Gas compressor starters use a small turbine whose blades spin when high-pressure supply gas is introduced to the starter. The supply gas is usually vented to the atmosphere after exiting the starter. Compressed air may power the starter, but natural gas is used more often than air.

Compressor Driver A mechanical energy source, typically an reciprocating internal combustion engine or turbine that drives a natural gas compressor.

Compressor Station A compressor station is a site, usually on a gas pipeline, where natural gas is compressed to raise the pressure and keep the gas flowing. In addition to the compressors, compressor stations can have equipment such as separators, pig launchers/receivers, electricity generators, and control equipment.

Condensate Light hydrocarbons that are gas phase under subsurface well high temperature and pressure conditions and condense to liquid at surface conditions.

Continuous-Bleed Pneumatics

Continuous-bleed pnuematics vent gas both when the device actuates and when it is on standby; thus, the emissions depend on the actuating bleed rate and the stationary bleed rate. This is opposed to intermittent-bleed pneumatics which emit gas only when the device actuates.

Direct Greenhouse Effects

Radiative effects that occur when the gas itself is a greenhouse gas.

Direct Industrial Sales M&R Station

A direct sales point/connection along a high-pressure (> 100 psig) transmission or distribution pipeline to provide gas to a specific customer. Includes a gas meter and (usually self-contained) pressure regulator.


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Term Definition

Distribution Industry Segment

Distribution facilities receive high pressure gas from transmission pipelines, reduce the pressure, and deliver the gas to residential, commercial, and industrial consumers. This industry segment includes pipelines (mains and services), metering and pressure regulating stations, and customer meters.

Emission Factor Amount of GHG (e.g. tonne, lb) released to atmosphere per unit operations (e.g. MMBtu fuel fired, MW-hr electricity produced)

ESD Abbreviation for emergency shutdown - equipment and pipelines leading to a facility are shut down; the ESD system may then open blowoff valves that depresssure the facility to the atmosphere.

Farm Tap M&R Station

A direct sales point/connection along a high-pressure (> 100 psig) transmission or distribution pipeline to provide gas to the property owner (usually free gas in exchange for the pipeline right-of-way). Includes a gas meter and a (usually self-contained) pressure regulator.

Field Gas Untreated natural gas that has not been sweetened; that is, acid gases such as CO2 or H2S have not been removed. However, if the field gas is to be used as fuel, H2O, and sometimes H2S, are typically removed. Field gas may also be referred to as raw gas.

Flare The burning of gas through a pipe, typically as an open flame. Fugitive Emissions Fugitive emissions are unintentional leaks of gas from sealed surfaces. See also

the fugitive component counts definition.

Gathering Pipeline Water Removal Blowdowns/Pull-backs

Blowdowns on low-pressure (e.g. less than 76 psi) gathering gas system pipelines that have short segments vented briefly (about 10 seconds) to remove accumulated water.

Gathering Pipeline Pipeline used to gather oil or gas from wellsites or other surface facilities before transfer to a main pipeline, such as an intrastate or interstate pipeline.

Global Warming Potential

The global warming potential (GWP) is an index used to relate the level atmospheric impact of emissions of various greenhouse gases to a common measure. It describes the relative amount of global warming (or radiative forcing, including both direct and indirect effects) produced by the gas relative to the global warming produced by carbon dioxide, the reference gas, over a specified period of time. The GWP is used to compare the capacity of different greenhouse gases to trap heat in the atmosphere relative to CO2. Global warming potentials are calculated as the following ratio: Radiative Forcing per unit mass of Greenhouse Gas/Radiative Forcing per unit mass CO2 By definition, CO2 has a GWP of 1, while CH4 and N2O currently have GWPs of 21 and 310, respectively [U.S. Environmental Protection Agency, 1998]. These values are based on a 100-year time period, as recommended by the IPCC.

Glycol Dehydrator Gas-liquid contacting equipment used to remove water from natural gas using triethylene glycol or ethlylene glycol. Natural gas components (e.g. methane) are absorbed by glycol in small amounts and are emitted when the glycol is regenerated by heating to drive off absorbed water. Some dehys are equipped with flash tanks and/or emissions controls to reduce hydrocarbon emissions.

