Application for Approval of Peace River Oil Sands Carmon Creek Project

Shell Canada Limited
2011-09-22
Alberta Energy Resources Conservation Board

Application for Approval of Peace River Oil Sands

Carmon Creek Project

Submitted by: Shell Canada Limited

Submitted to: Alberta Energy Resources Conservation Board and to Alberta Environment

SEPTEMBER 2011

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Shell Canada Limited

400- 4th Avenue S.W.

P.O. Box 100 , Station M Calgary, Alberta T2P 2H5 Tel (403) 691-3 111

IAelTlE!t www.tlel.ca

September 23, 2011

Mr. Steve Thomas, P. Eng.

Section Leader, In Situ Oil Sands Applications Energy Resources Conservation Board

640 - 5th Avenue SW

Calgary , Alberta T2P 3G4

 

Mr. Gary Sasseville

District Approvals Manager Alberta Environment

Second Floor, Provincial Building

9621 - 96 Avenue

Peace River, Alberta TBS 1T4

Dear Sirs:

Re:      Carmon Creek Project Supplemental Information Responses Round 2 ERCB Application No. 1637869

Amendment to ERCB Approval No. 8143J AENV EPEA Application No. 020-1642 Water Act File No. 21375

Plase find attached a CD of the responses to the Supplemental Information Requests (SIRs), Round 2, provided to Shell Canada Limited on May 24, 2011, for the Peace River In Situ Expansion Carmon Creek Project Application and EIA.

If you need any clarifications regarding the submitted information, please contact Martin Vandcnbeld at (403) 384-5327.

Martin Vandenbeld

Regulatory Lead - Canada

Encl.

cc:        Brad Gilmour, Bennett Jones LLP

Carmon Creek Project

Supplemental Information Round 2

September 2011

OVERVIEW

PURPOSE

This document provides responses to the Supplemental Information Requests (SIRs) Round 2 for the Shell Peace River In Situ Expansion Carmon Creek Project (the Carmon Creek Project or the project). Corrections to errors and omissions identified in the responses provided in Supplemental Information, Round 1, are also provided.

Since filing the application in January 2010, Shell has made some minor refinements to the project, such as:

  • using two test separators on a well pad instead of one
  • realigning the boundary the initial development area, resource development area and project area to exclude the areas north, south and west of the proposed central processing facilities where there are no proposed well pads
  • reducing the power line right-of-way from 13 m to 7 m, when power lines can be co-located adjacent to a road right-of-way

These minor changes do not substantively alter the project design or scope, and do not affect the project assessment. The project, at the time of submitting these supplemental information request responses, remains essentially as it was at the time of filing the application.

Shell is also working with other stakeholders, such as Aboriginal groups, through its comprehensive consultation process and will continue to meet with stakeholders to understand and attempt to resolve their concerns.

REGULATORY COMMUNICATION CONTACTS

All communication with Shell on this regulatory application should be directed to both:

Martin Vandenbeld                                  Mr. Brad Gilmour

Regulatory Lead                                      Bennett Jones LLP

Shell Canada Limited                               Barristers and Solicitors

400 – 4 Avenue S.W.                               4500 Bankers Hall East

PO Box 100, Station M                            Calgary, Alberta T2P 4K7

Calgary, Alberta T2P 2H5                        Tel: (403) 298-3382

Tel: (403) 384-5327                                 Fax: (403) 265-7219

Fax: (403) 691-2379                                email: gilmourb@bennettjones.ca

email: martin.vandenbeld@shell.com

ERRORS AND OMISSIONS

SUPPLEMENTAL INFORMATION ROUND 1 ERRATA

Section 2 and 5 Maps

Errata                           ERCB Figures 3-1, 18-1, 18-2 and 22-1

The initial development area shown in Figure ERCB 18-1 is different from that shown in figures ERCB 3-1, ERCB 18-2, ERCB 22-1.

Correction                    As discussed in the response to Supplemental Information Round 1, ERCB

SIR 3b, Shell revised its initial development area, resource development area and project area to exclude the areas north, south and west of the proposed central processing facilities (CPFs) where there are no proposed well pads. However, several figures used in the responses in Supplemental Information Round 1 did not accurately reflect these boundary changes. Table 1-2 provides a cross- reference to the Supplemental Information Round 1 figures and the updated versions presented here in the Supplemental Information Round 2 responses.

Table 1-1: Updated Figures from Supplemental Information Round 1 

 

 

Supplemental Information Round 1 Figure Number

Supplemental Information Round 2 – Updated Figure Number

ERCB 4-1

SIR 2, Figure 2-1

ERCB 10-1

SIR 2, Figure 2-2

ERCB 10-2

SIR 2, Figure 2-3

ERCB 10-3

SIR 2, Figure 2-4

ERCB 10-4

SIR 2, Figure 2-5

ERCB 10-5

SIR 2, Figure 2-6

ERCB 10-6

SIR 2, Figure 2-7

ERCB 10-7

SIR 2, Figure 2-8

ERCB 10-8

SIR 2, Figure 2-9

ERCB 10-9

SIR 2, Figure 2-10

ERCB 10-10

SIR 2, Figure 2-11

ERCB 18-1

SIR 2, Figure 2-12

Section 11, Terrestrial

Errata                           Subsection 11.1, AENV SIRs 100-158, page 11-6

In Supplemental Information Round 1, AENV SIR 105a, the site size of the CPFs was incorrectly given as 48 ha.

Correction                    The correct site size for the CPFs is 222.2 ha. See the response to SIR 24a for additional information on the total disturbance area of the CPFs.

Section 12, Health

Errata                           Subsection 12.1, AENV SIRs 167b and 168a, pages 12-17 to 12-19

The endpoint for the aliphatic C5-C8 group oral limit should not have been listed as nervous system effects in Supplemental Information Round 1, Table AENV 167-2.

Correction                    The basis of the endpoint is unknown, as stated in the toxicity profile from the human health risk assessment (HHRA) (see EIA, Volume IIA, Appendix 5A). Table AENV 167-2 has been revised and is presented here as Table 31-1, with the corrected entry in bold.

The response to Supplemental Information Round 1, AENV SIR 168a is correct. In the original HHRA, there were only two mixtures in the chronic oral assessment, i.e., hepatotoxicants and renal toxicants. No oral neurotoxicants mixture was included in the original assessment.

Section GL, Glossary

Errata                           Definition of H2, page GL-8 and MONG, page GL-11

Typographical errors occurred in the definition of H2 and MONG.

Correction                    The correct definitions are: 

  • H2 – The chemical formula for hydrogen (molecular ion).
  • MONG – The abbreviation for marsh.

Table 31-1: Chronic Oral Exposure Limits

 

 

COPC

Exposure Limit

(µg/kg bw/d)

 

 

Endpoint

 

 

Source

Volatile organic compounds

Dichlorobenzene

70

Liver and kidney effects

ATSDR

Formaldehyde

200

Kidney effects, gastrointestinal effects

US EPA *

Polycyclic aromatic hydrocarbons

Anthracene

300

(40)

Information not available

US EPA

Benzo(a)pyrene equivalent

0.0014

Gastrointestinal cancers

US EPA

Fluorene

300

(40)

Liver and kidney effects

US EPA *

Pyrene

30

Kidney effects

US EPA *

Petroleum hydrocarbon fractions

Aliphatic C5-C8 group

2,000

Unknown

RIVM

Aliphatic C9-C16 group

100

Liver effects

TPHCWG

Aromatic C9-C16 group

40

Liver and kidney effects

CCME

Aromatic C17-C34 group

30

Kidney effects

CCME

Note *: The exposure limits available for anthracene and fluorene are presented in this table. Because of the existence of a lower exposure limit for the petroleum hydrocarbon fraction group to which these substances belong (the aromatic C9-C16 group), the lower limit for the group was used. This group limit of 40 µg/kg-day is shown in brackets in this table.

Section 2.1

ERCB COMMERCIAL APPLICATION

CARMON CREEK PROJECT SUPPLEMENTAL INFORMATION ROUND 2

GENERAL SIRS 1 – 2

Question No. 1

Request                        SIR Response 1a, Page 2-1.

Regarding stakeholder notification and consultation, Shell has provided a list of four parties, including “local residents not directly affected by the project”, from which Alberta Environment has received statements of concern. The original supplemental information request solicited a discussion on any concerns or objections respecting the subject application and efforts to resolve them.

In its response, Shell has omitted reference to objections received by the ERCB from:

  • the Woodland Cree First Nation (Objection No. 18584),
  • Mikisew Cree First Nation (Objection No. 19068),
  • Donna Dahm (Objection No. 26902),
  • Diane Plowman (Objection No. 26903),
  • Bob Plowman (Objection No. 26904),
  • Jim Anderson (Objection No. 18884; existing from Application No. 1492110), and
  • Duncan First Nation (Objection No. 21133.

The ERCB expects Shell to communicate with members of the public and industry that raise concerns or objections respecting the proposed development to address specific questions and attempt to resolve concerns.

1a         Provide an outline of the specific concerns and objections raised by each party on record with the ERCB or Alberta Environment and any other party Shell is aware of with unresolved concerns.

Response         1a         Shell has received statements of concern (SOCs) from:

  • the Woodland Cree First Nation (Objection No. 18584)
  • Jim Anderson (Objection No. 18884, existing from Application No. 1492110)
  • the Mikisew Cree First Nation (Objection No. 19068)
  • the Duncan First Nation (Objection No. 21133)
  • Donna Dahm (Objection No. 26902)
  • Diane Plowman (Objection No. 26903)
  • Bob Plowman (Objection No. 26904)

Shell is not aware of any other party having unresolved concerns about the project.

Woodland Cree First Nation

In June 2007, the Woodland Cree First Nation (WCFN) submitted Objection No. 18584 to the previously filed Carmon Creek Application No. 1492110. However, Shell withdrew Application No. 1492110 in November 2008. Since 2009, Shell has engaged the WCFN in an effort to understand their concerns regarding the current Carmon Creek Project application. It was Shell’s understanding, through consultation with the WCFN, that the WCFN intended to review the current application and would submit any concerns to Shell regarding the project.

Furthermore, in the discussions with the WCFN, Shell indicated that it would not respond to Objection No. 18584.

To date Shell has not received any specific concerns or objections related to the current Carmon Creek Project application. In addition, Shell has offered to fund a third-party review of the application, which has not been pursued by the WCFN.

Table 1-1 is a log of Shell’s consultation with the WCFN. In addition, a copy of Shell’s June 29, 2011, letter outlining Shell’s recent communications with the WCFN concerning items of interest is provided as Attachment 1.

Jim Anderson

Shell received a letter of concern on June 14, 2007, from Mr. Anderson concerning the environmental and socio-economic impacts to the region relating to the previously filed Carmon Creek Application No. 1492110. Shell met with Mr. Anderson on December 14, 2007, to discuss the concerns raised and provided a response. Shell also sent a letter of acknowledgement to Mr. Anderson on December 17, 2007, concerning the meeting. Shell understands that these concerns have been addressed and are now closed.

Shell has not received any concerns or objections from Mr. Anderson regarding the current Carmon Creek Project application.

Mikisew Cree First Nation

The Mikisew Cree First Nation withdrew Objection No. 19068 in 2008. The objection related to the previously filed Carmon Creek Application No. 1492110. For this reason, Shell is requesting that this objection be removed.

Shell has not received any concerns or objections from the Mikisew Cree First Nation regarding the current Carmon Creek Project application.

Duncan’s First Nation

Shell has engaged the Duncan’s First Nation (DFN) since 2009 in an effort to understand the DFN’s concerns relating to the proposed project. In June 2010, the DFN submitted an SOC (Objection No. 21133), which included a report by Management and Solutions in Environmental Science Inc. submitted to Alberta Environment (AENV) and Shell (see Attachment 2). The concerns noted in the report relate to the environmental impact assessment (EIA) methodologies and conclusions. Shell has reviewed and responded to each concern raised in the SOC and has provided a response to the DFN (see Attachment 3).

Table 1-2 is a log of Shell’s consultation with the DFN.

Donna Dahm – Diane Plowman – Bob Plowman

 

The August 4, 2010, SOC letter signed by Donna Dahm (Objection No. 26902), Diane Plowman (Objection No. 26903), and Bob Plowman (Objection No.

26904) was submitted to the Energy Resources Conservation Board (ERCB). The SOC was provided to Shell in April 2011. The SOC listed concerns relating to the cumulative impacts of the project, the EIA methodology, air, water and infrastructure impacts, and the consultation process. Shell responded to these concerns in a letter dated July 28, 2011 (see Attachment 4).

In addition, Shell has responded by phone and email to inquiries and requests from Donna Dahm relating to the Carmon Creek Project and the ongoing Peace River Complex (PRC) operations (see Table 1-3 for the consultation log).

 

Request

 

1b

 

For each concern or objection raised, outline efforts Shell has undertaken in response.

 

Response

 

1b

 

For information concerning Shell’s responses to stakeholder concerns and objections, see the response to SIR 1a.

Table 1-1: WCFN Consultation Log

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Table 1-2: DFH Consultation Log

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Table 1-3: D. Dahm Consultation Log

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Question No. 2

Request                        SIR Response Figures ERCB 3-1, Existing and Proposed Development Areas, Page 2-5, ERCB 18-1, Wilrich Member Isopach, Page 5-5, ERCB 18-2, Location Map – Cross-Section and Sampling Wells, Page 5-6 and ERCB 22-1, Existing Project Area Layout, Page 5-13.

Figure ERCB 18-1 appears to indicate an initial development area that is different from the other figures referenced.

2a         Clarify the apparent discrepancy and review all figures provided in the supplemental information response to provide necessary updates to correct discrepancies.

As discussed in the response to Supplemental Information Round 1, ERCB

SIR 3b, Shell revised its initial development area, resource development area and project area to exclude the areas north, south and west of the proposed CPFs where there are no proposed well pads (see Supplemental Information Round 1, Figure ERCB 3-1). However, several figures used in the responses in Supplemental Information Round 1 did not accurately reflect these boundary changes. Table 2-1 provides a cross-reference to the Supplemental Information Round 1 figures and the updated versions presented here in this response.

Table 2-1: Updated Figures from Supplemental Information Round 1 

Supplemental Information Round 1 Figure Number

Updated Figure Number

ERCB 4-1

2-1

ERCB 10-1

2-2

ERCB 10-2

2-3

ERCB 10-3

2-4

ERCB 10-4

2-5

ERCB 10-5

2-6

ERCB 10-6

2-7

ERCB 10-7

2-8

ERCB 10-8

2-9

ERCB 10-9

2-10

ERCB 10-10

2-11

ERCB 18-1

2-12

 

Request

2b

Figure ERCB 4-1, Bluesky Net Pay Initial Development Area – First 18 Pads, Page 3-3

 

 

does not include a legend. Update the figure with the revised initial development area boundary and include a labeled ATS section grid as requested.

 

Response

 

2b

 

An updated version of Supplemental Information Round 1, Figure ERCB 4-1 is provided here as Figure 2-1.

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Figure 2-1: Bluesky Net Pay Initial Development Area -

First 18 Pads

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Figure 2-2: Lithofacies Classification 1 - R Below 2 Facies lsopach

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Figure 2-3: Lithofacies Classification 1 - R10 Facies lsopach

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Figure 2-4: Lithofacies Classification 1 - R10 20 Facies lsopach

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Fiqure 2-5: Lithofacies 1 R20 50 Facies Isopach

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Figure 2-6: Lithofacies Classification 1 - R Above 50 Facies lsopach

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Figure 2-7: Lithofacies Classification 2 - Shale Facies lsopach

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Figure 2-8: Lithofacies Classification 2 - Shaly Sand Facies lsopach

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Figure 2-9: Lithofacies Classification 2 - Bedded Sand Facies lsopach

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Figure 2-10: Lithofacies Classification 2 - Bedded Sand Facies lsopach

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Figure 2-11: Lithofacies Classification 2 - Cross-Section

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Figure 2-12: Wilrich Member lsopach

GEOLOGY SIRS 3 – 6

Question No. 3

Request                        SIR Response 2, Open-Hole Logging Waiver, Page 2-3.

Shell indicates that a reduced requirement for open-hole logging all wells will be requested and that it intends to run open-hole logs on all dedicated steam injection wells. Shells states “surrounding production wells might only be logged with a cased hole gamma ray tool. This will result in 64 fully logged wells in a fully developed section.”

Confirm that Shell is requesting an open-hole logging waiver for resistivity and spontaneous potential logs for production wells as part of the subject application and confirm that Shell will conduct a cased hole gamma ray log on every production well at a minimum.

Response         3          As a minimum, Shell will run either a gamma ray log while drilling or a cased hole gamma ray log in every well. Shell will request a waiver from the Oil and Gas Conservation Regulations 11.140(1) requirement for resistivity and spontaneous potential logs for production wells.

Question No. 4

Request                        SIR Response 4b, Page 3-1 and Figure ERCB 4-1, Bluesky New Pay Initial Development Area – First 18 Pads, Page 3-3.

The figure provided requires further annotation. Revise the map, at a 1:20 000 scale, labelling each pad (similar to Figure ERCB 22-1, Existing Project Area Layout) and indicate which injector and producer wells are associated with each pad. Include a labelled township and section grid.

Response         4          Supplemental Information Round 1, Figure ERCB 4-1 has been revised and is provided as Figure 2-1 (see the response to SIR 2). The figure revisions include:

  • a map scale of 1:20,000
  • a section grid
  • pad labels

identification of injector and producer wells associated with each pad

Question No. 5

Request                        SIR Response 5, Page 3-2.

Shell states, “The viscosity data requested are not standard and are considered by Shell to be proprietary.” As originally referenced, Shell’s application states that 2007 viscosity measurements have increased its understanding of the proposed development area. The ERCB’s General Bulletin 2001-15: Collection and Submission of Well Data to the EUB states, “in accordance with section 11.120 of the Oil and Gas Conservation Regulations, all pressure and deliverability test data that are collected must be submitted to the EUB, including any data over and above the minimum requirements of Guide 40. Likewise, all bitumen viscosity data that are collected must be submitted to the EUB.” Provide the requested core-determined viscosities.

Response         5          Table 5-1 shows the core viscosity data for the delineation wells in the development area.

Table 5-1: Core Viscosity Table

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Question No. 6

Request                        SIR Response 8, Page 3-5.

 

Shell states, “Based on 2-D and recent 3-D seismic acquisition, these faults appear to terminate at the sub-Cretaceous unconformity with the Paleozoic. There are no indications that any faults transgress through the Bluesky reservoir interval or within younger age sediments above.”

In its annual In Situ Oil Sands Progress Report, 2010 Shell Peace River Presentation 8143, Page 21, Shell illustrates a dip structural cross section and notes, “relief on Debolt surface up to 35 meters – possible fault, or karst cliff.Additionally, various publications, including Hubbard (1999) have made reference to Bluesky Formation faults.

Hubbard, S.M. 1999. Sedimentology and Ichnology of Brackish Water Deposits in the Bluesky Formation and Ostracod Zone, Peace River Oil Sands, Alberta. M.Sc. Thesis. University of Alberta. p. 31-32

 

Response 6a

Explain the apparent discrepancy between Shell’s supplemental information response and its 2010 progress report statement.

