Ember Resources Vent Gas Capture Aggregation Project … › docs › c0c6eb47369f49448ec6bd07660465d9.pdfEmber Resources Vent Gas Capture Aggregation Project Phase 3 July 2018

Ember Resources Vent Gas Capture Aggregation Project Phase 3

July 2018

Offset Project Plan Form:


Project Developer:

Ember Resources Inc.

Prepared by:

Ember Resources Inc.

Date:

July 31, 2018


July 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 ................................................................................................ 7 2.2 Protocol ............................................................................................................... 8 2.3 Risks ................................................................................................................. 11

3.0 Project Quantification .......................................................................................... 13 3.1 Inventory or Sources and Sinks ............................................................................ 13 3.2 Baseline and Project Condition .............................................................................. 15

3.2.1 Baseline Condition ............................................................................................... 15 3.2.2 Project Condition ................................................................................................. 16 3.2.3 Functional Equivalence ......................................................................................... 16

3.3 Quantification Plan .............................................................................................. 16 3.3.1 Calculation of Baseline Emissions .......................................................................... 17 3.3.2 Sample Calculation .............................................................................................. 20

3.4 Monitoring Plan ................................................................................................... 22 3.5 Data Management System.................................................................................... 24

4.0 Project Developer Signature ................................................................................. 27 5.0 References ......................................................................................................... 28

List of Tables and Figures

Table 1 - Project Contact Information ..................................................................................... 3 Table 2 - Project Information ................................................................................................. 3 Table 3 – Vent Gas Capture Project Locations .......................................................................... 3 Figure 1 – Vent Gas Capture Project Locations (Map 1) ............................................................. 6 Figure 2 – Vent Gas Capture Project Locations (Map 2) ............................................................. 6 Table 4 - Assessment of Protocol Applicability Criteria ............................................................... 8 Figure 3 – Baseline Sources and Sinks of Emissions ................................................................ 13 Figure 4 – Project Sources and Sinks of Emissions .................................................................. 13 Table 5 - Included Sources and Sinks and Quantification Methods ............................................ 14 Table 6 - Data Sources Used in the Quantification of Baseline Emissions ................................... 19 Table 7 - Example GHG Emission Reduction Calculation .......................................................... 22 Table 8 - Sample Monitoring Plan ......................................................................................... 23 Figure 5 – Data Flow for the Project...................................................................................... 25


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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 Vent Gas Capture Aggregation Project Phase 3

Project

purpose and

objectives

The objective of Ember Resources’ Vent Gas Capture Aggregation Project Phase 3

(“The Project”) is to reduce greenhouse gas (GHG) emissions from thirty-two (32)

natural gas compressor stations, by installing SlipStream® technology to capture

and combust natural gas that was previously vented to the atmosphere during

normal operations. The vent gas is redirected into the air intake of a reciprocating

engine where it is combusted as a supplemental fuel source, thereby reducing

methane emissions.

Activity start

date

The Project start date is January 16, 2014.

Offset

crediting

period

The project crediting period is for 8 years and runs from January 16, 2014 to

January 15, 2022.

Estimated

emission

reductions/

sequestratio

n

For the initial 8-year crediting period from January 16, 2014 to January 15, 2022

the total estimated GHG emission reductions are approximately 165,000 tCO2e

with an annual average of approximately 20,625 tCO2e/year. If the Project is

granted a 5-year crediting period extension, a further 103,125 tCO2e of GHG

reductions are anticipated based on continued annual reductions 20,625

tCO2e/year.

Unique site

identifier

The Project consists of an aggregation of greenhouse gas emission reductions from

thirty-two (32) facilities located in Alberta, Canada. The table below provides a list

the facility locations and corresponding map identifiers in Figure 1 and Figure 2.

Table 3 – Vent Gas Capture Project Locations

http://emberresources.com/

http://emberresources.com/

mailto:[email protected]

mailto:[email protected]


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Map Letter

(Figure 1) Site Name LSD

Legal Land Location (Latitude and Longitude)

A Cavalier 08-04 K201 08‐04‐24‐23W4 (K201) 51.0141473, -113.1475554

A Cavalier 08-04 K202 08‐04‐24‐23W4 (K202) 51.0141473, -113.1475554

B Cavalier 05-11 05-11-23-23W4 50.9414701, -113.1185287

C Hussar Crowfoot 01-26 01‐26‐24‐22W4 51.0687245, -112.9615450

D Hussar Crowfoot 06-15 06‐15‐24‐22W4 51.0432735, -112.9964172

E Hussar Crowfoot 07-30 07‐30‐23‐22W4 50.9850710, -113.0603491

F Hussar Crowfoot 13-25 13‐25‐23‐22W4 50.9923855, -112.9557552

G Hussar Crowfoot 15-15 15‐15‐22‐20W4 50.8760116, -112.6903326

H Hussar Crowfoot 16-08 16‐08‐23‐21W4 50.9486479, -112.8917916

I Hussar Crowfoot 16-10 16‐10‐23‐22W4 50.9487134, -112.9847629

J Hussar Crowfoot 16-20 16‐20‐23‐20W4 50.9777900, -112.7520450

K Hussar Crowfoot 16-34 16‐34‐22‐22W4 50.9196403, -112.9622077

L Redland South 06-14 06‐14‐26‐22W4 51.2179231, -112.9731866

M Redland South 09-30 09‐30‐26‐21W4 51.2506436, -112.9150620

N Rockyford 05-17 05‐17‐25‐22W4 51.1305139, -113.0487891

O Severn 04-25 04‐25‐25‐23W4 51.1560230, -113.0952826

P Severn 05-18 05‐18‐25‐21W4 51.1305868, -112.9324766

Q Severn 08-05 08‐05‐26‐22W4 51.1888777, -113.0314003

R Severn 09-28 09‐28‐25‐22W4 51.1634057, -113.0081595

S Severn 10-05 10‐05‐27‐22W4 51.2796493, -113.0612778

T Severn 12-11 12‐11‐25‐23W4 51.1196682, -113.1185175

U Severn 15-35 15‐35‐25‐22W4 51.1815239, -112.9673768


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Map Letter (Figure 2)

