Offset Project Report Form Advantage Oil & Gas Ltd. Prepared by: … · which were incorporated into calculations for volumes of acid gas injected and volumes of acid gas sent to

Advantage Glacier Acid Gas Injection Offset Project

February 2019

Version 2.0 Report Template – July 2018

Offset Project Report Form


Project Developer:

Advantage Oil & Gas Ltd.

Prepared by:

Blue Source Canada ULC

Reporting Period:

January 1, 2018 – December 31, 2018

Date:

February 27, 2019


February 2019


Greenhouse Gas Assertion

Project Developer:


Reg Beck

Suite 300, 440 2nd Avenue SW

Calgary, AB T2P 5E9

(403) 718-8123

www.advantageog.com

Email [email protected]

Project Documents:

Offset Project Report:

Advantage Glacier Acid Gas Injection Offset Project Report

Offset project plan:

Advantage Glacier Acid Gas Injection Offset Project Plan (August 29, 2012)

Protocol:

Quantification Protocol for Acid Gas Injection (version 1.0, May 2008)

Project Identification:

Project Title:


Reporting Period:


Project description:

The opportunity for generating carbon offsets with this project arises from the direct greenhouse

gas emission (GHG) reductions resulting from the geological sequestration of acid gas, containing

CO2, as a part of raw natural gas processing. Prior to acid gas injection (AGI), CO2 was generated

during combustion of the acid gas and make-up dilution gas in the flare stack. Additionally, as a

result of surpassing the 1 tonne/day of sulphur inlet concentrations, the Glacier Sour Gas Plant

would have required the employment of a sulphur recovery unit (SRU), in the form of a Split-Flow

Claus process, to treat the sulphur in the acid gas stream had AGI not been implemented. The

Split-Flow Claus process would have relied on fossil fuels for its operation and processing—resulting

in additional emissions.

Legal Land Description:

The Project is located in Alberta. Both the Glacier Sour Gas Plant and the active injection wells are

northwest of Grande Prairie, Alberta and near the BC-Alberta border.


February 2019


Plant Active Injection

Well

Backup Injection

Well

LSD 05-02-076-12 W6 02/03-12-076-13W6 00/16-01-076-13W6

Latitude 55.554089° 55.564861° 55.561342°

Longitude -119.755366° -119.87815° -119.865237°

Emission Reduction or Sequestration Assertion:

Vintage Gas Type Quantity (tCO2e)

2018 CO2 81,221

2018 CH4 8,495

2018 N2O 681

Total Quantity 2018 CO2e 90,397


February 2019

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Version 2.0 Report Form – July 2018

Table of Contents

Greenhouse Gas Assertion ..................................................................................................... 2 1.0 Contact Information .............................................................................................. 6 2.0 Project Scope and Site Description .......................................................................... 6

2.1 Project Implementation .......................................................................................... 8 2.1.1 Project Implementation Timeline ............................................................................. 8

2.2 Protocol ............................................................................................................. 12 2.3 Risks ................................................................................................................. 13

3.0 Project Quantification .......................................................................................... 14 3.1 Summary Table Non-Levied Emissions ................................................................... 14 3.2 Summary Table Levied Emissions and Biogenic CO2 ................................................ 14 3.3 Calculations ........................................................................................................ 14

3.3.1 SS B5b (Split-Flow Claus Process) ......................................................................... 15 3.3.2 SS B6 (Flaring) ................................................................................................... 17 3.3.3 SS B9 (Fuel Extraction & Processing) ..................................................................... 18 3.3.4 SS P6 (Acid Gas Dehydration and Compression) ...................................................... 19 3.3.5 SS P8 (Upset Flaring) .......................................................................................... 20 3.3.6 SS P12 (Fuel Extraction & Processing) ................................................................... 21

3.4 Emission Factors ................................................................................................. 21 4.0 References ......................................................................................................... 23 Appendix A: Approval to Use Flagged Protocol ....................................................................... 24

List of Tables

Table 1: Project Contact Information ...................................................................................... 6 Table 2: Project Information .................................................................................................. 6 Table 3: Summary of changes made in the 2018 reporting period .............................................. 9 Table 4: Summary of calculation changes made in the 2013 reporting period ............................ 10 Table 5: Summary of changes made in the 2014 reporting period ............................................ 10 Table 6: Summary of changes made in the 2015 reporting period ............................................ 11 Table 7: Summary of changes made in the 2016 reporting period ............................................ 12 Table 8: Summary Non-Levied Emissions .............................................................................. 14 Table 9: Summary Levied Emissions and Biogenic CO2 ........................................................... 14 Table 10: Key 2018 Operating Parameters ............................................................................ 15 Table 11: Emission Factors Used in the Project ...................................................................... 21


February 2019

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1.0 Contact Information

Table 1: Project Contact Information

Project Developer Contact Information Additional Contact Information


Click here to enter text.

