altagas bantry acid gas injection project...sulsim sulphur recovery unit simulation page 5 prepared...

ALTAGAS BANTRY ACID GAS INJECTION PROJECT

Greenhouse Gas Emissions Reduction

Offset Project Report

For the Period January 1, 2016 – December 31, 2016

FINAL REPORT, version 1

8 March 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.bluesourceCAN.com

Prepared for: AltaGas Processing Partnership (Project Proponent) 1700, 355 – 4th Avenue SW Calgary, Alberta T2P 0J1 T: (403) 691-7575 F: (403) 691-7576

www.altagas.ca

http://www.bluesourcecan.com/

http://www.altagas.ca/

Prepared by: Blue Source Canada ULC 700, 717 7th Ave. SW, Calgary, AB, T2P 0Z3 Tel: (403) 262-3026 Fax: (403) 269-3024

Contents Contents ........................................................................................................................................................ 2

List of Tables ................................................................................................................................................. 3

List of Figures ................................................................................................................................................ 3

List of Abbreviations ..................................................................................................................................... 3

1 PROJECT SCOPE AND PROJECT DESCRIPTION ....................................................................................... 5

2 PROJECT CONTACT INFORMATION ....................................................................................................... 8

3 PROJECT DESCRIPTION AND LOCATION ................................................................................................ 9

4 PROJECT IMPLEMENTATION AND VARIANCES ................................................................................... 10

5 REPORTING PERIOD ............................................................................................................................ 14

6 GREENHOUSE GAS CALCULATIONS ..................................................................................................... 14

SS B9 (Fuel Extraction and Processing) ............................................................................................... 15

SS B6 (Incineration) ............................................................................................................................. 16

SS B5 (Sulphur Recovery Unit Operation) ........................................................................................... 18

SS P12 (Fuel Extraction and Processing) ............................................................................................. 18

SS P6 (Acid Gas Dehydration and Compression) ................................................................................. 18

SS P8 (Upset Flaring) ........................................................................................................................... 19

SS P9 (Injection Unit Operation) ......................................................................................................... 20

7 GREENHOUSE GAS ASSERTION ........................................................................................................... 23

8 OFFSET PROJECT PERFORMANCE ....................................................................................................... 24

9 PROJECT DEVELOPER SIGNATURES ..................................................................................................... 25

10 STATEMENT OF SENIOR REVIEW .................................................................................................... 26

11 REFERENCES .................................................................................................................................... 27


List of Tables TABLE 1 - EMISSION FACTORS USED FOR THE ALTAGAS BANTRY AGI PROJECT ......................................................... 22

TABLE 2 - OFFSET TONNES CREATED FOR 2015 BY THE PROJECT. .............................................................................. 23

List of Figures FIGURE 1 - CREDITS CREATED BY THE PROJECT, BY VINTAGE YEAR ............................................................................ 24

List of Abbreviations ACCO Alberta Climate Change Office

AEOR Alberta Emissions Offset Registry

AER Alberta Energy Regulator

AENV Alberta Environment (now Alberta Climate Change Office)

AESRD Alberta Environment & Sustainable Resource Development (now Alberta Climate

Change Office)

AEUB Alberta Energy and Utilities Board

AEP Alberta Environment and Parks (previously Alberta Environment & Sustainable Resource

Development)

AGI Acid Gas Injection

Blue Source Blue Source Canada ULC

CH4 Methane

CO2 Carbon Dioxide

CO2e Carbon Dioxide-equivalent

ERCB Energy Resources Conservation Board

GHG Greenhouse gas

GWP Global Warming Potential

H2S Hydrogen Sulphide

HFC Hydrofluorocarbon(s)

N2O Nitrous Oxide

PFC Perfluorocarbon(s)

S2(s) Elemental Sulphur

SF6 Sulphur Hexafluoride

SGER Specified Gas Emitters Regulation

SO2 Sulphur Dioxide

SRU Sulphur Recovery Unit

SS Sources and Sinks

STP Standard Temperature and Pressure


SULSIM Sulphur Recovery Unit Simulation


1 PROJECT SCOPE AND PROJECT DESCRIPTION The project title is: AltaGas Bantry Acid Gas Injection 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 carbon dioxide (CO2), as a

part of raw natural gas processing. Previously, GHGs were produced as a

result of operating the Xergy sulphur recovery unit (SRU) and through the

incineration of tail gas.

Date when the project began:

The Project began on January 12, 2009, 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 the

Xergy SRU and tail gas incinerator and is expected to be well in excess of the

credit duration period.

