Page
i
Prepared by: Blue Source Canada
Suite 700, 717 7th Ave. SW, Calgary, AB, T2P 0Z3 Tel: (403) 262-3026 Fax: (403) 269-3024
Greenhouse Gas Emissions Reduction
Offset Project Report
For the Reporting Period January 1, 2016– December 31, 2016
Version 3.0
February 23, 2017
Prepared by: Blue Source Canada ULC (Authorized Project Contact) Suite 700, 717-7th Avenue SW Calgary, Alberta T2P 3R5 T: (403) 262-3026 F: (403) 269-3024 www.bluesource.com
Prepared for: Trilogy Energy by its managing partner, Trilogy Energy Corp. (Project Proponent) 1400, 332 – 6th Avenue SW T: (403) 290-2901 F: (403) 263-8915 www.trilogyenergy.com
TRILOGY KAYBOB ACID GAS INJECTION OFFSET PROJECT
Page 2
Prepared by: Blue Source Canada Suite 700, 717 7th Ave. SW, Calgary, AB, T2P 0Z3 Tel: (403) 262-3026 Fax: (403) 269-3024
TABLE OF CONTENTS
1.0 Project Scope and Project Site Description ..................................................................... 5
2.0 Project Contact Information ............................................................................................. 9
3.0 Project Description and Location ....................................................................................10
4.0 Project Implementation and Variances ...........................................................................11
Variances and Clarifications specific to the 2016 reporting period ......................................11
Standard Variances and Clarifications since the First Reporting Period .............................13
5.0 Reporting Period ............................................................................................................20
6.0 Greenhouse Gas Calculations ........................................................................................20
SS B9 (Fuel Extraction & Processing) ................................................................................21
SS B6 (Incineration) ...........................................................................................................22
SS B5b (Multi-Stage Claus Unit) ........................................................................................25
SS P12 (Fuel Extraction & Processing) ..............................................................................26
SS P6 (Acid Gas Dehydration and Compression) ..............................................................26
SS P8 (Upset Flaring) ........................................................................................................27
7.0 Greenhouse Gas Assertion ............................................................................................30
8.0 Offset Project Performance ............................................................................................31
9.0 Project Developer Signatures .........................................................................................32
10.0 Statement of Senior Review ...........................................................................................33
11.0 References .....................................................................................................................34
Page 3
Prepared by: Blue Source Canada Suite 700, 717 7th Ave. SW, Calgary, AB, T2P 0Z3 Tel: (403) 262-3026 Fax: (403) 269-3024
LIST OF TABLES
Table 1: summary of changes made in the 2016 reporting period ................................................................... 11
Table 2: Changes made by reporting period .............................................................................................................. 13
Table 3: Summary of changes made in fourth reporting period ........................................................................ 16
Table 4: Summary of changes made in 2015 reporting period .......................................................................... 18
Table 5: Emission factors used for Trilogy Kaybob Acid Gas Injection Offset Project. ............................. 29
Table 6: Offset tonnes created by the Trilogy Kaybob Acid Gas Injection Offset Project between
January 1, 2016 to December 31, 2016. ....................................................................................................................... 30
Table B-1. Metering Maintenance and Calibration details. .................................................................................. 40
LIST OF FIGURES
Figure 1. Credits created by the Trilogy Kaybob Acid Gas Injection Offset Project. .................................. 31
Figure 2 Simplified Data Flow Chart .............................................................................................................................. 39
Page 4
Prepared by: Blue Source Canada Suite 700, 717 7th Ave. SW, Calgary, AB, T2P 0Z3 Tel: (403) 262-3026 Fax: (403) 269-3024
LIST OF ABBREVIATIONS
AEOR Alberta Emissions Offset Registry
AENV Alberta Environment (now AEP)
AEP Alberta Environment and Parks (previously AESRD)
AER Alberta Energy Regulator (previously ERCB)
AESRD Alberta Environment and Sustainable Resource Department (now AEP)
AGI Acid Gas Injection
CO2e Carbon Dioxide-Equivalent
ERCB Energy Resources Conservation Board (now AER)
GHG Greenhouse gas
GWP Global Warming Potential
H2S Hydrogen Sulphide
LHV Lower Heating Value
OPP Offset Project Plan
SGER Specified Gas Emitters Regulation
SRU Sulphur Recovery Unit
SS Sources and Sinks
Page 5
Prepared by: Blue Source Canada Suite 700, 717 7th Ave. SW, Calgary, AB, T2P 0Z3 Tel: (403) 262-3026 Fax: (403) 269-3024
1.0 Project Scope and Project Site Description
The project title
is:
Trilogy Kaybob Acid Gas Injection Offset Project (herein referred to as the
‘Project’)
The project’s
purpose(s) and
objective(s)
are:
The opportunity for generating carbon offsets with this project arises from the
direct greenhouse gas (GHG) emission reductions resulting from the geological
sequestration of acid gas, containing CO2, as a part of raw natural gas processing.
Previously, GHGs were generated through on-site acid gas flaring and off-site
through the operation of a sulphur recovery unit (SRU) or, specifically, a Super
Claus unit and incineration of the resulting tail gas.
Date when the
project began:
The Project began on October 7, 2010, and is a result of actions taken on, or after,
January 1, 2002.
Expected
lifetime of the
project:
The Project, acid gas injection (AGI), is expected to permanently replace acid gas
flaring at the Kaybob Gas Plant (herein referred to as ‘the Plant’) and will,
therefore, exceed the credit duration period for this project.
Credit start
date:
Credit start date for this project is October 7, 2010.
Credit duration
period:
Proponents for the Project intend to claim offsets for a period of 8 years, starting
October 7, 2010 and ending on October 6, 2018.
Reporting
period:
January 1, 2016 to December 31, 2016
Actual
emissions
reductions:
In this report, which covers the period January 1st, 2016 to December 31st, 2016,
the total project emission reductions are calculated to be 37,342 tCO2e. The
Project has created the following emission reductions:
2010 (October 7th, 2010 to December 31st, 2010): 2,015 t CO2e
2011 (January 1st, 2011 to December 31st, 2011): 21,077 t CO2e
2012 (January 1st, 2012 to December 31st, 2012): 28,923 t CO2e
2013 (January 1st, 2013 to December 31st, 2013): 51,655 t CO2e
2014 (January 1st, 2014 to December 31st, 2014): 44,636 t CO2e
2015 (January 1st, 2015 to December 31st, 2015): 42,908 t CO2e
2016 (January 1st, 2016 to December 31st, 2016): 37,342 t CO2e
Page 6
Prepared by: Blue Source Canada Suite 700, 717 7th Ave. SW, Calgary, AB, T2P 0Z3 Tel: (403) 262-3026 Fax: (403) 269-3024
Total: 228,556 t CO2e
Quantification
Protocol:
The quantification protocol used is the Quantification Protocol for Acid Gas
Injection, May 2008, Version 1 (AENV, 2008) published by Alberta Environment
(AENV).
Protocol
Justification:
In the project condition the capture and permanent sequestration of the entire
acid gas stream directly reduces the quantity of CO2 released to the atmosphere.
Further, the process of compression, transportation, and injection of acid gas
reduces the quantity of GHG emissions released to the atmosphere relative to
more GHG intensive baseline processes (i.e. flaring and sulphur recovery)
required for safe disposal of the hydrogen sulphide (H2S) contained within the
acid gas stream.
As the activities of the Project are applicable under the Quantification Protocol
for Acid Gas Injection, May 2008, Version 1 (AENV, 2008) and AGI was not an
industry standard at the time the project commenced and started to create
credits, the results of this project are considered additional and would not have
occurred under business as usual circumstances.
Other
Environmental
Attributes:
There are no other environmental attributes, credits, or benefits that this Project
is generating.
Legal land
description of
the project or
the unique
latitude and
longitude:
The Project is located in Alberta. Both the Kaybob Gas Plant and the Kaybob Field
injection well are located north of Fox Creek, Alberta. Specifically, the Plant and
the injection well are located at the following unique identifiers:
LSD: 08-09-064-19W5 (Plant); 00/08-09-064-19W5/2 (Injection well)
Latitude: 54.521531° (Plant, Injection well)
Longitude: -116.80219° (Plant, Injection well)
Ownership: Trilogy Energy by its managing partner, Trilogy Energy Corp. (herein referred
to as ‘the Proponent’) owns 100% of the AGI equipment and the environmental
attributes associated with the Project.