Reg Beck


Suite 300, 440 2nd Avenue SW


Calgary, AB T2P 5E9


(403) 718-8123

www.advantageog.com

[email protected]

Authorized Project Contact (if applicable)

Blue Source Canada ULC

Amy Zell

1605 – 840 7th Avenue SW

Calgary, AB T2P 3G2

(403) 262-3026 ext 260

www.bluesource.com

[email protected]

2.0 Project Scope and Site Description

Table 2: Project Information

Project title Advantage Glacier Acid Gas Injection Offset Project (the “Project”)

Project purpose and

objectives

The opportunity for generating carbon offsets with this project arises from

the direct greenhouse gas emission (GHG) reductions resulting from the

geological sequestration of acid gas, containing CO2, as a part of raw

natural gas processing. Prior to acid gas injection (AGI), CO2 was

generated during combustion of the acid gas and make-up dilution gas in

the flare stack. Additionally, as a result of surpassing the 1 tonne/day of


February 2019

Page 7 of 24


sulphur inlet concentrations, the Glacier Sour Gas Plant would have

required the employment of a sulphur recovery unit (SRU), in the form of

a Split-Flow Claus process, to treat the sulphur in the acid gas stream had

AGI not been implemented. The Split-Flow Claus process would have

relied on fossil fuels for its operation and processing—resulting in

additional emissions.

Activity start date October 27, 2011

Offset start date October 27, 2011

Offset crediting

period

October 27, 2011 – October 26, 2019

Reporting period

covered by the

project


Actual emission

reductions/

sequestration

90,397 t CO2e

Unique site identifier

Plant Active Injection

Well

Backup

Injection Well

LSD 05-02-076-

12W6

02/03-12-076-

13W6

00/16-01-076-

13W6

Latitude 55.554089° 55.564861° 55.561342°

Longitude -119.755366° -119.87815° -119.865237°

Is the project located

in Alberta?

Yes

Project boundary The Project is located in Alberta. Both the Glacier Sour Gas Plant and the

active injection well are northwest of Grande Prairie, Alberta and near the

British Columbia-Alberta border.

The operational project boundary encompasses all equipment and

processes involved in the acid gas compression, transportation and

injection.

Ownership Advantage Oil & Gas Ltd. as the sole owner of the Glacier Sour Gas Plant

(herein referred to as ‘the Plant’), could reasonably claim entitlement to

the emission offset project. The Plant currently accepts third-party gas

for processing. However, under the current processing agreement, third-

party producers will not benefit from any monies, credits or otherwise

(past or future) in relation to GHG reduction benefits resulting from the


February 2019

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implementation of AGI at the Plant located at 05-02-076-12W6M. As

such, the Project Developer could reasonably claim entitlement to any

other benefits associated with the emission offset project.

Blue Source Canada ULC (“Bluesource”) has the right to market and sell

the emission offsets on behalf of Advantage Glacier through contractual

agreements. Excerpts of the relevant sections on ownership and right to

transact in the contractual document will be made available to

demonstrate the entitlement.

2.1 Project Implementation

The Project was implemented according to the Offset Project Plan (OPP) dated August 29, 2012,

under the Quantification Protocol for Acid Gas Injection (version 1.0, May 2008) (the “Protocol”).

Emission credits for the Project are only being claimed once.

In 2018, the Glacier Sour Gas Plant upgraded several parts of the facility to increase gas handling

capacity. Two new amine skids were installed and became operational. After an overlap period

where all four amine skids were in use, the two new units replaced the existing amine skids which

were removed from service. The new amine skids have new meters (FQI-4070 and FQI-4570)

which were incorporated into calculations for volumes of acid gas injected and volumes of acid

gas sent to flare.

The facility also installed a new fuel meter (FQI-7154) which measures the dilution gas sent to

the flare. This meter replaced meters FQI-4701 and FQI-4711.

The facility improvements also included upgrades that did not affect the Project, such as new

inlet slug catchers and a new refrigeration unit.

There are no modifications to the data collection or record keeping procedures, emission factors

or any other project variables not already identified.

In 2016, due to phased plant expansions, the Glacier facility crossed 100,000 tonnes of emissions

and became a Large Final Emitter under the SGER. The offset project received approval on

January 9, 2017 to discount the direct project emissions by a factor of 1 minus the reduction

target to back out the emissions subject to the SGER reduction target.

There are no changes to the emission reduction activity.

2.1.1 Project Implementation Timeline

The following summary of changes were made in previous reporting periods in comparison to the

offset project plan dated August 29, 2012 and are relevant to the current reporting period.

In 2013, the project period July 1st to December 31st, 2012 was audited by Alberta Environment

and Sustainable Resource Development (AESRD). The audit firm contracted by AESRD was ICF

Consulting Canada Inc. Audit findings identified two material understatements of the GHG

assertion and several minor, immaterial misstatements. After discussion with AESRD, agreement

was reached on the required actions to correct these misstatements for future deliveries, starting

with the 2013 vintage year. Thus, there were several modifications and clarifications, as

compared to the Offset Project Plan, outlined in the 2014 OPR. These modifications and


February 2019

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clarifications remain valid for the 2018 reporting year and are summarized in Tables 4, 5 and 6.

