altagas bantry agi offset project report v2 february 28 2011

Prepared by: Blue Source Canada ULC

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

OFFSET PROJECT REPORT:

ALTAGAS BANTRY ACID GAS INJECTION OFFSET PROJECT

FINAL

February, 2011

AltaGas Bantry Acid Gas Injection Project Report February, 2011

Blue Source Canada ULC Page 1

1. PROJECT INFORMATION

AltaGas Processing Partnership operates an acid gas injection (AGI) project at the

Bantry Sour Gas Processing Plant. At the facility, the acid gas is compressed and then

transmitted through a 1km pipeline to the injection well. The acid gas waste stream at

the Bantry Sour Gas Processing Plant is now being geologically sequestered in an

existing and well characterized aquifer. The injection of acid gas into the Nisku

formation, results in permanent sequestration of the CO2 contained in the acid gas that

would have otherwise been released to the atmosphere.

Additionally the injection of acid gas avoids the consumption of fuel gas previously

required to operate a sulphur recovery unit and associated tail gas incinerator at the site

and therefore reduces direct GHG emissions from the use of fuel gas (natural gas).

Flaring of acid gas is now conducted only on an emergency basis during equipment

failures or process upsets, using a low pressure flare.

Before the implementation of the acid gas injection system, AltaGas was approved to

operate an Xergy sulphur recovery unit (SRU) to incinerate the tail gas stream from the

SRU and to emit up to 1 tonne per day of sulphur emissions. Had the facility not

implemented the acid gas injection project, all of the acid gas produced from natural gas

processing operations at the Bantry facility would have continued to have been

processed in the Xergy sulphur recovery unit, or similar equipment, and the tail gas from

the SRU would have been incinerated, resulting in direct emissions of CO2 separated

from the inlet raw gas and direct emissions of greenhouse gases from the combustion

of fuel gas to operate the SRU and the tail gas incinerator.

2. REPORTING PERIOD

For this project, the carbon dioxide equivalent emission reduction credits are claimed for

activities from January 1th, 2010 to December 31st, 2010. No changes to the project

operation occurred during this time.



3. GHG CALCULATION

GHG emission reductions were calculated following the Alberta Offset System

Quantification Protocol for Acid Gas Injection Projects (Version 1, May 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.

Only one flexibility mechanism was used in the quantification of sources, sinks and

removals of emissions, specifically Flexibility Mechanism #3, as defined in the Alberta

Offset System Quantification Protocol for Acid Gas Injection Projects. The use of this

flexibility mechanism involved the application of a site specific fuel gas emission factor

in place of the default Environment Canada CO2 emission factor for natural gas. The

use of this project specific emission factor, calculated based on the actual carbon

content of the natural gas combusted at the site, follows the approach defined by the

Canadian Association of Petroleum Producers (CAPP) April 2003 Guide Calculating

GHG Emissions1 and increases the accuracy of the calculated GHG emission

reductions.

1 http://membernet.capp.ca/raw.asp?NOSTAT=YES&dt=PDF&dn=55904



Appendix A

OFFSET PROJECT PLAN:


FEBRUARY, 2011

Prepared by: Blue Source Canada ULC

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

OFFSET PROJECT PLAN:


FINAL

FEBRUARY, 2011

Bantry Acid Gas Injection Offset Project February, 2011

Prepared By Blue Source Canada ULC

CONTENTS

1.0 Introduction ..................................................................................................................... 1

2.0 Project and Proponent Identification ................................................................................ 2

3.0 Project Description .......................................................................................................... 3

3.1 Project Scope ................................................................................................................ 3

3.3 Pre-Project Conditions ......................................................................................... 6

3.4 Actions Taken ................................................................................................................ 9

3.5 Project Condition ........................................................................................................... 9

3.5.1 Compressor .......................................................................................................... 9

3.5.2 Pipeline ................................................................................................................. 9

3.5.3 Injection and monitoring infrastructure .................................................................. 9

3.6 Quantification Protocol Applicability ............................................................................. 10

3.6.1 Removal of emissions ............................................................................................11

3.6.2 Ownership of Emission reductions .......................................................................11

3.6.3 ERCB Approval .......................................................................................................11

3.6.4 Fugitive Emissions ..................................................................................................12

3.6.5 Type of Gas Processing Facility ...........................................................................12

3.6.6 Co-mingling of Acid Gas from Other Facilities ...........................................................12

3.6.7 Quantification of Reductions .....................................................................................13

3.6.8 Offset Eligibility Requirements .............................................................................13

4.0 Identification and Justification of Baseline ...........................................................................13

5.0 Quantification of Emission Reductions ................................................................................15

5.1 Process Description ..................................................................................................... 15

5.2 Data Sources ............................................................................................................... 17

5.3 Quantification Plan ....................................................................................................... 17

5.4 Monitoring and Quality Assurance/Quality Control (QA/QC) Plan ................................ 24

5.4.1 Metering Maintenance and Calibration ......................................................................24

5.4.2 AltaGas PROMET Data Management System ..........................................................25

5.4.3 Manual Data Collection ........................................................................................25

5.4.4 Record Keeping ...................................................................................................27

6.0 Reporting of Emission Reductions ..................................................................................27


Prepared By Blue Source Canada ULC Page 1

1.0 INTRODUCTION

The AltaGas Bantry Acid Gas Injection Offset Project (the Project) is an acid gas injection (AGI)

project that located at the Bantry Sour Gas Processing Plant located near Tilley, Alberta. The

Project is owned and operated by the AltaGas Processing Partnership (AltaGas).

The AltaGas Bantry Sour Gas Processing Plant has a total licensed raw gas inlet capacity of 708

e3m3 per day. The plant is owned and operated by the AltaGas Processing Partnership. Before

the implementation of the acid gas injection system, AltaGas was mandated to implement a

sulphur emission control system at its Bantry facility due to de-grandfathering under the relevant

sulphur emission regulations (termination of regulated pre-existing sulphur emission limits). As a

result of this de-grandfathering, Alberta Environment imposed a requirement on AltaGas to

recover at least 69.7% of the inlet sulphur to the plant on a quarterly basis. This revision to the

operating permit did not address carbon dioxide emissions from the facility. An Xergy sulphur

recovery unit, 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

Bantry.

AltaGas encountered difficulties in meeting the required sulphur emission reductions using the

Xergy system. In an attempt to reach required sulphur levels, upgrades were made to the

sulphur recovery unit (SRU) including the testing of different catalysts, the installation of a new

acid gas blower in 2005, and the installation of a new tail gas incinerator in 2006. Despite costly

upgrades, AltaGas was unable to operate the system in a consistent manner to meet the

quarterly sulphur recovery requirements of greater than 69.7% sulphur recovery. AltaGas was

granted approval from the Alberta Energy Resources and Conservation Board (ERCB) for a

variance from the above sulphur recovery guidelines, and allowed to continue to work to improve

the performance of the SRU.