Reporting
details:
As stated in the Offset Project Plan (OPP), the Proponent intends to submit
annual reports for the Project. This reporting period will cover the full year of
2016, as stated above.
Verification
details:
The verifier RWDI is an independent third-party that meets the requirements
outlined in the Specified Gas Emitters Regulation (SGER). An acceptable
Page 7
Prepared by: Blue Source Canada Suite 700, 717 7th Ave. SW, Calgary, AB, T2P 0Z3 Tel: (403) 262-3026 Fax: (403) 269-3024
verification standard (e.g. ISO14064-3) has been used and RWDI has been vetted
to ensure technical competence with this project type.
This is the fifth verification carried out by RWDI for this project.
Project activity: This Project meets the requirements for offset eligibility as outlined in section
3.1. of the Technical Guidance for Offset Project Developers (version 4.0,
February 2013). In particular:
1. The project occurs in AB: as outlined above;
2. The project results from actions not otherwise required by law and beyond
business as usual and sector common practices: Offsets being claimed under
this project originate from a voluntary action. The project activity (i.e. AGI)
occurs at a non-regulated facility and is not required by law. The Project was
commenced using a government approved quantification protocol, which
indicated that when the Project was first registered the project activity was
undertaken by less than 40% of the industry and was therefore not
considered to be sector common practice1;
3. The project results from actions taken on or after January 1, 2002: as
outlined above;
4. The project reductions/removals are real, demonstrable, quantifiable and
verifiable: The Project is creating real reductions that are not a result of
shutdown, cessation of activity or drop in production levels. The emission
reductions are demonstrable, quantifiable and verifiable as outlined in the
remainder of this plan.
5. The project has clearly established ownership: The Proponent owns 100%
of the AGI equipment and is the primary contributor to the acid gas stream
directed to injection. Credits created from the specified reduction activity
have not been created, recorded or registered in more than one trading
registry for the same period.
6. The project will be counted once for compliance purposes: The Project
credits will be registered with the Alberta Emissions Offset Registry (AEOR)
1 Note that the Quantification Protocol for Acid Gas Injection, May 2008, Version 1 was terminated by Alberta
Environment and Sustainable Resource Development (AESRD) in a memo dated January 28, 2013. As per the
termination notice, 'existing projects that were approved and listed on the Alberta Offset Registry will be eligible
for the remainder of their crediting period'. As the Project was already approved and listed on the AEOR prior
to January 28, 2013, it has de facto permission to continue using this protocol until the end of its eligible
crediting period on October 6, 2018.
Page 8
Prepared by: Blue Source Canada Suite 700, 717 7th Ave. SW, Calgary, AB, T2P 0Z3 Tel: (403) 262-3026 Fax: (403) 269-3024
which tracks the creation, sale and retirement of credits. Credits created
from the specified reduction activity have not been, and will not be, created,
recorded or registered in more than one trading registry for the same
period.
Page 9
Prepared by: Blue Source Canada Suite 700, 717 7th Ave. SW, Calgary, AB, T2P 0Z3 Tel: (403) 262-3026 Fax: (403) 269-3024
2.0 Project Contact Information
Project Developer Contact Information
Trilogy Energy by its managing partner, Trilogy Energy Corp. Sean Draper, Area Engineering Manager Phone: (403) 290-2901 Fax: (403) 263-8915 Email: [email protected]
1400, 332 - 6 Avenue S.W. Calgary, Alberta Canada T2P 0B2
Alternate: Carrie Muskett, Engineering Technician Phone: (403) 290-2937 Fax: (403) 263-8915 Email: [email protected]
Web: www.trilogyenergy.com
Authorized Project Contact
Blue Source Canada ULC Tooraj Moulai Senior Engineer, Carbon Services Phone: (403) 262-3026 x259 Fax: (403) 269-3024 Email: [email protected]
Suite 700, 717 - 7th Avenue SW Calgary, Alberta Canada T2P 0Z3 Web: www.bluesourcecan.com
Verifier
RWDI Air Inc. Alena Saprykina, M.Sc. Lead Verifier Phone: (403) 232-6771 ext. 6273 Fax: (519) 823-1316 Email: [email protected] CONSECUTIVE VERIFICATIONS CONDUCTED: 5
1000 – 736 8th Avenue SW Calgary, Alberta, T2P 1H4 Canada
Website: www.rwdi.com
Page 10
Prepared by: Blue Source Canada Suite 700, 717 7th Ave. SW, Calgary, AB, T2P 0Z3 Tel: (403) 262-3026 Fax: (403) 269-3024
3.0 Project Description and Location
The Project is located at the Kaybob Gas Plant—north of Fox Creek, Alberta. Specifically, the LSD for
the Project is 08-09-064-19W5 (for the Plant) and 00/08-09-064-19W5/2 (for the injection well).
The Project proponent is Trilogy Energy by its managing partner, Trilogy Energy Corp. (herein
referred to as ’the Proponent’). Currently, the Proponent owns 100% of the AGI equipment and is the
primary contributor to the acid gas stream directed to injection.
In 2010, Trilogy began construction on the acid gas injection system to convert from the emissions
intensive treatment of the superclause acid gas SRU. On October 7, 2010, the SRU was
decommissioned and the AGI system actively began injection. The AGI activity combines the acid gas
stream produced by both Plant-D and Plant-E at the Kaybob Gas Plant for acid gas compression and
injection into a well-characterized depleted producing reservoir which results in the permanent
geological sequestration (>1000 years) via transport by an acid gas pipeline. The operation of the
AGI scheme directly reduces GHG emissions compared to the prior flaring operations by geologically
sequestering CO2 contained in the acid gas stream and by reducing fossil fuel consumption normally
required to supplement the acid gas flaring and sulphur recovery operations.
Page 11
Prepared by: Blue Source Canada Suite 700, 717 7th Ave. SW, Calgary, AB, T2P 0Z3 Tel: (403) 262-3026 Fax: (403) 269-3024
4.0 Project Implementation and Variances
Variances and Clarifications specific to the 2016 reporting period
During this reporting period, it should be noted that the following operational incidents occurred:
1. The facility was shut down between May 15-18 due to wildfires in the area. This would have
resulted in a lower volume of acid gas sent to disposal for May.
2. Gas analyses for the Acid Gas Injection point for May show a higher than normal N2 and H2
mole fractions. This could be due to either air contamination or due to the sample being taken
a couple days after the plant came back online from the wildfires.
3. The Gas Analysis for Plant D failed in October due to air contamination.
4. The combined Acid Gas Injection analysis for November was not taken due to work in the
area. Instead, a blended analysis from the two acid gas streams was taken before injection.
The following clarifications have been added for transparency:
5. Energy exports and imports for the multi-stage Claus Process have been based on simulations
carried out by SULSIM in 2013. These parameters have not been updated as the values of the
energy export and import from the multi-stage claus unit are immaterial to the energy
balance of the baseline fuel source.
The following methodological updates were made in the current reporting period and are explained
in more detail in paragraph 6. to 9. below:
Table 1: summary of changes made in the 2016 reporting period
Change Item SS Affected Previous Value Revised Value
kW consumption of
fans SSP6
PFAN = FANkW x
COMPhours
PFAN1 = FANkW x
COMPhours x
COMPuse3
kW consumption of
compressors A1 &
A2
SSP6 PCOMP = COMPkW x
COMPhours
PCOMP = ΣkWh Stages
1-6 of compressors
curves
Gas Analysis
Averages
SSB6a, SSP8a,
SSP8b
Time Weighted
Average
Volume Weighted
Average
SULSIM from
Sulphur Experts
SS B6a, SS B6b,
SS B9
Sulphur Experts,
February 2016,
“Trilogy Energy
Sulphur Experts,
February 2017,
“Trilogy Energy
Page 12
Prepared by: Blue Source Canada Suite 700, 717 7th Ave. SW, Calgary, AB, T2P 0Z3 Tel: (403) 262-3026 Fax: (403) 269-3024
Change Item SS Affected Previous Value Revised Value
Kaybob South SRU
Simulation
Report”, Project
No. ESC2205
Kaybob South SRU
Simulation Report”
Project No.