For more detailed explanation of the revised methodology and supporting theory please refer to

the OPR for the period of January 1, 2014 – December 31, 2014.

Table 3: Summary of changes made in the 2018 reporting period

Change Item Description SS Affected SS Related Previous

Calculation

Methodology

or Reference

Revised Calculation

Methodology or

Reference

1 Acid Gas

System Start

Up

Unmetered

Flare

Volumes

P8b n/a Previous

calculation

did not

reference

FQI-4070C

or FQI-

4570C

Updated to

reference FQI-

4070C and FQI-

4570C

2 Acid Gas to

Flare at

Amine

P8b n/a Previous

calculation

did not

reference

FQI-4070C

or FQI-

4570C

Updated to

reference FQI-

4070C and FQI-

4570C

3 Flare Fuel

Gas

P8a, P12 n/a Previous

calculation

referenced

FQI-4701

and FQI-

4711 only

Updated to

reference FQI-7154

which measures

dilution gas to flare

4 Purge Gas to

Flare Knock

Out Drum

P8a, P12 n/a Previous

calculation

did not

reference

FQI-4070C

or FQI-

4570C

Updated to

reference FQI-

4070C and FQI-

4570C

5 Increased

accuracy of

molar mass

B6b, P8b n/a Previous

calculator

used

rounded

molar

masses

Updated to use

molar masses with

2 decimal points for

increased accuracy


February 2019

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Table 4: Summary of calculation changes made in the 2013 reporting period

• Change

Item

• SS

Affected

• SS

Related

• Previous Calculation

Methodology

• Revised Calculation Methodology

(i)a

(ii)

• P8b • B6b • Emissions from Acid Gas

Flaring = PAF (HMI

Volumes)

• Emissions from Acid Gas Flaring =

PAF(HMI Volumes) + PAFUV

(Unmetered Volumes)

• (iii) • B6b • B6a, B9 • VTAIL = Volume of Acid Gas

Flared + Volume of Acid

Gas Injected

• VTAIL = (Volume of Acid Gas Flared

(HMI) + Volume of Acid Gas

Injected + Volume of Acid Gas

Flared (unmetered)) x n2:n1

• (iv) a • P6 • P12 • PFAN1+2 = FAN1+2 x LFAN1+2

•

• PFAN3+4 = FAN3+4 x LFAN3+4

• PFAN1+2 = FAN1+2 x (LFAN1+2)3

•

• PFAN3+4 = FAN3+4 x (LFAN3+4)3

• (v) • P6, P8a,

B6a, B9

• n/a • Annual Time weighted

Average Sales gas CO2EF

• Monthly Sales Gas CO2EF

• (vi) • B9 • n/a • BTotal-Fuel = BFF + NGAIR +

NGHP

• BTotal-Fuel = BFF + VNET,NG,B


• Chan

ge

Item

• Description • SS

Affected

• SS

Related


Methodology or

Reference

• Revised Calculation

Methodology or

Reference

• 1 • Global

Warming

Potentials

• All • n/a • IPCC Second

Assessment Report

(1996)

• IPCC Fourth

Assessment Report

(2007)

• 2 • Acid Gas

Compressor

Fuel

Consumption

• SS P6 • n/a NGAGC= (AGC x R x

LAGC x 3.6 MJ/kWh) ÷

(TE x LHVFuel x ηGenerator

x 1000 m3/e3m3)

NGAGC= (AGC x R x

LAGC x 3.6 MJ/kWh) ÷

(LHVFuel x ηGenerator x

1000 m3/e3m3)

• 3 • Intercooler

Fuel

Consumption

• SSP6 • n/a NGFan1+2= (PFAN1+2 x R

x 3.6 MJ/kWh) ÷ (TE x

LHVFuel x ηGenerator x

1000 m3/e3m3)

NGFan1+2= (PFAN1+2 x R

x 3.6 MJ/kWh) ÷

(LHVFuel x ηGenerator x

1000 m3/e3m3)

• 4 • Unmetered

Flared Acid

Gas for

Blowdown/Re

start

• SS B6b

• SSP8b

• n/a VTAIL=(PAF+Pdisposal+P

AFUV) x n2:n1TAIL

PAFT = PAFUV +PAF

VTAIL=

(PAF+Pdisposal+PAFUV +

PAFUV, RESTART) x

n2:n1TAIL


February 2019

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• Chan

ge

Item

• Description • SS

Affected

• SS

Related


Methodology or

Reference

• Revised Calculation

Methodology or

Reference

PAFT =

PAFUV+PAFUV,RESTART

+PAF

• 5 n2:n1 Molar

Volume Ratio

•

• P8b

• P6b

• n/a Advantage Oil and Gas

LTD SRU Simulation

Report, August 2012

Advantage Oil and Gas

LTD SRU Simulation

Report, February 2015

• 6 • Energy

Imports and

Exports

• SSB5b • n/a Advantage Oil and Gas

LTD SRU Simulation

Report, August 2012

Advantage Oil and Gas

LTD SRU Simulation

Report, February 2015


Change

Item

Description SS Affected SS Related Previous

Calculation

Methodology

or Reference

Revised

Calculation

Methodology

or Reference

1 Site Specific CO2

Calculation

SSB5b,

SSB6a SSP6,

SSP8a

n/a CAPP Guide,

“Calculating

Greenhouse

Gas

Emissions”,

April 2003,

Page 1-11

eq.3

Refer to

Section 3.4 of

this report

2 Purge Gas Combustion

Emissions

P8a n/a Project Level

dilution gas

metered

volume only.