Site Name LSD Legal Land Location

(Latitude and Longitude)

A Cavalier 01-28 01-28-23-23W4 50.9813914, -113.1475547

B Hussar Crowfoot 06-18 06-18-23-20W4 50.9559551, -112.7870789

C Hussar Crowfoot 06-14 06-14-24-22W4 51.0432702, -112.9731537

D Centron 02-12 02-12-23-28W4 50.9377288, -113.7814069

E Redland South 09-20 09-20-27-21W4 51.3232496, -112.9147347

F Redland South 07-13 07-13-27-22W4 51.3050495, -112.9676872

G Hussar Crowfoot 07-32 07-32-22-20W4 50.9123864, -112.7368250

H Hussar Crowfoot 11-33 11-33-23-21W4 51.0032316, -112.8801357

I Severn 16-33 16-33-25-22W4 51.1815103, -113.0080699

J Hussar Crowfoot 08-20 08-20-24-22W4 51.0578695, -113.0313011

The following two maps show the locations of the thirty-two (32) vent gas capture

systems that were commissioned in 2014 and are the subject of this offset project

plan.


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Figure 1 – Vent Gas Capture Project Locations (Map 1)

Figure 2 – Vent Gas Capture Project Locations (Map 2)

Is the Yes, all of the sub-projects that make up this aggregated Project are located in


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project

located in

Alberta?

Alberta.

Project

boundary

The boundary for this aggregated Project encompasses thirty-two (32) distinct gas

compression facilities in Alberta. These field booster compressor stations operate

within a natural gas gathering system in order to gather and compress natural gas

for distribution to central processing facilities where the gas is dehydrated and

input into a sales pipeline. Each field booster compressor typically consists of a

single compressor driven by a natural gas-fueled reciprocating engine. These sites

typically do not have electricity and therefore rely on natural gas-driven pneumatic

systems for process control.

At each facility the vent gas capture systems were installed as retrofits to the

existing natural gas-driven pneumatic instrumentation systems to reduce venting

of instrument gas (fuel gas), which contains primarily methane. The vent gas

capture technology does not require any incremental gas compression or electricity

to operate so there are no additional energy inputs required to capture the vented

gas. This is achieved by inputting the low pressure vent gas into the engine air

intake, which operates under vacuum.

The projects do not include any rich-to-lean engine modifications to alter the air-

fuel ratio of the engines in order to achieve fuel savings. In all cases, the engines

were already lean-burn engines and the scope of the project was limited to the

installation of vent gas capture systems.

The vent gas capture systems were integrated with the existing pneumatic gas-

driven instrumentation and controls without altering the function of the natural gas

compression equipment at the site. The vents from the existing pneumatic control

loops were collected with a common vent header with the gas directed through a

valve train that includes metering equipment and safety systems to allow the

system to revert back to the original venting configuration in the event the vent

gas capture system is offline. Therefore, the vent gas capture system is

functionally equivalent to the original instrument gas system as the same level of

service (pressure) is provided.

Ownership This Project consists of an aggregation of greenhouse emission reductions from

thirty-two (32) vent gas capture projects. Ember Resources has a 100% working

interest in 1 of the facilities. To facilitate verification and registration of offsets

from the Project facilities, Ember is acting as the aggregator of offsets on behalf of

the working interest owners of the other facilities. Ownership has been established

through written agreements for the sub-projects that are not operated or owned

by Ember. These agreements will be updated as needed during subsequent

reporting periods. No other parties could reasonably claim entitlement to any other

benefit associated with the emission offsets.

2.1 Project Description

This aggregated project involves the use of a new and innovative vent gas capture technology

called SlipStream®, developed by REM Technology Inc. The SlipStream® technology integrates

with the existing lean-burn engine and the existing pneumatic gas-driven instrumentation and

controls at each site without altering the operation or output of the engine or the gas

compressor. The vent gas capture technology does not require any incremental gas

compression or electricity to operate so there are no additional energy inputs required to

capture the vented gas. This is achieved by inputting the low pressure vent gas into the engine

air intake, which operates under vacuum.


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The retrofit of the vent gas capture system involved installing a new valve train and associated

piping to deliver the captured vent gas from a common piping header to the air intake of the

engine. The SlipStream® system is installed to safely control the input of the vent gas into the

engine, reducing the main fuel supply to the engine by an equal amount.

The sub-projects do not include any rich-to-lean engine modifications to alter the air-fuel ratio

of the engines in order to achieve fuel savings. In all cases, the engines were already lean-burn

engines and the scope of the project was limited to the installation of vent gas capture systems.

The vent gas capture systems were integrated with the existing pneumatic gas-driven

instrumentation and controls without altering the function of the natural gas compression

equipment at the site. The vents from the existing pneumatic control loops were collected with

a common vent header with the gas directed through a valve train that includes metering

equipment and safety systems to allow the system to revert back to the original venting

configuration in the event the vent gas capture system is offline. Therefore the project and

baseline conditions are functionally equivalent.

2.2 Protocol

The Project will be quantified using the Quantification Protocol for Engine Fuel Management and

Vent Gas Capture Projects” Version 1.0, October 2009 (Herein referred to as “The Protocol”) for

the initial crediting period, up to no later than January 1, 2019, at which time the Project will be

quantified using the Quantification Protocol for Engine Fuel Management and Vent Gas Capture”

Version 2.0, June 2018. An updated offset project plan will be submitted when the Project

transitions to using Version 2 of the Protocol.

The quantification protocol is applicable to the Project because the Project involves the

implementation of technology to capture and combust gases (containing primarily methane)

that are vented to the atmosphere as part of normal baseline operations at natural gas

compressor stations. The table below outlines how the Project meets the applicability

requirements in the Protocol.

