offset project plan form: ember resources instrument air

Ember Resources Instrument Air Conversion at Strathmore Phase 1

April 2018

Offset Project Plan Form:


Project Developer:

Ember Resources Inc.

Prepared by:

Ember Resources Inc.

Date:

April 12, 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 ................................................................................................................... 6

3.0 Project Quantification ............................................................................................ 8 3.1 Inventory or Sources and Sinks .............................................................................. 8 3.2 Baseline and Project Condition .............................................................................. 10

3.2.1 Baseline Condition ............................................................................................... 10 3.2.2 Project Condition ................................................................................................. 11 3.2.3 Functional Equivalence ......................................................................................... 11

3.3 Quantification Plan .............................................................................................. 11 3.3.1 Calculation of Baseline Emissions .......................................................................... 12 3.3.2 Calculation of Project Emissions ............................................................................ 13 3.3.3 Sample Calculation .............................................................................................. 14

3.4 Monitoring Plan ................................................................................................... 15 3.5 Data Management System.................................................................................... 17

4.0 Project Developer Signature......................................................................................19

5.0 References.............................................................................................................20

List of Tables and Figures

Table 1 - Project Contact Information ..................................................................................... 3 Table 2 - Project Information ................................................................................................. 3 Figure 1 – Baseline Sources and Sinks of Emissions .................................................................. 8 Figure 2 – Project Sources and Sinks of Emissions .................................................................... 9 Table 3 - Included Sources and Sinks and Quantification Methods .............................................. 9 Table 4 - Excluded Sources and Sinks and Justification ........................................................... 10 Table 5 - Data Sources Used in the Quantification of Baseline Emissions ................................... 12 Table 6 - Data Sources Used in the Quantification of Project Emissions ..................................... 13 Table 7 - Example GHG Emission Reduction Calculation .......................................................... 15 Table 8 - Sample Monitoring Plan ......................................................................................... 15 Figure 3 – Data Flow for the Project...................................................................................... 17


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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

The project crediting period is from January 1, 2010 to December 31,

2022, which includes the initial 8-year crediting period and a five year

crediting period extension granted by Alberta Climate Change Office.

Estimated emission

reductions/capture/se

questration

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.

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

http://emberresources.com/

http://emberresources.com/

mailto:[email protected]

mailto:[email protected]


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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

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


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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

Effective Jan 1, 2018, as required for the crediting period extension, the relevant, approved

quantification protocol used for this Project is the Quantification Protocol for Greenhouse Gas

Emission Reductions from Pneumatic Devices Version 2.0, January 25, 2017, referred to herein

as the “Protocol”.

For the initial 8-year crediting period from Jan 1, 2010 to Dec 31, 2017, the Project was

quantified using the Quantification Protocol for Instrument Gas to Instrument Air Conversion in

Process Control Systems (Version 1.0, October 2009).


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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. Instrument gas to instrument air conversions are one of the eligible

project types under the Quantification Protocol for Greenhouse Gas Emission Reductions from

Pneumatic Devices.

The Project will meet the five applicability criteria in the protocol as follows:

1) The pneumatic devices were not altered as part of the instrument air conversion project.

The pressure supply medium (natural gas) was replaced with compressed air, but the actual

pneumatic devices were not modified so the function of each device is the same in both the

project and baseline.

2) The Project is a methane vent reduction project. The Strathmore Phase 1 facility did not use

propane as the pressure energy supply medium for process control operations as only

natural gas was used.

3) The Project is an instrument gas to air conversion at a brownfield site that was implemented

after January 1, 2002 and is therefore eligible under the protocol.

4) The Project plan includes periodic monitoring of the instrument air system for excessive

usage of air by conducting periodic leak inspections. If leak inspections are not performed,

the discount factors in the protocol will be used.

5) The Project will keep an inventory of pneumatic devices.

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 Greenhouse Gas Emission

Reductions from Pneumatic Devices and no other protocols were used in the quantification. The

protocol is not currently “flagged”.

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.


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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 Pneumatics Protocol was approved in 2017 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

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.


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3.0 Project Quantification

3.1 Inventory or Sources and Sinks

Sources and sinks of GHG emissions that may be relevant to typical pneumatic device

conversion and instrument gas to air conversion projects are outlined in the figures below

based on guidance from sections 2.1 and 3.1 of the “Quantification Protocol for Greenhouse Gas

Emission Reductions from Pneumatic Devices” Version 2.0 (January 2017). These figures

represent general sources and sinks of emissions that are relevant to most pneumatic

conversion or instrument gas to air conversion projects. Sources and sinks of emissions that

are relevant to the Ember Resources Strathmore Phase 1 Instrument Air Conversion Project

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 3 - 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.

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 Strathmore Phase 1 Instrument Air

Conversion Project, a number of the generic sources and sinks identified in the “Quantification

Protocol for Greenhouse Gas Emission Reductions from Pneumatic Devices” Version 2.0 (January

2017) were not applicable and were therefore excluded from the quantification. A summary of the

rationale for excluding these sources of emissions has been provided in the table below.

