# Directive 060

Release date: May 01 , 2014
Effective date: August 15 , 2014 Replaces previous edition issued April 15 , 201 4 

## Upstream Petroleum Industry Flaring, Incinerating, and Venting

The Alberta Energy Regulator approved this directive on April 30 , 201 4

.
[< original signed by >]

Jim Ellis
President and Chief Executive Officer

Contents

1 Introduction

................................ ................................ ................................ ................................ ............ 5

1.1 Purpose of This Directive

................................ ................................ ................................ .............. 5
1.2 What’s New in This Edition

................................ ................................ ................................ ........... 5
1.3 Flaring, Incineration, and Venting Management Hierarchy and Framework

................................ 5

1.4 Access to Production Flaring, Incineration, and Venting Data

................................ ..................... 7
1.5 AER Requiremen ts and Compliance Assurance

................................ ................................ .......... 7
1.6 Notification through the AER Digital Data Submission System

................................ .................... 8

2 Solution Gas Management (Crude Oil / Bitumen Battery Flaring, Incineration, and Venting)

............... 9

2.1 Solution Gas Flaring Reduction Targets

................................ ................................ ....................... 9

2.2 Solution Gas Venting Reduction

................................ ................................ ................................ ... 9
2.3 Solution Gas Flaring and Venting Decision Tree

................................ ................................ ........ 10

2.4 Conservation at Crude Bitumen Batteries

................................ ................................ .................. 10
2.5 Conservation at Conventional Crude Oil Batteries

................................ ................................ ..... 11
2.6 General Conservation Requirements at all Crude Oil and Crude Bitumen Batteries

................. 12

2.7 Clustering

................................ ................................ ................................ ................................ .... 13
2.8 Power Generation Using Otherwise

- Flared/Vented Gas

................................ ............................ 13
2.9 Economic Evaluation of Gas Conservation

................................ ................................ ................ 14
2.9.1 Economic Evaluation Criteria

................................ ................................ ......................... 14
2.9.2 AER Economic Evaluation Audit Requirements

................................ ............................. 16
2.10 Public Involvement

................................ ................................ ................................ ...................... 17

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 1Alberta Energy Regulator

2.10.1 Public Information Package

................................ ................................ ............................ 17

2.11 Nonroutine Flaring, Incineration, and Venting at Solution Gas Conserving Facilities

................ 17

2.11.1 Limitations on Nonroutine Flaring, Incineration, and Venting During Outages at Solution Gas Conserving Facilities

................................ ................................ .............................. 18

2.11.2 Planned Shutdown (Turnaround) C onsiderations

................................ .......................... 20
2.11.3 Alternatives to Solution Gas Shut

- in Requirements

................................ ....................... 20

2.12 Royalty Treatment of Flared and Vented Gas

................................ ................................ ............ 20
2.13 Solution Gas Reporting Requirements and Data Access

................................ ........................... 21
2.13.1 Solution Gas Reporting Requirements

................................ ................................ ........... 21
2.13.2 Cooperating with Third Parties

................................ ................................ ....................... 21
3 Temporary and Well Test Flaring and Incinerating

................................ ................................ .............. 22
3.1 Temporary Flaring and Incinerating Decision Tree

................................ ................................ .... 22
3.2 Oil and Gas Well Test Flaring, Incinerating, and Venting Duration Limits

................................ .. 23
3.3 Temporary Flaring/Incineration Permits

................................ ................................ ...................... 25
3.3. 1 Conditions That Require a Temporary Flaring/Incineration Permit

................................ 26
3.3.2 Conditions That Do Not Require a Temporary Flaring/Incineration Permit

.................... 28
3.4 Flaring and Incineration Permits for Underbalanced Drilling

................................ ...................... 29
3.5 Permit Requirements for Temporary Flares and Incinerators

................................ .................... 29
3.5.1 General Permit Requirements

................................ ................................ ........................ 29
3.5.2 Requests to Exceed the Volume Allowance Threshold

................................ ................. 30
3.5.3 Blanket Flaring/Incineration Permits

................................ ................................ ............... 30
3.5.4 AER Review of Permit Requests

................................ ................................ .................... 32
3.6 Site

- Specific Requirements Related to Well Flaring and Incineration

................................ ........ 32
3.7 Temporary Facilities for In

- Line Tests

................................ ................................ ........................ 33
3.8 Notification Requirements

................................ ................................ ................................ ........... 34
3.8.1 Addressing Resident Concerns

................................ ................................ ...................... 36
3.8.2 AER Flaring/Incinerating/Venting Notice Form

................................ .............................. 37
3.9 Reporting Gas Well Test Data

................................ ................................ ................................ .... 37
3.10 Zero Flaring Agreements

................................ ................................ ................................ ............ 38

4 Gas Battery, Dehydrator, and Compressor Station Flaring, Incinerating, and Venting

........................ 39

4.1 Gas Battery, Dehydrator, and Compressor Station Flaring, Incinerating, and Venting Decision
Tree

................................ ................................ ................................ ................................ ............. 39

4.2 Notification

................................ ................................ ................................ ................................ .. 40
4.3 Reporting

................................ ................................ ................................ ................................ .... 40

5 Gas Plant Flaring, Incinerating, and Venting

................................ ................................ ........................ 42
5.1 Gas Plant Flaring, Incinerating, and Venting Decision Tree

................................ ....................... 42
5.2 Gas Plant Flaring/Incineration/Venting Volume Limits

................................ ............................... 43
5.3 Frequent Nonroutine Flaring/Incineration/Venting Events

................................ .......................... 44
5.4 Notification

................................ ................................ ................................ ................................ .. 45

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 2Alberta Energy Regulator

5.5 Measurement and Reporting

................................ ................................ ................................ ...... 45
6 Pipeline Flaring, Incinerating, and Venting

................................ ................................ ........................... 47
6.1 Pipeline Systems Flaring, Incineration, and Venting Decision Tree

................................ ........... 47
6.2 Additional Requirements for Gas Gathering Systems

................................ ................................ 48
6.3 Natural Gas Transmission Systems

................................ ................................ ........................... 49
6.4 Notification

................................ ................................ ................................ ................................ .. 49

7 Performance Requirements

................................ ................................ ................................ .................. 51

7.1 Conversion Efficiency

................................ ................................ ................................ ................. 52

7.1.1 Heating Value and Exit Velocity for Flares

................................ ................................ ..... 52

7.1.2 Minimum Residence Time and Exit Temperature for Incinerators

................................ . 53

7.2 Smoke Emissions

................................ ................................ ................................ ....................... 55
7.3 Ignition

................................ ................................ ................................ ................................ ........ 56
7.3.1 Requests to Extinguish Sour Flare Pilots at All Batteries

................................ ............... 56

7.4 Stack Design

................................ ................................ ................................ ............................... 57
7.5 Sour and Acid Gas Flaring/Incineration Procedures

................................ ................................ .. 58
7.6 Liquid Separation

................................ ................................ ................................ ........................ 59
7.6.1 Exceptions to Separator Requirements

................................ ................................ .......... 61

7.7 Backflash Control

................................ ................................ ................................ ........................ 61
7.8 Fl are and Incinerator Spacing Requirements

................................ ................................ ............. 62
7.9 Compliance with Fire Bans

................................ ................................ ................................ ......... 63
7.10 Noise

................................ ................................ ................................ ................................ ........... 63

7.11 Flare Pits

................................ ................................ ................................ ................................ ..... 63

7.12 Dispers ion Modelling Requirements for Sour and Acid Gas Combustion

................................ .. 64

7.12.1 Modelling Approach

................................ ................................ ................................ ........ 64

7.12.2 Individual Source

................................ ................................ ................................ ............ 65
7.12.3 SO 2 Cumulative Emissions Assessment

................................ ................................ ........ 66

7.12.4 Temporary and Well Test Flaring Dispersion Modelling

................................ ................ 66
7.12.5 Nonroutine Flaring Dispersion Modelling

................................ ................................ ....... 68
8 Venting and Fugitive Emissions Management Requirements

................................ .............................. 73
8.1 General Requirements

................................ ................................ ................................ ................ 73
8.2 Limitations of Venting Gas Containing H 2 S or Other Odorous Compounds

.............................. 74
8.3 Limitations on Venting Gas Containing Benzene

................................ ................................ ....... 75
8.4 Venting of Noncombustible Gas Mixtures

................................ ................................ .................. 75
8.5 Coalbed Methane Venting

................................ ................................ ................................ .......... 76
8.6 Fugitive Emissions Management

................................ ................................ ................................ 76
8.7 Requirements for the Peace River Area

................................ ................................ ..................... 76
8.7.1 Background

................................ ................................ ................................ .................... 76
8.7.2 Peace River Area Definition

................................ ................................ ........................... 76
8.7.3 Requirements

................................ ................................ ................................ ................. 77

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 3Alberta Energy Regulator

9 Sulphur Recovery Requirements and Sour Gas Combustion

................................ .............................. 78
9.1 Sulphur Recovery Exemption at Solution Gas Conservation Facilities

................................ ...... 78
10 Measurement and Reporting

................................ ................................ ................................ ................ 80
10.1 Flaring, Incineration, and Venting Records (Logs)

................................ ................................ ..... 80

Appendices Appendix 1 References and Contacts Cited

................................ ................................ ........................ 81 Appendix 2 Definitions of Terms as used in Directive 060

................................ ................................ .. 83 Appendix 3 Abbreviations

................................ ................................ ................................ .................... 86 Appendix 4 Background to Directive 060

................................ ................................ ............................. 87 Appendix 5 Information for Permit Request to Flare or Incinerate in Exceedance of Flared or Incinerated Volume Allowance Threshold (600, 400, or 200 10 3 m 3 Exceedance)

.......... 89 Appendix 6 Sour Gas Flaring/Incineration Data Summary Report

................................ ..................... 91 Appendix 7 Air Quality Management Plans for Temporary SO 2 Emissions

................................ ......... 93 Appendix 8 Screening Dispersion Modelling Using AER Spreadsheet

................................ ............... 95 Appendix 9 Resident Flaring/Venting/Incinerating Notification Sample Form

................................ ..... 99 Appendix 10 Agreement on Zero Flaring

................................ ................................ ............................. 100 Appendix 11 Request to Extinguish Sour Gas Flare Pilots

................................ ................................ .. 101

Fig ures Figure 1. Solution gas flaring/venting management framework (adapted from CASA)

..................... 7 Figure 2. Solution gas flaring/venting decision tree (adapted from CASA)

................................ ...... 10 Figure 3. Temporary flaring and incineration decision tree (adapted from CASA)

.......................... 23 Figu re 4. Temporary flaring/incineration permit process

................................ ................................ .. 27 Figure 5. Facility flaring, incinerating, and venting decision tree (adapted from CASA)

.................. 39 Figure 6. Facility flaring, incinerating, and venting decision tree (adapted from CASA)

.................. 43 Figure 7. Pipeline flaring, incinerating, and venting decision tree (adapted from CASA)

................ 48 Figure 8. Comprehensive management of the nonroutine flaring of sour gas

................................ . 69 Figure 9. Flare management strategy flowchart

................................ ................................ ............... 72 Figure 10. Peace River area

................................ ................................ ................................ .............. 77

Tables
Table 1. Limitations and notification requirements for nonroutine flaring, incinerati ng, and venting during solution gas conserving facility outage

................................ ................................ .. 19
Table 2. Temporary flaring, venting, and incineration notificati on requirements

............................ 35
Table 3. Major flaring event definition

................................ ................................ ............................. 44
Table 4. Cumulative facility or lease site benzene emission limits

................................ ................. 75

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 4Alberta Energy Regulator

1 Introduction

1.1 Purpose of This Directive

The Alberta Energy Regulator ( A ER) Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting contains the requirements for flaring, incinerating, and venting in Alberta

at all upstream petroleum industry wells and facilities

. Directive 060 requirements also apply to pipeline installation s that convey gas ( e .g., compressor stations, line heaters ) licensed by the A ER
in accordance with the Pipeline Act

. With the exception of oil sands mining schemes and operations,
Directive 060 applies to all schemes and operations approved under section 10 of the Oil Sands
Conservation Act ( OSCA ). Directive 060 does not apply to any processing plants approved under
section 11 of the OSCA

. Most of these requirements have been developed in consultation with the Clean Air Strategic
Alliance (CASA) to eliminate or reduce the potential and observed impacts of these activities and to ensure that public safety concerns and environmental impacts are addressed before beginning to flare, incinerate, or vent. Directive 060 requirements are also aligned to ensure compliance with
Alber ta Environment and Sustainable Resource Development’s (ESRD’s) Alberta Ambient Air Quality Objectives and Guidelines ( AAAQO )

. Note: Appendices have been included t o further the understandin g of Directive 060 requirements.
See a ppendix 1 for a list of references and contacts, a ppendix 2 for definitions of terms, and

a ppendix 3 for abbreviations.

1.2 What’s New in This Edition

In response to the March 31, 2014
, Decision 2014 ABAER 005: Report of Recommendations on
Odours and Emissions in the Peace River Area
, 1 table 1 and section 8.1 (5) have been revised and
section 8.7 has been added.

1.3 Flaring, Incinerati o n, and Venting Management Hierarchy and Framework

Flaring, incinerating, and venting are associated with a wide range of energy development activities
and operations , including disposal of gas associated with

• oil, bitumen, and gas well drilling ;

• oil, bitumen, and gas well completion or well servicing (wel l “cleanup”) ;

• gas well testing to estimate reserves and determine productivity ;

• routine oil or bitumen production (solution gas) ;

• planned nonroutine de pressuri zi ng of processing equipment and gas pipelines for maintenance ;

1 This decision and the AER’s response can be found on the AER website, aer.ca.

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 5Alberta Energy Regulator

• unplanned non rout ine depressuri zi ng of process equipment and gas pipelines due to process
upsets or emergency ; and

• oilfield waste management facilities.

Two multistakeholder teams from CASA have made recommendations for flaring, incinerati o n, and venting for the upstream petroleum industr y , and the A E R has based this directive on those recommendations (see appendix 4 for background on Directive 060 ).

In particular, the A ER has adopted CASA’s objective hierarchy and its framework for managing routine solution gas flares (see figure 1) and h as extended its application of the hierarchy to include flaring, incinerati o n, and venting of gas in general. 2

In accordance with the objective hierarchy, licensees, operators, and approval holders must evaluate the following three options:

• Can flaring, in cinerati o n, and venting be eliminated?

• Can flaring, incinerati o n, and venting be reduced?

• Will flaring, incinerati o n, and venting meet performance standards?

2 See CASA’s 1998 Management of Routine Solution Gas Flaring in Alberta: Rep ort and Recommendations of the Flaring Project

Team on its website www.casahome.org.

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 6Alberta Energy Regulator

Information Research

Implement Meet flare, incinerator, and vent performance requirements Objective Hierarchy

• Eliminate routine flaring, incinerating, and venting of unburned gases

• Reduce the volume of flared, incinerated, and vented gases

• Improve the efficiency of flare, incinerator, and vent systems Goal Eliminate Flaring, Incinerating, and Venting

Involve public

Get approvals

Evaluate management framework and future targets Eliminate Reduce Cannot reduce Reduce to target threshold volumes Apply decision tree Evaluate options

Figure 1. Solution g as f laring/ v

enting m anagement f ramework (adapted from CASA)

1.4 Access to Production Flaring, Incinerati o n, and Venting Data

The A ER reports flaring, incinerati o n, and venting volumes annually in the ST60B: Upstream Petroleum Industry f laring r eport on the A ER w ebsite www. aer .ca under Data & Publications : Statistical Reports.

The A ER also makes flaring , incinerati o n, and venting information available to licensees, operators, and approval holders in order to facilitate solution gas conservation and clustering opportunities, as
described in s ection 2.13

.
1.5 AER Requirements and Compliance Assurance

A ER requirements are those rules tha t a duty holder (e.g., licensee, operator, company, applicant,

approv al holder, or permit holder) as specified in legislation is required to follow. Terms such as “must” and “required” indicate a requirement, while terms such as “recommends” and “expects” indicate a recommended practice. In Directive 060 , the duty holder re sponsible for compliance with a given AER requirement is as follows:

• the licensee , in the case of a licen s ed well
, facilit y, or pipeline

• the operator , in the case of a facility that is exempt from a licence or approval

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 7Alberta Energy Regulator

• the approval holder , in the case of an oilfield waste management facility

Noncompliance with any risk

- asse ssed requirement will result in a response in accordance with the
latest edition of Directive 019: Compliance Assurance

. A list of noncompliant events is on the AER
website www.aer.ca under Data & Publications : Statistical Reports : ST108

.

The AER encourages all duty holders to be proactive by monitoring their compliance with AER requirements. If a duty holder identifies a noncompliance, it should inform the AER of the noncompliance for consideration under the AER v oluntary s elf

- d isclosure policy set out in
Directive 019

.

Further information on compliance assurance is on the AER w ebsite www.aer.ca under Safety & Compliance

.
1.6 Notification through the AER Digital Data Submission System

The licensee, operator, or approval holder must notify the appropriate AER f ield c entre before planned flaring, venting, or incinerati o n operations by completing and submitting an AER
f laring/ i ncinerati o n/ v enting n otice f orm within the Field Inspection System (FIS) 3 of the AER ’s Digital Data Submission ( DDS ) S ystem. The AER strongly encourages all licensees, operators, and approval holders to follow the FIS Web User Guide when completing and submitting this form to
avoid a Directive 019 response. A ny operations that may result in a public compla int must be called in to the appropriate AER f ield c entre’s 24

- hour emergency phone number (see a ppendix 1).

For questions on using FIS, contact the FIS a dministrator by e

- mail at FIS.Administrator@aer.ca or by tele phone at 403

- 297

- 4845.

3 FIS electronically records and monitors upstream oil and gas activities and installations. The AER Field Surveillance and

Operations Branch uses FIS to track notifications, incidents, and inspections, and to monitor compliance provincially.

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 8Alberta Energy Regulator

2 Solution Gas Management (Crude Oil / Bitumen Battery Flaring, Incinerati o n, and Venting)
The AER’s goal is to have the upstream petroleum industry continue to reduce the volume of solution gas routine ly flared, incinerate d, and vented. The AER expects that the upstream petroleum industry will pursue continuous improvement in reducing solution gas flaring
, incinerati o n, and venting in Alberta, and, in consultation with stakeholders, will monitor progress to determine the

ne ed for additional requirements to facilitate increased solution gas conservation.

Combustion of solution gas in incinerators is not considered an alternative to conservation.

For solution gas management and disposition reporting, incinerated gas must be r eported as flared.

Conservation is defined as the recovery of solution gas for use as fuel for production facilities, for other useful purposes (e.g., power generation), for sale, or for beneficial injection into an oil or gas pool (e.g., pressure mainten ance, enhanced oil recovery). Conservation opportunities are evaluated
as economic or uneconomic based on the criteria listed in s ection 2. 9

.
2.1 Solution Gas Flaring Reduction Targets

D irective 060 incorporates recommendations made by CASA in 2002, 2004, and 2005 to reduc e flaring

. 1) The Alberta solution gas flaring limit is 670 million cubic metres (10 6 m 3 ) per year (50 per cent of the revised 1996 baseline of 1340 10 6 m 3 /year).

2) If solution gas flaring exceeds the 670 10 6 m 3 limit in any year, the AER will impose reductions that will stipulate maximum solution gas flaring limits for individual operating sites based on analysis of the most current annual data so as to reduce flaring to less than 670 10 6 m 3 /year. For example, s olution gas flaring could be limited to a max imum of 500 thousand (10 3 ) m 3 /year at any one site.

2.2 Solution Gas Venting Reduction

The AER does not consider venting an acceptable alternative to flaring. If gas volumes are
sufficient to sustain stable combust ion, the gas must be burned (or conserved) (see s ection 8.1). If venting is the only feasible alternative, the requirements in section 8 must be met.

In 2005
, 59 per cent less s olution gas was vent ed than in 2000. The CASA Flaring and Venting Project Team considered solution gas venting in the report
, Gas Flaring and Venting in Alberta: Report and Recommendations for the Upstream Petroleum Industry by the Flaring and Venting Project Team , which it released in 2004

. 4 The AER accepts these recommendations and has incorporated them into Directive 060

.

4 This and other reports from this team are available on CASA’s w eb site www.casahome.org under Projects : Completed Pr ojects :

Flaring and Venting Implementation.

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 9Alberta Energy Regulator

2.3 Solution Gas Flaring and Venting Decision Tree

The AER adopted the s olution g as f laring/ v enting m anagement f ramework ( f igure 1) and endorses
the s olution g as f laring and v enting d ecision t ree p rocess ( f igure 2) as recommended by CASA. The
licensee or operator must apply this decision tree to all flaring or venting of more than 900 m 3 /day and be able to demonstrate how each element of the decision tree was considered and, where appropriate, implemented

.

Reduce flaring and venting Eliminate solution gas flaring and venting

Meet performance and venting and fugitive emissions management requirements ( see sections 7 and 8) Implement YES NO

NO Tests

• Public concern?

• Safety concern?

• Economic alternatives?

• Environmental impacts/benefits?

• YES

Figure 2. Solution g as f laring/ v

enting d ecision t ree (adapted from CASA)

2.4 Conservation at Crude Bitumen Batteries

F or the purpose of Directive 060

, crude bitumen battery is defined in a ppendix 2.

1) The licensee or operator of a multiwell bitumen site must build solution gas conservation lines to one common point on the lease as part of initial constru ction.

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 10Alberta Energy Regulator

2) For new bitumen wells, the test period (excluding completion and cleanup operations ) limit is
either six months or until combined flared and vented volumes at the site exceed a rolling average of 900 m 3 /day for any consecutive three

- month period
, whichever is less

. a) As soon as testing shows that combined flaring and venting volumes at t he site exceed
900 m 3 /day, conservation must be evaluated as described in s ection 2.9. Volumes are
calculated based on a three

- month rolling average.

b) If conservation is required, it must occur as quickly as possible and must not ex ten d for
more than six months after flow rate determination. Shorter tie

- in times must be pursued wherever possible. Wells must be shut in if the required conservation is not ope rational
within the timelines noted above.

3) If testing shows that combined flaring and venting volumes at the site do not exceed
900 m 3 /day, economic evaluation of solution gas conservation is not required and the well may proceed to produce without conserv ing the solution gas. The AER, however, still recommends economic evaluation of gas conservation, even when volumes are less than 900 m 3 /day

.
2.5 Conservation at Conventional Crude Oil Batteries

For the purpose of Directive 060

, crude oil battery is defined in appendix 2.

In general, for new oil wells the solution gas flaring during the test period must not extend beyond the time required to obtain data for the economic evaluation and for sizing conservation equipment. Any flaring for testing, cleanup, and comp letions must not exceed 72 hours (see section 3.2 for further details and extensions to time limits).

1) Upon completion of the testing period, if testing shows that combined flaring and venting
volumes at the site will exceed 900 m 3 /day, solution gas conserv ation must be evaluated as
described in s ection 2.9. The wells must be shut in at the end of the test period and remain shut in pending the results of the solution gas conservation evaluation process.

a) If the results of the solution gas conservation evaluat ion indicate that conservation is required, the wells must remain shut in until conservation is implemented.

b) If the results of the solution gas conservation evaluation indicate that conservation is not required and the AER has not directed that conservation be implemented, the wells may proceed to produce without conserving the solution gas.

2) If testing shows that combined flaring and venting volumes at the site do not exceed 900

m 3 /day and the AER has not directed that conservation be implemented , the wells may proceed to produce without conserving the solution gas. The AER, however, still recommends economic evaluation of gas conservation, even when volumes are less than 900 m 3 /day.

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 11Alberta Energy Regulator

2.6 General Conservation Requirements at all Crude Oil and Crude Bi tumen Batteries

These requirements apply to all oil and bitumen batteries unless otherwise specified.

1) The licensee or operator must conserve solution gas at all sites 5 where

a) the combined flaring and venting volume is greater than 900 m 3 /day per site 6 and the decision tree process and economic evaluation (see s ection 2.8) result in a n et p resent v alue (NPV) greater than

– Cdn$55 000;

b) the gas:oil ratio (GOR) is greater than 3000 m 3 /m 3

. A ll wells producing with a GOR greater
than 3000 m 3 /m 3 at any time during the life of the well must be shut in until the gas is conserved;

c) flared volumes are greater than 900 m 3 /day per site and the flare is within 500 m of a residence, regardless of economics; or

d) the AER directs the licensee, operator
, or ap proval holder to conserve solution gas, regardless of economics.

