Offset Project Report Form: Ember Resources Inc. …...Ember Resources Instrument Air Conversion at...

Ember Resources Instrument Air Conversion at Strathmore Phase 1

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Offset Project Report Form:


Project Developer:

Ember Resources Inc.

Prepared by:


Reporting Period:

August 1, 2016 to Dec 31, 2017

August 20, 2018


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Greenhouse Gas Assertion

Project Developer:


Steve Gell, P.Eng

The Devon Tower, 800 – 400 3rd Avenue SW

Calgary, Alberta, T2P 4H2

403-698-8983

http://emberresources.com/

[email protected]

Project Documents:

Offset Project Report Form: Ember Resources Instrument Air Conversion at Strathmore Phase 1

Offset Project Plan Form: Ember Resources Instrument Air Conversion at Strathmore Phase 1 (July

31, 2018)

Quantification Protocol for Instrument Gas to Instrument Air Conversion in Process Control

Systems” Version 1.0, October 2009

Project Identification:


Reporting Period: August 1, 2016 to December 31, 2017

The objective of the Ember Resources Instrument Air Conversion at Strathmore Phase 1 (“The

Project”) is to reduce greenhouse gas emissions from instrumentation by converting the existing

instrument gas system used for process control at the Strathmore 09-27-024-25W4 compressor

station over to instrument air.

Latitude: 51.076

Longitude : -113.403

LSD: 09-27-024-25 W4M (located near Strathmore, AB).


mailto:[email protected]


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Emission Reduction or Sequestration Assertion:

Vintage Gas Type Quantity (tCO2e)

2016 CO2 1.11

2016 CH4 139.56

2016 N2O 0.02

2016 Other (CO2e) -0.54

Total 2016 CO2e 140.15

Total 2016 (Rounded) CO2e 140

2017 CO2 1.90

2017 CH4 214.83

2017 N2O 0.03

2017 Other (CO2e) -0.93

Total 2017 CO2e 215.83

Total 2017 (Rounded) CO2e 215

Total for Reporting

Period (Rounded)

CO2e 355


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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 greenhouse gas

assertion, the accompanying project report on which it is based. 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, and that all matters affecting the validity of the emission reduction claim or

the protocol(s) upon which it is based have been fully disclosed. 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 report as of the ____day of____, 2018.

Signature: ________________________________________

Name: Steve Gell, P.Eng

Title: Vice President, Production

21 Aug


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Table of Contents

Greenhouse Gas Assertion ..................................................................................................... 2 1.0 Contact Information .............................................................................................. 6 2.0 Project Scope and Site Description .......................................................................... 6

2.1 Project Implementation .......................................................................................... 7 2.2 Protocol ............................................................................................................. 10 2.3 Risks ................................................................................................................. 12

3.0 Project Quantification .......................................................................................... 13 3.1 Summary Table Non-Levied Emissions ................................................................... 13 3.2 Summary Table Levied Emissions and Biogenic CO2 ................................................. 14 3.3 Calculations ........................................................................................................ 14

4.0 References ......................................................................................................... 18

List of Tables

Table 1: Project Contact Information ...................................................................................... 6 Table 2: Project Information .................................................................................................. 6 Table 3: Assessment of Protocol Applicability Criteria .............................................................. 10 Table 4: Summary of Non-Levied Emissions .......................................................................... 13 Table 5: Data Sources Used in the Quantification of Baseline Emissions .................................... 15 Table 6: Data Sources Used in the Quantification of Project Emissions ...................................... 16


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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 January 1, 2010.

Offset start date The offset start date is January 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.

Reporting period

covered by the project

August 1, 2016 to December 31, 2017

Actual emission

reductions/ capture/

sequestration

The total quantity of GHG emission reductions claimed as emission

offsets for the reporting period from August 1, 2016 to December 31,

2017 is 355 tonnes CO2e. The table below provides a summary of the

offsets claimed to date for the Project.

Vintage Year Offsets Created (tCO2e)

2010 2,161






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2011 2,068

2012 2,787

2013 2,294

2014 3,238

2015 (January 1 to January 15th) 133

2015 (January 16 to Dec 31st) 2,728

2016 (January 1 to July 31st) 904

2016 (August 1 to Dec 31st) 140

2017 215

The total emission offsets generated to date for the Project are 16,668

tCO2e.