Due to the costly upgrades and poor reliability of the SRU, AltaGas chose to implement an acid

gas injection project. There were no regulatory barriers to prevent the acid gas injection project

from proceeding and the Alberta ERCB and Alberta Environment granted permits for the project.

In late 2008, construction of the acid gas injection system was completed to replace the previous

SRU. The operation of the acid gas injection scheme directly reduces greenhouse gas emissions

compared to the prior sulphur recovery operations by geologically sequestering carbon dioxide

contained in the acid gas stream and by reducing fossil fuel consumption normally required for

sulphur recovery operations. The acid gas, containing primarily carbon dioxide, is compressed,

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

permanent geological sequestration (>1000 years).

This Offset Project Plan has been completed in accordance with the Alberta Offset System

Offset Credit Project Guidance Document Version 1.2 (February, 2008). The Project also

complies with the Alberta Offset System Quantification Protocol for Acid Gas Injection Projects,

(Version 1, May 2008), herein referred to as the Acid Gas Injection Protocol.



2.0 PROJECT AND PROPONENT IDENTIFICATION

The Bantry Acid Gas Injection Project involves the injection of acid gas, containing primarily CO2,

into a well characterized reservoir, resulting in permanent geological sequestration of

greenhouse gases that would normally have been vented to the atmosphere following natural

gas processing and sulphur recovery. Additionally, had AltaGas not implemented the acid gas

injection project, the acid gas would have been treated using the pre-existing sulphur recovery

unit, which would have resulted in further greenhouse gas emissions from the combustion of fuel

gas to operate the sulphur recovery unit and the tail gas incinerator.

The project proponent is the AltaGas Processing Partnership. Contact information is provided

below.

Corporate Contact Information: AltaGas Processing Partnership

1700 355 4th Avenue S.W

Calgary, Alberta

T2P 0J1

Phone: (403) 691-7575

Fax: (403) 691-7195

Contact Information for Project: Jon Remmer, Commercial/Operations Engineer

AltaGas Ltd.

1700 355 4th Avenue S.W

Calgary, Alberta

T2P 0J1

Phone: (403) 269-5678

Fax: (403) 691-7000

Email: [email protected]

Direct and indirect emission reductions generated by the Project are owned solely by the

AltaGas Processing Partnership. This Offset Project Plan covers all direct and indirect emission

reductions generated by the Project.



3.0 PROJECT DESCRIPTION

3.1 PROJECT SCOPE

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

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

carbon dioxide, produced during natural gas processing operations, and direct greenhouse gas

emission reductions due to the avoided use of fossil fuels that would have been required in the

operation of the SRU and related tail gas incineration units.

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 sequestration of acid gas reduces the quantity of GHG

emissions released to the atmosphere relative to more GHG intensive baseline processes

(sulphur recovery unit) required for safe disposal of the sulphur contained within the acid gas

stream.

The acid gas injection system includes infrastructure for acid gas compression, pipeline

transportation, injection and process monitoring. The acid gas stream is diverted through a

compressor to boost the pressure of this stream for transportation through the pipeline and into

the injection well. There are various monitoring instruments along the way to measure system

operating parameters as well as to ensure there is no leakage from the on-site infrastructure or

from the reservoir. Due to the toxicity of the acid gas, leakage is prevented as per ERCB

Approval No. 11200.

The geological sequestration of the acid gas stream is also considered permanent based on the

assessed integrity of the reservoir into which the acid gas is being disposed. The geological

assessment was a requirement of the ERCB Approval No. 11200 required for the implementation

of the acid gas injection process. Regulations relative to the hydrogen sulphide content of the

acid gas stream provides added assurance that the sequestration is permanent.

A site map for the Bantry Facility is provided as Figure 3.1.

Acid Gas Injection Offset Project Plan February, 2011


Figure 3.1 – Bantry Site Plan



3.2 PROJECT SITE DEFINITION

The Bantry sour gas processing plant, operated by AltaGas, is a sour gas processing facility with

a licensed capacity of 708 e3m3/day. The emission reductions quantified under this report are

relative to the treatment and disposal of the acid gas stream generated during the processing of

sour natural gas at the facility.

The Bantry facility consists of two natural gas processing plants. At Plant 1, low pressure

(100kPa) inlet raw gas goes through slug catchers and inlet separators, the gas is then

compressed through 3 stages of compression to approximately 2,400 kPa. This sour gas then

flows through an amine system (sweetening process) to remove H2S and CO2. The sweetened

gas then flows through a glycol de-hydration tower and refrigeration system, and is then

compressed in a 4th stage of compression to approximately 5,000 kPa to be sent to the TCPL

mainline.

The process at Plant 2 is very similar but the inlet raw gas is at a higher inlet pressure

(approximately 2,500 kPa) and no compression is required before gas sweetening. The raw gas

passes through inlet separators, a sweetening train and a refrigeration system before combining

with the processed gas from Plant 1 in order to undergo 4th stage of compression

The acid gas is injected into the Nisku formation in the Bantry field. This reservoir is a water

aquifer zone and contains no producing wells. The Bantry Acid Gas Injection Well is the only well

located in this zone and has the following unique ID:

Bantry Acid Gas Injection Well: 02/13-33-017-12W4/0.

Further, the approvals from the ERCB and Alberta Environment provide evidence that the

Government of Alberta has approved of the injection program.



3.3 PRE-PROJECT CONDITIONS

Given the requirement to reduce sulphur emissions, the baseline condition for the plant is the

continued use of the existing Xergy sulphur recovery unit at the plant to convert hydrogen

sulphide into elemental sulphur. This baseline is reasonable as the continued use of the pre-

existing SRU is a reasonable baseline since the SRU, acid gas blower, tail gas incinerator and

other related equipment were relatively new (less than 8 years old) and were not

decommissioned at the end of their respective useful lives. Additionally, the Alberta ERCB had

granted the Bantry Facility a variance from sulphur recovery guidelines provided that AltaGas

continue to evaluate and work to improve the performance of the SRU. Also, the sulphur

recovery process used by AltaGas was designed to meet the required standards for treatment of

the acid gas stream, and the protocol is based on design specifications as a means to calculate

the baseline.

The acid gas from Plant 2 is mixed with the acid gas from Plant 1 and sent to the Xergy SRU. In

the SRU, the acid gas is heated from 50 to 270°C in a salt bath heater and mixed with air to

facilitate the exothermic reaction of hydrogen sulphide into elemental sulphur and sulphur

dioxide. The catalytic oxidation reaction takes place in one of two packed bed reactors

containing an activated carbon catalyst. The produced sulphur sorbs to the activated carbon,

while the other gases pass through the reactor. Only one reactor is used at a time as the

catalysts contained in the activated carbon beds have to be regenerated from time to time.