ESC2473
6. Previously the power draw of the fan impellers was calculated based on operational hours of
the compressors. The revised methodology follows the assumption that changes to the
volume of air required to be moved by the fans, Q is directly proportional to the changes of
acid gas flow rate from the maximum design throughput. This is a reasonable assumption as
the rate of heat transfer from the air to the acid gas must remain constant to achieve the
desired output temperature.
To determine the power, draw of the fans operating at a percent of maximum speed the Fan
Affinity laws are observed.
Fan affinity laws state that the air flow is proportional to fan speed, N: 𝑄2
𝑄1=
𝑁2
𝑁1
and that the power, W, is proportional to the cube of the fan speed:
𝑊2
𝑊1= (
𝑁2
𝑁1)
3
Therefore, combining the above equations and solving for W2 results in the rated power draw
of the fan impellers at the reduced air flow:
𝑊2 = 𝑊1 × (𝑄2
𝑄1)
3
7. Previously the power draw of the compressors was calculated based on compressor run time
hours, assuming constant maximum power draw. This has been updated to make use of
compressor curves provided by Ariel for acid gas compressors A1 and A2. Ariel performed
three runs to test the six different stages of each compressor and results were used to
determine the corresponding compressor curves for each stage.
This revised methodology uses real performance data to calculate power draw at various kW
consumptions and is therefore more accurate than assuming constant maximum power draw.
Page 13
Prepared by: Blue Source Canada Suite 700, 717 7th Ave. SW, Calgary, AB, T2P 0Z3 Tel: (403) 262-3026 Fax: (403) 269-3024
8. Gas composition averages were formerly being calculated using time weighted averages.
This has been updated to use volume weighted averages instead, which allows for a more
accurate average to be calculated, specifically in the case of failed analyses, shutdown or
similar events.
9. In this reporting period, key components in the acid gas composition showed considerable
variance from the previous reporting period. The changes were determined to be significant
enough to have a material impact on the SULSIM ratio parameter that is used in determining
the tail gas volumes sent to the incinerator. For this reason and to ensure accuracy of the
emissions calculations, an updated Sulphur Experts simulation was obtained for this
reporting period. The SULSIM ratio is 1.82 for the current reporting period.
Standard Variances and Clarifications since the First Reporting Period
Several variances and modifications, as compared to the Offset Project Plan, dated March 7, 2012,
were made for this reporting period and are listed in Table 2. More information is available in
paragraphs (i)-(xviii) below. Note that these changes are all consistent with previous quantifications
and have been repeated here for transparency.
Table 2: Changes made by reporting period
Reporting Period Changes Made
January 1, 2012 - December 31, 2012 (i)-(v)
January 1, 2013 –December 31, 2013 (vi)
January 1, 2014 – December 31, 2014 (vii)-(xii)
January 1, 2015 – December 31, 2015 (xiii)-(xvii)
Changes Made in the Second Reporting Period (January 1, 2012 – December 31,
2012) (i) SS B9 (Fuel Extraction & Processing):
In the first reporting period for the Project (i.e. October 7, 2010 – December 31, 2011),
the total fuel gas volumes consumed in the baseline included fuel gas volumes to
supplement acid gas and tail gas flaring from Plant-D and Plant-E, respectively. Beginning
with the second reporting period and going forward, the fuel gas equivalent-volume to
operate the first stage reheater as a part of the operation of the SRU (i.e. a Multi-Stage
Claus unit) has been included to increase the accuracy of the emissions reductions. The
other components that require an energy import for their operation either run on indirect
Page 14
Prepared by: Blue Source Canada Suite 700, 717 7th Ave. SW, Calgary, AB, T2P 0Z3 Tel: (403) 262-3026 Fax: (403) 269-3024
steam (e.g. acid gas preheater, air preheater, reheater 2 and 3) or grid electricity (e.g.
furnace air blower and sulphur pump) and, therefore, are not included in this SS. This
change increases the accuracy of the quantification.
(ii) SS (B5b) Multi-Stage Claus Unit:
a. In the first reporting period for the Project (i.e. October 7, 2010 – December 31, 2011),
ηEnergy was assumed to be 100%; however, beginning with the second reporting
period and going forward, ηEnergy is replaced with the fuel energy efficiency of a small
gas utility boiler at 70%2 in order to apply conservativeness in the quantification
approach for SS B5b. This modification, alone, results in a slight decrease to the
overall emission reductions.
b. The operation time for SS B5b was previously assumed to be continuous or 24 hours
per day for the entire reporting period. In order to increase the accuracy to the
quantification approach of SS B5b, the operational time is adjusted to consider the
total operating time of the two acid gas compressors, unit A-1 and A-2.
c. The baseline is maintained as a Multi-Stage Claus unit; however, the energy inputs
and outputs were simulated by an independent expert simulation third-party,
Sulphur Experts, using SULSIM. The full report is included in Appendix A: List of
Supporting Documentation. Previously, the variables required for the quantification
were obtained from SemCAMS who provided data that was prorated to the
Proponent’s share of acid gas volumes for the last year (i.e. 2010) in which the
Proponent had sent their acid gas for sulphur recovery. Therefore, the emission
reduction quantified is now more accurate.
d. Previously, the fuel gas lower heating value (LHV) was based on the average fuel gas
composition experienced at SemCAMS in 2011. Beginning with the second reporting
period and going forward, the fuel gas LHV is based on the fuel gas used at the Plant.
As the LHV is relatively similar for both facilities (i.e. between 36 – 38 MJ/m3), this
modification has minimal affect on the emission reductions.
(iii) SS (B6b) Incineration (Acid Gas):
a. Previously, as stated in Section 2.5.1 “Quantification Approaches” in the Protocol, only
CO2 and CH4 were considered in the incineration of acid gas; however, since residual
hydrocarbons other than CH4 are present in the acid gas (from Plant D) and tail gas
2 CIBO. 2003, Energy Efficiency & Industrial Boiler Efficiency: An Industry Perspective. [pdf] Available at:
<www.cibo.org>
Page 15
Prepared by: Blue Source Canada Suite 700, 717 7th Ave. SW, Calgary, AB, T2P 0Z3 Tel: (403) 262-3026 Fax: (403) 269-3024
(from Plant E), including C2H6, C3H8, C4H10, C5H12, C6H14, and C7H16, it is therefore more
accurate to consider these components in the quantification of SS B6b.
b. Although not stated, the density of CO2 and CH4 provided in the Protocol are based on
conditions of 0°C and 101.325 kPa. Since the metered volumes are temperature and
pressure compensated to 15°C and 101.325 kPa, appropriate densities have been
sourced from the GPA Standard 2145-093 and are used in the quantifications. This
modification results in a more accurate estimate of overall emission reductions.
(iv) SS (P12) Fuel Extraction/Processing:
The total volume of natural gas combusted in the project condition (i.e. AGI) was
previously assumed to be the sum of the total fuel gas volumes sent to Plant E (which was
also assumed to be equivalent to the total fuel gas consumed for SS P6) and the fuel gas
volumes used to assist in the incineration of acid gas in SS P8. The volume of natural gas
combusted in the Project condition has been adjusted and equates to the fuel gas volumes
required to supplement the flaring of acid gas during upset conditions. The quantification
methodology for SS P6 has been revised as described below. This modification results in
a more accurate estimate of overall emission reductions.
(v) SS (P8) Upset Flaring:
a. Previously, as stated in Section 2.5.1 “Quantification Approaches” in the Protocol, only
CO2 and CH4 were considered in the incineration of acid gas during upset flaring;
however, since residual hydrocarbons other than CH4 are present in the acid gas
streams, including C2H6, C3H8, C4H10, C5H12, C6H14, and C7H16, it is therefore more
accurate to consider these components in the quantification of SS P8b.
b. Although not stated, the density of CO2 and CH4 provided in the Protocol are based on
conditions of 0°C and 101.325 kPa. Since the metered volumes are temperature and
pressure compensated to 15°C and 101.325 kPa, consistent with ERCB reporting
requirements, appropriate densities have been sourced from the GPA Standard 2145-
093 and are used in the quantifications. This modification results in a more accurate
estimate of overall emission reductions.
Changes Made in the Third Reporting Period (January 1, 2013 – December 31,
2013) (vi) Affected SS: B6b Tail Gas Incineration, Related SSs: B6a Fuel Gas Incineration; B9 Fuel
Extraction and Processing;
3 GPA Standard 2145-09: Table of Physical Properties for Hydrocarbons and Other Compounds of Interest to
the Natural Gas Industry.
