Ember Resources Instrument Air Conversion at Strathmore Phase 1 July 2018 Offset Project Plan Form: Ember Resources Instrument Air Conversion at Strathmore Phase 1 Project Developer: Ember Resources Inc. Prepared by: Ember Resources Inc. Date: July 31, 2018
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Ember Resources Instrument Air Conversion at Strathmore Phase 1
July 2018
Offset Project Plan Form:
Ember Resources Instrument Air Conversion at Strathmore Phase 1
Project Developer:
Ember Resources Inc.
Prepared by:
Ember Resources Inc.
Date:
July 31, 2018
Ember Resources Instrument Air Conversion at Strathmore Phase 1
July 2018
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Table of Contents
1.0 Contact Information .............................................................................................. 3 2.0 Project Scope and Site Description .......................................................................... 3
3.3 Quantification Plan .............................................................................................. 12 3.3.1 Calculation of Baseline Emissions .......................................................................... 13 3.3.2 Calculation of Project Emissions ............................................................................ 14 3.3.3 Sample Calculation .............................................................................................. 15
3.4 Monitoring Plan ................................................................................................... 17 3.5 Data Management System.................................................................................... 19
Table 1 - Project Contact Information ..................................................................................... 3 Table 2 - Project Information ................................................................................................. 3 Table 3 - Assessment of Protocol Applicability Criteria ............................................................... 6 Figure 1 – Baseline Sources and Sinks of Emissions .................................................................. 9 Figure 2 – Project Sources and Sinks of Emissions .................................................................. 10 Table 4 - Included Sources and Sinks and Quantification Methods ............................................ 10 Table 5 - Data Sources Used in the Quantification of Baseline Emissions ................................... 13 Table 6 - Data Sources Used in the Quantification of Project Emissions ..................................... 14 Table 7 - Example GHG Emission Reduction Calculation .......................................................... 17 Table 8 - Sample Monitoring Plan ......................................................................................... 18 Figure 3 – Data Flow for the Project...................................................................................... 20
Ember Resources Instrument Air Conversion at Strathmore Phase 1
July 2018
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1.0 Contact Information
Table 1 - Project Contact Information
Project Developer Contact Information Additional Contact Information
Ember Resources Inc. Ember Resources Inc.
Steve Gell, P.Eng
Dana Sorensen
The Devon Tower, 800 – 400 3rd Avenue SW The Devon Tower, 800 – 400 3rd Avenue SW
Ember Resources Instrument Air Conversion at Strathmore Phase 1
July 2018
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in Alberta?
Project boundary The Strathmore Phase 1 compressor station is located at 09-27-024-25
W4M, near the town of Strathmore, Alberta. The instrument air
conversion project is entirely located within the compressor station
lease site and consists of an air compressor package, auxiliary
equipment and piping to distribute compressed air to each unit
operation and process building at the site. The project boundary
includes all of the pneumatic devices that use compressed air (which
previously used pressurized natural gas for process control). The
Strathmore Phase 1 facility is connected to the Alberta electricity grid
and the air compressors use a small amount of electricity.
Ownership Ember Resources owns 100% of the Strathmore 09-27-024-25W4
facility and is the sole owner of the emission offsets from the instrument
gas to air conversion project. No other party could reasonably claim
entitlement to any other benefit associated with the emission offsets.
2.1 Project Description
This Project achieves greenhouse gas emission reductions through the installation and
operation of an instrument air system at Ember Resources’ Strathmore Phase 1 natural gas
compression facility, located at 09-27-024-25W4, near Strathmore, Alberta, Canada. The air
compressor and related infrastructure was installed as a retrofit to the existing natural gas-
driven pneumatic instrumentation systems to eliminate venting of instrument gas (fuel gas),
which contains primarily methane.
A small amount of electricity is required to run the air compressor, but the magnitude of the
GHG emissions from this energy input are an order of magnitude smaller than the baseline
methane emissions from operating the existing instrument gas system.