Unique site identifier Latitude: 51.076

Longitude : -113.403

LSD: 09-27-024-25 W4M (located near Strathmore, AB).

The project is not an aggregated project.

Is the project located

in Alberta?

Yes, the Project is located in Alberta, near the town of Strathmore.

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 Implementation

Since commissioning of the Strathmore Phase 1 Instrument Air Project in 2010, several

changes were made to the Project. The following section summarizes changes made since the

original Offset Project Plan was submitted as well as changes made during this reporting period

from August 1, 2016 to Dec 31, 2017.

i. Inclusion of Emissions from Fossil Fuel Extraction and Processing (B10)


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The baseline emissions associated with the extraction and processing of fossil fuels under SSR

B10 had previously been excluded from quantification in prior offset claims (January 1, 2012 to

January 15, 2015) to simplify data management processes.

For consistency with the Instrument Air Protocol requirements, this emission source has now

been included in the quantification for subsequent offset claims beginning with the period

January 16, 2015 to July 31, 2016 and continuing in this reporting period from August 1, 2016

to Dec 31, 2017. The formulas used in the quantification of baseline emissions from fossil fuel

extraction and processing under SSR B10 are described in Section 3.3 of this offset project

report. The emission factors for fuel extraction and processing are taken from the Alberta

Environment and Parks Carbon Offset Emission Factors Handbook (Version 1, 2015).1

ii. Inclusion of Emissions from Electricity Use (SSR P6) (Previously Excluded)

The project emissions associated with the usage of electricity to operate the instrument air

compressors were added for all offset claims beginning January 1, 2012 to meet new

requirements from Alberta Environment and Parks. The electricity emission factor for grid

electricity usage from the Alberta Environment and Parks Carbon Offset Emission Factors

Handbook (Version 1, 2015)2 has been used for this reporting period. The addition of this

emission source to the quantification was both conservative and immaterial as the modification

resulted in <0.5% reduction in the quantity of offsets claimed during this reporting period.

The GHG emissions associated with electricity usage under SSR P6 were estimated based

electrical equipment ratings in kilowatts, loading percentage, facility operating hours and the

Alberta Grid Usage Emission Factor, as shown in Section 3.3 of this offset project report.

iii. Update of the Global Warming Potential for Methane

Consistent with the most recent guidance from Alberta Environment and Parks and published

factors contained in the Carbon Offset Emission Factors Handbook (Version 1, 2015),3 the

Global Warming Potential of Methane was updated from 21 to 25 for all reporting periods

beginning January 1, 2014.

iv. Exclusion of Baseline Emissions of Vented CO2 (SSR B7)

The baseline emissions from venting CO2 contained in the instrument gas were excluded from

the calculation of emissions under SSR B7 as these emissions are negligible. In 2016, a

laboratory gas analysis of the fuel gas at the Strathmore Phase 1 site confirmed that the vented

gas contained only 0.12% CO2 by volume versus an average of 97.59% methane. The baseline

emissions from the venting of CO2 contained in the natural gas at Strathmore Phase 1 were

estimated to be less than 0.1 tonne of CO2 during this reporting period. Therefore this emission

source is immaterial. The exclusion of these emissions is also consistent with guidance in the

Instrument Air Protocol, found on page 28 in section 2.5 under the quantification of emissions

for SSR B7.

v. Air Usage from Equipment at the Fueling Station Adjacent to the Strathmore Phase 1

Plant

The Offset Project Plan makes reference to a compressed natural gas (CNG) fueling station that

previously operated adjacent to the Strathmore Phase 1 facility and used a very small amount

of compressed air that was supplied from the Project facilities. In 2014 the adjacent CNG

fueling station was completely decommissioned and the compressed air supply lines were

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

2 Ibid.

3 Ibid.

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




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removed from service. Therefore, the Project no longer supplies compressed air to this CNG

facility and the baseline emissions under SSR B7 are no longer impacted.

vi. Use of Daily Instrument Air Volumes from SCADA

Beginning January 16, 2015, the data management system for this offset Project was simplified

in order to pull data directly from SCADAvantage (“SCADA”) to avoid using a separate data

historian service called “PI” since this software was no longer available. The PI data historian

had been used to quantify GHG emissions since 2012 to trend and average data from the

instrument air flow meter and to perform standardized calculations.