2) For any sites flaring or venting combined volumes greater than 900 m 3 per day and not conserving, conservation economics must be completed every 12 months using the criteria in
section 2.9.

3) The AER may still, on a case

- by

- case basis, require economic evaluations for sites that are flaring or venting combined volumes less than 900 m 3 /day and not conserving if it is believed that conservation may be feasible.

4) Conserving facilities must be desi gned for 95 per cent conservation with a minimum operating level of 90 per cent.

5) The licensee or operator may apply to discontinue conservation if annual operating expenses exceed annual revenue. See section 2.6 (6).

6) The licensee or operator must get approval from the AER Authorizations Operations Group to discontinue conservation once it has been implemented at any facility
, and must
a) complete a decision tree to evaluate alternatives to discontinuing conservation,

b) provide information on actual annual operating expenses and revenues,

c) notify the appropriate AER f ield c entre and residents within 500 m of its intention to discontinue conservation and initiate flaring or venting at a site, and

d) if conservation facilities are not operational
, comply with tabl e 1 until such time as approval from the AER Authorizations Operations Group to discontinue conservation is granted.

5 A site is defined as a single

- surface lease (pads counted as one lease) where gas is flared or vented.

6 Volumes are calculated based on a three

- month rolling average.

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 12Alberta Energy Regulator

2.7 Clustering

Clustering is defined as the practice of gathering the solution gas from several flares or vents at a common point for conservation. Solution gas is economic to conserve in some areas if licensees and
operators coordinate their efforts in an efficient, cooperative process to take advantage of combined gas volumes and economies of scale. Furthermore, solution gas conservation economics (see

s ection 2. 9 ) will be enhanced if conservation is incorporated into the i nitial planning of larger
multi well projects.

1) Licensees or operators of active production facilities operating within th ree kilometres (km) of each other or other appropriate oil and gas facilities (including pipelines) must evaluate clustering when evaluating solution gas conservation economics.

The AER may suspend production in the area under consideration until the economic assessment is complete.

The AER recommends that

a) all licensees and operators exchange production data and jointly consider clustering of solution gas production or regional gas conse rvation systems, and

b) the licensee or operator with the largest flare and vent volumes take the lead in coordinating the evaluation of conservation economics for the area.

2) The licensee or operator of a multiwell oil or bitumen development must assess conse rvation on a project or development area basis regardless of distance. Evaluations must address all potential gas vent and flare sources associated with the multiwell development.

a) The licensee or operator must incorporate provision for conservation at all stages of project development to optimize the opportunity for economic conservation of solution gas.

b) Applications under Directive 056: Energy Development Applications and Schedul es for multiwell oil or bitumen developments must include a summary of the gas conservation evaluation and a description of the licensee or operator’s related project plans.

The AER may suspend production at any facility until the economic assessment is co mplete.

2.8 Power Generation Using Otherwise

- Flared/Vented Gas

Power generation is a means of conserving solution gas. The operator or licensee should consider power generation if distribution lines are nearby or if onsite power is required. The AER may
invest igate flared or vent ed volumes as low as 500 m 3 /day if it appears that gas is stable

. 1) Approval of electrical power plants by the Alberta Utilities Commission is required under the Hydro and Electric Energy Act

.

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 13Alberta Energy Regulator

Alberta Utilities Co mmission Rule 007: Applications for Power Plants, Substations, Transmission Lines, and Industrial System Designations provides application requirements for power plant applications and includes a simplified application form for electric power generating pr ojects of 1.0 megawatt (MW) or smaller

. 2) Power plants with a generation capacity greater than 1.0 MW at peak load require approval
issued by ESRD under the Environmental Protection and Enhancement Act ( EPEA )

.
2.9 Economic Evaluation of Gas Conservation

If conservation is determined to be economic by any method using the economic decision tree process, the gas must be conserved

. 1) Methods of conservation must incl ude pipeline to sales, fuel, power generation, pressure maintenance, or any other method that may become available.

2) Licensees or operators must update the conservation economics for any sites that are flaring or venting combined volumes of more than 900 m 3 /day and that are not conserving every 12 months. This information, with the responsible individual named and the document dated, is to be kept on file by the licensee or operator and must be provided to the AER upon request. Evaluation information may be stored at a central location rather than on site.

3) A licensee or operator must provide the evaluation to the AER within five working days of receipt of a request.

4) If the AER Authorizations Operations Group determines that the economic evaluation process
has n ot been completed in accordance with Directive 060 requirements, the licensee or operator will be subject to a response in accordance with Directive 019 , which may include susp ension of facility operations.

2.9.1 Economic Evaluation Criteria Economic evaluations of gas conservation must use the criteria listed below

. The l icensee or operator must consider the most economically feasible option in provi ding detailed economics. Specific AER economic evaluation submission requirements are listed in s ection 2. 9 .2.

1) Evaluations must be completed on a before

- tax basis, and must exclude contingency and
overhead costs.

2) Conservation economics must be evaluated on a royalties

- in basis (paying roya lties) for incremental gas and gas by

- products that would otherwise be flared or vented. If the economic
evaluation results in an NPV less than

– Cdn$55 000, the licensee or operator must re

- evaluate the gas conservation project on a royalties

- out basis (n ot paying royalties). If the evaluation
results in an NPV

– Cdn$55 000 or more, the licensee or operator must proceed with the conservation project and may then apply to Alberta Energy for an “otherwise flared solution gas” royalty waiver.

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 14Alberta Energy Regulator

3) Price forecasts used in the evaluation of solution gas conservation projects (gas gathered, processed, and sold to market) must use the most recent version of commodity price forecast
from GLJ Petroleum Consultants Limited . Gas prices must be obtained from the “Natural Gas and Sulphur Price Forecast Table” in the “ARP” column ($Cdn/MMBtu). Condensate prices
must be obtained from the “Crude Oil and Natural Gas Liquids Table” in the “Alberta Natural Gas Liquids Section

– Edmonton Pentanes Plus” column ($Cdn/bbl).

4) Price forecasts for power generation projects must reflect the most recent 12

- month rolling average of the pool monthly summary pri ce as published by the Alberta Electric System Operator (AESO). 7 The power price must be escalated at the long

- term inflation rate (see item 9). Alternatively, the cost of the power displaced at the site may be used.

5) The licensee or operator must have information to support the remaining reserves calculation and the production forecast (including planned drilling programs and pressure maintenance schemes). The production forecast must be reviewed by a qualified technical professional who
is a member of the association as defined in the Engineering and Geoscience Professions Act

. 8

6) The licensee or operator must have a detailed breakdown of capital costs showing equipment, material, installati on, and engineering costs. Capit al costs must be approved

- for

- expenditure quality numbers based on selection of appropriate technology. Any capital costs incurred before the initiation of the solution gas project ( i.e., sunk costs) must not be included in the analysis; only future capita l costs related to solution gas conservation may be included.

a) For new flares, if capital cost savings result from implementing gas conservation
, such as any equipment that would otherwise be required , the flares must be considered in the
conservation econ omic evaluation and subtracted from the overall cost of the conservation infrastructure in evaluating the economics of solution gas tie

- in.

b) Salvage value of gas conservation infrastructure must be included as project revenue in the year the value would be realized (e.g., transfer of a gas compressor from one conservation project at the end of that project’s life to another conservation project). The salvage value must be a reasonable market value estimate of the equipment and not a depreciated value
from a taxation perspective.

7) The incremental annual operating costs for the gas conservation project, including gas gathering and processing fees, are to be assumed as up to 10 per cent of the initial capital cost of installing the conservation facilities. If the gas contains 10 moles per kilomole (mol/kmol) hydrogen sulphide (H 2 S) or more, the incremental annual operating costs for the solution gas project may be assumed to be up to 20 per cent of the capital cost to initially install the
conservation facilities.

7 T he most recent 12

- month rolling averag e of the p ool m onthly s ummary price can be found on the AESO w ebsite at

http://ets.aeso.ca

. 8 Engineering and Geoscience Professions Act , RSA 2000 c. E

- 11, as amended

.

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 15Alberta Energy Regulator

a) The economic evaluation must account for any cost savings, such as reduced trucking, equipment rental, and the licensee ’s or operator ’s costs that may result from the conservation project.

8) The incremental annual operating costs for power generation projects are to be assumed as up
to 10 per cent of the initial capital cost of installing the generation facilities. Standby fees may be calculated in addition to this 10 per cent allowance.

9) The most recent infl ation rate must be based on the current economic trends report published quarterly on the Government of Alberta, Treasury Board and Finance, Economy and Statistics
website.

10) The discount rate must be equal to the prime lending rate of ATB Financial on loans payable in Canadian dollars plus 3 per cent, based on the month preceding the month the evaluation was
conducted in. T his rate is reviewed periodically by the AER and will be revised if the cost of capital for the oil and gas industry changes significantly.

11) A solution gas conservation project is considered economic, and the gas must be conserved , if the economics of gas c onservation generates an NPV before

- tax of more than

– Cdn$ 55 000

. a) The NPV is defined as the sum of discounted, annual, before

- tax cash flows for the economic life of the solution gas conservation project, where each annual before

- tax cash
flow is net of t hat year’s conserving project capital investment, if any.

b) The economic life of a conservation project is defined as the period from the start of the project to the time when annual expenses exceed annual revenue. Note that s ection 2. 6 (6) provides a process whereby the licensee or operator may apply to discontinue conservation if annual expenses exceed annual revenue.

12) If a solution gas conservation project has an NPV less than

– Cdn$ 55 000 and is therefore
considered uneconomic on its initial evaluation, the project economics must be

re

- evaluated annually (within 12 months of the latest evaluation) using updated prices, costs,
and forecasts.

2.9.2 AER Economic Evaluation Audit Requirements
1) Economic evaluation audit packages submitted to the AER Authorizations Operations Group upon request must contain the following information in SI (i nternational system of units) units :
a) detailed capital and operating cost schedules as set out in s ections 2. 9 .1( 6 ) and 2. 9 .1( 7 )

b) oil and gas reserves calculations and supporting i nformation (including a discussion of planned drilling programs and pressure maintenance schemes)

c) a production forecast for both the oil and gas streams and the economic limit (date and production rates) of the project based on the oil production rate (inc luding planned drilling programs and pressure maintenance schemes)

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 16Alberta Energy Regulator

d) a copy of the gas analysis from the project or a representative analog complete with gas heating value and gas liquid yields

e) documentation of alternatives that were considered in order to e liminate or reduce flaring, incineration, or venting, how they were evaluated, and the outcome of the evaluation

f) documentation of compliance with the requirements listed in s ections 7 and 8

2.10 Public Involvement

Licensees or operators with continuous solution gas flares, incinerators, or vents are expected to respond to questions or concerns raised by the public in relation to activities rela ted to the flaring,
incineration , and venting of solution gas at upstream petroleum industry facilities. To help respond to the public, public information packages should be prepared and provided. Licensees or operators must also meet consultation and notification requirements in Directive 056

. 1) The licensee or operator must notify residents, the appropriate AER field c entre , and ESRD of nonroutine flaring, incineration , and venting at production and processi ng facilities, as described in section 2.11, t able 1.

2) The licensee or operator must meet minimum spacing requirements (s ee section 7.8).

2.10.1 Public Information Package

As a minimum, public information packages should include the following:

1) the definition of solution gas, and information on its conservation and use

2) an explanation of solution gas flaring, incineration, and venting management options and the decision tree proces s
3) a summary of analysis completed to determine that flaring, incineration, or venting is needed

4) information on general flare/vent performance requirements and reduction targets

5) descriptions of specific actions the licensee or operator will take to eliminat e or reduce flaring, incineration, or venting or improve the efficiency of the flare, incinerator, or vent source based
on the evaluation

6) a list of industry, AER , and government contacts that are related to public consultation and relevant to the project

2.11 N onroutine Flaring, Incinerati o n, and Venting at Solution Gas Conserving Facilities

The licensee or operator must minimize nonroutine flaring, incinerati o n, and venting during upsets
and outages of solution gas conserving facilities.

T he AER also recommends that the licensee or operator contact the appropriate AER f ield c entre
for recommendations for minimiz ing solution gas flaring during outages at conserving facilit ies

.

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 17Alberta Energy Regulator

2.11.1 Limitations on Nonroutine Flaring, Incinerati o n, and Venting During Outages a t Solution Gas Conserving Facilit ies
1) Production operations must be managed to control nonroutine flaring, incineration, and venting of normally conserved solution gas in accordance with table 1 below.

2) Table 1 does not apply to nonassociated gas (the percen tage cutbacks listed in table 1 apply to solution gas only). All nonassociated gas must be shut in during facility outages.

3) Emergency or plant upset shut in of production and reduction of solution gas inlet requirements in table 1 do not apply to thermal i n

- situ production.

4) The licensee or operator must provide notification as required in table 1.

5) If there is a restriction to the plant inlet, the AER recommends that solution gas processing have priority over the processing of nonassociated gas in order to limit the unnecessary flaring of solution gas.

6) The AER recommends that wells with the highest GOR be the first to be shut in during facility outages and cutbacks.

7) Provided the overall required percentage reduction in solution gas production is achieved, i t is not necessary to implement equal reductions at all locations upstream of the conserving facility
outage

. a) When multiple licensees or operators are involved, they may determine how to best implement the overall required production reductions. If an agreement cannot be reac hed,
each licensee and /or operator must reduce production as specified in t able 1.

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 18Alberta Energy Regulator

Table 1. Limitations and notification requirements for nonroutine flaring, incinerating, and venting during solution gas conserving facility 1 outage Shutdown category Duration Operational requirements Partial equipment outages < 5 days Unless directed by the AER to flare, incinerate

, or conserve all casing gas and tank

- top gas, s hut

- in of production is not required for equipment outages last ing less than 5 days that involve sm all volumes of gas (e.g., storage tank vapour recovery unit repair). This allowance is limited to a maximum of 2 10 3 m 3 per day subject to limitation on venting as defined in section 8. If the event is ≥ 5 days, the operator must meet requirements stated b elow (planned shutdown category, > 4 hours duration)

Planned < 4 hours The licensee or operator must make all reasonable efforts 2 to reduce battery or solution gas plant inlet gas volumes by 50 per cent of average daily solution gas production over the preceding 30

- day period.

> 4 hours The licensee or operator must reduce battery or solution gas plant inlet gas volumes by 75 per cent of average daily solution gas production over the preceding 30

- day period and meet the following requirements:

• Solution gas must not be flared from wells that have an H 2 S content greater than 10 per cent.

• Production may be sustained at rates that will provide sufficient throughput to keep equipment operating safely and within minimum design turndown range. If this volume is greater than 25 per cent of the average daily solution gas production, a variance must be obtained from the appropriate AER field centre (see section 2.11.3).

• Residents within 500 m must be notified 3 at least 24 hours before the planned flaring e vent.

• The AER also recommends that the licensee or operator notify individuals who have identified themselves to the licensee or operator as being sensitive to or interested in emissions from the facility.

• The appropriate AER field centre must be notified 4 24 to 72 hours in advance if the event meets reporting requirements identified in IL 98

- 01
, 4 section 4.4. Emergency 6 or plant upset < 4 hours No reduction in the plant inlet is required.

> 4 hours The licensee or operator must reduce battery or solution gas plant inlet gas volumes by 75 per cent of average daily solution gas production over the preceding 30

- day period and must meet the following requirements:

• Solution gas must not be flared from wells that have an H 2 S content greater than 10 per cent.

• Production may be sustained at rates that will provide sufficient throughput to keep equipment operating safely and within minimum design turndown range. If this volume is greater than 25 per cent of the average daily production, a variance must be obtained from the appropriate AER field centre (see section 2.11.3).

• Residents within 500 m must be notified 4 without delay about the flaring event.

• The AER also recomme nds that the licensee or operator notify individuals who have identified themselves to the licensee or operator as being sensitive to or interested in emissions from the facility.

• The appropriate AER field centre 3 must be notified without delay if the even t meets reporting requirements identified in IL 98

- 01
, 5 section 4.4. Repeat nonroutine flaring 7 The licensee or operator must investigate causes of repeat nonroutine flaring or venting and take steps to eliminate or reduce the frequency of such incidents.

1 For the definition of conserving facility, see a ppendix 2

. 2 Notwithstanding solution gas reduction requirements listed in t able 1, if a sour or acid gas flare or incinerator stack is not

designed to meet the one

- hour AAAQO for sulphur dioxide (SO 2 ) under high flow

- rate conditions, action must be taken immediately to reduce gas to a rate compliant with the AAAQO (see s ection 7 .12.5 ).

3 The appropriate AER f ield c entre must be notified through the AER f ield i nspection s ystem in t he DDS System. In situations

where limits have been exceeded

, the appropriate AER f ield c entre must be contacted by telephone before DDS is notifi ed

. 4 Refer to section 3.8 (4) for r esident notification requirements

5 IL 98

- 01: A Memorandum of Understanding Between Alberta Environmental Protection and the Alberta Energy and Utilities Board

Regarding Coordination of Release Notification Requirements and Subseq uent Regulatory Response

. 6 Emergency shutdowns or plant upsets are unplanned events at the battery site or at facilities downstream of the battery that

cause s the nonroutine flaring at the battery.

7 Repeat nonroutine flares are defined a s recurring events of similar cause at a conserving facility during a 30

- day period.

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 19Alberta Energy Regulator

2.11.2 Planned Shutdown (Turnaround) Considerations
1) A l icensee or operator must evaluate and implement appropriate measures to reduce solution gas flaring, incinerati o n, and vent ing during a facility turnaround or planned shutdown

. Alternatives that minimize impacts of planned shutdowns include

a) delivering solution gas to a nearby gas plant or facility that is not on turnaround;

b) scheduling maintenance at related oil facilities to c oincide with the gas plant turnaround;

c) injecting solution gas into the gas cap of an oil pool or into a gas reservoir and producing it back when the gas plant is back on stream ( see Directive 065: Resources Applications for Conventional Oil and Gas Reservoirs ); and

d) communicating with well, battery, and gas plant licensees or operators to ensure that nonroutine solution gas flaring, incinerati o n, and venting are minimized.

2.11.3 Alternatives to Solution Gas Shut

- in Requirements The appropriate AER f ield c entre will consider alternatives to the shut

- in requirements listed in this directive for solution gas. This will be done only if the licensee or operator can demonstrate
that shu tting in a well or a group of wells may cause damage to well equipment or permanent reduction in productivity or if shutting in is impractical due to the remoteness of facilities. In these special cases, the licensee or operator must consult with the AER f ield c entre about
alternatives to shut

- in for a particular gas plant or battery.
1) A licensee or operator must plan for outages. If an alternative to t able 1 is justified, the AER recommends that the licensee or operator submit a written request to the AER f ield c entre a t
least 30 days before a planned shutdown explaining the alternative requested and giving supporting reasons for the request. The AER recommends that wherever possible, contact
with the AER f ield c entre not be deferred until an actual outage o ccurs.

2.12 Royalty Treatment of Flared and Vented Gas

In December 1998, the Government of Alberta created the Otherwise Flared Solution Gas Royalty Waiver Program to encourage the productive use of solution gas currently being flared. For more information, see Alberta Energy Information Letter (IL) 99

- 19: Otherwise Flared Solution Gas Royalty Waiver Program available on Alberta Energy’s website www.energy.alberta.ca

. 9

8 http://www.energy.alberta.ca/NaturalGas/1139.asp

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 20Alberta Energy Regulator

The program is summarized as follows:

• The Alberta Department of Energy has developed criteria for ensur ing that when gas can be economically conserved, it does not receive a royalty waiver.

• The program covers all methods of conserving solution gas.

2.13 Solution Gas Reporting Requirements and Data Access

2.13.1 Solution Gas Reporting Requirements
1) Flared, incinerated, and vented solution gas must be reported monthly through PETRINEX (Canada’s Petroleum Information Network) as described in s ection 10

. a) A licensee or op erator must report all new oil well production, including the test period, and obtain a battery code for any new oil wells before production, including flaring, can be reported (see Directive 017: Measurement Requirements for Oil and Gas Operations ).

2.13.2 Cooperating with Third Parties

The AER recomme nds that the licensee or operator cooperate with qualified third parties attempting to conserve solution gas through open market or clustering efforts by providing nonconfidential information, such as gas analyses, flared and vented volumes, pressures, and other relevant data, on a timely basis (also see s ection 2. 7 ).

In cases where conservation is determined by the licensee or operator to be uneconomic (as per

s ection 2.8) but where a third party is able to conserve the gas, the AER recommends that the
licensee or operator either conserve the gas or make the gas available at the lease boundary at no charge within three months of a request for the gas. It would be understood that this gas may be provided without processing or compression, and the third

- pa rty organization must not affect the upstream operations.

Any third party request ing data from a licensee or operator must be technically qualified and have a reasonable expectation of proceeding with the gas conservation project. Third parties
must also c omply with all relevant AER requirements.

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 21Alberta Energy Regulator

3 Temporary and Well Test Flaring and Incinerating This section applies to temporary flaring and incinerati o n activities. These activities include well testing, well cleanup, well servicing, sour gas pipeline (as d efined in Directive 056 ) blowdown, coalbed methane well testing, underbalanced drilling, maintenance blowdowns, and emergency blowdowns through temporary or permanent flare or in cinerator equipment.

Unplanned nonroutine flaring and incinerating (e.g., process upsets, emergencies) do not require a temporary permit. Planned nonroutine flaring and incinerati o n events (e.g., maintenance blowdowns, pipeline depressur iz ing, turnarounds ) do require a temporary flaring or incinerati o n permit, as stated in s ection 3.3.

The AER does not consider venting an acceptable alternative to flaring or incineration . If gas volumes are sufficient to sustain stable combustion, the gas must be burned or conserved (see

s ection 8.1(5) for specifics on well test venting). If venting is the only feasible alternative, it must meet the requirements in s ection 8.

3.1 Temporary Fl aring and Incinerating Decision Tree

1) Licensees must use the temporary flaring and incinerating decision tree process (figure 3) to evaluate all opportunities to eliminate or reduce flaring and incineration, regardless of
volume.

2) Licensees must evaluate o pportunities to use existing gas gathering systems before beginning temporary maintenance, well cleanup, or testing operations (i.e., “in

- line testing”).
In

- line testing must be done when economic and feasible to do so. Information on the
evaluation of the most feasible option (e.g., closest potential tie

- in location) must be provided with permit requests (section 3.5.1). The AER recommends that in

- line testing be

u s ed in situations where

a) suitable infrastructure exists in proximity to the well and can be co nnected at moderate

cost and where use of the infrastructure does not compromise integrity , or
b) sufficient productivity information is known about a development well s o that connecting pipelines can be built with minimal financial risk before testing.

3) If in

- line testing is not possible , licensees must design completions and well testing programs to minimize emissions while ensuring technically sound well completion and acquisition of sufficient reservoir and productivity information for future development
decisions. Directive 040: Pressure and Deliverability Testing Oil and Gas Wells must be consulted on the minimum pressure and deliverability requirements for well testing and on the recommended practices in order to ensure that the appropriate information is obtained for conservation and pool management purposes in addition to the requirements of this d irective.

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 22Alberta Energy Regulator

Licensees m ust use appropriate equipment and design temporary (maintenance, well completion, or test) programs to comply with performance requirements in s ection 7 and the AAAQO

.

Reduce flaring/incinerating Avoid well test/completion flaring incinerating

Meet performance

requirements Implement YES NO

NO Tests

• Nonflaring opportunities

- in

- line testing

- other evaluation techniques

• Economic risk reduction framework?

• Environmental or safety impacts?

• Public concern?

