DEEP PANUKE OFFSHORE GAS DEVELOPMENT

DEVELOPMENT PLAN VOLUME 2

Prepared by: PanCanadian Energy Corporation 7th Floor, Royal Centre 5161 George Street Halifax, Nova Scotia B3J 1M7

March 2002 PREFACE

This Development Plan is the second of six 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 Summary Volume 2 Development Plan Volume 3 Canada-Nova Scotia Benefits Plan Volume 4 Environmental Impact Statement Volume 5 Socio-Economic Impact Statement Volume 6 Public Consultation Report

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 geological, geophysical and petrophysical interpretation, the Reservoir Management Plan, drilling, processing, facilities, and environmental and safety management for the Project.

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

Volume 4, the Environmental Impact Statement (EIS), describes the physical and biological environment in which the Project will operate, provides an assessment of the potential environmental impacts of the Project, and identifies mitigation measures.

Volume 5, the Socio-Economic Impact Statement (SEIS), describes the socio-economic environment for the Project, in relation to the surrounding landfall and associated communities as well as the Province of Nova Scotia. It also assesses the potential impacts, discusses ways to minimize impacts and to maximize potential benefits, and estimates the economic impact of the Project.

Volume 6, the Public Consultation Report (PCR), describes the public consultation process in support of the regulatory process for the Project and identifies the issues raised during the public consultation for the Project.

Deep Panuke Volume 2 (Development Plan)· March 2002 i TABLE OF CONTENTS

Page No.

1 INTRODUCTION AND PROJECT OVERVIEW...... 1-1 1.1 Introduction...... 1-1 1.2 Purpose and Scope of the Project...... 1-2 1.3 Project Facilities ...... 1-3 1.4 Project Timing...... 1-6 1.5 Development Approach...... 1-6 1.6 Project Principles...... 1-9 1.7 Regulatory Overview...... 1-11 2 GEOLOGY, GEOPHYSICS, AND PETROPHYSICS...... 2-1 2.1 Geological Interpretation and Reservoir Description ...... 2-1 2.1.1 Regional and Reservoir Structural Setting...... 2-2 2.1.2 Regional and Reservoir Stratigraphy...... 2-3 2.1.3 Sedimentology and Diagenesis of the Abenaki Formation, Reservoir Development...... 2-7 2.1.4 Hydrocarbon Source, Generation, and Migration...... 2-9 2.1.5 Hydrogeology...... 2-9 2.1.6 Trapping Mechanisms of the Bacarro Member, Abenaki 5 cycle ...... 2-11 2.1.7 Pool History ...... 2-12 2.1.8 Pool Description...... 2-12 2.2 Geophysics...... 2-20 2.2.1 Seismic Database ...... 2-21 2.2.2 Time Interpretation...... 2-23 2.2.3 Depth Conversion...... 2-25 2.2.4 Porosity Estimation...... 2-25 2.3 Petrophysics ...... 2-26 2.3.1 Modeling Overview ...... 2-26 2.3.2 Lithology and Porosity...... 2-26 2.3.3 Permeability ...... 2-28 2.3.4 Fluid Identification and Saturation Modelling...... 2-29 2.3.5 Reservoir Parameter Summaries...... 2-31 2.3.6 Future Data Acquisition Strategy...... 2-32 3 RESERVOIR ENGINEERING ...... 3-1 3.1 Reservoir Data ...... 3-1 3.1.1 Reservoir Description ...... 3-1 3.1.2 Well Test Data...... 3-3 3.1.3 Core Analysis and Special Core Analysis...... 3-3 3.1.4 Reservoir Fluid Properties ...... 3-5

Deep Panuke Volume 2 (Development Plan) · March 2002 TOC-i 3.2 Reservoir Simulation...... 3-6 3.2.1 Integrated Surface-Subsurface Simulation...... 3-6 3.3 Project Plan Development...... 3-7 3.4 Reserves...... 3-9 3.5 Reservoir Management Philosophy ...... 3-10 4 WELL CONSTRUCTION...... 4-1 4.1 Strategy ...... 4-1 4.2 Exploration and Delineation Wells...... 4-3 4.3 Development Drilling...... 4-6 4.3.1 Tentative Drilling Schedule ...... 4-6 4.3.2 Drilling Hazards...... 4-6 4.3.3 Drilling Details...... 4-9 4.3.4 Directional Drilling ...... 4-10 4.4 Well Completions...... 4-11 4.4.1 Design Philosophy ...... 4-11 4.4.2 Tubing Design...... 4-11 4.4.3 Metallurgy...... 4-14 4.4.4 Downhole Equipment...... 4-15 4.4.5 Completion, Workover & Packer Fluid ...... 4-15 4.4.6 Annular Barriers ...... 4-16 4.4.7 Production/Injection Trees...... 4-16 4.4.8 Perforating...... 4-17 4.5 Well Interventions...... 4-17 4.5.1 Major Workovers ...... 4-17 4.5.2 Minor Workovers...... 4-17 5 PRODUCTION AND TRANSPORTATION SYSTEMS...... 5-1 5.1 Introduction...... 5-1 5.2 Design Criteria...... 5-1 5.2.1 Philosophy...... 5-1 5.2.2 Regulations and Certifying Authority...... 5-3 5.2.3 Codes and Standards ...... 5-4 5.3 Environmental Criteria...... 5-4 5.3.1 Operating Limits ...... 5-6 5.3.2 Marine Growth...... 5-7 5.4 Geotechnical Criteria...... 5-7 5.5 Production Installation and Topside Facilities...... 5-9 5.5.1 Platform Structures ...... 5-9 5.5.1.1 Wellhead Facilities ...... 5-10 5.5.1.2 Production Platform...... 5-10

Deep Panuke Volume 2 (Development Plan) · March 2002 TOC-ii 5.5.1.3 Accommodation Platform...... 5-10 5.5.2 Offshore Pipeline ...... 5-10 5.5.3 Onshore Facilities ...... 5-12 5.6 Subsea Installations...... 5-12 5.6.1 Subsea Production Trees...... 5-13 5.6.2 Flowlines...... 5-14 5.6.3 Subsea Control System...... 5-14 5.6.4 Diver and ROV Interface Requirements ...... 5-15 5.6.5 Oil Spill and Leak Protection...... 5-15 5.7 Processing Facilities ...... 5-15 5.7.1 Separation...... 5-15 5.7.2 Metering...... 5-15 5.7.3 Gas Sweetening...... 5-17 5.7.4 Acid Gas Injection...... 5-17 5.7.5 Dehydration...... 5-20 5.7.6 Hydrocarbon Dewpoint Control...... 5-20 5.7.7 Condensate Treatment for Fuel...... 5-20 5.7.8 Produced Water Treatment and Disposal ...... 5-20 5.7.9 Compression...... 5-20 5.7.10 Utilities...... 5-21 5.7.10.1 Electrical Power Generation ...... 5-21 5.7.10.2 Platform Fuel...... 5-21 5.7.10.3 Service Water Supply...... 5-21 5.7.10.4 Closed Drain and Open Drain Effluent...... 5-21 5.7.10.5 Relief and Blowdown System...... 5-21 5.7.10.6 Inert Gas System...... 5-22 5.7.10.7 Instrument Air...... 5-22 5.7.10.8 Breathing Air...... 5-22 5.8 Production Operations...... 5-22 5.9 Provisions for Decommissioning and Abandonment...... 5-22 5.10 Assessment of Development Alternatives ...... 5-23 5.10.1 Substructure Type ...... 5-25 5.10.2 Topside Type...... 5-27 5.10.3 Total Number of Platforms ...... 5-29 5.10.4 Re-Use of Existing Platform...... 5-31 5.10.5 Processing Location...... 5-32 5.10.6 Acid Gas Handling...... 5-37 5.10.7 Produced Water Disposal...... 5-40 6 CONSTRUCTION AND INSTALLATION ...... 6-1 6.1 Contracting Philosophy...... 6-1 6.2 Management Philosophy...... 6-1 6.3 Schedule...... 6-2

Deep Panuke Volume 2 (Development Plan) · March 2002 TOC-iii 6.4 Project Execution Plan...... 6-2 6.4.1 Wellhead Platform...... 6-2 6.4.2 Production Platform...... 6-2 6.4.3 Utilities / Quarters (U/Q) Platform...... 6-5 6.4.4 Offshore Pipeline ...... 6-5 6.4.5 Well Development & Subsea Tie Backs ...... 6-6 6.4.6 Onshore Facilities and Pipeline ...... 6-6 6.4.7 Offshore Hook-up and Commissioning...... 6-6 7 DEVELOPMENT ECONOMICS...... 7-1 7.1 Production Profile ...... 7-1 7.2 Preliminary Development Capital Costs ...... 7-2 7.3 Preliminary Operating Costs ...... 7-3 8 LIABILITY AND COMPENSATION...... 8-1 8.1 Introduction...... 8-1 8.2 Environmental Protection...... 8-1 8.3 Legislative and Regulatory Requirements ...... 8-1 8.4 Voluntary Compensation...... 8-2 9 SAFETY PLAN...... 9-1 9.1 Introduction...... 9-1 9.1.1 Health, Safety and Environment Corporate Statement ...... 9-1 9.1.2 Operations Risk Management System...... 9-2 9.1.3 Health, Safety and Environment Management System...... 9-2 9.1.4 Organization and Responsibilities ...... 9-4 9.2 Hazards and Effects Management Process ...... 9-6 9.2.1 Design ...... 9-7 9.2.2 Construction...... 9-8 9.2.3 Operations ...... 9-8 9.2.4 Documentation and Quality Assurance...... 9-9 10 ENVIRONMENTAL PROTECTION PLAN...... 10-1 10.1.1 Environmental Compliance Monitoring...... 10-2 10.1.2 Environmental Effects Monitoring...... 10-3 10.1.3 Waste Management Plan...... 10-3 10.1.4 Fisheries Compensation Plan...... 10-3 11 CONTINGENCY PLANNING ...... 11-1 11.1 Introduction...... 11-1 11.2 Alert/Emergency Response Contingency Plan ...... 11-3 11.2.1 Loss of Well Control (Drilling & Well Servicing) ...... 11-4 11.2.2 Subsea Pipeline Breaks ...... 11-5 11.2.3 Platform Incidents ...... 11-5

Deep Panuke Volume 2 (Development Plan) · March 2002 TOC-iv 11.2.4 Collision...... 11-5 11.2.5 Marine Incidents...... 11-6 11.2.6 Aviation Incidents ...... 11-6 11.2.7 Fire / Explosion...... 11-7 11.2.8 Hydrogen Sulphide Release...... 11-7 11.2.9 Spills ...... 11-8 11.3 Accountability...... 11-8 11.4 Training...... 11-8 11.5 Drills and Exercises ...... 11-9 11.5.1 Philosophy of Exercising ...... 11-9

LIST OF TABLES

Page No.

Table 1.1 Deep Panuke Project Principles...... 1-10 Table 2.1 Well Information for Deep Panuke Exploration and Development Wells ...... 2-12 Table 2.2 Summary of Deep Panuke Seismic Data Acquisition...... 2-22 Table 2.3 Deep Panuke Mapped Seismic Events ...... 2-23 Table 2.4 Deep Panuke Reservior Parameter Summary...... 2-31 Table 3.1 Drill Stem Test Data...... 3-2 Table 3.2 Core Sample Intervals...... 3-3 Table 3.3 Special Analysis Intervals...... 3-5 Table 3.4 Fluid Analysis Summary...... 3-5 Table 3.5 Probabilistic Reserves...... 3-9 Table 4.1 Exploration and Delineation Wells - Summary Information...... 4-6 Table 5.1 Preliminary Environmental Design Criteria - Pipeline ...... 5-5 Table 5.2 Preliminary Environmental Design Criteria - Deep Panuke Installation...... 5-5 Table 5.3 Operating Limits ...... 5-6 Table 5.4 Design Profile ...... 5-8 Table 5.5 Substructure Development Alternatives ...... 5-26 Table 5.6 Topside Development Alternatives...... 5-28 Table 5.7 Total Number of Platforms Development Alternatives ...... 5-30 Table 5.8 Re-Use of Existing Platform Development Alternatives...... 5-33 Table 5.9 Location of Processing Development Alternatives...... 5-34 Table 5.10 Acid Gas Handling Development Alternatives...... 5-38 Table 5.11 Produced Water Development Alternatives...... 5-41

Deep Panuke Volume 2 (Development Plan) · March 2002 TOC-v LIST OF FIGURES Page No.

Figure 1.1 Proposed Field Layout ...... 1-4 Figure 1.2 Preliminary Master Schedule...... 1-7 Figure 2.1 Location of the Deep Panuke Field...... 2-1 Figure 2.2 Physiography of the Scotian Shelf...... 2-2 Figure 2.3 Tectonic Elements of the Scotian Shelf...... 2-3 Figure 2.4 Generalized Stratigraphy, Scotian Shelf...... 2-4 Figure 2.5 Deep Panuke Sequence Stratigraphy...... 2-6 Figure 2.6 Nova Scotia Late Jurassic Paleogeography...... 2-8 Figure 2.7 Deep Panuke Pressure Data ...... 2-10 Figure 2.8 Abenaki 5 Depth converted seismic surface, 3-D View, looking North...... 2-11 Figure 2.9 Well Locations, Panuke License...... 2-13 Figure 2.10 Structural Cross-Section, Strike Direction, left SW, right NE...... 2-14 Figure 2.11 Dip Section with Seismic backdrop through M-79/M-79a, left NW, right SE...... 2-15 Figure 2.12 Abenaki 5 Sequence Boundary Structure ...... 2-16 Figure 2.13 Abenaki 5 net pay, wells and pseudowells sgs cck with average seismic porosity ...... 2-18 Figure 2.14 Abenaki 5 Phi-h map, wells and pseudowells sgs cck with average seismic porosity .. 2-19 Figure 2.15 Deep Panuke Production Licence (P12902) Seismic Database Map...... 2-21 Figure 2.16 Deep Panuke Seismic Section...... 2-24 Figure 2.17 Distribution of Modeled Total Porosity in the Abenaki Formation Penetrated by the Wells in the Study Area (Porosity is noted on the x-asis; cumulative number of occurrences on the y-axis.)...... 2-27 Figure 2.18 Distribution of Core Porosity in the Abenaki Formation Penetrated by the Wells in the Study Area. (Porosity is noted on the x-axis; cumulative number of occurrences is noted on the y-axis.) ...... 2-28 Figure 2.19 Correlation between Core Porosity and Permeability of the Abenaki Formation Penetrated by the Wells in the Study Area...... 2-29 Figure 2.20 Correlation Between Porosity, Elevation and Gas Saturation of the Abenaki Formation Penetrated by the Wells in the Study Area...... 2-30 Figure 3.1 Porosity versus Permeability Relationship, Deep Panuke ...... 3-4 Figure 3.2 Sales Gas Production Forecast...... 3-8 Figure 3.3 Water Production Forecast...... 3-9 Figure 4.1 Tentative Well Construction Schedule...... 4-2 Figure 4.2 Exploration and Delineation Wells...... 4-4 Figure 4.3 Delineation Wells, Composite Drilling Curves ...... 4-5 Figure 4.4 Typical Production Well Schematic...... 4-12 Figure 4.5 Typical Acid Gas Injection Well Schematic...... 4-13 Figure 5.1 Proposed Field Layout ...... 5-2 Figure 5.2 Typical Fixed Steel Platform (PanCanadian's Scott/Telford Field, UK) ...... 5-9 Figure 5.3 Offshore Pipeline Routing...... 5-11 Figure 5.4 Spool Subsea Trees...... 5-13 Figure 5.5 Simplified Process Flow Diagram...... 5-16 Figure 5.6 Upper Logan Canyon, Lithofacies in centre of log track, yellow areas in Gamma ray track on left indicate clean porous sand...... 5-18

Deep Panuke Volume 2 (Development Plan) · March 2002 TOC-vi Figure 5.7 Lower Logan Canyon to Missisauga: centre of log track indicates lithology, yellow .. areas in gamma track on left indicate clean porous sandstone...... 5-19 Figure 6.1 Preliminary Master Schedule...... 6-3 Figure 6.2 Saipem 7000 SSCV...... 6-4 Figure 6.3 Thialf SSCV...... 6-4 Figure 6.4 Castoro Sei Pipelaying Vessel ...... 6-5 Figure 7.1 Average Daily Gas Production Rate ...... 7-2 Figure 9.1 HSE Activity Matrix...... 9-5 Figure 11.1 PanCanadian’s Emergency Preparedness ...... 11-3

Deep Panuke Volume 2 (Development Plan) · March 2002 TOC-vii 1 INTRODUCTION AND PROJECT OVERVIEW

1.1 Introduction

While the Nova Scotia offshore has been the subject of exploration and study for the past five decades, interest in exploring in the region has increased significantly in the last five to ten years. Much of the recent interest in exploration activities in the Nova Scotia offshore is likely attributable to the development of the Sable Offshore Energy Project (SOEP) and the Maritimes and Northeast Pipeline (M&NP) project, each of which began operations in 1999. The SOEP was the first offshore natural gas development on the Scotian Shelf. M&NP provides open access natural gas transportation facilities to growing markets located in Canada and the northeastern United States.

Since 1996, when the regulatory applications for SOEP and M&NP project were filed, there has been a total of 34 exploration, delineation, and development wells drilled in Nova Scotia’s offshore. This is a significant increase in the level of activity prior to the SOEP filing. Today, exploration commitments for offshore Nova Scotia total $1.56 billion on 59 active exploration licenses.

In 1983 the Geological Survey of Canada, in the last published estimate of gas potential on the Scotian Shelf, estimated the total potential gas resources for the Scotian Shelf at 508 billion cubic metres. This equates to about 18 trillion cubic feet (tcf) while actual discovered gas on the Scotian Shelf is only 6 tcf. Industry estimates of Scotian Shelf potential are much higher, suggesting a potential for up to 40 tcf of recoverable gas.

PanCanadian Energy Corporation (PanCanadian) has been an active participant in the exploration activities on the Scotian Shelf. From June 1998 to January 2002, PanCanadian drilled 11 exploration and delineation wells including the Deep Panuke discovery well, PP-3C.

PanCanadian’s future exploration commitments were outlined to the Canada-Nova Scotia Offshore Petroleum Board (CNSOPB) in January 2001 to drill between eight to 15 wells over the next three to five years at an estimated cost commitment of $350 – 450 million. This is a significant exploration commitment, one vital to the development of Nova Scotia’s oil and gas industry.

Developments, such as the SOEP and Deep Panuke Project (the Project), in Nova Scotia’s offshore have not only resulted in positive economic benefit for the province, but have also allowed Nova Scotia’s potential as a participant in the offshore oil and gas industry to be noticed on the world stage.

Deep Panuke Volume 2 (Development Plan) · March 2002 1-1 On January 9, 2002, Halifax was named as the newest member of the World Energy Cities Partnership. This membership will provide the opportunity for Halifax, and other parts of Nova Scotia, to benefit from the experiences of other energy cities with more mature oil and gas sectors, transferring knowledge and skills to Nova Scotia companies.

The proximity of the Scotian Shelf, now connected by the M&NP mainline to growing markets in Canada and the northeastern United States, creates a strong impetus for further developments, such as the Deep Panuke Project, offshore Nova Scotia.

While these developments are positive, it must be recognized that the industry in Nova Scotia is in its infancy. The oil and gas industry is an internationally competitive industry, subject to the uncertainties and realities of the marketplace. To help support long-term stability of the industry, it is critical to maintain an economic environment in Nova Scotia that encourages development, which is commercially, socially and environmentally acceptable.

The development plan for the reserves associated with the Deep Panuke Project is specifically described in this Volume 2 of this Development Plan Application (DPA). The Deep Panuke DPA also includes an assessment of the environmental (Volume 4) and socio-economic (Volume 5) impacts of the Project, a Canada-Nova Scotia Benefits Plan (Volume 3) describing various processes and procedures to promote Canada-Nova Scotia benefits associated with the Project, and a report (Volume 6) describing the public consultation efforts carried out in relation to the Project. In addition to Environmental and Socio- economic Impact Statements, comprising Volumes 4 and 5 of this DPA, PanCanadian has prepared a Comprehensive Study Report (CSR) in accordance with the provisions of the Canadian Environmental Assessment Act (CEAA). Volume 1 of this DPA is a Project Summary.

Simultaneous with the filing of this DPA, PanCanadian is also filing an application with the National Energy Board (NEB), pursuant to Section 52 of the National Energy Board Act (NEB Act).

1.2 Purpose and Scope of the Project

In 1996, PanCanadian purchased a 50 percent interest in, and became the operator of, the Cohasset Project. While producing oil from the Cohasset Project, PanCanadian was also conducting exploration drilling in the area. PanCanadian’s exploration drilling resulted in the completion of the PP-3C discovery well in late 1998.

The PP-3C well encountered the highly fractured and porous Abenaki 5 formation, a dolomotized section of a larger carbonate reef structure. The PP-3C discovery well was followed by three successful delineation wells; PI-1B, H-08 and M-79/A.

Deep Panuke Volume 2 (Development Plan) · March 2002 1-2 The four Deep Panuke wells have identified a natural gas reservoir containing an expected 26.3 E9m3 (935 bcf) of recoverable gas reserves with an expected 33.0 E9m3 (1.2 tcf) of gas in place. The Deep Panuke field centre is located approximately 175 km southeast of Goldboro, and 250 km southeast of Halifax, Nova Scotia where water depths are approximately 40 meters. The Deep Panuke gas pool is located on Production License (PL) 2902 in which PanCanadian holds a 100 percent working interest. The purpose of the Project is to maximize recovery of Deep Panuke natural gas reserves on PL 2902 in a manner that maximizes return to PanCanadian’s shareholders.

Corollary benefits of the Project are the establishment of additional infrastructure and Project development skills to the benefit of the developing Nova Scotia gas industry. As a single project, the Deep Panuke Project does not constitute a natural gas industry in Nova Scotia; such an industry will only arise as the cumulative effect of several development projects. However, the Deep Panuke Project will contribute to the establishment of the skills, infrastructure and, by providing a second source of gas supply, the scope required for a sustainable natural gas industry in Nova Scotia.

