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Deep Panuke Offshore Gas DevelopmentEnvironmental Assessment Report

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Volume 4

DEEP PANUKE OFFSHORE GAS DEVELOPMENT

ENVIRONMENTAL ASSESSMENT REPORT VOLUME 4

Document No.: DMEN-X00-RP-RE-00-0005 Rev 01U

Prepared by: EnCana Corporation

Suite 700, 1701 Hollis Street Halifax, Nova Scotia

B3J 3M8

November 2006

Deep Panuke Volume 4 (Environmental Assessment Report)• November 2006 1

PREFACE

This Environmental Assessment Report is the fourth of five documents comprising a Development Plan Application (DPA) for approval of the Deep Panuke Offshore Gas Development. The documents comprising the DPA are as follows:

Volume 1 Project SummaryVolume 2 Development PlanVolume 3 Canada-Nova Scotia Benefits PlanVolume 4 Environmental Assessment ReportVolume 5 Socio-Economic Impact Statement

Volume 1, the Project Summary, summarizes the DPA and provides a description of the Project for a general review.

Volume 2, the Development Plan, describes the development strategy and includes details on subsurface interpretation, drilling, processing, facilities, and environmental and safety management for the Project.

Volume 3, the Canada-Nova Scotia Benefits Plan, describes the processes to promote Canada and Nova Scotia benefits associated with the Project.

Volume 4, the Environmental Assessment (EA) Report, describes the physical and biological environment in which the Project will operate, provides an assessment of the potential environmental, and socio-economic effects of the Project, and identifies mitigation measures.

Volume 5, the Socio-Economic Impact Statement (SEIS) provides a summary of the existing socio-economic conditions and a summary of the potential impacts with the project.

Deep Panuke Volume 4 (Environmental Assessment Report) November 2006

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EXECUTIVE SUMMARY

In December 2002, EnCana Corporation (EnCana) received Ministerial approval for the Deep Panuke Comprehensive Study Report (CSR; approved 2002 CSR). Approval was based on a project comprising three offshore platforms producing 11.3 x 106 m3/d [400 MMscfd] of sales gas through a dedicated 610 mm [24 inch], 176 km export pipeline with tie-in to Maritimes and Northeast Pipeline (M&NP) facilities. In February 2003, just prior to the public hearing process for application to the Canada-Nova Scotia Offshore Petroleum Board (CNSOPB) and National Energy Board (NEB), a project “time-out” was requested by EnCana to allow further review and refinement of the Project. Between 2003 and 2006, EnCana completed the re-evaluation phase and is now re-filing a Development Plan Application (DPA) and NEB application based on a new project basis (the Project).

As part of pre-filing consultation with regulators, EnCana identified elements of the previously approved 2002 CSR that are still valid for the revised Project. The Canadian Environmental Assessment Act (CEAA) permits the use of previously conducted assessments. Section 24 of CEAA requires that previous environmental assessments (EAs) be used to whatever extent is appropriate in conducting the EA of the revised Project.

Section 24 of CEAA reads as follows:

24. (1) Where a proponent proposes to carry out, in whole or in part, a project for which an environmental assessment was previously conducted and (a) the project did not proceed after the assessment was completed, (b) in the case of a project that is in relation to a physical work, the proponent proposes

an undertaking in relation to that work different from that proposed when the assessment was conducted,

(c) the manner in which the project is to be carried out has subsequently changed, or (d) the renewal of a licence, permit, approval or other action under a prescribed

provision is sought, the responsible authority shall use that assessment and the report thereon to whatever extent is appropriate for the purpose of complying with section 18 or 21.

(2) Where a responsible authority uses an environmental assessment and the report thereon pursuant to subsection (1), the responsible authority shall ensure that any adjustments are made to the report that are necessary to take into account any significant changes in the environment and in the circumstances of the project and any significant new information relating to the environmental effects of the project.

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Pursuant to Section 17 of CEAA, the Responsible Authorities (RAs) have delegated the conduct of the environmental assessment to the proponent. This environmental assessment report (EA Report) (DPA Volume 4) will also be submitted to the CNSOPB to form the Environmental Impact Statement (EIS) component of the DPA and to the NEB to form the EA component of the pipeline application. The EA Report will be distributed for public comment under the CSR process and will form the basis for the CSR to be prepared by the RAs following the public comment period.

EnCana filed a Project Description on August 28, 2006 to initiate provisions of the Federal Coordination Regulations pursuant to CEAA. A draft scoping document was released for public review in September 2006. A final scoping document was released in November 2006.

Project Overview

EnCana holds a majority working interest in and is the Operator of Deep Panuke, which is located approximately 250 km southeast of Halifax, Nova Scotia (NS) and about 48 km west of Sable Island on the Scotian Shelf. The Project design consists of a jack-up mobile offshore production unit (MOPU) in a water depth of approximately 44 m. The Project will initially include re-completing four previously drilled wells and drilling a new production well and a new acid gas injection well. Up to three additional subsea production wells could be drilled. All subsea wells will be tied back individually to the MOPU with subsea flowlines and control umbilicals.

The export system will consist of a single subsea pipeline delivering Deep Panuke sales product to one of two delivery points (collectively referred to as the “Proposed Project Options”):

• Goldboro, Nova Scotia, to an interconnection with M&NP (herein referred to as the “M&NP Option”); or

• the Sable Offshore Energy Project (SOEP) 660 mm [26 inch] export pipeline at a close point on the pipeline route to Goldboro (herein referred to as the “SOEP Subsea Option”).

The gas processing system will include inlet compression, separation, sweetening, dehydration, export compression and measurement. Deep Panuke is considered a sour gas reservoir with raw gas containing approximately 0.18% hydrogen sulphide (H2S); therefore, gas sweetening equipment is required. Acid gas processing will be performed offshore through application of an amine unit to remove H2S and carbon dioxide (CO2), collectively also known as acid gas. Subsequent to its removal from the raw gas stream, the acid gas will be disposed by injection into a suitable reservoir. Disposal of acid gas by injection compared to other potential disposal options (e.g., flaring) will result in an annual reduction of CO2 equivalent of 34 kilotonnes to the atmosphere and will reduce total sulphur emissions to negligiblelevels. Acid gas injection will yield an approximate 18% reduction in total annual CO2 equivalent emissions for the Project.


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For the M&NP Option, hydrocarbon dewpointing is required on the MOPU. The condensate stream will be treated and used for fuel. Currently, it is estimated that there will be no surplus condensate produced beyond fuel usage; however, in the event that condensate must be injected, it will be disposed with the acid gas stream in the injection well. For the SOEP Subsea Option, treated condensate will be re-combined with the gas in the multi-phase export pipeline.

The production facility will have a design capacity of 8.5 x106 m3/d [300 MMscfd] with turndown capability to 1.1 x106 m3/d [40 MMscfd].

The major modifications between the revised Project basis and the Project basis for the approved 2002 CSR include:

production design capacity of 8.5 x 106 m3/d [300 MMscfd] versus 11.3 x 106 m3/d [400 MMscfd];subsea wellheads with subsea tie-backs versus platform wells; single integrated installation (MOPU) versus three fixed platforms; revised field centre location; additional export (multi-phase) pipeline option (SOEP Subsea Option); and greater produced water discharge rate.

Table ES.1 provides a more detailed comparison between the Project basis for the approved 2002 CSR and the revised Project basis.

Table ES.1 Comparison of Approved 2002 CSR Project Basis and the Revised Project Basis

Project Item Base Case (Approved 2002 CSR) M&NP Option SOEP Subsea Option

Well Count and Configuration

Maximum of 8 – platform wells 5-6 new drilled production wells: H08, PI1B, M79A, PP3C and 1-2 future wells 1-2 new drilled injection wells

Maximum of 9 – subsea wells 4 re-entry wells: H-08 (PL 2902), M-79A (PL 2902), F-70 (EL 2387), and D-41 (PL 2901) 1 new production well: H-99 (PL 2902) 1 new injection well D-70 (EL 2387) Up to three future wells (currently undefined locations on PL 2901, SDL 2255H, PL 2902 or EL 2387) Buried flowlines and umbilicals from wellheads to installation

Project Life Expected mean case: 11.5 years Expected mean case: 13.3 years Expected range: 8-17.5 years

Field Centre Base Case Relocated 3.6 km NNE


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Table ES.1 Comparison of Approved 2002 CSR Project Basis and the Revised Project Basis


Base Structure Three fixed platforms including: Production platform Utilities/quarters platform Wellhead platform

1 MOPU Integrated facility

Discharge of Muds / Cuttings for New Wells

Drilled from field centre WBM/cuttings overboard SBM/cuttings skipped and shipped or injected

Drilled from individual well locations WBM/cuttings overboard No SBM

Delivery Point M&NP tie-in Onshore, adjacent to SOEP gas plant

SOEP subsea tie-in SOEP 660 mm [26 inch] pipeline

Export Pipeline 610 mm [24 inch], 176 km Single phase Trenched ~ 50% of route

560 mm [22 inch], 176 km Single phase Trenched ~ 50% of route

510 mm [20 inch], 15 km Multi-phase Trenched 100% of route

Export Gas 11.3 x 106 m3/day [400 MMscfd] Sales quality

8.5 x 106 m3/day [300 MMscfd] Sales quality

8.5 x 106 m3/day [300 MMscfd] Sweet and dehydrated

Export Condensate N/A Maximum of 220 m3/day Sweet and stabilized, commingled with gas

Condensate Use Fuel, surplus injected Sales product

Produced Water Maximum 1,100 to 1,600 m3/day [7,000 to 10,000 bpd] Discharged overboard

Maximum 6,400 m3/day [40,000 bpd] Discharged overboard

Acid Gas Dedicated injection well ~180 x 103 m3/day [6 MMscfd]

Dedicated injection well ~130 x 103m3/day [4.5 MMscfd]

Malfunctions and Accidental Events

EnCana has reviewed the various potential malfunctions and accidental events that may occur during the Project and has updated spill probability analysis, spill behaviour modelling and air quality modelling based on the new Project design and location. Spill probability remains low, with the highest frequency for smaller, platform spills (less than 1 bbl). The probability of a spill from a flowline or export pipeline is estimated to be 0.03% chance per year for spills between 1,000 and 10,000 barrels. In general, the spill behaviour modelling results present potential impact zones similar to or smaller than those identified in the approved 2002 CSR. EnCana has incorporated design features and procedures to


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virtually eliminate or minimize the risk of major releases. EnCana will also develop and implement safety, spill response and contingency plans to reduce adverse environmental effects in the unlikely event of such incidents.

Public Consultation and Aboriginal Communications

A substantial consultation process on the Project took place between 2000 and 2002 as part of the environmental assessment process leading to the Ministerial approval of the CSR in 2002. In 2006, EnCana initiated a public consultation program to seek public and stakeholder input to the current environmental assessment and Project planning process. Discussions with Aboriginal groups have been initiated with respect to the currently proposed Project and to highlight the findings and conclusions of the EA Report. Issues identified through these processes have been tracked for consideration in Project planning and the preparation of the EA Report. EnCana will continue to proactively communicate with interested stakeholders and will provide supplementary information as part of this ongoing public consultation process. EnCana remains committed to communication around public and stakeholder concerns and the development of mutually constructive relationships.

Scope of the Assessment

The scope of the assessment was defined based on differences between the Project basis for the approved 2002 CSR and the revised Project basis. As such, the EA Report focussed on Project modifications and regulatory, biophysical, and socio-economic updates since the approved 2002 CSR. These modifications and updates were identified through a review of the Proposed Project Options, regulatory and stakeholder consultation, background research, and professional judgment of the Study Team. The final scope of the assessment was provided by the relevant regulatory authorities in November 2006 following a period of public comment.

Biophysical Valued Environmental Components (VECs) selected for the approved 2002 CSR remained valid and were reselected for this EA Report. The socio-economic VECs selected for this EA Report were updated from the approved 2002 CSR and focussed on social components most likely to be affected by the Proposed Project Options.

Since the scope of this EA Report was limited to modifications and updates from the approved 2002 CSR, potential interactions which had been assessed previously did not require reassessment. Likewise, where a Project modification was predicted to result in a lower effect than that previously assessed (e.g.,smaller footprint, less emissions), in general, the effects analysis presented in the approved 2002 CSR was referenced and no further analysis was required.


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Based on this scoping exercise, the following VECs were selected:

Air Quality Marine Water Quality Marine Benthos Marine Fish Marine Mammals and Turtles Marine Related Birds Sable Island Onshore Environment Land Use Economy Commercial Fisheries and Aquaculture Other Ocean Users

The scoping for the cumulative effects assessment (CEA) also focussed on Project modifications and regulatory, biophysical and socio-economic updates since the approved 2002 CSR. The activities considered in the CEA reconsidered those activities that have changed since 2002 such that the cumulative effects would differ from that originally predicted, or interact cumulatively with the revised Project options, resulting in different cumulative effects than originally predicted for the approved 2002 CSR.

Biophysical Assessment

In general, effects on biophysical VECs were predicted to be similar to or less than, those presented in the approved 2002 CSR. As was the case in the approved 2002 CSR, the only predicted significant adverse effect is the effect on air quality in the unlikely event of a well blowout or piping rupture resulting in the release of large amounts of acid gas. Such an event could have health and safety consequences for platform workers and passengers on vessels downwind. Design prevention measures, rendering such an event extremely unlikely, and emergency response contingency planning will further reduce the likelihood that workers or others would be seriously affected by emissions. Air quality modelling for accidental events indicates exposure levels to receptors on Sable Island remain not significant and have decreased from that originally predicted in the approved 2002 CSR. Spill modelling indicates that accidental releases of hydrocarbon from the Project will dissipate quickly without widespread effects and would not reach Sable Island.

Modelling studies of produced water discharges and drill wastes were updated to reflect Project modifications. Despite the greater volumes of produced water discharges, modelling has shown that

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these discharges are not expected to result in significant adverse effects on marine water quality or marine organisms. Project modifications will result in lower total WBM and cuttings discharges spread over a larger area (i.e., disposed at well sites, not a single platform location). Dispersion modelling of these discharges reveal an increased initial dispersion of drilling wastes, resulting in smaller cutting piles.

New Project related effects not considered in the approved 2002 CSR include potential effects on wetlands and freshwater habitat as a result of onshore components for the M&NP Option. EnCana is currently in discussions with landowners to finalize the routing of the onshore pipeline (and location of associated facilities). Through these discussions, EnCana will make every reasonable effort to minimize interactions with wetlands or any other sensitive onshore environmental features. Analysis of potential effects of the Project on the onshore environment assumed that EnCana may be unable to avoid wetlands and watercourse crossings. Mitigation and follow-up to minimize adverse effects on these features have been included and there are not predicted to be any significant residual adverse effects.

The biophysical CEA focussed largely on potential cumulative effects with the proposed Keltic Petrochemical Inc. petrochemical facility and LNG project (Keltic/Maple Project), which is planned to begin construction in the Goldboro Industrial Park in 2007. Spatial and temporal overlap between the Keltic/Maple Project and the Deep Panuke Project could result in cumulative effects on the nearshore and onshore environment. However, due to mitigation and monitoring/follow-up proposed by both proponents (EnCana and Keltic/Maple), these effects are not likely to be significant.

Socio-economic Assessment

The socio-economic impact assessment presented in this EA Report builds upon the socio-economic impact assessment prepared and filed in 2002. In this EA Report, the socio-economic impact assessment concentrated on offshore (Commercial Fisheries and Aquaculture, Other Ocean Users) and onshore (Land Use) effects. Economic impacts associated with the revised Project were presented in the Economy VEC.

The Deep Panuke Project is not likely to have significant adverse socio-economic effects. The Project will bring positive socio-economic benefits to the Province of Nova Scotia and represents an important step in the further development of the offshore oil and gas industry in Atlantic Canada. The Project is predicted to result in employment, business, and training opportunities, and contribute to economic stability and growth within the Province of Nova Scotia and for all Canadians. By bringing a second offshore natural gas field into production, the Project strengthens and diversifies the supply of natural gas in the Province and other domestic markets in Canada.

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EnCana and the Province of Nova Scotia have worked collaboratively to agree to commitments for potential development of Deep Panuke with respect to Nova Scotian opportunities and other issues including royalty treatment and funding of research and development, education and training, and programs for disadvantaged groups. These commitments were documented in the Offshore Strategic Energy Agreement (OSEA) signed on June 22, 2006. The Project will contribute positively to local and provincial employment, incomes and gross economic output. During the Deep Panuke Project, EnCana has committed to certain levels of economic activity within Nova Scotia. EnCana will continue to provide manufacturers, consultants, contractors, service companies in Nova Scotia and other parts of Canada with a full and fair opportunity to participate on a competitive basis in the supply of goods and services required for the Project.

Positive effects are predicted for Land Use and Economy as the Project will be consistent with designated use in the Goldboro Industrial Park and will contribute to economic development.

In the unlikely event of a pipeline rupture and fire associated with the onshore or landfall portion of EnCana’s pipeline (M&NP Option), there is potential to cause a significant adverse effect on land use if the Keltic/Maple facilities become involved causing large scale fire and/or release of dangerous materials. A detailed quantitative risk analysis considering potential risk synergies between the nearshore/onshore components of the Project with the proposed Keltic/Maple Project will be undertaken during detailed route design in conjunction with further Keltic/Maple Project planning and design. Compliance with all applicable design codes and standards will ensure that cumulative risks of hazard to land use and inhabitants between the two projects are extremely low.

The offshore pipeline route options will interact with an experimental sea cucumber fishery (M&NP Option only) and quahog fishery. Current plans are that quahogs will be harvested prior to construction, thereby limiting the potential for effects on this fishery. The potential effects on the sea cucumber fishery, if the fishery is indeed developed, are expected to be limited due the small area of overlap with Project activities and the low density of sea cucumbers.

Effects on marine navigation are predicted to be not significant given implementation of appropriate mitigation, including effective communication with other ocean users. The issuance of Notices to Mariners during installation activities and the charting of all Project infrastructure and safety zones will decrease the likelihood of interaction between vessels and Project components. No significant adverse effects are predicted on socio-economic VECs.

Similar to the biophysical CEA, the socio-economic CEA focussed largely on potential cumulative effects with the Keltic/Maple Project. The environmental assessment for the Keltic/Maple Project predicted significant economic benefits and significant demands on the local transportation infrastructure as a result of project development. There is predicted to be a positive cumulative effect on


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the economy as a result of the two projects. The cumulative contribution of EnCana’s onshore construction activities (M&NP Option) and the Keltic/Maple Project to adverse effects on transportation infrastructure will be relatively small and mitigated. Proponents of the Keltic/Maple Project have also committed to working with local authorities to help mitigate transportation effects to non-significant levels.

The socio-economic CEA also considered cumulative effects associated with subsea infrastructure and safety (fishing exclusion) zones on commercial fisheries. The proposed safety zone for the Deep Panuke Project is not located within a heavily fished area. In summary, significant adverse cumulative socio-economic effects are not considered likely.

Effects of the Environment on the Project

As predicted in the approved 2002 CSR, effects of the environment on the Project are not considered to be significant. Project facilities will be designed and installed based on the appropriate environmental design criteria to ensure the safety and integrity of these facilities during severe environmental conditions. Monitoring and/or contingency planning will also serve to minimize adverse effects.

Environmental Management Features and Commitments

EnCana will honour all commitments made in the approved 2002 CSR except where a commitment is no longer valid due to Project design modifications or other updates. In addition, this EA Report identifies new commitments to minimize adverse effects that could occur as a result of these design modifications. Section 11 of this EA Report summarizes these exceptions and new commitments. The following is a list of key environmental management features of the Project and other commitments made by EnCana to minimize adverse environmental effects of the Project:

injection of waste acid gas into a suitable geological structure which will reduce potential atmospheric emissions of greenhouse gases (GHG) (by 18% ) and sulphur compounds ( >99%) during routine operations;an internal design target (25 mg/L) for oil in produced water which is lower than the regulatory limit (30 mg/L, 30-day rolling weighted average); in addition to a hydrocyclone, use of a dedicated full-time polishing unit (organophillic clay type) and stripping tower to reduce hydrocarbons (and potentially other chemicals) and H2Srespectively in produced water prior to discharge; co-operation with the Fisheries and Oceans (DFO) Centre for Offshore Oil and Gas Environmental Research (COOGER) on investigating fate and effects of produced water discharges from the MOPU;


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in addition to a separator tank, use of a dedicated full-time polishing unit (organophillic clay type) to reduce hydrocarbons (and potentially other chemicals) in deck drainage prior to discharge;use of water-based muds only; recovery of waste heat during offshore operations; use of surplus condensate for offshore power generation (M&NP Option); use of an existing pipeline corridor (M&NP Option) or pipeline (SOEP Option) for transporting gas to shore; design (protective concrete coating) and/or installation (burial) of pipelines/flowlines to minimize interactions with fishing activities; Project configuration and planned mitigation to avoid harmful alteration of fish habitat as defined under the Fisheries Act and disposal at sea as defined under the Canadian Environmental Protection Act (CEPA);no nearshore pipeline construction during lobster fishing season (April 19 to June 20) which also covers the period when the endangered Roseate Tern typically prospects for nests and lays eggs on nearby Country Island (May 1 to June 20); routing of the onshore pipeline to minimize interactions with sensitive environmental locations such as wetlands and major stream crossings where possible; and adherence to corporate Codes of Practice for Sable Island, Country Island and the Gully Marine Protected Area.

Conclusions

In conclusion, the Deep Panuke Project is not likely to have significant adverse effects on the environment. The Project will contribute positively to the Canadian and Nova Scotia economies by establishing a viable facility and operation. The Project will reduce adverse environmental effects to acceptable levels through the use of technically and economically feasible design and mitigation measures.

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Table of Contents Page No.

EXECUTIVE SUMMARY ................................................................................................................ ES-1 1 INTRODUCTION........................................................................................................................... 1-1

1.1 Project Overview .................................................................................................................... 1-2 1.2 Purpose and Need for the Project............................................................................................ 1-6 1.3 Regulatory and Planning Context ........................................................................................... 1-6 1.4 Scope of the Assessment......................................................................................................... 1-8

1.5 Project Study Area .................................................................................................. 1-82 PROJECT DESCRIPTION ........................................................................................................... 2-1 2.1 Reservoir Description .............................................................................................................. 2-1 2.2 Project Infrastructure Components .......................................................................................... 2-3 2.2.1 Mobile Offshore Production Unit (MOPU)................................................................ 2-3 2.2.2 Subsea Wells and Flowlines ....................................................................................... 2-5 2.2.3 Export Pipeline............................................................................................................ 2-5 2.2.4 Onshore Pipeline and Facilities ................................................................................ 2-10 2.3 Construction and Installation ................................................................................................. 2-14 2.3.1 MOPU Facilities ....................................................................................................... 2-14 2.3.2 Export Pipeline.......................................................................................................... 2-16 2.3.3 Subsea Tie-In Facilities............................................................................................. 2-16 2.3.4 Subsea Flowlines and Umbilicals ............................................................................. 2-17 2.3.5 Construction Methods Involving Sediment Displacement ....................................... 2-18 2.3.6 Subsea Equipment and Associated Protection Structures......................................... 2-19 2.3.7 Onshore Facilities and Pipeline (M&NP Option Only)............................................ 2-22 2.3.8 Development Well Construction............................................................................... 2-22 2.3.9 Hydrostatic Testing................................................................................................... 2-29 2.4 Operations .............................................................................................................................. 2-31 2.4.1 Production................................................................................................................. 2-31 2.4.2 Utilities...................................................................................................................... 2-40 2.4.3 Support and Servicing............................................................................................... 2-42 2.4.4 Project Safety Zones ................................................................................................. 2-43 2.4.5 Onshore Facilities ..................................................................................................... 2-44 2.5 Decommissioning and Abandonment .................................................................................... 2-44 2.6 Project Schedule..................................................................................................................... 2-45 2.7 Emissions and Discharges...................................................................................................... 2-46 2.7.1 Air Emissions............................................................................................................ 2-46 2.7.2 Noise Emissions........................................................................................................ 2-52 2.7.3 Electromagnetic Emissions....................................................................................... 2-52

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2.7.4 Drill Waste Discharges ............................................................................................. 2-53 2.7.5 Effluent Discharges................................................................................................... 2-55 2.7.6 Naturally Occurring Radioactive Material (NORM)................................................ 2-57 2.7.7 Non-Hazardous Solid Wastes ................................................................................... 2-57 2.8 Hazardous Materials and Waste............................................................................................. 2-57 2.9 Environmental and Safety Protection Systems ...................................................................... 2-57 2.9.1 Equipment Inspection and Maintenance................................................................... 2-57 2.9.2 Pipeline Leak Prevention .......................................................................................... 2-58 2.9.3 Blowout Prevention Safeguards................................................................................ 2-58 2.9.4 Flowline Protection................................................................................................... 2-59 2.9.5 Subsea Protection Structures..................................................................................... 2-60 2.9.6 Project Safety Zones ................................................................................................. 2-60 2.10 Project Alternatives............................................................................................................... 2-60 2.10.1 Alternatives to the Project......................................................................................... 2-60 2.10.2 Alternatives Means of Carrying Out the Project....................................................... 2-603 MALFUNCTIONS AND ACCIDENTAL EVENTS ................................................................... 3-1 3.1 Potential Malfunctions and Accident Events.......................................................................... 3-1 3.1.1 Platform-based Spills ................................................................................................. 3-2 3.1.2 Collisions ................................................................................................................... 3-2 3.1.3 Malfunction of Acid Gas Management System......................................................... 3-2 3.1.4 Blowout Releases....................................................................................................... 3-3 3.1.5 Pipeline and Flowline Releases ................................................................................. 3-3 3.1.6 Effects of the Environment on the Project ................................................................. 3-3 3.2 Marine Spill Risk and Probability............................................................................................ 3-4 3.2.1 Platform-based Spills ................................................................................................. 3-4 3.2.2 Blowouts .................................................................................................................... 3-4 3.2.3 Spills from Pipelines and Flowline Operations ......................................................... 3-6 3.3 Onshore Pipeline Risk.............................................................................................................. 3-6 3.3.1 Accident Scenarios..................................................................................................... 3-6 3.3.2 Hazards ...................................................................................................................... 3-7 3.3.3 Risks........................................................................................................................... 3-7 3.4 Marine Spill Release Behaviour .............................................................................................. 3-8 3.4.1 Platform-based Spills .................................................................................................. 3-8 3.4.2 Blowouts and Pipeline/Flowline Ruptures................................................................ 3-10 4 ENVIRONMENTAL MANAGEMENT........................................................................................ 4-1 4.1 Environmental Management Framework ................................................................................. 4-1 4.1.1 Corporate Responsibility Policy ................................................................................. 4-2 4.1.2 EHS Best Practice Management System .................................................................... 4-3 4.1.3 Deep Panuke EHS Management System Guidance Manual....................................... 4-4

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4.2 Stakeholder Consultation........................................................................................................ 4-4 4.3 Deep Panuke Emergency Management Plan .......................................................................... 4-5 4.4 Deep Panuke Spill Reponse Plan............................................................................................ 4-5 4.5 Deep Panuke Environmental Effects Monitoring Plan........................................................... 4-5 4.6 Environmental Protection Plan ............................................................................................... 4-6 5 PUBLIC CONSULTATION PROGRAM..................................................................................... 5-1 5.1 Consultation Program Background and Objectives................................................................. 5-1 5.2 Consultation Activities............................................................................................................. 5-2 5.2.1 Public Consultation Stages ......................................................................................... 5-2 5.2.2 Phase I - Stakeholder Identification and Preliminary Communications..................... 5-2 5.2.3 Phase II – Consultation on the Project Description, Issues Identified and Scoping ... 5-5 5.2.4 Phase III - Follow-up and Ongoing Communication.................................................. 5-7 5.2.5 Aboriginal Communications....................................................................................... 5-7 5.3 Integration of Issues and Concerns into Project Planning ....................................................... 5-86 IMPACT ASSESSMENT SCOPE AND METHODS ................................................................. 6-1 6.1 Scope of the Assessment......................................................................................................... 6-1 6.2 Selection of Valued Environmental Components................................................................... 6-1 6.3 Potential Interaction between Project Activities and Valued Environmental Components.................................................................................................. 6-14 6.4 Environmental Effects Assessment Framework ................................................................... 6-14 6.5 Scoping of Cumulative Effects Assessment ......................................................................... 6-26 7 BIOPHYSICAL AND SOCIO-ECONOMIC SETTING............................................................ 7-1 7.1 Biophysical Setting ................................................................................................................. 7-1 7.1.1 Marine Physical Environment.................................................................................... 7-1 7.1.2 Marine Biological Environment ................................................................................ 7-2 7.1.3 Onshore Environment .............................................................................................. 7-16 7.1.4 Summary of Special Status Species......................................................................... 7-22 7.2 Socio-economic Setting ......................................................................................................... 7-27 7.2.1 Land Use ................................................................................................................... 7-27 7.2.2 Economy ................................................................................................................... 7-30 7.2.3 Fisheries and Aquaculture......................................................................................... 7-32 7.2.4 Other Ocean Users .................................................................................................... 7-44 8 BIOPHYSICAL IMPACT ASSESSMENT.................................................................................. 8-1 8.1 Air Quality .............................................................................................................................. 8-1 8.1.1 Boundaries ................................................................................................................. 8-1 8.1.2 Residual Environmental Effects Evaluation Criteria................................................. 8-1 8.1.3 Project Modifications and Potential Interactions....................................................... 8-4 8.1.4 Analysis, Mitigation, and Residual Environmental Effects Prediction ..................... 8-6 8.1.5 Follow-up and Monitoring....................................................................................... 8-26

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8.1.6 Sustainable Use of Renewable Resources ............................................................... 8-27 8.1.7 Summary of Residual Environmental Effects Assessment...................................... 8-27 8.2 Marine Water Quality ........................................................................................................... 8-33 8.2.1 Boundaries ............................................................................................................... 8-33 8.2.2 Residual Environmental Effects Evaluation Criteria............................................... 8-33 8.2.3 Project Modifications and Potential Interactions..................................................... 8-33 8.2.4 Analysis, Mitigation and Residual Environmental Effects Prediction .................... 8-35 8.2.5 Follow-up and Monitoring....................................................................................... 8-41 8.2.6 Sustainable Use of Renewable Resources ............................................................... 8-42 8.2.7 Summary of Residual Environmental Effects Assessment...................................... 8-42 8.3 Marine Benthos..................................................................................................................... 8-47 8.3.1 Boundaries ............................................................................................................... 8-47 8.3.2 Residual Environmental Effects Evaluation Criteria............................................... 8-47 8.3.3 Project Modifications and Potential Interactions..................................................... 8-48 8.3.4 Analysis, Mitigation and Residual Environmental Effects Prediction .................... 8-51 8.3.5 Follow-up and Monitoring....................................................................................... 8-61 8.3.6 Sustainable Use of Renewable Resources ............................................................... 8-62 8.3.7 Summary of Residual Environmental Effects Assessment...................................... 8-62 8.4 Marine Fish ........................................................................................................................... 8-66 8.4.1 Boundaries ............................................................................................................... 8-66 8.4.2 Residual Environmental Effects Evaluation Criteria............................................... 8-66 8.4.3 Project Modifications and Potential Interactions..................................................... 8-67 8.4.4 Analysis, Mitigation and Residual Environmental Effects Prediction .................... 8-69 8.4.5 Follow-up and Monitoring....................................................................................... 8-77 8.4.6 Sustainable Use of Renewable Resources ............................................................... 8-77 8.4.7 Summary of Residual Environmental Effects Assessment...................................... 8-77 8.5 Marine Mammals and Turtles................................................................................................ 8-82 8.5.1 Boundaries ............................................................................................................... 8-82 8.5.2 Residual Environmental Effects Evaluation Criteria............................................... 8-82 8.5.3 Project Modifications and Potential Interactions..................................................... 8-82 8.5.4 Analysis, Mitigation and Residual Environmental Effects Prediction .................... 8-85 8.5.5 Follow-up and Monitoring....................................................................................... 8-87 8.5.6 Sustainable Use of Renewable Resources ............................................................... 8-87 8.5.7 Summary of Residual Environmental Effects Assessment...................................... 8-88 8.6 Marine Related Birds ............................................................................................................ 8-92 8.6.1 Boundaries ............................................................................................................... 8-92 8.6.2 Residual Environmental Effects Evaluation Criteria............................................... 8-92 8.6.3 Project Modifications and Potential Interactions..................................................... 8-93 8.6.4 Analysis, Mitigation and Residual Environmental Effects Prediction .................... 8-95

Deep Panuke Volume 4 (Environmental Assessment Report) November 2006 v

8.6.5 Follow-up and Monitoring....................................................................................... 8-98 8.6.6 Sustainable Use of Renewable Resources ............................................................... 8-98 8.6.7 Summary of Residual Environmental Effects Assessment...................................... 8-98 8.7 Sable Island.......................................................................................................................... 8-102 8.7.1 Boundaries ............................................................................................................. 8-102 8.7.2 Residual Environmental Effects Evaluation Criteria............................................. 8-102 8.7.3 Project Modifications and Potential Interactions................................................... 8-103 8.7.4 Analysis, Mitigation and Residual Environmental Effects Prediction .................. 8-104 8.7.5 Follow-up and Monitoring..................................................................................... 8-105 8.7.6 Sustainable Use of Renewable Resources ............................................................. 8-105 8.7.7 Summary of Residual Environmental Effects Assessment.................................... 8-105 8.8 Onshore Environment ......................................................................................................... 8-107 8.8.1 Boundaries ............................................................................................................. 8-107 8.8.2 Residual Environmental Effects Evaluation Criteria............................................. 8-107 8.8.3 Project Modifications and Potential Interactions................................................... 8-107 8.8.4 Analysis, Mitigation and Residual Environmental Effects Prediction .................. 8-110 8.8.5 Follow-up and Monitoring..................................................................................... 8-115 8.8.6 Sustainable Use of Renewable Resources ............................................................. 8-116 8.8.7 Summary of Residual Environmental Effects Assessment.................................... 8-116 8.9 Biophysical Cumulative Effects Assessment...................................................................... 8-121 8.9.1 Air Quality ............................................................................................................. 8-121 8.9.2 Marine Water Quality ............................................................................................ 8-123 8.9.3 Marine Benthos...................................................................................................... 8-124 8.9.4 Marine Fish ............................................................................................................ 8-126 8.9.5 Marine Mammals and Turtles................................................................................ 8-128 8.9.6 Marine Related Birds ............................................................................................. 8-129 8.9.7 Sable Island............................................................................................................ 8-130 8.9.8 Onshore Environment ............................................................................................ 8-130 8.9.9 Summary ................................................................................................................ 8-131 9 SOCIOECONOMIC EFFECTS ASSESSMENT ........................................................................ 9-1 9.1 Land Use ................................................................................................................................. 9-1 9.1.1 Boundaries ................................................................................................................. 9-1 9.1.2 Residual Environmental Effects Evaluation Criteria................................................. 9-1 9.1.3 Project Modifications and Potential Interactions....................................................... 9-2 9.1.4 Analysis, Mitigation and Residual Environmental Effects Prediction ...................... 9-4 9.1.5 Follow-up and Monitoring......................................................................................... 9-5 9.1.6 Sustainable Use of Renewable Resources ................................................................. 9-6 9.1.7 Summary of Residual Environmental Effects Assessment........................................ 9-6

Deep Panuke Volume 4 (Environmental Assessment Report) November 2006 vi

9.2 Economy ............................................................................................................................... 9-11 9.2.1 Boundaries ............................................................................................................... 9-11 9.2.2 Residual Environmental Effects Evaluation Criteria............................................... 9-11 9.2.3 Project Modifications and Potential Interactions..................................................... 9-12 9.2.4 Analysis, Mitigation and Residual Environmental Effects Prediction .................... 9-17 9.2.5 Follow-up and Monitoring....................................................................................... 9-19 9.2.6 Sustainable Use of Renewable Resources ............................................................... 9-19 9.2.7 Summary of Residual Environmental Effects Assessment...................................... 9-19 9.3 Commercial Fisheries and Aquaculture................................................................................ 9-23 9.3.1 Boundaries ................................................................................................................ 9-23 9.3.2 Residual Environmental Effects Evaluation Criteria................................................ 9-24 9.3.3 Project Modifications and Potential Interactions...................................................... 9-24 9.3.4 Analysis, Mitigation and Residual Environmental Effects Prediction ..................... 9-27 9.3.5 Follow-up and Monitoring........................................................................................ 9-31 9.3.6 Sustainable Use of Renewable Resources ................................................................ 9-31 9.3.7 Summary of Residual Environmental Effects Assessment....................................... 9-31 9.4 Other Ocean Users ................................................................................................................. 9-37 9.4.1 Boundaries ................................................................................................................ 9-37 9.4.2 Residual Environmental Effects Evaluation Criteria................................................ 9-37 9.4.3 Project Modifications and Potential Interactions...................................................... 9-38 9.4.4 Analysis, Mitigation and Residual Environmental Effects Prediction ..................... 9-40 9.4.5 Follow-up and Monitoring........................................................................................ 9-41 9.4.6 Sustainable Use of Renewable Resources ................................................................ 9-41 9.4.7 Summary of Residual Environmental Effects Assessment....................................... 9-41 9.5 Socioeconomic Cumulative Effects Assessment ................................................................... 9-45 9.5.1 Land Use ................................................................................................................... 9-45 9.5.2 Economy ................................................................................................................... 9-46 9.5.3 Commercial Fisheries and Aquaculture.................................................................... 9-47 9.5.4 Other Ocean Users .................................................................................................... 9-47 9.5.5 Summary ................................................................................................................... 9-48 10 EFFECTS OF THE ENVIRONMENT ON THE PROJECT................................................. 10-1 11 CONCLUSIONS .......................................................................................................................... 11-1 11.1 Biophysical Impact Assessment ....................................................................................... 11-1 11.2 Socio-Economic Impact Assessment................................................................................ 11-2 11.3 Effects of the Environment on the Project ........................................................................ 11-4 11.4 Environmental Design, Mitigation and Monitoring Measures ......................................... 11-4 11.5 Residual Environmental Effects ..................................................................................... 11-11

Deep Panuke Volume 4 (Environmental Assessment Report) November 2006 vii

12 REFERENCES............................................................................................................................ 12-1 12.1 Literature Cited .................................................................................................................. 12-1 12.2 Personal Communications ............................................................................................... 12-12 LIST OF ACRONYMS .............................................................................................................................1

List of Tables Page No.

Table 1.1 Comparison of Approved 2002 CSR Project Basis and the Revised Project Basis ........... 1-5 Table 2.1 Export Pipeline ................................................................................................................... 2-5 Table 2.2 Construction Methods....................................................................................................... 2-20 Table 2.3 Pile Driving Details .......................................................................................................... 2-23 Table 2.4 Hydrostatic Fluid Discharge Summary............................................................................. 2-30Table 2.5 Acid Gas Injection System – Composition and Flow....................................................... 2-34 Table 2.6 Produced Water Production Rates .................................................................................... 2-37 Table 2.7 Water Composition ........................................................................................................... 2-38 Table 2.8 Routine Project Emissions/Effluents ................................................................................ 2-47 Table 2.9 Deep Panuke Potential Drilling Waste Discharge Summary............................................ 2-55 Table 2.10 Centre Substructure Type Alternatives............................................................................. 2-64 Table 2.11 Processing Location Alternatives ..................................................................................... 2-68 Table 2.12 Acid Gas Handling Development Alternatives ................................................................ 2-71 Table 2.13 Produced Water Disposal Alternatives ............................................................................. 2-73Table 2.14 Condensate Handling........................................................................................................ 2-77 Table 2.15 Acid Gas Injection Location Alternatives ........................................................................ 2-82Table 3.1 Predicted Number of Blowouts and Spills for the Deep Panuke Project............................ 3-5 Table 3.2 Comparison of New Modelling Results with Approved 2002 CSR Modelling Results .. 3-12 Table 5.1 Stakeholders Contacted During Phase I.............................................................................. 5-4 Table 5.2 Integration of Key Issues Overview ................................................................................... 5-9 Table 6.1 Project Modifications and Environmental Assessment Considerations ............................. 6-2 Table 6.2 Changes to Regulatory Environment since the Approved 2002 CSR ................................ 6-6 Table 6.3 Changes to the Biophysical Environment since the Approved 2002 CSR......................... 6-8 Table 6.4 Changes to the Socio-Economic Environment since the Approved 2002 CSR ................. 6-8 Table 6.5 Selection of VECs............................................................................................................. 6-10 Table 6.6 Project Interactions with Biophysical VECs .................................................................... 6-15Table 6.7 Project Interactions with Socio-economic VECs.............................................................. 6-22 Table 6.8 Scoping of Potential Cumulative Interactions with Biophysical VECs ........................... 6-31 Table 6.9 Scoping of Potential Cumulative Interactions with Socio-economic VECs..................... 6-33 Table 7.1 Marine Fish Species at Risk Offshore Nova Scotia............................................................ 7-6 Table 7.2 Rare and Sensitive Vascular Plant Species Potentially Present in the Project Area......... 7-18

Deep Panuke Volume 4 (Environmental Assessment Report) November 2006 viii

Table 7.3 At Risk Bird Species Potentially Present in the Onshore Study Area (ACCDC 2006).... 7-21 Table 7.4 Nova Scotia and Federal Species Rarity Rankings........................................................... 7-24 Table 7.5 Species of Special Status that May Occur in the Study Area ........................................... 7-24 Table 7.6 Age Distribution of Individuals within Nova Scotia, the Halifax Regional Municipality,

and the Municipal Districts of Guysborough and St. Mary’s, 2001 ................................. 7-30 Table 7.7 Summary of Selected Income and Labour Characteristics, 2001..................................... 7-31 Table 7.8 Summary of Labour Force by Industry, 2001................................................................... 7-32Table 7.9 Annual Catch (1992, 2002 to 2005) (tonnes) Within NAFO Unit Areas 4We, 4Wf, and 4Wh ......................................................................................................... 7-37 Table 7.10 Statistical District Landings for Nearshore Fisheries (tonnes) ......................................... 7-42 Table 7.11 Licensed Seasons for Key Fisheries in the Project Area .................................................. 7-43 Table 8.1 Nova Scotia Air Quality Regulations (Environment Act) and Canadian Environmental Protection Act Ambient Air Quality Objectives................................................................. 8-2 Table 8.2 Project Modifications and Potential Interactions Related to Air Quality ........................... 8-4 Table 8.3 Summary of Air Emissions during Project Operations (Normal Conditions,

Malfunctions and Accidental Events)................................................................................. 8-9 Table 8.4 Atmospheric Effects from Normal Production (Minimum Continuous Flaring) ............. 8-13 Table 8.5 Atmospheric Effects from Production with Routine Maintenance (Maximum Continuous Flaring) .......................................................................................................... 8-13 Table 8.6 Nova Scotia GHG Emissions (2003 or most recent) by Sector........................................ 8-14 Table 8.7 Malfunction – Acid Gas Flaring – H2S............................................................................. 8-17 Table 8.8 Malfunction – Acid Gas Flaring – SO2............................................................................. 8-17 Table 8.9 Flare Malfunction During Normal Operations (Venting) CH4......................................... 8-18 Table 8.10 Malfunction – Maximum Flaring – Atmospheric Effects ................................................ 8-19 Table 8.11 Malfunction – Emergency Depressurizing (Blowout) - Atmospheric Effects ................ 8-19 Table 8.12 Acid Gas Injection Well - Subsea Blowout – H2S........................................................... 8-20 Table 8.13 Production Well - Subsea Blowout –– CH4...................................................................... 8-21 Table 8.14 Production Well - Subsea Blowout – H2S ........................................................................ 8-21 Table 8.15 Residual Environmental Effects Assessment Matrix: Air Quality ................................... 8-29 Table 8.16 Residual Environmental Effects Summary: Air Quality .................................................. 8-32 Table 8.17 Project Modifications and Potential Interactions Related to Marine Water Quality ........ 8-34 Table 8.18 Summary of Discharged Water Far-Field Dispersion Modelling Results........................ 8-38 Table 8.19 Residual Environmental Effects Assessment Matrix: Marine Water Quality .................. 8-43 Table 8.20 Residual Environmental Effects Summary: Marine Water Quality ................................. 8-46 Table 8.21 Project Modifications and Potential Interactions Related to Marine Benthos.................. 8-48 Table 8.22 Comparison of Wells and Drill Waste Volumes Between the Revised Project and the .......... Project Basis in the Approved 2002 CSR........................................................................ 8-52 Table 8.23 Summary of Mud/Cutting Discharges .............................................................................. 8-52Table 8.24 Residual Environmental Effects Assessment Matrix: Marine Benthos............................ 8-63

Deep Panuke Volume 4 (Environmental Assessment Report) November 2006 ix

Table 8.25 Residual Environmental Effects Summary: Marine Benthos ........................................... 8-65 Table 8.26 Project Modifications and Potential Interactions Related to Marine Fish ........................ 8-67 Table 8.27 Residual Environmental Effects Assessment Matrix: Marine Fish .................................. 8-78 Table 8.28 Residual Environmental Effects Summary: Marine Fish ................................................. 8-81 Table 8.29 Project Modifications and Potential Interactions Related to Marine Mammals and Turtles ....................................................................................................... 8-83 Table 8.30 Residual Environmental Effects Assessment Matrix: Marine Mammals and Turtles...... 8-89 Table 8.31 Residual Environmental Effects Summary: Marine Mammals and Turtles ..................... 8-91 Table 8.32 Project Modifications and Potential Interactions Related to Marine Related Birds ......... 8-93 Table 8.33 Residual Environmental Effects Assessment Matrix: Marine Related Birds ................... 8-99 Table 8.34 Residual Environmental Effects Summary: Marine Related Birds ................................ 8-101 Table 8.35 Project Modifications and Potential Interactions Related to Sable Island...................... 8-103 Table 8.36 Residual Environmental Effects Summary: Sable Island ............................................... 8-106 Table 8.37 Project Modifications and Potential Interactions Related to Onshore Environment ...... 8-108 Table 8.38 Residual Environmental Effects Assessment Matrix: Onshore Environment ................ 8-117 Table 8.39 Residual Environmental Effect Summary: Onshore Environment................................. 8-120 Table 9.1 Project Modifications and Potential Interactions Related to Land Use .............................. 9-2 Table 9.2 Residual Environmental Effects Assessment Matrix: Land Use ........................................ 9-7 Table 9.3 Residual Environmental Effects Summary: Land Use ..................................................... 9-10 Table 9.4 Project Modifications and Potential Interactions Related to Economy ............................ 9-12 Table 9.5 Estimated Economic Impact from OSEA Commitments ................................................. 9-16 Table 9.6 Residual Environmental Effects Assessment Matrix: Economy ...................................... 9-20 Table 9.7 Residual Environmental Effects Summary: Economy ..................................................... 9-22 Table 9.8 Project Modifications and Potential Interactions Related to Commercial Fisheries and Aquaculture ................................................................................................................ 9-24 Table 9.9 Residual Environmental Effects Assessment Matrix: Commercial Fisheries and Aquaculture....................................................................................................................... 9-33 Table 9.10 Residual Environmental Effects Summary: Commercial Fisheries and Aquaculture..... 9-36 Table 9.11 Project Modifications and Potential Interactions Related to Other Ocean Users ............. 9-38 Table 9.12 Residual Environmental Effects Assessment Matrix: Other Ocean Users ....................... 9-42 Table 9.13 Residual Environmental Effects Summary: Other Ocean Users ...................................... 9-44 Table 11.1 Modified Commitments from Approved 2002 CSR......................................................... 11-6 Table 11.2 Summary of New Commitments for the Deep Panuke Project ...................................... 11-10 Table 11.3 Summary of Residual Environmental Effects ................................................................ 11-11

Deep Panuke Volume 4 (Environmental Assessment Report) November 2006 x

List of Figures Page No.

Figure 1.1 Deep Panuke Location Map ............................................................................................... 1-3 Figure 2.1 Generalized Stratigraphy, Offshore Nova Scotia ............................................................... 2-2Figure 2.2 Proposed Field Rendering .................................................................................................. 2-4 Figure 2.3 Proposed Offshore Pipeline Route ..................................................................................... 2-7 Figure 2.4 Proposed Offshore Pipeline Route Detail # 1..................................................................... 2-8Figure 2.5 Proposed Offshore Pipeline Route Detail # 2..................................................................... 2-9Figure 2.6 Revised Onshore Pipeline Corridor.................................................................................. 2-11 Figure 2.7 Typical Onshore Facility .................................................................................................. 2-13 Figure 2.8 Typical Production Well Schematic................................................................................. 2-26 Figure 2.9 Typical Acid Gas Injection Well Schematic .................................................................... 2-27Figure 2.10 Simplified Process Flow Diagram................................................................................... 2-32 Figure 4.1 Deep Panuke Environmental Management Framework.................................................... 4-2 Figure 6.1 Other Projects and Activities Relative to Deep Panuke Project Area ............................. 6-28 Figure 7.1 Existing Data Sources Consulted for the Characterization of Benthic Habitat................. 7-3 Figure 7.2 2003 DFO Ocean Quahog Distribution and Sea Cucumber Experimental Fishery Zone 1 ................................................................................................................... 7-4 Figure 7.3 Foraging Locations and Critical Habitat for the Roseate Tern........................................ 7-13 Figure 7.4 Land Use of the Goldboro Industrial Park ...................................................................... 7-28Figure 7.5 2002 Combined Fisheries Catch and Effort ..................................................................... 7-33Figure 7.6 2003 Combined Fisheries Catch and Effort ..................................................................... 7-34Figure 7.7 2004 Combined Fisheries Catch and Effort ..................................................................... 7-35Figure 7.8 2005 Combined Fisheries Catch and Effort ..................................................................... 7-36Figure 7.9 Nearshore Fisheries .......................................................................................................... 7-41 Figure 7.10 Country Harbour Aquaculture Lease Blocks ................................................................... 7-45

Deep Panuke Volume 4 (Environmental Assessment Report) November 2006 xi

List of Appendices

APPENDIX A Approved CSR APPENDIX B Scope of the Assessment APPENDIX C Concordance Table Between Approved 2002 CSR and Environmental Assessment Report APPENDIX D Produced Water and Drill Waste Dispersion Modelling APPENDIX E1 Marine Spill Probability Assessment APPENDIX E2 Spill Fate and Behaviour Modelling APPENDIX F Air Emissions Modelling APPENDIX G Information on EnCana’s Proposed Environmental Management Plans and Codes of Practice APPENDIX H Public Consultation Materials APPENDIX I Aboriginal Communications APPENDIX J Commercial Fisheries Mapping

Deep Panuke Volume 4 (Environmental Assessment Report) November 2006 1-1

1 INTRODUCTION

In December 2002, EnCana Corporation (EnCana) received Ministerial approval for the Deep Panuke Comprehensive Study Report (CSR; approved 2002 CSR). Approval was based on a project comprising three offshore platforms producing 11.3 x 106m3/d [400 MMscfd] of sales gas through a dedicated 610 mm [24 inch], 176 km export pipeline with tie-in to Maritimes & Northeast Pipeline (M&NP) facilities. In February 2003, just prior to the public hearing for application to the Canada-Nova Scotia Offshore Petroleum Board (CNSOPB) and National Energy Board (NEB), a project “time-out” was requested by EnCana to allow further review and refinement of the Project. Between 2003 and 2006, EnCana completed the re-evaluation phase and is now re-filing a Development Plan Application (DPA) and NEB application based on a new project basis (the Project).

As part of pre-filing consultation with regulators, EnCana identified elements of the previously approved 2002 CSR that are still valid for the revised Project. The Canadian Environmental Assessment Act (CEAA) permits the use of previously conducted assessments. Section 24 of CEAA requires that previous environmental assessments (EAs) be used to whatever extent is appropriate in conducting the EA of the revised Project.

Section 24 of CEAA reads as follows:

24. (1) Where a proponent proposes to carry out, in whole or in part, a project for which an environmental assessment was previously conducted and (a) the project did not proceed after the assessment was completed, (b) in the case of a project that is in relation to a physical work, the proponent proposes

an undertaking in relation to that work different from that proposed when the assessment was conducted,

(c) the manner in which the project is to be carried out has subsequently changed, or (d) the renewal of a licence, permit, approval or other action under a prescribed

provision is sought, the responsible authority shall use that assessment and the report thereon to whatever extent is appropriate for the purpose of complying with section 18 or 21.

(2) Where a responsible authority uses an environmental assessment and the report thereon pursuant to subsection (1), the responsible authority shall ensure that any adjustments are made to the report that are necessary to take into account any significant changes in the environment and in the circumstances of the project and any significant new information relating to the environmental effects of the project.


Pursuant to Section 17 of CEAA, the Responsible Authorities (RAs) have delegated the conduct of the environmental assessment to the proponent. This environmental assessment report (EA Report) will also be submitted to the CNSOPB to form the Environmental Impact Statement (EIS) component of the Development Plan Application (DPA) and to the NEB to form the EA component of the pipeline application. The EA Report (DPA Volume 4) will be distributed for public comment under the CSR process and will form the basis for the CSR to be prepared by the Responsible Authorities (RAs) following the public comment period.

1.1 Project Overview

In 1996, EnCana purchased a 50 percent interest in and became the operator of the Cohasset Project near Sable Island. While producing oil from the Cohasset Project, EnCana was also conducting exploration drilling in the area. In February of 2000, EnCana announced the discovery of a potentially significant natural gas reservoir in the Deep Panuke location. Further delineation drilling results led EnCana to file a DPA with the CNSOPB and a pipeline application with the NEB in March 2002, and conduct an EA in the form of a Comprehensive Study under CEAA. A CSR was submitted by EnCana and later approved by the Minister of Environment in December 2002. The regulatory applications were withdrawn by EnCana in December 2003, prior to completion of the regulatory review, to allow further evaluation of the reservoir. Between 2003 and 2006, EnCana completed the re-evaluation phase and is re-filing the DPA and NEB application amended as necessary to include the changes from the original applications. The EA Report, conducted based on modifications between the Project basis of the approved 2002 CSR and the revised Project basis, is being filed under CEAA and as a component of the DPA and NEB application.