Reduction opportunities

• Justify needed volumes ( Directive 060 , section 3.5.2)

• Minimize cleanup flaring/incineration

• Improve data interpretation, minimize

test volumes

• YES

1. Performance requirements ( Directive 060 , section 7) 2. Public consultation requirements ( Directive 056 )

*In

- line testing may still involve very small quantities of flared or incinerated gas. Figure 3. Temporary f laring and i ncinerati o n d ecision t ree (adapted from CASA )

3.2 Oil and Gas Well Test Flaring, Incinerating

, and Venting Duration Limits

1) These time limits are per zone , are nonconsecutive
, and do not include shut

- in time. These periods include flaring, incinerat ing
, and venting during cleanup, completion, workover
, and testing. Licensees and operators must not exceed the following flaring, incinerating
, and venting time limits :
a) c rude oil wells/sites : 10 72 hours

b) bitumen wells/sites: until flow rates exceed an avera ge of 900 m 3 /day for any
consecutive three

- month period, not to exceed six months. See section 2.4.

c) gas (nonassociated, noncoalbed methane) wells: 72 hours

10 A site is defined as a single

- surface lease (pads counted as one lease) where gas is flared or vented.

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 23Alberta Energy Regulator

d) dry coalbed methane development wells (producing less than 1 m 3 of water per operating day): 120 hou rs
e) dry coalbed methane nondevelopment wells (producing less than 1 m 3 of water per operating day): 336 hours

f) wet coalbed methane wells (producing more than 1 m 3 of water per operating day): see Section 3.2(7) below

2) Extensions to the time limits listed in ( 1 ) (a), (c), (d)
, and (e) above are allowed only if

a) cleanup of the wellbore is not complete

. Cleanup is considered complete when sand, proppant, or acid is no longer produced or when the gas composition meets the minimum pipeline specifications for the nea rest pipeline that could accept the gas ;
b) stabilized flow has not been reached

. Refer to Directive 040: Pressure and Deliverability Testing Oil and Gas Wells , section 4.3
, and Directive 034: Gas Well Testing, Theory and Practice , section 7.1 ; or
c) there have been mechanical problems with the well.

3) For extensions to the time limits stated in (1)(b) and (f), licensees must request approval from the AER as described in (5) below.

4) The licensee must document these reasons for extension and keep the information on file for review and/or audit by the AER field c entre when requested. The licensee is not required to
ask permission to extend the flaring/incinerati o n beyond the specified time limit listed in ( 1)(a), (c), (d), or (e) if the reason matches those listed in (2)(a), (b), or (c), but must notify the appropriate AER field centre in advance through the DDS system as soon as the licensee recognizes that the time limit will be exceeded. The licensee must include reasons for the extension and the duration of the flaring, incinerating, and venting.

a) If an audited licensee fails to jus tify the need to exceed the time limitation to the AER
f ield c entre’s satisfaction, enforcement action will apply.

5) If more time for well test flaring
, incinerati o n , or venting is needed for reasons other than those listed above, the AER must be contacted for approval to continue as soon as possible, and no later than the end of the specified period.

6) If a temporary flaring/incineration permit has been issued, the volume allowed in the permit will take precedence over the time limit described in (1) above.

7) W hen well test information indicates that cleanup is complete and the well flow is stabilized and all other AER requirements (e.g., AER Directive 040 ) are met, flaring/incineratio n/ venting must be discontinued, even if the time limit or the flaring/incineration permit volume has not been reached. This requirement does not apply to bitumen or wet coalbed methane

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 24Alberta Energy Regulator

wells. Timing requirements for bitumen are in section 2.4(2). Timing r equirements for wet coalbed methane wells are in (8) below.

8) For wet coalbed methane wells producing more than 1 m 3 of water per operating day, flaring/incinerating or venting must cease (gas must be conserved) within six months of gas production for an ind ividual well exceeding a cumulative total of 100 10 3 m 3 for any
consecutive three

- month period (a bout 1100 m 3 /day). Shorter tie

- in periods must be pursued wherever possible.

a) Licensees must notify the AER Authorizations Operations Group as soon as the cumulative total gas production exceeds 100 10 3 m 3 for any consecutive three

- month period at a wet coalbed methane well that is flaring
, incinerating
, or venting.

b) For wet coalbed methane wells that do not trigger the requirement above ( i.e., 100 10 3

m 3 in 3 months)
, flaring
, incinerati o n , and venting are limited to the lesser of

i) a total period of 18 months
, includin g the time to tie in the well, or
ii) a total cumulative volume of 400 10 3 m 3 for t ier 2 (development) wells or 600 10 3 m 3

for t ier 1 (other) well s per zone tested (see section 3.3.1[2])

. Wells already tied in

are treated as t ier 3 and allowed a maximum cumulative flare
, incineration
, and vent
volume of 200 10 3 m 3

. c) If additional flaring/incinerati o n or venting durations or volumes are needed to test a
coalbed methane well producing more than 1 m 3 of water per operating day, the licensee must make a written request to the AER Authorizations Operations Group as early as possible and in no ca se later t han the end of the 18

- month or volume allowance flare/incineration or vent period. Any request must include the reasons for the extension. Extensions may be granted to allow for additional flaring/ incineration/vent duration or
volume for reservoir evaluat ions or if other special circumstances warrant.

3.3 Temporary Flaring/Incinerati o n Permits

Figure 4 depict s the t emporary f laring/ i ncinerati o n p ermit p rocess.

The AER may suspend well flaring or incineration for noncompliance with conditions of the permit. Th e licensee must comply with the conditions of the temporary flaring permit.

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 25Alberta Energy Regulator

3.3.1 Conditions That Require a Temporary Flaring/Incinerati o n Permit Note that an exemption for flaring small volumes of sour gas is found in s ection 3.3.2(2).

1) Licensees m ust obtain a permit to flare or incinerate sour gas containing more than
50 mol/kmol H 2 S (5 per cent ) or sour gas from any well classified as a critical sour well.

a) If operations result in H 2 S concentrations that are higher than concentrations at the well (e

. g. , flaring gas from tanks), the composition of the gas to be burned must be
determined in order to establish whether a permit is required. This composition must also be used in any required dispersion modelling.

b) If supplemental fuel gas is used, the resultin g composition must be used for dispersion modelling. However, the gas composition from the source is still used as the basis for determining whether a permit is required.

2) Licensees must obtain a permit for temporary flaring or incinerati o n of natural gas if gas well test volumes exceed the v olume a llowance t hreshold. This is based on the volume of gas flowed back from the well ( and does not include fuel gas added , and volumes from vented nitrogen or carbon dioxide used in fracturing fluid )

. a) The v olume a llo wance t hreshold is defined in three tiers based on the volume of raw gas flowed back from the well (not including fuel gas added and carbon dioxide [CO 2 ] or nitrogen used for hydraulic fracturing). These volumes apply to gas well tests only:

i) Tier 1 ≤ 600 10 3 m 3 : applies to wells that have not been tied in and have a Lahee
classification of n ew f ield w ildcat (NFW), n ew p ool w ildcat (NPW), d eeper p ool

t est (DPT), or o utpost (OUT).

ii) Tier 2 ≤ 400 10 3 m 3 : applies to wells that have not been tied in and have been assigned a Lahee classification (including d evelopment) not listed in the t ier 1 allowance (excluding r e

- entry [REN] and e xperimental [EX] wells. See (b) and (c) below).

iii) Tier 3 ≤ 200 10 3 m 3 : appl ies to any well that has been tied in to facilities appropriately designed to handle production from the formation being tested (e.g., sweet versus sour service).
All requested volumes must be justified and may be questioned by the AER.

b) The v olume a llowan ce t hreshold for a r e

- entry well is the same tier allowance (1, 2, or 3) that applied to the well before it was reclassified as re

- entry.
c) For wells with a Lahee classification of e xperimental, the v olume a llowance t hreshold is the same tier allowance (1, 2, or 3) that applied to the well before it was reclassified as

e xperimental or that normally would have applied to the well had it not been classified

as e xperimental.

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 26Alberta Energy Regulator

Figure 4. Temporary flaring/incineration permit process

d) An incremental volume of 200 10 3 m 3 may be added to the v olume a llowance t hreshold defined above for each additional zone being tested during continuous operations on a well (with continuous operations meaning that servicing equipment and personnel are not demobilized between tests on each zone)
, subject to the following limitations:

i) The volume flared from any zone during multiple

- zone tests must not exceed the volume allowance threshold for a single zone unless a larger volume is specifically approved by the AER Authorizations Operations Gr oup.
ii) The incremental allowance does not apply to single tests over multiple commingled zones. Each zone to be tested must be identified and fully accounted for in the related flare permit request

.

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 27Alberta Energy Regulator

3.3.2 Conditions That Do Not Require a Temporary Flaring/Incine rati o n Permit
1) A permit is not required if the gas contains 50 mol/kmol H 2 S (5 per cent ) or less and the total volume (for gas well tests) is less than the v olume a llowance t hreshold (see section above ). However, licensees must meet the requirements in s ection 3 and s ection 7, as well as the notification requirements in s ection 3. 8

. a) Licensees must evaluate compliance with the one

- hour AAAQO for SO 2 if the gas
contains more than 10 mol/kmol H 2 S (1 per cent ). Related dispersion modelling results must be provided to the AER Authorizations Operations Group upon request.

2) Flaring or incinerating small volumes of sour gas containing more than 50 mol/kmol H 2 S (5 per cent ) are exempt from AER permit requirements provided that the following
conditions are met:

a) Maximum sulphur emission rates do not exceed 1.0 tonne per day over the duration of
the event

. b) T otal flared or incinerated volume do not exceed 50 10 3 m 3 over the duration of the

event

. c) Equipment is designed to ensure com pliance with the one

- hour AAAQO for SO 2 or operating procedures are in place to ensu re compliance with the AAAQO . Related dispersion modelling evaluations and design information are documented and available
to the AER Authorizations Operations Group upon request.
d) Rates and volumes are measured and reported as defined in s ection 10.

e) Written notification is provided to the AER Authorizations Operations Group.
N otification includes total expected gas volumes and sulphur emissions. If applicable,
notification provides an explanation of any air quality management plans needed to ensure compliance with the AAAQO

. 3) The AER does not require temporary permits for the use of permanent flares or incinerators
installed in AER

- licensed facilities, including batteries, co mpressor stations, and gas plants provided that licensees can show, on request from the AER Authorizations Operations Group or f ield c entre staff, that

a) t he flaring or incinerati o n volumes, rates
, and gas composition are within t he limits of the facility li cenc e ;
b) the flares or incinerators are designed to operate safely under the intended conditions in compliance with the AAAQO ; and

c) the total volumes are less than the volume allowance threshold.

4) Similarly, the AER does not require temporary permits for unpla nned nonroutine events such

as emergencies . Licensees must ensure that temporary nonroutine systems are adequately

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 28Alberta Energy Regulator

designed to operate safely under anticipated emergency and upset conditions and meet the requirements in s ection 7.

a) For planned nonroutine events , including maintenance blowdowns, pipeline depressur iz ing, and turnarounds , licensees must obtain a temporary permit if required by
section 3.3.1
, unless exempted in (2) or (3) above.

5) The AER does not require temporary permits for flaring at oil an d bitumen batteries. The operator must meet conservation requirements described in section 2.

3.4 Flaring and Incinerati o n Permits for Underbalanced Drilling

Permit requirements ( s ection 3.3) and notification requirements ( s ection 3. 8 ) for temporary flaring an d incinerati o n also apply to underbalanced drilling.

For more detail on underbalanced drilling requirements, see Interim Directive ( ID) 94

- 03: Underbalanced Drilling
, ID 97

- 06: Sour Well Licensing and Drilling Requirements

, and

a ppendix 5

.
3.5 Permit Requi rements for Temporary Flares and Incinerators

Figure 4 summarizes the temporary permit process

.
3.5.1 General Permit Requirements
1) Requests for temporary permits must be submitted to the AER Authorizations Operations Group via e

- mail (Directive060Inbox@aer.ca) and must include complete information on the proposed activity, as requested in the AERflare.xls and AERincin.xls spre adsheets (available
on the AER w ebsite under Regulations & Directives : Directives : Directive 060 ) and
summarized as follows:

a) a cover letter requesting a permit and informing th e AER Authorizations Operations Group of any public objections to or concerns about the proposed flaring/incineration

b) information about the site on wh ich flaring/incinerati o n will occur, including location, Lahee classification, and related National Topogr aphical System 1:50 000 scale maps
c) an evaluation of the most feasible option for in

- line testing

d) information on planned flaring/incinerati o n, including reasons (e.g., well testing, completions, pipeline depressur iz ing), H 2 S content, flow rates, total volumes, and type
of combustion d evice to be used (i.e., flare or incinerator)

e) information on the licensee’s assessment of effect s on ambient air quality, including results of dispersion modelling for SO 2

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 29Alberta Energy Regulator

f) in situations with potential to exceed the risk

- based criteria (see section 7.12.4) for SO 2 , information on the licensee’s p roposed air quality management plan to prevent
exceedances

2) Any inconsistencies in the request or modelling will result in the request being rejected and
returned to the licens ee. Permit requests are processed in the order received, and resubmissions will be treated as new permit requests.

3) Temporary permit requests can be submitted electronically by the licensee. A p ermit will be
in the name of the licensee.

3.5.2 Requests to Exceed the Volume Allowance Threshold Information requirements apply to all requests to exceed the v olume a llowance t hreshold. However, any volume of gas flared or incinerated must be defensible.

1) Licensees must provide specific engineering, economic, and operati onal information to justify flaring or incinerating gas volumes in excess of the volume allowance threshold.

2) All requests for volumes greater than the volume allowance threshold regardless of H 2 S
content must be submitted to the AER Authorizations Operatio ns Group (e

- mail Directive060Inbox@aer.ca) and must include the following, in addition to information in

s ection 3.5.1 (note that 1 [ e ] and [ f ] of that section do not apply to sweet gas wells).

a) Requests relating to tests to determine if enough gas supply exists to justify related investments must include information on the scope of development required to produce the well and necessary threshold rese rves. (See appendix 5).

b) Request s relating to tests to determine the relationship between a bsolute o pen f low (AOF) and deliverability of the well must include justification of the volume being requested as it pertains to obtaining an accurate deliverability relationship , in accordance
with AER Directive 040

. c) Request s relating to tests to establish the stabilized flow rate of the well must include justification of the flare volume r equest as it pertains to obtaining a stabilized flow rate, including identification of any analogous wells being used for comparison purposes.

3) Should the information described above not be available or applicable , licensees must include discussion on why i t is not included with the exceedance request.

4) For underbalanced drilling, follow the guidelines in appendix 5.

3.5.3 Blanket Flaring/Incinerati o n Permits Sour oil and gas well operations such as well servicing may result in flaring of relatively small
volumes of gas at several sites in a local area. T o simplify temporary permit request requirements, the AER Authorizations Operations Group may issue a single “blanket” permit to

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 30Alberta Energy Regulator

cover several flaring events at different sites in an area if so requested by the lic ensee. Blanket permit request requirements and limitations are as follows:

1) Blanket permits are issued on a fixed

- term basis for periods not to exceed one calendar year. Licensees must complete and submit a new flare permit request to renew blanket permits for additional periods of time.

2) Blanket permits are limited to specific stack heights, locations, rates, maximum volumes per event, maximum H 2 S concentrations, and maximum sulphur emissions per event as listed in the permit request.

3) All wells must be licen sed before they can be considered for a blanket permit.

4) For every well being consider ed for a blanket permit , licensees must use the AERflare.xls or AERincin.xls spreadsheet (available on the AER w ebsite under Industry Zone : Rules, Regulations, Requiremen ts : Directives : Directive 060 ) to evaluate the temporary flaring or
incinerati o n parameters during the period in wh ich flaring/incinerati o n is planned.

a) The spreadsheets provide screening modelling. R efined modelling may be requir ed and

must meet the ris k

- based criteria

. b) Any inconsistencies in the request or modelling will result in the request being rejected
and returned to the licensee.

5) A blanket permit will not be considered if

a) projected volumes are greater than 100 10 3 m 3 per site or flaring event;

b) total sulphur emissions will exceed 10 tonnes per event;

c) an air quality management plan is necessary for compliance with the risk

- based c riteria
for SO 2 ; or
d) complex terrain modelling is required for specific locations

. Exceptions may be made only after con sultation with the AER Authorizations Operations Group.

6) A list of wells and their bottomhole and surface locations and licence numbers must be
submitted to the AER Authorizations Operations Group before a blanket permit request will
be considered.

7) A sour gas flaring/incineration data summary report (see appendix 6) for each well must be completed and submitted to the AER Authorizations Operations Group within 30 days of the end of each calendar quarter

- year.

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 31Alberta Energy Regulator

If no flaring or incineration was done ov er the previous calendar quarter

- year, a sour gas flaring/incineration data summary report on the lack of flaring or incineration must be
submitted.

8) Licensees must comply with public and AER f ield c entre notification requirements for each
flare event cover ed by the blanket permit
, as described in s ection 3. 8

.
3.5.4 AER Review of Permit Requests Requested volumes, rates, or conditions may not be granted by the AER Authorizations Operations Group . Consideration will be given to total volumes, total sulphur emission s, local land uses, proximity of residences, and potential for exceedance of the AAAQO before a permit is granted. AER Authorizations Operations Group staff will consult with licensees in such
situations.

1) Licensees must avoid temporary flaring or incinera ti o n in situations where existing infrastructure can be reasonably used for in

- line disposition of the gas, especially in populated areas.

2) Licensees must limit the volumes for gas that they request, especially gas with high H 2 S

contents . Situations involvi ng sulphur emissions of 50 tonnes or more are subject to closer scrutiny by the AER Authorizations Operations Group. The AER Authorizations Operations Group typically will not approve permits where total sulphur emissions exceed 300 tonnes.

3.6 Site

- Specific Requirements Related to Well Flaring and Incinerati o n

The following requirements apply to the use of temporary flares and incinerators

. 1) Temporary flares and incinerators must comply with design and operation requirements
defined in s ection 7.

a) Flares and in cinerators must not be operated outside design operating ranges as specified by the designing or reviewing qualified technical professional who is a member of the
Association as defined in the Engineering and Geoscience Professions Act

. 11

2) Licensees must determine the H 2 S content of flared or incinerated gas using Tutweiller or gas chromatography methods as soon as is practical after beginning operation if gas analysis has not been done within the preceding 12 months.

3) If the H 2 S content in the gas i s found to exceed 50 mol/kmol H 2 S and no flaring or incineration permit has been issued by the AER Authorizations Operations Group, or if the
H 2 S content of the gas exceeds the maximum value listed in the related permit, operations must be suspended and th e appropriate AER field centre notified. Operations must not

11 Engineering and Geoscience Professions Act , RSA 2000 c. E

- 11, as amended.

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 32Alberta Energy Regulator

resume until a permit or permit amendment is issued by the Operations Group in response to a written request.

4) Both high

- and low

- pressure gas

- liquid separation stages must be used for sour gas to minimize vapour released from produced hydrocarbon liquid and sour water storage.

5) Liquid storage must be designed to prevent the escape of sour gas to the environment. For
more detail
, see the most current edition of Industry Recommended Practice [IRP] Volume 4: Well Testing and Fluid Handling from the Canadian Petroleum Safety Council.

3.7 Temporary Facilities for In

- Line Tests

T o facilitate conservation, the licensee or operator may install a temporary compressor and pipeline connections. For temporary compressor installation, see Directive 0 56

.

S ection 3.7 of this d irective does not apply to oil batteries. However, Directive 0 56 application requirements apply to both temporary and permanent oil batteries.

1) Details on application requirements and exceptions for temporary well test facilities and pipeline connections are in Directive 056 . In the case of a discrepancy between this directive
and Directive 056

, Directive 056 application requirements apply.

2) Exceptions to AER applications requirements for temporary facilities, such as temporary connection to existing gathering systems, are intended to encourage conservation of gas

assoc iated with well testing. The provisions do not apply to testing situations in which gas
will be flared.

3) Only one test period will be approved at each site. If there are multiple events, an application is required (see Directive 056 ).

4) For extended tests or multiple tests that require temporary facilities to operate for more than 21 days, the licensee or operator must complete an application (see Directive 056 ).

5) Proposals to install temporary compressors and other facilities for reasons other than testing

ne w wells must comply with Directive 056 application requirements.

6) Any licensee or operator intending to use temporary production, compression, and/or pipeline facilities must notify the appropriate AER f ield c entre and obtain approval for a
variance from Di rective 0 56 application requirements.

a) The notification must include a description of the proposed equipment (including relevant capacities), driver type, and layout ( e.g. , give the compressor power rating and note whether the driver type is gas, diesel, or electric)

.

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 33Alberta Energy Regulator

b) A l icensee or operator intending to install and use temporary pipelines for well testing must complete and submit to the appropriate AER f ield c entre the Checklist for 21

- Day Temporary Surface Pipelines for Well Testing Purposes. 12

c) AER f ield c entre approvals for temporary facilities are valid for 21 days and include the dismantling and removal of temporary facilities (including pipelines) from the lease. Any exception s, including allowances for downtime during testing, must be referred to the appropriate AER f ield c entre for further review.

7) Temporary facilities, including pipelines, must comply with relevant AER requirements.

a) Temporary facilities must meet noise contr ol requirements defined in Directive 038:
Noise Control

. b) The licensee or operator must meet emergency response plan requirements for sour wells. The plan must incorporate provisi ons for the temporary equipment, as appropriate.
See Directive 071: Emergency Preparedness and Response Requirements for the Upstream Petroleum Industry

. 8) Temporary sweetening pro cesses, if used, must be of the zero

- sulphur

- emissions type. The licensee or operator must submit a facility application, as described in Directive 056

, for temporary installation of regenerative sweetening processes with acid gas.

a) All temporary or permanent regenerative sweetening facilities require an ESRD sour gas processing plant approval.

9) Temporary pipelines and batteries must comply with Directive 0 56 public consultation requirements

.
3.8 Notification Requirements

Unless t he l icensee, operator, or approval holder reaches
, with the peo ple who require
notification in accordance with this directive , an agreement that provides for an alternate means
of notific ation, the licensee, operator, or approval holder must provide noti ce of flaring, venting,

or incinerati o n in accordance with this directive . The AER does not require the licensee, operator,

or approval holder to obtain the consent of residents within the notification radius

. 1) The l icensee, operator, or approval holder must notify all residents of flaring, incineration, and venting in accordance with table 2. The notification distances in table 2 are minimum requirements.

2) Notice must be given to the appropriate AER field centre via the DDS system of any planned flaring, incineration, or venting at least 24 hours in advance.

12 Available on the Directive 056 page of the AER website

, www.aer.ca

.

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 34Alberta Energy Regulator

a) Notice to the appropriate AER field centre must include a contact name and telephone

n umber in case of complaints or emergencies.

Table 2. Temporary flaring, venting, and incinerati o n notification requirements 1

Type of operation (applies to sweet and sour streams) Duration of event (hrs in 24

- hr period) * Gas volume (10 3 m 3 in a 24

- hr period) Notification 3
Temporary (i.e., for well cleanup, testing, or maintenance) < 4 and < 30 No notification 4

Temporary (i.e., for well cleanup, testing, or maintenance) if gas contains ≤ 10 mol/kmol H 2 S > 4 or > 30 Residents, 1.5 km radius; AER field centre

Temporary (i.e., for well cleanup, testing, or maintenance) if gas contains >10 mol/kmol H 2 S > 4 or > 30 Residents, 3 km radius; AER field centre Temporary (i.e., for well cleanup, testing, or maintenance) through permanent battery or plant flare or incin erator < 4

-- No public notification; 4 Notify the AER 5 if flaring >30 10 3 m 3
Temporary (i.e., for well cleanup, testing, or maintenance) through permanent battery or plant flare or incinerator > 4

-- Residents, 0.5 km radius; 5 AER field centre

1 See s ection 1.6 for information on the AER DDS system and how to notify the appropriate AER f ield c entre via DDS.
2 24 to 72 hours in advance of planned flaring, venting, or incinerati o n operations, the licensee, operator, or approval holder must

notify th e appropriate AER f ield c entre via the DDS system, all rural residents outside towns, villages, and urban centres and within the specified radius , and the chief administrative officer or equivalent of a town, village, or urban centre within the specified radius. Note that for incorporated centres and hamlets, it is sufficient to contact only the appropriate administrator. Advance notification of more than 72 hours (not longer than 90 days) must also offer the option for renotification within the 24

- to 72

- hour period before operations. After 90 days, renotification is mandatory.
3 The AER recommends additional “good neighbour” notification for short

- duration events for residents who have identified

themselves to the licensee, operator, or approval holder as being sensitive to or interested in emissions from the facility within the same notification radius as specified for events of more than four hours.
4 The AER recommends additional “good neighbour” notification for longer duration e vents ( of more than four hours) for residents

who have identified themselves to the licensee, operator, or approval holder as being sensitive to or interested in emissions from the facility.