Greenhouse Gases A gas that contributes to the natural greenhouse effect. The Kyoto Protocol covers six greenhouse gases (GHGs) produced by human activities: carbon dioxide, methane, nitrous oxide, hydrofluorocarbons, perfluorocarbons, and sulfur hexafluoride. For the purposes of E&P reporting, carbon dioxide, methane, and nitrous oxide are considered.

Heater Indirectly fired equipment used to heat process materials. Heat Input The amount of heat (in MMBtu/hr) supplied by the fuel on an hourly basis, on a

higher heating value basis.


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Term Definition

Heat Rate A measure (in Btu/hp-hr) of a compressor driver's fuel efficiency and is calculated as Fuel heat input divided by equipment power output. Calculated by using the lower heating value of the fuel.

Heavy Crude Oil API designates heavy crude oil as having an API gravity of less than 20°. To convert from specific gravity to API gravity, use:°API = [141.5 / (specific gravity) ] – 131.5

Heavy Duty Truck A truck with a Gross Vehicle Weight greater than 8,500 pounds. Horsepower Units of mechanical power. hp Abbreviation for horsepower. hp-hr Abbreviation for horsepower-hour. Hydroelectric Electric Technology

Technology for electricity generation that uses the natural power of running water in streams, rivers, and lakes.

ICE Abbreviation for (reciprocating) internal combustion engine Incinerator A combustion device used to oxidize waste gases or other waste materials. Indirect Emissions Indirect emissions refer to those due to purchased electricity consumption; that is,

electricity generated at an off-site power plant. By including emissions from electric power generation in the overall facility emissions estimate, companies can take credit for greenhouse gas reductions due to using more energy-efficient processes.

Indirect Greenhouse Effects

Radiative forcing effects occur when chemical transformation of the original gas produces a greenhouse gas, or when a gas influences the atmospheric lifetimes of other gases.

Intermittent-Bleed Pneumatics

Intermittent-bleed pneumatics are devices that emit gas only when the device actuates. This is opposed to continuous-bleed pnuematics, which vent gas both when the device actuates and when it is on standby. Pneumatic Displacement Valve Operators and Turbine Valve Operators are intermittent bleed valve operators.

"Junked" Vehicle Vehicles that were completely removed from service or "junked" (no longer operating). Does not include vehicles that were sold for reuse.

Kimray Pump A positive displacement, gas-assisted pump commonly used in glycol dehydration units that uses gas from a glycol absorber to provide the motive energy for the pump. With these types of pumps, some additional gas is sent to the glycol regenerator. Depending on the glycol dehydrator configuration (e.g. use of a flash tank and/or combustion control for the regenerator emission), all or some of the pump gas will be vented to atmosphere. Kimray is actually a brand name, but the term is used here to indicate any type of pump where dehydrator gas is used to operate the pump.

Large Gathering Compressors

Large gathering compressors are those of sufficient size and horsepower (typically more than three stages) to be in a station setting, much like the stations used in gas transmission. This is opposed to small gathering compressors that may simply be on a pad at the wellsite. The large vs. small distinction is important because compressors in large stations tend to have separate vent lines and larger suction headers, discharge headers, and block valves, which lead to greater fugitive emissions. In the 1996 GRI/EPA Study, large gathering compressor stations were defined as those reported to United States Federal Energy Regulatory Commission (FERC) that had at least 16 stages of compression (5 compressors per station and an average of 3.3 stages per compressor).

LB Abbreviation for lean burn. Leak Detection and Repair (LDAR) Program

This is a maintenance program that involves regularly scheduled leak detection of an entire facility, followed by a repair effort for the identified leaks. The number of leaks is tracked and the total leak rate may also be tracked. Another name commonly used for the LDAR program is Inspection and Maintenance (I&M).


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Term Definition

Lean-Burn IC Engine

A lean-burn IC engine has an air-to-fuel ratio that is greater than stoichiometric and can not be adjusted to operate with an exhaust O2 concentration of less than 1%. Air-to-fuel mass ratios typically range between 20:1 and 60:1. A lean-burn engine is typically available in two designs: direct-injected and premixed.