Credit start date: The credit start date for this project is January 12, 2009.

Credit duration period: Proponents for the Project intend to claim offsets for a period of 8 years,

between January 12, 2009 and December 31, 2016. This is the final crediting

year for the Project.

Reporting period: January 1st, 2016 to December 31st, 2016.

Actual emissions reductions:

The total project emission reductions as a result of this project since January

12, 2009 (the Project credit start date) are listed here:

2009: 15,549 tonnes of CO2e/year





2014: 36,029 tonnes CO2e/year


Emissions reductions from this final reporting period which covers January 1, 2016 to December 31, 2016 are:



Total: 230,375 tonnes CO2e

Applicable Quantification Protocol(s):

The quantification protocol used is the Quantification Protocol for Acid Gas

Injection, May 2008, Version 1 (AENV, 2008) published by Alberta

Environment (AENV). This protocol 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.

Protocol(s) Justification: 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 carbon dioxide (CO2), as a

part of raw natural gas processing. Previously, GHGs were produced as a

result of operating the Xergy sulphur recovery unit (SRU) and through the

incineration of tail gas.

Other Environmental Attributes:

No other environmental attributes, credits, or benefits are being sought or

created by this Project.

Legal land description of the project or the unique latitude and longitude:

The Project is located in Alberta. The injection well is located near Tilley,

Alberta.

LSD: 1/4-33-17-12W4M (Bantry Gas Plant); 02/13-33-017-12W4/0 (Injection

Well);

Latitude: 50.471873° (Bantry Gas Plant); 50.4828° (Injection Well)

Longitude: -111.605562° (Bantry Gas Plant); -111.605567° (Injection Well)

Ownership: AltaGas Processing Partnership (herein referred to as ‘the Proponent’) is the

sole owner of the Bantry Sour Gas Processing Plant (herein referred to as ‘the

Plant’) and maintains 100% ownership of the environmental attributes

created by the Project. This is the final crediting year for the Project to

complete the 8-year crediting duration.

Reporting details: The verifier, Brightspot Climate, 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 the

verifier has been vetted to ensure technical competence with this project

type.

This is the 1st verification carried out by the verifier for this project.

Verification details: 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 Alberta: 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 protocol uses a government approved

quantification protocol, which before its termination indicated the

activity was undertaken by less than 40% of the industry and was

therefore not considered to be sector common practice; the protocol

was terminated in 2013 as the activity was no longer considered

“additional.” 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.

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 activities at the Plant. Credits created from the

specified reduction activity have not been created, recorded or

registered in more than one trading registry for the same time period.

The project will be counted once for compliance purposes: The Project credits


will be registered with the Alberta Emissions Offset Registry (AEOR) 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 time period.

Project activity: 6.

2 PROJECT CONTACT INFORMATION Project Developer Contact Information

AltaGas Processing Partnership

Stefan Dimic,

Commercial Representative

1700, 355 4th Avenue SW

Calgary, AB T2P 0J1

Direct: 403-691-7031

Main: 403-691-7575

Fax: (403) 691-7000

Email: [email protected]

Web: www.altagas.ca

Alternate:

Jason Fleck,

Operations Engineer

1700, 355 4th Avenue SW

Calgary, AB T2P 0J1

Office: (403) 691-9894

Mobile: (403) 771-6901

[email protected]

Web: www.altagas.ca

Authorized Project Contact

Blue Source Canada ULC

Kelsey Lank

Carbon Solutions Analyst

Phone: 403-262-3026 x228

Fax: 403-269-3024

Email: [email protected]

Suite 700

717 - 7th Avenue SW

Calgary, AB

T2P 0Z3

Canada

Web: www.bluesourcecan.com

Verifier

Brightspot Climate Aaron Schroeder Principal Phone: 604-353-0264 Email: [email protected]

225 West 8th Avenue, Vancouver BC V5Y 1N3 Web: www.brightspot.co

This is the 1st verification carried out by the verifier for this project.

mailto:[email protected]





http://www.bluesourcecan.com/


http://www.brightspot.co/


3 PROJECT DESCRIPTION AND LOCATION The AltaGas Bantry Acid Gas Injection Project (‘the Project’) is an AGI project located at the Bantry Sour

Gas Processing Plant located near Tilley, Alberta. The Project is owned and operated by the Proponent.