Table 4 - Excluded Sources and Sinks and Justification

Relevant Source, Sink

Controlled. Related, or

affected

Justification for Exclusion

B8 Uncaptured Fuel Gas

Controlled Not applicable. Excluded as the Project does not involve vent gas capture systems.

P7 Project Vented Gas

Controlled Not applicable. Excluded as the Project does not involve vent gas capture systems. No gas is vented in the project condition since the pneumatic systems were converted to instrument air.

P8 Process Control Electricity

Controlled Not applicable as the project scope does not include electrified control devices or electric chemical pumps. Incremental electricity usage related to the instrument air project is already captured under P6 Air Compression.

P9 Fuel Extraction/ Processing

Related Not applicable. Excluded as fossil fuels are not used to operate any of the equipment added to operate the instrument air system.

P17 Vent Gas

Capture

Controlled Not applicable. Excluded as the Project does not involve vent gas

capture systems.

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. Flaring of instrument gas was not practiced in the baseline at the

Strathmore Phase 1 facility 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. B7 is the only

source of emissions quantified for the Project.

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


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performance at the Strathmore Phase 1 facility, the baseline emissions are estimated to be

approximately 200 tCO2e/year.

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 Greenhouse Gas

Emission Reductions from Pneumatic Devices” Version 2.0 (January 2017). 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 Project = Emissions Air Compression

Where:


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

Emissions Baseline Vented Gas = emissions under B7 Baseline Vented Gas

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

Emissions Air Compression = emissions under P6 Air Compression

3.3.1 Calculation of Baseline Emissions

The following formula is used to calculate baseline emissions under B7.

1) Emissions Baseline Vented Gas (B7) =

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

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

emissions for each instrument air conversion.

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

Parameter Description Units Source

Baseline Emissions under B7

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 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)

%

Assumed to be 0% in years where leak detection and repair was completed, or assumed to be 2.5% per year from the date that the system was last inspected, if leak inspection was not completed.

Gas Equivalency Ratio /

GER

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 Ratio of 1.2977 used as per Appendix A of the Protocol.

%CH4

Percent methane (by volume) contained in the fuel gas

(instrument gas).

% volume

Direct measurement of composition of fuel gas, completed annually by a

third party laboratory.

Density of Methane /

0.6797 kg/m3 at 15°C and 1 atmosphere1

t/e3m3

At 15º C and 101.3kPa, the

standard reference conditions used by the natural gas industry.

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

4CH

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


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Global Warming Potential of Methane /

Reference value of 25 as per AB Offset System guidance documents2

t CO2e/ t CH4

Carbon Offset Emission Factors Handbook.

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

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

typically contains about 0.1% CO2 by volume) and the exclusion of these emissions is conservative.

3.3.2 Calculation of Project Emissions

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

2) 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

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.

%

Estimated loading based on actual air usage as a percentage of the air compressor capacity (average volume of air used during the year divided by the maximum 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).3

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

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

4CHGWP

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

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


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3.3.3 Sample Calculation

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

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 readings4 = 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 site, obtained from third party gas analysis = 97.59%.

Reference Values:

• GEF = 1.2977, as outlined in the Protocol

• ρ CH4 is the density of methane at standard conditions of 15°C and 1 atmosphere5 =

0.6797 kg/m3.

• GWP CH4 is the Global Warming Potential of Methane, obtained from the Specified Gas

Emitters Regulation = 25.

By plugging the above values into Equation 1), the baseline emissions were calculated to be 235.64

tCO2e over the 365 day operating period.

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

2) Emissions Air Compression (P6) =

yElectricitGridRatingEquipment EFHoursOperatingLoadkW _**%*001.0*

Where the following data inputs were used in the calculation:

Collected Data Inputs:

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% 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

4 1 e3m3 = 1000 m3

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

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


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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 2), the project emissions are estimated to be 0.63

tCO2e over the 365 day operating period.

Based on the above calculation inputs, the GHG emission reductions were calculated to be 235

tonnes of CO2-equivalent 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 (t CO2e)

Total Project Emissions (t CO2e)

Net GHG Emission Reductions (t CO2e)

235.64 0.63 235.01

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.

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 at (meter outputs values at standard

6 Note totals may not add up due to rounding.


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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


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


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

Data parameter Quantity of electricity used to power air compressors


E 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


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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.

Figure 3 – Data Flow for the Project

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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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,

• 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.

4.OProject Developer Signature

I am a duly authorized corporate officer of the project developer mentioned above and havepersonally examined and am familiar with the information submitted in this project plan. Basedupon reasonable investigation, including my inquiry of those individuals responsible for obtainingthe information, I hereby warrant that the submitted information is true, accurate and complete tothe best of my knowledge and belief. I understand that any false statement made in the submittedinformation may result in de-registration of credits and may be punishable as a criminal offence inaccordance with provincial or federal statutes.

The project developer has executed this offset project plan as of the 12th day of April, 2018.

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

Signature:

Name: Steve Gell, P.Eng

Title: Vice President, Production


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5.0 References

Alberta Government. Quantification Protocol for Greenhouse Gas Emission Reductions from

Pneumatic Devices. Version 2, January 2017.

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

offset project plan form: ember resources instrument air

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