 

Response 6a

 Both Shell’s supplemental information response and the 2010 progress report refer to faults within the Paleozoic that appear to terminate at the sub-Cretaceous unconformity, and that do not transgress through the Bluesky oil sand interval. The sub-Cretaceous unconformity with the Paleozoic carbonates represents an erosional surface, which was exposed over a period of many millions of years.

The Cretaceous Bluesky oil sands are deposited over this unconformity.

 

In some areas of the proposed project development area, covered by the recent 3-D seismic surveys, there are deep valleys in the Paleozoic carbonates. These valleys have provided the largest accommodation space and, consequently, the

thickest deposition of Bluesky clastics. The edges that define these valleys in the Paleozoic structure could be the result of erosion, as well as possible karsting and faulting in the Paleozoic carbonates. A valley on the Paleozoic surface was illustrated on the geological cross-section in the 2010 Shell Peace River Annual Performance Review (shown here as Figure 6-1). The equivalent seismic section (traverse A-B) shows an absence of faulting indicating that the relief on the Debolt Formation in this area is likely because of erosion (see Figure 6-2).

Response 6b

Provide a depth migrated seismic section, over the proposed project area, with annotated tie-in wells that illustrate the above-referenced fault terminations at the sub-Cretaceous unconformity.

Response 6b

 As requested, Figure 6-3 shows a north-south seismic section (traverse C-D) with a fault that does not continue through the top of the Bluesky Formation.

 

 

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Figure 6-1: Dip Structural Cross-Section

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Figure 6-2: Pre-Stack Depth-Migrated Seismic Section (Traverse A-B)

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Figure 6-3: Pre-Stack Depth-Migrated Seismic Section Illustrating Fault Terminations at Sub-Cretaceous Unconformity (Traverse C-D)

Question No.

7

 

 

Request

 

 

SIR Response 18a, Page 5-2.

SIR Response 23c, Figure ERCB 23-2, Steam Injection and Bitumen Production Forecasts for One Inverted Seven-Spot Well Pattern, Page 5-18. SIR Response 26a, Page 5-21. SIR Response 26b, Page 5-22

 

 

Shell states, “Vertical steam drive is designed as a low –pressure steam drive. For all stages of the development, the intention is to minimize fractureing of the Bluesky reservoir. In general, Shell plans to operate the injection wells at bottomhole pressures of less than 13 MPa. However…injection pressure might temporarily be raised above the Bluesky reservoir fracture pressure. …The maximum tubing head injection pressure for all stages will be 14.3 MPa.”

 

7a

Provide a simulation plot similar to Figure ERCB 23-2 for both the steam injection well and production wells that illustrates the bottomhole injection pressure versus time with a time scale from 0 to 2920 days.

 

Response

 

7a

 

The requested simulation plots for injection bottomhole pressure (BHP) information are presented in Figure 7-1. In the half-pattern symmetry model, I001 is a dedicated steam injection well at the centre of the pattern, and wells I002, I003 and I004 are three of the surrounding six cyclic steam stimulation (CSS) wells.

 

Request

 

7b

 

Clarify how high the bottomhole injection pressure “might temporarily be raised” above the Bluesky reservoir fracture (breakdown) pressure and the caprock fracture closure pressure and clarify how long the bottomhole injection pressure might be temporarily raised above the Bluesky reservoir and caprock fracture closure pressure, including the injection volumes during this time period.

 

Response

 

7b

 

Shell does not intend to raise bottomhole injection pressure above the caprock fracture closure pressure. However, under some circumstances, bottomhole injection pressure might be temporarily raised slightly above the Bluesky

reservoir fracture closure pressure only.

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Figure 7-1: Simulated Injection BHP for Steam Injection and Production Wells

The QFlow model maximum predicted injection BHP will be 15.5 MPa, based on:

  • a maximum tubing head pressure (THP) of 14.3 MPa
  • a steam injection rate range of 50 t/d to 250 t/d

For details of the QFlow modelling, see the response to SIR 7e.

As stated in the response to Supplemental Information Round 1, ERCB SIR 18e: 

  • the measured fracture pressure of the Bluesky reservoir ranges from 13.2 MPa to 20.6 MPa
  • the measured fracture pressure for the Wilrich caprock is 21.5 MPa

The 6.0 MPa difference between the maximum predicted injection BHP of 15.5 MPa and the caprock fracture (breakdown) pressure represents a safety factor of more than 25%.

 

Although Shell has measurements of the Wilrich caprock fracture pressure, by

the end of 2012, Shell plans to acquire fracture closure pressure data from the

Wilrich caprock. Shell will provide this data to the ERCB.

During the first two 30-day steam injection cycles for the producers and the first

year and a half of steam injection for the injector, the BHP might temporarily be

above the Bluesky reservoir fracture pressure, but would be significantly below

the Wilrich caprock fracture pressure. The estimated steam injection volume

above the Bluesky reservoir fracture pressure will be about 7,500 t (250 t/d

*30 d) for each producer per cycle, and 99,000 t (180 t/d *550 d) for the injector.

For information concerning the timing of steam injection above 13 MPa injection

BHP, see the response to SIR 7c.

 

Request

 

7c

 

Provide Shell’s criteria and rationale for the scenario when it “might

 

 

temporarily” raise the bottomhole injection pressure above the Bluesky reservoir

 

 

fracture (breakdown) pressure, including the risks to the loss of steam

 

 

containment and caprock integrity during this period.

 

Response

 

7c

 

Shell would temporarily raise the BHP above the Bluesky reservoir fracture

 

 

pressure to improve injectivity, if the target steam injection rate of 150 t/d cannot

 

 

be achieved at a BHP below 13 MPa during:

 

 

  • the first two 30-day steam injection cycles for the producers
  • the first year and a half of steam injection for the injector

 

 

Because the maximum predicted steam injection BHP is about 6 MPa below the

 

 

caprock fracture (breakdown) pressure, the risk of loss of steam containment and

 

 

to caprock integrity is low. Containment risk is further reduced because of the 60

 

 

m to 80 m minimum caprock thickness (see the response to Supplemental

 

 

Information Round 1, ERCB SIR 18c), and the tendency of fractures to grow

 

 

horizontally (see the response to Supplemental Information Round 1, ERCB SIR

 

 

18e).

 

Request

 

7d

 

Based on SIR Response 26a and Figure ERCB 26-1, it appears that the planned

 

 

bottomhole injection pressure of the steam injection well is approximately 13

 

 

MPa during the first 2 years of steam injection when the associated production

 

 

wells are operated with cyclic steam stimulation (CSS).

 

 

i.    Explain the discrepancy between the planned bottomhole injection

 

 

pressure of 13.0 MPa at the steam injection well and the stated low–

 

 

pressure steam drive design.

 

 

ii. Discuss the rationale for proposing the maximum bottomhole injection

 

 

pressure of 13 MPa, including the risk to fracturing the caprock,

 

 

considering that the maximum bottomhole injection pressure should be

 

 

below the fracture closure pressure or minimum in-situ stress of the

 

 

 

reservoir or caprock with the incorporation of a safety factor to ensure steam containment and caprock seal integrity.

 

Response

 

7d

 

i.    The low-pressure steam drive design requires a short period of high pressure (i.e., 13 MPa) to establish communication between the injector and producer wells (see Figure 7-1). For more than half of the operational lifespan of an injector/producer well pattern the BHP will be below 4.0 MPa (i.e., low pressure).

 

 

ii. The rational for the proposed maximum steam injection pressure of

13.0 MPa is that it will be below:

 

 

  • the lower limit of the measured fracture pressure of the Bluesky reservoir (i.e., 13.2 MPa)

 

 

  • the anticipated Wilrich caprock fracture pressure of 21.5 MPa

Therefore, there will be a sufficient safety factor to ensure steam containment and caprock seal integrity (see the response to SIR 7b).

Request

7e

Provide the maximum bottomhole injection pressure corresponding to the proposed maximum tubing head injection pressure of 14.3 MPa and the supporting calculations.

 

Response

 

7e

 

The QFlow model maximum predicted injection BHP will be 15.5 MPa with a THP of 14.3 MPa, if the wellbore is full of water. Figure 7-2 shows the supporting model calculations.

 

Question No.

 

8

 

 

Request

 

 

SIR Responses 23a and 23b, Page 5-15 to 5-17.

 

 

Shell has described its model and the simulation results that support the proposed recovery processes. Provide the input and output files for the reference reservoir simulation model.

 

Response

 

8

 

Shell will provide the ERCB with this confidential data under separate cover subject to a confidentiality order request to be submitted to the ERCB.

Chart Graph Placeholder

Figure 7-2: QFlow Model Predicted Injection BHP

WELL OPERATIONS SIR 9

Question No. 9

Request                        SIR Response 17, Pages 5-1 to 5-2.

Regarding a review of well completion and abandonment status within the application area, Shell states that it will conduct such a review prior to submitting an application for a drilling license. The ERCB requires this review as part of the subject scheme application in order to evaluate the steam containment risks associated with the proposed development.

9a         Provide the requested review of wells in the area of initial pad development, including identification of all abandoned, suspended, and active wells drilled into the caprock top or deeper and identify wells that may pose a risk to steam containment.

Response         9a         As shown in Figure 9-1, the notional initial 18 well pads in the initial development area will be located:

  • northeast and adjacent to the existing Pad 19 soak radial wells
  • adjacent to the abandoned Peace River Expansion Project (PREP) Pad 11 and Pads 15 to 18
  • over the existing:
    • Pad 21, converted 1997 steam-assisted gravity drainage (SAGD) wells
    • Pad 40, producing CSS wells
    • Horizontal Well Demonstration Project (HWDP) wells

One hundred existing and abandoned wells will either border or be located underneath the initial 18 well pads. The 100 wells listed in Table 9-1 are categorized as: 

  • abandoned producer wells (49)
  • appraisal and delineation wells (4)
  • observation wells (8)
  • producing wells (27), including injector wells
  • shut-in or suspended wells (12)

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Figure 9-1: Notional 18 Well Pads in the Initial

Development Area

Table 9-1: Status of Wells Adjacent To or Below the Initial Development Area

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Abandoned Wells

Most of the abandoned wells (i.e., 45 wells) are PREP wells, located at the edges of Pad 11 and Pads 15 to 18. These PREP wells were cemented with thermal foamed cement and cased with L-80 grade material and premium connections.

The PREP wells were abandoned between 1999 and 2001 in accordance with the requirements of ERCB Directive 020, Well Abandonment. Abandonment consisted of setting a bridge plug within 5 m of the top of the Bluesky Formation, and spotting at least eight linear metres of thermal cement on top of the bridge plug, resulting in a final cement top extending at least 15 m above the top of the Bluesky Formation. Surface abandonment involved spotting a 1 m cement plug at least 4 m below ground level, cutting off the casing stub 1 m below ground level, and welding a plate on top of the casing stub.

In addition to the PREP wells, there are four nearby abandoned Peace River In Situ Pilot (PRISP) producer wells. The PRISP wells were abandoned in 1993 and 1994, in a manner similar to the PREP wells, in accordance with the ERCB’s thermal well abandonment requirements.

None of these wells are expected to pose a risk to downhole steam containment.

Appraisal and Delineation Wells

Three delineation wells and one appraisal well have been drilled in the initial development area:

  • well 5-27 (UWI 1AA052708518W5M00) drilled in 1972 as an appraisal well and abandoned as a dry hole without casing being run
  • well F60-90 (UWI 100132208518W500) drilled in 2008 as an observation well for the planned F60 demonstration well project to assess downhole well performance for the project well designs. The demonstration well project was cancelled in 2009. Well F60-90 will be converted into a temperature observation well for the project.
  • well F99-24 (UWI 1AA091508518W500) drilled in 2008, and remains a standing hole
  • well OBS OV 13-15-85-18 (UWI 1AA131508518W500) abandoned in 1972

Wells F60-90 and F99-24 were completed with thermally-suited casing, connections, and cement.

None of the delineation wells are expected to pose a risk to downhole steam containment.

Observation Wells

Eight temperature observation wells have been drilled and completed in the initial development area:

  • well TH2 (UWI 105012008518W500) for the 1996 SAGD wells
  • well TH11 (UWI 104051508518W500) and well TH12 (UWI 100121508518W500) for the 1997 SAGD wells (now referred to as Pad 21)
  • well TH40-A (UWI 107101008518W500) and well TH40-B (UWI 100121008518W500) for Pad 40
  • well DEL 1 OBS (UWI 100161708518W500), well DEL 2 OBS (UWI 1000091708518W500), and well DEL 3 OBS (UWI 1000081708518W500) for the HWDP wells

All of the observation wells, except for wells DEL 1, 2 and 3, have thermocouple strings installed in the wellbores with the wellbores cemented internally to surface with thermal cement. These wells are not deemed to pose a risk to future thermal operations, as the wellbores have been effectively abandoned.

Wells DEL 1, 2 and 3 were completed with 73-mm casing with a suspended thermocouple string in each. The 73-mm casing has a Hydril CS connection across the Bluesky Formation, and external upset ends connections to surface. These three wells have not been completed in a manner that would support a large-scale thermal development project. If these wells were to be used by the Carmon Creek Project, they would need to be cemented to surface with the thermocouple strings inside before the start of operation of the project. If these wells were not required by the project, then they would be abandoned before the start of project operation.

Producing Wells

A number of producing wells are located under the initial development area. These include Pad 21, Pad 22 and Pad 40 wells, which are currently operational. Because of limited cumulative oil recoveries to date, new wells will be placed in and around these existing wells. The existing wells might continue operation in unison with the new project wells, or might be abandoned before the start-up of any adjacent new project wells. If these wells continue to operate, then normal well integrity monitoring will be used to look for anomalies that could lead to steam containment failure. Well abandonment will be conducted in accordance with the requirements of ERCB Directive 020.

Shut-In Wells 

 

The shut-in wells include some of the Pad 19 soak radial wells drilled and completed in 1986 and 1987, forming the northeast boundary of the Pad 19 development area. The wells were completed in the Bluesky Formation as multilateral horizontal wells, with pre-cut casing windows starting about 2 m below the top of the Bluesky Formation, and the laterals located near the bottom of the Bluesky Formation. All wells were cased with L-80 grade equivalent casing, premium connections, and cemented with thermal Class G cement. All of the boundary wells, except well UWI 100042808518W505, will be re-activated as part of the approved Pad 19 Infill Project that will be drilled later this year and placed in production in 2012. The remaining wells are expected to be abandoned before the start of well operation in the initial development area.

A number of PAD 21 injector wells have also been shut-in. These wells are located under the initial development area.

Also in this category are the HWDP wells, which are suspended at this time. These wells were drilled, cased and operated as thermal wells, and will be abandoned before the drilling of the nearby project wells. These well will likely be abandoned in the next one or two years, in accordance with ERCB Directive 020.

None of the shut-in or suspended wells are expected to pose a risk to downhole steam containment.

 

Request

 

9b

 

Provide the criteria used to determine thermal compatibility and to evaluate the risks to steam containment.

 

Response

 

9b

 

The criteria used by Shell to determine the thermal compatibility of wells, and to evaluate the risks to steam containment include:

  • The metallurgy of the casing strings to minimize the risk of corrosion and corrosion-related failures in a high temperature, sour-service environment. This includes the chemistry and the post-manufacture heat treatment of the casing.
  • The casing yield strength to avoid failure because of exposure to the high temperature, sour environment
  • The casing connection strength, to ensure connections can withstand the cyclic loading expected over the operating life of the well.
  • The casing makeup during wellbore installation, to ensure connections are made up to the manufacturers’ specifications, such as torque, thereby reducing the risk of leaks.
  • The use of appropriate thermal cement for cementing casing strings, to ensure cement can withstand the range of operating temperatures expected during the life of a well.
  • The temperature, pressure rating, and metallurgy of surface components used to control well production, and to produce the well.

All wells located within, or directly adjacent to, the Carmon Creek Project initial pad development area were designed and installed using the previously listed criteria, to minimize the risk of loss of steam containment. Abandoned wells in the area proximate to the Carmon Creek Project have been abandoned in accordance with ERCB’s Directive 20.

WATER SOURCE AND DISPOSAL SIRS 10 – 11

Question No.

10

 

 

Request

 

 

SIR Response 31, Page 6-2.

 

 

Shell states, “regeneration wastewater will be disposed of in the Leduc

 

 

Formation”. In its application, Volume 1, Section 5.5.1, Page 5-9, Water

 

 

Disposal Wells, Shell states, “One or two regeneration wastewater disposal wells

 

 

will be drilled to dispose of wastewater from the water softening system.”

 

 

Provide a map illustrating the anticipated location of the proposed disposal wells

 

 

and any associated monitoring program. Include a description of the rationale

 

 

for the monitoring program and target criteria for management response.

 

Response

 

10

 

Shell plans to use the existing disposal well (UWI 001/16-27-085-19W5/0) for

 

 

disposal of regeneration wastewater (see Figure 10-1). If required, an additional

 

 

well will be drilled near to the existing disposal well location. The well

 

 

monitoring program will include:

 

 

  • flow rate and injection pressure monitoring
  • a visual inspection of the well site three times a week
  • an annual packer isolation test

Flow rate and injection pressure will be used to keep a material balance and to predict the remaining disposal capacity. Injection pressure will also be monitored to ensure it remains below the approved maximum injection pressure. The management response will be to consider drilling additional disposal wells if the disposal capacity becomes insufficient, or if the injection pressure required to inject wastewater becomes too high.

Inspections and tests will be conducted to confirm well integrity. Based on a negative inspection or test, the management response would be to shut-in and repair the well.

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Figure 10-1: Regeneration Waste Disposal Well Location

Question No. 11

Request                        Volume 1, Section 5.5.4, Page 5-10, Saline Groundwater Source Wells.

Shell states, “saline groundwater will be supplied through dedicated saline groundwater source wells drilled into the Paddy-Cadotte interval. Having water available from these saline groundwater source wells will reduce dependency on river water for steam production.” Provide a map that illustrates the location of water source wells.

Response         11         Figure 11-1 provides the notional location of the saline groundwater source wells and associated infrastructure (i.e., roads, pipelines, and power lines). The footprint for the saline groundwater source wells and associated infrastructure was included throughout the EIA in all of the assessments and maps.

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Figure 11-1: Saline Groundwater Wells and Associated Infrastructure

FACILITIES SIRS 12 – 14

Question No.

12

 

 

Request

 

 

SIR Response 34, Page 6-7.

 

 

Shell states that it “is proposing that an average well test plan include four well tests per month for each well, with each well test being four hours in duration (i.e., a total of 16 hours of test time per well per month).” Further, Shell states, “with more than 30 years of operational experience at Peace River, Shell firmly believes that the objective to obtain quality well data can be achieved…”.

 

12a

Discuss the measurement technology and/or configurations other than test separation that Shell has considered for this application and the potential for these to obtain more than 16 hours of test time per month.