Volume

obtained

from meters

FQI- 4701

and FQI -

4711

Project level

dilution gas

metered

volume +

purge gas

volume

calculation

from flare

specifications.

In 2016, the Glacier gas plant added a second acid gas compressor and dehydration package.

This compressor package is supplementary to the operation of the original package.


February 2019

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On January 1, 2016, a new acid gas flare meter, FQI-7152 was installed and operational. This

acid gas flare meter records both the acid gas and dilution gas sent to the flare. Therefore, the

total fuel gas flared calculation in source P8b was amended to account for the total volume

measurement by this meter.


Change Item Description SS Affected SS Related Previous

Calculation

Methodology

or Reference

Revised Calculation

Methodology or

Reference

1 n2:n1 molar

ratio

B6b B6a, B69 The molar

volume of n1

was based

upon the wet

acid gas

composition

The molar volume of

n1 is based upon the

dry acid gas

composition.

2 Flare stack P8a

P12 Volume of

fuel gas to

the flare was

previously

determined

by meters

4701 + 4711

and the flare

pilot gas

Volume of fuel gas

to flare now also

includes purge gas

for the acid gas flare

knock out drum

This total volume is

used in source P12.

2.2 Protocol

The relevant, approved protocol used for the project is the Quantification Protocol for Acid Gas

Injection (version 1.0, May 2008).

This protocol is applicable to use based upon statements from Section 1.0 of the Protocol, “is

written for the acid gas processing system operator […] and direct and indirect reductions

greenhouse gas emissions from the geological sequestration of acid gas streams containing

greenhouse gasses as part of raw natural gas processing.”

The emission offset project fulfills all 6 criteria under the protocol applicability section:

1. The sequestration results in removal of emissions

2. The emissions reductions are not double counted

3. The acid injection scheme obtained approval from the ERCB and meets the requirements

under Directive 051

4. Metering of injected gas volumes takes place as close to the injection point to address

potential for fugitive emissions


February 2019

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5. The AGI project was installed at a new natural gas processing facility constructed after July

1, 2007 with total baseline emissions below the coverage threshold of 100,000 tCO2e.

6. The acid gas streams account for one emitting facility

7. The quantification of reductions is based on actual measurement and monitoring

8. The project meets the requirements for offset eligibility

The Project uses two flexibility mechanisms as identified in the offset project Plan, flexibility

mechanisms # 2 and #3. The use of these flexibility mechanisms ensures the reductions are

accurate and representative of conditions at the Glacier site.

The Project received approval to use a flagged protocol on June 13, 2012 from the Acting Director

of the Climate Change Secretariat of Alberta Environment and Sustainable Resource

Development. This approval has been provided in Appendix A.

There were three terms of approval:

1. Include project period electricity usage: this condition is not applicable to the Plant

2. Update to the revised protocol once approved: this condition is not required

3. Detail the data contingency method outlined in the project report: the data contingency

method follows that of the approved protocol.

The protocol deviation was authorised as stated in Section 2.1 Project Implementation, on

January 9, 2017 from the Director of Emissions Inventory and Trading. The deviation requires

the direct project emissions are adjusted to remove the emissions subject to the reduction target

under the SGER as the facility is now regulated. This has been performed as required.

No other protocol is used in the quantification of this Project therefore no other terms and

conditions or authorizations are required to be outlined here.

2.3 Risks

There are no additional risks associated with the emission offset project other than those

identified in the project plan. Since the plan was completed, the project developer increased

redundancy in the Project by constructing a secondary disposal well and installing a secondary

acid gas compression and dehydration package.

There are no other emission offset projects on the legal land description of the emission offset

project site.

A project level additionality assessment is not required for this project type.


February 2019

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3.0 Project Quantification

3.1 Summary Table Non-Levied Emissions

Table 8: Summary Non-Levied Emissions

Vintage Gas Type Baseline

Emissions

Project Emissions Total

Reduction or

Sequestration

2018 CO2 83,348 2,127 81,221

2018 CH4 8,767 272 8,495

2018 N2O 698 17 681

Total 2018 CO2e 92,813 tCO2e 2,416 tCO2e 90,397 tCO2e

Total for

Reporting

Period

CO2e 92,813 tCO2e 2,416 tCO2e 90,397 tCO2e

3.2 Summary Table Levied Emissions and Biogenic CO2

There are no levied or biogenic emissions present in this offset project reporting period.