Regeneration of the catalyst involves passing hot inert gases at elevated pressures through the

reactor to desorb the sulphur.

The gas products exiting the activated carbon reactor are then sent to a tail gas incinerator to

destroy any remaining unreacted hydrogen sulphide and other trace hydrocarbons. Any SO2

produced as a by-product during the sulphur recovery process or produced from the combustion

of hydrogen sulphide during tail gas incineration is emitted to the atmosphere along with the CO2

separated from the raw gas, both of which are not combustible.

The elemental sulphur produced from the chemical reaction is cooled in a sulphur condenser and

stored as liquid sulphur in a heated underground sulphur tank.

The Xergy unit required quarterly catalyst changes, resulting in 3-4 days of SRU downtime per

quarter and causing the flaring of sour solution gas upstream at the gas batteries or flaring of

produced acid gas at the gas plant. The flaring of sour solution gas and/or acid gas would result

in additional greenhouse gas emissions as would the off-site energy inputs required to

regenerate the spent catalyst or to produce new activated carbon catalysts for the SRU reactors.

Note that for conservativeness, these emission sources were not quantified.

The Xergy unit consumed fuel gas directly in a 219 kilowatt (kW) heater (the salt bath heater) to

heat the reactants before entry into the activated carbon beds. Electricity was used to drive a

glycol air chiller used to condense sulphur produced from the reaction. Additionally, the liquid

sulphur storage tank was heated to keep the sulphur in liquid form. The tail gas incinerator

consumed fuel gas directly to maintain a high temperature at all times to ensure complete

destruction of any leftover H2S. No heat was recovered from the Xergy sulphur recovery

process.



The fuel gas for both plants is pipeline grade natural gas or ‘sales gas’, which is purchased from

TransCanada Pipelines Limited (TCPL) through a buyback line.

All of the carbon dioxide separated from the raw natural gas and all of the carbon dioxide

produced from the combustion of sales gas to operate the SRU and to operate the tail gas

incineration unit would have been emitted to the atmosphere.

In addition, the resulting sulphur product from the SRU would have had to be stored in liquid form

in a heated tank, handled on site and then shipped to markets. This would have resulted in

some additional greenhouse gas emissions. Given the difficulty in quantifying these potential

emissions, they were not included in the analysis, thereby contributing to the conservativeness of

this emission reduction calculation.



Figure 3.2: Bantry Sulphur Recovery Unit Process Flow Diagram

Acid Gas Injection Offset Project Plan February 2011


3.4 ACTIONS TAKEN

Under the acid gas injection program, acid gas (greater than 94% carbon dioxide and less than

5% hydrogen sulphide) is compressed, using an electric-motor-driven compressor, and

transported by pipeline approximately one kilometer to an injection site in a well characterized

aquifer. This project thereby significantly reduces sulphur dioxide emissions and the effective

carbon dioxide emissions from the site and results in fuel gas savings from the decommissioning

of the sulphur recovery unit and tail gas incinerator.

In 2008, AltaGas completed construction of the acid gas injection system, including a

compressor, pipeline, injection well and monitoring infrastructure. Each component is

summarized below:

• Compressor – a 596 kW electric compressor was installed to boost the pressure of the

acid gas stream for transportation through the pipeline and into the injection well;

• Pipeline – a one km long pipeline was installed to transport the compressed acid gas to

the injection reservoir.

• Injection and Monitoring Infrastructure – various monitoring instruments were installed

along the pipeline to measure system operating parameters and ensure there is no

leakage from the on-site infrastructure or from the reservoir. Due to the toxicity of the

acid gas, leakage is prevented as per ERCB Approval 11200.

3.5 PROJECT CONDITION

The acid gas injection system commenced operation January 12, 2009. Flaring of acid gas is

conducted on an emergency basis only, using a low pressure open flare. Details of the three

systems included in the project are provided in the sections below.

Details of the systems included in the project are provided in the sections below.

3.5.1 COMPRESSOR

The compressor is composed of a 596 kW electric motor-driven compressor. The acid gas is

compressed to a pressure of up to 8300 kPa for injection into the selected nearby disposal

reservoir, and transported by a new 88.9 mm pipeline. New piping was required to connect the

various components of the injection system.

3.5.2 PIPELINE

The pipeline runs approximately one km north to the injection well located at 02/13-33-017-

12W4/0.

3.5.3 INJECTION AND MONITORING INFRASTRUCTURE

Compressed acid gas will be transported by pipeline to a well-characterized aquifer that will

result in essentially permanent geological sequestration (>1000 years). Regular pressure

surveys will be conducted to ensure that the injected gas is being contained within the target

reservoir.



Issuance of the operational permits from the ERCB provides assurance that the required

measurement and monitoring programs are in place to ensure long-term sequestration of all

components of the acid gas stream. In particular, a complete geological assessment of the

injection reservoir with respect to permanence of sequestration, an assessment of any potential

leakage and contemplation of the leakage mitigation and management strategies that AltaGas

has implemented was included in the review completed by the ERCB during the permitting for

this project activity.

3.6 QUANTIFICATION PROTOCOL APPLICABILITY

The applicability criteria, identification of sources and sinks, and quantification methodologies for

this project have been determined in accordance with the Alberta Offset System Quantification

Protocol for Acid Gas Injection Projects (Version 1, May 2008). As outlined in the protocol, the

project must conform to the following applicability criteria. This Offset Project Plan must

demonstrate that:

1. The sequestration project results in removal of emissions that would otherwise have been

released to the atmosphere as indicated by an affirmation from the project developer and

project schematics;

2. Where the entities/operations are separate and distinct, the emissions reduced are

captured under the protocol and will be reported as being emitted at the source facility

such that the emission reductions are not double counted;

3. The Acid Gas injection scheme has obtained approval from the Alberta Energy and

Resources Conservation Board (ERCB) and meets the requirements outlined under

Directive 051: Injection and Disposal Wells – Well Classifications, Completions, Logging

and Testing Requirements.

4. 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 a project

schematics;

5. The sequestration project involves the installation of an acid gas injection project at one

of the following;

A) An existing sour natural gas processing facility which commenced operations

prior to July 1, 2007, which may either have an operational sulphur recovery unit

(i.e. Multi-Stage Claus or Liquid Redox) or may directly incinerate the acid gas

stream;

B) Any new natural gas processing facility constructed after July 1, 2007 with total

facility GHGs output in the first year of operation, inclusive of any CO2 that has

been captured and sequestered, less than the identified coverage threshold on

direct emissions as defined by the Specified Gas Emitter Regulation. Therefore

acid gas injection projects applying this protocol at natural gas processing



facilities commissioned after July 1, 2007 must also have total baseline emissions,

calculated as per Table 2.4 of the protocol, less than the identified coverage

threshold for direct emissions as defined by the Specified Gas Emitter Regulation.

