October 20, 2004 Shell Canada Limited Post Office Box 100, Station ‘M’ Calgary, Alberta T2P 2H5
Delivered by Courier
Michel Mantha Secretary National Energy Board 444 Seventh Avenue S.W. Calgary, AB T2P 0X8
Dear Sir:
Re: Shell Canada Limited Development Plan Application Pursuant to the Canada Oil and Gas Operations Act (COGOA)
Enclosed are 15 copies of Part I of an application for approval of a development plan pursuant to subsection 5.1 of the COGOA respecting the Niglintgak field (the Application).
Niglintgak is a component of the Mackenzie Gas Project. The other components are:
• two other onshore natural gas fields, Taglu and Parsons Lake
• the Mackenzie gathering system, which includes:
• gathering pipelines to transport production from the three gas fields to the Inuvik area facility
• the Inuvik area facility, which will process production from the three gas fields into gas and natural gas liquids
• a pipeline to transport natural gas liquids from the Inuvik area facility to Norman Wells
• the Mackenzie Valley pipeline, which will transport gas from the Inuvik area facility to an interconnection with the NOVA Gas Transmission Ltd. system in Alberta
Shell Canada Limited is submitting the Application as the registered interest holder and operator of the Niglintgak field.
In accord with subsection 5.1(3) of the COGOA, the Application is in two parts:
• A volume entitled Application for Approval of the Development Plan for Niglintgak Field, Project Description – (Part 1 of the Application)
• A volume entitled Application for Approval of the Development Plan for Niglintgak Field, Confidential Studies – (Part 2 of the Application)
Part 2 of the Application contains financial, commercial, scientific or technical information, which is: – 2 – a) Confidential under the terms of the Access to Information Act (Canada) and is not to be released or made public except as provided in that Act, and b) Privileged under the terms of the Canada Petroleum Resources Act and is not to be disclosed without the written consent of Shell Canada Limited.
Part 2 of the Application, Confidential Studies, will be submitted to the National Energy Board under separate cover.
In addition to the above, the Application is supported by an Environmental Impact Statement, comprised of eight volumes (the EIS), and Public Consultation Program information comprised of two volumes. The EIS and Public Consultation Program information, which are each being submitted to the National Energy Board (NEB) under separate cover by Imperial Oil Resources Ventures Limited, also support concurrent applications for the other components of the Mackenzie Gas Project that are being submitted to the NEB by the respective operators.
Please direct all communications regarding the Application to:
Mr. Paul Davies and to: Mr. Shawn Denstedt Regulatory Application Coordinator Bennett Jones LLP Frontier – Northern Development 4500 Bankers Hall East Shell Canada Limited 855 Second Street S.W. 400 Fourth Avenue S.W. Calgary, AB T2P 4K7 Calgary, AB T2P 2H5 Phone: (403) 298-3449 Phone: (403) 691-4146 Fax: (403) 265-7219 Fax: (403) 691-2444 e-mail: [email protected] e-mail: [email protected]
Yours truly,
SHELL CANADA LIMITED
Dave Collyer Vice President, Frontier
Enclosures cc: Mr. Shawn Denstedt, Bennett Jones LLP Mr. Brian Chambers, Northern Gas Project Secretariat Application for Approval of the Development Plan for
Niglintgak Field
Project Description
Submitted to: National Energy Board
Submitted by: Shell Canada Limited
August 2004
Cover photograph courtesy of the Government of the Northwest Territories IN THE MATTER OF the Canada Oil and Gas Operations Act, R.S.C. 1985, c.0-7, as amended (hereinafter referred to as the Act), and the Regulations made thereunder;
AND IN THE MATTER OF an application by Shell Canada Limited pursuant to Section 5.1 of the Act for approval of a Development Plan with respect to the lands within Significant Discovery Licence (SDL) 19;
AND IN THE MATTER OF the Canadian Environmental Assessment Act, S.C. 1992 c.37, as amended and the Regulations made thereunder.
To: Office of the Secretary National Energy Board 444 Seventh Avenue S.W. Calgary, Alberta T2P 0X8
APPLICATION BY SHELL CANADA LIMITED
1. Shell Canada Limited (Shell) hereby applies to and requests approval by the National Energy Board (NEB), pursuant to section 5.1 of the Act, of a development plan with respect to the natural gas and natural gas liquids within, upon, under or producible from Significant Discovery Licence SDL 19 (the Niglintgak field).
2. The information contained in this application has been prepared solely for submission to the NEB for its consideration of the Development Plan Application and does not form part of the public disclosure record for oil and gas activities for Shell.
3. Shell is the interest holder in the Niglintgak field. Shell will be the operator of the Niglintgak field and will hold legal title to the production and processing facilities described in the development plan for the Niglintgak field submitted with this application.
4. Natural gas will be transported from the Niglintgak field by the proposed Mackenzie gathering system to the Inuvik area gas processing facility. Natural gas from the Inuvik area facility will be transported on the proposed Mackenzie Valley pipeline which will connect with the Alberta natural gas pipeline system. The gathering pipelines will also transport natural gas and natural gas liquids from the Taglu and Parsons Lake gas fields.
5. The gathering system is the subject of a separate and concurrent application for authorization to construct made to the NEB by Imperial Oil Resources Ventures Limited as operator on behalf of the owners of the gathering system. Other separate applications for the Taglu and Parsons Lake gas fields and the Mackenzie Valley pipeline are also being concurrently submitted to the NEB for gas field development plan approvals and a pipeline Certificate of Public Convenience and Necessity, respectively. The Niglintgak, Taglu and Parsons Lake gas fields, the Mackenzie gathering system and the Mackenzie Valley pipeline are, together, called the Mackenzie Gas Project. – 2 –
6. The Niglintgak field is estimated to contain recoverable resources of about 27 Gm3 of raw natural gas and natural gas liquids. The productive life of the field is estimated to be about 25 years, with planned initial daily wellhead production rates of about 4.3 Mm3/d.
7. Capital costs for Niglintgak field pre-development work, facilities construction and development well drilling are estimated to be about $369 million (2003$). Subject to regulatory approval, the Niglintgak field is scheduled to begin production in 2009.
8. The Niglintgak field is subject to review by a joint review panel appointed by the Minister of the Environment and the Mackenzie Valley Environmental Impact Review Board for a common environmental review of the Mackenzie Gas Project. The preface to the Niglintgak field development plan contains information on the coordination of the Niglintgak field development plan and various submissions by the proponents of the Mackenzie Gas Project, including those to support the environmental review.
9. Part 2 of this Application contains financial, commercial, scientific or technical information which:
a. is confidential under the terms of the Access to Information Act (Canada) and is not to be released or made public except as provided in that Act, and
b. is privileged under the terms of the Canada Petroleum Resources Act and is not to be disclosed without Shell’s written consent.
ALL OF WHICH IS RESPECTFULLY SUBMITTED.
This application is made at the City of Calgary in the Province of Alberta this 20th day of October, 2004.
Dave Collyer Vice President, Frontier Shell Canada Limited
Communications with respect to this application for approval of the development plan for the Niglintgak field should be sent to:
Mr. Paul Davies and to: Mr. Shawn H. T. Denstedt Shell Canada Limited Bennett Jones LLP 400 – 4th Avenue S.W. 4500 Bankers Hall East P.O. Box 100, Station M 855 – 2nd Street S.W. Calgary, AB T2P 2H5 Calgary, AB T2P 4P7
Phone: (403) 691-2208 Phone: (403) 298-3449 Fax: (403) 691-2444 Fax: (403) 265-7219 e-mail: [email protected] e-mail: [email protected] Section P.1 PREFACE
APPLICATION FOR APPROVAL OF THE DEVELOPMENT PLAN FOR NIGLINTGAK FIELD PROJECT DESCRIPTION EXECUTIVE SUMMARY
P.1.1 PURPOSE OF THIS PLAN
Shell Canada Limited (Shell) proposes to develop the natural gas resources recoverable from Significant Discovery Licence 19 (the Niglintgak field). The Niglintgak field is located about 120 km northwest of Inuvik and 85 km west of Tuktoyaktuk in the Northwest Territories. Shell is submitting this development plan for the Niglintgak field to the National Energy Board (NEB) for approval under the Canada Oil and Gas Operations Act (COGOA).
P.1.2 EXPLORATION HISTORY
The Niglintgak field was discovered by Shell in 1973 when the H-30 well was drilled. Appraisal well C-58, drilled the same year, was located 6 km to the southeast. Three infill wells were also drilled:
• M-19 in 1975 • B-19 in 1976 • E-58 in 1977
All of these wells have been abandoned. Shell has spent in excess of $120 million (2003$) on exploring the Niglintgak field and preparing regulatory applications for its development. Shell’s proposed development seeks to recover the company’s investment and realize the full value of the Niglintgak field in a manner that is consistent with its seven principles of sustainable development. Based on the most recent interpretations of the exploration data obtained, the proponent estimates that the Niglintgak field might contain about 27 Gm3 of recoverable natural gas and natural gas liquids (NGLs).
P.1.3 PRODUCTION FACILITIES
The main production facilities at the Niglintgak field will consist of six to 12 production wells located on three well pads. A system of above-ground flow lines will bring the produced gas and associated NGLs to a gas conditioning facility located in the Kumak Channel. The development will also include a disposal well, a disposal sump for cuttings disposal, and associated infrastructure, such as an emergency shelter and helipads. One deep sand well and three A sand wells will be drilled from the north well pad. One A sand well will be drilled from the centre well pad, while a deep sand well will be drilled from the south
August 2004 Shell Canada Limited P-i NDPA-P1 Section P.1 PREFACE EXECUTIVE SUMMARY
P.1.3 PRODUCTION FACILITIES (cont’d)
well pad. Based on the results of the reservoir monitoring plan, up to six additional wells might be required after start-up to deplete the reservoir.
Construction is planned over the three winter seasons following NEB approval for the Niglintgak field, from 2006 until 2009. The Operations Phase is planned to begin in 2009 and continue for about 25 years.
P.1.4 ESTIMATED CAPITAL AND OPERATING COSTS
Initial capital expenditures for drilling and facilities at the Niglintgak field are expected to total $369 million. The estimated operations and maintenance expenditure at Niglintgak over the life of the gas field is $250 million.
P.1.5 TRANSPORTATION PLAN
One of the main components required for realizing the opportunity presented by the resources of the Niglintgak field is a means of transporting the natural gas and NGLs to market. The Mackenzie Gas Project consists of developing natural gas in the Mackenzie Delta from the three largest discovered onshore natural gas fields, known as the anchor fields:
• Niglintgak • Parsons Lake • Taglu
The owners of the three anchor fields are proposing to construct the Mackenzie gathering system, which consists of gathering pipelines to collect the natural gas and associated NGLs and transport them to a facility located near Inuvik (the Inuvik area facility). The Mackenzie gathering system will also include gas processing and NGL recovery facilities at the Inuvik area facility and an NGL pipeline to extend south about 480 km from the Inuvik area facility to Norman Wells, where it will tie in to the existing Enbridge Pipelines (NW) Inc. pipeline. The Mackenzie Gas Project also includes the Mackenzie Valley pipeline, which will extend from Inuvik along the Mackenzie River to Norman Wells and continue south to connect to an extension of the NOVA Gas Transmission Ltd. (NGTL) system, south of the Northwest Territories–Alberta boundary.
Imperial Oil Resources Ventures Limited will operate both the Mackenzie gathering system and the Mackenzie Valley pipeline system.
P.1.6 ENVIRONMENTAL AND SOCIO-ECONOMIC EFFECTS
In keeping with the direction provided by the various regulatory agencies responsible for assessing and regulating energy developments in the Northwest Territories, Shell, together with the other proponents of the Mackenzie Gas Project, developed an Environmental Impact Statement (EIS) for the Mackenzie
P-ii Shell Canada Limited August 2004 NDPA-P1 Section P.1 PREFACE EXECUTIVE SUMMARY
Gas Project. The EIS describes the existing baseline conditions, the potential effects of the project, the associated measures to reduce these effects and the predicted residual effects after mitigation.
The environmental assessment of the project focused on identifying issues most important to potentially affected northern communities. These key issues were identified through a public consultation process that began in 2001 and will continue throughout the life of the project.
To ensure that the EIS did not under-report potential effects, a precautionary principle was applied, which requires that where threats of serious or reversible damage exist, lack of full scientific certainty will not be used as a reason for postponing cost-effective measures to prevent environmental degradation. Although some studies are ongoing, the field development is not expected to have any significant adverse environmental or socio-economic effects, taking into account available mitigation strategies and extensive monitoring commitments.
The concept of environmental and socio-economic sustainability was used as the basis for determining the significance of the project’s effects. Shell’s commitment to sustainable development is one of the company’s key business strategies. The Niglintgak development will be managed to ensure that key sustainable development principles are maintained throughout the design, construction and operations phases of the project.
P.1.7 PROJECT BENEFITS
Planning, designing, constructing, operating and maintaining the Niglintgak field and the overall Mackenzie Gas Project will generate a significant demand for qualified labour. To the extent possible, qualified Aboriginal and other northern residents and businesses in the Northwest Territories, as well as other Canadians, will be provided with employment or contracting opportunities. The project will also result in indirect and induced economic and employment benefits through the procurement of supplies and materials for the project, and because people employed directly and indirectly by the project will be spending their disposable income.
Consistent with sustainable development principles, the major project priorities are to:
• design, construct and operate the project safely
• demonstrate care for the environment
• create a wide range of business and employment opportunities for Aboriginal, other northern and other Canadian residents
• meet quality, cost and schedule targets necessary to meet Shell’s shareholder investment expectations
August 2004 Shell Canada Limited P-iii NDPA-P1 Section P.1 PREFACE EXECUTIVE SUMMARY
P.1.7 PROJECT BENEFITS (cont’d)
The Mackenzie Gas Project will be anchored by developing about 164 Gm3 of sweet natural gas from the three anchor fields. The Mackenzie Valley pipeline is needed to economically transfer the natural gas from the fields to southern markets over the next 25 to 30 years.
P.1.8 CONSULTATION
The Mackenzie Gas Project consultation activities were designed to meet the communities’ expectations for meaningful involvement in developing the project, and to satisfy the proponents’ corporate and regulatory requirements for public consultation. The proponents used various methods to address the broad range of interests, levels of understanding and needs of the project stakeholders. The methods and activities were also designed to accommodate the remote location of some of these stakeholders. Considerable effort was made to respect consensus-based decision making and information exchange, to develop a consultation program that would provide the communities with the opportunity for input.
Through consultation, the proponents sought to explain the purpose, needs and limitations of the project, and at the same time, sought to understand and address local concerns and to provide information to the project team for consideration in the program execution. The consultation program will extend beyond the regulatory submission and will continue throughout the construction and operations of the Niglintgak field.
P.1.9 CONCLUSION
Shell views itself as a long-term stakeholder in the North. As a result, Shell is committed to contributing to sustainable development and integrating economic, environmental and social considerations in the decision-making process across all of its business activities. Shell will incorporate sustainable development principles into the design and development of Niglintgak in a way that enhances commercial benefits, reduces environmental impacts and takes into account traditional uses for land. Shell is committed to developing the field in a socially responsible way that benefits Canadians, including Aboriginal and other northerners.
P-iv Shell Canada Limited August 2004 NDPA-P1 CONTENTS
APPLICATION FOR APPROVAL OF THE DEVELOPMENT PLAN FOR NIGLINTGAK FIELD PROJECT DESCRIPTION TABLE OF CONTENTS
Letter of Transmittal
The Application
Preface Executive Summary ...... P-i
Contents Table of Contents ...... v List of Illustrations ...... xvii
1. Introduction 1. Development Plan Overview ...... 1-1 1.1.1 Approval Requested ...... 1-1 1.1.1.1 Niglintgak Location ...... 1-1 1.1.1.2 Conceptual Design Flexibility ...... 1-2 1.1.1.3 Approval Request ...... 1-2 1.1.2 Scope of Application ...... 1-2 1.1.3 Canada Benefits Plan ...... 1-4 1.1.4 Project Proponent ...... 1-4 2. Project Principles and Policies ...... 1-5 1.2.1 Policies ...... 1-5 1.2.2 Sustainable Development ...... 1-5 1.2.3 Health, Safety and Environment Policy ...... 1-7 3. Project Purpose and Need ...... 1-9 1.3.1 Project Purpose ...... 1-9 1.3.2 Project Need ...... 1-9 4. Niglintgak Field Development ...... 1-11 1.4.1 Mackenzie Gas Project Overview ...... 1-11 1.4.2 Niglintgak Discovery and Delineation ...... 1-12 1.4.3 Niglintgak Development Phases ...... 1-13 1.4.3.1 Feasibility Study Phase ...... 1-13 1.4.3.2 Project Definition Phase ...... 1-13 1.4.3.3 Construction Phase ...... 1-13 1.4.3.4 Operations Phase ...... 1-14 1.4.4 Key Field Characteristics ...... 1-14 1.4.4.1 Scope ...... 1-14 1.4.4.2 Shallow Gas Reservoir ...... 1-15 1.4.4.3 Compartmentalized Reservoir ...... 1-15 1.4.4.4 Delta Floodplain with Permafrost ...... 1-15
August 2004 Shell Canada Limited v NDPA-P1 CONTENTS TABLE OF CONTENTS
1.4.4.5 Development within Kendall Island Bird Sanctuary ...... 1-15 1.4.4.6 Shallow Water Depths ...... 1-15 1.4.5 Niglintgak Development Process ...... 1-16 1.4.5.1 Design Concept ...... 1-16 1.4.5.2 Wells and Well Pads ...... 1-16 1.4.5.3 Flow Lines ...... 1-18 1.4.5.4 Gas Conditioning Facility ...... 1-18 1.4.5.5 Support Infrastructure ...... 1-19 1.4.5.6 Transportation ...... 1-19 1.4.6 Development Schedule ...... 1-20 5. Regulatory Requirements ...... 1-23 1.5.1 Cooperation Plan ...... 1-23 1.5.2 Regulatory Process ...... 1-23 1.5.2.1 Preliminary Information Package ...... 1-23 1.5.2.2 Commercial Discovery Application ...... 1-24 1.5.2.3 Other Regulatory Applications and Approvals ...... 1-24
2. Geology, Geophysics and Petrophysics 1. Geological Description ...... 2-1 2.1.1 Regional History ...... 2-1 2.1.1.1 Burial and Structural History ...... 2-1 2.1.1.2 Source Rocks ...... 2-2 2.1.1.3 Geological Seal ...... 2-2 2.1.1.4 Reservoir Blocks ...... 2-2 2.1.2 Reservoir Stratigraphy ...... 2-4 2.1.2.1 Y and Z Sands ...... 2-7 2.1.2.2 U to X Sands ...... 2-7 2.1.2.3 Q to T Sands ...... 2-7 2.1.2.4 M to P Sands ...... 2-7 2.1.2.5 K and L Sands ...... 2-7 2.1.2.6 I and J Sands ...... 2-7 2.1.2.7 H Sand ...... 2-7 2.1.2.8 D to G Sands ...... 2-8 2.1.2.9 B and C Sands ...... 2-8 2.1.2.10 A Sand ...... 2-8 2.1.3 Sedimentology And Diagenesis ...... 2-9 2.1.4 Hydrogeology ...... 2-10 2.1.4.1 Current Aquifer Conditions ...... 2-10 2.1.4.2 Past Active Aquifer ...... 2-11 2.1.4.3 Aquifer Extent ...... 2-11 2. Geophysics ...... 2-13 2.2.1 Seismic Acquisition and Interpretation ...... 2-13 2.2.1.1 Seismic Acquisition ...... 2-13 2.2.1.2 Seismic Quality and Calibration ...... 2-14 2.2.2 Horizons ...... 2-15 2.2.2.1 Top A and D Sands ...... 2-15 2.2.2.2 L-Upper Sand ...... 2-15 2.2.3 Faults ...... 2-16 2.2.4 Amplitudes ...... 2-16 2.2.5 Depth Conversion ...... 2-17 vi Shell Canada Limited August 2004 NDPA-P1 CONTENTS TABLE OF CONTENTS
2.2.5.1 A Sand Depth-Structure Map Construction ...... 2-17 2.2.5.2 L Sand Depth-Structure Map Construction ...... 2-19 2.2.6 Faults Used in the Depth-Structure Maps ...... 2-19 3. Petrophysics ...... 2-21 2.3.1 Lithology, Porosity and Permeability ...... 2-21 2.3.1.1 Lithology ...... 2-21 2.3.1.2 Porosity ...... 2-21 2.3.1.3 Permeability ...... 2-21 2.3.2 Petrophysical Evaluation ...... 2-23 2.3.3 Fluid Identification and Saturation ...... 2-24 2.3.4 Reservoir Definition ...... 2-25 2.3.5 Future Data Acquisition ...... 2-27 2.3.5.1 Formation Evaluation Program ...... 2-27 2.3.5.2 Evaluation Techniques ...... 2-27
3. Reservoir Engineering 1. Reservoir Data ...... 3-1 3.1.1 3-D Dynamic Reservoir Model ...... 3-1 3.1.2 Reservoir Description ...... 3-1 3.1.3 Well Test Data ...... 3-2 3.1.3.1 Pressure-Versus-Depth Plots ...... 3-3 3.1.3.2 Temperature-Versus-Depth Plot ...... 3-3 3.1.3.3 In Situ Methane Hydrates ...... 3-3 3.1.3.4 Core Data Analysis ...... 3-3 3.1.4 Reservoir Fluid Properties ...... 3-6 2. Resources and Production Estimates ...... 3-9 3.2.1 Approach ...... 3-9 3.2.2 Probabilistic Modelling ...... 3-9
4. Reservoir Depletion 1. Introduction ...... 4-1 4.1.1 Approach ...... 4-1 4.1.2 Reservoir Simulation ...... 4-1 4.1.3 Development Alternatives ...... 4-2 4.1.4 Reservoir Uncertainties ...... 4-2 4.1.5 Reservoir Monitoring Plan ...... 4-3 2. Reservoir Simulation ...... 4-5 4.2.1 Purpose ...... 4-5 4.2.2 Reservoir Simulation Model ...... 4-5 4.2.2.1 Dynamic Model Initialization ...... 4-6 4.2.2.2 Regional Aquifer Model ...... 4-6 4.2.3 Water Production ...... 4-6 4.2.4 Evaluation Process ...... 4-6 4.2.5 Reservoir Simulation Results ...... 4-6 4.2.6 Reservoir Uncertainty Analysis ...... 4-7 4.2.7 A Sand Reservoir Realizations ...... 4-9 4.2.8 Horizontal Wells ...... 4-10 3. Alternatives Considered ...... 4-11 4.3.1 Assessment Process ...... 4-11 4.3.2 Screening Analysis ...... 4-11
August 2004 Shell Canada Limited vii NDPA-P1 CONTENTS TABLE OF CONTENTS
4.3.3 Detailed Evaluation ...... 4-12 4.3.3.1 Evaluation Results ...... 4-13 4.3.3.2 Concerns and Future Work ...... 4-14 4. Deferred Development ...... 4-15 4.4.1 Future Potential Development ...... 4-15 4.4.2 Other Significant Discovery Licences ...... 4-15 4.4.3 Future Resource Evaluations ...... 4-15 4.4.4 Special Drilling Spacing Units for Subsurface Drilling Locations ...... 4-16 5. Reservoir Management Plan ...... 4-17 4.5.1 Purpose of Data Collection ...... 4-17 4.5.2 Monitoring Program ...... 4-17 4.5.2.1 Formation Evaluation ...... 4-17 4.5.2.2 Monitoring Objectives ...... 4-17 4.5.2.3 Monitoring Strategy ...... 4-18 4.5.2.4 Monitoring Criteria ...... 4-18 4.5.3 Implementation Process ...... 4-19 4.5.3.1 Obtaining Data ...... 4-19 4.5.3.2 Analyzing Data ...... 4-20 4.5.3.3 Documenting Results ...... 4-20 4.5.3.4 Addressing Main Uncertainties Early ...... 4-20 4.5.4 Four-Dimensional Seismic ...... 4-20 6. Development Plan Key Features ...... 4-21 4.6.1 Key Features ...... 4-21 4.6.2 Wells ...... 4-21 4.6.3 Well Completions ...... 4-21 4.6.4 Reservoir Evaluation Programs ...... 4-22 4.6.5 Production Forecast and Assumptions ...... 4-22 4.6.6 Well Pad Facilities and Flow Lines ...... 4-22 4.6.7 Gas Conditioning Facility ...... 4-23 4.6.8 Utilities and Support Systems ...... 4-23
5. Design Criteria 1. Design Philosophy ...... 5-1 5.1.1 Design Approach ...... 5-1 5.1.2 Codes and Standards ...... 5-2 5.1.2.1 Legislation ...... 5-2 5.1.2.2 Design Codes and Standards ...... 5-2 2. Environmental Criteria ...... 5-5 5.2.1 Scope ...... 5-5 5.2.2 Site Description ...... 5-5 5.2.3 Meteorology ...... 5-6 5.2.3.1 Data ...... 5-6 5.2.3.2 Temperature ...... 5-6 5.2.3.3 Precipitation ...... 5-7 5.2.4 Hydrology ...... 5-8 5.2.4.1 Flooding and Ice Conditions ...... 5-9 5.2.4.2 Design Impact ...... 5-9 5.2.5 Hydrogeology ...... 5-9 5.2.6 Terrain ...... 5-10 5.2.7 Vegetation ...... 5-10 viii Shell Canada Limited August 2004 NDPA-P1 CONTENTS TABLE OF CONTENTS
3. Geotechnical Criteria ...... 5-13 5.3.1 Surficial Geology and Geomorphology ...... 5-13 5.3.1.1 Deposition Levels ...... 5-13 5.3.1.2 Wetlands ...... 5-13 5.3.1.3 Subsidence ...... 5-13 5.3.1.4 Seismic Activity ...... 5-14 5.3.2 Impacts on Design ...... 5-15 5.3.2.1 Gas Conditioning Facility ...... 5-15 5.3.2.2 Permafrost ...... 5-15 4. Functional Criteria ...... 5-17 5.4.1 Flow Streams and Design Rates ...... 5-17 5.4.1.1 Flow Rates ...... 5-17 5.4.1.2 Availability ...... 5-17 5.4.1.3 Hydrocarbon Liquids Design Flow Rate ...... 5-18 5.4.1.4 Produced Water Design Flow Rate ...... 5-19 5.4.1.5 Pressure ...... 5-19 5.4.2 Fluid Properties ...... 5-19 5.4.2.1 Hydrocarbon Composition ...... 5-19 5.4.2.2 Waxes, Asphaltenes and Emulsions ...... 5-19 5.4.2.3 Produced Water ...... 5-20 5.4.2.4 Sand ...... 5-20 5.4.2.5 Naturally Occurring Radioactive Material ...... 5-20 5.4.3 Product Specifications ...... 5-21
6. Drilling and Completions 1. Development Drilling ...... 6-1 6.1.1 Exploration and Delineation Drilling ...... 6-1 6.1.2 Initial Development Drilling Requirements ...... 6-1 6.1.3 Directional Drilling Design ...... 6-3 6.1.4 Casing Program ...... 6-4 6.1.4.1 Design Considerations ...... 6-4 6.1.4.2 Regulations and Standards ...... 6-4 6.1.4.3 Conductor ...... 6-4 6.1.4.4 Surface Hole and Casing ...... 6-4 6.1.4.5 Intermediate Hole – Section One and Casing ...... 6-4 6.1.4.6 Intermediate Hole – Section Two and Liner ...... 6-5 6.1.4.7 Main Hole – Completion and Casing ...... 6-5 6.1.5 Drilling Fluids ...... 6-5 6.1.6 Drilling Cuttings Disposal ...... 6-6 6.1.6.1 Disposal Plan ...... 6-6 6.1.6.2 Disposal Alternatives Considered ...... 6-7 6.1.7 Drilling Considerations – Selected Options and Alternatives ...... 6-8 6.1.7.1 Access for Drilling Operations ...... 6-8 6.1.7.2 Drilling Site Selection ...... 6-8 6.1.7.3 Drilling Pad Design and Layout ...... 6-9 6.1.7.4 Drilling Schedule and Alternatives ...... 6-9 6.1.8 Permafrost Protection ...... 6-11 6.1.8.1 Well Design and Well Spacing ...... 6-11 6.1.9 Potential Drilling Hazards ...... 6-11 6.1.9.1 Gas Cutting and Kicks ...... 6-12
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6.1.9.2 Formation Pressure Gradient and Abnormal Pressure ...... 6-12 6.1.9.3 Borehole Stability ...... 6-12 6.1.9.4 Permafrost – Borehole Enlargement ...... 6-13 6.1.9.5 Circulation and Mud Losses ...... 6-13 6.1.9.6 Differential Sticking ...... 6-13 6.1.9.7 Cementing and Gas Migration ...... 6-13 6.1.10 Well Control ...... 6-14 6.1.11 Drilling Equipment ...... 6-14 6.1.12 Drilling and Completions Execution ...... 6-15 6.1.12.1 Drilling Pads and Ice Roads ...... 6-15 6.1.12.2 Well Drilling and Completions ...... 6-15 6.1.12.3 Drilling Personnel Transport ...... 6-16 2. Completions ...... 6-17 6.2.1 Design Requirements ...... 6-17 6.2.1.1 Production Reliability and Rigless Intervention ...... 6-17 6.2.1.2 Subsurface Safety Valves ...... 6-17 6.2.1.3 Hydrate Inhibition ...... 6-17 6.2.1.4 Sand Control ...... 6-17 6.2.1.5 Water Production ...... 6-18 6.2.1.6 Commingled Production ...... 6-18 6.2.1.7 Stimulation ...... 6-18 6.2.2 Completion Designs ...... 6-18 6.2.2.1 A Sand – Southeast Block B-19 and E-58 ...... 6-18 6.2.2.2 A Sand – Northwest Block H-30 and M-19 ...... 6-19 6.2.2.3 D, E and F-G Sands (with Possible H Sand Evaluation and Production) ...... 6-19 6.2.2.4 L, M and N Sands (with Possible O-P Sand Evaluation and Production) ...... 6-20 6.2.3 Tubular Program ...... 6-20 6.2.4 Metallurgy ...... 6-24 6.2.5 Well Testing ...... 6-24 6.2.6 Fluid Handling ...... 6-24 6.2.7 Completions Equipment ...... 6-25 6.2.8 Perforations ...... 6-25 6.2.9 Wellhead Equipment ...... 6-25 6.2.10 Alternatives Considered ...... 6-25 6.2.10.1 A Sand – Southeast Block B-19 and E-58 ...... 6-25 6.2.10.2 A Sand – Northwest Block H-30 and M-19 ...... 6-26 6.2.10.3 D, E and F-G Sands ...... 6-26 6.2.10.4 L, M and N Sands ...... 6-26
7. Production Facilities 1. Development Plan ...... 7-1 7.1.1 Development Approach ...... 7-1 7.1.2 Development Basis ...... 7-1 7.1.2.1 Production Forecasts ...... 7-1 7.1.2.2 Well Production Compositions ...... 7-2 7.1.3 Scope of Facilities ...... 7-2 7.1.3.1 Well Pads ...... 7-3 7.1.3.2 Flow Lines ...... 7-3 x Shell Canada Limited August 2004 NDPA-P1 CONTENTS TABLE OF CONTENTS
7.1.3.3 Gas Conditioning Facility ...... 7-3 7.1.3.4 Process Utilities ...... 7-3 7.1.3.5 Construction and Drilling ...... 7-4 7.1.4 Facility Expansion and Third-Party Access ...... 7-4 7.1.5 Facility Layout ...... 7-4 2. Well Pad Facilities and Flow Lines ...... 7-7 7.2.1 Well Pad Facilities ...... 7-7 7.2.2 Flow Lines ...... 7-8 7.2.3 Kumak Channel Crossing ...... 7-9 7.2.4 Pig Launcher and Receiver ...... 7-10 7.2.5 Hydrate Control ...... 7-10 7.2.6 Corrosion Control ...... 7-12 3. Gas Conditioning Facilities ...... 7-15 7.3.1 Scope ...... 7-15 7.3.2 Inlet Separation ...... 7-15 7.3.3 Gas Compression ...... 7-15 7.3.4 Gas Dehydration ...... 7-17 7.3.5 Gas Refrigeration ...... 7-18 7.3.5.1 Gas Chiller ...... 7-19 7.3.5.2 Propane Refrigerant Compressor ...... 7-19 7.3.5.3 Propane Refrigerant Condenser ...... 7-19 7.3.6 Metering ...... 7-19 7.3.7 Hydrocarbon Liquids Tankage and Reinjection ...... 7-20 7.3.8 Produced-Water Handling System ...... 7-20 4. Process Utilities And Support Systems ...... 7-21 7.4.1 Scope ...... 7-21 7.4.2 Electrical Power Generation ...... 7-21 7.4.3 Utility Heat and Heat Tracing ...... 7-22 7.4.4 Control and Instrumentation ...... 7-22 7.4.5 Communication Systems ...... 7-23 7.4.6 Relief and Blowdown System ...... 7-24 7.4.7 Flare System ...... 7-24 7.4.8 Fuel Gas Systems ...... 7-25 7.4.9 Tankage and Storage ...... 7-26 7.4.10 Other Utilities and Support Systems ...... 7-26 7.4.10.1 Storage Areas ...... 7-26 7.4.10.2 Instrument and Utility Air ...... 7-26 7.4.10.3 Utility Cooling System ...... 7-27 7.4.10.4 Closed and Open Drain Systems ...... 7-27 7.4.10.5 Potable Water System ...... 7-27 7.4.10.6 Sewage Treatment System ...... 7-27 5. Civil and Infrastructure Facilities ...... 7-29 7.5.1 Site Access ...... 7-29 7.5.1.1 Helicopter Access ...... 7-29 7.5.1.2 Airstrip and Helicopter Pads ...... 7-30 7.5.1.3 Boat and Barge Access ...... 7-30 7.5.1.4 Roads ...... 7-30 7.5.2 Existing Facilities ...... 7-31 7.5.3 Shared Facilities ...... 7-31 7.5.4 Foundations ...... 7-31
August 2004 Shell Canada Limited xi NDPA-P1 CONTENTS TABLE OF CONTENTS
7.5.4.1 Well Pads ...... 7-31 7.5.4.2 Gas Conditioning Facility ...... 7-32 7.5.5 Accommodation ...... 7-33 6. Facilities Safety Design ...... 7-35 7.6.1 Design Considerations ...... 7-35 7.6.2 Gas Conditioning Facilities ...... 7-35 7.6.2.1 Fire and Gas Protection ...... 7-35 7.6.2.2 Active Fire Protection ...... 7-36 7.6.2.3 Passive Fire Protection ...... 7-36 7.6.2.4 Additional Safety Systems ...... 7-36 7.6.3 Well Pad Facilities and Flow Lines ...... 7-36 7. Development Alternatives ...... 7-37 7.7.1 Alternatives Considered ...... 7-37 7.7.2 Land-Based Gas Conditioning Facility ...... 7-37
8. Pipeline Transport Systems 1. Gathering System ...... 8-1 8.1.1 Scope ...... 8-1 8.1.2 Gathering System Components ...... 8-2 8.1.2.1 Gathering Pipelines ...... 8-2 8.1.2.2 Inuvik Area Facility ...... 8-2 8.1.2.3 NGL Pipeline ...... 8-2 8.1.3 Expansion Capability ...... 8-3 2. Mackenzie Valley Pipeline ...... 8-5 8.2.1 Scope ...... 8-5 8.2.2 Proposed Pipeline Route ...... 8-5 8.2.3 Gas Pipeline Components ...... 8-5 8.2.4 Compressor Stations ...... 8-6 8.2.5 Other Facilities ...... 8-6
9. Construction and Installation 1. Construction Approach ...... 9-1 9.1.1 Scope ...... 9-1 9.1.2 Construction Management Philosophy ...... 9-1 9.1.3 Quality Assurance ...... 9-2 9.1.4 Contracting Strategy ...... 9-3 2. Construction Execution Plan ...... 9-5 9.2.1 Purpose ...... 9-5 9.2.2 Construction Organization ...... 9-5 9.2.3 Construction Execution Schedule ...... 9-6 9.2.4 Existing Facilities ...... 9-6 9.2.5 Materials and Services ...... 9-6 9.2.5.1 Materials and Equipment ...... 9-6 9.2.5.2 Construction Services ...... 9-7 9.2.6 Construction Activities ...... 9-8 9.2.6.1 Module Fabrication ...... 9-8 9.2.6.2 Infrastructure and Logistics ...... 9-8 9.2.6.3 Site Preparation ...... 9-9 9.2.6.4 Pile Installation ...... 9-9 9.2.6.5 Transportation and Site Installation ...... 9-10 xii Shell Canada Limited August 2004 NDPA-P1 CONTENTS TABLE OF CONTENTS