The Plant has a total licensed raw gas inlet capacity of 991 e3m3 per day (as per ERCB Facility License

(Amendment) No. F-2187). Prior to the implementation of AGI, the Proponent was mandated to

implement a sulphur emission control system as a result of degrandfathering the Plant. AESRD imposed

a requirement on the Proponent to recover at least 69.7% of the inlet sulphur on a quarterly basis. The

revision to the operating permit did not address CO2 emissions from the facility. An Xergy SRU, which

was a new technology designed to recover sulphur from sour natural gas and sour solution gas streams,

was selected to meet these sulphur recovery requirements at the Plant.

Despite costly upgrades, the Proponent was unable to operate the Xergy system in a consistent manner

to meet the quarterly sulphur recovery requirements of 69.7%. The Proponent was granted approval

from the Alberta Energy Resources and Conservation Board (ERCB) for a variance from the sulphur

recovery guidelines and was given permission to continue to work on improving the performance of the

Xergy SRU. As a result of the costly upgrades and poor reliability of the Xergy SRU, the Proponent chose

to implement AGI. There were no regulatory barriers to prevent the AGI project from proceeding and

the Alberta ERCB and AESRD granted permits for the Project.

In late 2008, construction of the AGI system was completed to replace the Xergy SRU and on January 12,

2009, the AGI program was initiated. The operation of the AGI scheme directly reduces GHG emissions

by geologically sequestering CO2 contained in the acid gas stream and reduces fossil fuel consumption

normally required for sulphur recovery operations. The acid gas, containing primarily CO2, is

compressed, transported by pipeline and injected into a well-characterized aquifer which results in,

essentially, permanent geological sequestration (>1000 years).


4 PROJECT IMPLEMENTATION AND VARIANCES Highlighted below are the variances and, or, modifications made to this reporting period, as compared

to the previous reporting period:

i) SS P6 Acid Gas Dehydration and Compression

For previous reporting periods, the power usage for the Acid Gas Compressor (Meter FE-

2502) was determined using the kW rating for the compressor and runtime hours. This

method assumed full compressor load was being utilized at all times. For this reporting

period monthly power consumption (kWh) data for the compressor was obtained, as it is

metered separately from the plant. Thus, the calculator includes the exact power

consumption data for the compressor rather than an estimate based on runtime hour;

adhering to the ISO 14064-2 principle of accuracy. Conversely, a meter for power

consumption from the auxiliary components including: the glycol return pumps, acid gas

chiller glycol circulating pumps, intercoolers, refrigerant compressors, and refrigerant aerial

cooler was not available. Therefore, the power consumption for these components is

calculated using the previous method of runtime hours and kW ratings for each component.

Using the directly metered power consumption data over the previous estimation method

resulted in a 4.8% increase in credits created by the project (or 1923 tonnes CO2e).

ii) SS B6a Incineration (Fuel Gas) and B6b Incineration (Tail Gas)

In the previous reporting periods the SULSIM ratio was calculated using the molar flow of

the tail gas stream and the molar flow of a wet acid gas stream. For this reporting period it

was confirmed that the acid gas being injected has had water removed from the stream as a

result of the compression processes before injection and, therefore, it was determined that

using a dry acid gas stream in the calculation of the molar flow ratio is more accurate. This

change in methodology was applied to determining the tail gas volumes for this reporting

period in line with the ISO 14064-2 principle of accuracy. As a result, a higher SRU molar

ratio (1.118) is calculated relative to the previous year's (1.085), thereby increasing the

volume of tail gas that would have been produced by the SRU by 2.95%. In addition, the

baseline volume of fuel gas required for incineration is increased by 3.0%. Therefore, the

new method results in an increase of baseline emissions due to the increased volume of tail

gas and fuel gas required for incineration, and a larger project emission reduction.

iii) SS B6b Incineration (Tail Gas) – Inclusion of N2O emissions

For this reporting period, N2O emissions created during the incineration of tail gas were

added to SS B6 – Baseline Emissions from Incineration calculations. The formula is included

in Section 6.0 below, under the SS B6 subsection.

iv) SS P12 – Fuel Extraction and Processing


In previous reporting periods, the volume of natural gas used in project condition

calculations was the amount of fuel gas that would have been required to flare acid gas in

the absence of the project. For this reporting period, the volume of fuel gas required by the

catadyne heater in the acid gas injection scheme was also included in SS P12 calculations.