1.3 Project Facilities

Deep Panuke natural gas reserves contain low volumes of associated gas liquids (lean) and approximately 0.2% hydrogen sulphide. The volumes of condensate produced are small, approximately 2000 barrels per day at a peak gas production of 11.6 E6m3/d (400 MMscf/d). Peak production will continue for a period of approximately three years, after which, production is expected to decline over the remaining life of the pool.

In order to develop the Project, PanCanadian will install facilities to produce, process and transport (via pipeline) the Deep Panuke reserves. The Project will utilize three separate offshore platforms: a wellhead platform, a production platform and an accommodations platform. The three platforms will be connected via pedestrian/service bridges. Market-ready gas will be transported to shore via a sub-sea pipeline which will make landfall near Goldboro, Nova Scotia to interconnect with pipeline facilities owned and operated by M&NP (Figure 1.1).

Produced condensate will be used as the primary fuel source for all three platforms, supplemented with natural gas as the condensate production declines.

The production platform, the largest of the three platforms to be constructed for the Project, will contain processing equipment, including compression to produce market-ready gas. H2S and CO2 (acid gas) contained in the produced gas will be removed on the production platform and injected for sub-surface disposal in an injection well. Production equipment is designed to allow “turn-down” so as to maximize recovery as gas reserves decline.

Deep Panuke Volume 2 (Development Plan) · March 2002 1-3 M&NP CustodyTransfer * Facility

SOEIGoldboroGasPlant

SableIsland

DEEPPANUKE SOEIThebaudPlatform DEVELOPMENT PanCanadianPipelineRoute

Wellhead Platform ProductionWell ProductionWell Production M-79 H-08 Platform Accommodations Platform NottoScale

P:\EnvSci\15xxx\P:\EnvSci\15xxx\15999PanCan\500RASCoordination\DevelopmentPlanApplication\DPAReport January\Figures\Figure1_1.cdr

Figure1.1ProposedFieldLayout The accommodations platform will contain living quarters for offshore personnel and associated utilities, safety systems and a control room. Additionally, the accommodations platform will house an emergency generator and a helicopter deck with associated re-fuelling facilities.

The wellhead platform will be used for dry wellheads and production and test manifolds. The wellhead platform will accommodate both production and injection wells.

The Project includes drilling of at least three additional production wells. These new wells will be drilled from the wellhead platform using a jack-up drilling rig. In addition to the new wells, the Project is evaluating the feasibility of re-using the two existing delineation wells, H-08 and M-79A, which will be produced via tieback sub-sea lines to the wellhead platform. Control umbilicals for the two remote sub-sea wells will run between the production platform and the H-08 and M-79A wells. Each of M-79A and H-08 will require re-completion prior to their tieback to the wellhead platform. Current plans for re- completion of the H-08 and M-79A wells involve use of the same jack-up drilling rig to be used to drill the additional wells from the wellhead platform. If the existing delineation wells are not used, they will be re-drilled from the wellhead platform. The timing and total number of development wells may be altered, depending on the drilling results and production performance.

An injection well will be used to dispose of H2S and CO2 removed from produced raw gas during processing. Condensate that is in excess to platform fuel requirements may also be injected. If condensate in excess of platform fuel requirements is produced it will likely be injected in a common injection well with H2S and CO2 or, if necessary, a second, dedicated condensate injection well. PanCanadian has determined that recovery and sale of the excess condensate is not economically viable.

The water produced in association with Deep Panuke gas will be treated on the production platform and discharged overboard in accordance with the Offshore Waste Treatment Guidelines (NEB et al., 1996)

Sub-sea gathering lines and control umbilical lines, between the H-08 and M-79A wells and the wellhead and production platforms, will be buried for their entire length.

Subsequent to processing on the production platform, market-ready gas, which meets M&NP’s specifications, will be transported via a 610 mm (24-inch) nominal diameter sub-sea pipeline to shore. The offshore portion of the Deep Panuke pipeline is approximately 175 km in length. The onshore portion of the Deep Panuke pipeline is from three to four kilometres in length, spanning the area between the landfall and interconnection with the M&NP mainline.

Deep Panuke Volume 2 (Development Plan) · March 2002 1-5 In addition to the onshore pipeline, PanCanadian’s onshore facilities will likely include the above-grade piping/metering, pipeline isolation valves, temporary pig facilities, SCADA facilities and a small building for SCADA and metering. These facilities will be developed in coordination with the M&NP custody transfer station.

1.4 Project Timing

The Project’s three main phases are the Development Phase, the Production Phase, and the Decommissioning Phase. The Development Phase consists of the following activities:

· definition – Front End Engineering Design (FEED) Study, Regulatory Application Preparation; · engineering; · procurement; · well construction; · facilities construction; and · facilities commissioning.

The Project is currently in the FEED Study/Regulatory Application phase.

The Production Phase will consist of gas production and processing and, as required, further drilling and well workovers.

Currently, the Development Phase is expected to continue until 2005. The Production Phase of the Project is expected to continue for a further 11.5 years following commissioning of Project facilities. It is important to note that the Project facilities have a design life of 25 years such that, with proper maintenance, Project facilities will be available to subsequent discoveries within the Panuke area.

Project timing is elastic and may be adjusted to account for market conditions, further drilling success or other developments that may occur over the life of the Project and or Project facilities.

Figure 1.2 provides a detailed breakdown of the Development Phase schedule for the Project.

1.5 Development Approach

As noted above, the Project is currently at the FEED Study stage of the development phase. As the FEED study continues, the Project will evolve in response to further and better information. Accordingly, the proposed Development Plan is a flexible one.

Deep Panuke Volume 2 (Development Plan) · March 2002 1-6 2000200120022003200420052006

Conceptual Definition Phase Phase

Preliminary FEEDStudy TechnicalOptions& ValueEngineering FeasibilityStudies Prep&FileDPA Complete PrepareBidPkgs ProjectSanction Regulatory Approvaland PCEBoard RegulatoryReview Sanction

Pre-Eng Engineering FirstGas Mat'lPlanning Equip&MatlProcurement on Platform ExecutionPhase Pre-Eng PipelineEng,Procure,Coating,&Install FirstGas Jackets&PlatformsFabrication Onshore Determine OffshoreDevDrilling(Eng&Drill) Potential Fabricators Offshore Install Hook-up &Comm

OperationsPhase Production

P:\EnvSci\15xxx\15999PanCan\500RASCoordination\DevelopmentPlanApplication\DPAReportJanuary\Figures\Fig1_2.cdr Figure1.2PreliminaryMasterSchedule The Project has relied on the advice of various disciplines in refining the development plan. Building upon the best efforts of the multi-disciplinary team assembled to develop the Deep Panuke Project, the Development Plan must be flexible so as to allow the Project to respond to the challenges of an offshore development.

The Project faces numerous operational uncertainties. As an example, the current drilling plan for the Project relies on a Reservoir Management Plan and production forecast that is based on a total of four wells, plus geological and geophysical information. As engineering studies continue, both before and after the Project facilities are fully operational, new data will become available that may cause a necessary adjustment to the plans for both reservoir management and drilling. The Reservoir Management Plan is a plan that will evolve as the multidisciplinary team responsible for its design and implementation incorporates new dynamic and static data to economically optimize recovery of Deep Panuke reserves.

Although PanCanadian will not consider full sanction to the Project until after regulatory approvals are received, PanCanadian has already begun to make some of the commercial arrangements necessary for the Project to proceed. The most significant of these commercial arrangements is a conditional agreement with M&NP to transport up to 400 MMBtu/d of sales-quality natural gas for a period of ten years. This significant financial commitment underscores the need for a flexible development plan that will allow PanCanadian to respond to operating and market conditions.

During the concept development and ongoing FEED stages, several potential development alternatives were analyzed. The result of this analysis is the facilities and development plan proposed herein. The production and transportation systems described in this Development Plan are, in PanCanadian’s opinion, the most technically and economically feasible means of developing the Project in a safe and environmentally responsible manner. In arriving at the development plan described in this DPA, the Project team examined several development alternatives. Each development alternative was compared against a number of criteria to derive the Development Plan.

As a precursor to formal evaluation of various development alternatives against pre-identified criteria, it was necessary to outline a central development concept by which the Project would be guided. The development concept for Deep Panuke is that the Project will, because of its reserve size, take advantage of pre-existing infrastructure to the maximum extent possible. As noted, PanCanadian has made conditional commercial arrangements to transport Deep Panuke gas on the M&NP system, specifying delivery to M&NP at Goldboro. Accordingly, development alternatives, which would not allow PanCanadian to take advantage of the infrastructure installed by M&NP were not evaluated against the pre-determined criteria because they lacked economic feasibility. Examples of development options which fell outside the Project’s central development concept are alternatives involving landfall sites

Deep Panuke Volume 2 (Development Plan) · March 2002 1-8 other than Goldboro, and the use of technologies requiring substantial new infrastructure such as liquefied natural gas or compressed natural gas technologies.

The evaluation of development alternatives is described in Chapter 5 of this Volume 2 of the Deep Panuke DPA.

1.6 Project Principles

Project success depends upon Project economics; the quality of output and the efficiency of operation in a very competitive world energy market. Additionally, Project economics are a crucial factor in PanCanadian’s internal allocation of capital. Therefore, the basic principle for the development and operation of the Deep Panuke Project is that it must be internationally competitive as it operates in a dynamic, market-driven environment.

An outflow from the principle of development of an internationally competitive project is that this Project, because of its relative reserve size, must take advantage of pre-existing infrastructure to the maximum extent possible.

Along with Project economics, other important principles, such as safety and environmental performance, also guide the Project’s development team.

Also crucial to the success of the Project are open and ethical business practices. Open and ethical business practices include working to the highest professional standards, placing top priority on safety and quality and ensuring that staff, employees and contractors are treated in a fair and equitable manner. The Deep Panuke Project Management Principles are more particularly described in the Canada-Nova Scotia Benefits Plan included as Volume 3 of this DPA.

The principles that will guide PanCanadian in the development of the Deep Panuke Project are described in Table 1.1.

Deep Panuke Volume 2 (Development Plan) · March 2002 1-9 Table 1.1 Deep Panuke Project Principles

GUIDING PRINCIPLE

The Project operates in a dynamic, market-driven environment and must be internationally competitive.

HEALTH, SAFETY & ENVIRONMENT CANADA-NOVA SCOTIA BENEFITS

The Project is fully committed to protecting the health and The Project will provide full and fair opportunity for all safety of all individuals affected by their work, as well as interested parties to participate in the supply of goods and the environment in which they live and operate. services to the Project on a “best value” basis. Specifically, the Project will be guided by the following principles, which outline PanCanadian’s Health, Safety · Goods and services will be procured through and Environment Corporate Statement: competitive tender.

· We comply with government regulations, follow · The bidding process will be open and fair. accepted industry practices and maintain our own policies at levels which are commensurate with the high · Best value is a blend of total cost, quality, technical standards by which we conduct our business. suitability, reliability, delivery and assurance of supply, while at the same time meeting or exceeding safety and · We will establish appropriate health, safety and environmental standards. environmental performance goals and regularly review our progress toward them. · We will encourage the development of long-term industrial support for the Project in Nova Scotia and · We will communicate on health, safety and Canada through consultation and communication. environmental matters in an open and timely manner with all affected parties. PROJECT MANAGEMENT · Project Management will develop the culture and provide the training and resources necessary to support Quality and safety are the fundamental values that define our commitments and will take health, safety and the Project’s Management Philosophy. environmental matters into account when making business decisions. · The Project’s management structure will operate to ensure quality and safety, while maintaining cost · The Project will be maintained as a healthy and safe control and schedule requirements. place to work and a desirable member of the community in which it operates. · The Project will fully comply with all appropriate regulatory standards and industry codes.

DEVELOPMENT PRINCIPLES · New technology will be embraced where an analysis indicates that such use is prudent and does not create · The Project will be competitive with other investment undue risk for the Project. opportunities available to PanCanadian.

· Our Project will serve natural gas customers on a competitive basis, on reasonable terms and conditions.

· Commercial arrangements for the Project will ensure that access to the North American pipeline grid is assured.

Deep Panuke Volume 2 (Development Plan) · March 2002 1-10 1.7 Regulatory Overview

Oil and gas development projects offshore Nova Scotia are regulated in several ways. The CNSOPB regulates oil and gas activities generally under the Canada-Nova Scotia Offshore Petroleum Resources Accord Implementation Act (the Accord Act) and specifically requires proponents to file a Development Plan Application for development projects. The pipeline between the Production Platform and the interconnect with M&NP must be approved by the NEB. PanCanadian will make application to the NEB, simultaneously with filing this DPA with the CNSOPB, for a Certificate of Public Convenience and Necessity, and an order under Part IV of the NEB Act, for the Deep Panuke pipeline. The NEB will require a public review of the application. In addition to the CNSOPB and NEB approvals necessary for the Project, the Government of Nova Scotia asserts jurisdiction over, and requires approval of, the pipeline associated with the Project under the Nova Scotia Pipeline Act.

The Project will also undergo a comprehensive study environmental review under the CEAA. By operation of the Federal Coordination Regulations process under the CEAA, the Project has been “scoped” for environmental assessment purposes. A “Memorandum of Understanding on the Environmental Assessment of the Deep Panuke Project” has been entered into amongst the CNSOPB, NEB, Department of Fisheries and Oceans (DFO), Environment Canada (EC), Industry Canada (IC), the Canadian Environmental Assessment Agency (the Agency) and the Province of Nova Scotia as represented by the Nova Scotia Department of Labour and Environment (the Province)(the Deep Panuke MOU). Each of the CNSOPB, NEB, DFO, EC and IC are, or may be, Responsible Authorities in relation to the environmental assessment under the CEAA. The Province may have environmental responsibilities regarding the assessment of environmental effects for the onshore portion of the project, under the Nova Scotia Environment Act, in the event the onshore pipeline is greater than five kilometres in length.

Under the terms of the Deep Panuke MOU, the CNSOPB is designated as the lead responsible authority (RA) under the CEAA and will coordinate the Comprehensive Study Report (CSR) process for federal purposes. The Province will coordinate the process for provincial purposes, to the extent an environmental assessment is required under the terms of the Nova Scotia Environment Act. The parties to that MOU have agreed to coordinate the assessment of the environmental effects of the Project.

The CNSOPB, as the lead RA, will conduct a review of the CSR for the Project. The CSR for the Project is being filed in draft form, simultaneously with this DPA. Responsibility for preparation of the CSR for the Project has been delegated to PanCanadian by the RAs.

After the RAs are satisfied the Project’s CSR is complete, it will be submitted to the Agency which, in turn, will publish the CSR for public comment.

Deep Panuke Volume 2 (Development Plan) · March 2002 1-11 Subsequent to the public-comment process on the final CSR, conducted by the Agency, the Federal Minister of the Environment will take a decision pursuant to Section 23 of the CEAA. Under Section 23 of the CEAA, the Minister of the Environment may refer the Project back to the RAs for a decision or refer the Project to a mediator or review panel.

Assuming the Federal Minister of the Environment’s decision under Section 23 of the CEAA refers the Project back to the RAs for decision, the CNSOPB and NEB would then conduct their respective reviews of PanCanadian’s applications in relation to this Project. Notices of public hearings by the CNSOPB or the NEB will not be issued until the final CSR and the public comments received on that document are submitted to the Minister by the Agency.

Deep Panuke Volume 2 (Development Plan) · March 2002 1-12 2 GEOLOGY, GEOPHYSICS, AND PETROPHYSICS

The Deep Panuke Project will produce natural gas from a porous carbonate reservoir located some 3500- 4000 metres (m) below the seafloor in the area of the abandoned Cohasset oil development project. This chapter provides a statigraphic, sedimentological, and structural review of the Deep Panuke natural gas field. Additionally, this chapter describes the petrophysical and analytical procedures used to develop PanCanadian’s understanding of the Deep Panuke gas field.

2.1 Geological Interpretation and Reservoir Description

The Deep Panuke natural gas field occurs in the margin of the carbonate platform (Abenaki Formation) 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 reservoir is made up of limestone and dolomite. The natural gas pool is formed in a combined structural/stratigraphic trap, with structural closure to the northeast and southwest, and stratigraphic closure updip into tight platform interior sediments to the northwest. The platform thins and plunges to the southeast. The general location of the field is shown in Figure 2.1. The pool is located about 250 kilometers (km) offshore southeast of Halifax, Nova Scotia.

Figure 2.1 Location of the Deep Panuke Field

Deep Panuke Volume 2 (Development Plan) · March 2002 2-1 2.1.1 Regional and Reservoir Structural Setting

The Scotian Shelf is part of the continental margin of eastern North America. The shelf extends from the Laurentian Channel to the Northeast Channel. The physiographic location of the Scotian Shelf is shown in Figure 2.2.

Figure 2.2 Physiography of the Scotian Shelf

The regional geology of the Scotian Shelf has been reviewed in detail by several authors. Key references with regard to the regional geology of the Scotian Shelf are provided in Part Two (DPA-Part 2, Ref # 2.1.1.1, 2.1.1.3, and 2.1.2.2). The Scotian Shelf is underlain by attenuated, rifted, continental basement. The basement is composed of plutonic Devonian granite and Late Precambrian to Ordovician metasediments. The Scotian Shelf began rifting in response to the separation of Africa in the late Triassic and extensional faulting was complete by the early Jurassic. This process created a network of basement ridges and basins. The Abenaki carbonate margin often overlies the outer edge of the basement ridges. The Deep Panuke gas field overlies part of the Moheida ridge feature. The leading

Deep Panuke Volume 2 (Development Plan) · March 2002 2-2 edge of the carbonate platform appears to have been controlled by a combination of syndepositional listric faulting, clastic sediment influx, and a break in slope produced by the underlying basement structure (DPA-Part 2, Ref # 2.1.1.1). Diagnesis may have been localized by reactivated wrench faulting along the underlying basement faults. One phase of this reactivation may have coincided with the separation of the Grand Banks and Iberia at the end of the Jurassic (DPA-Part 2, Ref # 2.1.1.2). The tectonic elements of the Scotian Shelf are illustrated in Figure 2.3.

Figure 2.3 Tectonic Elements of the Scotian Shelf

2.1.2 Regional and Reservoir Stratigraphy

The regional stratigraphy of the Scotian Shelf consists of an underlying basement made up of folded and faulted Cambro-Ordovician metasediments and Devonian granitic intrusives and an overlying cover of Triassic to Recent sediments (DPA-Part 2, Ref # 2.1.2.2). The general stratigraphy of the Scotian Shelf is shown in Figure 2.4.

Deep Panuke Volume 2 (Development Plan) · March 2002 2-3 Figure 2.4 Generalized Stratigraphy, Scotian Shelf

Deep Panuke Volume 2 (Development Plan) · March 2002 2-4 Dry rift sedimentation occurred during the initial phase of the opening of the North Atlantic in the Late Triassic to Early Jurassic. Synrift continental clastics (Eurydice Formation) filled grabens and half grabens formed by extensional faulting. The rift then was flooded and marine conditions dominated with the deposition initially of evaporites (Argo Formation) and then of dolomites and anhydrites in a coastal sabkha and shallow marine ramp system (Iroquois Formation). Siliciclastics covered the shelf (Mohican Formation) during the Toarcian.

A carbonate system was re-established on the outer edge of the platform by the Bathonian with the deposition of a carbonate ramp (Scatarie Member, Abenaki Formation). This ramp was drowned and deeper water siliciclastics again dominated (Misaine Member, Abenaki Formation). The carbonate system developed again as a thick platform of agrading and prograding carbonate cycles (Baccaro Member, Abenaki Formation) (DPA-Part 2, Ref. # 2.1.2.1 and 2.1.3.1). At Deep Panuke, the Abenaki has been divided into seven third order sequences based on cycle stacking patterns, log character, and seismic sequence stratigraphy (DPA-Part 2, Ref. # 2.1.2.4). The sequence stratigraphic model is displayed in Figure 2.5. The model correlates the third order cycles observed at Deep Panuke to the global sea level curve developed by Haq et al. (DPA-Part 2, Ref. # 2.1.2.5). Micropaleontology and micropalynology data were key to developing the correlations. The timing of deposition of individual cycles at the M-79 well as determined by these techniques is indicated on Figure 2.5.

Outboard of the carbonate margin, deep-water siliciclastics were deposited (Verrill Canyon Formation). Marginward of the carbonate system, siliciclastics were deposited in a fluvial/deltaic to shoreline setting (Mic Mac Formation). To the northeast of Deep Panuke, the system became dominated by clastics related to the Jurassic Sable delta and the platform margin is replaced by a mixed carbonate clastic deltaic system. The carbonate system on the Scotian Shelf was drowned by the Berriasian, with the last carbonate cycle deposited on the flooded shelf being the deep water Artimon member (Abenaki 7 cycle).

The continued outpouring of continental clastics through the Early Cretaceous resulted in the formation of a fluvial/deltaic sandstone complex (Lower and Upper Missisauga, Logan Canyon Formations) and prodelta and deeper water marine shales (Verrill Canyon Formation, Naskapi Shale). The deltaic system was flooded and marine shales and carbonates deposited (Dawson Canyon Formation, Wyandot Formation) Deeper marine sedimentation continued through the Tertiary with the deposition of deeper water siliciclastics (Banquereau Formation). Final deposition in the Recent consists of glaceo-marine and glaceo-fluvial sediments (Laurentian Formation). A detailed review of stratigraphy can be found in Part Two (DPA-Part 2, Ref # 2.1.2.1, 2.1.2.2, 2.1.2.3, and 2.1.2.4).

Deep Panuke Volume 2 (Development Plan) · March 2002 2-5 Figure 2.5 Deep Panuke Sequence Stratigraphy 2.1.3 Sedimentology and Diagenesis of the Abenaki Formation, Reservoir Development

The Scatarie member of the lower Abenaki was deposited in a low angle carbonate ramp setting. In the Deep Panuke pool whole core, sidewall core and ditch cuttings from the Scatarie consist of oolitic grainstone and packstone deposited in a shallow shoal to intershoal environment. The Misaine shale member is made up of deeper water marine siliciclastics and carbonates.