6. The consolidation or comingling of acid gas streams from multiple emitting facilities

during the project’s crediting period must be fully accounted for to ensure that each

individual emitting facility is eligible to apply this protocol based on the above criteria. The

metering and measurement systems implemented for the acid gas injection project

activity should allow for disaggregation of the total baseline and project emissions back to

the original emitting facilities.

7. The quantification of reductions achieved by the project is based on actual measurement

and monitoring (except where indicated in this protocol) as indicated by the proper

application of this protocol; and

8. The project must meet the requirements for offset eligibility as specified in the applicable

regulation and guidance documents for the Alberta Offset System.

Demonstration that the Project complies with the applicability criteria outlined above is provided

in the following sections.

3.6.1 REMOVAL OF EMISSIONS

In the absence of the acid gas injection system, AltaGas would have continued to operate the

existing Xergy SRU in order to comply with regulations to reduce sulphur emissions, while

continuing to incinerate the tail gas from the SRU and releasing all CO2 contained in the acid gas

stream to the atmosphere.

3.6.2 OWNERSHIP OF EMISSION REDUCTIONS

No other entity is claiming credit for the GHG reductions realized at the AltaGas Bantry Sour Gas

Processing Plant. AltaGas Processing Partnership is the sole owner of the Bantry Sour Gas

Processing Plant and all offsets created under this project are owned by AltaGas Processing

Partnership. Offsets created from the Project have not been created, recorded or registered

under any other offset system or emissions offset registry for the same time period.

3.6.3 ERCB APPROVAL

The Alberta ERCB granted approval No. 11200 for the Class III injection scheme for the disposal

of hydrogen sulphide and carbon dioxide (acid gas) into the Nisku Formation in the Bantry Field,

11200.

The ERCB approval No. 11200 contains a number of operating requirements to prevent the

leakage of acid gas. These conditions include requiring AltaGas to monitor the wellhead injection

pressure to ensure it does not exceed 10,500 kPa (gauge); to monitor the pressure of the

tubing/casing annulus on a daily basis; to monitor the bottomhole pressure in the disposal zone;

and to submit annual progress reports to the Enforcement and Surveillance Section of the

ERCB’s Resources Applications Group.



Additionally, the facility Bantry continues to operate under Alberta Environment approval No.

9821-02-00, which is valid until 2015. Copies of the ERCB and Alberta Environment approvals

can be obtained from the respective government authority.

3.6.4 FUGITIVE EMISSIONS

The volumes of acid gas injected are measured upstream of the acid gas injection well at Plant 1

and Plant 2 immediately after the amine units. The acid gas is not metered at the wellhead, but

fugitive emissions are not a concern as any small leaks of acid gas (at the parts per million H2S

level) would be a major safety issue at the site due to the potential for fatalities if operators were

exposed to hydrogen sulphide. Operations personnel carry hydrogen sulphide detectors and

have to undergo safety training to understand and prevent exposure to hydrogen sulphide.

Based on these safety considerations, fugitive emissions are not expected to impact the

quantification of GHG emissions in any way.

Additionally, any upsets to the acid gas injection system would result in flaring of acid gas for

safety reasons and the flares at Plant 1 and Plant 2 are directly metered and the recorded

volume of acid gas flared is reported to Alberta Environment on a monthly basis. As such, any

risks of overestimating due to metering the acid gas upstream of the injection well at Bantry can

be mitigated by tracking the volumes of acid gas flared. The volume of acid gas injected is also

reported to the ERCB on a monthly basis, which further ensures that the integrity of the metering

systems should not be compromised by fugitive emissions. All of this data is collected and

managed in accordance with industry standards.

ERCB issuance of the operational permit (Approval No. 11200) for the acid gas injection system

provides assurance that the required measurement and monitoring programs are in place to

ensure the long-term sequestration of all components of the acid gas stream, including an

assessment of the injection reservoir in terms of permanence of sequestration, any potential

leakage, and mitigation and management strategies that AltaGas has implemented to ensure

that there are no potential leaks.

3.6.5 TYPE OF GAS PROCESSING FACILITY

The Bantry Sour Gas Processing Plant is an existing sour gas processing plant that commenced

operations prior to July 1, 2007 that previously operated a sulphur recovery unit and was later

retrofitted in 2008 to include acid gas injection. Additionally, the Bantry Sour Gas Processing

Plant is not regulated under the Specified Gas Emitters Regulation and is therefore eligible to

generate offsets under the Acid Gas Injection Protocol.

3.6.6 CO-MINGLING OF ACID GAS FROM OTHER FACILITIES

The Bantry Sour Gas Processing Plant has the capability to receive diluted acid gas or raw sour

gas from the nearby Princess Sour Gas Processing Facility (also owned by AltaGas) as a

dedicated pipeline connects the two facilities. However, no acid gas was received from Princess

Sour Gas Processing Plant in 2010.

The Princess Sour Gas Processing Plant is not currently regulated under the Specified Gas

Emitters Regulation and therefore the portion of acid gas received from Princess (if any) would



still be eligible to generate offsets under the Quantification Protocol for Acid Gas Injection

Projects (Version 1, May 2008) Acid Gas Injection Protocol, in the same manner as acid gas

generated from the Bantry facility and its connected gathering systems.

3.6.7 QUANTIFICATION OF REDUCTIONS

The quantification of reductions achieved by this project is achieved by actual measurement and

monitoring, as outlined in section 5.0 of this Offset Project Plan.

3.6.8 OFFSET ELIGIBILITY REQUIREMENTS

This project meets the requirements for offset eligibility as specified in the applicable regulation

and guidance documents for the Alberta Offset System. In particular:

• The acid gas injection program began January 12, 2009, which is after the specified start

date of January 1, 2002. The project start date is demonstrated by the commissioning of

the acid gas injection system;

• The Project proponent intends to claim offsets for an initial period of 8 years, as specified

in the Alberta Offset System Offset Credit Project Guidance Document. The end of the

initial Project offset crediting period is thus set to December 31, 2016; and

• Ownership of the emission reductions has been established. No other entity is claiming

offsets from the GHG reductions realized at the Bantry sour gas processing facility due to

the implementation of the acid gas injection project. Offsets created from the specified

reduction activity have not been created, recorded or registered under any other offset

system or offsets registry for the same time period.

• The acid gas injection system installed at the Bantry sour gas processing facility results in

real GHG reductions that are not the result of a shutdown or cessation of an activity. The

emission reductions are related to the facility’s operations and are quantifiable using the

government approved protocol based on metered and measured data.