9.2.6.6 Commissioning ...... 9-11 9.2.7 Drilling and Completions ...... 9-11 9.2.8 Transportation and Logistics ...... 9-11 9.2.8.1 Material and Equipment Transportation ...... 9-12 9.2.8.2 Drilling and Construction Personnel Transportation ...... 9-14 9.2.9 Water and Waste Management ...... 9-16 9.2.9.1 Construction Water Management ...... 9-16 9.2.9.2 Construction Waste Management ...... 9-16 3. Construction Infrastructure ...... 9-17 9.3.1 Construction and Drilling Camps ...... 9-17 9.3.1.1 Drilling Camps ...... 9-17 9.3.1.2 Camp Farewell ...... 9-18 9.3.1.3 Facilities Construction Camp ...... 9-18 9.3.2 Staging and Stockpile Sites ...... 9-19 9.3.3 Granular Resources ...... 9-19
10. Operations and Maintenance 1. Organization and Staffing ...... 10-1 10.1.1 Operations and Maintenance Organization ...... 10-1 10.1.2 Staffing ...... 10-2 10.1.2.1 Commissioning and Start-Up ...... 10-2 10.1.2.2 Initial Operation ...... 10-3 10.1.2.3 Steady-State Operation ...... 10-3 2. Procedure Development ...... 10-5 10.2.1 SOTIS System ...... 10-5 10.2.1.1 Purpose ...... 10-5 10.2.1.2 Scope ...... 10-5 10.2.2 Site-Specific Procedures ...... 10-6 10.2.3 Training ...... 10-7 10.2.3.1 Purpose ...... 10-7 10.2.3.2 Pre-Start-Up Training ...... 10-7 10.2.3.3 Ongoing Training ...... 10-7 3. Downtime and Well Interventions ...... 10-9 10.3.1 Production Downtime ...... 10-9 10.3.1.1 Target Availability ...... 10-9 10.3.1.2 Design Factors ...... 10-9 10.3.1.3 Maintenance ...... 10-9 10.3.1.4 Operations ...... 10-10 10.3.2 Well Interventions and Workovers ...... 10-10 10.3.2.1 Purpose ...... 10-10 10.3.2.2 Minor Workovers ...... 10-11 10.3.2.3 Major Workovers ...... 10-11 4. Logistics and Communication ...... 10-13 10.4.1 Logistics ...... 10-13 10.4.1.1 Scope ...... 10-13 10.4.1.2 Transportation ...... 10-13 10.4.1.3 Warehousing ...... 10-14 10.4.1.4 Infrastructure ...... 10-14 10.4.2 Communication ...... 10-15 10.4.2.1 Voice and Data Communication ...... 10-15
August 2004 Shell Canada Limited xiii NDPA-P1 CONTENTS TABLE OF CONTENTS
5. Control and Monitoring Systems ...... 10-17 10.5.1 System Design ...... 10-17 10.5.2 Remote Operating and Monitoring ...... 10-17 10.5.3 Flow Line Control ...... 10-18 10.5.4 Leak Monitoring and Detection ...... 10-18 6. Abandonment and Reclamation ...... 10-21 10.6.1 Scope ...... 10-21 10.6.2 Regulatory Guidelines ...... 10-21 10.6.3 Drilling Areas and Flow Lines ...... 10-21 10.6.3.1 Well Abandonment ...... 10-21 10.6.3.2 Well Pads ...... 10-22 10.6.3.3 Remote Disposal Sump ...... 10-22 10.6.3.4 Flow Line Reclamation ...... 10-22 10.6.4 Gas Conditioning Facility ...... 10-23
11. Safety Plan 1. Introduction ...... 11-1 11.1.1 HSE Management System ...... 11-1 11.1.2 ISO Basis ...... 11-2 2. HSE Plan For Niglintgak ...... 11-3 11.2.1 Scope ...... 11-3 11.2.2 Leadership and Commitment ...... 11-3 11.2.3 Policies and Objectives ...... 11-4 11.2.3.1 Policies ...... 11-4 11.2.3.2 Objectives ...... 11-4 11.2.4 Plan Administration ...... 11-4 11.2.4.1 Organization and Resources ...... 11-4 11.2.4.2 Responsibilities and Competency ...... 11-5 11.2.4.3 Contractor Management ...... 11-5 11.2.4.4 Standards ...... 11-5 11.2.4.5 Document Control ...... 11-6 11.2.5 Hazard and Effects Management ...... 11-6 11.2.6 Plans and Procedures ...... 11-9 11.2.6.1 Purpose ...... 11-9 11.2.6.2 Contingency and Emergency Planning ...... 11-9 11.2.6.3 Security Planning ...... 11-11 11.2.7 Monitoring and Performance Reporting ...... 11-11 11.2.7.1 Monitoring ...... 11-11 11.2.7.2 Incident Reporting and Investigation ...... 11-12 11.2.8 Audit, Management Review and Corrective Action ...... 11-12
12. Public Consultation 1. Introduction ...... 12-1 12.1.1 Background ...... 12-1 12.1.2 Consultation Policy and Principles ...... 12-1 12.1.3 Niglintgak Consultation Plan ...... 12-2 12.1.4 Consultation Strategy and Approach ...... 12-3 12.1.5 Consultation Activities ...... 12-3 2. Concerns and Responses ...... 12-17 12.2.1 Key Concerns and Responses ...... 12-17 xiv Shell Canada Limited August 2004 NDPA-P1 CONTENTS TABLE OF CONTENTS
12.2.1.1 Size and Nature of Footprint ...... 12-17 12.2.1.2 Gas Conditioning Facility ...... 12-17 12.2.1.3 Dredging ...... 12-18 12.2.1.4 Potential Loss of Jobs and Business Opportunities ...... 12-18 12.2.1.5 Protecting the River System ...... 12-18 12.2.1.6 Drilling Waste Disposal ...... 12-19 12.2.2 Other Concerns ...... 12-19 12.2.2.1 Sensory Impacts on Wildlife ...... 12-19 12.2.2.2 Local Benefits ...... 12-20
13. Environmental and Socio-Economic Impacts 1. Introduction ...... 13-1 13.1.1 Scope ...... 13-1 13.1.2 Key Issues ...... 13-1 13.1.3 Objectives ...... 13-1 13.1.4 Approach ...... 13-2 13.1.4.1 Methods ...... 13-2 13.1.4.2 Stage 1 ...... 13-2 13.1.4.3 Stage 2 ...... 13-2 13.1.4.4 Stage 3 ...... 13-2 13.1.4.5 Stage 4 ...... 13-2 13.1.4.6 Stage 5 ...... 13-3 13.1.4.7 Public Participation ...... 13-3 2. Biophysical Impacts ...... 13-5 13.2.1 Scope ...... 13-5 13.2.2 Air Quality ...... 13-5 13.2.3 Noise ...... 13-6 13.2.4 Groundwater ...... 13-7 13.2.5 Hydrology ...... 13-7 13.2.6 Water Quality ...... 13-8 13.2.7 Fish and Fish Habitat ...... 13-10 13.2.8 Soils, Landforms and Permafrost ...... 13-10 13.2.9 Vegetation ...... 13-12 13.2.10 Wildlife ...... 13-13 13.2.11 Cumulative Effects ...... 13-15 3. Socio-Economic Impacts ...... 13-17 13.3.1 Scope ...... 13-17 13.3.2 Regional Economic Effects ...... 13-17 13.3.2.1 Capital and Operating Expenditures ...... 13-18 13.3.2.2 Employment ...... 13-20 13.3.2.3 Labour Income ...... 13-20 13.3.2.4 Demography and Population Mobility ...... 13-24 13.3.3 Infrastructure ...... 13-25 13.3.3.1 Transportation ...... 13-25 13.3.3.2 Energy and Utilities ...... 13-26 13.3.3.3 Housing ...... 13-26 13.3.3.4 Recreation Resources ...... 13-27 13.3.3.5 Governance ...... 13-27 13.3.4 Individual, Family and Community Wellness ...... 13-28 13.3.4.1 Community Well-Being and Delivery of Social Services ...... 13-29
August 2004 Shell Canada Limited xv NDPA-P1 CONTENTS TABLE OF CONTENTS
13.3.4.2 Health Conditions and Health Care Services ...... 13-29 13.3.4.3 Human Health Risks ...... 13-31 13.3.4.4 Public Safety and Protection Services ...... 13-32 13.3.4.5 Education Attainment and Services ...... 13-32 13.3.5 Traditional Culture ...... 13-33 13.3.5.1 Traditional Harvesting and Land Use ...... 13-33 13.3.5.2 Preserving Traditional Language and Culture ...... 13-34 13.3.6 Non-Traditional Land and Resource Use ...... 13-35 13.3.6.1 Protected Areas ...... 13-37 13.3.6.2 Visual and Aesthetic Resources ...... 13-38 13.3.7 Heritage Resources ...... 13-38 13.3.7.1 Archaeological Investigations ...... 13-38 13.3.7.2 Infrastructure Investigations ...... 13-39 13.3.7.3 Borrow Site Investigations ...... 13-39 13.3.8 Traditional Knowledge ...... 13-39
14. Capital and Operating Costs 1. Cost Estimate Basis ...... 14-1 14.1.1 Scope ...... 14-1 14.1.2 Historical Costs ...... 14-1 2. Capital Cost Estimate ...... 14-3 14.2.1 Scope ...... 14-3 14.2.2 Drilling and Completions ...... 14-3 14.2.3 Facilities ...... 14-4 14.2.4 Preliminary Cost Estimate ...... 14-4 3. Annual Operating Cost Estimate ...... 14-7 14.3.1 Scope ...... 14-7 14.3.2 Operating and Maintenance Costs ...... 14-7
15. Liability and Compensation 1. Liability ...... 15-1 15.1.1 Scope ...... 15-1 15.1.2 Canada Oil and Gas Operations Act ...... 15-1 15.1.3 Inuvialuit Final Agreement ...... 15-2 15.1.3.1 Wildlife Harvester Provisions ...... 15-2 15.1.3.2 Worst Case Scenario Assessment ...... 15-2 2. Compensation ...... 15-3 15.2.1 Scope ...... 15-3 15.2.2 Harvesters’ Compensation Agreement ...... 15-3 15.2.3 Environmental Agreement ...... 15-3 15.2.4 Proof of Financial Capability ...... 15-3
Glossary
xvi Shell Canada Limited August 2004 NDPA-P1 CONTENTS
APPLICATION FOR APPROVAL OF THE DEVELOPMENT PLAN FOR NIGLINTGAK FIELD PROJECT DESCRIPTION LIST OF ILLUSTRATIONS
LIST OF FIGURES
Figure 1-1 Location of Niglintgak Field ...... 1-1 Figure 1-2 Commitment to Sustainable Development ...... 1-6 Figure 1-3 Mackenzie Gas Project ...... 1-11 Figure 1-4 Niglintgak Chosen Development Scheme ...... 1-17 Figure 1-5 Niglintgak Field Development Schedule ...... 1-20 Figure 2-1 Sequence Stratigraphy of Tertiary Strata in the Niglintgak Region ...... 2-3 Figure 2-2 Regional Structural Elements of the Mackenzie Delta and Beaufort Basins ...... 2-4 Figure 2-3 Reservoir Block Names ...... 2-5 Figure 2-4 Niglintgak Structural Cross-Section – A to G Sands with Planned Wells ...... 2-5 Figure 2-5 Stratigraphic Column – Niglintgak M-19 ...... 2-6 Figure 2-6 Deposition Settings in the Reindeer A Sand, Kumak E-58 ...... 2-9 Figure 2-7 Niglintgak 3-D Seismic Outline ...... 2-13 Figure 2-8 Seismic Line Through the Niglintgak Field ...... 2-14 Figure 2-9 Location of Seismic Lines of Section ...... 2-15 Figure 2-10 Well Log and Seismic Calibration ...... 2-16 Figure 2-11 Niglintgak Major Faults ...... 2-17 Figure 2-12 Seismic Line Through E-58 (Gas) and C-58 (Wet) Wells Showing Amplitude ...... 2-18 Figure 2-13 Log-Calculated Porosity Versus Core-Measured Porosity Corrected for Stress ...... 2-23 Figure 2-14 Permeability Versus Porosity Transforms ...... 2-24 Figure 3-1 Pressure-Versus-Depth Plot for the Niglintgak Field ...... 3-4 Figure 3-2 Composite Temperature – Depth-Plot Farewell Structure ...... 3-6 Figure 4-1 Niglintgak Daily Raw Gas Production Forecast ...... 4-8 Figure 4-2 Niglintgak Cumulative Natural Gas Production Forecast ...... 4-8 Figure 4-3 Niglintgak Daily Water Production Forecast ...... 4-9 Figure 4-4 Special Drilling Spacing ...... 4-16 Figure 5-1 Expected Niglintgak Air Temperatures ...... 5-7 Figure 5-2 Tuktoyaktuk Wind Rose ...... 5-8 Figure 6-1 Drilling Pad Locations and Plan View of Wells ...... 6-2 Figure 6-2 Sump Location Map ...... 6-7 Figure 6-3 Artist's Impression of Winter Drill Site ...... 6-10 Figure 6-4 Southeast Block A Sand Preliminary Well Completion Design ...... 6-21 Figure 6-5 D, E, F, G and H Sand Preliminary Well Completion Design ...... 6-22 Figure 6-6 Tubing Performance Curves for A Sand Well D-1 ...... 6-23 Figure 7-1 Niglintgak Facilities Location ...... 7-2 Figure 7-2 Niglintgak Overall Process Configuration ...... 7-3 Figure 7-3 Artist's Impression of Niglintgak Well Pad ...... 7-5 Figure 7-4 Artist's Impression of Niglintgak Gas Conditioning Facility ...... 7-6
August 2004 Shell Canada Limited xvii NDPA-P1 CONTENTS LIST OF ILLUSTRATIONS
Figure 7-5 Niglintgak Well Pad Process Schematic ...... 7-7 Figure 7-6 Typical Above-Ground Flow Line Concept ...... 7-11 Figure 7-7 Conceptual HDD River Crossing Design ...... 7-13 Figure 7-8 Niglintgak Separation and Compression Process ...... 7-16 Figure 7-9 Niglintgak Dehydration and Refrigeration Process ...... 7-17 Figure 8-1 Gathering Pipelines ...... 8-1 Figure 9-1 Barge Transportation Routes ...... 9-15 Figure 11-1 HSE Management System Framework ...... 11-1 Figure 11-2 Hazard and Effects Management Process ...... 11-7 Figure 11-3 HSE Case Structure ...... 11-8
LIST OF TABLES
Table 1-1 Niglintgak Construction and Drilling Activities ...... 1-21 Table 2-1 Core Data for Niglintgak SDL 19 ...... 2-22 Table 2-2 Example Water Analysis from DST 16 in B-19 Well ...... 2-25 Table 2-3 Summary of Cut-Offs Used for Calculating Net Pay ...... 2-26 Table 2-4 Petrophysical, Lithological and Fluid Characteristics of Geological Units ...... 2-26 Table 3-1 Niglintgak Field Well Gas Zone Tests ...... 3-2 Table 3-2 Pressure and Depth Input Data ...... 3-5 Table 3-3 Niglintgak Estimated Free Water Levels ...... 3-5 Table 3-4 Expected Reservoir Gas Composition for Niglintgak ...... 3-7 Table 3-5 Estimated Hydrocarbon Volumes for SDL 19 ...... 3-10 Table 4-1 Summary of Reservoir Realization Cases ...... 4-9 Table 4-2 Ultimate Raw Recoverable Gas and Average Field Production Plateau by Realization Case ...... 4-10 Table 4-3 Niglintgak Development Options ...... 4-12 Table 4-4 Niglintgak Development Options Evaluation ...... 4-13 Table 5-1 Niglintgak Gas Production Forecast ...... 5-18 Table 5-2 Niglintgak Expected Blended Gas Composition ...... 5-20 Table 5-3 Gathering Pipeline Specifications ...... 5-21 Table 6-1 Summary of Niglintgak Exploration and Delineation Wells ...... 6-1 Table 6-2 Niglintgak Preliminary Drilling Schedule and Directional Information ...... 6-3 Table 7-1 Gas Conditioning Facility Design Water Level Information ...... 7-34 Table 12-1 Niglintgak Project Definition Consultation Meetings ...... 12-4 Table 12-2 Inuvialuit Business Opportunity Benefits from Shell Work in the ISR ...... 12-20 Table 13-1 Potential Effects of Niglintgak Activities on Air Quality ...... 13-6 Table 13-2 Potential Effects of Niglintgak Activities on Noise ...... 13-7 Table 13-3 Potential Effects of Niglintgak Activities on Groundwater ...... 13-8 Table 13-4 Potential Effects of Niglintgak Activities on Hydrology ...... 13-9 Table 13-5 Potential Effects of Niglintgak Activity on Water Quality ...... 13-10 Table 13-6 Potential Effects of Niglintgak Activities on Fish ...... 13-11 Table 13-7 Potential Effects of Niglintgak Activities on Soils and Landforms ...... 13-11 Table 13-8 Potential Effects of Niglintgak Activities on Vegetation Abundance and Distribution ...... 13-12 Table 13-9 Potential Effects of Niglintgak Activities on Vegetation Health ...... 13-13 Table 13-10 Potential Effects of Niglintgak Activities on Wildlife Habitat Availability ...... 13-14 Table 13-11 Potential Effects of Niglintgak Activity on Wildlife Movement ...... 13-15 Table 13-12 Potential Effects of Niglintgak Activity on Wildlife Mortality ...... 13-16 xviii Shell Canada Limited August 2004 NDPA-P1 CONTENTS LIST OF ILLUSTRATIONS
Table 13-13 Mackenzie Gas Project Capital Expenditures ...... 13-18 Table 13-14 Mackenzie Gas Project Capital Investment by Area ...... 13-19 Table 13-15 Capital Expenditures for the Niglintgak Field, Barge Option ...... 13-19 Table 13-16 Estimated Labour Pool Available in ISR and GSA for Project-Related Work ...... 13-20 Table 13-17 Project Employment Demand in the ISR and GSA ...... 13-21 Table 13-18 Estimated Project-Related Labour Income in the ISR and GSA – 2006 to 2010 ...... 13-21 Table 13-19 Estimated Project-Related Annual Average Employment (2009 to 2030) ...... 13-22 Table 13-20 Annual Average Labour Income in the ISR and GSA ...... 13-22 Table 13-21 Niglintgak Field, Barge Option – Peak Construction Employment ...... 13-23 Table 13-22 Niglintgak On-Site Drilling, Completions and Related Employment ...... 13-23 Table 13-23 Niglintgak Operations Labour Force Requirements ...... 13-24 Table 13-24 Economic Effects of the Project and Niglintgak Field ...... 13-24 Table 13-25 Potential Construction Effects on Population Mobility ...... 13-25 Table 13-26 Potential Operations Effects on Population Mobility ...... 13-25 Table 13-27 Potential Effects on Transportation Infrastructure ...... 13-26 Table 13-28 Potential Effects of Mackenzie Gas Project on Housing ...... 13-27 Table 13-29 Potential Project Effects on Well-Being Conditions ...... 13-30 Table 13-30 Potential Project Effects on Delivery of Social Services ...... 13-30 Table 13-31 Potential Project Effects on Health Conditions ...... 13-31 Table 13-32 Potential Project Effects on Health Care Services ...... 13-31 Table 13-33 Potential Mackenzie Gas Project Effects on Traditional Harvesting ...... 13-34 Table 13-34 Potential Project Effects on Language and Culture Preservation ...... 13-35 Table 13-35 Potential Project Effects on Non-Traditional Land and Resource Use ...... 13-36 Table 14-1 Costs for Niglintgak Field – 1970 to 2003 ...... 14-2 Table 14-2 Preliminary Capital Cost Estimate ($Million 2003) ...... 14-5 Table 14-3 Preliminary Annual Average Operating Cost Estimate ($Million 2003) ...... 14-8
August 2004 Shell Canada Limited xix NDPA-P1 Section 1.1 INTRODUCTION
APPLICATION FOR APPROVAL OF THE DEVELOPMENT PLAN FOR NIGLINTGAK FIELD PROJECT DESCRIPTION DEVELOPMENT PLAN OVERVIEW
1.1.1 APPROVAL REQUESTED
1.1.1.1 Niglintgak Location
Shell Canada Limited (Shell), holder of the Niglintgak Significant Discovery Licence 19 (SDL 19), is proposing to develop and produce the natural gas and natural gas liquids (NGLs) from the Niglintgak gas field. The Niglintgak field is located above the Arctic Circle in the Mackenzie Delta in the Northwest Territories (NWT). Niglintgak is about 120 km northwest of Inuvik and 85 km west of Tuktoyaktuk (see Figure 1-1).
132° 136° 135° 134° 133°
69°30'
Tuktoyaktuk
Taglu
N iglintga k
Parsons Lake
69°00'
68° 30´ Route of Gathering Pipelines Route of NGL and Gas Pipelines Dempster Highway Winter Road Inuvik 20 km Kendall Island Bird Sanctuary 10 miles Anchor Field Aklavik Facility Site
Figure 1-1: Location of Niglintgak Field
August 2004 Shell Canada Limited 1-1 NDPA-P1 Section 1.1 INTRODUCTION DEVELOPMENT PLAN OVERVIEW
1.1.1.2 Conceptual Design Flexibility
The Niglintgak development plan described in this application is based on a conceptual design. At the current stage of development, there remain some design uncertainties that will be resolved as ongoing development and design activities progress. Flexibility has been included in this development plan so that it can continue to be refined as new technical, environmental, stakeholder, economic and other information becomes available.
For development areas where design flexibility is required, the expected range of design uncertainties has been identified and included in the development evaluations and environmental assessments. Flexibility for future refinement has been considered in the following specific parts of the conceptual design:
• the number of future development wells (up to six additional wells identified) required to manage the reservoir compartmentalization uncertainty
• alternatives for water crossing techniques if horizontal directional drilling (HDD) is not feasible
• phasing optimization of drilling and construction activities
• optimization of gas conditioning facility barge transportation, foundations and potential dredging
• the final design flow rate for production facilities
For the Niglintgak gas conditioning facility design, Shell has conducted its environmental impact assessment (EIA) at a nominal capacity of 5.7 Mm3/d (200 MMscf/d), which has shown that no significant effects are likely at that rate of production. Shell requests that the facility throughput rate not be limited, provided emissions from the facility are within the assessed amounts.
The range of design flexibility has been evaluated in the development plan, with no significant impacts identified in the EIA or other evaluations. As this conceptual design is refined, Shell believes that the overall impacts will remain within the scope of this conceptual design.
1.1.1.3 Approval Request
Pursuant to Section 5(1)(b) of the Canada Oil and Gas Operations Act (COGOA), Shell requests approval of the Niglintgak development plan as outlined in this submission and associated support documentation.
1.1.2 SCOPE OF APPLICATION
The Niglintgak gas field is one of the three anchor fields included in the Mackenzie Gas Project. The other two fields are:
• Taglu, held by Imperial Oil Resources Limited
1-2 Shell Canada Limited August 2004 NDPA-P1 Section 1.1 INTRODUCTION DEVELOPMENT PLAN OVERVIEW
• Parsons Lake, held 75% by ConocoPhillips Canada (North) Limited (ConocoPhillips) and 25% by ExxonMobil Canada Properties (ExxonMobil), and operated by ConocoPhillips
The Mackenzie Gas Project includes developing:
• the three anchor fields
• the Mackenzie gathering system, which comprises gathering pipelines, a gas processing facility near Inuvik (the Inuvik area facility), and an NGL pipeline to transport the NGLs from the Inuvik area facility to Norman Wells
• the Mackenzie Valley pipeline, to transport gas from the Inuvik area facility to the Northwest Territories–Alberta boundary
Although the overall project is an integrated development, separate regulatory applications are being submitted for each of the anchor fields, the gathering system and the gas pipeline.
The Niglintgak development plan and associated support material are contained within several documents, some of which will be submitted separately. The application is made up of two parts:
• Part 1, which includes a general description of the proposed development plan, including reservoir development, production facilities design, construction activities and operational plans
• Part 2, which provides additional information to support key aspects of the application. Part 2 information is presented as a list of confidential information supporting Part 1, including reports on geology and geophysical interpretation, drilling and completions evaluations, and a cost estimate. Part 2 contains information that Shell deems to be privileged and confidential, and is submitted to the National Energy Board (NEB) in confidence pursuant to the Canada Petroleum Resources Act.
Additional supporting material submitted includes:
• the Mackenzie Gas Project Public Consultation, Volume 1: Consultation Program, and Volume 2: Appendices
• the Mackenzie Gas Project Environmental Impact Statement (EIS), Volumes 1 to 8, which cover the biophysical and socio-economic assessment of the Niglintgak development and other components of the Mackenzie Gas Project
• the Mackenzie Gas Project Gas Resource and Supply Study, Gilbert Laustsen Jung Associates Ltd.
• the Mackenzie Valley Pipeline Market Supply/Demand and Infrastructure Analysis, Navigant Consulting, Inc.
August 2004 Shell Canada Limited 1-3 NDPA-P1 Section 1.1 INTRODUCTION DEVELOPMENT PLAN OVERVIEW
1.1.3 CANADA BENEFITS PLAN
Shell will develop and submit to Indian and Northern Affairs Canada (INAC) a Canada Benefits Plan as part of the documentation supporting this application. The Niglintgak benefits plan will be based on common benefits principles developed jointly with the other Mackenzie Gas Project proponents in consultation with Benefits Plan stakeholders. The Niglintgak plan will include benefits principles common to all proponents, as well as those benefits plan details unique to the Niglintgak development.
The Niglintgak development is within the Inuvialuit Settlement Region (ISR) and will require a separate land access and benefits agreement between Shell and the Inuvialuit. The negotiated land access and benefits agreement with the Inuvialuit will remain a confidential agreement, but will be consistent with the principles identified in the Canada Benefits Plan documentation.
1.1.4 PROJECT PROPONENT
The Niglintgak field is being developed by Shell, which holds and operates SDL 19. Shell also has an interest in the proposed Mackenzie gathering system and the Mackenzie Valley pipeline.
Shell is a Canadian corporation whose ownership is divided between public shareholders (22%) and Shell Investments Limited (78%). With headquarters in Calgary, Shell is one of the country’s largest integrated energy companies and a major producer of natural gas, NGLs, sulphur and bitumen. Shell manufactures, distributes and markets refined petroleum products across the country.
Shell has extensive experience with exploration and development in Canada and, through its majority shareholder, throughout the world. Shell’s experience in development activities in similar remote and northern environments will be fully used in the Niglintgak development.
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APPLICATION FOR APPROVAL OF THE DEVELOPMENT PLAN FOR NIGLINTGAK FIELD PROJECT DESCRIPTION PROJECT PRINCIPLES AND POLICIES
1.2.1 POLICIES
Commitments and policies are the means by which management communicates its intentions and expectations to employees, contractors and stakeholders. Shell policies and commitments are not voluntary, they are mandatory for all Shell’s businesses. Specific policies that will guide this venture include Shell’s:
• commitment to sustainable development • health, safety and environment (HSE) policy • business principles and code of ethics • drug and alcohol policy • corporate security policy • commitment to the protection of personal information • respectful workplace policy
1.2.2 SUSTAINABLE DEVELOPMENT
Shell strives to meet its commitments and to lessen the negative impacts of its activities on the communities where the company resides and operates. Shell’s goal is to assess its performance and show continuous improvement against targets and measures that are relevant to key business issues and that matter to stakeholders. In 2004, Shell published its 13th sustainable development report and is proud of the progress demonstrated over the years.
Shell’s commitment to sustainable development (see Figure 1-2) is one of the company’s key business strategies, guided by the following seven principles:
• protect the environment • manage resources • respect and safeguard people • benefit communities • work with stakeholders • generate robust profitability • deliver value to customers
Evaluation criteria used for design decisions in the Niglintgak development plan are consistent with, and are based on, these seven sustainable development principles.
August 2004 Shell Canada Limited 1-5 NDPA-P1 Section 1.2 INTRODUCTION PROJECT PRINCIPLES AND POLICIES
I A L Commitment to Sustainable Development C E O N S V Shell Canada is committed to contribute to sustainable development. To our company, this means the integration I of economic, environmental and social considerations in the decision-making process across all of our businessR
activities. It means addressing both short-term and long-term needs. O C
I
N M
Commitment to Sustainable Development Health, Safety and Environment PolicyM O E
N N
T
Our activities are guided by the following principles: Shell Canada is committedO to:
A C
L • pursue the goal of no harm to people.E Generate robust profitability • protect the environment and pursue the goal of prevention of Successful financial performance is essential to our sustainable pollution. future and contributes to the prosperity of society. • use material and energy efficiently to provide our products and Deliver value to our customers services. Customers are the lifeblood of our business. We seek constantly to • develop energy resources, products and services consistent with these aims. strengthen existing customer relationships and develop new ones. • publicly report on our performance and engage in stakeholder Protect the environment consultation. The natural environment supports all human activity. We continually • play a leading role in promoting best practice in our industry. look for new ways to reduce the environmental impact of our • manage health, safety and environment as any other critical operations, products and services throughout their life. business activity. • promote a culture in which all Shell employees share this Manage resources commitment. Efficient use of natural resources, for example, energy, land and water, reduces our costs and respects the needs of future Shell Canada Limited: generations. We constantly look for ways to minimize their use. • has a systematic approach to health, safety and environmental management designed to ensure compliance with the law and to Respect and safeguard people achieve continuous performance improvement. We aim to treat everyone with respect. We strive to protect people • sets targets for improvement and measures, appraises and from harm from our products and operations. reports performance. • requires contractors to manage in accordance with this policy. Benefit communities • requires joint ventures under its operational control to apply this Wherever we work we are part of a local community. We will policy and uses its influence to promote this policy in its other constantly look for appropriate ways to contribute to the general well ventures. being of the community and the broader societies who grant our • includes health, safety and environmental performance in the license to operate. appraisal of all staff and rewards accordingly. Work with stakeholders We strive to achieve a health, safety and environmental performance We affect, and are affected by, many different groups of people, our that we are proud of, to earn the confidence of customers, stakeholders. We aim to recognize their interest in our business and shareholders and society at large, to be a good neighbour and to to listen and respond to them. contribute to sustainable development.
Clive Mather President and C.E.O.
August 1, 2004
Figure 1-2: Commitment to Sustainable Development
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1.2.3 HEALTH, SAFETY AND ENVIRONMENT POLICY
The management of health, safety and the environment is integral to all Shell’s activities. Shell is committed to a health, safety and environmental performance of which it can be proud, to earn the confidence of its customers, shareholders and society at large and to be a good neighbour.
Shell has maintained comprehensive health, safety and environmental management systems since 1990, and has maintained ISO 14001 registration in all its oil and gas production operations since 2001. Ongoing registration ensures that Shell continues to make improvements in its overall HSE performance through effective implementation of these systems.
August 2004 Shell Canada Limited 1-7 NDPA-P1 Section 1.3 INTRODUCTION
APPLICATION FOR APPROVAL OF THE DEVELOPMENT PLAN FOR NIGLINTGAK FIELD PROJECT DESCRIPTION PROJECT PURPOSE AND NEED
1.3.1 PROJECT PURPOSE
The purpose of the Mackenzie Gas Project is to develop Mackenzie Delta onshore gas and deliver it safely and reliably to the Northwest Territories– Alberta boundary for sale into existing pipeline infrastructure. The Niglintgak field development is one of three anchor fields needed to provide an adequate natural gas supply to economically justify the development of the Mackenzie Gas Project gathering system and gas pipeline system.
1.3.2 PROJECT NEED
The Niglintgak field development is needed as part of the Mackenzie Gas Project to generate robust profitability for Shell and its shareholders, while maintaining a commitment to its seven principles of sustainable development. Shell requires good financial performance to continue to meet the financial expectations of its shareholders and remain attractive to oil and gas investors. The Niglintgak development will contribute significantly to Shell’s corporate portfolio through the addition of replacement gas resources, and by providing a reasonable return on capital invested.
As part of the Mackenzie Gas Project, the Niglintgak field development is needed to provide new gas needed by future markets. Long-term gas market studies were completed to assess the gas market needs for incremental gas production from the Mackenzie Delta. These assessments included a regional market analysis and an evaluation of the gas supply and deliverability for North America. A study conducted by Navigant Consulting Inc. concluded that there would be sufficient market need for the Mackenzie Delta gas to support the construction of the Mackenzie Valley pipeline and the gas it transports.
August 2004 Shell Canada Limited 1-9 NDPA-P1 Section 1.4 INTRODUCTION
APPLICATION FOR APPROVAL OF THE DEVELOPMENT PLAN FOR NIGLINTGAK FIELD PROJECT DESCRIPTION NIGLINTGAK FIELD DEVELOPMENT
1.4.1 MACKENZIE GAS PROJECT OVERVIEW
The Niglintgak gas field is being developed as part of the Mackenzie Gas Project (see Figure 1-3).
Figure 1-3: Mackenzie Gas Project
The Mackenzie Gas Project comprises developing:
• sweet natural gas from Taglu, Parsons Lake and Niglintgak, the three largest discovered onshore natural gas fields in the Mackenzie Delta
August 2004 Shell Canada Limited 1-11 NDPA-P1 Section 1.4 INTRODUCTION NIGLINTGAK FIELD DEVELOPMENT
1.4.1 MACKENZIE GAS PROJECT OVERVIEW (cont’d)
• the Mackenzie gathering system, consisting of:
• gathering pipelines to collect the natural gas and associated NGLs, and transport them to a facility located near Inuvik
• gas processing and NGL recovery facilities at the Inuvik area facility
• an NGL pipeline to extend south about 480 km from the Inuvik area facility to Norman Wells, where it will tie into the existing Enbridge Pipelines (NW) Inc. pipeline
• the Mackenzie Valley pipeline, which will extend from Inuvik along the Mackenzie River to Norman Wells and continue south to connect to an extension of the NOVA Gas Transmission Ltd. (NGTL) system south of the Northwest Territories–Alberta boundary
For additional information on the Mackenzie Gas Project, see Section 8, Pipeline Transport Systems.
1.4.2 NIGLINTGAK DISCOVERY AND DELINEATION
Mackenzie Delta exploration land was first obtained by Shell in 1958. A series of 2-D seismic programs in the following decade led Shell to the discovery of the Niglintgak field in 1973 with the drilling of the Niglintgak H-30 well. Shell drilled four additional wells between 1974 and 1977 to delineate the field, three of which successfully tested gas during well tests:
• Shell Kumak C-58 water • Shell Niglintgak M-19 gas and oil • Shell Niglintgak B-19 gas • Shell Niglintgak E-58 gas
The results of this exploration and delineation drilling program led to SDL 16 and SDL 19 being granted in 1988.