Table 4 - Assessment of Protocol Applicability Criteria

Criteria Proponent Justification

1. The engine modification must not impair the

functionality of the unit, process or overall facility such

that additional energy inputs are required as

demonstrated by facility process flow diagrams and/or

unit operational performance data. Unit operational data

may include engine operating hours, records of down

time or other records to demonstrate that the

combustion of captured vent gases does not de-rate the

engine or cause a significant increase in down time (and

potentially increase compressor start gas emissions).

The project proponent would need to show that the use

of other units (engines) and/or supplemental fuels is not

needed to compensate for increased parasitic loads,

reduced fuel energy content and/or decreased engine

power output. Functional equivalence may be

demonstrated through an affirmation from the project

developer or other qualified third party;

The use of vent gas as a supplemental

fuel for engines does not impact

engine functionality or performance.

The SlipStream® vent gas capture

systems do not create significant

parasitic loads on the engine and

therefore no incremental fuel

consumption is required to operate

these devices. As such, functional

equivalence is maintained.

2. There must not be any regulations requiring the

capture and destruction or conservation of vent gas

emissions from the processes and/or units impacted by

the Project activity that have been quantified in the

baseline as vented GHG emissions under SS B5b Venting

The vent gases captured under this

aggregation Project are not subject to

Directive 60 as these vent gases are

small emission sources (e.g.

instrument vents) that cannot sustain


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of Emissions Captured in the Project. Project proponents

should refer to the November 16, 2006 version of the

Alberta Energy and Resources Conservation Board

(ERCB) Directive 60 (D60) Upstream Petroleum Industry

Flaring, Incineration and Venting for further guidance on

restrictions on flaring and venting of solution gas and

other types of vent gases. D60 provides sector specific

performance standards for flaring and venting that must

be met by operators as well as decision trees to evaluate

whether gas can be economically conserved instead of

vented or flared. Conservation opportunities are

evaluated as economic or uneconomic based on the

criteria listed in Section 2.8 of D60. It should be noted

that D60 does not prescribe any one particular

conservation option and the use of solution gas for

supplemental fuel could be compared to re-injection of

the solution gas for reservoir pressure maintenance as a

conservation option, each with significantly different

GHG implications.

The following guidelines are intended to assist project

proponents in evaluating whether their project activity of

capturing a vent gas stream may be considered to be

surplus to regulation, but should in no way be seen as

an exhaustive list of requirements or a replacement for

the guidance in D60 and other regulations enforced by

the ERCB or AESRD.

a. If the ERCB determines that an individual source

of vent gas has sufficient flow rate to sustain

stable combustion and must be flared according to

D60 Section 8.1, then the project proponent will

not be eligible for offsets from venting in the

baseline under SS B5b.

b. If a project is not covered under criteria 3.a) but

involves the recovery and use of solution gas at

levels exceeding the 900 m3/day threshold

specified in Section 2.3 of D60 and is also deemed

to be economic to implement one or more

conservation activities as specified in Section 2.8

of D60, then the Project may not be eligible for

offsets from venting under SS B5b. If the

captured volume of solution gas cannot sustain

stable combustion and is less than the threshold

or deemed to be uneconomic to conserve then the

Project activity may be eligible for offsets from

venting.

c. As stated in Section 8.3 of D60, if the total

facility benzene emission limits specified in

Directive 039 Revised Program to Reduce Benzene

Emissions from Glycol Dehydrators are exceeded

at the Project site then venting may not be

permitted and the Project may not be eligible for

stable combustion on their own. The

captured vent gases included under

this aggregation Project do not

include solution gas or off-gases from

glycol dehydration operations, and as

such, solution gas conservation,

benzene emission regulations and/or

flaring requirements under Directive

60 are not applicable. No other

regulations would require the capture

or conservation of the vent gas

sources included under this

aggregation Project.


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offsets from venting in the baseline under SS B5b.

3. For Projects where the combustion of vent gases is

required under D60 (or other applicable regulation) or

where the baseline practice already involved the flaring

or incineration of the waste gas stream, then the

baseline condition is the flaring of the waste gas stream.

The project proponent can claim offsets following the

Flexibility Mechanism in Appendix A of the protocol, to

quantify GHG reductions from reduced fuel gas

consumption for flaring and engine operation. The

project proponent must demonstrate that the re-

direction of the waste gases to the engine actually

results in reduced flare fuel usage as evidenced by

metered volumes of waste gas sent to flare/incinerator

and/or volumes of supplemental fuel consumed or

through engineering designs for the flare/incinerator

unit;

Not applicable. The baseline condition

for all sites under this aggregated

offset Project is the venting of

methane to the atmosphere as

evidenced through engineered vents

and associated piping in existence at

each compressor station. None of the

sites previously employed flares or

incinerators and flaring was not

required under Directive 60.

4. The boundary of the Project activity must not

include the quantification of baseline GHG emissions

from engine fuel combustion and vent gas emissions

that are subject to regulation under the Alberta Specified

Gas Emitters Regulation (SGER).

None of the facilities included under

this aggregation program are subject

to the Carbon Competitiveness

Incentives Regulation (CCIR, formerly

the SGER).

5. The quantification of reductions achieved by the

Project is based on actual measurement and monitoring

(except where indicated in this protocol) as indicated by

the proper application of this protocol; and,

The GHG reductions have been

quantified using metered data in

accordance with the Quantification

Protocol for Engine Fuel Management

and Vent Gas Capture.

6. The Project must meet the requirements for offset

eligibility as specified in the applicable regulation and

guidance documents for the Alberta Offset System. Of

particular note:

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;

All of the vent gas capture units

included under this aggregation

Project were installed after January 1,

2002. The first installation was

commissioned on January 16, 2014

and subsequent systems were

commissioned later in 2014.

b. The Project may generate emission reduction

offsets for a period of 8 years unless an extension

is granted by AESRD, as indicated by facility and

offset system records. Additional credit duration

periods require a reassessment of the baseline

condition; and,

All of the installations included under

this aggregation Project will claim

offsets for a period of eight years

from the date that commercial

operation of the first vent gas capture

system was achieved. A further 5

years of offsets will be claimed for

each installation, should an extension

to the crediting period be granted by

AEP.