Light Crude Oil API designates light crude oil as having an API gravity of greater than 20°. To convert from specific gravity to API gravity, use:°API = [141.5 / (specific gravity) ] – 131.5

Light Duty Truck A truck or large scale SUV with a Gross Vehicle Weight less than or equal to 8,500 pounds. The average miles per gallon for gasoline light duty trucks is 14 mpg and the average miles per gallon for diesel light duty trucks is 15 mpg.

Meter A device used to measure volumes or rates of fluids (liquid or gas). MMBtu Abbreviation for million British thermal units. MMhp-hr Abbreviation for million horsepower hours. MMscf Abbreviation for million standard cubic feet per year. MMscf/yr Abbreviation for million standard cubic feet. Standard conditions are 60°F and 1

atmosphere. MMscfd Abbreviation for million standard cubic feet per day, a commonly used measure of

natural gas flow. Standard conditions are 60°F and 1 atmosphere.

Mscf Abbreviation for thousand standard cubic feet at 60°F and 1 atmosphere. MW Megawatt. Natural Gas Pipeline quality gas that has had processing for sour gases and heavy

hydrocarbons removal. N2O Nitrous oxide is a naturally occurring greenhouse gas. Nitrous oxide is also

formed during fossil fuel combustion. N2O emission factors are sometimes calculated by assuming that 1.5% of NOx emissions are N2O.

Non-associated Gas Gas dissolved in crude oil that is released at well surface conditions (lower pressure and temperature)

NOx Oxides of nitrogen (usually NO and NO2) that are formed during fossil fuel combustion, lightning, soil microbial activity, biomass burning, and, in the stratosphere, from nitrous oxide. Nitrogen oxides are considered ozone precursors and have an indirect effect on climate change because of their role in promoting the formation of tropospheric ozone.

Other Direct Vented Vented emissions not accounted by emissions sources not otherwise listed. Pipeline Blowdown Venting of gas from a pressurized pipeline, usually to the atmosphere, for repairs,

to remove old pipelines from service, or to put new pipelines in service.

Pipeline Dig-In A pipeline dig-in refers to unintentional impact with a buried pipeline, usually caused by excavation activity in the pipeline right-of-way. The dig-in may cause a pipeline scrape, puncture, or rupture and gas release.

Piston Displacement Valve Operators

Valve operators that use pneumatic force (gas pressure) to move a piston. The piston acts on an arm or level that rotates the valve stem. Gas is supplied to one side of the piston and exhausted from the other, so that the arm is moved in either direction, opening and closing the valve.

Plastic Pipeline The plastic pipeline category includes any pipe made of a non-steel material. A common pipeline plastic is polyvinylchloride (PVC), although others are available. Plastic pipe is most commonly used in low-pressure applications, such as gas distribution or low-pressure gathering systems.

Platform ESD An emergency shut-down (ESD) on an offshore platform.


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Term Definition

Pneumatic Displacement Valve Operators

These are valve operators that use pneumatic force (gas pressure) to move a valve actuator element in one direction. The pneumatic force is either applied directly to the actuator element or applied to an oil so that hydraulic force moves the actuator. The actuator element is "displaced" from its original position by the pneumatic or hydraulic force. In either case, gas is discharged when the valve is actuated. Displacement operators in the gas industry are of two basic types: 1.) rotary vane; and 2.) piston. A common application is as an isolation valve operator. These are intermittent bleed pnuematic devices.

Processing Industry Segment

Processing facilities are those that process natural gas to recover natural gas liquids and remove undesirable substances such as hydrogen sulfide. A gas processing facility is defined as a separate, stand-alone plant that handles entire field volumes for multiple processing purposes, such as dehydration, compression, hydrocarbon liquid recovery, acid gas rejection, etc. While some gas processing steps can be performed at individual onshore wellsites (dehydration and H2S removal, for example), these smaller operations are not included in the definition of gas processing.

Production Industry Segment

Facilities in the production segment are those that gather natural gas or oil from production wells. These facilities may include separators, heaters, tanks, dehydrators, amine units, compressors, and gathering pipelines.