Table 9: Summary Levied Emissions and Biogenic CO2

Vintage Gas Type Baseline

Emissions

Project Emissions Total

Reduction or

Sequestration

Year X CO2 n/a n/a n/a

Year X CH4 n/a n/a n/a

Year X N2O n/a n/a n/a

Year X Other n/a n/a n/a

Year X Biogenic n/a n/a XX tCO2

Total Year X CO2e XX tCO2e XX tCO2e XX tCO2e

Total for

Reporting Period

CO2e XX tCO2e XX tCO2e XXtCO2e

3.3 Calculations

GHG emission reductions were calculated following the Protocol. The activities and procedures

outlined in the Offset Project Plan provide a detailed description of the Project’s adherence to the

requirements of the quantification protocol. The formulas used to quantify GHG offsets by the


February 2019

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Project are listed below. A flexibility mechanism was utilized in the quantification procedures: a

site specific emission factor for CO2 from natural gas combustion was substituted for the generic

emission factor from Environment Canada.

Emission Reduction = Emissions Baseline – Emissions Project

Emissions Baseline = sum of the emissions under the baseline condition.

(i) Emissions Fuel Extraction and Processing = emissions under SS B9

(ii) Emissions Split-Flow Claus = emissions under SS B5b

(iii) Emissions Flaring = emissions under SS B6

Emissions under Liquid redox Process, SS B5a have been removed as they are not applicable to

the baseline emissions.

Emissions Project = sum of the emissions under the project condition.

(iv) Emissions Fuel Extraction and Processing = emissions under SS P12

(v) Emissions Gas Dehydration and Compression = emissions under SS P6

(vi) Emissions Upset Flaring = emissions under SS P8

Emissions under Recycled Gas, SS P10 have been removed as this source is not applicable to the

project emissions.

Table 10: Key 2018 Operating Parameters

Parameter Symbol Units Value

Total volume acid gas disposal units 1 and 2 PD,T e3m3 8,299.58

Recovered thermal energy from Claus operation VnetNG,B e3m3 -419.64

SULSIM Acid Gas: Tail Gas Molar Ratio n2:n1 n/a 1.913

Volume Fuel Gas Flared PFF e3m3 612.85

Volume Acid Gas Flared PAFT e3m3 251.64

Total Stationary combustion from dehydration and compression NGDehyTotal e3m3 141.91

3.3.1 SS B5b (Split-Flow Claus Process)

Emissions of CO2 = [Vol. FuelNG − EClaus∗ηHeat

ηEnergy∗LHVFuel] x EFCO2= -2,541.86 t CO2

Emissions of CH4 = [Vol. FuelNG − EClaus∗ηHeat

ηEnergy∗LHVFuel] x EFCH4= -8.04 t CH4

Emissions of N2O = [Vol. FuelNG − EClaus∗ηHeat

ηEnergy∗LHVFuel] x EFN2O= -0.08 t N2O


February 2019

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Where,

EFCO2/EFCH4/EFN2O = emission factor for natural gas combustion of CO2, CH4, and N2O,

tonnes/e3m3;

Vol. FuelNG = Fuel gas volume equivalence to operate the Split-Flow Claus unit

= NGAGPH + NGAPH + NGRH1 + NGRH2 + NGAIR + NGHP =-698.42 e3m3

and,

NGAGPH = Fuel gas volume equivalence to operate the Acid Gas Preheater, e3m3;

NGAPH = Fuel gas volume equivalence to operate the Air Preheater, e3m3;

NGRH1 = Fuel gas volume equivalence to operate Reheater #1, e3m3;

NGRH2 = Fuel gas volume equivalence to operate Reheater #2, e3m3;

NGAIR = Fuel gas volume equivalence to operate Furnace Air Blower, e3m3; and

NGHP = Fuel gas volume equivalence to operate Hot Oil Pump, e3m3

NGAGPH, NGAPH, NGRH1, and NGRH2 are heated indirectly by a hot oil system. NGAIR and NGHP, are

powered by electricity and as the Plant has an on-site generator operating on fuel gas, the fuel gas

volume-equivalence to operate the equipment is calculated according to the following general

equation:

Fuel Usage = Output Rating (kW) × Utilization (hrs)

LHVFuel (MJ/m3) × ηGenerator (%)

ηGenerator (%) = Electrical efficiency of the on-site generator used at the Plant, 75%1;

The acid gas preheater, reheater #1 and reheater #2, waste heat exchanger, and condenser #1 and

condenser #2 power ratings are included in the annual recalculation of the baseline SRU model by

SULSIM. However, the power ratings for the furnace air blower and hot oil pump are not included in

the scope of the re-calculation. Therefore, values for these two pieces of equipment remain as

modelled from the 2012 SULSIM SRU simulation.

Utilization hours of the hypothetical split flow Claus process obviously cannot be established. In order

to ensure functional equivalence between the baseline and project conditions, the utilization hours

of the split flow Claus process have been assumed equal to the utilization hours of the project acid

gas compressor.

Emissions that would have occurred during the non-operational hours for the baseline hypothetical

Split Flow Claus process were not calculated in this quantification. The only way to ensure functional

equivalence and capture these emissions would be to assume flaring occurrences equivalent to that

of the project. As this is not conservative, emissions during assumed shutdown of the Claus unit

were omitted.