 

Response

 

12a

 

Shell is currently testing the following technologies in its PRC operations:

 

 

  • pump-off controllers to estimate gross rates combined with auto samplers or in-line water-cut analysers to provide oil cut

 

 

  • wellhead temperature sensors and wellhead pressure sensors to continuously record trend data

 

 

  • in-line multiphase flowmeters

Furthermore, Shell will soon test software used to interpolate rates in between tests, using correlations between production rates and the continuously recorded data.

All of these technologies will be considered for the Carmon Creek Project.

Following a recent internal review, Shell has concluded that the current Peace River well test data do not fully demonstrate the ability to reliable allocate the Carmon Creek production with one test separator per pad. Based on this review, Shell has decided to change the project design to use two test separators per pad, with a maximum of 18 wells per test separator (36 production wells per two separators). The responses provided here reflect the new design of two test separators per pad, and a maximum of 18 production wells per test separator.

Shell remains of the opinion that with its high well density vertical well scheme, it will have better control over the spatial allocation of bitumen production than a typical horizontal well scheme. Therefore, fewer test separators would be required for the Carmon Creek Project than would be required for a typical horizontal well scheme (see the response to Supplemental Information Round 1, ERCB SIR 34).

Shell will continue its technology testing to improve the reliability and efficiency of its production allocation process.

Table 12-1 provides the well test durations and purge times for two test separators per pad, to a maximum of 18 production wells per separator, four-hour (net) well tests and four tests per well per month.

Table 12-1: Well Test Durations and Purge Times

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Request

12b

Clarify the estimated purge time that would be required for each well at the

 

 

lower rates and what duration of the proposed four hour test would be

 

 

representative of the actual production rate.

 

Response

 

12b

 

Based on historical Peace River operations (i.e., data from analog steam drive

 

pads, which are similar to the Carmon Creek Project design), a lower liquid flow

rate of 20 m3/d can be expected for the Carmon Creek Project. The purge time for

this rate for the project pad design is calculated to be 66 minutes per test, based

on the following input and assumptions:

  • a pipeline size between wellhead to test separator of 0.0762 mm (3 in.)
  • a test separator size of OD x s/s =762 mm x 3,048 mm
 
  • assumed pipeline length between wellhead to test separator inlet nozzle of 100 m
  • assumed high-liquid level is one-third of test separator height
  • liquid low flow rate estimated as 20 m3/d (based on Peace River historical data)

Purge time equals liquid volume/flow rate:

= (3.1415/4) x (0.762)2 x 3.048/3 + (3.1415/4) x (0.0762) 2 x 100]/

[(20 m3/d)/(1,440 min/d)] = 66 min

 

 

The total four-hour test time will be representative of the actual production rate, as the four hours do not include purge time and switching time.

 

Request

 

12c

 

Provide a discussion and the necessary data to support Shell’s ability to obtain quality well production data for similar test durations and configurations, having consideration for the following as part of thermal operations.

 

 

i.    The ability to maintain proration factors within the targets specified in Table 12.4 of Directive 017: Measurement Requirements for Oil and Gas Operations.

 

 

ii. The reliability of testing equipment and well test automation systems.

 

 

iii. The ability to achieve representative tests within the allocated time.

 

 

iv. The action to be taken if a valid test is not achieved for a well within four hours.

 

Response

 

12c

 

i. During the last 10 years, Shell has maintained the PRC monthly proration factors within the targets specified in Table 12.4 of ERCB Directive 017, Measurement Requirements for Oil and Gas Operations, for:

 

 

  • 74% of the time for produced bitumen (see Figure 12-1)

 

 

  • 36% of the time for produced water (see Figure 12-2)

 

 

Production from the PRC is almost entirely from CSS, which is a challenging process for proration because of the highly variable production rates, and periods without tests during flowback. Production from the Carmon Creek Project will be from vertical steam drive (VSD) complemented by CSS. Vertical steam drive will produce at more stable rates, which should result in better proration.

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Figure 12-1: PRC Historical Oil Proration

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Figure 12-2: PRC Historical Water Proration

  1. Figure 12-3 shows the actual PRC test reliability data from January 2010 to May 2011 for pads comparable to those proposed for use by the Carmon Creek Project. The test equipment reliability percentage includes equipment failures, maintenance downtime, or any other reason a test was not completed. The average test equipment reliability of 71% has been used in the calculations in the response SIR 12a. The PRC pads presented in Figure 12-3 all use automated well switching, the reliability of which has been included in the total reliability of 71%. The Carmon Creek Project design does not include automated well switching.
  2. The test validity reliability data presented in Figure 12-3 represents all the occasions where a test was performed, but subsequent analysis of the data rendered the test invalid. The data is largely based upon four-hour tests and demonstrates Shell’s ability to get representative tests in a four-hour time frame (average test validity reliability is 90%). This average test validity reliability has been used in the calculations in the response SIR 12a. A number of reasons, not related to test duration, might result in an invalid test, such as gas ingress and water cut meter malfunction.
  3. If a valid test cannot be achieved in four hours, the test will be rescheduled and repeated at a later date. The test frequency calculated in the response to SIR 12a includes a 36% allowance for repeat tests, and equipment maintenance.

Chart Graph Placeholder

Figure 12-3: Peace River Complex Test Reliability Data

Question No.

13

 

 

Request

 

 

SIR Response 40b, Page 6-82.

 

 

Shell states, “Commissioning and testing of the warm lime softener and evaporation facilities will not be completed in time to treat river water used during CPF 1 start-up or initial production.” The ERCB expects water treatment facilities to be given the same priority for start up as steam generation and oil separation trains. Discuss why Shell’s water treatment systems will not be completed at the same time as steam generation facilities and why produced water returns will be disposed of for the first year of operations when they could potentially be recycled if the systems were operational at start up.

 

Response

 

13

 

The produced water treatment facilities will be available to treat produced water as soon as a sufficient quantity of produced water exists to run these facilities reliably. During the first six months of operation (the first steam cycle), there will not be enough produced water available to start up the produced water treatment facilities. The turndown of the treatment system will be a function of the chemical feed systems, which have not yet been determined, but typically, a turndown of 50% or less is achievable. Once sufficient quantities of produced water volumes are available and the water treatment system is operational, the next six months of operation will be dedicated to improving the quality of the boiler feedwater to enable steam generation using produced water. Initially, the boiler feedwater quality will likely not be adequate for steam generation, and this water will be disposed of. After a short learning period, some of the produced water will be of sufficient quality to be fed to the steam generators. The balance of the produced water will continue to be disposed of to mitigate the risk to the steam generation systems resulting from anticipated process upsets of the produced water treatment systems. By the end of the start-up year, all of the produced water is expected to be recycled for steam generation. Furthermore, co- treating of river water with the produced water can only be accomplished once the produced water treatment systems are operating reliably.

 

 

Notwithstanding the availability of produced water for reuse, Shell’s strategy is to maximize produced water recycling as early as possible after start-up.

 

Question No.

 

14

 

 

Request

 

 

SIR Response 46, Page 6-99.

 

 

Shell discusses the energy balance submitted as part of the application. In SIR Response 27a, Page 5-23, Shell states that it is “currently investigating the option of adding a diluent to steam injection. If Shell decides to proceed with the use of a diluent, Shell will submit a scheme amendment to the ERCB.” The ERCB does not consider diluent injection to be part of the current application.

Provide an updated energy balance that does not include diluent loss to the reservoir.

Response  14a   The energy balances presented in Supplemental Information Round 1, Figures ERCB 46-1 and ERCB 46-2, shown here as Figures 14-1 and 14-2, have been revised to show the requested change (see red text in figure).

Request            14b Discuss the reason for not including produced gas in the energy consumption formula.

Response         14b       In a meeting between Shell and the ERCB in 2007, the energy consumption formula was discussed and it was agreed at that time between the parties that the formula would not include produced gas. However, Shell has included produced gas in the revised energy balances presented in Figures 14-1 and 14-2.

Request            14c       Discuss the reason for the overall energy efficiency to be lowered by adding more cogeneration facilities in Phase 2.

Response         14c       As previously stated in the application, three cogeneration units will be installed to support both CPF 1 and CPF 2. Initially, a single cogeneration unit will support CPF 1. Once the two additional units are operational, all three cogeneration units will jointly support both CPFs. By operating both CPFs, and matching the steam forecast for the two CPFs, the cogeneration units will not be operated at the high level of duct firing for steam generation, as was used for the single cogeneration unit supporting CPF 1.

Request            14d       Provide the conversion efficiency for the cogeneration systems 

Response         14d       Conversion efficiency was calculated using the Natural Resources Canada Class 43.1 Technical Guide and Technical Guide to Canadian Renewable and Conservation Expenses (CRCE). The conversion efficiency will be different depending on the operating scenario and the design parameters, which are for the most part still preliminary. Currently, conversion efficiency is estimated to range from 76% to 80%. Conversion efficiency might change as detailed engineering progresses.

 Picture Placeholder

Figure 14-1: CFP 1 Energy Balance

Picture Placeholder

Figure 14-2: CFP 1 and CPF 2 Energy Balance

EMISSIONS MANAGEMENT SIRS 15 – 17

Question No.

15

 

 

Request

 

 

SIR Response 16 (a), Section 9-1, Page 9-6.

 

 

Shell states that Shell’s participation in the Peace Airshed Zone Association would require that organization to expand its existing airshed boundary to include the area surrounding the Carmon Creek Project. Provide details of any previous discussion with the Peace Airshed Zone Association regarding boundary extension or joining the PASZA.

 

Response

 

15

 

In March 2006, Daishowa Marubeni International Ltd. (DMI) and Shell, in collaboration with Amarok Consulting and Focus Corporation, circulated information about the Peace Airshed Zone Association’s (PASZA) potential plans for expanding the airshed boundary. This information along with meeting invitations was extended to:

 

 

  • the forestry and agriculture industry in the Peace River region

 

 

  • Baytex Energy Corp., Canadian Forest Oil Ltd., Husky Energy and PennWest Exploration

In March 2006, PASZA hosted public meetings in the areas under consideration in the boundary expansion feasibility assessment to communicate plans to the public and interested parties. The meetings were held in:

  • Whitecourt
  • Slave Lake
  • Swan Hills
  • Peace River

In June 2006, Shell provided project-specific information to Alberta Environment for submission to PASZA. The submission was intended to assist PASZA with its feasibility assessment for boundary extension into the Peace River region.

During 2007 and 2008, PASZA added two continuous monitoring stations (Peace River and Cadotte Lake). The data collected was made available to the public.

These additional stations were removed at the end of 2008. Further recommendations for expansion were not implemented because of a lack stakeholder support, and the availability of sustainable funding for the monitoring program.

Since 2008, Shell has maintained its membership in PASZA, and continues to work with stakeholders and emissions working groups around the area of Shell’s operations, to understand the concerns and how best to address them.

 

Question No.

 

16

 

 

Request

 

 

SIR Response 18 (a), Section 9-1, Page 9-7.

 

 

Shell states “that the existing dust suppression program at the Peace River Complex involves having a third-party contractor apply water to roads to suppress dust during dry periods.”

 

 

Shell’s existing dust suppression program as provided to Alberta Environment considers the use of three dust suppressants namely Durasoil, DSF 65 and Dust Stop.

 

16a

Discuss the details of the existing dust suppression program, and confirm if different suppressants from the ones presented here are considered for the proposed Project.

 

Response

 

16a

 

The dust suppression program currently in use at the PRC is being considered for use by the Carmon Creek Project during project construction and operations. The PRC dust suppression program involves:

 

 

  • implementing the program during hot and dry conditions (e.g., during the summer months). Dust suppression is not required during the winter because conditions are not conducive to dust creation.

 

 

  • applying water to the project roads – no supplemental dust suppressants are used. A third-party contractor has been hired to apply the water to project roads.

 

 

Shell has found that the application of water is an effective means of controlling dust. Consequently, Shell has not used the supplemental dust suppressants (i.e., Durasoil, DSF 65 and Dust Stop) listed in the dust suppression program provided to Alberta Environment.

 

 

Therefore, during project construction and operations, water is the only dust suppressant proposed for use by the project.

 

Request

 

16b

 

Provide details of the dust suppression program that would be applied during construction, particularly in the winter months when freezing conditions make it

inappropriate for water application.

Response         16b       As stated in the response to SIR 6a, the dust suppression program currently in use at the PRC will be used for both project construction and operations.

In over 30 years of operations in the project area, Shell has not experienced conditions requiring the need for dust suppression during the winter. Based on this experience, the proposed project dust suppression program does not include plans for dust suppression during the winter.

Question No. 17

Request                        SIR Response 20 (a), Section 9-1, Page 9-10.

Shell indicates that several of the combined flaring events exceed the AAAQO, and would require flaring management to cease flaring within 36 minutes, using the 99.9th 1-hour concentration levels. Discuss the practicability of ceasing flaring within 36 minutes and management plans to control flaring if it exceeds 36 minutes.

Response         17         Flaring duration depends on the event and the time required to correct the issue. It might be practical to cease flaring within 36 minutes in some cases, but under certain circumstances, the event may persist, resulting in a longer flaring duration. The expected frequency of overlapping flaring events is very low.

During the detailed design phase of the project, Shell will assess stack and equipment design to minimize, where feasible, the frequency, duration, and flow rate of flaring events.

Once the final design has been completed, if required, a management plan will be developed to meet regulatory requirements based on the selected equipment design and dispersion modelling results. The management plan might include mitigation measures, such as the use of supplemental fuel gas, or decreasing the flow rate or volume of flared gas. Shell will ensure that the management plan is operationally feasible before start-up.

AIR QUALITY ASSESSMENT SIR 18

Question No.

18

 

 

Request

 

 

SIR Response 39 (b), Section 9-1, Page 9-52.

 

 

Shell states that “continuous sulphur dioxide emissions storage have been

 

 

reduced from 14 t/d, approved at the time of filing, to negligible amounts…”.

 

 

Provide evidence to support the claim that total sulphur dioxide emissions have

 

 

reduced to negligible amounts as a result of the Three Creeks Project compared

 

 

to Pre-Three Creeks Projects periods.

 

Response

 

18

 

Table 18-1 shows the daily sulphur dioxide (SO2) emissions from the PRC steam generators and flare stacks, from January 2010 to March 2011. The data show

 

 

that SO2 emissions dropped to negligible levels after the start-up of the Three Creeks Project.

 

 

Before start-up of the Three Creeks Project in August 2010, the daily average

 

 

SO2 emissions from the PRC steam generators were 5.6 t/d (from January to July

2010). By October 2010, the total daily average SO2 emissions from the PRC steam generators dropped to 0.20 t/d. From October 2010 to March 2011, the

 

 

daily average SO2 emissions were reduced to 0.08 t/d.

Table 18-1: Daily SO2 Emissions from the PRC as Reported to AENV

Chart Graph Placeholder

 

AQUATICS SIRS 19 – 22

Question No.

19

 

 

Request

 

 

SIR Response 79 (c), Section 10.1, Page 10-61.

 

 

Shell states that Fish species tolerant of low dissolved oxygen concentrations, such as brook stickleback, were found in the LSA. Generally, periods of low dissolved oxygen occur in under-ice conditions.

 

19a

What specific fish species, in addition to brook stickleback were found in the course of aquatic surveys in the LSA would be capable of surviving in waterbodies with less than 2.0 mg/L of dissolved oxygen and how long fish can be exposed to these conditions?

 

Response

 

19a

 

A literature search regarding fish species tolerance of low levels of dissolved oxygen (DO) concentrations was completed for fish species known to occur in the regional study area (RSA). The information is presented in Table 19-1 and, as requested, includes the fish species captured in the local study area (LSA) during the seasonal baseline data collection program.

 

 

In addition to brook stickleback, other fish species captured in the LSA that might be tolerant of low DO concentrations (i.e., less than 2.0 mg/L) include finescale dace and sucker species. The available literature that discusses the time duration of fish species able to endure suboptimal conditions was limited to

northern pike, a species not captured in the LSA.

Table 19-1: DO Tolerance for Fish Species Known to Occur in the RSA

Chart Graph Placeholder

 

References

Canadian Council of Ministers of the Environment (CCME). 1999 (with 2001 and 2002 updates). Canadian Environmental Quality Guidelines. Winnipeg, Manitoba.

Chambers, P A., S. Brown, J.M. Culp, R.B. Lowell and A. Pietroniro. 2000. Dissolved oxygen decline in ice-covered rivers of northern Alberta and its effects on aquatic biota. Journal of Aquatic Ecosystem Stress and Recovery (Formerly the Journal of Aquatic Ecosystem Health) Volume 8, Number 1, 27-38, DOI: 10.1023/A:1011491706666

Edwards, E. 1983. Habitat Suitability Index Models: Longnose Sucker. Fish and Wildlife Service. Fort Collins, CO.

Inskip, P. 1982. Habitat Suitability Index Models: Northern Pike. Fish and Wildlife Service. Fort Collins, CO.

Krieger, D.A., J.W. Terrell and P.C. Nelson. 1983. Habitat Suitability Information: Yellow perch. U.S. Fish and Wildlife Service. Fort Collins, CO.

Nelson, J. and M. Paetz. 1992. The Fishes of Alberta. The University of Alberta Press. Edmonton, AB.

Oster, D. 1999. Successful Walleye Fishing: The complete how-to guide for finding and catching Walleye. Creative Publishing. Chanhassen, MN.

Stasiak, R. and G.R. Cunningham. (2006, March 7). Finescale Dace (Phoxinus neogaeus): a technical conservation assessment. [Online]. USDA Forest Service, Rocky Mountain Region. Available: http://www.fs.fed.us/r2/projects/scp/assessments/finescaledace.pdf [May 9, 2011].

Twomey, K.A., K.L. Williamson and P.C. Nelson. 1984. Habitat Suitability Index Models and Instream Flow Suitability Curves: White Sucker. Fish and Wildlife Service. Fort Collins, CO.

Request            19b       Discuss the potential for these conditions to occur in open water situations.

Response         19b       The potential for these conditions to occur (i.e., DO concentration of less than 2.0 mg/L) in open water is dependent on the site conditions of each waterbody.

Furthermore, conditions will vary during the open-water season. Some of the site conditions that could affect DO levels include:

  • weather
  • water in-flow and outflow
  • aquatic vegetation and algae blooms
  • water depth
  • water temperature fluctuations (Lindenberg et al. 2009)

Low DO conditions were observed at study site L7 during the 2005 summer and fall site visits. Other sites that were observed to have low DO during open-water seasons included: WC3, WC4, WC5, WC6, WC9, WC12, WC17, WC18 and WC31.

Reference

Lindenberg, M.K., G. Hoilman and T.M. Wood. 2009, Water quality conditions in Upper Klamath and Agency Lakes, Oregon, 2006: U.S. Geological Survey Scientific Investigations Report 2008-5201, 54 p.

Question No. 20

Request                        SIR Response 81 (a) and (c), Section 10.1, Page 10-63 and 10-64.

Shell states that “monitoring plans are to be used to manage residual negative effects that cannot be mitigated…. Shell is only intending to conduct aquatic monitoring in relation to specific construction activities.”

 

Shell also states that it “is not planning to conduct long-term aquatic monitoring” and indicates that monitoring of indicator species will occur only if approval conditions require long-term sampling.