The overlying Baccaro consists of repeated cycles of shallowing up platform carbonates. In the deeper water forereef area, skeletal wackestone and thrombolitic wackestone were deposited along with knoll reefs dominated by sponges and corals. At the platform margin, coral, stromatoporoid, chaetetid, rudstone to boundstone with skeletal packstone to grainstone matrix occur. The platform interior is characterized by oncolitic to pseudo-oncolitic grainstone to packstone and oolitic grainstone. The Baccaro is capped by the Artemon Member, which consists of deeper water siliciclastics and thrombolitic sponge mounds. This unit represents deposition during the drowning of the carbonate platform. A regional Late Jurassic paleogeographic map is presented below in Figure 2.6. As indicated in Figure 2.6, the carbonate bank, highlighted in blue, is developed as a continuous bank to the south and west of the Jurassic Sable Island delta. Outboard of the bank are deep marine clastics and inboard of the bank are delta and prodelta clastics. A more detailed review of deposition, sedimentology, and facies is provided in Part Two (DPA-Part 2, Ref # 2.1.3.1, 2.1.3.2, 2.1.3.3, and 2.1.3.5 through 2.1.3.9).

The rocks of the Abenaki formation show some indications of early marine cementation and compaction. These processes reduced primary intergranular and intrafossil porosity. Thin sections, cut from core samples, also exhibit vertical stylolites and microfracturing and brecciation, all of which indicated a compressional stress regime at some point in the past. This may be related to late Jurassic to early Cretaceous compression as the passive margin was affected by the separation of the Grand Banks from southern Europe (DPA-Part 2, Ref # 2.1.1.2). There is not a great deal of evidence in core and sidewall core for exposure and karst.

Deep Panuke Volume 2 (Development Plan) · March 2002 2-7 Figure 2.6 Nova Scotia Late Jurassic Paleogeography It is probable that the main diagenetic processes, which created the reservoir, are deep burial related. There were at least three phases of dolomitization, one of which was a late hydrothermal dolomite phase. Reservoir porosity was enhanced through a late leaching event, which has partially dissolved the dolomites and limestones creating inter- and intra-particle porosity, inter- and intra-crystalline porosity, and microporosity in the matrix and occasionally cavernous porosity created by dissolution of fossil skeletons. Porosity was reduced somewhat by precipitation of late coarse sparry calcite and minor amounts of anhydrite. It is thought that the reservoir consists of a dual porosity system: a narrow high permeability, high porosity, touching vug limestone to limy dolomite to a coarse grained intercrystalline dolomite zone; and a widespread low porosity, low permeability, partially leached matrix porosity zone (DPA-Part 2, Ref # 2.1.3.4).

Reservoir creating diagenesis has been focused primarily along the carbonate margin in the reef crest to forereef environment and along lineaments subparallel to the margin. The Abenaki 6 cycle represents a time of deeper water carbonate deposition after the platform was flooded and sediments deposited are clastic and carbonate mud rich. As a result, in the existing wells, the sediments deposited during the Abenaki 6 cycle do not have a great deal of porosity developed. There is a possibility that during the initial flooding of the platform in the Abenaki 6 cycle, reefal sediments may have continued to be deposited over the high parts of the platform margin. These zones have potential for porosity development. There are seismic amplitude anomalies in these positions in the Abenaki 6, but none have been tested to date. A more detailed review of diagenesis at Deep Panuke can be found in Part Two (DPA-Part 2, Ref # 2.1.3.1, and 2.1.3.4).

2.1.4 Hydrocarbon Source, Generation, and Migration

The Verrill Canyon shales are the most likely source of hydrocarbon. They are described as gas prone, low total organic content, type III, source rock (DPA-Part 2, Ref # 2.1.4.1, and 2.1.4.2). In the Panuke area, the Verrill Canyon would have reached gas generation maturity in the Upper Cretaceous to Tertiary (100 to 50 MA) (DPA-Part 2, Ref # 2.1.4.3). Migration into the Abenaki would be via direct contact with the Verrill Canyon at the platform margin and from deeper source rock via growth and wrench faults. A detailed review of hydrocarbon source, generation and migrations is provided in Part Two (DPA-Part 2, Ref # 2.1.4.1, 2.1.4.2, 2.1.4.3, and the vitrinite reflectance report from Ref # 2.1.2.3).

2.1.5 Hydrogeology

The Deep Panuke gas field is normally pressured. A hydrogeological review of well tests along the Abenaki margin indicates a common pressure system. As demonstrated in Figure 2.7, the Deep Panuke well tests indicate that all the wells are in the same pressure system. Note that the pressure data indicates the gas water contact is between –3493 and –3530 meters subsea. This brackets the petrophysically-

Deep Panuke Volume 2 (Development Plan) · March 2002 2-9 defined contact at –3504 meters subsea. Further information on the hydrogeology of the Deep Panuke pool is found within Part Two (DPA-Part 2, Ref # 2.1.5.1).

Figure 2.7 Deep Panuke Pressure Data

Deep Panuke Volume 2 (Development Plan) · March 2002 2-10 2.1.6 Trapping Mechanisms of the Bacarro Member, Abenaki 5 cycle

The gas at Deep Panuke has accumulated in a combined structural stratigraphic trap. There is an overall structural closure to the southwest and northeast parallel to the margin caused by underlying basement structure. This closure is aided by listric faults that have scalloped out the porous margin edge to the southwest and northeast of the pool. The pool is stratigraphically closed updip into the platform to the northwest by a facies change into tight oolitic and platform interior sediments. Top seal is provided by the tight deeper water carbonates of the Abenaki 6 and Abenaki 7 units (Artemon). The majority of the gas is trapped in the Abenaki 5 cycle, but there is gas present in the upper part of the Abenaki 4 cycle. There could be additional reserves in the lower portion of the Abenaki 6 but no wells have encountered significant porosity development. A three dimensional image of the Abenaki 5 surface is shown in Figure 2.8. The steep scalloped nature of the carbonate margin is demonstrated as well as the local NE/SW structural closure along the margin. Further information on the trapping mechanism is contained in Part Two (DPA-Part 2, Ref # 2.1.6.1).

Figure 2.8 Abenaki 5 Depth converted seismic surface, 3-D View, looking North

Deep Panuke Volume 2 (Development Plan) · March 2002 2-11 2.1.7 Pool History

The earliest well drilled in the immediate area was the Shell B-90 well, drilled in 1986. This well, which encountered tight platform carbonates in the Upper Baccaro, discovered the Panuke Cretaceous oil pool. PanCanadian discovered the Deep Panuke gas pool with the drilling of the PP-3C well in 1998. The well encountered gas in the Abenaki 5 cycle in a high porosity zone, circulation was lost and the well was drilled to total depth without regaining circulation. Wellbore petrophysical logging was limited to the use of measurement while drilling tools, and no ditch cuttings or core were recovered across the porous interval. Four delineation wells and two whip stocks were drilled in 1999 and 2000 resulting in three additional productive wells at H-08, M-79A, and PI-1B. These wells confirmed the presence of a significant gas accumulation. The location of the Deep Panuke wells are shown in Figure 2.9 along with the location of two cross-sections which are presented in Figures 2.10 and 2.11 of this document. Basic well information is provided in Table 2.1.

Table 2.1 Well Information for Deep Panuke Exploration and Development Wells Total Depth (m) Well I.D. Year Drilled Rotary Table to Sealevel (m) Measured PP-3C 1998 4163.4 46.8 PI-1A 1999 4030 46.5 PI-1B 1999 4046.3 46.5 H-08 2000 3682 39.2 M-79 2000 4598.3 47 M-79A 2000 3934.7 47 F-09 2000 3815 39.9

2.1.8 Pool Description

This section of the report provides a brief overview of the correlations between wells, surfaces within the pool, and porosity and reserve distributions within the pool. The first cross-section indicated in Figure 2.10 is a structural strike section (A to A’ on Figure 2.9) through the pool showing the Gamma Ray signature for each well and the third order sequence boundaries. The sequence stratigraphic framework of the Deep Panuke reservoir is discussed in detail in Part Two (DPA-Part 2, Ref # 2.1.2.4) Correlation of events within the pool was done on the basis of gamma ray character, seismic stratigraphy, and facies stacking patterns. The reservoir is made of depositional sequences or layers of rock that were deposited along the margin of the shelf in the marine subsea environment. Sequence boundaries are assumed to represent single points in time or time lines. Sequence boundaries separate the reservoir into depositional sequences or packages of rock that were deposited at the same time in a variety of environments. Depositional sequences are fairly constant in thickness along strike, thin to the interior of the platform and pinch out to the front of the platform margin. Lithofacies interpretations and lithological descriptions of ditch cuttings and core for the Deep Panuke wells are presented in Part Two (DPA-Part 2, Ref # 2.1.3.5, 2.1.3.6, 2.1.3.8, and 2.1.3.9).

Deep Panuke Volume 2 (Development Plan) · March 2002 2-12 Figure 2.9 Well Locations, Panuke License Figure 2.10 Structural Cross-Section, Strike Direction, left SW, right NE

Deep Panuke Volume 2 (Development Plan) · March 2002 2-14 The second cross-section shown in Figure 2.11 is a dip section (B to B’ in Figure 2.9) through the M-79 well and the M-79A side-track well. The section has a seismic backdrop of the latest reprocessed seismic in variable density display mode. Figure 2.11 demonstrates the aggradational style of platform development as well as the interfingering nature of the relationship between the carbonate platform and the basinal siliciclastics.

Figure 2.11 Dip Section with Seismic backdrop through M-79/M-79a, left NW, right SE

Time structure maps of the Abenaki 3, Abenaki 4, Abenaki 5, and Abenaki 6 sequence boundaries were converted to depth and adjusted to match the well tops. A depth structure map of the top of the Abenaki 5 sequence is displayed in Figure 2.12.

Deep Panuke Volume 2 (Development Plan) · March 2002 2-15 Figure 2.12 Abenaki 5 Sequence Boundary Structure Models of the reservoir were generated using the Landmark Stratamodel computer program. Merging of well porosity data with seismic attribute data in a mathematical process called sequential gaussian simulation collocated cokriging generated several geostatistical models of porosity distribution. The technique used honors the well porosity and extrapolates away from the wells using the pattern of porosity derived from the seismic data. The geostatistical technique used to generate models does not produce a unique solution. Models were simulated in a flow model and compared to well tests to assess validity.

The existing well data was insufficient to generate a geologically realistic model. Additional data points (pseudowells) were created and filled with seismically derived porosity characteristics to give additional control to the model.

The maps shown below are from the combination of the well data and the average porosity derived from the seismic volume. Petrophysical data indicated the gas water contact is located at –3504 m subsea. A net pay map shows the thickness of reservoir above a certain porosity cutoff. For example, if a well may have 10 meters of better than 3% porosity scattered through a 100 m thick depositional sequence above a gas water contact, it would have 10 m of net pay. Figure 2.13 shows the net pay map for the Abenaki 5 member.

Multiplying the net pay of the reservoir by its average porosity value and plotting the thickness of 100% porous reservoir generates a phi-h (porosity thickness) map. As an example, 30 m of 10% porous rock would have a phi-h of 3 m of 100% porosity. Figure 2.14 shows the phi-h map for the Abenaki 5 member. The porosity cutoff used on both maps was 3% porosity. On both maps the bright colors correspond to better porosity zones. Note the tendency of the most porous zones to parallel the margin. Further details on reservoir description can be found in Part Two (DPA-Part 2, Ref. # 2.1.6.1, and 2.1.8.1).

Deep Panuke Volume 2 (Development Plan) · March 2002 2-17 Figure 2.13 Abenaki 5 net pay, wells and pseudowells sgs cck with average seismic porosity Figure 2.14 Abenaki 5 Phi-h map, wells and pseudowells sgs cck with average seismic porosity The models had the porosity in the backreef areas reduced (northwest side of the model). Shaly and sandy tight carbonates, which occur in the platform interior to the northwest, have the same seismic character as porous carbonates. There is porous carbonate present in the platform interior but it cannot be easily differentiated from non-porous shaly and sandy carbonates hence it is not included in the porosity distribution. This is the reason for the abrupt drop in porosity in the net pay and phi-h maps, Figures 2.13 and 2.14 respectively, above. Porosity in the backreef area, as defined by seismic data, was divided by a factor of ten. The backreef may contain, and contribute, a significant volume of gas, but it is not possible to determine the porosity distribution at this time. Further discussion of porosity distribution and reserve distribution in the Abenaki is presented in Part Two (DPA, Part 2, Ref # 2.1.6.1, and 2.1.8.1).

Water saturation is the percentage of the open space in the rock (porosity) that is filled by water. Water takes up void space that could be filled by hydrocarbon. It is necessary to estimate water saturation before a gas in place calculation can be done. Water saturation was derived from interpretation of the petrophysical data, as discussed in Section 2.3 entitled “Petrophysics”.

Permeability is a measurement of the ability of the reservoir rock to allow fluid or gas to move through it. High permeability rock allows fluid to move through easily. Permeability determinations for Deep Panuke were based upon analysis of full diameter core and sidewall core samples. The core analysis results and permeability at Deep Panuke are discussed in Part Two (DPA-Part 2, Ref # 2.1.3.7, 2.1.6.1, 3.1.3.1).

Porosity distribution, as defined by the geostatistical models, the permeability model, derived from core analysis and transforms developed by F.J. Lucia (DPA-Part 2, Ref # 3.1.3.1), and the petrophysically determined water saturation were combined in a flow simulation model. The model was modified to match well tests in order to determine recoverable gas and generate production profiles. Information on reserve and production estimates can be found in Chapter 3.

2.2 Geophysics

The role of geophysics in reservoir characterisation is to provide a means of extrapolating well-bore information away from the wells.

The geophysical method of choice is reflection seismology, commonly referred to as seismic. The basic principle behind the seismic method is the reflection of sound waves by boundaries between different rock types within the earth. A surface source generates sound waves that penetrate the earth and are reflected back to the surface where receivers measure the strength and travel time of the reflected waves. This data is processed and is commonly displayed vertically as a seismic wiggle trace in which the amplitude of the wiggle indicates the strength of the reflection and the vertical direction represents travel

Deep Panuke Volume 2 (Development Plan) · March 2002 2-20 time. The display of such data collected along a line on the surface produces a two-dimensional (2D) seismic section that is an image of the rock boundaries beneath the surface. Data is collected over a grid on the surface produces a three-dimensional (3D) volume or ‘cube’ of traces. An example of a wiggle trace display is shown in Figure 2.16 which displays a 2D seismic section extracted from a 3D cube over the Panuke Field. The use of seismic data to estimate the depth to the top of the reservoir and the porosity of the reservoir rock across the Deep Panuke Field are described in the following sections.

2.2.1 Seismic Database

PanCanadian’s seismic database over the Panuke Production Licence consists of a number of 2D seismic lines and one 3D dataset as shown by the map in Figure 2.15.

Figure 2.15 Deep Panuke Production Licence (P12902) Seismic Database Map

Table 2.2 provides a summary of the data shown in Figure 2.15.

Deep Panuke Volume 2 (Development Plan) · March 2002 2-21 Table 2.2 Summary of Deep Panuke Seismic Data Acquisition Data Type Program No. Shot Date Acq. Style Approx. kms on PL2902 Incorp. In Study 3D NS24-L023-002E 1990 Marine 49sq Yes 2D 8624-S006-037E 1983 Marine 9 No 2D 8624-M003-049E 1984 Marine 9 No 2D 8620-N011-001E 1985 Marine 39 No 2D 8620-S014-006E 1983 Marine 20 No 2D 8624-S006-027E 1981 Marine 6 No 2D 8624-S006-033E 1982 Marine 14 No 2D 8624-W013-001P 1983 Marine 9 No

The Panuke 3D seismic dataset was the exclusive source for the reservoir geophysics study and will be described in more detail below.

Lasmo Nova Scotia Ltd. shot the 106.7 square km 3-D marine survey in 1990 to provide detailed information to support the development of the Panuke Oil Field within the Cohasset Project. A seismic vessel acquired the data towing an air-gun source array, and dual receiver cables (or streamers) each 2650 m in length and separated by 80 m. Subsequent processing of the data provided a seismic reflection amplitude trace at every 40 m in the NE-SW direction and at every 12.5 m in the NW-SE direction over the area of the survey. More extensive details of the acquisition and processing of the dataset can be found in the Panuke 3D Seismic Report in Part Two (DPA – Part 2, Ref.# 2.2.1.1).

PanCanadian became an owner of the 3D dataset through the acquisition of Lasmo’s interest in the Cohasset Project in 1996. The zone of interest for the design of the 3D program was the oil-bearing sands of the Upper Missisauga formation which lie at depths around 2000 m below sea level (BSL). As a result the acquisition and original processing parameters are less than optimum to image the carbonate rocks of the Abenaki formation buried at depths of over 3000 m BSL.

PanCanadian reprocessed the 3D seismic dataset in 1997 in order to improve the image of the Abenaki formation prior to the drilling of the PP-3C Deep Panuke discovery well. In 2001, the dataset was again reprocessed using the latest processing techniques to both further enhance the image and to extract information about reservoir properties such as porosity. Details of this latest reprocessing effort can be found in Part Two (DPA – Part 2, Ref. # 2.2.1.2 and 2.2.1.3).

Deep Panuke Volume 2 (Development Plan) · March 2002 2-22 2.2.2 Time Interpretation

This discussion is confined to the interpretation of seismic reflection events corresponding to rock boundaries within the Abenaki Formation. The Panuke 3D Seismic Report (DPA-Part 2, Ref.# 2.2.1.1) provides a discussion of seismic events arising from shallower formations. The interpretation process begins by matching seismic traces at the well locations to synthetic traces generated from well-bore measurements and, if available, to traces from a vertical seismic profile (VSP). Synthetic traces are computed from velocity and density well logs that have been converted from depth into travel time by a relationship known as a time–to-depth (TD) curve. The TD curve is derived from travel time measurements down the well bore, usually by sonic wire-line tools, check-shot surveys or VSPs. These measurements are often referred to as sources of velocity information as travel time to known depths is easily translated into velocity. The correlation of the synthetic or VSP traces to the seismic traces allows those reflections from specific rock boundaries penetrated by the well to be identified and their position on the seismic section located. More details of this correlation process are given in the Interpretation Report included in Part Two (DPA – Part 2, Ref. # 2.2.2.1)

For the Deep Panuke field, reflections corresponding to the top of the Abenaki 4, 5 and 6 sequences were identified. For each sequence top, Table 2.3 lists the depths and corresponding two-way seismic travel times (TWT) at the Deep Panuke well locations. The velocity sources available for each well are also listed.

Table 2.3 Deep Panuke Mapped Seismic Events Well Name Abenaki 6 Abenaki 5 Abenaki 4 Available Velocity Sources TWT DEPTH TWT DEPTH TWT DEPTH sonic checkshot VSP (msec) (M,ss) (msec) (M,ss) (msec) (M,ss) B-90 2286 -3179.2 2346 -3371.1 NDE Yes Yes No PI-1A 2292 -3176.8 2358 -3369.9 2410 -3503.7 Yes No No PI-1B 2292 -3176.4 2361 -3368.4 2411 -3492.9 Yes No No H-08 2331 -3256.6 2376 -3387.9 2432 -3532.1 Yes No Yes M-79 2314 -3202.4 2372 -3398.7 2422 -3523.5 Yes No No F-09 2268 -3143.8 2326 -3294.8 2372 -3411.9 Yes No No M-79A 2314 -3200.7 2370 -3378.0 NDE Yes No No PP-3C 2296 -3178.9 2355 -3362.0 2410 -3487.3 No No No

These reflections were then tracked from well to well and throughout the entire survey. This process was completed on a workstation using a combination of automated and manual methods. Figure 2.16 shows the tracked reflections or ‘horizons’ annotated on a seismic section that crosses the Deep Panuke field as shown on the map in Figure 2.15.

Deep Panuke Volume 2 (Development Plan) · March 2002 2-23 Figure 2.16 Deep Panuke Seismic Section

The accuracy of these horizons varies according to the difficulty in tracking the reflections between, and away from, the calibrated points at the wells.

The Abenaki 6 reflection is generally consistent over the platform and can be tracked easily. Beyond the platform edge, the dominant lithology changes from carbonate to shale, so there is less contrast in rock properties across the sequence boundary. Thus, tracking is more difficult as there is greater uncertainty in the identification of the correct event, particularly in the absence of well control in this area.

Tracking the tops of the Abenaki 4 and 5 sequences is more problematic. In the interpreted back-reef area the Abenaki 4 and 5 reflections are quite consistent, but towards the reef front, identification becomes difficult as their character changes with changes in rock type and the presence of porosity.

Deep Panuke Volume 2 (Development Plan) · March 2002 2-24 Basinward of the reef front, the dominant lithology changes from carbonate to shale making the identification of the top of the sequences very difficult. In this area the interpreted horizons tend to delineate the edge of the reef rather than the actual top of the sequences.

Mapping the two-way seismic travel times to the horizons produces time-structure maps over the field. Time-structure maps are included in Part Two (DPA – Part 2, Ref. # 2.2.2.1). The conversion of time- structure maps into depth maps is described in the next section.

2.2.3 Depth Conversion

The method used for depth conversion involves the creation of a continuous interval velocity model in which interval velocity varies both spatially and as a function of the seismic two-way travel time. The thickness between two time samples is the interval velocity multiplied by half the time difference of the two samples. Thus to calculate the depth to a particular horizon, the thicknesses of all the time samples down to the horizon are merely summed. Smoothed interval velocities, derived from analysis of the seismic data, formed the basis of the velocity model which was then adjusted by calibration with the time-depth curves used in the synthetic trace generation referred to in Section 2.2.2 of this report. To avoid the uncertainties associated with deviated wells, this calibration used the time-depth curves from only the vertical and near vertical wells H-08, B-90 and M-79. The model was further modified by calibration to the Abenaki 6 sequence tops at all the well locations. Further details of the velocity model, together with the corresponding depth maps, are included in Part Two (DPA – Part 2, Ref. # 2.2.3.1).