1 The generator efficiency is conservatively assumed to be 75% based upon reasonable operation

of the plant.


February 2019

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ηEnergy = Fuel energy efficiency of a direct-fired heater, %;

EClaus*ηHeat = Process energy recovered, MJ, as follows:

= ΣEnergy Exports × 3.6 MJ

kWh × R

∑Energy Exports (kW) = WHE + CD1 + CD2 + CD3;

WHE = Waste Heat Exchanger, kW;

CD1 = Condenser 1, kW;



R = Run-time for compressors 1 and 2, hrs;

The energy exports of the WHE and condensers are based on the modelled SULSIM case for maximum

acid gas volume through the Split Flow Claus process. This assumes the equipment would have been

designed for the maximum operating conditions and is conservative as it calculates the maximum

process energy possible to recover.

3.3.2 SS B6 (Flaring)

Emissions under SS B6 includes fuel gas (SS B6a) and tail gas flaring (SS B6b).

Emissions of CO2 (SS B6a) = BFF × EFCO2= 73,252.56 t CO2

Emissions of CH4 (SS B6a) = BFF × EFCH4 = 231.86 t CH4

Emissions of N2O (SS B6a) = BFF × EFN2O= 2.17 t N2O

Where,

BFF = Fuel gas volumes for baseline flaring

𝐵𝐹𝐹 = (PDisposal + PAF + 𝑃𝐴𝐹𝑈𝑉) × BRFG:AG = 35,877.16 e3m3

The tail gas contains CO2 and residual hydrocarbons including CH4, C2H6, C3H8, iC4H10, C4H10, and

C7H16. The tail gas composition is based upon the SULSIM simulation and is updated annually. Below

are the equations used to determine the tonnes CO2 emissions resulting from the combustion of each

hydrocarbon species:

Emissions of CO2 (SS B6b) = (PDisposal + PAF + 𝑃𝐴𝐹𝑈𝑉 ) × %CO2(TG) × ρCO2 = 7,914.55 tCO2

Emissions of CH4 (SS B6b) = (PDisposal + PAF+ 𝑃𝐴𝐹𝑈𝑉) × %CH4(TG) × ρCH4 × (44 (

g

moleCO2)

16(g

moleCH4)

) = 35.93 t CH4

Emissions of C2H6 (SS B6b) = (PDisposal + PAF + 𝑃𝐴𝐹𝑈𝑉) × %C2H6(TG) × ρC2H6 × (2 × 44 (

g

moleCO2)

30(g

moleC2H6)

)= 17.36 t

CO2


February 2019

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g

moleCO2)

44(g

moleC3H8)

) = 8.49

tCO2

Emissions of iC4H10 (SS B6b) = (PDisposal + PAF + 𝑃𝐴𝐹𝑈𝑉) × %iC4H10(TG) × ρiC4H10 × (4 × 44 (

g

moleCO2)

58(g

moleiC4H10)

) =

3.17 t CO2

Emissions of nC4H10 (SS B6b) = (PDisposal + PAF + 𝑃𝐴𝐹𝑈𝑉) × %nC4H10(TG) × ρnC4H10 × (4 × 44 (

g

moleCO2)

58(g

molenC4H10)

)=

4.02 t CO2

Emissions of iC5H12 (SS B6b) = (PDisposal + PAF + 𝑃𝐴𝐹𝑈𝑉) × %iC5H12(TG) × ρiC5H12 × (5 × 44 (

g

moleCO2)

72(g

moleiC5H12)

)=

2.74 t CO2

Emissions of nC5H12 (SS B6b) = (PDisposal + PAF + 𝑃𝐴𝐹𝑈𝑉) × %nC5H12(TG) × ρnC5H12 × (5 × 44 (

g

moleCO2)

72(g

molenC5H12)

)=

3.05 t CO2


g

moleCO2)

86(g

molenC6H14)

) =

5.30 t CO2


g

moleCO2)

100(g

moleC7H16)

)=

27.28 t CO2

The densities used in the above equations are based on assuming ideal gas behavior of each

hydrocarbon species.

3.3.3 SS B9 (Fuel Extraction & Processing)

Emissions of CO2 = BTotal−Fuel x NEPCO2EF= 4,651.08 t CO2

Emissions of CH4 = BTotal−Fuel x NEPCH4EF= 90.92 t CH4

Emissions of N2O = BTotal−Fuel x NEPN2OEF= 0.24 t N2O

Where,

NEPCO2EF/NEPCH4EF/NEPN2OEF = Emission factor for natural gas extraction and processing of CO2, CH4,

and N2O, tonnes/e3m3;

BTotal-Fuel = Volume of natural gas consumed in the baseline, e3m3

= BFF + NGAIR + NGHP − 𝑃𝐸𝑅𝐹𝑈𝐸𝐿

= 34,970.52 e3m3

and,

BFF = Baseline flared fuel gas volumes, e3m3

NGAIR and NGHP are identified under SS B5b;