Shell references a number of monitoring activities in Volume II-B such as monitoring drainage, runoff ponds, culvert installations, contoured areas, erosion, and sediment control (Pages 3-37 to 3-38). Monitoring is also made reference to in Volume II-B under the aquatic ecology section (Section 5.1, Page 5-1). These monitoring aspects do not address all aspects of the Project that could impact the aquatic ecosystem.

 

20a

Discuss what activities, specific to aquatic ecology, will be used to determine if any project effects have impacted the aquatic ecosystem during the construction and operational phases of the Project. Include in the discussion, how Shell will determine that the proposed Project's activities did not have immediate or long term impact on the aquatic ecosystem given that no direct monitoring of this aspect is proposed at the operational level nor is long term monitoring proposed for construction activities.

 

Response

 

20a

 

Shell will conduct an aquatic ecology monitoring program that includes assessing potential habitat alteration and sedimentation associated with watercourse crossing construction. This monitoring approach will verify the EIA impact predictions. During operations, watercourse crossings will be monitored for effects of erosion for a two-year period after construction, and during heavy rain events.

 

 

The monitoring program will meet the requirements of the:

 

 

  • Environmental Code of Practice for Watercourse Crossing, Water Act – Water (Ministerial) Regulation, Section 6(1)c-iii and Section 14(1)

 

 

  • Code of Practice for Pipelines and Telecommunication Lines Crossing a Water Body, Water Act – Water (Ministerial) Regulation, Section 13(1).

 

 

Because the aquatic ecology assessment rated impacts to aquatic ecology as low to negligible with mitigation, Shell does not envisage that the project Environmental Protection and Enhancement Act (EPEA) approval conditions will include monitoring benthic invertebrates, or estimating fish populations as part of the aquatic ecology monitoring program.

 

Request

 

20b

 

Provide reasoning for the designation and value in the use of indicator species if there is no intent for long term monitoring in the local study area (LSA) for these species.

 

Response

 

20b

 

The rationale for selecting indicator species to assess potential project impacts on aquatic ecology, as per the terms of reference (TOR), is provided in EIA, Volume IIB, Section 5.2.2.

 

 

In an environmental impact assessment, indicator species are used to focus the assessment of baseline conditions, as well as acting as surrogates for the larger system, when assessing the potential impacts of a proposed project. Where the impact assessment finds that impacts are rated low to negligible, there is no need to conduct long-term monitoring of the indicator species.

 

 

For information concerning the TOR requirements for fisheries data collection, see the response to SIR 22b.

 

Question No.

 

21

 

 

Request

 

 

SIR Response 88 (a), Section 10.1, Page 10-71.

 

 

Shell states that “Based on the relatively homogenous fish habitat and hydrological characteristics observed throughout the LSA, these location were chosen to characterize the area.” Discuss the implications of characterizing an area the size of the LSA with this number of sample sites (i.e., based on accepted survey design methods). Provide references from peer reviewed literature to support the response.

 

Response

 

21

 

As required by the TOR, the number of sample sites selected was sufficient to provide an appropriate assessment of baseline aquatic conditions within the LSA. The following criteria were used to select study sites:

 

 

  • proximity of the sample site to a project-related disturbance (i.e., either existing or planned)

 

 

  • relative distribution of sample sites throughout the LSA

 

 

  • accessibility of the sample site

 

 

  • presence of existing non-project related disturbances, such as cutlines or rights-of-way

 

 

  • potential of the sample site to provide potential fish habitat, based on connectivity to waterbodies or watercourses known to contain fish

This sampling methodology has been used in the environmental impact assessments of numerous project applications, such as the following projects that have been deemed complete:

  • Kai Kos Dehseh Project (StatOil Canada)
  • Leismer Demonstration Project (StatOil Canada)
  • Long Lake Project (Nexen Inc.)
  • McKay River Project (McKay Operating Corporation)
  • Dover Central Plant (Dover Operating Corporation)
  • BlackGold Project Phase 1 (Harvest Operations Corporation)
Additional site-specific data will be collected before the start of construction, based on site-specific fish habitat assessments necessary to meet watercourse crossings regulatory requirements.

Question No. 22

Request                        SIR Response 95 (a), Section 10.1, Page 10-76

SIR Response 84 (b), Section 10.1, Page 10-68

Volume II-B, Section 5.4, Page 5-8 to 5-18.

Shell states that “Adequate sampling over four seasons….was conducted using standard survey methods.”

It is unclear which “standard survey methods” were utilized for sampling conducted via electrofishing, baited setlining and minnow trapping. In SIR response 84 some information was provided for the gill net sampling.

Shell states that Mesh sizes for gill nets were pattered after those discussed by Morgan (2002) in the Manual Instructions – Fall Walleye Index Netting (FWIN). It seems that Shell utilized a standard method for gill net equipment, but deviated from the actual sampling protocol of Morgan (2002). (i.e., sampling at certain temperatures, timing of sampling – fall).

22a       Describe or reference what “standard survey methods” were used for electrofishing, baited setlining and minnow trapping and discuss how they are relevant to this LSA.

Response         22a       The survey methods used for electrofishing, baited setlining, and minnow trapping are summarized in Bonar et al. (2009), McRae and Jackson (2006), and the B.C. Ministry of Environment (1997). These standard methods have been used extensively for EIAs in Alberta, including EIAs that have been deemed complete or approved, and are the accepted methods to complete baseline surveys for fish for EIAs, and other projects that might affect aquatic habitat. The survey methods used in the LSA are relevant because these methods can capture a wide range of body sizes, regardless of species or geographic location.

References

B.C. Ministry of Environment. 1997. Fish Collection Methods and Standards. Lands and Parks, Fish Inventory Unit for the Aquatic Ecosystems Task Force, Resources Inventory Committee. 58 pp.

Bonar, S.A., W.A Huberta and D.W. Willis. (eds.). 2009. Standard methods for sampling North American freshwater fishes. American Fisheries Society, Bethesda, Maryland.

MacRae, P.S.D. and D.A. Jackson. (2006, February 3).Characterizing north temperate lake littoral fish assemblages: a comparison between distance sampling and minnow traps. Canadian Journal of Fisheries and Aquatic Sciences. 63: 558–568.

Request

22b

Discuss how the results from the “standard survey methods” for all fish

 

 

community sampling can be repeated to verify results and to detect changes in

 

 

the aquatic ecosystem. Include in the discussion how this can occur if only

 

 

certain portions of standard protocols like Morgan (2002) were followed or if

 

 

only parts of the sampling process identified in Volume II, Section 5.4.2,

 

 

Methods.

 

Response

 

22b

 

The results from the fisheries assessment were intended to meet the TOR, rather

 

than to be repeated to verify results and detect changes in the aquatic ecosystem.

The TOR did not require Shell to collect fisheries data that could be used as the

baseline for an ongoing fisheries program, it required Shell to collect data to

describe the existing fish and other aquatic resources, including:

  • species composition
  • distribution
  • relative abundance
  • movements
  • life history parameters
  • existing fish habitat

For information concerning the TOR requirements for using indicator species in assessing potential impacts to aquatic ecology, see the response to SIR 20b.

LAND USE AND LAND MANAGEMENT SIRS 23 – 25

Question No.

23

 

 

Request

 

SIR Response 104, Section 11.1, Page 11-4

Volume II-C, Section 6.8.2.3, Figure 6.8-6, Page 6-23

Volume I, Section 12.4.1, Page 12-15.

 

 

Shell indicates that they will develop a 20 m pipeline right-of-way (ROW) with a maximum of 25 m ROW for expansion loops. Shell also provided information describing why power lines cannot share the same as above ground pipelines (safety considerations).

 

 

Shell provides Figure 6.8-6 and shows a conceptual drawing of an access, pipeline, and powerline within a common ROW on mineral soil. Generally powerlines located adjacent to road right of ways have power poles located immediately adjacent to the LOC right-of-way edge, as opposed to the center of the right-of-way, limiting the clearing required to keep the powerline free of hazardous vegetation. Typically in these cases the powerline ROW would only be 7-8 m in width.

 

23a

Identify if Shell has considered locating powerline poles directly adjacent to road ROW, rather than in the centre of a dedicated 13m ROW as this is common practice to reduce footprint where powerlines and roadways share a linear corridor.

 

Response

 

23a

Shell will locate power lines adjacent to the edge of the road right-of-way (ROW), and not in the centre of the power line ROW, as proposed on

Figure 6.8-6 (see EIA, Volume IIC). By placing power lines adjacent to the edge of the road ROW, the width of the power line ROW will be reduced from 13 m to 7 m (see Figure 23-1).

 

Request

 

23b

 

Evaluate the design strategy in (a) and assess the suitability of this option for the Project.

 

Response

 

23b

 

The design strategy discussed in the response to SIR 23a is a suitable option for the project to reduce the footprint of linear corridors.

Request            23c       Provide an updated Figure 6.8-6 showing Shell’s commitment to a 20m above ground pipelines and any additional changes as applicable.

Response         23c       Figure 6.8-6 has been revised (shown here as Figure 23-1) to illustrate Shell’s commitment to a 20 m wide above-ground pipeline ROW, and a 7 m wide power line ROW in a common ROW with a road.

Question No. 24

Request                        SIR Response 105 (a), Section 11.1, Page 11-6 Volume II-C, Section 6.2.2, Table 6.2-1, Page 6-2 Page.

Shell indicates that an area of 48 ha is required for the CPF site; however, in Table 6.2-1 (Volume II-C) a new disturbance area of 222.2 ha is identified for Central Processing Facilities.

24a Clarify the discrepancy for the area required for the CPF and confirm what area was used to determine the preferred and alternative sites for the CPF. Update the assessment, if required.

Response         24a       The total disturbance area for the CPFs is 222.2 ha, as noted in the EIA, and includes:

  • plant infrastructure
  • landfills
  • soil stockpiles
  • industrial runoff ponds
  • support infrastructure

The 48 ha mentioned in the response to Supplemental Information Round 1, AENV SIR 105a, was only the footprint for plant infrastructure, not the total footprint for the CPFs. The area used to determine the preferred and alternative sites for the CPFs was 222.2 ha.

Picture Placeholder

Figure 23-1: Conceptual Access, Pipeline and Power Line Common ROW on Mineral Soil

Question No. 25

Request                        SIR Response 105 (c), Section 11.1, Page 11-6

SIR Response 102 (b), Section 11.1, Page 11-3

Volume I, Sec 6.1.5, Page 6-2 and 6-3.

Shell identifies site selection criteria and the advantages of selected site for Central Processing Facilities (CPF), but does not clearly outline the integration of the existing processing facility within the new proposed development scheme.

Shell indicates in the response to SIR 102 (b) that the decommissioning and reclamation of the existing Peace River Complex is expected to begin approximately 1 year after start-up of CPF 1. This existing Complex is currently authorized under two public lands dispositions MLL850015, and MSL8734 which together are approximately 71 ha in size.

According to Shell’s conceptual development schedule, the Peace River Complex decommissioning and reclamation will occur approximately 2 years prior to construction of CPF 2 and associated facilities. In the conceptual development schedule (Volume 1, Figure 1-5) Shell indicates that construction for CPF 2 will begin approximately 3 years following construction of CPF 1.

25a       Provide alternatives to locating a portion of the planned facilities for CPF 1 and CPF 2 including associated facilities (landfill, camp, etc.) on the existing footprint, which is currently utilized for the Peace River Complex.

Response         25a       Some minor project components, such as the administration complex, maintenance shop, and warehouse located at the PRC site will continue to be used by the project (see the response to Supplemental Information Round 1, ERCB SIR 37a). As discussed in the response to SIR 25b, no other project components, such as the construction camp or landfills are being considered for location at the PRC site.

Through adaptive management and consultation with Alberta Sustainable Resource Development (ASRD) and other stakeholders, Shell will endeavour to reduce the overall project footprint. Footprint minimization opportunities could include: 

  • reducing the size and number of clearings on previously undisturbed land (i.e., new clearing)
  • reusing land that has an existing disturbance, where possible
  • co-locating project components to make disturbance as compact as possible

Request            25b       If there are no feasible alternatives provided in (a), discuss why no alternatives are possible.

Response         25b       Except for the minor project components identified in the response to SIR 25a, it is not feasible to locate the main CPF 1 and CPF 2 components at the PRC site for the following reasons:

  • the timing of PRC decommissioning and reclamation, relative to the tinting of CPF 2 construction
  • the geotechnical and environmental conditions at the PRC site

The preamble to this SIR states 'construction for CPF 2 will begin approximately three years following construction of CPF 1'; however, tllis statement requires clarification. Figure 25-1 illustrates the construction of CPF 2 will begin about three years after the sta1t of construction of CPF 1, and not the end of construction of CPF 1, as implied in the preamble.

Because the PRC will still be operating during the first year of construction for CPF 2, it would not be possible to locate any of the major project components for CPF 2 at the PRC site.

Picture Placeholder

Figure 25-1: Timing of CPF Construction and PRC Decommissioning

To clarify, the first four years of the conceptual project development schedule are as follows:

  • strut construction of CPF 1
  • about three years later:
    • sta1t commissioning and start-up of CPF 1
    • PRC begins suppo1ting CPF 1
    • strut construction of CPF 2
  • about one year later:
    • start of normal operations for CPF 1
    • start decommissioning and reclamation of the PRC

The construction camp cannot be located at the PRC site because of the timing of the PRC decommissioning and reclamation relative to the timing of CPF 2 construction. The construction camp will be required many years before the decommissioning and reclamation of the PRC site.

Geotechnical and environmental site conditions are the main reason that the landfills cannot be located at the PRC site. The PRC site does not comply with the primary siting criteria for landfills in Alberta (Standards for Landfills in Alberta, Alberta Environment, February 2010). The surficial geology at the PRC site consists of a thin layer of sandy clay till overlying water bearing sands.

Landfills are not permitted on permeable materials, such as sands, or overlying shallow aquifers.

The design philosophy for the CPFs is to have all project components laid out in a single site. This approach will reduce the footprint by minimizing: 

  • the total area cleared for setback from facilities to the forest (i.e., less area cleared compared to two separate facilities)
  • the number and size of soil stockpiles
  • the number and size of industrial runoff ponds and associated ditches
  • the number and size of additional roads required to transport equipment and personnel between the CPFs, and between the CPFs and the PRC, or to transport waste to other disposal locations

WILDLIFE SIRS 26 – 27

Question No.

26

 

 

Request

 

 

SIR Response 146 (a), Section 11.1, Pages 11-70 and 11-71.

 

26a

Given the dates during which the track counts were conducted, provide a discussion indicating how confident Shell is that the winter track count data has captured moose presence in early winter in the LSA and RSA.

 

Response

 

26a

 

Although the late winter track count data cannot capture moose presence in early winter, Shell is confident that moose are present in the LSA in the early winter and throughout the year. As stated in EIA, Volume IIC, Appendix 4B, the winter tracking surveys were conducted in January, February and March. However, other sources of data obtained by Shell indicate the presence of moose within the LSA year-round, including:

 

  • observations by on-site Shell staff of moose year-round
  • research conducted in the LSA by Dunne (2007) that includes photographic evidence of moose year-round
  • pellet surveys conducted by Shell in September 2002
 
 

Based on this data, Shell is confident that moose are present in the LSA in the early winter.

Reference

Dunne, B. 2007. Effectiveness of above-ground pipeline crossing structures for the movement of moose and other large mammals. Master’s degree project submitted to the Faculty of Environmental Design in partial fulfillment of the requirements for the Master of Environmental Design Degree in Environmental Science. 136 pp plus appendices.

Question No. 27

Request                        SIR Response 157, Section 11.1, Pages 11-89 to 11-91.

Although ASRD field staff did indicate several years ago that owls or bats would not be included in the list of indicator species, there has been a significant shift within ASRD to understand industrial impacts on selected species. For example, considerable efforts within ARSD to develop models to understand impacts of industry on barred owls in Alberta.

The TOR requires Shell to describe and map existing wildlife resources (amphibians, reptiles, birds and terrestrial and aquatic mammals) and their use and potential use of habitats.

27a       Provide Shell’s plan to augment baseline data for owls and bats to describe and map presence of bat and owl species on the LSA and RSA.

Response         27a Owl Survey

In April 2012, Shell plans to conduct a survey to describe and map the presence of owl species in the LSA. The owl survey will only be conducted within the LSA for the following reasons:

  • The LSA is delineated to determine direct and indirect project effects to wildlife resources of concern. The RSA was identified and used to assess impacts on wildlife indicators with large home ranges, such as moose (see EIA, Volume IIC, Section 4.3.1 and 4.3.2). Project effects are not expected to extend beyond the LSA for most small species of wildlife, including owls.
  • It is expected that all owl species that could potentially occur within the RSA will also be found within the LSA, because of the wide diversity of habitat types available within the LSA. Therefore, a survey within the LSA would be representative of baseline owl conditions in the RSA.

The owl survey methods will follow the established survey methodology outlined in the Guidelines for Nocturnal Owl Monitoring in North America (Takats et al. 2001) and the Alberta Wildlife Animal Care Committee Class Protocol #006 (ASRD 2005). The owl survey will be stratified to establish points in forested habitat types with a structural stage 5 or greater, as opposed to shrubland and graminoid habitats – these habitat types provide minimal nesting habitat for owl species expected to respond to call playbacks. For example, short-eared owls, a species that uses shrubland or graminoid habitats, are not known to respond to call playback. Within forested habitat, survey stations will be spaced at least 1,600 m apart, as recommended by Takats et al. (2001), to minimize the chance of surveying the same owl twice.

Bat Survey

 

In late July or early August 2012, Shell plans to conduct a bat survey to describe and map the presence of bat species within the LSA. The bat survey will focus on the LSA for the same reasons previously stated for the owl survey.

The bat survey will use two methods to detect the presence of bats:

  • physical capture using mist nets
  • echolocation detection using the AnaBat II Bat Detector with compact flash zero-crossing analysis interface module (CF ZCAIM; Titley Electronics).

 The exact locations of the survey sites has not yet been determined; however, sites along cutlines and overgrown trails between old growth forests (roosting habitat) and wet areas such as streams, bogs and marshes (foraging habitat) will be selected. Bat detectors will be placed at the mist netting locations, and other locations to increase the sample size.

References

Alberta Sustainable Resource Development (ASRD). 2005. Alberta Wildlife Animal Care Committee Class Protocol #006: Call Playback for Owls. Available online at: http://www.srd.alberta.ca/fishwildlife/guidelinesresearch/pdf/protocol/O wl_playback_Class_Protocol_006.pdf

Takats, D.L., C.M. Francis, G.L. Holroyd, J.R. Duncan, L.M. Nazur, R.J. Cannings, W. Harris and D. Holt. 2001. Guidelines for Nocturnal Owl Monitoring In North America. Beaverhill Bird Observatory and Bird Studies Canada, Edmonton, Alberta, p 32.

Request

27b

For owls and bats, describe and map all those species listed as “at Risk, May be at Risk and Sensitive” in The Status of Alberta Species (Alberta Sustainable Resource Development) and all species listed in Schedule 1 under the Federal Species at Risk Act and those listed as “at risk” by COSEWIC that could be present in the Project Area, LSA and RSA.