2.2.4 Porosity Estimation

The amplitude of reflected sound waves from a boundary is a function of the difference in rock properties across that boundary and also the angle of incidence. Using sophisticated analysis of seismic traces, it is possible to extract a number of seismic attributes, of which amplitude would be an example, which relate to various rock properties. Attribute analysis was performed on the 3D dataset to see if an attribute or combination of attributes could be related to rock porosity at the well locations and hence used in estimating the porosity over the entire field. Several relationships were established, the details of which are provided in Part Two of this report (DPA – Part 2, Ref.# 2.2.4.1 and 2.2.4.2). The confidence in the estimated porosity increases with porosity, indicating that the seismic data is a better discriminator of the higher porosity zones within the reservoir than those of lower porosity.

Deep Panuke Volume 2 (Development Plan) · March 2002 2-25 2.3 Petrophysics

2.3.1 Modeling Overview

Full petrophysical evaluations have been completed on all Deep Panuke exploration and delineation wells in the Abenaki formation. Representative offset wells were modeled concurrently using a consistent physical model framework detailed in Part Two (DPA-Part 2, Ref. # 2.3.1.1 to 2.3.1.8).

Application software featuring a multimineral model framework (DPA-Part 2, Ref. # 2.3.1.9 to 2.3.1.13) employing a probabilistic numerical solver was used to determine most of the reservoir petrophysical parameters presented in this report. Specific attributes and models used vary from well to well in order to account for the variety of data, as well as the operational circumstances at time of recording.

Listings of logging-while-drilling logs, wireline logs and core data on which the models are described are found in the CNSOPB well history files for each well.

2.3.2 Lithology and Porosity

At Panuke, the Abenaki formation was laid down in a carbonate ramp system featuring a main reef buildup, associated fore- and back-reef, grainstone shoals and bounding lagoon and slope margin areas (DPA-Part 2, Ref. # 2.1.2.4 and 2.1.3.9). These carbonate rocks are composed predominantly of limestone and are occasionally dolomitized. Little argillaceous rock is present.

There are several expressions of porosity in the Abenaki carbonates. Primary porosity is intergranular in the limestones and intercrystalline in the dolostones. Vuggy and cavernous (in limestones) secondary porosity is important in reservoir quality rock. Both these porosity types are evident in the core, log data and well test data.

Figure 2.17 illustrates that the total porosity in the Abenaki formation, as determined from log data, ranges from 0.6 to 36 %, averaging approximately 4 %. The primary controls on porosity are rock fabric at the time of deposition, degree of dissolution, and dolomitization. These primary controls on porosity are further described in Part Two (DPA – Part 2, Ref. # 2.1.3.4).

Deep Panuke Volume 2 (Development Plan) · March 2002 2-26 Figure 2.17 Distribution of Modeled Total Porosity in the Abenaki Formation Penetrated by the Wells in the Study Area (Porosity is noted on the x-asis; cumulative number of occurrences on the y-axis.)

As shown in Figure 2.18, limited available core porosity data (DPA-Part 2, Ref. # 2.1.3.7) describes porosity distributions of 0.7 to 11 % averaging approximately 4 %. The lower range of porosity values from core data, as opposed to the total porosity modeled from logs and shown in Figure 2.17, is due to an under-representation of higher (>11 %) vuggy and cavernous porosity in the core data. This follows from operational difficulties and low success rates when sampling rock intervals, from the Abenaki formation, dominated by this porosity type.

Deep Panuke Volume 2 (Development Plan) · March 2002 2-27 Figure 2.18 Distribution of Core Porosity in the Abenaki Formation Penetrated by the Wells in the Study Area. (Porosity is noted on the x-axis; cumulative number of occurrences is noted on the y-axis.)

Porosity (and lithology) was modeled from sonic, density, neutron and photoelectric logs normalized for the borehole environment. Standard and special core analysis data was used for control on modeled total porosity and lithology.

2.3.3 Permeability

Modeled permeability described in Section 2.3.5, entitled “Reservoir Parameter Summaries”, is derived from an analytical model based on core porosity and permeability data. This analytical model is described in Part Two (DPA-Part 2, Ref.# 2.3.5.1).

Deep Panuke Volume 2 (Development Plan) · March 2002 2-28 Figure 2.19 Correlation between Core Porosity and Permeability of the Abenaki Formation Penetrated by the Wells in the Study Area

Core data describes significant intergranular/intercrystalline permeability development in reservoir rocks exhibiting greater than approximately 5 % porosity. Vuggy, cavernous and fracture permeability development evident in well test data as described in Section 3, is not well described in the core data.

2.3.4 Fluid Identification and Saturation Modelling

Water saturation values used to identify gas-water contacts at each well location were modeled using a dual-porosity/variable-m-exponent variation of the Archie equation more fully described in Part Two (DPA-Part 2, Ref.#2.3.4.1). This partly accounts for the scatter in the porosity-resistivity relationship,

Deep Panuke Volume 2 (Development Plan) · March 2002 2-29 otherwise attributable to the heterogeneous nature of the dissolution porosity encountered in the limestone and dolostone lithology.

Figure 2.20 is a plot of elevation vs. total porosity colored by bulk water volume (BVW = porosity x water saturation), which illustrates the regional gas-water contact for Deep Panuke area wells over the Abenaki formation. Hotter colours (red end of spectrum) identify data regions of higher gas saturation.

Figure 2.20 Correlation Between Porosity, Elevation and Gas Saturation of the Abenaki Formation Penetrated by the Wells in the Study Area

Formation water salinity is high, based on analyses of fluid samples recovered from wireline formation tests and production tests. Typically salinity is in the order of 100 kppm NaCl.

Deep Panuke Volume 2 (Development Plan) · March 2002 2-30 True formation resistivity was generally based on, as available, the long spaced 2Mhz logging while drilling resistivity measurement. As many resistivity logs were recorded under conditions of total losses of conductive drilling fluids into vuggy/cavernous porosity, invasion effects incorrectly bias modeled water saturation values towards high Sw values. Capillary pressure data described in Part Two (DPA- Part 2, Ref. # 2.1.3.7) was used to bound water saturation modeled from logs.

2.3.5 Reservoir Parameter Summaries

Net pay summaries for each well in the pool are described in Part Two (DPA-Part 2, Ref. # 2.3.5.1) and presented in Table 2.4.

Table 2.4 Deep Panuke Reservior Parameter Summary Panuke PP3-C K.B. 46.8 m Measured Depth Elevation Gross Net Average Average Zone Top Base Top Base Thick-ness Pay Porosity Sw (m) (m) (m ss) (m ss) (m) (m) (v/v) (v/v) Abenaki 6 3714.0 3916.0 3179.3 3362.0 182.7 0.0 - - Abenaki 5 3916.0 4052.0 3362.0 3487.8 125.8 44.6 0.24 0.28 Abenaki 4 4052.0 4150.0* 3487.8 3575.5 87.8 0.0 - - Total 3714.0 4150.0 3179.3 3575.5 396.3 44.6 0.24 0.28 Panuke PI1-A K.B. 46.5 m Abenaki 6 3661.0 3856.0 3176.5 3370.0 193.5 2.0 0.06 0.19 Abenaki 5 3856.0 3991.0 3370.0 3503.7 133.7 1.5 0.06 0.19 Abenaki 4 3991.0 4031.0* 3503.7 3543.3 39.7 0.0 - - Total 3661.0 4031.0 3176.5 3543.3 366.8 3.5 0.06 0.19 Panuke PI1-B K.B. 46.5 m Abenaki 6 3661.0 3861.0 3176.5 3368.7 192.2 0.0 - - Abenaki 5 3861.0 3995.0 3368.7 3493.1 124.4 13.9 0.07 0.08 Abenaki 4 3995.0 4025.0* 3493.1 3521.0 27.9 10.2 0.06 0.10 Total 3661.0 4025.0 3176.5 3521.0 344.5 24.2 0.07 0.09 Panuke H08 K.B. 39.2 m Abenaki 6 3296.0 3427.0 3256.7 3387.7 131.0 3.2 0.08 0.32 Abenaki 5 3427.0 3572.0 3387.7 3532.7 145.0 104.7 0.24 0.22 Abenaki 4 3572.0 3680.0 3532.7 3540.7 108.0 0.0 - - Total 3296.0 3680.0 3256.7 3640.7 383.9 108.0 0.23 0.22 Panuke F09 K.B. 39.9 m Abenaki 6 3246.0 3426.0 3143.5 3295.0 151.4 0.0 - - Abenaki 5 3426.0 3569.0 3295.0 3411.6 116.7 0.0 - - Abenaki 4 3569.0 3710.0 3411.6 3526.4 114.7 0.0 - - Total 3246.0 3710.0 3143.5 3526.4 382.8 0.0 - - Panuke M79 K.B. 47.0 m Abenaki 6 3250.0 3446.0 3202.6 3398.5 195.9 0.0 - - Abenaki 5 3446.0 3571.0 3398.5 3523.3 124.8 0.0 - - Abenaki 4 3571.0 3706.0 3523.3 3658.2 134.8 0.0 - - Total 3250.0 3706.0 3202.6 3658.2 455.6 0.0 - - Panuke M79-A K.B. 47.0 m Abenaki 6 3248.0 3484.0 3200.3 3378.2 177.9 0.0 - - Abenaki 5 3484.0 3934.0* 3378.2 3445.3 67.1 11.4 0.10 0.05 Total 3248.0 3934.0 3200.3 3445.3 245.0 11.4 0.10 0.05 * Last petrophysical evaluation depth

Deep Panuke Volume 2 (Development Plan) · March 2002 2-31 Porous, permeable gas-bearing rock is netted out based on porosity (>0.05), lithology (=carbonate), water saturation (<0.40) and thickness (>1m) cutoffs. These intervals also correlate well to gas producing intervals from well tests.

2.3.6 Future Data Acquisition Strategy

During the pre-development and development phases, data acquisition plans will be directed toward refining the field model and reducing uncertainties around the size of the pool in order to maximize recovery and value.

Logging while drilling and/or wireline recordings of sonic, density/neutron and resistivity will be recorded as a standard over the reservoir section where practical and safe to do so. However, formation and fluid sampling will be carried out, and image logs run to meet the goals of further data acquisition plans. Cased hole production monitoring logs will also be run as required to monitor reservoir performance.

Deep Panuke Volume 2 (Development Plan) · March 2002 2-32 3 RESERVOIR ENGINEERING

Reservoir engineering is an integral part of the Reservoir Management Plan for Deep Panuke. All subsurface data whether known, inferred, or calculated are combined to create an understanding of the reservoir description and the fluid it contains. This description is used to predict fluid off-take with time under specific reservoir and operating conditions. Coupling these understandings into most likely scenarios is done through a Reservoir Management Plan.

Generally, the fluid flow models utilize pre-development data and data from existing analogue pools within the basin. As this is the first carbonate development in this basin, analogue data is non-existent. As further information becomes available through additional drilling, and information from other newly discovered pools within the basin are made public, PanCanadian’s understanding of the Deep Panuke reservoir will change. Also, ongoing production from Deep Panuke will provide additional insight into the reservoir model. This is a natural progression of the reservoir management process; considerations for refinement of the model must be included in any development plan.

The following sections describe the information compiled and used in the development of the Reservoir Management Plan for Deep Panuke, and the resulting production forecasts. Finally, a discussion on reservoir management philosophy is included.

3.1 Reservoir Data

3.1.1 Reservoir Description

Within the Panuke Production license, gas has been identified in the Abenaki 4 and Abenaki 5 sequences.

The Abenaki 4 sequence has been penetrated by two wellbores and contains a relatively small volume of gas underlain by water. It is not considered economic at this time.

The hydrocarbon bearing sequence is the Abenaki 5. All current wells drilled in Deep Panuke have penetrated the Abenaki 5, although not all have been tested. Four wellbores are currently suspended in the Abenaki 5 formation.

Deep Panuke Volume 2 (Development Plan) · March 2002 3-1 Table 3.1 Drill Stem Test Data Depth Test Reservoir Max Gas Condensate Water Ratio DPA- Part 2 Well Zone (mTVD) # Pressure Rate Ratio (m3/E6m3) Reference (kPa) (E3m3/D) (m3/E6m3) DST PP3C AB 5/4 3475.7 2 36510 1690 8.1 10.0 3.1.2.1 PP3C AB 5/4 3475.9 4 36440 1650 12.0 20.0 3.1.2.1 PI1B AB 5 3454.6 2 36768 1490 12.5 8.3 3.1.2.2 H-08 AB 5 3448.0 1 36355 1450 6.9 17.5 3.1.2.3 M79A AB 5 3355.5 1 36310 1790 20.0 6.3 3.1.2.4

MDT PI1A AB 5 3489.1 18 36630 2.1.5.1 AB 5 3502.5 13 36655 2.1.5.1 AB 5 3504.4 12 36671 2.1.5.1 AB 4 3562.4 10 36857 2.1.5.1 AB 4 3566.9 9 36901 2.1.5.1 AB 4 3569.8 8 36922 2.1.5.1 AB 4 3573.8 7 36954 2.1.5.1 AB 4 3579.3 6 37004 2.1.5.1 AB 4 3582.2 5 37038 2.1.5.1 AB 4 3584.2 4 37047 2.1.5.1 AB 4 3588.2 3 37324 2.1.5.1 M-79A AB 4 3636.3 58 37541 2.1.5.1 AB 4 3648.5 49 37665 2.1.5.1 AB 4 3652.0 48 37702 2.1.5.1 AB 4 3653.5 47 37712 2.1.5.1 AB 4 3655.0 64 37742 2.1.5.1 AB 4 3663.0 43 37811 2.1.5.1 AB 4 3678.6 39 37969 2.1.5.1 AB 4 3679.5 37 37969 2.1.5.1 AB 4 3680.5 36 37990 2.1.5.1

Deep Panuke Volume 2 (Development Plan) · March 2002 3-2 3.1.2 Well Test Data

Drill Stem Tests (DST) and Modular Dynamic Tests (MDT) have been conducted on most wells in the Abenaki 5 and Abenaki 4. Only one well in the Abenaki 4 has a DST. A compilation of this information is included below in Table 3.1 with appropriate references back to Part Two.

Flow and buildup times for each DST varied depending on specific well testing objectives. In addition, testing configurations change with changing wellbore configuration. Two wells encountered lost circulation, which required the application of special completion and testing techniques and altered the temperature profile near the wellbore and zone of interest. These wells tended to have higher gas water ratios during test. One well was drilled, completed, and tested in a horizontal configuration.

Wellbore configuration, gauge placement, surface shut-in, and wellbore thermal effects from seawater injection during lost circulation events create uncertainty in some of the near wellbore pressure response and subsequent interpretations. In addition, temperature differences at the wellbore before and after main flow testing make it difficult to compare final shut-in pressure at sandface before and after testing.

The skin factors calculated in most tests are high, with a large component associated with turbulence. Most of this turbulent skin is wellbore and completion based. The installation of an appropriate production string and stimulation of the wellbores will eliminate some of this damage. This is discussed further in Section 3.3.

3.1.3 Core Analysis and Special Core Analysis

Core and sidewall cores were collected from many of the Panuke wells in the reservoir and adjacent zones. See Table 3.2 for a summary of samples collected.

Table 3.2 Core Sample Intervals Well I.D. Core Interval Sidewall Core Interval Recovery H-08 3446-3460 m 3.2 m F-09 3264-3798 31 plugs PI-1a 4029.28-4040 m 1.15 m PI-1a 3895-4034 m 44 plugs M-79 4532.7-4538.7 m 5 m M-79 3348-4591 m 98 plugs

Deep Panuke Volume 2 (Development Plan) · March 2002 3-3 Routine core analysis was done on most samples and was used along with lithological descriptions and petrography to develop an understanding of the relationships between primary the depositional environment, diagenesis, and porosity development. That relationship is discussed in Section 2.1.3. Routine core analysis data is available in the CNSOPB files.

The relationship between permeability and porosity was examined in order to develop a relationship to be used in estimating permeability away from the wellbore. The cross-plot of porosity versus permeability was similar to that generated by F.J. Lucia for his Class 2 grain dominated packstone to medium crystalline mud dominated dolopackstone fabrics; hence the Class 2 transform was applied to the porosity models to estimate permeability (DPA – Part 2, Ref.# 3.1.3.1). The divergence at higher porosity values is probably due to the presence of vuggy porosity at Deep Panuke. Figure 3.1 illustrates the relationship between porosity and permeability in the Panuke cores.

Figure 3.1 Porosity versus Permeability Relationship, Deep Panuke

Deep Panuke Volume 2 (Development Plan) · March 2002 3-4 During the drilling process, seawater was injected in high permeability, lost circulation zones in order to control the wells. It was important to evaluate if damage had been done to the reservoir during this process. Special core analysis was conducted on selected cores to determine the amount of permeability regain and to determine capillary pressure for the pool. Core intervals evaluated are listed in Table 3.3 below.

The results of the special core analysis used in modeling the field are described in Part Two (DPA – Part 2, Ref #. 2.1.3.7). These analyses indicated that permeability regain is possible, and that the extent of the regain is a function of the pressure drop across the impacted rock.

Table 3.3 Special Analysis Intervals Type of Analysis Well I.D. Number of Samples Permeability Regain H-08 6 Mercury Capillary Pressure H-08 15

3.1.4 Reservoir Fluid Properties

Wellhead gas and separator condensate samples were recovered during testing operations. These samples were recombined analytically, based on flowing conditions and gas condensate ratios.

The gas from Deep Panuke is very lean with relatively low levels of H2S (0.2%) and minor amounts of

CO2 (3.6%). Recombination analyses are included in Table 3.4.

No retrograde behavior is expected of the Deep Panuke gas at the reservoir temperature of 123 oC. Some condensate dropout may occur in the tubular and subsurface flow lines prior to separation and processing. The calculated condensate: gas ratio for this gas is approximately 28m3/E6m3.

Table 3.4 Fluid Analysis Summary PP-3C PI-1B H-08 M-79A Well Sample Mole Percent Mole Percent Mole Percent Mole Percent HE 0.02 0.02 0.02 0.03 N2 0.68 0.81 0.82 0.84 CO2 3.37 3.43 3.51 3.59 H2S 0.06 0.20 0.09 0.30 C1 91.41 90.97 90.62 90.72 C2 2.81 2.74 2.87 2.76 C3 0.87 0.85 0.91 0.87 IC4 0.13 0.13 0.14 0.13 NC4 0.23 0.21 0.24 0.22 IC5 0.07 0.07 0.08 0.07 NC5 0.07 0.06 0.07 0.07 C6 0.03 0.08 0.09 0.06 + 0.25 0.43 0.53 0.34 C7

Deep Panuke Volume 2 (Development Plan) · March 2002 3-5 3.2 Reservoir Simulation

Reservoir simulation studies for Deep Panuke have been conducted using Eclipse 100, a fully implicit, non-thermal, full field scale simulator. Reservoir simulation models were imported from Stratamodel and upscaled to allow efficient run-time without sacrificing reservoir performance predictions.

Wellbore and subsea tieback pipelines have been modeled using ProFES and Pipesim 2000. ProFES is an integrated software environment that addresses flow assurance challenges such as multiphase flow simulations for wells and pipelines, enabling integration of engineering data and tools and allows access to process simulators for steady state and dynamic analysis.

Pipesim 2000 is a steady state, multiphase flow simulator for oil and gas production systems including completion design, tubing performance and subsea pipeline modeling. Pipesim 2000 was coupled with the Eclipse 100 simulator to fully integrate reservoir, tubular and pipeline flow characteristics.

Deep Panuke subsurface technical data has been consolidated and a reservoir model generated using the Stratamodel software by Landmark. Data includes regional and local geological concepts, diagenetic studies, stratigraphic and structural information, sedimentological, petrophysical and special core information. Siesmic attribute transforms were used to describe porosity distributions within the reservoir. Numerous models were developed through these techniques and upscaled through Stratamodel into Eclipse. The reservoir performance model represents a most likely probabilistic result of these models. Porosity distributions around each well were scaled to be consistent with spatial storativity interpretations from the welltest analysis.

As new data becomes available, both regionally and locally, the reservoir simulation model will be modified and refined.

At such an early stage in the Project, reservoir and pipeline modeling describes the uncertainty in the flow attributes of the model that impact reserves recovery. Pool off-take rates, recovery, water encroachment, well numbers, well location and completion designs and pipeline specifications are the primary areas where uncertainty exists and, therefore, must be described. Additional development wells will be targeted to help reduce and minimize the more significant uncertainties.

3.2.1 Integrated Surface-Subsurface Simulation

Integrated surface and subsurface modeling enables the physical performance of the entire system to be predicted during the production lifetime. Operational targets are a constant production rate of 11.3 E6m3/D (400 MMscfd) of sales gas to the M&NP custody transfer point. Compression upstream of the facilities inlet has also been included in the integrated simulation model.

Deep Panuke Volume 2 (Development Plan) · March 2002 3-6 Two wells, H-08 and M-79A, are modeled using a subsea gathering system tied back to the production platform. All other wells are modeled as being drilled from the Deep Panuke wellhead jacket.

Utilizing these constraints, completion designs, tubular and pipeline sizing as well as individual well off- takes were varied to maximize production output with minimal pressure losses. More discussion on completion design and pipeline sizing can be found in Section 4. Well test pressure drops from sandface to gauge bundle carriers were calculated using Pipesim 2000, with appropriate adjustments to flowing sandface pressures and residual skins. This work identified completion, tubular and pipeline pressure drops to be the major influence on inflow performance and recovery.

3.3 Project Plan Development

The integrated production model, including reservoir, tubing and pipeline descriptions, was used to model a distribution of resource sizes and reservoir realizations. The most likely scenario is included in this report. A more detailed discussion of these reviews is included in Part Two (DPA – Part 2, Ref. # 3.3.1).

The most likely scenario requires four additional wells to be drilled: two to replace the PP-3C and PI-1B wellbores, and the other two as additional development wells. A review of lost production capability due to well downtime may justify the drilling of an additional development location, or the drilling of multilateral well bores. The total number of wells may be altered depending on drilling results and production performance.

Figure 3.2 provides the sales gas production forecast for Deep Panuke. Compression is not required until late in year 3, and may be delayed depending on individual inflow potential from the producing wells. Longer-term pool performance will also depend on connectivity of high permeability systems to the lower permeability reef matrix and contributions from back-reef facies.