PERFUEL = Equivalent Fuel savings from baseline process energy recovered, e3m3


February 2019

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Where:

𝐵𝐹𝐹 = 𝑉𝑇𝐴𝐼𝐿 × 𝐵𝑅𝐹𝐺:𝐴𝐺

BRFG:AG = Baseline, fuel gas to acid gas ratio;

= LHVCombined − LHVTG

LHVFuel − LHVCombined

LHVCombined = Net combined heating value, MJ/m3;

LHVTG = Lower heating value of tail gas, MJ/m3;

LHVFuel = Lower heating value of natural gas, MJ/m3;

And:

𝑉𝑇𝐴𝐼𝐿 = (𝑃𝐴𝐹 + 𝑃𝑑𝑖𝑠𝑝𝑜𝑠𝑎𝑙 + 𝑃𝐴𝐹𝑈𝑉,𝑅𝐸𝑆𝑇𝐴𝑅𝑇 + 𝑃𝐴𝐹𝑈𝑉) × 𝑛2: 𝑛1

PDisposal = Acid gas disposal volumes, e3m3;

PAF = Acid gas flared volumes (upset conditions), HMI data, e3m3;

PAFUV = Acid Gas Flared volumes (unmetered), e3m3

PAFUV,RESTART = Acid Gas Flared volumes, unmetered occurring during system restart

n2:n1 = Split Flow Claus unit molar volume adjustment

None of the components of the SRU requiring an energy import from the hot oil system (e.g. Acid

Gas Preheater, Air Preheater, and Reheater No. 1 and 2) were included in SS B9 for conservativeness.

The waste heat exchanger and condensers of the SRU produce waste heat energy that is captured

by a hot oil system (see SULSIM report in Appendix A: Project Period Supporting Documentation);

therefore, it was assumed under SS B9 that components operating on recovered energy do not

require an additional volume of fuel gas to supplement the hot oil system and so this equivalent

volume was subtracted from the BFF.

3.3.4 SS P6 (Acid Gas Dehydration and Compression)

Emissions from acid gas dehydration and compressor occurred from the operation of both the original

compressor package and the secondary K160 compressor package.

NGDehyC,a + NGdehyc,K160 = NGDehyc,total = 274.60 e3m3

NGdehyc,a = (NGAG−Comp + NGFans−1&2 + NGFans−3&4 + NGRegenerator + NGSPARGE + NGPUMPS) = 84.87 e3m3

NG dehyCk160=NGk160 + NGCOOLER + NGReboiler + NGPUMPS = 189.73 e3m3

Emissions of CO2 = NGDehyc, total × EFCO2 = 555.14 t CO2

Emissions of CH4 = NGDehyc, total × EFCH4= 1.76 t CH4

Emissions of N2O = NGDehyc, total × EFN2O= 0.02 t N2O

As seen in Equation 1 in Section 2.1.2 of the OPP the equation used to determine the equivalent

natural gas consumption for the fan coolers is as follows:


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NG =Output Rating (kW) × Utilization (

hrsmnth

) × AverageLoading (%

month)

LHVfuel × CombinedGenerator Efficiency (%)

Average loading from the fan power draw on the generator is determined through a linear relationship

between the compressor acid gas throughput and volume of air moved by the fans. It assumes

specifically that a change in acid gas flow rate will see a proportional change in the flow rate of air

needed to cool the gas. Then using the following fan laws: a. air flow varies in proportion to fan

speed and b. the power required varies in proportion to the cube of fan speed, the power draw of

the fans on the generator can be calculated. This is shown by the equation:

𝑃𝐹𝐴𝑁 = 7.5𝑘𝑊 × (𝑉𝑜𝑙. 𝐴𝐺𝑎𝑣𝑔

𝑉𝑜𝑙𝑀𝑎𝑥)

3

This equation also assumes that at the maximum flow rate of the compressor, the fans were sized

to also be running at the maximum speed of 1800 rpm.

This is a reasonable assumption as more acid gas processed per day through the system will require

increased air volume moved per day to cool the gas to its required temperature. The increased air

flow will result in increased power consumption.

3.3.5 SS P8 (Upset Flaring)

Emissions under flaring SS P8 includes fuel gas (SS P8a) and acid gas flaring (SS P8b).

Emissions of CO2 (SS P8a) = ( PFF + 𝑉𝑃𝑈𝑅𝐺𝐸 + 𝑉𝑃𝑖𝑙𝑜𝑡) × EFCO2 = 1,191.11 t CO2

Emissions of CH4 (SS P8a) = ( PFF + 𝑉𝑃𝑈𝑅𝐺𝐸 + 𝑉𝑃𝑖𝑙𝑜𝑡) × EFCH4 = 3.77 t CH4

Emissions of N2O (SS P8a) = ( PFF + 𝑉𝑃𝑈𝑅𝐺𝐸 + 𝑉𝑃𝑖𝑙𝑜𝑡) × EFN2O = 0.04 t N2O

VPILOT = QPILOT x 0.028 m3/ft3 x Days= 258.39 m3

𝑉𝑃𝑈𝑅𝐺𝐸 = 𝑉𝑀7152 − 𝑃𝐹𝐹 − 𝑃𝐴𝐹 = 418.63 e3m3

Where: VM7152 is total metered volume of acid gas flare meter 7152

The acid gas contains CO2 and residual hydrocarbons including CH4, C2H6, C3H8, iC4H10, C4H10, and

C7H16. Below are the equations used to determine the t CO2e of each hydrocarbon species due to

flaring of the acid gas during upset conditions.