EnCana holds a majority working interest in and is the Operator of Deep Panuke, which is located approximately 250 km southeast of Halifax, Nova Scotia (NS) and about 48 km west of Sable Island on the Scotian Shelf. The revised Project design consists of a jack-up mobile offshore production unit (MOPU) in a water depth of approximately 44 m (Figure 1.1). The revised Project will initially include re-completing four previously drilled wells and drilling a new production well and a new acid gas injection well. Up to three additional subsea production wells could be drilled. All subsea wells will be tied back individually to the MOPU with subsea flowlines and control umbilicals.

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Deep Panuke Volume 4 (Environmental Assessment Report)• November 2006 1-4

The export system will consist of a single subsea pipeline delivering Deep Panuke sales product to one of two delivery points (collectively referred to as the “Proposed Project Options”):

• Goldboro, Nova Scotia, to an interconnection with M&NP (herein referred to as the “M&NP Option”); or

• Sable Offshore Energy Project (SOEP) 660 mm [26 inch] export pipeline at a close tie-in location on the pipeline route to Goldboro (herein referred to as the “SOEP Subsea Option”).

The gas processing system will include inlet compression, separation, sweetening, dehydration, export compression and measurement. Deep Panuke is considered a sour gas reservoir with raw gas containing approximately 0.18% hydrogen sulphide (H2S); therefore, gas sweetening equipment is required. Acid gas processing will be performed offshore through application of an amine unit to remove H2S and carbon dioxide (CO2), collectively also known as acid gas. Subsequent to its removal from the raw gas stream, the acid gas will be disposed by injection into a suitable reservoir.

For the M&NP Option, hydrocarbon dewpointing is required on the MOPU. The condensate stream will be treated and used for fuel. Currently, it is estimated that there will be no surplus condensate produced beyond fuel usage; however, in the event that condensate must be injected, it will be disposed with the acid gas stream in the injection well. For the SOEP Subsea Option, treated condensate will be re-combined with the gas in the multi-phase export pipeline.

The production facility will have a design capacity of 8.5 x 106 m3/d [300 MMscfd] with turndown capability to 1.1 x 106 m3/d [40 MMscfd].

The major modifications between the revised Project and the Project basis from the approved 2002 CSRinclude:

• production design capacity of 8.5 x 106 m3/d [300 MMscfd] versus 11.3 x 106 m3/d [400 MMscfd];

• subsea wellheads with subsea tie-backs versus platform wells;• single integrated installation (MOPU) versus three fixed platforms;• revised field centre location;• additional export (multi-phase) pipeline option (SOEP Subsea Option); and• greater produced water discharge rate.

Table 1.1 provides a more detailed comparison between the Project basis for the approved 2002 CSR and the revised Project basis.


Table 1.1 Comparison of Approved 2002 CSR Project Basis and the Revised Project Basis


Well Count and Configuration

Maximum of 8 – platform wells 5-6 new drilled production wells: H08, PI1B, M79A, PP3C and 1-2 future wells 1-2 new drilled injection wells

Maximum of 9 – subsea wells 4 re-entry wells: H-08 (PL 2902), M-79A (PL 2902), F-70 (EL 2387), and D-41 (SDL 2255H) 1 new production well: H-99 (PL 2902) 1 new injection well D-70 (EL 2387) Up to three future wells (currently undefined locations on PL 2901, SDL 2255H, PL 2902 or EL 2387) Buried flowlines and umbilicals from wellheads to installation

Project Life Expected mean case: 11.5 years Expected mean case: 13.3 years Expected range: 8-17.5 years

Field Centre Base Case Relocated 3.6 km NNE

Base Structure Three fixed platforms including: Production platform Utilities/quarters platform Wellhead platform

1 MOPU Integrated facility

Discharge of Muds / Cuttings for New Wells

Drilled from field centre WBM/cuttings overboard SBM/cuttings skipped and shipped or injected

Drilled from individual well locations WBM/cuttings overboard No SBM

Delivery Point M&NP tie-in Onshore, adjacent to SOEP gas plant

SOEP subsea tie-in SOEP 660 mm [26 inch] pipeline

Export Pipeline 610 mm [24 inch], 176 km Single phase Trenched ~ 50% of route

560 mm [22 inch], 176 km Single phase Trenched ~ 50% of route

510 mm [20 inch], 15 km Multi-phase Trenched 100% of route

Export Gas 11.3 x 106 m3/day [400 MMscfd] Sales quality

8.5 x 106 m3/day [300 MMscfd] Sales quality

8.5 x 106 m3/day [300 MMscfd] Sweet and dehydrated

Export Condensate N/A Maximum of 220 m3/day Sweet and stabilized, commingled with gas

Condensate Use Fuel, surplus injected Sales product

Produced Water Maximum 1,100 to 1,600 m3/day [7,000 to 10,000 bpd] Discharged overboard

Maximum 6,400 m3/day [40,000 bpd] Discharged overboard

Acid Gas Dedicated injection well ~180 x 103m3/day [6 MMscfd]

Dedicated injection well ~130 x 103m3/day [4.5 MMscfd]


1.2 Purpose and Need for the Project

The purpose and need for the Project do not differ from that previously stated in the approved 2002 CSR. The primary purpose is to allow EnCana to exercise its rights under, and obtain economic benefits from, the licenses issued to it under the Canada-Nova Scotia Offshore Petroleum Resources Accord Actand the Canada-Nova Scotia Offshore Petroleum Resources Accord Implementation (Nova Scotia) Act(Accord Acts). By recovering the value of the resources that EnCana has obtained the rights under the Accord Acts, it can provide a return to its shareholders on the capital invested in the Project. The value of the Deep Panuke resources will be obtained by exploiting the opportunity presented by the considerable and growing demand for natural gas and other forms of energy in markets in Canada and the United States. The proximity of the Deep Panuke discovery to existing infrastructure serving these growing energy markets is one of the foundations of the Project. The Project will, therefore, provide further opportunity for Nova Scotians, and other Canadians, to participate in, and benefit from, the offshore oil and gas industry, thereby contributing to the economies of Nova Scotia and Canada.

1.3 Regulatory and Planning Context

The CNSOPB regulates offshore oil and gas activities under the Accord Acts and requires proponents to file a DPA for development projects.

Proposed production installations and development drilling for offshore oil and gas are subject to environmental assessment under CEAA. Amendments to the Federal Authorities Regulations in January 2001 designated the CNSOPB as a Federal Authority under CEAA. The CNSOPB will therefore be an RA for the environmental assessment. As required under the amended (2003) CSR process, the CEA Agency is the Federal Environmental Assessment Co-ordinator (FEAC) and, together with the CNSOPB, will lead the EA process for the Project.

Application of the Federal Coordination Regulations process under CEAA requires federal departments with decision making responsibility (under CEAA) or expert knowledge to declare their interest in the project. The potential RAs for this Project and potential respective CEAA “triggers” include:

• CNSOPB (approval of a development plan, under Section 143(4)(a) and authorization under Section 142 (1)(b) of the Accord Act, referred to as item 1.2 in Schedule I, Part I of the Law List Regulations);

• Fisheries and Oceans Canada (authorizations under Sections 32, 35 and 37 of the Fisheries Act, referred to as item 6 in Schedule I, Part I of the Law List Regulations);

• Environment Canada (Disposal at Sea permit under paragraph 127(1) of the Canadian Environmental Protection Act (CEPA), referred to as item 3 in Schedule I, Part I of the Law List Regulations);


Transport Canada (paragraph 5(1) of the Navigable Waters Protection Act, referred to as item 11 in Schedule I, Part I of the Law List Regulations); Industry Canada (paragraph 5(1)(f) of the Radiocommunication Act, referred to as item 13 in Schedule I, Part I of the Law List Regulations); and NEB (Certificate under Section 52 or Section 58 Order of the National Energy Board Act related to the pipelines, referred to as item 7 in Schedule II of the Law List Regulations).

Based on current discussions with regulators, EnCana does not expect that a DFO authorization related to harmful alteration or destruction of fish habitat under Sections 32, 35(2) or 37 of the Fisheries Act, or a Disposal at Sea permit from Environment Canada under Part 7, Division 3 (Sections 122 - 137) of the CEPA will be required, based on the configuration of the Project and planned mitigation. Specifically:

There will be no disposal of muds/cuttings from more than a single well at any specific location on Sable Island Bank; Betty's Cove Brook, the only permanent stream in the onshore pipeline corridor, will be crossed in the “dry” during pipeline installation;the MOPU will use standard spud cans or equivalent, similar to typical drilling jack-up rig footings; and all subsea equipment (i.e, wellheads, hot-tap and tie-in structures, sub-surface isolation valves) shall be protected by trawlable, cage-like, open tubular structures which allow for fish passage. In addition, there will be no blasting in the aquatic or marine environments. If required in the nearshore landfall area, any blasting will be carried out in the “dry” during periods of low tide; and The proposed Deep Panuke installation activities do not constitute “disposal” as that term is defined in CEPA.

Consultation with the regulatory agencies in respect of these requirements will continue as the information in respect of the Project is refined.

The CNSOPB requires an EIS as a condition of its approval process. The NEB requires an EA as a condition of its approval process. Based on pre-filing consultation with the regulators, EnCana’s CEAAEA Report will also form the EIS requirement of the DPA and the EA requirement for the NEB application.

In 2002, EnCana conducted an EA in the form of a comprehensive study under CEAA. EnCana submitted a CSR and received Ministerial approval in December 2002. In February 2003, EnCana requested a regulatory time-out to allow further evaluation of the Deep Panuke Project. In December 2003, EnCana withdrew regulatory applications with the CNSOPB and the NEB to allow further review and refinement of the Project.


Between 2003 and 2006, EnCana re-evaluated the reservoir and facilities to determine the optimum Project basis. As part of pre-filing consultation with the regulators, the FEAC and expected RAs have put together a draft work plan for the Deep Panuke Project in order to guide the regulatory review process. The draft work plan indicated that the assessment would be a new comprehensive study, but that it would solely address the variations between the Project basis of the approved 2002 CSR and the revised Project basis.

EnCana filed a Project Description on August 28, 2006 to initiate provisions of the FederalCoordination Regulations pursuant to CEAA. A draft scoping document was released for public review in September 2006. A final scoping document was released in November 2006.

1.4 Scope of the Assessment

In accordance with the work plan and Scope of Environmental Assessment (CEA Agency 2006), this EA Report has been prepared to assess the variations arising from the revised Project basis and the Project basis for the approved 2002 CSR. The EA must also consider relevant changes to the regulatory, biophysical and socio-economic environment that have occurred since the approved 2002 CSR. Section 6.1 contains additional information on the scoping process and identification of regulatory, biophysical and socio-economic updates to be incorporated in the EA Report.

More specifically, the Scope of Environmental Assessment (CEA Agency 2006) outlines the RA-specified requirements for the assessment of the Deep Panuke Project under the CEAA process. Refer to Appendix B for the Scope of Environmental Assessment and demonstration of the EA Report’s concordance with the Scope.

1.5 Project Study Area

Upon review of the revised Project options, it was determined that the Project Study Area defined in the approved 2002 CSR remains valid for this EA Report. Figure 1.1 shows the delineated study area around the revised Project Options. Refer to Section 1.5 of the approved 2002 CSR for a description of the study area and rationale for delineation.


2 PROJECT DESCRIPTION

This section provides an overview of the technical and operational considerations related to the Deep Panuke Project. A detailed description of the Project’s technical aspects is contained in the Development Plan (DPA Volume 2) is being submitted to the CNSOPB.

2.1 Reservoir Description

The Deep Panuke Project will produce natural gas from a porous carbonate reservoir located 3,500-4,000 m below the seafloor. The reservoir occurs in the margin of the carbonate platform (Abenaki formation) (refer to Figure 2.1) which formed along the East Coast of North America during the opening of the Atlantic Ocean in the Middle to Late Jurassic, approximately 170 to 128 million years ago. The Deep Panuke gas pool was discovered by EnCana drilling in 1998. Additional drilling in the Abenaki formation in 1999 and 2000 confirmed the presence of a significant gas accumulation. A detailed geological and geophysical description of the reservoir is contained in the Development Plan (DPA Volume 2).

Deep Panuke raw gas is very lean (i.e., with low volumes of associated gas liquids) and contains low levels of CO2 (approximately 3.5%). The raw gas contains a small amount of H2S and is therefore referred to as “sour gas”. H2S concentration in the raw gas is expected to be approximately 0.18% or 1,800 parts per million by weight (ppmw).

The components of the Deep Panuke raw gas are as follows:

Aromatics: Deep Panuke raw gas contains low levels of benzene, toluene, ethyl benzene, and xylene commonly known as BTEX. BTEX concentration in the raw gas is expected to be 0.17 mole% or 1,400 ppm. Trace Elements: Deep Panuke raw gas contains very low levels of mercury (Hg), measured at an average concentration of 0.5 g/m3 (microgram/m3).Metals: A metal analysis by method ASTM D5185 was conducted on a number of samples of produced condensate and heavy metals, such as barium, vanadium; and lead concentrations were less than the detection limit.

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Potential Radioactive Components: The presence of radon, a Naturally Occurring Radioactive Material (NORM), was measured during well testing by an RDA 200 Radon Detector. Deep Panuke raw gas contains very low levels of radon (Rn), in the range of 50-100 Bq/m3, equivalent to 1.4-2.7 pCi/Litre (Conversion factor: 1Bq = 27.027 pCi).

The following sections describe the process by which EnCana proposes to develop this reservoir and produce market-ready gas.

2.2 Project Infrastructure Components

The main Project infrastructure components include a mobile offshore production unit (MOPU), subsea wells and flowlines, and a subsea pipeline to transport sales product to either Goldboro, NS (M&NP Option) or SOEP 660 mm [26 inch] pipeline tie-in (SOEP Subsea Option).

A rendering of the proposed layout is presented in Figure 2.2.

2.2.1 Mobile Offshore Production Unit (MOPU)

The MOPU comprises the hull and topsides facilities. The hull includes all facilities and equipment that would normally be supplied with a mobile jack-up unit including jacking systems, legs, foundations, accommodations, helideck and utilities. The topsides facility will include all equipment required for processing hydrocarbon fluids from the reservoir. The topsides equipment will generally be located on top of the main deck but may also include equipment located within the hull, such as the central control room.

The topsides facility will contain processing equipment to separate, measure, dehydrate, and sweeten the raw gas. Acid gas and water handling equipment will also be installed on the MOPU. Hydrocarbon dew pointing will be required for the M&NP Option and the condensate will be used as the primary fuel for power generation and compression. Currently, it is estimated that there will be no surplus condensate produced beyond fuel usage; however, in the event that condensate must be injected, it will be injected down-hole with the acid gas stream. For the SOEP Subsea Option, condensate separated from the gas will be dehydrated, sweetened, and recombined with the export gas for delivery to the tie-in for the SOEP Subsea Option. The production facility is designed to export 8.5 x 106 m3/d [300 MMscfd].

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2.2.2 Subsea Wells and Flowlines

The initial development well program will consist of re-completing four existing production wells (H-08, M-79A, F-70, and D-41), drilling one new injection well (D-70) in Margaree (EL 2387), and one new production well (H-99) in Panuke (PL 2902). Up to three new production wells could be drilled after first gas in Cohasset (PL 2901), Deep Cohasset (SDL 2255H), Panuke (PL 2902) or Margaree (EL 2387).

All wells will be completed with horizontal subsea trees and tied back to the MOPU with individual subsea flowlines and control umbilicals. All subsea flowlines and control umbilicals will be trenched and buried.

2.2.3 Export Pipeline

EnCana proposes to transport sales product via a subsea pipeline from the offshore processing facility to one of two delivery points:

Goldboro, Nova Scotia (M&NP Option) to an interconnection with M&NP; or SOEP 660 mm [26 inch] pipeline tie-in (SOEP Subsea Option) at a close point on the pipeline route.

The Deep Panuke export pipeline will have a capacity of 8.5 x 106 m3/d [300 MMscfd] at mean environmental conditions. The proposed routes of the export pipeline will minimize its footprint by using existing pipeline and flowline corridors where practical. The pipeline details for both options are presented in Table 2.1. All values are approximate.

Table 2.1 Export Pipeline Pipeline Diameter

(mm [inch]) Pipeline Length (km) Pipeline Phases

M&NP Option 560 [22] 176 (including approximately 3 km

onshore)

Single phase

SOEP Subsea Option 510 [20] 15 Multi-phase

For the SOEP Subsea Option, the export pipeline tie-in point will be at a subsea location. The tie-in facility will likely consist of a hot tap tie-in assembly and a valve tie-in assembly. Each assembly will be secured to the seabed using piles and surrounded by a subsea protection structure. Final processing of the Deep Panuke fluids will be done by SOEP at the onshore plants near Goldboro, NS and Point Tupper, NS.


The pipeline will be trenched where the water depth is shallow, as dictated by design requirements. This will also reduce span correction and reduce the potential for sediment scour to the pipeline. The pipeline will be designed to withstand impacts from conventional mobile fishing gear in accordance with the Det Norske Veritas (DNV) Guideline No. 13, Interference Between Trawl Gear and Pipelines, September, 1997.

The proposed offshore pipeline routes for both the M&NP Option and the SOEP Subsea Option are presented on Figure 2.3. The following criteria were used to determine the proposed pipeline route:

Minimize the environmental effects, seabed disturbance, and effects to fisheries due to the installation and operation of the new pipeline. Minimize the pipeline route length where possible while still satisfying all other route criteria. Minimize the number of subsea pipeline and cable crossings. Where crossings are unavoidable, routing of the pipeline shall, where possible, have a crossing angle of greater than 30 .Consider any known future pipelines. Consider concerns raised by landowners and stakeholders. The pipeline route shall be such that “normal” pipelay operations (pipelay vessel) are not precluded and appropriate minimum horizontal radius of curvature (to be defined during detailed design, dependent on the pipeline size and water depth) could be kept. Consider approaches near the MOPU (which may be installed in advance of the pipeline installation) to ensure compliance with safety and layout requirements. The shore approach routing shall be such to enable shore pull-in systems to be as simple as possible. Due consideration shall be made of the existing SOEP pipeline in the close confines of the harbour. Within the limits of the lay corridor and SOEP pipeline proximity requirements, route selection shall minimize potential pre-lay works (pre-sweeping, etc.) and post-lay rectification requirements for freespans.


2.2.3.1 M&NP Option

The proposed pipeline route for the M&NP Option extends 173 km and closely follows the existing SOEP gas pipeline. With the exception of a slight route change offshore due to the revised location of the field centre, the offshore pipeline routing for this option remains unchanged from the route outlined in the approved 2002 CSR.

2.2.3.2 SOEP Subsea Option

The export pipeline to the SOEP Subsea Option tie-in point will be approximately 15 km in length. The water depth ranges from approximately 20 m to 45 m in depth and the seabed is relatively featureless. It is anticipated that the pipeline for SOEP Subsea Option will be buried. The pipeline will traverse a region of Sable Island Bank noted for its heterogeneous surficial geological characteristics. The dominant substrates along the proposed route are well-sorted Sable Island sand and, to a lesser extent, gravel. Sand ripples and mega-ripples are common due to the influence of waves and currents. The surficial sediments of the pipeline route are under the influence of dynamic sediment transport regimes, with large volumes of sand moved during storm events. In contrast to the M&NP option, the SOEP Subsea Option pipeline will not traverse areas of rock outcroppings, basins or other notable geological features.

2.2.4 Onshore Pipeline and Facilities

Onshore facilities are required for the M&NP Option only. In this option, EnCana’s onshore facility will consist of the physical components necessary for interconnection of EnCana’s natural gas pipeline with M&NP’s facility. EnCana will install a pig launcher/receiver facility and a safety/emergency shutdown valve system. The onshore facility will interface with the M&NP owned facility, which will include custody transfer meters, the final section of pipeline, and the tie-in to the existing M&NP pipeline. This facility is estimated to be 60 m x 45 m in area and will be enclosed by a security fence. The onshore pipeline will be located within the pipeline corridor indicated on Figure 2.6.


The onshore portion of the pipeline will be approximately 2 to 4 km in length. Design criteria for the onshore pipeline include the following:

consideration of physical features such as rock outcrops; minimizing environmental effects through avoidance of Deer Wintering Areas; minimizing pipeline length; minimizing impact on wetlands through avoidance where feasible; minimizing impact on stream crossing by use of dry crossing techniques; consideration of pipelay restriction, such as minimum horizontal radius of curvature;minimizing effects on landowners’ properties through which the pipeline will run; and ensuring best use of industrial park land consistent with the Municipality’s conceptual plan for the park.

The environmental constraints on the pipeline route and expected mitigation measures to manage these constraints will be included in the Request for Quote for the onshore pipeline installation package. Additionally, onshore environmental constraints will be considered in the Project’s Environmental Protection Plan (EPP).

An access road may be required which will likely run parallel to the new pipeline. The final location of the onshore facilities will depend on the final pipeline routing and access, as well as biophysical, socio-economic and engineering constraints. When additional survey work is completed, EnCana will consult with the land owners in the Goldboro Industrial Park to determine the location of the onshore facilities, as well as the onshore pipeline route.

Although layout of the onshore facilities is not complete at this time, Figure 2.7 is a schematic of the typical onshore facility that would be required for the Deep Panuke Project.

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2.3 Construction and Installation

2.3.1 MOPU Facilities

The MOPU will be fabricated onshore, towed to the field, and jacked up on location. The MOPU will be situated on specifically designed footings, such as spud cans or equivalent, similar to typical drilling jack-up rig footings. The topsides facilities will be fabricated separately and installed on the MOPU at an atshore location. The Project has no requirement for an offshore heavy lift.

The hull portion of the MOPU is expected to utilize the basic design premise of an existing mobile offshore drilling unit (MODU) jackup design with the minimum number of changes required to accept the topsides production facilities. Some modifications are expected for additional safety and control systems, which must be integrated platform wide and other specific modifications, including appurtenances, risers, and umbilicals, which interface with the sea and seabed below. However, the intent will also be to minimize the deviations to the standard MODU design so that re-conversion of the unit back to a drilling unit in future can be readily accommodated if desired. The MOPU hull will be based upon a typical jack-up drilling rig fabrication method; however, the associated drilling equipment will not be installed.

The hull designs must be structurally capable of withstanding the environmental design conditions for offshore Nova Scotia on a year round basis; these MODUs are generally referred to a “harsh environment jack-up rigs”.

The production topsides will house all the production equipment and will be located on the hull in the areas where the drilling package is normally located. The topsides will be constructed in modular format. The expected weight of the production facilities is 6,000 tonnes and a single module is preferred from a construction and commissioning viewpoint. However, multiple modules can also be utilized should this be a better fit for the selected hull. Final arrangement will be determined during detailed design.

The modules will be designed to be lifted or skidded onto the hull structure and will be supported by the main girders within the hull.

The accommodations unit(s) will be designed to be constructed within Nova Scotia and therefore may have a design and build plan which will allow for transportation to the integration site and integration of the unit with the remainder of the MOPU, if required. Special considerations will include design of interface systems for power and utilities as well as load out and lifting considerations. The accommodations unit will be designed for a minimum of 68 persons on board (POB) and steady state POB of approximately 30 persons; however, it could also be larger if the MOPU contractor chooses to


use a standard MODU accommodations design to allow for easier conversion back to MODU operations in the future. Final accommodations size and layout will be determined during detailed design and will not impact the predictions of the EA Report.

The flare structure will also be designed to be constructed in Nova Scotia and therefore must also accommodate the loadout, transport, and installation considerations similar to the accommodations unit(s). The flare structure is expected to be a tubular lattice type structure and may be vertical or a boom type configuration. It will be in the order of 70 m above the topsides production facilities top most deck and will house the high pressure and low pressure flare lines and flare tips.

The topsides module(s) and the MOPU hull will likely be fabricated at separate locations and then brought to a common yard where they will be integrated. The topside(s) will be installed onto the MOPU hull and the remaining construction work will be completed. It is crucial to the effectiveness of the offshore phase that all the construction work is complete and commissioned as far as possible prior to the MOPU sailing away for installation.

Installation activities include the transportation and installation of the completed MOPU.

During the early stages of the detailed design phase of the Project, it will be important to ensure that the MOPU is designed to be transportable by the most economical means. Accordingly, until the MOPU fabrication yard is known, it will be essential to maintain design flexibility.

The actual installation of the MOPU at the offshore location is the same as the installation of a typical jack-up drilling rig. That is, the MOPU jacking system will be activated to raise the hull above the sea level to its final design elevation.

Installation will be in accordance with installation manuals which will provide full details of the sequence and content of each operation. The Project’s EPP will be integrated with the development of the installation manuals. The following summarizes the installation activity for the MOPU:

tow the MOPU to the offshore site; jack the MOPU legs down to the seafloor; jack the hull out of the water to the pre-loading elevation; perform pre-loading operations to jack the hull to the final design elevation; and installation of scour protection material (if required).


2.3.2 Export Pipeline

A proposed pipeline corridor has been selected as described in Sections 2.2.3 and 2.2.4 and shown on Figures 2.3 to 2.6.

For the M&NP Option, the route will head towards the existing SOEP pipeline and then follow the previously approved route paralleling the existing SOEP pipeline to shore. The two lines will be approximately 1 km apart, except where on bottom topography necessitates close proximity. In the near shore area, approximately 7 km from land, the two lines will be approximately 100 m apart.

For the SOEP Subsea Option, the route will head towards a close tie-in location.

Preliminary route studies for the SOEP Subsea Option as well as the M&NP Option pipeline route affected by the field centre change have been completed. Detailed route studies will be conducted during detailed design to confirm and refine preliminary routing and construction methods. Pipelines will be hydrostatically tested during commissioning.

Nearshore and offshore pipeline installation activities as presented in the approved 2002 CSR have not changed; therefore, these activities are not addressed in this section as there is no need to re-assess. However, further to the pipelay information provided in the approved 2002 CSR, refer to Section 2.3.5 which provides additional detail on methods involving sediment disposal.

2.3.3 Subsea Tie-In Facilities

For the SOEP Subsea Option, sales product is transferred from the Deep Panuke MOPU via a 15 km, 510 mm [20 inch] export pipeline to the existing SOEP 660 mm [26 inch] pipeline. The connection to the SOEP pipeline will be by a subsea tie-in, referred to as a “hot tap”. The hot tap process involves the connection of a tee (i.e., branch nipple) and an isolation valve onto the existing pipeline through which a “coupon” can be cut out of the existing pipeline while the pipeline is still operational. The branch nipple connection can either be attached by welding or installing a mechanical clamp.

“Welded” hot tap activities can be described as follows:

expose buried pipeline section by airlifting sediments; remove weight and corrosion coating; install and commission welding habitat; inspect pipeline; weld branch nipple onto pipeline; install reinforcement sleeve;


install branch nipple flange; install isolation valve; remove habitat; install “hot tap” machine; perform “hot tap”; remove “hot tap” machine; and install “hot tap” protection structure.

“Mechanical” hot tap activities can be described as follows:

expose buried pipeline section by airlifting sediments; remove weight and corrosion coating; inspect pipeline; install mechanical clamp; install “hot tap” machine; perform “hot tap”; remove “hot tap” machine; and install “hot tap” protection structure.

The “hot tap” structure is connected via a spool piece to a Deep Panuke tie-in structure which houses the equipment that will be required at the end of the Deep Panuke export pipeline. This equipment includes a manual isolation valve, a check valve and provision for a temporary subsea pig receiver. A protection structure will be placed around each of the SOEP pipeline hot tap equipment and the Deep Panuke pipeline tie-in equipment.

Refer to Section 2.3.5 which provides additional detail on methods involving sediment disposal with respect to the hot tap installation.

2.3.4 Subsea Flowlines and Umbilicals

A total of six to nine subsea flowlines will be installed on the seafloor to tie-in the five to eight production wells and one injection well. It is expected that the subsea production flowlines will be 200 to 250 mm [8 to 10 inches] in diameter and range from 1 to approximately 10 km in length. The injection flowline is expected to be 75 mm [3 inches] in diameter and approximately 1.7 km in length. The flowlines may be a flexible or rigid design and may be installed by reel-lay or s-lay pipelay methods. The flowlines will be trenched and buried. Flowline lengths, diameters, and installation method will be confirmed during detailed design.


A dedicated subsea umbilical will be required for each well in order to control, monitor, and supply chemicals to the wells. All umbilicals will be trenched and buried.

Offshore pipeline installation activities as presented in the approved 2002 CSR are applicable to the subsea flowline as well as umbilical installation and therefore are not addressed in this section as there is no need to re-assess. It should be noted that, while pipeline installation by reel-lay for flexible lines was not specifically addressed in the approved 2002 CSR, there is no change in the assessment as both reel-lay and s-lay pipelay methods simply refer to the methods used to feed the pipeline from the vessel to the seabed.

Further to the pipelay information provided in the approved 2002 CSR, refer to Section 2.3.5 which provides additional detail on methods involving sediment disposal with respect to subsea flowlines and umbilicals installation.

2.3.5 Construction Methods Involving Sediment Displacement

The Deep Panuke project has three infrastructure components that will require some form of sediment disturbance during the construction/installation phase. These components are as follows:

export pipeline (either M&NP Option or the SOEP Subsea Option); flowlines; and umbilicals.

The activities, location, techniques, duration and amount of sediment disturbance are described in Table 2.2 below. A summary for each component is described in the following paragraphs.

2.3.5.1 Export Pipeline

For the M&NP Option, the first kilometre from shore will be pre-trenched and covered with native material. Alternatively, this may be replaced by a horizontal directional drill (HDD) section where the cuttings will be disposed of onshore. Approximately 50% of the remaining 173 km offshore section will be trenched approximately 1 m into the seabed with natural or mechanical replacement of native sediments.

For the SOEP Subsea Option, the SOEP pipeline tie-in location will have to be exposed by airlift techniques. The 15 km Deep Panuke export pipeline will be trenched approximately 1 m into the seabed with natural or mechanical replacement of native sediments.


2.3.5.2 Flowlines

Flowlines for the five to eight production (18-31 km in total length) and one acid gas injection (1.7 km) will be trenched approximately 1 m into the seabed with natural or mechanical replacement of native sediments.

2.3.5.3 Umbilicals

Umbilicals for the five to eight production (18-31 km in total length), one acid gas injection (1.7 km) and gas buy-back valve, which forms part of the subsea isolation valve (SSIV) assembly (150 m), will be trenched approximately 1 m into the seabed with natural or mechanical replacement of native sediments.

2.3.6 Subsea Equipment and Associated Protection Structures

The following subsea equipment will be protected by dedicated protection structures:

wellhead (up to 9 in total); hot tap (SOEP Subsea Option only, see Section 2.3.3);tie-in (SOEP Subsea Option only, see Section 2.3.3); andSSIV skid (protection structure may not be required since SSIV is located in MOPU Safety Zone).

These shall be separately deployed structures. The protection structures shall be designed to allow adequate access to the wells for all planned diver and remotely operated vehicle (ROV) intervention tasks. The SSIV assembly shall be designed to support the piping and valves and to provide protection against dropped objects. All subsea protection structures will be trawlable, cage-like, open tubular construction. The protection structures footprint is expected to be approximately 10 m x 10 m for the wellheads, 10 m x 6 m for the hot tap, 20 m x 15 m for the tie-in, and 5 m x 5 m for the SSIV skid.

Dee

p Pa

nuke

Vol

ume

4 (E

nvir

onm

enta

l Ass

essm

ent R

epor

t) N

ovem

ber 2

006

2-20

Tab

le 2

.2 C

onst

ruct

ion

Met

hods

C

ateg

ory

Act

ivity

/Pur

pose

Loc

atio

nT

echn

ique

(s)

Dur

atio

nA

mou

ntEx

pose

the

exis

ting

SOEP

660

m

m [2

6 in

ch] p

ipel

ine

to p

erfo

rm

“hot

tap”

App

roxi

mat

ely

KP1

62 o

f SO

EP

pipe

line.

See

Fig

ure

2.3

Airl

ift

1-2

days

(for

mec

hani

cal

hot t

ap) o

r 2-4

day

s (fo

r w

elde

d ho

t tap

)

App

rox.

10m

x 1

0m x

3m

for w

elde

d ho

t tap

A

ppro

x. 5

m x

5m

x

3m fo

r mec

hani

cal h

ot

tap

Expo

rtPi

pelin

e –

SOEP

Opt

ion

Tren

chin

g of

the

expo

rt pi

pelin

e fo

r on-

botto

m st

abili

ty.

15 k

m le

ngth

from

MO

PU to

SO

EP h

ot ta

p lo

catio

n. S

ee F

igur

e 2.

3

Mul

ti pa

ss p

loug

h (M

PP),

MPP

with

se

para

te b

ack

fill p

loug

h (B

FP),

jetti

ng,

mec

hani

cal d

igge

r with

nat

ural

or

mec

hani

cal r

epla

cem

ent o

f nat

ive

sedi

men

ts

On

aver

age

150

to 4

00 m

/hr

(dep

ende

nt o

n so

il co

nditi

ons)

Tren

ch to

allo

w 1

m o

f co

ver

Hor

izon

tal d

irect

iona

l dril

ling*

or

trenc

h of

app

roxi

mat

ely

first

1km

of

pip

elin

e fr

om o

nsho

re fo

r on-

botto

m st

abili

ty a

nd p

rote

ctio

n.

KP0

to K

P1.0

. Se

e Fi

gure

2.4

Fo

r tre

nchi

ng, t

renc

h by

a d

ippe

r/flo

atin

g ba

ckho

e/flo

atin

g gr

ab d

redg

e. S

ome

blas

ting

may

be

requ

ired

in n

ears

hore

are

a (in

the

dry

durin

g pe

riods

of l

ow ti

de)

3 to

4 m

onth

s Pi

pelin

e w

ill b

e la

id in

pr

e-ex

cava

ted

trenc

h an

d co

vere

d w

ith

nativ

e m

ater

ial

Expo

rtPi

pelin

e –

M&

NP

Opt

ion

Tren

chin

g of

the

expo

rt pi

pelin

e fo

r on-

botto

m st

abili

ty.

App

rox.

KP1

.0 to

KP2

2.0

and

KP1

10.0

to th

e M

OPU

. Se

e Fi

gure

2.

3

MPP

, MPP

with

sepa

rate

BFP

, jet

ting,

m

echa

nica

l dig

ger w

ith n

atur

al o

r m

echa

nica

l rep

lace

men

t of n

ativ

e se

dim

ents

On

aver

age

150

to 4

00 m

/hr

(dep

ende

nt o

n so

il co

nditi

ons)

Tren

ch to

allo

w

appr

oxim

atel

y 1m

of

cove

r

Flow

lines

Tr

ench

ing

of a

ppro

x. 3

1 km

of

200

to 2

50 m

m [8

to 1

0 in

ch] a

nd

1.7

km o

f 75m

m [3

inch

] flo

wlin

es fo

r ins

ulat

ion,

pr

otec

tion

and

on-b

otto

m st

abili

ty

See

Figu

re 2

.2M

PP, M

PP w

ith se

para

te B

FP, j

ettin

g,

mec

hani

cal d

igge

r with

nat

ural

or

mec

hani

cal r

epla

cem

ent o

f nat

ive

sedi

men

ts

On

aver

age

150

to 4

00 m

/hr

(Dep

ende

nt o

n so

il co

nditi

ons)

Tren

ch to

allo

w

appr

oxim

atel

y 1m

of

cove

r

Um

bilic

als

Tren

chin

g of

app

roxi

mat

ely

31

km o

f 100

mm

[4 in

ch] u

mbi

lical

s fo

r flo

wlin

es a

nd b

uy-b

ack

gas

valv

e.

See

Figu

re 2

.2

MPP

, MPP

with

BFP

, jet

ting,

mec

hani

cal

digg

er w

ith n

atur

al o

r mec

hani

cal

repl

acem

ent o

f nat

ive

sedi

men

ts

On

aver

age

150

to 4

00 m

/hr

(dep

ende

nt o

n so

il co

nditi

ons)

Tren

ch to

allo

w

appr

oxim

atel

y 1m

of

cove

r

* H

oriz

onta

l dire

ctio

nal d

rillin

g of

this

sect

ion

wou

ld n

ot d

ispl

ace

surf

ace

sedi

men

ts.

HD

D c

uttin

gs w

ill b

e di

spos

ed o

f ons

hore

.


2.3.6.1 Pile Driving

The Project basis in the approved 2002 CSR comprised three bottom-founded platforms. Each platform was to be fastened to the seabed via 2100 mm [84 inch] diameter skirt piles driven 61 to 68 m below the seabed. The piles were to be driven with a Menck MHU-1700 Hammer (or equivalent). This hammer has a maximum energy output of 1.70 million Newton-meters (1.25 million foot-pounds). The piles were to be approximately 75 m in length and the water depth was approximately 37 m. As a result, approximately 40 to 45% of the hammer impacts would have occurred underwater with the remainder in air. The pile driving duration was estimated to be 4 to 6 hours per pile based upon previous experience with the Panuke and Cohasset platform piles.

In the approved 2002 CSR, a SSIV assembly was to be situated approximately 150 m from the production platform. It was anticipated that the SSIV assembly may have been pre-fabricated onto a skid for ease of installation and may have required a protection frame. The skid/protection frame may have been fastened to the seabed via four piles ranging in size from 610 mm [24 inch] to 910 mm [36 inch] driven approximately 8 to 12 m below seabed. These piles would be driven with an IHC S-90 (or equivalent) hammer which has a maximum energy output of 89,000 Newton-meters (66,000 foot-pounds). The actual pile driving duration is estimated to be 0.5 to 1 hours based upon previous experience with the Panuke platform docking piles.

The revised Project design basis is based upon having a MOPU with subsea production wells individually tied back to the MOPU. The MOPU does not require any piles for installation. There may be up to eight subsea production wells and one acid gas injection well. Each wellhead will require a protection structure. The sales product(s) will be either exported to shore (M&NP Option) or to the existing SOEP pipeline (SOEP Subsea Option). A SSIV assembly will be required for both options as per the design basis approved in the approved 2002 CSR. For the SOEP Subsea Option, the connection to the SOEP pipeline will be via a “hot tap” which will in turn be spool connected to a Deep Panuke “tie-in” structure.

As a result, the following subsea protection structures will be required for the revised Project design basis:

wellhead (up to 9 in total); SSIV assembly skid (1); hot tap (1) (SOEP Subsea Option only); and tie-in (1) (SOEP Subsea Option only).


These subsea structures may be fastened to the seabed via four piles ranging in size from 610 mm [24 inch] to 910 mm [36 inch] driven approximately 8 to 12 m below seabed. These piles would be driven with an IHC S-90 (or equivalent) hammer which has a maximum energy output of 89,000 Newton-meters (66,000 foot-pounds). The actual pile driving duration is estimated to be 0.5 to 1 hours based upon the previous experience of driving the Panuke platform docking piles.

Although the total number of piles has increased for the revised Project design basis, the diameter and length of the piles is smaller requiring an overall shorter duration of the activity with a lower energy hammer. As a result, the potential pile driving requirements associated with the 2006 Project basis is less than the Project basis approved in the 2002 CSR; refer to Table 2.3 for comparison.

2.3.7 Onshore Facilities and Pipeline (M&NP Option Only)

Onshore pipeline installation activities as presented in the original CSR have not changed; therefore, these activities are not addressed in this section as there is no need to re-state.

2.3.8 Development Well Construction

Development wells will include five to eight production wells and one injection well, all of which will be subsea. A jack-up drilling unit will be used to complete the existing wells and to drill the subsea wells. A jack-up drilling unit is a MODU that has legs that can be jacked up or down. Once towed to the site, the legs are jacked down until they are in contact with the seafloor, then the rig platform is elevated until it is approximately 25 m above the water surface. The jack-up drilling unit will remain on location during drilling and completion operations and then be removed. Well construction activities are expected to take approximately 430 days (five new drill wells at 60 days each plus four re-entry wells at 32 days each) in total to complete.

The normal drilling program for all Deep Panuke wells involves conventional hole and casing/pipe sizes. All casing designs are based on CNSOPB Offshore Petroleum Drilling Regulations.

Dee

p Pa

nuke

Vol

ume

4 (E

nvir

onm

enta

l Ass

essm

ent R

epor

t) N

ovem

ber 2

006

2-23

Tab

le 2

.3

Pile

Dri

ving

Det

ails

Proj

ect D

esig

n B

asis

of 2

002

App

rove

d 20

02 C

SR

No.

Pi

les

Size

[mm

(in)

] Pe

netr

atio

n [m

] H

amm

er S

ize

Max

. Ene

rgy

]N.m

(ft.

lbs)

] A

ctua

l Dri

ving

Dur

atio

n/Pi

le

Act

ual

Dri

ving

Dur

atio

nW

ellh

ead

Plat

form

4

2100

(84)

61

M

enck

MH

U-1

700

(o

r equ

ival

ents

) 1,

699,

000

(1,2

53,0

00)

4 to

6 h

r 16

hr -

24hr

Prod

uctio

nPl

atfo

rm8

2100

(84)

68

Sam

e as

WH

P 1,

699,

000

(1,2

53,0

00)

4 to

6 h

r 32

hr -

48hr

Util

ities

and

Q

uart

ers P

latf

orm

4

2100

(84)

65

Sam

e as

WH

P 1,

699,

000

(1,2

53,0

00)

4 to

6 h

r 16

hr -

24hr

SSIV

Ski

d1

4 61

0-91

0 (2

4-36

) 8

- 12

IHC

S-9

0

(o

r equ

ival

ents

) 89

,000

(66,

000)

0.5h

r - 1

hr

2hr -

4hr

Estim

ated

Tot

al D

urat

ion2 (M

enck

MH

U-1

700)

64

hr -

96hr

2.7

d –

4 d

Estim

ated

Tot

al D

urat

ion3 (I

HC

S-9

0)

2hr -

4hr

Rev

ised

Pro

ject

Bas

is

No.

Pi

les

Size

[mm

(in)

] Pe

netr

atio

n [m

] H

amm

er S

ize

Max

. Ene

rgy

[N.m

(ft.

lbs)

] A

ctua

l Dri

ving

Dur

atio

n/pi

le

Act

ual

Dri

ving

Dur

atio

n

Wel

lhea

dPr

otec

tion

(x9)

36

24

- 36

8

- 12

IHC

S-9

0

(o

r equ

ival

ents

) 89

,000

(66,

000)

0.

5hr -

1hr

18

hr -

36hr

Hot

Tap

4

24 -

36

8 - 1

2 Sa

me

as W

ellh

ead

89,0

00(6

6,00

0)0.

5hr -

1hr

2h

r - 4

hr

Tie

-in4

24 -

36

8 - 1

2 Sa

me

as W

ellh

ead

89,0

00(6

6,00

0)

0.5h

r - 1

hr

2hr -

4hr

SSIV

Ski

d14

24 -

36

8 - 1

2 Sa

me

as W

ellh

ead

89,0

00(6

6,00

0)

0.5h

r - 1

hr

2hr -

4hr

Estim

ated

Tot

al D

urat

ion3 (I

HC

S-9

0)

24hr

- 48

hr

1d -

2d

1 May

not

be

requ

ired

sinc

e in

Pla

tform

/MO

PU S

afet

y Zo

ne

2 App

roxi

mat

ely

40 to

45%

of t

he d

urat

ion

is u

nder

wat

er h

amm

er a

ctiv

ities

3 A

llth

e du

ratio

n is

und

erw

ater

ham

mer

act

iviti

es


For the new production and injection wells drilled, the conductor pipe (first string of pipe) will be set approximately 100 m below the seafloor. This is the same method that has been used on the existing suspended delineation wells. This section will be drilled primarily with seawater and viscosifiers to aid in ensuring cuttings removal from the wellbore. These cuttings are deposited at the seabed and are generally equivalent to the volume of the hole drilled, approximately 65 m³.

The conductor pipes will serve as the primary weather barrier to take environmental loading and protect the inner strings of casing (length of pipe) while drilling the well. The conductors also take the surface loading implied by the other strings of casing that are returned to the mudline suspension system. Once the drilling has been completed, the conductors will be removed and the well will be converted to a subsea wellhead. With the production tree installed, a high pressure riser will be required to tieback to the surface blowout preventor (BOP) stack. The high pressure riser will be designed to withstand the environmental loads as well as all internal design loads.

All wells, including production and injection, will set the surface casing into the Wyandot member at approximately 950 m below sea level in the general direction that the bottom of the well will be located. The BOP stack is then installed on top of the surface casing prior to drilling the intermediate hole section.

For the re-entry wells, an intermediate hole section has been drilled just into the top of the limestone at approximately 3200m true vertical depth (TVD). An intermediate casing string has been set 20 m into the Abenaki 7/6 formation and cemented back just above any potential hydrocarbon bearing sands (~2300 m). The new production well(s) will be similarly constructed to the existing suspended delineation wells. Prior to drilling the reservoir section and with the well secured, the surface wellhead and conductor will be removed and the well will be converted to a subsea wellhead. The production tree will be installed with high pressure riser connected back to the surface BOP stack.

A rotating BOP and an injection spool will be installed with the surface BOP stack in preparation for annular velocity control (AVC) drilling techniques and the main hole section will be drilled through the productive interval of the carbonate reef. On the re-activation wells, the reservoir section has been drilled to a total depth of circa 3650 m TVD which is about 150 m past the gas-water contact (GWC) at 3504 m TVD. On many of the delineation wells, this GWC was not clearly evident while drilling the section as the formation was not porous at this depth, however it was clearly identified while drilling the MarCoh D-41 well. On each of the wells to be re-used for production, a liner (string of pipe) has been installed across the reservoir section and cemented back to the previous casing shoe. For the new producing well(s), the reservoir section may be left open, with no liner in place, in order to maximize the flow potential of the well.


For re-entry of the existing wells, a “trash cap” will first be removed from the conductor stub 3 m above the seafloor. A “trash cap” is a cylinder device closed on one end that sets over the conductor to keep out marine organisms or falling debris. Once the trash cap has been removed, a running and retrieving tool is used to back off the temporary abandonment caps. Each of the wells then has a cement plug set that has to be drilled out.

The production wells will all be completed with a downhole packer (plus other ancillary downhole equipment), production tubing, surface controlled subsurface safety valve, a tubing hanger, and a subsea production tree. Once all hydrostatic tests and function tests are performed, the production wells will be opened for clean-up flow on the drilling rig. This will remove any water or debris from the wellbore prior to handover for production operations on the MOPU. See Figure 2.8 for details on the production wells.

The injection well will be drilled using similar processes and procedures as with the production wells. Once the surface casing is set in the Wyandot formation, the main well bore will be drilled vertically to the injection zone in the Upper Mississauga formation located at approximately 2400 m TVD. See Figure 2.9 for details on the injection well. Similar to the production well, the completion for the injection well will consist of tubing, downhole packer, subsurface safety valve, tubing hanger and injection tree.

For the M&NP Option, it is estimated that there will be no surplus condensate produced beyond fuel usage; however, the ability to inject condensate down-hole with the acid gas stream provides operational flexibility in times of maintenance and/or operational issues. It is currently planned to inject the condensate with the acid gas into the one injection well that will be drilled west of the MOPU field centre. Injection pumps on the main production platform will be used to pump the condensate down the well at the required pressures for injection into the downhole disposal zone.

This injection well for acid gas and condensate (if necessary) will be drilled into a porous and permeable zone in the Upper Mississauga Formation; the targeted injection zone is the Tidal-Fluvial Sandstone. The impermeable Naskapi shales located directly above will prevent any migration of injected acid gas or condensate. The Upper Mississauga Formation will be capable of containing the entire acid gas and surplus condensate volumes that will be produced over the life of the Project. Migration of injection fluids to other formations and/or to the surface is considered extremely unlikely. The possibility of acid gas injection souring the Panuke oil zone is also considered to be extremely unlikely. See Figures 2.8 and 2.9 for production and injection well schematics.

P:\EnvSci\101xxx\1015157 - Deep Panuke\Graphics\Figures\Fig2_8.cdr

Figure 2.8

Typical Production Well Schematic

P:\EnvSci\101xxx\1015157 - Deep Panuke\Graphics\Figures\1015157_Figure2-09.cdr

Figure 2.9

Acid Gas Injection Well Schematic


2.3.8.1 Drilling Fluid Program

Water-based muds (WBM) will be used in development drilling. These muds are used to protect and clean the drill hole, for overbalancing formation pressures, and for bringing cuttings to the surface. The selection of the drilling fluid is based on factors such as the hole angle, the formation types drilled (mudstone, sandstone, clays, etc.), and the time of exposure.

WBM is a suspension of solids and dissolved material in a carrier base fluid of water. WBM tends to be used for wells that are normally pressured or do not encounter difficult geology. Based on the experience gained while drilling the Deep Panuke delineation wells, it was determined that only WBM will be used for any new development drilling activities.

The typical composition of WBM (seawater gel mud type) for Deep Panuke are as follows:

barite;bentonite;potassium chloride (KCl); polymers; water;glycol;soda ash/sodium bicarbonate/lime; caustic soda; and salt (sodium chloride or calcium chloride).

During drilling of the new wells, the mud is circulated down the drillpipe from the drilling unit to the bottom of the wellbore and returned to the drilling unit in the annular space (between drill pipe and open hole/casing) carrying the cuttings from the well. Each hole section of a wellbore requires different fluid properties. Thus after each hole section, the mud is modified or changed out. WBM that is no longer required will be disposed of overboard, along with WBM cuttings in accordance with the Offshore Waste Treatment Guidelines (OWTG) (NEB et al. 2002).

For the wells to be re-entered and completed, some drilling is required to remove cement suspension plugs. This will be done using a viscosified brine solution and so traditional drilling mud will not be required. Prior to removal of the last suspension plug on the existing wells, the well will be displaced with filtered completion brine which will act as an overbalanced annulus fluid for setting the production packer. Some viscous pills of polymer gelled brine may be used to ensure removal of all solid particles in the wellbore. The completion fluid will be clear brine with additives for corrosion and oxygen inhibition as well as H2S scavengers.


Once the well completion is set and the production tree is in place, it will be necessary to flow the well to clean up and remove completion fluids from the reservoir. This operation will be done using a well test package installed on the drilling rig. In order to flow the well, it is necessary to provide an underbalance for the well to flow naturally. This underbalance can be achieved in a number of ways but, in general, involves lowering the density of the completion fluid inside the tubing string. It is typically not recommended to use fresh water to lower fluid density in a gas well as this can lead to the formation of hydrates. Circulating nitrogen into the completion tubing is one alternative to lowering fluid density but tends to be equipment intensive on the drilling rig. Another alternative is to displace some of the completion fluid in the tubing string with either diesel or glycol or a combination of both. This will likely be the method used for Deep Panuke wells. The underbalanced fluid column, also referred to as the “fluid cushion”, is caught by the well test equipment on the drilling rig and burned through the oil burner on the flare boom. Typically this represents a very small volume of diesel in the order of 20 to 30 m³.

Through the life of the field, workovers will be required in the wellbores. These workovers will require various pieces of equipment to be sent offshore to perform downhole work. Completions brines may be used during these processes. These brines will be composed of water and a salt formulation kept in suspension using a viscosifier (polymer).

2.3.9 Hydrostatic Testing

The export pipeline for both M&NP and SOEP Subsea Options and the production and injection flowlines will be hydrostatically tested. It may be necessary to treat the seawater introduced into the pipeline with corrosion inhibitors and biocides as these chemicals protect the interior surface of the pipeline if the time between the installation of the pipeline and its commissioning into service exceeds the timeframe allowed for leaving untreated seawater in the pipeline. Leaving untreated seawater in the pipeline for more than one month can establish conditions which permit corrosion to occur at a later stage in the life of the pipeline. The introduction of treatment chemicals is a safety measure for the prevention of corrosion over the life span of the pipeline.

The hydrostatic test plan for the export pipeline is detailed in Table 2.4 and the following paragraphs. For the export pipeline (M&NP Option), the discharge of hydrostatic fluids occurs at the MOPU. The cooling water pumps, running at 2400 m3/hr, will be flowing into the discharge caisson while discharging the hydrostatic fluid. This provides a dilution factor as outlined in the table below. There is no dilution for the export pipeline (SOEP Subsea Option) since the release point is at the tie-in location. For the flowlines, hydrostatic fluids may be discharged at the MOPU or at the individual subsea wellheads. This will be confirmed during detailed design. Therefore, no dilution for the flowlines is assumed as a worst case scenario.


Table 2.4 Hydrostatic Fluid Discharge Summary

Case Length [km]

Release Point Release Volume [m3]

Release Rate

[m3/hr]

Cooling Water Rate

[m3/hr]

DilutionFactor

Export Pipeline (M&NP Option)

176 Field Centre 43,200 400 2400 6:1

Export Pipeline (SOEP Subsea Option)

15 SOEP Subsea Tie-in location

3040 400 n/a n/a

Production Flowlines (at start-up)

18.2 Field Centre 590 175 n/a n/a

Production Flowlines (after start-up)

12.4 Field Centre 402 175 n/a n/a

Acid Gas Injection Flowline 1.7 Field Centre 8 24 n/a n/a

Although assessed in the previously approved 2002 CSR, hydrostatic testing must be re-assessed due to changes in dilution factors, location of release, and additional pipeline and flowlines scenarios.

For both the M&NP Option and the SOEP Subsea Option, the pipeline will be installed cleaned, gauged, flooded, and hydrotested. The pipeline spool between the pipeline and MOPU will be installed and the pipeline will be leak tested, dewatered, dried and nitrogen packed. For the M&NP Option, the fluid will be disposed at the MOPU location. For the SOEP Subsea Option, the fluid will be disposed at the SOEP subsea tie-in location.

The flowlines will be installed cleaned, gauged, flooded and hydrotested. The flowline spool between the pipeline and MOPU will be installed and the flowline leak tested. For the flowlines, it is unknown at this time whether the fluid will be discharged at the MOPU location or at the individual wellhead locations. This will be determined during detailed design.