Deep Panuke Volume 2 (Development Plan) · March 2002 3-7 450

400

350

300

250

200

Million Cubic Feet per Day 150

100

50

0 0 2 4 6 8 10 12 14 Production Year

Figure 3.2 Sales Gas Production Forecast

Current reservoir description predicts gas water contact along the front, northern and southern edges of the reef structure. Figure 3.3 shows the associated water production forecast. The vertical and horizontal distances between wellbores and the gas water contact is the main factor considered in determining water production. Based on initial simulation models the aquifer size and proximity to Deep Panuke reserves is not expected to significantly impact operational issues or recovery. However, additional work will be done to identify potential variations and distributions to the regional aquifer. The Reservoir Management Plan will incorporate strategies to better identify aquifer support and encroaching water in the more critical areas of the pool.

Deep Panuke Volume 2 (Development Plan) · March 2002 3-8 300

250

200

150 Cubic Meters per Day 100

50

0 0 2 4 6 8 10 12 14 Production Year

Figure 3.3 Water Production Forecast

3.4 Reserves

The resource base of “original gas in place”(OGIP) was derived from the statistical distribution of the models generated and the uncertainty analysis described in Part Two (DPA – Part 2, Ref. # 2.1.6.1 and 2.1.8.1). The models were then loaded into a flow simulator and recovery factors derived to give a probabilistic estimate of recoverable gas. The reserve distribution for the Deep Panuke field is provided in Table 3.5.

Table 3.5 Probabilistic Reserves P10 P50 P90 Expected Value Expected Value Field OGIP OGIP OGIP OGIP SGIP 9 3 9 3 (E9m3) (E9m3) (E9m3) (E m ) (E m ) Abenaki 5 43.7 31.0 22.0 33.0 26.3 Notes: P = 90 % probability of equal or greater than value 90 P = 50 % probability of equal or greater than value 50 P = 10 % probability of equal or greater than value 10 OGIP = Original Gas in Place SGIP = Sales Gas in Place

Deep Panuke Volume 2 (Development Plan) · March 2002 3-9 3.5 Reservoir Management Philosophy

Reservoir management is an evergreen process, starting with the identification of a commercial development and continuing through to abandonment and reclamation. The projection of field performance and acceptable performance tolerances, the monitoring of actual performance, and the identification of contingency actions are the building blocks of a successful depletion plan.

Identification of appropriate data to monitor performance and assess contingencies is fundamental to a sound Reservoir Management Plan. This data includes daily pressure, temperature, production numbers, and fluid compositions. Additional information will be acquired as needed to address specific questions or uncertainties. This data includes pressure transient analysis, production logging, MDT, DST, and other open hole or cased hole logs.

In addition to managing expected production volumes and rates at the field and well level, it is also critical to manage resource depletion within the total field. History matching production data and any additional information with the current reservoir model develops an understanding of resource definition within the reservoir and its subsequent depletion patterns. Model changes will occur to account for energy balances and fluid movements within the reservoir. Changes to resource and recovery factors are reviewed with the goal of optimizing recovery of the total system.

Enhancements to the reservoir model honour the original input data while incorporating new dynamic and static data. Recharacterisation of the reservoir model requires a multidisciplinary team to incorporate this new data in an effective manner. In addition to the conventional input received from subsurface geoscience and engineering team members, contributions from wellbore, pipeline, compression and facilities team members become critical in understanding total system performance and identifying bottlenecks to the system.

This multi-disciplinary team will recommend adjustments to the Reservoir Management Plan and take remedial action where appropriate. This may include additional drilling, recompletions or infrastructure upgrading.

The development of a multidisciplinary asset management team and management plan will be a focus of future work, prior to commencement of production.

Deep Panuke Volume 2 (Development Plan) · March 2002 3-10 4 WELL CONSTRUCTION

Since the discovery of the Deep Panuke gas reservoir in 1998, several delineation wells have been drilled. The discovery well and three of the delineation wells were suspended for potential future re- entry with the remaining wells abandoned. PanCanadian’s current plan is to evaluate the option of completing two of the suspended wells as subsea tiebacks and to drill approximately three to four new production wells and one to two injection wells from the new wellhead platform. If further reservoir analysis concludes the need for additional off-take points within the formation, the number of wells may be increased in order to optimize resource recovery. This Section details the overall construction (drilling and completion) of the wells to be used for the Project.

4.1 Strategy

The development of well construction plans for the Project is guided by a desire to minimize risk and costs associated with the initial drilling and completion and future operations of all wells. Technological developments that could enhance well construction will be considered as the Project progresses. Some future technological options could include intelligent completion wells, multi-lateral wells, and extended reach wells.

All platform-based wells for the Project will be constructed using a cantilever jack-up rig that is equipped with appropriately sized blow-out preventers (BOPs). The subsea tieback wells could be constructed using either a cantilever jack-up or possibly a small semi-submersible drilling rig. The 100- year storm criteria within the Project location establishes minimal acceptable rig design and thus limits overall selection. All completion and workover operations will utilize either a large drilling rig or equipment, such as coiled tubing or wireline units, present and certified on the rig. An exception would be skid-mounted units that could be placed on the platform or a service vessel. Operating procedures, industry guidelines and certification requirements will be followed for all equipment.

The contracting strategy for tubulars, wellheads, trees, flowlines and services will likely be based on enhanced supplier relationships. Synergy may be possible with contractors and suppliers already operating off the East Coast for items such as workboats and helicopters, particularly in conjunction with PanCanadian’s exploration activities. Some of the additional selection criteria for well construction contractors will be based on their experience with annular velocity control (AVC) drilling techniques in offshore wells, technical ability, cost, benefits, and health, safety, and environment (HSE) considerations.

Specific safety issues for well construction will be considered in the Project’s Safety Plan (see Section 9). These safety issues include the development of procedures to be followed during simultaneous operations, such as drilling and production.

Deep Panuke Volume 2 (Development Plan) · March 2002 4-1 During some periods of well construction operations, the potential exists that only one rig may be operating in the Scotian Shelf area. Agreements will be established with the CNSOPB for a contingency plan should relief well drilling be necessary. Casing, wellhead, and mudline suspension equipment will also be available for control of a blowout situation. The likelihood of this scenario is remote.

All manuals and drilling programs will be completed, and approvals obtained, prior to the proposed well construction start date for the Project. A tentative schedule has been developed for the timing and completion of the activities, and the acquisition of critical components. Figure 4.1 illustrates the currently proposed well construction schedule.

2000 2001 2002 2003 2004 2005 Pre-Development Analysis FEED Subsea Analysis Corrosion Study Completion Philosophy DPA Preparation Detailed Engineering Procurement Manufacture Rig & Services Wellheads & Trees Tubulars Downhole Components Operations Pre-Planning Manuals Programs Approvals Offshore Operations

Figure 4.1 Tentative Well Construction Schedule

Deep Panuke Volume 2 (Development Plan) · March 2002 4-2 4.2 Exploration and Delineation Wells

The Deep Panuke gas reservoir was discovered in late 1998, with the original discovery well, PP-3C, drilled from the Panuke platform using the jack-up/drilling production unit, Rowan Gorilla III (RGIII). This well discovered a highly fractured, highly porous carbonate formation, which led to significant loss circulation problems during drilling. The discovery well was eventually cased, tested and then suspended. Following this discovery, a delineation well and its sidetrack, PI-1A/B, were drilled from the Panuke platform in late 1999. The sidetrack, PI – 1B, was tested in early 2000 and then suspended.

In May 2000, following rig re-certification, the RGIII moved to a new location and drilled the third delineation well, H-08. This vertical well found a substantial pay zone of gas and the well was tested and suspended. Concurrently, the Rowan Gorilla V (RGV) moved to drill the final delineation well and sidetrack, M-79/A. The RGV drilled the deepest vertical well through the Abenaki reef to date, but the well was not tested. The main wellbore was plugged back and a sidetrack was initiated by milling a window near the bottom of the 245 mm casing. The sidetrack was drilled to almost horizontal and it was cased, tested and then suspended.

Figure 4.2 shows the relative locations of the existing wells and Figure 4.3 shows the composite drilling curves for the existing wells. Table 4.1 lists details of the existing wells.

Deep Panuke Volume 2 (Development Plan) · March 2002 4-3 Panuke License M-79 Panuke Platform PI-1A

PI-1B M-79A

PP-3C

H-08

1 0 2 KILOMETER KILOMETER 0 1 2 MILES MILES

Figure 4.2 Exploration and Delineation Wells

Deep Panuke Volume 2 (Development Plan) · March 2002 4-4 Depth vs. Time For Deep Panuke Wells 0

500

1000

H-08 1500 PI-1A/B

2000 M-79A

PP-3C 2500 Depth (m)

3000

3500

Abenaki Limstone (3400)

4000

4500

5000 0 20 40 60 80 100 120 140 Time (days)

Figure 4.3 Delineation Wells, Composite Drilling Curves

Deep Panuke Volume 2 (Development Plan) · March 2002 4-5 Table 4.1 Exploration and Delineation Wells - Summary Information Well Name Year Drilled Status Total Depth1 PP-3C (Discovery Well) 1998 Suspended 4163 m PI-1A 1999 Abandoned 4033 m PI-1B 2000 Suspended 4046 m H-08 2000 Suspended 3645 m M-79 2000 Abandoned 4598 m M-79A 2000 Suspended 3934 m 1 Measured Depth below the Rotary Table (RT)

4.3 Development Drilling

Subject to further engineering in regard to existing wellbores, and revisions to the Reservoir Management Plan, the drilling activities for the Project will be limited. PanCanadian’s current plan involves directionally drilling approximately three to four additional new production wells and at least one, and possibly two, injection well(s) from the wellhead platform. Preliminary detailed engineering will determine the feasibility of using the two suspended delineation wells as subsea tiebacks, to the wellhead platform, through the use of mudline conversion, horizontal production trees with flowlines and umbilicals. The number of wells may be altered depending on drilling results and production performance.

4.3.1 Tentative Drilling Schedule

The current plan is to start well construction activities in early 2004 to enable full production to be available by the time the facilities and pipelines are commissioned in 2005. During this time, the selected rig will re-enter the suspended subsea wells, perform any necessary remedial work, install the completion string, and prepare the wells for tie back to the production facility. Also, all additional new platform wells will be drilled and completed. This schedule may change based on PanCanadian’s exploration activities, and availability of existing equipment and services. Figure 4.1 provides a preliminary overall well construction schedule.

4.3.2 Drilling Hazards

Extensive drilling experience within the area of the Panuke license provides an excellent understanding of the well construction hazards. The two primary areas of concern when dealing with any wells in the

Abenaki reef structure are the potential for loss circulation problems and the hydrogen sulphide (H2S) content of Deep Panuke gas. While these operational difficulties were dealt with appropriately during the drilling of the discovery and delineation wells, they must be appropriately accounted for during any well construction activity. Other more routine drilling hazards could include hole instability, shallow gas and differential sticking. These hazards are described in more detail below.

Deep Panuke Volume 2 (Development Plan) · March 2002 4-6 4.3.2.1 Loss Circulation

While drilling into a highly fractured/highly porous carbonate formation, it is sometimes difficult to maintain circulation. This condition was encountered during the drilling of the discovery well, PP-3C, where it was determined that the formation would only support a mud density of approximately 10 kg/m3 more than the wellbore fluid ingress density required to keep formation fluids in place. Therefore, a wellbore that would stand full of drilling mud would begin to lose fluid as soon as circulation began due to annular pressure loss. To overcome this problem, PanCanadian developed a drilling method called the annular velocity control (AVC) drilling technique. The AVC technique employs stripping and snubbing equipment to maintain dynamic well control by pumping down the well with seawater at a rate that is higher than the gas migration rate up the wellbore.

4.3.2.2 Hydrogen Sulphide (H2S)

H2S was encountered during all well tests from the discovery and delineation wells, but none was detected during the drilling of any of these wells. Through proper drilling practices and the application of appropriate HSE procedures and policies, the exposure of well construction operations to the H2S risk will be managed safely.

4.3.2.3 Shallow Gas

A shallow gas deposit could cause uncontrollable well flow before adequate casing is set to allow use of a BOP system to divert the gas flow. Although some site surveys have indicated the possibility of shallow gas on the Panuke license, it has not been encountered in any of the wells drilled on the Panuke license to date. Detailed site surveys of the proposed new platform location will be performed prior to detailed engineering. Therefore, the new wellhead platform will be positioned to ensure no danger of shallow gas.

4.3.2.4 Hole Instability

Hole instability problems result in extended drilling times and increased costs, but do not pose a hazard to personnel, equipment or the environment. Inhibited water-based and oil-based (low-toxicity mineral oil (LTMO) and synthetic based) drilling fluid systems will be used to reduce hole enlargement in the reactive shales that will be encountered while drilling Project wells. On previous wells, hole instability was more severe in highly deviated wells and resulted in drilling delays.

Deep Panuke Volume 2 (Development Plan) · March 2002 4-7 On the Cohasset Project, KCl-polymer drilling fluid was used on the main hole of the four original Panuke wells with limited success, especially on the higher angle hole sections. Once the rig commenced drilling at the Cohasset location, invert LTMO drilling fluid was used, which dramatically improved hole conditions, including substantial improvements in hole gauge. The main hole of the discovery and first delineation wells for Deep Panuke also used LTMO drilling fluid with no hole instability difficulties noted.

On high-angle wells, the formations will be exposed to drilling for longer periods of time and hole instability will be accentuated. Hole cleaning issues could become significant if hole instability increases. The use of oil-based mud helps to alleviate these problems, as proven during the drilling of the Cohasset development wells.

4.3.2.5 Abnormal Pressure

Abnormal pressures are not expected throughout the Abenaki Reef. Reservoir pressure in the Abenaki 5 is approximately 37 MPa.

4.3.2.6 Well Control

As described above in Section 4.3.2.1, well control is of primary concern due to the very tight pore pressure / kick tolerances within the reservoir. The discovery well (PP-3C) experienced significant loss circulation that was eventually killed using a seawater bullheading technique. The probability of well control incidents or uncontrolled kicks is low through the utilization of PanCanadian’s tripping, drilling and AVC techniques.

4.3.2.7 Differential Sticking

Differential sticking across the hydrocarbon zones may occur in high-angle wells. Tight control of drilling fluid properties and good tripping practices will minimize this problem.

4.3.2.8 Directional Control

Direction will be closely controlled using the latest measurement-while-drilling (MWD) technologies on the additional development wells. Likewise, locating existing wells is not a concern due to accurate records and tight directional control techniques used during the previous drilling of these wells.

Deep Panuke Volume 2 (Development Plan) · March 2002 4-8 4.3.3 Drilling Details

This section presents the well design based on experience from existing Deep Panuke discovery and delineation wells. The well design will evolve over the life of the Project and the field to take advantage of equipment development, new techniques and drilling experience. The detailed design specifications will be submitted with the Drilling Program prior to the spud of each well in accordance with CNSOPB Regulations.

4.3.3.1 Casing and Hole Sizes

The stand alone delineation wells (H-08 and M-79/A) used 762 mm casing that was cemented in a drilled 914 mm hole section to approximately 90 m below the seafloor. For new Project wells, the conductor will likely be 610 mm casing set by using the drill and drive method. The existing wells, H-08 and M-79A were drilled and cased using conventional hole and casing sizes as described below. See Part Two for existing casing and cementing details. (DPA-Part 2, Ref. # 4.3.3.1)

The normal drilling program for the Deep Panuke wells will involve conventional hole and casing sizes. A 444.5 mm intermediate hole is drilled and 339.7 mm casing run and cemented. The setting depth of the surface hole is usually into the Wyandot Chalk at about 920 m True Vertical Depth (TVD). Historically, this provides pressure integrity greater than an equivalent mud density of 1680 kg/m3. A 311 mm main hole is then drilled to near the top of the Abenaki Formation. The 244.5 mm production casing would be set at this point. A 216 mm main hole would then be drilled to total depth (TD) and completed. One of the key concerns for the Deep Panuke wells is corrosion of the tubulars. Corrosion issues will be mitigated through the use of proper metallurgy in all components.

All casing designs are based on CNSOPB drilling regulations and can be found in Part Two. (DPA-Part 2, Ref. # 4.3.3.2)

4.3.3.2 Drilling Fluid Program

The drilling fluids used will be optimized to reduce fluid loss and provide hole cleaning, well control and hole stability. The drilling fluid program will be similar to that used on the past exploratory and delineation wells. It is planned that water-based mud (WBM) will be used for the top intervals of the well to the surface casing setting depth. Oil-based mud (OBM) systems consisting of a base fluid of either LTMO or synthetic oil (SBM) may be used for the intermediate and main holes to stabilize them, minimize formation damage and maximize drilling efficiency (the use of the fluid type can depend upon hole angle). Formations in directional wells will be exposed to drilling for longer periods of time, which increases the risk of hole instability.

Deep Panuke Volume 2 (Development Plan) · March 2002 4-9 OBMs are the most reliable methods of managing hole stability, while also providing lubricity to lower drilling strong torque and drag. OBMs used in the North Sea have improved drilling performance and reduced hole instability significantly. Inhibited WBM systems, such as a glycol drilling fluid will also be considered depending on well design.

When LTMO or SBM fluids are used, an existing disposal method or any new proven technological development will be used conforming to CNSOPB cuttings disposal regulations.

4.3.3.3 Cementing Program

The cementing program is expected to be similar to that used for the exploratory and delineation wells. The conductor will be cemented at its toe, since it will be installed using the drill and drive process. The surface, intermediate and production casing will be cemented high enough to prevent future casing instability and to isolate permeable zones. To ensure a leak-off path for trapped-fluid expansion during production, intermediate and production casings may not be cemented into the previous shoe. The liner may be fully cemented or left as an uncemented completion. External casing packers and stage tools may be used in high loss circulation situations to isolate the highly porous zones, if cementing is performed. The cementing program will be designed to ensure containment of the acid gas within the reservoir and minimize corrosion issues. If the liner is not cemented in place, proper metallurgy and liner top packers will ensure containment of the reservoir fluids to ensure a safe production wellbore.

4.3.3.4 Well Control System

The selection of the BOP configuration will be part of the rig evaluation process. Typically, a 346 mm, 103 MPa (or 69 MPa) BOP equipped with four rams and an annular preventer will be installed on a 508 mm wellhead and used for the remainder of the well. In addition, a snubbing unit and rotational BOP may be installed for the sections drilled using the AVC method.

4.3.4 Directional Drilling

High hole angles (up to horizontal) may be used in the pay zone if increased productivity can be realized. Kick-off elevation and well profiles will be customized for each well. High hole angles may also be used to minimize the possibility of encountering low quality reservoir rock since longer intervals of the reservoir will be exposed.

Mud pulse telemetry directional tools will be used for directional control. The survey intervals and the type of surveying system used will be sufficient to assure entry into the target, while avoiding collision with adjacent wells, and providing adequate wellbore positioning information to reliably target a relief well.

Deep Panuke Volume 2 (Development Plan) · March 2002 4-10 4.4 Well Completions

4.4.1 Design Philosophy

For the Project, PanCanadian will use completion systems that are simple, reliable, economic and meet all requirements for the corrosive environment in which they will be placed. The completions will be designed with minimal need for intervention as one of the key drivers. The tubing string will likely be a combination of 178 mm, 127 mm and 114.3 mm sizes for a tapered conventional completion string or 177.8 mm tubing for a monobore completion string for the production wells. The injection well(s) will likely use a 88.9 mm or 114.3 mm tubing string. Figures 4.4 and 4.5 provide a schematic example of the production well and injection well.

Some of the production and injection objectives considered in the completion design are:

· ensure operational safety; · keep completions as simple as possible; · minimize the number of wells while maximizing recovery and effectively depleting the reserves; · design completions to ensure that downtime is minimized, including workovers; · maintain a surplus in deliverability to mitigate production downtime due to workovers or suspended wells; and · maintain the flat-life production of the Project as long as possible.

4.4.2 Tubing Design

The tubing size will be maximized so that wellbore deliverability is not minimized by tubing- constraints. Tubing size is limited by the outside diameter (OD) of the subsurface safety valve (SSSV) that will fit in the production casing. The tubing design must provide a flow conduit consistent with the inflow performance of the completed reservoir for the life of the field. The injection well will also be designed so that the tubing string does not provide pressure constraints.

Deep Panuke Volume 2 (Development Plan) · March 2002 4-11 ProductionTree andWellhead Pipingto Processing

SEA LEVEL

SEAFLOOR

+ 100 m BelowSeaFloor 24" Conductor

Sub-SurfaceSafetyValve

+ 900 m BelowSeaFloor 13-3/8" Surface Wyandot Formation

7”Tubing

Downhole Press. & Temp. Gauge LinerHangerandPackerwith PolishedBoreReceptacle(PBR)

+ 3200m BelowSeaFloor 9-5/8" Production

Flow Control

+ 3450 m BelowSeaFloor

DeepPanuke-Abenaki ReefProductionZone

P:\EnvSci\15xxx\15999PanCan\500RASCoordination\DevelopmentPlanApplication\DPAReportJanuary\Figures\Fig4_4.cdr Figure4.4TypicalProductionWellSchematic WELLHEAD& INJECTIONTREE

ACIDGAS COMPRESSOR

PIPINGFROM PROCESSING WELLHEADJACKET FACILITY

SEALEVEL

SEAFLOOR

±100mBelowSeaFloor 24”CONDUCTOR

BANQUEREAU SUBSURFACESAFETYVALVE

±1000mBelowSeaFloor

13-3/8”CASING

WYANDOT 3-½”TUBING

±2300mBelowSeaFloor

INJECTION

Perfs ZONE

NOTTOSCALE 9-5/8”x7”CASING

P:\EnvSci\15xxx\15999PanCan\500RASCoordination\DevelopmentPlanApplication\DPAReportJanuary\Figures\Fig4_5.cdr Figure4.5TypicalAcidGasInjectionWellSchematic The casing-tubing configurations to be used for the subsea wells, if completed, will be conventional completions, while the new platform wells will be either conventional or monobore completions. Conventional completions have production casing/liner across the zone of interest. Production tubing in conventional completions is smaller than the casing across the pay zone.