The formulas for calculating fuel extraction and processing emissions with the combined

volume of project condition fuel gas have been adjusted below in Section 6.0.

v) SS P9 Injection Unit Operation – Updated the High Heating Value of Natural Gas

The HHV of natural gas was updated to the 2016 National Inventory Report; whereas CAPP

2003 guidelines were used in previous reporting periods. The value was changed from 37.4

To 39.6.

There were a number of key changes to the Project in the previous VY2015 reporting period as

compared to the Offset Project Plan. These changes were described in the Project report for the

previous reporting period. For transparency, they have also been provided here:

(i) SS P9 Injection Unit Operation

A number of small emission sources as part of the acid gas injection scheme were identified

during the site visit. These include one fuel gas Catadyne heater used to maintain optimal

temperature in the winter time for a number of measurement devices, and three electric

Ruffneck heaters used to heat the compressor building during winter months. Emissions

from these sources were calculated and included as project emissions under "P9 Injection

Unit Operation" for this reporting period. This is a variance from the offset project plan,

which had excluded emissions from P9 Injection Unit Operation. Emissions were calculated

for operating the heaters during five winter months resulting in a total of 53.8 tonnes of

CO2e and a 0.15% drop in emissions reductions achieved.

(ii) Change in Grid Emissions Intensity Factor

Alberta Environment & Parks (AEP) released the Carbon Offset Emission Factors Handbook

Version 1.0 in March of 2015. This document contains updated emission factors for projects

in the Alberta carbon offset system. The Project uses grid electricity for the operation of the

acid gas compressor, electric heaters and other electric devices resulting in emissions in the

project condition. Therefore, the grid emissions intensity factor was updated to 0.64 tonnes

CO2e per MWh for this reporting period. Using this updated emission factor is more

accurate than the previous grid emissions factor.

There were a number of key changes to the Project in the previous reporting periods as compared to the

Offset Project Plan. These changes were described in the Project reports for the VY2014 and VY2013

reporting periods. For transparency, they have also been provided here:


(iii) SS B6b Incineration (Tail Gas)

Emissions from tail gas incineration were calculated by multiplying the percentage of CO2

and other carbon components found in the acid gas by the volume of acid gas produced.

This approach was updated so that the tail gas volumes generated and the tail gas

composition based on the SULSIM produced by Sulphur Experts are used. Use of the

simulated tail gas composition and the calculated tail gas volumes due to the molar flow

change within the SRU are more accurate than using the acid gas composition and the acid

gas volumes, which was previously done. This increased the accuracy of emissions from tail

gas combustion in the baseline.

(iv) Change in Global Warming Potentials

Alberta Environment and Sustainable Resource Development (AESRD) released a

memorandum on January 23, 2014 entitled "Notice of Change for Global Warming

Potentials". The memorandum stated that Alberta has adopted the 2007 global warming

potentials as published by the International Panel on Climate Change (IPCC). These new

global warming potentials (GWPs) apply to all vintage credits generated in 2014 onwards in

the Alberta Offset program. As a result, the global warming potentials for methane (25,

previously 21) and nitrous oxide (298, previously 310) were updated for 2014 and

subsequent reporting periods.

(v) Metering of Injected Acid Gas Volumes

In order to comply with AER Directive 17, which requires an acid gas injection meter at the

injection well if the well is separate from the facility lease, the Proponent installed a new

meter in 2013 to capture the acid gas disposal volume at the injection well. As such, the

metered acid gas volumes injected are now based on the meter at the injection well (FE-

4062). This increases accuracy of the quantifications and addresses the potential fugitive

emissions as stated in the protocol applicability requirement #4: “The project developer

must provide evidence that metering of injected gas volumes takes place as close to the

injection point as is reasonable to address the potential for fugitive emissions as

demonstrated by project schematics.”

(vi) SS B6: Tail Gas Volumes and Fuel Gas Incineration

a. In determining the incinerator fuel gas consumption in the baseline (ratio of fuel gas to

tail gas), the methodology - as outlined in the offset project plan - did not calculate the

fuel gas required to meet the minimum heating value in SS B6a as required by the

protocol and was therefore understating previous emission reductions. The equation for

determining the minimum heating value of the combined tail gas and fuel gas streams

(See Section 6 for details) is outlined in the protocol in Table 2.4 Quantification

Procedures under B6a (page 30). This minimum heating value is required to ensure


effective combustion of the flare as per AER’s Directive 0601. The method of calculating

the fuel gas volumes in the baseline has been updated as per the protocol requirements,

resulting in a more accurate assertion.

b. 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. This

method is based on the results of a simulation produced by Sulphur Experts (“SULSIM”),

a third-party simulator. The simulation models the function of a hypothetical SRU using

project specific acid gas composition and volumes produced. The SULSIM indicates a

change in the molar flow within of the SRU, such that the tail gas volume is higher than

the acid gas volume being processed.