The instrument air conversion project at the Strathmore Phase 1 compressor station involved
the following steps:
Installation of a skid-mounted air compressor package with desiccant air dryers and an
air receiver (pressure vessel that acts as a buffer for air supply) housed in a dedicated
building near the electrical motor control centre (MCC) building. The air compressor
package features dual air compressors operated in a lead-lag configuration (e.g. where
one air compressor runs at any given time and the other provides redundant capacity
and the operator can switch back and forth between compressors during service or
maintenance intervals).
Installation of new above and below ground piping to connect air supply from the air
compressor building to other buildings on the lease that house the sales gas
compressor, booster compressor, glycol dehydrator, inlet separator, and other
equipment.
Completion of piping tie-ins to connect air supply to individual instrumentation and
pumps within or outside each building.
Electrical wiring to connect air compressor motors to the MCC building.
Installation of a dedicated meter run with a flow meter and temperature and pressure
transmitters to measure the flow rate of air at a point downstream of the air dryers.
The instrument air system was integrated with the existing pneumatic gas-driven
instrumentation and controls without altering the function of the natural gas compression,
processing or dehydration equipment at the site. The compressed air simply replaces
pressurized natural gas as the medium that delivers pressure to the pneumatic instrumentation
Ember Resources Instrument Air Conversion at Strathmore Phase 1
July 2018
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and pumps at the site. The operating pressure of the individual instruments is dictated by
manufacturer specifications (e.g. most instruments operate at either 20 or 30-35 psig) and site
specific requirements and the pressure of the air (or gas) supplied to them is regulated to the
appropriate set point. Therefore, the instrument air system is functionally equivalent to the
original instrument gas system as the same level of service (pressure) is provided.
Conditions Prior to Project Implementation
Throughout the oil and gas industry, pressurized natural gas (“instrument gas”) is used to
operate pneumatic instruments in process control applications. Instruments are used to take a
variety of measurements which are then used for process control by relaying a signal to adjust
the position of a valve or other equipment when changes in process conditions have occurred.
Once the pressurized gas has provided the input signal to the instruments, it is vented to the
atmosphere through dedicated process vents, resulting in methane emissions. Methane is a
potent GHG, with a global warming potential (GWP) of 25 times that of carbon dioxide.
Pneumatic instrumentation remains the standard in the oil and gas industry due to its
simplicity, reliability and low cost. Instrument gas is often the preferred source of pressure
(energy) for pneumatic instrumentation systems due to its availability on-site. Fuel gas is
generally supplied to all buildings on a lease to supply heaters, engines and other equipment in
addition to instrumentation.
Due to high capital costs and infrastructure constraints, many older gas processing and
compression facilities have not been upgraded to operate on instrument air and still rely on
instrument gas. At these facilities dedicated process vents exist in each building to ensure that
instrument gas is directed from the instrumentation through piping to the outside of each
building to prevent any accumulation of combustible gas. Venting of instrument gas from these
engineered vents is not a source of fugitive emissions, but is a requirement to safely operate
pneumatic gas-driven equipment and other pressurized devices.
The Strathmore Phase 1 facility was built in the 1970s. Prior to project implementation, natural
gas (referred to as “fuel gas” or “instrument gas”) was used to provide pressure to the
pneumatic control system and was vented to the atmosphere continuously. Fuel gas had been
the preferred medium to operate pneumatic control systems from day one, due to its
availability on-site. Historically, the fuel gas at Strathmore Phase 1 has contained greater than
95% methane by volume, but recent gas analyses have had lower levels of methane as richer
streams of gas have been routed to the facility since 2017.
Instrument gas was not flared at the Strathmore Phase 1 facility as venting was necessary to
avoid putting any back pressure on the instrumentation. Back pressure could cause the
instruments to migrate from intended set points or even possibly to malfunction, which could
result in facility downtime, unsafe conditions or damage to equipment.