Page 16
Prepared by: Blue Source Canada Suite 700, 717 7th Ave. SW, Calgary, AB, T2P 0Z3 Tel: (403) 262-3026 Fax: (403) 269-3024
A methodology revision has been made to the calculation of baseline Tail Gas Volumes
leaving the SRU and being sent to the incinerator. This revision has been made to increase
the accuracy of the calculation, in line with the principles of ISO 14064-2.
The methodology revision surrounding the determination of baseline tail gas volume
directly affects the emissions from tail gas incineration. The change in volume calculation
also affects emissions related to fuel gas incineration and fuel extraction and processing;
as the tail gas volume is used in conjunction with the acid gas to fuel gas ratio to determine
the volume of fuel gas required to achieve a combined heating value of 20 MJ/m3.
A third-party simulation expert, Sulphur Experts, modeled the baseline SRU and
incinerator using their proprietary software, SULSIM. Per the SULSIM report, the multi-
stage Claus unit consists of a thermal reaction furnace where H2S is converted to SO2 via
the oxidation reaction:
H2S + 3/2O2 SO2 + H2O (1)
The addition of air to supply enough oxygen for the reaction to tend to completion results
in a large increase in the molar volume of the acid gas mixture, which was not captured
in previous quantifications. The SULSIM model captures this increase in the material
balance of the acid gas inlet stream (INLETAG (outlet)) and the tail gas stream to the
incinerator (ADA (outlet)). Prior to the process, the inlet stream is comprised mainly of
CO2, H2S and H2O. Following the SRU, the primary tail gas components are CO2, N2, and
H2O, with a molar flow rate approximately 1.82 times that of the inlet stream due to the
introduction of nitrogen. As the acid gas stream is assumed to follow ideal gas behaviour
at standard temperature and pressure, any changes to the number of moles in the gas will
see an equal change in the spatial volume occupied by that gas, regardless of the different
composition.
Therefore, to obtain an accurate volume representation of the baseline tail gas to
incineration, VTAIL, the inlet volume will need to be multiplied by the ratio of the molar
flow rate of ADA (outlet), n2, to the molar flow rate of the acid gas inlet stream, INLETAG
(outlet), n1.
Changes Made in the Fourth Reporting Period (January 1, 2014 – December 31,
2014) The following items in Table 3 had been updated for the period of January 1, 2014 – December 31,
2014), and are explained in paragraphs viii. to xi. below.
Table 3: Summary of changes made in fourth reporting period
Page 17
Prepared by: Blue Source Canada Suite 700, 717 7th Ave. SW, Calgary, AB, T2P 0Z3 Tel: (403) 262-3026 Fax: (403) 269-3024
Change Item SS Affected Previous Value Revised Value
kW rating of
fans/coolers for
Unit A-2
SSP6 9.7 kW 14.9 kW
Global Warming
Potentials
All IPCC Second
Assessment Report
(1996)
IPCC Fourth
Assessment Report
(2007)
Baseline N2O
Emissions from
Flaring and
Incineration of Acid
Gas
SSB6b Baseline N2O
emissions were
previously omitted
Baseline N2O
emissions have
now been included
Tail Gas LHV
Composition
SSB6a Just included H2S
in LHV calculation
Includes all
combustible
components in
LHV calculation
(vii) Compressor Fan Power Rating
As noted in the verification report from the third reporting period (January 31, 2013 –
December 31, 2013), the kW rating of compressor fan power ratings was incorrectly
identified. The fan power rating for compressor unit A-2 has now been updated, and this
has been reflected in the calculator for this reporting period.
(viii) Global Warming Potentials
As per the Memorandum dated January 23, 2014, from Neenu Walia, Section Head,
Regulatory and Mitigation, AESRD, global warming potentials (GWPs) used for
quantification for this reporting period have been updated to the 2007 Fourth
Assessment Report values, published by the International Panel on Climate Change
(IPCC).
(ix) Baseline N2O Emissions
As noted in the verification report from the third reporting period (January 31, 2013 –
December 31, 2013), the emissions of N2O associated with the flaring and incineration of
acid gas in the baseline were previously omitted. These emission reductions have now
been included, and this has been reflected in the calculator for this reporting period.
(x) Tail Gas LHV Composition
Page 18
Prepared by: Blue Source Canada Suite 700, 717 7th Ave. SW, Calgary, AB, T2P 0Z3 Tel: (403) 262-3026 Fax: (403) 269-3024
Previously, the tail gas LHV composition calculation only included H2S. To be more
accurate, and to account for all combustible components in the tail gas, the following
compounds have now also been included in the LHV calculation: H2, COS, CO and CS2.
The following clarifications have been added for transparency:
(xi) Purge Gas
Fuel gas is used to purge compressors during maintenance periods. Of the fuel gas used
for purge, 99.9% is sent to flare, with the other 0.01% being vented to atmosphere. This
flared volume is measured by FIT-E-330-01A and is included in all project level
calculations.
Fuel gas consumption is metered at the plant level for all of Plant E and as such, the fuel
gas is not individually measured for each compressor. Compressors are purged at 5000
hour intervals for scheduled maintenance, or about once every 1.5 years. Other
compressor purges are unscheduled due to breakdowns or repairs needed. About 5.0
e3m3 of fuel gas is required to purge one unit, which amounts to approximately 15 e3m3
for scheduled maintenance to both units, each year. Therefore, the total amount of purge
gas that is vented and associated upstream emissions represent less than 0.01% of total
emissions, and as such have been excluded from calculations.
Changes Made in the Previous Reporting Period (January 1, 2015 – December 31,
2015)
(xii) Due to cost cutting measures the sample schedule was revised and gas analyses were not
taken for MVS E-500-01 after March 2015. This sample point has been updated for the
Project to point FR1A, which is the Alliance Sales Meter (FRALL). Sample point MVS E-500-
01 is on the same line as FR1A and therefore represents the same gas that was previously
being sampled at MVS E-500-01.
(xiii) A programming change was made to the logic for the flare process in late February 2015.
These changes were made to ensure that the flared gas heating value of 20 MJ/m3 is met as
per AER requirements.
The following items in Table 4 were updated during the fifth reporting period (January 1, 2015 –
December 31, 2015) and are explained in paragraphs xiv. to xvi. Below:
Table 4: Summary of changes made in 2015 reporting period
Change Item SS Affected Previous Value Revised Value
Total Acid Gas
Volume
SS B6a, SS B6b,
SS B9
Included flared
acid gas volume in
total acid gas
volumes
Revised to exclude
flared acid gas
volumes
Page 19
Prepared by: Blue Source Canada Suite 700, 717 7th Ave. SW, Calgary, AB, T2P 0Z3 Tel: (403) 262-3026 Fax: (403) 269-3024
Change Item SS Affected Previous Value Revised Value
SULSIM from
Sulphur Experts
SS B6a, SS B6b,
SS B9 Sulphur Experts,
February 2015,
“Trilogy Energy
Kaybob South SRU
Simulation
Report”, Project
No. ESC1958
Sulphur Experts,
February 2016,
“Trilogy Energy
Kaybob South SRU
Simulation Report”
Project No.
ESC2205
Fuel sources for
Multi Stage Claus
Unit
SS B5b Total fuel usage of
acid gas pre-
heater, air pre-
heater, and re-
heaters #1, #2 and
#3
Total fuel usage of
re-heater #1
(xiv) In the fourth reporting period an error was identified in the calculated project level acid gas
volumes. Previously, flared acid gas volumes from meter FIT E-330-01 were being added to
acid gas volumes from MVS E-500-04 (Plant D) and MVS E-200-28 (Plant E). This was due
to an incorrect project assumption and led to the double counting of project level acid gas
flare volumes as well as baseline level acid gas and supplemented fuel gas volumes. The
quantification methodology has now been updated to only include acid gas volumes from
MVS E-500-04 and MVS E-200-28.