As modeled by the SULSIM, 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

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. The SULSIM

model captures this increase in the material balance of the acid gas inlet stream (Dry

Acid Gas) and the tail gas stream to the incinerator (Tail Gas to INCT). Prior to the

process, the inlet stream is comprised mainly of CO2, H2S and H2O. Following the SRU,

the tail gas components are CO2, N2, and H2O; with a molar flow rate approximately

1.11812 times that of the inlet stream due to the introduction of nitrogen and oxygen.

As the acid gas stream is assumed to follow ideal gas behavior 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 sent to

incineration the inlet volume of acid gas will need to be multiplied by the ratio of the

molar flow rate of Tail Gas to INCT, n2, to the molar flow rate of the acid gas inlet

stream, Dry AG 2016, n1.

With an increase in the tail gas volumes going into the incinerator the incinerator fuel

gas requirements also increase to meet the minimum LHV value for combustion. As a

1 Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and Venting (November 2006) requires any combined tail gas and fuel gas streams to meet a minimum heating value of 20 MJ/m3 2 Sulphur Experts (January, 2017), “AltaGas Bantry SRU Simulation Report”.


result, the emissions from incineration of fuel gas are higher. This methodological

change is a more accurate estimation of the tail gas volumes produced in the baseline.

(vii) Heat Value of Tail Gas

This parameter is determined from the SULSIM that specifies the tail gas composition of the

Claus unit. The heat value was calculated using the molar percent of the tail gas and heating

values for each component. Previously, this value was based on an engineering estimate.

Using the tail gas stream from the SULSIM is representative of the Project conditions and

therefore increases the accuracy of the calculation.

5 REPORTING PERIOD For the purposes of this project report, the carbon dioxide equivalent emission reduction credits are

claimed for activities from 1 January, 2016 to 31 December, 2016.

6 GREENHOUSE GAS CALCULATIONS GHG emission reductions were calculated following the Quantification Protocol for Acid Gas Injection,

version 1.0 (AENV, 2008). The activities and procedures outlined in the Offset Project Plan provide a

detailed description of the Project’s adherence to the requirements of the quantification protocol. The

formulas used to quantify GHG offset 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 Environment Canada (2016).

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 Sulphur Reduction Unit = emissions under SS (B5) Sulphur Recovery Unit

Operation3

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

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

Processing

3 The sulphur recovery unit at the Bantry Sour Gas Processing Plant was the Xergy; therefore, the baseline

emissions from the operation of the Xergy SRU is herein referred to as SS (B5) Sulphur Recovery Unit to replace SS B5a (Liquid Redox Process) and SS B5b (Multi-Stage Claus Unit).


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

Dehydration and Compression

(iii) Emissions Upset Flaring = emissions under SS (P8) Upset Flaring

(iv) Emissions Injection Unit Operation = emissions under SS (P9) Injection Unit Operation

SS B9 (Fuel Extraction and Processing)

Emissions of CO2 = (VolSalt + BFlaring ) x NEPCO2EF

Emissions of CH4 = (VolSalt + BFlaring ) x NEPCH4EF

Emissions of N2O = (VolSalt + BFlaring ) x NEPN2OEF

Where,

NEPCO2EF/NEPCH4EF/NEPN2OEF (tonnes/e3m3) = Emission factor for natural gas extraction and processing of

CO2, CH4, and N2O;

VolSalt (e3m3) = Volume of fuel gas consumed for sulphur recovery by the Xergy system

=FuelSalt

12 monthsyear⁄

FuelSalt (e3m3) = Total annual fuel gas requirement to operate the Xergy system

= kWSalt x HRSalt x 3.6 MJ/kWh

ESalt x HHVFG x 1000 m3/e3m3

kWSalt (kW) = kW rating of salt bath heater;

HRSalt (hrs) = Operating hours of the salt bath heater;

ESalt (%) = Assumed efficiency of the salt bath heater;

HHVFG (MJ/m3) = higher heating value of fuel gas

BFlaring (e3m3) = Fuel gas volume for baseline tail gas flaring;

= (AGFlare + PDisposal) x FG: AG

AGFlare (e3m3) = Acid gas flared volumes (upset flaring);

PDisposal (e3m3) = Acid gas disposal volumes;

FG:TG = Fuel gas to tail gas ratio;

= LHVCombined − LHVTail Gas

LHVFuel − LHVCombined


LHVCombined = Combined net heating value of tail gas and make-up fuel gas;

LHVTail Gas = Lower heating value of tail gas (composition of tail gas based on simulation provided by

Sulphur Experts);

LHVFuel = Lower heating value of fuel gas

TG = tail gas produced by the Sulphur Recovery Unit.