The instrument air conversion project was undertaken as a retrofit to an existing gas processing
and compression facility. The retrofitted facilities were all originally designed, constructed and
operated with instrument gas. Therefore, based on past practices, the baseline condition was
the venting of instrument gas to the atmosphere.
The expected lifetime of the instrument air system (air compressors, air dryers, air receiver,
piping and associated infrastructure) is up to 20 years.
2.2 Protocol
For the initial 8-year crediting period from January 1, 2010 to December 31, 2017, which is the
period covered by this offset project plan, the Project will be quantified using the Quantification
Protocol for Instrument Gas to Instrument Air Conversion in Process Control Systems (Version
1.0, October 2009). Effective Jan 1, 2018, as required for the crediting period extension, the
Ember Resources Instrument Air Conversion at Strathmore Phase 1
July 2018
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Project will be quantified using the Quantification Protocol for Greenhouse Gas Emission
Reductions from Pneumatic Devices (Version 2.0, January 25, 2017), but that will be covered in
a new updated offset project plan.
The quantification protocol is applicable to the Ember Resources Instrument Air Conversion at
Strathmore Phase 1 because the Project involved the installation of an instrument air
compressor package and related infrastructure to retrofit an existing gas processing and
compression facility that previously relied on natural gas-driven pneumatic instrumentation
systems for process control. Prior to the instrument air retrofit, all of the process control
equipment at the Strathmore Phase 1 facility was driven by pressurized natural gas (fuel gas),
which resulted in continuous venting of gas (primarily methane) to the atmosphere as part of
normal baseline operations. As part of ongoing operations the instrument air usage will be
measured directly in order to meet the protocol requirements.
The Project will meet the six applicability criteria in the protocol as outlined in the table below.
Table 3 - Assessment of Protocol Applicability Criteria
Criteria Proponent Justification
1. Pneumatic instruments are designed to operate
using a pressurized gas (i.e. 20 or 35 psig for
commercially available devices), regardless of the
gas type. As a result, the instrument air system
must be designed to provide this same level of
pressure that the instrument gas system would
have provided to ensure functional equivalency;
The installation of the instrument air system
did not require any changes to be made to
the operating pressures of individual
instruments. The same pressure signal is
delivered to the instruments regardless of
whether the supply medium is natural gas or
compressed air. The pressure of the supply
medium is regulated down to specific
pressures as required by the instrument
specifications, not the type of pressure
delivery medium. Most instruments operate
at 20 or 30-35 pounds per square inch,
gauge (psig).
2. The Project is a conversion from instrument gas
to instrument air and does not include facilities
originally constructed to use instrument air or
replacements due to end-of-life;
The instrument air conversion was
implemented as a retrofit to the existing
Strathmore Phase 1 gas compression facility
that previously relied on instrument gas
(natural gas) to operate pneumatic
instrumentation systems.
3. To facilitate verification and allow for changes in
the facility, the proponent will develop an inventory
of devices to be maintained annually. Any changes
to the inventory, i.e. devices removed, will impact
net offsets claimed. The list will also help in
determining what fraction of the natural gas used
by pneumatic devices was vented and what fraction
was flared (if applicable);
An inventory of pneumatic devices has been
developed for the Project and this inventory
will be updated periodically. Instrument gas
was not flared in the baseline as all vent
lines were directed to atmosphere for
operational and safety reasons (e.g. to avoid
putting backpressure on the controllers).
Ember Resources Instrument Air Conversion at Strathmore Phase 1
July 2018
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4. The key concept in this applicability criterion is
for the project proponent to inspect and repair
leaks prior to actual metering to reduce and
mitigate risks associated with overestimation of
emissions. Prior to the implementation of the
instrument air system and metering, the project
proponent must demonstrate that the instrument
air system’s piping network has been inspected for
leaks as pursuant to section 8.7 in Directive 60.
