Ember Resources Instrument Air Conversion at Strathmore Phase 1€¦ · Ember Resources Instrument Air Conversion at Strathmore Phase 1 July 2018 Page 4 of 23 in Alberta? Project

Ember Resources Instrument Air Conversion at Strathmore Phase 1

July 2018

Offset Project Plan Form:


Project Developer:

Ember Resources Inc.

Prepared by:

Ember Resources Inc.

Date:

July 31, 2018


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Table of Contents

1.0 Contact Information .............................................................................................. 3 2.0 Project Scope and Site Description .......................................................................... 3

2.1 Project Description ................................................................................................ 4 2.2 Protocol ............................................................................................................... 5 2.3 Risks ................................................................................................................... 8

3.0 Project Quantification ............................................................................................ 9 3.1 Inventory or Sources and Sinks .............................................................................. 9 3.2 Baseline and Project Condition .............................................................................. 11

3.2.1 Baseline Condition ............................................................................................... 11 3.2.2 Project Condition ................................................................................................. 12 3.2.3 Functional Equivalence ......................................................................................... 12

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

4.0 Project Developer Signature ................................................................................. 22 5.0 References ......................................................................................................... 23

List of Tables and Figures

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


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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

Calgary, Alberta, T2P 4H2 Calgary, Alberta, T2P 4H2

403-698-8983 403-270-0803

http://emberresources.com/ http://emberresources.com/

[email protected] [email protected]

2.0 Project Scope and Site Description

Table 2 - Project Information

Project title Ember Resources Instrument Air Conversion at Strathmore Phase 1

Project purpose and

objectives

The objective of the Ember Resources (“Ember”) Instrument Air

Conversion at Strathmore Phase 1 (“The Project”) was to reduce

greenhouse gas emissions from pneumatic instrumentation by

converting the existing instrument gas (natural gas) system used for

process control at Ember’s Strathmore 09-27-024-25W4 compressor

station over to instrument air.

Activity start date The project start date is Jan 1, 2010.

Offset crediting

period

This offset project plan covers activities during the initial 8-year

crediting period, which is from January 1, 2010 to December 31, 2017.

In 2018, a five year crediting period extension was granted by the

Alberta Climate Change Office in 2018, but this reporting period will be

covered under a new updated offset project plan.

Estimated emission

reductions/

sequestration

For the initial 8-year crediting period from January 1, 2010 to December

31, 2017 the total estimated GHG emission reductions are 16,650 tCO2e

with an annual average of 2,080 tCO2e/year.

For the subsequent 5-year crediting period extension, the total GHG

emission reductions are estimated to be 1,000 tCO2e and the annual

GHG reductions are estimated to be 200 tCO2e/year.

Unique site identifier The latitude and longitude of the Project location is 51.076, -113.403,

and the legal land description of the Project is 09-27-024-25 W4M, near

the town of Strathmore, Alberta. The Project takes place at a single

facility and is not an aggregated project.

Is the project located Yes, the Project is located near Strathmore, Alberta.

http://emberresources.com/

http://emberresources.com/

mailto:[email protected]

mailto:[email protected]


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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


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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


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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).


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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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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


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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


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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.


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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

comparison of the baseline and the Project:

Emission Reduction = Emissions Baseline – Emissions Project

Emissions Baseline = Emissions Baseline Vented Gas + Emissions Fuel Extraction/Processing

Emissions Project = Emissions Air Compression

Where:

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

Emissions Vented Fuel Gas = emissions under SS B7 Vented Fuel Gas.

Emissions Fuel Extraction/Processing = emissions under SS B10 Fuel Extraction/Processing.


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

Emissions Air Compression = emissions under SS P6 Air Compression.