 

Response

 

27b

 

Table 27-1 identifies owl and bat species that could be present in the Terrestrial LSA and RSA, and classified as:

 

  • At Risk, May Be At Risk and Sensitive by ASRD (ASRD 2011)
  • Schedule 1 of the Species at Risk Act (SARA 2011)
  • Endangered, Threatened or Special Concern by the Committee on the Status of Endangered Wildlife in Canada (COSEWIC 2011).
 
 

Table 27-1: Owl and Bat Species Potentially Occurring in the Terrestrial LSA and RSA Considered At Risk

Chart Graph Placeholder

Information on the presence of, and habitat use by, owl and bat species within the LSA will be updated once the surveys for these species groups are completed in 2012 (see the response to SIR 27a).

The ecosite phases indicated in Table 27-2 as potential habitat for each owl species are based on coarse scale habitat associations, as described in the literature. The potential habitat is not modelled and does not provide fine scale habitat preferences. Similarly, potential nesting habitat illustrated in the figures is based on the ecosite phases and structural stages provided in the table or text.

Barred Owl

The barred owl is found throughout Canada except the prairie and arctic regions (Johnsgard 1988, ASRD 2005). In Alberta, the barred owl occurs in forested areas of the Rocky Mountains, Foothills, and Boreal Forest Natural Regions (ASRD 2005). Four barred owls were detected in the northern part of the LSA, at three locations (see Figure 27-1).

In Alberta, barred owl breeding habitat is associated with mature and old mixedwood forests (Mazur et al. 1998, Takats 1998, ASRD 2005). Breeding barred owls prefer old mixedwood and deciduous forests (i.e., forests more than 80 years old) because of the greater availability of potential nest sites and open areas for hunting (Mazur et al. 1998). Cavities in large balsam poplar trees are preferred for nesting (FAN 2007). Within the LSA, deciduous and mixedwood forests of a structural stage 6 and 7 were included as potential barred owl nesting habitat (see Figure 27-1 and Table 27-2).

Great Gray Owl

The breeding range of the great gray owl is the Holarctic biogeographic region, which occurs across North America from central Alaska and northern Yukon, across the western provinces to northern Manitoba and northern Ontario (Johnsgard 1988). In the United States, the range of the great gray owl includes portions of the Cascades, Sierra, and Rocky Mountains, as well as portions of Minnesota, Michigan, Wisconsin, and New York (Duncan and Hayward 1994). The great gray owl is a year-round resident, if uncommon inhabitant, of the northern and western parts of Alberta (Semenchuk 1992, McGillivray and Semenchuk 1998). However, during the winter, great gray owls tend to wander irregularly southward (Duncan 1994). Great gray owls were detected at two locations in the northeast part of the LSA, and at four locations north of the LSA (see Figure 27-2).

Great gray owls nest in mature and old growth forested habitats, including coniferous, mixedwood, and deciduous stands (Semenchuk 1992). Drier pine stands and open areas without trees are generally avoided (Bull and Duncan 1993). The great gray owl hunts small mammals in natural openings in the forest, and within edge habitats (Godfrey 1986). Great gray owls nest in the abandoned stick nests of other avian species, such as crows, ravens or hawks. In Alberta, great gray owls may nest in deciduous or coniferous trees, but prefer to nest in large balsam poplar trees in proximity to muskeg habitat (Semenchuk 1992).

Potential nesting habitat in the LSA includes mature and old growth deciduous, mixedwood, and coniferous forests (see Figure 27-2 and Table 27-2).

Northern Hawk Owl

The northern hawk owl is unevenly distributed throughout its boreal forest range across Alaska and Canada (Duncan and Duncan 1998). In Alberta, the northern hawk owl occurs mainly in the Boreal Forest Natural Region and occasionally in the Foothills, Parkland and Rocky Mountain Natural Regions (Semenchuk 1992, FAN 2007). Northern hawk owls are not migratory; however, they may relocate within their breeding range in the winter to areas where winter prey is more abundant (Semenchuk 1992, Duncan and Duncan 1998). Although suitable nesting habitat is present in the LSA, no northern hawk owls were detected in the LSA during any surveys conducted for the project (see Figure 27-3).

The northern hawk owl breeds in relatively dense mature coniferous or mixedwood forest stands bordering open areas, such as marshes, muskeg, clearcuts, or burnt areas (Semenchuk 1992, Duncan and Duncan 1998, ASRD 2010). Northern hawk owls will nest in burnt forests where snags and stumps provide suitable nesting sites (Salt and Salt 1976). Preferred nest structures include natural tree cavities, woodpecker cavities, the top of hollow tree snags, or abandoned crow or hawk nests (Godfrey 1986). Since northern hawk owls prefer to nest in mature forests, coniferous or mixedwood ecosite phases within the LSA of a structural stage 6 and 7 were included as potential nesting habitat (see Figure 27-3). The ecosite phases included as potential nesting habitat in the LSA are shown in Table 27-2.

Northern Pygmy Owl

The North American range of the northern pygmy owl extends across the western portion of the continent from the southern coastal tip of Alaska to southern Mexico (Hannah 1999). Alberta includes the northeastern extent of the northern pygmy owl’s range (Hannah 1999). It is a resident of the Rocky Mountain and Foothills Natural Regions with occasional occurrences in the Boreal Forest Natural Region (FAN 2007). Northern pygmy owls are regularly recorded in the Parkland and Grassland Natural Regions in the winter (Semenchuk 1992). One northern pigmy owl was detected in the south-central portion of the LSA (see Figure 27-4).

The northern pygmy owl typically prefers to nest in dense mature coniferous forest stands interspersed with small clearings (Salt and Salt 1976, Hannah 1999). Mixedwood forests are also preferred, as long as there are high components of coniferous tree species present (i.e., spruce, pine or fir). Nests are usually located in abandoned hairy woodpecker or northern flicker tree cavities (Semenchuk 1992). Potential nesting habitat for the northern pygmy owl includes coniferous and mixedwood forests with a structural stage of 6 and 7 (see

Figure 27-4 and Table 27-2).

Short-Eared Owl

The short-eared owl occurs on every continent except Australia and Antarctica making it one of the most widely distributed owls in the world (Clayton 2000, COSEWIC 2008). Short-eared owls breed across the northern portion of North America and migrate south to Mexico and the West Indies during winter (Hoffman et al. 1999, Clayton 2000). In Alberta, the majority of the short-eared owl breeding range occurs in the Grassland Natural Region, and to a lesser extent in the Parkland, Boreal Forest, Foothills, and Rocky Mountain Natural Regions (FAN 2007). Although suitable nesting habitat is present in the LSA, no short- eared owls were detected in the LSA (see Figure 27-5).

The short-eared owl breeds in a wide variety of open habitats, such as grasslands, Arctic tundra, taiga, bogs, marshes, old pastures, croplands, grassy or brushy meadows and cutblocks (Semenchuk 1992, Clayton 2000, Wiggins et al. 2006, FAN 2007, COSWIC 2008). Preferred nesting sites are on the ground and usually in areas of dense grassland (COSEWIC 2008). Within the LSA, potential nesting habitat includes lowland habitat, with low tree cover, open fens, shrublands, regenerating cutblocks, cutblocks and marshes (see Figure 27-5 and Table 27-2).

Potential Impacts on Owl Species at Risk

The project will have various effects on wildlife, but owls are most likely to be affected by loss of habitat and reduced habitat effectiveness. Mortality from collisions with vehicles is expected to be negligible because of speed restrictions in place on access roads within the LSA. Based on the general habitat associations described in Table 27-2, the project will result in a loss of potential habitat ranging from 9.9% to 15.6% (see Table 27-3). This estimate is conservative as fine scale habitat associations were not modelled, and it is unlikely that all habitat described is suitable for each species. Habitat loss for the indicator species assessed in the EIA ranged from 1.1% for beaver to 16% for moose, with an average of 9.5% (Volume IIC; Section 4.6.1.3).

The project will result in loss of habitat and reduced habitat effectiveness. Populations of owls within the LSA may decline below Baseline Case levels through the life of the project, although this affect will vary among species. Populations are expected to recover in the LSA after reclamation. However, there is extensive habitat within the RSA, and regionally owl populations are not expected to change as a result of the project. Residual impacts on habitat availability for the indicator species assessed in the EIA were rated negligible to moderate. As with these indicator species, the habitat loss is unlikely to threaten the long-term sustainability of owl species in the RSA. The impacts are expected to be reversible in the long term because of project reclamation to an equivalent land capability.

Table 27-2: Potential Nesting Habitat in the LSA for Owl Species at Risk

Chart Graph Placeholder

Table 27-3: Potential Habitat Availability for Owl Species at Risk, Baseline and Application Cases

Chart Graph Placeholder

Hoary Bat

The hoary bat is one of the most widespread mammals ranging throughout North, South and Central America (Pattie and Fisher 1999, ASRD 2009a). It is widespread throughout Alberta (ASRD 2009a). Although suitable roosting habitat is available in the LSA (see Figure 27-6), no hoary bats were detected in the LSA.

Hoary bats prefer to roost in coniferous trees (ASRD 2009a) and will often choose mature white spruce trees (Picea glauca) as roost sites (Willis and Bringham 2005).

Northern Long-Eared Bat

The northern long-eared bat ranges throughout the forested regions of Canada, with the exception of western British Columbia and the northern portions of the boreal forest (Caceres and Pybus 1997). In the United States, the range extends across the eastern half of the United States south to the northern tip of Florida (Caceres and Pybus 1997). In Alberta, the northern long-eared bat is found in forested areas within the Boreal Forest, Peace Parkland, Central Parkland as well as the northern portions of the Foothills Natural Regions (Caceres and Pybus 1997, Pattie and Fisher 1999). Although suitable roosting habitat is available in the LSA (see Figure 27-6), no northern long-eared bats were not detected in the LSA.

Preferred roosting sites consist of mature tree stands with the presence of large diameter, partially decayed trees with exfoliating bark, small cavities or long vertical cracks in the trunk (Caceres and Pybus 1997, Psyllakis and Bringham 2006).

Silver-Haired Bat

The silver-haired bat ranges across the southern half of Canada and throughout the United States (Pattie and Fisher 1999). These bats are distributed throughout Alberta and are more frequently observed in the Rocky Mountains (Pattie and Fisher 1999, ASRD 2009b). Although suitable roosting habitat is available in the LSA (see Figure 27-6), no silver-haired bats were detected in the LSA.

Silver-haired bats might roost individually or in small groups in forested areas under peeling bark, in tree cavities, in abandoned bird nests, or hanging upside down among leaves (Harvey et al. 1999, ASRD 2009b).

Potential Impacts on Bat Species at Risk

Bats might be affected by loss of habitat and by reduced habitat effectiveness. Reduced habitat effectiveness might result from the effects of lighting project facilities. For information concerning mitigation to reduce impacts from lighting, see Supplemental Information Round 1, AENV SIR 144.

Bat roosting habitat consists predominantly of old growth forests, therefore, the assessment of effects of the project on old growth forests (see EIA, Volume IIC, Section 3.5.1.3.1) can be used to assess project effects on bats. The predicted loss of old growth forest habitat is 14.1% and the effect was determined to be moderate and long term in duration. Although the project might result in a decrease in the bat population within the LSA, the habitat loss is unlikely to threaten the long-term sustainability of bat species in the RSA.

References

Alberta Sustainable Resource Development (ASRD). 2005. Status of the Barred Owl (Strix varia) in Alberta. Alberta Sustainable Resource Development, Fish and Wildlife Division, and Alberta Conservation Association, Wildlife Status Report No. 56, Edmonton, AB. 15 pp.

ASRD. 2009a. Hoary Bat (Lasiurus cinereus). http://www.srd.alberta.ca/FishWildlife/WildSpecies/Mammals/Bats/Hoar yBat.aspx. Accessed August 2011.

ASRD. 2009b. Silver-haired Bat (Lasionycteris noctivagans). http://www.srd.alberta.ca/FishWildlife/WildSpecies/Mammals/Bats/Silv erhairedBat.aspx. Accessed August 2011.

ASRD. 2010. Northern Hawk Owl (Surnia uvula). http://www.srd.alberta.ca/FishWildlife/WildSpecies/Birds/Owls/Norther nHawkOwl.aspx. Accessed August 2011.

ASRD. 2011. The General Status of Alberta Wild Species 2010. http://www.srd.alberta.ca/BiodiversityStewardship/SpeciesAtRisk/Gener alStatus/GeneralStatusofAlbertaWildSpecies2010/Default.aspx. Accessed May 11 2011.

Bull, E. L. and J. R. Duncan. 1993. Great Gray Owl (Strix nebulosa), The Birds of North America Online (A. Poole, Ed.). Ithaca: Cornell Lab of Ornithology; Retrieved from the Birds of North America Online: http://bna.birds.cornell.edu/bna/species/041 doi:10.2173/bna.41. Accessed August 2011.

Caceres, M.C. and M. J. Pybus. 1997. Status of the Northern Long-eared Bat (Myotis septentionalis) in Alberta. Alberta Environmental Protection, Wildlife Management Division, Wildlife Status Report No. 3, Edmonton, Alberta.

Clayton, K.M. 2000. Status of the short-eared owl (Asio flammeus) in Alberta. Alberta Environment, Fisheries and Wildlife Management Division, and Alberta Conservation Association, Wildlife Status Report No. 28, Edmonton, AB.

Committee on the Status of Endangered Wildlife in Canada (COSEWIC). 2008. COSWEIC assessment and update status report on the short-eared owl Asio flammeus in Canada. Committee on the Status of Endangered Wildlife in Canada. Ottawa. Vi + 24 pp. (www.sararegistry.gc.ca/status/status_e.cfm).

COSEWIC. 2011. Canadian Species at Risk. http://www.cosewic.gc.ca/eng/sct5/index_e.cfm. Accessed May 11 2011.

Duncan, J.R. 1994. Great Gray Owl habitat use literature review. Prepared for Manitoba Forestry/ Wildlife Management Project. 32 pp.

Duncan, J.R. and P.H. Hayward. 1994. Review of technical knowledge: Great Gray Owls. Chapter 14. Pp. 159-175. In Hayward, G.D. and J. Verner (eds.). Flammuated, boreal, and great gray owls in the United States: a technical conservation assessment. USDA Forest Service, General Technical Report RM-253. 213 pp.

Duncan, J.R. and P. A. Duncan. 1998. Northern Hawk Owl (Surnia ulula), The Birds of North America Online (A. Poole, Ed.). Ithaca: Cornell Lab of Ornithology; Retrieved from the Birds of North America Online: http://bna.birds.cornell.edu/bna/species/356 .doi:10.2173/bna.356.

Federation of Alberta Naturalists (FAN). 2007. The Atlas of Breeding Birds of Alberta: A Second Look. Federation of Alberta Naturalists, Edmonton, Alberta.

Godfrey, W.E. 1986. The Birds of Canada. The National Museum of Natural Sciences, National Museums of Canada. 595 pp. Short-eared owl.

Hannah, K.C. 1999. Status of the Northern Pygmy Owl (Glaucidium gnoma californucum) in Alberta. Alberta Environmental Protection, Fisheries and Wildlife Management Division, and Alberta Conservation Association, Wildlife Status Report No. 20, Edmonton, Alberta.

Harvey, M.J., J.S. Altenbach and T.L. Best. 1999. Bats of the United States. Arkansas Game and Fish Commission, Arkansas.

Hoffman, W., G.E. Woolfendon and P.W. Smith. 1999. Antillean short-eared owls invade southern Florida. Wilson Bulletin 111: 303-313.

Johnsgard, P.A. 1988. North American Owls, Biology and Natural History. Smithsonian Institution Press, Washington and London. 295 pp.

McGillivray, W.B. and G.P. Semenchuk. 1998. Field Guide to Alberta Birds. The Federation of Alberta Naturalists, Edmonton, Alberta. 350 pp.

Mazur, K.M., S.D. Frith and P.C. James. 1998. Barred owl home range and habitat selection in the boreal forest of central Saskatchewan. The Auk 115 (3): 746-754.

Pattie, D., and C. Fisher. 1999. Mammals of Alberta. Lone Pine Publishing, Edmonton. 240 pp.

Psyllakis, J.M. and R.M. Bringham. 2006. Characteristics of diurnal roosts used by female Myotis bats in sub-boreal forests. Journal of Forest Ecology and Management 223: 93-102.

Salt, W.R. and J.R. Salt. 1976. The Birds of Alberta. Edmonton, AB: Hurtig Publishers.

Semenchuk, G.P.(ed.). 1992. The Atlas of Breeding Birds of Alberta. The Federation of Alberta Naturalists, Edmonton, Alberta. 391 pp.

Species at Risk Act (SARA). 2011. Species at Risk Registry. http://www.sararegistry.gc.ca/default_e.cfm. Accessed May 2011.

Takats, D.L. 1998. Barred owl habitat use and distribution in the Foothills Model Forest. M.Sc. Thesis, University of Alberta, Edmonton, Alberta.

Wiggins, D. A., D. W. Holt and S. M. Leasure. 2006. Short-eared Owl (Asio flammeus), The Birds of North America Online (A. Poole, Ed.). Ithaca: Cornell Lab of Ornithology; Retrieved from the Birds of North America Online: http://bna.birds.cornell.edu/bna/species/062.doi:10.2173/bna.62. Accessed August 2011.

Willis, K.R. and R.M. Bringham. 2005. Physiological and ecological aspects of roost selection by reproductive female hoary bats (Lasiurus cinereus).Journal of Mammology 86(1): 85-94.

Picture Placeholder

Figure 27-1: Barred Owl Potential Nesting Habitat and

Observations in the Terrestrial LSA

Picture Placeholder

Figure 27-2: Great Gray Owl Potential Nesting Habitat

and Observations in the Terrestrial LSA

Picture Placeholder

Figure 27-3: Northern Hawk Owl Potential Nesting

Habitat in the Terrestrial LSA

Picture Placeholder

Figure 27-4: Northern Pygmy Owl Potential Nesting

Habitat and Observations in the Terrestrial LSA

Picture Placeholder

Figure 27-5: Short-Eared Owl Potential Nesting Habitat

and Observations in the Terrestrial LSA

Picture Placeholder

Figure 27-6: Potential Bat Roosting Habitat in the

Terrestrial LSA

SIRS 28– 32

Question No.

28

 

 

Request

 

 

Volume II- A, Section 5, Appendix 5A, Section 5A.22, Page 5A-98.

 

 

Shell states …the OEHHA (2009) presents a cancer unit risk value of 3.4E-05 (ug/m³)-1(equivalent to an RsC of 0.3 ug/m³). This value is based upon two bioassays by the NTP (1992, 2000)….. Given that the US EPA and other agencies have not derived cancer-based values, it suggests that the weight of evidence at the current time in support of human carcinogenicity in association with naphthalene exposure is limited.

 

 

The IARC has classified naphthalene as a Group 2B carcinogen. The HHRA has included the assessment of potential carcinogenicity for PAH within the Group 2B and Group 3 IARC classification. The OEHHA presents a cancer unit risk value for naphthalene and the US EPA, in a draft IRIS document reviewing naphthalene toxicity, also provides a cancer unit risk value for naphthalene (document available at: http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=84403#Download).