The project proponent must develop and implement
a program to detect and repair leaks meeting or
exceeding the CAPP Best Management Practice
(BMP) for Fugitive Emissions Management;
A leak inspection and repair program was
carried out prior to commissioning the
Proejct. Post commissioning, leak inspections
have been performed periodically using
ultrasonic leak detection equipment. During
periods when leak detection surveys have
not been performed, the discount factor has
been used, in accordance with the
quantification methods in the Instrument Air
Protocol.
5. This protocol has been designed for specific use
in natural gas processing plants. However, other
facilities in the oil and gas industry use instrument
gas to provide pressure to pneumatic devices. This
protocol may be applied to projects where existing
gas provides pressure to instrumentation or
Chemical Injection Pumps (CIP), or other types of
equipment.
The Project was implemented and
commissioned at the Strathmore Phase 1
natural gas processing and compression
facility.
6 a. The date of equipment installation, operating
parameter changes or process reconfiguration are
initiated or have effect on the project on or after
January 1, 2002 as indicated by facility records;
The Project was constructed and
commissioned after January 1, 2002. The
project was constructed in December 2009
and crediting began January 1, 2010 after
commissioning of metering equipment.
6 b. The project may generate emission reduction
offsets for a period of 8 years unless an extension is
granted by the Alberta Climate Change Office, as
indicated by facility and offset records.
The Project will claim offsets for a period of 8
years beginning January 1, 2010 and ending
December 31, 2017. A 5-year crediting
period extension has been granted
subsequent to the end of the initial 8-year
crediting period and an updated offset
project plan will be developed.
6 c. Ownership of offsets must be established as
indicated by facility records.
Ember Resources owns 100% of the
Strathmore 09-27-024-25W4 facility and is
the sole owner of the emission offsets from
the instrument gas to air conversion project.
No other party could reasonably claim
entitlement to any other benefit associated
with the emission offsets.
No flexibility mechanisms have been used in the quantification of GHG emission reductions for
this Project.
No deviations were made to the Quantification Protocol for Instrument Gas to Instrument Air
Conversion in Process Control Systems (Version 1.0, October 2009). The Quantification Protocol
for Instrument Gas to Instrument Air Conversion in Process Control Systems is not currently
“flagged”, but the protocol was replaced by the Quantification Protocol for Greenhouse Gas
Emission Reductions from Pneumatic Devices in January 2017. Therefore the Project will cease
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July 2018
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using the Instrument Air Protocol after the end of its initial 8-year crediting period, which ends
December 31, 2017.
2.3 Risks
There are a number of risks that could impact the performance of the Strathmore Phase 1
Instrument Air Conversion Project and a non-exhaustive list of risks has been provided below.
None of these risks are expected to materially impact the Project.
Technical risks
o Data risks – a loss of data caused by a communications system failure or meter
failure could cause the Project to rely on contingent data collection mechanisms.
Given the significant operational history of the Project this risk can be managed
by experienced personnel and the use of conservative estimates based on past
performance, if required.
o Metering failure – the instrument air meter is calibrated annually and is a
common type of meter that Ember technicians and contractors are very familiar
with maintaining for other measurement purposes.
o A power outage, air compressor failure or related equipment failure could lead to
facility blowdowns (venting), downtime or other issues. This is mitigated by using
a lead-lag air compressor configuration, selection of robust equipment and
regular maintenance.
o Instrumentation system leaks resulting in increased air usage. This is mitigated
through periodic air leak inspections or the use of the discount factor provided in
the protocol.
Permanence risks
o There is no risk of a reversal of emissions as GHG emission reductions from this
Project are permanent in nature as they are achieved by a dedicated capital
investment into the installation of an instrument air system at an existing natural
gas processing and compression facility to eliminate the venting of natural gas
from pneumatic instrumentation systems.
o Commodity price/market risks could result in facility shut-ins due to low natural
gas prices or declining production and result in gas production being moved to a
facility that does not have an instrument air system. This risk is mitigated by the
fact that Ember operates a number of other instrument air and vent gas capture
projects at nearby facilities which also reduce or eliminate methane emissions
from pneumatic equipment.