• The GHG emission reductions created as a result of the acid gas injection project at the

Bantry sour-gas processing plant are surplus to any regulation.

4.0 IDENTIFICATION AND JUSTIFICATION OF BASELINE

The baseline condition for projects applying the Quantification Protocol for Acid Gas Injection

Projects (Version 1, May 2008) is defined as the mass of carbon dioxide that would be released

to the atmosphere during incineration of the tail gas (acid gas) from a Liquid Redox Process or

Multi-Stage Claus unit at a natural gas processing facility or from the direct incineration of this

acid gas stream. Additionally, the emissions associated with fuel gas consumption to operate the

Liquid Redox Process or Multi-Stage Claus unit, or other sulphur recovery process and the tail

gas incinerator would be included in the baseline emissions.

The baseline scenario for this protocol is dynamic as the volume of acid gas injected would be

expected to change materially from year to year.



The Acid Gas Injection Protocol also contains a flexibility mechanism that allows for the use of an

alternative baseline sulphur treatment technology as described below.

“Project developers may use an alternative sulphur recovery technology than the Claus and

Liquid Redox technologies described in this protocol to quantify the baseline. The use of an

alternate technology would be acceptable if a different type of sulphur recovery technology is

assessed as the preferred baseline scenario or is already installed and operational at the project

site. The developer must justify that the chosen methodology for calculating emissions from the

alternate technology is based on engineering designs or one year or more of operational data

and provides an equivalent or more conservative estimate of baseline emissions.1”

Therefore, the baseline identified for the AltaGas Bantry Acid Gas Injection Project was the

continued use of the Xergy SRU that had been in operation at the site since 2002. This baseline

is justified on the basis that the Bantry facility had operated the pre-existing sulphur treatment

unit operating prior to the implementation of the acid gas injection project. The most likely

alternative was the continued operation of the Xergy unit or the implementation of a similar SRU

designed to meet the requisite sulphur recovery requirements. The baseline was selected as the

continued operation of the Xergy unit in order to utilize measured data to the extent possible

rather than a theoretical design.

As such, the baseline is defined by the mass of CO2 that would have been vented to the

atmosphere following the incineration of the tail gas stream from the SRU and by the

consumption of fuel gas to operate the tail gas incinerator and the SRU. This baseline includes

direct emissions from venting of CO2 from the incinerator stack that was originally contained in

the acid gas and direct emissions from fuel gas consumption to operate the SRU and to operate

the incinerator unit.

1 Alberta Offset System Quantification Protocol for Acid Gas Injection Projects.

http://environment.gov.ab.ca/info/library/7961.pdf



5.0 QUANTIFICATION OF EMISSION REDUCTIONS

5.1 PROCESS DESCRIPTION

Quantification of the reductions, removals and reversals of relevant sources and sinks of

emissions (SS’s) for each of the greenhouse gases was completed using the methodologies

outlined in Section 2.5 of the Acid Gas Injection Protocol.

Under the baseline condition defined in the Acid Gas Injection Protocol two SS’s are included in

the quantification of baseline emissions related to the operation of a sulphur recovery unit,

namely SS B5a ‘Liquid Redox Process’ and SS ‘B5b Multi-Stage Claus Unit.’ Since the previous

sulphur recovery unit at the Bantry gas plant was an Xergy unit, the baseline emissions from the

operation of the Xergy SRU are herein referred to as ‘SS B5 Sulphur Recovery Unit’ to replace

the above mentioned SS5a and SS5b defined in the Acid Gas Injection Protocol.

Under the project condition defined in the Acid Gas Injection Protocol there are three sources

that DO NOT apply to this Project, which are outlined below:

Emissions Gas Dehydration and Compression = emissions under SS P6 Acid Gas

Dehydration and Compression

Emissions Injection Unit Operation = emissions under SS P9 Injection Unit Operation

Emissions Recycled Gas = emissions under SSP 10 Recycled Acid Gas

The acid gas injection system only utilizes an electric compressor and no other equipment,

therefore there are no direct GHG emissions from the operation of the AGI system as no fossil

fuels are combusted to operate the system. Therefore SS’s ‘P6 Acid Gas Dehydration and

Compression’ and ‘P9 Injection Unit Operation’ were not included.

The SSR P10 for Recycled Gas was not included as there are no natural gas production wells in

the Nisku Formation as concluded by ERCB Approval No. 11200 and therefore no acid gas is

recycled from the injection formation.



The following three equations serve as the basis for calculating the emission reductions from the

comparison of the baseline and project conditions:

Where:

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

Emissions Fuel Extraction and Processing = emissions under SS B9 Fuel Extraction /

Processing

Emissions Sulphur Recovery Unit = emissions under SS B5 Sulphur Recovery Unit

Emissions Incineration = emissions under SS B6 Incineration

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

Emissions Fuel Extraction and Processing = emissions under SS P11 Fuel Extraction /

Processing

Emissions Upset Flaring = emissions under SS P8 Upset Flaring

The details of the parameters used in the above equations are outlined in the Acid Gas Injection

Protocol and discussed in Section 5 of this report.

Note that densities in the Protocol are reported at 0°C and 101.325 kPa. Project calculations use

densities at 15°C and 101.325 kPa so as to maintain consistency with metered volumes

corrected to these conditions.

Emission Reduction = Emissions Baseline – Emissions Project

Emissions Baseline = Emissions Fuel Extraction and Processing + Emissions Sulphur Recovery Unit

+ Emissions Incineration

Emissions Project = Emissions Fuel Extraction and Processing + Emissions Upset Flaring



5.2 Data Sources

As Table 5.3.1 demonstrates, the data required for calculation of the emission reduction

generated by the Project consists of the following:

• Volume of acid gas produced and injected in the project condition;

• Composition of acid gas (% CO2, % CH4, % H2S and % trace compounds);

• Volume of acid gas flared in the project condition;

• Volume of fuel gas consumed to supplement flaring in the project condition;

• Volume of fuel gas consumed to operate the SRU in the baseline condition.

• Volume of fuel gas consumed to operate the tail gas incinerator in the baseline condition;

• Composition and higher heating value of fuel gas (sales gas) used at Bantry;

The specific methods of quantification for the above data sources are presented in the following

section.

5.3 QUANTIFICATION PLAN

Quantification of the emission reductions generated by the project will be conducted using a

customized excel Quantification Calculator, developed by Blue Source Canada according to the

Acid Gas Injection Protocol. The general methods of quantification for the required data listed

above are as follows:

• Volume of acid gas injected – The volume of acid gas injected is determined based on

the difference between the volume of acid gas produced and the volume of acid gas

flared.