* Notification requirements include duration and volume from flowback operations. These gases may be hydrocarbon or gases

used in fracturing fluids (carbon dioxide or nitrogen) in any mixture. For reporting purposes, hydrocarbon volumes must be distinguished from fracture gas volumes (see section 3.9)

3) Upon AER field centre request, the licensee, operator, or approval holder must provide a list of notified residents who live within the specified notification radius, as well as a sample of the information provided to residents.

4) Unless the licensee, operat or , or approval holder has reached an agreement with current
residents for an alternative method of notification
, notification must be in writ ing (s ee

a ppendix 9 ) and include the following basic information about the flaring, incinerati o n , or venting:

a) l icensee, operator, or approval holder ’s n ame, contact persons, and telephone numbers

b) the location of the flaring, incinerati o n , or venting

c) the duration of the event (start date and expected completion date)

d) the expected event volume and rates

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 35Alberta Energy Regulator

e) information o n the type of well (oil, gas
, or coalbed methane ) and, if applicable,
information on the H 2 S content of the flared or incinerated gas

f) AER f ield c entre contact telephone number

5) The l icensee, operator, or approval holder may conduct a one

- time notification p rogram for multiple

- well projects in an area unless the licensee, operator
, or approval holder has reached an agreement with current residents for an alternative method of notification . In addition to the information above, the related multiple

- well project notification must provide

a) the locations where flaring, incinerati o n, or venting will occur,
b) the period during which the project will be carried out, and
c) the expected duration and v olume of temporary flaring, venting, or incinerati o n.
6) The l icensee, operator, or approval holder may limit the number of repeat notifications to
individual residents if

a) the resident requests that the number of notifications be reduced ; b) the licensee, operator, or approval holder provide s the resident with an outline of expected flaring and incinerati o n activities in the area ; and
c) the licensee, operator, or approval holder document s a written agreement to reduce
notifications and obtains written evidenc e of the current residents’ acceptance of the
agreement . A copy of this letter agreement must be provided to the AER upon request.
7) The l icensee, operator, or approval holder may conduct a single notification to each resident
within the notification area an d the appropriate AER f ield c entre, rather than a separate notification for each flaring, venting, or incinerati o n period throughout the program, if this is acceptable to the current residents . The method of notification must be discussed during the
initia l notification process.

8) The AER recommends that the licensee, operator, or approval holder consider placing signage on public roads surrounding the temporary flaring or incineration operations indicating the operation type and the contact phone number for inquir i es.

3.8.1 Addressing Resident Concerns Compliance with Directive 060 ensures that licensees, operators, and approval holders have considered public safety and environmental impacts before flaring, incineration, and venting activities; however, additional concerns or complaints may be expressed by nearby residents regarding impacts of the operational aspects of flaring or incineration (e.g., timing of flaring and associated traffic). The following ensure that concerns of nearby residents are addressed:

1) The AER encourages the licensee, operator, or approval holder to work with nearby residents prior to commencing proposed and existing flaring or incineration activities.

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 36Alberta Energy Regulator

2) The licensee, operator, or approval holder must immediately disclose any unresolved

conce rns of nearby residents about those activities to the appropriate AER field centre in order to discuss concerns or complaints related to those activities.

3) Residents may subsequently contact the appropriate AER field centre to discuss concerns or complaint s related to those activities.
The AER may work further with the licensee, operator, or approval holder to modify one or more operational aspects of the proposed or existing flaring or incineration activities to address nearby resident concerns, but it wil l not suspend flaring or incineration activities in response to a concern or complaint unless there is clear evidence that the licensee, operator, or approval holder is not in compliance with Directive 060

.
3.8.2 AER Flaring/Incinerating/Venting Notice Form
1) T o comply with the requirements in s ection 3.8 above, the licensee, operator, or approval
holder must complete the AER f laring/ i ncinerati o n/ v enting n otice f orm in the DDS system and submit it electronically to t he appropriate AER f ield c entre

.
3.9 Reporting Gas Well Test Data

1) Well test results and information required by flaring and incinerati o n permits must be
submitted in accordance with the requirements of Directive 040 ; Bulletin 2004

- 15 : New Well Test Capture (WTC) System Implementation Date Reminder Changes to Final WTC
Pressure ASCII Stan dard (PAS) Formats and Version 4.0 PAS File Business Rules Implications ; the applicable permit ; and s ection 10

. a) All well test reports must be submitted within three months of completing the fieldwork. This information must include the volume of gas produced to flare, vent, or pipeline, as well as all gas analyses from samples gathered at the wellhead

. S ubmi ssions must be in a pressure ASCII standard (PAS) format and submitted via the w ell test data capture system in DDS. For questions on these submissions, e

- mail the well test helpline at
Welltest

- Helpline@ aer .ca

. 2) For a ll well tests that require permits
, a s our g as f laring /incineration data s ummary r eport
must be submitted to the AER Authorizations Operations Group within three weeks of the completion of flaring or incineration (see s ection 10.1 , appendix 6, and AERflare.xls or AERincin.xls spreadsheet).

3) A l l flaring , incinerati o n , and venting at a well site (including well tests) must be reported on the appropriate production reporting submissions, including PETRINEX ( s ee Directive 007: Volumetric and Infrastructure Requirements ).

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 37Alberta Energy Regulator

a) In order to be able to report to the AER , the licensee, operator, or approval holder must obtain a battery code. Any pr oduced volumes, including those flared, incinerated
, or vented, must be reported (s ee Directive 00 7 ).

b) Fluid volumes and fuel consumption must be recorded and reported on the monthly production submissions (see s ection 10).

3.10 Zero Flaring Agreements

Flaring is allowed by the AER when done in accordance with Directive 060

. However, parties may agree to zero flaring
, as set out in a z ero f laring a greement (see appendix 10) . The

a greement must be signed by both parties and filed by the applicant with the well a pplication.
Once filed
, the zero flaring agreement becomes a condition of the well licen c e

. Should the licensee, operator, or approval holder fail to adhere to this agreement, operations at the well may be suspended. This agreement, including the condition, expires when production begi ns.
Once the well or facility is licensed, if the licensee, operator, or approval holder needs to change
this z ero f laring a greement, it must file a n a pplication to c hange the a greement with the AER
Authorizations Ope rations Group
, with a copy to the co

- signers

. 1) An application to change a zero flaring agreement must include

a) the reasons that th e agreement needs to be changed,

b) a copy of the original application and approval,

c) a copy of the original and revised z ero f lari ng agreement , and

d) a summary of the consultation and notification that have been done, including confirmation of agreements reached with the parties affected by this agreement.

Until the AER deci des on this application, flaring may only occur as set out in the z ero f laring

a greement. For oil wells, agreement not to flare during well testing means that the licensee,
operator, or approval holder ha s agreed to initially conserve the gas. Later, i f it becomes uneconomic to conserve the gas, the licensee, operato r, or approval holder must follow the process in s ection 2.6(6) of this directive to discontinue conservation.

The l icensee, operator, or approval holder must try to address the landowner or occupant concerns and may use the AER’s appropriate dispute reso lution process 13 if that becomes

necessary before applying with the AER to change this zero flaring agreement.

13 See AER Informational Letter ( IL ) 200 1

- 1: Appropriate Dispute Resolution (ADR) Program and Guidelines for Energy Industry

Disputes for more information.

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 38Alberta Energy Regulator

4 Gas Battery, Dehydrator , and Compressor Station Flaring, Incinerating, and Venting This section addresses gas battery, dehydrator
, and compressor station flaring, incinerating, and venting and includes

• routine flaring and incineration, and

• nonroutine flaring, incinerati o n, and venting for equipment depressur ization for
maintenance ; process upsets ; and emergency depressur iz ing for safety reasons.

4.1 Gas Battery, Dehydrator

, and Compressor Station Flaring, Incinerating, and Venting Decision Tree

1) The l icensee or operator must use the decision tree analysis shown in figure 5 to evaluate all new and existing gas battery, dehydrator
, and compressor station flares, incinerators , and vents regardless of volume except for intermittent small sources (less than 100 m 3 per month) such as pig trap depressur iz ing.

Reduce facility flaring, incinerating, and venting Eliminate routine and minimize upset flaring, incinerating, and

venting at production and process facilities*

Meet performance and venting and fugitive emissions management requirements ( see sections 7 and 8) Implement YES NO

NO Tests

• Environmental or safety impacts? Public concern?

• YES

* This does not apply to emergency situations.

Figure 5. Facility f laring, i ncinerating, and v enting d ecision t ree (adapted from CASA)

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 39Alberta Energy Regulator

2) The licensee or operator must document alternatives that were considered in order to eliminate or reduce flaring, incineration, and venting, how they were evaluated, and the

outc ome of the evaluation.

3) New batteries proposing routine flaring, venting, or incineration must be evaluated before application as part of the facility design. All existing batteries with routine sources were required to have been evaluated by December 31, 2 004.

4) The licensee or operator must assess opportunities to eliminate or reduce nonroutine flaring,
incinerati o n, and venting of gas due to frequent (i.e.
, one event per month) maintenance or facility shutdowns

. a) The l icensee or operator must investigate and correct frequent nonroutine events at gas
batteries.

b) The l icensee or operator must address concerns or objections of residents related to
nonroutine gas battery flaring.

5) Flare, incinerator, and vent systems must be designed and operated in compliance with

s ections 7 and 8 , good engineering practice , and any other safety codes and regulations required by other agencies

.
4.2 Notification

1) The l icensee or operator must notify residents and the appropriate AER f ield c entre of
nonroutine flaring at gas batteries as follows:

a) If gas battery flaring exceeds four hours in duration, the licensee or operator must notify
residents as described in s ection 3. 8 and t able 2.

b) If a gas battery flaring event exceeds 30 10 3 m 3 and/or four hours in duration or is likely

to cause resident concern, the appropriate AER f ield c entre must be notified (see t able 2).
If Directive 060 notification requirements differ from those of IL 98

- 01
, the licensee or operator must comply with the more stringent requirement.

2) The licensee or operator must give the AER f ield c entre a t least 24 hours notice of planned gas battery outages and turnarounds that will result in flaring of more than 30 10 3 m 3 or for
more than four hours duration. The licensee or operator must give resi dents notification without delay or as soon as practical of unplanned gas battery outages that result in flaring of

more than 30 10 3 m 3 or for more than four hours duration

.
4.3 Reporting

1) All monthly flared and vented volumes must be reported separately on PET RINEX in
accordance with section 10 and Directive 007 . Incinerated volumes must be combined with and reported as flared volumes.

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 40Alberta Energy Regulator

2) Gas burned in an incinerator must be reported as flared. Fuel gas burned in an incinerator must be reported as fuel gas.

3) Gas flared or vented at gas batteries must be reported at the flaring or venting location . For facilities that do not require a licence (such as small booster compressors), the flared and vented volumes must be reported at the nearest upstream reporting well, battery, or pipeline facility.

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 41Alberta Energy Regulator

5 Gas Plant Flaring, Incinerating, and Venting This section addresses disposal of gas from gas proce ssing plants by flaring, incinerating, and venting . Sources of natural gas flaring, incinerati o n, and venting at gas production facilities
include

• routine flaring, incinerati o n, and venting of low

- pressure flash gas and other gas streams,
and

• nonroutine fl aring, incinerati o n, and venting for equipment d epressur iz ing for maintenance process upsets, and emergency depressur iz ing for safety reasons.

5.1 Gas Plant Flaring, Incinerating, and Venting Decision Tree

Licensees must use the decision tree analysis shown i n f igure 6 to evaluate all new and existing gas plant flares, incinerators, and vents regardless of volume except for intermittent small sources (less than 100 m 3 per month) such as pig trap depressur iz ing. Furthermore, these evaluations must be updated an nually or when changes at the plant materially change plant operation.

1) Licensees must document alternatives that were considered in order to eliminate or reduce flaring, incineration, or venting, how they were evaluated, and the outcome of the
evaluation.

2) Licensees must assess opportunities to eliminate or reduce nonroutine flaring, incineration, and venting of gas due to frequent maintenance or facility reliability outage, as well as

3) address concerns and objections of residents notified in accordance wi th table 2 related to nonroutine flaring, and

4) comply with the limitations on total flared, incinerated, and vented volumes and the number of repeat events defined in sections 5.2 and 5.3.

5) Flare, incinerator, and vent systems must be designed and operated i n compliance with
sections 7 and 8 , good engineering practice, and any other safety codes and regulations required by other agencies.

a) Gas streams directed to continuous gas plant flares must have a minimum heating value
as def ined in s ection 7.1.1.

b) All existing plants were required to have performance evaluations completed by December 31, 2004.

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 42Alberta Energy Regulator

Reduce facility flaring, incinerating, and venting Eliminate routine and minimize upset flaring, incinerating, and venting at

production and process facilities

Meet performance and venting and emissions management requirements (see sections 7 and 8) Implement YES NO

NO Gas plant flaring limits

• Maximum annual volume

• Maximum event frequency

Tests

• Environmental or safety impacts?

Public concern? YES

*

•

* Th is does not apply to emergency situations. Figure 6. Facility f laring, i ncinerating, and v enting d ecision t ree (adapted from CASA)

5.2 Gas P lant F laring / I ncineration /V enting V olume L imits

The AER limits the total annual volume of gas disposed of by flaring, incinerati o n, and venting at gas processing plants. Fuel gas used for pilots or flare system purge and acid gas volumes from gas sweetening (which are normally continuously flared) are excluded from the following
limits:

1) For gas plants processing less than 1.0 billion (10 9 ) m 3 per year (raw gas inlet volume), flaring, incineration, and venting must not exc eed 1 per cent of raw gas receipts in the first year of operation and must not exceed 0.5 per cent of receipts in any subsequent year.

2) For gas plants processing more than 1.0 10 9 m 3 per year, flaring, incineration, and venting must not exceed the greater of 0.2 per cent of receipts or 5.0 10 6 m 3 per year.
3) If multiple flare stacks are available in gas production, gathering, and processing systems
, licensees must use the flare stack that is the most efficient and capable of providing the best dispersion. In most cases this would be the gas plant flare stack.

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 43Alberta Energy Regulator

a) Licensees can deduct solution gas flared at gas plants during plant shutdowns lasting more than seven days in calculating the annual flared volumes applicable to (1) and (2) above. These solution gas vo lumes must be documented and provided to the AER upon request.
4) Licensees must comply with the solution gas reduction limitations in section 2.11 during facility outages.

5) All nonassociated gas must be shut in during facility outages.

6) The AER recommends tha t solution gas process ing take priority over the processing of nonassociated gas.

5.3 Frequent Nonroutine Flaring /Incineration/Venting Events

1) Licensees must investigate and correct causes of repeat nonroutine flaring, incineration, and venting.

2) Gas pla n ts must not exceed six major nonroutine flaring events in any consecutive (rolling)
six

- month period (6

- in

- 6). Major flaring events are defined in table 3

.
Table 3. Major flaring event definition Approved plant inlet capacity Major flaring event definition*

> 500 10 3 m 3 /d 100 10 3 m 3 or more
150

– 500 10 3 m 3 /d 20 per cent of plant design daily inlet or more

< 150 10 3 m 3 /d 30 10 3 m 3 or more

* The definition of a flaring event includes situations where 1) volumes greater than or equal to those specified in the table are flared in any single day; each day that specified

flared volumes are exceeded is considered to be a separate, individual event; or 2) volumes greater than or equal to those specified in the table a re flared in one contiguous period spanning more

than one day ( e.g. , flaring for four days at a continuous rate of 25 10 3 m 3 /d is considered one event).

3) Licensees must log and monitor nonroutine flaring events, as required in s ection 10.1

. Major flaring events must be flagged. The following applies if a sixth major flaring event occur s within any consecutive (rolling) six

- month period:

a) Licensees must submit a written “exceedan ce” report to the appropriate AER f ield

c entre and copy this report to the AER Authorizations Operations Group within 30 days of the occurrence of the sixth flaring event.

i) The exceedance report must provide data on all flaring events (volume and duration) for the consecutive (rolling) six

- month period in question and on their possible

causes.
ii) The report must also propose a plan and corresponding timeline for implementing corrective actions to ensure that frequent major nonroutine flaring does not recur.

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 44Alberta Energy Regulator

b) Licensees must obtain AER field centre approval of the proposed plan referred to in 3(a) (ii) above.

i) If facility modifications are proposed in the plan and approvals are required by
Directive 056

, AER Applications Group approval must be obtained before implementing any such actions

. ii) Upon AER field centre approval of the plan
, including facility modifications,
licensees are expected to expedite schedules for implementing the plan.

c) After the plan implementation date, the AER will take enforcement action if another
exceedance of the 6

- in

- 6 criterion occurs within 24 months.

5.4 Notification

1) Licensees must notify residents and the appropriate AER f ield c entre of nonroutine flaring at gas plants (see t able 2).

a) The appropriate AER f ield c entre must be notified if a nonroutine flaring event exceeds
30 10 3 m 3 , exceeds four hours’ duration, or is likely to cause public concern.

b) If more stringent notification requirements than r equired by this directive have been put in place through IL 98

- 01 : A Memorandum Of Understanding Between Alberta Environmental Protection And The Alberta Energy And Utilities Board Regarding Coordination Of Release Notification Requirements And Subsequent Regulatory Response
, licensees must comply with the more stringent requirements.

c) Licensees must provide the appropriate AER f ield c entre with a t least 24 hours’ notice
of a plant turnaround

. d) The appropriate AER field centre must be notified 24 to 72 hours before planned flaring and as soon as practical of unplanned flaring when notification is required.

5.5 Measurement and Reporting

Measurement and reporting requirements for gas plants include the following:

1) All monthly flared and vented volumes must be reported separately on PETRINEX in
accordance with section 10 and Directive 007

. 14 Incinerated volumes must be combined with and reported as flared volumes.

2) Flaring of sour gas must also be reported on the S

- 30 Monthly Gas Processing Plant Sulphur Balance Report (see section 11 of Directive 017 ).

14 This inform ation is summarized annually in AER ST13A: Alberta Gas Plant/Gas Gathering System Activities

— Annual Statistics , and monthly in ST13B:Alberta Gas Plant/Gas Gathering System Activities

— Monthly Statistics , and ST13C: Alberta Gas Gathering System Activities

— Monthly Statistics

.

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 45Alberta Energy Regulator

3) When measurement is not required, engineering estimates must be used to report any flared

g as not measured (see section 10).

4) Licensees must provide a documented system for measurement and/or estimation of flared and vented gas volumes (as defined in section 10) upon AER Authorizations Operations Group request. All flare events both minor and ma jor must be logged (in accordance with section 10.4) and provided upon request.

5) Fuel gas that is flared, incinerated, or vented (e.g., flare pilot gas, header purge gas, storage tank blanket gas) must be reported as fuel gas, not flared gas.

6) Licensees must monitor and minimize fuel gas use for flare header purge, flare
, and incinerator pilots.

a) Licensees must be able to justify fuel gas usage volumes.

b) The AER may require evidence of this justification on the basis of case

- specific audits and inspections.

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 46Alberta Energy Regulator

6 Pipeline Flaring, Incinerating, and Venting This section addresses disposal of gases from gas gathering and transmission lines by flaring,
incinerati o n, and venting. Sources of gas flaring, incinerati o n, or venting include

• routine flaring, incinerati o n, and venting of low

- pressure flash

- gas and other gas streams at pipeline system compressor and dehydration facilities, and

• nonroutine flaring, incinerati o n, and venting for pipeline depressur iz ing for maintenance,
process upsets , or emergency depressur iz ing for safety reasons.

6.1 Pipeline Systems Flaring, Incinerati o n, and Venting Decision Tree

Licensees must use the decision tree analysis shown in f igure 7 to evaluate all new and existing pipeline systems
, including compression station flares , incinerators, and vents
, except for intermittent small sources (less than 100 m 3 per month) such as pig trap depressur iz ing. T hese evaluations must be updated before any planned flar ing, incinerating, or vent ing

. 1) Licensees must document alternatives considered in order to eliminate or reduce flaring, incineration, or venting, how they were evaluated, and the outcome of the evaluation.

2) Licensees must assess opportunities to eliminate or reduce flaring, incineration, and venting of gas due to frequent maintenance or faci lity outage as follows:

a) I nvestigate and correct repeat events at gas pipelines and related facilities (e.g., compressor stations)

. b) A ddress public complaints and concerns about pipeline facility flaring, incinerati o n, or venting

. c) I nvestigate and implement feasible measures to conserve gas from the depressur iz ing of pipeline systems.

3) Licensees of gas pipeline systems must ensure that flares, incinerators, and vents are designed and operated in compliance with s ections 7 and 8 , good engineering practices, and any other safety codes and regulations required by other agencies.

4) Th e sulphur recovery requirements of s ection 9 and ID 2001

- 03: Sulphur Recovery Guidelines for the Provinc e of Alberta apply to any continuous flaring or incineration of sour gas at gas gathering facilities (e. g. , compressor or dehydrator sites).

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 47Alberta Energy Regulator

Reduce pipeline flaring, incinerating, and venting Eliminate pipeline flaring, incinerating, and venting

Meet performance and venting and fugitive emissions management requirements

(see sections 7 and 8) Implement YES

YES NO

NO Tests

• Public concern?

• Safety concern?

• Economic alternatives?

• Environmental impacts/benefits?

Figure 7. Pipeline f laring, i ncinerating, and v enting d ecision t ree (adapted from CASA)

6.2 Additi onal Requirements for Gas Gathering Systems

1) All monthly flared, incinerated, and vented volumes must be reported separately on
PETRINEX in accordance with section 10 and Directive 007 . Incinerated volumes must be combined with, and reported as, flared volumes.

2) Gas containing more than 5 parts per million (ppm) H 2 S must not be released from a pipeline
without the approval of the AER unless the gas is burned such t hat it meets the requi rements
in s ection 7.

• Flaring or incinerati o n of gas must meet the requirements in s ection 7.

• Venting of ga s must meet the requirements in s ection 8

.

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 48Alberta Energy Regulator

3) Licensees must get an AER temporary flaring/incinerati o n permit in order to use temporary
flares or incinerators for the disposal of sour gas containing more than 50 mol/kmol (5 per
cent ) H 2 S, as described in s ection 3.3.

a) Permits are not required for disposal of small amounts of sour gas if the requirements
defined in s ection 3.3.2 are met.

b) Permit request requirements ( s ection 3.5 ) apply to temporary flares and incinerators used for sour gas pipeline depressur iz ing, except in emergencies.

4) Notification requirements described in table 2 apply.

6.3 Natural Gas Transmission Sys tems

This d irective applies to flaring, incinerati o n, and venting in conjunction with natural gas transmission systems
, subject to the following provisions:

1) Licensees of sweet natural gas transmission pipelines must minimize venting
, flaring , and
incinerat ion volumes.

a) The economic evaluation in s ection 2.9 doe s not appl y to evaluating conservation of gas
from nonroutine pipeline depressur iz ing for maint enance.
b) When evaluat ing conservation of gas from planned nonroutine pipeline depressur iz ing
, l icensees must consider the value of gas, the costs of conserving the gas, and the
economic effe cts of extending outages on downstream customers and upstream producers.

2) Flaring or incinerati o n of gas from sweet natural gas transmission pipeline depressur iz ing may not be practical when impacts on system customers and producers are considered. In
such situations
, the appropriate AER f ield c entre may allow the ven ting of gas to reduce the duration of system outages and related impacts.

6.4 Notification

1) Licensees must notify residents and the appropriate AER f ield c entre of nonroutine flaring
, incineration, or venting at licensed gas pipeline facilities as follows:

a) If p ipeline facility flaring
, incineration, or venting exceeds four hours in duration or 30
10 3 m 3

, licensees must notify as specified in s ection 3. 8 and t able 2.

b) In areas where more stringent notification requirements than those defined in t able 2 are required by IL 98

- 01 or through other regulatory requirements

, licensees must comply with the more stringent requirements.

2) Licensees must provide the appropriate AER field centre with at least 24 hours notice of planned pipeline facility outages that will result in flaring, incineration, or venting.

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 49Alberta Energy Regulator

3) When nonroutine pipeline flaring, incineration, or venting is planned, licensees of sweet natural gas transmission pipelines must notify the appropriate AER field centre and discuss
the measures taken to minimize emissions.