Shortly after the discovery of the Niglintgak pool in the early 1970s, a development project was initiated to develop field and pipeline concepts for the Mackenzie Delta. The selected Niglintgak production concept was similar to that currently proposed and was developed to the point of regulatory application submission. As part of the regulatory review process, the Government of Canada appointed Thomas Berger to lead a Royal Commission to investigate the impact of the proposed pipeline development on the North. As a result of this review, the development process was stopped and the project put on indefinite hold in 1977.
Shell conducted a 3-D seismic survey in the winter of 1988–1989 to support further development planning activities. Little additional delineation work occurred on the Niglintgak field between 1988 and the current development activities. All original Niglintgak exploration and delineation wells were
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abandoned in 1996. Historical well data and core sample information from these wells have been used extensively in developing the current reservoir understanding and in planning development drilling activities.
In addition to the Niglintgak field, several other Shell SDLs were granted in the surrounding area, including Kumak, Unipkat, Titalik, and Ya Ya North and South. These other SDLs are not part of the current Niglintgak development application, but will be considered as future production options when processing and transportation capacity becomes available.
1.4.3 NIGLINTGAK DEVELOPMENT PHASES
The Niglintgak field development has four phases:
1. Feasibility Study Phase 2. Project Definition Phase 3. Construction Phase 4. Operations Phase
1.4.3.1 Feasibility Study Phase
The Feasibility Study Phase started in 2000 and was completed in 2001. It involved assessing external factors, including:
• natural gas markets • economic feasibility • the regulatory environment • Northern support • field resources and development feasibility studies
1.4.3.2 Project Definition Phase
The Project Definition Phase began in 2001 and will end in 2006. This phase includes:
• conducting engineering studies • conducting environmental field studies • conducting public consultation • developing benefits and land access agreements • preparing the regulatory application, and having it reviewed and approved • evaluating project economics and commercial viability
1.4.3.3 Construction Phase
The Construction Phase is planned for the three years from 2006 until 2009, subject to NEB project approval for Niglintgak, and includes:
• completing the detailed facility design
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1.4.3.3 Construction Phase (cont’d)
• preparing the infrastructure required for construction and operations
• drilling and completing the development wells
• procuring, fabricating and constructing the well pads, gas conditioning facility and flow lines
1.4.3.4 Operations Phase
The Operations Phase is scheduled to begin at start-up in 2009 and continue for about 25 years, until 2034. This phase includes:
• commissioning and starting up of wells and facilities
• producing and processing gas and NGLs from the Niglintgak field for delivery into the gathering system and gas pipeline and for transport to markets in the south
• abandoning and reclaiming the developed areas at the end of production life, including:
• decommissioning and removing all above-ground facilities • abandoning all production and disposal wells • reclaiming the area affected by the Niglintgak development
1.4.4 KEY FIELD CHARACTERISTICS
1.4.4.1 Scope
Key characteristics of the Niglintgak reservoir and Niglintgak local area that have influenced the development of the proposed concept include:
• a relatively shallow gas reservoir about 1,000 m below surface
• a reservoir broken up into several compartments as a result of subsurface faulting, with a significant portion of the gas reservoir being located under the Mackenzie River
• a development located in an active delta floodplain, with permafrost under parts of the proposed development
• a development located within the Kendall Island Bird Sanctuary
• the relatively shallow water depths where the Mackenzie River enters the Beaufort Sea
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1.4.4.2 Shallow Gas Reservoir
The shallow gas reservoir has influenced field development in several ways. Gas pressures are lower, resulting in gas compression being required from the start of field production to enable the gas to reach gathering pipeline pressures. The shallower gas is relatively cool and will require the addition of chemicals and heat to keep it from forming frozen gas hydrates during production. The shallow burial depth of the reservoir sands makes them poorly consolidated and necessitates a wellbore design that includes sand control technology to manage sand production with the gas. Finally, the shallower depth reduces drilling time, enabling a shorter, winter-only drilling program to be executed.
1.4.4.3 Compartmentalized Reservoir
A compartmentalized reservoir caused by subsurface faulting requires more well locations to effectively drain the resource. Six wells are believed to be sufficient for the expected compartmentalization, but additional wells might be required if production monitoring indicates that additional faults and compartments exist. Directionally drilled wells will be required to access those gas compartments located under the Mackenzie River. However, the horizontal distance that can be drilled from a central well pad location is limited by the relatively shallow reservoir depth. As a result, three drilling well pad locations will be required for the Niglintgak development.
1.4.4.4 Delta Floodplain with Permafrost
The presence of permafrost in the Niglintgak area influenced the design of wells, facilities and flow lines. The wells will use refrigeration during drilling and insulated completion designs to enable production without permafrost damage. Well pad facilities and flow lines will be constructed on elevated pile foundations to avoid seasonal floods and to prevent permafrost damage during operations.
1.4.4.5 Development within Kendall Island Bird Sanctuary
Constructing and operating the facilities within the Kendall Island Bird Sanctuary necessitates additional environmental considerations to reduce the impact of development activities on summer bird populations. Design considerations included:
• reducing the land footprint • reducing equipment noise • using winter construction, where feasible
1.4.4.6 Shallow Water Depths
Shallow water depths encountered in the mouth of the Mackenzie River channels as they enter the Beaufort Sea make access from the Beaufort Sea more difficult. The gas conditioning facility will be designed to optimize weight and draft to eliminate or reduce the dredging requirements during transportation.
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1.4.5 NIGLINTGAK DEVELOPMENT PROCESS
1.4.5.1 Design Concept
The evaluation criteria used throughout the Niglintgak design process were developed to be consistent with Shell’s seven principles of sustainable development. These sustainable development principles will continue to be used throughout design, construction and operational project activities.
Key features of the design concept chosen for Niglintgak include:
• 6 to 12 production wells and one disposal well located on three well pads (north, central and south)
• a remote sump for disposing of drilling cuttings during drilling operations
• elevated facilities at the well pads
• a system of above-ground flow lines, including an HDD Kumak Channel crossing, to bring the produced gas and associated NGLs to the gas conditioning facility
• a gas conditioning facility located in the Kumak Channel that includes process equipment for gas separation, compression, dehydration and refrigeration
• associated infrastructure and transportation
Figure 1-4 shows the layout for the Niglintgak development.
1.4.5.2 Wells and Well Pads
The relatively shallow gas reservoirs combined with the number of separate reservoir compartments require three well pad locations to access all parts of the Niglintgak gas reservoir. Six production wells are initially planned for the development:
• four from the north pad • one from the central pad • one from the south pad
A disposal well will also be drilled from one of the three well pads, for produced water disposal. Up to six future development wells could be required if reservoir monitoring indicates that additional compartments are present.
Well pad foundations for drilling and production facilities will be built using elevated piles for flood and permafrost protection during the first winter of construction following regulatory approval. Well drilling operations are planned for completion during three winters, using up to two drilling rigs. Winter drilling enables the permanent well pad footprint to be reduced by using ice pad working areas.
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–135° 25´ W –135° 15´ W
69° 20´ N
Shell Significant Discovery Licence Boundary
Kendall Island Bird Sanctuary Boundary
69° 16´ N
Figure 1-4: Niglintgak Chosen Development Scheme
Downhole well completions will include sand control equipment and provide for isolation of individual production zones for water shutoff, if required. Some well completions will be finished during late summer, using helicopter-supported on- site drilling rigs. Care will be taken to reduce the adverse impact on summer bird populations and minimize work activity during specified restricted periods. Drilling muds are expected to be water based. Drilling cuttings will be transported by truck to a new remote sump for disposal.
Well pad facilities will be fabricated in modules and transported, by a combination of barges and trucks, from Alberta to site for winter installation. These facilities will be designed to produce, measure and heat the produced gas before it is transported to the gas conditioning facility for processing. Use of methanol in the wells and heat in the surface facilities will prevent hydrate formation.
The main well pad facilities will include:
• wellheads and production choke valves • well metering • line heaters • pigging facilities
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1.4.5.2 Wells and Well Pads (cont’d)
• chemical injection facilities • a flare stack • a helipad • an emergency shelter
Access to well pad facilities will be primarily by winter road or helicopter. No permanent road or permanent barge access is planned. Granular material will only be required for possible permafrost protection below the flare stack.
1.4.5.3 Flow Lines
Flow lines will be required to transport gas and liquids from the three well pads to the gas conditioning facility, and to transport produced water back to the disposal well for injection. The insulated flow lines will be built on elevated piles to prevent the heated gas from damaging the permafrost. Additional fuel gas and utility lines will be installed with the production lines to provide utilities back to the well pads from the gas conditioning facility.
An HDD river crossing is planned to route gas from the Niglintgak Island well pads through a flow line under the Kumak Channel. Once across the Kumak Channel, this flow line and the south well pad flow line will cross an access bridge onto the gas conditioning facility. Flow line and HDD installation will be completed during winter construction, using temporary winter roads for construction access.
1.4.5.4 Gas Conditioning Facility
The gas conditioning facility will process the produced gas to meet the quality specifications of the gathering pipelines. The gas conditioning facility will include:
• inlet separation • gas compression • gas dehydration • gas refrigeration • metering • hydrocarbon liquids tankage and reinjection into the gathering pipeline • a produced-water handling system
Gas entering the gas conditioning facility will be separated to remove liquids, compressed to gathering pipeline pressure, dehydrated to remove water and refrigerated to -1°C to protect the permafrost once the gas enters the gathering pipeline. Produced water will be sent through a flow line to a disposal well for re- injection into a deep, water-bearing reservoir.
In addition to the main processing equipment, the gas conditioning facility design will include utility and other support equipment, including:
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• electrical power generation • utility heat for building heating and equipment heat tracing • control and instrumentation • a communications system • relief and equipment blowdown systems • fuel gas systems • tankage and storage • accommodation and an emergency shelter
The gas conditioning facility will be constructed off site and will be towed to Niglintgak via the Beaufort Sea. The gas conditioning facility design and transport route will be optimized to eliminate or reduce dredging requirements on the chosen route. Once on site, ballast and piles will be used to provide a permanent foundation for the gas conditioning facility on the east side of the Kumak Channel.
In developing the current production concept for the Niglintgak field, one of the early concepts evaluated was the use of a floating production facility located on a barge moored in the river channel. This evolved into the current development concept, with the gas conditioning facility being installed on a permanent foundation on the river channel bottom. Because the construction plan involves towing the structure into place, it is described as the barge option in the EIS and other documents.
The gas conditioning facility will be designed to allow for future remote operation, but will be staffed during initial operations.
1.4.5.5 Support Infrastructure
Support infrastructure and logistics for the Niglintgak development will be integrated as much as possible with the other Mackenzie Gas Project development activities. This includes barging, staging areas, granular resource development and other transportation needs.
In addition to shared infrastructure, Niglintgak will have a construction camp, temporary warehouse and gravelled storage area at the construction site. Shell will use Camp Farewell, located 15 km upstream of the Niglintgak development, as a support base for Niglintgak construction and operations activities. Camp Farewell facilities include an airstrip, accommodations for 35 people, an equipment laydown area, a barge landing site and fuel storage facilities.
1.4.5.6 Transportation
Plans for transporting materials, equipment and personnel to the Niglintgak area will include using:
• fixed-wing aircraft into Camp Farewell year-round
• winter roads from Inuvik to Niglintgak during construction and, potentially, during operations
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1.4.5.6 Transportation (cont’d)
• helicopters year-round into and out of Niglintgak
• barges to Camp Farewell and the gas conditioning facility during construction and operations
Well pads and the gas conditioning facility will be equipped with helipad access facilities.
1.4.6 DEVELOPMENT SCHEDULE
The key events and milestones of the schedule for the Niglintgak development are shown in Figure 1-5. Table 1-1 summarizes the specific construction activities from regulatory approval through to start-up.
Activity 2004 2005 2006 2007 2008 2009 Regulatory Application Application Preparation File Development Plan Application File Project Permit Applications Regulatory Review Process Development Plan Approval Engineering Front-End Engineering Detailed Engineering Procurement Facilities and Infrastructure Drilling Materials and Services Shop Fabrication Well Pad Module Fabrication Gas Conditioning Facility Fabrication Transportation Materials and Modules Gas Conditioning Facility Tow Construction Gravel Mining and Hauling Piling and Structural Module and Flow Line Installation Gas Conditioning Facility Installation Drilling Start Up Final Commissioning Start-Up
Figure 1-5: Niglintgak Field Development Schedule
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Table 1-1: Niglintgak Construction and Drilling Activities
Season Activity Summer 2006 • Start off-site fabrication of gas conditioning facility and modules • Transport construction and drilling equipment, camp facilities, materials and provisions by barge to Camp Farewell Winter 2006–2007 • Construct winter roads, ice pads, camp facilities, storage facilities and supporting infrastructure • Install piling and steel decking at well sites • Construct an off-site drilling sump • Begin drilling program • Develop borrow sites, transport material to Niglintgak and place Summer 2007 • Conduct completion operation on one well • Transport fuel, materials, well site modules and provisions by barge to Camp Farewell • Dewater and compact gravel Winter 2007–2008 • Construct the winter roads and ice pads • Continue drilling program • Install piles for flow lines and well-site modules • Complete horizontal directional drill of Kumak Channel for flow line Summer 2008 • Conduct well completion operations • Tow the gas conditioning facility to Niglintgak and set in place • Transport fuel, materials, modules and provisions to Camp Farewell or directly to Niglintgak Winter 2008–2009 • Construct winter roads and ice pads • Complete drilling program and demobilize • Complete flow lines and facilities construction, and well pad facilities • Begin commissioning Summer 2009 • Continue commissioning • Begin demobilizing construction equipment and camps Winter 2009–2010 • Start up operating facilities • Perform construction activity reclamation Summer 2010 • Complete demobilization and construction activity reclamation
August 2004 Shell Canada Limited 1-21 NDPA-P1 Section 1.5 INTRODUCTION
APPLICATION FOR APPROVAL OF THE DEVELOPMENT PLAN FOR NIGLINTGAK FIELD PROJECT DESCRIPTION REGULATORY REQUIREMENTS
1.5.1 COOPERATION PLAN
The Mackenzie Gas Project requires approvals from federal, territorial, provincial and local regulatory authorities responsible for assessing and regulating energy developments. The agencies involved include:
• the Canadian Environmental Assessment Agency (CEAA) • Indian and Northern Affairs Canada (INAC) • the Inuvialuit Region Environmental Screening and Review Boards • the Mackenzie Valley Environmental Impact Review Board • the National Energy Board (NEB) • the Northwest Territories Water Board
To clarify the regulatory process, the agencies involved agreed to work together to make the environmental assessment processes for the project more efficient and effective. This resulted in the development of the Cooperation Plan for the Environmental Impact Assessment and Regulatory Review of a Northern Gas Pipeline Project through the Northwest Territories (Cooperation Plan) issued in June 2002. This plan outlines a process that satisfies the needs of all northern agencies, honours land claims agreements and complies with the regulations of all federal and territorial legislation.
The procedures in the plan coordinate the regulatory process, while recognizing the independence of each regulatory authority. Key to the success of the Cooperation Plan is the referral of environmental and socio-economic matters by all agencies to a Joint Review Panel that will oversee the public hearings addressing these matters. After the Joint Review Panel hearings, recommendations will be given to the various regulatory agencies. These agencies will then complete the regulatory process by processing permit applications in a manner consistent with the recommendations and conditions outlined in the Joint Review Panel report.
1.5.2 REGULATORY PROCESS
1.5.2.1 Preliminary Information Package
In June 2003, the proponents of the Mackenzie Gas Project submitted to regulators a Preliminary Information Package containing information on all
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1.5.2.1 Preliminary Information Package (cont’d)
aspects of the project. The submission of this document initiated the following regulatory processes for Niglintgak and other proponents’ developments:
• the regulatory process for field and gathering system developments under COGOA
• the regulatory process for the gas pipeline under the National Energy Board Act (NEBA)
• the environmental review process under the Canadian Environmental Assessment Act (CEAA), the Mackenzie Valley Resource Management Act and the Inuvialuit Final Agreement
1.5.2.2 Commercial Discovery Application
In April 2004, Shell submitted an application to the NEB for a Declaration of Commercial Discovery under the Canada Petroleum Resources Act. The Declaration of Commercial Discovery shows that development of the gas resource is commercially viable. Approval of the proposed Niglintgak development and the Declaration of Commercial Discovery are required before the NEB can issue the production licence for Niglintgak’s construction and operations.
1.5.2.3 Other Regulatory Applications and Approvals
Other regulatory permits, approvals and agreements that are required before construction and operations activities can be initiated include:
• water use licences for construction and operations
• construction land use permits
• benefits and land access agreements
• surface lease permits
• well drilling permits
• Fisheries and Oceans Canada permits and authorizations
• construction and operations approvals within the Kendall Island Bird Sanctuary
• marine transportation approvals
• permits for any dredging required in the Beaufort Sea and Mackenzie River
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As described in the Cooperation Plan, applications for these permits will be submitted before the Joint Review Panel regulatory hearings are completed.
The Niglintgak development plan application is one of five Mackenzie Gas Project regulatory applications submitted to the NEB. These applications include:
• development plan applications under COGOA for the three anchor fields submitted separately by each field operator
• the gathering system application under COGOA, submitted by Imperial Oil Resources Ventures Limited, as operator
• the gas pipeline application for a Certificate of Public Convenience and Necessity (CPCN) submitted by Imperial Oil Resources Ventures Limited, as operator
Submission of the required applications for all five parts of the project will be coordinated to enable the regulators to evaluate the combined development for the Mackenzie Gas Project.
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APPLICATION FOR APPROVAL OF THE DEVELOPMENT PLAN FOR NIGLINTGAK FIELD PROJECT DESCRIPTION GEOLOGICAL DESCRIPTION
2.1.1 REGIONAL HISTORY
Over the past 95 million years, about 11,000 m of sediment have been deposited throughout the Niglintgak region by the shifting courses of ancient rivers in the Beaufort–Mackenzie Basin and by the formation of deltas near the mouths of these rivers. These deposits have become a thick package of rock that can be divided into 11 main sequences (or cycles), each separated by major depositional hiatuses or unconformities (see Figure 2-1).
Late Cretaceous and younger strata are separated from older basement strata in the region by a major unconformity. The stratigraphic interval of most interest in the Niglintgak area is contained within the Lower Tertiary.
2.1.1.1 Burial and Structural History
Tertiary deltaic sequences of the rapidly subsiding Beaufort–Mackenzie Basin have been punctuated by pulses of tectonism, the shifting of the rock plates forming the earth’s crust. The Niglintgak gas field is located just west of the Donna River fault zone (see Figure 2-2), a right-lateral strike-slip zone that trends southwest to northeast. Relative tectonic quiescence during the late Cretaceous to mid-Paleocene led to the deposition of the deepwater shales of the Fish River Sequence, which underlies the Reindeer Sequence.
Uplift and subsequent erosion of the Richardson Range to the south provided sediment for the compositionally and texturally immature Reindeer reservoir sands. Some of these uplift events seem to extend into the vicinity of Niglintgak during Reindeer time (late Paleocene to mid-Eocene), and have resulted in numerous unconformities within the thick package of interbedded sandstones and shales.
Major basin subsidence led to the mid-Eocene deposition of the Richards Sequence, which provides the reservoir seal. Regionally, this was followed by the deposition of the Kugmallit in the Oligocene, but subsequent uplift and erosion at the sub-Iperk unconformity resulted in its absence from the Niglintgak field. The deepest burial of the top of the Reindeer reservoir in the vicinity of Niglintgak was about 2,200 true vertical depth metres subsea (TVD mSS) during the Oligocene.
A northeast-oriented compressional event resulted in a series of northwest-to- southeast trending anticlines, fully formed by the Oligocene or early Miocene.
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2.1.1.1 Burial and Structural History (cont’d)
One of these, the Farewell Anticline, contains the Niglintgak and Kumak fields. Transpression during the formation of the anticline resulted in it being crosscut by a series of faults.
The last tectonic event was signalled by major uplift to the south and subsequent erosion (the late Miocene sub-Iperk unconformity). No significant faults cross this surface, constraining the period of tectonic activity.
2.1.1.2 Source Rocks
Regional source rocks include the Smoking Hills and Fish River, but it is likely that most hydrocarbons in the Niglintgak field are derived from the Reindeer Sequence on the flanks of the Farewell Anticline.
Rich woody debris, and algae and plankton deposited with the Reindeer sands, resulted in a high organic content prone to generating hydrocarbon gas. The main period of hydrocarbon gas generation, when these organic materials were subjected to heat and pressure, was during the time of deepest burial during the Oligocene and Miocene epochs.
2.1.1.3 Geological Seal
The shale-dominated Richards Sequence is thick enough at Niglintgak to effectively act as a geological seal or cap for hydrocarbon containment. In adjacent anticlines and fault-uplifted blocks, the Richards shale is often thin or absent because of truncation by the sub-Iperk unconformity. In these structures, the silty shales between Reindeer A to Z sands can retain only small hydrocarbon columns.
This is reflected in Niglintgak, where the A to D sands retain a gas column of about 300 m and all other reservoir units have columns of around 100 m or less. The poor quality of the seals might also be reflected in the distribution of oil in some reservoir units, where gas migrated out of a horizon, leaving only low- grade American Petroleum Institute (API) oil behind.
2.1.1.4 Reservoir Blocks
Within the Niglintgak area, a number of faults crosscut the Farewell Anticline. These faults break the Niglintgak field into six blocks or areas. For the reservoir block names, see Figure 2-3. For a structural cross-section of the same area, see Figure 2-4.
The faults have not caused enough structural offset to completely disrupt the continuity between the A to D sands. As a result, the A to D sands form a single gas reservoir with a common free water level. Fault seal analysis indicates that the A sand is likely to communicate between fault blocks within the field during production. The deeper strata typically contain thinner, lower net-to-gross ratio sands and remain geologically isolated from each other.
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Taglu and Richards Position of Unipkat Area Depositional Shoreline Niglintgak and Kumak Area Sequences Basinward Landward Richards Sequence 7 mfs SB A Channel and Canyon SB 6 Richards Complex SB 5 4b mfs SB
Taglu 4a mfs SB H Canyon 3 IPERK SB
mfs SB K Canyon Fluvial Channel
UPPER Parasequence REINDEER (TAGLU) 2c Set
mfs SB N Channel
2b
SB 2a SB 1 Akalak Sequence
Pal Paleocene Pleis Pleistocene SB Sequence Boundary TST Transgressive Systems Tract Sandy Channel Fill Mio Miocene Hol Holocene mfs Maximum Flooding Surface LST Lowstand System Tract Pli Pliocene Mbr Member HST Highstand Systems Tract Shale-Filled Canyon
Figure 2-1: Sequence Stratigraphy of Tertiary Strata in the Niglintgak Region
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–136° 0´ W –135° 30´ W –135° 0´ W –134° 30´ W –134° 0´ W –133° 30´ W –130° 0´ W
e n o Z lt 69° 45´ N u a F r e iv R a n n o D
69° 30´ N
Taglu
h g u Kumak o r T *Niglintgak* 69° 15´ N t i l Unipkat al *Tuktoyaktuk*
m g u K
Parsons Lake
69° 0´ N
e Kugpik n C o Z e n t tr l a u h l a c 68° 45´ N D r F e A lt r a e k a v l i k R e A n a o n Z
n t o l u D a F
s e k 68° 30´ N a L
mo i k
Es
Abandoned Well Gas Well
Figure 2-2: Regional Structural Elements of the Mackenzie Delta and Beaufort Basins
2.1.2 RESERVOIR STRATIGRAPHY
The primary reservoir in the Niglintgak field, Taglu field and surrounding SDL areas, such as Kumak, Unipkat and Ya Ya, is within the Reindeer Sequence. The Reindeer Sequence consists of more than 3,000 m of sandstone, siltstone and shale deposited in a deltaic and fluvial setting. Numerous regional and local
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unconformities cut the strata, complicating stratigraphic correlation between fields.
Shell has subdivided the Reindeer Sequence into 26 main units, labelled Reindeer A to Z. These units typically coarsen upwards and are capped by sand. Therefore, the upper portion of a unit is often referred to as a sand, such as the E sand.
– 135° 25´ 00´´ W – 135° 20´ 00´´ W – 135° 15´ 00´´ W –135° 10´ 00´´ W
Upluk A-42 69° 21´ 00´´ N
Upluk C-21
69° 20´ 00´´ N H-30 Upluk Block Niglintgak H-30 Block
M-19 Niglintgak M-19 69° 19´ 00´´ N Block
Niglintgak B-19 B-19 69° 18´ 00´´ N Block Kumak E-58
Kumak C-58
E-58 69° 17´ 00´´ N Block South Niglintgak Block 69° 16´ 00´´ N
Bottomhole Location Gas Well Surface Location Shell SDL Non-Shell SDL
Figure 2-3: Reservoir Block Names
NW SE P3 P11 P4 D1 P2 0
-500
-1,000
-1,500
H-30 P4l M-19 Fault B-19 Fault Fault E-58 C-58 Fault LMN Sand Well
Permafrost Iperk Richards A to G Sands Original Wells Abandoned (in black) 0 1 Kilometre
Figure 2-4: Niglintgak Structural Cross-Section – A to G Sands with Planned Wells
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2.1.2 RESERVOIR STRATIGRAPHY (cont’d)
The Niglintgak area has received river sand (fluvial) deposition and, in periods of subsidence, the sea has advanced over the area, depositing fine mud materials. The advancing and retreating shoreline has also meant that the Niglintgak area reservoir was variously deposited on the ocean shelf, along shorelines and on delta floodplains.
The Reindeer Sequence consists of shelf, shoreface, delta front and delta plain deposits. These strata are cut or incised by numerous unconformities, allowing for subdivision into the 26 Reindeer A to Z sands. The main sand units are described in order of deposition from Z to A. Figure 2-5 shows the typical character of hydrocarbon-bearing sands A through T.
TRDR A
TRDR L
TRDR D
TRDR M
TRDR E
TRDR F
TRDR G
TRDR H
TRDR N
TRDR O
TRDR I
TRDR P TRDR J
TRDR Q
TRDR R
TRDR S
TRDR T
Figure 2-5: Stratigraphic Column – Niglintgak M-19
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2.1.2.1 Y and Z Sands
A significant unconformity separates the delta front Y and Z sands (the Aklak Sequence) from the rest of the strata. These coarsening upward cycles of sand are separated by thick shales.
2.1.2.2 U to X Sands
Sands U to X are thick wave-dominated shoreline cycles. These sands fill in the lows created by concurrent block faulting, and thicken northwards.
2.1.2.3 Q to T Sands
Sands Q to T consist of channeled floodplain deposits 30 to 100 m thick, built by a series of prograding fluvial-dominated deltas.
2.1.2.4 M to P Sands
In the M to P sands, there is a switch from delta plain progradation to aggradation. The N, O and P sands consist of coal-rich floodplain deposits with minor channels. The M sand consists of a 90-m-thick mouth bar complex overlain by stacked channels and over-bank deposits. A persistent bentonite horizon near the base of the M sand provides a stratigraphic marker. The M sand is divided into upper, middle and lower for resource determination purposes.
2.1.2.5 K and L Sands
The L sand consists of shoreline deposits capped by crevasse splay cycles and some channel sands. The thinner coarsening upward cycles signal the start of shoreline retrogradation. The southward movement of the shoreline continues in the 300-m-thick K sand, which is composed of five stacked shoreface sands. The L sand is divided into upper and lower for resource determination purposes.
Tectonic uplift and a drop in relative sea level resulted in a major erosional event cutting hundreds of metres down into the top of the L unit, or perhaps further. This erosional event formed the K Canyon, which is filled with estuarine muds and occasional sands.
2.1.2.6 I and J Sands
The I and J sands overlie the K Canyon and are composed of shoreface cycles, indicating renewed shoreline retrogradation.
2.1.2.7 H Sand
A new period of tectonic uplift resulted in the delta plain deposits of the H sand. The H sand was then cut into by another erosional event that formed the H Canyon, which is several hundred metres deep. This canyon is primarily filled with mud and silt.
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2.1.2.8 D to G Sands
Distributary mouth bar and delta plain deposits characterize the D to G sands. This unit represents a time of major delta progradation northwards. The D sand was followed by a major regional flooding event.
Another stratigraphic marker, the D Bentonite, occurs about 5 m above the top of the D sand.
2.1.2.9 B and C Sands
During the initial discovery at Niglintgak, the B and C sands were part of the original stratigraphy for reservoir modelling purposes. These two sands are now considered part of the A sand. The B sand is no longer used and the C sand is considered a lag deposit on the base of the A Canyon.
2.1.2.10 A Sand
The first expression of the A delta complex (composed of sands A1 to A6) came with the deposition of organic-rich prodelta muds and thin, sharp-based turbidite sands. This deep-water stratum shallows to delta front and then to the distributary mouth bar deposits of the A6 sand, which are regionally truncated by an unconformity.
The A6 sand is overlain by the furthest progradation of the delta complex in the entire Reindeer Formation. The reservoir sands of the A sand were deposited in a wide delta plain. The plain consists of braided distributary channels (sands A1 to A5) separated by minor shoaled areas. The channels consist of massive to cross- bedded, medium to coarse-grained sandstones. They are predominant in the A sand and appear to cut into each other, forming high net-to-gross reservoir development, multistorey channel complexes. Figure 2-6 shows samples of the different depositional types by cores taken from the Kumak E-58 well.
In areas where deposition was inactive, sediment compaction led to the formation of local swamps (represented by coals) and interdistributary bays (thinly bedded fine-grained sediments with rare bioturbation). Correlation of the various reservoir sands at Niglintgak is possible using these flooding events and erosional surfaces at the bases of the A1 and A5 sands. Overall, the A sand stratigraphy provides a layer-cake style reservoir. However, well control and discontinuous horizons in the seismic data suggest the potential for a number of erosional windows through the various layers.
The A sands rapidly thin in the 2 km between the Niglintgak B-19 and M-19 wells. For a summary of Niglintgak wells, see Section 6, Drilling and Completions. The thinning could be ascribed to the variable depth of incision by another unconformity, post-dating deposition of either the A3 or A2 sand. Above this erosional surface, the fill appears similar to the H and K canyons and consists of thinly bedded sand lag deposits (the C sand, lying within the A sand) in what is otherwise a muddy-silty column of sediment. This feature is referred to as the A Canyon, and can be observed on the 3-D seismic survey.
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Kumak E-58
c23
A1 Sand A2 Sand c18
Braided Fluvial Crevasse Splay A3 Sand
A4 Sand
A5 Sand A6 Sand
Paleosoil Braided Fluvial
D Sand
Marsh Distributary Mouth Bar
Figure 2-6: Deposition Settings in the Reindeer A Sand, Kumak E-58
The A1 sand, consisting of multistorey stacked braided channels, overlies another major unconformity. The furthest progradation towards the basin of the entire complex occurred at this time. Generally, the A sand has:
• high net-to-gross reservoir development • high porosity • high connectivity
A major marine flooding event, accompanied by the onset of regional active faulting, ended the deposition of this deltaic complex (A1 to A6 sands).
2.1.3 SEDIMENTOLOGY AND DIAGENESIS
The reservoir rocks are typically fine to medium grained, moderate to well sorted, poorly cemented and angular grained sandstones. Typical grain contacts in the shallower reservoir sands are tangential or floating. The reservoir sandstones can be characterized as chert-rich litharenites. Framework grains consist of:
• monocrystalline and polycrystalline quartz • chert • mica
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2.1.3 SEDIMENTOLOGY AND DIAGENESIS (cont’d)
• feldspar and rock fragments, including argillaceous, volcanic and metamorphic
Organic material is common, but variably abundant throughout the strata. Authigenic clays are rare and consist of kaolinite, with lesser amounts of illite and smectite. Some fine-grained detrital material sits in the pore spaces and could migrate with production. There appear to be no stratigraphic compositional trends through the Reindeer Sequence, but grain size plays a role, with finer- grained units having increasing monocrystalline quartz content.
Although the rocks are generally poorly cemented (there is little evidence of quartz overgrowths), there are localized sideritized and calcitic zones. Sideritization appears to be an early diagenetic event, as ripped-up sideritized mudstone and siltstone clasts are common in reservoir sands throughout the Reindeer Sequence. Recycling of the ripped-up clasts results in them breaking down to sand-sized particles, a significant component of all the reservoir sandstones.
2.1.4 HYDROGEOLOGY
Conclusions about aquifer strength are hindered by a historical lack of production data. The gas column in the A sand at Niglintgak most likely has an edge aquifer because of horizontal (shaly) barriers within and beneath the reservoir sands.
2.1.4.1 Current Aquifer Conditions
Drill stem tests (DSTs) of fields in the vicinity of Niglintgak suggest that the fields share a common water gradient down to at least 2,100 TVD mSS. Partially dissolved grains suggest that there was abundant groundwater flow before the sands filled with gas. Major faults surrounding the Niglintgak field are expected to hinder aquifer flow. Several aquifer scenarios were run in the 3-D dynamic reservoir model (see Section 4.2, Reservoir Simulation) to gauge the ability of the current field development plan to handle water influx.
Below 3,200 TVD mSS, all fields are overpressurized (geopressured), and above 2,100 TVD mSS, all fields are normally pressurized (hydropressured). In between this range, there is a mix of hydropressured and geopressured reservoirs. The potential for isolation of gas-filled sands suggests that the aquifer could be restricted, particularly below 2,100 TVD mSS. In Niglintgak, none of the hydrocarbon resources are overpressurized.
If aquifer pressure is too low, possible recharge sources for the aquifer include:
• Caribou Hills, 20 km south
• Reindeer Sequence subcrops at the base of the Iperk unconformity, just north of the Titalik and Reindeer SDLs 33, 34 and 64. The activity of this source depends on the depth of permafrost but, unlike Caribou Hills, it allows a
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continuous sand pathway for water to move along, rather than moving across aquitards via faults.
2.1.4.2 Past Active Aquifer
Petrology provides indirect evidence of an active aquifer in the past. Thin sections of the A sand at Niglintgak exhibit significant levels of secondary quartz and chert grain dissolution and a lack of quartz overgrowths. This implies high transmissibility, good sand continuity and a large volume of alkaline water flushing through the system before gas accumulation, dissolving silica elements. Low salinities in tested formation waters also suggest an active flow through the aquifer. Tested formation water in Lower Tertiary strata across the Mackenzie Delta yields from 8 to 15,000 mg/L in total dissolved solids.
2.1.4.3 Aquifer Extent
Recent mapping of the Reindeer A sand, in conjunction with compiling local and regional petrophysical and structural geological data, suggests that a large aquifer might exist. A major fault acts as a trap for the gas at the north end of the Niglintgak field and other major regional faults are expected to impede aquifer flow.
It is uncertain how important a role faults internal to the field or variations in sand thickness play in retarding the aquifer. When issues like fault seal and overpressurization are taken into account, actual aquifer strength is expected to be much lower. As a check, field production behaviour under different aquifer strengths was dynamically modelled.
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APPLICATION FOR APPROVAL OF THE DEVELOPMENT PLAN FOR NIGLINTGAK FIELD PROJECT DESCRIPTION GEOPHYSICS
2.2.1 SEISMIC ACQUISITION AND INTERPRETATION
2.2.1.1 Seismic Acquisition
Seismic data in the Niglintgak region consists of 2-D and 3-D surveys. The 2-D seismic was acquired in the 1960s and 1970s, and consists of Shell and trade seismic.
Shell’s Niglintgak 3-D seismic survey covers 205 km2 and was acquired in the winter of 1988–1989 (see Figure 2-7). The survey covers the following SDLs:
• Niglintgak (SDLs 16 and 19) • Kumak (SDLs 18, 31 and 59)
– 135° 30´ 00´´ W– 135° 20´ 00´´ W – 135° 10´ 00´´ W – 135° 0´ 00´´ W –134° 50´ 00´´ W
69° 24´ 00´´ N
69° 22´ 00´´ N
Upluk SDL 016 69° 20´ 00´´ N
Niglintgak SDL 019 69° 18´ 00´´ N
Kumak Kumak SDL 018 69° 16´ 00´´ N SDL 059
Kumak Kumak SDL 018 SDL 031 69° 14´ 00´´ N
69° 12´ 00´´ N
0 1 2 3 4 5 Shell SDL Non-Shell SDL kilometres
Figure 2-7: Niglintgak 3-D Seismic Outline
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2.2.1.1 Seismic Acquisition (cont’d)
The seismic volume was processed in 1989 by Western Geophysical and in 2000 by Shell. However, poor well ties and phase concerns prompted Shell to reprocess the data in 2001, when most of the seismic interpretations were done.