 

28a

Would the inclusion of naphthalene as a carcinogen within the B[a]P group, using the OEHHA cancer unit risk value or the cancer unit risk value proposed by the US EPA, result in any changes to the conclusions of the HHRA with regards to potential carcinogenic effects?

 

 

i.    If no, provide a qualitative discussion as to why the conclusions would not change.

 

 

ii. If unacceptable cancer risks would be predicted with the inclusion of naphthalene, revise the HHRA (i.e., results and follow-up and monitoring sections) to account for these risks.

 

Response

 

28a

i.    Concerning the potential carcinogenicity of naphthalene and how it was evaluated in the HHRA (see EIA, Volume IIA, Appendix 5A), the criteria for selecting both carcinogenic and non-carcinogenic exposure limits for the HHRA involved selecting limits that complied with the following attributes:

 

 

  • established or recommended by reputable scientific authorities

 

 

  • protective of the health of the general public, based on the current scientific understanding of the health effects known to be associated with exposures to the chemical
  • protective of sensitive individuals through the use of appropriate uncertainty factors 
  • supported by adequate and available documentation

In those cases where more than one exposure limit met the selection criteria, the most relevant and scientifically defensible limit was generally selected. For chronic naphthalene exposure via inhalation, the most relevant exposure limit for the HHRA was determined to be the reference concentration (RfC) of 3 µg/m³. This value was selected for the following reasons.

The United States Environmental Protection Agency (USEPA) still has not finalized its external review draft (USEPA 2004) of the reassessment of the inhalation carcinogenicity of naphthalene. Because the cancer unit risk value remains in draft form, it was not considered in the HHRA. In fact, the external reassessment clearly states that the draft is not to be cited or quoted. As such, the HHRA relied on the carcinogenicity information that is currently presented in the USEPA’s Integrated Risk Information System (IRIS). In its carcinogenicity assessment on IRIS, the USEPA states that “available data are inadequate to establish a causal association between exposure to naphthalene and cancer in humans.” Further, “an inhalation unit risk estimate for naphthalene was not derived because of the weakness of the evidence (observations of predominantly benign respiratory tumours in mice at high doses only) that naphthalene may be carcinogenic in humans.” (USEPA 2004).

In a recent review of the potency equivalency factors (PEFs) for carcinogenic polycyclic aromatic hydrocarbons (PAHs), the carcinogenic potential for naphthalene was noted as being nil due to it being non-genotoxic and exhibiting low tumour initiating potential (Equilibrium and URS 2006). The authors of the review state that “for PAHs assigned a PEF of 0, it is recommended that available non-cancer endpoint regulatory guidelines be used to assess their potential toxicity”.

However, if it were assumed that naphthalene is a non-threshold carcinogen, the USEPA’s draft inhalation unit risk of 0.0001 per µg/m³ (the equivalent to a risk-specific concentration (RsC) of 0.1 µg/m³) would be used to provide a conservative estimation of potential cancer risks. This comparison was completed for the project and future incremental cases only, and the highest predicted incremental annual average concentration for each of the receptor groups (aboriginal, cabin, and residential) was selected. The USEPA value is more conservative than the one presented by the California Office of Environmental Health Hazard Assessment (OEHHA 2009). The draft USEPA unit risk equates to an RsC of 0.1 µg/m³, based on an acceptable incremental lifetime cancer risk (ILCR) of 1 in 100,000. The predicted air concentrations are presented in Table 28-1. As the inhalation unit risk is based on the summed risk for two different tumour types (respiratory epithelial adenomas and olfactory epithelial neuroblastomas) within the nasal cavity, the naphthalene cancer risks were added to the nasal carcinogen mixtures along with acetaldehyde and propylene oxide (see Table 28-2).

Table 28-1: Predicted Maximum Annual Average Incremental Concentrations for Receptor Groups and Comparison with Draft USEPA RsC Value [µg/m³]

Receptor Group

Project

Future

Aboriginal

1.5E-05

4.5E-05

Cabin

3.9E-05

7.7E-04

Residential

1.9E-05

6.3E-05

Naphthalene RsC

0.1


Table 28-2: Revised Nasal Tumourigens Chronic Inhalation Mixture ILCRs

Receptor Group

Project

Future

Aboriginal

1.1E-04

2.9E-04

Cabin

3.1E-04

1.4E-03

Residential

1.2E-04

6.1E-04

The inclusion of naphthalene in the carcinogenicity assessment does not change the original findings of the HHRA, in that all relevant ILCRs are less than 1 in 100,000. This suggests that the incremental cancer risks from the project and future industrial emission sources are essentially negligible.

With respect to why naphthalene was not and cannot be included in the benzo(a)pyrene toxic equivalency quotient (TEQ) group, all of the PAHs included in the benzo(a)pyrene group had available PEFs, where the toxicity of the individual PAHs were scaled to the potency of benzo(a)pyrene, and then summed to a TEQ. The PEFs used in the HHRA were adopted from Health Canada (2009). A PEF for naphthalene is not listed in the Health Canada (2009) document. The scientific review conducted by Equilibrium and URS (2006), which served as the basis of the Health Canada (2009) values, states that the overall weight of evidence suggests that naphthalene is non-genotoxic and has a low tumour-initiating potential. Equilibrium and URS (2006) subsequently recommend a PEF value of zero for naphthalene on this basis.

The carcinogenicity of several PAHs has been found to be related to the formation of potent metabolites, primarily involving bay, hindered bay, K- and fjord regions on PAH ring structures (Baird et al. 2005, Equilibrium and URS 2006). Figure 28-1 (reproduced from Baird et al) shows the structural features of PAHs that contribute to biological activity through the formation of potent metabolites. For example, the three PAHs in Figure 28-1 were assigned PEFs of 1 (benzo(a)pyrene), 10 (7,12-dibenz(a)anthracene), and 100 (dibenzo(a,l)pyrene) (Health Canada 2009; Equilibrium and URS 2006).

In contrast to the structures in Figure 28-1, the chemical structure of naphthalene (see Figure 28-2) lacks these active structural moieties, as it only consists of two rings, unlike the larger multi-ring structures of benzo(a)pyrene and other carcinogenic PAHs.

Picture Placeholder

Figure 28-1: Structural Characteristics of PAHs that Contribute to Biological Activity (Baird et al. 2005)

Picture Placeholder

Figure 28-2: Chemical Structure of Naphthalene (ATSDR 2005)

Based upon a lack of reliable evidence that naphthalene is similar to benzo(a)pyrene with respect to metabolism and carcinogenicity, and the lack of a defensible PEF value to calculate its equivalency with benzo(a)pyrene (as per the rest of the carcinogenic PAHs), naphthalene should not be included in the benzo(a)pyrene group in the HHRA. The conclusions would not change because naphthalene cannot be included as a carcinogen to the B[a]P group.

ii. No unacceptable cancer risks are predicted in regards to naphthalene; therefore, no revision of the HHRA is required.

References

Agency for Toxic Substances and Disease Registry (ATSDR). 2005. Toxicological Profile for Naphthalene, 1-methylnaphthalene, 2- methylnaphthalene. US Department of Health and Human Services.

Baird W.M., L.A. Hooven and B. Mahadevan. 2005. Carcinogenic polycyclic aromatic hydrocarbon-DNA adducts and mechanism of action. Environ Mol Mutagen 45:106-114.

Equilibrium Environmental Inc. and URS Canada Inc. 2006. Potency Equivalency Factors for Carcinogenic Polycyclic Aromatic Hydrocarbons. Prepared for: Health Canada, Health Environments and Consumer Safety Branch.

Health Canada. 2009. Federal Contaminated Site Risk Assessment in Canada. Part I: Guidance on Human Health Preliminary Quantitative Risk Assessment (PQRA). Version 2. Contaminated Sites Division, Health Environments and Consumer Safety Branch.

California Office of Environmental Health Hazard Assessment (OEHHA). 2009. Technical Support Document for Cancer Potency Factors:  Methodologies for derivation, listing of available values, and adjustments to allow for early life stage exposures. California Environmental Protection Agency, Office of Environmental Health Hazard Assessment, Air Toxicology and Epidemiology Branch. May 2009. Available at: http://www.oehha.ca.gov/air/hot_spots

United States Environmental Protection Agency (USEPA). 2004. Toxicological Review of Naphthalene (CAS No. 91-20-3) – External Review Draft. NCEA-S-1707. June 2004.

USEPA. Integrated Risk Information System http://www.epa.gov/ncea/iris/subst/0436.htm.

 

Question No.

 

29

 

 

Request

 

 

SIR Response 160 (a), Section 12.1, Page 12-3.

 

 

Shell states Chao et al. (1999) conducted measurements designed to detect trace element emissions from natural gas combustions. …the following references also support the assertion that the combustion of natural gas will not emit metals into the environment. …Produced gas will be treated to remove 96% of the hydrogen sulphide. …During normal operations there should not be detectable levels of H2S in flue gas.

 

 

The response provided references for studies on the potential (or lack thereof) for metal emissions from natural gas combustion; however, no evidence was provided to support that metals will not be emitted as a result of produced gas combustion.

 

29a

Are there any data/studies on the combustion products of produced gas?

 

 

  1. i.       If yes, provide this information.
    1. ii.        If no, discuss plans to monitor produced gas emissions?

 

Response

 

29a

 

There are published data and studies concerning the presence of trace metals in produced gas in Alberta. In a study of mercury concentration in gases, condensates, and formation water by the ERCB, Shaw et al. (1972) reported an inability to detect mercury in most samples, with a detection limit of 0.1 ppb

(w/w) for natural gases. Because no concentrations that might give rise to environmental concerns could be found, this work was abandoned after a survey

of eighteen gas fields. St. Pierre et al. (1991) outlined some of the difficulties measuring trace element concentrations in gas processing streams in Alberta. Their measurements support the Shaw et al. (1972) conclusions regarding mercury, but note unexplainable high variability in some samples for other elemental concentrations and inconclusive sources of the contaminants. The conclusion of this analysis was that the concentrations measured were not likely to create a critical emissions problem for trace elements at the plants tested.

Therefore, Shell does not envision the EPEA approval conditions to include the requirement for the project air quality monitoring program to monitor trace elemental concentrations in produced gas.

Request            29b       Are there any monitoring data/studies to support the statement that H2S should not be detectable with produced gas combustion?

i.       If yes, provide this information.
ii.      If no, discuss plans to monitor produced gas emissions?

Response         29b       Shell does not have monitoring data or studies to support the statement that “[hydrogen sulphide] H2S should not be detectable with produced gas combustion”. It is generally considered that the thermal destruction of H2S at the high temperature and residence time typical within a boiler will achieve high combustion efficiency (i.e., near complete oxidation) of H2S. Trace H2S, or partially oxidized sulphur emissions, are not part of the monitoring requirements for boilers. The environmental impacts of trace emissions are included in the air quality assessment by conservatively assuming total conversion to SO2 (i.e., complete oxidization).

Therefore, Shell does not envision the EPEA approval conditions to include the requirement for the project air quality monitoring program to monitor trace sulphur products in boiler flue gases.

References

Shaw, D.R., R.B. Dunbar and J.C. Mackid. 1972. A Study of the Mercury Content of Alberta Petroleum Reservoir Fluids; Unpublished, available from Energy Resources Conservation Board Library, Calgary, Alberta.

St. Pierre, C.C., A.Q. Gnyp, D.S. Smith, S. Viswanathan and H.F. Thimm. 1991. The Measurement of Trace Element Concentrations in Sour Gas Plant Process Streams, Journal of Canadian Petroleum Technology, Vol 30. No. 4. Available at: http://www.onepetro.org/mslib/servlet/onepetropreview?id=PETSOC- 91-04-04&soc=PETSOC

Question No.

30

 

 

Request

 

 

SIR Response 160 (d), Section 12.1, Page 12-8.

 

30a

Define the term odour unit in Table AENV 160-3.

 

Response

 

30a

 

The number of odour units (OU) is the concentration of a sample divided by the odour threshold, as calculated by the following general expression:

 Formula Placeholder

 

The odour threshold concentration, also called the odour detection limit, is the

most widely reported odour measurement in the literature. The odour threshold

concentration is the lowest concentration level that will elicit a response without

reference to odour recognition or description.

Using the odour threshold concentration, a sample with an OU above one will

probably be detected by 50% of the population and, conversely, a sample with an

OU below one is unlikely to be detected by 50% of the population.

 

Question No.

 

31

 

 

Request

 

 

SIR Responses 167 (b) and 168 (a), Section 12.1, Page 12-17 to 12-19.

 

 

Table AENV 167-2: Chronic Oral Exposure Limits lists “Nervous system effects”

 

 

as the endpoint for the aliphatic C5-C8 group. However, the response to 168a

included the following statement: …oral exposure to the aliphatic C5-C8 group was excluded since the underlying basis of the chronic limit is unavailable from

 

 

the supporting documentation.

 

31a

Provide clarification on the endpoint for the chronic oral exposure limit selected

 

 

to represent aliphatic C5-C8 group.

 

Response

 

31a

 

The endpoint for the aliphatic C5-C8 group oral limit should not have been listed as nervous system effects in Supplemental Information Round 1, Table AENV

 

167-2. The basis of the endpoint is unknown, as stated in the toxicity profile from

the HHRA (see EIA, Volume IIA, Appendix 5A). Table AENV 167-2 has been

revised and is presented here as Table 31-1, with the corrected entry in bold.

The response to Supplemental Information Round 1, AENV SIR 168a is correct.

In the original HHRA, there were only two mixtures in the chronic oral

assessment, i.e., hepatotoxicants and renal toxicants. No oral neurotoxicants

mixture was included in the original assessment.

Table 31-1: Chronic Oral Exposure Limits

Chart Graph Placeholder

Question No.

32

 

 

Request

 

 

SIR Response 168 (b), Section 12.1, Page 12-22.

 

 

Shell states The chronic inhalation exposure limit is based on lung cancer, whereas the chronic oral and dermal exposure limit is based on stomach cancer. The two different target tissues do not support addition of these risks.

 

 

As described in Volume II-A, Appendix 5A, Section 5A.14, Pages 5A-56 and 5A- 57, tumors of the forestomach have been reported in mice and rats following chronic dietary exposure to benzo[a]pyrene and tumors of the forestomach have been reported in hamsters following chronic inhalation exposure to benzo[a]pyrene, supporting the addition of lifetime cancer risks for inhalation and oral/dermal exposures.

 

32a

Provide chronic risk estimates for combined inhalation and oral/dermal exposures to the benzo[a]pyrene equivalent group.

 

Response

 

32a

 

As stated in Appendix 5A to the HHRA (see EIA, Volume IIA), the selected RsC was developed based on exposure to benzo(a)pyrene via multi-stage modelling of respiratory tract tumours in Syrian golden hamsters (Thyssen et al. 1981; CEPA 1994). The dose-response data used to generate the cancer risk estimate did not

include forestomach cancer incidence (CEPA 1994), therefore, stomach tumours were not considered as an endpoint in the mixtures assessment for benzo(a)pyrene. The toxicological basis of the exposure limit used for the benzo(a)pyrene TEQ group was not based on forestomach tumour data. As a result, the cancer risk estimate from the inhalation exposure assessment cannot be added to the cancer risk estimate from the oral/dermal assessment, as the endpoints are not the same.

References

Canadian Environmental Protection Act (CEPA). 1994. Priority Substances List Assessment for Polycyclic Aromatic Hydrocarbons. Government of Canada. ISBN: 0-662-22209-1.

Thyssen J, J. Althoff, G. Kimmerle and U. Mohr. 1981. Inhalation studies with benzo(a)pyrene in Syrian Golden Hamsters. J Natl Cancer Inst. 66(3): 575-7.

WATER ACT SIR 33

Question No.

33

 

 

Request

 

 

SIR Response 224b, Section 13.1, Page 13-40 Volume 1, Section 7.5.3, Page 7-20.

 

 

Shell states that Shell plans to install two new settling ponds directly north of the existing river source station.

 

 

Shell states the existing deemed licences under the Water Act (originally issued under the Water Resources Act) to divert and use water from the Peace River do not need to be amended for the construction of the settling ponds or the Carmon Creek Project. As discussed in the response to AENV SIR 224a, Shell will obtain the necessary authorizations under the Water Act for the construction of the settling ponds.

 

 

The Carmon Creek Project has been designed so that fresh water requirements during start-up and on occasion during the life of the project will be meet within the existing licenses. Consequently, no amendment to the licences are required for the project

 

 

Under the Water Act, the proposed project requires several authorizations for both non-consumptive (Approval) and consumptive (Licence) purposes. An ‘Approval’ for the construction of settling ponds and borrow pits with a capacity greater than 2,500 cubic metres is required. A Licence is required for the diversion and use of water (surface runoff collected at the industrial runoff ponds).

 

 

As per the Water Act, Section 54(b), on application by the licensee an amendment is required “to add terms and conditions to the licence”. The existing three licenses require amending to add a condition to include plans detailing the location of the Carmon Creek Project and the water supply alignment from the river intake at the Peace River to the CPFs, and the revision to the WTP site to include the 2 new settling ponds with pond dimensions.

 

 

The existing licenses are relevant only to the existing Shell Canada Limited Peace River Complex and require updating (amending).

 

33a

Submit an application under the Water Act for an amendment to the existing three licenses.

Response         33a       Shell will submit a Water Act application to amend the existing three licenses to include:

  • plans for the settling ponds at the river water intake station
  • alignment of the river water supply pipeline to the CPFs that will be connected to the existing river water supply pipeline to the PRC

Shell will submit the amendment application once the final engineering design for the settling ponds and pipeline has been completed

 

ALBERTA SUSTAINABLE RESOURCE DEVELOPMENT SIRS 34 – 38

 

Question No.

 

34

 

 

Request

 

 

SIR Response 75, Section 10.1, Page 10-53

 

 

SIR Response 140, Section 11.1, Page 11-85

 

 

Volume II, Part C, Section 3.5.1.2, Page 3-49.

 

 

Shell indicates that they will avoid clearing sensitive vegetation features and

 

 

avoid clearing within 100 m of defined waterbodies, where possible. For SIR

 

 

Response 75, Shell provides maps showing watercourse and waterbody buffers,

 

 

and provides circumstances where it may not be possible to avoid clearing within

 

 

100 m of waterbodies.

 

34a

Identify all site developments that are proposed to be located within 100 m of

 

 

watercourses/waterbodies. (It is not required to include linear developments such

 

 

as roads and pipelines where they cross a watercourse. However, this response

 

 

should include linear developments where they parallel a watercourse/waterbody

 

 

within the 100 m buffer).