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c. Ownership of the emission reduction offsets must

be established as indicated by facility records. This Project consists of an

aggregation of greenhouse emission

reductions from thirty-two (32) vent

gas capture projects. Ember

Resources is the operator of and owns

a 100% working interest in 1 of the

facilities. To facilitate verification and

registration of offsets from the Project

facilities, Ember is acting as the

aggregator of offsets on behalf of the

other owners of the facilities.

Ownership has been established

through written agreements for the

32 sub-projects. These agreements

will be updated as needed during

subsequent reporting periods. No

other parties 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 and no other protocols were used in the

quantification. The Quantification Protocol for Engine Fuel Management and Vent Gas Capture is

not currently “flagged”, but version 1 of the protocol (October 2009) was replaced with a new

version (2.0) in June 2018. Consistent with Alberta Environment and Parks guidance on

protocol withdrawals and replacements,1 the Project will cease using version 1 of the Protocol

for activities beginning no later than Jan 1, 2019 and no earlier than January 1, 2018. This

offset project plan covers activities from August 1, 2016 to Dec 31, 2017 and therefore still

uses the October 2009 version (v1) of the Protocol. An updated offset project plan will be

submitted when the Project transitions to the updated (Version 2) Protocol.

2.3 Risks

There are a number of risks that could impact the performance of the 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 vent gas meters are calibrated annually by qualified

technicians and are common types of meters that Ember technicians and

contractors are familiar with maintaining.

o Vent gas capture equipment failure could lead to facility blowdowns (venting),

downtime or other issues. The vent gas capture systems are all designed to be

1 aep.alberta.ca/climate-change/guidelines-legislation/specified-gas-emitters-regulation/documents/EmissionsOffsetRevision-Apr06-2018.pdf


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fail-safe and are designed to return back to the original pneumatic control system

configuration (venting to atmosphere) if the vent gas capture system goes

offline.

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 vent gas capture systems at existing natural

gas processing and compression facilities to reduce 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 a vent gas capture system. This risk is mitigated by

the fact that Ember operates a large number of other vent gas capture projects

and instrument air conversion 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. This Project consists of thirty-two (32) sub-projects that were voluntary

installations of vent gas capture technology in order to reduce methane emissions

from pneumatic devices at the facilities beginning in 2014, ahead of any

regulatory requirements. There are currently no requirements to reduce methane

emissions at these facilities and since the Project has already greatly reduced

methane emissions, these facilities are not expect to be impacted by future

methane regulations.

o Project level additionality, in terms of common practice, is assessed at the

protocol development stage. The Protocol was approved in 2009 and as of year-

end 2017 only a handful of other companies appear to be operating vent gas

capture emission offset projects in Alberta. All of these factors support the fact

that vent gas capture retrofits are not common practice.

o Regulatory additionality is also continuously monitored. At this time, there are no

regulations requiring the use of vent gas capture systems or requiring the retrofit

of existing pneumatic control systems with lower emitting technologies to reduce

methane emissions.

Other Risks

o There are not expected to be any scenarios that could result in double counting of

emission offsets since ownership letters have been signed with each of the

working interest owners in the thirty-two (32) sub-projects that make up this

aggregated Project. These agreements will be updated as needed during

subsequent reporting periods.

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 any of the thirty-two (32) facilities

where the sub-projects are located.

The annual quantity of GHG emission reductions from this Project may vary from year to year

depending on facility downtime, commodity prices and other


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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 engine fuel management

and/or vent gas capture projects are outlined in the figures below based on guidance from the

Quantification Protocol for Engine Fuel Management and Vent Gas Capture Projects” (Version

1.0, October 2009). These figures represent general sources and sinks of emissions that are

relevant to most engine fuel management and vent gas capture projects. Sources and sinks of

emissions that are relevant to the Ember Resources Vent Gas Capture Aggregation Project

Phase 3 have been summarized in the subsequent section with rationale provided for the

inclusion or exclusion of each source.

Figure 3 – Baseline Sources and Sinks of Emissions

Figure 4 – 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.


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Table 5 - Included Sources and Sinks and Quantification Methods

Relevant Source, Sink

Controlled. Related, or

affected

Source Method

Baseline

B1 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 B5b) 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).

B5b 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 vent gas capture rates and vent gas compositions and densities at each sub-project facility.

Project

No sources and sinks are quantified for the project condition.

Based on the specific configuration of the Ember Resources Vent Gas Capture Aggregation Project

Phase 3, a number of the generic sources and sinks identified in the Quantification Protocol for

Engine Fuel Management and Vent Gas Capture Projects” (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, four 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.

P1 Fuel Extraction/ Processing – Excluded as this source of emissions is accounted for

under SS B1, as specified in the Protocol on page 29.

P4 / B4 Unit Operation - Excluded since the total engine fuel usage at each site is not

impacted by the implementation of the vent gas capture equipment. The scope of the

Project is limited to the implementation of vent gas capture systems and does not include

any rich-to-lean conversions to reduce fuel gas usage. The composition of fuel burned in

each compressor engine does not change from the baseline to the project since the vented

instrument gas (fuel gas) is from the same source as the engine fuel gas (ie there is a

single compressor at each site and only a single supply of natural gas available for both fuel

and for pneumatic instrumentation). Since the composition of fuel gas and vent gas is the

same, the captured vent gas displaces fuel gas on a one-for-one basis so there is no change

in emissions under SS P4/B4 and therefore these sources and sinks have been excluded as

they are not applicable to Ember’s Project configuration.

P5b Capture of Vent Gases - Excluded as this source of emissions is accounted for under

SS B5b, as specified in the Protocol on page 29.