2.2.1.2 Seismic Quality and Calibration
The seismic data is of good quality and shows the Farewell Anticline plunging from northwest to southeast. In the mid-1970s, Shell drilled a series of wells down the crest and plunge of the Farewell Anticline. The C-58 well encountered water at the southeast end of the structure and is a good calibration point.
For an overview of the seismic data through the Niglintgak field, see Figure 2-8, which represents seismic line A to A' (see Figure 2-9).
A A´ L300 L350 L400 L488 T221 T217 T212 T250 0
500
1,000
Kumak E-58
1,500
2,000 Niglintgak H-30
Niglintgak B-19
2,500 Niglintgak M-19 Kumak C-58 NW SEW E
Figure 2-8: Seismic Line Through the Niglintgak Field
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Upluk C-21
A
Niglintgak H-30
Niglintgak M-19
Niglintgak B-19
B Kumak E-58
Kumak C-58 A' B'
Bottomhole Location Shell SDL Gas Well Surface Location Non-Shell SDL
Figure 2-9: Location of Seismic Lines of Section
2.2.2 HORIZONS
The three main seismic horizons that were picked are:
• top A sand • D sand • L-upper sand (the top L sand)
Figure 2-10 shows the well log and seismic calibration.
2.2.2.1 Top A and D Sands
Top A and D sands are sandstones with high (25 to 35%) porosities and, when filled with gas, appear as a robust trough on the seismic data. The sands remain a trough when filled with water and are easily picked and tracked. Near faults, seismic events tend to dim in amplitude, which makes it difficult to pick event terminations for fault definition. The result is conservative fault gap picking that might be slightly pessimistic.
2.2.2.2 L-Upper Sand
The L-upper sand is a sandstone that occurs at or near erosion surfaces. In some instances, the L-upper sand is removed and the erosion surface penetrates into the M sand. The horizon is a trough, but it is not a direct hydrocarbon indicator.
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500 500 Niglintgak M-19
A Sand
1,000 1,000 D Sand
1,500 1,500 L Sand
Niglintgak M-19 2,000 2,000 Arbitrary Line Arbitrary Line W E W E
Figure 2-10: Well Log and Seismic Calibration
2.2.3 FAULTS
Faults transect the structure from west-northwest to east-southeast in a series of normal faults that have scissor-type movement. The seismic data can be used to map the faults from their tips with zero throw, increasing in throw to hundreds of metres toward the east (see Figure 2-11).
2.2.4 AMPLITUDES
The top A sand amplitude is greatly affected by the presence of gas, which results in a robust direct hydrocarbon indicator. The amplitude is calibrated by the wet C-58 well and can be used to delineate the area of the gas accumulation (see Figure 2-12, which represents seismic line B to B').
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– 135° 25´ 00´´ W – 135° 20´ 00´´ W – 135° 15´ 00´´ W –135° 10´ 00´´ W
Upluk A-42 69° 21´ 00´´ N
Upluk C-21
69° 20´ 00´´ N
Niglintgak H-30
Niglintgak M-19 69° 19´ 00´´ N
Niglintgak B-19 Inc reasing fault At fault tips, fault throw 69° 18´ 00´´ N throw is zero Kumak E-58
Kumak C-58
69° 17´ 00´´ N
69° 16´ 00´´ N
Bottomhole Location Gas Well Surface Location Shell SDL Non-Shell SDL
Figure 2-11: Niglintgak Major Faults
2.2.5 DEPTH CONVERSION
Seismic data was used to develop depth-structure maps for the A sand and L sand. These two maps were then used to construct depth-structure maps for other sands by using individual unit thicknesses in the 3-D static model.
Additional depth-structure maps were built for:
• D to J sands – constructed using the A sand depth-structure map • L to R sands – constructed using the L sand depth-structure map
2.2.5.1 A Sand Depth-Structure Map Construction
An A sand depth-structure map was constructed using data collected from the:
• A sand interval velocity contour map • A sand time-structure map
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B B´ L450 L500 E-58 T225 C-58 T246 Kumak E-58 Kumak C-58
500500 500
Amplitude ~10,000
Amplitude ~5,000
A1 Sand A2 Sand A3 Sand A4 Sand A1 Sand A5 Sand A2 Sand A3 Sand A4 Sand A5 Sand D Sand
1,000 1,000 D Sand E Sand F–G Sand E Sand H0 Sand F–G Sand Kumak E-58 H0 Sand H1 Sand H2 Sand
Figure 2-12: Seismic Line Through E-58 (Gas) and C-58 (Wet) Wells Showing Amplitude
Construction Process
The process for constructing the A sand interval velocity map was:
1. Top A sand interval velocities were calculated from the surface for each well.
2. The interval velocity contour map was constructed with the contour lines running about perpendicular to the strike of the anticline.
3. Velocity contours were then adjusted to closely fit the hydrocarbon amplitude anomaly outline for the A sand, which is indicative of the most likely free water level of 998 TVD mSS.
The resulting interval velocity contour map had a general trend of increasing velocities from:
• northwest to southeast, following the plunge of the Farewell Anticline and the direction of increasing permafrost thickness, factors that cause increases in interval velocities
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• the crest of the Farewell Anticline down the east flank of the structure, in the direction of increasing permafrost thickness
The A sand time-structure map from seismic was depth converted using the velocity map. The most likely free water level (998 TVD mSS) structural contour was then manually adjusted where small structural discrepancies existed between the amplitude anomaly map and the free water level. This resulted in the top A sand depth-structure map that was used to derive depth-structure maps for the A to J intervals.
Fault Cutout
In the C-21 well, the A sand is missing because of a fault cutout. The fault is large and regional, with a throw of hundreds of metres. It has been interpreted that the C-21 well lies in a complex fault zone and formation tops from this well have not been incorporated into the interpretation. The result is a structural interpretation that is somewhat optimistic (higher in elevation) near the C-21 well.
2.2.5.2 L Sand Depth-Structure Map Construction
The same process used to build the A sand depth-structure map was used to produce a depth-structure map of the L-upper sand.
Construction Process
The L-upper interval velocity contour map was constructed from well interval velocities. These velocity contours mimic the A sand velocity contours. Unlike the A sand, no further adjustments were needed because there were no associated hydrocarbon seismic anomalies with the top L sand.
Poorly Defined Areas
In certain sections of the 3-D seismic survey, the L sand is poorly defined. Weak seismic amplitudes in the eastern area of the 3-D seismic survey indicate erosion by the K Canyon. The K Canyon erosional event consists of a series of nested channels that are difficult to map seismically.
An attempt to map this erosional surface near the L sand is called the K Canyon horizon. Seismic mapping of the K Canyon horizon indicated that the L sand event had been cut into by the K Canyon erosional event, removing the L sand in some areas and reducing the potential reservoir volume of the formation.
2.2.6 FAULTS USED IN THE DEPTH-STRUCTURE MAPS
Faults that cut through rock formations are rarely vertical and usually run diagonally through the rock. In an overhead or map view, faults create gaps in the rock formation and the seismic data. The greater the deviation from vertical in the fault, the wider the gap in the seismic map view. These gaps form polygon
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2.2.6 FAULTS USED IN THE DEPTH-STRUCTURE MAPS (cont’d)
shapes on the seismic map, and these areas are not included in resource estimates.
Fault gaps mapped in the A sand have been used in drawing the depth-structure maps of formations down to the J sand. The A to D sands contain the majority of the Niglintgak field’s resources. Therefore, this approach is reasonable and conservative.
The faults generally trend northwest to southeast, with the downthrown block usually on the northeast side of the fault plane. The fault planes are slightly inclined from vertical, dipping to the northeast. The use of fault polygons in depth-structure maps from upper sands for deeper sands, such as A sand for D sand, reduces slightly the estimate of the possible hydrocarbon-bearing area of the deeper sands.
Fault gaps in the L sand have been similarly used for formations below L. For the L to R sands, where the hydrocarbon accumulations are smaller in areal extent and located near the M-19 well, the approach of using just the L fault polygons might be slightly conservative for deeper sands.
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APPLICATION FOR APPROVAL OF THE DEVELOPMENT PLAN FOR NIGLINTGAK FIELD PROJECT DESCRIPTION PETROPHYSICS
2.3.1 LITHOLOGY, POROSITY AND PERMEABILITY
2.3.1.1 Lithology
Lithological characteristics of the upper Reindeer Formation sands can be broadly described as:
• chert lithic sandstone • silty • fine to medium grained • moderately to well sorted • slightly to moderately argillaceous
Although the physical properties are highly variable within a sand and from sand to sand, the mineral composition seems to be more consistent, probably indicating a similar sediment source. These sediments were deposited in deltaic and fluvial settings.
A normalized lithology interpretation was completed using log data, which was then calibrated to core during visits to the Geological Survey of Canada core laboratory. Table 2-1 shows the core data acquired at Niglintgak. The normalized lithology curves were used as the primary sand versus nonsand discriminator.
2.3.1.2 Porosity
The porosity of the upper Reindeer Formation is mainly primary and intergranular. The A sand, representing the main focus of the Niglintgak Field Development Plan, has a high total average porosity of 28%, and the standard deviation is generally about 4%.
Figure 2-13 shows that, on average, the log-calculated porosity is equivalent to the core-measured porosity, and the standard deviation is between 4 and 5% (see Section 3.1, Reservoir Data).
2.3.1.3 Permeability
The final permeability profile was estimated by using a set of four facies- dependent permeability versus porosity transforms, based on core permeability and porosity data, reconciled with well test data (see Figure 2-14).
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2.3.1.3 Permeability (cont’d)
The in situ average permeability is considered excellent for gas production (400 mD) in the A sand. As porosity decreases with depth to about 15% in the deeper L, M and N sands, the permeability decreases to about 25 mD.
Table 2-1: Core Data for Niglintgak SDL 19
Core Core Core Start Core Stop Recovery Dominant Well Name No. (m) (m) (m) Sand Lithology Niglintgak H-30 1 1,077.7 1,087.2 9.5 E Shale 2 1,108.5 1,126.8 18.3 F-G Sand 3 1,127.1 1,132.3 5.2 F-G Sand 4 1,781.7 1,800.0 18.3 L Sand, silt 5 2,122.0 2,126.2 4.3 O Sand, silt Niglintgak M-19 1 969.2 978.4 9.1 A Shale 2 996.3 1,005.5 9.1 D Sand 3 1,005.5 1,008.8 3.4 D Sand 4 1,009.1 1,011.6 2.4 D Sand 5 1,088.4 1,097.6 9.1 E Sand 6 1,184.5 1,185.4 0.9 H Sand 7 1,185.7 1,193.6 7.9 H Sand 8 1,193.6 1,202.7 9.1 H Sand 9 1,292.7 1,301.2 8.5 H Sand, shale 10 1,301.8 1,311.0 9.1 H Sand, shale 11 1,331.4 1,340.5 9.1 I Sand 12 1,341.5 1,350.6 9.1 I Sand 13 2,715.9 2,716.8 0.9 X Conglomerate 14 2,756.1 2,764.3 8.2 X Sand Niglintgak B-19 1 893.0 902.4 9.5 A Sand 2 902.4 911.0 8.5 A Sand 3 911.0 920.7 9.8 A Sand 4 928.4 929.3 0.9 A Sand 5 929.6 947.0 17.4 A Sand 6 997.9 1,007.0 9.1 A Sand 7 1,137.2 1,146.3 9.1 D Sand 8 1,236.3 1,245.4 9.1 E Sand 9 1,943.6 1,952.1 8.5 M Silt 10 2,748.5 2,752.1 3.7 V Sand 11 2,753.0 2,762.2 9.1 V Sand 12 2,951.2 2,960.4 9.1 X Sand Kumak E-58 1-25 1,065.5 1,257.6 192.1 A Sand Kumak C-58 1 1,029.9 1,036.6 6.7 A Sand 2 1,036.6 1,049.1 12.5 A Sand 3 2,205.8 2,223.2 17.4 M Sand
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124 27.0
112 24.3
99 21.6
87 18.9
74 16.2
62 13.5
50 10.8 Number Samples Number
37 8.1 of Total Percentage
25 5.4
12 2.7
0 0.1 –0.15 –0.12 –0.09 –0.06 –0.03 0.00 0.03 0.06 0.09 0.12 0.15 Delta Porosity Histogram plot Cumulative 0 – 100% Mean –0.011 Standard Mode 0.000 Deviation 0.047 Median 0.000
Figure 2-13: Log-Calculated Porosity Versus Core-Measured Porosity Corrected for Stress
2.3.2 PETROPHYSICAL EVALUATION
Shell proprietary software LOGIC was used for the petrophysical evaluation, as follows:
1. Raw log and raw core data were loaded into the database. Preprocessing, systematic and ad-hoc edits were made where necessary.
2. A normalized lithology interpretation was done using log data. The interpretation was then checked against the core data and used as the primary cut-off to compute sand versus nonsand sediments.
3. Porosity was computed from the density log, using a Monte Carlo algorithm, and calibrated on stressed core porosity measurements.
4. Water saturation was computed from the corrected dual laterolog resistivity tool responses, using a Waxman-Smits approach with a Monte Carlo algorithm.
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2.3.2 PETROPHYSICAL EVALUATION (cont’d)
5. The final permeability profile was estimated from calculated porosity, using four facies-dependent transforms, based on core permeability and porosity data.
6. Water salinity was obtained from produced water during flow tests, log analyses and regional data. The water salinity was estimated to be between 8,000 and 15,000 ppm sodium chloride equivalent for most of the formations of interest. Although a mean temperature versus depth relationship was used, the shallow temperature profile is locally variable because of a changing permafrost thickness. New and historical relationships and parameters were used for Qv, B, m* and n* Waxman- Smits variables.
7. Total porosity and total water saturation models were used.
1.E+04 General Trend y = 0.0130e 0.3633x R2 = 0.78 1.E+03
1.E+02
1.E+01
1.E+00 K Air AtmosphereK Air (ka-atm) 1.E-01
1.E-02 0 5 10 15 20 25 30 35 40 Stressed Porosity Channel Facies Mouth Bar Facies Lower Quality Non Reservoir 2001 Pressure Petrographic Image 1973 Test Permeability Transient Analysis Analysis (average LMN)
Figure 2-14: Permeability Versus Porosity Transforms
2.3.3 FLUID IDENTIFICATION AND SATURATION
Water saturation values used to identify gas–water contacts at each well location were modelled using the Waxman-Smits shaly-sand empirical formula combined with a Monte Carlo simulation. The total average water saturation of the A sand is relatively high (20 to 30%) and the uncertainty (standard deviation) is about 10%.
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Formation water salinity is relatively low, based on flow tests, log analyses and local temperature profiles (see Table 2-2). Relatively clean formation water recoveries from DSTs indicated a total dissolved solids (TDS) content of about 11,000 mg/L with a resistivity of 0.5 ohm-m at 25ºC. This equates to a total salinity of about 11,000 ppm sodium chloride. Using logs, the estimation of formation water resistivity from water-bearing intervals yielded values of 0.4 and 0.5 ohm-m. This is equivalent to a formation water salinity of 12,000 ppm sodium chloride at reservoir temperature.
Table 2-2: Example Water Analysis from DST 16 in B-19 Well
Amount Component Ion (mg/L) Sodium and Potassium Na+ K 4,425 Calcium Ca 7 Magnesium Mg 2 Chlorine Cl 4,803
Bicarbonate HCO3 452
Sulphate SO4 350
Carbonate CO3 1284
Hydrogen Sulphide H2S None Total Dissolved Solids 11,323
True formation resistivity was determined from the dual laterolog tool response. Mud filtrate invasion appears to have affected the deep reading response of the laterolog tool, according to the invasion profile observed on logs. Corrections were applied, where necessary.
Free water levels have been interpreted from a combination of DST pressure and recovery data, log interpretation and other appropriate geological data (see Section 3.1, Reservoir Data).
2.3.4 RESERVOIR DEFINITION
The reservoir from logs was defined as:
• net reservoir – sand or silty sand with a total porosity greater than 10%, equivalent to an atmospheric permeability to air of 0.1 to 0.5 mD
• net pay – net reservoir with a water saturation of less than 60%
Table 2-3 summarizes the cut-offs used for calculating net pay.
Table 2-4 summarizes the petrophysical, lithological and fluid characteristics of the geological units in Niglintgak.
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Table 2-3: Summary of Cut-Offs Used for Calculating Net Pay
Category Cut-Off Net sand reservoir Lithology = sand or silt Porosity greater than 10% porosity cut-off Net pay Net sand reservoir Water saturation less than 60% Porosity Given for pay interval if net pay is greater than 0 Given for net sand reservoir if net pay = 0
Table 2-4: Petrophysical, Lithological and Fluid Characteristics of Geological Units
Net Sand Net Sand Reservoir Water Top Base Reservoir (TVD Net Pay Porosity Saturation Fluid Test Type Unit Well (mKB) (mKB) (mKB) mSS) (mKB) (%) (%) Type and Number Lithology A H-30 761.2 902.4 43.8 43.8 22.0 28 24 Gas NT Sand, shale A M-19 812.6 985.4 28.8 28.8 19.2 28 28 Gas DST 4,6 Sand, shale A B-19 889.6 1,107.9 135.0 129.3 80.2 28 33 Gas, water DST 16, 17 Sand, silt, shale, coal A E-58 1,053.3 1,298.6 111.8 83.9 101.6 31 28 Gas DST 1, 2 Sand, silt, PT 1, 2 shale, coal C H-30 902.4 954.4 20.0 20.0 16.6 29 44 Gas NT Shale, silt D H-30 954.4 1,057.1 62.2 62.2 34.4 29 36 Gas NT Sand, silt D M-19 985.4 1,085.1 40.6 40.6 9.2 23 48 Gas, water DST 26, 28 Sand, silt E H-30 1,057.1 1,100.0 25.0 25.0 14.6 30 31 Gas DST 1 Sand, shale E M-19 1,085.1 1,122.4 14.6 14.6 0.0 20 100 Water DST 25, 27 Sand E E-58 1,421.0 1,466.4 3.0 2.4 2.0 25 43 Gas NT Sand, silt F-G H-30 1,100.0 1,156.1 35.0 35.0 14.0 32 30 Gas NT Sand, silt, shale F-G E-58 1,466.4 1,538.0 40.8 35.7 4.6 27 40 Gas NT Sand, silt, shale H0 H-30 1,159.0 1,207.2 29.0 29.0 23 28 41 Gas, oil NT Sand, silt H1 H-30 1,207.2 1,294.6 14.6 14.6 4.0 24 54 Oil NT Sand, shale H2 M-19 1,285.0 1,323.0 11.8 11.8 4.0 19 55 Mud DST 23, 24 Sand, silt, shale I H-30 1,333.4 1,402.0 11.4 11.4 6.0 24 50 Oil NT Silt, sand, shale I M-19 1,323.0 1,379.4 36.0 36.0 15.2 25 47 Oil DST 21, 22 Sand, silt, shale J M-19 1,379.4 1,450.0 15.4 15.4 2.0 21 56 Oil DST 20 Sand, silt, shale K B-19 1,632.4 1,867.4 42.0 33.1 5.2 18 45 Oil, water DST 12, 14 Sand, silt, shale L-u M-19 1,702.4 1,744.6 30.6 30.6 24.0 19 38 Gas DST 19 Sand, shale, coal L-u B-19 1,867.4 1,899.4 19.0 15.6 0.0 12 100 Water DST 11, 15 Sand, shale, coal L-l M-19 1,744.6 1,821.4 22.4 22.4 5.0 15 53 Gas, oil, DST 15, 16, Sand, shale water 18 M H-30 1,864.0 2,038.0 22.8 22.8 0.0 17 100 Water DST 2 Sand, silt, shale, coal
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Table 2-4: Petrophysical, Lithological and Fluid Characteristics of Geological Units (cont’d)
Net Sand Net Sand Reservoir Water Top Base Reservoir (TVD Net Pay Porosity Saturation Fluid Test Type Unit Well (mKB) (mKB) (mKB) mSS) (mKB) (%) (%) Type and Number Lithology M-u M-19 1,821.4 1,861.8 11.6 11.6 7.6 14 43 Gas DST 14 Sand, silt, shale, coal M-m M-19 1,861.8 1,874.6 7.8 7.8 7.0 16 31 Gas DST 13 Sand, silt, shale, coal M-l M-19 1,874.6 1,999.5 34.6 34.6 4.6 16 55 Gas, oil DST 12 Sand, shale, silt M B-19 1,981.0 2,185.6 85.0 78.7 0.0 14 100 Water DST 10 Sand, silt, shale, coal N M-19 1,999.5 2,067.8 6.0 6.0 3.6 13 50 Gas DST 11 Sand, silt, coal N B-19 2,185.6 2,249.0 6.8 6.4 0.0 12 100 Water DST 9 Sand, silt, coal, shale O M-19 2,067.8 2,131.0 35.4 35.4 12.0 14 39 Gas, oil DST 10 Sand, silt, coal Q M-19 2,173.0 2,264.0 15.2 15.2 8.0 14 48 Oil DST 9 Sand, silt, shale R B-19 2,452.0 2,502.8 17.6 17.3 0.0 12.6 100 Water DST 8 Sand, silt, coal S M-19 2,326.0 2,367.0 16.6 16.6 1.6 12 48 Gas DST 8 Sand U B-19 2,621.0 2,658.0 17.1 17.0 0 10 100 Water DST 7 Silt, sand W B-19 2,787.0 2,871.0 31.2* 30.9* 0.0 9.2* 100 Water DST 6 Sand X B-19 2,871.0 3,063.0 11.5* 11.3* 0.0 9.3* 100 Water DST 5 Sand Y M-19 2,875.0 3,008.0 7.2* 7.0* 0.0 8.9* 100 Mud DST 7 Sand Y B-19 3,063.0 3,144.0 19.3* 19.0* 0.0 9.5* 100 Water DST 2, 4 Sand Note: mKB = metres from kelly bushing NT = not tested (fluid type inferred from log data) PT = production test * = below porosity cut-off
2.3.5 FUTURE DATA ACQUISITION
2.3.5.1 Formation Evaluation Program
The formation evaluation program will be designed to ensure that the maximum amount of information can be gained as early as possible in development drilling operations. Data acquisition plans will be directed toward refining the field models and reducing the uncertainties.
2.3.5.2 Evaluation Techniques
Open-hole logging services used in evaluating the field formation might include:
• array resistivity • array acoustic, with both compressional and shear measurements • resistivity and acoustic imaging • natural gamma-ray spectroscopy • elemental capture spectroscopy
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2.3.5.2 Evaluation Techniques (cont’d)
• advanced modular wireline testing
Cased-hole saturation and production monitoring logs might also be run to monitor reservoir performance.
Plans will be made to achieve selective coring during development drilling and will include basic and special core analysis measurements.
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APPLICATION FOR APPROVAL OF THE DEVELOPMENT PLAN FOR NIGLINTGAK FIELD PROJECT DESCRIPTION RESERVOIR DATA
3.1.1 3-D DYNAMIC RESERVOIR MODEL
This section describes the information used in developing the 3-D dynamic reservoir model used to forecast gas production and recovery for the Niglintgak field. The Niglintgak field was discovered in 1973 with the drilling of the Shell Niglintgak H-30 well. Five additional exploration and delineation wells were drilled:
• Chevron SOBC Upluk (C-21) • Shell Kumak (C-58) • Shell Niglintgak (M-19) • Shell Niglintgak (B-19) • Shell Kumak (E-58)
The C-21 and C-58 wells were abandoned immediately after drilling and evaluation. The remaining four wells were tested and suspended, then abandoned in 1996. The C-21 well is interpreted to be in a complex fault zone and its data is not significantly used in the interpretation.
The data obtained from the wells includes:
• cores • well logs • drill stem tests (DSTs) • production tests (PTs) • fluid analyses
3.1.2 RESERVOIR DESCRIPTION
The stacked sands of the Niglintgak field contain an accumulation of hydrocarbon pools. Hydrocarbon volumes are recorded in the A through R sands and consist of non-associated gas and oil. Only non-associated gas is part of this development, for which the gas-bearing sands are:
• A sand • C sand • D sand • E sand
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3.1.2 RESERVOIR DESCRIPTION (cont’d)
• F-G sand • L-upper sand • M-upper sand • M-middle sand • N sand
The L-upper, M-upper, M-middle and N sands are sometimes referred to as the L, M, N sands, indicating the non-associated gas sands to be developed. The shallow A sand is the primary reservoir in the Niglintgak field. This sand is characterized by:
• high porosity (28%) • high permeability (average 400 mD) • high net-to-gross reservoir development
Generally, porosity and permeability decrease as one goes deeper in the reservoir.
3.1.3 WELL TEST DATA
Numerous DSTs and two PTs were conducted in the Niglintgak wells. Table 3-1 summarizes the Niglintgak field well tests for the sands included in the development.
The most extensive testing was done in M-19, where a total of 28 DSTs were run over more than a dozen distinct sands.
Table 3-1: Niglintgak Field Well Gas Zone Tests
Type of Test Rate Rate Well Name Test Date Run Unit Result (Mm3/d) (MMscf/d) Shell Niglintgak (H-30) January 1973 DST 1 E Gas 0.167 5.9 Shell Niglintgak (M-19) June 1974 DST 4 A Gas 0.238 8.4 June 1974 DST 6 A Gas 0.235 8.3 December 1974 DST 11 N Gas and NGLs 0.232 8.2 December 1974 DST 13 M-m Gas and NGLs 0.275 9.7 December 1974 DST 14 M-u Gas and NGLs 0.235 8.3 January 1975 DST 19 L-u Gas and NGLs 0.476 16.8 January 1975 DST 28 D Gas 0.193 6.8 Shell Niglintgak (B-19) February 1976 DST 17 A Gas 0.241 8.5 Shell Kumak (E-58) May 1977 DST 1 A Gas 0.249 8.8 May 1977 DST 2 A Gas 0.238 8.4 May 1977 PT 1 A Gas 0.521 18.4 May 1977 PT 2 A Gas 0.266 9.4
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The most recent and extensive A sand testing program was conducted in well E-58 in 1977. Two DSTs and two production tests were run to quantify the A sand productivity at different rates and drawdown combinations.
Most DSTs were performed as cased and perforated tests. Generally, the tests were short (less than 12 hours) except for the two extended production tests done in E-58. The time lapse between drilling and testing activities ranged from several days to several weeks. Consequently, in some cases, reservoir rock formations were exposed to the drilling fluid for a substantial period of time, reducing the quality of the data recorded.
Although recent pressure transient analysis results show relatively high formation damage with high skin factors for most of the tests, good deliverability was achieved under minimal drawdown. Therefore, deliverability and, subsequently, permeability-thickness of the upper sands is considered to be high. This is confirmed by the exceptionally rapid buildup of pressure registered by pressure gauges in many of the DSTs for the A to E sands.
3.1.3.1 Pressure-Versus-Depth Plots
Pressure versus depth plots are derived from data obtained from formation tests and are used to help determine hydrocarbon-water levels (free water levels) in a reservoir sand. Figure 3-1 shows the pressure versus depth plot for the Niglintgak field.
Data from the pressure-depth plot (see Table 3-2), logs, DSTs and a Monte Carlo simulation of DST pressure equations were used to determine a most likely free water level (see Table 3-3).
3.1.3.2 Temperature-Versus-Depth Plot
The temperature versus depth plot (see Figure 3-2) was compiled from data collected from the well tests. The temperature gradient is about 2.7°C/100 m.
3.1.3.3 In Situ Methane Hydrates
With the low temperature gradient, the possibility of in situ methane hydrates in the A sand reservoir was considered in the H-30 well. The H-30 well was not tested and is structurally higher than the M-19 well. No reservoir hydrates were observed in the M-19 well, with a top A sand of 804 TVD mSS. The DST results indicated a normal test and ruled out hydrates below this depth. A reservoir hydrates study done in 2003 concluded that no methane hydrates were likely at initial reservoir conditions.
3.1.3.4 Core Data Analysis
A total of 485 m of core was taken in the wells drilled by Shell. Niglintgak core measurements consisted of standard routine analyses and a number of special core analyses done on a representative set of samples for several of the hydrocarbon-bearing sands. These included measurements for:
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3.1.3.4 Core Data Analysis (cont’d)
• stressed porosity • capillary pressure • formation resistivity factors (FRF) • saturation exponent (n) • lithological exponent (m) • Waxman-Smits’ cation exchange capacity (Qv)
-700
M-19 #6 A -800 M-19 #4 A E-58 PT#2 A
-900 E-58 #2 A E-58 #1 A B-19 #17 A M-19 #28 D -1,000 H-30 #1 E M-19 #25 E -1,100 M-19 #26 D B-19 #16 A -1,200
-1,300 Water Data Regression Line Best Fit Anchored on M-19 #26 D -1,400
-1,500
-1,600 True Vertical Depth Depth (m) True Vertical
-1,700 B-19 #11 L B-19 #15 L M-19 #19 L-u M-19 #15 L-l -1,800 M-19 #14 M-u B-19 #10 M M-19 #13 M-m -1,900 H-30 #2 M
M-19 -2,000 #11 N B-19 #9 N
-2,100
-2,200 10,000 12,000 14,000 16,000 18,000 20,000 22,000 Pressure – kPa(a)
Figure 3-1: Pressure-Versus-Depth Plot for the Niglintgak Field
Core measurements were used to examine the relationship between permeability and porosity (see Section 2.3, Petrophysics).
Capillary pressure measurements done on the Niglintgak core were not considered reliable enough to be used in saturation-height functions, possibly because the measurements were poorly consolidated and measurement techniques for such core in the 1970s lacked precision.
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The saturation-height functions were generated using the analytical techniques of Thomeer and Corey-type models based on logs, fluid properties and elevation above the free water level. Seven groups of saturation-height functions, along with their consistent relative permeability functions, were generated on a set of seven permeability bins and were used in the 3-D dynamic reservoir model.
Table 3-2: Pressure and Depth Input Data
Test Test Interval Interval Recorder Extrapolated Test Start Stop Formation Depth Fluid Pressure Sand Well Number (TVD mSS) (TVD mSS) Fluid Type (TVD mSS) (kPa[a]) A M-19 4 807 834 Gas 808 10,945 A M-19 6 807 817 Gas 812 10,973 A B-19 16 1,001 1,012 Water 1,003 11,086 A B-19 17 980 988 Gas 979 11,037 A E-58 1 934 942 Gas 932 10,940 A E-58 2 903 910 Gas 901 10,940 A E-58 PT#2 807 834 Gas 821 10,800 D M-19 26 995 1,001 Mud filtrate 997 11,029 D M-19 28 977 987 Gas 980 10,946 E H-30 1 1,039 1,077 Gas 1,026 11,638 E M-19 25 1,079 1,085 Water 1,081 11,891 L-u M-19 19 1,710 1,716 Gas 1,713 18,269 L-l M-19 15 1,748 1,754 Water 1,748 18,345 M-up M-19 14 1,834 1,841 Gas 1,837 19,962 M-mid M-19 13 1,851 1,857 Gas 1,864 19,565 M H-30 2 1,896 2,007 Water 1,886 19,882 M B-19 10 1,857 1,878 Water 1,858 19,379 N M-19 11 1,888 1,996 Gas 1,991 21,213 N B-19 9 2,029 2,033 Water 2,029 21,102 R B-19 8 2,244 2,252 Water 2,245 23,475
Table 3-3: Niglintgak Estimated Free Water Levels
Most Likely Free Water Level Sand (TVD mSS) A, C, D 998 E 1,067 F-G 1,115 L-upper 1,743 M-upper 1,920 M-middle 1,875 N 2,045
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Mean Surface Temperature -3°C
0 Base Permafrost 120 m
1,000
2,000 Depth (m)
3,000
4,000
Temperature Gradient 2.73°C / 100 m
5,000
0 25 50 75 100 Temperature (°C)
Figure 3-2: Composite Temperature – Depth-Plot Farewell Structure
3.1.4 RESERVOIR FLUID PROPERTIES
Gas analysis of the samples collected during well testing indicated the presence of sweet gas, with over 98% methane in A sand and 95% methane in the L, M and N sands (see Table 3-4). The variation in the methane composition of the gas samples collected from the tested wells (H-30, M-19, B-19 and E-58) was within 1%. Given the various sands tested and test conditions, such variations are not unexpected.
No hydrogen sulphide was observed in the gas analysis.
Natural gas liquids were produced from L, M and N sands during DSTs. The expected average liquid to gas ratio is about 38 m3/Mm3 (6.8 bbl/MMscf) from L, M and N sands.
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Table 3-4: Expected Reservoir Gas Composition for Niglintgak
L, M and N A Sand Sands Component Symbol (mol%) (mol%)
Hydrogen sulphide H2S0 0
Carbon dioxide CO2 0.87 1.5
Nitrogen N2 0.13 0.02
Methane C1 98.34 95.11
Ethane C2 0.61 2.32
Propane C3 0.02 0.11
Isobutane IC4 0.02 0.12
Normal butane C4 0.01 0.03
Isopentane IC5 -0.05
Pentane C5 -0.01
Hexane C6 -0.02
Heptane plus C7+ - 0.71 Total 100 100
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APPLICATION FOR APPROVAL OF THE DEVELOPMENT PLAN FOR NIGLINTGAK FIELD PROJECT DESCRIPTION RESOURCES AND PRODUCTION ESTIMATES
3.2.1 APPROACH
Two different methods were used to calculate the hydrocarbon resources for each sand layer:
• a probabilistic model • a 3-D dynamic reservoir model
Both methods generated similar results.
3.2.2 PROBABILISTIC MODELLING
Resources were calculated using a probabilistic model with Shell’s proprietary software FASTRACK. The software uses Monte Carlo simulation to calculate a range of potential volumes and the respective probability for each. Data combinations were used to generate 1,000 possible volume estimates for the individual formations.
A risk assessment for undrilled blocks was done using a method consistent with that used in the National Energy Board’s Probabilistic Estimate of the Hydrocarbon Volumes in the Mackenzie Delta and Beaufort Sea Discoveries, 1998. The analysis yielded a distribution curve of potential volumes in place. The P-90 estimate is a relatively low volume with a 90% probability of being met or exceeded, while the P-10 estimate is at the high end of potential volumes with an estimated 10% probability. The P-50 estimate is the median of volume and probability, and is called the most likely estimate.
Input data for each reservoir included:
• areas from the top reservoir structural map, based on seismic and well control
• an uncertainty area
• hydrocarbon contacts, based on pressure depth plots, DSTs and petrophysical data
• net reservoir thickness, based on geological models, well control and seismic interpretation
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3.2.2 PROBABILISTIC MODELLING (cont’d)
• gross reservoir thickness, based on geological models, well control and seismic interpretation
• average porosity, based on core data, well log data and geological models
• average hydrocarbon saturation, based on special core analyses and well log petrophysical evaluations
• formation volume factors, based on compositional analyses
• recovery factors, based on results from dynamic reservoir models
• shrinkage of 7.4% over the field life, based on current development and economic models
For the estimated hydrocarbon resources contained in Shell’s SDL 19, see Table 3-5.