The volumes of acid gas produced at Plant 1 and at Plant 2 are metered separately (FE-

401 and FE-2502, respectively) and summed to determine the total volume of acid gas

produced. These meters are connected to the AltaGas PROMET data management

system and metered volumes are uploaded automatically once per day as part of the

plant’s daily production report. Note that in 2010 the wells at Plant 1 were shut in. No

acid gas was produced by Plant 1 and Meter FE-401 was not in operation during 2010.

The total volume of acid gas flared is determined from three meters: the acid gas

slipstream meter (FE-2502A) and the diluted acid gas sent to the low pressure acid gas

flare (FE-4046) are added together and the metered volume of fuel gas (FE-4044) added

to dilute the acid gas sent to flare via FE-4046 is subtracted from that sum (FE-2502A +

FE-4046) to obtain the total volume of acid gas flared. All three of these meters are



connected to the AltaGas PROMET data management system and metered volumes are

uploaded automatically once per day to meet ERCB reporting requirements.

The monthly volumes of acid gas injected are calculated based on the difference between

the volumes of acid gas produced (FE-401 + FE-2502) minus the volume of acid gas

flared (FE-2502A + FE4046 - FE-4044). Direct metering and daily automatic uploading of

recorded data ensures the accuracy of the injected volumes.

• Composition of acid gas – The composition of acid gas is measured monthly by a third

party laboratory. The composition is reported in terms of the volume percentage of

hydrogen sulphide, carbon dioxide, methane and other trace compounds contained in the

acid gas. The monthly percentage of CO2 and methane are entered directly into the

Quantification Calculator to determine the baseline and project emissions from

incineration and upset flaring, respectively.

• Volume of acid gas flared in the project condition – flaring of acid gas is required

during upset conditions or during system maintenance to upstream gas processing

equipment. Direct GHG emissions result from the release of the carbon dioxide contained

in the acid gas. The volume of acid gas flared is measured continuously and recorded

electronically in the PROMET data management system via daily data uploads. The total

volume of acid gas flared is determined based on the sum of volumes recorded from

meters FE-2502A and FE-4046, less the volume of fuel gas metered by FE-4044 (that is

used to dilute the acid gas sent to flare and included in the measurements of FE-4046).

The total volume of acid gas flared is summed on a monthly basis and entered into the

Quantification Calculator.

• Volume of fuel gas consumed to supplement flaring in the project condition –

flaring of acid gas may be required during upset conditions or during system maintenance

to upstream processing elements. GHG emissions would result from the combustion of

natural gas to supplement the flaring of acid gas to ensure safe destruction of hydrogen

sulphide. The volumes of natural gas used to supplement flaring are measured

continuously and recorded using three different meters (FE-206, FE-4044 and FE-2501).

The volume of fuel gas metered by FE-206 is recorded manually in daily operator

workbooks at the plant and summed on a monthly basis for reporting to the production

accounting department. The volumes of fuel gas metered by FE-4044 and FE-2501 are

recorded electronically and data is automatically uploaded on a daily basis to the

PROMET data management system. The total volume of fuel gas used to supplement the

flaring of acid gas is calculated on a monthly basis as the sum of the three metered

values and entered into the Quantification Calculator.

• Volume of fuel gas consumed to operate the sulphur recovery unit in the baseline

condition – fuel gas would have been consumed to operate the salt bath heater that is

used to heat the reactants that enter the SRU in the baseline condition.

o The volume of fossil fuels consumed by the SRU was estimated from design

documents based on equipment ratings in kilowatts (kW) for the salt bath heater

according to the following formula obtained from the Canadian Association of



Petroleum Producers (CAPP) Guide for Calculating Greenhouse Gas Emissions

(April, 2003) Example 2 (page 12):2

1) Vol. Fuel Gas = (kW Rating) *(Op. Hours) / (HHV fuel gas * Eff.)

Where,

kW Rating = design fuel consumption rate of salt bath heater, equal to 219kW as

per AENV Approval #9821-02-00.

Op. Hours = estimated operating hours of SRU (assumed 8736 hours or 4 days of

downtime per quarter for catalyst changes to be overly conservative compared to

the typical 2 days of downtime)

HHV fuel gas = Average annual Higher Heating Value (HHV) of fuel gas as

measured by third party lab analyses

Eff. = Heater efficiency (assumed to be 100% for conservativeness compared to a

typical heater of <375kW with efficiency of 70% as per the referenced CAPP

document)

• Volume of fuel gas consumed to operate the tail gas incinerator in the baseline

condition – fuel gas would have been required to incinerate tail gas (primarily CO2, SO2

and trace amounts of H2S) from the sulphur recovery unit in the baseline to ensure

complete destruction of hydrogen sulphide.

o The volume of fuel gas (sales gas) required to incinerate the tail gas is estimated

based on historical metered fuel gas consumption from 2008. To develop a

reasonable estimate of the theoretical incinerator fuel gas consumption the total

fuel gas consumed over twelve months in 2008 was divided by the total volume of

acid gas produced at Bantry during 2008.

This average fuel gas consumption per unit of acid gas from 2008 was then used

to extrapolate the annual fuel gas consumption that would have occurred in the

baseline to operate the incinerator based on the annual volume of acid gas

produced in the project condition. It was assumed in this theoretical calculation

that the composition of the tail gas would be consistent as the sulphur recovery

unit and tail gas incinerator units would both have been operated in a consistent

manner to meet minimum sulphur recovery levels (e.g. emit less than 2 tonnes

sulphur per day) and to maintain a minimum stack top temperature of 825°C (as

per Alberta Environment approval No. 9821-02-00), respectively. As such, it is

reasonable to assume that the ratio of incinerator fuel gas consumption per unit of

acid gas treated by the SRU would be consistent.




The following formula summarizes the estimation method used to determine the

baseline fuel gas requirements for tail gas incineration.

2) Vol. Fuel Gas Incinerator = [Vol. Fuel Gas 2008 / Vol. Acid Gas 2008]* Vol. Acid

Gas Project

Where,

Fuel Gas Incinerator = Estimated volume of fuel gas consumed in the baseline

condition under SS B6 Incineration.

Vol. Fuel Gas 2008 = Volume of fuel gas consumed by incinerator over a 12 month

period in 2008. Note that the volumes of fuel gas used in this equation must be at

reference conditions of 15°C and 1 atmosphere. The conversion from actual ‘as-

metered’ volumes to reference conditions is shown in equation 3, below.

Vol. Acid Gas 2008 = Volume of acid gas treated by SRU over the same 12 month

period in 2008

Vol. Acid Gas Project = Volume of acid gas produced in the project condition.

In order to convert the as-metered 2008 volumes of incinerator fuel gas

(measured in 100 ft3) into volumes at standard conditions of 15°C and 1

atmosphere (to correspond with the acid gas flow meters which are already

compensated for pressure and temperature, as required by ERCB Directive 17) a

modified version of the ideal gas law is used, as shown, below. The pressure and

temperature of the fuel gas metered to the incinerator are consistent as the fuel

gas line is connected to the main plant fuel gas distribution line. Additionally, this

meter is no longer in use as the tail gas incinerator has been decommissioned.