Regulatory risks
o There are currently no regulatory requirements that are expected to impact the
Project. Since the voluntary instrument air conversion eliminated all methane
emissions from pneumatic devices at the facility since 2010, the Project is not
expected to be impacted by future methane regulations.
o Project level additionality, in terms of common practice, is assessed at the
protocol development stage. The Instrument Air Protocol was approved in 2009
and the Project received a crediting period extension in 2018. As of year-end
2017, no other companies appear to be operating instrument air offset projects in
Ember Resources Instrument Air Conversion at Strathmore Phase 1
July 2018
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Alberta. All of these factors support the fact that instrument gas to air conversion
retrofits are not common practice.
o Regulatory additionality is also continuously monitored.
Other Risks
o There are not expected to be any scenarios that could result in double counting of
emission offsets since the Strathmore Phase 1 facility is 100% owned by Ember.
o There are no adverse impacts expected from the Project.
o The Project will not generate any other types of environmental attributes.
o There are no other emission offset projects at the site and the Project is not an
aggregated offset project.
The annual quantity of GHG emission reductions from this Project may vary from year to year
depending on facility downtime, commodity prices and other factors.
3.0 Project Quantification
3.1 Inventory or Sources and Sinks
Sources and sinks of GHG emissions that may be relevant to typical instrument gas to air
conversion projects are outlined in the figures below based on guidance from the Quantification
Protocol for Instrument Gas to Instrument Air Conversion in Process Control Systems (Version
1.0, October 2009). These figures represent general sources and sinks of emissions that are
relevant to most instrument gas to air conversion projects. Sources and sinks of emissions that
are relevant to the Ember Resources Instrument Air Conversion at Strathmore Phase 1 have
been summarized in the subsequent section with rationale provided for the inclusion or
exclusion of each source.
Figure 1 – Baseline Sources and Sinks of Emissions
Ember Resources Instrument Air Conversion at Strathmore Phase 1
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Figure 2 – Project Sources and Sinks of Emissions
The table below summarizes the sources and sinks of emissions that have been included in both
the baseline and project condition for the Project and provides an overview of the quantification
approach.
Table 4 - Included Sources and Sinks and Quantification Methods
Relevant Source, Sink
Controlled. Related, or
affected
Source Method
Baseline
B7 Vented Fuel Gas
Controlled Venting of Natural Gas
Included as this is the major source of emissions for this project type. Estimated based on
measured air flow rates and gas compositions using the gas equivalency formula in the protocol.
B10 Fuel Extraction/ Processing
Related Upstream emissions
associated with extraction and
production of natural gas
Estimated based on the baseline quantity of natural gas vented to the atmosphere (as calculated under B7) and the upstream emission factors for the processing and extraction of
natural gas (provided in the Alberta Environment and Parks Carbon Offset Emission Factors Handbook).
Project
P6 Air compression
Controlled Use of Grid Electricity
Included as incremental electricity is required to operate the air compressors. Estimated based on electrical equipment ratings in kilowatts, operating hours and the Alberta Grid Emission Intensity Factor.
Ember Resources Instrument Air Conversion at Strathmore Phase 1
July 2018
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Based on the specific configuration of the Ember Resources Instrument Air Conversion at
Strathmore Phase 1, a number of the generic sources and sinks identified in the Quantification
Protocol for Instrument Gas to Instrument Air Conversion in Process Control Systems (Version 1.0,
October 2009) were not applicable and were therefore excluded from the quantification. A
summary of the rationale for excluding these sources of emissions has been provided below.
As outlined below, three sources and sinks of emissions were excluded from the quantification
since they are not applicable to the Project, and the equations in the following section reflect these
changes.
B8 Flared/ Combusted Fuel Gas - Not applicable. Excluded as the Strathmore Phase 1
facility did not previously flare instrument gas. Instrument gas was vented directly outside
each building for safety and operational reasons, which is standard industry practice.