 

Response

 

34a

 

The conceptual project footprint proposed in the application did not include any

 

 

development within 100 m of a defined waterbody. However, the proposed

 

 

conceptual footprint is based on a preliminary design and the locations of defined

 

 

waterbodies were assessed based on a desktop study using:

 

 

  • aerial photographs
  • lidar data
  • soils maps

During final design, engineering constraints that might alter the footprint could include:

  • locating well pads such that the inverted seven-spot well pattern can be fully developed
  • routing access roads and above-ground pipelines efficiently while creating minimal impedance to wildlife movement

During pre-construction scouting, field conditions could be discovered that might alter the footprint, including locating:

  • defined waterbodies that are not shown in any of the data sets
  • places without waterbodies where the data sets show a waterbody

Based on the final design and the pre-construction scouting results, Shell might adjust the footprint by altering:

 

 

  • the routing of access roads and above-ground pipelines
  • the location of well pads and borrow pits
  • pad size or shape, possibly by reducing the number of wells on a pad

 

 

Any change to the location of a well pad, or the number of wells on a pad, will

 

 

require either moving adjacent pads, or changing the number of wells per pad on

 

 

adjacent pads (as well as their size), to ensure that the inverted seven-spot well

 

 

pattern can be fully developed.

 

 

As the footprint evolves, Shell will endeavour to avoid clearing sensitive

 

 

vegetation features, and avoid clearing within 100 m of defined waterbodies. All

 

 

adjustments to the footprint will be made in consultation with ASRD.

 

Question No.

 

35

 

 

Request

 

 

SIR Response 101 (b), Section 11.1, Page 11-2

 

 

Volume I, Section 1.1, Figure 1-4, Page 1-8

 

 

Volume I, Section 8.1.3.1, Page 8-2.

 

 

In SIR Response 101(b) Shell explains that the sequence of borrow pit

 

 

development is to follow the sequence of the well pads. The location and size of

 

 

the borrow pits are shown in Figure 1-4.

 

35a

Further to the response for SIR 101(b), identify which of the first 18 well pads in

 

 

the initial development will require fill material, and which specific borrow pits

 

 

will be developed in relation to particular well sites and roads requiring pads.

 

Response

 

35a

 

Before the start of construction, Shell will assess which of the initial 18 well pads

 

 

will require borrow material, and the specific borrow pits supplying the material.

 

 

The estimates used in the EIA were to provide borrow pit information for the

 

 

purpose of defining the project terrestrial footprint. These estimates were based

 

 

on a desktop exercise, which identified the:

 

 

  • well sites and roads requiring pads
  • total volume of borrow material required
  • possible size and location of borrow pits

The desktop process for estimating which well sites and roads will require pads used information on surficial geology, as interpreted from lidar data and aerial photography. Well sites and roads on organic soils were assumed to require pads. Figure 2.5-1 (see EIA, Volume IIC) is a map of the interpreted surficial geology.

The desktop process for estimating the total volume of borrow material required, and the possible size and location of borrow pits, is included in the response to Supplemental Information Round 1, AENV SIR 101a.

Before the start of construction, pre-development site assessments and field scouting will determine exactly which well sites and roads will require pads. The field scouting results, and discussions with ASRD, will determine the exact location, size, and shape of the borrow pits.

As discussed in the response to Supplemental Information Round 1, AENV SIR 101b, the borrow pits will be developed on an as needed basis. When an area is found to need borrow material for pads, field scouting will determine the closest source (i.e., the potential borrow pit) that meets ASRD borrow pit siting requirements. Shell plans to create large borrow pits to reduce the total number of pits required, as per ASRD’s request, as discussed in the response to Supplemental Information Round 1, AENV SIR 101a. Once a borrow pit has been opened, Shell will attempt to use the borrow material from that pit until it has reached its target size.

If pad construction is completed before a borrow pit has reached its target size, Shell may negotiate with ASRD to not fully excavate the pit. If a pit reaches its target size before pad construction is complete, Shell may negotiate with ASRD to expand the borrow pit, rather than open an additional borrow pit.

Question No. 36

Request                        SIR Response 106, Section 11.1, Page 11-8

Volume I, Figure 6-1, Page 6-4

Volume I, Section 10.2.3.1, Section 10.4.2.1.

Shell identifies the construction of 6 landfill cells on the CPF site, which is located on crown green area land. Generally, ASRD does not support the locating of landfills on green area crown land, and instead prefers that other alternatives are chosen (private land, white area land sale, etc.)

In SIR 106, Shell identifies criteria for selecting landfill sites, but does not identify any alternatives as requested. Shell also references Volume I, Section

10.4.2.1 as containing justification why a new landfill location is required, and why existing landfills cannot provide Shell with adequate disposal options. However, the proposal of new onsite landfills does not seem to conserve land as indicated in section 10.4.2.1, nor is rationale provided showing that the local landfill options are not suitable for the selected waste streams for which onsite disposal is proposed.

36a       As ASRD does not normally consider applications for landfills on crown land, identify what alternatives to the chosen onsite landfill can be utilized. Include a discussion of other options such as nearby private land.

Response         36a       Shell will continue to discuss landfill options with ASRD. However, Shell feels that there are drawbacks to the alternatives for managing water treatment solid waste.

The project has been designed to minimize fresh water withdrawal from the Peace River, and will rely on recycled produced water and saline groundwater to produce steam. Before this water can be safely used to produce steam, it must be treated to remove:

  • solids
  • silica
  • calcium carbonate (i.e., hardness)

The water treatment process will produce large volumes of solid waste, which will need to be placed in a landfill.

The water treatment solid waste management alternatives considered by Shell included:

  • transporting waste by truck to an existing off-site third-party landfill
  • transporting waste by truck within the project area to a new landfill located in the White Area
  • placing waste in a new landfill located adjacent to the CPFs

Third-Party Landfill

Transporting water treatment waste by truck to an off-site third-party landfill would not be the preferred alternative because of the:

  • lack of available capacity at nearby third-party landfills
  • requirement to haul waste long distances on public roads

Over the life of the project, the volume of water treatment solid waste produced will exceed the available capacity of the East Peace Regional Landfill. Once the landfill reaches capacity, Shell could look further afield for additional capacity. However, this approach would place a burden on the Northern Sunrise County and all other users of the East Peace Regional Landfill (e.g., opening a new landfill or causing users to access other existing landfills that might be less accessible (i.e., located a further distance) than the East Peace Regional Landfill). For these capacity-related reasons, placing water treatment solid wastes in an off- site third-party landfill would not be a preferred alternative.

Stakeholders have expressed concerns about the volume of project-related traffic (i.e., increase) on public roadways. Transporting water treatment solid waste about 20 km from the project to the East Peace Regional Landfill on public roads, and even further once the East Peace Regional Landfill has reached capacity, could affect highway safety and wildlife mortality. Collisions with equipment and vehicles are a factor that might result in direct project-related wildlife mortality (see EIA, Volume IIC, Section 4.2.1.3). To mitigate stakeholder concerns and potential project impacts on wildlife, transporting water treatment solid wastes by truck to an off-site third-party landfill would not be a preferred alternative.

Shell has taken steps to mitigate air quality effects and to reduce overall project emissions. Transporting solid waste to regional landfills by truck would result in increased project emissions and air quality effects. Therefore, this alternative would not be a preferred option.

White Area Landfill

Building a new landfill in the White Area within the project area would not be a preferred alternative because the land in the White Area would be unsuitable for a landfill. Table 36-1 outlines the AENV Standards for Landfills in Alberta and the issues relating to locating the landfill in the White Area.

Table 36-1: Issues Concerning Landfill in the White Area

Chart Graph Placeholder

Landfill Adjacent to CPFs

Shell conducted a landfill site assessment (see EIA, Volume IIB, Appendix 2D) to examine the possibility of constructing landfills adjacent to the CPFs to dispose of water treatment solid waste.

The assessment determined that building a landfill adjacent to the CPFs would be the best alternative because this option would have the least potential impacts, and would be located in an area that met ERCB and AENV requirements. The benefits of locating the landfill adjacent to the CPFs include:

  • reducing traffic-related impacts of waste transportation
  • having land available to develop a landfill of sufficient capacity to store the expected volume of project waste. Furthermore, there would be no affect on the users of regional landfills.
  • meeting the regulatory requirements in:
    • ERCB Directive 058, Oilfield Waste Management Requirements for the Upstream Petroleum Industry
    • Standards for Landfills in Alberta (AENV)
    • Waste Control Regulation (AENV)
    • Conservation and Reclamation Regulation (AENV)

 

To clarify the preamble to this question, Figure 6-1 (see the Project Description,

Volume I) shows 12 landfill cells in total (four initial landfill cells labelled 7, 8,

16, and 17, and eight additional cells labelled ‘Future Landfill Cell’). Figure 2D-

1 (see EIA, Volume IIB, Appendix 2D) also highlights the location of the initial

landfill cells.

 

Question No.

 

37

 

 

Request

 

 

SIR Response 108 (b), Section 11.1, Page 11-9

 

 

Volume I, Section 8.1.1.2, Page 8-1.

 

 

Shell states that there will not be any redundant existing access roads associated

 

 

with CPF 1, CPF 2 or the field facilities. Shell also provides Figure AENV

 

 

108-1, which shows new and existing roads in the resource development area.

 

37a

Provide an update to Figure AENV 108-1 including all existing Shell License of

 

 

Occupations (LOC)’s within the Carmon Creek resource development area

 

 

including:

 

 

i.    LOC050473, LOC022827, LOC064186, LOC063945, LOC043647,

 

 

LOC080848, LOC070190, LOC080005; and

 

 

ii. Any other Shell access roads not shown on the figure or included above.

 

Response

 

37a

 

Supplemental Information Round 1, Figure AENV 108-1, accurately identified

 

 

all:

 

 

  • existing all-weather access roads
  • proposed new all-weather access roads

As requested, Figure AENV 108-1, shown here as Figure 37-1, has been revised to include the requested licence of occupation (LOC) information (LOC050473, LOC022827, LOC064186, LOC063945, LOC043647, LOC080848, LOC070190 and LOC080005). The revised figure also includes information on other Shell owned and non-Shell owned linear features in the resource development area, such as:

 

 

  • existing all-weather access roads

 

 

  • proposed new all-weather access roads

 

 

  • existing pipelines

 

 

  • proposed new pipelines

 

 

  • existing power lines

 

 

  • proposed new power lines

 

Request

 

37b

 

Identify the future requirements for the above mentioned LOC’s and any other roads which were not initially included on Figure AENV 108-1.

 

Response

 

37b

 

Supplemental Information Round 1, Figure AENV 108-1 only identified all- weather access. Therefore, LOC050473, LOC022827, LOC064186, LOC063945, LOC043647, LOC080848, LOC070190 and LOC080005 were not included on the figure because they are not all-weather access roads.

 

 

As shown on Figure 37-1, some of the LOCs that were not included in Figure AENV 108-1, have been incorporated into the project development plan. Others were not incorporated as they:

 

 

  • do not efficiently connect to project features

 

 

  • run through areas, such as wetlands, where development of all-weather access is constrained

 

 

By using existing LOCs efficiently, the project has minimized the requirement for new clearing. Table 37-1 lists the potential reuse of the LOCs that were not included in Figure AENV 108-1.

 

Request

 

37c

 

Identify appropriate decommissioning and reclamation timelines for any of the LOCs identified above should they not be required as a result of new road construction associated with the project.

 

Response

 

37c

 

Any existing Shell access roads or LOCs, or portions thereof, which are not used by the project, will be reclaimed when they are no longer in use, as per the conservation and reclamation plan under which they were developed.

Table 37-1: Potential Reuse of LOCs

Chart Graph Placeholder

Picture Placeholder

Figure 37-1: Linear Developments

Question No.

38

 

 

Request

 

 

SIR Response 235 and 236, Section 13.1, Page 13-48

 

 

Volume I, Section 14.6.5, Page 14-24

 

 

Volume II-C, Executive Summary, Page v and Page vii

 

 

Volume II-C, Section 2.6, Page 2-39 and Page 2-43

 

 

Volume II-C, Section 3.5.1.3, Page 3-55

 

 

Volume II-C, Section 6.3, Page 6-2

 

 

Volume II-C, Section 6.8 Page 6-29 to Page 6-39

 

 

Volume II-C, Section 6.9, Pages 6-46 and 6-47.

 

 

Shell states in both SIR 235 and SIR 236 that the stated reclamation strategy

 

 

provides the best possible alternative. However, Shell does not provide any

 

 

alternatives to its proposal to leave the road bed in place on arterial roads or to

 

 

reclaim most borrow pits as water features.

 

 

Shell states, Most of the borrow pits will be reclaimed as water features. In

 

 

related plans for reclamation, Shell states Arterial roads will be reclaimed with

 

 

the road beds in place and will be revegetated to an upland h1 vegetation type.

 

 

The 2010 Reclamation Criteria for Well Sites and Associated Facilities for

 

 

Forested Lands states that If a site changes land use, the

 

 

landowner/occupant/manager should be involved in the discussion but any such

 

 

changes will require their written approval (Section 3.1). As such, any proposals

 

 

to leave the pad in place, and not reclaim borrow pits to the original land use are

 

 

to be assessed on a site specific basis by ASRD (the Land Manager) and

 

 

generally are not approved.

 

38a

Identify what alternatives were considered to the proposed reclamation strategy

 

Response

 

38a

 

In 2009, when Shell developed the conceptual reclamation plan provided in the

 

 

EIA (see Volume IIC, Section 6), no specific alternatives were considered for the

 

 

reclamation of:

 

 

  • arterial roads constructed on organic soils
  • borrow pits

The conceptual reclamation plan, as described in the EIA, was to leave pad material in place when reclaiming arterial roads constructed on organic soils, and to leave most of the borrow pits as water features. This approach followed standard industry practices and met the regulatory reclamation requirements in place at the time. Although the assessments and analyses in the conceptual reclamation plan were based on those plan assumptions (i.e., industry best practice and the prevailing regulatory requirements), Shell is committed to adaptive management and will adjust the conceptual reclamation plan to incorporate changes to: 

  • industry best practices
  • regulatory requirements
  • reclamation techniques

Shell acknowledges that ASRD’s reclamation requirements changed in 2010. To meet these new requirements, Shell is considering the following alternatives for the reclamation of arterial roads constructed on organic soils:

  • removing as much pad material as possible
  • removing pad material down to near the water table

Alternative One – Maximizing Removal of Pad Material

By recovering as much of the pad material as possible from the roadbed of arterial roads, Shell would have much more material to return to the borrow pits. Shell would, on a site-by-site basis, attempt to fill the borrow pits to a level where they could be returned to their original land use. For sites where insufficient material is available to return to a borrow pit to restore its original land use, Shell would recontour the edges of the borrow pit to create a shallow marsh along the edges of the resultant waterbody.

Although removing as much of the pad material as possible from the roadbed of arterial roads would not restore the sites as uplands, it also might not result in them being reclaimed to their original land use. Because of compaction of the organic soils under the pad material, the water depth after pad removal is often beyond that required for re-establishing wetland vegetation. Therefore, the resulting landform often ends up as a waterbody, which does not match the original land use.

Alternative Two – Removing Pad Material to Near Water Table

By recovering pad material down to near the water table, conditions might be favourable for regrowth of wetland vegetation and the return of the sites to their original land use. Research into peatland reclamation is starting to show promising results based on this approach. Shell continues to support reclamation research and will, wherever possible, incorporate research results into reclamation plans.

By recovering pad material down to the near water table, more material would be returned to the borrow pits than in the existing conservation and reclamation plan. Therefore, more of the borrow pits could be completely refilled and returned to their original land use. For sites where insufficient material is available to return to a borrow pit to restore original land use, Shell would recontour the edges of the borrow pit to create a shallow marsh along the edges of the resultant waterbody.

Selected Alternative

Alternative Two would return more sites to their original land use than the EIA conceptual conservation and reclamation plan or Alternative One (see Table 38-1). However, ongoing reclamation research might provide better alternatives in the future. Shell will continue to assess alternatives and adjust the conceptual reclamation plan.

Table 38-1: Summary of Resulting Land Forms and Land Uses for Various Reclamation Alternatives

 

 

Reclamation Plan

 

 

 

Description

Arterial Road Sites

Borrow Pits

 

Resulting Land Form

Meeting Original Land Use?

 

Resulting Land Form

Meeting Original Land Use?

Conceptual Conservation and Reclamation Plan (presented in the EIA)

Leave all pad material in place when reclaiming arterial roads constructed on organic soils

Upland

No

Few as uplands, most as      waterbodies

No

Alternative One

– Maximizing Removal of Pad Material

Recover as much pad material as possible when reclaiming arterial roads constructed on organic soils

Most as waterbodies

No

Most as uplands, some as       waterbodies

Most

Alternative Two

– Removing Pad Material to Near Water Table

Recover pad material down to near the water table when reclaiming arterial roads constructed on organic soils

If research is successful, most as peatlands

Yes

Some as uplands and some as waterbodies

Some

 

Request

38b

Identify why the proposed reclamation strategy for borrow pits is considered the

 

 

best alternative as compared to those identified in (a).

 

Response

 

38b

 

See the response to SIR 38a.

 

Request

 

38c

 

Identify why the proposed reclamation strategy for arterial roads is considered

 

 

the best alternative as compared to those identified in (a).

 

Response

 

38c

 

See the response to SIR 38a.

 

Request

 

38d

 

Describe how Shell’s project design, construction, and reclamation requirements

 

 

would change should ASRD not approve the reclamation strategy as presented.

 

Response

 

38d

 

Shell acknowledges that reclamation requirements will change over time and is

 

 

committed to adaptively managing reclamation plans in consultation with

 

 

regulators and stakeholders. If ASRD does not approve the reclamation strategy,

 

 

as presented, Shell will adjust the reclamation plan to incorporate changes to:

 

 

  • industry best practices
  • regulatory requirements
  • reclamation techniques

Shell does not expect that changes to the reclamation plan will trigger any changes to the project design or construction requirements.

FISHERIES AND OCEANS CANADA SIRS 39 – 40

Question No.

39

 

 

Request

 

 

SIR Response 78 (a) and (b), Section 10.1, Page 10-61.

 

39a

Does the water intake on the Peace River have fish exclusion screens?

 

Response

 

39a

 

The river water intake for the PRC does not have fish exclusion screens. The intake was constructed at a time when fish exclusion screens were not envisaged as a design component for intake structures.

 

Request

 

39b

 

If not, discuss Shell’s plans to modify the intake structure design or operation to mitigate potential impacts to fish or fish populations.

 

Response

 

39b

 

As part of the ongoing operations of the PRC, Shell is in communication with Fisheries and Oceans Canada (DFO) regarding plans to modernize the intake structure, including the installation of fish exclusion screens that meet current standards.

 

Question No.

 

40

 

 

Request

 

 

SIR Response 86a, Section 10.1, Page 10-70 SIR Response 91, Section 10.1, Page 10-73

SIR Response 238 and 239, Section 13.1, Page 13-49.

 

 

When considering the available fisheries information both in the EIA and historical fisheries information for the Project Area, slight differences in fish distribution are noted. Shell has commitment to clear span streams where potential fish habitat exist.

 

40a

Provide a map (or watercourse crossing table) that confirms which watercourse crossing method will be utilized at each of the crossing locations in the Project

Area (i.e. clear-span bridge versus culvert) to provide clarity on what Shell considers potential fish habitat.

