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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.
AltaGas Bantry Acid Gas Injection Project Report February, 2011
Blue Source Canada ULC Page 2
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
AltaGas Bantry Acid Gas Injection Project Report February, 2011
Blue Source Canada ULC Page 4
Appendix A
OFFSET PROJECT PLAN:
ALTAGAS BANTRY ACID GAS INJECTION OFFSET PROJECT
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:
ALTAGAS BANTRY ACID GAS INJECTION OFFSET PROJECT
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
Bantry Acid Gas Injection Offset Project February, 2011
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.
Bantry Acid Gas Injection Offset Project February, 2011
Prepared By Blue Source Canada ULC Page 2
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.
Bantry Acid Gas Injection Offset Project February, 2011
Prepared By Blue Source Canada ULC Page 3
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
Prepared By Blue Source Canada ULC Page 4
Figure 3.1 – Bantry Site Plan
Acid Gas Injection Offset Project Plan February, 2011
Prepared By Blue Source Canada ULC Page 5
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.
Acid Gas Injection Offset Project Plan February, 2011
Prepared By Blue Source Canada ULC Page 6
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.
Bantry Acid Gas Injection Offset Project February, 2011
Prepared By Blue Source Canada ULC Page 7
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.
Acid Gas Injection Offset Project Plan February, 2011
Prepared By Blue Source Canada ULC Page 8
Figure 3.2: Bantry Sulphur Recovery Unit Process Flow Diagram
Acid Gas Injection Offset Project Plan February 2011
Prepared By Blue Source Canada ULC Page 9
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.
Bantry Acid Gas Injection Offset Project February, 2011
Prepared By Blue Source Canada ULC Page 10
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
Bantry Acid Gas Injection Offset Project February, 2011
Prepared By Blue Source Canada ULC Page 11
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.
Bantry Acid Gas Injection Offset Project February, 2011
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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
Bantry Acid Gas Injection Offset Project February, 2011
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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.
Bantry Acid Gas Injection Offset Project February, 2011
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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
Bantry Acid Gas Injection Offset Project February, 2011
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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.
Bantry Acid Gas Injection Offset Project February, 2011
Prepared By Blue Source Canada ULC Page 16
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
Bantry Acid Gas Injection Offset Project February, 2011
Prepared By Blue Source Canada ULC Page 17
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
Bantry Acid Gas Injection Offset Project February, 2011
Prepared By Blue Source Canada ULC Page 18
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
Bantry Acid Gas Injection Offset Project February, 2011
Prepared By Blue Source Canada ULC Page 19
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.
2 http://membernet.capp.ca/raw.asp?NOSTAT=YES&dt=PDF&dn=55904
Bantry Acid Gas Injection Offset Project February, 2011
Prepared By Blue Source Canada ULC Page 20
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)
Bantry Acid Gas Injection Offset Project February, 2011
Prepared By Blue Source Canada ULC Page 21
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.
3 http://membernet.capp.ca/raw.asp?NOSTAT=YES&dt=PDF&dn=55904
Acid Gas Injection Offset Project Plan February, 2011
Prepared By Blue Source Canada ULC Page 22
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.
Acid Gas Injection Offset Project Plan February, 2011
Prepared By Blue Source Canada ULC Page 23
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.
Acid Gas Injection Offset Project Plan February, 2011
Prepared By Blue Source Canada ULC Page 24
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%
Volume of natural gas
consumed to operate the
SRU in the baseline.
N/A N/A N/A N/A N/A
Acid Gas Injection Offset Project Plan February, 2011
Prepared By Blue Source Canada ULC Page 25
Volume of natural gas
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
Acid Gas Injection Offset Project Plan February, 2011
Prepared By Blue Source Canada ULC Page 26
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
Acid Gas Injection Offset Project Plan February, 2011
Prepared By Blue Source Canada ULC Page 27
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.