3.3.1 Calculation of Baseline Emissions

The following two formulas are used to calculate baseline emissions under SS B7 and SS B10,

respectively.

i. Emissions Vented Fuel Gas (SS B7) =

444sInstrument Control **%**days/year 365*DR)-(1* Air Compressed CHCH GWPCHGEF

ii. Emissions Fuel Extraction/Processing (SS B10) =

tionFuelExtractionFuelExtracFuel EFGEFEFVol **days/year 365* Air Compressed* sInstrument Control

Table 5 - Data Sources Used in the Quantification of Baseline Emissions

Baseline Emissions under SS B7 and SS B10

Parameter Description Units Source

Compressed Air

Used for

Pneumatic

Instruments /

Compressed Air

Control Instruments

Volume of compressed air used

for pneumatic instruments.

e3m3/

day

Continuous direct

measurement of air flow

rate at the Strathmore

Phase 1 facility in units of

e3m3/ day and averaging of

measurements on a daily

basis.

Discount Rate /

DR

Discount rate for leak detection

and repair (if not completed). %

DR = 0 if leak inspection

occurred within < 1 year.

Otherwise DR assumed to

be 2.5% per year from the

date that the system was

last inspected.

Gas Equivalency

Factor / GEF

Conversion factor to convert from

volume of air to an equivalent

volume of natural gas that would

have been vented in the baseline.

-

Gas Equivalency Factor of

1.2977 used as per

Appendix A (page 39) of the

Instrument Air Protocol.

% CH4

Percent methane (by volume)

contained in the fuel gas

(instrument gas) at each facility.

%

volume

Direct measurement of

composition of fuel gas at

the Strathmore Phase 1

facility, completed annually

by a third party laboratory.


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Density of

Methane /

0.6797 kg/m3 at 15°C and 1

atmosphere.1 t/e3m3

At 15º C and 101.3kPa, the

standard reference

conditions used by the

natural gas industry.

Global Warming

Potential of

Methane /

Reference value of 25 as per the

Alberta Environment and Parks

Carbon Offset Emission Factors

Handbook.

t CO2e/

t CH4

Alberta Environment and

Parks Carbon Offset

Emission Factors Handbook

(version 1, March 2015).

FuelVol

Calculated value. The baseline

volume of fuel gas used (vented

from pneumatic equipment) is

calculated based on the

measured air volume times the

gas equivalency factor. This

calculated value is then used to

determine the indirect upstream

emissions associated with fuel

extraction and processing under

SS B10.

e3m3

natural

gas/

day

Calculated value.

tionFuelExtracEF

Reference emission factors for

CO2, CH4 and N2O. Emission

factors for fuel extraction and

processing are from the Alberta

Environment and Parks Carbon

Offset Emission Factors

Handbook.

tCO2/

e3m3;

tCH4/

e3m3;

tN2O/

e3m3;

Alberta Environment and

Parks Carbon Offset

Emission Factors Handbook

(version 1, March 2015),

Table 4.

Note that the emissions of vented CO2 contained in the fuel gas have not been included in the

calculation for emissions under SS B7 as these emissions are negligible (the instrument gas at the

Strathmore Phase 1 facility typically contains approximately 0.1% CO2 by volume) and the

exclusion of <1 tonne of vented CO2 emissions is immaterial and conservative. Refer to page 28 in

the Instrument Air Protocol for further explanation.

3.3.2 Calculation of Project Emissions

The following formula is used to calculate project emissions under P6 Air Compression.

1) Emissions Air Compression (P6) =

yElectricitGridRatingEquipment EFHoursOperatingLoadkW _**%*001.0*

The following table provides a summary of the key data sources used in the calculation of project

emissions for each instrument air conversion.

Table 6 - Data Sources Used in the Quantification of Project Emissions

Project Emissions Under P6 Air Compression

1 http://encyclopedia.airliquide.com/Encyclopedia.asp?GasID=41

4CH

4CHGWP

http://encyclopedia.airliquide.com/Encyclopedia.asp?GasID=41


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Parameter Description Units Source

Equipment Rating / kW Equipment Rating

kW rating of air compressor

electric motors are used to estimate electricity usage from the air compressor.

kW Air compressor motor size (kW) obtained from equipment specifications.

% Load Percentage loading of air compressor.