= (AGFlare + PDisposal) ∗ TG: AG

TG:AG = molar flow ratio of tail gas to acid gas as simulated by the SULSIM produced by Sulphur Experts.

= TailGasINCT ÷ DryAG2016

TailGasINCT = molar flow of acid gas streaming into the sulphur recovery unit as simulated by Sulphur

Experts and presented in the SULSIM.

DryAG2016 = molar flow output (tail gas) of sulphur recovery unit as simulated by Sulphur Experts and

reported in the SULSIM.

SS B6 (Incineration)4

Emissions of CO2 (SS B6a) = BFlaring x EFCO2−Bantry

Emissions of CH4 (SS B6a) = BFlaring x EFCH4

Emissions of N2O (SS B6a) = BFlaring x EFN2O

EFCO2-Bantry (tonnes/e3m3) = Bantry site-specific CO2 emission factor for natural gas combustion;

EFCH4/EFN2O (tonnes/e3m3) = Emission factor for natural gas combustion of CH4 and N2O;

The acid gas from Bantry’s contains CO2, N2O and residual hydrocarbons including CH4, C2H6, C3H8, iC4H10,

nC4H10, neoC5H12, iC5H12, nC5H12, nC6H14, as well as N2O. Below are the equations used to determine the

tonnes of CO2e of each hydrocarbon species and N2O due to flaring of tail gas in the baseline condition.

Emissions of CO2 (SS B6b) = TG x %CO2, Combined x ρCO2

Emissions of CH4 (SS B6b) = TG x %CH4, Combined x ρCH4 x [44

gmole

CO2

16g

moleCH4

]

Emissions of C2H6 (SS B6b) = TG x %C2H6, Combined x ρC2H6 x [2 x 44

gmole

CO2

30g

moleC2H6

]

4 Density of CO2 and CH4 from Alberta Environment 2008 AGI Protocol (pg 25, 26, and 31)


Emissions of C3H8 (SS B6b) = TG x %C3H8, Combined x ρC3H8 x [3 x 44

gmole

CO2

44g

moleC3H8

]

Emissions of iC4H10 (SS B6b) = TG x %iC4H10, Combined x ρiC4H10 x [4 x 44

gmole

CO2

58g

moleiC4H10

]

Emissions of nC4H10 (SS B6b) = TG x %nC4H10, Combined x ρnC4H10 x [4 x 44

gmole

CO2

58g

molenC4H10

]


gmole

CO2

72g

molenC5H12

]

Emissions of iC5H12 (SS B6b) = TG x %iC5H12, Combined x ρiC5H12 x [5 x 44

gmole

CO2

72g

moleiC5H12

]


gmole

CO2

72g

molenC5H12

]


gmole

CO2

86g

molenC6H14

]


gmole

CO2

100g

molenC7H16

]

Emissions of nC8H18 (SS B6b) = TG x %nC8H18 x ρnC8H18 x [8 x 44

gmole

CO2

114g

molenC8H18

]

Emissions of nC9H20 (SS B6b) = TG x %nC9H20 x ρnC9H20 x [9 x 44

gmole

CO2

128g

molenC9H20

]

Emissions of nC10H22 (SS B6b) = TG x % nC10H22 x ρnC10H22 x [10 x 44

gmole

CO2

142g

molenC10H22

]

Emissions of N2O (SS B6b) = TG x EFN2O−Producer


Densities used in the above equations are based on assuming ideal gas behaviour of each hydrocarbon

species.