The quantification of baseline emissions under SSR B7 is now done manually using daily

average instrument air volumes (e3m3/day) that are downloaded directly from SCADA instead

of the hourly average volumes obtained from the PI data historian. The underlying data still

comes from the same flow meter and is still polled at the same frequency as before using the

same SCADA system.

vii. Incorporation of Discount Factor for Leak Detection

For the offset claim for August 1, 2016 to December 31, 2017, the discount factor for leak

detection was set to 0% since a comprehensive leak detection assessment was completed in

December 2016 (e.g. it had been less than one year since all facilities had undergone a

complete leak survey and inspection).

viii. Change of Ownership

Since January 16, 2015 the Strathmore Phase 1 facility has been owned and operated by Ember

Resources. For the reporting period from January 16, 2015 to July 31, 2016, Encana acted as

the aggregator of emission offsets for this Project and several other instrument conversion

projects for administrative purposes. For the reporting period from August 1, 2016 to December

31, 2017 Encana Corporation had no ownership interest in the facility and did not participate in

the emission offset project. As such, the Project name has been changed to reflect the fact that

the Strathmore Phase 1 facility is 100% owned and operated by Ember Resources.

ix. Operational Changes Impacting Emission Offsets from the Project

The air usage at the Strathmore Phase 1 facility and the resulting GHG emission reductions

generated from the Project have decreased significantly since April 2016, when the majority of

the facility was shut-in. Only the inlet separator and one electric booster compressor are

currently operational as the sales gas compressor, dehydration unit and other equipment

continue to be shut-in since the boosted gas has been re-routed to another facility for final

processing and sales.

x. Change in Fuel Gas Composition

In August 2017, the Strathmore Phase 1 facility began receiving a richer gas supply from a

third party so the gas composition analysis was updated to reflect that operational change. In

past reporting periods the annual percent methane value from the gas analysis was used for

the entire calendar year, but for this reporting period the new gas analysis from October 13,

2017 was used only from August 1, 2017 to December 31, 2017 to more accurately reflect the

time period that the facility was handling the richer gas supply. The Nov 7, 2016 fuel gas

analysis was used for the period from August 1, 2016 to July 31, 2017 to more accurately

reflect the fuel gas composition at the facility.

Calculation procedures, data collection procedures and record keeping practices have not been

modified since the last offset project report. No changes were made to the emission factors

used for the project.


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No changes have been made to the Project for regulatory reasons and the Project continues to

be additional (surplus to regulations).

2.2 Protocol

The relevant quantification protocol being applied to this Project is the “Quantification Protocol

for Instrument Gas to Instrument Air Conversion in Process Control Systems” Version 1.0,

October 2009 (Herein referred to as the “Instrument Air Protocol”).

The quantification protocol is applicable to the Project because the Project replaces pressurized

natural gas (fuel gas) with compressed air to power pneumatic instruments in process control

systems. The instrument air conversion project achieves GHG emission reductions by utilizing

compressed air instead of compressed natural gas for control of pneumatic equipment, avoiding

methane emissions. Prior to the instrument air conversions, the process control equipment at

the Strathmore Phase 1 compressor station was driven by fuel gas (“instrument gas”).

The table below outlines how the Strathmore Phase 1 Instrument Air Conversion Project meets

the applicability requirements in the Instrument Air Protocol.

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 an instrument air system

does 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 Project was implemented as a retrofit to

an existing 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 will be updated

annually. 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 of the

instrument air conversion. Post

commissioning, leak inspections have been

performed periodically using ultrasonic leak

detection equipment. During periods when

leak detection has 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 instrument air conversion project was

constructed and commissioned at the

Strathmore Phase 1 facility, which is a

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 in late 2009 and

was commissioned on January 1, 2010.

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

Dec 31, 2017. A crediting period extension

has been requested.

6 c. Ownership of offsets must be established as

indicated by facility records.

Ember is the sole owner of offsets from the

Project through its 100% working interest in

the Strathmore Phase 1 facility.