(xv) For the fifth reporting period, key components in the acid gas composition showed
considerable variance from the previous reporting period. These included the composition
of H2S and hydrocarbons (i.e. CH4, C2H6, C3H8, C4H10, C5H12, C6H14, C7H16, and C8H18), which
are all oxidized during the sulphur recovery process and require the addition of combustion
air. The average H2S% for Plant E (40.32%) found in the acid gas composition was 6% lower
than the average H2S composition in the previous reporting period (42.99%). The
concentration of methane increased from 0.23% to 0.30% and for ethane from 0.04% to
0.06%. Similarly, there were composition increases observed for the majority of the higher
hydrocarbons (C3 to C8). The changes in these parameters were determined to be
significant enough to have a material impact on the SULSIM ratio parameter that is used in
determining the tail gas volumes sent to the incinerator. For this reason and to ensure
accuracy of the emissions calculations, an updated Sulphur Experts simulation was
obtained for this reporting period. The SULSIM ratio is 1.98 for the fifth reporting period.
(xvi) Prior to 2015, the volume of fuel used in the baseline for the Multi Stage Claus Unit was
calculated by summing total fuel usage of the acid gas pre-heater, air pre-heater and re-
heaters #1, #2 and #3. Re-heater #1 is a direct fired re-heater; other components including
Page 20
Prepared by: Blue Source Canada Suite 700, 717 7th Ave. SW, Calgary, AB, T2P 0Z3 Tel: (403) 262-3026 Fax: (403) 269-3024
re-heater #2, #3, the air pre-heater and acid gas pre-heater, all operate on process heat.
Therefore, these other components do not require an additional volume of fuel gas for steam
generation and as such the calculation has been updated to exclude these components.
5.0 Reporting Period
For the purposes of this project report, the carbon dioxide equivalent (CO2e) emission reduction
credits are claimed for activities from January 1, 2016 to December 31, 2016.
6.0 Greenhouse Gas Calculations
GHG emission reductions were calculated following the Quantification Protocol for Acid Gas Injection,
Version 1 (AENV, 2008). The activities and procedures outlined in the Offset Project Plan, dated March
7, 2012, 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 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 the Carbon
Offset Emission Factors Handbook (2015).
The following equations serve as the basis for calculating the emission reductions from the
comparison of the baseline and project conditions as per Quantification Protocol of Acid Gas Injection,
Version 1 (AENV, 2008):
The following is a detailed description of the equations used for the identified SSs in the
quantification of emissions due to CO2, CH4, and N2O for the Project.
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 (Fuel Extraction
& Processing)
(ii) Emissions Incineration = emissions under SS B6 (Incineration)
(iii) Emissions Multi-Stage Clause Unit = emissions under SS B5b (Multi-Stage Claus Unit)
Emissions Project = sum of the emissions under the project condition.
(iv) Emissions Fuel Extraction and Processing = emissions under SS P12 (Fuel Extraction
& Processing)
(v) Emissions Gas Dehydration and Compression = emissions under SS P6 (Acid Gas
Dehydration and Compression)
(vi) Emissions Upset Flaring = emissions under SS P8 (Upset Flaring)
Page 21
Prepared by: Blue Source Canada Suite 700, 717 7th Ave. SW, Calgary, AB, T2P 0Z3 Tel: (403) 262-3026 Fax: (403) 269-3024
SS B9 (Fuel Extraction & Processing)
Emissions of CO2 = BTotal−Fuel x NEPCO2EF
Emissions of CH4 = BTotal−Fuel x NEPCH4EF
Emissions of N2O = BTotal−Fuel x NEPN2OEF
Where,
NEPCO2EF/NEPCH4EF/NEPN2OEF (tonnes/e3m3) = Emission factor for natural gas extraction and
processing of CO2, CH4, and N2O;
BTotal-Fuel (e3m3) = Total fuel gas volumes consumed in the baseline
= NGRH1 + Plant_EFlaring + Plant_DFlaring
Plant_DFlaring (e3m3) = Fuel gas volumes to incinerate acid gas from Plant D
= (AGTotal) x Plant_DFG:AG x [AGPlant_D
AGPlant_D+ AGPlant_E]
Plant_EFlaring (e3m3) = Fuel gas volumes to incinerate tail gas from Plant E following SuperClaus unit
= (AGTotal) x Plant_EFG:AG x [AGPlant_E
AGPlant_D+ AGPlant_E]x n2:n1
AGTotal (e3m3) = Total acid gas volumes produced by the Project
= AGPlant_D + AGPlant_E
AGPlant_D (e3m3) = Acid gas volumes from Plant D (as-metered);
AGPlant_E (e3m3) = Acid gas volumes from Plant E (as-metered);
Plant_EFG:AG = Ratio of fuel gas to acid gas for flaring acid gas originating from Plant E
=LHVCombined – LHVTail_Gas
LHVFuel−Kaybob – LHVCombined
Plant_DFG:AG = Ratio of fuel gas to acid gas for flaring acid gas originating from Plant D;
=LHVCombined − LHVPlant_D
LHVFuel−Kaybob − LHVCombined
LHVCombined = Combined lower heating value of acid gas and make-up fuel gas directed to flare as per
ERCB Directive 060 (ERCB, 2011);
LHVTail_Gas = Lower heating value of tail gas based on acid gas composition simulated by Sulphur
Experts;
LHVPlant_D = Lower heating value of acid gas from Plant D;
Page 22
Prepared by: Blue Source Canada Suite 700, 717 7th Ave. SW, Calgary, AB, T2P 0Z3 Tel: (403) 262-3026 Fax: (403) 269-3024
LHVFuel-Kaybob = Lower heating value of fuel gas from the Kaybob Gas Plant;
n2:n1 = Multi-Stage Claus unit molar volume adjustment;
NGRH1, is a component of the SRU and is a direct-fired natural gas heater as defined under SS B5b
(Multi-Stage Claus Unit), below. The other SRU components are not included under SS B9 for
conservativeness as they are considered as energy imports that operate on indirect steam energy or
grid electricity. The waste heat exchanger and condensers of the SRU produce waste heat energy to
produce low-pressure and high-pressure steam; therefore, it was assumed under SS B9 that
components operating on indirect steam do not require an additional volume of fuel gas for steam
generation via a steam boiler.
SS B6 (Incineration)
Emissions of CO2 (SS B6a)
= (AGTotal x n2: n1x AGPlant_E
AGPlant_E + AGPlant_D x Plant_EFG:AG
+ AGTotal x AGPlant_D
AGPlant_E + AGPlant_D x Plant_DFG:AG ) x EFCO2−Kaybob
Emissions of CH4 (SS B6a)
= (AGTotal x n2: n1x AGPlant_E
AGPlant_E + AGPlant_D x Plant_EFG:AG
+ AGTotal x AGPlant_D
AGPlant_E + AGPlant_D x Plant_DFG:AG ) x EFCH4
Emissions of N2O (SS B6a)
= (AGTotal x n2: n1 x AGPlant_E
AGPlant_E + AGPlant_D x Plant_EFG:AG
+ AGTotal x AGPlant_D
AGPlant_E + AGPlant_D x Plant_DFG:AG ) x EFN2O
Where,
EFCO2-Kaybob (tonnes/e3m3) = Kaybob site-specific CO2 emission factor for natural gas combustion;
EFCH4/EFN2O (tonnes/e3m3) = Emission factor for natural gas combustion;
n2:n1 = Multi-Stage Claus unit molar volume adjustment;
The acid gas from Plant D contains CO2 and residual hydrocarbons including CH4, C2H6, C3H8, iC4H10,
C4H10, iC5H12, C5H12, C6H14 and C7H16. Tail gas composition, following sulphur recovery via the Multi-
Page 23
Prepared by: Blue Source Canada Suite 700, 717 7th Ave. SW, Calgary, AB, T2P 0Z3 Tel: (403) 262-3026 Fax: (403) 269-3024
Stage Claus unit, was simulated by Sulphur Experts using SULSIM. Below are the equations used to
determine the t CO2e of each hydrocarbon species due to flaring of acid gas in the baseline condition.