All the water introduced into the line shall be thoroughly filtered to 50 microns. During filling, cleaning, gauging and hydrostatic testing, chemical inhibition package(s) will be continuously injected into the seawater. The chemical inhibition package may include: dye to aid in the detection of leaks; a biocide to control marine organisms and sulphate reducing bacteria; a corrosion inhibitor; and a dissolved oxygen scavenger to minimize corrosion on the interior of the pipeline. During the filling cycle, some spillage of this water may occur at the pig receiving station offshore. This occurs when excess hydrostatic water is required to push the pig into the pig receiver at the end of the pipeline.

The chemicals to be used in this application will be approved for discharge through the Offshore Chemical Selection Guidelines (OCSG) (NEB et al. 1999) and selected from a list of chemicals approved for use in Canada. Since the installation program for the pipeline is still under development and a supplier has not yet been selected, the definitive treatment chemicals cannot be specified.


A study, consisting of two components, will be undertaken to confirm predictions there will be minimal effects of the selected chemicals discharged into the environment. A toxicity bioassay program (first study component), will be undertaken prior to discharging these compounds. The bioassay will employ samples of the proposed chemical diluted in seawater to emulate the mixtures of chemicals and concentrations proposed for the hydrostatic test program. The results will be applied in a plume dispersion model (second study component) to confirm that there will be minimal effect to the marine environment around the platform. Prior to undertaking this study, the parameters and scope of the bioassay study will be discussed with Environment Canada and DFO.

The onshore section of the pipeline will also require hydrostatic testing, which may be conducted concurrently with the offshore section of the pipeline as discussed above, using the same seawater source and treatment chemicals.

Should the schedule of the onshore section of the pipeline installation be changed, then a separate hydrostatic test may be required. Under this circumstance, the hydrostatic test water could be left in the onshore pipeline until the offshore testing is completed and the hydrostatic test water discharged with the offshore hydrostatic test water.

2.4 Operations

2.4.1 Production

Production facilities on the MOPU will be operated to optimize production while maintaining environmental protection and high safety standards and minimizing environmental impact. The production facilities will be staffed on a 24-hour basis. Facility maintenance and inspection requirements will be managed through a maintenance management system that will incorporate proactive and predictive methods as well as intelligent condition monitoring techniques.

Production facilities will consist of equipment for separation, metering, amine sweetening, acid gas injection, dehydration, hydrocarbon dewpoint control (M&NP Option only), produced water treatment and disposal, condensate treatment, condensate injection (M&NP Option only), feed gas and export gas compression, and utilities. A simplified process flow diagram is presented as Figure 2.10.

For the M&NP Option, all production and treatment facilities are located offshore. For the SOEP Subsea Option, production and treatment facilities are primarily located offshore but the export gas and liquids will be routed to the existing SOEP facilities near Goldboro and, subsequently, Point Tupper for further processing.

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For the M&NP Option, the export gas will be “on specification” sales gas meeting the hydrocarbon dewpoint and water content requirements for the M&NP pipeline. As a result, there is no onshore treatment required. The sales gas will be routed to shore near Goldboro in a new 560 mm [22 inch] pipeline with a connection into the existing M&NP pipeline. Onshore facilities are related to metering/quality measurement and isolation valve requirements only. The liquids will be treated offshore and used as fuel. Currently it is estimated that there will be no surplus condensate produced beyond fuel usage. To allow flexibility in times of maintenance and/or operational issues, condensate will be commingled with the acid gas and re-injected for disposal.

For the SOEP Subsea Option, the export gas and condensate will be commingled and routed to the SOEP 660 mm [26 inch] pipeline and routed to the existing SOEP Goldboro gas plant. At Goldboro, the gas and liquids will be separated and the gas further processed into sales gas by SOEP and shipped via the existing M&NP pipeline to market. The liquids will be routed to the SOEP Point Tupper liquids plant for processing and sale.

2.4.1.1 Separation

The well fluids will be processed through the production or test separator for separation of the gas, condensate, and water.

2.4.1.2 Metering

The Deep Panuke production facilities will adhere to the applicable regulations and the Canada-Newfoundland Offshore Petroleum Board (CNOPB)/CNSOPB Measurement Guidelines, October 2003.

2.4.1.3 Amine Sweetening

The amine sweetening system, which uses methyldiethanolamine (amine), is designed to remove the H2S contained in the raw gas. The removal of the H2S and CO2 from raw gas results in a waste acid gas stream predominantly containing H2S and CO2. The H2S content of the raw gas during the life of the Project will vary. The amine sweetening system is designed to operate safely over the expected variation of H2S content in the raw gas.

The Deep Panuke gas contains up to 3.5 mole % CO2 and approximately 1,800 ppm H2S. The amine sweetening unit is designed to be fed with gas that contains up to 2,500 ppmv of H2S and up to 3.5 mole % CO2 to provide some operational design flexibility. The facility metallurgical design will be for 3,000 ppmv of H2S and 4.0 mole % CO2 to provide some metallurgical design flexibility. The sales gas specification requires the H2S content to be a maximum of 6 mg/m3 (approximately 4 ppmv) and 3.0 mole % CO2. The current design basis unit outlet is for an H2S level of 2 ppmv and CO2 at 2.8 mole %.


Although the M&NP Option is the only option producing sales gas, the same product specification requirements will be met for SOEP Subsea Option as the SOEP facilities require a sweet feedstock.

The amine-sweetening unit is based on physical absorption using a solvent to absorb the impurities (H2S and CO2). The solvent is then regenerated via heating to release the absorbed impurities. The process is cyclic, in which the amine is continuously circulated through the absorber/contactor to pick up the impurities, then routed to a regenerator to release the impurities.

Remaining CO2 and H2S amounts not removed during the amine sweetening process remain in the sales gas, which is sent to market. The amine-sweetening unit is a closed loop system.

The amine solvent used in the sweetening unit will be methyldiethanolamine, which will improve the selectivity between H2S and CO2 absorption. The cyclic process can result in a build up of impurities in the amine solvent over time. If the amine solvent requires a change, whether complete or partial (dilute out the impurities), it is removed from the process and shipped to shore for reclaiming (manufacturer to clean and recycle). Production will be halted when a complete change-out of amine solvent is required. The change-out of the amine solvent will be subject to the EPP.

2.4.1.4 Acid Gas Handling

Acid gas from the amine regenerator will be compressed to approximately 15,100 kPa (from a feed pressure of 150 kPa) using a multi-stage compressor. Water condensing between the compressor stages recycled back to the processing facilities. The compressed acid gas will be injected into a suitable, subsurface reservoir. Table 2.5 describes the design flow and composition for the acid gas injection system.

The Project does have the capability to flare acid gas. The capability to flare the acid gas stream is required to provide operational flexibility in times of maintenance and/or operational issues.

Table 2.5 Acid Gas Injection System – Composition and FlowDescription Design Data

Mass Flow (kg/h) 8100STD Gas Flow (m3/hr) 5325Molar Flow (kgmole/hr) 230Pressure (kPa) 150Temperature (C) 56Component Mole %CO2 63.2H2S 18.5CH4 17.0C2+ 1.1H2O 0.24Note: The flow represents the total feed to the acid gas management system including acid gas from the amine system and H2S removed from the condensate fuel for the Mean Production Profile (Mean denotes the statistical Mean value of a probability distribution).


2.4.1.5 Dehydration

Sweet gas from the amine-sweetening unit contains water that must be removed prior to hydrocarbon dewpoint adjustment (M&NP Option) or prior to export (both options). The gas dehydration unit is a liquid desiccant process utilizing a solvent to absorb the water. The solvent, triethylene glycol (TEG), is then regenerated via heating to release the absorbed water. The process is cyclic in which the TEG is continuously circulated through the absorber/contactor to pick up the water then routed to a regenerator to release the water. A brief description of the process follows.

Treated gas from the amine unit is routed to the TEG system for dehydration. The gas first is routed to the TEG contactor in which the incoming gas flows counter current to the lean TEG. The lean TEG absorbs the entrained water in the gas stream and reduces the water content of the gas.

The rich TEG leaving the contactor cools the regenerator overheads and is routed to the TEG flash drum. The flashed gas from the flash drum is routed to the flare. The flash drum liquids then pass through the TEG charcoal filter (to remove trace hydrocarbons) and the TEG filter (to remove charcoal) before being heated in the TEG regenerator feed/effluent heat exchanger before entering the regenerator.

The bottoms of the regenerator are heated to remove the water from the rich TEG. A small amount of stripping gas is used to enhance the water removal of the regenerator. The regenerator overheads are cooled for tower top temperature control, with the overhead gas stream being routed to the flare.

The water removed from the sweet gas dehydration process is removed from the top of the TEG regenerator in the overhead gas stream and routed to the low-pressure (LP) flare header. A large portion of the water in the overhead gas stream will condense in the flare piping or drum. The flare drum liquids will be pumped into either the inlet or test separators and the water portion of the liquids in these separators is routed to the produced water treating facilities. Non-condensable hydrocarbons will be flared.

The lean glycol leaves the regenerator column, enters the TEG surge drum, then is cooled in the TEG regenerator feed/effluent heat exchanger. The lean TEG is further cooled in the lean TEG cooler (cooling medium cooler) before entering the TEG contactor.

The dry gas from the TEG contactor passes through a coalescer to reclaim any entrained TEG leaving the contactor in the overhead gas stream. The TEG is returned to the flash drum. The dehydration process is a closed loop system. The circulating TEG builds up contaminants, primarily salts. Once the levels build to a point, the risk of corrosion and or deposits increase to the point where removal of some/all the TEG is required and new TEG added. Rate of build up varies with the feed quality so it is difficult to predict how long before this happens.


Spent TEG has no measurable H2S and will be disposed of an approved facility.

2.4.1.6 Hydrocarbon Dewpoint Control

For the M&NP Option, the dehydrated gas from the TEG system is cooled via the Joule-Thompson (JT) effect by dropping the pressure of the gas. A portion of the gas stream condenses (condensate), which is then separated. This step will be done offshore as it is necessary to satisfy pipeline gas specification requirements.

For the SOEP Subsea Option, the export gas routed to the SOEP 660 mm [26 inch] pipeline need not meet sales gas specification requirements. For these cases, hydrocarbon dewpoint control operations will be done via the SOEP gas plant existing facilities.

2.4.1.7 Condensate Treatment for Fuel

Recovered condensate will be treated via stabilization to remove light ends and H2S. The light ends and H2S thus released are recycled back to the raw gas stream for processing.

For the M&NP Option, condensate is burned on the MOPU as the primary source of fuel. Operation of the condensate stabilizer will remove H2S in order to minimize air emissions and to produce a fuel meeting the turbine driver requirements. Given that the amount of condensate is a function of raw gas rate thus declining over the life of the Project, it will be supplemented with natural gas as necessary to maintain adequate fuel levels.

The SOEP Subsea Option, all recovered condensate will be routed to the shore based SOEP facilities for separation, processing, and sale.

Condensate production is based on the production profile for the Project. The production profile has been calculated for a range of reservoir gas compositions. The intent is that the MOPU will be designed for the entire possible range. Over the range, the facility will produce less condensate than that required for fuel thus no surplus condensate will exist for the M&NP Option.

The MOPU will have some minimal storage for condensate. This storage is, approximately 55 m3 and represents approximately five hours of consumption at full rate. The intention of this storage is to cover periodic production upsets with enough time to allow for short term troubleshooting and/or swinging fuel from condensate to either fuel gas or diesel. The storage tank is a pressure vessel that is pressured with inert gas with excess pressure routed to the flare.


For the M&NP Option, it is estimated that there will be no surplus condensate produced beyond fuel usage; however, the ability to inject condensate down-hole with the acid gas stream provides operational flexibility in times of maintenance and/or operational issues. The probability of the acid gas injection well malfunctioning and becoming inoperable is very low (<1%). Any maintenance work for the well will be scheduled during planned shutdowns. If the injection well becomes unavailable at any time, additional condensate can be consumed through the operation of “spare” fired turbine equipment.

There is no capability to flare condensate with this Project.

2.4.1.8 Produced Water Treatment and Disposal

Water produced with raw gas and separated during the initial stages of processing is called produced water or formation water. This water contains residual hydrocarbons and other contaminants that must be removed to acceptable levels prior to ocean discharge.

Table 2.6 indicates the P10 (value at the 10th Percentile) basis for produced water production. This water production forecast is a reasonable maximum water rate for the facilities.

Table 2.6 Produced Water Production Rates Year Cumulative Water Production Water Production

(103 m3) (103 m3/day) 0 0 0 1 180 0.5 2 1,000 2.4 3 2,900 5.3 4 5,200 6.4 5 7,500 6.4 6 9,700 6.4 7 12,000 6.4 8 14,300 6.4 9 16,500 6.4

10 18,800 6.4 11 21,100 6.4 12 23,300 6.2 13 25,300 5.8 14 27,300 5.5 15 29,400 5.8 16 31,300 5.5 17 33,100 5.0 18 33,500 1.2

The water composition is provided in Table 2.7; this information is based on water samples from the production formation.


Table 2.7 Water Composition

Component Abenaki 5 Formation Water (mg/l) Na+ 29,163 K+ 513

Ca2+ 5,885 Mg2+ 950 Ba2+ 8 Sr2+ 448 Fe2+ 0 Mn2+ 0 Cl- 55,321

HCO3- 731

CO3- 0

SO42- 1,570

Produced water will be treated to a target dispersed oil concentration of 25 mg/L (30-day weighted average). The OWTG (NEB et al. 2002) specify a 30-day weighted average of 30 mg/L. The following is a brief description of the treatment process.

Prior to discharge, produced water is treated in several ways. Water from the inlet separator, test separator, condensate stabilizer surge drum, and stabilizer feed filter coalescers is commingled and routed directly into the produced water feed drum. Water from other LP vessels is typically routed to the closed drains header, which is routed to the LP flare drum. Liquids from the LP and high-pressure (HP) flare drums are routed to either the inlet or test separators.

The function of the water feed drum is to hold produced water until sufficient volume is available to route to the hydrocyclones. The small amount of gas from this drum is routed to the acid gas injection compressor. At the start of the field life, the water rates are anticipated to be very low, such that batch processing in the hydrocyclones is likely. As the water rates increase, the flow will be continuous.

The hydrocyclones will remove all but trace amounts of liquid hydrocarbons. The hydrocyclones oil outlet is routed to the closed drains. The water is continuously routed to cartridge-style produced water polishers to further reduce trace amounts of liquid hydrocarbons.

The water is then heated in the produced water stripper feed preheaters prior to entering the produced water stripper. The amount of heat will be adjusted to aid in the H2S removal capabilities of the stripper tower. The produced water stripper tower is a packed counter current gas/liquid stripping column in which sweet fuel gas flows upwards counter current to the water to remove H2S; preliminary indications suggest that H2S will be lowered to a concentration between 1 to 2 ppmw. The gas from the stripper is routed to the acid gas injection compressor.


The flow to the stripper column will change dramatically over the field life. It may be necessary to provide flow via recycle or process in batches during low flow periods.

The water outlet of the stripper is sampled for oil and H2S and routed overboard. The waste gas from the produced water stripper will be routed to the acid gas injection compressor for injection. This will be the normal mode of operation. The plant does have the capability to divert the produced water stripper gas to the flare in the event of a malfunction of the acid gas injection well and/or compressor. If the produced water stripper gas were flared, it would be a maximum of 980 kg/h of 19.7 MW gas containing 1.5 mole % H2S.

The concentrations of amine and TEG in produced water at the outlet to the sea are below those concentrations which would impact marine species. Studies on the eco-toxicity of methyldiethanolamine and TEG, undertaken by the manufacturers, indicate that these substances are of low toxicity to fish and invertebrates in the concentrations present in the produced water discharge and that these substances are readily bio-degradeable (Woodburn and Stott, undated).

Currently the design envisages platform-based laboratory facilities for verification of produced water measurements.

The produced water will be routed overboard via the discharge caisson where it will mix with approximately 2,400 m3/hr of seawater which is used for process cooling purposes.

2.4.1.9 Compression

For the M&NP Option, the sales gas will be compressed on the platform for delivery to shore. The expected sales gas discharge pressure on the platform is approximately 13,000 kPa. The Deep Panuke compressor system is composed of three 7 MW units for a total of 21 MW of compressor power. The compressors will be used for sales gas export and feed gas. The feed gas service will be to account for declining reservoir pressure. These compressors will be tri-fuel (condensate, fuel gas, and diesel).

For the SOEP Subsea Option, the export gas will be compressed on the platform for delivery to the existing SOEP 660 mm [26 inch] pipeline and subsequently routed to shore. The expected export gas discharge pressure on the platform is approximately 13,000 kPa. Like the M&NP Option, the Deep Panuke compressor system is composed of three 7 MW units for a total of 21 MW of compression power. The compressors will be used for gas export and feed gas. The feed gas service will be to account for declining reservoir pressure. These compressors will be dual-fuel (fuel gas and diesel).


2.4.2 Utilities

2.4.2.1 Electrical Power Generation

Electrical power generation for the Deep Panuke MOPU will be provided by multiple redundant fuel turbine generating sets. For the M&NP Option, the turbines will be tri-fuel (condensate, fuel gas, and diesel). For the SOEP Subsea Option, the turbines will be dual-fuel (fuel gas and diesel). For the first production start-up, sufficient quantity of diesel will be available for power generation.

Emergency power will be provided by a diesel engine driven generator set as per CNSOPB regulations. The design requires the use of diesel fuel for emergency situations (emergency generator, firewater pumps), for certain start up scenarios (i.e., when buy back gas is not available), and for certain maintenance scenarios (i.e., power generators when no buy back gas is available).

The transfer of diesel from ships to the MOPU storage tanks will occur via loading hose. Bulk transfer/hose-handling procedures will be outlined in the EPP.

Battery back-up will be provided for critical emergency services.

2.4.2.2 Platform Fuel

For the M&NP Option, condensate will be used as fuel. Fuel gas may also be used as supplemental fuel, as required. For the SOEP Subsea Option, fuel gas will be the primary fuel source. Diesel will be used as fuel for the crane and the emergency generator. Diesel will also be used for start-up and shutdown of the compressor and power generation turbines. The MOPU will have a storage capacity of approximately 70 m3 for diesel. The area around the diesel storage will be “bunded” or “dyked” to collect diesel fuel in the unlikely event of a leak/spill. The bunded area will be routed to the open drains system within which the hydrocarbon is recovered. There is no capability to flare diesel on the MOPU.

All fuel will be metered.

2.4.2.3 Heating Medium System

The processing facilities require heat input for a number of systems including amine regeneration, TEG regeneration, condensate stabilization, and produced water processing. The heating system is a “closed circuit” system in which a heating medium (essentially the same solution as per the cooling medium except it contains some stabilization additives) is pumped through waste heat recovery units (WHRUs). There are three WHRUs, one installed on each turbine exhaust of the compressors. The heating


medium, circulating through the WHRUs, extracts heat that would be destined as waste to ambient and routes to various users.

2.4.2.4 Cooling Medium System

Cooling water for process and utility systems will be done via an indirect seawater/cooling medium system. Seawater will be pumped through a filter then a heat exchanger. The exchanger will cool a mixture of ethylene glycol and water (cooling medium). The cooling medium will then be distributed to the equipment and the plant requiring cooling. The once through seawater is returned to the ocean via the discharge caisson.

2.4.2.5 Deck Drainage

Deck drainage will be collected and treated according to the OWTG (NEB et al. 2002). Drainage from equipment areas on platforms will be directed through a header system to a collection tank to an oil/water separator treatment unit on the MOPU. Petroleum hydrocarbons and sludge in the oil/water separator will be transferred into containers for shipment to shore for disposal. The water from the oil/water separator will be treated using a cartridge-style water polisher and tested prior to discharge to ensure compliance with the discharge criteria of 15 mg/L or less.

The deck drainage system does have overflows to permit water to be routed directly overboard in the event of a deluge event or rain water in excess of the design condition.

2.4.2.6 Relief and Blowdown System

Safety systems and devices will be designed to meet Project standards and the requirements of all applicable standards, codes, and local regulations, including:

API B31.3 – Piping; API 14C – Cause and Effects; API 520, 521 – PSV’s/Rupture Discs; IEC 61508 – Functional Safety System; ANSI/ISA-84.01-1996 – Safety Instrumented Systems; NFPA 72E – Automatic Fire Detectors; and NORSOK-1-002 – Safety and Automation System.

The principal elements of the relief and blowdown system include the pressure relief devices, flare piping system, flare separator, flare structure and the flare burner. The flare design will take place during detailed design. Application of all relevant codes will be followed for the system design. The system


will be designed considering emergency shutdowns, blocked discharges, fire exposure, tube rupture, control valve failure, thermal expansion and utility failures.

Scheduled activation of the relief and blowdown system will occur for planned tests and inspection or maintenance work. When the system is commissioned and activated, hydrocarbons will be safely directed to the flare system. The flare will be designed to prevent any impact on the helideck and the living quarters during worst-case weather scenarios.

2.4.2.7 Inert Gas System

The Project will include an inert gas system. Inert gas is necessary for commissioning and start-up exercises as well as ongoing operations. The main use of the inert gas is in the gas compressor seals. The inert gas may also be used as a blanketing or purging gas to displace hydrocarbon vapours and reduce the risk of explosion and fire.

2.4.2.8 Instrument Air

Instrument air will be produced by electric driven air compressors and used in the instrumentation and controls system. The air will be dried.

2.4.2.9 Breathing Air

A breathing air system will be included in the design of the Project. Breathing air will be required for emergency purposes and for routine maintenance activities.

2.4.3 Support and Servicing

Supply vessels and helicopters will be used to supply personnel, fuel, food, well construction equipment and other materials required to maintain production, construction, and well construction operations. Typically, helicopters will be used for regular crew changes, visits from regulatory agencies, service personnel and other visitors that need to be transported to and from the offshore facilities.

2.4.3.1 Support Vessels

Supply vessels will be used to provide the platform operations with materials. Supply vessels will hold liquid drill mud, drill water, potable water, barite (weighting material), fuel, cement, bentonite (fresh water gel), drill pipe, casing and various equipment necessary for well construction operations, production operations and construction. It is anticipated that supply vessels will make periodic round trips from a dockside shorebase in Nova Scotia to the platform operation between two and four times a


week during normal operations. It is anticipated that there will be approximately six trips a week during construction and heavy maintenance periods. In addition, a standby vessel is required near the platform at all times as per CNSOPB regulations.

2.4.3.2 Helicopters

Personnel will be transported to and from the offshore facilities via helicopters from the heliport located at the Halifax International Airport. During pipelay and heavy lift activities, the frequency of helicopter activity is estimated to be two to three trips per week. During hook-up and commissioning, the frequency is estimated to be seven to ten trips per week. The frequency will reduce to approximately six to ten flights per month during operations. These helicopters are used primarily to transport crew members, company personnel and service personnel. In some cases, small equipment and parts are transported via air transportation.

2.4.4 Project Safety Zones

EnCana will consult with the appropriate regulatory authorities to develop a safety zone around the Deep Panuke facilities in accordance with the Nova Scotia Offshore Petroleum Drilling Regulations and the Nova Scotia Offshore Area Petroleum Production and Conservation Regulations. This zone will include, as a minimum, an area extending 500 m around the MOPU and will likely also include the interfield flowlines and wellheads. The exact configuration of the safety zone will be determined based on safety risk assessment studies and consultations with the regulatory agencies. There will also be a temporary 500 m safety zone around the drilling rig when it is on location for development drilling. A Notice to Mariners will be issued and appropriate mariner charts will be updated for the installations through the Canadian Hydrographic Service.

Standard operating procedures will be developed to lessen the risk of collisions between ships and Project infrastructure. These would include, but are not limited to, the following:

presence of structures and safety zones would be indicated on nautical charts; Coast Guard Notice to Mariners would apply during construction; and radio operators would notify approaching vessels of the presence of the structures. The distance at which mariners would be notified would be dependent on a number of factors, including the direction and speed of the approaching vessel and weather conditions.

Although there are no regulations under the CNSOPB that provide a similar safety zone around a pipelaying vessel, EnCana will request the Coast Guard issue a Notice to Mariners with regard to this temporary construction activity. Mariners will be informed as to the status of the pipelaying operation and the vessels taking part in the activity. The export pipeline’s design takes into consideration fishing activity in the area so that once the pipeline is laid, there will be no restrictions with regard to safety


zones over the pipeline although there will be fishing restrictions over the subsea connection to the SOEP pipeline for the SOEP Subsea Option. As with the installation and interfield flowlines, nautical charts will be updated for the export pipeline through the Canadian Hydrographic Service.

2.4.5 Onshore Facilities

In addition to the onshore pipeline, other onshore facilities will include a pig launcher/receiver facility and a safety/emergency shutdown valve system. Periodic mechanical, electrical, instrumentation and general housekeeping maintenance will be performed. For example, valves, piping, or general lighting will require routine maintenance. Site visits will take place periodically.

EnCana will take care to avoid use of invasive species in post-construction revegetation efforts and will place a clear priority on the use of native species. Vegetation management will be conducted mainly by mechanical means and will be confined to the RoW. Herbicide use will be restricted to valve sites and meter stations and will involve low application rates of compounds with low persistence and low ecological toxicity. Herbicides will not be used within close proximity (e.g., 30 m) of watercourses or wetlands.

2.5 Decommissioning and Abandonment

The mean production life of the Project is anticipated to be 13.3 years; however, the resource forecast show a probable production life ranging from 8 to 17.5 years. The design life is 20 years for the topsides and 25 years for the remaining Project structures. As is common in the industry, facility life could be extended beyond 20 years with appropriate technical and maintenance activities in the event reservoir productivity or additional resources prolong the life of the Project.

The following facilities will require decommissioning and abandonment:

• MOPU;• subsea production and injection wells;• subsea facilities;• offshore gas export pipeline;• onshore pipeline (M&NP Option only); and• onshore facilities (M&NP Option only).

Decommissioning and abandonment of these facilities will be performed in accordance with the regulatory requirements applicable at the time of such activities. An action plan for decommissioning will be submitted to the appropriate authorities for approval prior to commencement of decommissioning and abandonment activities.


Requirements for eventual removal of facilities will be taken into account during detailed design. Although regulatory requirements could change prior to the time of decommissioning and abandonment, current practices would see the facility degassed, degreased and cleaned to applicable standards, the MOPU towed to another location for re-use or retrofit, the wells abandoned and conductors cut below the seafloor, and the pipeline, flowlines and umbilicals flushed, cleaned, and abandoned in place. The potential presence of contaminants that could be encountered during recovery and transportation of the facilities will be taken into account. Potential reuse of the MOPU will be considered on an economic basis.

Wells will be abandoned in compliance with applicable drilling regulations and according to standard industry practices.

With the exception of the pipeline, onshore facilities will be removed and the land restored in accordance with applicable regulations. Buried onshore pipelines will be flushed, capped, and abandoned in place. The onshore pipeline RoW will be allowed to return to a natural state. Any above- ground structures associated with onshore pipelines will be removed. A Decommissioning Plan will be developed for the Project, which will provide detailed procedures for decommissioning onshore facilities.

2.6 Project Schedule

The Project Offshore Strategic Energy Agreement (OSEA), signed in June 2006, initiated the start of the next Project phase. Consisting primarily of the regulatory approval process, major contract tendering and negotiations, and a field centre bid competition, this phase is expected to be completed in the third quarter of 2007, with an expectation of project sanction in the third quarter of 2007. Assuming sanction and after contract awards, the Project will engage in detailed engineering and procurement. Subsequent onshore fabrication at existing facilities will occur prior to installation offshore.

Hull and topsides fabrication is scheduled to commence third quarter 2008, with the MOPU hull and topsides ready for at-shore integration first quarter 2010.

It is anticipated that the onshore and offshore sections of the export pipeline will be constructed either in 2009 or 2010. The tie-ins to the MOPU and to either the M&NP facilities or to the SOEP pipeline will be completed after the MOPU and the export pipeline installation is complete. Hook-up and offshore commissioning activities will commence third quarter 2010 once the MOPU has been transported to the field centre. First gas is anticipated to be produced in the fall of 2010.

Well construction and completions will be completed with a separate mobile offshore drilling unit and will be scheduled between 2008 and 2010.


2.7 Emissions and Discharges

EnCana will adhere to the OWTG (NEB et al. 2002) and all applicable regulations for emissions and waste management. Where no standards exist, best industry practice will guide EnCana. EnCana will minimize, to the extent practical, both the volumes of wastes being discharged and the concentration of contaminants entering the environment. A Waste Management Plan (WMP) (included in the EPP) will be developed for the Project that will address all phases of the Project including construction, installation, operation, decommissioning, and abandonment. The goal of this plan is to minimize offshore wastes, discharges, and emissions and identify appropriate mitigative measures.

Estimated quantities of wastes, discharges, and emissions that will be generated for both the construction/installation/drilling and production/operation phases of the Project are summarized in Table 2.8. The table also includes summary descriptions of the characteristics of the waste discharges and disposal procedures to meet regulatory compliance standards.

2.7.1 Air Emissions

Sources and types of air emissions during routine Project construction and operation will include:

exhaust from supply and stand-by vessels; short-term flaring of the produced fluid from production wells during clean-up; exhaust from machinery on the platform (e.g., gas turbines); fugitive emissions (e.g., emission of volatile organic compounds from valves, filter changeouts, storage of hydrocarbons, etc.); emissions associated with processing operations including continuous flaring for processing by-products from TEG and produced water treatment systems; and flaring of the full acid gas stream during routine maintenance of the acid gas management system (approximately 2% of operating time).

The gas vented from the TEG regenerator must be continuously flared to prevent emissions of aromatic hydrocarbons (BTEX) from the system. If the produced water stripping unit is required to remove residual H2S prior to disposal, the waste gas from this unit will be injected into the acid gas disposal well.

Refer to Appendix F for details on the atmospheric modelling undertaken for their Project. Further information on routine air emissions, including generation rates, is presented in Table 2.8 and Section 8.1. Information on air emissions during malfunctions and accidental events is provided in Section 8.1.4.4.

Dee

p Pa

nuke

Vol

ume

4 (E

nvir

onm

enta

l Ass

essm

ent R

epor

t) N

ovem

ber 2

006

2-47

Tab

le 2

.8 R

outin

e Pr

ojec

t Em

issi

ons/

Eff

luen

ts

Typ

e E

mis

sion

/Eff

luen

t E

stim

ated

Qua

ntity

C

hara

cter

istic

s D

ispo

sal S

tand

ard

Cons

truct

ion/

Insta

llatio

n/D

rillin

g G

ener

ator

, eng

ine

and

utili

ties e

xhau

sts

Tem

pora

ry, m

inor

C

O2,

SO2,

NO

x, TS

P A

tmos

pher

ic e

mis

sion

s will

com

ply

with

the

Air Q

ualit

y Re

gula

tions

(Nov

a Sc

otia

Env

iron

men

t Act

) and

Am

bien

t Air

Qua

lity

Obj

ectiv

es

(CEP

A).

Atm

osph

eric

E

mis

sion

s

Flar

ing

durin

g w

ell

clea

n-up

and

com

plet

ion

Expe

cted

~1/

2 da

y pe

r pr

oduc

tion

(new

and

re-e

ntry

) w

ell,

unle

ss o

ther

wis

e re

quire

d by

ope

ratin

g re

quire

men

ts.

Poss

ible

NO

x, C

H4,

TSP,

SO

2, C

O2,

TPH

, H2S

Com

plia

nce

with

CN

SOPB

Pro

duct

ion

and

Con

serv

atio

n Re

gula

tions

(Sec

tion

32),

Air Q

ualit

y Re

gula

tions

(Nov

a Sc

otia

Env

iron

men

t Act

)an

d A

mbi

ent A

ir Q

ualit

y O

bjec

tives

(CEP

A).

WB

M

Bul

k su

rfac

e re

leas

e of

ap

prox

imat

ely

700

m3 o

f WB

M

for p

rodu

ctio

n w

ell;

600

m3 fo

r in

ject

ion

wel

l. W

BM

on

cutti

ngs i

s exp

ecte

d to

be

244

m3 fo

r eac

h pr

oduc

tion

wel

l an

d 23

3 m

3 for i

njec

tion

wel

l.

Typi

cal c

onst

ituen

ts

incl

ude:

bar

ite, b

ento

nite

, K

Cl,

poly

mer

s, N

aHC

O3,

lime,

cau

stic

soda

, sal

t, an

d w

ater

WB

M w

ill b

e di

spos

ed o

verb

oard

.1

WB

M a

ssoc

iate

d cu

tting

s A

ppro

xim

atel

y 55

8 m

3of

WB

M a

ssoc

iate

d cu

tting

s di

scha

rged

for e

ach

new

pr

oduc

tion

wel

l to

be d

rille

d;

487

m3 fo

r inj

ectio

n w

ell.

Roc

k cu

tting

s coa

ted

with

W

BM

WB

M a

ssoc

iate

d cu

tting

s will

be

disp

osed

ove

rboa

rd.1

Dri

ll W

aste

D

isch

arge

s

Com

plet

ion

brin

e A

ppro

xim

atel

y 10

00 m

3 of

com

plet

ion

brin

e w

ill b

e di

scha

rged

at t

he su

rfac

e fo

r ea

ch n

ew p

rodu

ctio

n w

ell t

o be

dr

illed

; 300

m3 fo

r eac

h w

ell

re-e

ntry

and

the

inje

ctio

n w

ell

com

plet

ion.

Wat

er-b

ased

brin

e, p

ossi

bly

visc

osifi

ers

Com

plet

ion

fluid

will

be

disc

harg

ed o

verb

oard

as p

erm

itted

by

the

CN

SOPB

.1

Liq

uid

Eff

luen

t fo

r O

cean

D

isch

arge

Sani

tary

and

food

was

te

Max

imum

cap

acity

of t

he

faci

lity

durin

g op

erat

ion

is

appr

oxim

atel

y 68

per

sons

with

an

est

imat

ed v

olum

e of

20

L pe

r per

son

per d

ay; a

mou

nts

will

incr

ease

dur

ing

cons

truct

ion

phas

e w

ith

incr

ease

d pr

esen

ce o

f ves

sels

an

d cr

ews.

Mac

erat

ed fo

od, g

rey

wat

er

and

sani

tary

was

te

Sani

tary

and

food

was

te w

ill b

e m

acer

ated

to a

par

ticle

size

of 6

mm

or

less

prio

r to

ocea

n di

scha

rge.

1

Dee

p Pa

nuke

Vol

ume

4 (E

nvir

onm

enta

l Ass

essm

ent R

epor

t) N

ovem

ber 2

006

2-48

Tab

le 2

.8 R

outin

e Pr

ojec

t Em

issi

ons/

Eff

luen

ts

Typ

e E

mis

sion

/Eff

luen

t E

stim

ated

Qua

ntity

C

hara

cter

istic

s D

ispo

sal S

tand

ard

Dec

k dr

aina

ge

As g

ener

ated

Po

ssib

le o

ily w

ater

with

so

me

parti

cula

te m

atte

r R

oof d

rain

age

will

be

dire

cted

ove

rboa

rd.1

Dec

k dr

aina

ge w

ill b

e tre

ated

to re

duce

its o

il co

ncen

tratio

n to

mee

t reg

ulat

ory

requ

irem

ents

oc

ean

disc

harg

e.1

Bilg

e/ba

llast

wat

er

(Con

stru

ctio

n/Su

ppor

t ves

sels

)

As r

equi

red

Wat

er w

ith h

ydro

carb

ons

Bilg

e/ba

llast

wat

er w

ill b

e tre

ated

as n

eces

sary

to re

duce

its o

il co

ncen

tratio

n to

15

mg/

L or

less

prio

r to

ocea

n di

scha

rge.

1

Hyd

rost

atic

test

flui

ds

(Pip

elin

e co

mm

issi

onin

g w

ater

)

47,2

40 m

3 (ove

r sev

eral

day

s)

see

Sect

ion

2.3.

4 fo

r mor

e de

tails

.

Seaw

ater

con

tain

ing

bioc

ide

and

corr

osio

n in

hibi

tors

The

disc

harg

e of

hyd

rote

st fl

uids

will

requ

ire p

re-a

ppro

val f

rom

En

viro

nmen

t Can

ada.

Solid

Was

teM

isce

llane

ous s

olid

w

aste

s (tra

nspo

rted

to

shor

e)

As r

equi

red

Con

stru

ctio

n m

ater

ials

, br

oken

equ

ipm

ent

com

pone

nts,

pack

agin

g an

d sh

ippi

ng m

ater

ials

, da

mag

ed c

onta

iner

s and

ge

nera

l deb

ris a

nd re

fuse

as

soci

ated

with

co

nstru

ctio

n

Was

tes w

ill b

e so

rted

and

disp

osed

acc

ordi

ng to

loca

l reg

ulat

ory

regi

me

of th

e sh

ore

base

, inc

ludi

ng th

e N

ova

Scot

ia S

olid

Was

te-

Reso

urce

Man

agem

ent R

egul

atio

ns a

nd m

unic

ipal

requ

irem

ents

. M

etal

s will

be

salv

aged

.

Prod

uctio

n/O

pera

tion

Flar

ing

(aci

d ga

s dur

ing

rout

ine

mai

nten

ance

) re

fer t

o Ta

ble

8.3

H2S

, SO

2, N

Ox,

CO

2 A

tmos

pher

ic e

mis

sion

s will

com

ply

with

the

Air Q

ualit

y Re

gula

tions

(Nov

a Sc

otia

Env

iron

men

t Act

) and

Am

bien

t Air

Qua

lity

Obj

ectiv

es

(CEP

A).

Nor

mal

Geo

turb

ine

oper

atio

nsre

fer t

o Ta

ble

8.3

SO2,

NO

x, C

O2

Atm

osph

eric

em

issi

ons w

ill c

ompl

y w

ith th

e Ai

r Qua

lity

Regu

latio

ns(N

ova

Scot

ia E

nvir

onm

ent A

ct) a

nd A

mbi

ent A

ir Q

ualit

y O

bjec

tives

(C

EPA)

.

Air

Em

issi

ons

Prod

uced

wat

er

refe

r to

Tabl

e 2.

6H

ydro

carb

on, H

2S in

wat

er

(sou

r wat

er)

Prod

uced

wat

er w

ill b

e tre

ated

to a

targ

et d

ispe

rsed

oil

conc

entra

tion

of

25 m

g/L

(30-

day

wei

ghte

d av

erag

e).

The

OW

TG sp

ecify

a 3

0-da

y w

eigh

ted

aver

age

of 3

0 m

g/L.

1

Coo

ling

wat

er

2,40

0 m

3 /hC

hlor

inat

ed w

ater

; te

mpe

ratu

re 2

0C

abo

ve

ambi

ent (

befo

re m

ixin

g in

ca

isso

n)

Mix

ed w

ith p

rodu

ced

wat

er b

efor

e di

scha

rge.

Tot

al re

sidu

al fr

ee

chlo

rine

in c

oolin

g w

ater

will

not

nor

mal

ly e

xcee

d 0.

25 p

pm.

Liq

uid

Eff

luen

t fo

r O

cean

D

isch

arge

Dec

k dr

aina

ge

Pum

p ca

paci

ty is

150

m3 /h

Rai

n an

d de

luge

wat

er, m

ay

cont

ain

oily

wat

er w

ith

som

e pa

rticu

late

s

Roo

f dra

inag

e flo

ws d

irect

ly o

verb

oard

as p

erm

itted

by

CN

SOPB

gu

idel

ines

.1 D

eck

drai

nage

will

be

treat

ed to

redu

ce h

ydro

carb

ons t

o <1

5 m

g/L.

1

Dee

p Pa

nuke

Vol

ume

4 (E

nvir

onm

enta

l Ass

essm

ent R

epor

t) N

ovem

ber 2

006

2-49

Tab

le 2

.8 R

outin

e Pr

ojec

t Em

issi

ons/

Eff

luen

ts

Typ

e E

mis

sion

/Eff

luen

t E

stim

ated

Qua

ntity

C

hara

cter

istic

s D

ispo

sal S

tand

ard

Bilg

e/ba

llast

wat

er

As r

equi

red

Wat

er w

ith h

ydro

carb

ons

Bilg

e/ba

llast

wat

er w

ill b

e tre

ated

as n

eces

sary

to re

duce

oil

conc

entra

tion

to 1

5 m

g/L

or le

ss p

rior t

o oc

ean

disc

harg

e.1

Wel

l tre

atm

ent f

luid

s/

Wel

l com

plet

ion

and

wor

kove

r flu

id

As r

equi

red

Wel

l com

plet

ion

fluid

s ha

ve si

mila

r pro

perti

es to

W

BM

Flui

ds w

ill b

e tre

ated

to a

n oi

l con

cent

ratio

n of

40

mg/

L or

less

prio

r to

disc

harg

e.1

Wat

er fo

r fire

con

trol

syst

ems

As r

equi

red

Exce

ss d

eck

drai

nage

wat

er

Dis

char

ged

over

boar

d w

ithou

t tre

atm

ent.1

Des

alin

atio

n br

ine

13 m

3 /hr

Estim

ated

salin

ity o

f 35-

40

ppt

Dis

char

ged

over

boar

d w

ithou

t tre

atm

ent.1

Was

te p

rodu

ctio

n flu

ids

and

by-p

rodu

cts

As r

equi

red

Was

te re

sidu

es in

the

prod

uctio

n sy

stem

in

clud

ing

oily

slud

ge, s

cale

, fil

ters

and

filte

r res

idue

s an

d ch

emic

al w

aste

s

Haz

ardo

us w

aste

s w

ill b

e ac

cum

ulat

ed i

n su

itabl

e co

ntai

ners

and

pl

aced

in

appr

opria

te s

hipp

ing

cont

aine

rs f

or r

etur

n to

sho

re f

or

disp

osal

and

col

lect

ed b

y lic

ence

d w

aste

hau

lers

. Pro

vinc

ial r

egul

atio

ns

for

the

stor

age,

dis

posa

l, tra

nspo

rt an

d m

anag

emen

t of

use

d oi

l pr

oduc

ts w

ill b

e fo

llow

ed a

s w

ell a

s th

e Tr

ansp

orta

tion

of D

ange

rous

G

oods

Act

as a

pplic

able

. H

azar

dous

L

iqui

ds fo

r O

nsho

re

Dis

posa

l

Mis

cella

neou

s sol

id

was

te (t

rans

porte

d to

sh

ore)

As r

equi

red

Dom

estic

solid

was

te a

nd

non-

haza

rdou

s sol

ids s

uch

as p

acki

ng m

ater

ial

Was

tes w

ill b

e so

rted

and

disp

osed

acc

ordi

ng to

loca

l reg

ulat

ory

regi

me

of th

e sh

oreb

ase,

incl

udin

g th

e N

ova

Scot

ia S

olid

Was

te-

Reso

urce

Man

agem

ent R

egul

atio

ns a

nd o

ther

mun

icip

al re

quire

men

ts.

Solid

Was

te

Mis

cella

neou

s sol

id

was

te (t

rans

porte

d to

sh

ore)

As r

equi

red

Dom

estic

solid

was

te a

nd

non-

haza

rdou

s sol

ids s

uch

as p

acki

ng m

ater

ial

Was

tes w

ill b

e so

rted

and

disp

osed

acc

ordi

ng to

loca

l reg

ulat

ory

regi

me

of th

e sh

oreb

ase,

incl

udin

g th

e N

ova

Scot

ia S

olid

Was

te-

Reso

urce

Man

agem

ent R

egul

atio

ns a

nd o

ther

mun

icip

al re

quire

men

ts.


2.7.1.1 Air Pollutants

The following describes criteria air pollutants (i.e., regulated by federal guidelines or provincial limits) emitted by the Project, although some may be emitted in minor amounts and may not necessarily result in the effects described below unless otherwise indicated in Section 8.1.

Nitrogen Oxides

Nitrogen oxides are produced in most combustion processes, and almost entirely made up of nitric oxide (NO) and nitrogen dioxide (NO2). Together, they are often referred to as NOx. NO2 is an orange to reddish gas that is corrosive and irritating. Most NO2 in the atmosphere is formed by the oxidation of NO, which is emitted directly by combustion processes, particularly those at high temperature and pressure, such as diesel engines. NO2 is the regulated form of NOx. NO is a colourless gas with no direct effects on health or vegetation at ambient levels. The levels of NO and NO2, and the ratio of the two gases, together with the presence of hydrocarbons and sunlight are the most important factors in the formation of ground-level ozone and other oxidants. Further oxidation, and combination with water in the atmosphere, contributes to the production of “acid rain”.

Generally NO2 constitutes 5 to 10% of the initial total emissions of NOx, and the conversion of the majority of NO occurs after emission to the atmosphere. Emissions information on boilers usually refers only to total NOx, partly because the conversion rate of NO to NO2 is somewhat site specific. For instance, the amount of NO2 generated by a stationary combustion turbine can be calculated using the National Emission Guidelines for Stationary Combustion Turbines set by the Canadian Council of Ministers of the Environment (CCME). This is accomplished by taking into account the turbine’s power output and heat output, which could potentially be recovered. Other methods for the assessment of NOx

effects include the ozone limiting method.

For this Project, nitrogen oxides are produced primarily in the generation of power for electrical loads and compressors. It is estimated that the compression load of 14 to 21 MW and expected electrical load of 7 MW will be met through the use of combustion turbines.

Sulphur Dioxide

Sulphur dioxide (SO2) is a colourless gas with a distinctive pungent sulphur odour. It is produced in combustion processes by the oxidation of sulphur in the fuel. SO2 can, at high enough concentrations, cause damage to vegetation and adverse health effects impacting the respiratory system.

This Project incorporates a sulphur management system that removes H2S from the gas stream and injects it into a disposal well. In the event of maintenance requiring downtime, or a malfunction of the


acid gas injection system, the gas stream will be redirected to the flare which will result in limited emissions of SO2.

Total Suspended Particulate Matter

Total suspended particulate matter (TSP) is a measure of the particles in the atmosphere that are too small to settle out quickly, but remain suspended for significant periods of time. Generally, this means particles with an aerodynamic diameter of less than 44 µm. TSP is produced by mechanical processes, such as the abrasion of vehicle tires on unpaved roads, and by combustion processes. Most particulate matter formed by combustion is either mineral ash from the fuel, or hydrocarbons formed by incomplete combustion.

This Project will result in construction-related emissions of particulate matter for necessary onshore components of the Project; these emissions will be similar in type and scale to those created by other medium to large sized construction projects. Offshore, the vessel exhausts will contain some particulate matter; these emissions are no more critical than those of similar vessels in everyday operation.

Fine and Respirable Particulate Matter

Although TSP is an excellent measure of the loading of particulate matter in the air, it does not necessarily reflect the health risks of the particulate matter. Large aerodynamic particles are trapped by the upper airways, and do not enter the lungs. Smaller diameter particles make their way to the lungs, and may become lodged there. Over the past few years, greater concern with regard to these fine particles has led to research resulting in new sampling methods and criteria. In June, 2000, the CCME adopted in principle Canada Wide Standards for particulate matter. Although these standards are not yet applicable, they will be relevant in the future. These standards provide for a proposed PM2.5 standard of 30 µg/m3 for particulate <2.5 µm and a proposed PM10 standard of 65 µg/m3 for particulate <10 µm, with the current objective of meeting the standard by 2010. It should be noted that TSP includes the PM2.5 and PM10 fractions. If the TSP reading is less than 30 µg/m3, the PM2.5 standard is attained, likely by a considerable margin. The concentration of PM2.5 is typically of greater concern since it represents the finest particles, which are more critical to health effects. The fine particulate matter is discussed for completeness; however, the total emissions of particulate matter from the Project activities are low.

Hydrogen Sulphide

H2S is a colourless, poisonous gas with a characteristic odour of rotten eggs at low concentrations. Humans are particularly sensitive to the odour of H2S at low concentrations; however, the gas causes rapid fatiguing of the olfactory system at higher concentrations. Environmental exposures are generally to the noxious odours. At higher exposures, such as in industrial operations, low concentrations can


result in eye irritation, respiratory system irritation, and higher concentrations can result in asphyxia. H2S is a by-product of decomposition of sulphur-containing organic material, and is associated with certain natural gas deposits, including this Project. H2S has been safely managed in the natural gas resource sector. The relatively low levels of acid gas and the acid gas management system for this Project will result in the removal and elimination of H2S from the gas stream. In the unlikely event of a failure of the injection system and the extinguishing of the flare, there may be a brief period of controlled H2S emissions to atmosphere from this Project. In the event of the even much less likely scenario of a blowout of the injection well, there will be a release of H2S to the environment. In the event of a blowout from a production well, H2S will be released as a component of the raw gas.

2.7.1.2 Air Emissions Modelling

In order to predict the dispersion and subsequent effect of air emissions from the Project, a simulation was conducted using a mathematical computer model of atmospheric transport. This method provides quantitative results and enables direct comparison of the simulated project effects with regulatory criteria. For certain sources where the quantitative releases are too difficult to predict, an assessment has been made based on the relative likelihood of releases, and the potential consequences. Modelling results and environmental effects associated with significant air emissions are presented in Appendix F and Section 8.1.

2.7.2 Noise Emissions

Noise emissions will mainly be generated offshore during pile driving, blasting, and drilling operations. Other noise generating activities will include ship and air traffic of materials and personnel to offshore facilities. Onshore noise will be limited primarily to construction of the pipeline and other onshore facilities. The discussion presented in the approved 2002 CSR regarding noise emissions (offshore and onshore) remains valid (refer to Section 2.7.2 of the approved 2002 CSR). An updated discussion on noise associated with pile driving is presented in Section 2.3.6.

2.7.3 Electromagnetic Emissions

The description of electromagnetic emissions presented in the approved 2002 CSR remains valid. Refer to Section 2.7.3 of the approved 2002 CSR.


2.7.4 Drill Waste Discharges

2.7.4.1 Use of Drill Muds

All drilling fluids (mud) go through a cyclic process during the drilling of a well. Prior to drilling a specific hole section, the required type of mud must be prepared. It is either prepared onshore and brought to the rig, or the required base products are brought to the rig and it is prepared onboard. Once the mud is ready for use, the drilling may begin for that hole section. The following describes the simple cycle that all drilling fluids follow:

1. The mud is pumped down the drillpipe to the bit on the bottom. 2. The mud comes out the bit and picks up the cuttings that the bit has produced and carries these

cuttings back to the rig on the outside of the drillpipe. 3. Once back on the drilling rig, the cuttings (solid materials) are separated from the mud using solids

control equipment. Linear vibrating shakers plus periodic use of centrifuges are the main components of the solids control equipment used to separate solids (cuttings from the wellbore) from the drilling mud.

4. The clean mud returns to the original tanks for any minor modifications (additional products) before starting the cycle again.

5. The cycle continues until the hole section reaches final depth.

Once the final depth of the hole section is achieved, the mud is cleaned for re-use on the next hole section or it is removed from the rig to allow for the next drilling fluid for the subsequent operation. Bulk mud releases will be minimized by re-using mud on the next hole section or well if possible. WBM will be released overboard during bulk releases.

Typically, a conventional production well would be installed as follows:

1. Drill and case the conductor hole, then prepare WBM and change drilling tools.2. Drill and case the surface hole, then change the mud system and drilling tools. 3. Drill and case the intermediate hole section, then change the drilling tools. 4. Drill and case the main hole section re-using the mud system from the intermediate hole section. 5. Circulate the well to clean out drilling solids, displace drilling fluid from the wellbore to completion

fluid and install the completion tubing / equipment. 6. Provide underbalance and allow the well to flow to surface removing all completion fluids until

burnable gas at surface prior to handover to production. 7. Secure the well and move the rig to the next well location and repeat the process.


Typically, a re-entry and completion of existing wells will be conducted as follows:

1. Remove temporary abandonment caps and convert mudline suspension system to subsea wellhead. 2. Install high pressure riser to rig tension deck and BOP stack.3. Drill out 340mm casing cement plugs and pull bridge plugs using suspension brine. 4. Confirm well is secure and remove high pressure riser and BOP stack and install subsea production

tree.5. Drill out 245mm casing cement plugs and pull bridge plugs using suspension brine, change tools. 6. Drill out 178mm casing cement plugs and pull bridge plugs using suspension brine. 7. Filter and clean suspension brine to completion fluid specifications. 8. Install the completion tubing/equipment. 9. Provide underbalance and allow the well to flow to surface removing all completion fluids until

burnable gas at surface prior to handover to production. 10. Secure the well and move the rig to the next well location and repeat the process.

Spent WBM and associated drill cuttings will be discharged in accordance with the OWTG (NEB et al.2002).

The conservative case of five new wells using WBM for all hole sections has been modelled with results presented in Appendix D.

2.7.4.2 Drill Waste Discharge Behaviour and Modelling

When cuttings and mud are discharged, the fine materials in the discharge form a turbidity plume near the sea surface, but the bulk of the material (cuttings) drops to the seabed with the fine materials being stripped from the plume as it descends. Typically, a cuttings pile forms on the seabed near the discharge point. However, in high energy environments, like the Deep Panuke site, cuttings and fine particles and associated metals, such as barium, are more likely to disperse rather than settle (refer to Appendix D).

Barite is typically used to increase the density of the drilling fluid. It is also used to build small volumes of high density slugs used to trip drill pipe out of the hole dry. The type of drilling fluids used for Deep Panuke wells will be salt-based and the density will be adjusted by increasing the concentration of salt in the drilling fluid. Therefore, the use of barite will be minimized and generally only used for the preparation of high density slugs to pull the drill pipe out of the hole dry.

Oceanographic plume modelling for discharge of mud and cuttings at sea was conducted for surface discharge of WBM. See Section 2.3.4 for further details. The modelling of drill mud and cuttings discharges is based on the following assumed operational processes and volumes shown in Table 2.9. Modelling results of ocean disposal of drill waste discharges are presented in Appendix D.