4) Each purchaser or transporter of sweet natural gas must report the particulars of the disposition and delivery of its gas to the AER monthly (see section 12.051 of the Oil and
Gas Conservation R ule s [ OGCR ] ).

a) Flared and vented volumes of sweet natural gas must be reported separately

. Incinerated volumes must be combined with, and reported as, flared volumes.

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 50Alberta Energy Regulator

7 Performance Requirements

These requirements apply to flares and in cinerators in all upstream oil and gas industry systems for burning sweet, sour, and acid gas, including portable equipment used for temporary operations including well completion, servicing, and testing. Flare and incinerator systems include associated separation equipment, piping
, and contro ls.

For the purposes of this directive, the terms flare and incinerator are used interchangeably except as specifically noted in s ections 7.1 and 7.4. In these sections, some requirements are specific to the type of equipment used
, and this is specified i n those requirement s

. Although some design or operating specifications are provided, this directive is not a substitute for comprehensive engineering design codes and guidelines. It identifies minimum AER regulatory requirements but is not intended as a comprehensive design manual.

1) The l icensee, operator, or approval holder must ensure that a qualified technical professional
who is a member of the association as defined in the Engineering and Geoscience
Pr ofessions Act 15 is responsible for the design or review of fla re and incinerator systems , including separation, related piping, and controls, and for the specification of safe operating procedures.

a) Equipment and controls design information must be provided to the AER upon request if the AER determines that there is a concern with the equipment or controls

. 2) The l icensee, operator, or approval holder must ensure that operating procedures that define the operational l imits of flare or incinerator systems are d ocumented and implemented and that these procedures meet the design requirements

. a) Operating limits and procedures must be provided to the AER immediately upon request.
b) Flare and i ncinerator systems must be operated within the operational ranges and type s of service specified by the designing or reviewing engineer, technician
, or technologist. If this equipment is used for emergency shutdowns
, this must be considered in the design.

3) If using
, in a field service , a flare or incinerator that has not previousl y been field tested, the licensee, operator, or approval holder must be able to provide actual monitoring data to show that performance specifications will be met.

a) Field testing of newly designed equipment is not allowed unless there are acceptable and
red undant combustion systems to ensure that any sweet, sour, or acid gas can be properly combusted if the new equipment fails to perform as predicted , or unless the facility is capable of being shut in if problems arise.

15 Engineering and Geoscience Professions Act , RSA 2000 c. E

- 11, as amended.

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 51Alberta Energy Regulator

4) ANSI/API Standard 521: Pressure

- Reliev ing and Depressuring Systems
, as well as applicable fire safety codes, electrical codes, CSA standards, and mechanical engineering standards, are all necessary references for the design of gas combustion systems.

5) The licensee, operator, or approval holder must comply with Alberta safety regulations with respect to the design of pressure vessels and piping systems and the design of equipment and operating procedures (see Pressure Equipment Safety Regulation ).

6) The AER recommends that all licensees, operators, and approval holders use best engineering practices
, as well as appropriate engineering codes and standards
, in the design and operation of flare systems.

7.1 Conversion Efficiency

Definitions and calculations for carbon conversion efficiency, sulphur conversion efficiency
, and combustion efficiency are in a ppendix 2

. 1) Flares and incinerators and other gas combustion systems, including those using sour gas as

a fuel for production or process equipment, must be designed, maintained
, and operated so
that emissions do not

a) result in off

- lease H 2 S odours, or

b) exceed the AAAQO.

2) The l icensee, operator, or approval holder must modi fy or replace existing flares or
incinerators if operations result in off

- lease odours, odour complaints, or visible emissions (e.g., black smoke).

7.1.1 Heating Value and Exit Velocity for Flares

If a flare is also subject to both an AER and a n ESRD approval, the more stringent requirement

o n minimum heating value will apply.

1) The combined net or lower heating value of gas, including make

- up fuel gas, directed to a flare must not be less than 20 megajoule s per cubic met re (MJ/m 3 ), except as noted below:

a) If existing stacks have an established history of stable operation and compliance with
the AAAQO ( the licensee, operator, or approval holder is expected to support claims that existing stacks have operated satisfactorily over time) , the licensee, operator, or approval holder is allowed to main tain the current heating value provided it is not less
than 12 MJ/m 3

. i) I f flare stacks have a history of flame failure, odour complaints, or exceedances of
the AAAQO
, the licensee, operator, or approval holder must operate with a combined flare gas heating value of not less than 20 MJ/m 3

.

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 52Alberta Energy Regulator

b) The combined net or lower heating value of acid gas plus make

- up fuel gas directed to existing or new flares must not be less than 12 MJ/m 3 under any circumstance

. c) Sour gas plant emergency systems must be configured to en sure that the flared gas heating value is not less than 12 MJ/m 3 and that the AAAQO are met.
i) The AER recommends that 20 MJ/m 3 heating value be maintained for nonroutine flaring but recognizes that short

- duration emergency flaring with a gas heating value

o f less than 20 MJ/m 3 may occasionally occur.

2) If fuel make

- up is required, it must be specified for flare stacks by a qualified technical professional who is a member of the association as defined in the Engineering and Geoscience Professions Act

. 16

a) Equipme nt controls must be installed
, and operating procedures must be documented to ensure minimum fuel gas make

- up during routine and nonroutine operating conditions.

b) Facilities must be operated in compliance with specified minimum fuel gas make

- up requirements

. 3) The flare tip diameter must be properly sized for the anticipated flaring rates. The
AERflare.xls spreadsheet provides a range of recommended values.

a) The AER recommends that stacks be designed to avoid downwash due to low exit
velocities and excessive no ise due to high exit velocities.

4) Equipment and controls design information must be provided to the AER upon request if the AER determines that there is a concern with the equipment or controls.

5) Operating limits and procedures must be provided to the AER im mediately upon request.

7.1.2 Minimum Residence Time and Exit Temperature for Incinerators

If an incinerator is subject to an EPEA approval, any requirements regarding minimum residence time or exit temperature in that approval will take precedence over these requirements. The requirements below do not apply to sour gas plants subject to ESRD approvals.

1) Incinerators must provide a min imum residence time 17 of 0.5 seconds at maximum flow rate

or more as required for complete combustion of heavier gases.

a) Incinerators must be operated without exposed flame

. b) If the gas contains less than 10 mol/kmol (1 per cent ) H 2 S and the unsupplemented
he ating value of the gas is 20 MJ/m 3 or more , no minimum residence time is required.

16 Engineering and Geoscience Professsions Act , RSA 2000 c. E

- 11, as amended

. 17 Residence time is calculated between the top of the final burner and the stack exit.

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 53Alberta Energy Regulator

2) Incinerators must operate with a minimum exit temperature 18 of 600 o C.

a) For combustion of gases with less than 10 mol/kmol (1 per cent ) H 2 S and an unsupplemented heating value of 20 MJ/m 3 or more , no minimum exit temperature or temperature monitoring is required.

b) For combustion of gases with more than 50 mol/kmol (5 per cent) H 2 S, the facility must be designed to automatically shut down if the exit temperature of the incinerator drops
below either 600 o C or the required temperature to meet the AAAQO , whichever is higher.

i) The incinerator must also be equipped with process temperature control and recording.

ii) All violations
, together with measures taken to prevent recur rence , must be immediately reported by the licensee, operator, or approval holder to the appropriate
AER f ield c entre

. 3) Any operator proposing to use an enclosed combustion technology that does not meet the above requirements ( minimum exit temperature and m inimum residence time) must submit
third

- party verified conversion efficiency test results to the AER Authorizations Operations Group for approval unless the facility is subject to an EPEA approval.

a) Test programs and submissions must be provided by a qualified technical professional
who is a member of the association as defined in the Engineering and Geoscience Professions Act

. 19 and must include

i) i nlet gas parameters
, including flow rates and composition ;
ii) s tack gas exit parameters
, including temperature and composition ;
iii) m aterial and energy balance calculations ;
iv) a mass

- weighted conversion efficiency value representative of the exit conditions (see s ection 7.1.2 [6] below) ;
v) d iscussion of the variation of measured and calculated results
, depending on samplin g location across the stack ; and

vi) d iscussion of extending test results to other inlet conditions, including discussion of
inlet limitations for H 2 S concentration and inlet gas flow rate

. b) All testing must meet the Alberta Stack Sampling Code

. 20

c) Temperature monitoring and reporting requirements would still apply

.

18 Exit temperature must be measured within one stack diameter of the exit. A shielded thermocouple must be used if the bu rner

flame is visible to the temperature monitor. For further information, consult the Alberta Stack Sampling Code or contact Alberta Environment and Sustainable Resource Development

. 19 E ngineering and Geoscience Profe ssions Act , RSA 2000 c. E

- 11, as amend ed.

20 Copies of the Alberta Stack Sampling Code are available at cost from the Queen's Printer

.

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 54Alberta Energy Regulator

4) Equipment and controls design information must be provided to the AER upon request if the AER determines that there is a concern with the equipment or controls.

5) Operating limits and procedures must b e provided to the AER immediately upon request.

6) Any l icensee, operator, or approval holder using incinerators must be able to provide details about the conversion efficiency of the equipment. Any of the following are considered to be acceptable evidence of compliance with this requirement:

a) t he design at the maximum specified capacity meets the residence time, temperature
, and conversion efficiency requirements ( see [6][b] below ), as calculated using the
AERincin.xls spreadsheet

b) the c onversion efficiency for incinerators is 99 per cent or more , based on one of the following:

i) the manufacturer’s third

- party

- verified conversion efficiency test results, provided that the tests were conducted under conditions representative of the facility design

ii) actual field me asurements of conversion efficiency from the operating facilities following start

- up (see also s ection 7 [3] ) .

c) If conversion efficiency is less than 99 per cent , th e incinerator will be considered to operate as a flare and must meet all requirements for fl ares, including stack height.

7.2 Smoke Emissions

1) Smoke emissions from a well, battery, or gas plant must be controlled in accordance with sections 7.040(1) and 9.050(6)(d) of the OGCR , except under emergency circumstances that
involve equipment failure or as otherwise approved by the AER Authorizations Operations Group.

a) Routine gas combustion must not result in continuous or repeat black smoke emissions.

b) Black smoke from nonroutine or emergency flaring must not exceed an average of 40
per cent opacity over six consecutive minutes or as defined
, after the issue of this
d irective
, in Alberta ’s Environmental Protection and Enhancement Ac t Substance Release Regulation. 21

2) Any smoke emissions that may result in public concern must immediately be reported to the appropriate AER f ield c entre.

21 Substance Release Regulation AR 124/93.

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 55Alberta Energy Regulator

7.3 Ignition

1) Acid gas and sour gas flares and incinerators must have reliable systems t hat ensure continu ous ignition of any gas that may discharge to the device.

a) At all facilities (excluding gas plants and batteries regulated as crude bitumen batteries ) where the gas contains more than 10 mol/kmol H 2 S, a pilot or automatic ignition device
must be installed on flares and incinerators for continuous (e.g., sour water or
condensate tank flash

- gas) and intermittent (e.g., emergency depressur iz ing) sources.

b) At crude bitumen batteries where the H 2 S release rate is greater than 0.04 m 3 /hr, a pilot

or automatic ignition device must be installed on flares and incinerators for continuous (e.g., storage tank flash

- gas) and intermittent (e.g., truck loading operations ) sources

. c) At gas plants where gas contains more than 10 ppm H 2 S, pilots and automatic ignition

must be installed on flares and incinerators.

d) I f repeat failures have occurred or off

- lease odours or other impacts have resulted from failure to ensure ignition of sour gas, regardless of H 2 S content, the AER may require
installation of

i) pilots and automatic i gnition, and/or

ii) flame failure detection and alarms.

2) Manual flare and incinerator ignition subject to good fire safety practices will be accepted
for nonroutine purposes where

a) no continuous gas flow exists, and

b) no automatic relieving systems are connected to the stack.

7.3.1 Requests to Extinguish Sour Flare Pilots at All Batteries Significant volumes of fuel gas are used to sustain pilots for emergency flares at producing facilities. Continuous pilots may be necessary where gas is flared on a constant or routin e basis (see s ection 7.3) or where sour gas can potentially be released from pressure safety valves (PSVs) or emergency shutdown valves (ESDVs). In situations where gas is not continuously or routinely flared, where ESDVs are not configured to depressur ize facilities to flare, and where maximum foreseeable operating pressures are well below PSV release pressures, the potential exists to safely conserve natural gas by extinguishing the flare pilots.

When considering a request to extinguish flare pilots, the AER f ield c entre takes into account both local conditions and the operating history of the facility.

1) The l icensee, operator, or approval holder must get approval from the appropriate AER field centre to extinguish flare pilots at sour gas batteries.

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 56Alberta Energy Regulator

2) The issuing of an approval is only considered if

a) the maximum design operating pressure of production piping and pressure vessel systems is greater than 105 per cent of the maximum stabilized static wellhead pressure of all wells connected to the battery;

b) there will be no continuous or routinely flared gas streams;

c) t he facility is connected to sweet or level

- 1 or level

- 2 sour wells, as defined in ID 97

- 06 ;
d) no active injection or cycling schemes are taking place in or planned for any pools with
wells connected to the facility;

e) the facility connections to the flare are isolated with rupture disks upstream of PSVs

. This is subject to section 38(1)(b) of the Pressure Equipment Safety Regulation (A R 49/2006) administered by the Alberta Boilers Safety Association ; and

f) all manual depressur iz ing valve s connected to the flare system contain double block
valves.

3) Requirements for extinguis hing flare pilots are in appendix 11.

4) If the licensee , operator, or approval holder propose s to connect additional wells to an existing approval, they must first supply updated information and get approval from the appropriate AER f ield c entre.

7.4 Stack Desi gn

Flares and incinerators must meet or exceed the following stack design requirements :

1) Flare and incinerator stacks must be designed so that the total radiant heat intensity at ground
level will not exceed 4.73 kilo w atts per square metre ( kW/m 2 ).

a) Ground

- level radiant heat determinations for flares must be based on calculation procedures outlined in the AERflare.xls spreadsheet, ANSI/API Standard 521 s ection
6 .4.2.3, or GPSA Engineering Data Book (1 3 th edition), s ection 5. Incinerators must be

opera ted without exposed flame.

b) Exceptions to the requirement in section 7.4(1) will be considered on request to the AER
Authorizations Operations Group, provided an equivalent level of safety can be ensured.

i) In such cases , the licensee, operator, or approval holder must restrict access to the area where the radiant heat intensity guideline could be exceeded and must ensure that this area is free of combustible materials and vegetation. Access restrictions must include appropriate warning signs
, and the area mu st be clearly marked.

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 57Alberta Energy Regulator

ii) Appropriate procedures (e.g., safe

- work permit system) must be in place when it is necessary to work within the area where the radiant heat intensity guideline could be
exceeded.

2) Flares and incinerators located within a distance of 5 times the height of any neighbouring buildings must have a height of at least 2.5 times the height of the highest building
, tank
, or enclosed structure on the lease site

.

• The foregoing does not apply to devices for destruction of trace vent gases, such as those emitted from gas dehydrators.

3) Flare stacks for acid or sour gas containing more than 10 mol/kmol H 2 S must have a height of at least 12 m above ground level. At crude bitumen batteries where the H 2 S release rate is greater than 0.04 m 3 /hr, the mini mum height above ground level for the flare stack is 12 m, or such greater height as may be required to ensure that the AAAQO are not exceeded. Existing crude bitumen batteries must meet the minimum height requirement by December 31, 2015.

4) Flares and incin erators must be high enough to provide adequate plume dispersion to comply
with the AAAQO for SO 2 (see s ection 7.12).

a) Proper stack heights must be used in order to minimize fuel consumption. If the use of supplemental fuel gas is proposed, all other optio ns must be investigated first. Fuel gas use and amounts must be justified.

5) Interconnecting lines to the flare or incinerator must be secured to prevent whipping or flailing.

7.5 Sour and Acid Gas Flaring/Incineration Procedures

A l icensee, operator, or approva l holder must meet the requirements in this section or those in table 1, whichever is more stringent and results in more gas being shut in.

Devices for combustion of sour or acid gas must be designed and evaluated to ensure compliance with the AAAQO for SO 2 . Evaluations must us e methodologies acceptable to the
AER Authorizations Operations Group and ESRD

. One of the methods described in s ection 7.12

or ESRD’s Non

- Routine Flaring Modelling Guidance must be used.

1) A cumulative emissions assessment must be conducted if a flaring event is routine and if modelling results of the individual source exceed one

- third of the AAAQO for SO 2 (see section 7.12).

2) It is not necessary to do a cumulative emissions assessment if the r outine flaring is reasonably expected to be of short duration (less than four hours). Cumulative assessment requirements are intended to address the effects of multiple or continuous SO 2 sources in a

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 58Alberta Energy Regulator

given area (see s ection 7.12.3). Even if a cumulative emissions assessment is not required, modelling m ay still be required, as described in s ection 7.12.

a) Operating procedures must be put into place to limit the release duration if the routine stack design is based on the above exception

. 3) If operating procedures and controls are used to limit the magnitude or the duration of the
event, they must be documented and the facility must be operated in accordance with these procedures.

a) Automated shutdowns must be installed in facilities that ar e not staffed 24 hours/day (i.e., are semi

- attended) to ensure compliance with this requirement.

b) Staff responsible for operations must be aware of the current operating procedures and
must be trained at following the m

. 4) Operating procedures and related disp ersion evaluations must be provided to the AER upon request.

7.6 Liquid Separation

Entrained liquids in a flare or incinerator stream may reduce combustion efficiency and contribute to increased emissions of total reduced sulphur compounds, hydrocarbons, and products of incomplete combustion. Proper gas

- liquid separation facilities adequate to protect the pipeline system or gas combustion system must be used.

Note that for the purposes of this section and s ection 7.6.1, the terms knock out, knock out drum,

scru bber
, and separator are used interchangeably. The following requirements apply to all of
these devices.

1) Liquid separation equipment must be provided in both temporary (including well test) and permanent flare and incinerator systems to prevent the carryov er of liquid hydrocarbons, water, or other liquids.

2) Flare and incinerator separators must be designed in accordance with good engineering practice to remove droplets of 300 to 600 micron diameter and larger (see ANSI /API
Standard 521 ).

a) Designs must be based on the lowest density hydrocarbon liquids that could be released
to the flare or incinerator system.

3) The flare and incinerator separators or knockout drums must be designed to have sufficient holding capacity for liquid that may accumulate as a resul t of upstream operations, such as hydrocarbon carryover, liquid slugs, and line condensation.

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 59Alberta Energy Regulator

4) All flare and incinerator separators and knockouts must have visual level indicators and operating procedures to ensure that the liquid retention in the vessel w ill not exceed the
maximum design liquid level under all operating conditions.

a) For manually

- operated flares and incinerators (e.g.
, maintenance flares) where the flare or incinerator is normally isolated from the process stream (i.e.
, manual block valve), visual level indicators are not required whe n the operator has operating procedures in place to assess and mitigate the risk of liquid carryover. In the absence of an adequate operating procedure, the separator must be emptied before each flaring event

. i) These operating procedures must be provided to the AER immediately upon request.

5) All flare and incinerator separators and knockouts must have high

- level facility shutdowns or high

- level alarms that can be responded to by the operator b efore liquid carryover. If impacts such as liquid carryover or unacceptable smoke emissions (see s ection 7.2) have occurred as a result of failure to control liquid level, both high

- level facility shutdowns and high

- level alarms must be provided.

a) Where onl y manually operated flaring or incinerati o n will occur (such as manual equipment depressur iz ing, handling hydrates, or for well cleanup and initial testing) and the operation is continuously attended, high

- level facility shutdowns or high

- level
alarms are not required. Where personnel are not devoted to a flaring or incinerati o n operation, the operation will not be considered to be continuously attended, despite a
facili ty being continuously staffed.

6) High

- level alarms and facility shutdowns must be installe d on all flare and incinerator separators where liquid streams are directed to the separator for storage or where free liquids

are contained in continuously combusted streams.

7) Flare and incinerator separators or knockout drums must be designed and be in ac cordance
with AER Directive 055 : Storage Requirements for the Upstream Petroleum Industry

. 8) Design information on flare and incinerator system liquid separation equipment must be submitted upon request to the AER , including Directive 056 facilities application review

processes

.

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 60Alberta Energy Regulator

7.6.1 Exceptions to Separator Requirements
1) The AER does not require independent flare or incinerator separators in situations where the only vessels connected t o the flare or incinerator are production separators equipped with an High Level Shut Down ( HLSD ) or equivalent devices or with a system that prevents liquids from entering the flare or incinerator

. The following limitations apply to this exception:

a) The HLSD must be configured to shut down and block in, but not depressur iz e, the facility . The HLSD trip level must be set so that adequate vapour

- liquid separation is not impaired at maximum liquid level and vapour flow rates.

b) If liquid carryover involving sp ills occurs around the flare or incinerator or if black smoke is formed, the licensee, operator, or approval holder must install adequately sized flare or incinerator separators.

2) The AER does not require independent flare or incinerator separators for comb ustion devices
that destr oy trace vent gases emitted from gas dehydrators

.
7.7 Backflash Control

Inadequately purged flare or incinerator systems may have enough oxygen present to support combustion. Backflash may occur when the linear velocity of the combust ible mixture of gas and air in the system is lower than the flame velocity.

1) The l icensee, operator, or approval holder must take precaution s to prevent backflash using appropriate engineering and operating practices, including

a) installin g flame arresters b etween the point of combustion and the flare or incinerator
separator, or
b) provi d in g sufficient flare header sweep gas velocities (i.e., purge or blanket gas) to prevent oxygen intrusion into the flare or incinerator system.

2) Check valves are not an acceptable form of backflash control.

3) Safe work procedures must be in place to ensure complete purging of oxygen from flare or incinerator systems before ignition.

4) The licensee , operator, or approval holder must provide information on backflash controls to
the AER upon request if the AER determines that there is a concern with the equipment or
controls

.

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 61Alberta Energy Regulator

7.8 Flare and Incinerator Spacing Requirements

Licensees, operators, and approval holders must follow good engineering and safety prac tices in the layout of facilities. Despite liquid separation requirements, unexpected liquid carryover to
flares and incinerators can happen. Adequate spacing of these devices from areas frequented by workers and from sources of combustible gas is prudent. A l icensee, operator, or approval holder must consult fire protection codes and guidelines as part of facility design. Licensees, operators and approval holders must immediately report f ires (both on or off lease ) caused by flares or
incinerators to the local field centre

. 1) Flares and incinerators must be located, as measured from the base of the stack, at least

a) 50 m from wells, not including water disposal wells or water injection wells where there is no risk of flammable vapours ;
b) 50 m from storage tanks containing flammable liquids or flammable vapours ;
c) 25 m from any oil and gas processing equipment . This does not apply to combustio n devices that destr oy trace vent gases, such as those emitted from gas dehydrators. These devices must be designed to prevent ignition of gas that may leak from surrounding equipment (i.e., devices must be equipped with flame arresters) ; and

d) 25 m from cru de bitumen wells, storage tanks, or other sources of ignitable vapour, including lined

- earth excavations used to store waste oil at batteries regulated as
bitumen sites.
Flare knockout drums and integral knockout drums are exempt from flare and incinerator spacing requirements provided they have no means to vent to the atmosphere.

The incinerator that combusts gas from the sulphur recovery process is not required to meet incinerator spacing requirements for sulphur plant process equipment (i.e., converters and condensers).

2) Flares and incinerators must be located, designed, and operated so that th ey are not a hazard to public property. They must be at least 100 m away from surface improvements and
surface developments as defined in Directive 056 (except for surveyed roadways or road allowances, which must be 40 m from flares and incinerators)

. 22

3) The area a round flares and incinerators must be free of fire hazards . Flare or incinerator spacing and operating practices must comply with the Forest and Prairie Protection Act 23 and any regulations under that act. 24

22 The 40 m spacing requirement applies to pu blic road allowances and roads to wh ich the public has open access. There is no

spacing requirement for private licensee access roadways or private roadways on operating sites.

23 Forest and Prairie Protection Act , RSA 2000, c. F

- 19, as amended.