SS B5 (Sulphur Recovery Unit Operation)

Emissions of CO2 = VolSalt x EFCO2−Bantry

Emissions of CH4 = VolSalt x EFCH4−industrial

Emissions of N2O = VolSalt x EFN2O−industrial

SS P12 (Fuel Extraction and Processing)

Emissions of CO2 = NGProject x NEPCO2EF

Emissions of CH4 = NGProject x NEPCH4EF

Emissions of N2O = NGProject x NEPN2OEF

Where,

NGProject (e3m3) = Fuel gas volumes used in flaring (upset flaring) and the catadyne heater

SS P6 (Acid Gas Dehydration and Compression)

Emissions of CO2 = (PAG + PAX) x EFCO2eEF

Where,

EFCO2eEF (t CO2e/MWh) = Grid electricity intensity factor for consumption;

PAG (MWh) = Metered power usage of acid gas compressor

PAX (MWh) = Power usage of auxiliary acid gas compressor components

=R x ( kWGR + kWGC + kWCoolers + kWRCA + kWRCB + kWAIR)

1000(kWhMWh⁄ )

R (hrs) = Operating hours of acid gas compressor;

kWGR (kW) = kW rating of glycol return pumps;

kWGC (kW) = kW rating of acid gas chiller glycol circulating pumps;

kWCoolers (kW) = kW rating of 5-stage intercoolers;

kWRCA (kW) = kW rating of refrigerant compressor A;


kWRCB (kW) = kW rating of refrigerant compressor B;

kWAIR (kW) = kW rating of aerial cooler;

SS P8 (Upset Flaring)

Emissions of CO2 (SS P8a) = FGFlare x EFCO2−Bantry

Emissions of CH4 (SS P8a) = FGFlare x EFCH4

Emissions of N2O (SS P8a) = FGFlare x EFN2O

Below are the equations used to determine the t CO2e of each hydrocarbon species due to flaring of acid

gas in the project condition.

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

16g

moleCH4

]

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

gmole

CO2

30g

moleC2H6

]


gmole

CO2

44g

moleC3H8

]

Emissions of iC4H10 (SS P8b) = AGFlare x %iC4H10, Combined x ρiC4H10 x [4 x 44

gmole

CO2

58g

moleiC4H10

]

Emissions of nC4H10 (SS P8b) = AGFlare x %nC4H10, Combined x ρnC4H10 x [4 x 44

gmole

CO2

58g

molenC4H10

]


gmole

CO2

72g

molenC5H12

]

Emissions of iC5H12 (SS P8b) = AGFlare x %iC5H12, Combined x ρiC5H12 x [5 x 44

gmole

CO2

72g

moleiC5H12

]



gmole

CO2

72g

molenC5H12

]


gmole

CO2

86g

molenC6H14

]


gmole

CO2

100g

moleC7H16

]

SS P9 (Injection Unit Operation)

Emissions of CO2 (SS P9) = FGHeater x EFCO2−Bantry

Emissions of CH4 (SS P9) = FGHeater x EFCH4−Producer

Emissions of N2O (SS P9) = FGHeater x EFN2O−Producer

Where,

FGHeater (e3m3) = Volume of natural gas (fuel gas) required to operate the fuel gas Catadyne heater

= PCONS x 3.6 MJ/kWh

HHVFG x 1000 m3/e3m3

HHVFG (MJ/m3) = higher heating value of fuel gas

PCONS (kWh) = power consumption of fuel gas Catadyne heater

= kWFGH x Qty x Hrs

kWFGH (kW) = power rating of fuel gas heater = 1.47 kW

Qty = number of catadyne heaters = 1

Hrs = annual runtime hours

= 5 months x 30.5days

monthx 24

hrs

day

Emissions of CO2e (SS P9) = PCONS x EFCO2eEF

Where,

PCONS (kWh) = power consumption of electric Ruffneck heaters

= kWEHx Qty x Hrs

kWEH (kW) = power rating of electric heaters = 7.5 kW

Qty = number of Ruffneck heaters = 3

Hrs = annual runtime hours

= 5 months x 30.5days

monthx 24

hrs

day


Table 1 provides the emission factors used for the Project.


Table 1 - Emission factors used for the AltaGas Bantry AGI 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

B5, B6a, P8a, P9

2.015 tonnes/e3m3

Site-specific 0.0064 tonnes/e3m3

Environment Canada (2016)

0.00006 tonnes/e3m3

Environment Canada (2016)

-

Natural Gas

Extraction

B9, P12 0.043 tonnes/e3m3

Carbon Offset Emission Factors

Handbook, Version 1.0 March 2015

0.0023 tonnes/e3m3



0.000004 tonnes/e3m3



-

Natural Gas

Processing

B9, P12 0.090 tonnes/e3m3



0.0003 tonnes/e3m3



0.000003 tonnes/e3m3



-

Electricity

Consumption

P6, P9 - Carbon Offset Emission Factors


- - - - 0.64

tonnes/MWh


7 GREENHOUSE GAS ASSERTION The greenhouse gas 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 tonnes of carbon dioxide equivalent (CO2e) is

calculated using the global warming potentials (GWPs) referenced in the SGER.