Table 2.9 Deep Panuke Potential Drilling Waste Discharge Summary

Each New Production Well

One New Injection Well

Each Re-entry Production Well

Total Discharges

Seabed release of WBM associated cuttings (m3)

131 131 0 656

Surface release of WBM associated cuttings (m3)

427 356 0 2062

Seabed release of WBM on cuttings (m3)

180 180 0 900

Surface release of WBM on cuttings (m3)

64 53 0 309

Surface release of WBM (bulk mud release) (m3)

700 600 0 3400

Surface release of completion fluid (m3)

1000 300 300 5500

Notes:All volumes are approximations that represent each well’s discharges. Using a conservative approach to dispersion modelling, it is assumed four existing wells will be re-completed using completion fluid (“re-entry” production wells), and four new production wells and one new injection well will be drilled using WBM with overboard discharge. The completion fluid is a brine (NaCl) with various additives for oxygen scavengers, H2S scavengers and corrosion protection in some cases. Prior to use, all chemicals will be screened using the CNSOPB Offshore Chemical Selection Guidelines

2.7.5 Effluent Discharges

2.7.5.1 Produced Water

Produced water management is described in Section 2.4.1.8. Produced water will be treated to a target dispersed oil concentration of 25 mg/L (30-day weighted average). The OWTG specify a 30-day weighted average of 30 mg/L. Refer to Appendix D for results of produced water dispersion modelling.

2.7.5.2 Cooling Water

The cooling system will use seawater to indirectly cool a circulating medium (40% ethylene glycol, 60% water (volume)) solution. The cooling water flow rate will be constant at 2,400 m3/hr and will have a temperature approximately 15°C above background water temperature. It will be mixed with produced water before discharge.

The seawater is treated with chlorine generated by a sodium hypochlorite generator to prevent/reduce the growth of marine biological growth. The design chlorine concentration at the seawater lift pump inlet is 2 ppm (1 ppm during normal operation with an increase during periods of high larval mussel concentration). The residual free chlorine concentration at the outlet will normally be below 0.25 ppm. The combined produced water and cooling water stream exit temperature will not exceed 25 oC above ambient.


2.7.5.3 Deck Drainage

During construction and installation, prior to operation of the drains system, deck drainage will be discharged overboard. Deck drainage water might contain traces of petroleum hydrocarbons, such as lube oils, helicopter fuel, and diesel fuel. Every effort will be made to prevent chemical contamination on decks, which could be entrained into deck drainage. Storage areas for totes containing chemicals and petroleum products will have secondary containment to prevent discharge onto deck surfaces.

During the operation phase, deck drainage will be collected and treated according to the OWTG (NEB etal 2002). Drainage from equipment areas on the topsides will be directed through a header system to a collection tank to an oil/water separator treatment unit on the MOPU. Petroleum hydrocarbons and sludge in the oil/water separator will be transferred into containers for shipment to shore for disposal. The water from the oil/water separator will be treated using cartridge-style water polishers and tested prior to discharge to ensure compliance with the discharge criteria of 15 mg/L or less. The deck drainage system does have overflows to permit water to be routed directly overboard in the event of a deluge event or rain water in excess of the design condition.

Any spills of petroleum products (or other chemicals) will be cleaned up immediately and reported. Oil absorbent pads and “oil dry” compounds will be available, at all times, in spill kits located at strategic sites on the platforms, to remove petroleum products from deck surfaces. The used absorbent materials and any other oily wastes will be placed in sealed containers and returned to shore for treatment and disposal at an approved waste management facility.

EnCana will develop a Deep Panuke Emergency Management Plan (DPEMP) for the Project which will include a Spill Response Plan (refer to Appendix G) that will be submitted to the regulators for review and approval. It is the responsibility of all EnCana employees and contractors to report any accidents, incidents or spills to the Offshore Installation Manager for immediate action. The standby vessel in the field will also be tasked as part of their regular duties to observe and report any spills from the facilities.

2.7.5.4 Other Ocean Discharges

Other ocean discharges (e.g., bilge/ballast, sanitary/food waste/testing waters, etc.) are summarized in Table 2.6 for the construction and operations phases of the Project. Those wastes, which are identified in the OWTG (NEB et al. 2002) and other regulations, are included along with the compliance standard. Each waste stream will be treated or managed to make sure the discharges comply with the respective regulatory limits and EnCana’s environmental protection policies.


2.7.6 Naturally Occurring Radioactive Material (NORM)

The description of NORM and appropriate management procedures presented in the approved 2002 CSR remain valid. Refer to Section 2.7.6 of the approved 2002 CSR.

2.7.7 Non-Hazardous Solid Wastes

The discussion of non-hazardous solid wastes presented in the approved 2002 CSR remains valid. Refer to Section 2.7.7 of the approved 2002 CSR.

2.8 Hazardous Materials and Waste

The discussion of management of hazardous materials and waste presented in the approved 2002 CSR remains valid. This includes, but is not limited to, commitments by EnCana to adhere to all applicable federal and provincial codes and regulations for the handling and transport materials. Refer to Section 2.8 of the approved 2002 CSR.

2.9 Environmental and Safety Protection Systems

2.9.1 Equipment Inspection and Maintenance

All Project equipment will meet the requirements of industry standards, and be certified as being safe and fit for its intended use. Purchase orders for such equipment will be suitably monitored during the manufacturing and testing processes for strict compliance to these standards and to all applicable regulations as set out by the CNSOPB. Where required, the Certifying Authority (CA) may provide additional surveillance. Once installed, equipment will be operated and maintained in accordance with documented processes and procedures. EnCana will submit inspection and monitoring programs, a maintenance program and a weight control program to the CA for approval. These regular inspection and maintenance programs will ensure continued equipment reliability and integrity. Necessary critical spares will be maintained should equipment change-out be required. Subsea inspection programs allow for regular monitoring of critical subsea components such as pipelines.

As part of the maintenance of the Certificate of Fitness for the MOPU, the CA is required to conduct inspections and surveys during the operation phase of the Project (Annual Surveys). These surveys will verify that installations is being operated in accordance with the approved programs noted above and provide further assurance that safety and protection of the environment are being upheld.


2.9.2 Pipeline Leak Prevention

The pipeline design philosophy, in accordance with CNSOPB regulations, incorporates designs for: internal pressure containment; dropped objects protection; fatigue; spanning; and hook, pull or snag loads due to fishing activities. The pipeline will be designed to withstand impacts from conventional mobile fishing gear in accordance with the Det Norske Veritas (DNV) Guideline No. 13, Interference Between Trawl Gear and Pipelines, September, 1997. During the operational phase, inspections are carried out as part of the Annual Survey to ensure that the pipeline integrity is maintained.

Leak detection for the pipeline will be carried out by the use of mass balancing. This method uses process conditions at either end of the pipeline along with gas composition to calculate the mass entering the pipeline and exiting it. The M&NP custody transfer meter along with onshore instruments will be utilized to gather flow, temperature and pressure measurements. Similarly on the MOPU, the flow, temperature, and pressure will be used in conjunction with the gas composition to calculate the mass entering the pipeline. The onshore measurements along with the offshore gas composition will be used to calculate the mass exiting the pipeline. The mass entering and exiting the pipeline will be used to detect leaks. The leak detection system will be designed accordingly for the export option selected.

In the event that a leak is confirmed, the pipeline has a series of shutdown valves that will isolate the pipeline from the M&NP pipeline and the MOPU to prevent additional hydrocarbons from entering the system.

2.9.3 Blowout Prevention Safeguards

There are many safeguards in place to prevent blowouts or uncontrolled releases of hydrocarbons during the various stages of a wellbore’s life cycle. The equipment used to drill, complete and workover a wellbore is essentially the same regardless of whether it is an injection or production well. Also, there is a separate set of permanently installed equipment that is used during the production or injection phase of the life cycle.

The objective during the drilling of the well is to provide a wellbore through the selected reservoir interval in the safest and most efficient manner. Several strings of pipe (casing) are set at increasingly deeper depths to achieve this goal. The first section of pipe, the conductor, is set to approximately 75 m below the seafloor with no well control or blowout prevention equipment. For the next hole section (surface hole), a large diverter assembly is installed on top of the conductor pipe. This provides a means to divert any shallow gas that may be encountered over the side of the rig in a controlled manner until the mud weight can be increased to control the flow. The probability of encountering shallow gas during this hole section is unlikely since the rig is positioned to avoid any shallow gas anomalies based on a shallow seismic survey.


Once the surface section has been drilled and cased, blowout preventers are installed which can withstand/holdback the reservoir pressures expected during the drilling process should a well control incident occur. The primary method of well control is the hydrostatic pressure exerted by the column of mud in the wellbore. The density of the mud that is used to drill the hole section is tailored to ensure that the ingress of wellbore hydrocarbons is prohibited. If the density of this fluid is too low a “kick” occurs by which an amount of reservoir fluid enters the wellbore. As soon as this kick is detected, the well is shut in and monitored to determine the conditions surrounding the kick. The BOPs are used to shut in the well. Once the well is shut in, the mud is circulated to bring the reservoir fluids to surface. The hydrocarbons are vented or burnt at the flare in a controlled manner. The density of the mud is increased the appropriate amount and the drilling process may begin again.

These blowout prevention safeguards are well-known operational procedures for which standard industry practices are in place. EnCana’s Well Control Manual deals with these types of situations and is constantly updated based on the most recent technological innovations. All personnel are trained on a continuous basis and exercises and drills are routinely performed during operations on the drilling rig.

During the production or injection life of a well, there are several safety measures in place to insure no uncontrolled release of hydrocarbons occur. The primary prevention mechanism within an offshore wellbore is the surface-controlled subsurface safety valve (SC-SSSV). The fail-close valve has a control line to surface that is constantly pressured to keep the valve open. In the case of an accident, the ESD procedure would have the valve close as soon as the hydraulic pressure is removed from the line. All reservoir fluids are contained within the production or injection tree on top of the wellhead. This tree (series of fail-close surface valves) is connected to the tubing string within the wellbore that is used to transport the fluids to or from the reservoir. The SC-SSSV is an integral part of the tubing string usually located at a depth below the seafloor. At the bottom of the tubing string, a production packer is placed between the tubing and casing to prevent migration of reservoir fluids in the annulus (space between the tubing and casing). This equipment provides a fit for purpose design conduit for the fluids to be removed from or injected into the reservoir.

2.9.4 Flowline Protection

The flowlines design philosophy, in accordance with CNSOPB regulations, incorporates designs for internal pressure containment, dropped objects protection, fatigue and spanning. The flowlines will be buried to avoid impacts from conventional mobile fishing gear and their locations will be charted. During the operational phase, inspections will be carried out as part of the Annual Survey to ensure that the pipeline integrity is maintained. Environmental and safety protection systems, such as emergency shutdown (ESD) valves, will be provided on the flowlines.


2.9.5 Subsea Protection Structures

The production and acid gas injection well trees and the hot tap (SOEP Subsea Option) will be protected by dedicated protection structures. These shall be separately deployed structures and designed to withstand impacts from conventional mobile fishing gear. They will also serve as dropped objects protection and shall be designed to allow adequate access to the wells for all planned diver and ROV intervention tasks. The wells and hot tap locations will be charted.

2.9.6 Project Safety Zones

Refer to Section 2.4.4 for information.

2.10 Project Alternatives

2.10.1 Alternatives to the Project

The Alternatives to the Project as presented in the approved 2002 CSR have not changed. Accordingly, alternatives to the Project are not addressed in this section as there is no need to re-assess.

2.10.2 Alternatives Means of Carrying Out the Project

Since the approval of the CSR in 2002, EnCana has investigated options and alternatives that are more economically feasible based on resource estimates which are lower than those predicted in 2002. The Project, as conceived at present, shares many similarities with the original Project concept; however, some aspects have changed.

This section describes the Project design basis as originally conceived in 2002 and discusses the alternatives that were studied leading to the final concept selection.

The 2002 Project basis was designed to produce a sour gas reservoir via an offshore processing concept and transport sales quality gas to market via a 610 mm [24 inch] 176 km pipeline with an onshore tie-in to the M&NP pipeline near Goldboro, NS. The producing reservoir was located in a relatively small areal plot enabling production to be sourced from a cluster of directionally-drilled wells from a central wellhead platform. Offshore processing was to be performed on a second bridge-linked production platform. The production platform contained the main process-related utility systems. The main elements that formed the process were as follows:

• H2S removal; • condensate recovery and processing as the primary source for fuel on the platform;• gas dehydration;


• gas dewpointing;• produced water treatment and disposal; and• extraction and disposal of acid gas and surplus condensate.

The process plant also required inlet and export compression to maximize resource recovery and to transport sales gas through the offshore pipeline to market. The production platform was bridge-linked to a third platform which housed the central control room, non-hazardous utilities, and accommodations for offshore workers.

The 2002 Project basis was designed to process 400 MMscfd at peak capacity with design allowances to allow peak production year round. This overall concept required significant infrastructure with a total topsides weight of approximately 13,000 tonnes to accommodate all the required facilities offshore. The topsides were to be built as three separate integrated decks and installed offshore by means of a semi-submersible crane vessel.

Key similarities in the design basis between the current Project basis and the Project basis for the approved 2002 CSR are as follows:

• fluid composition and properties;• offshore gas processing;• acid gas injection into a subsea reservoir;• produced water treatment and ocean disposal; and• condensate handling, (for the M&NP Option only).

Compared to the Project basis for the approved 2002 CSR, the current Project design basis has:

• a larger reservoir area requiring subsea completions with tie-backs;• reduced resource estimate;• reduced peak production capacity;• increased volume of produced water; and• a MOPU replacing the three fixed platforms.

2.10.2.1 Alternative Assessment Methodology

The following methodology was used to assess Project alternatives:

• review the alternatives and supporting work for the 2002 DPA and determine which fundamental principles and decisions are still valid for the revised resource forecast and current concepts;


consider concept alternatives for reduced peak production capacity(5.7 x 106 m3/d and 8.5 x 106 m3/d [200 MMscfd and 300 MMscfd]); consider a subsea tie-in to the SOEP pipeline as a product export option;consider platform and processing facilities which could be leased to reduce capital expenditures; andreassess safety/occupational health and environmental criteria in light of revised concepts.

The decision to proceed with the development basis described herein was based on evaluation of the following criteria:

technical suitability (including operational factors, flexibility and ease of decommissioning); capital and operating costs, taking into consideration leased arrangements of some infrastructure; commercial risk; concept deliverability; safety; and environmental considerations.

If an alternative was deemed to be technically and economically unfeasible, further assessment of that alternative using other criteria was not considered.

As a precursor to the formal evaluation of various development alternatives against selected evaluation criteria, it is also worth noting that development alternatives which will not allow EnCana to take advantage of the infrastructure installed by M&NP were not evaluated due to economic reasons. Examples of development options which fell outside the Project’s central development concept (and hence were determined not to be economically feasible) are alternatives involving landfall sites other than Goldboro, and the use of technologies requiring substantial new infrastructure such as liquefied natural gas (LNG) or compressed natural gas (CNG) technologies. The following development alternatives were evaluated:

substructure type; topsides type; total number of platforms; re-use of existing platform processing location; acid gas handling; produced water disposal; condensate handling; production capacity alternatives; field centre structure type;


export pipeline alternatives; subsea tie-back alternatives; and acid gas injection location.

For the 2002 Project basis, consideration was given to using, in addition to WBM, oil-based muds, due to the drilling conditions associated with directionally drilled wells. However, based on the experience gained while drilling the Deep Panuke delineation wells, it was determined that only WBM will be used for any new development drilling activities. Therefore, the disposal options for oil-based mud drilling cuttings described in the approved 2002 CSR are no longer applicable to the Deep Panuke Project.

2.10.2.2 Substructure Type

The environmental conditions at the field centre location are considered harsh, by offshore standards, but are well within the criteria which fit many world-wide accepted design solutions for substructures. Several types of substructures were investigated and were classed into three groups; 1) floating structures; 2) permanent bottom founded structures; and 3) mobile structures. Each option was evaluated against the evaluation criteria summarized in Table 2.10 and these are discussed in the following sections.

Floating Structures

The floating type structure evaluated was the semi-submersible type which requires a fixed mooring system with fluids being conveyed on and off the structure through a series of subsea flexible risers. This type of structure is not well suited for the relatively shallow water depth at the field centre location and has not been proven for use in harsh, shallow water applications. It would be technically challenging to provide a mooring and riser design that would meet the project environmental conditions. Also, there have been some unfavourable experiences in other projects using a semi-submersible as a gas production platform. Therefore, this concept was eliminated for technical reasons.

Bottom-Founded Structures

Two types of permanent bottom-founded structures were investigated: gravity-based and jacket structures. The gravity-based concept was deemed to be technically acceptable; however, it was rejected due to higher commercial risk imposed by limited suppliers in the world market.

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s N

o


Jacket-type structures piled into the sea floor are the most common solution world-wide for the environmental conditions experienced at the Project site. This concept is currently in use in Nova Scotia by SOEP. The concept has the advantage of offering the lowest cost, technically acceptable solution with acceptable commercial risk. However, the disadvantage is that fixed structures have little to no residual value at the end of a project as they are unlikely to be reused on another project. Since this option does not fit with EnCana’s financing objectives for the projected life of the Deep Panuke Project, it was rejected based on commercial considerations.

Mobile Structures

Two types of mobile structures were investigated; a jack-deck structure and a jack-up type structure. Each of these configurations can be used to construct a MOPU. The MOPU concept provides a facility that is designed to self-install, produce oil or gas at a given location and then demobilize for reuse at another location. This concept is in use world-wide for fields that have marginal reserves or are expected to have a short production life. Also, contractors may offer these types of structures on a lease basis; therefore the capital cost can be amortized over more than one project.

Both the jack-deck and the jack-up concept are quite similar, each employing a three-legged structure supporting a production topsides. The MOPU is brought to the field centre where it self elevates by jacking up on location. Risers for production fluids and export pipeline are connected to the structure for conveying produced fluids on and off the structure. At the end of the field life, the risers are disconnected from the flowlines and pipeline, legs are retracted and the platform jacked down for removal from the field. The structure can potentially be relocated and reused at another field.

The main difference between the jack-deck and the jack-up structure is in the design of the deck. The jack-deck is a custom engineered lattice-type structure designed to house the specific production equipment needed for the specific application. Because it is a lattice-type structure, it cannot float and therefore is brought to and removed from location on a barge. The jack-up type structure incorporates a floating hull so it does not require a barge for transportation. The jack-up carries a purpose-built topsides to provide the necessary production equipment. The jack-up hull design concept is used extensively for mobile offshore drilling rigs.

The jack-deck concept was investigated and deemed to be technically feasible. However, it had some distinct disadvantages when compared to the jack-up concept. First, this concept requires a custom design where the topsides are fully integrated into the supporting leg structure. Further, the legs and foundations are custom engineered for the specific application. Thus, at the end of the Project life, the chance of reuse for this type of structure at another location is greatly reduced, thus affecting the residual value of the MOPU. The majority of the cost must be amortized over one project. Also, this structure type must be transported on an installation barge. The on-site installation using a barge scheme


is much more weather-dependent than using a floating hull type installation and requires a calmer sea state. This could impact the project by adding cost and time for schedule impacts due to unfavorable weather. The cost of the jack-deck is also more expensive than other solutions and leasing options were not available. As a result of the economic disadvantages compared to the jack-up solution, this option was rejected.

Two approaches for executing the jack-up concept were investigated: 1) build a new jack up-hull to a ‘harsh environment’ drill rig specification to accommodate a new purpose-built topsides or 2) refit/modify an existing harsh environment MODU to accommodate a new purpose built topsides. The jack-up structure was selected as the best option for the Project, the final concept of a new build or re-fitted jack-up structure will be confirmed during the MOPU bid competition.

2.10.2.3 Topsides Type

The type of topsides for the revised Deep Panuke Project has not yet been confirmed. It will be largely dependent on the hull design of the jack-up structure. This design will be conducted by the MOPU contractor, selected through a competitive bid process, who will engineer all elements of the MOPU, including the topsides.

2.10.2.4 Total Number of Platforms

Offshore installations are generally designed to be built as the largest components possible to maximize construction, hookup and commissioning activities onshore, which greatly reduces cost. Multiple structures are used when the size of the structure exceeds lifting capabilities for heavy lift vessels or there are other specific requirements that dictate the use of multiple platforms. As per the Project design basis for the approved 2002 CSR, the preferred development alternative for number of platforms was three separate platforms for wellheads, processing, and living quarters/utilities based on concept deliverability criteria, reduced drilling and installation flexibility, as well as safety.

For the revised Project, the size of the topsides required for the revised 8.5 x 106 m3/d [300 MMscfd] production capacity is well within the weight and size limitations for placement on one jack-up type structure. However, EnCana had specific concerns regarding personnel safety offshore because of the presence of H2S in the fluids stream. A twin-platform arrangement employing a production platform and separate bridge-linked accommodations and control room platform was investigated, but was found to increase capital cost significantly.


A single platform solution was investigated on a single jack-up type structure. Target levels of safety were identified that are consistent for offshore installations within the industry. All types of hazards for the installation were identified, including fire, explosion, ship collision, helicopter crashes, and sour gas leaks. The work concluded that the Project facilities could be safely placed on one platform offshore, provided additional special measures are put in place to protect workers against the effects of a potential sour gas leak. The special measures include a combination of infrastructure, such as portable breathing air apparatus, and work procedures for personnel offshore. Thus, the Project has selected a single-platform solution to support the topsides facilities.

2.10.2.5 Re-Use of Existing Platform

In the approved 2002 CSR, re-use of the existing Panuke platform, which was installed as part of the Cohasset Project was examined and rejected as a Project option. In any event, the Panuke jacket was removed during the decommissioning of the Cohasset Project in 2005, and therefore, re-use of the Panuke platform is no longer a valid alternative that can be assessed.

2.10.2.6 Processing Location

Onshore versus offshore processing was reviewed to determine which alternative provided the best option for the evaluation criteria noted above. Onshore versus offshore processing was assessed in 2002 with the following cases considered:

full offshore processing; onshore processing with minimal offshore processing to allow transportation only; and split onshore/offshore processing (intermediate case).

Between 2002 and 2006, the following additional alternative was considered:

full onshore processing via a long subsea tie-back.

The alternatives are summarized in Table 2.11 and are discussed below.

Full Offshore Processing

Full offshore processing involves gas sweetening, acid gas injection, TEG dehydration, gas dewpointing, gas compression, produced water treatment and disposal, and condensate treatment/usage for platform fuel offshore. Market-ready natural gas is shipped to shore in a subsea pipeline.

Dee

p Pa

nuke

Vol

ume

4 (E

nvir

onm

enta

l Ass

essm

ent R

epor

t) N

ovem

ber 2

006

2-68

Tab

le 2

.11

Pro

cess

ing

Loc

atio

n A

ltern

ativ

esA

ltern

ativ

e T

echn

ical

Sui

tabi

lity

Cos

t C

omm

erci

al R

isk

Tec

hnic

ally

and

E

cono

mic

ally

Fea

sibl

e C

once

ptD

eliv

erab

ility

Safe

ty

Env

iron

men

tal I

mpa

ct

Full

Off

shor

e Pr

oces

sing

B

est t

echn

ical

so

lutio

n (H

2S a

nd

cond

ensa

te re

mov

al

at so

urce

to p

rodu

ce

natu

ral

gas)

Low

er c

ost t

han

onsh

ore

proc

essi

ng

No

spec

ific

conc

erns

Y

es

Equi

vale

nt

Dea

ls w

ith H

2S a

t sou

rce

ther

eby

min

imiz

ing

safe

ty

risk

rela

ted

to p

ipel

ine

trans

port

of g

as to

shor

e

Dea

ls w

ith H

2S a

t sou

rce,

ther

eby

elim

inat

ing

risks

to th

e on

shor

e en

viro

nmen

t.

Few

er se

nsiti

ve e

nviro

nmen

tal r

ecep

tors

an

d gr

eate

r aci

d bu

ffer

ing

capa

city

in th

e of

fsho

re m

arin

e en

viro

nmen

t O

nsho

re

Proc

essi

ng

(with

min

imal

of

fsho

re

proc

essi

ng fo

r tra

nspo

rtatio

n)

Hig

her r

isk

than

of

fsho

re p

roce

ssin

g as

soci

ated

with

pi

pelin

e in

tegr

ity

Hig

her c

ost t

han

offs

hore

pro

cess

ing

Ris

k to

Pro

ject

ec

onom

ics s

houl

d pi

pelin

e co

rrod

e an

d be

ou

t of s

ervi

ce fo

r an

exte

nded

per

iod

of ti

me

Incr

ease

d ris

k to

pro

ject

ec

onom

ics d

ue to

pi

pelin

e in

tegr

ity

conc

erns

Yes

Equi

vale

nt

Tran

spor

ts H

2S fr

om o

ffsh

ore

to p

opul

ated

are

a (in

crea

sed

safe

ty ri

sks)

A g

reat

er n

umbe

r of s

ensi

tive

envi

ronm

enta

l rec

epto

rs a

nd th

eref

ore

pote

ntia

l im

pact

s ons

hore

with

rega

rd to

H

2S e

mis

sion

s

Incr

ease

d co

rros

ion

risk

asso

ciat

ed w

ith

trans

mis

sion

of H

2S in

a 1

76 k

m p

ipel

ine

incr

ease

s ris

k of

gas

rele

ase

Ons

hore

Pr

oces

sing

(L

ong

subs

ea

tieba

ck)

Tech

nica

lly n

ot

feas

ible

Off

shor

e/O

nsho

re

(Int

erm

edia

te

Cas

e)

Dup

licat

ion

of so

me

faci

litie

s ons

hore

and

on

shor

e

Hig

hest

– m

ust

dupl

icat

e el

emen

ts o

f pr

oces

sing

off

shor

e an

d on

shor

e

No

spec

ific

conc

erns

N

o

Off

shor

e/O

nsho

re

usin

g SO

EP

Subs

ea T

ie-in

Tech

nica

lly fe

asib

le

Yet

to b

e de

term

ined

Yet

to b

e de

term

ined

Y

es

Mar

gina

l in

crea

sed

risk

whe

n co

mpa

red

to

full

offs

hore

Sam

e as

off

shor

e pr

oces

sing

M

argi

nal i

ncre

ased

adv

anta

ge o

ver f

ull

proc

essi

ng b

y re

duct

ion

of b

enth

ic

dist

urba

nce

resu

lting

from

a sh

orte

r pi

pelin

e


Onshore Processing with Minimal Offshore Facilities

Onshore processing with minimal offshore processing was based on minimally treating the gas such that the gas and the condensate could be transported, in a common pipeline, for processing onshore. Onshore processing involves some processing offshore including dehydrating the gas and separating the water from the condensate so that the pipeline may be operated free of water. The removal of water is necessary for corrosion control and hydrate prevention. The offshore facilities for the onshore processing alternative include separation, TEG dehydration, condensate treatment, produced water handling and a multiphase export pipeline for the combined gas and condensate streams. The associated onshore facilities include a slugcatcher, separation, gas sweetening, sulphur recovery, TEG dehydration, gas compression, gas dewpointing, condensate treatment, and sour water handling. Onshore processing is more expensive than the offshore processing due to the duplication of facilities at both the offshore and onshore locations including separation, TEG dehydration, condensate treatment, compression, and sour water handling. Due to economic reasons, the onshore processing case was rejected.

Full Onshore Processing with Long Subsea Tie-Back

Another alternative for providing full onshore processing would be to use a “long subsea tie-back”. This alternative involves using only the reservoir pressure to push reservoir fluids to shore via a 176 km corrosion-resistant pipeline. An offshore subsea gathering system, with a subsea manifold, collects all the fluids produced from the subsea wells and transports them to shore via a multiphase pipeline. The onshore plant provides full processing of the reservoir fluids and contains all the process equipment similar to the offshore processing alternative plus a slugcatcher, sulphur recovery plant and sour water handling equipment.

Onshore processing creates additional safety and human health risk associated with handling sour gas onshore near populated areas. The probability of a large-scale accidental release of sour gas from a processing facility, albeit remote, is a serious concern. While the oil and gas industry has proven capable of handling sour gas in populated areas, EnCana submits that the most prudent approach is to minimize risk by locating sour gas facilities away from populated areas.

While proven and effective mitigation measures exist to address safety/occupational health and environmental concerns, EnCana’s preferred approach for this Project is to deal with the sour gas at source to minimize overall risk. While population density in the onshore project area is low, there would nevertheless be some added risk to the public with an onshore compared to offshore acid gas handling site. In general, there are many more environmental receptors onshore and acidic buffering capacity is far greater in the marine environment.


After carefully considering the concept, EnCana rejected the onshore processing with subsea tie-back option as not technically feasible. There is no precedent of tie-backs of this length anywhere world-wide to date. In addition, the lack of inlet compression offshore would impact the recovery of the resource and result in a larger unrecoverable portion of the resource when compared to an offshore solution. These technical issues and reduced resource recovery contributed to the rejection of the onshore processing with subsea tie-back option.

Split Onshore/Offshore Processing (Intermediate Case)

An intermediate case for onshore processing was also reviewed. The intermediate case requires dehydration and H2S removal offshore, transportation to shore in a dedicated multi-phase pipeline, and separation, dewpointing and condensate treatment occurring at the onshore facility. Under this scenario, condensate must also be treated offshore for H2S removal since the pipeline and the onshore facility are designed for processing sweet gas. Treating condensate offshore requires the same facilities as full offshore processing plus, additional, duplicative facilities onshore. There is no technical or economic advantage in recombining the gas and condensate for multiphase transport since duplicate facilities for condensate separation and treatment would be required onshore. Accordingly, the intermediate case was rejected based on technical and economical considerations.

EnCana’s proposed solution is offshore processing. The alternate pipeline case will dictate the final configuration - full offshore processing under the M&NP Option or partial processing under the SOEP Subsea Option.

In summary, offshore processing was selected as the preferred option based on the following:

treating and disposing of sour gas as close to source as possible and thereby reducing risk to the local population and environment near Goldboro; offshore injection of acid gas minimizes safety and environmental risk due to the buffering capacity of the marine environment and the few receptors in the offshore project area; reduced risk related to subsea pipeline integrity with the removal of both water and H2S prior to transport to shore; and capital and operating costs.

2.10.2.7 Acid Gas Handling

Removal of H2S from the inlet gas stream results in a concentrated waste stream to be handled offshore. The FEED study investigated four options for handling acid gas offshore including flaring, seawater scrubbing, offshore sulphur recovery, and acid gas injection. The alternative chosen for the Project is the acid gas injection technology. A summary of the investigation is included below and summarized in Table 2.12.

Dee

p Pa

nuke

Vol

ume

4 (E

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l Ass

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ent R

epor

t) N

ovem

ber 2

006

2-71

Tab

le 2

.12

Aci

d G

as H

andl

ing

Dev

elop

men

t Alte

rnat

ives

Alte

rnat

ive

Tec

hnic

al S

uita

bilit

y C

ost

Com

mer

cial

Ris

k T

echn

ical

ly a

nd

Eco

nom

ical

ly

Feas

ible

Con

cept

Del

iver

abili

ty

Safe

ty

Env

iron

men

tal I

mpa

ct

Aci

d ga

s in

ject

ion

Prov

en te

chno

logy

Use

d ex

tens

ivel

y in

Wes

tern

C

anad

a –

EnC

ana

has

exis

ting

inst

alla

tions

App

roxi

mat

ely

$45

MM

No

sign

ifica

nt c

once

rns

Yes

M

oder

ate

risk

– sp

ecia

lized

eq

uipm

ent a

nd a

dditi

onal

sa

fety

con

cern

s

Incr

emen

tal r

isk

over

fla

ring

due

to h

andl

ing

of

high

pre

ssur

e ac

id g

as

Sign

ifica

ntly

redu

ces a

ir em

issi

ons a

nd m

arin

e di

scha

rges

co

mpa

red

with

oth

er fe

asib

le

optio

ns

Flar

ing

Prov

en te

chno

logy

Use

d w

orld

wid

e

App

roxi

mat

ely

$1 M

M*

Fuel

gas

requ

ired

to

ensu

re e

ffic

ient

op

erat

ion

Not

app

licab

le

Yes

Le

ast r

isk

So

me

risk

asso

ciat

ed w

ith

hand

ling

acid

gas

H

ighe

st a

ir em

issi

ons

Seaw

ater

sc

rubb

er

Tech

nolo

gy n

o lo

nger

av

aila

ble

Not

ass

esse

d N

ot a

pplic

able

N

o

Off

shor

e su

lphu

r re

cove

ry

Off

shor

e fo

otpr

int r

equi

red

mak

es O

ptio

n un

econ

omic

al

Ver

y hi

gh

Not

app

licab

le

No

Not

e: *

Bas

ed o

n es

timat

es p

repa

red

in 2

002.


Flaring acid gas consists of directing the acid gas stream to a flare system for incineration and emission to the atmosphere. Flaring is a relatively low-cost option and is widely used for this type of acid gas. There are SO2 emissions resulting from the incineration process, which while permissible, can impact air quality. In this case the amount of SO2 released is within air quality guidelines. This alternative was not ruled out, but was considered less preferable than acid gas injection, where economic and operable.

The seawater scrubbing option consists of an incinerator and a scrubber. The unit accepts acid gas from the incinerator that has converted the H2S to SO2. The SO2 is subsequently removed by seawater absorption in a packed column. The acid gas leaving the incinerator flows up the column contacting the seawater counter currently. The spent seawater flows by gravity to a mixing device, where it is combined with other plant discharge water (cooling water, produced water, etc.) and returned to the ocean.

Seawater scrubbing technology has been used in some onshore facilities such as power plants, but has very limited experience in offshore applications. Two offshore applications were identified, and both installations do not have established performance records. Further, an environmental review of this technology performed in 2002 identified that the discharge stream would likely be considered to be deleterious to marine life. Further recent investigation has found that equipment vendors are no longer offering this type of equipment. The seawater scrubbing was rejected on the basis of being a technically unproven and unacceptable alternative.

Offshore sulphur recovery was considered as an alternative for acid gas handling. After preliminary review of the option, it was determined that it was not economically feasible due to the size of the platform required for the process and the logistics of handling the sulphur product.

2.10.2.8 Produced Water Disposal

EnCana identified four potential alternatives for produced water disposal on the Deep Panuke Project. These alternatives were treatment and discharge overboard, injection into a dedicated well, simultaneous injection into the condensate/acid gas injection well, and injection into the annular space of an existing well. Each alternative carries different types and levels of risk to the Project (further information provided in Table 2.13). After a thorough review of the alternatives, the treatment and discharge overboard option was deemed the best technical and commercial option.

Discharge Overboard

Treatment and discharge overboard is a proven technology that is used world-wide in offshore oil and gas facilities, including offshore Nova Scotia. The treatment technology proposed for the Project will ensure that the prescribed CNSOPB limits for produced water discharge are met or improved upon.

Dee

p Pa

nuke

Vol

ume

4 (E

nvir

onm

enta

l Ass

essm

ent R

epor

t) N

ovem

ber 2

006

2-73

Tab

le 2

.13

Prod

uced

Wat

er D

ispo

sal A

ltern

ativ

es

Alte

rnat

ive

Tec

hnic

alSu

itabi

lity

Cos

t C

omm

erci

al R

isk

Tec

hnic

ally

and

E

cono

mic

ally

Fea

sibl

e C

once

ptD

eliv

erab

ility

Sa

fety

E

nvir

onm

enta

l Im

pact

Trea

tmen

t and

di

spos

alov

erbo

ard

Prov

en te

chno

logy

Cur

rent

ly u

sed

wor

ldw

ide

in o

ffsh

ore

oil a

nd g

as fa

cilit

ies

Mee

ts p

ublis

hed

CN

SOPB

gui

delin

es

Bas

e ca

se fo

r cap

ital

cost

s

Ann

ual o

pera

ting

cost

s fo

r env

ironm

enta

l m

onito

ring

No

sign

ifica

nt c

once

rns

Yes

N

o si

gnifi

cant

con

cern

s N

o si

gnifi

cant

co

ncer

nsLi

kely

no

sign

ifica

nt im

pact

to

the

mar

ine

envi

ronm

ent d

ue to

hy

drod

ynam

ical

ly a

ctiv

e di

scha

rge

loca

tion

Wat

er w

ill b

e tre

ated

and

di

spos

ed a

ccor

ding

to e

xist

ing

regu

latio

ns

Inje

ctio

n in

to

dedi

cate

d w

ell

Prov

en te

chno

logy

on

shor

e

Will

requ

ire d

uplic

atio

n of

ove

rboa

rd e

quip

men

t in

cas

e w

ell g

oes d

own

Bas

e co

st fo

r dis

posa

l ov

erbo

ard

plus

ap

prox

imat

ely

60 M

M

Add

ition

al o

pera

tiona

l co

sts f

or w

ell

inte

rven

tions

, inj

ectio

n ch

emic

als,

and

pow

er fo

r pu

mpi

ng

No

sign

ifica

nt c

once

rns

Tech

nica

lly fe

asib

le

Una

ttrac

tive

econ

omic

ally

, ad

d un

nece

ssar

y co

st a

nd

com

plex

ity

Sim

ulta

neou

s in

ject

ion

with

ac

id g

as in

to

acid

gas

in

ject

ion

wel

l

Con

cept

is n

ot

tech

nica

lly fe

asib

le, d

ue

to v

arie

d pr

oduc

ed

wat

er v

olum

es

Not

ass

esse

d N

ot a

sses

sed

No

Dee

p Pa

nuke

Vol

ume

4 (E

nvir

onm

enta

l Ass

essm

ent R

epor

t) N

ovem

ber 2

006

2-74

Tab

le 2

.13

Prod

uced

Wat

er D

ispo

sal A

ltern

ativ

es

Alte

rnat

ive

Tec

hnic

alSu

itabi

lity

Cos

t C

omm

erci

al R

isk

Tec

hnic

ally

and

E

cono

mic

ally

Fea

sibl

e C

once

ptD

eliv

erab

ility

Sa

fety

E

nvir

onm

enta

l Im

pact

Inje

ctio

n in

to a

n an

nulu

sC

once

pt h

as si

gnifi

cant

te

chni

cal r

isks

If c

orro

sion

pro

blem

oc

curs

, will

shut

dow

n a

prod

ucer

wel

l

Add

ition

al c

apita

l cos

t fo

r inj

ectio

n eq

uipm

ent,

addi

tiona

l pip

ing,

wel

l co

nstru

ctio

n, a

nd

wel

lhea

d m

odifi

catio

ns

Add

ition

al o

pera

tiona

l co

sts f

or in

ject

ion

chem

ical

s

Pote

ntia

l ris

k of

shut

-do

wn

of p

rodu

ctio

n w

ell

that

is b

eing

inje

cted

into

(c

orro

sion

)

Unc

erta

inty

with

rega

rd

to a

suita

ble

inje

ctio

n zo

ne

No


Injection into a Dedicated Well

Water injection into a dedicated well is a proven technology on offshore oil developments and is normally done for reservoir pressure maintenance. This concept would involve the use of all equipment for the overboard disposal scheme plus the addition of a dedicated flowline, a dedicated umbilical, a new injection well, injection pumps, and filters. For this concept, the capability to discharge produced water overboard would be required to provide operational flexibility in times of maintenance and/or operational issues. The concept, while technically feasible, is considerably more expensive than the simpler overboard disposal concept. Since the overboard disposal concept provides a proven, environmentally acceptable alternative at a significantly lower cost, the dedicated injection well was rejected based on economic considerations.

Simultaneous Injection of Acid Gas and Produced Water

Simultaneous injection of produced water into the condensate/acid gas well is not commonly practiced offshore due to risks associated with phase separation. Although the design rate of 6,400 m3/d [40,000 bpd] is sufficient to dissolve 130 x 103 m3/d [4.5 MMscfd] of acid gas, the rate of produced water varies between 0 and 6,400 m3/d [40,000 bpd] and cannot be predicted with certainty at this time. Therefore, this option cannot be considered as a reliable solution for produced water disposal and was rejected.

Injection of Produced Water into an Annular Space

Injection into the annular space of an existing well is not widely practiced. This concept involves injecting the produced water into an annular space between the surface and production casing strings. The concept will require injection pumps and equipment on the topsides similar to the dedicated well concept as well as a special dual completion type wellhead and production tree arrangement. This concept has the following technical challenges:

the annular space on any of the existing production wells will not have sufficient cross-sectional area to accept up to 6,400 m3/d [40,000 bpd]. Therefore, none of the existing wells could be re-used;well construction to accommodate this concept for either of the two new drill wells (H-99 or D-70) will be difficult and technically challenging because a special oversized surface casing will be needed along with a custom wellhead and production tree; and injection of the total expected quantity of produced water over the field life into a non-permeable zone, where the surface casing terminates, is questionable. There may be operational issues with this concept.


Therefore, injection into an annular space was rejected on the basis of high risk of deliverability of this concept.

2.10.2.9 Condensate Handling

The method employed for condensate handling is directly tied to the export tie-in alternatives. For the M&NP Option, three options were investigated for handling condensate. The preferred option is to use the condensate as primary fuel for the turbine drivers offshore. The rationale for this selection is described below.

For the SOEP Subsea Option, the condensate is transported to SOEP via the export pipeline and commingled with the export gas. Final condensate handling is done onshore at the SOEP gas plant at Goldboro and the fractionation plant at Point Tupper.

Handling of the condensate stream either as the primary fuel on the platform or processing at the SOEP facilities are both technically feasible. Final selection of the condensate handling alternative will be made when discussions between EnCana and ExxonMobil are concluded.

The following three options for condensate handling were evaluated for the M&NP Option:

1. the use of a dedicated pipeline to shore; 2. use of condensate as a fuel; and3. condensate storage and shipment by tanker.

The three alternatives were identified as technically feasible with different types and levels of risk (refer to Table 2.14); however, options 1 and 3 were deemed not to be economically feasible. After reviewing the alternatives, it was determined that use of condensate handling as the primary fuel is the preferred alternative for the M&NP Option.

The maximum expected volume of condensate that will be produced with Deep Panuke gas at peak production is approximately 220 m3/day [1400 bpd].

Dee

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2-77

Tab

le 2

.14

Con

dens

ate

Han

dlin

g

Alte

rnat

ive

Tec

hnic

alSu

itabi

lity

Cos

t C

omm

erci

al R

isk

Tec

hnic

ally

and

E

cono

mic

ally

Fe

asib

le

Con

cept

Del

iver

abili

ty

Safe

ty

Env

iron

men

tal I

mpa

ct

Ded

icat

edpi

pelin

e to

shor

e Pr

oven

tech

nolo

gy

Hig

h ca

pita

l cos

ts

No

sign

ifica

nt c

once

rns

No

Use

of

cond

ensa

te a

s a

fuel

Tri-f

uel u

sage

(g

as/c

onde

nsat

e/di

esel

) not

w

idel

y us

ed in

off

shor

e pr

oduc

tion,

but

feas

ible

Leas

t exp

ensi

ve

No

sign

ifica

nt c

once

rns

Yes

Sp

ecia

lized

equ

ipm

ent

whi

ch is

not

ava

ilabl

e in

C

anad

a ha

s lon

g le

ad

deliv

ery

Req

uire

s spe

cial

des

ign

cons

ider

atio

ns h

owev

er,

tech

nica

lly a

chie

vabl

e

Red

uced

tran

sfer

s of d

iese

l (r

equi

red

as a

bac

kup

fuel

) si

nce

a tri

-fue

l sys

tem

will

be

in u

se

Stor

age

and

ship

men

t by

tank

er

Prov

en te

chno

logy

H

igh

capi

tal c

osts

N

o si

gnifi

cant

con

cern

s N

o

Deep Panuke Volume 4 (Environmental Assessment Report) • November 2006 2-78

Use of a dedicated condensate pipeline to shore would necessitate the construction of onshore condensate handling facilities such as storage tanks which would result in substantial capital costs. The pipeline would have to be buried over its entire length (not easily accomplished over rocky areas) to meet regulatory requirements and to protect it from possible damage from mobile fishing gear. In addition, the condensate pipeline would not be protected from clam dredges unless deeply buried. The potential environmental effects associated with rupture of such a condensate pipeline would also be a concern. The quantities of condensate to be produced from the Deep Panuke field do not justify the costs associated with a dedicated condensate pipeline. Thus, a dedicated condensate pipeline to shore was deemed not economically feasible and was therefore rejected.

The use of condensate as the primary fuel on the MOPU was also considered. Using condensate as fuel eliminates the substantial capital and operating costs associated with a condensate pipeline to shore and associated onshore handling facilities. The use of condensate as fuel on the platform conserves the resource by maximizing the quantity of natural gas exported to shore and by utilizing all components of the Deep Panuke resource.

A seafloor subsea storage tank for holding a six-month volume of condensate offshore was also considered. While subsea storage tanks have been used at other offshore facilities, there is a high risk for potential seafloor scour due to the relatively shallow water at the Deep Panuke site. That would necessitate large quantities of rock protection around the tank. The prohibitive costs of such an installation resulted in this option being considered not economically feasible.

2.10.2.10 Production Capacity Alternatives

The 2002 Project basis for production capacity was 11.3 x 106 m3/d [400 MMscfd]; however, alternatives for smaller facilities with peak production capacities of 8.5 x 106 m3/d [300 MMscfd] and 5.7 x 106 m3/d [200 MMscfd] were also considered. Concepts were initially developed for jacket-supported structures for each alternative. It was found that the platform footprint, weight, and cost reduced considerably when the production capacity was reduced from 11.3 x 106 m3/d [400 MMscfd] to 8.5 x 106 m3/d [300 MMscfd]. However, the reduction in topsides weight (and cost) when the production capacity was further reduced to 5.7 x 106 m3/d [200 MMscfd] is marginal since the size of processing equipment does not decrease in the same proportion as production capacity. The economic modelling case at the 5.7 x 106 m3/d [200 MMscfd] production rates showed that the payout period was too lengthy at this rate, severely impacting the economics. It was concluded that the 8.5 x 106 m3/d [300 MMscfd] plant size is more economically feasible for the Mean reservoir case and therefore was selected for the plant production capacity rating.


2.10.2.11 Export Pipeline Alternatives

There are two alternatives for the export pipeline. EnCana proposes to transport product for sale via a subsea pipeline from the offshore processing facility to one of two delivery points:

• Goldboro, Nova Scotia (M&NP Option); or• SOEP 660 mm [26 inch] pipeline tie-in (SOEP Subsea Option).

Both export pipeline alternatives are technically feasible and routes have been chosen to minimize environmental impact. The selected alternative will be determined pending the outcome of commercial discussions between the operator of SOEP, ExxonMobil, and EnCana.

2.10.2.12 Subsea Tie-back Alternatives

The Deep Panuke reservoir areal extent has changed substantially from the 2002 Project basis of one license, PL2902, to the current Project basis covering PL2902, EL2387, SDL2255H, PL2901 and EL2360. The pool size estimate requires a minimum of five production wells for the P90 case (value at 90th Percentile) and a maximum of eight production wells for the P10 case (value at 10th Percentile) to effectively deplete the resources. The large extent of the pool necessitates the use of a subsea solution.

The Project plans to utilize four suspended wells from the exploration drilling program as production wells which allows for reduced capital costs and environmental interactions. One new production well will be drilled for the Project start-up. Up to three additional production wells could be drilled in future. A subsea tie-back study was carried out to determine the optimal method of tying in the wells to the field centre. It should be noted that a new acid gas injection well must also be tied back to the field centre; however, the geology in the area allows numerous options for the location of this well so this was not considered as a driver for the lay-out study.

From a layout consideration, it was determined that a tie-back of individual wells to the field centre was the best technical solution. The proposed well locations do not suit a template or manifold arrangement. The field centre location was determined by minimizing the tie-back lengths of the wells to lower capital costs and improve flow assurance.

Three alternative methods for flowline installation were considered: 1) “S-lay” barge method; 2) “reel lay” technique; and 3) flexible flowline method. The “S-lay” lay barge method involves the use of an offshore barge to weld and then lay lengths of rigid pipe on the seabed by means of a “stinger” overhanging the stern of the barge. Subsequently, the pipe is trenched using a subsea trenching or ploughing spread. The “reel lay” method involves pre-welding rigid pipe lengths together at a specialized “spool base” onshore and then reeling the entire flowline onto a large diameter reel. The reel


is taken offshore on a special lay vessel where it is straightened and laid on the seabed as a continuous length. The flowline is trenched in a similar manner to the lay barge method. The “flexible” solution uses a flowline of non-rigid type. Each flowline is manufactured in one single piece at a specialized factory and coiled on a large reel and taken offshore. A special lay vessel uncoils the flowline and lays it on the sea bed. Trenching methods are similar to the other schemes. Hook-ups for all three alternatives are carried out by diver/ROV operations.

All three methods are technically acceptable with similar environmental effects and the preferred solution will be chosen following the competitive bidding process.

2.10.2.13 Acid Gas Injection Location

As indicated in Section 2.10.2.7, the option chosen for acid gas handling for the Project is the acid gas injection technology. The location chosen for the acid gas injection well is D-70. An alternative location considered for the acid gas injection well was H-82. A summary of the investigation is included below and summarized in Table 2.15.

Both acid gas well locations are technically and economically feasible. However, the distance from the MOPU to H-82 is longer than the distance to D-70 (4.8 km versus 1.7 km), which would result in an additional cost of approximately $1 MM to $2 MM for the extra length of flowline and umbilical for H-82.

The possibility of acid gas injection souring the Panuke oil sands is considered to be extremely unlikely for both the D-70 and H-82 locations; the likelihood of souring is only slightly greater for the D-70 location.

The longer flowline for an acid gas injection well at H-82 results in an increased operational risk associated with a higher risk of hydrate formation in the flowline. In addition, there is also an increased safety risk in the very unlikely event of an acid gas injection flowline rupture due to the larger volumes of acid gas contained in the longer flowline to H-82.

The environmental impact from both locations would be very similar, although the H-82 location is expected to have a slightly higher environmental impact due to the following:

longer flowline resulting in larger benthic footprint (greater area of benthic disturbance); larger safety zone area to include H-82 well and flowline location, resulting in higher impact on fisheries (especially quahog fishery) and other ocean users; and increased impact to air quality in the unlikely event of acid gas flowline rupture due to larger volume of acid gas contained in the longer flowline to H-82.


However, these differences are not likely to result in significant environmental effects and the assessment presented in this EA Report (DPA Volume 4) for the D-70 location is expected to be applicable to the H-82 location.

Based on the fact that both acid gas well locations are very similar in terms of technical feasibility and environmental impact, the acid gas well injection location at D-70 was selected due to lower costs and slightly lower risks associated with concept deliverability and safety.

Dee

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2-82

Tab

le 2

.15

Aci

d G

as In

ject

ion

Loc

atio

n A

ltern

ativ

es

Alte

rnat

ive

Tec

hnic

al S

uita

bilit

y C

ost*

C

omm

erci

al R

isk

Tec

hnic

ally

and

E

cono

mic

ally

Fe

asib

leC

once

pt D

eliv

erab

ility

Sa

fety

E

nvir

onm

enta

l Im

pact

D-7

0 Te

chni

cally

feas

ible

B

ase

case

for c

ost (

as p

er

Tabl

e 2.

12)

Extre

mel

y lo

w ri

sk o

f so

urin

g th

e Pa

nuke

sa

nds,

Yes

Le

ast r

isk

Leas

t ris

k Lo

wer

impa

ct

H-8

2 Te

chni

cally

feas

ible

A

dditi

onal

cos

t fro

m b

ase

case

of a

ppro

xim

atel

y $1

-2

MM

for i

nsta

llatio

n of

ext

ra

leng

th (a

ppro

x. 3

.1 k

m) o

f flo

wlin

e an

d um

bilic

al

Ris

k of

sour

ing

the

Panu

ke sa

nds e

xtre

mel

y un

likel

y (s

light

ly lo

wer

th

an D

-70)

Yes

In

crea

sed

oper

atio

nal r

isk

asso

ciat

ed w

ith lo

nger

flow

line

(prim

arily

incr

ease

d ris

k of

hy

drat

e fo

rmat

ion)

Incr

ease

d sa

fety

risk

as

soci

ated

with

unl

ikel

y ru

ptur

e of

aci

d ga

s inj

ectio

n flo

wlin

e du

e to

larg

er

volu

me

of a

cid

gas i

n flo

wlin

e (4

.8 k

m fl

owlin

e in

stea

d of

1.7

km

)

Hig

her i

mpa

ct d

ue to

long

est

flow

line

resu

lting

in:

larg

er b

enth

ic fo

otpr

int

(gre

ater

are

a of

ben

thic

di

stur

banc

e)

larg

er sa

fety

zon

e ar

ea a

nd

impa

ct o

n fis

herie

s (e

spec

ially

qua

hog)

and

ot

her o

cean

use

rs

incr

ease

d im

pact

to a

ir qu

ality

in u

nlik

ely

even

t of

acid

gas

flow

line

rupt

ure

due

to la

rger

vol

ume

of a

cid

gas i

n flo

wlin

e


3 MALFUNCTIONS AND ACCIDENTAL EVENTS

This section provides an overview of potential malfunctions and accidental events that, while unlikely, may occur during the Project, with an emphasis on the effects of these events. Spill risk and behaviours have been modelled to determine the probability and extent of impacts (Appendix E). While a significant spill or release of gas is extremely unlikely, the potential consequences of such an event need to be understood so that safety, emergency response and contingency planning can be completed to ensure the risk is further minimized.

Accidental air emission and marine spill modelling presented in the approved 2002 CSR required updating due to the following Project modifications:

re-location of the field centre; new production and acid gas injection subsea wells and flowlines;new multi-phase pipeline (carrying condensate) for SOEP Subsea Option; and revised Project life.

To minimize confusion and improve readability, this discussion is being presented in its entirety as originally presented in the approved 2002 CSR, with updated scenarios and results noted.

3.1 Potential Malfunctions and Accidental Events

Malfunctions and upset conditions having potential environmental effects include: platform-based spills; malfunction of the acid gas management system; blowouts and pipeline/flowline ruptures; and collisions.