The monobore completion technique is an alternative to conventional completions. This style has production casing set at the top of the zone and uses a liner with a tie back packer to case the zone. Tubulars, downhole equipment, and trees are sized so that all equipment has a similar internal diameter. This concept will be investigated for the new drill wells.

The design of the tubing connections will likely incorporate the following:

· primary metal-to-metal seals; · multiple seals; · internal flush bore to prevent turbulence and corrosion; · high strength to withstand combined stresses; · minimum outside diameter; and · proven reliability with make-up/break-out history, particularly with respect to the design metallurgy.

Where practical, one size, weight, grade, and connection will be used for each tubing string. This will minimize inventory and prevent the use of improper materials. Design limits for production tubing will meet or exceed the minimum tolerances of burst, tension and collapse, as calculated for the influence of combined stress under expected operating conditions. Final selection of the tubular connection will adhere to a connection qualification program that meets industry standards.

4.4.3 Metallurgy

Careful consideration will be given to the materials used for tubulars, wellhead and downhole equipment because of exposure to corrosive fluids. Due to the presence of H2S, CO2 and chlorides, high alloy steel or CRA (Corrosion Resistant Alloy) material may be required for tubulars and downhole equipment, and a corrosion resistant cladding may be required for wellhead equipment. Both production and injection wells will require detailed attention to the type of materials used for all components. PanCanadian is undertaking a study to determine the corrosion potential of the producing environment, and to determine suitable material and operational guidelines

Deep Panuke Volume 2 (Development Plan) · March 2002 4-14 4.4.4 Downhole Equipment

The use of downhole completion tools will be minimized to reduce workover potential and wellbore complexity. The corrosive environment may reduce the performance of any equipment in the wellbore.

The current design has tubing retrievable SSSVs installed (with the ability to lock open and insert a wireline-retrievable (WR-SSSV) and all wells are equipped with a polished bore receptacle system to facilitate tubing change-out. The liner hanger design incorporates a packer assembly above the slips to ensure positive pressure integrity. The selection of all seals and elastomers will incorporate the results of the corrosion study.

The maximum anticipated wellhead pressure will be contained safely and effectively through the selection of appropriate wellhead and production / injection tree equipment. Full-bore access to the tubing will allow for well-kill operations and be integrated with an operating and emergency control and shutdown system, both manual and hydraulic. Due to the operating environment, the wellhead and tree will most likely be clad in a corrosion/erosion resistant material. The tubing hanger will be ported to allow capability to handle downhole injection and control lines. Depending upon anticipated workover scenarios, the hydraulic valves in the production trees may be capable of cutting both wireline and coiled tubing.

The present completion strategy allows for the integration and use of typical downhole equipment including flow control nipples, chemical injection and mandrels for real-time pressure and temperature read-out.

4.4.5 Completion, Workover & Packer Fluid

Separate completion fluids will be used for the following three phases of completions operations:

· cleaning out the well; · providing an annular packer fluid; and · perforating (when required)/pre-flow.

Well clean-out will follow the removal of all suspension plugs or the installation of the production liner. The fluid used to clean the wellbore will be water based. Viscous pills of polymer gelled fluid may be used at total depth to sweep the hole clean.

Packer fluid will likely be fresh water based (brine), corrosion inhibited, and oxygen and hydrogen scavenged.

Deep Panuke Volume 2 (Development Plan) · March 2002 4-15 Three alternatives are available for a perforating/pre-flow fluid: non-damaging brine, a nitrogen cushion or an oil-based fluid. The fluid of choice will depend upon the well and the final reservoir requirements. All of these fluids will be flowed back to the processing or testing system during startup or cleanup.

4.4.6 Annular Barriers

There will be two annular barriers between the formation and the seafloor. The first barrier is the packer in the well, separating the formation from the annulus. The second barrier is the tubing hanger and annular master valve on the tree.

4.4.7 Production/Injection Trees

The Project may use a combination of surface and subsea production trees. The surface trees will be located on the wellhead jacket and will consist of a standard configuration that may be either horizontal or vertical, depending upon the design criteria established for the production and injection wells. The subsea trees, if used, will be a mudline conversion horizontal production tree to minimize design tree height and facilitate easier wellbore intervention.

Horizontal or spool trees use wireline plugs as vertical barriers and have the master valves located on the side outlets. The subsea trees would be protected from fishing gear and dropped objects, and the lower tree height will also reduce snag potential and the associate loads. Subsea trees would also be designed to provide easy access for remotely operated vehicles (ROV) for override functions. Means will be provided to relieve tubing/casing annular fluid heat-up pressures. All trees will provide access for downhole chemical injection and downhole pressure/temperature monitoring. Additional detail regarding subsea production trees can be found in Section 5.6 - Subsea Installations.

The maximum expected pressure at surface is approximately 30 MPa for all wells. Therefore, 34.5 MPa tree equipment may be up-rated to 38 MPa, if required, through rigorous qualification testing to meet all applicable regulations. During workovers, control of the wellhead equipment from the platform will be locked out to avoid accidental operation of equipment when the workover unit is connected to the wellhead.

Deep Panuke Volume 2 (Development Plan) · March 2002 4-16 4.4.8 Perforating

Perforating the production casing or liner allows formation fluids to flow into the wellbore (or injected fluids to access the reservoir). The three alternatives available for perforating are:

· wireline-conveyed perforating; · tubing-conveyed perforating using coiled tubing or drillpipe; or · tubing-conveyed perforating on tail pipe below the packer.

The appropriate method of perforating for each individual well will be chosen based on its merits for the particular operation.

4.5 Well Interventions

4.5.1 Major Workovers

Major workovers are those that require a mobile drilling unit to accomplish the required tasks. Few major workovers are anticipated through the life of the field due to the reservoir type, the completion style and the use of quality components throughout.

Typical major intervention activities include:

· replacing tubing; · replacing tubing retrievable SSSVs and control lines; · replacing chemical injection line; · drilling up / replacing packer; and · replacing / repairing trees.

4.5.2 Minor Workovers

Minor workovers could encompass both wireline and coiled tubing operations for both production and injection wells. On the subsea wells, these workovers could be performed using a specialized vessel, a semi-submersible or jack-up drilling unit. Slickline or coiled tubing operations are required at the beginning and end of all workover programs on subsea wells, minor or major, to remove plugs in the horizontal tree, thereby providing access to the well. The assumed frequency for minor workovers is one intervention per well per five to seven years. For surface wells on the wellhead platform, access for wireline or coiled tubing intervention will be provided using platform cranes when required. Coiled

Deep Panuke Volume 2 (Development Plan) · March 2002 4-17 tubing intervention on the surface wells may also require a jack-up rig or specialized vessels, equipment and operating procedures.

Typical minor workover activities include:

· installing or removing plugs and prongs; · installing or replacing WR-SSSVs; · installing or replacing chemical injection valves; · running or retrieving downhole pressure recorders; · production logging; · formation logging; · perforating; · circulating fill or debris from wellbore; · jetting scale or paraffin from tubing interior; · acid stimulations; · setting packers or bridge plugs; · cement squeezes; and · replacing a surface production tree or valve.

Deep Panuke Volume 2 (Development Plan) · March 2002 4-18 5 PRODUCTION AND TRANSPORTATION SYSTEMS

5.1 Introduction

The Deep Panuke reservoir contains lean sour gas. Full processing of the gas including H2S removal will be carried out offshore. Market-ready gas is to be transported via a subsea pipeline to Goldboro, Nova Scotia for tie-in to M&NP. See Figure 5.1 for the proposed field layout.

Minimal and intermediate processing offshore were also evaluated during the FEED study. A summary of the alternatives evaluated is provided in Section 5.10.

5.2 Design Criteria

5.2.1 Philosophy

PanCanadian is committed to protecting the health and safety of all individuals as well as the environment in which it operates. Therefore, the design of the Project facilities is based on high standards for personnel safety, environment, and resource conservation. PanCanadian will employ a systematic approach in identifying and addressing potential hazards, and defining design criteria and appropriate control and recovery measures.

Applicable standard industry practices will be adopted for the Project. Safety reviews will be held periodically throughout all phases of the Project, including the FEED study, detailed design, construction, commissioning, and decommissioning. All project installations will be designed, constructed, installed and commissioned in accordance with a quality assurance program that meet the requirements specified in CNSOPB regulations.

PanCanadian also intends to ensure that quality assurance for the Deep Panuke Project meets the requirements of ISO 9000. Quality plans and procedures will be developed and quality control, through auditing and surveillance, will ensure that the appropriate levels of quality assurance are present throughout the Project and that all requirements are being met.

The final design will achieve fit for purpose facilities using proven technology and equipment with low life cycle costs.

Deep Panuke Volume 2 (Development Plan) · March 2002 5-1 M&NP CustodyTransfer * Facility

SOEIGoldboroGasPlant

SableIsland

DEEPPANUKE SOEIThebaudPlatform DEVELOPMENT PanCanadianPipelineRoute

Wellhead Platform ProductionWell ProductionWell Production M-79 H-08 Platform Accommodations Platform NottoScale

P:\EnvSci\15xxx\P:\EnvSci\15xxx\15999PanCan\500RASCoordination\DevelopmentPlanApplication\DPAReport January\Figures\Figure5_1.cdr

Figure5.1ProposedFieldLayout 5.2.2 Regulations and Certifying Authority

To fulfil the requirements of the Accord Act an independent third party known as a Certifying Authority (CA) will be required to confirm to the regulatory agency that all Project installations and structures have been designed, constructed, and installed in accordance with recognised standards. This confirmation will be provided in the form of a Certificate of Fitness issued by the CA. Onshore facilities will comply with all applicable municipal, provincial and federal requirements. The following list includes, but is not limited to, the regulations and guidelines that will be used for the Project:

· Nova Scotia Offshore Area Petroleum Production and Conservation Regulations; · Nova Scotia Offshore Certificate of Fitness Regulations; · Nova Scotia Offshore Petroleum Installations Regulations; · Nova Scotia Offshore Petroleum Occupational Health and Safety Guidelines; · Nova Scotia Offshore Petroleum Drilling Regulations; · Nova Scotia Offshore Area Petroleum Diving Regulations; · Canada Shipping Act (and related guidelines); · Fisheries Act (and related guidelines); · Offshore Waste Treatment Guidelines; · Pilot Offshore Chemical Selection Guidelines; · Physical Environmental Guidelines; and · Guidelines on Operator’s Safety Plans.

The CA will be engaged at the end of the FEED study and involved in all subsequent phases from detailed design, procurement, construction, installation, hook-up, commissioning, and production start- up. The CA will also participate in the operations phase and decommissioning. The CA will conduct design appraisal and perform verification surveys. This ongoing monitoring effort will provide the necessary justification that all regulations are being met.

Some of the key CA activities in the first couple of months of engagement are:

· review of FEED study documentation including design documents; · review of the design basis memorandum (DBM) and concept safety analysis prepared during the FEED study; · prepare, and submit to the CNSOPB for approval, a scope of work that details how the CA intends to examine whether the Project satisfies all requirements and regulations such that Certificates of Fitness may be issued upon completion of the work; · prepare a quality plan, project specific procedures, and work instructions that detail how the CA will carry out its scope of work;

Deep Panuke Volume 2 (Development Plan) · March 2002 5-3 · review the project purchase order register and the master list of project design documents and indicate what the CA’s level of involvement will be for each item; and · complete a design review and survey of long lead items of major equipment and materials.

PanCanadian will be working closely with the CA to ensure that activities that fall within the CA’s scope of work will be carried out in accordance with the Project Master schedule. Certification activities will be co-ordinated and an updated register of the certification status of all items will be maintained. PanCanadian will develop procedures that specify how it intends to manage quality assurance, quality control, and certification activities for the Project

5.2.3 Codes and Standards

The codes and standards that will be used for the Deep Panuke Project include, but are not limited to, the following:

· American Petroleum Institute; · American Society of Mechanical Engineers; · National Fire Protection Association; · National Association of Corrosion Engineers; · Canadian Standards Association; · Institute of Electrical and Electronic Engineers; · International Standards Organisation; · International Electrotechnical Commission; · Transport Canada; · International Maritime Organisation; and · Canadian Council of Ministers of Environment.

5.3 Environmental Criteria

Preliminary meteorological and oceanographic (Metocean) design criteria have been developed for the Deep Panuke Project in accordance with the Nova Scotia Offshore Petroleum Installation Regulations. These criteria were created from hindcast studies and data accumulated over the life of the Cohasset Project. The design criteria take into account parameters such as winds, waves, currents and ice conditions and converts extreme conditions into a 100-year outlook for installation design purposes. Wave and current criteria have also been developed for representative locations along the pipeline route for design purposes. Further information can be found in Part Two (DPA-Part 2, Ref. #5.3.1).

Deep Panuke Volume 2 (Development Plan) · March 2002 5-4 The preliminary environment design criteria for the pipeline to be constructed from the production platform to shore can be found in Table 5.1.

Table 5.1 Preliminary Environmental Design Criteria - Pipeline Return Sites along KP 5 KP 15 KP 40 KP 70 KP 125 KP 150 Platform period pipeline route (years) Depth (m) 25 50 140 100 50 25 44.7 Hmax2 (m) 9.0 10.4 12.2 13.3 14.0 13.0 14.7 1 Tp3 (s) 11.2 11.3 11.5 11.8 11.9 11.9 12.1 Hmax (m) 12.5 14.2 16.5 17.5 18.0 17.2 18.9 10

Waves Tp (s) 13.6 13.1 13.7 13.6 13.5 13.5 14.0 Hmax (m) 16.0 18.0 20.7 21.7 23.2 19.5 24.0 100 Tp (s) 16.0 14.9 15.9 15.4 15.1 15.1 16.2 1 Uc4 (m/s) 1.0 0.9 0.8 0.8 0.9 1.0 0.8 10 Uc (m/s) 1.2 1.0 0.9 0.9 1.0 1.2 1.0

Currents 100 Uc (m/s) 1.5 1.3 1.1 1.1 1.3 1.5 1.2 Notes: 1. Kilometer point from shoreline noted KP 2. Maximum wave height noted Hmax 3. Associated Peak Period noted Tp 4. Estimated bottom current (non-wave component) noted Uc

A summary of the preliminary 1, 10 and 100-year return environmental criteria for the Deep Panuke installation is found in Table 5.2.

Table 5.2 Preliminary Environmental Design Criteria - Deep Panuke Installation Parameter 1 year 10 year 100 year Winds 1 hour wind speed at 10m MSL1 (m/s) 27.1 35.8 41.6 3 second gust at 10m MSL (m/s) 36.3 48.0 55.7 Waves Significant wave height (Hs) (m) 9.1 11.1 13.0

Maximum wave height (Hmax) (m) 16.9 20.6 24.2

Peak period associated with Hs (sec) 12.6 14.6 16.6 Currents Surface (m/s) 1.5 1.8 2.2 Mid-depth (m/s) 1.4 1.7 2.0 Bottom (m/s) 0.8 1.0 1.2 Water Levels Design water depth (m) 36.5 Maximum astronomical tide (m) 1.6 1.6 1.6 Storm surge above MSL (m) 0.3 0.5 0.7 Tsunami water level above MSL2 (m) 0.5 0.5 0.5 Air and Water Temperatures Minimum air temperature (0C) -13.7 -16.8 -20.0 Maximum air Temperature (0C) 23.3 26.4 29.4 Minimum sea surface temperature (0C) -1.0

Deep Panuke Volume 2 (Development Plan) · March 2002 5-5 Table 5.2 Preliminary Environmental Design Criteria - Deep Panuke Installation Parameter 1 year 10 year 100 year Maximum sea surface temperature (0C) 24.3 CSA Toughness (0C) -13.3 Marine Biofouling +2m LAT3 to –25m LAT (mm) 125 -25m LAT to mud line (mm) 60 Design Seismic Parameters 1000 year 100 year Peak horizontal ground acceleration (g) 0.099 0.028 Peak horizontal ground velocity (m/s) 0.110 0.017 Peak vertical ground acceleration (g) 0.066 0.019 Peak vertical ground velocity (m/s) 0.011 0.011 Notes: 1 MSL refers to Mean Sea Level 2 It should be noted that the likelihood of a tsunami is low and thus its effect is not included in the calculation of extreme water level. 3 LAT refers to Lowest Astronomical Tide

5.3.1 Operating Limits

Initial operating limits for equipment use offshore were developed and verified during the Cohasset Project. These limits will be reviewed and potentially modified by PanCanadian operations personnel for the Project. Table 5.3 overviews the existing preferred operating limits for PanCanadian’s offshore operations.

Table 5.3 Operating Limits Jack-Up Rigs And Fixed Platforms Wind Speed (Kts) Wind Gusts Mean Combined Specific Equipment/Operation (1-Minute-Mean) (Kts) Seas (m) Crane Operation 40 50 -- Transfer of Personnel - 20 2.5 Supply Vessel Alongside 40 50 4 to 5 Helicopter Operations 50 60 -- Tripping In/Out of Well 50 70 -- Initiation of Production Test 40 50 4 to 5 Running Casing with Stack Installed 45 50 -- Logging Well 50 60 --

For non-emergency conditions, Table 5.3 outlines the preferred upper operating limits for the various equipment/operations listed. Because these are listed as preferred upper operating limits, it is not intended to imply that operations must cease when the limits are met or exceeded, rather, the intention is that when conditions approach or reach these limits, operations should be reviewed to confirm safe operation may continue.

Deep Panuke Volume 2 (Development Plan) · March 2002 5-6 5.3.2 Marine Growth

Marine growth criteria (100-year) have been developed for the Project and are included in Part Two (DPA- Part 2, Ref. #5.3.1). The criteria identified for the Project build upon earlier Cohasset studies and takes into account data accumulated at site from 1993-2000. The compressed thickness criteria for marine growth are 125 mm (from +2m LAT to –25m LAT) and 60 mm (from –25m LAT to the mud line) for the Panuke jacket. Regular scheduled subsea inspections of the jackets will determine if the criteria have been exceeded and if remedial action is warranted.

5.4 Geotechnical Criteria

PanCanadian has geotechnical data for the Panuke area from the Cohasset Project. A description of the field investigations that were completed and an overview of the soil tests, stratigraphy, soil properties, interpretation and the resulting design criteria are found in Part Two (DPA – Part 2, Ref. # 5.4.1)

Two boreholes were completed at the Panuke site, to a depth of 100 m below mudline. Results indicate that the area around the Panuke jacket consists of layers of dense to very dense sands and hard clays. Table 5.4 gives a description of the soil stratum per depth drilled.

The borehole data as obtained from the Panuke wellhead location will be used for the initial design of the Project platform foundations. New boreholes will be completed in 2002 at the selected platform locations and the new data will be used for detailed design for each platform foundation.

Deep Panuke Volume 2 (Development Plan) · March 2002 5-7 Table 5.4 Design Profile

qc gt w Relative Su ø’ c’ Stratum Description (depth in m) 3 OCR (Mpa) kN/m % Density (%) (kPa) (deg.) (kPa) Dense to very dense >10 I 30 20.0 22 70-100 - 45-41 - Fine to medium SAND (19.5) (>4) II Very stiff CLAY (24.1) 3 20.0 25 - 200 24 20 (4.0) III Dense SAND with gravel (27.0) 25-70 21.0 15 85-100 0 40-42 - (3.8) IV Hard CLAY (29.5) 6 21.0 15 - 340 24 30 (3.8) V Very dense fine SAND (32.3) 70 20.0 21 95-100 - 41 - (3.7) Hard silty CLAY VI - silt partings 4-6 20.5 24 - 290 24 30 (3.3) - silt and sand seams (50.5) VII Very dense SAND (52.3) >70 20.0 22 85-100 - 39 - (3.0) Hard CLAY with VIII 5 20.5 26 - 340 24 30 (3.0) Occ. sand layers (56.0) Dense to very dense 3.9 IX Fine to medium SAND >60 20.0 24 85-100 - 38 - (2.7) -increasingly silty with depth (72.0) Hard CLAY X 7 21.5 18 - 405 17 150 (2.4) - sand seams (87.5) Very dense layered XI >70 21.0 16 85 - 37 - (2.1) Fine to medium SAND (100.2) Note: qc: Core resistance

gt: Density W: Water content Su: Undrained shear strength ø’: Friction angle

c’: Effective cohesion

OCR: Over consolidated ratio

Deep Panuke Volume 2 (Development Plan) · March 2002 5-8 5.5 Production Installation and Topside Facilities

5.5.1 Platform Structures

The platforms will be fixed-steel jacket platforms. The preferred design consists of a production platform (PP) bridge-connected to a separate utilities-quarters platform (UQP) and a wellhead platform (WP).

All developments to date offshore Nova Scotia (Cohasset and SOEI) have used the steel jacket platform concept. There are currently six (6) fixed steel platforms located on the Scotian Shelf with a combined operational history that is greater than 25 years. Thousands of steel jacket platforms exist worldwide and have a long proven track record in similar harsh environment areas such as the North Sea. An example of a typical steel jacket platform is provided in Figure 5.2.

Figure 5.2 Typical Fixed Steel Platform (PanCanadian's Scott/Telford Field, UK)

Deep Panuke Volume 2 (Development Plan) · March 2002 5-9 Alternatives to the steel jackets have been investigated and are discussed in Section 5.10.1

5.5.1.1 Wellhead Facilities

New production and injection wells are expected to be drilled from a new wellhead platform, which will be bridge-connected to the production platform. The intent is to install the wellhead jacket early in the construction phase to facilitate drilling, and completion of the production and injection wells prior to Project startup. A development alternative would involve setting a well template, installed by a jackup rig, to serve as a conductor guide during drilling. This would require the wells being completed with tie- backs from the sea bottom once the platform is in place. This option is more costly and provides additional technical risk. Further information on the well construction can be found in Section 4.0.

5.5.1.2 Production Platform

The production platform is the largest of the three platforms and will contain the main production equipment and power generation for all three platforms. The platform will have risers for the gas export line and the potential subsea control umbilicals from remote wells. Details of the processing facilities are described in Section 5.7.

5.5.1.3 Accommodation Platform

The living quarters are to be located on a separate platform along with the required support utilities and the process control room to ensure the highest level of worker safety. The helideck will be located on the accommodation platform, most likely on top of the accommodation module.