Emissions of CO2 (SS B6b)
= (AGTotal) x ( %CO2,Plant_D x [AGPlant_D
AGPlant_D + AGPlant_E]
+ %CO2(TG)x n2: n1 x [AGPlant_E
AGPlant_D + AGPlant_E]) x ρCO2
Emissions of CH4 (SS B6b)
= (AGTotal) x ( %CH4,Plant_D x [AGPlant_D
AGPlant_D + AGPlant_E]
+ %CH4(TG)x n2: n1 x [AGPlant_E
AGPlant_D + AGPlant_E]) x ρCH4 x
44 (g
moleCO2)
16(g
moleCH4)
Emissions of C2H6 (SS B6b)
= (AGTotal) x ( %C2H6,Plant_D x [AGPlant_D
AGPlant_D + AGPlant_E]
+ %C2H6(TG) x n2: n1 x [AGPlant_E
AGPlant_D + AGPlant_E]) x ρC2H6 x (2 x
44 (g
moleCO2)
30(g
moleC2H6)
)
Emissions of C3H8 (SS B6b)
= (AGTotal) x ( %C3H8,Plant_D x [AGPlant_D
AGPlant_D + AGPlant_E]
+ %C3H8(TG) x n2: n1 x [AGPlant_E
AGPlant_D + AGPlant_E]) x ρC3H8 x (3 x
44 (g
moleCO2)
44(g
moleC3H8)
)
Emissions of iC4H10 (SS B6b)
= (AGTotal) x ( %iC4H10,Plant_D x [AGPlant_D
AGPlant_D + AGPlant_E]
+ %iC4H10(TG) x n2: n1 x [AGPlant_E
AGPlant_D + AGPlant_E]) x ρiC4H10 x (4 x
44 (g
moleCO2)
58(g
moleiC4H10)
)
Page 24
Prepared by: Blue Source Canada Suite 700, 717 7th Ave. SW, Calgary, AB, T2P 0Z3 Tel: (403) 262-3026 Fax: (403) 269-3024
Emissions of nC4H10 (SS B6b)
= (AGTotal) x ( %nC4H10,Plant_D x [AGPlant_D
AGPlant_D + AGPlant_E]
+ %nC4H10(TG) x n2: n1 x [AGPlant_E
AGPlant_D + AGPlant_E]) x ρnC4H10 x (4 x
44 (g
moleCO2)
58(g
molenC4H10)
)
Emissions of iC5H12 (SS B6b)
= (AGTotal) x ( %iC5H12,Plant_D x [AGPlant_D
AGPlant_D + AGPlant_E]
+ %iC5H12(TG) x n2: n1 x [AGPlant_E
AGPlant_D + AGPlant_E]) x ρiC5H12 x (4 x
44 (g
moleCO2)
72(g
moleiC5H12)
)
Emissions of nC5H12 (SS B6b)
= (AGTotal) x ( %nC5H12,Plant_D x [AGPlant_D
AGPlant_D + AGPlant_E]
+ %nC5H12(TG) x n2: n1 x [AGPlant_E
AGPlant_D + AGPlant_E]) x ρnC5H12 x (4 x
44 (g
moleCO2)
72(g
molenC5H12)
)
Emissions of C6H14 (SS B6b)
= (AGTotal) x ( %C6H14,Plant_D x [AGPlant_D
AGPlant_D + AGPlant_E]
+ %C6H14,(TG) x n2: n1 x [AGPlant_E
AGPlant_D + AGPlant_E]) x ρC6H14 x (7 x
44 (g
moleCO2)
86(g
moleC6H14)
)
Emissions of C7H16 (SS B6b)
= (AGTotal) x ( %C7H16,Plant_D x [AGPlant_D
AGPlant_D + AGPlant_E]
+ %C7H16(TG) x n2: n1 x [AGPlant_E
AGPlant_D + AGPlant_E]) x ρC7H16 x (7 x
44 (g
moleCO2)
100(g
moleC7H16)
)
Emissions of N2O (SS B6b)
= (AGTotal) x ( [AGPlant_D
AGPlant_D + AGPlant_E] + [
AGPlant_E
AGPlant_D + AGPlant_E]) x TGN2OEF
Page 25
Prepared by: Blue Source Canada Suite 700, 717 7th Ave. SW, Calgary, AB, T2P 0Z3 Tel: (403) 262-3026 Fax: (403) 269-3024
Where, the densities used above are based on assuming ideal gas behavior of each hydrocarbon
species.
And:
n2:n1 = Multi-Stage Claus unit molar volume adjustment;
TGN2OEF (tonnes/e3m3) = Emission factor for tail gas combustion.
SS B5b (Multi-Stage Claus Unit)
Emissions of CO2
= (FGMulti−Claus − [ηHeat x EClaus
ηEnergy x LHVFuel−Kaybob]) x EFCO2−Kaybob
+ [(AIR + SP) x (RA−1 + RA−2) ÷ 1000 kWhMWh⁄ x ECCO2eEF]
Emissions of CH4 = [FGMulti−Claus −ηHeat x EClaus
ηEnergy x LHVFuel−Kaybob] x EFCH4
Emissions of N2O = [FGMulti−Claus − ηHeat x EClaus
ηEnergy x LHVFuel−Kaybob] x EFN2O
Where,
ECCO2eEF (t CO2e/MWh) = Emission factor for grid electricity consumption
FGMulti-Claus (e3m3) = Fuel gas volumes to operate the Multi-Stage Claus unit
= NGRH1
NGRH1 (e3m3) = Fuel gas volume equivalence to operate reheater #1;
AIR (kW) = kW rating of the furnace air blower;
SP (kW) = kW rating of the sulphur pump;
RH1 is a direct-fired natural gas heater and, as a result, the SULSIM simulation provided the fuel gas
consumption for the unit. AIR and SP operate on grid electricity directly.
NGAGPH, NGAPH, NGRH2, and NGRH3 are heated by indirect steam. The general equation used to calculate
the fuel gas volume-equivalence for their operation is outlined below:
Fuel Usage =
Output Rating (kW) x Utilization (hours)Thermal Efficiency (%) x LHVFuel Gas(MJ/m3)
Steam Boiler Efficiency (%)
Page 26
Prepared by: Blue Source Canada Suite 700, 717 7th Ave. SW, Calgary, AB, T2P 0Z3 Tel: (403) 262-3026 Fax: (403) 269-3024
The thermal efficiency was determined on the assumption that the saturated steam temperature is
30°C higher than the outlet temperature of the respective stream. Given that the temperature of the
reaction furnace and the waste heat exchanger is relatively high (i.e. 1052°C and 300°C, respectively)
as seen in the simulation report (refer to Appendix A: List of Supporting Documentation), it is not
implausible to create steam at the required pressures to operate at the desired temperatures
described here.
EClaus*ηHeat (MJ) = Process energy recovered, as follows:
= Energy Exports x 3.6MJ
kWhx (RA−1 + RA−2)
Energy produced by the Multi-Stage Claus unit, with the exception of the energy produced by the
fourth and final condenser, provides beneficial use elsewhere in the plant. The energy exporters
include the waste heat exchanger, and condensers 1, 2, and 3.
ηEnergy (%) = Fuel energy efficiency of a small gas utility boiler
RA-1 and RA-2 is defined in SS (P6) Acid Gas Dehydration and Compression, below.
SS P12 (Fuel Extraction & Processing)
Emissions of CO2 = FGFlare x NEPCO2EF
Emissions of CH4 = FGFlare x NEPCH4EF
Emissions of N2O = FGFlare x NEPN2OEF
FGFlare is defined in SS (P8) Upset Flaring, below.
SS P6 (Acid Gas Dehydration and Compression)
Emissions from the operations of the compressor fans are calculated as follows:
Emissions of CO2e from Fans = [𝐴𝐶𝑖 x 𝑅𝑖 x (𝑇𝑜𝑡𝑎𝑙𝑣𝑜𝑙
𝐹𝐶𝑜𝑚𝑝−𝑖)
3
] ÷ 1000kWh
MWh x ECCO2eEF
Where,
ACi = kW rating of acid gas compressor A-1 or A-2, dependant on which was running;
Ri = Run time hours of unit A-1 or A-2, dependant on which was running;
Page 27
Prepared by: Blue Source Canada Suite 700, 717 7th Ave. SW, Calgary, AB, T2P 0Z3 Tel: (403) 262-3026 Fax: (403) 269-3024
FComp-i = Max flow rate of acid gas compressor A-1 or A-2, dependant on which was running;
Totalvol = Total acid gas volume to compressor.