3) Vol. Fuel Gas 2008 = [As-metered Vol. Fuel Gas 2008] * [P actual / P reference]*[T

reference / T actual] *[z reference / z actual] *Unit Conversion

Where,

Vol. Fuel Gas 2008 = Volume of fuel gas at standard conditions of 15°C and 1

atmosphere used in Equation 2)

As-metered Vol. Fuel Gas 2008 = volume of fuel gas metered at the incinerator at

actual conditions

P actual = Pressure at as-metered conditions at the fuel gas main header = 886 kPa

absolute (785 kPa gauge)

P reference = Pressure for reference conditions = 101.325 kPa absolute

T reference = Temperature for reference conditions = 288.15 Kelvin (15°C)

T actual = Temperature at as-metered conditions at the fuel gas main header =

303.15 Kelvin (30°C)



z reference = Compressibility Factor for fuel gas at reference conditions of 15°C and

1atm = 0.998

z actual = Compressibility Factor at as-metered conditions at the fuel gas main

header = 1

Unit Conversion = [0.0001 (Million ft3) / 100 ft3] * [28.3 e3m3 / (Million ft3)]

• Composition of fuel gas used at Bantry – The monthly composition of fuel gas,

measured by a third party lab, is averaged annually to develop a project specific CO2

emission factor based on the carbon content of the sales gas that is used at Bantry for

flaring of acid gas (project condition), operation of the SRU (baseline) and tail gas

incineration (baseline). The sales gas (pipeline quality natural gas) composition is

relatively consistent as it is purchased via a buyback line that has to meet natural gas

pipeline specifications. The calculation methodology for the project specific fuel gas CO2

emission factor was based on the Canadian Association of Petroleum Producers (CAPP)

Guide for Calculating Greenhouse Gas Emissions (April, 2003) Equation 3 (page 12),3

and is given below. The equation has been modified to include hexane and heptanes for

increased accuracy. The project specific CO2 emission factor represents a slight

deviation from the Acid Gas Injection Protocol, which references Environment Canada

emission factors, but this approach increases the accuracy of the GHG emission

reduction claim by using site-specific sales gas analyses.

4) [(a + 2b + 3c + 4d + 5e + 6f + 7g + h) x 44.01] / 23.64 = kg CO2/m3 fuel

combusted Where, a through h = mole fractions of natural gas components, where a = C1, b=C2, c=C3, etc., and h = CO2 44.01 = molecular weight of CO2 23.64 = volume in m3 occupied by one kmole of gas at 15°C and 101.325 kPa

Detailed descriptions of the measurement methods for the required data are provided in Table

5.3.1 below.




Table 5.3.1 – Quantification Methods

Required data Project-specific

data

Measurement method Measurement Frequency Meter ID Quantification

Method

Volume of acid

gas injected

Volume of acid

gas injected

Direct metering of the volume of acid

gas produced at each of Plant 1 and

Plant 2 and the volume of acid gas

flared to determine the volume

injected (acid gas produced minus

flared).

Note that in 2010 Plant 1 did not

produce acid gas due to well shut-

ins and meter FE-401 was not

operational.

Continuous metering. FE-401 +

FE-2502

Manual entry of

monthly totals into

the Quantification

Calculator.

Composition of

injected acid gas

% Volume of

CO2, H2S,

Methane and

trace compounds

in the acid gas

Monthly sampling and gas analysis

by a third party laboratory.

Monthly sampling and lab

analyses N/A

Manual entry of

monthly average

into the

Quantification

Calculator.

Volume of acid

gas flared in the

project condition

Volume of acid

gas flared during

upset flaring.

Direct metering. Continuous metering.

FE-

2502A +

FE-4046 –

FE-4044

Manual entry of

monthly totals into

the Quantification

Calculator.

Volume of fuel

gas consumed for

upset flaring in the

project condition

Volume of sales

gas consumed to

supplement acid

gas flaring during

upset flaring.

Direct metering. Continuous metering.

FE-206 +

FE-2501 +

FE-4044

Manual entry of

monthly totals into

the Quantification

Calculator.

Volume of fuel

gas consumed to

operate the SRU

in the baseline

Volume of

natural gas

consumed to

operate the SRU

salt bath heater

Calculated from engineering design

documents containing the equipment

rating for the fuel gas-fired salt bath

heater that pre-heats acid gas to

facilitate sulphur recovery.

Reconciliation of equipment

rating from permits and

engineering drawings

N/A

Manual entry of

monthly totals into

the Quantification

Calculator.



Volume of fuel

gas consumed to

incinerate tail gas

from the SRU in

the baseline

condition

Volume of

natural gas

consumed to

supplement the

tail gas

incinerator in the

baseline

condition

Estimated based on the ratio of

metered fuel gas consumed per unit

of acid gas produced at Bantry

during 12 months of operation in

2008. This ratio is then used to

estimate the fuel gas consumption in

the baseline by multiplying the ratio

(fuel gas per unit of acid gas) by the

volume of acid gas produced in the

project condition.

Continuous metering of

volume of acid gas produced

in the project condition and,

previously in 2008, continuous

measurement of fuel gas to the

incinerator (FQI-801) the year

prior to decommissioning.

FQI-801 +

FE-401 +

FE-2502

Manual entry of

monthly total into

Quantification

Calculator.

Composition of

fuel gas used on-

site at Bantry for

flaring, SRU

operation and tail

gas incineration

Volume % of

each carbon-

containing

compound in the

sales gas and

HHV of sales

gas.

Monthly third party lab analyses are

used to determine an annual

average composition of fuel gas.

The higher heating value of the fuel

gas was also averaged to determine

an average HHV for use in the

calculation of fuel gas consumption

to operate the SRU (SS B5).

Monthly sampling and lab

analyses N/A

Manual entry of

data collected into

the Quantification

Calculator.



5.4 MONITORING AND QUALITY ASSURANCE/QUALITY CONTROL (QA/QC) PLAN

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. 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 by the AltaGas metering systems that are automatically entered

into the PROMET database; and

• Manual data collection reported in third party laboratory analysis reports and metered

data that is reported in operator logbooks

The specifics of the Monitoring and QA/QC plan are discussed in the following sections.

5.4.1 METERING MAINTENANCE AND CALIBRATION

Monitoring and QA/QC of the metering systems used at the AltaGas Bantry Sour Gas

Processing Plant include a maintenance and calibration program designed to ensure the

accuracy of data collection. The details of maintenance and calibration for each meter used in

the collection of data for the emission reduction calculations are provided in Table 5.4.1.