24 As at the date of this directive The Forest and Prairie Protection Regulations , AR 135/72

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 62Alberta Energy Regulator

4) The licensee, operator, or approval holder also comply with the Forest and Prairie Protection Regulations , part I ( AR 135/72 ) in unfor ested areas where there is a fire hazard associated with flare and incinerator operations.

5) In c ertain circumstances, the AER Authorizations Operations Group may consider variances
to AER flare and incinerator spacing requirements.

a) The AER discourages variance requests for new facilities.

b) Existing well site equipment spacing waivers in effect before the effective date of this
d irective are maintained.

c) A l icensee, operator, or approval holder requesting a spacing variance must first consult relevant codes and engineering practices and provide related information in support of the variance request.

7.9 Compliance with Fire Bans

Information on fire bans issued by Alberta Environment and Sustainable Resource Development
can be found at www.albertafirebans.ca
, directly from local municipal distri cts , or by calling
1

- 866

- 310

- FIRE (3473).

7.10 Noise

1) Flares and incinerators must be designed and operate in compliance with Directive 038

.
7.11 Flare Pits

Flare pits must not be used at any facilities built after July 1, 1996. For facilities built before July 1996, the licensee, operator, or approval holder must meet the following requirements:

1) All existing flare pits must be decommissioned by December 31
, 2015. Exemption requests for cryogenic flare pits must be submitted to the AER Authorizations Operations Group by December 31, 2015.

2) Produced liquids must not enter the pit, in accordance with section 8.080 of the OGCR

. 3) Flaring of sour gas must comply wit h the AAAQO

. 4) Gas containing more than 10 mol/kmol H 2 S must not be flared in pits.

5) The licensee, operator, or approval holder must conduct evaluations of solution gas flares for flare pits as described in sections 2 .3 and 2.9 and implement the resulting decision.

6) Access restrictions and procedures must be in place in areas around flare pits where ground

level radiant heat intensity at maximum flare ra tes will exceed 4.73 kW/m 2

. 7) If the facility is modified or if the facility increases its average annual production, the flare pit must be replaced with a flare stack.

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 63Alberta Energy Regulator

8) The AER can require the licensee, operator, or approval holder to replace flare pits with flares systems if any part of the facility is in noncompliance.

9) Operation of flare pits must comply with the provisions of the Forest and Prairie Protection
Act 25 and with any regulations under that act. 26

7.12 Dispersion Modelling Requirements for Sour and Acid Gas Combustion

T he following requirements apply to the combustion of sour gas in process equipment
, such as steam generators and process heaters, as well as to flares and incinerators.

1) The licensee , operator, or approval holder must demonstrate
, using dispersion modelling
methods outlined in ESRD’s Air Quality Mo del Guideline
, that SO 2 and H 2 S emissions from
the burning of sour and acid gas will not result in exceedance of the AAAQO if the gas
contains the following amounts or more :

• 10 mol/kmol H 2 S, or

• one tonne per day of sulphur emission rate during the event

.

A l icensee, operator, or approval holder combusting gas below the se concentrations and
emission rates is encouraged to consider dispersion modelling as part of environmental considerations. Facilities requiring approval from ESRD under the EPEA may need more detailed evaluation

. A l icensee, operator, or approval holder should consult ESRD direc tly in
these instances.

2) Dispersion modelling must be done by qualified technical personnel using computer models and methodologies acceptable to ESRD or, if appropriate, the method described in s ection
7.12 and appendix 7

.

7.12.1 Modelling Approach

The definitio n s of screening and refined dispersion modelling assessment s are in a ppendix 8

. 1) The licensee, operator, or approval holder must

• select a n appropriate model
,

• be able to demonstrate that the model selected is appropriate and follows ESRD accepted methodolog ies and standards , and

• use representative input parameters ( e .g., flow rate, gas composition) within the model and be prepared to demonstrate that those parameters are representative.

25 Forest and Prairie Protection Act , RSA 2000, c. F

- 19, as amended

26 As at the date of this directive, The Forest and Prairie Protection Regulations , AR 135/72

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 64Alberta Energy Regulator

7.12.2 Individual Source
1) Initial modelling may be conducted using the screening assessment provided in the
AERflare.xls and AERincin.xls spreadsheets.

2) For a screening assessment, ambient air quality modelling must use

a) stack

- specific terrain extracted by the spreadsheets or from 1:50 000 to pographical National Topographic System ( NTS ) maps,
b) the point s ource (not flare) option,

c) full screening meteorology,

d) appropriate land use characteristics, and

e) emission parameters as calculated by the AERflare.xls and AERincin.xls s preadsheets ( e. g., velocity, diameter
, and temperature inputs for dispersion modelling).

3) Modelling must address a full range of expected flow rate conditions and may include the low, average, and maximum flow rate.

4) The selected flare or incinerator design must not result in ground

- level SO 2 co ncentrations higher than those in the AAAQO

. a) A refined assessment may be used if the screening assessment results in an impractical stack height.

b) If it is not practical to design flares or incinerators of sufficient height for adequate dispersion, the li censee, operator, or approval holder may consider

i) u s ing an air quality management plan (see a ppendix 7 )
, ii) operating procedures and process controls to prevent emission rates or durations that
would exceed the AAAQO (see s ections 7.5, 7.12.4 ), and

iii) addin g fuel gas to increase heat release and plume rise. A s stated in s ection 7.4, proper flare stack height must be used to minimize fuel consumption.

c) The risk

- based criteria discussed in s ection 7.12.4 do not appl y to continuous (nontemporary) sour gas combust ion at permanent facilities.

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 65Alberta Energy Regulator

7.12.3 SO 2 Cumulative Emissions Assessment If predicted maximum hourly a ver age ground

- level concentrations for the individual continuous
source are more than one

- third of th e AAAQO for SO 2 , then the licensee, operator, or approval
ho lder must conduct an assessment o f cumulative effects of all routine SO 2 sources

. 1) The following steps must be followed for cumulative emissions assessments:

a) Identify the farthest downwind location where predictions exceed one

- third of the hourly average AAAQO for SO 2 to define the radius of influence.

b) Identify all other continuous sources of SO 2 within this radius of influence up to a maximum of 20 km; if no other sources of SO 2 are within the radius, no further modelling is required.

c) Quantify SO 2 emissio ns from these other sources and obtain all necessary input data, such as stack height and other parameters ( the licensee, operator, and approval holder
must share related data with each other on a timely basis). Maximum hourly flow rate
conditions must be used for all sources in the radius of influence.

i) In applications for a continuous source, other sources must be modelled at licensed
emission rates.

ii) SO 2 cumulative assessments are not required for nonroutine flaring, venting, and incineration ( e. g., well test or planned maintenance blowdown),.

d) Model the cumulative effect s of the SO 2 emission sources.

e) If the sum exceeds the AAAQO , determine the appropriate stack height required to meet
the AAAQO . All refined modelling must follow the methods outlined in t he Air Quality
Model Guideline (20 13 )

.

7.12.4 Temporary and Well Test Flaring Dispersion Modelling This section applies to temporary events that may require a permit (as described in section 3) and
well test flaring or incinerati o n activities. These activities include well testing, well cleanup, well servicing, coalbed methane well testing, underbalanced drilling, and sour gas pipeline (as
defined in Directive 56 ) blowdown through temporary flare or incinerator equipment. These activities exclude nonroutine flaring or incineration at permanent AER

- licensed facilities.

1) The licensee, operator, or approval holder must complete e ither the flaring ( AER flare.xls) or incinerator ( AER incin.xls) spreadsheet.

2) Information on ambient air quality impact eva luations must be included in requests to burn sour gas or, if no permit is required, must be provided to the AER upon request. The dispersion modelling within AER flare.xls or AER incin.xls may be sufficient if a screening assessment is adequate.

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 66Alberta Energy Regulator

3) Sour gas flares and incinerators must be designed for the gas composition and flow rates of
the situation for w hich there is a temporary permit (see section 7 for further information).

4) E quipment design or the operating procedures , or both, must address all modelled predictions that exceed the Albert a Ambient Air Quality Objectives , excluding predicted
values that meet the risk

- based criteria . The risk

- based criteria only apply to temporary

events.
a) Risk

- based criteria for temporary events allow limited exclusion of predicted ambient air quality result s, provided that

i) the 99 th percentile predicted values at a receptor do not exceed the one

- hour SO 2 Albert a Ambient Air Quality Objective , and

ii) the 99.9 th percentile predicted values do not exceed a predicted one

- hour SO 2 ambient concentration of 900 micrograms (μg) per m 3

.
Note that wh ereas model predictions up to 900 μg/m 3 will be considered, actual
exceedances of the Alberta Ambient Air Quality Objectives are never permitted.

b) Risk

- based criteria are incorporated into t he flar e and incinerator spreadsheet s for screening modelling

. c) If refined mode l ling is required to determine whether the temporary event meets the
risk

- based criteria, the refined modelling input files from the spreadsheet must be used

. d) The AER Authorizati ons Operations Group will also consider use of the risk

- based
criteria in situations where air quality management plans (see a ppendix 7 ) are necessary to ensure compliance with the Alberta Ambient Air Quality Objectives

. i) Air quality management plan decisi on criteria may be based on meteorological or ambient air quality monitoring data

. 5) Concurrent temporary sour gas burning (i.e., multiple well test flaring/ incinerating) must not
occur within 20 km of each other unless a licensee can demonstrate that the c umulative emissions from flaring can meet the AAAQO

. 6) Li censees must retain
, for one year after the flaring/incinerati o n event , information on dispersion assessments for flares or incinerators that require dispersion modelling but do not require a flaring permit (see s ection 3.3.2 ). This information must be provided to the AER
Authorizations Operations Group upon request.

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 67Alberta Energy Regulator

7.12.5 Nonroutine Flaring Dispersion Modelling This section applies to nonroutine planned and unplanned flaring from permanent flares. Temporary and well testing acti vities described in section 7.12.4 are not included here.

“Nonroutine” applies to intermittent and infrequent flaring, venting, and incineration. There are two types of nonroutine flaring: planned flaring and unplanned flaring.

• Planned flaring

— Flare event s where the operator has control over when flaring will occur, how long it will occur and the flow rates. Planned flaring results from the intentional depressurization of processing equipment or piping systems. Examples of planned flaring include: pipeline blowdowns
, equipment depressurization
, start

- ups , facility turnaround s, and well test s . Note that well testing dispersion modelling criteria are addressed in section
7.12.4.

• Unplanned flaring

— Emergency or upset operational activities closely associated with facility health and safety. Flare events where the operator has no control of when flaring will

occur . There are two types of unplanned flaring upset flaring and emergency flaring.

− Upset flaring occurs when one or more process parameters fall outside the allowable operating or design limits and flaring is required to aid in bringing the production back under control. Examples of upset flaring include: off

- spec product , hydra tes, loss of electrical power
, process upset, and operation error.

− Emergency flaring occurs when safety controls within the facility are enacted to depressurize equipment to avoid possible injury or property loss resulting from explosion, fire, or catastro phic equipment failure. Examples of upset flaring include: PSV overpressure and emergency shutdown.
Figure 8 summarizes the process for managing the nonroutine flaring of sour gas

.

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 68Alberta Energy Regulator

Figure 8. Comprehensive management of the nonroutine flaring of sour gas

1) The licensee, operator, or approval holder must evaluate impacts of nonroutine sour gas flaring on ambient air quality if

a) it is proposed to burn sour gas containing 10 mol/kmol H 2 S (1 per cent H 2 S) or more, or
b) 1 tonne of sulphur mass is released during the ev ent or the day (for multiple releases).

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 69Alberta Energy Regulator

Single nonroutine flare events that are predicted to be less than or equal to 15 minutes in duration and predicted to emit less than 1 tonne of sulphur over a rolling 24

- hour period are exempt from modelling require ments.

2) For new permanent flare stacks the licensee, operator, or approval holder must meet nonroutine flaring dispersion modelling criteria effective immediately upon the sanctioning
of this framework.

3) Unless the AER requires otherwise, w here previous mode lling reports of nonroutine flare events show compliance with the AAAQO using tools and methods no longer accepted by ESRD (e.g., SCREEN3, RTDM, ISC3, AQMG, and ERCB low risk criteria), the facility can continue to operate as is. If any emission changes oc cur at the respective facility or if the AER requests that new dispersion modelling be conducted for any reason, the operator will apply the flare management strategy flowchart (figure 9) and will reassess dispersion modelling using current modelling metho dology and tools.

4) For permanent flare stacks the licensee, operator, or approval holder must assess nonroutine flaring dispersion modelling criteria within the following timelines where facilities lack
evidence of dispersion modelling or where facilities are unable to satisfy the AAAQO for nonroutine flaring events using tools and methods no longer accepted by ESRD:

a) Sour gas processing plants: Within one year upon sanctioning of the framework.

b) Compressor stations and oil and gas batteries: Within two year s following sanctioning of
the framework.

c) Well sites and pipeline risers: Within four years following sanctioning of the framework.

d) If emissions change at existing AER

- licensed facilities, the licensee, operator, or approval holder must reassess nonroutine flaring dispersion modelling criteria when a renewal or amendment is required.

e) All processing facilities subject to the Environmental Protection Enhancement Act

– Activities Designation Regulation must remodel upon renewal.

5) Initial screen modelling may be conducte d using AERflare or AERincin or dispersion modelling methods outlined in ESRD’s Air Quality Model Guideline . If nonroutine refined modelling is required or if stack design is impractical, the licensee must apply the flare management strategy flow chart (figure 9) or equivalent, and dispersion modelling

e valuations must be conducted using methodologies described in ESRD’s Non

- Routine Flaring Modelling Guidance. The flare management strategy flow chart and refined modelling must be reapplied if facility operation or design changes significantly.

6) If modelling of worst

- case unplanned flaring scenarios show 99.9 th pe rcentile hourly predicted concentrations in excess of the AER SO 2 sheltering

- in

- place or evacuation criteria

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 70Alberta Energy Regulator

from D irective 071
, the licensee, operator, or approval holder must implement design or operational changes such that risk

- based criteria are met w ithin three years of the assessment. In the interim, for each unplanned flaring event at the facility, the licensee,
operator, or approval holder must do post

- event dispersion modelling (See section 7.12.5[1 1 ]).

7) If modelling of worst

- case scenarios shows t hat 99.9 th percentile hourly predicted
concentrations are lower than the AER SO 2 evacuation criteria from Directive 071 and higher than the Alberta Ambient Air Quality Objectives for SO 2 , then for each unplanned flaring event at the facility, the licensee, operator, or approval holder must do post

- event dispersion modelling (See section 7.12.5[1 1 ]).

8) For planned flaring events, the licensee, operator, or approval holder must develop flare management plans that meet the risk

- based criteria to ensure that the AAAQO are not exceeded, and implement them during flaring. It is acceptable for modelling to be based on actual flows and gas compositions, not licensed values.

9) If refined modelling for nonroutine flaring is required, the licensee must not exceed the risk

based criteria maximum number of flaring hours per calendar year described in ESRD ’s
Non

- Routine Flaring Modelling Guidance t able 1

. The licensee, operator, or approval holder

must log all flaring events, including flare duration, volume, and rates.

10) If nonroutine flaring exceeds the risk

- based criteria maximum number of flaring hours per year described in ESRD ’s Non

- Routine Flaring Modelling Guidance t able 1 or if the event
results in an exceedance of the Alberta Ambient Air Quality Objectives for SO 2 , the licensee,
operator, or approval holder must conduct post

- event dispersion modelling (see section 7.12.5[1 1 ]) and contact the AER Authorizations Operations Group immediately.

11) If post

- modelling is required, the actual conditions must be used. If site

- specific meteorological data during the event is not available, five years of meteorological data from a standard period is recommended using the ESRD data set ( h ttp://www.albertamm5data.com/ )

. One month per year must be modelled from the data set
, centred around the month of the event.
12) If the AER Authorizations Operations Group determines that the dispersion modelling has not been completed in accordance with Directive 060 requirements, the licensee, operator, or approval holder will be subject to enforcement action

. 13) The licensee, operator, or approval holder is not required to provide copies of nonroutine dispersion modelling or a flare management strategy flo wchart to the AER unless requested. Upon request, the licensee, operator, or approval holder must provide the evaluation to the
AER within five working days

.

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 71Alberta Energy Regulator

Figure 9. Flare management strategy flowchart

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 72Alberta Energy Regulator

8 Venting and Fugitive Emissions Management Requirements Venting is not an acceptable alternative to conservation or flaring.

8.1 General Requirements

1) All routine and nonroutine venting must be evaluated using the decision tree in the appropriate sections of this dire ctive.

2) The licensee , operator, or approval holder must burn all non conserved volumes of gas if volumes and flow rates are sufficient to support stable combustion.

a) The AER may investigate vented volumes of 500 m 3 /day, or even lower, if it appears that stable combustion of the gas may be feasible. U pon request, the licensee, operator,

or approval holder must provide its justification for volumes not combusted. Vented volumes include process venting, tank venting, and surface casing vents but exclude venting from pneumatic instrumentation and pumps.

b) Where metering is not required for gas vented in association with heavy crude or crude bitumen production, the AER may at any time request a new GOR or hourly rate tes t to be performed to verify vented volumes. Refer to Directive 017: Measurement Requirements for Oil and Gas Operations section 12.2.2 for acceptable testing methods

. Upon request, the operator must provide the evaluation to the AER within 30 working days.

3) P rovided that all other requirements in s ection 8 of this d irective are met , s ection 8.031 of
the OGCR permits the connection of pressure

- relieving devices at oil production batteries to open tanks ( i.e., “pop tanks”)

. 4) Hydrocarbon products stored in atmos pheric storage tanks at gas plants, compression stations, and gas batteries must not have a true vapour pressure of more than 83 kilo p ascals (kPa) at 21.1 ° C if the tanks are vented to the atmosphere

. 5) Unless directed by the AER to flare, incinerate
, or cons erve all casing gas and tank

- top gas,

t emporary, short

- term venting is allowed at wells (e.g.
, for well unloading and liquid cleanup), facilities , batteries where conservation is in place (see partial equipment outages in table 2), and pipelines (for natural gas transmission systems
, see s ection 6.3)
, with the following conditions:

a) Gas must contain less than 10 mol/kmol H 2 S and must not result in exceedances of the AAAQO outside the lease boundary

. b) Gas must not contain any free hydr ocarbon liquid ( if free hydrocarbon liquids are

presen t in the produced gas, a flare [ or other gas combustion device ] and liquid separation must be used).

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 73Alberta Energy Regulator

c) All liquids must be separated and contained in accordance with the s torage r equirements
of Directive 055

. d) Total gas volume must not exceed 2 10 3 m 3

, and the duration must not exceed 24 hours

. ( This does not include the clean out phase for well testing and servicing
, whe n liquids
and non combustible gases may prevent stable combustion. See s ection 8.5

. )

e) The l icensee, operator, or approval holder must conduct notification in accordance with

s ection 3. 8 and t able 2.

f) The AER f ield c entre may consider alternatives to these requirements should special
circumstances warrant. The l icensee, operator, or approval holder must contact the appropriate AER f ield c entre for approval of alternatives. For pipeline venting exemptions to these requirements
, see s ection 6.2.

6) The licensee or operator must notify residents and the appropriate AER field centre of nonroutine venting within 500 m and must comply with Directive 056 in respect of providing information about continuous flaring, incinerating
, and vent ing to persons entitled
it . Refer to section 3.8 for nonroutine venting notification requirements.

7) Vented gas must not constitute an unacceptable fire or explosion hazard and must comply
with the spacing requirements in section 7.8

. V enting must also not occur closer than

a) 25 m from any flame

- type equipment (for diesel engines equipped with air intake
shutoff device
, see AER Directive 036: Drilling Blowout Prevention Requirements and
Procedures ) ;
b) 50 m from a wellhead for vent stacks other than surface casing vents, or

c) 25 m from a wellhead for heavy oil/bitumen well, storage tank, or other ignitable vapour including lined earth excavations utilized for waste oil storage.

8) A flame arrester or equivalent safety device
, or proper engineer ing and operating procedures ( e. g., sufficient sweep gas velocity) must be used on all vent lines connecting oil storage
tanks to flare or incinerator stacks.

8.2 Limitations of Venting Gas Containing H 2 S or Other Odorous Compounds

1) Gas containing more than 10 mol/kmol H 2 S must not be vented to the atmosphere ( excluding crude bitumen batteries) . This includes gas off stock tanks, PSVs
, and equipment blowdown systems.
a) Sour pressure

- relief valves must be tied into flare systems if the gas contains more than
10 mol/kmol H 2 S or result in off

- lease H 2 S odours.

2) At crude bitumen batteries, H 2 S must not be vented to the atmosphere at a release rate greater than 0.04 m 3 /hr.

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 74Alberta Energy Regulator

a) Sour pressure

- relief valves must be tied i nto flare systems if the total H 2 S release rate is greater than 0.04 m 3 /hr H 2 S or result s in off

- lease H 2 S odours.

3) Venting and/or fugitive emissions must not result in any H 2 S odours outside the lease boundary. Venting and/or fugitive emissions must not result in any offensive hydrocarbon
odours outside the lease boundary that, in the opinion of the AER, are unreasonable either because of their frequency, their proximity to surface improvements and surface
develo pment (as defined in Directive 056 ) , their duration, or the ir strength

. a) The AER recommends that PSV s and blowdown systems be connected to a flare system where such systems are installed.

4) Venting must not result in exceedances of the AAAQO outside the lease boundary

.
8.3 Limitations on Venting Gas Containing Benzene

1) The l icensee or approval holder must control benzene emissions such that cumulative
emissions from all sources (dehydrators plus other sources) at the facility or lease site do not
exceed the li mits in t able 4 below.

Table 4. Cumulative f acility or lease s ite b en zene e mission l imits

Date facility or lease site commissioned Benzene e mission l imits

Before January 1, 1999 :

• more than 750 m to permanent residen t or public facility

• l ess than 750 m to permanent residen t or public facility 5 tonnes/yr 3 tonnes/yr

January 1, 1999, to January 1, 2007 3 tonnes/yr

After January 1, 2007 1 tonne/yr

2) The licensee or approval holder must ensure that vented gas from dehydrators meets all requirements specified in Directive 039 : Revised Program to Reduce Benzene Emissions from Glycol Dehydrators

.
8.4 Venting of Noncombustible Gas Mixtures

Release of inert gases such as nitrogen and carbon dioxide from upstream petroleum industry equipment or produced from wells may not have sufficient heating value to support combustion. These gases may be vented to atmosphere subject to the following requi rem ent:

1) Noncombustible gas mixtures containing odorous compounds including H 2 S must not be vented to the atmosphere if off

- lease odours may result. Alternatives to venting such gas include flaring or incinerating with sufficient fuel gas to ensure destruct ion of odourous compounds.

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 75Alberta Energy Regulator

8.5 Coalbed Methane Venting

A l icensee, operator, or approval holder may vent gas as part of the evaluation of coalbed methane development and technologies if the requirements for venting are met (i.e.
, gas conservation has been determined not to be economically feasible , the AER has not directed that conservation be implemented, and flows will not support stable combustion). Once conservation or combustion of the gas is possible, these options must be u s ed. If conservation is directed by the AER, the gas must be conserved.

Gas conservation in long

- term coalbed methane projects must be evaluated
, and test durations are limited by requirements found in s ection 3.2.

8.6 Fugitive Emissions Management

1) The facili ty licensee must develop and implement a program to detect and repair leaks.

a) These programs must meet or exceed the Canadian Association of Petroleum Producers (CAPP) Best Management Practice for Fugitive Emissions Management

. 2) The l icensee, operator, or approval holder must use pressurized tank trucks or trucks with suitable and functional emission controls when transporting sour fluids from upstream petroleum industry facilities.

8.7 Req uirements for the Peace River Area

8.7.1 Background In January 2014, a panel of AER hearing commissioners conducted an inquiry on odours and
emissions from heavy oil operations in the Peace River area of Alberta. On March 31, 2014
, the panel released Decision 2 014 ABAER 005: Report of Recommendations on Odours and
Emissions in the Peace River Area . The AER accepted all of the panel’s recommendations within its jurisdiction

. T he commitments the AER made in its response to the report included requir ing that

• heavy oil and bitumen operations in the Peace River area capture and flare, incinerate
, or conserve all casing gas and tank

- top gas.