Protected Steel Steel pipeline - bare and coated - that does have cathodic protection. PRV Pressure Relief Valve. PRVs protect equipment (e.g. vessel, pipeline) from

rupturing due to high pressure. If emergency conditions occur, where internal pressures exceed the vessel's design pressure, the valve lifts and allows gas flow out of the vessel.

psig Abbreviation for pounds per square inch gauge. Purge Purge is the process of clearing air from equipment by displacing it with natural

gas; in the process, some purge gas is emitted to the atmosphere is evacuated from the equipment.

Radiative Forcing A measure of changes in the energy transfers among space, the atmosphere, land, and the oceans.

Raw Gas Untreated natural gas that has not been sweetened; that is, acid gases such as CO2 or H2S have not been removed. Raw gas also typically has not had water, inerts, or liquid hydrocarbons removed. This may also be referred to as field gas; however, H2O, and sometimes H2S, are removed before the field gas is used as fuel.

RB Abbreviation for rich burn. Reciprocating Compressor

A compressor that uses pistons moving back and forth (reciprocating) in cylinders to compress natural gas. These compressors are typically driven by reciprocating internal combustion engines.

Renewables Renewables are sources for electricity generation that are not completely consumed during the generation process. Wind power and solar power are two examples. Renewable sources generally have insignificant greenhouse gas emissions relative to other electricity generation technologies.

Residual Fuel Oil Heavier oils that remain after the distillate fuel oils and hydrocarbons are distilled away in refinery operations and conform to ASTM Specifications D396. Included are No. 5, a residual fuel oil of medium viscosity; Navy Special, for use in steam powered vessels in government services and in shore power plants. And No. 6., which includes Bunker C fuel oil and us used for commercial and industrial heating, electricity heating, and to power ships

Rich-Burn IC Engine A rich-burn IC engine operates with an air-to-fuel ratio that is near stoichiometric, or fuel-rich, and has an exhaust O2 concentration ranging from 0% to 5%. Air-to-fuel mass ratios typically range between 16:1 and 20:1. Rich-burn engines include all naturally aspirated and non-scavenged, turbocharged 4-stroke engine


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Term Definition

models.

Rotary Vane Pneumatic/Hydraulic Displacement Operators

Rotary vane pneumatic/hydraulic displacement operators use natural gas to force a fixed amount of oil from one pressure bottle to another. The oil moves through the vane operator, delivering hydraulic force to the vane, and moving it and the attached valve stem one quarter turn. The oil moving through the bottle forces gas in the top of the receiving pressure bottle to vent to the atmosphere.

scf An abbreviation for standard cubic foot of gas. Standard conditions are 60°F and 1 atmosphere.

scm An abbreviation for standard cubic meter of gas. Standard conditions are 15°C (60°F) and 101.3 kPa (1 atmosphere).

Separator A vessel used to separate oil, gas, and water from the total fluid stream produced by a well. Separators can be either horizontal or vertical.

Simple Cycle A gas turbine that produces electricity without heat recovery or steam generation. Small Gathering Compressors

Compressors that are not of sufficient size and horsepower (typically three or fewer stages) to be in a separate station setting. Small compressors may individually have large horsepower, but are typically reciprocating engines on a pad by themselves at a wellsite or central facility. The large vs. small compressor distinction is important because large compressors tend to have separate vent lines and larger suction headers, discharge headers, and block valves, which lead to greater fugitive emissions. In the 1996 GRI/EPA Study, large gathering compressor stations were defined as those reported to United States Federal Energy Regulatory Commission (FERC) that had at least 16 stages of compression (5 compressors per station and an average of 3.3 stages per compressor).

Sour Gas Production natural gas that contains hydrogen sulfide and significant quantities of carbon dioxide. H2S and CO2 are often referred to as "sour gases".

Standard Conditions Standard conditions used to convert between mass and volumetric gas flow rates are 60°F and 1 atmosphere. This corresponds to 379 scf/lb-mol of gas.