5.5.2 Offshore Pipeline

Market-ready gas from the main production platform will be transported to onshore Nova Scotia with landfall anticipated to be at Goldboro. The pipeline is currently sized at 610 mm (24 inch) nominal outside diameter with a length of approximately 175 km. The pipeline size and length will be refined and may change during the FEED study and/or detailed engineering. It is currently proposed that the pipeline will head toward the SOEI pipeline corridor and to Goldboro as illustrated in Figure 5.3.

The offshore pipeline route was selected to maximize the length, which will parallel to the SOEI pipeline to minimize disturbance. The development of a common offshore pipeline corridor in keeping with the recently announced Nova Scotia Energy Strategy (Vol. 1, page 37).

Deep Panuke Volume 2 (Development Plan) · March 2002 5-10 Figure5.3OffshorePipelineRouting The pipeline will be externally coated for corrosion protection and concrete coated to provide negative buoyancy and on-bottom stability. Specifics regarding pipeline trenching will be determined in the FEED study and/or detailed engineering.

5.5.3 Onshore Facilities

Minimal facilities will be located onshore to deliver sales gas to the M&NP facility. The facilities will likely include aboveground piping, metering, pipeline isolation valves, temporary pig facilities, SCADA equipment, and a small building for metering and SCADA.

In the event of a fire, leak, or some other emergency situation, it may be necessary to shutoff the feed of gas to the onshore facility. This will be accomplished with emergency shutdown valves (ESDV) at the inlet to the gas line at the offshore facility and at a location onshore.

5.6 Subsea Installations

The Project will investigate the possibility of re-using two delineation wells that were drilled, tested and suspended in 2000. The Project’s subsea facilities would include all equipment from the wellhead to the connection of the flowlines at the riser on the production platform. The subsea systems would be designed to accommodate all planned subsea production wells and provide expansion opportunities. The design numbers and quantities discussed in this section are preliminary and will be confirmed during the detailed engineering phase, if the tie-in of the wells is deemed feasible.

The subsea design would include two subsea wells, H-08 and M-79A (see Figure 4.2). These wells were drilled using a mudline suspension system, surface wellheads and BOPs. The wells were successfully tested and suspended for future re-entry. The subsea production system would tie into the existing mudline suspension system to create a rigid subsea wellhead. A horizontal production tree will lock onto this high-pressure wellhead housing.

The subsea facilities will be comprised of the following components:

· mudline conversion wellhead systems; · horizontal production trees; · protection structures · flowlines; and · control systems including umbilicals.

Deep Panuke Volume 2 (Development Plan) · March 2002 5-12 5.6.1 Subsea Production Trees

Subsea well completions will be designed with two barriers against well flow under all conditions.

The standard wellhead system will likely be based on a 346 mm wellhead housing with a 69 MPa pressure rating. Trees will likely be rated for approximately 38 Mpa. Metal-to-metal seals will likely be used for all seals with potential for exposure to well fluids.

The production trees, with connections for production and service lines, will be optimised for productivity and ease of access for downhole interventions. Production trees will be designed to allow chemical injection into the production stream both downstream of the upper master valve and below the tree in the wellbore. Figure 5.4 provides an example diagram of a mudline conversion subsea production tree.

A roof and protection structure would be provided to protect the trees against dropped objects, dragging anchors and fishing gear.

H.P. Cap

Spool Tubing TreeAssembl Hanger y Wellhea Connectod r

Figure 5.4 Spool Subsea Trees

Deep Panuke Volume 2 (Development Plan) · March 2002 5-13 5.6.2 Flowlines

The length and size of flowlines will depend on the final field layout. However, the satellite well flowlines connecting each well to the wellhead platform are expected to be approximately 2.5 – 3.5 km long with a 200 mm (8 inch) nominal diameter.

Flowlines would be of either rigid steel or flexible construction. Breakaway couplings will likely be provided to minimise damage in the event of impact.

Chemical injection lines would be contained within the service umbilical along with the control lines. This umbilical would be laid on the seafloor parallel with the intrafield flowlines to provide remote control for the subsea tree functions.

5.6.3 Subsea Control System

An appropriate control system would be used to control each well. Due to its close proximity to the production platform, the wells could have a simple direct hydraulic control system. An electro-hydraulic system will also be investigated for possible use.

The control system would perform the following functions:

· provide individual control of all hydraulically operated valves on the trees; · provide indication of the opened/closed status for all hydraulically operated valves; and · monitor the pressure and temperature for tree bores and flowlines at the subsea tree.

The subsea control system would likely include the following components:

· a surface control unit - a computer system interface to the platform automation system (for control and shutdown functions); · control umbilicals – individual umbilicals to each well; · control pods – (if electro-hydraulic system chosen) a control pod for each tree, installable and retrievable by divers or a remote operated vehicle (ROV); · a monitoring system – containing pressure and temperature sensors; · a chemical injection system – a hydraulic unit responsible for all chemical injection of fluids for corrosion mitigation and hydrate control; and · a workover control system - a simple hydraulic control system used for tree operation from a workover vessel.

Deep Panuke Volume 2 (Development Plan) · March 2002 5-14 5.6.4 Diver and ROV Interface Requirements

The water depth at Deep Panuke is shallow enough for divers to install all subsea connections. Project facilities will be designed to make tasks easier for divers, including providing easy access and overhead lifting capability. Despite this diver-friendly design, use of ROVs will be preferred during subsea connection work. During installation of the wellheads and production trees, diver support services in the field are expected to be minimal. The rig that performs the installation would be capable of remotely controlling all functions required for the installation of these components with the assistance of an ROV. During the production phase, ROVs will likely be used to minimize the need for divers and will be continuously available for a wide variety of tasks.

5.6.5 Oil Spill and Leak Protection

Subsea facilities will be designed to reduce environmental impact in the event of leaks due to impact. Flowlines will be trenched by seafloor stability, thermodynamic, or overtrawling considerations. In the unlikely event of a spill, the PanCanadian Alert/Emergency Response Contingency Plan and the associated Spill Response Plan will be utilised. Further details are provided in Section 11.0.

5.7 Processing Facilities

The processing facilities will consist of separation, metering, sweetening, dehydration, dewpointing, acid gas injection, condensate treatment, produced water treatment and disposal, compression and utilities. See Figure 5.5 for a process flow diagram of these facilities.

5.7.1 Separation

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

5.7.2 Metering

The production and test separator’s individual streams are metered for reservoir management purposes as per existing regulations.

Deep Panuke Volume 2 (Development Plan) · March 2002 5-15 AcidGas Injection

Market-Ready FeedGas Hydrocarbon Gas SweetGas SaleGassGas Gas Compression Dewpoint Sweetening Dehydration CompressionCompression Marine (Future) Control Production Pipeline Wells

Fuel Condensate Inlet Condensate ForPlatform Separation Treatment Energy Generation

Potential Market-Ready Produced Water Surplus Gasto Water Disposal ThirdParty Treatment Condensate Injection Pipeline

Cooling Water

P:\EnvSci\15xxx\15999PanCan\500RASCoordination\DevelopmentPlanApplication\DPAReportJanuary\Figures\Fig5_5.cdr

Figure5.5SimplifiedProcessFlowDiagram 5.7.3 Gas Sweetening

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. However, the H2S in the raw gas is expected to reach a maximum of approximately 46 kgmole/hr. Deep Panuke sales gas is required to contain less than 4 ppmv of H2S, and have a CO2 concentration below 3.0 mole %. The removal of the H2S and CO2 from raw gas to produce sales gas results in a waste acid gas stream predominantly containing H2S and CO2. The H2S and CO2 are removed from the raw gas by absorption into a recirculated amine solution.

5.7.4 Acid Gas Injection

Acid gas from the amine regenerator will be compressed to approximately 15,000 kPa using a multistage compressor. Water condensing between the compression stages recycled back to the processing facilities. The compressed acid gas is transported to the injection well for injection into an acceptable reservoir.

Intervals of porous and permeable sandstone will be required for disposal of acid gas. Such intervals are present in the Logan Canyon Formation and in the Panuke P sands within the Naskapi shale. Figures 5.6 and 5.7 present images of the H-08 and PI-1B well bores with sand intervals shown on the lithology track and porous sand intervals coloured yellow on the gamma ray curve.

The Logan Canyon Formation was deposited in a coastal plain to shallow marine setting, seismic time slices through the Logan Canyon reveal a series of channels moving back and forth across the coastal plain. The sands range from medium to course grained in the Lower Logan Canyon and become finer in the upper Logan Canyon.

The P sands are thin fluvio-deltaic sands in the lower portion of the Naskapi member; these are the sands that were productive of oil at the Cretaceous Panuke field. The P sands were capable of flowing oil at very high rates.

All wells drilled have encountered these sand packages in the Logan Canyon and Naskapi to a varied degree. They are widely distributed in the immediate area and any disposal well should encounter sands with high enough porosity and permeability to permit disposal.

A parametric assessment of minimum inflow potential, reservoir dimensions and volume requirements are included in Part 2 (DPA-Part 2, Ref. # 5.7.4.1). Based on this study, identification of a suitable injection zone for the specified injection rates should not be a concern. Further work will be done to select the optimum injection zone and wellbore placement.

Deep Panuke Volume 2 (Development Plan) · March 2002 5-17 PI_1B H-08

Logan Canyon

Porous SS

Figure 5.6 Upper Logan Canyon, Lithofacies in centre of log track, yellow areas in gamma ray track on left indicate clean porous sand.

Deep Panuke Volume 2 (Development Plan) · March 2002 5-18 Figure 5.7 Lower Logan Canyon to Missisauga: centre of log track indicates lithology, yellow areas in gamma track on left indicate clean porous sandstone.

Deep Panuke Volume 2 (Development Plan) · March 2002 5-19 5.7.5 Dehydration

Sweet gas from the amine sweetening unit contains water which will be removed using triethylene glycol (TEG). Lean TEG (low water concentration) is countercurrently contacted with the sweet gas from the amine sweetening system to remove the water vapour to levels below hydrate formation concentrations. The rich TEG (high water concentration) is regenerated through a distillation column. Regenerated TEG is recirculated back to the contactor as lean TEG.

5.7.6 Hydrocarbon Dewpoint Control

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 is necessary to satisfy pipeline gas specification requirements.

5.7.7 Condensate Treatment for Fuel

Recovered condensate will be burned on the production platform as the primary source of fuel. In order to minimize air emissions, the residual H2S in the condensate is removed by heat in the condensate stabiliser. The H2S thus released is recycled back to the raw gas stream for removal by the amine solution. Condensate will be used as fuel over the life of the Project and will be supplemented with natural gas as necessary to maintain adequate fuel levels. In the early years of production, there may be a surplus of condensate available that will be injected into an injection well. See Section 5.7.4 for more information on the injection well. The selection of an optimum injection zone will be performed in conjunction with the acid gas disposal selection study.

5.7.8 Produced Water Treatment and Disposal

Formation water removed with raw gas and separated during the initial stages of processing is called produced water. This water contains residual hydrocarbons that must be removed to acceptable levels prior to ocean discharge. The produced water treatment and disposal system will likely include hydrocyclones for entrained oil removal. Polishers and/or sweet gas stripping will be used to ensure acceptable water quality prior to discharge. Treated produced water will be discharged overboard according to the Offshore Waste Treatment Guidelines (NEB et al., 1996).

5.7.9 Compression

The sales gas will be compressed on the platform for delivery to M&NP. The expected sales gas discharge pressure on the platform is 13,000 kPa requiring approximately 18 MW compression power. To account for the declining reservoir pressure in later years, approximately 9 MW of feed gas

Deep Panuke Volume 2 (Development Plan) · March 2002 5-20 compression is anticipated. The Deep Panuke compressor system is expected to consist of three units, two providing sales gas service and one providing feed gas service.

5.7.10 Utilities

5.7.10.1 Electrical Power Generation

Electrical power generation for the Deep Panuke platforms will be provided by multiple redundant dual fuel (condensate/gas) turbine generating sets. For the first production start-up, sufficient quantity of diesel will be available for power generation. Battery back-up will be provided for essential services. Emergency power will be provided by a diesel engine as per CNSOPB regulations.

5.7.10.2 Platform Fuel

Condensate will be used as platform fuel. Fuel gas will be used as supplemental fuel as condensate production declines. All platform fuel will be metered.

5.7.10.3 Service Water Supply

Service water for process and utility systems will be treated seawater.

5.7.10.4 Closed Drain and Open Drain Effluent

All liquids collected from closed drains, equipment drip trays, and other areas will be pumped back through the facility for separation and removal to separate facilities.

5.7.10.5 Relief and Blowdown System

The principal elements of the relief and blowdown system include the pressure relief devices, flare piping system, flare separator, flare boom and the flare system. Application of all relevant codes will be followed for the design of these Project elements.

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.

Deep Panuke Volume 2 (Development Plan) · March 2002 5-21 5.7.10.6 Inert Gas System

Provision for an inert gas system will be included in the design and layout of the Project. Inert Gas is necessary for commissioning and start-up exercises as well as ongoing operations. The inert gas may also be used as a blanketing gas to ensure oxygen does not enter a system.

5.7.10.7 Instrument Air

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

5.7.10.8 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.

5.8 Production Operations

PanCanadian holds 100% of the Deep Panuke licence and will therefore be the Operator. The operation will be maintained by a core group of individuals located both offshore and onshore.

The lead position on the installation will be the Offshore Installation Manager supported by a multi- disciplined team including operators, maintenance personnel, weather observers, logistics personnel, engineers, and catering staff. Additional staff will travel offshore on an as-needed basis.

The onshore staff will be located in Halifax and will consist of production, operations, maintenance, engineering, and loss management personnel as well as other support services. The Supply Base, located in Halifax, will be a focal point for the supply chain management group.

5.9 Provisions for Decommissioning and Abandonment

The following facilities will be utilised during the life of the Project and will eventually require decommissioning and abandonment:

· the offshore production platform; · the wellhead platform; · the accommodations and utilities platform; · the subsea wellheads, flowlines and umbilicals; · the offshore gas pipeline;

Deep Panuke Volume 2 (Development Plan) · March 2002 5-22 · the onshore gas pipeline; and · the onshore facilities.

The decommissioning and abandonment of these facilities will be performed in accordance with the regulatory requirements applicable at the time such activities are undertaken. Potential changes in technology, regulations, and accepted industry practices over the time between initial construction and abandonment make it difficult to commit to a specific course of action at this time. When the time arises, an action plan will be submitted to the appropriate authorities for approval prior to commencement of decommissioning and abandonment activities. However, based on today’s standards, a typical action plan is included below.

The requirement for eventual removal of facilities will be taken into account during design. Abandonment of the offshore platforms and jackets is currently envisioned as cutting off the jacket legs and/or piles below the mudline and transporting the jackets and platforms to a suitable site for recovery and disposal. 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 platforms and jackets will be considered on an economic basis.

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

The offshore pipeline will be abandoned ‘in place’ after it is flushed internally and filled with seawater. Its ends will be capped.

With the exception of the pipeline, onshore facilities will be removed and utilised land restored in accordance with applicable regulations. Buried onshore pipeline will be flushed, capped and abandoned in place. Pipeline right-of-ways will be re-vegetated and allowed to return by natural succession. Any above ground structures associated with the onshore pipeline will be removed.

5.10 Assessment of Development Alternatives

Several concepts were originally identified as potential development alternatives for the Deep Panuke Project. Each of these options was evaluated against a list of criteria to arrive at a preferred development concept.

As a precursor to the formal evaluation of various development alternatives against selected evaluation criteria, it was necessary to outline a central development concept by which the Project would be guided. The development concept for Deep Panuke is that the Project will, because of its reserve size, take advantage of pre-existing infrastructure to the maximum extent possible. PanCanadian has made

Deep Panuke Volume 2 (Development Plan) · March 2002 5-23 conditional commercial arrangements to transport up to 400 MMBtu/d of Deep Panuke gas on the M&NP system, specifying delivery at Goldboro. Accordingly, development alternatives which will not allow PanCanadian to take advantage of the infrastructure installed by M&NP were not evaluated against the criteria outlined below because they were determined to be not economically feasible. 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, which would be alternatives to this Project. With this central concept in mind, the following development alternatives were evaluated:

· substructure type; · topside type; · total number of platforms; · re-use of the existing Panuke platform; · processing location; · acid gas handling; and · produced water disposal.

The decision to proceed with the preferred development option described herein was based on evaluation of the various alternatives described above against the following criteria (the Evaluation Criteria):

· technical suitability (including operational factors); · costs; · commercial risk; · concept deliverability; · safety; and · environmental impact.

Although each alternative was evaluated using the Evaluation Criteria, the relevance and contribution of each criterion varied depending on the alternative under consideration. For example, although the capital cost to provide a separate platform for accommodations was considerable, it was determined that it was an acceptable cost opposed to the increased safety risk associated with including the personnel accommodations on the production platform.

If an alternative was deemed to be technically and economically not feasible, a further assessment of the alternative, including concept deliverability, safety and environmental factors, was not considered. If

Deep Panuke Volume 2 (Development Plan) · March 2002 5-24 alternatives are considered technically and economically feasible, they are also addressed in the EIS (Volume 4).

5.10.1 Substructure Type

Substructure alternatives investigated included steel semi-submersible hulls, concrete gravity based systems (GBS), large and medium sized jack-ups, and steel jackets. The evaluation of these alternatives against the Evaluation Criteria is summarised in Table 5.5 and discussed in Part Two (DPA – Part 2, Ref.# 5.10.1.1).

The steel semi-submersible hull was eliminated based on technical suitability as this concept has not been proven in the harsh/shallow water environment prevalent at the Deep Panuke site. The mooring and riser design would be technically very challenging and the concept lacked favourable experience with a steel semi-submersible as a gas production platform.

The other four options (GBS, large jack-ups, small jack-ups and jackets) were primarily compared on the basis of technical suitability, cost and commercial risk; the environment and safety impact for the four options were not significantly different. The GBS structure was rejected due to higher commercial risk imposed by a single source supplier and cost, thus it was determined to be not economically feasible.

The large jack-up alternative was also rejected as not economically feasible based on higher cost and increased commercial risk. There is limited experience worldwide with large jack-ups of this scale operating as a gas production platform. The experience of the large jack-up alternative indicates significant risks associated with cost and schedule overruns.

The initial screening study showed that the capital cost for mid-sized jack-ups and jacket options were very close in cost. Upon further investigation of the concept deliverability, it was found that similar jack-up projects had experienced significant delays associated with transportation and hook-up, demonstrating the actual cost of a jack-up option to be 10 % higher than the jackets option. The size of the production platform topsides would be a novel solution since it would be one of the largest applications of this technology for the harsh environment at Deep Panuke. Therefore, the mid-size jack- up option was rejected for technical and economic reasons.

In summary, conventional steel jackets were selected as the preferred development alternative based on economics and technical feasibility.

Deep Panuke Volume 2 (Development Plan) · March 2002 5-25 Table 5.5 Substructure Development Alternatives Cost Commercial Risk Technically and Concept Alternative Technical Suitability Safety Environmental Impact Economically Feasible Deliverability Jacket · proven for Deep Panuke site · lowest · lowest – competitive · yes · best · no specific · local seabed conditions procurement concern disturbance and · best estimate of offshore pile driving hook-up costs required

Steel Semi- · technical concerns related to riser · 10% higher · greater than jacket · no Submersible design and mooring, adjacent to other than jacket Hull platforms and riser design option · lack of experience in shallow/harsh conditions · only one semi in use for gas production (deeper water)

Concrete GBS · Gravity based system (GBS) widely · most expensive · single source of supply · no used – six examples in water this by could lead to high costs shallow approximately · inshore topside analysis avoids large $100 MM crane requirement · condensate storage is free

Medium Size · no semi-submersible crane vessel · 10% higher · higher contract management · no Jack-Up (SSCV) required costs than risk · co-location of facilities is required jacket option · installation problems due to jack-up size possible (Siri and Harding) · Foundation concerns · same risks as larger jack- · size required pushes the proven ups technology envelope · offshore hook-up costs high potential to exceed jacket HUC (SSVC)

Large Jack-Up · co-location of all facilities on a single · 15 % higher · significant risk of cost · no deck than jacket overruns (e.g., Elgin) · no SSCV required option · offshore HUC could be · some concerns regarding installation significant and challenge of blast loading on a · only one jack-up of this triangular deck scale operating (Elgin)

Deep Panuke Volume 2 (Development Plan) · March 2002 5-26 5.10.2 Topside Type

The production platform topsides will be configured as an integrated deck (approximately 7,000 tonnes dry weight), installed offshore in a single lift by a twin crane semi-submersible crane vessel (SSCV).

The feasibility of an alternative approach to the production platform topside design, based on splitting the deck into a number of discrete modules, was investigated during the FEED study. Initially this was seen as offering a number of potential benefits to the Project including more heavy lift contractors to choose from, and cost. The utility/quarters and wellhead platforms were not investigated for modularization because the deck size does not limit the number of heavy lift contractors to choose from.

Several modularization scenarios were considered with the following options studied in depth:

· two large modules consisting of a separation/gas treatment and a utilities/gas compression module with additional power generation and waste heat recovery skids on the top deck; · four medium sized modules consisting of a separation module, utilities module, gas treatment and gas compression modules with additional power generation and waste heat recovery skids on the top deck; and · six small modules consisting of one separation, one utilities, two gas treatment and two gas compression modules.

The results of the topside type alternatives analysis is summarised in Table 5.6.

The production platform modularization study determined that the difference in offshore installation costs of the various options is small. Although the day rates for the smaller installation vessels capable of installing the medium and smaller modules is lower, this is outweighed by the increased offshore installation time and thus increased exposure to weather downtime in the harsh offshore environment of the Scotian Shelf.

Integrated decks are more technically suitable alternatives than modular decks. Modularization offers a less efficient platform layout with increased pipework, cabling, and support steelwork resulting in a heavier and more costly platform. Modularization will result in a more complex onshore construction program and logistics with increased number of vessels to transport the platform components. The difference in hook-up and commissioning costs is significant with respect to offshore person-hours and other associated costs. The increased number of vessels presents some additional safety risks and, due to the increased emissions associated with a larger number of vessels, a less desirable environmental alternative (although not significantly so).