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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 in the Engine Fuel Management and Vent Gas Capture Protocol is defined as

the fuel consumption of the engine under its original configuration prior to the installation of the

engine fuel management system and/or the venting of gases containing methane to the

atmosphere.

Ember’s Vent Gas Capture Aggregation Project Phase 3 does not include the installation of engine

fuel management systems to reduce fuel combustion in reciprocating engines since all the engines

were already lean-burn engines. The scope of the project activity is limited to the capture and

combustion of natural gas, containing primarily methane, which was previously vented to the

atmosphere via dedicated process vents. These vents are designed to safely vent natural gas to the

atmosphere from pneumatic instrumentation systems used to control the operation of each

compressor. The baseline emissions are therefore equal to the quantity of methane that would

have been vented to the atmosphere in the absence of the installation of the vent gas capture

technology. Baseline emissions are determined based on direct measurement of the mass of vent

gas captured in the project condition and the composition of that captured vent gas.

Additionally, due to the configuration of Ember’s vent gas capture projects, the capture and

combustion of vent gas in each engine results in the displacement of an equal amount of fuel input

to the engine. Only one fuel gas supply source exists at each booster compressor location so the

fuel gas that is used in the engine and the vent gas that is captured from the pneumatic

instrumentation systems come from the same supply source (e.g. it is fuel gas that is being vented

from the pneumatic instrumentation systems). Therefore, when vent gas is captured and re-

directed into the engine, the result is a one-for-one displacement because the composition and

energy content of the vent gas are the same as that of the primary fuel gas supplied to the engine.

This one-for-one displacement means that the vent gas capture retrofits do not change the volume

of fuel combusted in the engine from baseline to project (fuel comes from two sources in the

project versus one source in the baseline, but the total quantity of fuel input is the same) and the

combustion emissions from the engine are unchanged since the composition of the fuel supplied to

the engine is also unchanged. Therefore the emissions under SS B4 “Unit Operation” can be

excluded from the quantification.

The use of vent gas as a supplemental fuel for an engine does not impact engine functionality or

performance as the SlipStream® vent gas capture system does not create significant parasitic loads

on the engine and therefore no incremental fuel consumption is required to operate the vent gas

capture system. Therefore, the project and baseline scenarios are functionally equivalent.

The baseline volume of vented natural gas is determined under source “B5b” based on the metered

quantity of vent gas captured in the project condition and the methane content in the vent gas.

The baseline approach is projection-based.

The baseline emissions associated with the upstream extraction and production of natural gas

under source “B1” are estimated based on the volume of natural gas calculated under B5b 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 sub-project facilities, the baseline emissions are estimated to be approximately

20,200 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

This aggregated project involved the installation of SlipStream® vent gas capture technology at

thirty-two (32) natural gas booster compressor stations across southern Alberta in order to

capture and combust vented gas, containing primarily methane. The SlipStream® technology

integrates with the existing lean-burn engine and the existing pneumatic gas-driven

instrumentation and controls at each site without altering the operation or output of the engine

or the gas compressor. The vent gas capture technology does not require any incremental gas

compression or electricity to operate so there are no additional energy inputs required to

capture the vented gas. This is achieved by inputting the low pressure vent gas into the engine

air intake, which operates under vacuum.

Each vent gas capture system was installed as a retrofit to an existing compressor station,

which involved installing a new valve train and associated piping to deliver the captured vent

gas from a common piping header to the air intake of the engine. The standardized valve train

includes a mass flow meter to continuously measure the quantity of vent gas that is combusted

in the engine at each site. The SlipStream® system safely controls the input of the vent gas into

the engine, reducing the main fuel supply to the engine by an equal amount.

The sub-projects do not include any rich-to-lean engine modifications to alter the air-fuel ratio

of the engines in order to achieve fuel savings. In all cases, the engines were already lean-burn

engines and the scope of the project was limited to the installation of vent gas capture systems.

3.2.3 Functional Equivalence

The vent gas capture systems were integrated with the existing pneumatic gas-driven

instrumentation and controls without altering the function of the natural gas compression

equipment at the site. The vents from the existing pneumatic control loops were collected with

a common vent header with the gas directed through a valve train that includes metering

equipment and safety systems to allow the system to revert back to the original venting

configuration in the event the vent gas capture system is offline.

The use of vent gas as a supplemental fuel for an engine does not impact engine functionality

or performance as the SlipStream® vent gas capture system does not create significant

parasitic loads on the engine and therefore no incremental fuel consumption is required to

operate the vent gas capture system. Therefore the project and baseline conditions are

functionally equivalent.

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 Engine Fuel

Management and Vent Gas Capture Projects” (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 Fuel Extraction/Processing + Emissions Venting of Emissions Captured in Project

Emissions Project = 0

Where:


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

Emissions Fuel Extraction/Processing = emissions under SS B1 Fuel Extraction/Processing.

Emissions Venting of Emissions Captured in Project = emissions under SS B5b Venting of Emissions Captured

under the Project.

Emissions Project = sum of the emissions under the project condition = 0.

3.3.1 Calculation of Baseline Emissions

The following formulas are used to calculate baseline emissions for each sub-project under SS B5b

and SS B1, respectively.

Since there are no sources of Project Emissions included in this aggregated offset Project, the net

GHG emission reductions are equal to the sum of the Baseline Emissions under SS B5b and SS B1.

The emissions under SS B5b are calculated according to the following formula:

1) Emissions SS B5b Venting of Emissions Captured in Project:

= ∑[(Mass VENT GAS /Density VENT GAS) * % CH4 * ρ CH4 * GWP CH4*.001 – (Emissions

Incremental Pneumatic Controllers)

Where,

Emissions SS B5b Venting of Emissions Captured in Project represents the calculated

value in tonnes of CO2e for the baseline emissions from the venting of methane (captured in

the Project condition) which is estimated based on the mass of vent gas captured and

combusted in the engine as supplemental fuel.