No flexibility mechanisms have been used in the quantification of GHG emission reductions for

this Project.

No deviations were made to the Quantification Protocol and no other protocols were used in the

quantification. 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 using the Instrument Air Protocol after the end

of its initial 8-year crediting period, which ends Dec 31, 2017. This offset project report covers

activities from August 1, 2016 to Dec 31, 2017 and therefore still uses the Instrument Air

Protocol.


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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 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. At this time, there are no

regulations requiring the retrofit or conversion of existing natural gas compressor

stations from instrument gas to instrument air.


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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 Summary Table Non-Levied Emissions

The table below provides a summary of the net GHG emission reductions from the Project for the

reporting period. All emission sources quantified for this Project are considered “Non-Levied”

emissions since none of the quantified emission sources are subject to the Alberta Carbon Levy.

Note that the totals may not add up due to rounding.

Table 4: Summary of Non-Levied Emissions

Vintage Gas Type Baseline

Emissions

(tCO2e)

Project

Emissions

(tCO2e)

Total Reduction

or Sequestration

(tCO2e)

2016 CO2 1.11 n/a 1.11

2016 CH4 139.56 n/a 139.56

2016 N2O 0.02 n/a 0.02

2016 Other (CO2e) n/a 0.54 -0.54

Total 2016 CO2e 140.69 0.54 140.15

Total 2016 (Rounded) CO2e n/a n/a 140

2017 CO2 1.90 n/a 1.90

2017 CH4 214.83 n/a 214.83

2017 N2O 0.03 n/a 0.03

2017 Other (CO2e) n/a 0.93 -0.93

Total 2017 CO2e 216.75 0.93 215.83

Total 2017 (Rounded) CO2e n/a n/a 215

Total for Reporting

Period (Rounded)

CO2e n/a n/a 355


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3.2 Summary Table Levied Emissions and Biogenic CO2

N/A. The Project does not include any “Levied” emission sources and does not include any biogenic

sources of CO2, so this section is not applicable and the summary table of Levied Emissions and

Biogenic CO2 has been deleted.

3.3 Calculations

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”.

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.

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 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 Vented Fuel 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.

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

Emissions Air Compression = emissions under SS P6 Air Compression.

Calculation of Baseline Emissions (SS B7 & B10)

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

respectively.


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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

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

emissions for the Strathmore Phase 1 Instrument Air Project.

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

Baseline Emissions under SS B7

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 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.

Density of

Methane /

0.6797 kg/m3 at 15°C and 1

atmosphere.4 t/e3m3

At 15º C and 101.3kPa, the

standard reference

conditions used by the

natural gas industry.

Global Warming

Potential of

Reference value of 25 as per the

Alberta Environment and Parks

t CO2e/

t CH4 Alberta Environment and

Parks Carbon Offset

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

4CH

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


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Methane /

Carbon Offset Emission Factors

Handbook.

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 site contains approximately 0.1% CO2 by volume) and the exclusion of <0.1

tonne of vented CO2 emissions is immaterial and conservative. Refer to page 28 in the Instrument

Air Protocol for further explanation.

Calculation of Project Emissions

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

iii. Emissions Air Compression (SS P6) =

yElectricitGridRatingEquipment EFHoursOperatingLoadkW _**%*001.0*

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

emissions for the Strathmore Phase 1 Instrument Air Project.

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

Project Emissions Under P6 Air Compression

Parameter Description Units Source

4CHGWP


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Equipment

Rating / kW

Equipment Rating

kW rating of air

compressor electric

motors are used to

estimate electricity

usage for the

instrument air project.

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

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 for

increased on-site use

of grid electricity as per

the Alberta

Environment and Parks

Carbon Offset Emission

Factors Handbook.

tCO2e/

MWh

Alberta Environment and

Parks Carbon Offset

Emission Factors

Handbook (version 1,

March 2015), Table 2.


August 2018

of 18

4.0 References

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

Process Control Systems. Version 1, October 2009.

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

Offset Project Report Form: Ember Resources Inc. …...Ember Resources Instrument Air Conversion at...

Documents

Transcript of Offset Project Report Form: Ember Resources Inc. …...Ember Resources Instrument Air Conversion at...