Table 2 identifies the greenhouse gas assertion, containing the calculated number of offset tonnes

achieved, separated by each unique vintage year and GHG released. As shown, the Project created

42,407 tonnes of GHG reductions in 2016.

Table 2 - Offset tonnes created for 2016 by the Project5.

2016 Greenhouse Gas in tonnes CO2e

CO2 CH4 N2O PFCs HFCs SF6 CO2e Total

Baseline 26,250.6 110 0.8 0 0 0 15,298.3 44,543.8

Project 182. 0.76 0.0057 0 0 0 1,933.7 2,136.5

Reductions 26,068.6 109.3 0.81 0 0 0 13,364.6 42,407

5 Emission reductions per GHG species, as shown in table, are subjected to rounding errors and may not work to

total tonnages displayed; however, the GHG assertion is correct.


8 OFFSET PROJECT PERFORMANCE The Project has created credits in seven previous vintage years. Figure 1 shows the credits created by

the Project annually for its full 8-year crediting duration starting January 12, 2009 and ending on

December 31, 2016.

Figure 1 - Credits Created by the Project, by Vintage Year

The credits created in vintage years 2013 to 2016 are higher than previous years. This large increase in

credits is due to methodological changes in quantification including the determination of the incinerator

fuel gas requirements in the baseline and the volumes of tail gas produced as modelled by the SULSIM.

These changes and the formulas used in the calculations are explained in detail in the above sections of

the report and were required in order to meet the principle of accuracy as described in ISO 14064-2.

Credits generated in 2016 (42,407 t CO2e) were 19% higher than 2015 (35,639 t CO2e) and the highest of

all project vintage years. This was due to a higher volume of acid gas injected in 2016 than 2015, a

difference of 732.4 e3m3. In addition, use of metered electricity for the acid gas compressor power usage

enabled a more accurate calculation of emissions resulting from compressor usage. As a result, the

project emissions were lower in 2016 and the overall emission reductions higher.

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

45,000

2009 2010 2011 2012 2013 2014 2015 2016

Cre

dit

s C

reat

ed

(t

CO

2e)

Vintage Year


10 STATEMENT OF SENIOR REVIEW This offset project report was prepared by Kelsey Lank, Blue Source Canada and reviewed by Tooraj

Moulai, 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:

Kelsey Lank Carbon Solutions Analyst 08/03/2017

Tooraj Moulai Senior Engineer, Carbon Services 08/03/2017


11 REFERENCES Alberta Environment and Sustainable Resource Development, 2013, Technical Guidance for Offset

Project Developers - Version 4.0, February 2013.

Alberta Environment and Sustainable Resource Development, 2015, Carbon Offset Emission Factor

Handbook – Version 1.0, March 2015.

Alberta Environment and Sustainable Resource Development, 2008, Quantification Protocol for Acid Gas

Injection, (May 2008, Version 1).

Alberta Energy Regulator, March 1994, Directive 051: Injection and disposal wells – well classifications,

completions, logging, and testing requirements, www.aer.ca/documents/directives/Directive051.pdf.

Alberta Energy Regulator, November 2009, Directive 071: Emergency preparedness and response

requirements for the petroleum industry, http://www.aer.ca/documents/directives/Directive071-with-

2009-errata.pdf.

Alberta Energy Regulator, 2016, Directive 065: Resources applications for conventional oil and gas

reservoirs, https://www.aer.ca/documents/directives/Directive065.pdf

Alberta Energy Regulator, 2016, Directive 060: Upstream Petroleum Industry Flaring, Incinerating, and

Venting. [pdf] Calgary, Alberta: Energy Resources Conservation Board. Available at:

https://www.aer.ca/documents/directives/Directive060.pdf

Environment Canada, 2016. National Inventory Report: Greenhouse Gas Sources and Sinks in Canada,

Part 2. Available at: https://ec.gc.ca/ges-ghg/

Heinrich J. J., Herzog, H. J., and Reiner, D. M., 2003. Environmental Assessment of Geologic Storage of

CO2. In: Laboratory for Energy and the Environment; Massachusetts Institute of Technology, Second

National Conference on Carbon Sequestration. Washington, May 5-8, Cambridge: MIT.

altagas bantry acid gas injection project...sulsim sulphur recovery unit simulation page 5 prepared...

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