%

The percent loading is estimated based on the annual average volume of air

used during the year divided by the maximum dry air capacity of the air compressor.

Operating Hours Air compressor operating hours hours Actual operating hours for facility or assumed 24/7 operating time per day for conservativeness.

Alberta Grid Electricity Emission Factor / EF Grid

Electricity

Reference value of 0.64 t CO2e/MWh as per AB Carbon Offset Emission Factors Handbook.

tCO2e/ MWh

Carbon Offset Emission Factors Handbook (Version 1, March 2015).2

3.3.3 Sample Calculation

A sample calculation has been provided below for the Project based on a 365 day operating period.

The calculation methods are the same for the other sub-projects and the total GHG reductions are

calculated as the sum of the GHG reductions from all of the sub-projects.

1) Emissions Vented Fuel Gas (B7) =

444sInstrument Control **%**days Operating*DR)-(1* Air Compressed CHCH GWPCHGEF

Where the following data inputs were used in the calculation:

Collected Data Inputs:

sInstrument ControlAir Compressed is the volume of air (e3m3/day) that was delivered to the

pneumatic instruments per day at the Strathmore Phase 1 facility, obtained from average

flow meter readings3 = 0.03 e3m3/day.

DR is the discount rate for leak detection = 0, assuming annual leak inspections.

Operating days = 365 days.

% CH4 is the percentage methane by volume in the instrument gas at the Strathmore

Phase 1 facility, obtained from third party gas analysis = 97.59%.

Reference Values:

• GEF = 1.2977, as outlined in the Instrument Air Protocol, Appendix A.

• ρ CH4 is the density of methane at standard conditions of 15°C and 1 atmosphere4 =

0.6797 kg/m3.

2 https://open.alberta.ca/publications/2368-9528 3 1 e3m3 = 1000 m3 4 http://encyclopedia.airliquide.com/Encyclopedia.asp?GasID=41

https://open.alberta.ca/publications/2368-9528

http://encyclopedia.airliquide.com/Encyclopedia.asp?GasID=41


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• GWP CH4 is the Global Warming Potential of Methane, obtained from the Carbon Offset

Emission Factors Handbook (version 1.0, March 2015) = 25.

By plugging the above values into Equation 1), the baseline emissions under SS B7 were calculated

to be 235.64 tCO2e over the 365 day operating period.

2) Emissions Fuel Extraction/Processing (SS B10) =

tionFuelExtractionFuelExtracFuel EFGEFEFVol **days/year 365* Air Compressed* sInstrument Control



sInstrument ControlAir Compressed is the volume of air (e3m3/day) that was delivered to the

pneumatic instruments per day at the Strathmore Phase 1 facility, obtained from average

flow meter readings5 = 0.03 e3m3/day.

Operating days = 365 days.

Reference Values:

GEF = 1.2977, as outlined in the Instrument Air Protocol, Appendix A.

EF Fuel Extraction CO2e = (EF Fuel Extraction CO2*GWP CO2) + (EF Fuel Extraction CH4*GWP CH4) + (EF Fuel

Extraction N2O*GWP N2O) = 0.200086 tCO2e/e3m3.

Reference emission factors for fuel extraction and processing for CO2, CH4 and N2O are

summarized in the table below, taken from the Alberta Environment and Parks Carbon

Offset Emission Factors Handbook (v1, March 2015).

GWP CO2, GWP CH4, GWP N2O are the global warming potentials of CO2 (GWP=1), CH4

(GWP=25) and N2O (GWP=298), taken from the Alberta Environment and Parks Carbon

Offset Emission Factors Handbook (v1, March 2015).

Emission Factors tCO2/e3m3 tCH4/e3m3 tN2O/e3m3 tCO2e/e3m3

Natural Gas Extraction 0.043 0.0023 0.000004 0.101692

Natural Gas Processing 0.09 0.0003 0.000003 0.098394

Combined EF 0.133 0.0026 0.000007 0.200086

By plugging the above values into Equation 2), the baseline emissions under SS B10 were

estimated to be 2.84 tCO2e over the 365 day operating period.