Routine operations can be conducted with sufficient mitigation to ensure that effects on the environment and human health and safety are not significant. There is potential for significant adverse environmental effects to occur in the extremely unlikely event of a blowout of an injection or production well, or an acid gas flowline rupture. Design, inspection, maintenance and integrity assurance programs, as well as proven engineering techniques, will be in place to prevent such events from occurring. All safety procedures will be documented and in place prior to the commencement of routine operations.

All fuel, chemicals and wastes will be handled in a manner that minimizes or eliminates routine spillage and accidents. EnCana’s EPP will include safe chemical handling and storage procedures as well as Project-specific spill response measures (refer to Appendix G). EnCana’s Deep Panuke Spill Response Plan includes general measures for preparing for and responding to spills, including the use of cleanup equipment, training of personnel and identification of personnel to direct cleanup efforts, lines of communications and organizations that could assist cleanup operations (refer to Appendix G).


3.1.1 Platform-based Spills

Platform-based spills were discussed in Section 3.1.1 of the approved 2002 CSR. Given the change in Project life and MOPU location, spill risk probability analysis and spill behaviour modelling have been updated (refer to Appendix E) and summarized in Section 3.2.1 and 3.4.1, respectively.

3.1.2 Collisions

The risk of collision between platforms and vessels is anticipated to be extremely low based on compliance with standard procedures. A safety zone will be established in accordance with CNSOPB regulations and will most likely encompass the MOPU, subsea well, flowlines and umbilicals. For further detail, refer to Section 2.4.4. Surface facilities will contain navigational aids and anti-collision radar will provide early warning of a potential collision hazard. In the unlikely event that a collision cannot be avoided, EnCana’s DPEMP would address response procedures.

3.1.3 Malfunction of Acid Gas Management System

Under normal operations, waste acid gas will be injected into a dedicated injection well. Malfunctions of compressors or other equipment associated with acid gas management could lead to conditions that require diversions of the acid gas to the MOPU flare. Equipment downtime and flaring will also be required for routine maintenance and is expected to be a brief period (e.g., a few days or a week). In the unlikely event of major equipment malfunctions, equipment downtime and associated flaring could last approximately one year (in the event that a new injection well needs to be drilled). Flaring of acid gas results in emissions of SO2; however, a flare malfunction resulting in failure to ignite, will result in emissions of H2S. Air emissions during upset conditions are described in detail in Section 8.1.4.4.

The acid gas injection well will be drilled into a suitable geological formation. The intended reservoir for disposal of the acid gas does not contain sulphur; therefore it is anticipated that a blowout during drilling of the injection well would not contain significant amounts of H2S. The primary prevention mechanism within the wellbore is the SC-SSSV. This is a failsafe valve that must be maintained open by hydraulic pressure on a line from the surface. Interruption of pressure on this valve, either through control action on the platform, or by accidental event, results in rapid closure of the valve. This would limit the potential discharge to the volume of gas within the pipe. Sections 3.4.2.1 and 8.1.4.4 describe the fate and behaviour of a blowout of the acid gas injection well.


3.1.4 Blowout Releases

There are two basic kinds of offshore oil/gas well blowouts. The first is a subsea blowout in which the discharging oil and gas emanates from the subsea well and rises through the water column to the water surface. The other possibility is an above-surface blowout in which oil and gas discharges into the atmosphere from some point on the platform above the water surface, and subsequently falls on the water surface some distance downwind.

Probability of blowouts is discussed in Section 3.2.2. Spill behaviour is discussed in Section 3.4.2. Atmospheric emissions related to well blowout are discussed in detail in Section 8.1.4.4. Design features to be used by EnCana to prevent or greatly minimize the chances of a serious spill are described in Section 2.9.

3.1.5 Pipeline and Flowline Releases

The export pipeline (both options) will be designed to withstand impacts from conventional mobile fishing gear in accordance with the DNV Guideline No. 13, Interference between Trawl Gear and Pipelines, September 1997. The subsea tie-in structures for the SOEP Subsea Option will be trawlable.

A leak system will be provided on the natural gas pipeline. In the event that a leak is confirmed, the pipeline has valves that will isolate the pipeline from either the M&NP pipeline or the SOEP pipeline and the MOPU to prevent additional hydrocarbons from entering the system. Section 2.9.2 provides additional detail on pipeline leak prevention.

Flowlines will be buried to avoid impacts from conventional mobile fishing gear and their locations will be charted. It is also likely that the safety zone will also encompass all wellhead flowlines and umbilicals. Environmental and safety protection systems, such as ESD valves, will be provided on the flowlines. Section 2.9.4 provides additional detail on flowline protection.

Risks of onshore pipeline and subsea pipeline/flowline releases are described in Sections 3.3 and 3.4, respectively. Atmospheric emissions related to subsea pipeline and flowline failures are discussed in Section 8.1.4.4.

3.1.6 Effects of the Environment on the Project

Effects of the environment on the Project (e.g., extreme waves, sea ice) which may cause upset conditions are discussed in Section 10.


3.2 Marine Spill Risk and Probability

A detailed discussion of spill risk and probability associated with the Project is presented in Appendix E. The calculated spill frequencies for the Project are summarized in Table 3.1.


Small and medium platform-based spills could contain diesel oil, hydraulic fluid, lubricants, other refined oils, or mineral oil. The highest frequencies for all spills are for the smaller, platform-based spills (<1 bbl). Statistics for these small spills are often difficult to interpret due to inconsistent reporting practices. The Project’s design will build upon lessons learned from previous spill events in order to minimize potential risk for spills, including small platform-based spills. Spill prevention measures will include state-of-the-art environmental protection systems (Section 2.9) and treatment systems for the MOPU’s effluents, including deck drainage (Section 2.7.5). One spill in the 1 to 49.9 barrels (bbl) range might occur over the course of the Project, although its average size can be expected to be less than 10 barrels. There is about a 5% chance that a platform-based spill larger than 50 barrels might occur over the course of the entire Project.

The annual probability of having a large (>1000 bbl) or very large (>10,000 bbl) spill as a result of an accident on a platform is one in 10,000 and one in 28,000 respectively. This is calculated on the basis of United States Outer Continental Shelf (US OCS) experience. This means that if the Project were to continue forever, one platform-based spill larger than 1,000 barrels might occur every 10,000 years. Similarly, very large platform spills (>10,000 bbl) might occur once every 28,000 years.

3.2.2 Blowouts

During the 12 months needed to drill five wells, the chances of an extremely large (>150,000 bbl) and very large (>10,000 bbl) oil well blowout from development drilling are extremely small. If this drilling rate were to continue forever, one could conservatively expect one extremely large spill every 7,500 years; a very large spill might occur every 3,700 years. For similar sized blowouts from production activities and workovers that might occur over the 17.5-year production period, one might expect one extremely large oil well blowout every 20,000 years, and one very large oil well blowout every 7,800 years of production. These predictions are based on worldwide blowout data which includes variability in regulatory standards and application.

Dee

p Pa

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Vol

ume

4 (E

nvir

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006

3-5

Tab

le 3

.1 P

redi

cted

Num

ber

of B

low

outs

and

Spi

lls fo

r th

e D

eep

Panu

ke P

roje

ct

Eve

nt

His

tori

cal

Freq

uenc

y D

eep

Panu

ke

Exp

osur

e

No.

of E

vent

s ove

r th

e C

ours

e of

the

Proj

ect

Ann

ual

Prob

abili

ty

BL

OW

OU

TS

1. D

eep

gas b

low

out d

urin

g de

velo

pmen

t dril

ling

2.4

x 10

-4/w

ells

dril

led

5 w

ells

dril

led

over

12

mon

ths

1.20

x 1

0-3

one

in 8

30

2. G

as b

low

out d

urin

g pr

oduc

tion

1.17

x 1

0-4/w

ell-y

ears

11

2 w

ell-y

ears

1.

31 x

10-2

on

e in

1,3

00

3. B

low

out d

urin

g pr

oduc

tion

invo

lvin

g so

me

oil d

isch

arge

>1

bbl

1.04

x 1

0-5/w

ell-y

ears

11

2 w

ell-y

ears

1.

16 x

10-3

on

e in

15,

000

4. D

evel

opm

ent d

rillin

g bl

owou

t with

oil

spill

> 1

0,00

0 bb

l 5.

3 x

10-5

/wel

ls d

rille

d 5

wel

ls d

rille

d ov

er 1

2 m

onth

s2.

67 x

10-4

on

e in

3,7

00

5. D

evel

opm

ent d

rillin

g bl

owou

t with

oil

spill

> 1

50,0

00 b

bl

2.7

x 10

-5/w

ells

dril

led

5 w

ells

dril

led

over

12

mon

ths

1.33

x 1

0-4

one

in 7

,500

6. P

rodu

ctio

n/w

orko

ver b

low

out w

ith o

il sp

ill >

10,

000

bbl

2.0

x 10

-5/w

ell-y

ear

112

wel

l-yea

rs

2.24

x 1

0-3

one

in 7

,800

7.

Pro

duct

ion/

wor

kove

r blo

wou

t with

oil

spill

> 1

50,0

00 b

bl

8.0

x 10

-6/w

ell-y

ear

112

wel

l-yea

rs

8.96

x 1

0-4

one

in 2

0,00

0

PLA

TFO

RM

SPI

LL

S (in

cl. b

low

outs

) 8.

Oil

spill

> 1

0,00

0 bb

l 5.

5 x

10-6

/wel

l-yea

r 11

2 w

ell-y

ears

6.

16 x

10-4

on

e in

28,

000

9. O

il sp

ill >

100

0 bb

l 1.

5 x

10-5

/wel

l-yea

r 11

2 w

ell-y

ears

1.

68 x

10-3

on

e in

10,

000

10. O

il sp

ill 5

0 to

999

bbl

4.

8 x

10-4

/wel

l-yea

r 11

2 w

ell-y

ears

5.

4 x

10-2

on

e in

330

11

. Oil

spill

1 to

49

bbl

1.0

x 10

-2/w

ell-y

ear

112

wel

l-yea

rs

1.12

on

e in

16

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Considering experience in the North Sea and the US Gulf of Mexico and taking into account the trend toward fewer and fewer blowouts, the prediction for Deep Panuke is that, during the initial 12 months when five wells will be drilled, the probability is 0.12% chance per year (one-in-830) of having a deep blowout (one that could involve sour gas). Similarly, during production at Deep Panuke, gas blowouts might be expected to occur every 1,300 years, and blowouts involving small amounts of discharged oil (>1 bbl) might be expected to occur once every 15,000 years.

3.2.3 Spills from Pipelines and Flowline Operations

Based on the maximum volume of condensate that may be handled as part of the Deep Panuke Project, and using historical spill frequencies from US offshore production data, the probability of a spill from interfield flowlines and export pipeline (SOEP Subsea Option) is estimated to be a 0.03% (one in 3,300) chance per year for spills greater than 1,000 barrels, and a 0.007% (one in 13,000) chance per year for spills greater than 10,000 barrels.

The US OCS data does not differentiate between interfield flowlines and export pipelines, nor is there any data specific to acid gas flowline failures. Spills from production and export pipelines are lumped together and calculated based on the broad exposure of total volume handled, rather than pipeline length, size, or other parameters.

3.3 Onshore Pipeline Risk

A detailed risk assessment of the onshore portion of the pipeline has been updated to reflect the new proposed adjacent industrial land uses in the onshore study area (i.e., proposed Keltic Petrochemical and Maple LNG facilities) (Bercha Engineering Limited 2006). However, EnCana has also identified the requirement to conduct a detailed quantitative risk analysis considering potential risk synergies between the nearshore/onshore components of the Project with the proposed adjacent petrochemical and LNG facilities. This analysis will occur during detailed route design as it requires specific information on relative layout of project components (for both projects). The following information summarizes some of the key findings of the updated assessment considering only risks associated with the Deep Panuke Project.

3.3.1 Accident Scenarios

The only accident scenarios associated with the onshore pipeline posing any threat to safety or environmental quality are accidental losses of containment. Although accidental losses of containment are extremely unlikely, it is important that the potential consequences of such an event are understood so that safety, emergency response and contingency planning can be completed to ensure the risk is further minimized.


An accidental release of natural gas would result in either dispersion or ignition of the flammable gas. Dispersion without ignition poses no hazard to people or the environment. The size of a potential pipeline release can vary from a small corrosion pinhole leak to a full rupture across the pipeline diameter. In order to represent the range of potential release sizes, losses of containment have been characterized as leaks (very small hole), holes, or ruptures. The likelihood of each of these is as follows:

Leaks – 1 in 600 per year; Holes – 1 in 1,500 per year; and Ruptures – 1 in 5,000 per year.

3.3.2 Hazards

The released gas only becomes hazardous in the instance that it is ignited. Based on the population density and level of industrial activity in the direct vicinity of the pipeline, leaks can be ignited with a probability of 5%, while holes or ruptures are associated with probabilities of ignition of approximately 35% and 60%, respectively. A portion of this probability of ignition is auto-ignition, from the energy released and possible sparks generated in the occurrence of the hole or rupture.

In the case of immediate ignition, a jet fire would result, involving the generation of a flame up to several hundred metres in length for full ruptures. In the case that ignition is delayed, under the most unfavourable atmospheric and release conditions, a natural gas cloud could extend several hundred meters, until it ignites from an ignition source. The gas cloud would then ignite, flashing back to the origin, and resulting in a jet fire, lasting until the gas in the entire pipeline has been depleted.

The probability of occurrence of the above mentioned jet fires or flash fires from holes or ruptures gives probabilities for potentially harmful scenarios (i.e., associated with ignition) as follows:

Holes with release ignition – 1 in 10,000 per year; and Ruptures with release ignition – 1 in 15,000 per year.

3.3.3 Risks

In the instance of either a jet fire or a flash fire, environmental damage would likely result in the form of ignition and/or burning of vegetation. Such damage, however, would only result over the footprint of the jet or flash fire, unless humidity and wind conditions were conducive to secondary fire escalation. Because the pipeline contains only market-ready gas, there would be no pipeline releases of hydrocarbon liquids that could pool and affect ecosystem components, such as streams and wetlands.

In regard to public or third-party worker safety, the combination of the likelihood of the occurrence of an initiating accident, ignition probability, and likelihood of people being exposed results in individual


specific risks in the slightly over 1 in 1 million-per-year at the pipeline, reducing to an insignificant level below 1 in 1 million-per-year within 200 m of the pipeline.

In summary, it can be stated that risks from the proposed onshore pipeline segment, are low both for public and worker safety and environmental integrity.

3.4 Marine Spill Release Behaviour

The following is a summary of the spill behaviour modelling results presented in Appendix E. Refer to Appendix E for a detailed description of the environmental data and modelling approach used.


Small batch spills of diesel fuel or condensates from hose ruptures during transfer operations from a supply vessel or from platform storage facilities may occur. These spills are considered instantaneous events and are modelled by considering the surface spreading, evaporation, dispersion, emulsification and drift of a single patch or slick of oil. The Project’s design will build upon lessons learned from previous spill events in order to minimize potential risk for spills, including small platform-based spills. Spill prevention measures will include state-of-the-art environmental protection systems (Section 2.9) and treatment for the MOPU’s effluents, including deck drainage (Section 2.7.5).

Batch spill fate modelling was conducted for diesel fuel spill and condensate (10 and 100 barrels spill scenarios for both). There was found to be very little difference in the behaviour of the winter and summer oil spill scenarios. The small differences that do exist can be attributed to the warmer summer temperatures and slightly higher evaporation amounts prior to the full dispersion of the slicks. The following summaries provide descriptions of the fate of the various spill scenarios that apply to both seasons.

3.4.1.1 Diesel

The diesel spill fate results using the new MOPU location are very similar to those presented in the approved 2002 CSR. The only differences are in the distances traveled by the surface slicks and the dispersed oil clouds. These differences are not due to the change in platform location but rather due to errors that have since been identified in the approved 2002 CSR modelling. Most of the distances are shorter in the new model results when compared to those reported in the approved 2002 CSR; the only case where the distance has increased is in the dispersed oil cloud travel distance for the 100 barrel winter spill scenario.


The 100-barrel batch spill of diesel will also lose about 30% through evaporation, persist as a slick for about 19 hours and travel about 18 km prior to the complete loss of the surface oil. The maximum dispersed oil concentration for this spill will be about 4 ppm and this will drop to 0.1 ppm within about 43 hours. The dispersed oil cloud will travel about 54 km and have a maximum width of about 4 km. Prevailing water currents would take the dispersed condensate cloud in a southwest direction away from Sable Island (located approximately 48 km from Deep Panuke). Therefore, no diesel is predicted to reach the shores of Sable Island.

The 10-barrel batch spill of diesel will lose about 30% through evaporation, persist as a slick for about 13 hours and travel about 12 km prior to the complete loss of the surface oil. The maximum dispersed oil concentration for this spill will be about 2 ppm and this will drop to 0.1 ppm within about 16 hours. The concentration of 0.1 ppm of total petroleum hydrocarbon is the exposure concentration below which no significant biological effects are expected, based on historical laboratory research. The dispersed oil cloud will travel about 14 km and have a maximum width of about 1 km.

3.4.1.2 Condensate

The condensate spill fate results using the new MOPU location are very similar to those presented in the approved 2002 CSR. The only differences are in the distances traveled by the surface slicks and the dispersed condensate clouds. These differences are not due to the change in platform location but rather due to errors that have since been identified in the approved 2002 CSR modelling. Most of the distances are shorter in the new, updated, model results when compared to those reported in the approved 2002 CSR; the only cases where the distance has increased are in the dispersed condensate cloud travel distance for the 10-barrel and 100-barrel winter spill scenarios.

Both the 10- and 100-barrel batch spills of condensate will evaporate and disperse very quickly. These batch spills are likely to persist on the surface for less than half an hour and travel only 400 to 700 m from the release point prior to dissipation under average wind conditions. The maximum condensate concentrations from these spills are estimated to be between 28 to 45 ppm. The dispersed oil concentration for the 10-barrel spill will drop to 0.1 ppm within about 15 hours. The dispersed condensate cloud will travel about 7 km and reach a maximum width of about 1 km. The dispersed oil concentration for the 100-barrel spill will drop to 0.1 ppm within about 41 hours. The condensate cloud for the larger release will travel about 24 km and reach a maximum width of 4 km.


3.4.2 Blowouts and Pipeline/Flowline Ruptures

The blowout liquid and gas flow rates were reduced for the new Deep Panuke modelling when compared to the approved 2002 CSR. Overall, lower flow rates reduced the size of potential impact zones. The spill fate described below can be applied to all of the well locations being considered in the Deep Panuke project. Only very minor differences in the fate of the condensate from spills at F-70, D-41, M-79A, H-08, H-99, and D-70 wells as well the northeast extreme location for future wells were evident when the subsea blowout scenario was run at these locations. The summary provided below in Section 3.4.2.1 is representative of the typical subsea blowout from all these sites. Pipeline and flowlines failure scenarios have been modelled as mini subsea blowouts, and are therefore also included in that section.

3.4.2.1 Fate and Behaviour of Subsea Well Blowout and Pipeline/Flowline Ruptures

The results of the production well subsea blowout modelling from the Deep Panuke formation indicate that thin condensate slicks or sheen will form initially over a width of about 1.8 km. The slicks will be about 3 µm thick and will disperse within minutes under average winds. The initial in-water condensate concentrations from these releases will be less than 0.2 ppm. Condensate concentrations will drop to 0.1 ppm within 8 hours if the modelled evaporation estimates (27-34%) are used. If 50% of the condensate is assumed to evaporate (a more likely estimate), the in-water condensate concentrations will drop to 0.1 ppm within about 4 hours. The width of the condensate cloud will be 2 to 2.5 km when it reaches 0.1 ppm.

The fate of the acid gas injection well subsea blowouts will be similar to the production well blowouts. These slicks will start out about 900 m wide and 8 µm thick and persist on the surface for a very short time. The initial in-water condensate concentrations from these releases will be about 0.6 ppm and will drop to 0.1 ppm within 15 hours. The width of the condensate cloud will be about 2 km when it reaches 0.1 ppm after traveling between 4 and 6 km from the release point.

The pipeline failure modelling assumes full production flow rates for the gas and condensate. The results of the modelling are valid for the case where the pipeline or flowline are not shut in and continue to flow for an extended period. This would be considered a worst case scenario. For example, a flowline could be ruptured and the SSIV in the well or valves on the subsea well tree fail when attempts are made to shut in the well feeding the flowline. The flowline would release product until the well flow is stopped. This would be a very low probability event.

The fate of the subsea production flowline releases will also be similar to the well subsea blowouts. These surface slicks will start out about 1340 m wide and 7 µm thick and persist on the surface for a very short time. The initial in-water condensate concentrations from these releases will be about 0.5 ppm


and will drop to 0.1 ppm within 19 hours. The width of the condensate cloud will be about 3 km when it reaches 0.1 ppm after traveling for between 5 and 8 km from the release site.

The fate of the subsea acid gas injection flowline releases will also be similar to the well subsea blowouts. These slicks will start out somewhat narrower (520 m wide) and thicker (20 µm thick) but will also persist on the surface only for a very short time. The initial in-water condensate concentrations from these releases will be about 1.3 ppm and will drop to 0.1 ppm within 16 hours. The width of the condensate cloud will be about 2 km when it reaches 0.1 ppm after traveling for between 4 and 7 km from the release site.

The fate of the SOEP Subsea Option pipeline release will also be similar to the other subsea releases modelled. These slicks will start out about 1.5 km wide and 6.5 µm thick and persist on the surface for a very short time. The initial in-water condensate concentrations from these releases will be about 0.5 ppm and will drop to 0.1 ppm within 19 hours. The width of the condensate cloud will be about 3 km when it reaches 0.1 ppm after traveling about 5 km from the release site.

3.4.2.2 Surface Blowout Fate and Behaviour

Surface blowouts associated with production wells will generate relatively narrow (about 200 m wide) and relatively thin (7 µm) slicks. About 70% of the condensate will evaporate in the air prior to reaching the water surface and the remaining condensate will disperse into the water within minutes, under average wind conditions. The resulting dispersed condensate clouds will diffuse to 0.1 ppm condensate concentration in 4 hours and have a width of about 500 m at this point about 1 km from the release point. The surface slicks will persist for only several minutes prior to dispersing; therefore, no condensate will reach the shores of Sable Island or mainland Nova Scotia.

The fate of the acid gas injection well surface blowouts will be very similar to the production well blowouts. The initial slicks will be about 150 m wide and 15 µm thick. About 70% of the condensate will evaporate in the air prior to reaching the water surface and the remaining condensate will quickly disperse into the water. The resulting dispersed condensate clouds will diffuse to 0.1 ppm condensate concentration in 5-7 hours and have a width of about 600 m at this point about 1 to 2 km from the release point.

No condensate is predicted to reach the shores of Sable Island (approximately 48 km away) or mainland Nova Scotia. The distance the surface condensate slick will travel is a function of the evaporation and dispersion rate, and the surface drift speed of the slick. The condensate release from the Uniacke G-72 incident is an example of an accidental event where there was no detectable condensate (surface slicks, aerosols or in-water condensate) at distances greater than 10 km from the source (Martec Limited 1984).


The Uniacke blowout occurred February 22, 1984 and continued for 10 days. The gas and condensate aerosol plume was estimated to rise approximately 10 m above its point of exit at the rotary table on the drilling floor. The slick that formed from the condensate fallout was approximately 300 m wide near the source and spread to a width of approximately 500 m. It was estimated that between 50 to 70% of the condensate volume evaporated in the air prior to reaching the water. Seventy-five percent of the slick area was estimated to be 1.8 m thick. Condensate was detected in the upper 20 m of the water column, up to 10 km from the well, in concentrations generally below 100 ppb. The maximum in-water condensate concentration measured was 1.5 ppm. The slick was observed to physically dissipate once the well was capped and there were no visual observations of a residual slick on over-flights the day after capping (day 11 after the blowout) (Martec Limited 1984).

3.4.2.3 Comparison of Modelling Results with Approved 2002 CSR

A general comparison of the new offshore spill modelling results with those presented in the approved 2002 CSR is provided in Table 3.2. In general, the new modelling results present potential impact zones similar to or smaller than those identified in the approved 2002 CSR.

Table 3.2 Comparison of New Modelling Results with Approved 2002 CSR Modelling Results

Spill Scenario New Spill Fate Results Compared to Approved 2002 CSR

Batch Diesel - 10 and 100 barrel Different travel distances (less in most cases) of surface slicks and oil clouds; otherwise fate of oil as in approved 2002 CSR

Batch Condensate - 10 and 100 barrel Different travel distances of surface slicks and oil clouds; otherwise fate of oil as in approved 2002 CSR

Subsea Well Blowouts (various sites) Lower condensate and gas flow rate reduces impact zone sizes when compared to approved 2002 CSR New locations and depths result in insignificant differences in general fate and trajectory when compared to approved 2002 CSR

Surface Well Blowouts (various sites) Lower condensate and gas flow rates reduce impact zone sizes when compared to approved 2002 CSR New locations and depths result in insignificant differences in general fate and trajectory when compared to approved 2002 CSR

Acid Gas Injection Well Blowouts (subsea and surface)

Smaller condensate and gas flows reduce impact zone compared to approved 2002 CSR

Subsea Production Flowline Release Modelled as a mini blowout of full flowline flow release - short-lived event Impact zone sizes similar to new subsea blowout results that are smaller than those presented in the approved 2002 CSR

Subsea Acid Gas Injection Flowline Release Modelled as a mini blowout of full flowline flow release - short-lived event Impact zone sizes similar to new subsea blowout results that are smaller than those presented in the approved 2002 CSR

SOEP Subsea Option Pipeline Release Modelled as a mini blowout of full pipeline flow release - short-lived event Impact zone sizes similar to new subsea blowout results that are smaller than those presented in the approved 2002 CSR


4 ENVIRONMENTAL MANAGEMENT

Environmental protection is fundamental to EnCana’s operations and forms an integral part of its Environment, Health and Safety (EHS) Management System. EnCana is committed to the implementation of the international best practices for Environmental Management Systems. This section outlines EnCana’s commitment to health, safety and environmental management, with an emphasis on environmental management for the Deep Panuke Project.

4.1 Environmental Management Framework

EnCana’s environmental management framework, shown in Figure 4.1, shows Project-specific plans as an integral part of EnCana’s corporate responsibility policy framework. These plans will be developed and continually revised as the Project moves through the phases of design, construction, installation, production, and decommissioning. Inherent in the environmental management system is the provision for continual improvement, and adaptability to allow the system to respond to environmental challenges so that predicted and actual effects are managed effectively.

Proposed tables of contents for the following plans are provided in Appendix G:

Deep Panuke Spill Response Plan; Deep Panuke Emergency Management Plan (DPEMP); Environmental Effects Monitoring Plan (EEMP); and Environmental Protection Plan (EPP).

This list of environmental plans for the Project has been modified from that presented in Appendix G of the approved 2002 CSR to accurately reflect the current Deep Panuke environmental management system. The EPP will cover practices (referred to as plans in the approved 2002 CSR) such as waste and chemical management, physical environmental monitoring, and activities associated with onshore and offshore construction and decommissioning. EnCana’s Codes of Practice for Sable Island, Country Island and the Gully MPA will also be included in the EPP. The EPP will also affirm EnCana’s adherence to the CNSOPB Compensation Guidelines Respecting Damages Relating to Offshore Petroleum Activity.

Details of the above-mentioned plans will be finalized once the Project design is finalized. The plans will be developed in consultation with the applicable regulatory agencies to ensure that their concerns are addressed in the planning process. Full versions of these plans will be provided to the regulators prior to Project start-up.


Figure 4.1 Deep Panuke Environmental Management Framework

4.1.1 Corporate Responsibility Policy

EnCana’s Corporate Responsibility Policy is built on the following eight areas of commitment that reflect existing and emerging benchmarks of Corporate Responsibility:

1. Leadership Commitment; 2. Sustainable Value Creation; 3. Governance & Business Practice; 4. Human Rights; 5. Labour Practices; 6. Environment, Health & Safety; 7. Stakeholder Engagement; and 8. Socio-Economic & Community Development.

Under this Policy, EnCana is committed to:

a) safeguarding the environment and operating in a manner consistent with recognized global industry standards in environment, health, and safety;

Corporate Responsibility Policy

EnCana EHS Best Practices Management System

Deep Panuke EHS Management System Guidance Manual

Stakeholder Consultation

Deep Panuke Environmental Effects

Monitoring Plan

Deep Panuke Emergency Management Plan

Deep Panuke EnvironmentalProtection Plan

Deep Panuke Spill Response Plan


b) striving to make efficient use of resources, to minimize its environmental footprint, and to conserve habitat diversity and the plant and animal populations that may be affected by its operations; and

c) striving to reduce its emissions intensity and increase its energy efficiency.

4.1.2 EHS Best Practice Management System

The EnCana EHS Best Practice Management System is a corporate-wide safety and environmental management system designed to guide all levels of employees, contractors and sub-contractors in achieving the desired level of EHS performance. The ten elements that make up the best practices focus on areas that are applicable to all operating entities within EnCana, and consist of:

1. Leadership; 2. Managing risk; 3. Emergency preparedness and response; 4. Assuring competency; 5. Conducting our business responsibly; 6. Ensuring contractor and supplier performance; 7. Managing incidents; 8. Documentation management; 9. Reporting EHS performance; and 10. Evaluating system effectiveness.

By following the programs, practices and procedures stemming from the best practices, the company meets its required accountabilities and in turn demonstrates sound EHS performance to its stakeholders.

Environmental management expectations and requirements are outlined for each of the ten elements and include the following:

setting of environmental goals and performance objectives, and measurement and communication of performance; environmental risk assessment; emergency response planning and preparedness; training and competency to ensure that employees are aware of and trained on the environmental responsibilities associated with their job activities;practices to ensure environmentally-sound performance throughout the lifecycle of the asset; compliance with permits, regulations and legal requirements; evaluation and selection of third party goods and services for conformance with environmental standards and requirements;


reporting, investigation and follow-up of environmental incidents; and system audit to identify opportunities for continuous improvement.

4.1.3 Deep Panuke EHS Management System Guidance Manual

The Deep Panuke EHS Management System Guidance Manual provides guidance to project staff in implementing the expectations and requirements of the corporate EHS management system. The environmental component will provide an umbrella for environmental protection planning, environmental monitoring, and stakeholder consultations. It will provide a framework to document, evaluate and communicate Project environmental performance.

4.2 Stakeholder Consultation

Inherent in the EnCana EHS Management System is the provision for stakeholder consultation, especially in relation to environmental issues. Stakeholders for the Deep Panuke Project include regulatory agencies, the fishing industry, non-government organizations, and the general public. With respect to environmental management, effective consultation is crucial for issues such as environmental assessment, EEM, environmental protection, emergency response and compensation.

The objectives of the consultation program for the Deep Panuke Project are as follows:

provide information to the public and interested stakeholders about the proposed Project in a timely fashion; provide opportunities for the public to have input into the Project to identify issues and concerns; provide early and adequate notice of these opportunities for involvement and input; seek advice from the scientific community to enhance environmental management; and develop relationships with the First Nations and Aboriginals and with stakeholders that can lead, where appropriate, to mutually beneficial relationships throughout the life of the Project, and also contribute to communications around other EnCana activities.

Section 5 and Appendices H and I of this EA Report describe the Project’s public consultation and communication program during various stages of the Project.


4.3 Deep Panuke Emergency Management Plan

The Deep Panuke Emergency Management Plan DPEMP will contain specific provisions for the notification, assessment and response to environmental incidents. Specifically, the DPEMP will provide emergency response command and control functions for both onshore and offshore emergency situations and will cover foreseeable emergencies during all phases of the Deep Panuke Project lifecycle. The DPEMP will take into account hazard identification and assessment, environmental considerations, consultation with government agencies, incorporation of industry best practice and use of external support resources.

4.4 Deep Panuke Spill Response Plan

The Deep Panuke Spill Response Plan will be subset of the DPEMP; the table of contents is shown in Appendix G. The purpose of this plan is to respond to spills that may result during offshore activities related to the development of the Deep Panuke Project. The plan will include planning considerations, response, and spill environmental effects monitoring. EnCana will make arrangements with third-party contractors for onshore spill response and clean-up.

4.5 Deep Panuke Environmental Effects Monitoring Plan

As part of its commitment to adaptive ecosystem management, EnCana will implement an EEMP for the lifecycle of the Project. The EEMP will take into account:

environmental effects predictions in the approved 2002 CSR and this EA Report and resulting CSR;findings of the EEM program; mitigation measures for various effects, and issues that may arise regarding environmental sustainability. The issues to be addressed by EnCana include but are not limited to:

- development of follow-up program principles; - refining the EEMP with updated information on marine birds; - management of spills and effects on marine birds; - influence of lighting and flaring on birds; - development of a program to monitor project effects on the roseate terns; - development of a program to discourage all-terrain vehicle traffic on the pipeline RoW; - verification of the absence of species of special concern; - verification of the impacts of drilling muds and cuttings; - applicability of the national pollutant release inventory;


- verification of the impacts of produced water discharges; and - consideration of resident organisms in the vicinity of the Project and contaminant

transport.

Specific programs to address these issues will be developed in consultation with the regulatory authorities having jurisdiction in such matters. It is anticipated that this planning process will be managed by the CNSOPB.

4.6 Environmental Protection Plan

EnCana will implement environmental protection measures, which will be documented in an EPP, to mitigate potential environmental effects from its activities. The EPP for EnCana’s Deep Panuke Project will be developed during the detailed engineering phase of the Project in consultation with regulators and key stakeholders. It will be developed to ensure the implementation of EnCana’s environmental commitments. The EPP will be updated as required over the life of the Project and will be consistent with the requirements of the CNSOPB’s regulations and guidelines.

The EPP will include environmental protection procedures for general activities common to all phases in the Project lifecycle. The EPP will cover the various Project phases/activities/procedures to provide clear and specific instruction and guidance to employees and contractors during these short term, but critical, phases of Project development. The EPP will cover practices (referred to as plans in the approved 2002 CSR) such as spill response, waste and chemical management; activities associated with onshore and offshore construction and decommissioning and compensation for fishing and aquaculture vessel and gear damage. Corporate environmental Codes of Practice will also be included in the EPP. The strategy and overall approach to spill response will be dealt with in the DPEMP.

Objectives

The EPP will be developed to provide detailed guidance, in particular for Project personnel (including contractors), on methods of eliminating or minimizing and mitigating adverse environmental effects from the Project. Specific objectives will be to:

ensure that EnCana’s commitments to minimize environmental effects are met; document environmental concerns, applicable legislative requirements and appropriate

protection measures; provide clear and specific guidance to employees and contractors regarding procedures for

protecting the environment and minimizing environmental effect; provide a field-usable, reference document for personnel when planning and/or conducting

specific activities;


provide for appropriate training of employees/contractors; communicate changes in procedures through the specified revision process; and provide procedures for monitoring compliance with applicable regulations.

Scope

This document is applicable to all EnCana Deep Panuke operations, both offshore and onshore. All EnCana and third party personnel working on the Deep Panuke Project will be required to adhere to the requirements of the EPP. The EPP will be reviewed at least annually during the life of the Project to ensure its effectiveness.

Integration with Deep Panuke EHS Management System

The EPP will be a practical document containing environmental protection requirements and will serve as an important tool in staff orientation and training, and an integral component of environmental inspection under EnCana's Deep Panuke EHS Management System.

Environmental performance will be reviewed throughout the life of the Project. The EPP will reflect the commitments that EnCana has made in the EA Report and other DPA documentation, regulatory conditions of approval, and other regulatory requirements of the Project, and will be a critical tool in understanding and evaluating these commitments.

EPP Requirements

An important aspect of the EPP is environmental compliance monitoring (ECM), which ensures compliance with all regulatory requirements and self-imposed environmental commitments. EnCana will use ECM to monitor performance standards developed for the Project. ECM will primarily involve monitoring for conformance with the discharge limits identified in the OWTG (NEB et al. 2002) and targets set by EnCana.

ECM procedures will be clearly defined in the EPP including sampling protocols, responsibilities, requirements for training, and reporting. The plan will address routine and abnormal conditions and emergencies that can reasonably be anticipated. Specifically, the CNSOPB’s Nova Scotia Offshore Area Petroleum Production and Conservation Regulations stipulate the development of a program to monitor the effects on the natural environment of routine operations of a production installation, and identification of the measures adopted to minimize or mitigate these effects. Compliance monitoring programs ensure that the composition of operational discharges is in accordance with the limits specified in the EPP.


Contractors’ environmental protection measures for particular scopes of work such as those related to construction and installation activities, will comply with the EPP.

The EPP will also include EnCana’s Codes of Practice for Sable Island, the Gully MPA and Country Island. The intent is to provide requirements for the development and implementation of the Deep Panuke Project so that sensitive and valued local environmental components are protected. All EnCana personnel and its contractors must comply with these Codes. For further detail on these Codes, refer to Appendix G.

Responsibilities

To ensure the successful implementation of environmental protection procedures, the EPP will include a clear description of the roles and responsibilities of all personnel having environmental responsibilities. This description will provide clear direction related to accountability, lines of communication and reporting relationships.


5 PUBLIC CONSULTATION PROGRAM

5.1 Consultation Program Background and Objectives

A substantial consultation process on the Project took place between 2000 and 2002 as part of the process culminating in the environmental assessment and the submission, review, and Ministerial approval of the CSR in December 2002. A diverse variety of groups and individuals participated, including nearshore and offshore fishing interests, local municipalities and regional development authorities, residents and businesses in the Guysborough County area, scientists, regulatory agencies, environmental non-governmental organizations (ENGOs), and the interested general public. This consultation program facilitated stakeholder input to the preparation of the approved 2002 CSR and Project planning.

Seeking public and stakeholder input remains a core principle of EnCana’s management approach and is a requisite component of CEAA environmental assessment process. Therefore in 2006, as part of the regulatory process for the current application for the revised Project and in accordance with its management practices, EnCana initiated a public consultation program. The purpose of the 2006 round of consultations was to ensure that stakeholders and the interested public received up-to-date information, specifically on the changes proposed by EnCana to the Project. In addition, the consultations were designed to offer the public an opportunity to respond to these Project changes and provide input into Project planning, including finalization of the EA Report.

The consultation program also sought to update information on stakeholder groups relevant to the Project and identify any changes in stakeholders’ activities or areas of interest (commercial, ecological, administrative, or regulatory) since the previous round of consultation four years ago. This process was also intended to advise stakeholders of future opportunities to engage in the regulatory process and form the basis for ongoing communication and consultation during the application review, post application follow-up process, and ultimately, Project construction, operation and decommissioning. EnCana will continue to provide information about the Project to interested stakeholders and to solicit input to avoid or minimize potential adverse effects and enhance positive effects of the Project. In particular, the EA regulatory review will include a public review of the draft Scoping Document from the RAs, an Information Request period on the Deep Panuke regulatory filings, including the EA, and public comments on the 2006 draft CSR.

The 2006 consultation program for the preparation of the EA was largely conducted between July and October 2006. It targeted a similar set of stakeholders as the previous process, but also included several new or emerging organizations that had not been previously consulted. The communications and consultation process involved various forms of interaction including electronic communication, phone contact and interviews, face-to-face interviews and meetings with individuals and small groups, group


presentations and discussions, as well as a public open house in Isaacs Harbour.1 The consultation program involved activities by EnCana staff and its consultants (the Study Team).

The objectives of the EA consultation program are summarized below:

provide information to the public and interested stakeholders about the proposed Project, with specific focus on Project modifications since the previous round of consultations, in a timely fashion;provide opportunities for the public to have input into the Project to identify issues and concerns, with focus on Project modifications; provide early and adequate notice of these opportunities for involvement and input; obtain updated information on relevant stakeholder activities for Project planning; seek advice from the scientific community to enhance environmental management; and contribute to communications around EnCana activities and to the development of mutually constructive relationships with all EnCana stakeholders.

5.2 Consultation Activities

5.2.1 Public Consultation Stages

In accordance with timelines of the Project development, environmental assessment, and regulatory processes, the public consultation program for the EA was largely concentrated over approximately two months (July to October 2006) and consisted of the following three phases:

Phases I Stakeholder Identification and Preliminary Communications;Phases II Consultation on the Project Description, Issues Identification and Scoping; and Phases III Follow-up and Ongoing Communication.

5.2.2 Phase I - Stakeholder Identification and Preliminary Communications

Identification of stakeholders was based on information gained during the previous consultation process updated by consultation with relevant industry, community and ENGO organizations. This stage included discussion with the Nova Scotia Environmental Network (NSEN) to update identification and invitation of ENGOs to the consultation process. Recommendations from the DFO and the Fisheries Advisory Committee (FAC) of the CNSOPB assisted in providing current information on fisheries and Aboriginal fishing interests. Similarly, communication with the Municipality of the District of Guysborough and the Guysborough County Regional Development Authority (GCRDA) served to

1 An additional Open House is planned for the town of Guysborough, NS on November 8, 2006.


update information on local community and business stakeholders. This stage of the consultation program involved the following:

establishing initial stakeholder contact; confirming stakeholder contact information and consultation interest; sharing information about the Project, including a preliminary outline and scope of the proposed

Project, and specific identification of new or revised Project elements; providing consultation guides that outline and suggest a consistent format for information

gathering, issues identification and communication of concerns or opinions; identifying and scheduling of appropriate and preferred methods of consultation; and providing early notice of upcoming opportunities for consultation on the Project.

Contact was initiated with most stakeholders through telephone conversations and/or email. A Project overview package consisting of a draft Project description, map, and table summarizing the differences between the approved 2002 CSR Project basis and the revised Project basis (Appendix H) was distributed to all targeted stakeholders. In addition, a consultation guide consisting of a set of preparatory questions for interviews or consultation meetings was customized for various stakeholder groups and sent to them prior to the interviews or consultation session(s) (Appendix H). A consultation record was developed to keep track of all contact with stakeholders and topics raised in consultation to ensure that this input was communicated to the Study Team and EnCana staff.

In general, there was a high degree of success in contacting, communicating with, and scheduling subsequent consultation sessions. Most groups were interested and able to participate during the EA. In some cases, for example with the Sable Island Green Horse Society, it was not possible to arrange in person or phone interviews, but alternative means of sharing Project information and inviting comments were identified. The Ecology Action Centre, a provincial ENGO which had participated in the 2000-2002 consultation process, declined to participate citing frustration with the previous Provincial and Federal regulatory processes regarding energy projects and a decision that costs (both time and personnel) to engage outweighed perceived benefits.

Table 5.1 lists stakeholders contacted during Phase I.


Table 5.1 Stakeholders Contacted During Phase I Fisheries Groups Area 24 Crab Fisherman’s Association Atlantic Aqua Farms, NS Limited (Country Harbour Sea Farms Ltd) Atlantic Herring Co-operative Clearwater Seafoods Limited Partnership Eastern Fishermen's Federation Eastern Shore Fishermens Protective Association Maritime Fisherman’s Union Local 6Guysborough County Inshore Fishermen's Association Shelburne County Quota Group Nova Scotia Sword Fishermen’s Association Seafood Producers Association of Nova Scotia (SPANS) Sambro Fisheries Limited Nova Scotia Fixed Gear 45-65 Scotia Fundy Mobile Gear Fishermen’s Association Sea urchin harvester (McGrath, Manthorne) Environmental Non-Governmental Groups (ENGOs) Canadian Parks and Wilderness Society Clean Nova Scotia Foundation Coastal Coalition Coastal Communities Network Ecology Action Centre World Wildlife Fund Sierra Club of Canada Sable Island Green Horse Society Sable Island Stakeholder Committee Nova Scotia Leatherback Turtle Working Group Nova Scotia Environmental Network Government Natural Resources Canada Department of Fisheries and Oceans Nova Scotia Department of Agriculture and Fisheries Guysborough County Regional Development Authority Municipality of the District of Guysborough Aboriginal Groups Maritime Aboriginal Aquatic Resources Secretariate Each of the Chiefs of the thirteen (13) Bands in Nova Scotia (Appendix I) Confederacy of Mainland Mi’kmaq (Appendix I) Union of Nova Scotia Indians (Appendix I)


5.2.3 Phase II – Consultation on the Project Description, Issues Identified and Scoping

Consultations with stakeholders took place largely between late July and October 2006. To the degree feasible, consultation sessions were customized to the needs, interests and preferences of the stakeholders, both in terms of format and content. The main content of the consultation sessions consisted of the following:

explaining the scope of the revised Project and alterations or refinements in design compared to the approved 2002 CSR Project basis; outlining the two Project options for gas (and potentially condensate) export currently under consideration and their implications; identifying the relationship between Project revisions and associated prospective changes to environmental or socio-economic impacts and mitigation measures; discussing the environmental and socio-economic assessment, and regulatory processes with most attention to issues identification and scoping;gathering information about ways in which the needs and interests of stakeholders might have changed since the last round of consultations; gathering information about any new or priority concerns or issues stakeholders might have regarding the Project; recording and communicating the issues identified by stakeholders to the appropriate members of the Study Team and to EnCana staff, for consideration, response, clarification or action;outlining the future regulatory process and schedule, including informing stakeholders as to future opportunities to offer input into this process; andclarifying expectations regarding future and ongoing communications.

A summary of the consultation activities is provided below; details are provided in Appendix H:

Two meetings were held with DFO (July 25 and August 9, 2006) to introduce the Project, address any comments, and determine the best way to gather information required for the EA, as well as how best to consult with other fisheries, scientific and other stakeholders.

Several meetings were held with the Municipality of Guysborough and the GCRDA (between August and October 2006) to discuss Project plans, particularly the evaluation of routing options onshore, interactions with other land uses and plans, economic benefits and potential local access to gas for further industrial development.


A meeting was held with ENGO representatives (August 15, 2006) to review the Project plan and discuss design and implementation of Project options, with particular focus on potential interactions with or impacts on valued environmental components. A number of questions, concerns and issues were brought forward. Some were discussed or answered during the meeting. Others were referred for future response or directed to the Study Team or EnCana staff for consideration and potential inclusion in assessment studies. Eight of ten invited ENGOs were represented at this meeting.

Fisheries and aquaculture interests were interviewed via telephone and in person meetings. Approximately ten substantive phone conversations or interviews were conducted and six face-to-face consultation meetings or group presentations (in Halifax, Goldboro, Truro, and Sherbrooke) took place with fishing stakeholders to inform them of the revised Project design and solicit input.

One Open House was advertised and held in the Goldboro area (Isaacs Harbour Fire Hall) on September 13, 2006. The presentation included story boards and maps of the Project; including key facts, figures and processes, and of the existing onshore and nearshore environment. These encompassed offshore and onshore Project facilities, pipelines and tie-ins (for both options), Project location and spatial extent, data on fisheries and aquaculture in the Project area, regulatory processes and timelines. Approximately 75 participants attended and were provided takeaway information on the Project and given the opportunity to provide comment through conversation with members of the Study Team and EnCana staff and/or through written comments. Staff in attendance recorded comments and questions for consideration in Project planning, environmental and socio-economic assessment, or to ensure follow-up. An additional Open House is to be held in the town of Guysborough on November 8, 2006. A meeting was held with the FAC of the CNSOPB on September 13, 2006. An update was provided on the Project plan, including a discussion of design and implementation of Project options. Discussions with fisheries stakeholders focussed on the regulatory process, consultation, environmental management, and environmental effects monitoring (EEM).

The input and comments received through this program were broad ranging and reflected a variety of perspectives about the value, need and scope of the Project, and about oil and gas development offshore Nova Scotia generally. Various perspectives were also recorded regarding preference or issues associated with the two export pipeline options. This input was incorporated into the environmental and socio-economic assessment process. Key topics raised are listed in Section 5.3 and addressed as appropriate in the relevant EA sections.


5.2.4 Phase III - Follow-up and Ongoing Communication

Pursuant to the initial set of consultations, EnCana staff and the Study Team continued follow-up and ongoing communication. Follow-up consisted primarily of responses to requests for information or concerns raised during the consultations. During the consultations, EnCana informed stakeholders as to the ways in which they can continue to give input into the Project during subsequent stages in the regulatory process (e.g., review of the EA Report). EnCana will continue to proactively communicate about the Project with interested stakeholders and will provide supplementary information as part of this ongoing process. In general, EnCana remains committed to communication concerning public and stakeholder concerns and the development of mutually constructive relationships.

5.2.5 Aboriginal Communications

The goal of communications with Aboriginal groups is to establish relationships and initiate discussions with respect to the currently proposed Project and to highlight the findings and conclusions of the approved 2002 CSR, respecting Aboriginal related matters, as well as EnCana’s commitments on Aboriginal matters in its 2002 Project submissions. EnCana’s current Aboriginal communication program (the Program) has been undertaken with the advice and recommendation of the Province of Nova Scotia, with guidance from the Province’s draft policy on consultations with the Mi’kmaq, dated June 14, 2006.

The first phase of the Program was to identify the Aboriginal groups who may have an interest in the Project and establishing initial contact with such groups. For that purpose, introductory letters (see Appendix I) were sent to the following organizations in July, 2006:

each of the Chiefs of the thirteen (13) Bands in Nova Scotia (Appendix I); the Confederacy of Mainland Mi’kmaq (Appendix I); and the Union of Nova Scotia Indians (Appendix I).

EnCana received a reply (see Appendix I) to the introductory letters to the aforementioned groups from the Lead Negotiator for the Planning and Priorities Committee of the Assembly of Nova Scotia Mi’kmaq Chiefs, advising that the legal entities entitled to engage in consultation issues are the 13 First Nations through their Chiefs and Councils and that the Lead Negotiator acts on their behalf in such matters through a delegated authority granted by Band Council Resolution by one or more Chief and Councils.


EnCana replied to the Lead Negotiator (see Appendix I) advising, among other things, of a prior Technical and Ecological Knowledge survey carried out in an area where the Deep Panuke onshore pipeline is anticipated to be located and of EnCana's commitments to Aboriginal people in its approved 2002 CSR to include Aboriginal representatives in pipeline right-of-way inspections.

EnCana also consulted with the Maritime Aboriginal Aquatic Resources Secretariate (MAARS) with respect to potential fisheries interactions with the Project.

5.3 Integration of Issues and Concerns into Project Planning

Through the preliminary communications, stakeholder meetings (including fisheries and ENGO sessions), phone conversations, written submissions, and Open House, EnCana gathered a wide range of questions, issues and concerns. EnCana was able to identify a number of key issues requiring further evaluation and attention. The key topics raised were organized into the following categories:

acid gas injection technology and sour gas; offshore pipeline/flowlines routing and installation; onshore pipeline routing and installation; drilling activities and use of drilling muds; effects on fishing activities; offshore safety zone, dimensions and fishing restrictions; effects on the ecosystem, particularly benthic communities, species at risk and commercial

species; air quality impacts; impacts associated with greater levels of produced water; health and safety of workers and nearby fishers; large scale or consequential accidental or emergency events and spills; cumulative effects such as climate change; economic benefits, employment and training; monitoring of impacts; and residual effects resulting from and following decommissioning.


Questions, issues and concerns identified through the consultation process were tracked and forwarded to the appropriate EnCana personnel and consultants for consideration in Project planning and the environmental assessment. These inputs have been utilized to:

identify the environmental and socio-economic issues of concern and to incorporate relevant issues into the assessment;

improve Project planning and/or Project design; and supplement information and knowledge of the biophysical and socio-economic environment to

enhance mitigation strategies.

EnCana has responded to issues and concerns brought forward by stakeholders in a variety of ways, including immediate response at Open Houses and meetings, follow-up communications, and within the EA Report. Table 5.2 outlines the means by which issues and concerns have been addressed. As detailed planning proceeds, EnCana is committed to continuing discussions with stakeholders and the public.

Table 5.2 Integration of Key Issues Overview

Issue and Primary Concerns ResponseNeed to retain access to the quahog resource and concern over potential contamination.

The impact on the new quahog fishery is assessed in Section 9.3. Clearwater has indicated that quahogs would be harvested intensively from the offshore project area on Sable Island Bank prior to the start of construction. The potential for effects on this fishery will be limited due to the long period (15-20 years) for quahogs to reach commercial size.

Maintaining access to the fisheries is a primary concern. The main pipeline should be trawlable.

The impact on fisheries due to potential loss of access is assessed in Section 9.3. During operations, the safety zone around the MOPU, flowlines and subsea wellheads will exclude fishing activity, and this zone will be marked on nautical charts. The portions of the M&NP Option pipeline from landfall to KP22 and from KP110 to the MOPU (see Section 2) will be buried, as will the entire SOEP Subsea Option pipeline. With respect to exposed sections, the export pipeline is designed to withstand impacts from conventional mobile fishing gear in accordance with the DNV Guideline No. 13, Interference Between Trawl Gear and Pipelines, September 1997. There will be no fishing restrictions over the export pipeline (except the area immediately around the subsea connection to the SOEP pipeline for the SOEP Subsea Option). In the event there is hang-up or damage to gear, EnCana will adopt the CNSOPB Compensation Guidelines Respecting Damages Relating to Offshore Petroleum Activity.



Issue and Primary Concerns ResponseNeed to evaluate impacts of accidental release of hydrogen sulphide from the injection well and/or feeder line. Concern over potential impact on fish.

The potential effects of an accidental release of hydrogen sulphide on Air Quality (Section 8.1) and Marine Fish (Section 8.4) were evaluated. A blowout resulting in the release of large quantities of acid gas from an injection well and/or their corresponding flowlines could result in a significant adverse short-term effect to air quality, and could result in important consequences affecting the health and safety of workers on the MOPU and vessels within up to 6 km. However, such an event would be both extremely unlikely (see Section 3.2) and of short duration, with the probability of occurrence further reduced through good design practices and maintenance. EnCana will develop and implement the DPEMP (see Appendix G) to minimize the potential adverse effects on air quality and human health and safety. Any H2S in solution would be rapidly diluted to background levels and oxidized into less toxic chemical species. Therefore, as stated in Section 8.2.4.4, a subsea release of H2S is unlikely to cause significant adverse effects on marine fish and invertebrates.

Potential concern over produced water impacts on marine biota, including fish reproduction and development. Produced water discharge should be monitored regularly.