Mass VENT GAS is the mass of vent gas that was captured and combusted at each site,

obtained from continuous mass flow meter readings, which are averaged and reported on a

daily basis in units of kg/hour or total kg/day. The total mass of vent gas that is captured

and combusted each month is obtained by calculating the sum of the daily mass of captured

vent gas.

Density VENT GAS is the density of vent gas (kg/m3) at each site, which is obtained from

annual third party gas analyses, where the density is calculated from the composition of the

vent gas and reference values for densities at conditions of 15°C and 1 atmosphere.

% CH4 is the percentage methane by volume in the vent gas at each site, also obtained

from the annual third party gas analyses.

ρ CH4 = 0.6797 kg/m3, is the density of methane2 at standard conditions of 15°C and 1

atmosphere

GWP CH4 = 25, is the Global Warming Potential of methane, obtained from the Alberta

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

which is used to convert calculated methane emissions into carbon dioxide equivalent

(CO2e) emission units.

Emissions Incremental Pneumatic Controllers is an adjustment (in tCO2e/year) that is made to the

calculation of emissions under SS B5b in order to account for the incremental gas usage

associated with the addition of one to two pneumatic controllers to operate the vent gas

capture valve train (applicable to all sub-projects) and to operate the engine fuel control

valve (applicable to Waukesha engines only). The adjustment is made to avoid

overestimating the baseline emissions since the added controllers were not in service in the

baseline and they require a small amount of natural gas to operate in the project condition.

The instrument gas used to operate the controllers is still input into the vent gas capture

system upstream of the flow meter and is combusted along with the rest of the captured

vent gas. The section below provides the detailed calculation.

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

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


July 2018

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Calculation of Incremental Emissions from Pneumatic Controllers

The vent gas capture valve train that directs the captured vent gas into the engine includes certain

control elements to safely introduce vent gas into the engine and these control systems are driven

by pneumatic pressure, similar to the rest of the instrumentation in the compressor building

(generally these sites are not connected to the electricity grid so electrically-driven control valves

are not an option). An electro-pneumatic transducer, called a "Fisher I2P-100", is used to control

the introduction of vent gas into the engine. This I2P-100 transducer is a "Low Bleed" device, but it

does use some incremental instrument gas (fuel gas) to operate and this gas usage has been

deducted from the offset claim to ensure accuracy (despite the small amount of gas that is used to

operate this device).

These I2P-100 transducers are operated at either 20 pounds per square inch gauge (psig) or 35

psig and gas consumption rates were obtained from manufacturer specifications.3 For

conservativeness, the higher bleed rate value of 5.33 standard cubic feet per hour (scfh) at 35psig

was selected and applied as a deduction to all of the vent gas capture installations.

The same SlipStream® valve train design is used in all of the installations included under this

aggregated Project; however, for the sub-projects that were installed at sites with Waukesha

engines, an additional valve positioner was installed to improve control over the fuel flow into the

engine. This device is called a Fisher DVC 6200 valve positioner and is also a “Low Bleed” device.

The bleed rate of this device was estimated to be 3.3 scfh at 35psig based on manufacturer

specifications.4

The emissions from the operation of these incremental controllers are calculated based on the

bleed rate of the devices and the composition of the gas at each site, as shown below.

2) Emissions Incremental Pneumatic Controllers (tCO2e/year) = (Bleed Rate Controllers) *(1m3/

35.314 ft3)*(24 hours/day)*(Operating Days)* % CH4 * ρ CH4 * GWP CH4 * 0.001

tonnes/kg

Where,

Bleed Rate Controllers = the gas consumption rate in standard cubic feet per hour (scfh) of

the controllers installed to operate the vent gas capture system and the engine fuel control

valve. For the vent gas capture configuration with only one I2P-100 controller on the

SlipStream® valve train operating at a supply pressure of 35 psig, this value is equal to 5.33

scfh. For vent gas capture systems that use both an I2P-100 and a DVC 6200 positioner,

the total bleed rate is equal to the bleed rate of the positioner (3.3 scfh) plus the bleed rate

of the I2P-100 (5.33 scfh) which equals 8.63 scfh.

Operating Days = days per year that each vent gas capture unit has a measurable non-

zero flow rate.

% CH4 is the percentage methane by volume in the vent gas at each site, also obtained

from the annual third party gas analyses.


atmosphere


Environment and Parks Carbon Offset Emission Factors Handbook. The GWP is used to

convert calculated methane emissions into carbon dioxide equivalent (CO2e) emission units.

The emissions under SS B1 are calculated according to the following formula:

3) Emissions SS B1 Fuel Extraction/Processing:

3http://www.documentation.emersonprocess.com/groups/public/documents/instruction_manuals/d103198x012.pdf 4 Estimated using linear interpolation of values at 20psig (2.1 scfh) and 80psig (6.9 scfh) to determine bleed rate at 35psig. http://www.documentation.emersonprocess.com/groups/public/documents/instruction_manuals/d103409x012.pdf 5 http://encyclopedia.airliquide.com/Encyclopedia.asp?GasID=41

http://www.documentation.emersonprocess.com/groups/public/documents/instruction_manuals/d103198x012.pdf

http://www.documentation.emersonprocess.com/groups/public/documents/instruction_manuals/d103409x012.pdf



July 2018

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= [(Vol. Fuel * EF Fuel CO2 * GWP CO2) + (Vol. Fuel * EF Fuel CH4 * GWP CH4) + (Vol.

Fuel * EF Fuel N2O * GWP N2O)] * 0.001

Where,

Vol. Fuel = ∑[(Mass VENT GAS /Density VENT GAS);

Emissions SS B1 Fuel Extraction/Processing represents the calculated value in tonnes

of CO2e for the baseline emissions from fuel extraction and processing which is estimated

based on the volume of gas vented in the baseline and the reference emission factors for

fuel extraction and processing.