Emissions from compressors are as calculated as follows:
Emissions of CO2e from Compressors = ([∑ 𝑚 𝑥 𝑇𝑜𝑡𝑎𝑙𝑣𝑜𝑙61 + 𝑏] 𝑥 𝑅𝑖) x ECCO2eEF
Where,
The summation is performed for each of the six compressor stages for both compressors A-1 and A-
2 and,
m = slope of compressor curve for the stage;
Totalvol = Total acid gas volume to compressor;
b = intercept of compressor curve for the stage;
Ri = Run time hours of unit A-1 or A-2, dependant on which was running.
SS P8 (Upset Flaring)
Emissions of CO2 (SS P8a) = FGFlare x EFCO2−Kaybob
Emissions of CH4 (SS P8a) = FGFlare x EFCH4
Emissions of N2O (SS P8a) = FGFlare x EFN2O
Where,
FGFlare (e3m3) = Fuel gas volumes to supplement acid gas flaring during upset conditions;
The combined acid gas (i.e. Plant D and Plant E) contains CO2 and residual hydrocarbons including
CH4, C2H6, C3H8, iC4H10, C4H10, iC5H12, C5H12, C6H14 and C7H16. Below are the equations used to
determine the t CO2e of each hydrocarbon species due to flaring of acid gas during upset conditions.
Emissions of CO2 (SS P8b) = AGFlare x %CO2,Combined x ρCO2
Emissions of CH4 (SS P8b) = AGFlare x %CH4,Combined x ρCH4 x 44 (
gmole
CO2)
16(g
moleCH4)
Page 28
Prepared by: Blue Source Canada Suite 700, 717 7th Ave. SW, Calgary, AB, T2P 0Z3 Tel: (403) 262-3026 Fax: (403) 269-3024
Emissions of C2H6 (SS P8b) = AGFlare x %C2H6,Combined x ρC2H6 x (2 x 44 (
gmole
CO2)
30(g
moleC2H6)
)
Emissions of C3H8 (SS P8b) = AGFlare x %C3H8,Combined x ρC3H8 x (3 x 44 (
gmole
CO2)
44(g
moleC3H8)
)
Emissions of iC4H10 (SS P8b) = AGFlare x %iC4H10,Combined x ρiC4H10 x (4 x 44 (
gmole
CO2)
58(g
moleiC4H10)
)
Emissions of nC4H10 (SS P8b) = AGFlare x %nC4H10,COmbined x ρnC4H10 x (4 x 44 (
gmole
CO2)
58(g
molenC4H10)
)
Emissions of iC5H12 (SS P8b) = AGFlare x %iC5H12,Combined x ρiC5H12 x (4 x 44 (
gmole
CO2)
72(g
moleiC5H12)
)
Emissions of nC5H12 (SS P8b) = AGFlare x %nC5H12,Combined x ρnC5H12 x (4 x 44 (
gmole
CO2)
72(g
molenC5H12)
)
Emissions of C6H14 (SS P8b) = AGFlare x %C6H14,Combined x ρC6H14 x (7 x 44 (
gmole
CO2)
86(g
moleC6H14)
)
Emissions of C7H16 (SS P8b) = AGFlare x %C7H16,Combined x ρC7H16 x (7 x 44 (
gmole
CO2)
100(g
moleC7H16)
)
Emissions of N2O (SS P8b) = AGFlare x TGN2OEF
Where, the densities used above are based on assuming ideal gas behavior for each hydrocarbon
species.
And:
TGN2OEF (tonnes/e3m3) = Emission factor for tail gas combustion.
Table 5 provides the emissions factors used in the quantification of emissions for this project.
Page 29
Prepared by: Blue Source Canada Suite 700, 717 7th Ave. SW, Calgary, AB, T2P 0Z3 Tel: (403) 262-3026 Fax: (403) 269-3024
Table 5: Emission factors used for Trilogy Kaybob Acid Gas Injection Offset Project.
Parameter Relevant
SS
CO2
Emission
Factor
CO2
Emission
Factor
Source
CH4
Emission
Factor
CH4
Emission
Factor
Source
N2O
Emission
Factor
N2O
Emission
Factor
Source
CO2e
Emission
Factor
Natural gas
combustion
B5b, B6, P6,
P8
2.1510
tonnes/e3m3 Site-specific
0.0064
tonnes/e3m3
Handbook of
Emission
Factors
(2015)
0.00006
tonnes/e3m3
Handbook of
Emission
Factors
(2015)
-
Natural gas
extraction B9, P12
0.043
tonnes/e3m3
Handbook of
Emission
Factors
(2015)
0.0023
tonnes/e3m3
Handbook of
Emission
Factors
(2015)
0.000004
tonnes/e3m3
Handbook of
Emission
Factors
(2015)
-
Natural gas
processing B9, P12
0.090
tonnes/e3m3
Handbook of
Emission
Factors
(2015)
0.0003
tonnes/e3m3
Handbook of
Emission
Factors
(2015)
0.000003
tonnes/e3m3
Handbook of
Emission
Factors
(2015)
-
Tail Gas
Combustion B6b, P8b - - - -
0.000033
tonnes/e3m3
Handbook of
Emission
Factors
(2015)
-
Electricity
Consumption - -
AENV Memo,
Dec 20, 2011 - - - -
0.88
tonnes/MWh
Page 30
Prepared by: Blue Source Canada Suite 700, 717 7th Ave. SW, Calgary, AB, T2P 0Z3 Tel: (403) 262-3026 Fax: (403) 269-3024
7.0 Greenhouse Gas Assertion
The GHG assertion is a statement of the number of offset tonnes achieved during the reporting period.
The assertion identifies emissions reductions per vintage year and includes a breakout of individual
greenhouse gas types (CO2, CH4, N2O, SF6, HFCs, and PFCs) applicable to the Project and total
emissions reported as CO2e. The total in units of t CO2e is calculated using the global warming
potentials (GWPs) referenced in the SGER.
Table 6 identifies the GHG assertion, containing the calculated number of offset tonnes achieved in
2016.
Table 6: Offset tonnes created by the Trilogy Kaybob Acid Gas Injection Offset Project between January
1, 2016 to December 31, 20164.
2016
Greenhouse Gas (GHG) in tonnes CO2e
CO2 CH4 N2O PFCs HFCs SF6 CO2e
Total
(in
CO2e)
Baseline 36,199 2,712 358 0 0 0 0 39,270
Project 238.5 23.5 3.6 0 0 0 1,662 1,927
Reductions 35,960.8 2,689.2 354.5 0 0 0 -1,662 37,342
4 Emission reductions per GHG species, as shown in table, are subject to rounding errors and may not work
out to total tonnages displayed; however, the GHG assertion is correct.
Page 31
Prepared by: Blue Source Canada Suite 700, 717 7th Ave. SW, Calgary, AB, T2P 0Z3 Tel: (403) 262-3026 Fax: (403) 269-3024
8.0 Offset Project Performance
The Project has created credits in six previous vintage years. Figure 1 below shows the credits
created by the Project between 2010 and 2016. Credits that were created in 2010 were lower than
other years, as this was a partial reporting year. Credits between 2013 to 2016 have increased in
comparison to 2011 and 2012 due to a methodological revision to the calculation of baseline Tail Gas
Volume leaving the SRU, as described in Section 4.0, page 10. This revision has been made to increase
the accuracy of the calculation, in line with the principles of ISO 14064-2. Furthermore, Figure 1
illustrates the impact of methodological changes from previous years to 2013 - 2016. This is shown
by the number of credits generated per 1000 cubic meters of acid gas injected and has been fairly
consistent from 2010-2012 and from 2013-2016. In 2013, the Project generated an additional 3
tonnes CO2e/e3m3 of acid gas injected in comparison to 2012. Total credits in 2016 have decreased
by 13.0% as compared to 2015 due to lower acid gas injection volumes.
Figure 1. Credits created by the Trilogy Kaybob Acid Gas Injection Offset Project.
0
1
2
3
4
5
6
7
0
10,000
20,000
30,000
40,000
50,000
60,000
2010 2011 2012 2013 2014 2015 2016
Ton
ne
s C
O2e
/ e
3m
3
Cre
dit
s C
reat
ed
(t
CO
2e)
Vintage Year
Number of Credits Credits perAG Injected
Page 33
Prepared by: Blue Source Canada Suite 700, 717 7th Ave. SW, Calgary, AB, T2P 0Z3 Tel: (403) 262-3026 Fax: (403) 269-3024
10.0 Statement of Senior Review
This offset project report was prepared by Aleena Dewji, Senior Carbon Analyst, Blue
Source Canada and Tooraj Moulai, Senior Engineer, Carbon Services. It was senior
reviewed by Kelly Parker, Engineer Carbon Solutions, Blue Source Canada. Although
care has been taken in preparing this document, it cannot be guaranteed to be free of
errors or omissions.