Response         40a       On August 2, 2011, Shell met with DFO to discuss the proposed watercourse crossings (i.e., road, pipeline, and power line) associated with the project, and provided the following information:

  • a map showing all watercourse crossings and their type (road, pipeline, and power line)
  • fisheries data collected in June 2011 for each watercourse crossing site
  • a watercourse crossing table summarizing the fisheries data and Shell’s proposed crossing method (i.e., culvert versus clear span bridge, trenchless versus open cut with isolation)

During the meeting, Shell and DFO reached a consensus concerning the presence and quality of fish habitat at each watercourse crossing, and the appropriate crossing method for each location.

Shell expects discussions with DFO regarding watercourse crossings to continue as the project footprint and the watercourse crossing engineering designs are finalized.

Question No.

41

 

 

Request

 

 

Volume II-C, Section 2.

 

41a

Provide an assessment of the effects of steaming generated heave of reservoir and overburden on the environment including local increases in hydraulic heads in groundwater aquifers and its environmental effects (including those on surface waters, bogs and fens).

 

Response

 

41a

 

As minimal or no heave is expected (see Project Description, Volume I, Section 4.1.4), Shell expects that the environmental effect of potential heave will be negligible.

 

 

Recent geomechanical modelling of the potential heave has confirmed the minimal heave assumption used in the EIA. The model predicts that the maximum potential heave will be less than 10 cm, which would have no impact on the hydrogeological models or the affects assessment.

 

 

Surface heave of less than 10 cm will have a negligible impact on hydraulic head and groundwater flow. As discussed in the response to Supplemental Information Round 1, AENV SIR 60, only near surface aquifers (i.e., less than 10 m below ground surface) have been found to have seasonal fluctuations in water level. For these aquifers, seasonal water level changes would make surface heave of less than 10 cm inconsequential. Aquifers below 10 m are not involved in groundwater-surface water interactions; therefore, heave of less than 10 cm would have no impact on these aquifers.

 

 

Because surface heave of less than 10 cm will have no impact on groundwater- surface water interactions, there are no anticipated affects on surface waters, bogs, or fens.

 

Request

 

41b

 

Provide support for the above environmental effects assessment by geomechanical model predictions illustrated by a contour map of the heave generated by the proposed project, and additional maps to illustrate potential

environmental effects such as those associated with elevated hydraulic heads and potential heave induced changes in groundwater flow.

Response        41b                  In August 2011, Shell completed a geomechanical modellingassessment of the potential heave that could be produced by the project. The model predicts that the maximum potential heave will be less than 10 cm (see Figure 41-1, heave potential at the surface of the top of the Bluesky Fonnation, and Figure 41-2, surface heave over time); as such the environmental effect of potenital heave will be negligible. Shell expects no potential environmental effects, such as those associated with elevated hydraulic heads, and no potential heave induced changes in groundwater flow

Chart Graph Placeholder

Figure 41-1: Maximum Potential Heave at Surface and Top of Bluesky Formation

The QuickBlocks model was set up as follows:

  • model dimensionsequal 20 km by 20 km
  • model was divided along depth axis into11layers, based on typelogand fonnations
  • model was dividedinto grids of 200 m by 200 m
  • locations of the injectors were mapped onto the 200 m by 200 m grid
  • if an injector was mapped onto the grid the average pressure and temperanire for that injector was assumed in the 200 m by 200 m grid
  • the injectorlocationswere approp1ai tely aligned spatially and in time, and followedthe rese1voir pressure and temperature cmves for the proposed steaming plan
  • heave at the smface and the displacementat the topof the BlueskyFo1mation were calculated at 90-day inte1vals for 20 years of injection/production
  • the model was calibratedusing heave measmements from PRC Pad 40 CSS cycles
Chart Graph Placeholder
Figure 41-2: Potent i al Heave at Surface for Years 1 through 8

 

Request

 

41c

 

Provide any information based on Shell’s experience in the region that may be

 

 

helpful to illustrate the assessment and predictions for the proposed project.

 

Response

 

41c

 

Shell has no field data for heave produced during VSD. However, as stated in the

 

 

response to SIR 41b, field data from the PRC Pad 40 CSS, a different in situ

 

 

recovery process, was used to calibrate the geomechanical model for assessing

 

 

VSD-associated heave.

 

Request

 

41d

 

Provide mitigation measures and plans to monitor the predictions.

 

Response

 

41d

 

Based on the model prediction of surface heave of less than 10 cm, and operating

 

 

experience with other in situ projects with higher potential for heave, Shell

 

 

believes there is no reason to monitor surface heave for the project.

 

 

The PRC Pad 40 uses CSS, which has a greater potential for surface heave than

 

 

VSD because of:

 

 

  • a higher BHP
  • the use of horizontal wells
  • steaming all wells on a well pad rather than a drive process

 

 

However, even under these conditions, the recorded surface heave from CSS

 

 

wells has been low (the maximum recorded surface heave during the first three

 

 

cycles was about 20 cm).

 

Question No.

 

42

 

 

Request

 

 

Volume II-C, Section 2.

 

42a

Describe how steam injection generated heave has been included in the

 

 

hydrogeological modeling and hydrogeological effects assessment.

 

Response

 

42a

 

Because minimal or no heave is expected because of steam injection (see Project

 

 

Description, Volume I, Section 4.1.4), the effects on the hydrogeology were

 

 

considered insignificant and, therefore, heave was not included in the

 

 

hydrogeological modelling or effects assessment.

 

 

Recent geomechanical modelling of the potential heave has confirmed the

 

 

minimal heave assumption used in the EIA. The model predicts that the

 

 

maximum potential heave will be less than 10 cm, which would have no impact

 

 

on the hydrogeological models or the effects assessment.

GLOSSARY

%                                        The symbol for percent.

°C                                       The symbol for degrees Celsius.

3-D                                      The abbreviation for three-dimensional.

AAAQO                               The abbreviation for Alberta Ambient Air Quality Objective.

acid gas                              A gas that forms an acid when mixed with water. In petroleum production and processing, the most common acid gases are hydrogen sulphide and carbon dioxide, both of which cause corrosion. Hydrogen sulphide is also very poisonous. See also hydrogen sulphide and sour crude oil.

adaptive management        A continuous improvement process of planning, implementing and evaluating results through monitoring and research programs and developing new plans from what has been learned.

AENV                                  The abbreviation for Alberta Environment.

airshed                               The geographic area requiring unified management for achieving air pollution control.

appraisal well                     A well drilled to confirm and evaluate the presence of hydrocarbons in a reservoir that have been found by a wildcat well.

aquifer                                A water-saturated, permeable body of rock capable of transmitting significant or usable quantities of groundwater to wells and springs under ordinary hydraulic gradients.

ASRD                                  The abbreviation for Alberta Sustainable Resource Development.

ATSDR                                The abbreviation for Agency for Toxic Substances and Disease Registry.

B(a)P                                  The chemical symbol for benzo(a)pyrene.

benthic invertebrates          Organisms that live at the bottom of lakes, ponds or streams.

BHP                                    The abbreviation for bottomhole pressure.

bitumen                              A highly viscous mixture, mainly of hydrocarbons heavier than pentanes.

In its natural state, it is not usually recoverable at a commercial rate through a well.

boiler feedwater                  Water that meets required purity specifications and which is fed to a steam generator to produce steam.

borehole                             The hole drilled by the bit. The wellbore may have casing in it, be partially cased or have no casing (open). Also known as wellbore or hole.

borrow pit                          An area that is excavated to provide material, such as gravel, sand or clay.

bottomhole                         The lowest or deepest part of the well. The bottom of the wellbore.

bottomhole pressure                             The pressure at the bottom of a wellhole.

brackish water                    Groundwater that has more than 4,000 mg/L of total dissolved solids. Also known as saline groundwater.

caprock                              A hard rock or stratum overlying a salt dome or a deposit of oil, gas or coal.

CCME                                 The abbreviation for the Canadian Council of Ministers of the Environment.

centipoise                           A measure of a fluid’s viscosity, or resistance to flow, equal to one- hundredth of a poise.

cm                                      The metric symbol for centimetre.

cogeneration                      The simultaneous on-site generation of electrical power and process steam or other hot fluids from the same plant.

commissioning                  The act of charging a system and conducting tests to ensure that the system functions safely before start-up.

condensate                         A light hydrocarbon liquid obtained by condensing hydrocarbon vapours from natural gas.

COPC                                 The abbreviation for chemicals of potential concern.

COSEWIC                           The abbreviation for the Committee on the Status of Endangered Wildlife in Canada.

cp                                       The abbreviation for centipoise.

CPF                                    The abbreviation for central processing facility.

crude oil                             Unrefined liquid petroleum.

CSS                                    The abbreviation for cyclic steam stimulation.

cumulative effects              Changes to the environment caused by an action, including projects and activities, in combination with other past, present and future human actions.

CVG                                    The abbreviation for casing vent gas.

cyclic steam stimulation     The injection of steam into the rock surrounding a production well to lower the viscosity of heavy oil and increase its flow into the wellbore. Steam injection might be followed by immediate production or by closing the well (called the soak phase) to allow even heat distribution before production begins. The cycle of injection, soak and production is repeated as long as the oil yield is profitable. Also known as huff ’n puff.

d                                         The abbreviation for day.

dead oil                              Oil in which little or no gas is dissolved.

 decommissioning, abandonment and reclamation The act of permanently stopping operations, removing facilities and restoring land to a productive state.

delineation well                  A well drilled in an existing field to determine, or delineate, the extent of the reservoir.

DFN                                    The abbreviation for Duncan’s First Nation.

DFO                                    The abbreviation for Fisheries and Oceans Canada.

diluent                                A light liquid hydrocarbon added to bitumen to lower viscosity and density.

dissolved oxygen               A relative measure of the amount of oxygen that is dissolved or carried in a given medium.

DMI                                     The abbreviation for Daishowa-Marubeni International Ltd.

DO                                      The abbreviation for dissolved oxygen.

ecosite                                An area with a unique recurring combination of vegetation, soil, landform and other environmental components.

ecosite phase                     A subdivision of the ecosite based on the dominant tree species in the canopy. On some sites where the tree canopy is lacking, the tallest structural vegetation layer determines the ecosite phase.

EIA                                     The abbreviation for environmental impact assessment.

EPEA                                  The abbreviation for Environmental Protection and Enhancement Act.

ERCB                                  The abbreviation for Alberta Energy Resources Conservation Board.

external upset ends            Forging of ends on (API) tubing and drill pipe to provide additional thickness for strengthening connections.

facies                                  A part of a bed of sedimentary rock that varies significantly from other parts of the bed.

flowback                             The movement of fluid up the well.

flowmeter                           An instrument that monitors, measures, or records the amount of fluids moving through a pipe or other container.

footprint                             The amount and shape of an area disturbed.

formation fracture pressure The point at which a formation will crack from pressure in the wellbore.

genotoxic                           Having a deleterious effect on cell DNA.

GJ/t                                    The abbreviation for gigajoule per tonne.

H2S                                     The chemical symbol for hydrogen sulphide.

ha                                       The metric symbol for hectare.

habitat                                The natural environment of an organism.

HHRA                                  The abbreviation for human health risk assessment.

Holarctic biogeographic region Nearctic and Palearctic regions considered together as a single biogeographic region.

hole                                    The hole drilled by the bit. The wellbore may have casing in it, be partially cased or have no casing (open). Also known as wellbore or borehole.

HP                                      The abbreviation for high pressure.

hr                                       The abbreviation for hour.

huff ’n puff                          The injection of steam into the rock surrounding a production well to lower the viscosity of heavy oil and increase its flow into the wellbore. Steam injection might be followed by immediate production or by closing the well (called the soak phase) to allow even heat distribution before production begins. The cycle of injection, soak and production is repeated as long as the oil yield is profitable. Also known as cyclic steam stimulation.

HWDP                                 The abbreviation for Horizontal Well Demonstration Project.

hydrocarbon                       A compound that consists mainly of hydrogen and carbon. The simplest hydrocarbons are gases at ordinary temperatures and, with increasing complexity of molecular structure, they become liquids and solids. Natural gas and petroleum are mixes of hydrocarbons.

hydrogen sulphide             A flammable, colourless gaseous compound of hydrogen and sulphur, which is highly corrosive and poisonous.

hydrogeology                     The science that deals with the occurrence of water on the surface and underground, its use, and its functions in modifying the earth, primarily by erosion and deposition.

ILCR                                   The abbreviation for incremental lifetime cancer risk.

in situ                                 In place or in the original position.

infrastructure                      Basic facilities, such as transportation, communications, power supplies and buildings, that enable an organization, project or community to function.

IRIS                                    The abbreviation for the USEPA’s Integrated Risk Information System.

isopach map                      A geological map of subsurface strata showing the various thicknesses of a given formation underlying an area.

karst                                   A topography formed over limestone, dolomite, or gypsum and characterized by sinkholes, caves, and underground drainage.

kJ                                       The metric symbol for kilojoule.

kJ/Sm3                                The metric symbol for kilojoule per standard cubic metre.

km                                      The metric symbol for kilometre.

kPa                                     The metric symbol for kilopascal.

kPa(g)                                 The metric symbol for kilopascal gauge.

lidar                                    The abbreviation for light detection and ranging.

linear features                     Disturbances to the landscape, caused by human activity, that are long, narrow and of uniform breadth, such as roads, seismic lines and pipelines.

lithofacies                           A subdivision of a specified stratigraphic unit distinguished on the basis of lithologic features.

LOC                                    The abbreviation for licence of occupation.

LSA                                    The abbreviation for local study area.

m                                        The metric symbol for metre.

m3/d                                   The metric symbol for cubic metres per day.

mg/L                                   The metric symbol for milligrams per litre.

mitigation                           Measures taken to eliminate, reduce or control a project’s adverse effects.

mm                                     The metric symbol for millimetre.

moiety                                A part or portion of a molecule having a characteristic chemical or pharmacological property.

monitoring, environmental Periodic inspections to observe and report on compliance with approval conditions, confirm effectiveness of approved protection measures, verify the accuracy of impact predictions, or to identify any effects not predicted in the impact assessment, or both.

MPa                                    The metric symbol for megapascal.

MPa(g) or MPag                  The metric symbol for megapascal gauge.

muskeg                              A thick deposit of partially decayed vegetable matter of wet boreal regions.

NA                                      The abbreviation for not applicable.

OD                                      The abbreviation for outside diameter.

OEHHA                               The abbreviation for the California Office of Environmental Health Hazard Assessment.

OU                                      The abbreviation for odour unit.

PAH                                    The abbreviation for polycyclic aromatic hydrocarbon.

PASZA                                The abbreviation for Peace Airshed Zone Association.

peatland                             An area of unconsolidated soil material consisting largely of undercomposed, or only slightly decomposed, organic matter.

PEF                                    The abbreviation for potency equivalency factor.

PRC                                    The abbreviation for Peace River Complex.

PREP                                  The abbreviation for the Peace River Expansion Project.

PRISP                                 The abbreviation for the Peace River In Situ Pilot.

produced gas                     Gas that is produced from the wellbore with bitumen and water.

produced water                  Water that is produced from the wellbore with bitumen and gas.

reclamation                        The process of returning disturbed land to its former or other productive uses.

reservoir                             A subsurface body of rock having sufficient porosity and permeability to store and transmit fluids.

Rge                                     The abbreviation for range.

right-of-way                        The right of passage or of crossing over someone else’s land. An easement in lands belonging to others that is obtained by agreement or lawful appropriation for public or private use.

RIVM                                  The abbreviation for The National Institute for Public Health and the Environment.

ROW                                   The abbreviation for right-of-way.

RSA                                    The abbreviation for regional study area.

RsC                                    The abbreviation for risk-specific concentration.

runoff                                 The portion of precipitation (rain and snow) that ultimately reaches streams via surface systems.

SAGD                                 The abbreviation for steam-assisted gravity drainage.

saline groundwater             Groundwater that has more than 4,000 mg/L of total dissolved solids. Also known as brackish water.

SARA                                  The abbreviation for the Species at Risk Act.

Shell                                   The abbreviation for Shell Canada Limited.

SO2                                                 The chemical symbol for sulphur dioxide.

SOC                                    The abbreviation for statement of concern.

sour crude oil                     Oil containing hydrogen sulphide or another acid gas.

sour-service                        Used in a sour crude oil or sour gas application.

stakeholder                         People or organizations with an interest or share in an undertaking, such as a commercial venture.

start-up                               The act of starting work or energizing machinery or equipment after commissioning, or restarting it after a temporary shutdown or decommissioning.

steam drive                        A method of improved recovery in which steam is injected into a reservoir through injection wells and driven toward production wells. The steam reduces the viscosity of crude oil, causing it to flow more freely. The heat vaporizes lighter hydrocarbons. As they move ahead of the steam, they cool and condense into liquids that dissolve and displace crude oil. The steam provides additional gas drive. This method is used to recover viscous oils. Also known as steam flood.

steam quality                      The percentage, by weight, of vapour in a steam and water mixture.

stockpile                             A gradually accumulated reserve of material.

t                                          The metric symbol for tonne.

t/d                                       The metric symbol for tonnes per day.

TEQ                                    The abbreviation for toxic equivalency quotient.

THP                                    The abbreviation for tubing head pressure.

till                                       Unsorted sedimentary material deposited directly by and underneath a glacier, consisting of a mixture of clay, silt, sand, gravel and boulders.

TJ/d                                    The abbreviation for terrajoule per day.

TOR                                    The abbreviation for terms of reference.

TPHCWG                            The abbreviation for Total Petroleum Hydrocarbon Criteria Working Group.

Twp                                    The abbreviation for township.

USEPA                               The abbreviation for the United States Environmental Protection Agency.

UWI                                    The abbreviation for unique well identifier.

vertical steam drive            A bitumen recovery method that involves moving steam horizontally between vertical wells.

viscosity                             A measure of the resistance of a fluid to flow.

volatile organic compound A compound that boils below a temperature of about 100oC, including all non-methane hydrocarbons.

VSD                                    The abbreviation for vertical steam drive.

W5M                                   The abbreviation for west of the fifth meridian.

waste                                  All solids, liquids and sludge produced in the course of constructing, operating and abandoning facilities.

waterbody                           A body of water up to the high-water mark, including canals, reservoirs, oceans and wetlands, but not including sewage or waste treatment lagoons.

watercourse                        A natural or artificial channel with perennial or intermittent flow and definable bed and banks.

WCFN                                 The abbreviation for Woodland Cree First Nation.

wellbore                             The hole drilled by the bit. The wellbore may have casing in it, be partially cased or have no casing (open). Also known as borehole or hole.

wetlands                             Land having the water table at, near or above the land surface, or which is saturated for long enough periods to promote wetland or aquatic processes. Wetlands include peatlands and areas that are influenced by excess water.

White Area                          One of two administrative areas in Alberta, consisting mainly of agricultural lands. This area is administered by the North West and North East regions of Alberta Agriculture, Food and Rural Development.

yield strength                     The amount of pressure inside or outside a joint of riser pipe that is required to permanently distort it.

μg/kg bw/d                                    The metric symbol for micrograms per kilogram body weight per day.

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