Vol. Fuel = Calculated value, expressed in m3/year. The volume of fuel gas used in the

baseline is calculated as the total mass of vent gas captured per year divided by the density

of that vent gas.

EF Fuel GHG = Reference emission factors for fuel extraction and processing are from the

Alberta Environment and Parks Carbon Offset Emission Factors Handbook and are expressed

in kilograms of CO2, CH4 and N2O per m3 of natural gas.

GWP GHG = Global Warming Potential of each greenhouse gas obtained from the Alberta

Environment and Parks Carbon Offset Emission Factors Handbook. The GWPCO2 =1, GWPCH4

= 25 and GWPN2O = 298.

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

Baseline Emissions under SS B5b and SS B1

Parameter Description Units Source

Mass of Vent

Gas Captured /

Mass Vent Gas

Mass of vent gas captured and

combusted in the engine.

kg/

hour

Continuous direct measurement

of mass flow rate of vent gas

input into the engine at each

facility in units of kg/hour

averaging of measurements on a

daily basis.

Density of Vent

Gas / Density

Vent Gas

Density of Vent Gas. kg/m3

Direct measurement of

composition of vent gas at each

facility calculation of density

based on reference values,

completed annually by a third

party laboratory.

% CH4

Percent methane (by volume)

contained in the vent gas at each

facility.

%

volume

Direct measurement of

composition of vent gas at each

facility, completed annually by a

third party laboratory.

Density of

Methane /

0.6797 kg/m3 at 15°C and 1

atmosphere.6 kg/m3

At 15ºC 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/

Alberta Environment and Parks

Carbon Offset Emission Factors


4CH



July 2018

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Methane /


Handbook.

t CH4 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 mass flow rate of vent

gas captured. This calculated

value is then used to determine

the indirect upstream emissions

associated with fuel extraction

and processing under SS B1.

m3

natural

gas/

year

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.

KgCO2/

m3;

kgCH4/

m3;

kgN2O/

m3;



Handbook (version 1, March

2015), Table 4.

GWP GHG

Global Warming Potential of each

greenhouse gas, where the

GWPCO2 =1, GWPCH4 = 25 and

GWPN2O = 298.

t CO2e/

t GHG



Handbook (version 1, March

2015).

3.3.2 Sample Calculation

A sample calculation has been provided below for the 10-05-027-22W4 sub-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 SS B5b Venting of Emissions Captured in Project:

= ∑[(Mass VENT GAS /Density VENT GAS) * % CH4 * ρ CH4 * GWP CH4*.001 – (Emissions

Incremental Pneumatic Controllers)

Where the following data inputs were used in the calculation:

Collected Data Inputs:

Mass VENT GAS is the total mass in kg of vent gas that was captured and combusted at the

10-05-027-22W4 sub-project site over a full year, obtained from average flow meter

readings = 52,352 kg which is approximately 5.5kg/h on average.

Density VENT GAS is the density of vent gas at the 10-05-027-22W4 site, obtained from an

annual third party gas analysis = 0.691 kg/m3.

% CH4 is the percentage methane by volume in the vent gas at the 10-05-027-22W4 site,

obtained from an annual third party gas analysis = 97.99%.

ρ CH4 is the density of methane at standard conditions of 15°C and 1 atmosphere7 =

0.6797 kg/m3.

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

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

Emissions Incremental Pneumatic Controllers =35.65 tCO2e, as calculated below.


4CHGWP



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The emissions from the operation of the incremental controllers are calculated based on the bleed

rate of each device and the composition of the fuel gas at each site, as shown below.

2) Emissions Incremental Pneumatic Controllers (tCO2e/year) = (Bleed Rate Controllers) *(1m3/

35.314 ft3)*(24 hours/day)*(Operating Days)* % CH4 * ρ CH4 * GWP CH4 * 0.001

tonnes/kg

Where,

Bleed Rate Controllers = the total gas consumption rate in standard cubic feet per hour (scfh)

of the two controllers installed to operate the vent gas capture system. The system at this

site includes two controllers, with one I2P-100 controller used on the standard SlipStream®

valve train and a Fisher DVC 6200 valve positioner was added for added fuel control

(Standard for all sub-project sites with Waukesha engines), this value is equal to 5.33 scfh

+ 3.3 scfh = 8.63scfh, based on the conservative assumption that both controllers operate

at a supply pressure of 35psig.

Operating Days = days per year that each vent gas capture unit has a measurable non-

zero flow rate. Assumed to be 365 days for this sample calculation.

% CH4 is the percentage methane by volume in the vent gas at the 10-05-027-22W4 site,

obtained from an annual third party gas analysis = 97.99%.


atmosphere


Environment and Parks Carbon Offset Emission Factors Handbook. The GWP is used to

convert calculated methane emissions into carbon dioxide equivalent (CO2e) emission units.

By plugging the above values into Equation 1) and 2), the baseline emissions under SS B5b were

calculated to be 1,230.21 tCO2e over the 365 day operating period.

3) Emissions SS B1 Fuel Extraction/Processing:

= [(Vol. Fuel * EF Fuel CO2 * GWP CO2) + (Vol. Fuel * EF Fuel CH4 * GWP CH4) + (Vol.

Fuel * EF Fuel N2O * GWP N2O)] * 0.001

Where,

Vol. Fuel = ∑[(Mass VENT GAS /Density VENT GAS);

Vol. Fuel = ∑[(Mass VENT GAS /Density VENT GAS) = 52,352 kg/ 0.691 kg/m3 =75,762.66

m3.

GWP GHG = Global Warming Potential of each greenhouse gas obtained from the Alberta

Environment and Parks Carbon Offset Emission Factors Handbook (v1, March 2015). The

GWPCO2 =1, GWPCH4 = 25 and GWPN2O = 298.

EF Fuel GHG = 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).

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




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By plugging the above values into Equation 3), the baseline emissions under SS B1 were estimated

to be 15.16 tCO2e over the 365 day operating period.