Prepared by:
Senior reviewed by:
Aleena Dewji, E.I.T
Senior Carbon Analyst
Tooraj Moulai, P.Eng
Senior Engineer, Carbon Services
Kelly Parker, P.Eng
Engineer, Carbon Solutions
Page 34
Prepared by: Blue Source Canada Suite 700, 717 7th Ave. SW, Calgary, AB, T2P 0Z3 Tel: (403) 262-3026 Fax: (403) 269-3024
11.0 References
AENV, 2008. Specified Gas Emitters Regulation: Quantification Protocol for Acid Gas Injection
(Version 1). [pdf] Edmonton, Alberta: Alberta Environment.
AESRD, 2013. Specified Gas Emitters Regulation: Technical Guidance for Offset Project Developers
(Version 4). [pdf] Edmonton, Alberta: Alberta Environment.
AESRD, 2014. Memorandum: Notice of Change for Global Warming Potentials. [pdf] Edmonton,
Alberta: Alberta Environment.
CIBO, 2003, Energy Efficiency & Industrial Boiler Efficiency: An Industry Perspective. [pdf] Council
of Industrial Boiler Owners. Available at: <http://cibo.org/pubs/whitepaper1.pdf>
Environment Canada, 2016. National Inventory Report 1990-2014: Greenhouse Gas Sources and
Sinks in Canada: Part 2. Pollutant Inventories and Reporting Division.
AER. 2011, Directive 060: Upstream Petroleum Industry Flaring, Incineration, and Venting. [pdf]
Calgary, Alberta: Alberta Energy Regulator.
Gas Processors Association, 2008. GPA Standard 2145-09: Table of Physical Properties for
Hydrocarbons and Other Compounds of Interest to the Natural Gas Industry. Tulsa, Oklahoma.
Page 35
Prepared by: Blue Source Canada Suite 700, 717 7th Ave. SW, Calgary, AB, T2P 0Z3 Tel: (403) 262-3026 Fax: (403) 269-3024
Appendix A
LIST OF SUPPORTING DOCUMENTATION
Page 36
Prepared by: Blue Source Canada Suite 700, 717 7th Ave. SW, Calgary, AB, T2P 0Z3 Tel: (403) 262-3026 Fax: (403) 269-3024
Parameter Supporting Documents Provided
to 3rd Party Verifier File Name
Offset Credits Created Blue Source Offset Calculator Trilogy_AGI_Offset_Calculator_v1.0_2017-02-
08.xlsx
Kaybob Fuel Gas
Analysis
Fuel gas analysis by AGAT
Laboratories (January –
December 2016)
Jan – Dec Gas Analysis – FR1A Gas Analyses Jan-
Sep.pdf;
Oct Gas Analysis – FR1A Gas Analyses Oct.pdf;
Nov Gas Analysis - Gas Analyses Nov.pdf;
Dec Gas Analysis – Gas Analyses Dec.pdf.
Acid Gas Composition
Acid gas analysis by AGAT
Laboratories (January –
December 2016)
Jan – Sep Gas Analysis –Acid Gas Injection Gas
Analyses Jan-Sep.pdf;
Oct Gas Analysis – Acid Gas Injection Gas
Analyses Oct.pdf;
Nov Gas Analysis - Gas Analyses Nov.pdf;
Dec Gas Analysis – Gas Analyses Dec.pdf.
Acid Gas Composition
(Plant D Acid Gas to
Compression)
Acid gas analysis for Plant D by
AGAT Laboratories (January –
December 2016)
Jan – Sep Gas Analysis –MVS E-500-04 Gas
Analysis Jan-Sep.pdf;
Oct Gas Analysis – Acid Gas Injection Gas
Analyses Oct.pdf;
Nov Gas Analysis - Gas Analyses Nov.pdf;
Dec Gas Analysis – Gas Analyses Dec.pdf.
Multi-Stage Claus Unit
Simulation
Sulphur Experts, January 2013,
“Trilogy Energy Corp. SRU
Simulation Report”, Project No.
SC1438
Sulphur Experts, February
2017, “Trilogy Energy Kaybob
South SRU Simulation Report”,
Project No. ESC2473
Trilogy_SULSIM_2012.pdf
Trilogy_SULSIM_2016.pdf
TSAT Selection (via
Sulphur Experts)
Email: RE Trilogy SULSIM Inlet
steam temperature and heat
capacity of acid gas
RE Trilogy SULSIM Inlet steam temperature and
heat capacity of acid gas.pdf
Facility Licence
Amendment 2012 ERCB Licence No. F14191 AER License Approval F14191
Acid Gas Compressor
Run Hours
Excel: E Plant Daily Report
(January – December 2016) A1 and A2 Hours.xlsx
Acid Gas and Fuel Gas
Volumes
Excel: MVS E-330-02;
FIT E-330-01;
MVS E-500-04;
Metering reports.xlsx
Page 37
Prepared by: Blue Source Canada Suite 700, 717 7th Ave. SW, Calgary, AB, T2P 0Z3 Tel: (403) 262-3026 Fax: (403) 269-3024
Parameter Supporting Documents Provided
to 3rd Party Verifier File Name
MVS E-200-28
Shutdowns Emails from Trilogy Email – Carrie Muskett re Plant Shutin.pdf.
Gas Analysis Issue Email from Trilogy Email – Carrie Muskett re October Plant D
Analysis.pdf.
Page 38
Prepared by: Blue Source Canada Suite 700, 717 7th Ave. SW, Calgary, AB, T2P 0Z3 Tel: (403) 262-3026 Fax: (403) 269-3024
Appendix B DATA INFORMATION MANAGEMENT SYSTEM AND METERING
Page 39
Prepared by: Blue Source Canada Suite 700, 717 7th Ave. SW, Calgary, AB, T2P 0Z3 Tel: (403) 262-3026 Fax: (403) 269-3024
Data Management and QA/QC at Trilogy Energy Corp.
In general, the data control processes employed for this Project consist of manual or electronic data
capture and reporting, and manual entry of monthly totals or average values into a Quantification
Calculator developed by Blue Source Canada ULC.
During the turnaround period in September 2013, the Proponent updated their data management
system from a Moore system to an Allen Bradley system. Essentially, the Allen Bradley system
functions the same as the Moore system except with new modern parts and support. For monitoring
and quality assurance purposes, the quantification methods and formulas used in the Quantification
Calculator have been reviewed on behalf of the Project Proponent.
There are two data streams involved in this project:
Electronic data captured at flow meters (e.g. fuel gas and acid gas volumes)
Manual data collection reported in third party laboratory analysis reports
The specifics of the Monitoring and QA/QC plan are discussed in the following sections and outlined
in Table 5. A simplified data flow chart has been included as Figure 2 below.
Figure 2 Simplified Data Flow Chart
Page 40
Prepared by: Blue Source Canada Suite 700, 717 7th Ave. SW, Calgary, AB, T2P 0Z3 Tel: (403) 262-3026 Fax: (403) 269-3024
Table B-1. Metering Maintenance and Calibration details.
Project Specific
Data Meter ID Meter Model Maintenance Schedule
Calibration
Schedule Accuracy Rating
Volume of
Dilution Gas
(B9, B6, P12,
P8)
MVS E-330-02 Bristol 3808
Every 6 months a volume
performance verification is
performed using Flowcheck
on the Controlwave Micro
for each run.
Every 6
months
DP and SP linear mode:
±0.075% of Calibrated
Span
Volume of Acid
Gas Flared (B6,
P8)
FIT-E-330-01A
Sage Thermo
Mass Flow
Meter
Every 6 months
Meter is
zeroed
every 6
months
+/-1% of Reading
Volume of Acid
Gas Injected
(B6)
MVS-E-500-04
(Plant “D”)
MVS-E-200-28
(Plant “E”)
Bristol 3808
Every 6 months a volume
performance verification is
performed using Flowcheck
on the Controlwave Micro
for each run.
Every 6
months
DP and SP linear mode:
±0.075% of Calibrated
Span