Offset Project Report Form Advantage Oil & Gas Ltd. Prepared by: … · which were incorporated...
Transcript of Offset Project Report Form Advantage Oil & Gas Ltd. Prepared by: … · which were incorporated...
Advantage Glacier Acid Gas Injection Offset Project
February 2019
Version 2.0 Report Template – July 2018
Offset Project Report Form
Advantage Glacier Acid Gas Injection Offset Project
Project Developer:
Advantage Oil & Gas Ltd.
Prepared by:
Blue Source Canada ULC
Reporting Period:
January 1, 2018 – December 31, 2018
Date:
February 27, 2019
Advantage Glacier Acid Gas Injection Offset Project
February 2019
Version 2.0 Report Template – July 2018
Greenhouse Gas Assertion
Project Developer:
Advantage Oil & Gas Ltd.
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:
Advantage Glacier Acid Gas Injection Offset Project
Reporting Period:
January 1, 2018 – December 31, 2018
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.
Advantage Glacier Acid Gas Injection Offset Project
February 2019
Version 2.0 Report Template – July 2018
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
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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
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Version 2.0 Report Form – July 2018
1.0 Contact Information
Table 1: Project Contact Information
Project Developer Contact Information Additional Contact Information
Advantage Oil & Gas Ltd.
Click here to enter text.
Reg Beck
Click here to enter text.
Suite 300, 440 2nd Avenue SW
Click here to enter text.
Calgary, AB T2P 5E9
Click here to enter text.
(403) 718-8123
www.advantageog.com
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
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
Advantage Glacier Acid Gas Injection Offset Project
February 2019
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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
January 1, 2018 – December 31, 2018
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
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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
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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
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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
Table 5: Summary of changes made in the 2014 reporting period
• Chan
ge
Item
• Description • SS
Affected
• SS
Related
• Previous Calculation
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
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• Chan
ge
Item
• Description • SS
Affected
• SS
Related
• Previous Calculation
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
Table 6: Summary of changes made in the 2015 reporting period
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.
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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.
Table 7: Summary of changes made in the 2016 reporting period
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
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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.
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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
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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
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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.
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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;
CD2 = Condenser 2, kW;
CD3 = Condenser 3, 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
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Emissions of C3H8 (SS B6b) = (PDisposal + PAF + 𝑃𝐴𝐹𝑈𝑉) × %C3H8(TG) × ρC3H8 × (3 × 44 (
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
Emissions of C6H14 (SS B6b) = (PDisposal + PAF + 𝑃𝐴𝐹𝑈𝑉) × %C6H14(TG) × ρC6H14 × (6 × 44 (
g
moleCO2)
86(g
molenC6H14)
) =
5.30 t CO2
Emissions of C7H16 (SS B6b) = (PDisposal + PAF + 𝑃𝐴𝐹𝑈𝑉) × %C7H16(TG) × ρC7H16 × (7 × 44 (
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
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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
Emissions of C3H8 (SS P8b) = (PAF + 𝑃𝐴𝐹𝑈𝑉 + 𝑃𝐴𝐹𝑈𝑉,𝑅𝐸𝑆𝑇𝐴𝑅𝑇) × %C3H8(AG) × ρC3H8 × (3 × 44 (
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
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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
Emissions of nC5H12 (SS P8b) = (PAF + 𝑃𝐴𝐹𝑈𝑉 + 𝑃𝐴𝐹𝑈𝑉,𝑅𝐸𝑆𝑇𝐴𝑅𝑇) × %nC5H12(AG) × ρnC5H12 × (5 × 44 (
g
moleCO2)
72(g
molenC5H12)
)
= 0.33 t CO2e
Emissions of nC6H14 (SS P8b) = (PAF + 𝑃𝐴𝐹𝑈𝑉 + 𝑃𝐴𝐹𝑈𝑉,𝑅𝐸𝑆𝑇𝐴𝑅𝑇) × %nC6H14(AG) × ρnC6H14 × (6 × 44 (
g
moleCO2)
86(g
molenC6H14)
)
= 0.57 t CO2e
Emissions of C7H16 (SS P8b) = (PAF + 𝑃𝐴𝐹𝑈𝑉 + 𝑃𝐴𝐹𝑈𝑉,𝑅𝐸𝑆𝑇𝐴𝑅𝑇) × %C7H16(AG) × ρC7H16 × (7 × 44 (
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)
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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