P9 Fuel Extraction/ Processing - Not applicable. Excluded as fossil fuels are not used to
operate any of the equipment added to operate the instrument air system.
P7 Air Management System - Not applicable. Excluded as all incremental electricity usage
in the project condition is already captured under P6 Air compression. The air management
system (air receiver) does not consist of any equipment that uses fossil fuels or electricity.
The following section provides an overview of the baseline and project scenarios as well as the
approaches used to quantify greenhouse gas emissions for each of the relevant sources and sinks
identified above.
3.2 Baseline and Project Condition
3.2.1 Baseline Condition
The baseline condition for instrument air projects applying the Protocol is defined as the continued
use of compressed natural gas (fuel gas) to operate pneumatic instrumentation for process control.
Direct greenhouse gas emissions in the baseline condition are a result of the venting of natural gas
from pneumatic instrumentation. The Strathmore Phase 1 facility did not previously flare
instrument gas, both for safety reasons and for operational reasons to prevent backpressure on the
instruments.
The baseline volume of vented instrument gas is determined under source “B7” based on the
metered volumes of compressed air used in the project condition. The equivalent volumes of
instrument gas that would have been required to operate the instrumentation in the baseline are
calculated based on the volumes of air used in the project condition and the gas equivalency factor
outlined in Appendix A of the Protocol. The baseline approach is projection-based.
The baseline emissions associated with the upstream extraction and production of natural gas are
estimated based on the volume of natural gas calculated under B7 and the published emission
factors for fuel extraction and production.
The baseline emissions for the Project will vary depending on process conditions at the facility, gas
compositions (% methane), operating hours and other parameters. Based on recent operating
performance at the Project, the baseline emissions are estimated to be approximately 200
tCO2e/year. Year-to-year variations in operating performance at each sub-project facility are not
unexpected given the dynamic nature of the oil and gas industry.
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3.2.2 Project Condition
The project condition includes the operation of an air compressor and related equipment to supply
all pneumatic equipment at the Ember Resources’ Strathmore Phase 1 natural gas compression
facility, located at 09-27-024-25W4, near Strathmore, Alberta, Canada. The air compressor and
related infrastructure was installed as a retrofit to the existing natural gas-driven pneumatic
instrumentation systems to eliminate venting of instrument gas (fuel gas), which contains primarily
methane.
The completion of the instrument gas to air conversion at the Strathmore Phase 1 compressor
station involved the installation of a skid-mounted air compressor package with desiccant air dryers
and an air receiver as well as the installation of piping to connect the air supply to each process
building on site. The piping was configured with a dedicated meter run, an orifice plate and
pressure and temperature transmitters to measure the air flow rate downstream of the air dryers.
A small amount of electricity is required to run the air compressor, but the magnitude of the GHG
emissions from this energy input are an order of magnitude smaller than the baseline methane
emissions from operating the existing instrument gas system. The electricity used by the air
compressor package is the only source of project emissions. Based on recent operations, this
electricity usage amounts to approximately 1 tCO2e/year.
3.2.3 Functional Equivalence
In both the baseline and the project conditions a pressurized gas, is used to provide a signal to
pneumatic instrumentation. Only the pressure medium has been changed and not the devices
themselves. The operating pressure of the individual instruments is dictated by manufacturer
specifications (e.g. most instruments operate at either 20 or 30-35 psig) and the pressure of the
air (or gas) supplied to them is regulated to the appropriate set point. Therefore, the instrument air
system is functionally equivalent to the original instrument gas system as the same level of service
(pressure) is provided.
3.3 Quantification Plan
The quantification of reductions of relevant sources of greenhouse gases has been completed
according to the methods outlined in Section 2.5 of the Quantification Protocol for Instrument Gas
to Instrument Air Conversion in Process Control Systems (Version 1.0, October 2009). As outlined
previously, certain sources and sinks have been excluded where not applicable, and the equations
below reflect these changes.
The following three equations serve as the basis for calculating GHG emission reductions from the