Table 5.4.1 – Metering Maintenance and Calibration Details

Project Specific Data Meter ID Meter

Make/Model

Maintenance

Schedule

Calibration

Schedule

Accuracy

Rating

Volume acid gas produced at

Plant 1. FE-401

Daniel Jr -

orifice meter

N/A

This meter was not in operation in 2010

because Plant 1 did not produce acid gas due

to well shut-ins.

Volume acid gas produced at

Plant 2. FE-2502

Daniel Jr -

orifice meter Annually Annually +/-0.25%

Volume of acid gas flared

during upset flaring.

FE-

2502A +

FE-4046

- FE-

4044

Reco Jr -

orifice meter

+ Daniel Sr -

orifice meter

Annually Annually +/-0.25%

Volume of natural gas

consumed to supplement

acid gas flaring in the project

condition.

FE-206 +

FE-2501

+ FE-

4044

Rotameter +

Daniel Sr. -

orifice meter

Annually Annually +/-0.25%


consumed to operate the

SRU in the baseline.

N/A N/A N/A N/A N/A




consumed to incinerate tail

gas from the SRU in the

baseline.

FQI-801 Roots Meter

N/A

This meter no longer operates since the tail

gas incinerator was decommissioned in 2009.

Acid gas composition.

3rd

Party

Lab

Analyses

N/A N/A N/A N/A

Fuel gas composition and

higher heating value

3rd

Party

Lab

Analyses

N/A N/A N/A N/A

5.4.2 ALTAGAS PROMET DATA MANAGEMENT SYSTEM

The PROMET data management system is monitored by field data capture coordinators that

handle the collection of information from each of AltaGas’ gas processing facilities in order to

comply with ERCB and Alberta Environment reporting requirements. This data is used to

generate daily production reports used internally by AltaGas operators and to generate monthly

and annual reports for the ERCB. The data capture for this offset project is handled in the same

fashion using the PROMET system to house the continuously metered data, with each meter

assigned a specific name, which is used to identify all data points associated with that meter.

For each meter that is connected to PROMET, the recorded data is uploaded automatically

every day at 10am to generate a daily production report for the facility. Printouts of the daily

production reports are stored at the plant in a binder and the electronic data from PROMET can

be downloaded as needed in excel format.

The following data was obtained from PROMET:

• Volume acid gas produced at Plant 1 (FE-401) – note this meter was not in operation in 2010

because Plant 1 did not produce acid gas due to well shut-ins.

• Volume acid gas produced at Plant 2 (FE-2502)

• Volume of acid gas flared (FE-2502A + FE-4046 – FE-4044)

• Volume of fuel gas used to supplement acid gas flaring (FE-2501 + FE-4044)

QA/QC procedures for the above PROMET data consisted of checking the annual or monthly

totals entered in the Quantification Calculator with the totals from raw data downloaded from

PROMET.

5.4.3 MANUAL DATA COLLECTION



The quantification of several sources and sinks of emissions for the Bantry Acid Gas Injection

Project relied on manual data collection. The following data was collected manually:

• Monthly composition of acid gas

• Monthly composition and higher heating value of fuel gas used at Bantry

• Daily volume of fuel gas (purge gas) used to supplement acid gas flaring (FE-206)

• Volume of fuel gas previously consumed to operate the now decommissioned tail gas

incinerator in 2008 (FQI-801)

• Equipment rating for decommissioned salt bath heater used as part of the sulphur

recovery process (209kW)

The monthly compositions of acid gas were manually entered into the Quantification Calculator

to calculate baseline emissions under SS B6 and project emissions under SS P8. QA/QC will

consist of checking the original values in the lab reports against the values entered into the

Quantification Calculator.

The monthly compositions and higher heating values of fuel gas used at Bantry were averaged

to develop a project specific CO2 emission factor for fuel gas combustion used to calculate

baseline emissions under SS B5 and SS B6 and project emissions under SS P8, as described

above. The average higher heating value of fuel gas at Bantry is used in the calculation of

baseline emissions under SS B5. QA/QC will consist of checking the original values in the lab

reports against the values entered into the Quantification Calculator.

The daily volume of fuel gas (purge gas) used to supplement acid gas flaring (FE-206) is

manually recorded in operator workbooks. The meter totalizer readings were used to determine

the annual fuel gas consumption by subtracting the first reading of the year from the last reading

of the year. This annual total was entered into the Quantification Calculator and added to the

totals from meters FE-2501 and FE-4044 to determine the total fuel gas consumption for acid

gas flaring.

The volume of fossil fuels consumed to incinerate the tail gas from the sulphur recovery unit

was estimated based on metered fuel gas consumption per unit of acid gas that was produced

at Bantry during the twelve months prior to decommissioning of the unit in 2008. The daily

volume of fuel gas consumed by the tail gas incinerator in 2008 was recorded manually in daily

meter reading log sheets and transcribed into daily operator workbooks. The monthly workbook

summaries were used to calculate the total volume of fuel gas consumed per unit of acid gas in

2008. The volume of acid gas produced in 2008 was determined from PROMET data for meters

FE-401 and FE-2502, as described above. The original hardcopies of the incinerator fuel gas

totalizer meter readings for the first and last days of 2008 were used to confirm the accuracy of

the records in the daily workbooks that were entered into the Quantification Calculator.

The volume of fossil fuels consumed to operate the sulphur recovery unit was estimated based

on the rated natural gas consumption of the relevant equipment. This equipment rating was



checked against facility drawings / permits and the annual fuel gas totals entered into the

Quantification Calculator were checked against the calculated soft copies.

Manual checking will be conducted on an annual basis by Blue Source Canada and will consist

of:

• Reconciliation of values in the calculator with hard-copy records or electronic data;

• Comparison with data from other time periods to identify any major discrepancies

(“reality checking”); and

• Recalculation of selected values to ensure that the Quantification Calculator remains

accurate.

5.4.4 RECORD KEEPING

Record keeping practices for the project consist of:

• Electronic recording of values of logged primary parameters for each measurement

interval;

• Printing of monthly back-up hard copies of all logged data;

• Written logs of operations and maintenance of the project system including notation of all

shut-downs, start-ups and process adjustments;

• Retention of copies of logs and all logged data for a period of 7 years; and

• Keeping all records available for review by a verification body.

6.0 REPORTING OF EMISSION REDUCTIONS

GHG Emission reductions achieved through this Project will be claimed starting January 12,

2009 through to December 31, 2016. After the initial GHG emission reductions claim, emission

reductions will be claimed on an annual basis and quantified in accordance with the calculation

methodology described in the Quantification Protocol for Acid Gas Injection Projects (Version 1,

May, 2008). Emission reductions will be verified by a third-party verifier according to the

Guidance Document provided by Alberta Environment.

altagas bantry agi offset project report v2 february 28 2011

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