8.7.2 Peace River Area Definition

The Peace River a rea includes the Three Creeks, Reno, Seal Lak e, and Walrus areas (see figure
10 below)

.

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 76Alberta Energy Regulator

Figure 10. Peace River area

8.7.3 Requirements
1) Unless otherwise directed in Bulletin 2014

- 17 , licensees, operators
, and approval holders that produce heavy oil and bitumen in the Peace River a rea, as illustrated on figure 10 , must

a) capture and flare, incinerate, or conserve all casing gas and tank

- top gas; or
b) shut in all wells that are venting casing gas or tank

- top gas.

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 77Alberta Energy Regulator

9 Sulphur Recovery Requirements and Sour Gas Combustion Certain types of oil production, gas gathering, and nonasso ciated gas battery facilities can have significant sulphur emissions from combustion (by flaring, incinerating
, or us e as equipment fuel) of sour solution gas, from low

- pressure produced water flash

- gas, and from flaring of glycol dehydrator vent gas. Appr opriate pollution prevention measures must be implemented in
such situations to minimize sulphur emissions from combustion of sour or acid gas.

1) Guidelines in ID 2001

- 03 apply to sour gas plants and other upstream petroleum facilities such as oil production batteries, gas batteries, and pipeline facilities.

2) For in situ bitumen sites, the sulphur recovery requirements in t able 1 of ID 2001

- 03 apply. The sulphur inlet used to determine the sulphur recovery requirement in t able 1 is based on total sulphur emissions from combustion of sour produced gas as fuel or by flaring or
incineration divided by the number of days over a calendar quarter year.

9.1 Sulphur Recovery Exemption at Solution Gas Conservation Facilities

The AER and ESRD may deviate from sulphur recovery requirements in circumstances where sulphur emissions would be minimal and sulphur recovery would re nder gas conservation
uneconomic.

Solution gas conservation clustering schemes that have a total inlet sulphur of between 1 and
5 tonnes/day may be considered for flexibility by ESRD and the AER in the application of
ID 2001

- 03

. Provisions for deviations from the sulphur recovery guidelines are in section 4 of
ID 2001

- 03

. 1) The l icensee or operator must apply to the AER for a variance from the sulphur recovery guidelines as part of related production project applications submitted to the AER. The application must take the form of a nonroutine Directiv e 056 application, and applicants must indicate on the application that the facility will NOT comply with the requirements of
Directive 060

. 2) The licensee or operator must demonst rate to the AER, using the methodology in s ection 2.9
, that implementin g sulphur recovery would make the gas plant uneconomic.

a) If gas production with sulphur recovery is economic, the licensee or operator must implement sulphur recovery.

3) The l icensee or operator must demonstrate that revenues and cost estimates are reasonable.

a) Capital cost estimates for sulphur recovery must be based on appropriate te chnologies

. The l icensee or operator must identify cost

- effective processes suited to the facilities in question.

b) Information on the following must be available to the AER upon request:

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 78Alberta Energy Regulator

i) volumes of gas available, including assessment of clustering other gas sources in the

area
ii) incremental energy ( e.g., fuel gas) requirements for gas compression and processing related to gas sweetening

iii) incremental energy (fuel gas) requirements for sulphur recovery processes

iv) H 2 S concentration of gas, along with expected average sulphur emissions and variability of sulphur emissions

v) information on technology selection and costs for equipment ( e.g., compression), gas gathering systems, and sulphur recovery processes. Note that the economic
evaluation is based on incremental costs of gas conservation ; therefore, equipment costs related to oil production, processing, and transportation must not be included

4) The l icensee or operator must consult with residents within the radius set out in Directive
056 , specifically explaining that a variance of the sulphur recovery guidelines is being applied for. Any objections must be disclosed in related facility applications.

5) The AER and ESRD will consider the scop e of the production project, the duration of the sulphur emissions, and the views of the local public in making decisions on applying the sulphur recovery guidelines.

a) The existing processes used for EPEA approvals for sour gas processing plants and for
AER approvals will be used to measure public acceptance of any proposals. If there are no unacceptable impacts and nearby residents do not object , meeting the sulphur recovery guidelines may not be required for solution gas facilities.

b) The AER does not allow multiple nonsulphur

- recovery sour operating sites in close proximity where it is practical to consolidate the facilities in one location and install sulphur recovery.

i) Sour gas facility proliferation guidelines in ID 2001

- 03 s ection 6 stipulate how the
AER will assess this matter.

6) The variances do not appl y to sour gas production and processing facilities handling primarily nonassociated gas.

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 79Alberta Energy Regulator

10 Measurement and Reporting Requirements for measuring and reporting volumes of gas flared, incinerated, and vented are provided in Directive 017: Measurement Requirements for Oil and Gas Operation
, Directive 007: Volumetric and Infrastructure Requirements , and the O GCR

.
10.1 Flaring, Inc inerati o n, and Venting Records (Logs)

1) The l icensee, operator, or approval holder must maintain a log of flaring, incinerati o n, and venting events and respond to public complaints in order to comply with release reporting requirements.

a) Release reporting re quirements are defined in IL 98

- 01 and ESRD ’s Release Reporting
Guideline

. b) Logs must include information on complaints related to flaring, incinerati o n, and venting and how these complaints were investigated and addressed.
c) Logs must describe each nonroutine flaring, incinerati o n, and venting incident and any changes made to prevent future nonroutine events from occurring.
d) Logs must include the date, time, duration, gas source or type ( e. g. , sour inlet gas, acid gas), rates, and volumes for each incident.
e) Logs must be kept for a t least 12 months.
2) Flaring, incinerati o n, and venting records must be made available to the AER upon request for each production facility, pipeline, and gas processing facility where flaring, incinerati o n, and venting occur.
a) A l icensee, operator, or approval holder may retain logs for remote or semi

- attended facilities at a central location (e.g., a regional office) where public complaints related to the facility in question would normally be received.
3) In situations governed by temporary flaring/incinerati o n permits, a s our g as f laring /incineration d ata s ummary r eport ( see appendix 6 ) must be comple ted in full and
submitted to the AER Authorizations Operations Group within three weeks of the flaring/incinerati o n completion date.

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 80Alberta Energy Regulator



## Appendix 1 References and Contacts Cited

AER Documents * Oil and Gas Conservation Regulations

Bulletin 2004

- 15: New Well Test Capture (WTC) System

Implementation Date Reminder: Changes to Final WTC Pressure ASCII Standard (PAS) Formats and Version 4.0 PAS File Business Rules Im plications

Directive 007: Volumetric and Infrastructure Requirements Directive 008: Surface Casing Depth Requirements Directive 017: Measur ement Requirements for Oil and Gas

Operations Directive 019: Compliance Assurance Directive 036: Drilling Blowout Prevention Requirements

and Procedures Directive 037: Service Rig Inspection Manual Directive 038: Noise Control Directive 039: Revised Program to Reduce Benzene

Emissions from Glycol Dehydrators Directive 040: Pressure and Deliverability Testing Oil and

G as Wells

— Minimum Requirements and Recommended Practices Directive 055: Storage Requirements for the Upstream

Petroleum Industry Directive 056: Energy Development Applications and

Schedules Directive 065: Resources Applications for Conventional Oil

and Gas Reservoirs Directive 066: Requirements and Procedures for Pipelines Directive 071: Emergency Preparedness and Response

Requirements for the Upstream Petroleum Industry

General Bulletin (GB) 2002

- 05: EUB Requirements for

Evaluation of Solution Gas Vent Gas Conservation

Interim Directive (ID) 91

- 03: Heavy Oil/Oil Sands

Operations ID 94

- 03: Underbalanced Drilling ID 97

- 06: Sour Well Licensing and Drilling Requirements ID 2001

- 03: Sulphur Recovery Guidelines for the Province

of Alberta

Informational Lette r (IL) 98

- 01: A Memorandum of

Understanding Between Alberta Environment and the Alberta Energy and Utilities Board Regarding Coordination of Release Notification Requirements and Subsequent Regulatory Response

IL 2001

- 01: Appropriate Dispute Resolution (A DR)

Program and Guidelines for Energy Industry Disputes AERflare.xls and AERincin.xls s preadsheets AERflare: A Screening Model for Non

- routine Flaring Approvals and Routine Flare Air Dispersion Modelling for Sour Gas Facilities

ABflare: A Refined Air Quality Dispersion Model for Evaluating Non

- routine Flaring for Sour Gas Facilities

ST13 A : Alberta Gas Plant/Gas Gathering System

Activities

— Annual Statistics ST13 B : Alberta Gas Plant/Gas Gathering System

Activities

— Monthly Statistics ST13C: Alberta Gas Gathering System Activities

— Monthly

Statistics ST60: Crude Oil and Crude Bitumen Batteries Monthly

Flaring, Venting, and Production Data ST60A: Crude Oil and Crude Bitumen Batteries Annual

Flaring, Venting, and Production Data ST60B: Upstream Petroleu m Industry Flaring and Venting

Report

Alberta Energy Document Information Letter (IL) 99

- 19: Otherwise Flared Solution

Gas Royalty Waive r Program

Alberta Environment and Sustainable Resource Development Air Quality Model Guideline Alberta Ambient Air Quality Objectives and Guidelines Environmental Protection and Enhancement Act Non

- routine Flaring Management: Modelling Guidance Release Reporting Guideline 1028

- F
Alberta Utilities Commission Document Alberta Utilities Commission Rule 007: Applications for

Power Plants, Substations, Transmission Lines, and Industrial System Designations

Other Documents Alberta Pressure Equipment Safety Regulations, Alberta

Safety Codes Act, The Pressure Equipment Safety Authority (AR 49/2006) ANSI/API

- 521, Pressure

- Relieving and Depressuring

System, American Petroleum Institute Clean Air Strategic Alliance (CASA), 1998, Management of

Routine Solution Ga s Flaring in Alberta
, Report and Recommendations of the Flaring Project Team (Edmonton, Alberta) CAPP, 2013, Sour Non

- routine Flaring Framework CAPP, 2006, Best Management Practices for Facility Flare

Reduction (continued)

* AE R documents are available on the AER website at www.aer.ca and from Information Services, 250

– 5 Street SW, 10th Floor, Calgary

AB T2P 0R 4; Tel: 403

- 297

- 8190; Fax: 403

- 297

- 7040.

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 81Alberta Energy Regulator

Other Documents (continued) CASA, 2002, Gas Flaring and Venting in Alberta, Report

and Recommendations for the Upstream Petroleum Industry by the Flaring/Venting Project Team (Edmonton, Alberta) CASA, 2004, Gas Flaring and Venting in Alberta, Report

and Recommendations for the Upstre am Petroleum Industry, Prepared by the Flaring and Venting Project Team for the Clean Air Strategic Alliance Board of Directors (Edmonton, Alberta) CASA, 2005, Flaring and Venting Recommendations for

Coal Bed Methane Final Report, Prepared by the Flaring

a nd Venting Project Team for the Clean Air Strategic Alliance Board of Directors (Edmonton, Alberta) CASA, 2005, Flaring and Venting Review of Well Test

Time Limits Final Report, Prepared by the Flaring and Venting Project Team for the Clean Air Strategic A lliance Board of Directors (Edmonton, Alberta ) Consumer Price Index forecast, Government of Alberta,

Department of Finance w ebsite : www.finance. gov.ab.ca/aboutalberta/economic_bulletins/ current_economic_indicators.pdf En gineering and Geoscience Profes sions Act, RSA 2000 c. E

11 Forest and Prairie Protection Act , RSA 2000 c. F19 Forest and Prairie Protection Regulations Part I and II (AR 135/72) GLJ Petroleum Consultants Limited
, Commodity Price

Forecast , “Natural Gas and Sulphur Price Forecast Table” Gas Flaring and Venting in Alberta: Report and

Recommendations for the Upstream Petroleum Industry by the Flaring/Venting Project Team, CASA GPSA E ngineering Data Book (1 3 th edition), Gas

Processors Suppliers Association Guide for Estimation of Flaring and Venting Volumes from Upstream Oil and Gas Facilities, CAPP Industry Recommended Practice (IRP) Volume 4

- 2000/02: Well Testing and Fluid Handling, Canadian Petroleum Safety Council PTAC Alberta Upstream Petroleum Research Fund Terms of Reference AER Contacts Authorizations Operation s Group : 403

- 297

- 6179 Field Centres

Bonnyville: 780

- 826

- 5352 Midnapore: 403

- 297

- 8303 Drayton Valley: 780

- 542

- 5182 Grande Prairie: 780

- 538

- 5138 High Level: 780

- 926

- 5399 Medicine Hat: 403

- 527

- 3385 Red Deer: 403

- 340

- 5454 St. Albert: 780

- 460

- 3800 Wainwright: 780

- 842

- 7570 Fort McMurray Office: 780

- 743

- 7214

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 82Alberta Energy Regulator



## Appendix 2 Definitions of Terms as u sed in Directive 060

Acid gas Gas that is separated in the treating of solution or nonassociated gas that contains hydrogen sulphide (H 2 S), total reduced sulphur compounds, and/or carbon dioxide (CO 2 ). Associated gas Gas that is produced from an oil or bitumen reservoir. Thi s may apply to gas produced from a gas cap or in conjunction with oil or bitumen.
Carbon c onversion
e

fficiency (CCE) The CCE quantifies the effectiveness of a device to oxidize hydrocarbons and is the relative conversion of carbon compounds in the reacta nts to products of complete and incomplete combustion. Incomplete combustion products include unburnt hydrocarbons ( hydrocarbon [ HC ] measured as methane [ CH 4 ]) and other partially oxidized carbon compounds
, such as carbon monoxide ( CO ) in the exhaust. CCE is reported as the percentage of carbon in the fuel that is converted to CO 2 and is obtained from

2 

### Mass Rate of Carbon in the Fuel Converted to CO CCE Mass Rate of Carbon in the Fuel =
With this definition, the mass and molar efficiency are the same. An adjustment must be made if there is CO 2 in the inlet stream
, as it does not react. The adjustment depends on the fraction of 2, fuel 

### CO and hydrocarbons

, X Y fuel 

### C H in the gas stream entering the device and the number of carbon moles (X) per molecule of hydrocarbon. CCE can be determin ed from exhaust and fuel c oncentration measurements using

This equation reduces to the following familiar expression if the inlet does not contain CO 2 (CO 2,inlet = 0):

2,

2, 

### ( ) stack

stack stack stack 

### CO CCE CO CO HC = + + Clustering T he practice of gathering the solution gas from several flares or vents at a common point for conservation.
Combustion
e

fficiency (CE) The CE quantifies the effectiveness of a device to fully oxidize a fuel. Products of complete combustion (i

. e ., CO 2 , H 2 O
, and sulphur dioxide [ SO 2 ]) result in all of the chemical energy released as heat. Products of incomplete combustion ( e.g., CO, unburnt hydrocarbons, other partially oxidized carbon compounds, H 2 S
, and other reduced and partially oxidized sulphur compounds) reduce the amount of ener gy released. CE is reported as the percentage of the net heating value that is released as heat through combustion.
Conservation The recovery of solution gas for use as fuel for production facilities, other useful purposes (e.g., power generation), sale, or beneficial injection into an oil or gas pool.
Conservation

e

fficiency Conservation e fficiency (%) = (Solution g as p roduction

– Flared

– Vented) / (Solution gas p roduction) x 100 Conserving facility Any potential tie

- in point that is conserving gas, s uch as batteries, plants, compressor stations, pipelines, and pump stations.
Crude bitumen Refer to the Oil and Gas Conservation Act

. 2, 2,
,

2, ( ( ))( )

( ) stack fuel X Y fuel stack stack

stack stack stack CO CO X C H CO HC CCE CO CO HC − +

= + +

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 83Alberta Energy Regulator

Crude bitumen battery A crude bitumen battery is an oil battery with crude bitumen production that has a density of 920 kg/m 3 or greater at 15 degrees Celsius

. Crude oil A mixture mainly of pentanes and heavier hydrocarbons that may be contaminated with sulphur compounds, that is recovered or is recoverable at a well from an underground reservoir and that is liquid at the conditions under which its volume is measured or estimated, and includes all other hydrocarbon mixtures so recovered or recoverable except raw gas, condensate or crude bitumen. Crude oil battery An oil battery with crude oil production ex cluding production that has a density of 920 kg/m 3 or greater at 15 degrees Celsius

. Emergency flaring Emergency flaring occurs when safety controls within the facility are enacted to depressurize equipment to avoid possible injury or property loss resulting fr om explosion, fire or catastrophic equipment failure. Examples of upset flaring include: PSV overpressure; and emergency shut down Fugitive emissions Unintentional releases of gas resulting from production, processing, transmission, storage , and delivery. Gas battery A system or arrangement of tanks and other surface equipment (including interconnecting piping) that receives the effluent from one or more wells that might provide measurement and separation, compression, dehydration, dew point control, H 2 S scaveng ing where < 0.1 t onne/day of sulphur is being treated, line heat ing, or other gas handling functions prior to the delivery to market or other disposition. This does not include gas processing equipment that recovers more than 2 m 3 /day o f liquids or that processes more than 0.1 t onne/day of sulphur. Gas processing plant A system or arrangement of equipment used for the extraction of H 2 S, helium, ethane, natural gas liquids, or other substances from raw gas; does not include a wellhead separator, tre ater, dehydrator, or production facility that recovers less than 2 m 3 /day of hydrocarbon liquids without using a liquid extraction process (e.g.
, refrigerant, desiccant). In addition, does not include an arrangement of equipment that rem oves small amounts of sulphur (less than 0.1 tonne/day) through the use of nonregenerative scavenging chemicals that generate no H 2 S or SO 2 . Nonassociated gas Gas produced from a gas pool (i.e., not associated with oil or bitumen reservoirs or with production).
Nonroutine f laring,

v

enting, i ncinerati o n “Nonr outine” applies to intermittent and infrequent flaring venting and incineration

. There are two types of nonroutine flaring: planned flaring and unplanned flaring.

Oil battery A system or arrangement of tanks or other surface equipment or devices receiving the effluent of one or more wells for the purpose of separation and measurement prior to the delivery to market or other disposition. Planned Flaring Flare events where the operator has control over when f laring will occur, how long it will occur and the flow rates. Planned flaring results from the intentional de

pressurization of processing equipment or piping systems. Examples of planned flaring include pipeline blowdowns
, equipment depressurization
, star t

- ups , facility turnarounds
, and well tests.
Qualified technical professional A person holding an accredited professional qualification and acting within that person’s professional scope of practice.
Risk

- based criteria Refer to the ESRD’s Non

- Routine Flaring Management Modelling Guidance for the purpose of Directive 060 only.

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 84Alberta Energy Regulator

Routine f laring,

v

enting, i ncinerati o n “Routine” applies to continuous or intermittent flaring, venting
, and incinerati o n that occurs on a regular basis due to normal operation. Examples of routine flaring include: glycol dehydrator reboiler still vapour flaring; storage tank vapour flaring; flash tank vapour flaring; and solution gas flaring. Screening assessment This is the quickest and simplest dispersion modelling approach. Screening assessments usually provide a conservative (worst

- case) estimate of downwind concentrations. If exceedances of the Alberta Ambient Air Quality Objectives and Guidelines are predicted by a screening asse ssment, a refined assessment may be necessary. Alternatively, stack design parameters may be modified until predicted ambient air quality meets the Alberta Ambient Air Quality Objectives and Guidelines

. Site A single surface lease (pads counted as one lea se) where gas is flared or vented Solution gas A ll gas that is separated from oil or bitumen production. Sour gas Natural gas, including solution gas, containing H 2 S.
Source All gas flared, incinerated, or vented from a single operating site, such as an oil battery or multiple

- well pad. Sulphur c onversion
e

fficiency (SCE) The SCE quantifies the effectiveness of a device to oxidize sulphur and is the relative conversion of sulphur compounds in the reactants to products of complete and incomplete combusti on. Incomplete combustion products include unburnt H 2 S, other reduced sulphur compounds (measured as H 2 S)
, such as carbonyl sulphide and carbon disulphide (especially if present in the fuel)
, and other partially oxidized sulphur compounds
, such as sulphur trioxide ( SO 3 ) in the exhaust (measured as SO 3 ). SCE is repo rted as the percentage of sulphur in the fuel that is converted to SO 2 and is obtained from

2 

### Mass Rate of Sulphur in the Fuel Converted to SO SCE Mass Rate of Sulphur in the Fuel =
With this definition, the mass and molar efficiency are the sa me. SCE can be determined from stack gas c oncentration measurements using

2,

2, 3, 2 

### ( + ) stack

stack stack stack 

### SO SCE SO SO H S = + Sulphur emissions A ll air emissions of sulphur

- containing compounds, including SO 2 , H 2 S, and total reduced sulphur compounds (e.g., mercaptans). Sulphur emissions from flare stacks are expected to be primarily in the form of SO 2 , with minor amounts of other compounds. Sulphur recovery efficiency Sulphur recovery efficiency = (sulphur produced + injected)/(sulphur produced + injected + sulphur emissions)
, where the sulphur emission is normally SO 2 expressed in sulphur equivalence. All values are units of mass. Unplanned Flaring E mergency or upset operational activities closely associated with facility health and safety. Flare events where the operator has no control of when flaring will occur. There are two types of unplanned flaring: upset flaring and emergency flaring. Upset Flaring Upset flaring occurs when one or more process parameters fall outside the allowable operating or design limits and flaring is required to aid in bringing the production back under control. Examples of upset flaring include: off

- spec product; hydrates; loss of electrical power; process upset; and operation error. Venting The intentional controlled release of uncombusted gas.

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 85Alberta Energy Regulator



## Appendix 3 Abbreviations

10 6 m 3 million cubic metres
10 3 m 3 thousand cubic metres AAAQO Alberta Ambient Air Quality Objectives and Guidelines
AOF absolute open flow
APEGA Association of Professional Engineers, and Geoscientists of Alberta
ASET Association of Science and Engineering Technology Professionals of Alberta
AUPRF Alberta Upstream Petroleum Research Fund
BMP Best Managemen t Practices
CAPP Canadian Association of Petroleum Producers
CASA Clean Air Strategic Alliance
CO 2 carbon dioxide
CSA Canadian Standards Association
DDS Digital Data Submission System
EPEA Environmental Protection and Enhancement Act
ESDV emergency shutdown valve
ESRD Environment and Sustainable Resource Development
FIS Field Information System
GOR gas

- to

- oil ratio (gas:oil)
H 2 S hydrogen sulphide
HLSD high

- level shutdown
km kilometre
kPa kilopascal
mol/kmol mole per kilomole
MJ megajoule
MJ/m 3 megajoule per cubic metre
MW megawatt
NOWPP New Oil Well Production Period
NPV net present value
NRFTT Non

- routine Flaring Task Team
NTS National Topographic System

ppm parts per million
PRA Petroleum Registry of Alberta (now PETRINEX)
PSV pressure safety valve
PTAC Petroleum Technology Alliance Canada
EPAC Exp lor ers and Producers Association of Canada
SO 2 sulphur dioxide

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 86Alberta Energy Regulator



## Appendix 4 Background to Directive 0 60

Concerns about flaring prompted the E U B (now the AER) and Alberta Environment (now Alberta Environment and Sustainable Resource Development) to support Alberta Research Council research on flaring. Findings reported in 1996 suggested that the efficiency of flare stacks at destroying waste gas was not as high as originall y thought and that vari ous products of incomplete
combustion were in flare emissions.

The EUB then consulted with stakeholders from industry, the public, and other government sectors and reviewed existing policies on solution gas conservation. CAPP brough t the issue of flaring to
the CASA b oard of d irectors in November 1996 and established the Flaring Project Team in February 1997 to develop recommendations to address potential and observed impacts of flaring. In its 1998 final report, Management of Routin e Solution Gas Flaring in Alberta: Report and Recommendations of the Flaring Project Team , the Flaring Project Team recommended a framework for solution gas flaring management and a decision tree process for reduc ing flar ing

. The EUB Implements the CASA Re commendations

In 1999 in the first edition of Directive 060 (then called Guide 60 ) , the EUB implemented the solution gas management framework ( s ection 2 ), the decision tree process ( s ection 2.3 ), and other CASA recommendations. The guide mandated firm, short

- term solution gas flare reduction targe ts
of 15 per cent and 25 per cent by the end of 2000 and 2001
, respectively
, relative to the 1996
revised baseline of 1340 10 6 m 3 per year; the guide also defined maximum limits on the total volume of solution gas that could be flared at individual sites if voluntary targets were not met.