Table 3-5: Estimated Hydrocarbon Volumes for SDL 19
Probabilistic Estimate Hydrocarbon Volume (most likely) Non-associated gas-initially-in-place 34.0 Gm3 Non-associated ultimate recoverable gas 25.7 Gm3 Non-associated marketable gas resources 23.8 Gm3 Ultimate recoverable NGL resources 0.05 Mm3
3-10 Shell Canada August 2004 NDPA-P1 Section 4.1 RESERVOIR DEPLETION
APPLICATION FOR APPROVAL OF THE DEVELOPMENT PLAN FOR NIGLINTGAK FIELD PROJECT DESCRIPTION INTRODUCTION
4.1.1 APPROACH
The Niglintgak development plan was created through a process that:
• established and modelled reservoir uncertainties • identified specific development variables and alternatives • modelled alternatives to establish optimum development concepts
This evaluation process assessed development alternatives using a range of evaluation criteria consistent with Shell’s sustainable development commitment and principles.
4.1.2 RESERVOIR SIMULATION
Reservoir simulations were created for 10 different interpretations of the subsurface, called realizations. These realizations are representative of the subsurface uncertainties and varied aspects of the subsurface, such as:
• degree of reservoir layering • aquifer strength • extent of faulting • reservoir rock properties and distribution
The reservoir simulations were used to evaluate the impact on gas resource recovery and well deliverabilities through varying:
• wellbore placement • number of wells • downhole wellbore size and equipment • rock properties • reservoir parameters • aquifer strengths
Results from this analysis identified several key characteristics to be considered in optimizing the Niglintgak development plan, including the need for:
• wells drilled high on the crest of the structure to delay water breakthrough and maximize resource recovery
August 2004 Shell Canada Limited 4-1 NDPA-P1 Section 4.1 RESERVOIR DEPLETION INTRODUCTION
4.1.2 RESERVOIR SIMULATION (cont’d)
• wells to be designed with the ability to isolate zones that might produce water
• sand control to maintain wellbore integrity
• commingled production in some wells to minimize well count
• at least six wells to deplete the resource efficiently
4.1.3 DEVELOPMENT ALTERNATIVES
Further analysis was conducted by combining the results of the reservoir simulations into specific development alternatives. The variables used in developing these alternatives included the:
• physical locations of well pads and the gas conditioning facility • number of well pads • number of wells and the complexity of the well design • flow line configuration • equipment configuration • abandonment pressure
One of the key results of assessing development options was well pad placement. Reducing the number of well pads increases the requirement for long-reach wells with high inclinations caused by the shallow depth of the reservoir sands. Long- reach wells of this type:
• increase the likelihood for the suboptimal placing of wellbores in the reservoir, thereby reducing resource recovery
• risk possible wellbore deformation when drilling through fault zones, which could affect the:
• ability to reach targets cost effectively • long-term viability of the wellbore for production purposes
• could increase operating costs because of the complexity of the wellbore path
The evaluation identified the need for three well pads from which to drill wells to reach targets for optimal resource recovery.
4.1.4 RESERVOIR UNCERTAINTIES
With the information from these evaluations, a field development plan was created with sufficient flexibility to ensure reasonable resource recovery for each of the different possible realizations. The six-well development plan obtains
4-2 Shell Canada Limited August 2004 NDPA-P1 Section 4.1 RESERVOIR DEPLETION INTRODUCTION
reasonable resource recoveries in all but one realization, the faulted case. This case requires a 12-well development to obtain a reasonable resource recovery.
4.1.5 RESERVOIR MONITORING PLAN
Production characteristics of the reservoir from each of the realizations were used to form a well and reservoir monitoring plan. The plan is designed to obtain necessary data that would help predict possible production problems and allow the correct mitigative actions to be taken to optimize resource recovery.
August 2004 Shell Canada Limited 4-3 NDPA-P1 Section 4.2 RESERVOIR DEPLETION
APPLICATION FOR APPROVAL OF THE DEVELOPMENT PLAN FOR NIGLINTGAK FIELD PROJECT DESCRIPTION RESERVOIR SIMULATION
4.2.1 PURPOSE
The purpose of the reservoir simulation was to:
• choose and optimize well placement for the development plan • assess the number of wells required • obtain estimates of field production and resource volumes • test alternative depletion plans • analyze the impact of geological and reservoir parameter uncertainties
4.2.2 RESERVOIR SIMULATION MODEL
The reservoir simulation model used a geological model of the subsurface (the static model) to predict the flow of subsurface hydrocarbons and water (the dynamic model) into simulated wellbores. The dynamic model tested various arrangements of well placements and their associated production forecasts to choose and optimize the field depletion plan. DEPSIM and MULTISIM, Shell proprietary static and dynamic modelling software, were used.
A detailed 3-D dynamic reservoir model was developed for gas-bearing reservoirs A to N in the Niglintgak field. For the stratigraphy of the Niglintgak field, see Section 2.1, Geological Description. Input into the model included:
• reservoir property maps for the 3-D dynamic reservoir model imported from the 3-D static geological model (DEPSIM) into the reservoir simulator (MULTISIM). The information imported included data for structural elevation, faults, gross thickness, net-to-gross ratios, porosity and permeability maps based on data from the wells described in Section 2, Geology, Geophysics and Petrophysics, and Section 3.1, Reservoir Data.
• capillary pressure and relative permeability curves
• gas and water compositions
An optimized model grid of the gas-bearing area was developed. The 3-D dynamic reservoir model covered an area of about 11 x 11 km, including the entire hydrocarbon area and the surrounding aquifer area. The result was a total of 75,600 model grid blocks.
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4.2.2.1 Dynamic Model Initialization
The reservoir dynamic model was initialized with:
• reservoir properties • well locations with well path deviations • hydraulic tables
Tubing sizes were optimized to meet the required rate per well. Subsurface safety valves were also considered in the lift curve analysis. Positive skin values of 5 to 10 were modelled, based on engineering estimates of the skin values for each well design and type of completion.
4.2.2.2 Regional Aquifer Model
A 3-D single layer regional aquifer model of the A1 sand was developed to study the impact of aquifer support on Niglintgak reservoir pressure. The 3-D regional aquifer model covered 40 x 26 km, including the Niglintgak, Kumak and Taglu fields. These results were used to model the aquifer support for the chosen case in the field reservoir model.
4.2.3 WATER PRODUCTION
Water production is expected in some wells in the Niglintgak field.
Water from the aquifer will move up the flanks of the field along the laterally continuous reservoir sands. The sands closest to the areas with gas–water contact will produce water first. Areas of high permeability might also result in early water breakthrough. To prevent problems with excess water production, specific water-producing intervals can be isolated. This is known as zonal isolation.
4.2.4 EVALUATION PROCESS
Wells were located to:
• maximize gas recovery • delay water breakthrough
The evaluation was based on different:
• well patterns • well spacing • well production rates • abandonment tubing head pressures
4.2.5 RESERVOIR SIMULATION RESULTS
The reservoir simulation key assumptions and output results for the chosen development plan included:
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• a well pattern of six wells located on the crest of the structure • a total field raw gas production rate of 4.3 Mm3/d (150 MMscf/d), allocated as:
• 3.5 Mm3/d (121 MMscf/d) from the A sand reservoir (four wells)
• 0.6 Mm3/d (22 MMscf/d) from the D, E, and F-G sand reservoirs (one well with commingled production)
• 0.2 Mm3/d (7 MMscf/d) from the L, M and N sand reservoirs (one well with commingled production)
• a tubing head abandonment pressure of 1,724 kPa • compression required from start-up • an economic production life of about 25 years • a plateau rate for 13 to 14 years • a cumulative total gas recovery of about 27 Gm3 • a cumulative NGL recovery of 0.04 Mm3
The following forecasts were generated by the reservoir model for the chosen Niglintgak development concept:
• Figure 4-1 – Niglintgak Reservoir Model Raw Gas Forecast • Figure 4-2 – Niglintgak Reservoir Model Cumulative Raw Gas Forecast • Figure 4-3 – Niglintgak Reservoir Model Water Production Forecast
These initial reservoir model forecasts do not include availability impacts which, when included, extend the expected production flatlife period. The model output was adjusted to include availability, fuel gas usage and liquids shrinkage to determine the expected sales gas forecast for the development (see Section 5.4, Functional Criteria).
The production forecasts for the Niglintgak field are based on Shell’s development on SDL 19, assuming no development on adjacent lands. Future adjacent developments might alter these forecasts.
4.2.6 RESERVOIR UNCERTAINTY ANALYSIS
To assess the impact on gas recovery, possible reservoir uncertainties were identified and have been studied with the 3-D dynamic reservoir model. These uncertainties are related to factors such as:
• fault transmissibility • aquifer strength • reservoir connectivity • gross rock volume variation • permeability variation • rock compressibility • residual gas saturation • kv/kh ratio (vertical permeability to horizontal permeability ratio)
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4.5
4
3.5 /d) 3 3
2.5
2
1.5 Natural Gas Rate (Mm Rate Natural Gas 1
0.5
0 0 5 10 15 20 25 30 35 Time (year)
Figure 4-1: Niglintgak Daily Raw Gas Production Forecast
30,000 ) 3
25,000
20,000
15,000
10,000
5,000 Cumulative Natural Gas Production(Mm Gas Natural Cumulative
0 0 5 10 15 20 25 30 35 Time (year)
Figure 4-2: Niglintgak Cumulative Natural Gas Production Forecast
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14
12
10 /d) 3 8
6 Water Rate (m Rate Water 4
2
0 0 5 10 15 20 25 30 35 Time (year)
Figure 4-3: Niglintgak Daily Water Production Forecast
4.2.7 A SAND RESERVOIR REALIZATIONS
To study a wide range of reservoir depletion scenarios, 10 subsurface reservoir realizations (R1 and R1.1 to R9) were considered for the A sand, which contains most of the Niglintgak gas resources.
Table 4-1 summarizes the 10 realization cases.
Table 4-1: Summary of Reservoir Realization Cases
Reservoir Realization Description R1 Layered reservoir with sealing faults (chosen case) R1.1 Layered reservoir with transmissible faults R2 Layered reservoir with a stronger aquifer R3 Layered reservoir with more sealing faults (faulted case) R4 Tank reservoir case R5 Tank reservoir case, with thief zone of high permeability R6 High GRV/GIIP case R7 Low GRV/GIIP case R8 Sweet fairway case - good permeability around wells only R9 Low permeability case Note: GRV = gross rock volume GIIP = gas-initially-in-place
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4.2.7 A SAND RESERVOIR REALIZATIONS (cont’d)
Table 4-2 summarizes the results for each realization, based on a six-well development with an initial rate of 4.3 Mm3/d (150 MMscf/d).
Table 4-2: Ultimate Raw Recoverable Gas and Average Field Production Plateau by Realization Case
Ultimate Raw Average Recoverable Production Case Resources Plateau Period Number Case Type (Gm3) (Years) R1 Layered reservoir with sealing faults (chosen 26.9 13 case) R1.1 Layered reservoir with transmissible faults 28.7 15 R2 Layered reservoir with a stronger aquifer 26.1 14 R3 Layered reservoir with more sealing faults 22.7 10 (faulted case – 12 wells ) R3 Layered reservoir with more sealing faults 14.7 3 (faulted case – six wells) R4 Tank reservoir case 30.2 16 R5 Tank reservoir case, with thief zone of high 29.2 15 permeability R6 High GRV/GIIP case 31.4 16 R7 Low GRV/GIIP case 21.9 10 R8 Sweet fairway case 24.6 13 R9 Low permeability case 24.4 11 Note: GRV = gross rock volume GIIP = gas-initially-in-place
With all these realizations, the chosen development plan will have reasonable resource recoveries with the six-well development from the three well pads, except for the faulted case (R3). Analogue fields show that more wells than had originally been planned are sometimes needed because of the compartmentalization of the reservoir caused by subseismic faulting or stratigraphic variability. The R3 faulted realization doubles the number of fault blocks that are seen from seismic. Reasonable recoveries can be achieved by adding additional development wells.
4.2.8 HORIZONTAL WELLS
A horizontal well with a horizontal length of 500 to 600 m was evaluated in both the north and south areas of the field. However, model results indicated that a horizontal well would not add significant value, compared to the planned deviated wells.
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APPLICATION FOR APPROVAL OF THE DEVELOPMENT PLAN FOR NIGLINTGAK FIELD PROJECT DESCRIPTION ALTERNATIVES CONSIDERED
4.3.1 ASSESSMENT PROCESS
During the conceptual design phase, Shell considered several options for developing the Niglintgak surface facilities. Consistent with Shell’s sustainable development principles, the following criteria were used to evaluate and compare the identified development options:
• environmental impact • stakeholder impact • socio-economic impact • impact on safety • impact on reliability • impact on operability • impact on resource recovery • capital and operating cost • future expansion capabilities
The evaluation was completed in two phases:
1. an initial screening to eliminate the least attractive options
2. a more detailed evaluation of the remaining options to assess their relative strengths and weaknesses
In addition to these evaluations, studies were completed by the Mackenzie Gas Project to assess different options of using a common centralized gas conditioning facility for the Niglintgak, Taglu and Parsons Lake fields. These studies concluded that there was no significant technical, economic or environmental advantage to this option.
Table 4-3 briefly describes each of the 10 alternatives considered.
4.3.2 SCREENING ANALYSIS
Many of the Niglintgak development alternatives have common characteristics with the proposed development option. The first phase of evaluation eliminated eight of the development scenarios.
August 2004 Shell Canada Limited 4-11 NDPA-P1 Section 4.3 RESERVOIR DEPLETION ALTERNATIVES CONSIDERED
Table 4-3: Niglintgak Development Options
Chosen Development Option Description Barge option • Six wells drilled from three well pads, including: • two well pads on Niglintgak Island • one well pad on the east bank of the Kumak Channel • Gas from island well pads produced through above-ground flow lines and under the Kumak Channel to the barge-based processing facility • Processing at gas conditioning facilities located on a foundation in the Kumak Channel Alternative Development Differences From the Chosen Development Option Options Land-based option • Gas processing on land-based facilities on the east bank of the Kumak Channel, including a barge landing and access road to these facilities Island dehydration • Gas processing on land-based facilities on the east bank of the Kumak Channel • An additional dehydration facility on Niglintgak Island to remove water before the river crossing Taglu processing • No processing facilities at Niglintgak; all raw gas transported to Taglu for dehydration and compression Two river crossings • A land-based processing facility located on Niglintgak Island, with river crossings for both the raw gas and gathering pipeline Minimum drilling footprint • Five wells drilled from one Niglintgak Island-based drilling pad to reduce the land footprint • A land-based processing facility located on Niglintgak Island Niglintgak Island • Six wells drilled from three well pads, with all three well pads located on Niglintgak Island • A land-based processing facility located on Niglintgak Island Outside Kendall Island Bird • Six wells drilled from three well pads Sanctuary • Well pads and a land-based processing facility located outside the bird sanctuary on the west side of the Middle Channel Artificial island • An artificial island constructed near the south end of Niglintgak Island to support the well pads and processing facility East bank • Two wells drilled from one well pad on the east bank of the Kumak Island to access the southern part of the reservoir only
Table 4-4 summarizes the key weaknesses of the eliminated options.
4.3.3 DETAILED EVALUATION
Evaluation of the two remaining development alternatives, the barge option and land option, was continued with technical, socio-economic and environmental assessments being completed for both options. The EIS provides details on the assessment of both the proposed development and the land-based processing option.
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Table 4-4: Niglintgak Development Options Evaluation
Development Option Key Factors in Elimination Island dehydration Minimal technical, economic or environmental benefits, with significant additional capital expenditure. Taglu processing Capital savings and reduced footprint insufficient for the increased technical concerns with: • operation of the longer wet flow line • reduced resource recovery with remote compression • loss of Niglintgak area facility benefits to future area development Two river crossings Benefits of relocating the gas processing facility to Niglintgak Island are insufficient for the additional capital expenditures required. Minimum drilling footprint Benefits of a reduced footprint are insufficient for the significant reduction in resource recovery because of the technical limits of drilling high-lateral-reach to true-vertical-depth ratio wells (long- reach drilling) required to access all reservoir compartments. Niglintgak Island Benefits of a less complex gathering system are insufficient compared to the loss of resources and increased complexity associated with the long-reach drilling required. Outside Kendall Island Bird Sanctuary Benefits associated with being outside the bird sanctuary are insufficient to offset the reduced resource recovery because of long-reach drilling, increased capital expenditures and additional environmental concerns. Artificial island The reduction in the land footprint is insufficient to offset loss of resources because of long-reach drilling and environmental concerns. East bank The reduction in the land footprint and the savings in capital expenditures are insufficient to offset loss of resources because of decreased well penetrations of resource-bearing sands.
The major differences for the land-based option are:
• the gas conditioning facility would be located on the east bank of Kumak Channel on a combined piled and gravel foundation
• a new dredged barge landing site would be required on the east bank of Kumak Channel, with an access road from the landing site to the gas conditioning facility
4.3.3.1 Evaluation Results
Based on the evaluation work completed, the barge-based processing facility option was chosen over the land-based option, mainly because:
• the estimated capital cost of constructing the barge-based option is lower than for constructing the land-based option
• constructing the barge facilities off site in a more controlled environment reduces the risk of cost escalation and schedule delays
August 2004 Shell Canada Limited 4-13 NDPA-P1 Section 4.3 RESERVOIR DEPLETION ALTERNATIVES CONSIDERED
4.3.3.1 Evaluation Results (cont’d)
• transporting the gas conditioning facility through the Beaufort Sea will reduce the overall Mackenzie Gas Project transportation and logistics requirements on the Mackenzie River. Limitations and bottlenecks associated with river transport logistics have been identified as a concern for the project.
• commissioning and start-up efficiencies will be realized by constructing and pre-commissioning the gas conditioning facility in a controlled environment
• the footprint within the Kendall Island Bird Sanctuary is reduced
• the barge can be refloated, removed and salvaged at the end of its life
4.3.3.2 Concerns and Future Work
Two concerns identified for the current development plan compared to a land- based processing alternative were:
• the potential need for dredging in the Beaufort Sea and the Mackenzie River
• the potential that constructing the barge facilities off site might reduce local employment opportunities in the short term
The impact of dredging in the Beaufort Sea and Mackenzie Delta was assessed in the EIS. No significant environmental impacts resulting from the expected dredging requirements were identified. Field programs to collect additional data will be completed in summer 2004 and will enable the dredging requirements to be further refined and optimized.
The barge option will result in some construction employment opportunities leaving the region and, possibly, Canada. However, the socio-economic assessment completed for the Mackenzie Gas Project indicates that this impact will be minimal because the project will generate more construction jobs than can be filled by the northern workforce. Ongoing long-term operations jobs and business opportunities are similar for both options.
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APPLICATION FOR APPROVAL OF THE DEVELOPMENT PLAN FOR NIGLINTGAK FIELD PROJECT DESCRIPTION DEFERRED DEVELOPMENT
4.4.1 FUTURE POTENTIAL DEVELOPMENT
The Niglintgak field consists of multiple stacked sands, primarily filled with dry gas. However, the field also contains some sands filled with oil and associated gas.
Low to medium (18 to 32) American Petroleum Institute (API) gravity oil is contained in the following reservoir sands:
• I, J and K • L-low • M-low • O-P • Q and R
The L-low, M-low and O-P sands have associated gas caps.
These resources are not likely to be developed in the foreseeable future.
4.4.2 OTHER SIGNIFICANT DISCOVERY LICENCES
Shell has working interests in several SDLs that hold smaller volumes of natural gas. Although no specific plans have been formulated yet, these volumes might be tied into the Niglintgak development during the life of the project.
4.4.3 FUTURE RESOURCE EVALUATIONS
Some evaluation tests might be done in the north end of the field to clarify the uncertain nature of hydrocarbon fill in the H0 sand. The thin sands at the top of the O-P unit might contain non-associated gas. In addition, some potential remains for resource recovery from the Richards Sequence above the A sand. Before drilling begins, a decision will be made about evaluating these intervals and potentially incorporating them into the plan during the production phase.
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4.4.4 SPECIAL DRILLING SPACING UNITS FOR SUBSURFACE DRILLING LOCATIONS
The wells in the Niglintgak field will be drilled to reach the optimal subsurface targets of the reservoirs. The current subsurface targets are located mainly at high elevation points on the crest of the structure that will allow for maximum gas recovery mainly through delay in future water production. The final detailed well trajectories will be derived from ongoing seismic and geological analyses.
To locate the wells on the crest of the structure, the wells probably will not be drilled according to the gas spacing unit format of the Draft Spacing Unit Regulations. Therefore, this will necessitate a special drilling spacing unit application, as described in the draft regulations, before drilling begins.
Shell owns 100% of the subsurface rights of SDL 19. The planned bottomhole locations of the wells will be located on SDL 19, and will not encroach upon the one grid unit buffer zone between adjacent landowners that is contemplated in the draft regulations. Therefore, these locations will not affect other leaseholders’ subsurface rights.
More than one well per section per reservoir unit might be needed to provide efficient drainage of the gas in the case where more compartmentalization of the reservoirs than is currently interpreted becomes apparent. The proposed buffer zone is shown in Figure 4-4.
-135° 26´ -135° 24´ -135° 22´ -135° 20´ -135° 18´ -135° 16´ -135° 14´ -135° 12´
60° 21´ SDL 16 Chevron 50% EL 407 Mosbacher 25% Anadarko 100% Talisman 25% 60° 20´
Drilling Spacing 60° 19´ Buffer SDL 19 Zone of 1 Grid Unit Shell 100%
60° 18´
EL 394 Burlington 100% 60° 17´
60° 16´
Figure 4-4: Special Drilling Spacing
4-16 Shell Canada Limited August 2004 NDPA-P1 Section 4.5 RESERVOIR DEPLETION
APPLICATION FOR APPROVAL OF THE DEVELOPMENT PLAN FOR NIGLINTGAK FIELD PROJECT DESCRIPTION RESERVOIR MANAGEMENT PLAN
4.5.1 PURPOSE OF DATA COLLECTION
The reservoir management plan for Niglintgak includes systematically collecting well and reservoir data throughout the field’s life cycle. Data collection starts when the wells are drilled. Data is collected through logs, cores, multi-formation tests and production tests to establish reservoir parameters and initial reservoir conditions. Pressure, production rate and fluid type data is collected and analyzed from the wells as the field matures, with the goal of early recognition and mitigation of any problems that might affect resource recovery.
4.5.2 MONITORING PROGRAM
Reservoir monitoring is necessary to ensure that the Niglintgak development operates effectively to optimize gas recovery and production. Well and reservoir monitoring requires:
• a method of systematically gathering, evaluating and documenting reservoir performance
• a thorough knowledge of how the wells and reservoir are functioning, so that any production anomalies can be identified and corrected
4.5.2.1 Formation Evaluation
A formation evaluation plan, including wellbore logging and coring, will be conducted when the wells are drilled. This data will be used with other data collected as the field is produced, to analyze reservoir performance.
4.5.2.2 Monitoring Objectives
The main objectives of well and reservoir monitoring are to:
• optimize field development and gas recovery
• help evaluate GIIP and resources
• help predict, plan and optimize production
• characterize the reservoir’s properties
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4.5.2.2 Monitoring Objectives (cont’d)
• identify production and technical problems as early as possible, so that corrective and mitigative actions can be taken before significant production loss occurs
• provide a historical and current database for:
• pressure • production • gas • fluid samples
• provide well and reservoir information to help evaluate well and reservoir performance effectively
4.5.2.3 Monitoring Strategy
The monitoring strategy will be to obtain production and pressure data from different surface and subsurface locations. Reservoir monitoring data will be used to:
• update the resource estimates • monitor:
• well performance • reservoir performance • aquifer influx and support • water production • sand control
• obtain a history match to update the current reservoir 3-D model • manage ongoing well intervention workovers and infill drilling programs
4.5.2.4 Monitoring Criteria
Flexibility is a key component of the monitoring plan. The major criteria affecting monitoring requirements are the:
• maturity of the project or reservoir • complexity of the well or reservoir
Maturity of the Project or Reservoir
As the reservoir matures or progresses through different phases, the monitoring effort required will change, as follows:
• initial or early life – This period covers the first two years of production. It is essential that a good database be obtained during this period for:
• future evaluations • early recognition and mitigation of problems
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• mid-life – This period extends from early life performance to or beyond the point of water breakthrough. It might encompass one or more major integrated reviews or studies. During this period, major changes might be required to ensure that optimum recovery is achieved. Infill drilling might be considered to ensure that drainage is adequate for optimum recovery.
• late life – This period covers the latter stages of reservoir depletion (the last 10% of the ultimate recovery). During this period, key monitoring of small- scale changes will help ensure that all zones and areas are adequately drained. For example, the monitoring might result in:
• isolating a high-water-producing zone
• recommending additional recompletion in an area of poor sweep efficiency
Complexity of the Well or Reservoir
The amount of monitoring required is also a function of the well’s or reservoir’s complexity. For example, a multizone, heterogeneous reservoir or commingled well might require more or different types of monitoring than a homogeneous reservoir with a single zone completion. The level of monitoring will be determined as information about the reservoir becomes available.
4.5.3 IMPLEMENTATION PROCESS
Implementing the proposed reservoir management plan involves four steps:
1. Obtain data. 2. Analyze data. 3. Document results. 4. Address main uncertainties early.
4.5.3.1 Obtaining Data
The initial implementation effort will require the coordinated efforts of the subsurface team members (reservoir, petrophysics, geology and geophysics), production engineering and operations. Data collection activities need to take into account the full life cycle of the project or field.
Daily monitoring data will include:
• surface tubing head pressures • surface tubing head temperatures • gas and water production
Data will also be acquired from:
• bottomhole pressure surveys • well production testing • production logging
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4.5.3.2 Analyzing Data
Data collected will be used to:
• evaluate the performance of reservoir properties • identify production contributions from individual sands • address specific uncertainties in field or reservoir development scenarios
To evaluate fault transmissibility across field blocks, interference tests across the faults will be done, if conditions are suitable.
Key modern data monitoring techniques, such as downhole permanent pressure gauges, will be assessed to determine their merit and level of incorporation into the plan.
Reservoir models will be updated periodically to incorporate the new monitoring data.
4.5.3.3 Documenting Results
Niglintgak field review meetings will be held at timely intervals to update and discuss all monitoring data items, including:
• how individual wells are performing • how monitoring data has been used in performance analysis • whether any problems associated with monitoring have occurred
Documentation will be prepared showing Niglintgak’s development performance, including an assessment of the ongoing monitoring efforts.
4.5.3.4 Addressing Main Uncertainties Early
The main uncertainties that need to be addressed early in the project include:
• fault configurations, their locations and sealing nature • aquifer support and its impact on water breakthrough in wells • the reservoir’s nature and performance
4.5.4 FOUR-DIMENSIONAL SEISMIC
Four-dimensional (4-D) seismic is an evolving reservoir monitoring technology that compares pre-production seismic data with new seismic data acquired during field production. Subsurface reservoir fluid movements can be monitored by comparing the difference between the two data sets. Shell will continue to monitor and evaluate this technology and review its applicability to the Niglintgak field.
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APPLICATION FOR APPROVAL OF THE DEVELOPMENT PLAN FOR NIGLINTGAK FIELD PROJECT DESCRIPTION DEVELOPMENT PLAN KEY FEATURES
4.6.1 KEY FEATURES
Key features of the chosen development plan include:
• wells • well completions • reservoir evaluation programs • production forecasts and assumptions • well pad facilities and flow line • a gas conditioning facility • utilities and support systems
4.6.2 WELLS
The well drilling program is planned for three winter seasons, using two rigs, and includes:
• six to 12 production wells • one disposal well • three well pads:
• north pad (H-30) – wells P-3, P-4, P-4L, and P-11 will be located at this pad
• central pad (B-19) – well D-1 will be located at this pad
• south pad (E-58) – well P-2 and the disposal well will be located at this pad
4.6.3 WELL COMPLETIONS
Completions are designed with:
• an evaluation program in key zones • zonal water shutoff capabilities • downhole sand control • hydrate inhibition
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4.6.4 RESERVOIR EVALUATION PROGRAMS
The reservoir will be evaluated and monitored by:
• an initial formation evaluation logging and coring program in key sands • a well and reservoir monitoring plan
4.6.5 PRODUCTION FORECAST AND ASSUMPTIONS
The following production forecast is expected from the field:
• a nominal field raw gas production rate of 4.3 Mm3/d (150 MMscf/d), allocated as:
• 3.5 Mm3/d (121 MMscf/d) from the A sand reservoir (four wells)
• 0.6 Mm3/d (22 MMscf/d) from the D, E, and F-G sand reservoirs (one well with commingled production)
• 0.2 Mm3/d (7 MMscf/d) from the L, M and N sand reservoirs (one well with commingled production)
• a cumulative total gas recovery of 26.9 Gm3 (950 Bcf)
The forecast is based on the following assumptions:
• production forecasts, including positive skins of 5 to 10 • a tubing head abandonment pressure of 1,724 kPa • compression from start-up • an economic production life of about 25 years • a plateau rate for 13 to 14 years • 100% availability
4.6.6 WELL PAD FACILITIES AND FLOW LINES
The field production facilities comprise:
• three well pad facilities constructed on elevated pile foundations
• three above-ground flow lines to connect the well pads to the gas conditioning facility
• an HDD crossing under the Kumak Channel
• power cable, fuel gas and chemical lines, installed with the flow lines connecting the well pads and the gas conditioning facility
4-22 Shell Canada Limited August 2004 NDPA-P1 Section 4.6 RESERVOIR DEPLETION DEVELOPMENT PLAN KEY FEATURES
4.6.7 GAS CONDITIONING FACILITY
The gas conditioning facility will be constructed offsite and towed to site through the Beaufort Sea. The facility will be located on a permanent foundation in the Kumak Channel, and will have:
• three-phase inlet separation • mole sieve dehydration • propane refrigeration • water and sand handling facilities • two-staged compression built from start-up
4.6.8 UTILITIES AND SUPPORT SYSTEMS
The systems supporting the ongoing operation and maintenance of the facilities are:
• a helicopter landing pad • on-site accommodations • control rooms at the gas conditioning facility and Inuvik • control and communications systems • power generation, building heat, heat tracing and tankage • flares and safety systems • tankage and storage
August 2004 Shell Canada Limited 4-23 NDPA-P1 Section 5.1 DESIGN CRITERIA
APPLICATION FOR APPROVAL OF THE DEVELOPMENT PLAN FOR NIGLINTGAK FIELD PROJECT DESCRIPTION DESIGN PHILOSOPHY
5.1.1 DESIGN APPROACH
The Niglintgak field development will be designed, constructed and operated to meet or exceed all required regulatory requirements and Shell’s design standards, guidelines and project procedures. Shell’s project procedures incorporate the use of risk management principles and best practices for similar applications.
Shell is committed to the principles of sustainable development and will ensure that these principles are incorporated into all phases of the Niglintgak field development. Optimizing the technical design will include incorporating safety and integrity requirements and managing any negative biophysical or socio- economic impacts.
Key design considerations that have influenced the proposed Niglintgak development plan include:
• designing for a 25-year life, including abandonment and reclamation activities
• using proven technology and designs, wherever feasible, to maintain reliability and safety of operations
• designing for both attended and unattended operations, including remote troubleshooting
• designing facilities for concurrent drilling, construction and operational activities
• reducing surface disturbance within the Kendall Island Bird Sanctuary
• using existing disturbed sites, where feasible
• integrating Niglintgak activities with other parts of the Mackenzie Gas Project
• using prefabricated modules, where possible, to optimize field construction activities
• designing for cold weather operation and start-up
August 2004 Shell Canada Limited 5-1 NDPA-P1 Section 5.1 DESIGN CRITERIA DESIGN PHILOSOPHY
5.1.1 DESIGN APPROACH (cont’d)
• considering future expansion and third-party processing options in design
• designing for flood, ice and permafrost protection
5.1.2 CODES AND STANDARDS
The proposed Niglintgak development requires different sets of codes and regulations to be considered for different components of the production facilities design. The well pad facilities, flow lines and gas conditioning facility equipment will be designed using a similar set of codes, standards and regulations.
The gas conditioning facility substructure will be designed as a marine structure, meeting the requirements of several additional codes and regulations specific to its marine operation.
5.1.2.1 Legislation
The Niglintgak development will comply with all applicable regional, territorial and federal legislative requirements, which include the:
• Inuvialuit Final Agreement • Canada Oil and Gas Operations Act (COGOA) and Regulations • National Energy Board Act (NEBA) Rules, Regulations and Guidelines • Canada Petroleum Resources Act (CPRA) and Regulations • Canada Oil and Gas Land Regulations • Transport Canada Acts and Regulations • Department of Fisheries and Oceans Acts and Regulations • Canadian Environmental Protection Act • Canadian Environmental Assessment Act • Mackenzie Valley Resource Management Act and Regulations • Northwest Territories Waters Act and Regulations • Canada Labour Code • Government of the Northwest Territories Acts and Regulations • International Maritime Organization (IMO) Conventions
5.1.2.2 Design Codes and Standards
In addition to applicable corporate standards, the following might also be used:
• Canadian Standards Association (CSA) Codes and Standards • National Building Code of Canada • American Society of Testing Materials (ASTM) Standards • American National Standards Institute (ANSI) Standards • American Petroleum Institute (API) Recommended Practices • American Society of Mechanical Engineers (ASME) Codes and Standards • National Fire Protection Association (NFPA) Codes and Standards • Institute of Electrical and Electronic Engineers (IEEE) Standards
5-2 Shell Canada Limited August 2004 NDPA-P1 Section 5.1 DESIGN CRITERIA DESIGN PHILOSOPHY
• National Electrical Manufacturers Association (NEMA) Standards • Instrumentation Systems and Automation (ISA) Standards • Manufacturers Standardization Society (MSS) Codes and Standards • Appropriate Ship Classification Society Rules and Guides • Engineering Equipment and Materials Users Association (EEMUA) Technical Guides and Standards
August 2004 Shell Canada Limited 5-3 NDPA-P1 Section 5.2 DESIGN CRITERIA
APPLICATION FOR APPROVAL OF THE DEVELOPMENT PLAN FOR NIGLINTGAK FIELD PROJECT DESCRIPTION ENVIRONMENTAL CRITERIA
5.2.1 SCOPE
The environmental considerations that influence the design of the Niglintgak development include:
• meteorology • hydrology, including ice • hydrogeology, including permafrost • terrain • vegetation
Data used to determine the design criteria include:
• site-specific data from the 1970s and from recent field studies for geology and hydrology
• Canadian Atmospheric Environment records and climatic observations collected at surrounding centres, particularly from Tuktoyaktuk
• environmental field work obtained during the Mackenzie Gas Project’s environmental impact assessment field studies
See EIS Volume 3, Biophysical Baseline, for additional details on environmental baseline information.
5.2.2 SITE DESCRIPTION
The Niglintgak development will be located within the Mackenzie Delta at the junction of the Middle and Kumak channels. The Mackenzie Delta is the second largest delta in North America and the second largest delta located in an arctic or subarctic region. Active fluvial deposits composed of silt and sand, with wetlands, thermokarst lakes and ponds, characterize the area around the Niglintgak field. Subject to flooding and ice floes, the terrain is continually being modified by the environment.
The Niglintgak development will include three well pads, flow lines from well pads to the gas conditioning facility, and the gas conditioning facility itself. All three well pads will be located at previously drilled well locations and will incorporate as much of the previously disturbed area as feasible.
August 2004 Shell Canada Limited 5-5 NDPA-P1 Section 5.2 DESIGN CRITERIA ENVIRONMENTAL CRITERIA
5.2.2 SITE DESCRIPTION (cont’d)
The north and central pads will be located on Niglintgak Island, the south pad on the east bank of Kumak Channel and the gas conditioning facility in the Kumak Channel. The approximate coordinates of the well pads and gas conditioning facility are:
• north pad E486437 N7690183 • central pad E487944 N7687996 • south pad E490195 N7686685 • gas conditioning facility E489632 N7688086
DATUM: North American Datum (NAD27) Projection: Universal Transverse Mercator (UTM) Zone 8
The entire Niglintgak development is located within the Kendall Island Bird Sanctuary.