Steam Turbine A turbine that produces electricity using steam as the driving fluid. Sweet Gas Natural gas that does not contain hydrogen sulfide [H2S] or significant quantities

of carbon dioxide [CO2]. Tanks Flashing Losses

The vaporization of volatile hydrocarbons when pressurized oil and condensate are dumped into a lower pressure (atmospheric) storage tank.

TDS Total Dissolved Solids - comprise inorganic salts (principally calcium, magnesium, potassium, sodium, bicarbonates, chlorides and sulfates) and some small amounts of organic matter that are dissolved in water.

Turbine A turbine, also called a gas turbine or combustion turbine, is a rotary engine that extracts energy from a flow of hot gas produced by combustion of gas in a stream of compressed air.

Turbine Valve Operators

Turbine valve operators release gas to the atmosphere across a small turbine similar to a gas starter turbine for a reciprocating compressor. The gas spins the blades, and the turbine shaft then turns gears that move the valve stem. A common application is as an isolation valve operator. These are intermittent bleed pnuematic devices.

Unprotected Steel Steel pipeline - bare and coated - that does not have cathodic protection. Vented Emissions Vented emissions are direct releases to the atmosphere resulting from equipment

design (dehydrator still vents, for example), regular process operations, maintenance activities, or emergency releases.


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Term Definition

Vented Gas Event A blowdown or purge of equipment for maintenance or emergency purposes that releases gas.

Vessel Equipment such as separators, dehydrators, and in-line heaters that contain process fluids (liquids and gas) under pressure.

Well (Gas) Completion

After well drilling operations are completed, the gas flow rate must be measured to size the production equipment. To measure the as flow rate, the gas from the well is routed through a meter and then vented to atmosphere or flared.

Well (Gas) Unloading/ Cleanup

Maintenance activity. Operators may routinely open some low flow rate gas wells to the atmosphere to remove salt water accumulation in the wellbore. Low-pressure natural gas wells can accumulate salt water and other fluids in the wellbore if the gas flow rate is not sufficient to lift out the free liquid. The well is isolated from the gathering pipeline and opened to a surface tank or pit. With no backpressure from the pipeline, gas flows at a higher rate and lifts out the water. The gas is released directly to the atmosphere.

Well Workover Well workovers pull the tubing from the well to repair corrosion or other downhole equipment problems. If the well has positive pressure at the surface, the well is "killed" first by replacing the gas and oil in the column with (heavier) water or mud, thus over-balancing the formation and stopping all oil and gas flow. A small amount of gas is released as the tubing is removed from the open surface casing.

wt% Abbreviation for weight percent.


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ATTACHMENT 2: CONVERSION TABLES

Common US Units

API Preferred SI Units

Other Conversions

1 kilogram

= 2.20462 pounds (lb) = 1000* grams (g)

1 pound (lb) = 0.4535924 kilograms = 453.5924 grams (g) 1 short ton (ton) = 907.1847 kilograms = 2000* pounds (lb)

Mass

1 metric tonne (tonne)

= 1000* kilograms = 2204.62 pounds (lb) = 1.10231 tons

1 cubic meter (m3) = 1000 *liters (L) = 35.3147 cubic feet (ft3) = 264.17 gallons

1 cubic foot (ft3) = 0.02831685 cubic meters (m3) = 28.31685 liters (L) = 7.4805 gallons

1 gallon (gal) 3.785412×10-3 cubic meters (m3) = 3.785412 liters (L)

Volume

1 barrel (bbl) = 0.1589873 cubic meters (m3) = 158.9873 liters (L) = 42* gallons (gal)

1 meter (m)

= 3.28084 feet = 6.213712×10-4 miles

1 inch (in) = 0.0254* meters (m) = 2.54* centimeters 1 foot (ft) = 0.3048* meters (m)

Length

1 mile = 1609.344* meters (m) = 1.609344* kilometers 1 Watt (W)

= 1* joule (J)/second = 9.47817×10-4 Btu/second = 1.341×10-3 horsepower (hp)