In 2000, a new CASA team, the Flaring/Venting Project Team, convened to review progress made

o n the 1998 recommendations as well as make further recommendations on flaring, incinerati o n, and venting. The result was the 2002 report, Gas Flaring and Venting in Alberta: Report and Recommendations for the Upstream Petroleum Industry by the Flaring/Vent ing Project Team . The report said that implementation of the solution gas management framework and the flare reduction targets by the upstream petroleum industry had successfully resulted in a 53 per cent reduction in solution gas flaring relative to the 1 996 baseline.

On the basis of that success, the Flaring/Venting Project Team recommended that a similar decision tree process be applied to solution gas venting, well test flaring, and facility flaring. T he team
recommended that a 50 per cent reduction tar get be maintained for all solution gas flaring in
Alberta relative to the 1996 baseline. Additional reports and recommendations were put forward in September 2004 and in March and June 2005. These recommendations were implemented through
a rewrite of Direc tive 060 released in November 2006. Significant changes included changing the economic threshold of the feasibility test for solution gas conservation from a net present value of

zero to

- $55 ,000. Also, economic evaluations were no longer required for site s that flared, incinerated, or vented less than 900 m 3 /day of solution gas. Another significant addition to the directive was the concept of a duration limit for well test flaring and incinerati o n.

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 87Alberta Energy Regulator

Canadian Association of Petroleum Producers Recommendation s In 2004, CAPP established the Nonroutine Flaring Task Team (NRFTT) to review dispersion modelling requirements for intermittent and infrequent flaring. The NRFTT comprised government and industry. The CAPP document titled, Sour Non

- Routine Flaring Framew ork outlines the new regulatory approach and comprehensive plan for managing nonroutine flaring as developed by the NRFTT, and the process that led to its development.

Work on further reducing flaring, incinerati o n , and venting continues.
Ongoing Researc h The AER supports the 2004 CASA recommendation s for additional research so that Alberta can continue to move toward the use of practical flare combustion efficiency standards where flaring is necessary. The AER expects that industry will support and part icipate in the funding of continued research focusing on

• understanding the relationship between gas composition and combustion efficiency, including
the effects of H 2 S content;

• understanding the effects of flare stack design, including flare tips on combus tion efficiency;
and

• reviewing the results of any field testing of combustion efficiency monitoring methodologies.

The AER supports the Petroleum Technology Alliance ’s Alberta Upstream Petroleum Research Fund (AUPRF). AUPRF is an industry

- sponsored fund su pported by CAPP and the Explorer and Producers Association of Canada ( EPAC ) . The objective of AUPRF is to provide an efficient and effective mechanism to coordinate, initiate, fun d, complete and communicate on e nvironmental
research that is needed by the industry and government regulators to enabl e a prosperous upstream oil and gas industry that achiev es socially and environmentally responsible recovery of Canada’s petroleum resources through effective, market

- driven collaboration. AUPRF supp orts practical
science

- based studies that develop credible and relevant information to address knowledge gaps in the understanding and management of high priority environmental and social matters related to oil and gas exploration and development in Albert a. Research reports are shared broadly with the oil and gas industry as well as with regulators, government agencies, and other stakeholders

.

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 88Alberta Energy Regulator



## Appendix 5 Information for Permit Request to Flare o r Incinerate in Exceedance of Flared or Incinerated Volume A llowance Threshold (600, 400, or 200 10 3 

## m 3 

## Exceedance)

If flare d or incinerated volumes are expected to exceed the volume allowance threshold during temporary operations, more information must be submitted to the AER

. 1) Underbalanced drilling requests must include the following information:

a) an explanation and supporting documentation o n how flaring or incineration rates are determined; possible sources of these estimates are
i) offset well AOF tests, or

ii) flaring or incineration rates from offset underbalanced d rilling operations;

b) the estimated time required to drill the well;

c) if a well test is proposed, the total volume requested for the test.

2) For well tests that are expected to exceed the volume allowance threshold , the request must include the following information:

a) A brief description of the development required to bring the well onto production (e.g., length and size of pipeline to tie in well, well site facilities, compression, gas processing facilities)

b) T he minimum recovera ble reserves required for the well to be economic (minimum economic reserves)

c) D etails of the analysis used to determine the minimum economic reserves . L icensees may use simplified “netback” economics showing the current operating profit ( revenues minus

ope rating costs ) to estimate the recoverable reserves required to pay out facility investment costs; alternatively, licensees may choose to present a more detailed economic analysis involving features such as discounted gas flow projections)

d) T he estimated recovery factor and surface loss for the pool

e) T he estimated initial reservoir pressure

f) T he amount of reservoir depletion being targeted by the test ( the licensee must provide a brief description justifying this depletion in relation to the minimum economic reserve)

. T he recommended maximum pressure depletion guidelines are

i) 1 per cent of the first 5000 kPa of reservoir pressure, and

ii) 0.5 per cent of the reservoir pressure above 500 kPa

.
F or example, a maximum depletion guideline of 100 kPa is targeted for a r eservoir with an initial pressure of 15 000 kPa

.

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 89Alberta Energy Regulator

g) J ustification for pretes t cleanup and servicing flaring or incineration if related volumes
exceed 200 10 3 m 3

Note that an incremental volume of up to 200 10 3 m 3 may be added to the permit request in order to provide for pretest c leanup and servicing operations if these are needed to establish the minimum economic reserve without additional justification.

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 90Alberta Energy Regulator



## Appendix 6 Sour Gas Flaring/Incineration Data Summary Report

This form must be completed in full and submitted to the AER’s Field Surveillance and Operations Branch within three weeks of the flaring completion date or, in the event no flaring took place, within three weeks of the expiry date:

Submit to: Flaring Approvals Fax: (403) 297

- 2691 E

- mail: Directive060Inbox@aer.ca
11 th Floor

– Field Surveillance and Operations Branch Alberta Energy Regulator Suite 1000, 250 5 th St. SW Calgary, AB T2P 0R4

Item Report Information

Approval No:

Company:

Well Name:

Unique Well Identifier:

Approval Issue Date: Expiry Date:

Volume of Formation Gas Flared: Approved: _____________ 10 3 m 3 Actual: _____________ 10 3 m 3

Instantaneous Flared Gas Flow Rate: Approved (Max.):

_____________ 10 3 m 3 /d Actual (Max.):

_____________ 10 3 m 3 /d Actual (Avg.):

_____________ 10 3 m 3 /d

Actual Fuel Gas Flared (if applicable): Volume: ________________ 10 3 m 3 Rate: ________________ 10 3 m 3 /d

Number of H 2 S Analyses Conducted: (Please provide tester report)

H 2 S Content of Raw Gas: Approved (Max.):

________________ % Actual (Max.):

________________ % Actual (Avg.):

________________ %

Total Sulphur Flared: ________________ tonnes [= 1.35592 (%H 2 S ÷ 100) (flared vol.)]

Flaring Dates:

Management Plan Required? No Yes

Meteorological Monitoring Conducted? No Yes (If yes, please provide electronic copy of monitoring report)

Air Monitoring Conducted? No Yes (If yes, please provide electronic copy of monitoring report)

Exc eedances of the Alberta Ambient Air
Quality Guidelines (H 2 S or SO 2 ): No Yes (If yes, please provide comments)

Field Centre Notification Date: AER Field Centre Contact:

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 91Alberta Energy Regulator

Item Report Information

Were there any problems while flaring?

If Yes, was the AER Field Centre

Contacted? No Yes

No Yes If yes, contact name:

Comments:

Company Representative:

Phone Number: E

- mail:

Fax Number: Signature:

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 92Alberta Energy Regulator



## Appendix 7 Air Quality Management Plans for Temporary SO 2 

## Emissions

If exceedances of the risk

- based criteria for SO 2 ( see appendix 8) are predicted and it is not proposed that flare/incinerator design parameters be altered to mitigate the potential exceedances, approval may be granted by the AER if suitable control measures are in place. In such situatio ns, an air quality management plan must be submitted with the temporary permit request

. The management plan must outline how predicted exceedances of the Alberta Ambient Air Quality Objectives and Guidelines w ill be avoided s o that the risk

- based criteria are met.

The air quality management plan may include the following:

1) Restrictions during specific meteorological conditions that will limit or avoid operations under conditions that result in predicted exceedances.

a) These atmospheric conditions may include

i) time of day
, ii) wind direction
, iii) wind velocity , and

iv) atmospheric stability

. b) Meteorological monitoring may be used as a management plan based on a maximum one

hour rolling (i.e., any consecutive 60 minutes), with measurements taken at a frequency of

no more than every 15 minutes (i.e., four measurements/hour).

2) The management plan must include specifications for locating meteorological monitoring equipment (if used). Wind monitoring devices must be elevated above the height of trees surrounding the site.

3) Restrictions that may be applied during unfavourable meteorological conditions.

a) Operational restrictions in air quality management plans may include

i) suspension of flaring or incineration operations
, ii) reduction or increase of flaring or incineration rates
, and

iii) requirements that supplemental fuel gas meet a minimum heating value or exit velocity.

4) If a reduction in flaring or incineration rate or an addition of supplemental fuel gas is proposed, compliance with the risk

- based criteria must be demonstrated with appropriate dispersion modelling results. (Note that reduced flaring or incineration rates do not result in a proportional reduction in predicted concentrations.)

5) Ambient air monitoring (mobile and/or stationary) must be located where exceedances of the Alberta Ambient Air Quality Objectives and Guidelines are predicted.

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 93Alberta Energy Regulator

a) Ambient air monitoring in conjunction with appropriate flar ing/incineration management procedures will only be accepted when it can be demonstrated that monitors can be placed in a manner that is reasonably protective of all locations where exceedances of the risk

based criteria are predicted. S tationary monitors are currently accepted to cover an arc of
22.5 

### ° C centred on t he source

. The l icensee or operator must provide a National Topographic System (NTS) map of the area (1:50 000) indicating the locations of the stationary monitors and a table with the coordinates (i.e.
, U niversal T ransverse M ercator [UTM ] ). In cases where monitoring is proposed
, a licensee or operator must demonstrate that there is good access to all areas with predicted exceedances before a request is
submitted.

b) The Alberta Ambient Air Quality Objectives and Guidelines must not be exceeded, based

on a one

- hour average. T o accomplish this, ambient air monitoring must occur at intervals
of 15 minutes or less. If the 30

- minute average exceeds the Alberta Ambient Air Quality Objectives and Guidelines, the flaring or inciner ati o n operation must be immediately
shut in

. 6) If there is more than one meteorological condition that requires a management response, or if a combination of meteorological restrictions and ambient air monitoring is proposed, the management plan must be sum marized in a flowchart that is clear and concise and can be applied by on

- site staff during flaring or incinerating operations. Furthermore, if multiple flow rates are proposed in the management plan
, the risk

- based criteria must be met for each flow

rate.
a) The management plan must clearly specify the frequency at which the meteorological or ambient air quality monitoring data will be monitored by on

- site staff. An averaging time
of no more than 15 minutes is mandatory, as this allows for observations of tre nds and provides enough time to respond to elevated concentrations.

7) The management plan must clearly define under what conditions flaring or incinerati o n may

resume if suspended or may return to normal operations if a management option such as fuel gas is proposed. Flaring or incinerati o n must remain suspended for at least one hour before operations may resume in order to prevent an exceedance or to respond to an exceedance.

a) Flaring or incinerati o n may begin again after one hour or after meteorological conditions change and remain favourable for 30 minutes, whichever is longer.

8) Real

- time dispersion modelling flare management plans must be based on maximum predicted concentrations. Pseudo input parameters must be calculated us ing AER Flare

. If real

- time dispersion modelling goes down, the operator must revert to a conventional flare management plan or shut in.

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 94Alberta Energy Regulator



## Appendix 8 Screening Dispersion Modelling Using AER Spreadsheet

The AER sour well test flaring and incineration permit spreadsheet s and technical descriptions are
available on the AER website www.aer.ca under AER Directives : Directive 060. They provide a screening analysis of the SO 2 and H 2 S dispersion from permanent and temp orary flares and
incinerators. If the screening level maximum concentration predictions in parallel and complex
ai rflow terrain for a source meet the Alberta Ambient Air Quality Objectives and Guidelines ( AAAQO ), no further analysis is required. The spreadsheet can be submitted in support of the dispersion modelling assessment.

Maximum predictions for routine sources must meet the AAAQO . Due to the short

- term nature of temporary nonroutine sources, risk

- based criteria can be applied. The risk

- based criteria apply to well tests and other temporary nonroutine flaring and incineration events. For further information about the spreadsheet refer to the AER flare User Guide: A Screening Model for Non

- routine Flaring Approvals and Routine Flare Air Dispersion Modelling for S our Gas Facilities.

If it is not practical to modify flare or incinerator design parameters, you may consider evaluating the proposed design with more refined dispersion modelling approaches. Additional refined dispersion modelling is required if the scree ning level maximum concentration predictions in parallel and complex airflow terrain for a source do not meet the AAAQO

. A refined dispersion modelling assessment must meet ESRD’s Air Quality Model Guideline (2013) or Non

- Routine Flaring Management: Modell ing Guidance (2013).

For routine flaring, a refined dispersion modelling assessment is also required if there are
continuous SO 2 emission sources within 10 km of the location or within the isopleth of one

- third of
the AAAQO for SO 2 (as described in section 7.12.3), whichever distance is less. This requires that the cumulative effects of the proposed flaring or incineration be assessed in combination with other

sources.
A licensee, operator, or approval holder is responsible for ensuring that appropriately trained and qualified personnel complete the air quality evaluations.

A refined dispersion modelling assessment must include the following:

1) A description of the meteorological data sourc e (location, years, and months). For models that require meteorologica l data, five years of meteorological data from a standard period is
recommended. T hree months per year must be modelled from the data set centred about the
month of the requested permit date . The acceptable data sets are posted on the ESRD website at http: //www.environment.alberta.ca/01119.html. Additional information about modelling and meteorological data requirements is on the ESRD website.

2) A wind rose (a representation of the history of wind directions and wind speeds).

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 95Alberta Energy Regulator

3) Refined modelling source paramete rs for maximum flow rate (Qmax), average flow rate (Qavg), and one

- eighth maximum flow rate (Q/8) from the spreadsheet.

4) A summary of the model input parameters (a printed copy of the input file is preferred, as output files may be large and need not be sub mitted).

5) The maximum predicted one

- hour ambient air SO 2 concentration for maximum flow rate (Qmax), average flow rate (Qavg), and one

- eighth maximum flow rate (Q/8).

6) If exceedances of the one

- hour AAAQO for SO 2 are predicted, a histogram of the overall

pro bability of exce edance based on meteorological data is to be calculated, as follows, by dividing the number of hours with predicted exceedances by the total number of hours used in the meteorological data set:

Probability of e xceedance = (Cumulative number of hours with predicted exceedances) (Total hours modelled)
7) A n interpretation of the modelling results (output files or model result printouts may be
inc luded if not excessively large).

8) Histograms showing exceedances based on criteria (e.g., wind direction, wind speed, and stability class).

If the risk

- based criteria are not met , a management plan (see a ppendix 7 ) must be developed to
achieve the risk

- based criteria

. Request s with management plans must include enough informatio n so that the AER can assess the management plan, including
1) for each flow rate, a summary table of output, including

• meteorological conditions (stability class and range of wind speeds and directions) or times of day that result in predicted exceedance of the one

- hour AAAQO for SO 2 ,

• maximum predicted SO 2 concentration for each condition where exceedances are predicted,
and

• the expected overall probability of exceedances before and after implementation of the management plan;

2) for each flow rate, an area map showing

• locations of predicted SO 2 ground

- level concentration isopleths (with a minimum 10 km radius) in excess of the one

- hour AAAQO for SO 2 ,

• sectors with flaring restrictions (if proposed),

• locations accessible with a mobile monitoring unit (if proposed ),

• approximate location of proposed stationary monitors (if proposed) and, if available, a recent air photo showing the approximate location of proposed stationary monitors, as well

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 96Alberta Energy Regulator

as specifications of the monitor location in a format usable by the monit oring licensee,
operator, or approval holder (e.g., UTM coordinates or latitude and longitude), with an acceptable offset distance if this is required to improve access or telemetry line of site; site
reconnaissance must be conducted before submission to e nsure that monitors can be placed,
and

• UTM coordinates of stationary monitors, as well as distance and direction from well;

3) a calculation of make

- up fuel gas requirements as a percentage of the produced gas being combusted (fuel gas may be used to increase plume rise; care should be taken to minimize fuel gas waste); and

4) ele ctronic copies (i.e., Microsoft Word or Excel files) of the ma nagement plan and decision tree (if applicable).

The AERflare .xls and AERincin .xls spreadsheet s also evaluate minimum and ma ximum exit velocities with respect to down

- wash criteria. The results will help the licensee, operator, or approval holder optimiz e flare and incinerator design and verify parameters used for temporary flaring and incineration permit request s

. 1) If down

- was h is predicted, the spreadsheet source parameters will conservatively account for
down

- wash; however, it is recommended that the stack design parameters (e.g., stack diameter)
be modified to avoid down

- wash.

2) The spreadsheet provides maximum and minimum ex it diameters based on the recommended exit velocities. You must size the exit diameter within the range of exit diameters provided in
AERflare.xls . Exit di ameter is a permitted parameter. A qualified technical professional who is
a member of the association as defined in the Engineering and Geoscience Professions Act 27 must review the design parameters.

The l icensee, operator, or approval holder may submit data based on modified modelling methods for consideration; however, results from one of the accepted unmodified models must also be submitted for comparison. Description and scientific justification of the modifications must be provided. Generally, review of permit requests that use a modified modelling method requires more time, and the AER may accept or reject the modif ied results at its discretion.

27 Engineering and Geoscience Professions A ct RSA 2000 c. E

- 11, as amended.

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 97Alberta Energy Regulator

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 98Alberta Energy Regulator



## Appendix 9 Resident Flaring/Venting/Incinerating Notification Sample Form

We will be flaring/ incinerating/ venting a (___ % H 2 S) well in accordance with AER Directive 060
at the locat ion stated below.

Flaring/Incinerating/Venting Category (check those that apply) AER Office (check one) Well test flaring Bonnyville (780

- 826

- 5352) Well test venting Drayton Valley (780

- 542

- 5182) Well test incinerating Grande Prairie (780

- 538

- 5138) Fort McMurray (780

- 743

- 7214) (Check one) High Level (780

- 926

- 5399) Oil well Medicine Hat (403

- 527

- 3385) Gas well Midnapore (403

- 297

- 8303) Red Deer (403

- 340

- 5454) St. Albert (780

- 460

- 3800) Wainwright (780

- 842

- 7570)

Flaring/Venting/Incinerating Comments
Well Licence No.
Well Name Location of Well (LSD) Estimated Flare/Incinerate/Vent Timing (30

- day window)* Estimated Start Date Estimated End Date Flaring/Incinerating/Venting Duration Estimated Volume (10 3 m 3 /day) Licensee or Operator Name Licensee or Operator Representative Contact Phone Number Testing Contractor Testing Representatives on Site Daytime Cell Phone Number Nighttime Cell Phone Number Emergency Phone Number
Please phone (__

_ _) __

_

_ -

___ __ _ if you would like notification 24 or 48 hours in advance of flaring / incinerating/venting operations.

• 30

- day window is to accommodate for weather and operational delays.

• Renotification is mandatory after 90 days.

Note:_______________________________________________________________________________

________________________________________________________ ____________________________

If you have questions or concerns, please phone (___) ___

-

______

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 99Alberta Energy Regulator



## Appendix 10 A greement on Zero Flaring

The following serves to outline the agreement b etween

__________________________ (applicant) and __________________________ (landowner or occupant) respecting flaring at the well located at
W . The applicant agrees to not fla re from the well before putting the well on production except as stated below in this agreement or in an emergency. Venting is not to be used as an alternative to flaring.

Exceptions

Flaring may occur as indicated bel ow and is limited to at most two of th e activities:

• Well t esting Yes? ____ No?_____

• Well c leanup Yes? ____ No?_____

• Drills tem t esting Yes? ____ No?_____

Emergencies

The licensee, operator, or approval holder may flare in emergency situations for safety of the public or environmental protection.

If the ownership of the well is transferred to another licensee, operator, and /or approval holder, this agreement will remai n in effect for the new licensee, operator, or approval holder and it is the licensee,
operator, or approval holder’s responsibility to advise any successors of this agreement.

This agreement no longer applies once this well is tied into a production facil ity or once production operations begin

. Applicant Signature______________

__________ Landowner or Occupant Signature (optional)_

____________ ____________ Printed Name _____________________

________ Printed Name__________________

____________ Licensee, operator, or approval holder

_________________________________ ________________ Location______________________

____________ Telephone________________________

________ Telephone_____________________

____________

E

- mail/Fax____

____________________________ E

- mail/Fax

_________________________________ Date __

__________________________

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 100

## Appendix 1 1 Request to Extinguish Sour Gas Flare Pilots

The following minimum requirements must be met in any situation where it is proposed to extinguish a flare pilot at a sour facility:

1) The maximum stabilized wellhead pressure must be determined based on the measured
stabilized static wellhead pressure corrected for the hydrostatic head of any li quid present in the wellbore at the time of testing.

a) This correction for the liquid column hydrostatic head must use the density of the produced water for the entire fluid column present in the wellbore.

b) The maximum stabilized static wellhead pressure must be determined by a qualified well test professional using accepted engineering practices. AER Directive 0 40 provides regulations for conducting pressure tests on wells.

2) The following features must be incorporated into the facility for consideration of the request to extinguish the flare pilot:

a) Nonfragmenting rupture disks must be installed on the upstream side of all pressure safety valves (PSVs). This is subject to section 38(1)(b) of the Pressure Equipment Safety Regulation (AR 49/2006) administered by t he Alberta Boilers Safety Association.

• A pressure gauge or suitable telltale indicator must be installed between each rupture disk and the corresponding PSV to allow detection of leakage or a disk rupture.

b) Two block valves in series must be installed for m anual depressurizing valves connected to
the flare.

c) The battery must be equipped with a pressure sensor, automatic emergency shutdown valves (ESDVs), and a control system configured to isolate the battery from the well and outlet gas pipeline. There must b e no automatically controlled emergency depressurizing
valves connected to the flare.

3) Upstream piping to the well must be designed for the maximum pressure that might be
encountered. The minimum operating requirements for any facility approved for extinguishing flare pilots include the following:

a) The l icensee, operator, or approval holder must monitor and document on a weekly basis the pressure between rupture disks and PSVs.

b) If a rupture disk fa ils or if odours result from gas released to the flare stack, the flare stack must be lit and immediate notification must be given to the appropriate AER f ield c entre, followed by a written incident report giving particulars. Approval to extinguish the fla re pilot is then considered void until the licensee, operator, or approval holder demonstrates to

Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014) 101Alberta Energy Regulator

the satisfaction of the appropriate AER f ield c entre that related problems have been successfully corrected.

c) The sweet gas or propane pilot must be ignited pr ior to any flaring or depressurizing at the
site.

d) The operation of the emergency shutdown system, including ESDVs, must be verified and
documented at least once a year

. e) AER approval to extinguish the flare pilot must be visibly displayed at each site.

4) Res idents within the emergency planning zone (EPZ) must be notified of plans to extinguish the flare pilot.

5) The following information must accompany the licensee’s, operator’s, or approval holder’s
request to extinguish flare pilots:

a) a list of all wells conne cted to the battery, including

i) normal wellhead operating pressure, and

ii) maximum stabilized static wellhead pressure;

b) the maximum design operating pressure of the piping and pressure vessel systems for the battery, including

i) a list of all PSVs connected to t he flare and related release set

- pressures, and

ii) a list of related rupture disks and burst pressures;

c) written confirmation that

i) none of the wells connected to the facility are completed in pools that have active injection or cycling schemes,

ii) rupture disks on PSVs and two valves in series have been installed on all streams tied into the flare system,

iii) maximum H 2 S release rates will not exceed the level

- 1 or

- 2 sour well classification,

iv) residents within the EPZ have been notifi ed , and

v) high

- pressure shutdowns a re in place, with a statement confirming calibration frequency.

102 Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (April 2014)