The potential effects of produced water on water quality (Section 8.2), marine benthos (Section 8.3), marine fish (Section 8.4) and marine related birds (Section 8.6) were assessed. Produced water will be treated on several levels on the platform prior to disposal (Section 2.4.1.9). The target dispersed oil concentration after treatment is 25 mg/L (30-day weighted average), below the OWTG limit of 30 mg/L. Also, the concentrations of amines and TEG in the produced water at the discharge outlet are below those concentrations that would impact marine species. Prior to discharge, the produced water will mix with approximately 2,400 m3/hr of seawater, further greatly reducing the concentrations of potential deleterious substances.

Need to make EEM reports and monitoring data available to the public as soon as possible.

EnCana will develop the offshore EEMP in collaboration with key regulatory agencies led by the CNSOPB. The EEM data will be required to be made public.

If horizontal directional drilling (HDD) is chosen in nearshore landfall area, there is concern that vibration will affect the lobster catch rates.

There is uncertainty regarding the impacts of HDD on lobster distribution and behaviour because of a lack of research; thus, EnCana will commit to avoiding the use of HDD during the nearshore lobster fishing season.

During construction and operations, need to communicate plans early with fishing companies including vessel captains so that fisheries can be better coordinated around EnCana's activities.

During construction, a Notice to Mariners will be issued to advise all ship captains of EnCana’s schedule and areas of activity. In addition, EnCana will communicate this information directly to managers of fishing organisations to facilitate fisheries planning. During operations, the safety zone around the MOPU, flowlines, and subsea wellheads excludes fishing activity. There will be no safety zones over the export pipeline, although there will be fishing restrictions over the subsea connection to the SOEP pipeline (SOEP Subsea Option). These zones will be marked on nautical charts.

Issue with pipes and flowlines remaining in the ground after decommissioning, rather than complete removal of all infrastructure.

Although regulatory requirements could change prior to the time of decommissioning and abandonment, current plans are for the pipeline, flowlines and umbilicals to be abandoned in place in compliance with applicable drilling and offshore regulations and according to standard international practice.

Multi-stakeholder monitoring advisory system desired.

EnCana will develop an offshore EEMP in collaboration with key regulatory agencies led by the CNSOPB.



Issue and Primary Concerns ResponsePotential impacts of drill mud and cuttings, including concern with the use of barite and the impacts of bio-available forms of mercury (methyl mercury) on the food chain.

The potential effects of barite used in drilling muds on the marine benthos were previously assessed in the approved 2002 CSR (see Section 6.3.3.4). The effects were predicted to be not significant. The results of the assessment remain valid. Barite is typically used to increase the density of drilling fluid. The type of drilling fluids used for Deep Panuke will be salt-based and the density will be adjusted by increasing the concentration of salt in the drilling fluid. Therefore, the use of barite will be minimized and generally only used for the preparation of high density slugs to pull the drill pipe out of the hole. Mercury occurs naturally in very small quantities in barite. The levels of mercury measured at drilling and production sites off the East Coast of Canada have consistently been very low. Furthermore, studies from the Florida Institute of Technology (Trefry et al. 1996) concluded that mercury introduced with barite during offshore drilling cannot be directly linked to enhanced levels of its bioavailable form, methyl mercury.

Request for an EnCana funded independent environmental monitoring program.

EnCana will develop the offshore EEMP in collaboration with key regulatory agencies led by the CNSOPB.

Need for EA to assess cumulative impacts such as impacts of the project on climate change and impacts of climate change on the Project.

The CEA Agency’s Guidelines for Incorporating Climate Change Considerations in Environmental Assessments requires that climate change be taken into consideration in the EA. The cumulative effect of the Project on climate change due to the emission of greenhouse gases is evaluated in Section 8.9. The estimated contribution of the Deep Panuke Project to total estimated GHG by all Canadian human-made sources is extremely small (0.3% of 2003 Canadian totals). Of note, the choice of acid gas injection incorporates permanent disposal of a significant quantity of CO2 that would otherwise be emitted to the atmosphere during hydrocarbon production. EnCana is committed to investigating other GHG reduction opportunities that arise during the Project. With respect to the effects of the environment on the Project (Section 10), facilities will be designed and installed based on the appropriate environmental design criteria to ensure the safety and integrity of these facilities during severe environmental conditions. The design of the structures incorporates an adequate factor to safely deal with anticipated changes in weather severity during the lifetime of the Project, including storms and sea level rise associated with climate change.

Impacts on biologic communities associated with authigenic-carbonates (communities and ecosystems that have been found to thrive on the natural off-gassing of oil and gas from the bottom of the ocean).

There are no known biologic communities associated with authigenic-carbonates in the Study Area, nor are there any known areas that could potentially support such communities.

Impacts of flares on migratory birds and consideration of protective shielding.

The potential impact of flaring events on marine related birds was assessed in the approved 2002 CSR (see Section 6.3.6.4), and predicted to be not significant.

Monitoring of invertebrate and other migrating pelagic species (e.g., jellyfish, mackerel, and herring) as an important part of the food chain to species at risk such as the leatherback turtles.

Observers will be used to monitor project activities, as required. In addition, it is expected that the EEM program will include monitoring of sentinel species, including fish and invertebrate species that may aggregate around the MOPU.

Observer data not always adequate (turtles have been grossly underestimated through aerial surveys). Options such as remote subsurface surveys should be considered.

In addition to observer data, there will be periodic ROV platform and pipeline videocamera surveys. Any sightings of species encountered will be reported as part of the EEM program.



Issue and Primary Concerns ResponseDemonstrating the relationship between EnCana and the ESSIM process goals.

The Project is consistent with the current ESSIM work, including the defined management actions and strategies. Furthermore, EnCana’s continued active involvement in the ESSIM process will help ensure that Project activities take place in the larger context of integrated ocean management planning and activities of other ocean users.

Pipeline is a concern as it may affect marine life. This includes disturbance of the sea bottom during construction and the potential for the release of toxic sediments.

The potential effects of the installation of the export pipeline on the marine benthos are evaluated in the approved 2002 CSR and in Section 8.3. Adverse effects are predicted to be not significant. New information has become available with respect to nearshore sediment contamination in Isaacs Harbour. Research conducted by NRCan to determine the impacts of historical mine tailings disposal on marine sediments show that the sediments at some sampling sites contain elevated levels of arsenic and mercury (see Section 7.1). However, the sampling points nearest the proposed nearshore pipeline corridor show much lower concentrations, and sampling during the 2001 nearshore pipeline route survey found no evidence of sediment contamination. Therefore, it is not expected that contaminated sediments will be encountered.

Potential interference between the proposed EnCana routing onshore and Keltic/Maple facilities. Corridor reserved for EnCana may overlap with Keltic/Maple land option and existing wetlands.

EnCana is in discussions with landowner(s) to finalize the routing of the onshore pipeline and location of associated onshore facilities. EnCana’s preference is to minimize environmental effects through avoidance of wetlands and other sensitive onshore environmental features. EnCana will ensure that all contractors adhere to an EPP during installation of the onshore facilities.

Introduction of exotic species (e.g.tunicates) via foreign vessels, which are known to foul mussel aquaculture gear. Require that vessels clean hulls before they come into coastal areas.

To date, there are no confirmed records of fouling of mussel aquaculture gear by tunicates in the nearshore Goldboro area (B. Hancock, Aqua Sea Farms, pers.comm. 2006). EnCana will ensure that all foreign vessels will replace their ballast water at sea before entering Canadian waters. It is neither feasible nor required for foreign vessels to have their hulls cleaned before they enter Canadian coastal waters.

Concerned that air quality be maintained, and avoiding the release of sulphur into the environment.

The potential effects of the Project on air quality were evaluated (Section 8.1). The only predicted significant adverse effect is with respect to the unlikely event of a well blowout or piping rupture resulting in the release of large amounts of acid gas. Such an event could have health and safety consequences for platform workers and individuals on vessels downwind. Design prevention measures, rendering such an event extremely unlikely, and emergency response contingency planning will further reduce the likelihood of significant adverse effects.

EnCana should work toward an agreement on principles of cooperation with fisheries interests.

EnCana’s public communications and consultation program will continue through all phases of the Project. EnCana prefers to continue its commitment to consult with stakeholders, including fisheries interests, and respond to inquiries as appropriate.



Issue and Primary Concerns ResponseAboriginal use of the study area for traditional purposes - of particular interest is underwater archaeology, especially in the nearshore landfall area

The Mi’kmaq Ecological Knowledge Study included in the Keltic/Maple EA reported that Mi’kmaq people currently undertake traditional use activities throughout the onshore study area (e.g., fishing, hunting, overnight camps.Experts from the Mi’kmaq Fish and Wildlife Commission, the Membertou Corporate Division, and Davis Archaeological Consultants have indicated that the proposed Deep Panuke onshore pipeline corridor and marine landfall area were not of high importance for traditional land use by the Mi’kmaq primarily since this site is far removed from the concentrations of Mi’kmaq population and the very short (2-4 km) onshore pipeline route should not pose any concerns. EnCana will invite aboriginal groups to review the applicability of these Mi’kmaq land use studies/opinions for the revised Deep Panuke Project and to arrange for a representative to monitor onshore and nearshore marine pipeline construction activities in conjunction with a professional archaeologist.

Economic benefits/opportunities for Mi'kmaq communities and people

EnCana will contract an Aboriginal liaison person/company to work with Aboriginal communities, businesses and individuals to ensure fair opportunity for contracts and services – based on competitiveness and the ability to meet EnCana’s standards.


6 IMPACT ASSESSMENT SCOPE AND METHODS

This EA Report has been prepared to meet the requirements of CEAA as well as the Scope of Environmental Assessment (CEA Agency 2006). In particular, the assessment addresses the specific requirements for a CSR pursuant to CEAA.

6.1 Scope of the Assessment

As discussed in Section 1.4, this EA Report has been prepared to address the following scope:

Variations between the revised Project basis and the Project basis presented in the approved 2002 CSR (Table 6.1); Changes to the regulatory environment since the approved 2002 CSR (Table 6.2); Changes to the biophysical environment since the approved 2002 CSR (Table 6.3); and Changes to the socio-economic environment since the approved 2002 CSR (Table 6.4).

Tables 6.1 to 6.4 present these variations and updates from the approved 2002 CSR. These variations and updates were identified through a review of the revised Project options, regulatory and stakeholder consultation (refer to Section 5), background research, and professional judgement of the Study Team. The purpose of this scoping exercise was to clearly define the scope of the assessment (i.e., identify gaps from the approved 2002 CSR) and identify issues that require reconsideration in the updated EA Report.

6.2 Selection of Valued Environmental Components

An important part of the assessment process is the early identification of key biophysical and socio-economic issues, known collectively as the valued environmental components (VECs) upon which the assessment will be focussed. Issues scoping is an important part of the VEC identification process. The issues scoping exercise for this EA Report included a review of Project changes, regulatory updates, biophysical updates, and socio-economic updates, as defined in Section 6.1. Issues scoping also included regulatory and stakeholder consultation; background research; and professional judgment of the Study Team. Table 6.5 presents the rationale for the selection of VECs, along with other scoping considerations.

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astru

ctur

e (f

low

lines

, um

bilic

als,

subs

ea p

rote

ctio

n st

ruct

ures

) will

requ

ire a

sses

smen

t of n

oise

, ai

r em

issi

ons,

mar

ine

disc

harg

es (i

nclu

ding

hy

dros

tatic

test

ing)

and

fish

erie

s int

erac

tions

In

crea

sed

bent

hic

foot

prin

t and

pot

entia

l gr

eate

r int

erac

tion

with

fish

ing

activ

ity d

ue to

flo

wlin

es a

nd su

bsea

wel

ls

Exis

ting

bent

hic

cond

ition

s mus

t be

upda

ted

to re

flect

new

fiel

d la

yout

and

wel

l loc

atio

ns

Som

e w

ell l

ocat

ions

clo

ser t

o Sa

ble

Isla

nd

and

SOEP

, pre

senc

e of

flow

lines

with

sour

ga

s, an

d pr

esen

ce o

f exp

ort p

ipel

ine

with

co

nden

sate

(SO

EP S

ubse

a O

ptio

n) re

quire

as

sess

men

t of a

ccid

enta

l rel

ease

pro

babi

lity

as w

ell a

s mar

ine

spill

and

atm

osph

eric

re

leas

e be

havi

our

Proj

ect L

ife

Expe

cted

mea

n ca

se: 1

1.5

year

sEx

pect

ed m

ean

case

: 13.

3 ye

ars

Expe

cted

rang

e: 8

-17.

5 ye

ars

Incr

ease

d pe

rson

-yea

rs o

f em

ploy

men

t In

crea

sed

dura

tion

of se

rvic

e an

d su

pply

ac

tivity

In

crea

sed

spill

risk

pot

entia

l Fi

eld

Cen

tre

Bas

e C

ase

Rel

ocat

ed 3

.6 k

m N

NE

from

200

2 Pr

ojec

t bas

is

Clo

ser t

o Sa

ble

Isla

nd

Pote

ntia

l diff

eren

ces i

n bi

ophy

sica

l co

nditi

ons,

incl

udin

g be

nthi

c co

nditi

ons

Dee

p Pa

nuke

Vol

ume

4 (E

nvir

onm

enta

l Ass

essm

ent R

epor

t) N

ovem

ber 2

006

6-3

Tab

le 6

.1

Proj

ect M

odifi

catio

ns a

nd E

nvir

onm

enta

l Ass

essm

ent C

onsi

dera

tions

Pr

ojec

t Ite

m

Proj

ect B

asis

in

App

rove

d 20

02 C

SR

M&

NP

Opt

ion

SOE

P Su

bsea

Opt

ion

EA

Sco

ping

Impl

icat

ions

Bas

e St

ruct

ure

Thre

e fix

ed p

latfo

rms

incl

udin

g:

Prod

uctio

n pl

atfo

rm

Util

ities

/qua

rters

pl

atfo

rm

Wel

lhea

d pl

atfo

rm

1 M

OPU

In

tegr

ated

faci

lity

MO

PU c

lose

r to

Sabl

e Is

land

than

pla

tform

s in

200

2 Pr

ojec

t bas

is

Less

ves

sel/h

elic

opte

r tra

ffic

dur

ing

cons

truct

ion

and

deco

mm

issi

onin

g Sh

orte

r dur

atio

n of

con

stru

ctio

n an

d de

com

mis

sion

ing

activ

ities

Sm

alle

r ben

thic

foot

prin

t N

o pi

le d

rivin

g w

ith M

OPU

inst

alla

tion

N

ew fl

are

heig

ht /

loca

tion

requ

ires n

ew a

ir di

sper

sion

mod

ellin

g D

isch

arge

of M

uds /

C

uttin

gs fo

r New

Wel

ls

Dril

led

from

fiel

d ce

ntre

WB

M/c

uttin

gs

over

boar

d SB

M/c

uttin

gs sk

ippe

d an

d sh

ippe

d or

in

ject

ed

Dril

led

from

indi

vidu

al w

ell l

ocat

ions

W

BM

/cut

tings

ove

rboa

rd

No

SBM

Smal

ler i

ndiv

idua

l cut

tings

pile

s loc

ated

at

indi

vidu

al w

ell l

ocat

ions

rath

er th

an la

rger

pi

le a

t the

fiel

d ce

ntre

O

vera

ll sm

alle

r vol

ume

of d

isch

arge

d m

ud

and

cutti

ngs

Del

iver

y Po

int

M&

NP

tie-in

O

nsho

re, a

djac

ent t

o SO

EP

SOEP

subs

ea ti

e-in

SO

EP 6

60 m

m [2

6 in

ch] p

ipel

ine

SOEP

subs

ea ti

e-in

requ

ires a

sses

smen

t of

nois

e em

issi

ons (

pile

driv

ing)

, fis

herie

s in

tera

ctio

n an

d sp

ill e

xpos

ure

Ons

hore

pip

elin

e co

rrid

or h

as b

een

mod

ified

du

e to

pla

nned

Kel

tic/M

aple

Pro

ject

nea

r G

oldb

oro;

how

ever

, will

stay

with

in th

e as

sess

ed O

nsho

re S

tudy

Are

a/G

oldb

oro

Indu

stria

l Par

k in

the

appr

oved

200

2 C

SR

Dee

p Pa

nuke

Vol

ume

4 (E

nvir

onm

enta

l Ass

essm

ent R

epor

t) N

ovem

ber 2

006

6-4

Tab

le 6

.1

Proj

ect M

odifi

catio

ns a

nd E

nvir

onm

enta

l Ass

essm

ent C

onsi

dera

tions

Pr

ojec

t Ite

m

Proj

ect B

asis

in

App

rove

d 20

02 C

SR

M&

NP

Opt

ion

SOE

P Su

bsea

Opt

ion

EA

Sco

ping

Impl

icat

ions

Expo

rt Pi

pelin

e 61

0 m

m [2

4 in

ch],

176

km

Sing

le p

hase

Tr

ench

ed ~

50%

of

rout

e

560

mm

[22

inch

], 17

6 km

Si

ngle

pha

se

Tren

ched

~ 5

0% o

f ro

ute

510

mm

[20

inch

], 15

km

M

ulti-

phas

e Tr

ench

ed 1

00%

of

rout

e

Con

stru

ctio

n ac

tiviti

es fo

r the

SO

EP S

ubse

a O

ptio

n pi

pelin

e an

d ne

w p

ortio

n of

pip

elin

e ro

ute

for t

he M

&N

P O

ptio

n w

ill re

quire

as

sess

men

t of n

oise

, air

emis

sion

s, m

arin

e di

scha

rges

, im

pact

on

bent

hic

habi

tat a

nd

fishe

ries i

nter

actio

ns

SOEP

Sub

sea

Opt

ion

pipe

line

and

new

po

rtion

of p

ipel

ine

rout

e fo

r the

M&

NP

Opt

ion

(due

to n

ew lo

catio

n of

fiel

d ce

ntre

) in

tera

ct w

ith n

ew fi

shin

g gr

ound

SO

EP S

ubse

a O

ptio

n m

ulti-

phas

e (c

onde

nsat

e/ga

s) p

ipel

ine

requ

ires a

sses

smen

t fo

r spi

ll ris

k pr

obab

ility

and

spill

fa

te/b

ehav

iour

N

ew re

leas

e po

ints

for h

ydro

stat

ic te

st w

ater

s of

pip

elin

e du

e to

fiel

d ce

ntre

relo

catio

n an

d SO

EP su

bsea

tie-

in; i

ncre

ased

con

cent

ratio

ns

of h

ydro

stat

ic te

st w

ater

s (e.

g., n

o di

lutio

n at

su

bsea

tie-

in re

leas

e po

int)

Expo

rt G

as

11.3

x 1

06m

3 /day

[4

00 M

Msc

fd]

Sale

s qua

lity

8.5

x 10

6m3 /d

ay [3

00

MM

scfd

] [at

pla

teau

pr

oduc

tion

rate

] Sa

les q

ualit

y

8.5

x 10

6 m

3 /day

[3

00 M

Msc

fd]

Swee

t and

deh

ydra

ted

N/A

Expo

rt C

onde

nsat

e N

/A

Max

imum

of 2

20

m3 /d

ay

Swee

t and

stab

ilize

d,

com

min

gled

with

gas

SOEP

Sub

sea

Opt

ion

mul

ti-ph

ase

pipe

line

will

requ

ire sp

ill ri

sk a

sses

smen

t

Con

dens

ate

Use

Fu

el, s

urpl

us in

ject

ed

Sale

s pro

duct

SO

EP S

ubse

a O

ptio

n w

ill p

rovi

de c

onde

nsat

e to

be

proc

esse

d as

val

ue-a

dded

pro

duct

Dee

p Pa

nuke

Vol

ume

4 (E

nvir

onm

enta

l Ass

essm

ent R

epor

t) N

ovem

ber 2

006

6-5

Tab

le 6

.1

Proj

ect M

odifi

catio

ns a

nd E

nvir

onm

enta

l Ass

essm

ent C

onsi

dera

tions

Pr

ojec

t Ite

m

Proj

ect B

asis

in

App

rove

d 20

02 C

SR

M&

NP

Opt

ion

SOE

P Su

bsea

Opt

ion

EA

Sco

ping

Impl

icat

ions

Prod

uced

wat

er

Max

imum

1,1

00 to

1,

600

m3 /d

ay [7

000

to

10,0

00 b

pd]

Dis

char

ged

over

boar

d

Max

imum

6,4

00 m

3 /day

[40,

000

bpd]

D

isch

arge

d ov

erbo

ard

Pote

ntia

lly h

ighe

r pro

duce

d w

ater

dis

char

ge

rate

requ

ires n

ew d

ispe

rsio

n m

odel

ling

and

cons

ider

atio

n in

term

s of e

ffec

ts o

n m

arin

e V

ECs

New

rele

ase

poin

t due

to fi

eld

cent

re

relo

catio

n

Dilu

tion

with

coo

ling

wat

er h

as c

hang

ed d

ue

to g

reat

er p

rodu

ced

wat

er ra

te a

nd lo

wer

co

olin

g w

ater

rate

A

cid

Gas

D

edic

ated

inje

ctio

n w

ell

~180

x 1

03 m3 /d

ay [6

M

Msc

fd]

Ded

icat

ed in

ject

ion

wel

l ~1

30 x

103 m

3 /day

[4.5

MM

scfd

] In

ject

ion

into

new

geo

logi

c fo

rmat

ion

requ

ires n

ew m

odel

ling

for a

ccid

enta

l spi

lls

and

air e

mis

sion

s


Table 6.2 Changes to Regulatory Environment since the Approved 2002 CSR Regulatory Update EA Scoping Considerations

Species at Risk Act (SARA) SARA was passed in December 2002, proclaimed in June 2003, and the last sections of the Act (prohibition and enforcement) came into force on June 1, 2004. The purpose of SARA is to prevent Canadian wildlife species from becoming extinct or extirpated, by providing for the recovery of endangered or threatened species, and encouraging the management of species of special concern.

SARA protects the plants and animals included in the List of Wildlife Species at Risk (Schedule 1 of SARA). Under SARAit is an offence to kill, harm, harass, capture or take, and to damage the residence of a listed endangered, threatened or extirpated species. A permit can be granted for an activity that would otherwise be a SARA offence, as long as measures are taken to minimize the impact, and the activity does not jeopardize the survival or recovery of the species. No clear definition has yet been provided for what constitutes “harassment” or “take” of an animal.

Effects of the Project on all marine and onshoreVEC species within the study area (including species now designated “at risk”) were assessed for the approved 2002 CSR. The EA Report addresses potential Project interactions with species at risk, as follows:

impact from the new Project components on Species at Risk; and updated information on species at risk, such as new species at risk, new information provided by species status reports and recovery plans/strategies, as applicable.

Environment Canada’s Environmental Assessment Best Practice for Wildlife at Risk in Canada (CWS 2004) has also been consulted with regard to evaluation of effects on species at risk.

Canadian Environmental Assessment Act (CEAA) Amendments to the Federal Authorities Regulations in January 2001 designated the CNSOPB as a Federal Authority (FA) under CEAA. On July 28, 2003, a number of amendments to regulations pursuant to CEAA came into force. These include amendments to the Inclusion List Regulations, Exclusion List Regulations, Law List Regulations and the Comprehensive Study List Regulations.Key changes include the following:

Work authorizations issued under paragraph 142(1)(b) of the Canada-Nova Scotia Offshore Petroleum Resources Accord Implementation Act are included in the Law List Regulations. This means that a CEAAenvironmental assessment must be completed for each work authorization issued by the CNSOPB, with the CNSOPB as a Responsible Authority. Section 11 of the Comprehensive Study Regulations was amended to clarify requirements of assessment for an offshore oil or gas production facility. The CEA Agency has an advisory role for all comprehensive studies and serves as the FEAC.

Section 1.3 of this EA Report indicates the expected Federal Authorities and Responsible Authorities for this Project and the requirement for a CSR under CEAA.

Gully Marine Protected Area (MPA) Regulations The Gully MPA Regulations came into force in May 2004. The MPA is divided into three management zones. The regulations prohibit the "disturbance, damage, destruction or removal of any living organism or part of its habitat [or] any part of the seabed within the MPA". Activities may be permitted within Zone 3 (the shallow banks on either side of the canyon) provided they do not impact Zones 1 and 2 and do not result in effects within Zone 3 "beyond natural variation of the area". An MPA Management Plan is being developed to provide guidelines for the implementation of the regulations (including approval and control of activities).

Because of the location of the Deep Panuke project (>100 km away from MPA boundary at northeast extreme location for future wells) and EnCana’s Gully MPA Code of Practice, no interaction is expected with the Gully MPA, hence the new MPA regulations are not expected to affect the Project. Nonetheless, the description of the Gully (Section 7.1.2.6) has been updated to acknowledge these regulations.


Table 6.2 Changes to Regulatory Environment since the Approved 2002 CSR Regulatory Update EA Scoping Considerations

Management of Sable Island Sable Island management was returned to the federal government on April 1, 2005. The Departments of Environment and Fisheries & Oceans are resuming management from a private organization, the Sable Island Preservation Trust (created in 1998). The federal government committed to maintaining a protective human presence on the island and will assume responsibility for staffing and operating the station. This resulted in a new structure for stakeholder consultation (a new Sable Island Stakeholder Committee was established in 2005 and includes representation by EnCana).

This regulatory update does not have a direct impact on the project and will not in itself require assessment. Section 7.1.2.6 of the EA Report acknowledges this update and stakeholder consultation included the Sable Island Stakeholder Committee (refer to Section 5).

Guidelines for Climate Change Considerations in Environmental Assessment In November 2003, the CEA Agency developed guidelines for EA practitioners regarding the incorporation of climate change considerations in environmental assessment. These guidelines include: methods that can be used to obtain and evaluate information concerning a project’s GHG emissions and the impacts of climate change on a project; key sources of information that practitioners can use to address climate change considerations in project EA; and methodology to encourage the consistent consideration of climate change in the EA process across federal, provincial and territorial jurisdictions and institutions of public government responsible for EA.

Section 8.1 (Air Quality) and Section 10 (Effects of the Environment on the Project) acknowledge these guidelines and have incorporated them as they are relevant.

Migratory Birds Convention Act (MBCA) Environment Canada’s recent review of the MBCA has resulted in some updates. The most relevant of which include a strengthening of Environment Canada’s authority to prosecute violations and formalizing the Act’s jurisdiction over the offshore area.

Section 7.1.2.5 acknowledges this updates to the Migratory Birds Convention Act however, it is unlikely that these updates have a direct impact on the Project.


Table 6.3 Changes to the Biophysical Environment since the Approved 2002 CSR Biophysical Update EA Scoping Considerations SARA and Species at Risk The biophysical impact analysis focusses on species at risk, particularly with

regard to marine fish, birds, mammals and sea turtles. Section 7.1.4 updates the approved 2002 CSR with respect to species at risk.

For the purpose of this EA Report, species at risk are defined as: “native wildlife species that are—or have become—most sensitive to human activity due to their rare occurrence, restricted range in Canada, dependence on specialized habitats or declining population or distribution” (CWS 2004). These may include species listed by SARA, COSEWIC, or NSNDR. ACCDC data has also been used as an early warning system to help identify some species that could be listed in the future. Although emphasis will be placed on SARA Schedule 1 species, it is important to be aware of additional species which have been identified through other mechanisms in order to take a more precautionary approach.

Where species recovery strategies or management plans have been developed or updated since the approved 2002 CSR (e.g., Roseate Tern, Ipswich Sparrow), these have been reviewed and discussed as appropriate to ensure the Project does not interfere with recovery of these species. Additional literature review has been conducted with respect to species at risk to provide further insight to status and behaviour of species and existing pressures on the populations (e.g., Rock 2005).

Scientific Research EnCana and the Study Team have conducted consultations with scientific and regulatory authorities to identify relevant research studies (e.g., produced water research, lobster/snow crab pipeline study, NRCan mine tailings contamination research) that have occurred since the approved 2002 CSR. This research has been used to enhance the effects analysis of biophysical VECs.

Table 6.4 Changes to the Socio-Economic Environment since the Approved 2002 CSR Socio-economic Update EA Scoping Considerations Offshore Strategic Energy Agreement (OSEA)

In June 2006, EnCana and the province of Nova Scotia announced an Offshore Strategic Energy Agreement (OSEA) that establishes the framework for Deep Panuke royalties, employment and industrial benefits, and funding for research and education. The socio-economic impact analysis presented in this EA Report (Section 9) updates the socio-economic information presented in the 2002 approved 2002 CSR, referencing the OSEA where relevant.

Fisheries Updates (General) EnCana and the Study Team have consulted with fisheries stakeholders (including nearshore fisheries and aquaculture license holders in the Goldboro landfall area) in the study area. The EA Report updates fisheries data, including maps, based on 2002-2005 effort and catch data and revises the impact analysis on fisheries and aquaculture accordingly.

New Quahog Fishery on Sable Island Bank A new quahog fishery opened on Sable Bank in 2005, although harvesting has yet to begin. This is the main expected fishery in the vicinity of the MOPU, wells, flowlines, SOEP Subsea Option, export pipeline and new portion of M&NP Option pipeline route (due to re-location of field centre) not previously assessed in the CSR. On Sable Island Bank, the flowlines and export pipeline will be buried deeper than 30 cm, which is considered to be the maximum depth for clam dredging. However, to ensure further protection during production, a safety zone will likely be established around the flowlines (which are considered vulnerable to mobile fishing gear), and wellhead subsea completions. The EA Report assesses direct and cumulative effects of subsea infrastructure on the new quahog fishery (refer to Section 9.3).


Table 6.4 Changes to the Socio-Economic Environment since the Approved 2002 CSR Socio-economic Update EA Scoping Considerations Sea Cucumber Experimental Fishery Consultations with DFO identified a sea cucumber experimental fishery on

Sable Island Bank, which overlaps the pipeline corridor for the M&NP Option. This area is identified on Figure 7.2.

Sea Urchin Licenses in Country Harbour/Isaacs Harbour Area

Consultations with DFO identified sea urchin licenses in the nearshore area in the vicinity of the nearshore pipeline route (M&NP Option). EnCana and the Study Team have consulted with the sea urchin license holders and these licenses are identified on Figure 7.9.

Eastern Scotian Shelf Integrated Management (ESSIM) Plan

A revised draft ESSIM Plan was released in July 2006 for public review. This Plan has been reviewed in context of compatibility of the Project within the Plan. Refer to Section 7.2.4 (Other Ocean Users) for additional information on ESSIM and its relevance to the Project.

Other Ocean Users EnCana and the Study Team have consulted with other ocean users (e.g.,DND, DFO, petroleum industry) to update information on their activities that could potentially interact with the Project. This information has been integrated into Sections 7.2.4 and 9.4 of the EA Report.

Preliminary discussions with Transport Canada and the CNSOPB indicated that the Project would require an application under the Navigable WatersProtection Act (NWPA). Potential impacts on navigation are included in Section 9.4.

Proposed Keltic Petrochemical Plant and Maple LNG Facility in Goldboro (Keltic/Maple Project)

Keltic Petrochemicals Inc. (in association with Maple LNG) has proposed construction and operation of a petrochemicals plant and LNG facilities directly adjacent to EnCana’s proposed onshore pipeline corridor (M&NP Option). These projects are currently undergoing environmental assessment under CEAA and the Nova Scotia Environment Act.

The onshore pipeline corridor identified for the approved 2002 CSR will likely change due to the planned Keltic Petrochemicals Project near Goldboro; however, it will remain within the assessed Onshore Study Area in the approved 2002 CSR. The EA Report updates the description of current and planned land uses in the landfall area (Section 7.2.2) and considers effects on this proposed land use (Section 9.1). The cumulative effects assessment (Sections 8.9 and 9.5) also considers the proposed Keltic and Maple facilities.

Traditional Land Use The 2002 approved CSR reported no evidence of traditional land use occurring in the study area. However, a Mi’kmaq Ecological Knowledge Study recently undertaken in support of the environmental assessment for the Keltic Petrochemicals Inc. Proposed LNG and Petrochemical Facilities (AMEC 2006) indicates current use of lands for traditional purposes (e.g.,fishing, hunting, overnight camps) within the Goldboro Industrial Park. It is assumed for the purpose of this assessment that current use of lands for traditional purposes could occur in the study area for this Project. As stated in the approved 2002 CSR, EnCana has committed to include Aboriginal representatives in pipeline RoW inspections.

Dee

p Pa

nuke

Vol

ume

4 ( E

nvir

onm

enta

l Ass

essm

ent R

epor

t) N

ovem

ber 2

006

6-10

Tab

le 6

.5

Sele

ctio

n of

VE

Cs

App

rove

d 20

02 C

SR V

EC

R

atio

nale

for

VE

C S

elec

tion

and

Oth

er S

copi

ng C

onsi

dera

tions

V

EC

for

Env

iron

men

tal

Ass

essm

ent

Biop

hysic

al V

ECs

Air

Qua

lity

Gro

und

leve

l con

cent

ratio

ns a

nd k

ey e

mis

sion

rate

s will

dec

reas

e as

a re

sult

of re

duct

ion

in

proc

essi

ng th

roug

hput

. C

O2 e

quiv

alen

ts (i

.e.,

gree

nhou

se g

as e

mis

sion

s) o

ver t

he P

roje

ct’s

life

will

dec

reas

e si

nce

the

cum

ulat

ive

gas p

rodu

ctio

n ha

s dec

reas

ed.

The

new

dril

ling/

re-c

ompl

etio

n pr

ogra

m a

nd th

e in

stal

latio

n of

new

subs

ea in

fras

truct

ure

by

trenc

hing

/pip

elay

ing

of fl

owlin

es a

nd u

mbi

lical

s will

resu

lt in

add

ition

al v

esse

l act

ivity

and

as

soci

ated

air

emis

sion

s. Pr

esen

ce o

f flo

wlin

es a

nd su

bsea

wel

ls in

trodu

ces n

ew fa

ilure

poi

nts f

or re

leas

e. F

low

lines

and

w

ells

(inc

ludi

ng a

cid

gas i

njec

tion)

mus

t be

eval

uate

d fo

r pot

entia

l fai

lure

pro

babi

lity

and

beha

viou

r of s

our h

ydro

carb

on re

leas

es.

The

chan

ge in

fiel

d ce

ntre

and

new

flar

e to

wer

hei

ght a

nd lo

catio

n re

quire

a n

ew a

sses

smen

t of

atm

osph

eric

rele

ases

dur

ing

norm

al a

nd a

ccid

enta

l eve

nts.

Su

mm

ary

Proj

ect d

esig

n ch

ange

s req

uire

reas

sess

men

t of r

outin

e an

d ac

cide

ntal

atm

osph

eric

rele

ases

. Air

Q

ualit

y re

mai

ns a

s a V

EC.

Air

Qua

lity

Mar

ine

Wat

er Q

ualit

y N

ew d

rillin

g an

d re

-com

plet

ion

prog

ram

will

resu

lt in

dis

char

ges t

o th

e m

arin

e en

viro

nmen

t.

Inst

alla

tion

of n

ew su

bsea

infr

astru

ctur

e w

ill re

sult

in m

arin

e di

scha

rges

and

incr

ease

d lo

caliz

ed

leve

ls o

f Sus

pend

ed P

artic

ulat

e M

atte

r dur

ing

cons

truct

ion.

H

ydro

test

ing

from

flow

lines

and

exp

ort p

ipel

ine

will

resu

lt in

low

er d

isch

arge

d vo

lum

es, b

ut n

ew

offs

hore

dis

char

ge p

oint

s and

, in

som

e ca

ses,

pote

ntia

lly h

ighe

r con

cent

ratio

ns o

f hyd

rote

st fl

uids

. U

ndilu

ted

fluid

con

cent

ratio

ns w

ill b

e as

sum

ed a

t sub

sea

tie-in

loca

tion

(SO

EP S

ubse

a O

ptio

n)

and

expo

rt pi

pelin

e an

d flo

wlin

e en

ds.

Hig

her p

rodu

ced

wat

er ra

te re

quire

s new

dis

pers

ion

mod

ellin

g an

d as

sess

men

t. N

ew re

sear

ch o

n ef

fect

s of p

rodu

ced

wat

er o

n m

arin

e or

gani

sms.

Incr

ease

d pr

oduc

tion

life,

new

wel

l pro

gram

, pre

senc

e of

flow

lines

and

mul

ti-ph

ase

expo

rt pi

pelin

e to

SO

EP (S

OEP

Sub

sea

Opt

ion)

will

aff

ect m

arin

e sp

ill p

roba

bilit

y.

New

fiel

d ce

ntre

loca

tion,

wel

l loc

atio

ns, s

ubse

a flo

wlin

es a

nd m

ulti-

phas

e ex

port

pipe

line

to

SOEP

car

ryin

g co

nden

sate

(SO

EP S

ubse

a O

ptio

n) re

quire

exa

min

atio

n of

pot

entia

l im

pact

by

mea

ns o

f spi

ll be

havi

our m

odel

ling.

Su

mm

ary

New

inte

ract

ions

with

Mar

ine

Wat

er Q

ualit

y re

quir

e fu

rthe

r ana

lysi

s. M

arin

e W

ater

Qua

lity

rem

ains

as

a V

EC.

Mar

ine

Wat

er Q

ualit

y

Dee

p Pa

nuke

Vol

ume

4 ( E

nvir

onm

enta

l Ass

essm

ent R

epor

t) N

ovem

ber 2

006

6-11

Tab

le 6

.5

Sele

ctio

n of

VE

Cs

App

rove

d 20

02 C

SR V

EC

R

atio

nale

for

VE

C S

elec

tion

and

Oth

er S

copi

ng C

onsi

dera

tions

V

EC

for

Env

iron

men

tal

Ass

essm

ent

Mar

ine

Ben

thos

R

eloc

atio

n of

fiel

d ce

ntre

, wel

l loc

atio

ns, s

ubse

a eq

uipm

ent,

SOEP

Sub

sea

Opt

ion

pipe

line

and

new

por

tion

of M

&N

P pi

pelin

e w

ill re

quire

upd

atin

g ex

istin

g be

nthi

c co

nditi

ons,

incl

udin

g co

mm

erci

al sp

ecie

s (e.

g., q

uaho

g).

New

dril

ling

prog

ram

and

inst

alla

tion

of n

ew su

bsea

infr

astru

ctur

e w

ill re

sult

in in

crea

sed

bent

hic

habi

tat d

istu

rban

ce d

urin

g co

nstru

ctio

n ov

er a

larg

er g

eogr

aphi

c ar

ea.

Sum

mar

yN

ew p

oten

tial i

nter

actio

ns w

ith M

arin

e Be

ntho

s req

uire

furth

er a

naly

sis.

Mar

ine

Bent

hos r

emai

ns a

s a

VEC

with

em

phas

is o

n co

mm

erci

al b

enth

ic sp

ecie

s.

Mar

ine

Ben

thos

Mar

ine

Fish

A

lso

refe

r to

cons

ider

atio

ns fo

r Mar

ine

Wat

er Q

ualit

y an

d M

arin

e B

enth

os.

Less

reef

and

refu

ge e

ffec

ts a

ssoc

iate

d w

ith o

ne in

stal

latio

n (M

OPU

) (in

stea

d of

thre

e pl

atfo

rms)

, su

bsea

infr

astru

ctur

e an

d re

late

d sa

fety

zon

e.

New

dril

ling/

re-c

ompl

etio

n pr

ogra

m a

nd in

stal

latio

n of

new

subs

ea in

fras

truct

ure

will

resu

lt in

no

ise

emis

sion

s. Th

ere

will

be

low

er n

oise

em

issi

ons a

ssoc

iate

d w

ith p

ile d

rivin

g (s

ubse

a pr

otec

tion

stru

ctur

es) d

istri

bute

d ov

er a

wid

er a

rea.

H

addo

ck B

ox is

loca

ted

appr

oxim

atel

y 49

km

from

the

Proj

ect a

rea

and

is n

ot e

xpec

ted

to in

tera

ct

with

the

Proj

ect.

Sum

mar

yN

ew p

oten

tial i

nter

actio

ns w

ith M

arin

e Fi

sh re

quir

e fu

rther

ana

lysi

s. M

arin

e Fi

sh re

mai

ns a

s a V

EC

with

em

phas

is o

n m

arin

e fis

h sp

ecie

s at r

isk

and

com

mer

cial

fish

spec

ies.

Mar

ine

Fish

Mar

ine

Mam

mal

s A

lso

refe

r to

cons

ider

atio

ns fo

r Mar

ine

Wat

er Q

ualit

y.

The

new

dril

ling/

re-c

ompl

etio

n pr

ogra

m a

nd th

e in

stal

latio

n of

new

subs

ea in

fras

truct

ure

will

re

sult

in n

oise

em

issi

ons.

Ther

e w

ill b

e lo

wer

noi

se e

mis

sion

s ass

ocia

ted

with

pile

driv

ing

(wel

lhea

d pr

otec

tion

stru

ctur

es) d

istri

bute

d ov

er a

wid

er a

rea.

C

onst

ruct

ion

and

deco

mm

issi

onin

g of

one

inst

alla

tion

(MO

PU) i

nste

ad o

f thr

ee p

latfo

rms w

ill

resu

lt in

less

ves

sel a

nd h

elic

opte

r tra

ffic

, the

reby

redu

cing

noi

se e

mis

sion

s. Su

mm

ary

In re

cogn

ition

of S

ARA,

the

asse

ssm

ent w

ill fo

cus o

n m

arin

e m

amm

al sp

ecie

s at r

isk.

The

re is

po

tent

ial f

or se

a tu

rtle

s at r

isk

to o

ccur

in th

e st

udy

area

. Thi

s VEC

is re

vise

d as

Mar

ine

Mam

mal

s an

d Tu

rtle

s and

focu

sses

on

spec

ies a

t ris

k.

Mar

ine

Mam

mal

s and

Tu

rtles

Dee

p Pa

nuke

Vol

ume

4 ( E

nvir

onm

enta

l Ass

essm

ent R

epor

t) N

ovem

ber 2

006

6-12

Tab

le 6

.5

Sele

ctio

n of

VE

Cs

App

rove

d 20

02 C

SR V

EC

R

atio

nale

for

VE

C S

elec

tion

and

Oth

er S

copi

ng C

onsi

dera

tions

V

EC

for

Env

iron

men

tal

Ass

essm

ent

Mar

ine

Rel

ated

Bird

s Th

e SO

EP S

ubse

a O

ptio

n w

ill re

sult

in e

limin

atio

n of

a d

edic

ated

exp

ort p

ipel

ine

to sh

ore,

th

ereb

y el

imin

atin

g Pr

ojec

t int

erac

tion

with

the

Cou

ntry

Isla

nd T

ern

popu

latio

n.

Con

stru

ctio

n an

d de

com

mis

sion

ing

of o

ne in

stal

latio

n (M

OPU

) ins

tead

of t

hree

pla

tform

s will

re

sult

in le

ss v

esse

l and

hel

icop

ter t

raff

ic, t

here

by re

duci

ng p

oten

tial i

nter

actio

n w

ith m

arin

e bi

rds.

The

new

dril

ling/

re-c

ompl

etio

n pr

ogra

m a

nd th

e in

stal

latio

n of

new

subs

ea in

fras

truct

ure

(incl

udin

g tre

nchi

ng/p

ipel

ayin

g of

flow

lines

and

um

bilic

als)

will

nee

d to

be

asse

ssed

for

inte

ract

ion

with

mar

ine

bird

s. R

efer

to c

onsi

dera

tions

for M

arin

e W

ater

Qua

lity

with

rega

rd to

mar

ine

spill

s. Th

ere

is n

ew in

form

atio

n av

aila

ble

on sp

ecie

s at r

isk

(e.g

. Ros

eate

Ter

n, Ip

swic

h Sp

arro

w) w

hich

ar

e cl

osel

y as

soci

ated

with

Sab

le Is

land

. Su

mm

ary

New

pot

entia

l int

erac

tions

with

Mar

ine

Rela

ted

Bird

s req

uire

furt

her a

naly

sis.

This

VEC

shal

l foc

us

on sp

ecie

s at r

isk.

Mar

ine

Rel

ated

Bird

s

Sabl

e Is

land

R

eloc

atio

n of

the

field

cen

tre, p

rodu

ctio

n w

ells

and

aci

d ga

s inj

ectio

n w

ell,

pres

ence

of f

low

lines

an

d, fo

r the

SO

EP S

ubse

a O

ptio

n, a

mul

ti-ph

ase

pipe

line

to S

OEP

, res

ult i

n ne

w p

oten

tial

scen

ario

s for

mar

ine

spill

s whi

ch a

re c

lose

r to

Sabl

e Is

land

, hen

ce, a

ccid

enta

l rel

ease

pro

babi

lity

and

beha

viou

r mod

ellin

g ne

ed to

be

reas

sess

ed w

ith c

onsi

dera

tion

to p

oten

tial i

nter

actio

n w

ith

Sabl

e Is

land

. R

efer

to c

onsi

dera

tions

for M

arin

e R

elat

ed B

irds w

ith re

gard

to S

able

Isla

nd.

Sum

mar

yTh

is V

EC a

naly

sis w

ill fo

cus o

n Pr

ojec

t int

erac

tions

ass

ocia

ted

with

acc

iden

tal e

vent

s.

Sabl

e Is

land

Ons

hore

Env

ironm

ent

The

onsh

ore

pipe

line

corr

idor

has

bee

n m

odifi

ed w

ithin

the

prev

ious

ly a

ppro

ved

stud

y ar

ea

(M&

NP

Opt

ion)

. Th

ere

are

new

(lis

ted

sinc

e 20

02) o

nsho

re sp

ecie

s at r

isk

that

requ

ire c

onsi

dera

tion.

Th

e pr

opos

ed p

ipel

ine

rout

e m

ay re

quire

cro

ssin

g w

etla

nd a

reas

. Th

e pr

opos

ed p

ipel

ine

rout

e m

ay re

quire

cro

ssin

g B

etty

’s C

ove

Bro

ok.

Ther

e is

new

dat

a av

aila

ble

on se

dim

ent c

onta

min

atio

n fr

om h

isto

ric m

inin

g ac

tivity

in th

e ne

arsh

ore

and

onsh

ore

area

.Su

mm

ary

This

VEC

ana

lysi

s will

focu

s on

spec

ies a

t ris

k an

d po

tent

ial i

mpa

ct o

n fr

eshw

ater

reso

urce

sand

wet

land

s.

Ons

hore

Env

ironm

ent

Dee

p Pa

nuke

Vol

ume

4 ( E

nvir

onm

enta

l Ass

essm

ent R

epor

t) N

ovem

ber 2

006

6-13

Tab

le 6

.5

Sele

ctio

n of

VE

Cs

App

rove

d 20

02 C

SR V

EC

R

atio

nale

for

VE

C S

elec

tion

and

Oth

er S

copi

ng C

onsi

dera

tions

V

EC

for

Env

iron

men

tal

Ass

essm

ent

Soci

o-ec

onom

ic V

ECs

The

Econ

omy

Empl

oym

ent

Bus

ines

s Opp

ortu

nitie

s Tr

aini

ngPr

oper

ty T

ax B

ase

Econ

omic

Sta

bilit

y an

d G

row

th

Aqu

acul

ture

and

the

Fish

ery

(Nea

rsho

re/O

ffsh

ore)

To

uris

m

The

OSE

A d

ocum

ent o

utlin

es e

cono

mic

ben

efits

incl

udin

g em

ploy

men

t, ro

yalti

es, i

ndus

trial

be

nefit

s and

fund

ing

for r

esea

rch

and

educ

atio

n. It

is re

fere

nced

in th

e B

enef

its P

lan

(DPA

V

olum

e 3)

. In

form

atio

n pr

esen

ted

in th

e ap

prov

ed 2

002

CSR

on

the

econ

omy

requ

ires u

pdat

ing.

In

stal

latio

n of

new

subs

ea in

fras

truct

ure

will

inte

ract

with

mar

ine

fishe

ries (

incl

udin

g pr

opos

ed

ocea

n qu

ahog

fish

ery)

and

pot

entia

lly o

ther

oce

an u

sers

. St

atus

of o

ffsh

ore

and

near

shor

e fi

sher

ies a

nd a

quac

ultu

re re

quire

s upd

atin

g fr

om th

e ap

prov

ed

2002

CSR

. Su

mm

ary

The

soci

o-ec

onom

ic im

pact

ana

lysi

s will

focu

s on

inte

ract

ions

with

offs

hore

and

nea

rsho

re fi

sher

ies

(incl

udin

g aq

uacu

lture

) and

oth

er o

cean

use

rs. T

he e

cono

mic

ben

efits

ana

lysi

s will

als

o be

upd

ated

.

Com

mer

cial

Fi

sher

ies a

nd

Aqu

acul

ture

O

ther

Oce

an U

sers

Ec

onom

y

The

Envi

ronm

ent

Wat

er Q

ualit

y A

ir Q

ualit

y

Sum

mar

yM

arin

e w

ater

qua

lity

and

air q

ualit

y ar

e VE

Cs c

onsi

dere

d in

the

biop

hysi

cal i

mpa

ct a

sses

smen

t and

ar

e no

t fur

ther

ana

lyze

d in

the

soci

o-ec

onom

ic im

pact

ass

essm

ent.

N/A

Infr

astru

ctur

e R

oads

W

harv

es

Emer

genc

y Se

rvic

es

The

onsh

ore

pipe

line

corr

idor

will

like

ly c

hang

e bu

t rem

ain

with

in th

e ap

prov

ed 2

002

CSR

stud

y ar

ea (M

&N

P O

ptio

n), b

ut th

is c

hang

e do

es n

ot im

pact

exp

ecte

d in

tera

ctio

n w

ith lo

cal

infr

astru

ctur

es.

Sum

mar

yIn

form

atio

n co

ntai

ned

in th

e ap

prov

ed 2

002

CSR

rem

ains

val

id fo

r the

se is

sues

and

will

not

requ

ire

furt

her a

sses

smen

t.

N/A

Soci

al F

acto

rs

Land

and

Wat

er U

se

Mar

ine

Arc

haeo

logi

cal R

esou

rces

La

nd B

ased

Arc

haeo

logi

cal

Res

ourc

esC

urre

nt L

and

and

Res

ourc

e U

se fo

r Fi

rst N

atio

n’s a

nd A

borig

inal

Pu

rpos

esPu

blic

Hea

lth a

nd S

afet

y

Larg

e in

dust

rial f

acili

ties (

Kel

tic/M

aple

Pro

ject

) are

now

pro

pose

d fo

r the

Gol

dbor

o In

dust

rial

Park

.Th

e on

shor

e pi

pelin

e co

rrid

or h

as b

een

mod

ified

with

in th

e pr

evio

usly

app

rove

d on

shor

e st

udy

area

(M&

NP

Opt

ion)

. In

stal

latio

n of

new

subs

ea in

fras

truct

ure

coul

d in

tera

ct w

ith o

ther

oce

an u

sers

. Su

mm

ary

Info

rmat

ion

cont

aine

d in

the

appr

oved

200

2 C

SR re

mai

ns v

alid

for t

he m

ajor

ity o

f the

se is

sues

and

w

ill n

ot re

quir

e fu

rthe

r ass

essm

ent,

with

the

exce

ptio

n of

pos

sibl

e m

odifi

catio

ns to

ons

hore

pip

elin

e ro

utin

g. T

he so

cio-

econ

omic

impa

ct a

naly

sis w

ill c

onsi

der i

mpa

cts o

n la

nd u

se a

nd o

ther

oce

an u

sers

.

Oth

er O

cean

Use

rs

Land

Use


6.3 Potential Interaction between Project Activities and Valued Environmental Components

Tables 6.6 and 6.7 summarize the potential interactions between biophysical VECs and socio-economic VECs, respectively. Where interactions are not indicated, it is considered that negligible (similar to normal variation in background conditions) or no interactions will occur. The specific nature and extent of these interactions are discussed and evaluated for each VEC in Sections 8 and 9. Where existing knowledge (e.g., the approved 2002 CSR) indicates than an interaction is not likely to result in an effect, certain issues may not warrant further analysis. Since the scope of this EA Report is limited to variations from the approved 2002 CSR, potential interactions which have been assessed previously do not require reassessment. Likewise, where a Project modification results in a lower effect than that previously assessed (e.g., smaller footprint, less noise disturbance), the effects analysis presented in the approved 2002 CSR is referenced and no further analysis is required. New commitments as a result of this EA or commitments revised from the approved 2002 CSR for mitigation, follow-up and monitoring made by EnCana are presented in Section 11.

6.4 Environmental Effects Assessment Framework

The environmental effects assessment framework presented in the approved 2002 CSR has also been used for this EA Report. Each VEC undergoes analysis using the same framework:

VEC identification and description of context; definition of boundaries; establishment of residual environmental effects evaluation criteria; Project modifications and potential interactions; analysis, mitigation and residual environmental effects prediction; follow-up and monitoring; consideration of sustainable use of renewable resources; andsummary of residual environmental effects assessment.

Each of these steps is described in Section 6.2.3 of the approved 2002 CSR. One difference between the methodology used previously in the approved 2002 CSR and this EA Report is that the cumulative effects assessment does not appear within each VEC analysis, but is instead presented in separate sections (Section 8.9 for biophysical and Section 9.5 for socio-economic). Additional information on the cumulative effects assessment is provided in Section 6.5.