The total baseline emissions are equal to the sum of emissions under B7 and B10 (235.64+2.84),

which equals 238.48 tCO2e.

As shown previously, Project Emissions are calculated according to the following formula:

3) Emissions Air Compression (P6) =

yElectricitGridRatingEquipment EFHoursOperatingLoadkW _**%*001.0*



5 1 e3m3 = 1000 m3


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RatingEquipmentkW is the size of the air compressor motor in kilowatts in use at the = 11.2kW.

% Load = the % loading on the air compressor motor, which is estimated to be 1.5%

based on typical operations since the system is very oversized.

Operating Hours are assumed to be 8760 hours for the operating period.

Reference Values:

0.001 is the conversion factor from kW to MW

yElectricitGridEF _ = 0.64 tCO2e/MWh, is the grid electricity emission factor for Alberta, obtained

from Alberta Carbon Offset Emission Factor Handbook.

By plugging the above values into Equation 3), the project emissions are estimated to be 0.94

tCO2e over the 365 day operating period.

The Net GHG reductions equal the sum of the baseline emissions (SS B7 + SS B10) minus the

project emissions (SS P6). Based on the above calculation inputs, the hypothetical GHG emission

reductions for the Strathmore Phase 1 facility were calculated to be approximately 237 tonnes

tCO2e emissions over a 365 day operating period, as summarized in the table below. Note that

actual GHG emission reductions per year are expected to vary from this estimate.

Table 7 - Example GHG Emission Reduction Calculation6

Total Baseline Emissions (B7 +

B10) (t CO2e)

Total Project Emissions (P6) (t

CO2e)

Net GHG Emission

Reductions (t CO2e)

238.48 0.94 237.54

3.4 Monitoring Plan

The primary parameter used to calculate emission offsets from the Project is the volume of air

used to operate pneumatic equipment at the Strathmore Phase 1 facility. The volume of

compressed air used at the Strathmore Phase 1 facility is measured directly on a continuous

basis and data is uploaded from the meter directly into Ember’s SCADA system. Flow rate data

points are stored as daily averages.

The calculation of baseline emissions under B7 is performed by using the aggregated air flow

rates and the percent methane in the instrument gas (fuel gas or sales gas) at the Strathmore

Phase 1 facility. The percent methane is obtained from an annual gas analyses and this data is

entered into the calculation spreadsheet annually. Prior to verification, the meter data is input

into a summary spreadsheet to aggregate emission reductions for each reporting period. At this

point in time, the discount rate for leak detection/repair is applied to the calculated baseline

emissions in the summary spreadsheet, if applicable.

The calculation of project emissions under P6 is performed manually in the summary

spreadsheet based on the equipment rating of the air compressor and conservative

assumptions related to loading and operating hours. The net GHG emission reductions are then

calculated based on the difference between the baseline and project emissions. The tables

below summarize key data and monitoring parameters of the Project.

6 Note totals may not add up due to rounding.


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Table 8 - Sample Monitoring Plan

Parameter Monitoring Specifications

Source/sink identifier and name B7 – Baseline Vented Gas

Data parameter Volume of compressed air used by instrumentation

Estimation, modeling, measurement or calculation approaches

Direct measurement of air flow rate downstream of air dryers.

Data unit e3m3 per day (the meter outputs values at standard temperature and pressure of 1 atm and 15°C).

Sources/Origin Direct metering of air flow rate on a continuous basis.

Sampling frequency Continuous

Description and justification of monitoring method

This is the most accurate method of measuring this parameter.

Uncertainty Based on meter specifications. Annual calibrations are performed to ensure meter is functioning correctly.


Source/sink identifier and name B7 – Baseline Vented Gas

Data parameter Percent methane in fuel gas

Estimation, modeling, measurement or calculation approaches

Direct measurement of gas composition by third party lab.

Data unit % methane

Sources/Origin Direct samples of fuel gas taken annually by third party.