Deep Panuke Volume 2 (Development Plan) · March 2002 5-27 Table 5.6 Topside Development Alternatives Technically and Concept Alternative Technical Suitability Cost Commercial Risk Economically Safety Environmental Impact Deliverability Feasible Integrated Deck · most technically · lowest · requires one of two heavy lift · yes · best control · minimum · least number of suitable alternative vessels in the world over schedule time required vessels required for offshore resulting in less hook-up emissions Two Large Modules · modular decks · increased mobilization costs · multiple contractors means · no result in less · installation vessels have lower increased management efforts efficient deck day rate but more weather and risk of delays (slowest yard layout and are more downtime expected due to dictates pace) – more logistics costly Deep Panuke site conditions · more installation vessels · construction · increased offshore hook-up available than integrated deck complexity is costs and commissioning · multiple yards increase weather increased · not as cost effective as four delays for transport/load out module option · no “extra”installation contractor to bid the job Four Medium · similar to two large · increased mobilization costs · multiple contractors means · no Modules modules · installation vessels have lower increased management efforts day rate but more weather and risk of delays (slowest yard downtime expected due to dictates pace) – more logistics Deep Panuke site conditions · more installation vessels · increased offshore hook-up available than integrated deck costs and commissioning · multiple yards increase weather · costs of four modules were 20 delays for transport/load out % higher (capital and hook-up, · allows one extra installation and commissioning) than contractor to bid the job integrated deck Six Small Modules · similar to two large · increased mobilization costs · multiple contractors means · no modules · installation vessels have lower increased management efforts day rate but more weather and risk of delays (slowest yard downtime expected due to dictates pace) – more logistics Deep Panuke site conditions · more installation vessels · increased offshore hook-up available than integrated deck and commissioning · multiple yards increase weather · not as cost effective as a four delays for transport/load out module option Two or Three · similar to two large · two module option has · multiple contractors means · no Modular Combination modules increase project cost of 20 % increased management efforts at an Integration Site · three module option has costs and risk of delays (slowest yard Onshore greater than two module cost dictates pace) – more logistics · multiple yards increase weather delays for transport/load out

Deep Panuke Volume 2 (Development Plan) · March 2002 5-28 Although modularization would increase the number of fabrication yards worldwide capable of constructing the deck, it also increases the cost of the Project and presents a schedule risk due to weather-related delays associated with transportation and load out from multiple fabrication yards. The four module option was considered to offer the most advantages, although after considering all the findings, this option would have cost approximately 20 % more than the integrated deck solution selected for the development plan (DPA – Part 2, Ref.# 5.10.2.1).

A further modularization study was performed to investigate the feasibility of a jacket substructure supporting two or three modules that would be built separately, and subsequently brought together at an integration site to be welded into a single deck structure. The study proved that this alternative would cost approximately 20 % more than the single integrated deck solution and also presented a schedule risk (DPA – Part 2, Ref.# 5.10.2.2).

In summary, after consideration of the additional costs and the increased effort for offshore hook-up and commissioning associated with modularization, it was determined that modularization was not economically and technically feasible.

5.10.3 Total Number of Platforms

Various platform layout scenarios were evaluated to determine the best option for the Project. The best option consists of three separate platforms – a production platform (PP), a utility/quarters platform (UQP) and a wellhead platform (WP). However, combinations of these individual platforms are technically and economically feasible, and were evaluated. The alternatives evaluated included the following:

· Case 1: separate PP, UQP and WP; · Case 2: a combined PP/UQP and a separate WP; and · Case 3: a combined PP/WP and a separate UQP.

Although each of Cases 1, 2 and 3 were analysed using the Evaluation Criteria as shown by Table 5.7, the primary design consideration during the development of platform layouts is safety of personnel, including the segregation of hazardous and non-hazardous areas. The option selection process utilised the As Low As Reasonably Practicable (ALARP) principle to analyse the relative safety of the three Cases considered.

Deep Panuke Volume 2 (Development Plan) · March 2002 5-29 Table 5.7 Total Number of Platforms Development Alternatives Technically and Concept Alternative Technical Suitability Cost Commercial Risk Economically Safety Environmental Impact Deliverability Feasible Three Separate Platforms: Living · equivalent · approximately · higher than co- · yes · equivalent · much lower risk · greater number of Quarters/Utilities, Processing and $28 MM more location due to to offshore platforms will create Wellhead Platforms expensive ($15 - load out/transport personnel than a minor increase in $38 MM range) risk and offshore either of the two disturbance to the hook-up and platform options benthic environment commissioning · relatively larger exclusion (safety) zone Two Platforms: · equivalent · lowest cost · lower than three · yes · equivalent · higher risk to · less disturbance to Co-located Living separate platform offshore personnel benthic environment Quarters on Production case than three platforms Facilities (single platform) and separate · smaller exclusion wellhead zone than three platforms

Two Platforms: · reduced drilling · lower than · lower than three · yes · reduced · low risk to · less disturbance to Co-located Production and installation separate living separate platform drilling and offshore personnel benthic environment Facilities and Wellheads flexibility quarters and case installation than three platforms (single platform) and separate quarters processing flexibility · smaller exclusion platform zone than three platforms

Deep Panuke Volume 2 (Development Plan) · March 2002 5-30 The safety risk associated with the utility/quarters location was determined by carrying out a risk assessment (DPA – Part 2, Ref.# 5.10.3.1). Full Quantitative Risk Assessment uses detailed information about the installation, together with generic equipment failure data (flanges, valves, compressors etc.), to estimate the following safety risk parameters:

· PLL (Potential Loss of Life): Represents the number of statistical fatalities likely to occur on an installation per year; · IRPA (Individual Risk Per Annum): Represents the probability of an individual becoming a statistical fatality in a period of one year; and · TRIF (Temporary Refuge Impairment Frequency): Represents the probability that the Temporary Refuge (TR) is impaired (together with associated life support and evacuation systems) in a period of one year.

A separate quarters platform (Cases 1 and 3) is the safest option because personnel are further removed from hazards such as a blow-out, riser/pipeline releases, and process topsides releases that could result in fires/explosions, or releases of H2S gas. While the costs of co-located living quarters would be significantly lower ($28 MM) than separating these two functions, the increased safety risk dictated that a separate UQP become the preferred option.

In terms of environmental impact, there is little difference between the two or three-platform options. For the three-platform option, the offshore footprint of the Project is larger and therefore, there is a greater impact to the benthic community and a larger exclusion (safety) zone. However, the environmental impact is still considered insignificant.

Case 3, combining the PP and the WP, was discarded due to the concept deliverability criteria, reduced drilling and installation flexibility, as well as safety. As a result, the preferred development alternative for Deep Panuke was based on three separate platforms (Case 1).

5.10.4 Re-Use of Existing Platform

The existing Panuke structure, bridge-connected to the main production platform, was investigated for use as the wellhead platform. The Panuke platform was designed for the Cohasset Project and installed in 1991. It contains five well slots from which the original Deep Panuke discovery well (PP-3C) and the first delineation well (PI-1A/B) were drilled. These wells were suspended during the first phase of decommissioning of the Cohasset Project with the intention to use them in the Deep Panuke Project. The ability to use these wells as Project development wells was a key driver behind the evaluation of the Panuke platform re-use. An evaluation was also conducted to determine whether refurbishing the platform was more cost-effective than building a new platform.

Deep Panuke Volume 2 (Development Plan) · March 2002 5-31 An evaluation of the existing two wellbores at the Panuke platform was performed and concluded that PP-3C would have to be re-drilled and PI-1B would require downhole modifications.

A platform inspection program was implemented during the summer of 2001 to investigate the structural adequacy of the Panuke platform as the Project wellhead platform. It was concluded that the jacket was acceptable for re-use; however, the deck would have to be either removed and replaced with a new one or modified offshore. The modifications would reduce the topside weight to accommodate the bridge weight from the production platform and outfit the required facilities for Deep Panuke.

The Panuke platform experiences excessive movement during storm conditions, creating a concern as to how the piping connections would accommodate relatively large differential movements between the two adjacent platforms.

Following the preliminary analysis of the technical suitability of re-using the existing Panuke platform, the two alternatives, re-use of the Panuke platform and use of a new wellhead platform, were compared using the Evaluation Criteria. This analysis is summarised in Table 5.8.

As Table 5.8 indicates, installation of a new wellhead platform is the most suitable technical solution. The clear deciding factor in the analysis was the relative safety and environmental risk of re-using the Panuke platform as compared to the installation of a new platform. Installation of a new platform removes the concern regarding the excessive movement of the Panuke platform, and the associated concerns in regard to the pipe connections that would exist between the production platform and the Panuke platform. In summary, in consideration of safety, environmental and technical factors, the re-use of the existing Panuke platform was rejected, as an alternative.

5.10.5 Processing Location

The Project involves offshore processing such that market-ready natural gas will be transported to shore in a subsea pipeline. The decision to process raw gas offshore was based on an analysis using the Evaluation Criteria. This analysis is summarised in Table 5.9. The alternatives analysed are as follows:

· offshore processing; · onshore processing; and · an intermediate case.

The preferred case for development is offshore processing. Offshore processing involves gas sweetening, acid gas injection, TEG dehydration, 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.

Deep Panuke Volume 2 (Development Plan) · March 2002 5-32 Table 5.8 Re-Use of Existing Platform Development Alternatives Cost Commercial Risk Technically and Concept Alternative Technical Suitability Economically Safety Environmental Impact Deliverability Feasible New · design and · additional cost of a new · delivery of new · yes · equivalent · no specific · more disturbance to benthic Wellhead installation of a new platform and well(s) wellhead platform concerns environment than re-use of Platform fit-for-purpose presents some existing platform wellhead is the best commercial risk technical solution · new fishing and vessel exclusion (safety) zone Re-use of · only five drilling · more cost effective (in terms of · very low, but does · yes · equivalent · concerns about · risk of potential spill due to Existing slots available for drilling) as it allows re-use of not balance off the excessive excessive movement related to Panuke Project development an existing wellbore(s) risk of re-drilling movement related pipeline connections Platform new well(s) to pipeline for · concern with · Panuke platform will require connections and · re-use of platform results in less Wellhead excessive movement modifications/upgrade offshore · offshore platform disturbance to benthic of Panuke platform and therefore accommodations construction could connections environment than a new vessel will be required negate the cost platform · major offshore advantage modifications · fishers and vessels accustomed required · PanCanadian only to existing exclusion zone at owns 50% of the Panuke platform

Deep Panuke Volume 2 (Development Plan) · March 2002 5-33 Table 5.9 Location of Processing Development Alternatives Technically and Concept Alternative Technical Suitability Cost Commercial Risk Safety Environmental Impact Economically Feasible Deliverability

Offshore · best technical · slightly lower · no specific · yes · equivalent · deals with H2S at · deals with H2S at source, thereby

Processing solution (H2S and cost than concerns source thereby minimizing environmental risk related condensate onshore minimizing safety risk to unnecessary transportation removal at source processing related to unnecessary · fewer sensitive environmental to produce natural · handling transportation receptors and potential impacts with gas) condensate regard to offshore sulphur emissions offshore improves economic feasibility

Onshore · higher risk than · slightly higher · substantial risk to · yes · equivalent · transports H2S from · A greater number of sensitive Processing offshore cost than Project economics offshore to populated environmental receptors and potential processing offshore should pipeline area (increased safety impacts onshore with regard to associated with processing corrode and be out risks) sulphur emissions pipeline integrity of service for an extended period of · increased corrosion risk associated

time with transmission of H2S in a 175 km · increased risk to pipeline increases risk of gas release project economics due to pipeline integrity concerns Intermediate · duplication of · highest – must · no specific · no Case some facilities duplicate concern onshore and elements of onshore processing offshore and onshore

Deep Panuke Volume 2 (Development Plan) · March 2002 5-34 Onshore 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 still involves offshore treatment 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 third processing alternative reviewed involved the intermediate case. The intermediate case requires dehydration and H2S removal offshore, transportation to shore in a multiphase pipeline, with separation, dewpointing and condensate treatment occurring onshore. As the study of the intermediate case progressed, it was realised that the condensate must also be treated offshore for H2S removal since the pipeline and the onshore facility are designed for sweet service. As a result of this finding, the intermediate case was rejected since treating the condensate offshore required 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 suitability considerations.

The offshore facilities for the onshore processing 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, dewpointing facilities, condensate treatment, and sour water handling. Onshore processing is more expensive than the offshore processing due to the duplication of facilities including separation, TEG dehydration, condensate treatment, and sour water handling.

While proven and effective mitigation measures to address these environmental and safety concerns exist, PanCanadian’s preferred approach for this Project is to deal with the sour gas at source to minimize the potential for risk to the public. The environmental evaluation of onshore processing determined that handling the sour gas onshore increases the potential impact on the onshore environment through acidic deposition, storage of elemental sulphur, and stack emissions. In general, there are many more environmental receptors onshore that are sensitive to potential acidification from routine and fugitive sulphur emissions (e.g., freshwater habitat, soils) than offshore, with buffering capacity provided by the marine environment.

For onshore processing, additional safety and human health risk of handling sour gas onshore near populated areas was also considered. The probability of a large-scale accidental release of sour gas from a processing facility is remote, but is nevertheless a serious concern. While the oil and gas industry has a proven ability to handle sour gas in populated areas, PanCanadian believes the most prudent approach

Deep Panuke Volume 2 (Development Plan) · March 2002 5-35 for the Project, when an economic choice is presented, is to keep sour gas away from populated areas thereby minimizing risk.

Onshore processing also presents operational and pipeline integrity concerns due to difficulties that may be encountered in guaranteeing that water will not enter the export pipeline. Hydrocarbons and H2S, in the presence of water, can form hydrates. Also, water and H2S, can cause localised internal corrosion, which results in a pipeline integrity risk. The pipeline integrity risk can be reduced with the use of corrosion inhibitors to manage localised corrosion created by H2S and water. While the corrosion inhibitors reduce the pipeline risk to an acceptable level in an onshore environment, the risk is still a significant concern given the length of the subsea pipeline and potentially prolonged downtime for the Project. Internally coating the pipeline was investigated to decrease this risk of corrosion; however, increased costs associated with “cladding” a pipeline make onshore processing not economically feasible when the cost criterion is applied.

Condensate Handling

The total volume of condensate that will be produced with Deep Panuke gas at peak production (400 MMscfd) is less than 2,000 barrels per day. This is a very small volume of condensate compared to the SOEP which produces approximately 20,000 barrels per day.

Offshore processing could include transportation of condensate, separated from produced gas on the production platform, to shore in a second, dedicated, condensate pipeline. Use of a dedicated condensate pipeline would also necessitate construction of condensate handling facilities, such as storage tanks, onshore. The alternative to a dedicated condensate line to shore is using condensate as the primary fuel on the production platform. Using condensate as fuel eliminates the substantial capital and operating costs associated with a condensate pipeline to shore and necessary onshore condensate handling facilities. Accordingly, transporting condensate to shore, rather than using it as fuel on the platform, is not economically feasible.

A small surplus of not economically recoverable condensate may be present in the early years of production after accounting for the fuel needs; however, this surplus can be injected into an acceptable reservoir. The deletion of the second pipeline to shore and the associated onshore facilities more than offset the injection costs resulting in net capital cost savings to the Project.

A subsea storage tank for handling the total condensate volume offshore was also considered. A tank was investigated with an optimum off-loading frequency of approximately six months to accommodate the relatively small quantity of condensate to be produced. Although subsea storage tanks are used in other facilities, the relatively shallow water at the Deep Panuke site presented a risk for potential

Deep Panuke Volume 2 (Development Plan) · March 2002 5-36 seafloor scour necessitating large quantities of rock protection. The prohibitive installation costs resulted in this option not being economically feasible.

Additional Considerations

By using condensate as fuel, PanCanadian maximizes the amount of gas sent to shore for sale.

Finally, an important consideration that supports the selection of offshore processing as the preferred option is the pipeline to shore transporting sweet gas. Based on the production profile for the Deep Panuke Project, the maximum production rate will likely drop after three to four years. With a sweet pipeline to shore, other projects that are developed after the Deep Panuke Project may be able to utilise the surplus capacity in PanCanadian’s sweet pipeline to bring their gas to shore. The increasing surplus capacity in PanCanadian’s pipeline may allow another project, with marginal economics, to be developed by using existing infrastructure and, at the same time, minimize the proliferation of facilities, which was raised as an issue during public consultation.

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 keeping acid gas away from populated areas which minimizes risk; · offshore injection of acid gas minimizes environmental impact; · reduced risk related to pipeline integrity in an offshore environment with the removal of both water

and H2S offshore; · handling condensate offshore improves economic feasibility of the Project; and · a sweet gas pipeline to shore may potentially be used by other offshore producers as PanCanadian’s production declines.

5.10.6 Acid Gas Handling

As a result of adopting offshore processing, 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 summarised in Table 5.10.

Deep Panuke Volume 2 (Development Plan) · March 2002 5-37 Table 5.10 Acid Gas Handling Development Alternatives Technically and Alternative Technical Suitability Cost Commercial Risk Economically Concept Deliverability Safety Environmental Impact Feasible Acid gas · proven technology · approximately $26 · costs may be higher · yes · intermediate risk – · incremental risk over · Significantly reduces air injection MM than anticipated due specialized equipment flaring due to handling emissions and marine · used extensively in to drilling has long lead delivery of high pressure acid discharges compared with Western Canada – difficulties but can be purchased in gas other options PanCanadian has Canada existing installations Flaring · proven technology · approximately $1 · not applicable · yes · least risk – equipment is · some risk associated · Highest air emissions MM readily available in with handling acid gas · used worldwide Canada · fuel gas required to ensure efficient operation Seawater · relatively new · approximately $13 · not applicable · yes · greatest risk – equipment · incremental risk over · Higher marine discharges scrubber technology for offshore MM is long lead delivery and flaring due to the compared with other – two offshore will likely be purchased handling of low pH options, lower air emissions facilities exist · requires 90% less internationally effluent compared with flaring fuel gas than flaring to ensure efficient operation

Offshore sulphur · offshore footprint · very high · not applicable · no recovery required makes option uneconomical

Deep Panuke Volume 2 (Development Plan) · March 2002 5-38 Flaring acid gas consists of directing the acid gas stream to a flare system for incineration and emission to the atmosphere. Although flaring is a relatively low-cost option, the SO2 resulting from the incineration process can be scavenged from the air by rain or may oxidise further to sulphate particles which can contribute to acidic deposition. In this situation the amount of SO2 released is within air quality guidelines, though long term emissions may be of concern with regard to federal/provincial agreements to reduce acid rain. This alternative was, however, ruled out because other economic alternatives are available.

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 countercurrently. 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.

The seawater scrubbing technology is successfully used in many facilities world wide, including two offshore facilities, although the offshore facilities are recently constructed and do not have an established performance record. The seawater scrubbing option has a substantially lower capital cost when compared to acid gas injection. Although an environmental review of this technology showed no significant impact to the environment, there were a number of atmospheric emissions and marine discharges that were relatively higher than the other acid gas management options. The seawater scrubbing option also had associated marine discharges (lower pH, chemical oxygen demand) not present with the other options. The seawater scrubber was rejected based on lack of performance data and higher atmospheric/marine emissions.

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.

Injecting acid gas into a reservoir is based on technology commonly used in gas and oilfield developments, including existing PanCanadian facilities. Compressors are used to inject the gas into the reservoir through a disposal well. In general, acid gas injection minimizes both air emissions and marine discharges using proven technology. In addition to minimizing SO2 emissions acid gas injection also minimizes CO2 emissions through injection, compared with the other options.

In summary, acid gas injection was selected as the preferred development alternative due to the established track record of the technology even though it is the most costly option. Acid gas injection also offers important environmental benefits through minimization of atmospheric and marine emissions.

Deep Panuke Volume 2 (Development Plan) · March 2002 5-39 5.10.7 Produced Water Disposal

The treatment and disposal of produced water overboard is commercially, technically and environmentally acceptable with proven technology and has been successfully practiced worldwide. In an effort to reduce discharges, PanCanadian evaluated the possibility of simultaneously injecting the produced water with the acid gas or surplus condensate into the injection wells. A summary of the investigation is included below and summarised in Table 5.11.

Simultaneous injection of produced water and acid gas is not widely practiced due to risks associated with phase separation (acid gas cap forms in the well reducing the ability to inject and presenting a safety risk), hydrate formation, and corrosion. However, given the right conditions, simultaneous injection can be accomplished successfully as proven by PanCanadian on the Thompson Lake facility in Alberta. The success of this process depends on the acid gas being completely dissolved in the water to prevent separation of the two phases. For the Deep Panuke development, the produced water production rate is not of a sufficient volume for dissolving the acid gas stream and this alternative was rejected since it was not technically feasible (DPA – Part 2, Ref.# 5.10.7.1).

Also, based on experience in western Canadian oil and gas facilities, simultaneous injection of produced water and condensate will likely create emulsions, hydrates, scale or reduced relative permeability creating restrictions in or near the wellbore. This will lead to inefficient operation and increased frequency of workovers. Therefore, the simultaneous injection of water and condensate is neither technically nor economically feasible.

Deep Panuke Volume 2 (Development Plan) · March 2002 5-40 Table 5.11 Produced Water Development Alternatives Technically and Concept Alternative Technical Suitability Cost Commercial Risk Safety Environmental Impact Economically Feasible Deliverability Treatment and disposal · proven technology · least expensive · not applicable · yes · not applicable · no risk · EIS concludes no overboard significant impact to the · currently used worldwide in environment offshore oil and gas facilities · Water will be treated · PanCanadian has successfully used and disposed according this technology on the Cohasset to existing regulations Project

Simultaneous injection · not technically feasible · higher cost · not applicable · no into acid gas injection than treatment well · inadequate volume of produced and disposal water to dissolve acid gas overboard

Simultaneous injection · not economically feasible · higher cost · not applicable · no into condensate than treatment injection well · condensate and water may form and disposal emulsions, hydrates, scale or create overboard relative permeability problems causing restrictions in or near wellbores necessitating workovers

Deep Panuke Volume 2 (Development Plan) · March 2002 5-41