Dee

p Pa

nuke

Vol

ume

4 (E

nvir

onm

enta

l Ass

essm

ent R

epor

t) N

ovem

ber 2

006

6-1

5

Tab

le 6

.6

Proj

ect I

nter

actio

ns w

ith B

ioph

ysic

al V

EC

s B

ioph

ysic

al V

EC

s Pr

ojec

t C

ompo

nent

Proj

ect

Mod

ifica

tion

Air

Qua

lity

Mar

ine

Wat

er

Qua

lity

Mar

ine

Ben

thos

M

arin

e Fi

sh

Mar

ine

Mam

mal

s and

T

urtle

s

Mar

ine

Rel

ated

B

irds

Sabl

e Is

land

O

nsho

re

Env

iron

men

t

Cons

truct

ion

and

Insta

llatio

nO

ffsh

ore

Prod

uctio

nFa

cilit

ies

1 in

stal

latio

n (M

OPU

) in

stea

d of

3 p

latfo

rms

Less

air

emis

sion

s fr

om v

esse

l/ he

licop

ter t

raff

ic

Less

ves

sel

disc

harg

esSm

alle

r be

nthi

cfo

otpr

int i

n ne

arby

lo

catio

n

Less

ves

sel

disc

harg

esLe

ss v

esse

l/ he

licop

ter

traff

ic; l

ess

vess

el

disc

harg

es

Less

ve

ssel

/hel

icop

ter

traff

ic; l

ess

vess

el li

ghts

and

di

scha

rges

N/A

N

/A

Flow

lines

, um

bilic

als,

subs

ea p

rote

ctio

n st

ruct

ures

(wel

ls, S

SIV

sk

id, a

nd h

ot ta

p an

d tie

-in fo

r SO

EP S

ubse

a O

ptio

n)

Gre

ater

air

emis

sion

s fro

m

incr

ease

d pi

pela

ying

/tren

chin

g ac

tivity

Gre

ater

su

spen

ded

parti

cula

tem

atte

r (SP

M)

from

incr

ease

d pi

pela

ying

/ tre

nchi

ng

activ

ity

Gre

ater

be

nthi

cfo

otpr

int f

rom

in

crea

sed

pipe

layi

ng/

trenc

hing

ac

tivity

Gre

ater

SPM

an

d no

ise

dist

urba

nce

from

incr

ease

d pi

pela

ying

/ tre

nchi

ng

activ

ity

Gre

ater

noi

se

dist

urba

nce

from

incr

ease

d pi

pela

ying

/ tre

nchi

ng

activ

ity; g

reat

er

vess

el p

rese

nce

Gre

ater

noi

se

dist

urba

nce

from

incr

ease

d pi

pela

ying

/ tre

nchi

ng

activ

ity; g

reat

er

vess

el p

rese

nce

N/A

N

/A

Cha

nge

in d

ilutio

n ra

te

and

rele

ase

loca

tion

for

hydr

osta

tic te

st w

ater

s fr

om e

xpor

t pip

elin

e an

d flo

wlin

es

N/A

W

ater

qua

lity

degr

adat

ion

from

dis

char

ge

of h

ydro

stat

ic

test

wat

er

Pote

ntia

l co

ntam

inat

ion

of b

enth

os

from

disc

harg

e of

hy

dros

tatic

te

st w

ater

Wat

er q

ualit

y de

grad

atio

nfr

om d

isch

arge

of

hyd

rost

atic

te

st w

ater

Wat

er q

ualit

y de

grad

atio

nfr

om d

isch

arge

of

hyd

rost

atic

te

st w

ater

Wat

er q

ualit

y de

grad

atio

nfr

om d

isch

arge

of

hyd

rost

atic

te

st w

ater

N/A

N

/A

Subs

eaEq

uipm

ent

Pile

driv

ing

for h

ot ta

p st

ruct

ure

(SO

EP

Subs

ea O

ptio

n) a

nd

wel

lhea

d/pr

otec

tion

stru

ctur

es; i

nvol

ves

muc

h sm

alle

r pile

s ov

er w

ider

are

a th

an

for o

rigin

al p

latfo

rms

Min

or a

ir em

issi

ons

over

a la

rger

ge

ogra

phic

are

a

Min

or S

PM

over

a la

rger

ge

ogra

phic

are

a

Less

noi

se

and

dura

tion

of d

istu

rban

ce

over

a la

rger

ge

ogra

phic

area

Less

noi

se a

nd

dura

tion

of

dist

urba

nce

over

a

larg

er

geog

raph

ic a

rea

Less

noi

se a

nd

dura

tion

of

dist

urba

nce

over

a la

rger

ge

ogra

phic

area

Less

noi

se a

nd

dura

tion

of

dist

urba

nce

over

a

larg

er

geog

raph

ic a

rea

N/A

N

/A

Dee

p Pa

nuke

Vol

ume

4 (E

nvir

onm

enta

l Ass

essm

ent R

epor

t) N

ovem

ber 2

006

6-1

6

Tab

le 6

.6

Proj

ect I

nter

actio

ns w

ith B

ioph

ysic

al V

EC

s B

ioph

ysic

al V

EC

s Pr

ojec

t C

ompo

nent

Proj

ect

Mod

ifica

tion

Air

Qua

lity

Mar

ine

Wat

er

Qua

lity

Mar

ine

Ben

thos

M

arin

e Fi

sh

Mar

ine

Mam

mal

s and

T

urtle

s

Mar

ine

Rel

ated

B

irds

Sabl

e Is

land

O

nsho

re

Env

iron

men

t

Expo

rt Pi

pelin

e to

SO

EP (S

OEP

Su

bsea

Opt

ion)

Con

stru

ctio

n of

new

pi

pelin

e to

SO

EP

subs

ea ti

e-in

Low

er a

ir em

issi

ons

from

equ

ipm

ent t

o in

stal

l sho

rter e

xpor

t pi

pelin

e in

new

lo

catio

n

Low

er S

PM (i

n ne

w lo

catio

n)

from

inst

alla

tion

of sh

orte

r exp

ort

pipe

line

Ove

rall

smal

ler

bent

hic

foot

prin

t (17

6 km

to 1

5 km

); bu

t rou

te

thro

ugh

new

ar

ea; n

o bl

astin

g re

quire

d

Less

SPM

and

no

ise

from

in

stal

latio

n of

sh

orte

r exp

ort

pipe

line

but i

n ne

w lo

catio

n

Less

noi

se a

nd

vess

el a

ctiv

ity

(in n

ew

loca

tion)

from

sh

orte

r exp

ort

pipe

line

Less

noi

se a

nd

vess

el a

ctiv

ity

(in n

ew

loca

tion)

from

sh

orte

r exp

ort

pipe

line;

no

inte

ract

ion

with

C

ount

ry Is

land

R

osea

te T

erns

N/A

N

/A

Expo

rt Pi

pelin

e to

Sh

ore

(M&

NP

Opt

ion)

Cha

nge

in e

xpor

t pi

pelin

e lo

catio

n du

e to

ne

w fi

eld

cent

re

N/A

N

/A

Min

or

redu

ctio

n in

be

nthi

cfo

otpr

int (

< 1

km) b

ut n

ew

loca

tion;

ro

utin

g w

ill

pass

thro

ugh

quah

ogfis

hing

grou

nds a

nd

rece

ntly

es

tabl

ishe

d ex

perim

enta

lse

a cu

cum

ber

fishi

ng a

rea

N/A

N

/A

N/A

N

/A

N/A

Dee

p Pa

nuke

Vol

ume

4 (E

nvir

onm

enta

l Ass

essm

ent R

epor

t) N

ovem

ber 2

006

6-1

7

Tab

le 6

.6

Proj

ect I

nter

actio

ns w

ith B

ioph

ysic

al V

EC

s B

ioph

ysic

al V

EC

s Pr

ojec

t C

ompo

nent

Proj

ect

Mod

ifica

tion

Air

Qua

lity

Mar

ine

Wat

er

Qua

lity

Mar

ine

Ben

thos

M

arin

e Fi

sh

Mar

ine

Mam

mal

s and

T

urtle

s

Mar

ine

Rel

ated

B

irds

Sabl

e Is

land

O

nsho

re

Env

iron

men

t

Dev

elop

men

tW

ell

Con

stru

ctio

n

Max

imum

tota

l num

ber

of w

ells

has

incr

ease

d to

9, b

ut d

urat

ion

of

drill

ing

and

com

plet

ion

activ

ities

has

de

crea

sed;

four

re-

entry

wel

ls in

clud

ed in

to

tal –

min

imal

dril

ling

to c

ompl

ete

Min

or d

ecre

ase

in

air e

mis

sion

s fro

m

shor

ter d

urat

ion

of

wel

l dril

ling

and

com

plet

ion

Low

er to

tal

volu

mes

of

WB

Mdi

scha

rges

and

as

soci

ated

cu

tting

s at

indi

vidu

al w

ell

loca

tions

inst

ead

of fi

eld

cent

re;

elev

ated

SPM

; gr

eate

r vol

ume

of d

isch

arge

d br

ine

for w

ell

re-c

ompl

etio

n

Low

er to

tal

WB

Mdi

scha

rges

and

asso

ciat

ed

cutti

ngs;

m

ore,

but

sm

alle

r cu

tting

s pile

s at

indi

vidu

al

wel

l loc

atio

ns

inst

ead

of

field

cen

tre;

grea

ter

volu

me

of

brin

e fo

r wel

l re

-co

mpl

etio

n;

loca

lized

sm

othe

ring

of

bent

hos;

pote

ntia

l in

gest

ion

of

cont

amin

ants

Low

er to

tal

WB

Mdi

scha

rges

and

as

soci

ated

cu

tting

s;di

scha

rges

at

indi

vidu

al w

ell

loca

tions

inst

ead

of fi

eld

cent

re;

grea

ter v

olum

e of

brin

e fo

r wel

l re

-com

plet

ion

disc

harg

ed;

elev

ated

SPM

; po

tent

ial

inge

stio

n of

co

ntam

inan

ts

Shor

ter

dura

tion

of

drill

ing

nois

e sp

read

ove

r a

wid

er a

rea

Shor

ter d

urat

ion

of d

rillin

g no

ise

spre

ad o

ver

wid

er a

rea

N/A

N

/A

Ons

hore

Pip

elin

e an

d Fa

cilit

ies

Mod

ifica

tion

to

onsh

ore

pipe

line

corr

idor

(M&

NP

Opt

ion)

N/A

N

/A

N/A

N

/A

N/A

N

/A

N/A

N

oise

and

ph

ysic

al

dist

urba

nce

to

terr

estri

al

habi

tat;

pote

ntia

l in

tera

ctio

n w

ith w

etla

nds

and

fres

hwat

er

reso

urce

s(i.

e., B

etty

’s

Cov

e B

rook

)

Dee

p Pa

nuke

Vol

ume

4 (E

nvir

onm

enta

l Ass

essm

ent R

epor

t) N

ovem

ber 2

006

6-1

8

Tab

le 6

.6

Proj

ect I

nter

actio

ns w

ith B

ioph

ysic

al V

EC

s B

ioph

ysic

al V

EC

s Pr

ojec

t C

ompo

nent

Proj

ect

Mod

ifica

tion

Air

Qua

lity

Mar

ine

Wat

er

Qua

lity

Mar

ine

Ben

thos

M

arin

e Fi

sh

Mar

ine

Mam

mal

s and

T

urtle

s

Mar

ine

Rel

ated

B

irds

Sabl

e Is

land

O

nsho

re

Env

iron

men

t

Ope

ratio

ns1

inst

alla

tion

(MO

PU)

inst

ead

of 3

pla

tform

s N

/A

N/A

Sm

alle

r be

nthi

cfo

otpr

int;

smal

ler r

eef

effe

ct

Few

er

reef

/refu

ge

effe

cts

Few

er

reef

/refu

ge

effe

cts f

or

prey

; sm

alle

r st

ruct

ure

foot

prin

t

Less

dis

char

ges

and

light

ing;

fe

wer

pla

tform

s fo

r col

oniz

atio

n,

shel

ter,

etc.

N/A

N

/A

Low

er p

rodu

ctio

n flo

w; l

ower

thro

ughp

ut

Less

rout

ine

emis

sion

s fro

m

flarin

g an

d ex

haus

t en

gine

s

N/A

N

/A

N/A

N

/A

N/A

N

/A

N/A

Off

shor

ePr

oduc

tion

Long

er p

rodu

ctio

n pe

riod

Gre

ater

tem

pora

l bo

unda

ries f

or

inte

ract

ion

Gre

ater

te

mpo

ral

boun

darie

s for

in

tera

ctio

n

Gre

ater

te

mpo

ral

boun

darie

sfo

r int

erac

tion

Gre

ater

te

mpo

ral

boun

darie

s for

in

tera

ctio

n

Gre

ater

te

mpo

ral

boun

darie

s for

in

tera

ctio

n

Gre

ater

te

mpo

ral

boun

darie

s for

in

tera

ctio

n

N/A

N

/A

Rel

ocat

ion

of fi

eld

cent

re

Cha

nge

in lo

catio

n of

sour

ce o

f air

emis

sion

s

Cha

nge

in

loca

tion

of

mar

ine

disc

harg

es

Cha

nge

in

loca

tion

of

bent

hic

foot

prin

t

Cha

nge

in

loca

tion

of

reef

/refu

ge

effe

cts;

cha

nge

in lo

catio

n of

m

arin

edi

scha

rges

Cha

nge

in

loca

tion

of

reef

/refu

ge

effe

cts f

or

prey

; cha

nge

in

loca

tion

of

mar

ine

disc

harg

es

Cha

nge

in

loca

tion

of

light

s/di

scha

rges

Clo

ser t

o Sa

ble

Isla

nd;

grea

ter

pote

ntia

l for

in

tera

ctio

n as

soci

ated

w

ithat

mos

pher

ic

and

acci

dent

al

mar

ine

rele

ases

N/A

Gre

ater

pro

duce

d w

ater

di

scha

rges

N/A

G

reat

er w

ater

qu

ality

de

grad

atio

n

Pote

ntia

l co

ntam

inat

ion

of b

enth

os

Gre

ater

wat

er

qual

ity

degr

adat

ion

and

pote

ntia

l to

xici

ty to

m

arin

eor

gani

sms

Gre

ater

wat

er

qual

ity

degr

adat

ion;

cont

amin

atio

nof

food

sour

ces

Con

tam

inat

ion

of fo

od so

urce

s N

/A

N/A

Dee

p Pa

nuke

Vol

ume

4 (E

nvir

onm

enta

l Ass

essm

ent R

epor

t) N

ovem

ber 2

006

6-1

9

Tab

le 6

.6

Proj

ect I

nter

actio

ns w

ith B

ioph

ysic

al V

EC

s B

ioph

ysic

al V

EC

s Pr

ojec

t C

ompo

nent

Proj

ect

Mod

ifica

tion

Air

Qua

lity

Mar

ine

Wat

er

Qua

lity

Mar

ine

Ben

thos

M

arin

e Fi

sh

Mar

ine

Mam

mal

s and

T

urtle

s

Mar

ine

Rel

ated

B

irds

Sabl

e Is

land

O

nsho

re

Env

iron

men

t

Subs

eaEq

uipm

ent

Flow

lines

, um

bilic

als

and

wel

lsN

/A

N/A

G

reat

er

refu

ge e

ffec

t as

soci

ated

w

ith la

rger

sa

fety

zon

e;

grea

ter r

eef

effe

ctas

soci

ated

w

ithad

ditio

nal

stru

ctur

es o

n se

aflo

or

Gre

ater

refu

ge

effe

ct a

ssoc

iate

d w

ith la

rger

sa

fety

zon

e;

grea

ter r

eef

effe

ct a

ssoc

iate

d w

ith a

dditi

onal

st

ruct

ures

on

seaf

loor

Gre

ater

food

su

pply

as

soci

ated

with

re

ef/re

fuge

ef

fect

s rel

ated

to

the

pres

ence

of

exp

osed

su

bsea

stru

ctur

es a

nd

safe

ty z

one

N/A

N

/A

N/A

Expo

rt Pi

pelin

e Pi

pelin

e to

SO

EP

subs

ea ti

e-in

(SO

EP

Subs

ea O

ptio

n)

N/A

N

/A

Pote

ntia

l re

ef/re

fuge

ef

fect

asso

ciat

ed

with

subs

ea

conn

ectio

nst

ruct

ures

Pote

ntia

l re

ef/re

fuge

ef

fect

ass

ocia

ted

with

subs

ea

conn

ectio

nst

ruct

ures

N/A

N

/A

N/A

N

/A

Ons

hore

Pip

elin

e an

d Fa

cilit

ies

Mod

ifica

tion

to

onsh

ore

pipe

line

corr

idor

N/A

N

/A

N/A

N

/A

N/A

N

/A

N/A

N

oise

and

ot

her

dist

urba

nce

of te

rres

trial

ha

bita

t and

w

ildlif

e du

ring

mai

nten

ance

of

pip

elin

e an

d R

oWD

ecom

miss

ioni

ng

1 in

stal

latio

n (M

OPU

) in

stea

d of

3 p

latfo

rms

Low

er a

ir em

issi

ons

Less

phy

sica

l di

stur

banc

e an

d SP

M

N/A

Le

ss p

hysi

cal

dist

urba

nce

and

SPM

; les

s noi

se

dist

urba

nce

Less

noi

se

dist

urba

nce

Less

noi

se

dist

urba

nce

N/A

N

/A

Proj

ect F

acili

ties

Dec

omm

issi

onin

g

Bur

ied

pipe

line,

flo

wlin

es a

nd

umbi

lical

s

N/A

Pr

esen

ce o

f ab

ando

ned

subs

east

ruct

ures

Pres

ence

of

aban

done

d su

bsea

stru

ctur

es

Pres

ence

of

aban

done

d su

bsea

stru

ctur

es

N/A

N

/A

N/A

N

/A

Dee

p Pa

nuke

Vol

ume

4 (E

nvir

onm

enta

l Ass

essm

ent R

epor

t) N

ovem

ber 2

006

6-2

0

Tab

le 6

.6

Proj

ect I

nter

actio

ns w

ith B

ioph

ysic

al V

EC

s B

ioph

ysic

al V

EC

s Pr

ojec

t C

ompo

nent

Proj

ect

Mod

ifica

tion

Air

Qua

lity

Mar

ine

Wat

er

Qua

lity

Mar

ine

Ben

thos

M

arin

e Fi

sh

Mar

ine

Mam

mal

s and

T

urtle

s

Mar

ine

Rel

ated

B

irds

Sabl

e Is

land

O

nsho

re

Env

iron

men

t

M

odifi

catio

n to

on

shor

e pi

pelin

e co

rrid

or

N/A

N

/A

N/A

N

/A

N/A

N

/A

N/A

N

oise

and

m

inor

phys

ical

di

stur

banc

e to

te

rres

trial

ha

bita

t

Mal

func

tions

and

Acc

iden

tal E

vent

s Lo

nger

pro

duct

ion

perio

dG

reat

er

blow

out/s

pill

risk

expo

sure

Gre

ater

spill

risk

ex

posu

reG

reat

er sp

ill

risk

expo

sure

bu

t pot

entia

l im

pact

s on

bent

hos

equi

vale

nt to

20

02 P

roje

ct

basi

s

Gre

ater

spill

risk

ex

posu

reG

reat

er sp

ill

risk

expo

sure

G

reat

er sp

ill ri

sk

expo

sure

Gre

ater

spill

ris

kex

posu

re

N/A

Off

shor

ePr

oduc

tion

Rel

ocat

ion

of fi

eld

cent

re

Cha

nge

in lo

catio

n of

sour

ce o

f air

emis

sion

s

Cha

nge

in sp

ill

loca

tion

N/A

C

hang

e in

spill

lo

catio

n

Cha

nge

in sp

ill

loca

tion

Cha

nge

in sp

ill

loca

tion

C

lose

r to

Sabl

e Is

land

; gr

eate

r po

tent

ial o

f in

tera

ctio

n as

soci

ated

w

ith sp

ills

and

ups

et

atm

osph

eric

re

leas

es

N/A

Subs

eaEq

uipm

ent

Flow

lines

, um

bilic

als,

wel

ls a

nd su

bsea

pr

otec

tion

New

risk

of s

ubse

a fa

ilure

resu

lting

in

atm

osph

eric

re

leas

es

New

risk

of

subs

ea fa

ilure

re

sulti

ng in

ac

cide

ntal

m

arin

e sp

ills

N/A

N

ew ri

sk o

f su

bsea

failu

re

resu

lting

in

acci

dent

al

mar

ine

spill

s

New

risk

of

subs

ea fa

ilure

re

sulti

ng in

ac

cide

ntal

m

arin

e sp

ills

New

risk

of

subs

ea fa

ilure

re

sulti

ng in

ac

cide

ntal

m

arin

e sp

ills

New

risk

of

subs

eafa

ilure

re

sulti

ng in

ac

cide

ntal

at

mos

pher

ic

rele

ases

and

m

arin

e sp

ills

N/A

Dee

p Pa

nuke

Vol

ume

4 (E

nvir

onm

enta

l Ass

essm

ent R

epor

t) N

ovem

ber 2

006

6-2

1

Tab

le 6

.6

Proj

ect I

nter

actio

ns w

ith B

ioph

ysic

al V

EC

s B

ioph

ysic

al V

EC

s Pr

ojec

t C

ompo

nent

Proj

ect

Mod

ifica

tion

Air

Qua

lity

Mar

ine

Wat

er

Qua

lity

Mar

ine

Ben

thos

M

arin

e Fi

sh

Mar

ine

Mam

mal

s and

T

urtle

s

Mar

ine

Rel

ated

B

irds

Sabl

e Is

land

O

nsho

re

Env

iron

men

t

Expo

rt Pi

pelin

e Pi

pelin

e to

SO

EP

subs

ea ti

e-in

(SO

EP

Subs

ea O

ptio

n)

Cha

nge

in lo

catio

n of

pot

entia

l fai

lure

po

int r

esul

ting

in

atm

osph

eric

re

leas

es

New

risk

of s

pill

expo

sure

asso

ciat

ed w

ith

mul

ti-ph

ase

pipe

line

to

SOEP

N/A

New

risk

of s

pill

expo

sure

asso

ciat

ed w

ith

mul

ti-ph

ase

pipe

line

to

SOEP

New

risk

of

spill

exp

osur

e as

soci

ated

with

m

ulti-

phas

e pi

pelin

e to

SO

EP

New

risk

of s

pill

expo

sure

asso

ciat

ed w

ith

mul

ti-ph

ase

pipe

line

to

SOEP

New

risk

of

spill

expo

sure

asso

ciat

ed

with

mul

ti-ph

ase

pipe

line

to

SOEP

N/A

Dev

elop

men

tW

ell

Con

stru

ctio

n an

d O

pera

tion

Tota

l num

ber o

f wel

ls

has i

ncre

ased

to 9

(in

clud

ing

4 w

ell r

e-en

tries

)

Cha

nge

in p

oten

tial

blow

out/s

pill

risk

expo

sure

Cha

nge

in

pote

ntia

l bl

owou

t/spi

llris

k ex

posu

re

N/A

C

hang

e in

po

tent

ial

blow

out/s

pill

risk

expo

sure

Cha

nge

in

pote

ntia

l bl

owou

t/spi

llris

k ex

posu

re

Cha

nge

in

pote

ntia

l bl

owou

t/spi

llris

k ex

posu

re

Cha

nge

in

pote

ntia

l bl

owou

t/spi

llris

kex

posu

re

N/A

Elim

inat

ion

of o

nsho

re

faci

litie

s and

pip

elin

e (S

OEP

Sub

sea

Opt

ion)

N/A

N

/A

N/A

N

/A

N/A

N

/A

N/A

N

/A

Ons

hore

Faci

litie

s and

Pi

pelin

eM

odifi

catio

n to

on

shor

e pi

pelin

e co

rrid

or (M

&N

P O

ptio

n)

Gre

ater

risk

of

pipe

line

rele

ases

N

/A

N/A

N

/A

N/A

N

/A

N/A

C

hang

e in

pi

pelin

e sp

ill

risk

prob

abili

ty

and

effe

cts

due

to c

hang

e in

loca

tion

and

surr

ound

ing

land

use

s

Dee

p Pa

nuke

Vol

ume

4 (E

nvir

onm

enta

l Ass

essm

ent R

epor

t) N

ovem

ber 2

006

6-

22

Tab

le 6

.7

Proj

ect I

nter

actio

ns w

ith S

ocio

-eco

nom

ic V

EC

s

Soci

o-ec

onom

ic V

EC

s Pr

ojec

t Com

pone

nt

Proj

ect M

odifi

catio

n L

and

Use

E

cono

my

Com

mer

cial

Fish

erie

s an

d A

quac

ultu

re

Oth

er O

cean

Use

rs

Cons

truct

ion

and

Insta

llatio

n O

ffsh

ore

Prod

uctio

n Fa

cilit

ies

1 in

stal

latio

n (M

OPU

) ins

tead

of

3 p

latfo

rms

N/A

Ec

onom

ic a

ctiv

ity

(em

ploy

men

t and

inco

me)

fr

om P

roje

ct c

onst

ruct

ion

Less

inte

rfer

ence

with

fis

hing

act

iviti

es d

ue to

m

ore

loca

lized

act

ivity

for

the

inst

alla

tion

of th

e M

OPU

N/A

Flow

lines

, um

bilic

als,

subs

ea

prot

ectio

n st

ruct

ures

(wel

ls,

SSIV

skid

, and

hot

tap

and

tie-in

for S

OEP

Sub

sea

Opt

ion)

N/A

Ec

onom

ic a

ctiv

ity

(em

ploy

men

t and

inco

me)

fr

om P

roje

ct c

onst

ruct

ion

Pote

ntia

l for

inte

rfer

ing

with

fish

erie

s act

iviti

es

due

to P

roje

ct v

esse

l ac

tivity

dur

ing

inst

alla

tion

of su

bsea

equ

ipm

ent;

pote

ntia

l phy

sica

l eff

ects

on

ben

thic

hab

itat

Pote

ntia

l int

erfe

renc

e fr

om

subs

ea e

quip

men

t ins

talla

tion

activ

ities

with

mar

ine

trans

porta

tion,

subm

arin

e ca

bles

, mili

tary

use

, and

oil

and

gas a

ctiv

ity; p

oten

tial

conf

lict w

ith th

e D

raft

ESSI

M

Plan

Subs

ea E

quip

men

t

Pile

driv

ing

for h

ot-ta

p st

ruct

ure

(SO

EP S

ubse

a O

ptio

n) a

nd

wel

lhea

d/pr

otec

tion

stru

ctur

es

N/A

N

/A

Effe

cts o

n fis

h ca

tcha

bilit

y fr

om u

nder

wat

er p

ile

driv

ing

nois

e (lo

wer

soun

d le

vels

but

at s

ever

al

loca

tions

inst

ead

of fi

eld

cent

re)

Pote

ntia

l int

erfe

renc

e w

ith

mili

tary

act

ivity

from

un

derw

ater

pile

driv

ing

nois

e (lo

wer

soun

d le

vel b

ut a

t se

vera

l loc

atio

ns in

stea

d of

on

e fie

ld c

entre

)

Expo

rt Pi

pelin

e to

SO

EP

(SO

EP S

ubse

a O

ptio

n)

Con

stru

ctio

n of

new

pip

elin

e to

SO

EP su

bsea

tie-

in

N/A

Ec

onom

ic a

ctiv

ity

(em

ploy

men

t and

inco

me)

fr

om P

roje

ct c

onst

ruct

ion;

le

ss e

cono

mic

act

ivity

as

soci

ated

with

shor

ter

pipe

line

(com

pare

d w

ith

M&

NP

Opt

ion)

but

ons

hore

co

nden

sate

pro

cess

ing

Pote

ntia

l for

inte

rfer

ence

w

ith fi

shin

g ac

tiviti

es d

ue

to P

roje

ct v

esse

l act

ivity

du

ring

pipe

line

inst

alla

tion;

pot

entia

l ph

ysic

al e

ffec

ts o

n qu

ahog

s and

ben

thic

ha

bita

t; el

imin

atio

n of

po

tent

ial i

nter

actio

ns w

ith

near

shor

e fis

herie

s and

aq

uacu

lture

Pote

ntia

l int

erfe

renc

e fr

om

pipe

line

inst

alla

tion

activ

ities

w

ith m

arin

e tra

nspo

rtatio

n,

subm

arin

e ca

bles

, mili

tary

us

e, a

nd o

il an

d ga

s act

ivity

; po

tent

ial c

onfli

ct w

ith th

e D

raft

ESSI

M P

lan

Dee

p Pa

nuke

Vol

ume

4 (E

nvir

onm

enta

l Ass

essm

ent R

epor

t) N

ovem

ber 2

006

6-

23

Tab

le 6

.7

Proj

ect I

nter

actio

ns w

ith S

ocio

-eco

nom

ic V

EC

s

Soci

o-ec

onom

ic V

EC

s Pr

ojec

t Com

pone

nt

Proj

ect M

odifi

catio

n L

and

Use

E

cono

my

Com

mer

cial

Fish

erie

s an

d A

quac

ultu

re

Oth

er O

cean

Use

rs

Expo

rt Pi

pelin

e to

Sho

re

(M&

NP

Opt

ion)

M

odifi

catio

n of

ons

hore

and

of

fsho

re p

ipel

ine

rout

e (d

ue

to re

loca

tion

of fi

eld

cent

re)

Enha

ncem

ent o

f lan

d us

e co

nsis

tent

with

pla

nnin

g de

sign

atio

n; p

oten

tial i

nter

actio

n du

ring

cons

truct

ion

of th

e pr

opos

ed M

aple

LN

G a

nd K

eltic

Pe

troch

emic

al fa

cilit

ies;

min

or

dist

urba

nces

to n

earb

y la

nd u

ses

(e.g

., tra

ffic

, noi

se, d

ust)

N/A

Po

tent

ial i

nter

actio

n w

ith

new

fish

erie

s (e.

g. q

uaho

g an

d se

a cu

cum

ber)

Pote

ntia

l int

erfe

renc

e w

ith

othe

r use

r act

iviti

es (e

.g.,

ESSI

M, m

arin

e tra

nspo

rtatio

n)

Dev

elop

men

t Wel

l C

onst

ruct

ion

Tota

l num

ber o

f wel

ls h

as

incr

ease

d to

9 b

ut in

clud

es 4

re

-ent

ries

N/A

Ec

onom

ic a

ctiv

ity

(em

ploy

men

t and

inco

me

) fr

om P

roje

ct c

onst

ruct

ion

Gre

ater

spat

ial b

ut sh

orte

r te

mpo

ral b

ound

arie

s for

po

tent

ial i

nter

actio

n w

ith

com

mer

cial

fish

erie

s

Pote

ntia

l int

erfe

renc

e fr

om

wel

l con

stru

ctio

n (in

clud

ing

drill

ing)

with

mar

ine

trans

porta

tion,

subm

arin

e ca

bles

, mili

tary

use

, and

oil

and

gas a

ctiv

ity; p

oten

tial

conf

lict w

ith th

e D

raft

ESSI

M

Plan

O

pera

tions

1 in

stal

latio

n (M

OPU

) ins

tead

of

3

N/A

N

/A

Larg

er sa

fety

zon

e ar

ound

M

OPU

, flo

wlin

es,

umbi

lical

s and

subs

ea

prot

ectio

n st

ruct

ures

N/A

Off

shor

e Pr

oduc

tion

Long

er p

rodu

ctio

n pe

riod

N/A

Ec

onom

ic a

ctiv

ity

(em

ploy

men

t and

inco

me)

as

soci

ated

with

faci

lity

oper

atio

ns a

nd m

aint

enan

ce

Cha

nge

in te

mpo

ral

boun

darie

s for

inte

ract

ion

with

com

mer

cial

fish

erie

s

Cha

nge

in te

mpo

ral

boun

darie

s for

inte

ract

ion

w

ith m

arin

e tra

nspo

rtatio

n,

mili

tary

use

, and

oil

and

gas

activ

ity

R

eloc

atio

n of

fiel

d ce

ntre

N

/A

N/A

C

hang

e in

loca

tion

of

pote

ntia

l int

erac

tions

with

of

fsho

re fi

sher

ies

Cha

nge

in lo

catio

n of

po

tent

ial i

nter

actio

n w

ith

mar

ine

trans

porta

tion,

mili

tary

us

e, a

nd o

il an

d ga

s act

ivity

; po

tent

ial c

onfli

ct w

ith D

raft

ESSI

M P

lan

Dee

p Pa

nuke

Vol

ume

4 (E

nvir

onm

enta

l Ass

essm

ent R

epor

t) N

ovem

ber 2

006

6-

24

Tab

le 6

.7

Proj

ect I

nter

actio

ns w

ith S

ocio

-eco

nom

ic V

EC

s

Soci

o-ec

onom

ic V

EC

s Pr

ojec

t Com

pone

nt

Proj

ect M

odifi

catio

n L

and

Use

E

cono

my

Com

mer

cial

Fish

erie

s an

d A

quac

ultu

re

Oth

er O

cean

Use

rs

G

reat

er p

rodu

ced

wat

er

disc

harg

esN

/A

N/A

G

reat

er w

ater

qua

lity

degr

adat

ion

near

MO

PU

N/A

Subs

ea E

quip

men

t Fl

owlin

es, u

mbi

lical

s and

w

ells

N/A

Ec

onom

ic a

ctiv

ity

(em

ploy

men

t and

inco

me)

as

soci

ated

with

faci

lity

oper

atio

ns a

nd m

aint

enan

ce

Larg

er sa

fety

zon

e ar

ound

M

OPU

, flo

wlin

es,

umbi

lical

s and

subs

ea

prot

ectio

n st

ruct

ures

Pote

ntia

l int

erfe

renc

e w

ith

othe

r oce

an u

sers

rela

ted

to

subs

ea st

ruct

ures

and

safe

ty

zone

; eff

ects

on

mar

ine

navi

gatio

nEx

port

Pipe

line

to S

hore

(S

OEP

Sub

sea

Opt

ion)

Pr

esen

ce o

f new

pip

elin

e to

SO

EP

N/A

N

/A

Pote

ntia

l int

erfe

renc

e w

ith

antic

ipat

ed q

uaho

g fis

hing

ac

tiviti

es

N/A

Mod

ifica

tion

to o

ffsh

ore

pipe

line

rout

e (d

ue to

re

loca

tion

of fi

eld

cent

re)

N/A

N

/A

Pote

ntia

l int

erfe

renc

e w

ith

antic

ipat

ed q

uaho

g fis

hing

ac

tiviti

es

N/A

Expo

rt Pi

pelin

e to

Sho

re

(M&

NP

Opt

ion)

Mod

ifica

tion

to o

nsho

re

pipe

line

corr

idor

En

hanc

emen

t of l

and

use

cons

iste

nt w

ith p

lann

ing

desi

gnat

ion;

pot

entia

l con

stra

ints

on

the

loca

tion

and

oper

atio

n of

th

e M

aple

LN

G a

nd K

eltic

Pe

troch

emic

al fa

cilit

ies

N/A

N

/A

N/A

Dec

omm

issio

ning

Pr

ojec

t Fac

ilitie

s D

ecom

mis

sion

ing

1 in

stal

latio

n (M

OPU

) ins

tead

of

3 p

latfo

rms

N/A

Ec

onom

ic a

ctiv

ity

(em

ploy

men

t and

inco

me)

as

soci

ated

with

faci

lity

deco

mm

issi

onin

g

Less

inte

rfer

ence

with

of

fsho

re fi

sher

ies

Red

uced

inte

rfer

ence

with

ot

her o

cean

use

rs

B

urie

d flo

wlin

es a

nd

umbi

lical

sN

/A

Econ

omic

act

ivity

(e

mpl

oym

ent a

nd in

com

e)

asso

ciat

ed w

ith fa

cilit

y de

com

mis

sion

ing

Pote

ntia

l int

erfe

renc

e w

ith

dred

ge fi

sher

ies (

e.g.

,qu

ahog

s)

N/A

A

band

onm

ent o

f pip

elin

e to

SO

EP su

bsea

tie-

in

N/A

Ec

onom

ic a

ctiv

ity

(em

ploy

men

t and

inco

me)

as

soci

ated

with

faci

lity

deco

mm

issi

onin

g

Pote

ntia

l int

erfe

renc

e w

ith

dred

ge fi

sher

ies (

e.g.

,qu

ahog

s)

N/A

Mal

func

tions

and

Acc

iden

tal E

vent

s O

ffsh

ore

Prod

uctio

n Lo

nger

pro

duct

ion

perio

d N

/A

N/A

G

reat

er sp

ill ri

sk e

xpos

ure

G

reat

er sp

ill ri

sk e

xpos

ure

to

mar

ine

trans

porta

tion,

mili

tary

us

e, a

nd o

il an

d ga

s act

ivity

Dee

p Pa

nuke

Vol

ume

4 (E

nvir

onm

enta

l Ass

essm

ent R

epor

t) N

ovem

ber 2

006

6-

25

Tab

le 6

.7

Proj

ect I

nter

actio

ns w

ith S

ocio

-eco

nom

ic V

EC

s

Soci

o-ec

onom

ic V

EC

s Pr

ojec

t Com

pone

nt

Proj

ect M

odifi

catio

n L

and

Use

E

cono

my

Com

mer

cial

Fish

erie

s an

d A

quac

ultu

re

Oth

er O

cean

Use

rs

R

eloc

atio

n of

fiel

d ce

ntre

N

/A

N/A

C

hang

e in

loca

tion

of

acci

dent

al sp

ill/

atm

osph

eric

rele

ases

Cha

nge

in lo

catio

n of

ac

cide

ntal

spill

/atm

osph

eric

re

leas

es p

oten

tially

aff

ectin

g m

arin

e tra

nspo

rtatio

n, m

ilita

ry

use,

and

oil

and

gas a

ctiv

ity

Flow

lines

, um

bilic

als,

wel

ls

and

subs

ea p

rote

ctio

n N

/A

N/A

C

hang

e in

loca

tion

of

acci

dent

al sp

ill/

atm

osph

eric

rele

ases

; in

crea

sed

spill

/air

rele

ase

risk

expo

sure

Gre

ater

spill

/atm

osph

eric

re

leas

e ris

k ex

posu

re to

m

arin

e tra

nspo

rtatio

n, m

ilita

ry

use,

and

oil

and

gas a

ctiv

ity

Subs

ea E

quip

men

t

Pipe

line

to S

OEP

subs

ea ti

e-in

(SO

EP S

ubse

a O

ptio

n O

nly)

N/A

N

/A

New

spill

/atm

osph

eric

re

leas

e ris

k ex

posu

re;

pote

ntia

l int

erac

tions

with

qu

ahog

fish

ery

and

othe

r fis

hing

act

iviti

es

New

spill

/atm

osph

eric

rele

ase

risk

expo

sure

pot

entia

lly

affe

ctin

g m

arin

e tra

nspo

rtatio

n, m

ilita

ry u

se,

and

oil a

nd g

as a

ctiv

ity

Ons

hore

Pip

elin

e M

odifi

catio

n to

ons

hore

pi

pelin

e co

rrid

or

Pote

ntia

l int

erac

tion

with

exi

stin

g an

d pl

anne

d la

nd u

ses (

e.g.

, Kel

tic

Petro

chem

ical

Fac

ility

and

Map

le

LNG

Fac

ility

) inc

ludi

ng g

reat

er

prob

abili

ty o

f an

acci

dent

al e

vent

N/A

N

/A

N/A


6.5 Scoping of Cumulative Effects Assessment

Environmental effects from individual projects can accumulate and interact to result in cumulative environmental effects. This EA considers cumulative environmental effects for each VEC as required by CEAA and the scoping document prepared by the RAs.

Project cumulative effects (i.e., those due to the accumulation and/or interaction of the Project’s own environmental effects) have been previously considered in the assessment for each VEC. This section focusses on the cumulative effects of the Project in combination with other relevant projects and activities.

The region’s natural and human environments have been affected by past and ongoing human activities. The description of the existing (baseline) environment in the approved 2002 CSR (Sections 6.1 and 7.2) and this document (Section 7) reflects the effects of these other anthropogenic pressures. The evaluation of cumulative environmental effects considers the nature and degree of change from these baseline environmental conditions as a result of the revised Project, in combination with other on-going and planned projects and activities.

An environmental assessment pursuant to CEAA must include consideration of the cumulative environmental effects for "reasonably foreseeable" projects or activities if they may affect the VECs and there is enough information about them to assess their effects (Cumulative Effects Assessment Working Group and AXYS Environmental Consulting Ltd. 1999). A critical step in the environmental assessment, therefore, is determining what other projects or activities have reached a level of certainty (e.g., “reasonably foreseeable”) such that they must be considered in the EA. The other projects and activities considered in this assessment are those that are ongoing or likely to proceed, and have been issued permits, licenses, leases or other forms of approval or entered the regulatory approvals process.

It is helpful to consider the clarification provided by the Joint Review Panel for the Express Pipeline Project in Alberta. Following an analysis of subsection 16(1)(a) of CEAA, that Joint Review Panel determined that certain requirements must be met for the Panel to consider cumulative environmental effects:

there must be a measurable environmental effect of the project being proposed; environmental effect must be demonstrated to operate cumulatively with the environmental effects from other projects or activities; and it must be known that the other projects or activities have been, or will be, carried out and are not hypothetical (NEB and CEA Agency 1996).


Furthermore, the Joint Review Panel indicated that it is an additional requirement that the cumulative environmental effects is likely to occur, that is, there must be some probability, rather than a mere possibility, that the cumulative environmental effect will occur. These criteria were used to guide the assessment of cumulative environmental effects for this Project.

A scoping exercise has been conducted to identify other past, present, and future projects and activities, the effects of which may interact cumulatively with those of the Project. These are limited to those projects and activities that have or will likely occur (e.g., seeking regulatory approvals) within the study area (Figure 6.1). As any measurable Project-related effects will occur within this study area, it is also reasonable to assume that any potential for cumulative effects will also occur within this study area.

These projects have been selected based on a review of those projects and activities considered in the approved 2002 CSR and updated accordingly. The Blue Atlantic Transmission System, Hudson Energy Company Power Project and Neptune Subsea Electrical Transmission System have not been reconsidered in this assessment as these projects have either been cancelled or put on hold indefinitely. The Sable Island Wind Turbine Project is proceeding, with the installation of wind turbines in March 2006 (previously reported to be constructed in 2002). However, operation of the turbines has yet to begin as of October 2006. New projects that have emerged since the approved 2002 CSR include the Keltic Petrochemical Plant and Maple LNG Facility in Goldboro. A list of these projects and brief description is provided below. These projects are also depicted on Figure 6.1.

Cohasset Project – The Cohasset Project began oil production in 1992 and produced 44.5 million barrels of oil over its 7.5 year production life. Decommissioning of the Cohasset facilities has been completed in accordance with EnCana’s decommissioning plan which involved removal of the platforms and subsea equipment which could pose a snagging hazard, and abandonment of buried flowlines, cables and mattresses in situ. EnCana plans to conduct a final field close out survey in fall 2006. A follow-up survey is planned by fall 2009.

Sable Offshore Energy Project – This natural gas development project consists of offshore platforms (manned central processing complex at Thebaud; unmanned satellite platforms at other locations), subsea interfield flowlines, export pipeline to shore (Goldboro), and onshore facilities (gas plant in Goldboro and fractionation plant in Point Tupper, interconnected by a natural gas liquids (NGL) pipeline). Tier I development included development of the Thebaud, North Triumph and Venture fields along with associated pipelines and onshore facilities. First gas flowed in December 1999. Tier II development has included installation and commissioning of platforms at Alma (2004) and South Venture (2005) fields as the installation of associated pipelines. A compression platform was installed as a part of the Thebaud complex in May/June 2006 with commissioning expected to be completed by year end.

5440

00

5440

00

6440

00

6440

00

7440

00

7440

00

8440

00

8440

00

4849000

4849000

4949000

4949000

OtherProjects&

ActivitiesRelativeto

DeepPanuke

ProjectArea

025

5012

.5

Kilo

met

ers

Map

Para

met

ers

Proj

ectio

n:U

TM-N

AD

83-Z

20Sc

ale

1:1,

000,

000

Dat

e:O

ctob

er20

,200

6Pr

ojec

tNo.

:101

5157

Figure6.1

SableIsland

NOVA

SCOTIA

DeepPanukeMOPU

CohassetProject

DeepPanukeProject

Dee

pP

anuk

eM

OPU

SOEP

Subs

eaO

ptio

nP

ipel

ine

M&

NP

Opt

ion

Pip

elin

e

Star

t-up

Flow

lines

SOEP

Facilities

SOEP

Plat

form

s

SOEP

Expo

rtan

dIn

terfi

eld

Pipe

lines

OffshorePetroleumInterests

Cur

rent

Exp

lora

tion

Lice

nse

Past

Exp

lora

tion

Lice

nse

Sign

ifica

ntD

isco

very

orP

rodu

ctio

nLi

cens

e

Keltic/MapleProject

Proj

ectL

ocat

ion:

See

Inse

t

Gol

dbor

o

ProposedKeltic

Petrochemicals

Plant&

Maple

LNGFacility

SOEP GAS

PLANT

Isaacs

Harbou

rGoldboro

020

4010

Kilo

met

ers

OnshoreFacilities

M&

NP

Mai

nlin

e

SOEP

NG

LLi

nean

dM

&NP

Poin

tTup

perL

ater

al

Subs

eaTe

leco

mm

unic

atio

nsC

able

s

EnC

ana

Prop

osed

Ons

hore

Cor

ridor

Prev

ious

Wel

lLoc

atio

ns(C

NS

OP

BW

ellD

irect

ory

(May

2006

))

Dec

omm

issi

onin

gLo

catio

n:Se

eIn

set

Dat

aS

ourc

e:w

ww

.cns

opb.

ns.c

a/

PL2902

PL2901

DeepPanukeMOPU

Flowline

Flowline

Flowlines

PowerCable

M&NP O

ption Pi

peline

SOEPSubs

eaOptionP

ipeline

100m

COHASSET

DECOMMISSIONINGINSET

04

82

Kilometers

KELTIC/MAPLEPROJECTINSET


Maritimes & Northeast Pipeline (M&NP) Gas Transmission- The M&NP system is a 1,300-kilometre transmission pipeline system built in 1999 to transport natural gas from developments offshore Nova Scotia to markets in Atlantic Canada and the northeastern United States. The M&NP system consists of 760 mm [30 inch]/600 mm [24 inch] mainline that runs from the SOEP gas plant at landfall in Goldboro, through Nova Scotia and New Brunswick, to the northeastern United States. The M&NP Option for the Deep Panuke Project involves tie-in to an M&NP custody transfer station bypassing the SOEP gas plant.

Keltic Petrochemicals Inc. and Maple LNG Project (Keltic/Maple Project) – Keltic Petrochemicals Inc. proposes to construct and operate a petrochemical and LNG facility near Goldboro, NS. The Project components include a LNG regasification facility, a petrochemical complex, a marginal wharf, a marine LNG terminal, LNG storage and an electric co-generation facility. The processing facilities will require approximately 300 ha of land zoned for industrial use in the Goldboro Industrial Park. Maple LNG will acquire 100% of the LNG portion of the project. Pending regulatory approval, project construction is planned to occur from Spring 2007 to the end of 2009, with commissioning to occur in Winter 2010. This project is currently undergoing environmental assessment under the Nova Scotia Environment Act and CEAA. The draft environmental assessment report (AMEC 2006) predicts several significant benefits to the local and regional economy. It also predicts a loss of terrestrial habitat (>700 ha, including impoundment of Meadow Lake), significant changes to freshwater aquatic habitat (due to creation of reservoir at Meadow Lake), and significant additional demands on local and regional roadways.

In addition to specific projects, the following activities (past, present and future) could interact cumulatively with the Project:

offshore petroleum exploration drilling (past, present, and future activity); seismic exploration (past, present, and future activity); research surveys (past, present, and future activity); shipping (domestic and international) (past, present, and future activity); commercial fishery (past, present, and future activity); commercial whaling (past activity); tourism (past, present, and future activity); military exercises (past, present, and future activity); use and occupation of Sable Island (past, present, and future activity); long-range transport of air pollutants; andtelecommunication cables (past, present, and future activity).


These activities were considered in the cumulative effects assessment (CEA) for biophysical VECs presented in the approved 2002 CSR (Section 6.3.9). The CEA contained in this EA Report only reconsiders those activities that:

have changed since 2002 such that the cumulative effects would differ than that originally predicted; or

interact cumulatively with the revised Project options, resulting in different cumulative effects than originally predicted for the 2002 Project basis.

Tables 6.8 and 6.9 consider potential interactions of the above projects and activities with the biophysical and socio-economic VECs, respectively. These interactions are discussed further within the respective cumulative effects sections (Section 8.9 and 9.5).

Dee

p Pa

nuke

Vol

ume

4 (E

nvir

onm

enta

l Ass

essm

ent R

epor

t) N

ovem

ber 2

006

6-3

1

Tab

le 6

.8

Scop

ing

of P

oten

tial C

umul

ativ

e In

tera

ctio

ns w

ith B

ioph

ysic

al V

EC

s B

ioph

ysic

al V

EC

O

ther

Pro

ject

s and

A

ctiv

ities

(Pas

t, Pr

esen

t, Fu

ture

) w

ith P

oten

tial f

or

Cum

ulat

ive

Effe

cts

Scop

ing

Con

side

ratio

ns

Air Quality

Marine Water Quality

Marine Benthos

Marine Fish

Marine Mammals and Turtles

Marine Related Birds

Sable Island

Onshore Environment

Pote

ntia

l Int

erac

tions

Coh

asse

t Pro

ject

(P

ast,

Pres

ent,

Futu

re)

Proj

ects

hav

e ov

erla

ppin

g fo

otpr

ints

.C

umul

ativ

e in

tera

ctio

ns w

ith

past

eff

ects

con

side

red

in

appr

oved

200

2 C

SR.

CEA

will

focu

s on

pote

ntia

l ov

erla

p be

twee

n C

ohas

set

deco

mm

issi

oned

stru

ctur

es

and

Proj

ect i

nfra

stru

ctur

e.

Pr

esen

ce o

f bur

ied

pipe

line,

inte

rfie

ld fl

owlin

es,

umbi

lical

s and

mat

tress

es; r

eef a

nd re

fuge

eff

ects

on

fish

and

ben

thic

org

anis

ms

Sabl

e O

ffsh

ore

Ener

gy P

roje

ct

(Pas

t, Pr

esen

t, Fu

ture

)

CEA

in a

ppro

ved

2002

CSR

re

quire

s upd

ate

with

resp

ect

to c

hang

es in

air

emis

sion

s, be

nthi

c ef

fect

s, an

d ch

ange

in

ons

hore

Pro

ject

loca

tion.

Air

emis

sion

s; e

ffec

ts o

n se

dim

ent a

nd b

enth

ic

com

mun

ities

; los

s of t

erre

stria

l hab

itat

M&

NP

Gas

Tr

ansm

issi

on (P

ast,

Pres

ent,

Futu

re)

CEA

in a

ppro

ved

2002

CSR

re

quire

s upd

ate

to re

flect

ch

ange

in o

nsho

re c

orrid

or

and

cust

ody

trans

fer s

tatio

n.

Lo

ss o

f ter

rest

rial h

abita

t; er

osio

n an

d se

dim

enta

tion;

sens

ory

dist

urba

nce

to w

ildlif

e

Sabl

e Is

land

Win

d Tu

rbin

e Pr

ojec

t C

EA in

app

rove

d 20

02 C

SR re

mai

ns v

alid

des

pite

Pro

ject

mod

ifica

tions

. No

furth

er a

sses

smen

t nec

essa

ry.

Kel

tic

Petro

chem

ical

Pla

nt

and

Map

le L

NG

Fa

cilit

y (P

ropo

sed)

CEA

requ

ires u

pdat

e to

in

clud

e th

is n

ew p

roje

ct in

on

shor

e/ne

arsh

ore

stud

y ar

ea.

Loss

of t

erre

stria

l hab

itat;

eros

ion

and

sedi

men

tatio

n; tr

affic

; sen

sory

dis

turb

ance

to

wild

life;

air

emis

sion

s; d

istu

rban

ce to

nea

rsho

re

bent

hos;

acc

iden

tal e

vent

s

Off

shor

eEx

plor

atio

n D

rillin

gC

EA in

app

rove

d 20

02 C

SR re

mai

ns v

alid

des

pite

Pro

ject

mod

ifica

tions

. No

furth

er a

sses

smen

t nec

essa

ry.

Seis

mic

Exp

lora

tion

CEA

in a

ppro

ved

2002

CSR

rem

ains

val

id d

espi

te P

roje

ct m

odifi

catio

ns. N

o fu

rther

ass

essm

ent n

eces

sary

. Sh

ippi

ng

CEA

in a

ppro

ved

2002

CSR

rem

ains

val

id d

espi

te P

roje

ct m

odifi

catio

ns. N

o fu

rther

ass

essm

ent n

eces

sary

.

Dee

p Pa

nuke

Vol

ume

4 (E

nvir

onm

enta

l Ass

essm

ent R

epor

t) N

ovem

ber 2

006

6-3

2

Tab

le 6

.8

Scop

ing

of P

oten

tial C

umul

ativ

e In

tera

ctio

ns w

ith B

ioph

ysic

al V

EC

s B

ioph

ysic

al V

EC

O

ther

Pro

ject

s and

A

ctiv

ities

(Pas

t, Pr

esen

t, Fu

ture

) w

ith P

oten

tial f

or

Cum

ulat

ive

Effe

cts

Scop

ing

Con

side

ratio

ns

Air Quality

Marine Water Quality

Marine Benthos

Marine Fish

Marine Mammals and Turtles

Marine Related Birds

Sable Island

Onshore Environment

Pote

ntia

l Int

erac

tions

Com

mer

cial

Fis

hery

C

hang

es in

fish

ing

activ

ity

(e.g

., ne

w q

uaho

g fis

hery

an

d ex

perim

enta

l sea

cu

cum

ber f

ishe

ry) r

equi

res

upda

te o

f CEA

.

C

ollis

ions

/ent

angl

emen

t with

mar

ine

mam

mal

s and

se

a tu

rtles

; dis

turb

ance

to b

enth

ic h

abita

t fro

m

drag

gers

/traw

lers

; mor

talit

y of

fish

Com

mer

cial

W

halin

g (P

ast)

CEA

in a

ppro

ved

2002

CSR

rem

ains

val

id d

espi

te P

roje

ct m

odifi

catio

ns. N

o fu

rther

ass

essm

ent n

eces

sary

.

