trilogy kaybob acid gas injection offset project · ownership: trilogy energy by its managing...

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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

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


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


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


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







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


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.


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.


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

http://www.trilogyenergy.com/

http://www.bluesourcecan.com/

http://www.rwdi.com/


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.


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



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.


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


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>


(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.


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



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


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


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



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


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)


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;


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_DFG:AG ) x EFCH4

Emissions of N2O (SS B6a)

= (AGTotal x n2: n1 x AGPlant_E



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;


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-


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


+ %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


+ %C2H6(TG) x n2: n1 x [AGPlant_E

AGPlant_D + AGPlant_E]) x ρC2H6 x (2 x

44 (g

moleCO2)

30(g

moleC2H6)

)






44 (g

moleCO2)

44(g

moleC3H8)

)

Emissions of iC4H10 (SS B6b)

= (AGTotal) x ( %iC4H10,Plant_D x [AGPlant_D


+ %iC4H10(TG) x n2: n1 x [AGPlant_E

AGPlant_D + AGPlant_E]) x ρiC4H10 x (4 x

44 (g

moleCO2)

58(g

moleiC4H10)

)


Emissions of nC4H10 (SS B6b)

= (AGTotal) x ( %nC4H10,Plant_D x [AGPlant_D


+ %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


+ %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


+ %nC5H12(TG) x n2: n1 x [AGPlant_E

AGPlant_D + AGPlant_E]) x ρnC5H12 x (4 x

44 (g

moleCO2)

72(g

molenC5H12)

)




+ %C6H14,(TG) x n2: n1 x [AGPlant_E


44 (g

moleCO2)

86(g

moleC6H14)

)






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


Where, the densities used above are based on assuming ideal gas behavior of each hydrocarbon

species.

And:


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 (%)


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;


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)


Emissions of C2H6 (SS P8b) = AGFlare x %C2H6,Combined x ρC2H6 x (2 x 44 (

gmole

CO2)

30(g

moleC2H6)

)


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)

)


gmole

CO2)

86(g

moleC6H14)

)


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.


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


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.


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


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


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.


Appendix A

LIST OF SUPPORTING DOCUMENTATION


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;



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;



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


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.


Appendix B DATA INFORMATION MANAGEMENT SYSTEM AND METERING


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


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