5.2.3 METEOROLOGY
5.2.3.1 Data
The Niglintgak meteorological design is based on meteorological data gathered from Tuktoyaktuk, which is located on the coast of the Beaufort Sea. This data is believed to be more representative of the Niglintgak climate than data from Inuvik, which is located farther inland. Although not as complete as the Inuvik database, the Tuktoyaktuk database has more than 20 years of data from 1971 to 2000. This data is adequate for engineering design purposes. However, it is sparse compared to data available in southern Canada.
Niglintgak’s high northern latitude defines its climate, which is arctic, with a moderating influence from its proximity to the Beaufort Sea. The short summer, with periods of 24-hour daylight, is offset by long cold winters with about two months of total darkness in winter.
Measured changes in Mackenzie Delta climate conditions have been documented, and future predictions modelled. The Niglintgak development is located within the Inuvialuit Settlement Region, for which a 1.5ºC increase in annual average temperature has been observed over the last 40 years. Total precipitation rates over the same 40 years have increased by 5.2 mm/a. Results of these trends and modelled future trends are documented in EIS Volume 5, Biophysical Impact Assessment, and will be incorporated into the Niglintgak development design.
5.2.3.2 Temperature
On the basis of the Tuktoyaktuk data, a yearly average daily mean temperature of -10.2ºC is expected at Niglintgak, with a wide seasonal variation. The yearly average daily minimum temperature expected is -13.9ºC (see Figure 5-1). The warmest month is normally July and the coldest is January.
5-6 Shell Canada Limited August 2004 NDPA-P1 Section 5.2 DESIGN CRITERIA ENVIRONMENTAL CRITERIA
Materials selection will be based on operating at the observed minimum temperature of -50oC. Heat tracing and insulation will be provided.
Daily maximum temperatures average -6.6ºC yearly. Daily maximum temperatures of 30ºC have been reported, but are rare, with an average of zero days per year above 30ºC, and 13.1 days above 20ºC. The design temperature daily maximum currently selected for the Niglintgak cooling system is 25ºC.
40
30
20
10
0
-10
-20
Temperature (°C) -30
-40
-50
-60 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Year Month Extreme Average Average Extreme Daily Mean Maximum Maximum Minimum Minimum
Figure 5-1: Expected Niglintgak Air Temperatures
5.2.3.3 Precipitation
The precipitation records for Tuktoyaktuk show a relatively dry climate with an average of less than 139.3 mm/a. The average yearly snow accumulation is 15 cm. Snow can occur every month of the year, with the smallest amounts in June, July and August. Although rare, extreme snow depths can approach 1 m.
Data indicates 33.5 days per year of poor visibility and 4.6 days per year of freezing rain and drizzle, both of which could affect aviation. The distribution of these observations indicates that up to six days per month could have reduced visibility, with May, June and July being the worst months.
Figure 5-2 shows the wind speed and relative duration according to its direction (known as the wind rose) for Tuktoyaktuk. The length of each directional band shows the percentage frequency from that direction. The width of the bands illustrates the wind speed distribution in that direction.
The Tuktoyaktuk wind rose indicates that wind distribution in two dominant directions can be expected at Niglintgak. Winds are a little stronger and more persistent from the east. However, winds from the northwest by west are also strong.
August 2004 Shell Canada Limited 5-7 NDPA-P1 Section 5.2 DESIGN CRITERIA ENVIRONMENTAL CRITERIA
Plant North
20°
NNW N NNE 20%
NW 15% NE 10% WNW ENE
W E 5%
WSW ESE
SW SE
SSW SSE S
Figure 5-2: Tuktoyaktuk Wind Rose
5.2.4 HYDROLOGY
The Niglintgak development is located within the lower Mackenzie Delta. It covers:
• part of the Mackenzie River Middle Channel and Kumak Channel • some smaller unnamed waterbodies • parts of Richards Island and Niglintgak Island
The two main river hydrology features in the Niglintgak area are the:
• Middle Channel (downstream of Niglintgak Island), which is about 2 km wide and shallow (less than 2 m deep)
• Kumak Channel, which is about 500 m wide, up to 25 m deep, with measured flows of 5,380 m3/s in June and 1,740 m3/s in September
5-8 Shell Canada Limited August 2004 NDPA-P1 Section 5.2 DESIGN CRITERIA ENVIRONMENTAL CRITERIA
A minor channel, Aklak Channel, is located immediately downstream of the Middle and Kumak channels. It is about 50 m wide and up to 6 m deep. In 1975, the flow rate was measured at 57 m3/s in June and 25 m3/s in September.
5.2.4.1 Flooding and Ice Conditions
The main hydrological concern at the Niglintgak site is flooding during spring breakup and late summer storms. On the basis of data from 1976, typical flood levels in the Niglintgak area are estimated to be about 2.3 to 2.5 m above mean sea level. With ground elevations of about 1.5 m above mean sea level, these peak water levels have resulted in inundation depths of 0.8 to 1.0 m. On the basis of maximum driftwood elevations surveyed in the area, the maximum expected inundation depth is about 1.6 m.
Maximum flood levels at Niglintgak are reached during spring breakup and are expected to be 3 m above mean sea level. Typically, spring flooding lasts about one week before receding. Project facilities will be elevated to protect them from flooding.
Ice on river channels can range from about 1.1 to 1.8 m thick. The variability depends mainly on the depth of water and the amount of insulating snow cover on the channel. Spring breakup studies in the Niglintgak area were completed between June 1 and 7 in 1975 and 1976 and more recently in 2003 and 2004. These studies indicate that the mode of breakup in the Niglintgak area is different from that in the upstream parts of the Mackenzie Delta.
Middle Channel, downstream of its junction with Kumak Channel, is shallow, and its ice cover melts before the ice cover upstream. The floe ice is then able to move unrestricted past Niglintgak through Middle Channel. At Kumak Channel, the breakup of ice cover downstream of Niglintgak is believed to be dominated by thermal degradation.
5.2.4.2 Design Impact
Transporting the gas conditioning facility through the delta might require some dredging because of the shallow water depth in some areas. To reduce dredging requirements and optimize route selection, additional data will be collected during the summer of 2004, including:
• bathymetric data on the topography of the Kumak Channel riverbed to determine the amount of dredging that will be required to prepare the barge set-down site and finalize the barge location
• water level, depth and bathymetric data for both the Mackenzie River and Beaufort Sea required for finalizing barge transportation plans
5.2.5 HYDROGEOLOGY
Niglintgak is located in an area of intermediate discontinuous permafrost. The active permafrost layer at Niglintgak ranges from 0.25 to 1.3 m thick. However,
August 2004 Shell Canada Limited 5-9 NDPA-P1 Section 5.2 DESIGN CRITERIA ENVIRONMENTAL CRITERIA
5.2.5 HYDROGEOLOGY (cont’d)
this layer is expected to become thinner farther away from the larger bodies of water and their associated areas of unfrozen permafrost (taliks). Taliks that extend completely through the permafrost (open taliks) are likely to occur beneath the larger lakes and river channels. Groundwater might be present within taliks.
5.2.6 TERRAIN
The Niglintgak gas field straddles the wide expanse of the Middle Channel of the Mackenzie River and Kumak Channel. This part of the Mackenzie Delta has distinctive fluvial characteristics, including:
• wetlands • active river channels • estuarine deposits
The landforms on the Mackenzie Delta are dynamic, thus are continually modified by their environment at different rates. For thousands of years, the shoreline and ice-rich landforms have responded to yearly, seasonal and daily climatic events, such as floods or storms.
Topographic information was obtained for the Niglintgak area through a LiDAR aerial survey completed in the summer of 2003. This survey provided detailed elevation information that was useful in evaluating different Niglintgak facility options.
The following key terrain features have affected Niglintgak development evaluations:
• The low, flat terrain found over most of Niglintgak Island and the nearby river banks requires both well pad and flow line designs to be further elevated and designed for flood and ice scour protection.
• The small island and associated depositional sandbar located on the east side of Kumak Channel provides additional protection for the grounded barge during spring breakup, and influenced the choice of the barge set-down location.
• The higher ground to the east of Kumak Channel is significantly above flood levels, making it a preferred location for the land-based processing facility alternative evaluated.
5.2.7 VEGETATION
The Niglintgak area is situated in the Tuktoyaktuk Coastal Plain Ecoregion of the Southern Arctic Ecozone, referred to as the Tundra Ecological zone. Abundant low shrubs, sedges and mosses characterize the tundra of the Tuktoyaktuk area.
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Vegetation in the Niglintgak area grows on a thin veneer of unfrozen organic or granular substrate overlying the permafrost. Vegetation types include:
• dwarf shrub heath • sedges • cotton grasses • sphagnum
August 2004 Shell Canada Limited 5-11 NDPA-P1 Section 5.3 DESIGN CRITERIA
APPLICATION FOR APPROVAL OF THE DEVELOPMENT PLAN FOR NIGLINTGAK FIELD PROJECT DESCRIPTION GEOTECHNICAL CRITERIA
5.3.1 SURFICIAL GEOLOGY AND GEOMORPHOLOGY
The Mackenzie Delta has undergone at least two periods of glaciation in the last 100,000 years. Before the glaciers formed, marine sediments were deposited, followed by sandy deposits of a large braided alluvial system.
Most of the landforms present are related to the last two major glacial events of the recent large Laurentide glaciation. The Laurentide ice approached the Inuvik area from the southeast and reached its maximum thickness 30,000 to 25,000 years ago.
Sediments deposited during this glacial event consisted of:
• sand and gravel, deposited in front of the advancing glacier • till, deposited as the glacier retreated or melted • sand and gravel, deposited by meltwater from the retreating glacier
5.3.1.1 Deposition Levels
The surficial geology of the area is dominated by nearly level deposits from the Mackenzie Delta with flat-topped hills, remnants of Pleistocene glacial deposits with elevations up to 30 m. Fluvial erosion and deposition is active, and mass movement related to slope or bank erosion is common. Ice-wedge polygons and pingos are common on low elevation landforms in the area.
5.3.1.2 Wetlands
The Niglintgak area is located within the Low Arctic Wetland Region where peatlands, or organic wetlands, are the dominant wetland type. These areas are saturated with water long enough to promote wetlands or aquatic processes. Indicators of wetlands include:
• poorly drained soils • hydrophytic vegetation • various kinds of biological activity that are adapted to a wet environment
5.3.1.3 Subsidence
Subsidence resulting from oil and gas withdrawal from reservoirs is the key geological environmental factor affecting the design criteria for the Niglintgak
August 2004 Shell Canada Limited 5-13 NDPA-P1 Section 5.3 DESIGN CRITERIA GEOTECHNICAL CRITERIA
5.3.1.3 Subsidence (cont’d)
development. Subsidence at the Niglintgak field will cover the production field area and occur gradually over the expected 25-year life of the reservoir. The subsidence will cause a dishing effect on the surface. The amount of subsidence will decrease uniformly with the distance from the centre of the reservoir.
Subsidence for the proposed Niglintgak development is expected to be about 45 cm at the centre of the reservoir, decreasing to about 10 cm at the gas conditioning facility location. Conceptual evaluations concluded that the differential settlement caused by subsidence:
• will have only a negligible effect on the infrastructure • will not affect the integrity of the structures, wells, pipeline or facilities • will not have a significant environmental impact
Where structures need to be elevated above the surface of the tundra to remain above high-water levels, the expected subsidence will be taken into account when determining the facility elevation.
The extent of subsidence monitoring required will be investigated as engineering design progresses.
5.3.1.4 Seismic Activity
Active faulting in the Niglintgak area terminated in the late Miocene (about five million years ago). No mapped faults reach the surface in the Niglintgak area. For further information on the area tectonism, see Section 2.1, Geological Description. Although no major faulting is currently occurring in the region, minor displacements in the bedrock might occur, which can induce detectable seismic activity. Since detailed record keeping started in 1954, no earthquake greater than four on the Richter scale has been recorded within 100 km of Niglintgak. This is barely strong enough to be felt at the epicentre and would not cause any damage to property.
The production of gas from the Niglintgak field may cause small-scale slip along subsurface faults. Typically, the primary trigger for production-induced seismic activity is injection of large volumes of water. Although a water disposal well is part of the proposed Niglintgak development, the volume of liquids to be injected is too small to have any significant impact.
Seismic hazard ratings across Canada are divided into seven seismic zones (zero to six) for both maximum ground acceleration and maximum horizontal ground velocity. Higher zoning represents increased seismic risk. The general Niglintgak area is considered to be within Seismic Zone 1 for both acceleration and velocity. The Niglintgak design will include consideration for earthquakes up to 0.08 g in the design.
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5.3.2 IMPACTS ON DESIGN
5.3.2.1 Gas Conditioning Facility
The Niglintgak gas conditioning facility will be located on a steel substructure that will be secured to the Kumak Channel riverbed. A technical feasibility evaluation was done to determine the most appropriate design and placement method, considering the geotechnical features at Niglintgak. This included a geotechnical analysis, which concluded that the riverbed could support the required load. Additional geotechnical data will be gathered to:
• confirm the final gas conditioning facility set-down location • provide design data for foundation design
5.3.2.2 Permafrost
Most of the Inuvialuit Settlement Region is classified as a continuous permafrost zone, with permafrost depths of up to 600 m. The active Mackenzie Delta, including the Niglintgak production area, has been classified as a zone of intermediate discontinuous permafrost because of the impact of waterbodies on permafrost formation.
Permafrost in the Niglintgak area primarily affects foundation and flow line design. Well pad foundations will be elevated for permafrost and flood protection, using an elevated pile design (see Section 7.5, Civil and Infrastructure Facilities, for additional details).
Options considered for flow line design required additional analysis of the permafrost impact and protection. A buried, insulated, warm flow line was one of the concepts evaluated in the early design work. Because of permafrost protection concerns and other criteria considerations, the buried option was replaced by the proposed elevated flow line design. The proposed flow lines will be placed on steel piles drilled and frozen in place.
August 2004 Shell Canada Limited 5-15 NDPA-P1 Section 5.4 DESIGN CRITERIA
APPLICATION FOR APPROVAL OF THE DEVELOPMENT PLAN FOR NIGLINTGAK FIELD PROJECT DESCRIPTION FUNCTIONAL CRITERIA
5.4.1 FLOW STREAMS AND DESIGN RATES
5.4.1.1 Flow Rates
The Niglintgak gas production profile has been developed to maximize resource recovery and economic return from the field. The estimated production rate used for the Niglintgak field is 4.3 Mm3/d (150 MMscf/d) raw gas with a flat life production period of 13 years, from 2010 to 2023. From 2024, production is expected to decline until a reservoir abandonment pressure of 1,724 kPa is reached.
The current production forecast is based on a daily production rate of 4.3 Mm3/d (150 MMscf/d). However, the final design flow rate of the production facilities might be up to 5.7 Mm3/d (200 MMscf/d) to accommodate scheduled maintenance, production downtime and additional gas sales opportunities. The environmental impact assessment of the processing facilities was based on a nominal design of 5.665 Mm3/d (200 MMscf/d), and demonstrated that no significant impacts are likely at this rate. Shell requests that the capacity of the processing facility only be limited by the assessment emissions levels.
5.4.1.2 Availability
During the conceptual design phase of the development, a reliability and maintenance (RAM) study was done to predict the availability of the Niglintgak facilities. The evaluation concluded that availability of about 78% would be achievable in the first year of operations, rising to 97% in the next three years of field life. Toward the end of field life, availability is expected to drop further to 93%, because of higher maintenance requirements.
Availability impacts, liquids shrinkage and fuel gas use reduce the daily natural gas production rate of 4.3 Mm3/d (150 MMscf/d) to an average annual sales gas production rate of about 3.7 Mm3/d (130 MMscf/d), at the Northwest Territories– Alberta boundary.
Table 5-1 summarizes the production forecast, including the impact of availability and sales gas production.
August 2004 Shell Canada Limited 5-17 NDPA-P1 Section 5.4 DESIGN CRITERIA FUNCTIONAL CRITERIA
Table 5-1: Niglintgak Gas Production Forecast
Average Annual Gas Rate (Mm3/d) Field Raw Gas North Alberta Condensate Year Production Boundary Sales Gas (m3/d) 2010 3.2 3.0 5.9 2011 4.0 3.7 7.4 2012 4.0 3.7 7.4 2013 4.0 3.7 7.2 2014 4.0 3.7 7.2 2015 4.0 3.7 7.1 2016 4.0 3.7 7.1 2017 4.0 3.7 7.1 2018 4.0 3.7 7.1 2019 4.0 3.7 7.1 2020 4.0 3.7 7.1 2021 4.0 3.7 7.1 2022 3.9 3.6 7.1 2023 3.9 3.6 7.1 2024 3.9 3.6 6.0 2025 3.4 3.2 0.0 2026 2.9 2.7 0.0 2027 2.4 2.2 0.0 2028 1.8 1.7 0.0 2029 1.3 1.2 0.0 2030 1.1 1.0 0.0 2031 0.8 0.7 0.0 2032 0.7 0.7 0.0 2033 0.7 0.6 0.0
5.4.1.3 Hydrocarbon Liquids Design Flow Rate
Well P-4L will produce a richer gas from the deep L, M and N reservoirs. All the other Niglintgak wells are expected to produce lean, sweet gas, with little to no hydrocarbon liquids, from the shallow A sand reservoirs. The overall blended gas composition is lean (98% methane) with the liquid-rich gas expected to make up less than 5% of the total flow from the field.
Any heavier components from the P-4L well can be absorbed into the leaner A sand gas. As a result, no liquid hydrocarbon dropout is expected in the Niglintgak gas conditioning facility under steady-state conditions. However, at the Inuvik gas conditioning facility, some liquid hydrocarbon will be extracted from the Niglintgak field product, at a low rate of about 6 m3/d (40 bbl/d).
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5.4.1.4 Produced Water Design Flow Rate
Water production is expected toward the middle of field life, when gradual water encroachment is expected in three or four of the wells. Water production timing and volumes will depend on the strength of aquifer support, the well positions, and the characteristics of the producing reservoir over time. Wells to the south of the field will be more susceptible to water production than those to the north. The production strategy will be to selectively isolate water-producing zones in the wells once water breakthrough is detected.
The conceptual design is currently based on an expected maximum water production rate of 32 m3/d (200 bbl/d). The facilities design has been evaluated with higher water flow rates to understand how the process could handle different subsurface performance or production from other fields. About 159 m3/d (1,000 bbl/d) of water could be handled in the flow lines, with some modifications required at the gas conditioning facility. Higher flow rates could require significant system redesign. This design will be optimized during the ongoing engineering evaluations.
5.4.1.5 Pressure
The initial flowing tubing head pressure for wells is expected to be about 9,650 kPa, except for the deep P-4L well, which is expected to be about 15,450 kPa.
The delivery pressure required for the gathering system at Niglintgak varies from 11,900 kPa in the summer to 12,600 kPa in the winter, as a result of the effect of ambient temperature on the gathering pipelines and equipment. To achieve these pressures at the Niglintgak facility outlet, gas compression will be required throughout the life of the field.
5.4.2 FLUID PROPERTIES
5.4.2.1 Hydrocarbon Composition
Niglintgak gas is lean (98% methane) and sweet, with less than 1% carbon dioxide and no hydrogen sulphide content expected (see Table 5-2). This blended gas composition is based on gas analyses completed during Niglintgak exploration in the 1970s and recombined in proportion to current well production forecasts.
5.4.2.2 Waxes, Asphaltenes and Emulsions
Waxes and asphaltenes are not expected to be of concern at Niglintgak. A wax appearance temperature study, done as part of the conceptual design, concluded that no wax is expected in the Niglintgak fluids.
The potential of the Niglintgak fluids to form emulsions with water, and any chemicals that might be required to inhibit corrosion or hydrates, will be studied during detailed design.
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Table 5-2: Niglintgak Expected Blended Gas Composition
Component Symbol Mole Fraction
Nitrogen N2 0.0012
Carbon dioxide CO2 0.0090
Hydrogen sulphide H2S 0.0000
Methane C1 0.9819
Ethane C2 0.0069
Propane C3 0.0002
Isobutane IC4 0.0002
Normal butane C4 0.0001
Isopentane IC5 0.0000
Normal pentane C5 0.0000
Hexane C6 0.0000
Toluene C6 0.0001
Normal heptane C7 0.0001
Normal octane C8 0.0001 Note: Composition assumes a ratio of 20:1 A sand to L, M, N sand gas.
5.4.2.3 Produced Water
Initially, only saturation water is expected to be produced from the Niglintgak wells. In time, free water production is expected as water encroaches in some wells. On the basis of well tests done in the 1970s, total dissolved solids (TDS) in the Niglintgak produced water are expected to be about 11,000 mg/L. These predicted TDS levels have been confirmed by:
• petrophysical analysis of the Niglintgak field • comparison with the regional water chemistry map • comparison with other anchor field produced water composition
5.4.2.4 Sand
The Niglintgak reservoir is in shallow, poorly consolidated rock, about 700 to 1,000 m below surface. Because of the reservoir’s geological setting, the development wells are expected to produce sand and fines. The baseline sand production rate for the Niglintgak facility design, using downhole sand control completions, is 0.8 to 3.2 kg/Mm3. Transient production rates from individual wells could be up to 16 kg/Mm3 for periods of up to six months.
The production strategy will be to use sand screens to selectively control or shut off sand-producing zones in the wellbore, to reduce the requirements for handling sand production in surface facilities.
5.4.2.5 Naturally Occurring Radioactive Material
No naturally occurring radioactive material (NORM) is expected in the Niglintgak fluids, based on the expected conditions of the Niglintgak field.
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5.4.3 PRODUCT SPECIFICATIONS
The Niglintgak gas conditioning facilities will process Niglintgak gas to meet the gathering pipeline requirements for pressure, temperature, water content and composition (see Table 5-3).
Table 5-3: Gathering Pipeline Specifications
Parameter Value Maximum water content (vapour) 6.0 mg/m3 Maximum water content (NGLs) 10 ppmw Hydrogen sulphide 3 mg/m3 Maximum total sulphur 0.5% by weight Maximum oxygen 0.4% by volume Delivery pressure 12,600 kPa Delivery inlet temperature -1°C
August 2004 Shell Canada Limited 5-21 NDPA-P1 Section 6.1 DRILLING AND COMPLETIONS
APPLICATION FOR APPROVAL OF THE DEVELOPMENT PLAN FOR NIGLINTGAK FIELD PROJECT DESCRIPTION DEVELOPMENT DRILLING
6.1.1 EXPLORATION AND DELINEATION DRILLING
The H-30 discovery well for the Niglintgak field was drilled in 1973. The discovery well and four additional wells drilled to delineate the field are summarized in Table 6-1. Drilling and testing information from these wells has been used in preparing well plans for the proposed development.
The C-21 and C-58 wells were abandoned immediately after drilling and evaluation. The remaining four wells were tested and suspended, then abandoned in 1996. There are no plans to use any of the abandoned wells. The wellbores have been evaluated and there is currently no economic benefit in re-entering these wells.
Table 6-1: Summary of Niglintgak Exploration and Delineation Wells
Rig Release Total Depth Directional Well Name Spud Date Date (mKB) Profile Shell Niglintgak (H-30) October 1972 April 1973 2,382.6 Vertical Chevron SOBC Upluk (C-21) February 1973 April 1973 1,637.1 Vertical Shell Kumak (C-58) April 1973 October 1973 3,530.2 Vertical Shell Niglintgak (M-19) June 1974 January 1975 4,025.2 Vertical Shell Niglintgak (B-19) October 1975 February 1976 3,144.0 Directional Shell Kumak (E-58) February 1977 June 1977 1,554.5 Directional
6.1.2 INITIAL DEVELOPMENT DRILLING REQUIREMENTS
The chosen development plan proposes drilling:
• six wells for gas production:
• four from a pad near Shell Niglintgak H-30 (north well pad) • one from a pad near Shell Niglintgak B-19 (central well pad) • one from a pad near Shell Kumak E-58 (south well pad)
• one well for water and production waste disposal, at E-58 or at a location convenient to the Niglintgak processing facility
The number and size of pads is designed to:
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6.1.2 INITIAL DEVELOPMENT DRILLING REQUIREMENTS (cont’d)
• minimize the development footprint • optimize gas recovery
Drilling sites on or adjacent to existing disturbances were selected to reduce the cumulative impact and land use. The minimum number of required sites is determined by the shallow gas reservoir depth and by reservoir compartmentalization caused by faulting. Where practical, the planned wellbores are oriented to avoid crossing major faults.
Figure 6-1 shows drilling pad locations and a plan view of the proposed wells.
–135° 25´ W –135° 15´ W
69° 20´ N
Shell Significant Discovery Licence Boundary
Kendall Island Bird Sanctuary Boundary
69° 16´ N
Figure 6-1: Drilling Pad Locations and Plan View of Wells
The number of wells required, the phasing of the wells and the completion designs used might be revised, based on test results of the initial wells. Up to 12 production wells might be required to optimize gas recovery.
Drilling will take place over three winters, beginning in January 2007. Some completions and testing might be done during each of the two intervening
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summers. The operating window for winter drilling is from about January 15 to April 15 each year.
The sequence of the wells will be influenced by the information obtained from the drilling and evaluation of each well. Improved understanding of the geology and reservoir will help to optimize placing and completing subsequent wells. Other factors considered in determining well order will be:
• drilling complexity • efficient use of each drilling season • rig-moving costs
6.1.3 DIRECTIONAL DRILLING DESIGN
All of the production wells will be directionally drilled to reach reservoir targets from the restricted surface access. In most cases, the wellbores will kick off from vertical below the surface casing and build to maximum inclination in the first intermediate hole section. The planned maximum inclination ranges from less than 40° to up to 75°.
Table 6-2 shows the preliminary directional drilling information, such as:
• maximum inclination • azimuths • total displacement • total measured depth (MD) • true vertical depth (TVD)
Table 6-2: Niglintgak Preliminary Drilling Schedule and Directional Information
Maximum Total Total Depth Drilling Inclination Azimuth Displacement Well Type Target Zones Schedule (degrees) (degrees) (m) MD TVD North Pad (H-30) P- 4L Production L, M and N Q1, 2007 45 130 to 150 1,275 2,550 2,100 P- 11 Production D, E and F-G Q1, 2008 40 340 to 360 500 1,400 1,250 P- 3 Production A1 to A2 Q1, 2008 35 160 to 170 350 1,050 950 P- 4 Production A1 to A2 Q1, 2009 75 130 to 150 1,200 1,700 850 Central Pad (B-19) D- 1 Production A1 to A6 Q1, 2008 48 300 to 360 500 1,200 1,000 South Pad (E-58) Disposal Injection D, E and F-G Q1, 2007 TBD* TBD* TBD* TBD* 1,500 P- 2 Production A1 to A6 Q1, 2009 72 230 to 250 1,380 1,900 1,020 Note: TBD – to be determined. * The intervals and area suitable for injection have been identified and options to optimize the location are being studied.
These trajectories might be revised as the targets are optimized with detailed well planning.
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6.1.4 CASING PROGRAM
6.1.4.1 Design Considerations
The hole sizes and depth for each interval were selected considering:
• the protection of the permafrost interval from thaw during drilling and production operations
• formation pressures and drilling safety
• the minimum wellbore diameter to achieve desired production rates
6.1.4.2 Regulations and Standards
The hole sizes and casing programs for the production wells will be standardized, where practical, to minimize the sizes and grades of casing required for the development program. Casing design will comply with the requirements of the Canadian Oil and Gas Drilling Regulations, Section 64.
6.1.4.3 Conductor
A hole will be augured to about 20 m below ground level to accommodate an insulated and refrigerated conductor with a 508.0 mm inner casing. This casing will:
• protect the surface permafrost from thaw during drilling and production operations
• provide a base for the diverter blowout preventer (BOP) used to drill the hole for surface casing
6.1.4.4 Surface Hole and Casing
A 444.5 mm hole will be drilled to about 200 m through the permafrost section. The 339.7 mm surface casing will be run and cemented to surface using low- thermal-conductivity permafrost cement. This casing will:
• isolate and protect the permafrost interval
• provide a base for BOP equipment to safely drill the intermediate hole section
6.1.4.5 Intermediate Hole – Section One and Casing
A 311.2 mm hole will be drilled to a TVD of about 600 m to set casing above the Lower Richards sand. The hole will kick off just below the surface casing in most cases and be built to the maximum inclination in this section.
The 244.5 mm casing will be run with an external casing packer and port collar. The packer will be positioned in the bottom joint of the 339.7 mm surface casing.
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Insulated centralizers will be run on the casing above the packer. After the casing is cemented, the packer will be set and the annulus will be displaced to gelled diesel through the port collar. A liner and tieback might be used instead of the port collar.
This casing is required to provide a secure base for BOP equipment to safely drill through the higher pressures expected in the Lower Richards sand at about 650 m TVD.
6.1.4.6 Intermediate Hole – Section Two and Liner
A 222.2 mm hole will be drilled and under-reamed to 235 mm. This hole will be drilled to the top of the A sand for the A sand producers, and to a greater depth for wells P-4L and P-11. A 193.7 mm liner will be run and cemented the full length of the hole.
6.1.4.7 Main Hole – Completion and Casing
The main hole will be drilled to a diameter of 158.8 mm to accommodate expandable sand screens and packers for the A sand wells. The hole will be under-reamed to 165 mm in the deeper wells (P-4L and P-11) to accommodate a 139.7 mm special clearance liner. The expandable screens and packers will be run and set in the A sand wells. The 139.7 mm liner will be run and cemented for the full length in the two deeper wells.
6.1.5 DRILLING FLUIDS
A water-based, potassium-chloride-polymer drilling fluid system, similar to that used for drilling the exploration and delineation wells, is planned for the development wells. Barite will be added to provide the density necessary to balance formation pressures with a sufficient safety margin.
The addition of potassium chloride will inhibit clay swelling and depress the freezing point of the mud. The drilling fluid will be cooled to reduce permafrost thaw.
The drilling fluid system was chosen because it has been proven successful for drilling in the Mackenzie Delta. Other water-based drilling fluids will be evaluated, and might be selected based on their ability to:
• maximize drilling efficiency, maintain borehole stability and provide proper hole cleaning
• reduce formation damage to potential production intervals
• meet environmental and safety requirements, including drilling cuttings disposal
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6.1.5 DRILLING FLUIDS (cont’d)
Oil-based drilling fluids could provide drilling efficiency. However, their use is not planned at present because of additional logistics requirements and their potential to damage the producing formations.
6.1.6 DRILLING CUTTINGS DISPOSAL
6.1.6.1 Disposal Plan
The main criteria considered in selecting the method for disposing of drilling cuttings and fluids for the Niglintgak field development wells were:
• technical feasibility • environmental impact • capital and operating costs
Disposing of drilling cuttings and fluids in an engineered remote sump with freezeback containment was selected. This method is consistent with the current disposal method used for all of the exploration and delineation wells drilled in the Mackenzie Delta.
The drilling cuttings will be stored on site in containers and transported via ice roads to the remote sump for disposal.
A remote sump site out of the floodplain of the Mackenzie River has been selected as suitable for drilling sumps for the Niglintgak field development. The site has been selected for long-term containment. The proposed location of the sump is about 13 km southeast of Camp Farewell (see Figure 6-2).
A sump of about 30 m x 40 m x 5 m will be constructed on the site each winter. The sump will accommodate:
• the expected volume of 1,500 m3 required for disposal each year
• a 100% contingency volume with sufficient freeboard to ensure that all cuttings are buried at least 1 m below the active layer
The sump will be capped each year before spring breakup. The total area required for sumps for the planned three-winter drilling program is 60 m x 210 m, including a 15 m perimeter working area around each sump.
The sumps will be designed, constructed and operated according to the best practices for construction, capping and monitoring. These practices, under ongoing study by industry and government, are evolving.
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Niglintgak Taglu SDL SDL
Camp Farewell
Sump Location Swimming Point
Tununuk Lucas Point Point
Winter Roads
Figure 6-2: Sump Location Map
6.1.6.2 Disposal Alternatives Considered
Alternatives considered for disposal of drilling cuttings and fluids in the Mackenzie Delta included:
• disposal to sumps at the Niglintgak drill sites or inside the Kendall Island Bird Sanctuary. This option was rejected because of land use restrictions.
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6.1.6.2 Disposal Alternatives Considered (cont’d)
• subsurface cuttings disposal at Niglintgak. This option was rejected because:
• the formations above the gas reservoir zones at Niglintgak are not suitable for disposal, as they contain gas
• a dedicated deep disposal well would be required, but the cost would be prohibitive relative to other options, given the small volume of cuttings expected to be generated from the Niglintgak development drilling program
• disposal into a third-party subsurface injection facility. This option is not currently feasible because:
• no third-party injection facility for cuttings currently exists in the Mackenzie Delta
• no planned facility has been identified that could confirm availability of capacity for the volume of cuttings from Niglintgak
• transportation to and disposal in an Alberta or BC landfill. This option would be significantly less costly than developing and using a cuttings injection facility at Niglintgak. However, transporting the cuttings out of the North is not desirable because it does not deal with the waste locally.
These options for disposing of drilling cuttings and fluids will continue to be pursued during ongoing drilling program design.
6.1.7 DRILLING CONSIDERATIONS – SELECTED OPTIONS AND ALTERNATIVES
6.1.7.1 Access for Drilling Operations
The Niglintgak development site is located within the Kendall Island Bird Sanctuary and is adjacent to the navigable Middle Channel of the Mackenzie River. Permanent roads were ruled out to minimize land use in the bird sanctuary.
Options for access that will be used are:
• winter ice roads on the river channel and over the tundra • barge and helicopter in summer • helicopter during shoulder seasons (spring breakup and fall freeze-up)
Camp Farewell, located about 15 km upstream on Middle Channel and operated by Shell, will be used as a staging point and operations base.
6.1.7.2 Drilling Site Selection
The shallow reservoir depth and compartmentalization require more than one drilling site for optimum gas recovery. Three drilling sites located adjacent to
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existing exploration and delineation well sites were chosen after considering numerous alternatives. The chosen configuration will:
• enable access to reservoir compartments, to optimize gas recovery • enable drilling of future infill wells, if required • reduce new land disturbance by using existing sites
6.1.7.3 Drilling Pad Design and Layout
An elevated pad for drilling and well production is considered necessary to:
• protect the permafrost from thaw • protect wells and production facilities from flooding • enable well intervention and production operations to be done in any season
The selected drilling pad layout consists of steel decking supported by steel piles. The pad will have enough area to support the drilling rig and key components, as well as equipment for well intervention during production operations. The steel pile supported area will be supplemented by an ice pad area to accommodate support equipment, equipment storage and the drilling camp during winter drilling operations (see Figure 6-3).
Analysis of potential permafrost thaw during production operations indicates that an interwell spacing of 10 to 15 m is required. The layout of the drilling pad will be finalized with detailed well and well production facility design. Requirements for drilling and well production facilities will be integrated.
Several alternatives were considered for the drilling and well production facility pads. For details of the alternatives considered, see Section 7.5, Civil and Infrastructure Facilities.
6.1.7.4 Drilling Schedule and Alternatives
The shallow well depth and estimated time required to drill the wells planned for the Niglintgak development make winter-only drilling a feasible option. This option is preferred because it will:
• reduce land disturbance within the Kendall Island Bird Sanctuary
• reduce activity during critical wildlife times in summer
• permit transporting drilling rigs and support equipment over ice roads, including equipment to drill a relief well, if necessary
• enable temporary ice pads to be used for drilling operations, to reduce the elevated pad area required
• facilitate transporting drilling cuttings and fluids to offsite disposal
This option requires high-cost ice roads to be built each year and has low annual utilization of equipment and personnel, but it reduces the permanent land use area within the Kendall Island Bird Sanctuary.