Tour

ism

C

EA in

app

rove

d 20

02 C

SR re

mai

ns v

alid

des

pite

Pro

ject

mod

ifica

tions

. N

o fu

rther

ass

essm

ent n

eces

sary

. M

ilita

ry E

xerc

ises

C

EA in

app

rove

d 20

02 C

SR re

mai

ns v

alid

des

pite

Pro

ject

mod

ifica

tions

. No

furth

er a

sses

smen

t nec

essa

ry.

Use

and

Occ

upat

ion

of S

able

Isla

nd

(Pas

t, Pr

esen

t, Fu

ture

)

CEA

in a

ppro

ved

2002

CSR

rem

ains

val

id d

espi

te P

roje

ct m

odifi

catio

ns. N

o fu

rther

ass

essm

ent n

eces

sary

.

Long

Ran

ge

Tran

spor

t of A

ir Po

lluta

nts (

Past

, Pr

esen

t, Fu

ture

)

CEA

in a

ppro

ved

2002

CSR

rem

ains

val

id d

espi

te P

roje

ct m

odifi

catio

ns. N

o fu

rther

ass

essm

ent n

eces

sary

.

Tele

com

mun

icat

ions

Cab

les (

Past

, Pr

esen

t, Fu

ture

)

Focu

s on

cum

ulat

ive

impa

ct

asso

ciat

ed w

ith se

abed

st

ruct

ures

.

Pres

ence

of s

truct

ures

on

seaf

loor

; pot

entia

l re

ef/re

fuge

eff

ects

Dee

p Pa

nuke

Vol

ume

4 (E

nvir

onm

enta

l Ass

essm

ent R

epor

t) N

ovem

ber 2

006

6-3

3

Tab

le 6

.9

Scop

ing

of P

oten

tial C

umul

ativ

e In

tera

ctio

ns w

ith S

ocio

-eco

nom

ic V

EC

s So

cio-

econ

omic

VE

C

Oth

er P

roje

cts a

nd

Act

iviti

es (P

ast,

Pres

ent,

Futu

re) w

ith

Pote

ntia

l for

C

umul

ativ

e E

ffect

s

Scop

ing

Con

side

ratio

ns

Land Use

Economy

Commercial Fisheries and Aquaculture

Other Ocean Users

Pote

ntia

l Int

erac

tions

Coh

asse

t Pro

ject

(Pas

t an

d Pr

esen

t) So

cio-

econ

omic

CEA

in

appr

oved

200

2 C

SR d

id n

ot

expl

icitl

y in

clud

e C

ohas

set

Proj

ect.

C

EA w

ill fo

cus o

n pr

esen

ce o

f sa

fety

zon

e an

d ov

erla

p be

twee

n C

ohas

set

deco

mm

issi

oned

stru

ctur

es a

nd

Proj

ect i

nfra

stru

ctur

e.

Pres

ence

of s

afet

y (n

o fis

hing

) zon

e; p

rese

nce

of st

ruct

ures

on

the

seaf

loor

; ef

fect

s on

publ

ic n

avig

atio

n an

d fis

hing

act

iviti

es

Sabl

e O

ffsh

ore

Ener

gy

Proj

ect (

Past

, Pre

sent

, Fu

ture

)

Soci

o-ec

onom

ic C

EA in

ap

prov

ed 2

002

CSR

add

ress

ed

cum

ulat

ive

econ

omic

eff

ects

. C

EA re

quire

s upd

ate

with

re

spec

t to

cum

ulat

ive

effe

cts

on fi

sher

ies a

nd o

ther

oce

an

user

s, an

d to

refle

ct c

hang

e in

on

shor

e Pr

ojec

t loc

atio

n (la

nd

use)

.

Pres

ence

of s

afet

y (n

o fis

hing

) zon

e; e

ffec

ts o

n pu

blic

nav

igat

ion;

reef

/refu

ge

effe

cts f

or fi

sh; i

ndus

trial

land

use

in st

udy

area

M&

NP

Gas

Tr

ansm

issi

on (P

ast,

Pres

ent,

Futu

re)

CEA

in a

ppro

ved

2002

CSR

re

quire

s upd

ate

to re

flect

ch

ange

in o

nsho

re c

orrid

or a

nd

cust

ody

trans

fer s

tatio

n.

In

dust

rial l

and

use

in st

udy

area

Kel

tic P

etro

chem

ical

Pl

ant a

nd M

aple

LN

G

Faci

lity

(Pro

pose

d)

CEA

requ

ires u

pdat

e to

incl

ude

this

new

pro

ject

in

onsh

ore/

near

shor

e st

udy

area

.

Con

tribu

tion

to p

rovi

ncia

l eco

nom

y; e

ffec

ts o

n ne

arsh

ore

fishe

ries a

nd

aqua

cultu

re; i

ndus

trial

land

use

in st

udy

area

; mar

ine

traff

ic; r

isk

for a

ccid

enta

l ev

ent

Off

shor

e Pe

trole

um

Expl

orat

ion

Dril

ling

(Pas

t, Pr

esen

t, Fu

ture

)

CEA

in a

ppro

ved

2002

CSR

rem

ains

val

id d

espi

te P

roje

ct m

odifi

catio

ns. N

o fu

rther

ass

essm

ent n

eces

sary

.

Dee

p Pa

nuke

Vol

ume

4 (E

nvir

onm

enta

l Ass

essm

ent R

epor

t) N

ovem

ber 2

006

6-3

4

Tab

le 6

.9

Scop

ing

of P

oten

tial C

umul

ativ

e In

tera

ctio

ns w

ith S

ocio

-eco

nom

ic V

EC

s So

cio-

econ

omic

VE

C

Oth

er P

roje

cts a

nd

Act

iviti

es (P

ast,

Pres

ent,

Futu

re) w

ith

Pote

ntia

l for

C

umul

ativ

e E

ffect

s

Scop

ing

Con

side

ratio

ns

Land Use

Economy

Commercial Fisheries and Aquaculture

Other Ocean Users

Pote

ntia

l Int

erac

tions

Seis

mic

Exp

lora

tion

CEA

in a

ppro

ved

2002

CSR

rem

ains

val

id d

espi

te P

roje

ct m

odifi

catio

ns. N

o fu

rther

ass

essm

ent n

eces

sary

. C

omm

erci

al F

ishe

ry

(Pas

t, Pr

esen

t, Fu

ture

) C

hang

es in

fish

ing

activ

ity

(e.g

., ne

w q

uaho

g fis

hery

and

ex

perim

enta

l sea

cuc

umbe

r fis

hery

) req

uire

s upd

ate

of

CEA

.

Con

tribu

tion

to p

rovi

ncia

l eco

nom

y; d

egra

datio

n of

mar

ine

bent

hos;

fish

m

orta

lity;

mar

ine

traff

ic

Mili

tary

Exe

rcis

es

(Pas

t, Pr

esen

t, Fu

ture

) C

EA to

con

side

r ves

sel t

raff

ic

and

hydr

oaco

ustic

s.M

arin

e tra

ffic

; noi

se; i

nter

actio

ns w

ith fi

sher

ies

Use

and

Occ

upat

ion

of

Sabl

e Is

land

(Pas

t, Pr

esen

t, Fu

ture

)

CEA

in a

ppro

ved

2002

CSR

rem

ains

val

id d

espi

te P

roje

ct m

odifi

catio

ns. N

o fu

rther

ass

essm

ent n

eces

sary

.

Tele

com

mun

icat

ions

Cab

les (

Past

, Pre

sent

, Fu

ture

)

Focu

s on

cum

ulat

ive

impa

ct

asso

ciat

ed w

ith se

abed

stru

ctur

es

Pr

esen

ce o

f stru

ctur

es o

n se

aflo

or p

oten

tially

aff

ectin

g co

mm

erci

al fi

sher

ies


7 BIOPHYSICAL AND SOCIO-ECONOMIC SETTING

7.1 Biophysical Setting

7.1.1 Marine Physical Environment

The description of the marine physical environment presented in the approved 2002 CSR remains valid for the purposes of this assessment (refer to Section 6.1.1 of the approved 2002 CSR). In particular, descriptions of climatology, air quality, physical oceanography, water quality, sediment quality and marine geology and geomorphology remain generally applicable and do not require updates, considering the change in field centre location and proposed pipeline associated with the SOEP Subsea Option.

However, new information has become available with respect to nearshore sediment contamination in Isaacs Harbour. In May and August 2004, Natural Resources Canada (NRCan) and DFO carried out a collaborative field program to determine impacts of historical mine tailings disposal on marine sediments and water in the Isaacs and Seal Harbour areas. Although these findings have yet to be published, consultation with NRCan has revealed some sampling sites in Isaacs Harbour show sediments containing elevated levels of arsenic and mercury up to 60 ppm and 470 ppb, respectively (C. Lockett, NRCan, pers. comm. 2006). These reported levels are in excess of the CCME Interim Marine Sediment Quality Guidelines, which stipulate that concentrations of arsenic and mercury in sediments should not exceed 7.24 ppm and 130 ppb, respectively (CCME 2005).

Arsenic and mercury concentrations in surface sediments at the sampling point nearest EnCana’s proposed nearshore pipeline corridor indicated arsenic levels between 4-10 ppm and mercury concentrations between 5-43 ppb (C. Lockett, NRCan, pers. comm. 2006). Furthermore, sampling during the Deep Panuke 2001 nearshore pipeline route survey found no evidence of sediments contaminated from old mine tailings (refer to Section 6.3.9.3 of the approved 2002 CSR). Therefore, it is not expected that sediments contaminated by old mine tailings will be encountered during construction of the M&NP Option pipeline.


7.1.2 Marine Biological Environment

7.1.2.1 Marine Benthos

Benthic Habitat and Communities in the Offshore Environment

The evaluation of benthic communities and habitat in the offshore Project area in the approved 2002 CSR (Section 6.1.2.1) was derived from information presented in the SOEP EIS (SOEP 1996a, 1996b), data collected for the Cohasset Project (John Parsons & Associates 1994), and site specific benthic habitat surveys (JWEL 2000a, 2000b; JWEL 2003). These data remain valid for the description of benthic habitat and communities for the new proposed Project Options. In addition, the Study Team reviewed wellsite surveys conducted by EnCana on Sable Island Bank. These wellsite surveys (refer to Figure 7.1 for coverage) are of high relevance in terms of facilitating the assessment of benthic communities and habitats in the new proposed Project footprint. A more detailed description of benthic habitat is provided in the updated Baseline Benthic Report (JW 2006).

The relocation of the field centre by approximately 3.6 km to the northeast of the original production platform location as per the approved 2002 CSR Project basis and the new field subsea structures (subsea wells, flowlines, and umbilicals) will not require changes to the description of benthic habitat and communities. Benthic communities contained within the footprints of the MOPU and subsea equipment are expected to be similar to the habitat described in the approved 2002 CSR in the area surrounding the 2002 Project location due to the habitat homogeneity of the area, and similar depth and close spatial proximity to the previously approved Project location.

The M&NP Option consists of a dedicated pipeline from the MOPU to shore, partially paralleling the SOEP pipeline. This route is relatively unchanged from the approved 2002 CSR Project basis, with the exception of the first 37 km from the new field centre. As discussed above, a review of data collected in the general Project area suggests the description of existing conditions provided in the approved 2002 CSR (Section 6.1.2.1) for the offshore pipeline route remains valid despite the minor modification in the offshore pipeline route, primarily due to the habitat homogeneity of the Sable Bank. However, since the publication of the approved 2002 CSR, an experimental sea cucumber (Cucumaria frondosa) fishery zone has been designated in an area that will be transected by the M&NP Option export pipeline (refer to Figure 7.2). Although the approved 2002 CSR identified this species as being present in the Project area, benthic surveys and seafloor video reconnaissance in this area have not revealed the presence of sea cucumbers in large numbers. The export pipeline options are in close proximity to concentrations of ocean quahog (Arctica islandica)identified as being present in the Project area in the approved 2002 CSR on Sable Island Bank. More information on sea cucumbers and quahogs commercial fishing activities is provided in Section 7.3.

6740

00

6740

00

6840

00

6840

00

6940

00

6940

00

7040

00

7040

00

4849000

4849000

4859000

4859000

4869000

4869000

ExistingData

Sourcesfor

Characterization

ofMarineBenthos

02.

55

1.25

Kilo

met

ers

Map

Para

met

ers

Proj

ectio

n:U

TM-N

AD

83-Z

20Sc

ale

1:10

0,00

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ate:

Oct

ober

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006

Proj

ectN

o.:1

0151

58

MapFeatures

Dee

pPa

nuke

Subs

eaW

ells

Star

t-up

Flow

lines

EnC

ana

22"E

xpor

tPip

elin

e(M

&NP

Opt

ion)

EnC

ana

20"E

xpor

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OEP

Subs

eaO

ptio

n)

SOEP

Expo

rtPi

pelin

ePreviousWellsiteSurveys

EnC

ana

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lsite

Surv

eys

(200

2)

EnC

ana

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(200

0-01

)

Form

erD

eep

Panu

kePl

atfo

rmC

entre

Surv

ey(2

002)

Prev

ious

Dee

pPa

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Pipe

line

Rou

teSu

rvey

s

EL2357

GRANDPRE

PL2901

COHASSET

EL2387

MARGAREE

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PANUKE

MAR

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LOWER

MUSQUODOBOIT

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P26

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PEL

INE

TOSO

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AS

PLA

NT

22"

EN

CA

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PIPE

LIN

EM

&N

PO

PTIO

N

20"

EN

CA

NA

PIPE

LIN

ESO

EP

SUB

SEA

OPT

ION

Figure7.1

(FugroJacquesGeoSurveysInc.)

Panu

keH

-08

(FJG

,200

0)

Que

ensl

and

M-8

8(F

JG,2

000)

Panu

keM

-79

(FJG

,200

0)

Coha

sset

(FJG

,200

2)

EnC

ana

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Mas

terS

ampl

ing

Grid

s(J

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2003

)

TOSO

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ATFO

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S

Form

erD

eep

Pan

uke

Expo

rtPi

pelin

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M79

and

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Surv

ey(2

001)

PREVIOUSDEEPPANUKEPIPELINE

ROUTE

SURVEY

PREVIOUSDEEPPANUKEPIPELINE

ROUTE

SURVEY

MiddleBank

SableIslandBank

6440

00

6440

00

7440

00

7440

00

4849000

4849000

2003DFO

OceanQuahog

Distribution&

SeaCucumber

Experim

ental

FisheryZone1

010

205 K

ilom

eter

s

Map

Par

amet

ers

Proj

ectio

n:U

TM-N

AD

83-Z

20Sc

ale

1:60

0,00

0D

ate:

Oct

ober

25,2

006

Proj

ectN

o.:1

0151

57D

ata

Sou

rce:

DFO

2003DFO

SurveyResearch

OceanQuahogDensities

Kg/1000m²

<1 1 250

750

1500

2500Figure7.2

SableIsland

ProjectComponents

Dee

pP

anuk

eM

OPU

Dee

pP

anuk

eSu

bsea

Wel

ls

SOEP

Pla

tform

s

EnC

ana

22"E

xpor

tPip

elin

e(M

&NP

Opt

ion)

EnC

ana

20"E

xpor

tPip

elin

e(S

OEP

Sub

sea

Opt

ion)

SOEP

Exp

ortP

ipel

ine

Star

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Flow

lines

Gul

lyM

PA

DeepPanuke

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Cuc

umbe

rExp

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ne1


The SOEP Subsea Option consists of subsea tie-in to the existing SOEP 660 mm [26 inch] pipeline downstream of the Thebaud complex. This pipeline would cross a 15 km area of Sable Island Bank that was not sampled during previous benthic surveys conducted in support of the approved 2002 CSR. Sable Island Bank is known to be an area of relatively homogeneous, sandy benthic habitat (Amos and Nadeau 1988; Breeze et al. 2002; Carter et al. 1985; JWEL 2000a, 2000b; JWEL 2003; John Parsons & Associates Biological Consultants 1994). As a result of the regional homogeneity of surficial sediment characteristics coupled with similar physical, chemical and biological conditions, the benthic communities in the area of the SOEP Subsea Option export pipeline are expected to be similar as those described in the approved 2002 CSR for the offshore (Sable Island Bank) environment. As such, the description of existing conditions for marine benthos provided in the approved 2002 CSR remains valid. However, similar to the M&NP Option, this export pipeline option is known to be in close proximity to concentrations of ocean quahog.

Benthic Habitat and Communities in the Nearshore Environment

Benthic sampling was conducted in 2002 to characterize the benthic habitat along the nearshore sections of the pipeline route to shore. The current proposed pipeline route to shore (M&NP Option) follows the same general route as the 2002 Base Case pipeline. As such, the description of existing conditions for the 2002 Project basis remains valid. Please refer to Section 6.1.2.1 of the approved 2002 CSR for a description of marine benthos in the nearshore environment. Refer also to updated information on potential sediment contamination in the vicinity of the nearshore pipeline route.

7.1.2.2 Marine Fish

The description of marine fish contained in the approved 2002 CSR (Section 6.1.2.2) remains valid for this EA Report with the exception of the designation of some fish species at risk. Since the publication of the approved 2002 CSR, there have been updates to the list of fish species at risk. Table 7.1 lists the fish species at risk and their current designation. None of these species are common to the Project area, nor is there any appreciable evidence of spawning activity by any of these species within the immediate Project area (COSEWIC 2003a, b, 2004, 2005, 2006a, b; Campana et al. 2005; Kulka and Simpson 2004; Simon et al. 2003).

Dee

p Pa

nuke

Vol

ume

4 (E

nvir

onm

enta

l Ass

essm

ent R

epor

t) N

ovem

ber 2

006

7-6

Tab

le 7

.1

Mar

ine

Fish

Spe

cies

at R

isk

Off

shor

e N

ova

Scot

ia

Mar

ine

Fish

Sp

ecie

sC

OSE

WIC

/ SAR

ASt

atus

Dis

trib

utio

n H

abita

t Sp

awni

ng

Atla

ntic

Cod

(G

adus

mor

hua)

(Mar

itim

e Po

pula

tion)

CO

SEW

IC

Spec

ies o

f Spe

cial

C

once

rn (2

003)

SARA

Rec

omm

ende

d to

not

be

liste

d un

der S

ARA

(200

5)

Inha

bit a

ll w

ater

s ove

r the

co

ntin

enta

l she

lves

of t

he

Nor

thw

est a

nd N

orth

east

Atla

ntic

O

cean

(CO

SEW

IC 2

003a

)

Adu

lts fo

und

in d

iver

se h

abita

ts

incl

udin

g co

asta

l wat

ers a

nd

offs

hore

ban

ks (C

OSE

WIC

20

03a)

It is

not

kno

wn

if co

d ha

ve

spec

ific

spaw

ning

hab

itats

and

is

hig

hly

unlik

ely

that

sp

awni

ng h

abita

t is l

imiti

ng

(CO

SEW

IC 2

003a

) Eg

gs a

re b

uoya

nt

Spaw

ning

occ

urs o

n Sa

ble

Isla

nd B

ank

from

Sep

tem

ber t

o M

ay w

ith a

pea

k in

Nov

embe

r, an

d th

roug

h w

inte

r, ad

ditio

nal

peak

in M

ay/J

une

Atla

ntic

Wol

ffis

h (A

narh

icha

s lu

pus)

(Atla

ntic

Po

pula

tion)

CO

SEW

IC

Spec

ies o

f Spe

cial

C

once

rn (2

000)

SARA

Sp

ecia

l Con

cern

, Sc

hedu

le 1

(200

2)

Wid

ely

dist

ribut

ed a

cros

s the

N

orth

Atla

ntic

and

eas

t coa

st o

f N

orth

Am

eric

a (E

nviro

nmen

t C

anad

a 20

06c)

Prim

ary

habi

tat i

nclu

des c

old

deep

wat

er o

f the

con

tinen

tal

shel

f with

rock

y or

har

d cl

ay

botto

ms

Rar

ely

uses

are

as w

ith sa

ndy

or

mud

dy b

otto

ms (

Envi

ronm

ent

Can

ada

2006

b)

Spaw

n in

shal

low

insh

ore

wat

ers i

n sp

ring

and

Sept

embe

r (E

nviro

nmen

t Can

ada

2006

c)

No

evid

ence

of s

paw

ning

has

be

en re

porte

d in

the

Proj

ect a

rea

Spot

ted

Wol

ffis

h (A

narh

icha

s m

inor

)

(Atla

ntic

Po

pula

tion)

CO

SEW

IC

Thre

aten

ed (2

001)

SARA

Thre

aten

ed, S

ched

ule

1 (2

002)

Nor

th A

tlant

ic fr

om S

cotla

nd to

C

ape

Bre

ton

and

in th

e A

rctic

O

cean

In W

este

rn N

orth

Atla

ntic

it

prim

arily

occ

urs o

ff n

orth

east

N

ewfo

undl

and

(Env

ironm

ent

Can

ada

2006

c)

Dem

ersa

l; in

col

d co

ntin

enta

l sh

elf a

nd sl

ope

wat

ers r

angi

ng

in d

epth

from

20

to 6

00 m

on

sand

subs

trate

s with

larg

e bo

ulde

rs (E

nviro

nmen

t Can

ada

2006

c)

Spaw

ns in

sum

mer

, lar

ge e

ggs

depo

site

d en

mas

s on

sand

y bo

ttom

. You

ng re

mai

n ne

ar

botto

m (E

nviro

nmen

t Can

ada

2006

a)

No

evid

ence

of s

paw

ning

has

be

en re

porte

d in

the

Proj

ect a

rea

Nor

ther

n W

olff

ish

(Ana

rhic

has

dent

icul

atus

)

(Atla

ntic

Po

pula

tion)

CO

SEW

IC

Thre

aten

ed (2

001)

SARA

Thre

aten

ed, S

ched

ule

1 (2

002)

Nor

way

to S

outh

ern

New

foun

dlan

d (E

nviro

nmen

t C

anad

a 20

06d)

In o

ffsh

ore

cold

wat

ers <

5o C

Dep

ths o

f sur

face

to 9

00 m

pr

imar

ily >

100

m

(Env

ironm

ent C

anad

a 20

06d)

Spaw

ning

occ

urs l

ate

in th

e ye

ar

with

larg

e eg

gs la

id in

nes

ts a

nd

guar

ded

No

evid

ence

of s

paw

ning

has

be

en re

porte

d in

the

Proj

ect a

rea

Dee

p Pa

nuke

Vol

ume

4 (E

nvir

onm

enta

l Ass

essm

ent R

epor

t) N

ovem

ber 2

006

7-7

Tab

le 7

.1

Mar

ine

Fish

Spe

cies

at R

isk

Off

shor

e N

ova

Scot

ia

Mar

ine

Fish

Sp

ecie

sC

OSE

WIC

/ SAR

ASt

atus

Dis

trib

utio

n H

abita

t Sp

awni

ng

Cus

k (B

rosm

e br

osm

e)

(Atla

ntic

Po

pula

tion)

CO

SEW

IC

Thre

aten

ed (2

003)

SARA

Ref

erre

d ba

ck to

C

OSE

WIC

for f

urth

er

cons

ider

atio

n (2

005)

Inha

bits

suba

rctic

and

bor

eal

wat

ers

Cen

tre o

f abu

ndan

ce in

the

wes

tern

Atla

ntic

bet

wee

n 41

and

44

o N (C

OSE

WIC

200

3b)

Occ

urs o

n ha

rd, r

ough

, and

ro

cky

subs

trate

s sel

dom

on

smoo

th sa

ndy

botto

ms

(CO

SEW

IC 2

003b

)

Spaw

ning

from

Apr

il to

July

w

ith p

eak

in la

ter J

une

on th

e Sc

otia

n Sh

elf

Buo

yant

egg

s La

rvae

in u

pper

wat

er c

olum

n (C

OSE

WIC

200

3b)

No

evid

ence

of s

paw

ning

has

be

en re

porte

d in

the

Proj

ect a

rea

Porb

eagl

e Sh

ark

(Lam

na n

asus

)

(Atla

ntic

Po

pula

tion)

CO

SEW

IC

Enda

nger

ed (2

004)

SARA

Pend

ing

publ

ic

cons

ulta

tion

for

addi

tion

to S

ched

ule

1 lis

ting

date

Mar

ch 2

006

Dis

tribu

ted

acro

ss th

e N

orth

A

tlant

ic a

nd in

a c

ircum

glob

al

band

in th

e so

uthe

rn A

tlant

ic,

sout

hern

Indi

an, s

outh

ern

Paci

fic

and

Ant

arct

ic O

cean

s

(C

OSE

WIC

200

4a)

Spec

ies i

s a p

elag

ic, e

pipe

lagi

c or

litto

ral s

hark

mos

t com

mon

on

con

tinen

tal s

helv

es

In C

anad

ian

wat

ers t

hey

occu

r in

wat

ers

betw

een

5-10

o C(C

OSE

WIC

200

4a)

Gra

vid

fem

ales

are

pre

sent

from

la

te S

epte

mbe

r to

Dec

embe

r on

the

Scot

ian

Shel

f and

Gra

nd

Ban

ks

Mat

ing

in th

e N

orth

wes

t A

tlant

ic o

ccur

s fro

m la

te

Sept

embe

r to

Nov

embe

r with

pa

rturit

ion

eigh

t to

nine

mon

ths

late

r

(C

OSE

WIC

200

4a)

No

evid

ence

of b

reed

ing

has

been

repo

rted

in th

e Pr

ojec

t are

a Sh

ort-f

in M

ako

(I

suru

s ox

yrub

chus

)

(Atla

ntic

Po

pula

tion)

CO

SEW

IC

Thre

aten

ed (2

006)

SARA

Not

list

ed

Circ

umgl

obal

ly in

all

tropi

cal a

nd

tem

pera

te o

cean

s (D

. Mill

ar,

DFO

, per

s. co

mm

. 200

6)

Pref

er te

mpe

rate

to tr

opic

al,

litto

ral t

o ep

ipel

agic

wat

ers a

nd

are

rare

ly fo

und

in w

ater

s of l

ess

than

16o C

(D

. Mill

ar, D

FO,

pers

. com

m. 2

006)

Birt

h la

ter w

inte

r to

mid

-su

mm

er a

fter a

15

to 1

8 m

onth

ge

stat

ion

perio

d (D

. Mill

ar,

DFO

, per

s. co

mm

. 200

6)

No

evid

ence

of b

reed

ing

has

been

repo

rted

in th

e Pr

ojec

t are

a B

lue

Shar

k (P

rion

ace

glau

ca)

(Atla

ntic

Po

pula

tion)

CO

SEW

IC

Spec

ial C

once

rn (2

006)

SARA

Not

list

ed

Wor

ldw

ide

dist

ribut

ion

Abu

ndan

ce p

eaks

in w

este

rn

Can

adia

n w

ater

s in

late

sum

mer

an

d fa

ll (D

. Mill

ar, D

FO,p

ers.

com

m. 2

006)

Off

shor

e be

twee

n su

rfac

e an

d 35

0 m

(D. M

illar

, DFO

, per

s. co

mm

. 200

6)

Mat

ing

sprin

g to

ear

ly su

mm

er.

Ges

tatio

n 9

-12

mon

ths (

D.

Mill

ar, D

FO, p

ers.

com

m. 2

006)

N

o ev

iden

ce o

f spa

wni

ng h

as

been

repo

rted

in th

e Pr

ojec

t are

a

Dee

p Pa

nuke

Vol

ume

4 (E

nvir

onm

enta

l Ass

essm

ent R

epor

t) N

ovem

ber 2

006

7-8

Tab

le 7

.1

Mar

ine

Fish

Spe

cies

at R

isk

Off

shor

e N

ova

Scot

ia

Mar

ine

Fish

Sp

ecie

sC

OSE

WIC

/ SAR

ASt

atus

Dis

trib

utio

n H

abita

t Sp

awni

ng

Whi

te S

hark

(C

arch

arod

on

carc

haria

s)

(Atla

ntic

Po

pula

tion)

CO

SEW

IC

Enda

nger

ed (2

006)

SARA

Not

list

ed

Glo

bally

sub-

pola

r to

tropi

cal s

eas

(D. M

illar

, DFO

,per

s. co

mm

. 20

06)

Pela

gic;

insh

ore

to o

ffsh

ore

wat

ers;

surf

ace

to 1

280

m (D

. M

illar

, DFO

, per

s. co

mm

. 20

06)

Littl

e kn

own

of sp

awni

ng a

nd

poss

ible

pup

ping

gro

unds

off

th

e ea

st c

oast

of N

orth

Am

eric

a in

clud

es th

e M

id-A

tlant

ic B

ight

(D

. Mill

ar, D

FO, p

ers.

com

m.

2006

) N

o ev

iden

ce o

f bre

edin

g ha

s be

en re

porte

d in

the

Proj

ect a

rea

Win

ter S

kate

(L

euco

raja

oc

elat

ta)

(Eas

tern

Sco

tian

Shel

f Pop

ulat

ion)

CO

SEW

IC

Thre

aten

ed (2

005)

SARA

Pend

ing

publ

ic

cons

ulta

tion

for

addi

tion

to S

ched

ule

1

Gul

f of S

t. La

wre

nce

and

sout

hern

N

ewfo

undl

and

to C

ape

Hat

tera

s in

dept

hs o

f 1 to

371

m (S

imon

et a

l.20

03)

Ben

thic

feed

ers,

usua

lly fo

und

on sa

nd a

nd g

rave

l in

dept

hs o

f 1

to 3

71 m

(CO

SEW

IC 2

005a

)

Egg

rele

ase

late

sum

mer

and

ea

rly fa

ll w

est o

f Sab

le Is

land

(S

imon

et a

l. 20

03)

No

evid

ence

of s

paw

ning

has

be

en re

porte

d in

the

imm

edia

te

Proj

ect a

rea

Skat

e eg

g pu

rses

hav

e be

en

iden

tifie

d in

the

sea

cucu

mbe

r ex

perim

enta

l fis

hery

zon

e 1


7.1.2.3 Sea Turtles

The description of existing conditions for sea turtles in the approved 2002 CSR (Section 6.1.2.3) remains valid with the exception of recognizing the listing of leatherback sea turtle as endangered by SARA (refer to Section 7.1.4 for more information on SARA and requirements for listed species). As a result of this SARA listing additional information on this species has become available for reference.

In 2006, a proposed recovery strategy for leatherback sea turtle was proposed (Atlantic Leatherback Turtle Recovery Team 2006). The strategy outlines basic biology, recovery goals, objectives and performance indicators, identifies knowledge gaps, discusses permitted activities, and anticipated challenges for recovery. The recovery strategy acknowledges that the population likely exceeds several hundred thousand individuals and model results suggest that the population can sustain human induced mortality up to about 1%. A review by DFO concluded that there was scope for human-induced mortality without jeopardizing survival or recovery of the species (Atlantic Leatherback Turtle Recovery Team 2006). The primary threat to leatherback turtles in Canadian waters is entanglement in fishing gear. There is little risk for entanglement in Project subsurface infrastructure as the structures are placed far enough apart such that there are few, if any spaces for head or flipper entanglement.

Peak leatherback occurrences in Canadian waters are during August-September but there are records for leatherbacks in Canadian waters for most months of the year (McAlpine et al. 2004, cited in Atlantic Leatherback Turtle Recovery Team 2006). Adult leatherbacks enter Canadian waters to feed on their preferred prey of jellyfish and other pelagic, soft-bodied invertebrates such as salps (family Salpidae). James et al. (2006) reveals a broad distribution of leatherbacks on the Scotian Shelf throughout the foraging seasons with most reported sightings occuring inshore from the continental shelf break. This recent study suggests that coastal and slope waters of the western Atlantic should be considered critical foraging habitat for the species. It is unlikely that juveniles venture into Atlantic Canadian waters, preferring to remain in waters warmer than 26 C until they exceed 100 cm (Atlantic Leatherback Turtle Recovery Team 2006).

7.1.2.4 Marine Mammals

The description of existing conditions for marine mammals presented in the approved 2002 CSR (Section 6.1.2.4) remains valid with the exception of the updated SARA and COSEWIC status for the species discussed in Section 7.1.4. Specific changes since the approved 2002 CSR include a status downgrade of the harbour porpoise and an elevated ranking status for the northern bottlenose whale.

There are three endangered marine mammal species that could potentially be present in the study area: blue whale, North Atlantic right whale, and northern bottlenose whale.


There is no reliable population estimate for the blue whale population in the western North Atlantic, however, it is thought to be in the low hundreds. The biggest factor responsible for low numbers of blue whales is the historical take in commercial whaling. Threats since the end of commercial whaling include ship strikes, disturbance from increasing whale watch activity, entanglement in fishing gear, and pollution. They may also be vulnerable to long-term changes in climate change as a result of change in abundance of prey (e.g., zooplankton) (Sears and Calambokidis 2002).

The North Atlantic right whale also suffered high mortality due to whaling. The total population is currently estimated to be about 322 individuals and continues to experience high mortality from ship strikes and entanglement in fishing gear. It has been estimated that the population could become extinct in about 200 years (COSEWIC 2003c).

The COSEWIC Assessment Summary for Northern Bottlenose Whale (Scotian Shelf Population)(COSEWIC 2002) states the reason for elevating this population to endangered status is primarily due to the threat of oil and gas development in and around the prime habitat (i.e., the Gully). It does, however, acknowledge there is little information as to how this species is, or is not, affected by oil and gas development activities. The COSEWIC assessment states that noise, chemical pollution and other disturbance of oil/gas exploration and production activities might lead the whales to abandon the Gully, potentially endangering the population. The Deep Panuke Project (including new potential well locations) is more than 100 km from the Gully MPA and EnCana will abide by the Code of Practice for the Gully, thereby minimizing any interaction with this population.

7.1.2.5 Marine Related Birds

The description of existing conditions of marine related birds in the approved 2002 CSR (Section 6.1.2.5) remains valid with the exception of the updated SARA and COSEWIC status for the species discussed in Section 7.1.4.

Two bird species at risk not mentioned in the approved 2002 CSR are Barrow’s Goldeneye and Ivory Gull. Ivory Gull was, however, addressed in the Additions and Errata for the Deep Panuke Comprehensive Study Report (EnCana 2002). Based on CWS expert opinion, it was determined that the Ivory Gull could potentially occur within the area influenced by the Project. EnCana committed to consider this species for protection in environmental management plans for the Project as applicable.


The Ivory Gull breeds in high-Arctic coastal areas with permanent pack ice and open water (Environment Canada 2006e). The Ivory Gull breeds in colonies of a few to more than 150 pairs. Nesting success is determined by weather conditions, predation and human disturbances. For example, they may abandon eggs if approached by low-flying aircraft (Environment Canada 2006e). The diet of the gull consists of leftover carcasses of fish and other marine species, and of marine mammals killed by polar bears. No traditional nesting grounds have been identified in the study area and their presence in the study area is expected to be incidental as they may arrive on ice flows; therefore limited interaction with Project activities is predicted.

Barrow’s Goldeneye is a diving duck that breeds and winters in Canada, although the only confirmed breeding records are from Quebec. Small numbers of this population (about 400) winter in the Maritime Provinces and along the northern Atlantic coastline in the United States. Specific population trends are unknown, but it is believed that the eastern population has been declining since the 20th Century. Population threats include oil spills and sediment contamination of key wintering areas. Hunting and forest exploitation (e.g., loss of breeding habitat), and degradation of lakes through stocking of brook trout also serve as population threats (Environment Canada 2006f). Therefore, limited interaction with Project activities is predicted.

The remaining species listed in Table 7.5 were addressed in the approved 2002 CSR. However, with the enactment of SARA, there have been specific recovery strategies and/or management plans developed to help protect some of these species at risk. A recovery strategy is a planning document that identifies what needs to be done to arrest or reverse the decline of a species. A management plan is an action-oriented planning document that identifies conservation activities and land use measures needed to ensure, at a minimum, that a species of special concern does not become threatened or endangered (Environment Canada 2006g).

The Management Plan for the Ipswich (Savannah) Sparrow (Environment Canada 2006h) aims to maintain the current breeding population at the current level, maintain the current breeding habitat, and remove or reduce threats to Ipswich Sparrows and their breeding and wintering habitat. The Ipswich Sparrow nests almost exclusively on Sable Island and is the dominant landbird on the island. The species’ localized distribution makes it particularly vulnerable to potential threats such as chance events (e.g., harsh weather and disease during breeding season), predation, human activity, and habitat loss. Available evidence suggests that aside from chance events, none of these factors currently threatens this particular population. The Plan also indicates that to date, offshore petroleum development near Sable Island has had no known effect on the sparrow or its habitat.

A Canadian Recovery Plan for the Roseate Tern was first developed in 1993 (Locke et al. 1993). Since then, more data has become available on the biology and distribution of the species. The 2006 proposed Recovery Strategy for the Roseate Tern (Environment Canada 2006g) takes advantage of this new


information. This Recovery Strategy has been reviewed and found to present information consistent with existing conditions for the species presented in the approved 2002 CSR (Section 6.1.2.5). This includes the confirmation that activities associated with the SOEP (i.e., laying of the pipe and support flights for offshore platforms) did not disturb or cause other adverse effects to Roseate Terns

The proposed Recovery Strategy for the Roseate Tern (Environment Canada 2006g) is the first recovery strategy for a migratory bird posted on the SARA Public Registry to identify “critical habitat” as defined in the Act. The Recovery Strategy recommends that critical habitat be identified as:

1. Sites that currently support more than 15 pairs of Roseate Terns (The Brothers, NS and Country Island, NS); and

2. Tern colonies in areas that have supported small but persistent numbers of nesting Roseate Terns for over 30 years (Sable Island, Magdalen Islands, Chenal Island).

This designation includes the entire terrestrial habitat of all islands as well as aquatic habitat out 200 m seaward from the mean high tide line of each island. The exception is Sable Island, where the terrestrial habitat designation is limited to polygons encompassing entire individual nesting tern colonies on the island. The 200 m is based on recommended buffer zones around tern colonies.

Additional information on critical habitat designation is provided in Section 7.1.2.6 with respect to Sable Island and Country Island.

In addition to the Recovery Strategy, the Study Team has also reviewed a recent study on foraging habits of Roseate Terns (Rock 2005). Information contained within the document is consistent with existing conditions information presented in the approved 2002 CSR, including the recognition that shallow coastal areas are important for foraging and that an oil spill close to nesting areas during the breeding season could have serious implications. New information presented indicates that Roseate Terns use Harbour Island and Goose Island as foraging areas. No foraging areas for Roseate Tern were identified at or in close proximity to the proposed landfall area of the pipeline for the M&NP option, or the existing SOEP pipeline (Rock 2005). Figure 7.3 has been prepared based on information contained in Rock (2005) and the proposed Recovery Strategy for the Roseate Tern (Environment Canada 2006g).

5990

00

5990

00

6040

00

6040

00

6090

00

6090

00

6140

00

6140

00

4994000

4994000

4999000

4999000

5004000

5004000

ForagingLocations

&CriticalHabitatfor

theRoseateTern

01,

500

3,00

075

0

Met

ers

Map

Para

met

ers

Proj

ectio

n:U

TM-N

AD

83-Z

20Sc

ale

1:65

,000

Dat

e:O

ctob

er05

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6Pr

ojec

tNo.

:101

0515

7

Topography

Brid

gePa

ved

Roa

dU

npav

edR

oad

Wat

erco

urse

Con

tour

(5m

)W

ater

bodyFigure7.3

ProjectCom

ponents

EnC

ana

Ons

hore

Pipe

line

Cor

ridor

EnC

ana

22"E

xpor

tPip

elin

e(M

&NP

Opt

ion)

SOEP

Expo

rtPi

pelin

e

M&N

PM

ainl

ine

SOEP

NG

LLi

nean

dM

&NP

Poin

tTup

perL

ater

al

Isaacs

Harbour

CountryHarbour

FishermansHarbour

SealHarbour

CoddlesHarbour

SealHarbour

Lake

GooseIsland

Harbour

Island

Country

Island

IsaacsHarbour

Goldboro

CoddlesHarbour

FishermansHarbour

316

DrumHead

SOEP Gas Pl

ant

ToAntigonish

SableIsland

RoseateTernCriticalHabitatonSableIsland

Des

igna

ted

Crit

ical

Hab

itat(

unde

rSAR

A)

Ros

eate

Tern

Nes

ting

Hab

itat

200m

Aqua

ticBu

fferZ

one

Foraging

Locations

(AdaptedFrom

Rock2005)

Ros

eate

Tern

Arct

icTe

rn

Com

mon

Tern

ToSableIsland

Des

igna

ted

Crit

ical

Hab

itat(

unde

rSAR

A)

Ros

eate

Tern

Nes

ting

Hab

itat

200m

Aqua

ticBu

fferZ

one

DesignatedCriticalHabitatFortheRoseateTern

(Env

ironm

entC

anad

a20

06)

Not

e:D

esig

natio

nof

Crit

ical

Hab

itat

for

the

Ros

eate

Tern

onSa

ble

Isla

ndis

defin

edas

poly

gons

enco

mpa

ssin

gen

tire

indi

vidu

alne

stin

gte

rnco

loni

eson

the

isla

ndan

da

200m

buffe

rar

ound

each

poly

gon.

For

the

purp

ose

ofen

viro

nmen

tal

asse

ssm

ent,

this

defin

ition

has

been

inte

rpre

ted

toin

clud

eth

een

tire

isla

ndw

itha

200m

buffe

rto

incl

ude

aqua

ticha

bita

t.

010

205

Kilo

met

ers

1:500,000


Environment Canada has recently undertaken a review of the Migratory Birds Convention Act which has resulted in some updates. The most relevant updates are a strengthening of Environment Canada’s authority to prosecute violations of the Act and formalization of the application of the Act over the offshore area.

7.1.2.6 Special Places

Sable Island

The physical and biological description of Sable Island provided in the approved 2002 CSR (Section 6.1.2.6) remains valid. There have been updates, however, in terms of the administration and designation of the Island.

On April 1, 2005, DFO and Environment Canada resumed management of Sable Island from the Sable Island Preservation Trust (SIPT) (created in 1998). The federal government committed to maintaining a protective human presence on the island and will assume responsibility for staffing and operating the station (see Table 6.2). Another administrative update is the designation of Sable Island as “critical habitat” for the Roseate Tern.

The proposed Recovery Strategy for the Roseate Tern (Environment Canada 2006g) recognizes that Sable Island has supported small but persistent numbers of nesting Roseate Terns for over 30 years and identifies a 200 m buffer encompassing nesting tern colonies on the Island as “critical habitat” for the species. SARA defines critical habitat as: “…the habitat that is necessary for the survival or recovery of a listed wildlife species and that is identified as the species’ critical habitat in the recovery strategy or in an action plan for the species”.

As per section 58(2) of SARA, within 90 days after posting the final version of this proposed recovery strategy, the Minister of Environment will publish in the Canada Gazette a description of the critical habitat that is on Sable Island. Ninety days after that description is published, prohibitions on critical habitat destruction will apply to that critical habitat (Environment Canada 2006g). Based on the recommended definition of critical habitat, section 58(1) prohibitions would immediately be enacted on Sable Island (and Country Island, see below) and in aquatic habitat identified around specific sites. Regulations may be enacted to legislate what can and cannot be done on critical habitat, including when and how activities must be conducted (Environment Canada 2006g).

Sable Island is located approximately 48 km from the revised field centre. There is no predicted interaction with Sable Island during routine Project operations. In the unlikely event that landing of vessels or aircraft or other activity is required near the Island, EnCana’s Code of Practice and the existing Sable Island Emergency Contingency Plan (Canadian Coast Guard 1994) will be adhered to for Sable Island.


Gully MPA

The description of the Gully provided in the approved 2002 CSR remains valid, but there are updates with respect to conservation status (see Table 6.2). DFO designated the Gully as a Marine Protected Area (MPA) in May 2004, in part to reduce ship collisions and noise disturbance to the whales. GullyMarine Protected Area Regulations (Oceans Act) were published in the Canada Gazette in December 2003. The purpose of the MPA designation for the Gully serves to conserve and protect the natural biological diversity within the protected area and to ensure its long-term health. The 2,364 square kilometres that define the Gully include three management zones, each with varying levels of protection based on the conservation objectives and ecological vulnerability.

Zone 1 consists of the deepest sections of the canyon and is preserved in a near-natural state with full ecosystem protection. This zone is highly restricted with few activities permitted. Zone 2 provides strict protection for the canyon sides and outer area of the Gully. Some fisheries are allowed in this region. Zone 3 includes the shallow water and sandy banks that are prone to regular natural disturbance. Some compatible uses are allowed subject to stringent review.

Fishing for halibut, tuna, shark and swordfish have been allowed in Zones 2 and 3 provided the activities are conducted under a federal fishing license and approved management plan. Scientific research and monitoring may be approved in all three zones provided a plan is submitted and the research meets all regulatory requirements. Other activities may be permitted in Zone 3 provided they do not cause disturbance beyond the natural variability of the ecosystem and are subject to plan submission and Ministerial approval.

Given the location of the Gully relative to Deep Panuke (approximately 113 km from MOPU site and more than 100 km from the northeast extreme location for future wells) and EnCana’s Code of Practice for the Gully MPA and commitment to avoid the Gully, there are not likely to be any Project interactions with the Gully.

Country Island

The description of Country Island and EnCana’s Code of Practice for Country Island presented in the approved 2002 CSR, remain valid. Country Island has not yet been designated a Migratory Bird Sanctuary under the Migratory Birds Convention Act. However, it has been identified as “critical habitat” for the Roseate Tern in a proposed Recovery Strategy for the Roseate Tern (Environment Canada 2006g). This designation includes the entire terrestrial habitat of the island as well as aquatic habitat out 200 m seaward from the mean high tide line. Refer to Section 7.1.2.5 for specific update


about the Roseate Tern, and to the above section on Sable Island for more discussion on the implications of defining critical habitat for a species at risk.

7.1.3 Onshore Environment

The proposed onshore pipeline corridor will likely change from that originally presented in the approved 2002 CSR due to future proposed land uses in the study area that have occurred since 2002. EnCana is currently in discussions with landowners to finalize the routing of the onshore pipeline and location of onshore facilities. A proposed corridor is presented in Figure 2.6. This revised corridor is located within the study area previously surveyed during field studies completed for the approved 2002 CSR (Figure 2.6).

7.1.3.1 Landform and Topography

The description of landform and topography provided in the approved 2002 CSR (Section 6.1.3.1) remains valid.

7.1.3.2 Geology and Soils

Despite the modification to the proposed onshore corridor, the description of geology and soils presented in the approved 2002 CSR (Section 6.1.3.2) remains valid. Since the approved 2002 CSR, however, there is new data available on the contamination of soil from past mining activities. Between 2003 and 2005, the Geological Survey of Canada (GSC) has been leading multidisciplinary research activities near abandoned gold mines throughout Nova Scotia. These studies focus mainly on the environmental implications of historical gold mining and milling practices. Some of the data collected in past-producing gold districts in the Goldboro area may be relevant to the onshore component of the Deep Panuke Project. In particular, the GSC has identified areas within the Goldboro Industrial Park that contain mine waste from past gold-mining activities. Much of this waste contains high concentrations of arsenic and mercury. The draft environmental assessment for the Keltic/Maple Project (AMEC 2006) indicates the presence of three mine tailings disposal sites on the proposed Keltic/Maple site. One of these sites is likely within the proposed corridor for the Deep Panuke Project.

Detailed maps showing the spatial distribution of metals in the Goldboro area is expected to be published by GSC in the near future. GSC further indicates that bedrock and surficial materials in the Goldboro area contain naturally elevated levels of arsenic associated with the abundant arsenopyrite in the mineralized rocks throughout the Goldboro gold district. Bedrock and surficial materials exposed during blasting and excavation may therefore contain high levels of reactive, arsenopyrite-bearing rock and must be disposed of in a manner that does not lead to accelerated leaching and release of arsenic.


Sediment samples were collected at five sites along Betty’s Cove Brook on September 7, 2006 and analyzed for total metals. Of particular interest are arsenic and mercury as these elements may be present at elevated levels in the study area due to past gold mining activities. Levels of arsenic and mercury in sediments were compared to CCME Interim Freshwater Sediment Quality Guidelines for the protection of aquatic life. The CCME limit for arsenic is 5.9 mg/kg. This level was exceeded in two of the five samples (7.6 and 21.0 mg/kg); however, these exceedances are relatively minor and considerably less than levels of arsenic reported in marine sediments sampled from Isaacs Harbour (i.e., 60 mg/kg). Levels of mercury were at or below the CCME limit (0.17 mg/kg) for each of the five samples. These levels of arsenic and mercury do not indicate contamination from past gold mining activities. Levels reported were expected given the surficial geology and water quality of the area. For example, the proximity of bedrock to the surface and the low pH of surface water in the study area (e.g., pH of 5.77 in Betty’s Cove Brook (AMEC 2006)) would aid in the liberation of metals from the surficial geology.

A geotechnical testing program will be conducted by EnCana during detailed pipeline design and routing including analysis of soil chemistry, to identify potential areas of contamination and/or acidic drainage. The EPP will include management practices to remove or contain any impacted soils or other excavated material. The EPP will also include mitigation similar to that included in M&NP’s Acid Drainage Construction Response Plan.

7.1.3.3 Vegetation

The description of vegetation in the study area obtained through field surveys conducted in 2001 and presented in the approved 2002 CSR (Section 6.1.3.3) remains valid in that it characterizes the general study area. This field survey identified a provincially rare (Pronych and Wilson 1993) plant species (northern commandra (Geocaulon lividum)) present in the study area. No new field surveys were conducted in 2006.

Since the approved 2002 CSR, it has been standard practice, during environmental assessment, to conduct a review of the Atlantic Canada Data Conservation Centre (ACCDC) database to obtain a list of provincially rare or sensitive wildlife species found within a 100 km radius of the Project area. ACCDC provides information on onshore species and ecological communities that require consideration for their conservation. The ACCDC listing and ranking system is useful since it provides a georeferenced outlook on rare or sensitive species and habitats. The ACCDC list, however, is generated on a radius that is considered to be in excess of the onshore ecological footprint of the Project. A model was therefore employed by the Study Team to determine the likelihood of the presence of the ACCDC ranked species within the onshore study area. Likelihood of presence was determined by cross-checking the habitat requirements of the ACCDC listed species with the habitat description within the onshore study area for the Project.


This rare plant modelling exercise gives direction for vegetation surveys in terms of habitat types and timing of surveys to identify rare plants. A detailed habitat survey will be conducted along the onshore pipeline route when the final routing has been determined. The results of the habitat modelling presented in Table 7.2 will be used to direct vegetation surveys at this time.

During surveys conducted in 2001, in support of the approved 2002 CSR, only one rare plant species was recorded: the northern commandra (Geocaulon lividum). The northern commandra is considered rare in Nova Scotia (Pronych and Wilson 1993), but is not considered to be nationally rare (COSEWIC 2006c; Argus and Pryer 1990).

A total of 91 Red or Yellow-listed species have been recorded within 100 km of the Project area. Based on the results of the habitat model, 27 Red or Yellow-listed species could potentially be present in the Project area. Table 7.2 lists these species along with their ACCDC and Nova Scotia Department of Natural Resources (NSDNR) rankings, and the habitats present in the study area where they could potentially be found.

Table 7.2 Rare and Sensitive Vascular Plant Species Potentially Present in the Project AreaBionomial Common Name Preferred Habitat Season for

Identification ACCDC

RankNSNDR

RankVaccinium boreale Northern Blueberry Exposed headlands

and barrens; has been found by JW team in drier open bog near Moose River Gold Mines

Not given for NS; likely identifiable in early summer on to October

S2 Red

Utricularia resupinata Northeastern Bladderwort Pond, lake and river shores

Flowers July to September, likely little noticeable or identifiable out of flower

S1 Red

Carex alopecoidea Foxtail Sedge Moist, overgrown clear-cut woods near the coast

Not given for NS; likely identifiable in early summer to October

S1 Red

Carex tenuiflora Sparse-Flowered Sedge Wet woods and bogs Not given for NS; most members of Heleonastesgroup flower June to August

S1 Red

Iris prismatica Slender Blue Flag Wet ground near the coast

Mid-July S1 Red

Listera australis Southern Twayblade Among the shaded sphagnum moss of bogs or damp woods

June; quickly senesces after flowering

S1 Red


Table 7.2 Rare and Sensitive Vascular Plant Species Potentially Present in the Project AreaBionomial Common Name Preferred Habitat Season for

Identification ACCDC

RankNSNDR

RankMalaxis brachypoda White Adder's-Mouth Moss cushions and

wet, mossy cliff-edges, where there is little competition from other plant species

Late May and June S1 Red

Selaginella selaginoides Low Spike-Moss Moist areas borderingbog tussocks, peat bogs, and stream margins

Produces spores in July and August; likely identifiable when not snow covered but very easily overlooked

S2 Red

Bidens connata Purple-Stem Swamp Beggar-Ticks

Boggy swales, and the borders of ponds, thickets and in ditches behind brackish shores

August and September; can be identified when not in flower

S3? Yellow

Megalodonta beckii Beck Water-Marigold Shallow, quiet waters, slow-moving streams, and ponds

August and September

S3 Yellow

Proserpinaca pectinata Comb-Leaved Mermaid-Weed

Wet savannas, sphagnous swales, and the sandy, gravelly, or muddy borders of lakes or ponds

June to October; can be identified when not in flower

S3 Yellow

Teucrium canadense American Germander Gravelly seashores, generally at crest of beach, above direct tidal influence

Flowers July to September when easiest to identify but identifiable from June to October

S2S3 Yellow

Utricularia gibba Humped Bladderwort Shallow lake margins, small pools and small ponds in quagmires or peaty situations

Late June to September; can be identified without flowers, but is very cryptic

S2 Yellow

Fraxinus nigra Black Ash Low ground, damp woods and swamps

May and June; can be identified without flowers

S3 Yellow

Epilobium coloratum Purple-Leaf Willow-Herb Low-lying ground, springy slopes and similar locations

July and October; seeds required for identification

S2? Yellow

Epilobium strictum Downy Willow-Herb Boggy areas and meadows

July to September S3 Yellow

Polygala sanguinea Field Milkwort Poor or acidic fields, damp slopes, and open woods or bush

Late June to October

S2S3 Yellow

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