Sampling frequency Annual

Description and justification of

monitoring method

This is the most accurate method of measuring this

parameter. Changes in gas composition are infrequent so annual samples are appropriate.

Uncertainty N/A.


Source/sink identifier and name P6 – Air Compression


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Data parameter Quantity of electricity used to power air compressors

Estimation, modeling,

measurement or calculation approaches

Estimated based on air compressor motor size (kW),

operating hours and loading, which is estimated based on the average air flow rate as a percentage of the rated capacity.

Data unit kWh

Sources/Origin Estimated based on air compressor motor size (kW), operating hours and loading.

Sampling frequency Annual estimation

Description and justification of monitoring method

Represents a conservative approach to estimation of a minor source of emissions (<5% of baseline) since

direct measurement is not possible (sub-metering of electricity is not an option).

Uncertainty N/A

3.5 Data Management System

Seven stages have been identified in the flow of data for the Project, as outlined in the figure

below. The components of the monitoring and QA/QC plan implemented at each stage are

outlined in the sections below. In order to reduce inaccuracies in data collection, the following

monitoring and QA/QC steps have also been implemented.


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Figure 3 – Data Flow for the Project

Data integrity is maintained through the following steps:

• Protecting records of monitored data (electronic storage);

• Checking data integrity on a regular and periodic basis (manual assessment, comparing

metered data, and detection of outstanding data/records);

• Comparing current estimates with previous estimates as a ‘reality check’;

• Third party meter specialists or trained personnel perform all maintenance and calibration of

monitoring devices. The air flow meter is calibrated annually using the same procedures as

for natural gas sales or production meters;

• Third party specialists perform annual gas analyses. Gas analyses are retained by Ember

and by the third party lab. Current gas analyses are compared by the lab to historical

analyses to identify anomalies as part of the lab’s QA/QC process; and,

3. SCADA system polls meter for air flow rate and stores

data

Record Keeping in Secure Server and Retention of Back-up Copies

of all Requisite Data

QA/QC Procedures:

1. Manual Check of Data for

Anomalies

2. Review of Final Calculations

Manual Data Collection:

1 Annual Gas Composition Analyses

2 Air Compressor Motor Size (kW) 2. Continuous measurement of air flow rate downstream of air dryer with dedicated

orifice meter

7. Annual Reporting of GHG emission reductions

5. Electricity use calculated annually to determine

project emissions

Supporting Documentation:

1. Annual Meter Calibration

2. Inventory of Pneumatic Devices

3. Leak Inspection and Repair Info

1. Annual gas analyses by third party to determine % methane in fuel gas at site

4. Ongoing data collection and storage using SCADA

6. Discount rates applied

annually to baseline

emissions, if applicable


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• Final review to check that calculation errors have not been made. All calculations are

performed by or reviewed by an experienced GHG quantification expert with at least 10

years of experience.

• All flow meter data and gas analyses used to quantify emission offsets are retained by

Ember Resources and by a third party consultant.


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4.0 Project Developer Signature

I am a duly authorized corporate officer of the project developer mentioned above and have

personally examined and am familiar with the information submitted in this project plan. Based

upon reasonable investigation, including my inquiry of those individuals responsible for obtaining

the information, I hereby warrant that the submitted information is true, accurate and complete to

the best of my knowledge and belief. I understand that any false statement made in the submitted

information may result in de-registration of credits and may be punishable as a criminal offence in

accordance with provincial or federal statutes.

The project developer has executed this offset project plan as of the ____day of August, 2018.

Project Title: Ember Resources Instrument Air Conversion at Strathmore Phase 1

Signature: ________________________________________

Name: Steve Gell, P.Eng

Title: Vice President, Production

1


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5.0 References

Alberta Government. Quantification Protocol for Instrument Gas to Instrument Air Conversion in

Process Control Systems (Version 1.0, October 2009).

Alberta Government. Carbon Offset Emission Factors Handbook. Version 1. April 2015.

Documents

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