The total baseline emissions are equal to the sum of emissions under B5b and B1 (1,230.21

+15.16), which equals 1,632.05 tCO2e. Since the project emissions equal zero, the Net GHG

reductions are equal to the sum of the baseline emissions which is 1,245.37 tCO2e.

Based on the above calculation inputs, the hypothetical GHG emission reductions for the 10-05-

027-22W4 sub-project were calculated to be approximately 1,245 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 Calculation9

Total Baseline Emissions (B5b +

B1) (t CO2e)

Total Project Emissions (t CO2e)

Net GHG Emission Reductions (t CO2e)

1,245.37 0 1,245.37

3.4 Monitoring Plan

The primary parameters used to calculate emission offsets from the Project are the mass of

vent gas captured and percent methane in that vent gas at each sub-project facility.

A dedicated thermal mass flow meter is used at each site to measure the mass of vent gas that

is captured and combusted. The captured vent gas stream is directed through a valve train,

which allows for metering of the vent gas and provides control over the flow of the vent gas

into the engine air intake. The mass flow rate of vent gas into the engine air intake is

monitored continuously with measurements taken every 0.5 seconds. The compressor PLC

(Programmable Logic Controller) sends the measured data to the remote terminal unit (RTU) at

each site which calculates the mass flow (kg/hr) of the captured vent gas. The SCADA system

(Supervisory Control and Data Acquisition) polls each compressor station approximately every

15 minutes and collects and stores the data. Daily average mass flow rates in kg/day or

kg/hour are stored in the SCADA system and can be viewed or downloaded as required.

The calculation of baseline emissions under B5b for each sub-project is performed by using the

aggregated mass flow rates of vent gas captured and the density and percent methane in the

vent gas (fuel gas) at each facility. The percent methane and densities are obtained directly

from 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 incremental emissions from

pneumatic controllers are estimated based on the operating days for each vent gas capture unit

and the bleed rate of the pneumatic controllers, which is obtained from manufacturer

specifications. For the purpose of this calculation, operating days are defined as any days where

the flow of vent gas through the meter is greater than zero. These incremental emissions are

deducted from the calculated baseline emissions in the summary spreadsheet.

The calculation of baseline emissions under B1 does not require any additional monitored data

as the baseline volume of natural gas displaced is already calculated under B5b based on the

metered mass of vent gas captured in the project condition. The emission factors for natural

gas extraction and processing are reviewed and updated each reporting period, if necessary.

9 Note totals may not add up due to rounding.


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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 B5b – Baseline Vented Gas

Data parameter Mass of vent gas captured and combusted in the engine at each sub-project.

Estimation, modeling,

measurement or calculation

approaches

Direct measurement of mass flow rate of vent gas

input into the engine at each sub-project facility.

Data unit kg/hour or kg per day at each sub-project facility.

Sources/Origin Direct metering of mass flow rate of vent gas input into the engine on a continuous basis at each sub-

project facility.

Sampling frequency Continuous

Description and justification of monitoring method

This is the most accurate method of measuring this parameter.

Uncertainty Based on meter specifications. An annual field meter verification (“proving”) procedure is performed to

ensure each meter is functioning correctly. Proving each meter in the field is an alternative to sending each meter back to the factory for a factory calibration.



Data parameter Percent methane in vent gas

Estimation, modeling, measurement or calculation

approaches

Direct measurement of gas composition at each sub-project facility by third party lab.

Data unit % methane

Sources/Origin Direct samples of vent gas taken annually at each sub-project facility by third party.

Sampling frequency Annual


This is the most accurate method of measuring this parameter. Changes in gas composition are infrequent


July 2018

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so annual samples are appropriate.

Uncertainty N/A.



Data parameter Density of vent gas

Estimation, modeling, measurement or calculation approaches

Direct measurement of gas composition at each sub-project facility by third party lab and calculation by the lab of density based on reference densities for each compound. Density values are obtained directly from

lab report.

Data unit kg/m3

Sources/Origin Direct samples of vent gas taken annually at each sub-project facility by third party.

Sampling frequency Annual


This is the most accurate method of measuring this parameter. Changes in vent gas composition are infrequent since the vented gas is the same as the fuel gas at each site so annual samples are appropriate.

Uncertainty N/A.

3.5 Data Management System

Five 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 5 – 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 mass flow meters are ‘proved’ annually by conducting a field

verification of each meter using a factory calibrated meter that is connected to proving taps

that were installed on the SlipStream® valve train that allow the factory calibrated meter to

operate in series with the in-situ field meter. This configuration allows the technician to

measure the vent gas flow rate using both meters at the same time to confirm that

measured flow rates are comparable from each meter and are within acceptable tolerances;

3. SCADA system polls meter for vent gas flow rate and stores data from each site

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 Pneumatic Device Bleed Rate Specifications (One Time)

2. Continuous measurement of mass flow rate of vent gas

with dedicated thermal mass flow meter at each site.

Operating days of incremental pneumatic

devices determined based on number of days with meter

flow rate greater than zero

5. Aggregation of data from each site and annual

reporting of GHG emission reductions

Supporting Documentation:

1. Annual Meter Field Verification

(Proving) Record

2. Emission Factors for Fuel/ Extraction and Processing

3. Global Warming Potentials

1. Annual gas analyses by third party to determine %

methane and density of vent gas at each site

4. Ongoing data collection and storage using SCADA


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

third party consultant 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/or 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 Vent Gas Capture Aggregation Project Phase 3

Signature: ________________________________________

Name: Steve Gell, P.Eng

Title: Vice President, Production

1


July 2018

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5.0 References

Alberta Government. Quantification Protocol for Engine Fuel Management and Vent Gas Capture

Projects” Version 1.0, October 2009.

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

Documents

Ember Resources Vent Gas Capture Aggregation Project … › docs › c0c6eb47369f49448ec6bd07660465d9.pdfEmber Resources Vent Gas Capture Aggregation Project Phase 3 July 2018