Emissions of CO2 (SS P8b) = (PAF + 𝑃𝐴𝐹𝑈𝑉 + 𝑃𝐴𝐹𝑈𝑉,𝑅𝐸𝑆𝑇𝐴𝑅𝑇) × %CO2(AG) × ρCO2= 258.25 t CO2

Emissions of CH4 (SS P8b) = (PAF + 𝑃𝐴𝐹𝑈𝑉 + 𝑃𝐴𝐹𝑈𝑉,𝑅𝐸𝑆𝑇𝐴𝑅𝑇) × %CH4(AG) × ρCH4 × 44 (

g

moleCO2)

16(g

moleCH4)

= 3.09 t CH4

Emissions of C2H6 (SS P8b) = (PAF + 𝑃𝐴𝐹𝑈𝑉 + 𝑃𝐴𝐹𝑈𝑉,𝑅𝐸𝑆𝑇𝐴𝑅𝑇) × %C2H6(AG) × ρC2H6 × (2 × 44 (

g

moleCO2)

30(g

moleC2H6)

) =

1.46 t CO2e


g

moleCO2)

44(g

moleC3H8)

) =

0.77 t CO2e

Emissions of iC4H10 (SS P8b) = (PAF + 𝑃𝐴𝐹𝑈𝑉 + 𝑃𝐴𝐹𝑈𝑉,𝑅𝐸𝑆𝑇𝐴𝑅𝑇) × %iC4H10(AG) × ρiC4H10 × (4 × 44 (

g

moleCO2)

58(g

moleiC4H10)

)

= 0.27 t CO2e


February 2019

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Emissions of nC4H10 (SS P8b) = (PAF + 𝑃𝐴𝐹𝑈𝑉 + 𝑃𝐴𝐹𝑈𝑉,𝑅𝐸𝑆𝑇𝐴𝑅𝑇) × %nC4H10(AG) × ρnC4H10 × (4 × 44 (

g

moleCO2)

58(g

molenC4H10)

)

= 0.40 t CO2e

Emissions of iC5H12 (SS P8b) = (PAF + 𝑃𝐴𝐹𝑈𝑉 + 𝑃𝐴𝐹𝑈𝑉,𝑅𝐸𝑆𝑇𝐴𝑅𝑇) × %iC5H12(AG) × ρiC5H12 × (5 × 44 (

g

moleCO2)

72(g

moleiC5H12)

) =

0.50 t CO2e


g

moleCO2)

72(g

molenC5H12)

)

= 0.33 t CO2e


g

moleCO2)

86(g

molenC6H14)

)

= 0.57 t CO2e


g

moleCO2)

100(g

moleC7H16)

) =

2.86 t CO2e

The densities used in the above equations are based on assuming ideal gas behavior of each

hydrocarbon species.

3.3.6 SS P12 (Fuel Extraction & Processing)

Emissions of CO2 = (PFF + NGDehyc, total) × NEPCO2EF = 114.86 t CO2

Emissions of CH4 = (PFF + NGDehyc, total) × NEPCH4EF = 2.25 t CH4

Emissions of N2O = (PFF + NGDehyc, total) × NEPN2OEF = 0.01 t N2O

Where,

PFF = Dilution gas volume used for upset flaring, HMI metered volume, 612.85 e3m3

NGDehyc,total = total stationary combustion gas for gas compression and dehydration, 274.60 e3m3

3.4 Emission Factors

Table 11 provides the emission factors used in the quantification of emissions for the Project.

Table 11: Emission Factors Used in the Project

A site specific CO2 emission factor was determined based on monthly gas analyses at the facility.

All other emission factors were sourced from the Carbon Offset Emission Factors Handbook

(version 1.0, March 2015).

Parameter CO2 Emission Factor

(t/e3m3)

CH4 Emission Factor

(t/e3m3)

N2O Emission Factor

(t/e3m3)


February 2019

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Natural gas combustion

(producer consumption)

2.02 0.0064 0.00006

Natural gas extraction 0.043 0.0023 0.000004

Natural gas processing 0.090 0.0003 0.000003


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4.0 References

Alberta Environment, 2008, Quantification Protocol for Acid Gas Injection (version 1.0, May 2008)

ACCO, 2018, Standard for Greenhouse Gas Emission Offset Project Developers: Carbon

Competitiveness Incentive Regulation (version 2.0)

CSA Standards, 2009, ISO 14064-2: Essentials Greenhouse Gas Projects

Alberta Environment and Parks, 2015, "Carbon Offset Emission Factors Handbook Version 1.0

March 2015


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Appendix A: Approval to Use Flagged Protocol