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Figure 6-3: Artist’s Impression of Winter Drill Site
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6.1.8 PERMAFROST PROTECTION
6.1.8.1 Well Design and Well Spacing
Permafrost thaw, caused by heat from the circulation of warm drilling fluids or from the production of warm reservoir fluids, can:
• cause local surface subsidence • place high stresses and strains on the casing
To assess the impact of permafrost thaw on production well design for the Niglintgak and other anchor fields, Shell, Imperial Oil Resources Limited and ConocoPhillips commissioned a permafrost study from C-FER Technologies and EBA Engineering. As part of the study, permafrost thaw and casing stress and strain analyses were modelled for the three fields. The cases considered were:
• Case 1 – an uninsulated wellbore • Case 2 – an insulated wellbore • Case 3 – a refrigerated frozen permafrost cap at surface • Case 4 – a multiwell case, to determine well spacing requirements
The analysis of the insulated wellbore case (Case 2) provided acceptable permafrost thaw and casing stress levels for the Niglintgak development wells. The wellbore was insulated by placing gelled diesel in the annulus between the 339.7 mm surface casing and the 244.5 mm intermediate casing.
The multiwell case (Case 4) evaluated an interwell spacing of 10 m. In this case, the permafrost thaw bulbs coalesced after 20 years, indicating that an interwell spacing of 15 m might be more desirable. Further work will be done to determine the optimal interwell spacing when the well configurations and well pad facility designs are more fully developed.
The impact of refreezing thawed permafrost (freezeback) was not analyzed in the permafrost study. However, based on tests conducted at the Alaskan North Slope, the maximum collapse force expected to result from freezeback is 9,000 kPa at 250 m. The collapse resistance of the surface casing planned for the Niglintgak wells is more than double this value. Consequently, the Niglintgak casing design is believed to be more than adequate to withstand freezeback.
6.1.9 POTENTIAL DRILLING HAZARDS
Drilling experience from exploration and delineation wells drilled at Niglintgak provides an excellent understanding of well construction hazards in the area. Potential drilling hazards have been identified and mitigative strategies devised. The only potential problems that could present public safety or environmental concerns are:
• gas cutting and kicks • formation pressure gradient and abnormal pressure
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6.1.9 POTENTIAL DRILLING HAZARDS (cont’d)
Other problems identified that could increase the time required to complete the drilling operations, but would not present safety or environmental concerns, are:
• borehole stability • permafrost – borehole enlargement • circulation and mud losses • differential sticking • cementing and gas migration
6.1.9.1 Gas Cutting and Kicks
Early exploration and delineation wells at Niglintgak experienced several events of mud gas cutting and kicks. These problems were exacerbated by the limitations of the mud system and solids control equipment on the heliportable rigs used to drill the wells.
Data from the delineation wells provides a pressure profile to enable casing points and mud densities to be selected that will minimize gas kick problems. Using the most appropriate mud rheology and drilling practices will also help eliminate gas kicks.
The presence of gas hydrates, their dissolution, and gas release during trips might have been responsible for some of the gas kicks on the delineation wells. Using a refrigerated mud system when drilling through potential gas-hydrate intervals will prevent the dissolution of any gas hydrates encountered and avoid this potential problem on the development wells.
6.1.9.2 Formation Pressure Gradient and Abnormal Pressure
The development area has a hydropressure gradient to a depth of about 2,100 TVD mSS, and a mixed zone of hydrocarbons and geopressurized zones from 2,100 to 3,200 TVD mSS. A geopressurized gradient exists below 3,200 TVD mSS, but no development wells are planned below 2,200 TVD mSS.
The Lower Richards sand at the H-30 well, at 660 TVD mSS, has a pressure gradient of up to 16.4 kPa/m. Drilling plans will incorporate appropriate casing points and adequate mud densities to control the pressures encountered on the development wells.
6.1.9.3 Borehole Stability
Exploration and delineation wells were drilled using a heliportable rig with mud circulation and solids control systems that had limitations. As a result, there were several borehole stability problems on these wells.
For the current development, borehole stability problems will be reduced by:
• using a suitably equipped drilling rig with adequate mud pumps and solids control systems to facilitate hole cleaning and conditioning
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• controlling the drilling fluid properties to ensure that adequate clay inhibition is achieved
• reducing the amount of time that each hole section is exposed to the drilling fluid
6.1.9.4 Permafrost – Borehole Enlargement
The development area is underlain by permafrost ranging from 90 to 250 TVD mSS. Drilling with warm fluid might cause the permafrost to thaw, which would enlarge the wellbore. To prevent permafrost thaw, the drilling fluid will be cooled.
6.1.9.5 Circulation and Mud Losses
Only minor mud losses were experienced during the drilling of exploration and delineation wells at Niglintgak. The mud losses were remedied by:
• reducing mud density • adding minor amounts of fibrous materials
6.1.9.6 Differential Sticking
In exploration and delineation wells, high mud densities required to control formation pressures led to some pipe sticking because of differential pressure between the borehole and the formation. In development wells, differential sticking will be reduced or eliminated by:
• selecting casing points that minimize the difference between the pressure exerted by the drilling fluid column and the pressure of the formations penetrated
• selecting drilling fluids with appropriate properties
• using drilling practices that limit time intervals when the drill string is static
6.1.9.7 Cementing and Gas Migration
Nonproductive time during the drilling of exploration and delineation wells at Niglintgak was frequently caused by cementing problems and gas migrating up the cemented casing annuli.
Some recent exploration wells in the area used modern permafrost cement blends that generate low heat when they set. These wells had significantly reduced waiting times for cement setting. Similar cement blends will be used for the permafrost interval in development wells at Niglintgak to prevent excessive waiting times for cement setting.
Gas migration problems will be reduced by:
• using modern cement blends that resist gas migration
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6.1.9.7 Cementing and Gas Migration (cont’d)
• paying special attention to hole conditioning, adequate centralization and pumping rates
6.1.10 WELL CONTROL
During the drilling of exploration and delineation wells at Niglintgak, data was gathered on the:
• formation fracture-gradient • drilling fluid density required to control formation pressures
This data has been analyzed to select casing points and mud densities that will provide safe pressure operating windows for development wells. Well control will be ensured by using:
• drilling and tripping practices that will prevent gas kicks
• BOP configurations that comply with Canada Oil and Gas Drilling Regulations, including using a:
• diverter while drilling the surface hole
• 346 mm casing bowl and BOP assembly, with a minimum of two rams and an annular BOP, while drilling the remainder of the well
• crew training, including frequent BOP well control drills, as an integral part of drilling operations
• equipment and procedures to make the loss of well control very unlikely even if a kick does occur
Contingency plans will be developed. Personnel and equipment will be available to respond to the loss of well control by capping the well at surface or drilling a relief well, if necessary.
6.1.11 DRILLING EQUIPMENT
To drill the six gas production wells and one disposal well for the Niglintgak development, two conventional land-based drilling rigs over three winters will be used, as follows:
• one rig will drill the disposal well, then the four production wells to be drilled from H-30 (north pad). The wells will be completed using the drilling rig. The multizone completions of wells P-4L and P-11 will be done during the summer of the second and third years.
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• the second drilling rig will drill and complete wells D-1 and P-2 in the second and third winter drilling seasons
The specialized equipment required to equip these rigs for arctic drilling will be built in Alberta and moved to the drilling sites. One rig will remain at the north pad (H-30) for the duration of the drilling program. The second rig will be mobilized to and demobilized from Alberta each year. The specialized arctic drilling equipment will be moved to and from Camp Farewell each year. Optimization of the drilling program is ongoing with respect to well sequence and phasing.
6.1.12 DRILLING AND COMPLETIONS EXECUTION
6.1.12.1 Drilling Pads and Ice Roads
The drilling pads will be built during the winter following development approval. The steel decking and piles for the pads, and critical equipment required for ice road construction and early pad construction operations, will be transported by barge and staged at Camp Farewell during the preceding barge season.
A supplemental ice pad area will be built adjacent to each drilling site to accommodate the drilling camp and equipment storage.
A temporary airstrip will be built on the river channel adjacent to the drilling site to support drilling operations.
6.1.12.2 Well Drilling and Completions
Equipment and materials needed for drilling and well completion to be done in the ensuing year will be transported to Camp Farewell by barge each summer. Equipment and materials not staged at Camp Farewell will be transported to Inuvik via the Dempster Highway, and then to the drilling site over ice roads.
The drilling rig, support equipment and camp will be transported by truck to the well pad as soon as ice road conditions permit. Drilling and completion operations throughout the winter will be supported by truck over the ice roads.
At the end of each winter drilling program, the drilling equipment and camp will be demobilized by truck to Camp Farewell or other areas.
Summer completion operations will use Camp Farewell as a support base and camp. Supplies and completion equipment will be stockpiled on the steel well pad before spring breakup of the ice roads. Equipment, materials and personnel needed for summer completion operations will be transported by barge and helicopter.
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6.1.12.3 Drilling Personnel Transport
Personnel from outside the Inuvik area will be transported to Inuvik by commercial airline or charter aircraft, coordinated by the Mackenzie Gas Project. Personnel will then be transported to Camp Farewell or the well site by:
• fixed-wing aircraft or helicopter • ground transportation via ice roads from Inuvik
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APPLICATION FOR APPROVAL OF THE DEVELOPMENT PLAN FOR NIGLINTGAK FIELD PROJECT DESCRIPTION COMPLETIONS
6.2.1 DESIGN REQUIREMENTS
6.2.1.1 Production Reliability and Rigless Intervention
Seasonal access conditions require that well completion designs for the planned development wells provide a high level of production reliability. The completions will accommodate intervention using wireline and coiled tubing to isolate or segregate individual sands for testing or zonal isolation.
6.2.1.2 Subsurface Safety Valves
Subsurface safety valves (SSSVs) and packers will be required to comply with regulations and to enhance the safety of production operations. Using tubing retrievable SSSVs is planned because of their reduced flow restriction compared to wireline retrievable SSSVs.
6.2.1.3 Hydrate Inhibition
Downhole hydrate inhibition is expected to be required during start-up for all wells and continuously for the A sand gas production wells. The wells will be equipped with downhole chemical injection lines and valves to facilitate the injection of hydrate inhibitors. Corrosion inhibitor could also be injected through these lines and valves, if required.
6.2.1.4 Sand Control
The Reindeer A and D sand zones are poorly consolidated and prone to sand production under certain conditions. Sand was produced on several of the drill stem tests (DSTs) and production tests (PTs) that were conducted on the exploration and delineation wells.
The cost and risk of handling sand production and the high cost of sand disposal at this remote site have dictated a conservative approach to sand control for the initial development. Planned completion designs for wells producing from A and D sands use screens for sand retention with packers for zonal isolation, where required.
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6.2.1.5 Water Production
Water production is expected at some point in the production life of all planned production wells, except those completed in A1 and A2 sands in the northwest area of the field.
An analysis of reservoir performance, as predicted by the 3-D dynamic reservoir model, indicates that selective shut-off of zones or sand layers producing water will result in improving ultimate gas recovery. The downhole shut-off of water- producing zones reduces the risk of sand production, and will also reduce surface water handling and disposal costs.
The selected completion designs provide for zonal isolation to shut off water production in all wells that might produce water.
6.2.1.6 Commingled Production
The gas production wells are designed to produce with commingled flow, either from two or more A sand layers or, in the case of deeper wells P-11 and P-4L, from several individual sands. Commingled production is required to deplete the multiple reservoir layers with a minimum number of wells.
6.2.1.7 Stimulation
Good to high permeability in the reservoir sands should provide satisfactory production deliverability from all zones to be completed, if formation damage is minimized by good drilling and completion practices. Stimulation treatments are not expected to be required and are not planned.
6.2.2 COMPLETION DESIGNS
Four distinct structural blocks with multiple reservoir units have specific characteristics requiring different well completion designs. The four blocks are:
• A sand – southeast block B-19 and E-58 • A sand – northwest block H-30 and M-19 • D, E and F-G sands • L, M and N sands
6.2.2.1 A Sand – Southeast Block B-19 and E-58
The gas in southeast fault block B-19 and E-58 is contained in four to six sand layers over a gross thickness of up to 160 m. The reservoir sand is high quality, well sorted and poorly consolidated, with estimated permeability ranging from 200 to over 1,000 mD. These sands are structurally lower than the northwest portion of the field, and there is a potential for water influx at some point in the wells’ production life. A large portion of this block is situated under the river channel, requiring wells with a higher inclination to position the wellbores for optimum gas recovery. Design production rates for the wells in this block are 0.700 to 1.400 Mm3/d (25 to 50 MMscf/d).
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The completion design for wells in this block will incorporate open hole completions with sand screens and external packers set in the shaly intervals between the individual sand layers. This completion will provide sand production abatement and the ability to isolate individual sands to control water production. The planned production tubing size is 139.7 mm and 177.8 mm.
Figure 6-4 shows the preliminary completion design for the southeast block A sand.
6.2.2.2 A Sand – Northwest Block H-30 and M-19
The gas in northwest block H-30 and M-19 is contained in two sand layers with a gross thickness of about 40 to 50 m. The reservoir sand is good quality, well sorted and poorly consolidated, with estimated average permeability ranging from 100 to 350 mD. The sands in this block are structurally high and water production is not expected. Design production rates for the wells in this block are 0.600 to 1.000 Mm3/d (20 to 35 MMscf/d).
The completion design for wells in this block will incorporate open hole completions with sand screens. An external packer will be set in the shaly interval between the individual sand layers, to limit annulus channeling and improve sand control reliability. This completion will retain sand production and provide the ability to isolate individual sands for evaluation and testing. The planned production tubing size is 139.7 mm.
The preliminary completion design from these wells will be similar to that in the southeast block A sand.
6.2.2.3 D, E and F-G Sands (with Possible H Sand Evaluation and Production)
The gas in the D, E, F and G sands block is contained in three sands situated in a single structurally high area in the northwest portion of the field. The depth ranges from the top of D sand at about 910 m TVD to the base of the F-G at 1,200 m TVD. The D sand is good quality, well sorted and poorly consolidated, with estimated permeability of 150 mD.
E and F-G sands permeability is in the 100 mD range. The initial reservoir pressure ranges from 11,000 kPa in D sand to about 12,000 kPa in F-G sands. Water production is expected from each zone at some point during its depletion. A single well is planned to recover the gas in this block. The design production rate for the well is 0.300 to 0.900 Mm3/d (10 to 30 MMscf/d).
The completion design includes setting and cementing a 193.7 mm liner to the base of the D sand, and cementing a 139.7 mm liner across the E and F-G intervals. The well will be completed by selectively perforating each zone. An internal sand screen will be run over the D sand interval. A production tubing string with packers and sliding side sleeves will provide selective isolation of each zone for testing and production control. The planned production tubing size is 114.3 mm.
August 2004 Shell Canada Limited 6-19 NDPA-P1 Section 6.2 DRILLING AND COMPLETIONS COMPLETIONS
6.2.2.3 D, E and F-G Sands (with Possible H Sand Evaluation and Production) (cont’d)
This well design could accommodate deepening to evaluate and produce the H sand, if required.
Figure 6-5 shows the preliminary completion design for the D, E and F-G sands.
6.2.2.4 L, M and N Sands (with Possible O-P Sand Evaluation and Production)
The gas in the L, M and N sands block is contained in three sands situated in a single structurally high area in the central portion of the field. The depth ranges from the top of L sand at about 1,700 m TVD to the base of N sand at 2,050 m TVD. The estimated permeability of these sands is 10 to 50 mD. Initial reservoir pressure ranges from 18,000 kPa in L sand to about 21,300 kPa in N sand. Water production is expected from each zone at some point during its depletion. A single well is planned to recover the gas in this block. The design production rate for the well is 0.20 to 0.50 Mm3/d (7 to 18 MMscf/d).
The completion design includes setting and cementing a 193.7 mm liner above the L sand. A 139.7 mm liner will be cemented across the L to N intervals, and the well will be completed by selectively perforating each zone. A production tubing string with packers and sliding side sleeves will provide selective isolation of each zone for testing and production control. The planned production tubing size is 88.9 mm.
This well design would permit deepening to evaluate and produce O and P sands that might contain non-associated gas, if required.
Although deeper than other Niglintgak wells, the preliminary completion design of this well will be similar to that for the D, E and F-G sands.
6.2.3 TUBULAR PROGRAM
Tubing sizes were evaluated for well deliverability rates and pressures based on reservoir depletion strategies for a range of reservoir realizations (see Section 4, Reservoir Depletion). The tubing sizes selected will balance well deliverability and costs with gas compression requirements. The sizes selected range from 88.9 mm for the P-4L well to 177.8 mm for the P-2 well. The P4L well has high reservoir pressure and a planned production rate of 0.200 to 0.500 Mm3/d (7 to 18 MMscf/d). The P-2 well has planned production rates of up to 1.4 Mm3/d (50 MMscf/d).
Figure 6-6 shows the tubing performance curves (inflow relationship versus intake pressure curve) for A sand well D-1 at various stages of reservoir depletion.
6-20 Shell Canada Limited August 2004 NDPA-P1 Section 6.2 DRILLING AND COMPLETIONS COMPLETIONS
508.0 mm Insulated or Refrigerated Conductor
339.7 mm Surface Casing
200 m 177.8/139.7 mm Production Tubing
244.5 mm Intermediate Casing
Subsurface Safety Valve
193.7 mm Production Liner MD – 700 to 1,000 m TVD – 650 m Chemical Injection Valve
139.7 mm Tieback Seal Assembly with Packer
139.7 mm Liner with Sand Screens and Packers
MD – 950 to 1,530 m TVD – 650 m
MD – 1,200 to 1,900 m TVD – 990 m Not to scale
Figure 6-4: Southeast Block A Sand Preliminary Well Completion Design
August 2004 Shell Canada Limited 6-21 NDPA-P1 Section 6.2 DRILLING AND COMPLETIONS COMPLETIONS
508.0 mm Insulated or Refrigerated Conductor
339.7 mm Surface Casing
200 m
114.3 mm Production Tubing
244.5 mm Intermediate Casing
Subsurface Safety Valve
193.7 mm Production Liner MD – 700 m TVD – 640 m Chemical Injection Valve
Production Packer
Internal Sand Screen D Sand (perforations) Sliding Sleeve
Production Packer MD – 1,170 m TVD – 1,030 m 139.7 mm Production Liner Sliding Sleeve E Sand (perforations) Production Packer
F and G Sand (perforations)
MD – 1,400 m TVD – 1,250 m
Not to scale
Figure 6-5: D, E, F, G and H Sand Preliminary Well Completion Design
6-22 Shell Canada Limited August 2004 NDPA-P1 Section 6.2 DRILLING AND COMPLETIONS COMPLETIONS
12,000
11,000
10,000
9,000
8,000
7,000
6,000
5,000 Flowing (kPa) Bottomhole Pressure
4,000 IPR – Initial Reservoir Pressure IPR – 8,000 kPa Reservoir Pressure IPR – 5,000 kPa Reservoir Pressure Tubing Head Pressure – 10,000 kPa – 139.7 mm Tubing - IPC 3,000 Tubing Head Pressure – 7,000 kPa – 139.7 mm Tubing - IPC Tubing Head Pressure – 4,000 kPa – 139.7 mm Tubing - IPC Tubing Head Pressure – 10,000 kPa – 114.3 mm Tubing - IPC Tubing Head Pressure – 7,000 kPa – 114.3 mm Tubing - IPC 2,000 Tubing Head Pressure – 4,000 kPa – 114.3 mm Tubing - IPC Tubing Head Pressure – 10,000 kPa – 177.8/139.7 mm Tubing - IPC Tubing Head Pressure – 7,000 kPa – 177.8/139.7 mm Tubing - IPC Tubing Head Pressure – 4,000 kPa – 177.8/139.7 mm Tubing - IPC 1,000 0 200 400 600 800 1,000 1,200 1,400 1,600 1,800 Gas Flow Rate (1,000 m3/d) IPR = Inflow Performance Relationship IPC = Intake Pressure Curve
Figure 6-6: Tubing Performance Curves for A Sand Well D-1
August 2004 Shell Canada Limited 6-23 NDPA-P1 Section 6.2 DRILLING AND COMPLETIONS COMPLETIONS
6.2.4 METALLURGY
Low-temperature carbon-steel tubulars of appropriate strength and weight will be used for production wells. Produced fluids will not contain hydrogen sulphide and will have a carbon dioxide content ranging from zero to slightly over 1%. Wells will be equipped for downhole chemical corrosion inhibitor injection. Corrosion will be monitored and a corrosion inhibition program will be implemented, as required.
6.2.5 WELL TESTING
Each zone to be completed is expected to require a flow test. The wells will be tested initially in conjunction with completion operations with flow to flare.
The objective of well testing will be to ensure adequate flow capability from each zone and to remove drilling and completion fluids from the wellbore. The length and rate of flow from each zone will vary, depending on the reservoir characteristics. Flow periods might be as brief as 6 hours and as long as 72 hours, and flow rates might vary from 0.030 Mm3/d to more than 0.300 Mm3/d (1 to 10 MMscf/d).
Well test equipment will consist of some or all of the following:
• a high-pressure separator • an indirect-fired (diesel or gas) heater • chokes • gas meters and liquid meters • liquid storage tanks • a flare stack and low-pressure separator
Equipment will be selected in conjunction with detailed well design. Extended well testing will be done with flow into the pipeline following the beginning of production operations.
6.2.6 FLUID HANDLING
The primary completion fluid will be water-based brine with an adequate density for well control. The production tubing annulus might be circulated with a gelled diesel or a water-glycol blend. Methanol will be required to inhibit gas hydrates. Minor quantities of other chemicals, such as corrosion inhibitor, biocides and oxygen scavengers, might be required.
The fluids will be stored in tanks with secondary containment. Transportation and handling procedures with spill contingency plans will be developed and followed. Fluids will be disposed of through subsurface wells or by another acceptable method.
6-24 Shell Canada Limited August 2004 NDPA-P1 Section 6.2 DRILLING AND COMPLETIONS COMPLETIONS
6.2.7 COMPLETIONS EQUIPMENT
The wells will be completed using the drilling rigs. Where required, specialized completion equipment will be used, including:
• wireline logging units • coiled tubing units • portable production testing equipment
6.2.8 PERFORATIONS
Open hole completions with sand screens are planned for the wells that will produce from the A sand. Wells cased through the production zone will be perforated over selected intervals, as determined by log evaluations and desired production performance. Perforating will be done by wireline or tubing-conveyed methods, depending on the well trajectory and wellbore configuration.
6.2.9 WELLHEAD EQUIPMENT
All wellhead components will be built to the appropriate pressure rating and will conform to the current API Specification 6A for Wellhead and Christmas Tree Equipment.
The wellhead assembly will include a 346.1 mm casing bowl that will be installed on the 339.7 mm surface casing and a 346.1 mm x 279.4 mm tubing head. Master valves and flow tees will be sized appropriately for the production tubing.
The tubing hanger and upper section of the wellhead will be designed to accommodate control lines for the SSSVs and injection lines for hydrate and corrosion inhibitors.
6.2.10 ALTERNATIVES CONSIDERED
Instrumented well completions incorporating extensive downhole instrumentation for reservoir monitoring and downhole flow-control capabilities were examined, but were considered uneconomic for the current well designs with existing technologies. These technologies are evolving rapidly and will continue to be considered as advances make them more suitable for development wells.
The well completion design chosen for each of the blocks is considered the most suitable to meet production objectives. Some other alternatives for well completion design were considered.
6.2.10.1 A Sand – Southeast Block B-19 and E-58
Alternative completion designs for B-19 and E-58 southeast block A sand were:
August 2004 Shell Canada Limited 6-25 NDPA-P1 Section 6.2 DRILLING AND COMPLETIONS COMPLETIONS
6.2.10.1 A Sand – Southeast Block B-19 and E-58 (cont’d)
• cased, cemented and perforated completion with internal sand screens. This design would be robust for zonal isolation, but would restrict flow more than the chosen design.
• open hole completion with wire-wrapped screens and external gravel pack. This design was rejected because it is more difficult to include selective zonal isolation.
• cased and selectively perforated completion with no mechanical sand control. This design would be economical and could provide reliable zonal isolation, but was rejected because the risk of sand production was considered unacceptable.
6.2.10.2 A Sand – Northwest Block H-30 and M-19
A completion design considered for H-30 and M-19 northwest block A sand was horizontal with multilateral wellbores. The permeability of the sand in this block will likely provide adequate well deliverability and reservoir drainage from vertical wells. This design might be used if, after being placed on production, the reservoir is determined to be more discontinuous than is currently indicated.
6.2.10.3 D, E and F-G Sands
Monobore well completion was considered for the D, E and F-G sands. This alternative could be less costly than the chosen well design, but the initial evaluation of each zone could be more difficult because of the limited ability to isolate zones. Sand control for D sand would be more difficult to incorporate.
6.2.10.4 L, M and N Sands
Monobore well completion was also considered for the L, M and N sands. As for the D, E and F-G sands, this alternative could be less costly than the chosen well design, but the initial evaluation of each zone would be more difficult because of the difference in reservoir pressures and limited ability to isolate zones. Liquid loading and uneven flow up the tubing might be a problem with this design because of tubing size constraints and associated flow velocity.
6-26 Shell Canada Limited August 2004 NDPA-P1 Section 7.1 PRODUCTION FACILITIES
APPLICATION FOR APPROVAL OF THE DEVELOPMENT PLAN FOR NIGLINTGAK FIELD PROJECT DESCRIPTION DEVELOPMENT PLAN
7.1.1 DEVELOPMENT APPROACH
Shell is committed to sustainable development. This means integrating short and long-term economic, environmental and social considerations in the decision- making process for all business activities. Shell’s sustainable development principles will be applied in all aspects of Niglintgak production facilities development.
Niglintgak production facilities will be designed to gather Niglintgak well production, and process this gas to meet the requirements of gathering pipeline specifications.
Alternative production concepts evaluated during conceptual design are described in Section 4.3, Alternatives Considered. The chosen concept was further refined through technical design studies to determine the optimum production concept required to meet Niglintgak processing requirements. This conceptual design for the Niglintgak field will continue to be refined throughout Project Definition Phase engineering.
7.1.2 DEVELOPMENT BASIS
Design parameters and criteria outlined in Section 5 were used as the basis for the production facilities conceptual design.
7.1.2.1 Production Forecasts
Low initial reservoir pressures combined with high gathering system pressure requirements have necessitated the use of compression at Niglintgak from the start of operations. The development production forecast requires increasing amounts of compression over time to maintain production. In addition, the well pads will be designed to enable future development drilling if additional wells are required to maintain required production rates.
The production facilities design capacity is higher than the forecasted daily average rate. Production facility capacity must be sufficient to enable lost production volumes to be made up during periods when additional pipeline capacity is available.
August 2004 Shell Canada Limited 7-1 NDPA-P1 Section 7.1 PRODUCTION FACILITIES DEVELOPMENT PLAN
7.1.2.2 Well Production Compositions
Gas composition is based on the predicted blend of well production from all production wells. Actual production composition and flow rates from each well will vary, so the facilities will be designed to accommodate the expected range of fluid compositions. For example, significant increases in produced hydrocarbon liquids might require future modification to the liquids handling and metering system.
7.1.3 SCOPE OF FACILITIES
Niglintgak production facilities will be designed to gather Niglintgak well production and process it to meet the gas and hydrocarbon liquids specification requirements of the gathering pipeline. The chosen development concept includes production well pads, flow lines and gas conditioning facilities, along with their associated utilities and infrastructure.
Figure 7-1 shows the proposed production facilities layout, including the well pads, flow line and gas conditioning facility locations. A simplified process configuration of the overall production facilities is provided in Figure 7-2.
–135° 25´ W –135° 15´ W
69° 20´ N
Shell Significant Discovery Licence Boundary
Kendall Island Bird Sanctuary Boundary
69° 16´ N
Figure 7-1: Niglintgak Facilities Location
7-2 Shell Canada Limited August 2004 NDPA-P1 Section 7.1 PRODUCTION FACILITIES DEVELOPMENT PLAN
Main Process
N Gas Gas Gas Well Pad Compression Dehydration Refrigeration Metering To Pipeline Hydrocarbon C Inlet Liquids Well Pad Separation Tankage and Reinjection
To S Water Disposal Well Pad Treatment Well
Main Utilities, Safety and Support Systems
Electric Utility Flare Fuel Gas Other Utilities Controls Communications Tankage Accommodation Power Heat System System and Support Generation Systems
Figure 7-2: Niglintgak Overall Process Configuration
7.1.3.1 Well Pads
Three well pads are required. These pads will be on elevated pile foundations, providing space for individual well operations and production equipment. Well pad facilities are required primarily to meter and control well production and to heat the gas before it is transported through the flow line to the gas conditioning facility.
7.1.3.2 Flow Lines
Produced gas from the well pads will be transported to the gas conditioning facility through 10 km of flow lines, which will be elevated to protect the permafrost and insulated to keep produced gas above its hydrate temperature (the temperature at which it will freeze) without thawing the permafrost. The flow line from the Niglintgak Island well pads will be routed under the Kumak Channel through an HDD crossing, where it will join the south well pad flow line and enter the gas conditioning facility.
7.1.3.3 Gas Conditioning Facility
The gas conditioning facility will consist of several production modules constructed on a steel substructure. It will be towed to the Niglintgak location, ballasted in place, and secured using a permanent piled foundation on the east side of Kumak Channel. In the gas processing facility, liquids will be separated from produced gas before the gas is compressed and dehydrated. Produced water will be sent to a disposal well for reinjection. The processed gas will be refrigerated and metered before it enters the buried Niglintgak lateral of the gathering pipeline.
7.1.3.4 Process Utilities
Process utilities will primarily be located at the gas conditioning facility and will include all auxiliary systems required to support the production facilities.
August 2004 Shell Canada Limited 7-3 NDPA-P1 Section 7.1 PRODUCTION FACILITIES DEVELOPMENT PLAN
7.1.3.4 Process Utilities (cont’d)
Utilities will include power generation, utility heating, chemical injection, fuel gas and process controls, and will be supplied for both the gas conditioning facility and well pads.
7.1.3.5 Construction and Drilling
Production facilities will be built over three years, targeting start-up in 2009. The current project execution schedule requires drilling activities to start early in this construction window. Construction of the production facilities will occur later, and will require construction and drilling activities to be conducted at well pads during the same period.
7.1.4 FACILITY EXPANSION AND THIRD-PARTY ACCESS
Other Shell and third-party SDLs and exploration prospects already exist in the Niglintgak area. Currently, there are no definitive plans to develop these fields. However, if these fields are developed in the future, the Niglintgak development plan would consider expanding the Niglintgak facilities to process these volumes.
As additional gas processing opportunities are identified during the design process, design modifications to include other area development might be considered, including:
• installing additional river crossings • enlarging flow line structural supports for future expansion • meeting additional fuel gas and power supply requirements for well pads
7.1.5 FACILITY LAYOUT
Preliminary layouts of Niglintgak production facilities reflect the space required for equipment described in the application scope. As engineering progresses, plot plans will be refined to optimize the use of space available and reduce the impact on the surrounding environment.
An artist’s impression of the current well pad design is shown in Figure 7-3. Changes in the orientation and layout of wells and production equipment will be further evaluated during ongoing engineering studies.
An artist’s impression of the current gas conditioning facility design is shown in Figure 7-4. Design factors must be balanced, including ease of construction and operation, minimum equipment spacing requirements and minimum weight for transportation. The proposed conceptual design will continue to be refined to ensure that this balance is maintained.
7-4 Shell Canada Limited August 2004 NDPA-P1 Section 7.1 PRODUCTION FACILITIES DEVELOPMENT PLAN
Figure 7-3: Artist’s Impression of Niglintgak Well Pad
August 2004 Shell Canada Limited 7-5 NDPA-P1 Section 7.1 PRODUCTION FACILITIES DEVELOPMENT PLAN
Figure 7-4: Artist’s Impression of Niglintgak Gas Conditioning Facility
August 2004 Shell Canada Limited 7-6 NDPA-P1 Section 7.2 PRODUCTION FACILITIES
APPLICATION FOR APPROVAL OF THE DEVELOPMENT PLAN FOR NIGLINTGAK FIELD PROJECT DESCRIPTION WELL PAD FACILITIES AND FLOW LINES
7.2.1 WELL PAD FACILITIES
Processing facilities at the well pads will be minimal (see Figure 7-5). However, before the gas leaves the well pads, a number of key operations will be carried out, including:
• production metering • hydrate inhibition • corrosion inhibition • flow control • flow integrity monitoring
Hydrate Inhibitor From Flare Knockout Pump from Tank or Gas Flow Conditioning Hydrate Inhibitor Meter ESD Choke Gas and NGLs to Facility (Booster) Pump
Valve Valve Gas Conditioning Facility Well Testing and via Flowlines Corrosion Inhibitor Meter Proving Loop Pig Launcher
from Tank or Gas Conditioning Corrosion Line Heater Facility Inhibitor (Booster) Pump
Wellhead Typical Well Pad Flare System Fuel Gas
from Gas Conditioning Equipment Facility Relief and Blowdown
Flare Knockout Vessel
Back to Main Flow
Flare Knockout Pump
Not to scale
Figure 7-5: Niglintgak Well Pad Process Schematic
Facilities at the well pads will likely include: • wellheads
August 2004 Shell Canada Limited 7-7 NDPA-P1 Section 7.2 PRODUCTION FACILITIES WELL PAD FACILITIES AND FLOW LINES
7.2.1 WELL PAD FACILITIES (cont’d)
• production choke valves • production manifold piping • line heaters for continuous flow line hydrate control • hydrate and corrosion inhibitor storage tanks and injection pumps • metering • flare stacks • pipeline inspection pig launchers • electrical power • helipads to allow site access all year • process buildings to protect process equipment and operations staff • walkways between equipment and buildings to protect the permafrost • emergency shelters • local control panels • communication equipment
Produced gas will be heated at the well pads and transported through the flow line to the gas conditioning facility for processing. With Niglintgak’s comparatively low reservoir temperatures, insulated wellbores can be used to protect the permafrost. Additional downhole refrigeration will not be required.
For allocation purposes, wet-gas meters will be placed on each well stream for continuous metering and reservoir monitoring. Temporary test separator connections will be provided in case a test separator is required, but no permanent test separator is planned for either of the well pads.
Well pad flare stacks will not have a continuous pilot, but will be manually lit as required. The flare system will be used primarily to depressurize the facilities and flow lines for maintenance, or in the unlikely event of a hydrate forming in the flow lines. Otherwise, well pad facilities will be blown down through the gas conditioning facility. Well pad flares might also be used for well workover operations.
A produced water disposal well will be required and is planned to be located at the south pad, which is closest to the gas conditioning facility. The location will be optimized in the design stages of the project.
7.2.2 FLOW LINES
Three flow lines will connect well pads to the gas conditioning facility: • an NPS 12, 3 km flow line transporting gas and associated liquids from the north pad to the central pad • an NPS 12, 4 km flow line transporting gas and associated liquids from the central pad to the gas conditioning facility • an NPS 8, 2.5 km flow line transporting gas and associated liquids from the south pad to the gas conditioning facility
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Flow line sizes are preliminary and will be optimized. The flow lines will be insulated and elevated at least 2.2 m above ground on vertical supports to protect the permafrost, avoid flood waters, and reduce surface disturbance (see Figure 7-6 for a typical design). The flow lines will be insulated with about 50 mm of polyurethane foam insulation to reduce heat loss.
Power cables, fuel gas and, possibly, chemical injection lines will be laid alongside production flow lines to supply well pad facilities. The design of well pad utilities and the chemical supply system will be further optimized as engineering progresses.