1 megawatt

106 Watts (W) = 1000* Joules/second = 1000* kilowatts (103 W)

Power

1 horsepower (hp) = 745.6999 Watts (W) = 0.7456999 kilowatts = 0.707 Btu/second

1 Joule (J)

= 9.47817×10-4 Btu = 2.778×10-7 kilowatt-hour = 0.7376 foot-poundsforce

1 horsepower-hour (hphr)

= 2.68452×106 Joules (J)

= 2544.43 Btu = 0.7457 kilowatt-hour

1 kilowatt-hour = 3.6*×106 Joules (J) = 3412.1 Btu = 1.341 horsepower-hours = 3600* kilo Joules

1 Btu = 1055.056 Joules (J) = 3.930×10-4 horsepower-hours = 2.931×10-4 kilowatt-hours

Energy

1 million Btu (106 Btu)

= 1.055056×109 Joules (J) = 1.055056 giga-Joules (109 J) = 293.1 kilowatt-hours

Pressure 1 kilo-Pascal (103 Pa) = 9.869233×10-3


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Common US Units

API Preferred SI Units

Other Conversions

atmosphere(atm) 1 atmosphere (atm) = 101.325* kilo-Pascals

(103 Pa) = 14.696 pounds per square inch (psi) = 760 millimeters mercury (mmHg) @ 0°C

1 pound per square inch (psi)

= 6.894757 kilo-Pascals (103 Pa) = 0.06804596 atmosphere (atm)

Heating Value

Mass basis: 1 Btu/pound

= 2326 Joules/kilogram (J/kg)

Volume basis:

1 Btu/cubic foot (Btu/ft3)

= 37,258.95 Joules/cubic meter (J/m3)

= 0.13368 Btu/gallon

1 kilogram/giga-Joule (kg/109 J)

= 2.32600 pound/million Btu (lb/106 Btu)

Emission Factor:

1 pound/million Btu (lb/106 Btu)

= 0.429923 kilograms/giga- Joule (kg/109 J)

= 0.429923 tonnes/tera-Joule (tonnes/1012 J) = 429.923 grams/giga-Joule (g/109 J)

Notes: * indicates the conversion factor is exact, any succeeding digits would be zeros. psig = Gauge pressure. psia = Absolute pressure (note psia = psig + atmospheric pressure). Temperature Conversions Degrees Fahrenheit (°F) = 1.8 (degrees C) + 32 Degrees Rankine (°R) = degrees F + 459.7 Degrees Celsius (°C) = (degrees F – 32)/1.8 Kelvin (K) = degrees C + 273.15


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ATTACHMENT 3: COMBUSTION EMISSION FACTORS

These tables are taken from API’s 2004 Compendium of GHG Emissions Methodologies. Table 1: CO2 Combustion Emission Factors (Fuel Basis) for Common Industry Fuel Types

Carbon Emission Factor from Original Source Document

CO2 Emission Factora, US Units

CO2 Emission Factora, SI Units Fuel

Emission Factor

Source tonnes/106 Btu (LHV)

tonnes/106 Btu(HHV)

tonnes/1012 J (LHV)

tonnes/1012 J (HHV)

Aviation Gas 18.87 MMTC/1015 Btu Table B1, EIA, 2002 0.0728 0.0692 69.0 65.6 Bitumen 22.0 tonne C/1012 J

(LHV) Table 1-1, IPCC, 1996 0.0851 0.0809 80.7 76.6

Coke (Coke Oven/ Gas Coke)

29.5 tonne C/1012 J (LHV)

Table 1-1, IPCC, 1996 0.1141 0.1084 108.2 102.8

Crude Oil 20.29 MMTC/1015 Btu Table B1, EIA, 2002 0.0783 0.0744 74.2 70.5 Diesel/Gas Oil 20.2 tonne C/1012 J

(LHV) Table 1-1, IPCC, 1996 0.0781 0.0742 74.1 70.4

Distillate Fuel 19.95 MMTC/1015 Btu Table B1, EIA, 2002 0.0770 0.0732 73.0 69.3 Electric Utility Coal 25.98 MMTC/1015 Btu Table B1, EIA, 2002 0.1003 0.0953 95.0 90.3 Ethanol 0.07 tonne CO2/106 Btu Texaco, 1999 0.0737 0.0700 69.8 66.3 Flexicoker Low Btu Gas

278 lb CO2/106 Btu (LHV)

Petroleum Industry Data

0.1261 0.1135 119.5 107.6

Fuel Oil #4

45.8 lb C/106 Btu Derived from fuel property data in Table 3-5

0.0802

0.0762 76.0 72.2

Jet Fuel

19.33 MMTC/1015 Btu Table B1, EIA, 2002 0.0746 0.0709 70.7 67.2

Kerosene/Aviation Kerosene

19.72 MMTC/1015 Btu

Table B1, EIA, 2002 0.0761 0.0723 72.1 68.5

Lignite 26.3 MMTC/1015 Btu Table B2, EIA, 2002 0.1015 0.0964 96.2 91.4 LPG 16.99 MMTC/1015 Btu Table B1, EIA, 2002 0.0656 0.0623 62.2 59.0


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CO2 Emission Factora, SI Units Fuel

Emission Factor

Source tonnes/106 Btu (LHV)

tonnes/106 Btu(HHV)

tonnes/1012 J (LHV)

tonnes/1012 J (HHV)

Butane 17.75 MMTC/1015 Btu Table B9, EIA, 2002 0.0685 0.0651 64.9 61.7 Ethane 16.25 MMTC/1015 Btu Table B9, EIA, 2002 0.0627 0.0596 59.4 56.5 Propane 17.2 MMTC/1015 Btu Table B9, EIA, 2002 0.0664 0.0631 62.9 59.8 Motor Gasoline (Petrol)


Naphtha (<104°F) 40.0 lb C/106 Btu Table 1.4-3, EIIP, 1999 0.0700 0.0665 66.4 63.1 Nat. Gas Liquids 17.2 tonne C/1012 J

(LHV) Table 1-1, IPCC, 1996 0.0665 0.0632 63.1 59.9

Natural Gas (Pipeline)b


Natural Gas (Flared) 14.92 MMTC/1015 Btu Table B1, EIA, 2002 0.0608 0.0547 57.6 51.9 Other Bituminous Coal

56.0 lb C/106 Btu Table 1.4-3, EIIP, 1999 0.0980 0.0931 92.9 88.3

Other Oil (>104°F) 44.0 lb C/106 Btu Table 1.4-3, EIIP, 1999 0.0770 0.0732 73.0 69.4 Pentanes Plus 40.2 lb C/106 Btu Table 1.4-3, EIIP, 1999 0.0704 0.0669 66.7 63.4 Petroleum Coke 27.85 MMTC/1015 Btu Table B1, EIA, 2002 0.1075 0.1021 101.9 96.8 Refinery Fuel Gas 139 lb CO2/106 Btu

(LHV) Petroleum Industry Data

0.0630 0.0567 59.8 53.8

Residual Fuel 21.49 MMTC/1015 Btu Table B1, EIA, 2002 0.0829 0.0788 78.6 74.7 Residual Oil #5 46.9 lb C/106 Btu Derived from fuel

property data in Table 3-5

0.0821

0.0780 77.8 73.9

Residual Oil #6 48.7 lb C/106 Btu Derived from fuel property data in Table 3-5

0.0853

0.0811 80.9 76.8

Special Naphtha 43.8 lb C/106 Btu Table 1.4-3, EIIP, 1999 0.0767 0.0728 72.7 69.0 Still Gas 38.6 lb C/106 Btu Table 1.4-3, EIIP, 1999 0.0713 0.0642 67.6 60.8 Sub-bituminous Coal 26.48 MMTC/1015 Btu Table B2, EIA, 2002 0.1022 0.0971 96.9 92.0 Unfinished Oils 44.6 lb C/106 Btu Table 1.4-3, EIIP, 1999 0.0781 0.0742 74.0 70.3


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a CO2 emission factors shown are based on the default Compendium assumption of 100% oxidation. Companies may wish to apply the fractional oxidation values provided in Table 4-3. To convert between higher and lower heating value emission factors, the assumed conversion for gaseous fuels is: (EF, HHV) = (0.9) × (EF, LHV), and for solids or liquids the assumed conversion is (EF, HHV) = (0.95) × (EF, LHV). b. Natural gas carbon coefficient is based on a weighted U.S. national average. Sources:

Energy Information Administration (EIA). Emissions of Greenhouse Gases in the United States 2001, DOE/EIA-0573(2001), December 2002.

Emission Inventory Improvement Program (EIIP). Guidance for Emissions Inventory Development, Volume VIII: Estimating Greenhouse Gas Emissions, EIIP

Greenhouse Gas Committee, October 1999. Intergovernmental Panel on Climate Change (IPCC). Greenhouse Gas Inventory Reference Manual: IPCC Guidelines for National

Greenhouse Gas Inventories, Volume 3, United Nations Environment Programme, the Organization for Economic Co-operation and Development, the International

Energy Agency, and the Intergovernmental Panel on Climate Change, 1996. Texaco Inc. Establishing Texaco’s Emission Inventory – A Guidance Document for Inventory Year 1998, March 2, 1999.

Table 2: CO2 Combustion Emission Factors (Fuel Basis) for Specialized Fuel Types



CO2 Emission Factora, SI Units

Fuel

Emission Factor

Source tonnes/106

Btu (LHV)

tonnes/106

Btu (HHV)

tonnes/1012 J (LHV)

tonnes/1012 J (HHV)

Anthracite 28.26 MMTC/1015 Btu Table B2, EIA, 2002 0.1091 0.1036 103.4 98.2 Asphalt and Road Oil 20.62 MMTC/1015 Btu Table B1, EIA, 2002 0.0796 0.0756 75.4 71.7 Industrial Coking Coal 25.63 MMTC/1015 Btu Table B1, EIA, 2002 0.0989 0.0940 93.8 89.1 Lubricants 20.24 MMTC/1015 Btu Table B1, EIA, 2002 0.0781 0.0742 74.0 70.3 Other Industrial Coal 25.74 MMTC/1015 Btu Table B1, EIA, 2002 0.0993 0.0944 94.2 89.5 Miscellaneous Petroleum Products and Crude

7.18E-04 tonne C/L Petroleum Industry Data

9.97E-03 tonnes CO2/gal 2.63E-03 tonnes CO2/L

Peat 28.9 tonne C/1012 J Table 1-1, IPCC, 1996 0.1118 0.1062 106.0 100.7


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CO2 Emission Factora, SI Units

Fuel

Emission Factor

Source tonnes/106

Btu (LHV)

tonnes/106

Btu (HHV)

tonnes/1012 J (LHV)

tonnes/1012 J (HHV)

(LHV) Petrochemical Feed 19.37 MMTC/1015 Btu Table B1, EIA, 2002 0.0748 0.0710 70.9 67.3 Residential/Commercial Coal

26.04 MMTC/1015 Btu

Table B1, EIA, 2002 0.1005 0.0955 95.3 90.5

Shale Oil 20.0 tonne C/1012 J (LHV)

Table 1-1, IPCC, 1996 0.0774 0.0735 73.3 69.7

Waxes and Miscellaneous


a CO2 emission factors shown are based on the default Compendium assumption of 100% oxidation. Companies may wish to apply the fractional oxidation values provided in Table 4-3. To convert between higher and lower heating value emission factors, the assumed conversion for gaseous fuels is: (EF, HHV) = (0.9) × (EF, LHV), and for solids or liquids the assumed conversion is (EF, HHV) = (0.95) × (EF, LHV). Sources:

Energy Information Administration (EIA). Emissions of Greenhouse Gases in the United States 2001, DOE/EIA-0573(2001), December 2002.

Intergovernmental Panel on Climate Change (IPCC). Greenhouse Gas Inventory Reference Manual: IPCC Guidelines for National Greenhouse Gas Inventories,

Volume 3, United Nations Environment Programme, the Organization for Economic Co-operation and Development, the International Energy Agency, and the Intergovernmental Panel on Climate Change, 1996.

OIL & GAS PRODUCTION PROTOCOL€¦ · Stirling Bates, British Columbia ... 4.2 Option 1: Reporting...

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