7.2.3 KUMAK CHANNEL CROSSING
The flow line from the central pad to the gas conditioning facility will cross Kumak Channel. The current plan is to use a trenchless HDD crossing of Kumak Channel to: • eliminate the risk of ice scour damage to the flow line • reduce the impact on aquatic habitat • take advantage of the ease of winter construction • avoid eroding river banks
Geotechnical work from the 1970s (about 17 boreholes) and from 2003 (three boreholes), plus recent conceptual design work, indicate that a cased HDD crossing is feasible. A crossing location, about 2 km downstream of the juncture of Middle and Kumak channels, has been chosen to avoid the eroding bank of Niglintgak Island and reduce the length of the crossing. Further geotechnical work will be done to finalize river crossing details.
If soil conditions at the crossing site are found to be unsuitable for HDD, the alternative would be a trenched flow line crossing. The preferred location for this trenched crossing would be about 900 m downstream of the proposed HDD crossing, based on current bathymetric and soils information.
A flow line bundle will be made up for the HDD channel crossing, and will consist of the required flow lines (production flow line, fuel gas line and, possibly, chemical supply lines) plus conduits for the other cables (power and control). The flow line and, possibly, portions of the casing, will be insulated to reduce heat loss. The current conceptual design suggests a crossing length of about 1 km with a bore diameter of about 1,000 mm and a casing diameter of about 800 mm.
Final casing and HDD bore diameters will depend on the final bundle design and the thickness of insulation. Thermosiphons might be required for permafrost protection at the banks on each side of the channel to prevent thaw settlement.
Crossing configuration details will be finalized during ongoing engineering design.
August 2004 Shell Canada Limited 7-9 NDPA-P1 Section 7.2 PRODUCTION FACILITIES WELL PAD FACILITIES AND FLOW LINES
7.2.3 KUMAK CHANNEL CROSSING (cont’d)
Figure 7-7 illustrates the proposed HDD crossing.
Construction is planned for the winter to enable ice pads to be used for temporary work space and to reduce the gravelled surface required. Following construction, all areas will be reclaimed.
Water required for HDD drilling operations will likely be mixed with bentonite clay to produce drilling mud. The drilling mud, when circulated in the drill hole, will carry the soil cuttings from the wellbore. The required water is expected to be sourced from Kumak Channel.
Cuttings and the small amount of remaining used drilling mud, once separated from the water, will be disposed of in an environmentally acceptable manner.
7.2.4 PIG LAUNCHER AND RECEIVER
The flow lines will be pigged during operations as part of the corrosion control and inspection program and, if required, to remove liquids from flow lines. Pigging facilities will be provided for: • each well pad – a pig launcher for pigging the flow lines leaving the well pad • the central well pad – a pig receiver for pigging flow lines from the north pad • the gas conditioning facility:
• a pig receiver to collect pigs from flow lines • a pig launcher for the Niglintgak lateral
The pig launchers and receivers might be automated to reduce operator intervention. Pigging will initially be done once a month and adjusted as required.
7.2.5 HYDRATE CONTROL
Gas leaving the wellhead will be saturated with water and, at the start of field life, is expected to be about 11,000 kPa and 8 to 10°C. At these pressures, the hydrate formation temperature of the gas will be about 16°C. Consequently, hydrate inhibition to prevent solid hydrates from forming is required both downhole and in surface equipment.
Downhole hydrate inhibition will be achieved by methanol injection. As pressure declines, downhole conditions will move outside the hydrate formation region and methanol injection will be reduced and eventually stopped. Because of low ambient temperatures, surface hydrate inhibition will be required throughout the field’s life. This will be done by heating and maintaining the gas above the hydrate formation temperature using a gas-fired line heater. Hydrate control options will be further evaluated in ongoing engineering studies.
7-10 Shell Canada Limited August 2004 NDPA-P1 Section 7.2 PRODUCTION FACILITIES WELL PAD FACILITIES AND FLOW LINES
Not to scale SK-L-0001A
Figure 7-6: Typical Above-Ground Flow Line Concept
August 2004 Shell Canada Limited 7-11 NDPA-P1 Section 7.2 PRODUCTION FACILITIES WELL PAD FACILITIES AND FLOW LINES
7.2.5 HYDRATE CONTROL (cont’d)
Methanol injection for normal production, start-up and shutdown operations will be provided as part of the surface facilities. Centralizing the methanol tanks and pumps at the gas conditioning facility, with distribution lines to the well pads, will be studied during Project Definition Phase engineering.
7.2.6 CORROSION CONTROL
The Niglintgak gas is expected to contain about 1% carbon dioxide. At the expected operating temperatures and an operating pressure of about 11,000 kPa, the partial pressure of carbon dioxide will be high. Consequently, corrosion control will be necessary and provided by:
• injecting corrosion inhibitor at the well pads to protect downstream equipment from corrosion
• including a corrosion allowance in the selected wall thickness of the Niglintgak flow lines
Carbon dioxide levels are not expected to be high enough to require using specialty materials for flow line control. The type of materials selected will be investigated further during future engineering. In addition, the concept of centralizing corrosion inhibition tanks and pumps at the gas conditioning facility, with distribution lines to the well pads, will also be evaluated.
7-12 Shell Canada Limited August 2004 NDPA-P1 Section 7.2 PRODUCTION FACILITIES WELL PAD FACILITIES AND FLOW LINES
Not to scale SK-L-0005
Figure 7-7: Conceptual HDD River Crossing Design
August 2004 Shell Canada Limited 7-13 NDPA-P1 Section 7.3 PRODUCTION FACILITIES
APPLICATION FOR APPROVAL OF THE DEVELOPMENT PLAN FOR NIGLINTGAK FIELD PROJECT DESCRIPTION GAS CONDITIONING FACILITIES
7.3.1 SCOPE
The Niglintgak gas conditioning facility will consist of a steel substructure and production modules. It will be towed to the Niglintgak location, ballasted in place and secured using a permanent piled foundation in a side stream of Kumak Channel, an area protected from river ice push. Flow lines will be connected to the gas conditioning facility by a short bridge from the east bank of Kumak Channel.
The main gas conditioning processes will include:
• inlet separation • gas compression • gas dehydration • gas refrigeration • metering • hydrocarbon liquids tankage and reinjection into the gathering system • a produced-water handling system
The design and configuration of the gas conditioning facilities will continue to be refined and optimized as engineering progresses.
7.3.2 INLET SEPARATION
Gas from Niglintgak well pads will enter the gas conditioning facility at the inlet separator. This vessel will be designed to allow separation of gas, water and, if required, hydrocarbon liquids. The vessel will be capable of handling liquid slugs from the flow line system.
Gas from the inlet separator will be sent to the compression facilities (see Figure 7-8). Water from the inlet separator will be sent to the produced-water handling system. Any hydrocarbon liquids from the separator will be sent to the hydrocarbon liquids tankage and reinjection facilities.
7.3.3 GAS COMPRESSION
Liquid-free gas from the inlet separators will be sent to the compression facilities. Compression will be required throughout the 25-year life of the
August 2004 Shell Canada Limited 7-15 NDPA-P1 Section 7.3 PRODUCTION FACILITIES GAS CONDITIONING FACILITIES
7.3.3 GAS COMPRESSION (cont’d)
Niglintgak field. As the Niglintgak reservoir is relatively shallow (700 to 1,000 m), the average reservoir pressure is below the gathering system’s required delivery pressure of 12,600 kPa. As a result, field compression will be required at the start of field operational life.
Gas to
Dehydration System
Compressor Gas Suction Scrubber Turbine Driver Compressor Aftercooler Compressor Fuel Gas
Gas and NGLs ESD Liquids to
Valve from Well Pads Storage Disposal via Flowlines Flow Meter System Pig Receiver HC Liquid Off-Gas Inlet Separator to Fuel Gas System or Vent
HC Liquid Flow Flash Drum Meter HC Liquids to Flow Meter Storage Tank
Produced Water
Not to scale to Disposal System
Figure 7-8: Niglintgak Separation and Compression Process
Considerations in developing the conceptual compression design included:
• using well pad compression • phasing the installation of compression • compressor horsepower requirements • compression driver choice
The conceptual design chosen includes:
• compression inlet suction scrubbers • two parallel centrifugal compressors • gas turbine drivers for each compressor • compressor discharge aerial coolers
Suction scrubbers will remove any particulate matter or small droplets of liquid carried over from the inlet separators to prevent damage to delicate compressor components.
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Compressors will compress the gas from the declining inlet pressure to the required gathering system delivery pressure. The conceptual design includes two centrifugal compressors installed in parallel at the start of field life. Both compressors will need to be refitted in about Year 8 of production to handle the declining reservoir pressure.
Compressor discharge aerial coolers will cool the gas, which will become hot during compression, by using fans to circulate air over a bank of tubes containing the gas. The gas will then be sent to the gas dehydration system.
7.3.4 GAS DEHYDRATION
Following compression, water will be removed from the gas through a dehydration process (see Figure 7-9). Considerations in developing the conceptual dehydration design included:
• the type of dehydration process used • dehydration location (well pad versus central facility) • management of dehydration feed chemical contaminants
Regeneration Gas Compressor Regeneration Gas Separator Regeneration Gas Cooler Produced Water
to Disposal System Gas from Regeneration Gas Mole Sieve Heat Exchanger Dehydrator Compressor 1 of 3
Filter- Coalescer Regeneration Gas Heater Fuel Gas
Propane Condensor
Dust Filter
Propane Compressor Propane Compressor Suction Scrubber Propane Surge Drum Gas to
Chiller Flow Gathering System Meter
Not to scale Pig Launcher
Figure 7-9: Niglintgak Dehydration and Refrigeration Process
August 2004 Shell Canada Limited 7-17 NDPA-P1 Section 7.3 PRODUCTION FACILITIES GAS CONDITIONING FACILITIES
7.3.4 GAS DEHYDRATION (cont’d)
Compressed gas will enter the dehydration system through a filter-coalescer designed to remove any liquid droplets, compression oil or particulates that might
have been carried over from the compression system. The filtering process helps maintain the integrity of the molecular sieve material, as contaminants, such as methanol and liquid hydrocarbons, are likely to deactivate the desiccant and reduce the adsorption capacity of the dehydration system.
The main dehydration system consists of three towers packed with molecular sieve material that adsorb water from the gas. The molecular sieve towers operate on a system whereby one tower is adsorbing while the second is regenerating and the third is on standby.
When the molecular sieve material in one tower reaches its full water capacity, operation will be switched to another tower to allow the first tower to be regenerated. Once the gas has been dehydrated, it will be passed through a dust filter to prevent any molecular sieve material from being passed into the gathering pipeline system. Gas leaving the dehydration system will then be sent to the gas refrigeration system.
The molecular sieve beds will be regenerated with a slipstream of dry gas taken from the dust filter outlet. Regeneration gas will be heated and passed through the molecular sieve bed to remove water and any other bed contaminants. This process will regenerate the molecular sieve material and allow it to adsorb water again on the next cycle.
Hot gas leaving the regenerated bed will be cooled to remove the absorbed water and recycled to the inlet of the dehydration system.
7.3.5 GAS REFRIGERATION
Dry gas from the dehydration system will be sent to a refrigeration system to cool it to the required gathering system temperature specification of -1ºC. Considerations in developing the conceptual refrigeration design included:
• the use of river water or aerial coolers for precooling • choice of refrigeration technology • refrigeration equipment drivers and sparing
The proposed refrigeration system will be a single-stage, closed-loop propane system with the following main process components:
• a gas chiller • a propane refrigerant compressor • a propane refrigerant condenser
7-18 Shell Canada Limited August 2004 NDPA-P1 Section 7.3 PRODUCTION FACILITIES GAS CONDITIONING FACILITIES
7.3.5.1 Gas Chiller
The chiller will be a heat exchanger with liquid propane refrigerant on one side and gas on the other. The chiller will be designed to cool the gas to meet the gathering pipeline temperature specification before it is metered and sent to the Niglintgak lateral.
Chilling the gas will result in vaporizing the propane refrigerant. This refrigerant vapour will exit the chiller and flow back to the refrigerant compressor.
7.3.5.2 Propane Refrigerant Compressor
In the conceptual design, an electrically-driven screw compressor is used to recompress the propane vapour to a higher pressure before it flows on to the refrigerant condenser.
7.3.5.3 Propane Refrigerant Condenser
The refrigerant condenser will be an aerial cooler designed to cool and condense the propane refrigerant leaving the propane compressor. Cross exchange with cold fuel gas will be evaluated as a method of trim cooling the propane during hotter summer months. From the propane condenser, the liquid refrigerant will be routed to the propane surge drum before being used for additional gas chilling.
7.3.6 METERING
For allocation and accounting purposes, wet-gas meters will be placed on each well stream for continuous metering and reservoir monitoring. A second stage of metering will take place at the inlet separator, where meters will be placed on the three outlet streams:
• gas • hydrocarbon liquids • water
Two fiscal-standard gas meters will be placed at the meter station between the Niglintgak facilities and the gathering pipelines. One meter will be owned and operated by Shell and the second will be used by the gathering system operator for accounting purposes.
Currently, no Shell liquid hydrocarbon meter is planned at Niglintgak because the quantities of liquid are expected to be too low to justify the cost of metering. Sampling and back-allocation of liquids from the Inuvik area facility will be sufficient for allocation purposes. Liquid metering facilities might be added if liquids production exceeds the current predictions.
August 2004 Shell Canada Limited 7-19 NDPA-P1 Section 7.3 PRODUCTION FACILITIES GAS CONDITIONING FACILITIES
7.3.7 HYDROCARBON LIQUIDS TANKAGE AND REINJECTION
Hydrocarbon liquids from the inlet separator and fuel gas system will flow to the hydrocarbon liquid flash drum. Vapours will be removed in the drum before the hydrocarbon liquids flow to the hydrocarbon liquid storage tank.
Hydrocarbon liquids will be injected into the sales gas line from the hydrocarbon liquid storage tank at a controlled rate that will not exceed the gathering pipeline specifications.
7.3.8 PRODUCED-WATER HANDLING SYSTEM
The inlet separator will remove most of the water from the Niglintgak gas. Smaller amounts of water will also be removed at the compression and dehydration stages of the process. This produced water will be sent to a storage tank and then pumped through a heat-traced flow line to the south well pad for injection into a deep water disposal well.
Fluids injected into the water disposal well will enter the water-bearing portion of a deep reservoir. Surface casing will be used to protect local groundwater and permafrost.
7-20 Shell Canada Limited August 2004 NDPA-P1 Section 7.4 PRODUCTION FACILITIES
APPLICATION FOR APPROVAL OF THE DEVELOPMENT PLAN FOR NIGLINTGAK FIELD PROJECT DESCRIPTION PROCESS UTILITIES AND SUPPORT SYSTEMS
7.4.1 SCOPE
In addition to the main processing facilities, utilities and support systems are required, including:
• electrical power generation • utility heat and heat tracing • control and instrumentation • communication systems • a relief and blowdown system • a high-pressure and a low-pressure flare system • fuel gas systems • tankage and storage • utilities and support systems
The design of the utility system will continue to be refined and optimized as engineering work progresses.
7.4.2 ELECTRICAL POWER GENERATION
Electrical power for the Niglintgak facilities will be supplied by on-site power generation, as no power grid or alternative supply is available in the area. About 4 MW of power is required for the Niglintgak facilities. In developing the conceptual power generation design, design considerations included:
• power driver options • capacity and sparing requirements
Electrical power will be supplied by:
• two natural gas-fuelled, gas turbine-driven generators as prime power units, each capable of providing 100% of the required power demand
• one diesel generator for standby emergency power and initial start-up requirements
A minimum of 14 days supply of diesel fuel (125 m3) will be stored on site for the backup diesel generator. An uninterruptible power supply battery system will also be installed to provide emergency power for critical systems. Power will be
August 2004 Shell Canada Limited 7-21 NDPA-P1 Section 7.4 PRODUCTION FACILITIES PROCESS UTILITIES AND SUPPORT SYSTEMS
7.4.2 ELECTRICAL POWER GENERATION (cont’d)
supplied from the gas conditioning facility to each of the well pads by a dedicated cable, installed alongside the field flow lines.
7.4.3 UTILITY HEAT AND HEAT TRACING
Most of the process equipment will be housed in insulated and heated modules. An ethylene glycol heating medium system will provide utility heat for:
• building heaters • tank heating coils • aerial cooler heating coils for freeze protection • fuel gas heating
The heat medium will likely be an 80 wt% ethylene glycol solution, maintained at a pressure of 345 kPa(a). A pressurized system is required to prevent system losses from vapourization at operating temperatures.
Electric heat tracing will also be provided for piping, where required, and will be evaluated as an alternative to an ethylene glycol process heater.
Most well pad utility heating requirements will be met through electric heating systems.
7.4.4 CONTROL AND INSTRUMENTATION
The gas conditioning facility and well pads will be designed for remote operation. Although the gas conditioning facility will be staffed during the early part of the field’s life, operations will eventually be based at the Inuvik area control centre.
The Inuvik area control centre will:
• monitor and control well pad and gas conditioning facilities, including starting and stopping equipment
• change control set points, as required for facility operation
• manually activate remote automatic shutdown systems, if required
The control systems will use industry-proven, computer-based equipment. Local control and protective systems will enable operations to be controlled either locally or remotely, as required.
In addition to the computerized distributed control system, a separate programmable safety control system will be provided to manage all critical safety systems, including:
7-22 Shell Canada Limited August 2004 NDPA-P1 Section 7.4 PRODUCTION FACILITIES PROCESS UTILITIES AND SUPPORT SYSTEMS
• gas detection • fire and smoke detection • high-pressure shutdown or relief • high-temperature shutdown • manual emergency shutdown stations located throughout the site
The facilities will be fully automated and will rarely require local intervention during normal operations. The safety control system will automatically ensure safe shutdown when required.
Instrumentation and control systems will be designed for high availability, with consideration given to the level of redundancy, quality of equipment and sparing required to reduce both downtime and repair disruptions.
Remote diagnostics capability for instruments, controls and mechanical equipment will be provided to facilitate remote troubleshooting and preventive maintenance applications. Remote programming capability will also be provided. If communications fail, the well pads, gas conditioning facility and safety systems will operate independently and will remain operational. The control system design will allow for future expansion.
7.4.5 COMMUNICATION SYSTEMS
At the gas conditioning facility, remote well monitoring and control will be required. The control system computer at the gas conditioning facility will regularly communicate with the various production wells for control and monitoring data. Communication between the well pads and the gas conditioning facility will be by either a hard-wired system, installed along with the flow lines and power cable, or a dedicated UHF radio communication network.
The well data will be available to the Inuvik area control centre by the backbone communication network between Niglintgak and the Inuvik area control centre.
The expected communication requirements for the Niglintgak gas conditioning facility and well pads include:
• Supervisory Control and Data Acquisition (SCADA) • voice, fax and data • remote diagnostics • video monitoring for security surveillance • accounting and business computer applications
Staff at the Inuvik area control centre will be able to continuously control and monitor the Niglintgak processing facility and well pads.
The communication technology proposed for the anchor fields and common anchor field control centre is a satellite communication network. Niglintgak will be equipped with a satellite terminal and associated electronic equipment. All voice and data communication will use transmission control protocol/Internet
August 2004 Shell Canada Limited 7-23 NDPA-P1 Section 7.4 PRODUCTION FACILITIES PROCESS UTILITIES AND SUPPORT SYSTEMS
7.4.5 COMMUNICATION SYSTEMS (cont’d)
protocol (TCP/IP). Using this common platform will allow for improved maintenance and reduce the requirement for spare equipment.
The choice of technology for communication systems will be evaluated further in ongoing engineering work.
7.4.6 RELIEF AND BLOWDOWN SYSTEM
The main elements of the relief and blowdown system include:
• pressure relief devices for major equipment • blowdown piping • the flare system
The relief and blowdown system will be used to lower the pressure in the gas conditioning facility, and to direct the process fluids in a safe and controlled manner to the flare system, when required. The relief and blowdown system might be manually activated for scheduled work activities, such as planned tests, inspections or maintenance work. It might also be manually activated to relieve pressure in a controlled manner from Niglintgak flow lines in the unlikely event of hydrate formation.
The relief and blowdown system will be automatically activated in an emergency to ensure safe depressurizing of the gas conditioning facility to the flare. The use of this system for depressurizing parts of the gathering system for maintenance will also be evaluated.
7.4.7 FLARE SYSTEM
The flare system will be designed to:
• reduce visual impact of the flare (i.e., height, light, smoke)
• meet the intent of regulatory guidelines
• reduce radiant heat effects on the ice and water surrounding the flare during flaring
The flare system will meet all relevant codes, standards and industry guidelines. Special measures for personnel access and exit, personnel protection systems, equipment layout, wind direction relative to flare location and other design considerations will be taken into account in the flare system design.
The flare system will likely consist of separate high-pressure and low-pressure systems. The possibility of having a single flare system will be re-evaluated in ongoing engineering studies, as will using other flare and vent technologies, such as pilotless flare systems and automatic ignition devices.
7-24 Shell Canada Limited August 2004 NDPA-P1 Section 7.4 PRODUCTION FACILITIES PROCESS UTILITIES AND SUPPORT SYSTEMS
The high-pressure flare system will handle major relief cases and will be designed to accommodate the largest possible flow from the gas conditioning facility during an emergency. The conceptual design of the flare system suggests that the high-pressure flare stack is likely to be about 40 m tall and could be either a sonic flare or a conventional atmospheric flare, depending on the final design load.
The low-pressure flare system will be designed to handle smaller relief cases from low-pressure systems. The conceptual design of the flare system suggests that the low-pressure flare stack is likely to be a conventional atmospheric flare about 20 m tall.
Flare knockout vessels will be used in both flare systems to remove any liquids from the relief flow. These liquids will be sent to the drain system and, if suitable, will be reprocessed or disposed of in the disposal well. If they are unsuitable for recycling or deep well disposal, the liquids will be stored and sent to an approved off-site disposal location.
7.4.8 FUEL GAS SYSTEMS
A high-pressure and a low-pressure fuel-gas system will be provided at Niglintgak. The high-pressure system will supply fuel gas for:
• well pad heaters • compressor turbine drivers • power generators • flow line system purging
The low-pressure system will supply fuel gas for:
• burners • the flare system • blanketing tanks, where required • accommodation facilities
Fuel gas will normally come from the dry gas stream exiting the molecular sieve dust filter. A buy-back line will also be provided from the gathering system as an alternative source of dry gas fuel, when required. From either source, the gas will be heated in a fuel gas preheater and then reduced in pressure before entering the high-pressure fuel gas system.
The fuel gas will flow through a fuel gas scrubber and any liquids that are condensed will be sent to the liquids storage or disposal systems. Gas leaving the scrubber will be sent to either the high-pressure or low-pressure fuel gas heater. Following heating, the fuel gas pressure will be reduced to the required pressure for either the low or high-pressure fuel gas system and routed to the fuel gas users on each system.
August 2004 Shell Canada Limited 7-25 NDPA-P1 Section 7.4 PRODUCTION FACILITIES PROCESS UTILITIES AND SUPPORT SYSTEMS
7.4.8 FUEL GAS SYSTEMS (cont’d)
Separate fuel gas lines will be run in parallel to the production flow lines, to provide fuel gas to the well pads.
7.4.9 TANKAGE AND STORAGE
The gas conditioning facility will include bulk storage tanks for:
• produced water • produced sand • produced hydrocarbon liquids • fuel, such as diesel and aero-type fuels • methanol • corrosion inhibitor • fresh water • sewage
Storage will also be required for small quantities of lubricating oils and heating fluids. Tanks in the steel substructure will be used to store river water for ballast.
Bulk storage tanks at the gas conditioning facility will likely be located in a common area. In addition to the required secondary containment berms around tanks, additional containment will be provided by the containment lip around the barge deck and the foundation substructure. The foundation substructure will not be used for direct storage of hazardous materials.
Methanol and corrosion inhibitor might also be stored in tanks located in a common area at the well pads. Secondary containment for these tanks will be provided by the well pad decking and drain system.
7.4.10 OTHER UTILITIES AND SUPPORT SYSTEMS
7.4.10.1 Storage Areas
A small land-based storage area is planned adjacent to the Niglintgak gas conditioning facility. An area of the gas conditioning facility will be reserved for laydown and a small warehouse will be provided for storing materials, small quantities of chemicals and spares. No significant storage area will be provided at the well pads.
Additional stockpile and storage facilities will be provided at Camp Farewell for staging, construction and operations support.
7.4.10.2 Instrument and Utility Air
Instrument air will be produced by electrically-driven air compressors and used in the gas conditioning facility instrumentation and controls system. Fuel gas will be used in place of instrument air in well pad facilities.
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7.4.10.3 Utility Cooling System
No utility cooling system is expected at Niglintgak. Sales gas will be cooled by the propane refrigeration system. Aerial coolers will provide the required cooling within the compression and dehydration units.
7.4.10.4 Closed and Open Drain Systems
The circumference of the gas conditioning facility deck will have a spill containment lip to prevent liquid from flowing directly into the river. Recessed drain boxes will also be provided on deck to collect spills, rain water, wash-down water and fire water deluge. Small spills and drain liquid flows will be collected in drain sumps.
Separate drain sump systems are planned to manage drain liquids from different areas of the production facilities. Sump liquids suitable for disposal well reinjection will be separated, pumped to a tank, combined with the produced water and directed to the water disposal well at the south pad. Remaining sump fluids will be stored and sent to an appropriate off-site waste disposal facility.
The Niglintgak drain system will be designed to prevent runoff discharge to the Mackenzie River. However, in an emergency, fire water deluge could be directed into the river if the drain sumps become full. Fire and deluge system requirements will be evaluated as part of the safety systems development.
7.4.10.5 Potable Water System
The potable water system design for the gas conditioning facility has not yet been finalized. Currently, two options are being considered:
• withdrawing water from the Kumak Channel • withdrawing water from a nearby lake
The water source will be finalized as engineering design progresses.
7.4.10.6 Sewage Treatment System
Three options are currently being considered for sewage treatment:
• treating sewage at Niglintgak and disposing of it in the produced-water disposal well
• transporting sewage from Niglintgak by truck or barge to the existing Camp Farewell sewage treatment facility for processing, to meet environmental release standards for release into the river
• treating sewage at a Niglintgak-based sewage treatment facility, to meet environmental release standards for release into the river
August 2004 Shell Canada Limited 7-27 NDPA-P1 Section 7.4 PRODUCTION FACILITIES PROCESS UTILITIES AND SUPPORT SYSTEMS
7.4.10.6 Sewage Treatment System (cont’d)
Currently, the plan is to treat sewage at Niglintgak for release into the river, although further analysis of these options will occur as engineering design progresses.
7-28 Shell Canada Limited August 2004 NDPA-P1 Section 7.5 PRODUCTION FACILITIES
APPLICATION FOR APPROVAL OF THE DEVELOPMENT PLAN FOR NIGLINTGAK FIELD PROJECT DESCRIPTION CIVIL AND INFRASTRUCTURE FACILITIES
7.5.1 SITE ACCESS
Access and transportation to the Niglintgak facilities site is challenging. In winter, cold temperatures and little daylight limit access by aircraft or helicopter. However, the cold weather and snow cover make it possible to build and use winter roads and airstrips.
In summer, the partial thaw of the ground presents severe travel restrictions on ground access to Niglintgak. Any site not served by an all-weather road or airstrip, or not located near a barge-landing site, will have limited access.
During the spring and fall, weather conditions can be unpredictable and access to the site can be limited by:
• road closures, as a result of thawed or unfrozen conditions • limited visibility because of fog • flooding, as a result of spring breakup, ice jams or storm surges
7.5.1.1 Helicopter Access
Helicopter access is the only reliable access to Niglintgak all year, subject to weather conditions. During operations, helicopters will provide the main access to the gas conditioning facility for:
• personnel • small quantities of supplies and equipment
Helicopters will provide access to well pads during the summer and for unplanned maintenance. If particularly large pieces of equipment are required for unplanned maintenance, a transport helicopter might be chartered.
Access by helicopter will be restricted by fog, primarily during the spring and fall. Based on weather information, air travel will likely not be available an average of:
• 33.5 days a year because of fog • four to six days a year because of freezing rain and drizzle
As a result, there might be occasions when it is difficult to access the gas conditioning facility and well pads for several days at a time. These access issues
August 2004 Shell Canada Limited 7-29 NDPA-P1 Section 7.5 PRODUCTION FACILITIES CIVIL AND INFRASTRUCTURE FACILITIES
7.5.1.1 Helicopter Access (cont’d)
will strongly influence maintenance and sparing philosophies as well as the personal protection equipment, accommodation and emergency response systems provided at the facilities.
7.5.1.2 Airstrip and Helicopter Pads
Currently, there are no plans to construct a permanent airstrip at Niglintgak. However, access plans include landing float planes on the river in summer and ski-equipped planes on the ice in winter. The existing gravel airstrip at Camp Farewell will be used for smaller fixed-wing access, as required.
Helipads will be located:
• at the gas conditioning module • at each of the Niglintgak well pads
7.5.1.3 Boat and Barge Access
In summer, the Niglintgak gas conditioning facility will be accessed by barge along the Mackenzie River. The main resupply route for operations and major maintenance equipment will be by barge from Hay River to either Camp Farewell or the Niglintgak gas conditioning facility directly.
Careful planning will be required during operations to ensure that all large equipment that cannot be transported by helicopter, small plane or truck is shipped in advance during the short summer barge season.
No permanent barge landing site is planned at Niglintgak. However, a resupply barge will be able to moor alongside the gas conditioning facility while supplies are unloaded by crane. The potential for well pad access by boat will be evaluated as engineering progresses.
7.5.1.4 Roads
Inuvik has road access from the south during most of the year by the Dempster Highway. No all-weather roads exist north of Inuvik and it is not feasible to build a 120 km road from Inuvik to Niglintgak.
Travel by ice road is possible in winter and the GNWT usually constructs an ice road from Inuvik to Tuktoyaktuk each winter. Shell will use this ice road and construct an ice road from Tununuk Point to Camp Farewell and Niglintgak, to accommodate construction and start-up activities during the first two winters of operation (2009 and 2010). Shell will also use ice roads, where feasible, to transport major maintenance equipment and materials required for major turnarounds, currently planned for once every four years.
During operations, ice roads to the gas conditioning facility and between the gas conditioning facility and the well pads will be constructed, as needed.
7-30 Shell Canada Limited August 2004 NDPA-P1 Section 7.5 PRODUCTION FACILITIES CIVIL AND INFRASTRUCTURE FACILITIES
7.5.2 EXISTING FACILITIES
Currently, Shell has a northern drilling base located at Camp Farewell, about 15 km south of Niglintgak. This base has been in operation since the 1970s and will be used to support Niglintgak drilling and construction operations. Camp Farewell will also be used for equipment staging, ongoing operations and maintenance support. Some expansion of Camp Farewell might be required for the Niglintgak development.
7.5.3 SHARED FACILITIES
Where possible, common warehouse space and common spares will be shared with the other anchor fields. A common warehouse will likely be located at the Inuvik area facility. A smaller warehouse for specialty or small, frequently used parts will be located at the Niglintgak gas conditioning facility.
7.5.4 FOUNDATIONS
Small quantities of borrow material will be required for:
• well pad flare permafrost protection • barge access bridge construction • HDD crossing construction • temporary construction buildings and storage areas
7.5.4.1 Well Pads
Well pad facilities and flow lines at Niglintgak will be designed as elevated structures above the tundra to:
• enable well intervention and production operations to be conducted all year • protect the permafrost from thermal degradation caused by project activities • protect from flooding, accounting for subsidence and global warming
Structures to be elevated include:
• buildings • equipment • flow lines • pipes • the helipad
Conceptual design studies were done to determine the most appropriate well pad foundations, considering the geotechnical features at Niglintgak. Alternatives considered included:
• gravel foundations, including:
August 2004 Shell Canada Limited 7-31 NDPA-P1 Section 7.5 PRODUCTION FACILITIES CIVIL AND INFRASTRUCTURE FACILITIES
7.5.4.1 Well Pads (cont’d)
• insulated gravel pads • ventilated gravel pads • gravel pads with thermosiphons • gravel pads with mechanical cooling systems
• shallow insulated foundations • pile foundations • pile-elevated platforms • temporary foundations
Criteria considered in selecting the type of well pad foundation included:
• geographical location • geotechnical and environmental conditions • environmental effects • cost • construction strategy • logistics • stakeholder input
A pile-elevated platform, set 3 to 4 m above grade, was selected as the preferred option. The exact height of the piles will be determined during detailed design. The foundation system will likely use adfreeze piles, which consist of steel pipe piles installed in predrilled holes. The annulus between the pipe and the hole will be filled with a sand slurry, which will freeze to provide the bearing capacity of the pile.
To eliminate the need for construction gravel and reduce the footprint of the pads, piles and well pad facilities will be installed during winter, when the tundra is frozen. Walkways will be provided between equipment and buildings to protect the permafrost.
7.5.4.2 Gas Conditioning Facility
The Niglintgak gas conditioning facility will consist of processing modules on a steel substructure. The gas conditioning facility will be towed to Niglintgak, ballasted in place and secured with a permanent piled foundation in a side stream of Kumak Channel. A number of studies were carried out on this concept during the conceptual design phase to confirm its feasibility.
The substructure will be about 110 m long, 55 m wide and 8 m high, with a towing draft of about 1.9 m.
Reducing the towing draft is a key design consideration to reduce or eliminate any dredging requirement to transport the facility to site. The gas conditioning facility weight and associated towing draft could be reduced by lowering the substructure height and optimizing its structural design. Temporary pontoons could potentially be used to reduce draft at key points in the towing operations.
7-32 Shell Canada Limited August 2004 NDPA-P1 Section 7.5 PRODUCTION FACILITIES CIVIL AND INFRASTRUCTURE FACILITIES
Once at the Niglintgak site, the gas conditioning facility will be secured in place, using ballast water and steel-piled foundations. The optimum location of the gas conditioning facility will be selected considering several criteria, including:
• ice flow protection • water depth • dredging requirements • re-supply barge access • shore access
The chosen location will likely require some preparation, such as dredging, to level the site.
The gas conditioning facility will be grounded by flooding the ballast tanks in the steel substructure. The bottom forces required will be finalized as engineering progresses and additional river bottom geotechnical information is acquired.
Ensuring year-round availability of water for ballast adjustment, as well as freeze prevention at the water intakes, will be two important features in the barge design. This requirement has been met in arctic platforms and vessels by having a heated sea chest within the hull of the unit.
The conceptual design of the gas conditioning facility is based on a water level of 2 to 3 m at the facility setdown location, based on current navigational charts. Conceptual design studies have also indicated that water levels in Kumak Channel can vary significantly over the course of the year, mainly during periods of ice break or storm surge.
Storm surge is expected to govern the maximum water level used for design. The highest registered storm surge over pre-storm levels is predicted to be about 3 m. Therefore, a minimum steel substructure height of 6 to 7 m is required to prevent flooding. The conceptual design allows for a substructure height of 8 m, providing 1 to 2 m above the highest expected water level.
The substructure design is also governed by the requirements to provide sufficient:
• volume for ballasting requirements • strength and freeboard for the ocean voyage, in case of a wet tow • strength for set down on location and related stresses
These factors will be taken into consideration during detailed design engineering. The conceptual design factors are summarized in Table 7-1.
7.5.5 ACCOMMODATION
The gas conditioning facility will contain facilities required for all operations and maintenance activities, as well as:
August 2004 Shell Canada Limited 7-33 NDPA-P1 Section 7.5 PRODUCTION FACILITIES CIVIL AND INFRASTRUCTURE FACILITIES
7.5.5 ACCOMMODATION (cont’d)
• accommodation for up to 20 people • an office • a small warehouse • a workshop
Temporary camps will be used for additional accommodation during initial construction, turnarounds or drilling activities, when necessary.
Each well pad will have an office building that includes emergency shelter for up to four people. A temporary refuge on the east bank of Kumak Channel will provide emergency shelter if the gas conditioning facility needs to be evacuated.
Table 7-1: Gas Conditioning Facility Design Water Level Information
Site Water Storm Ice Pile-Up Global Total Height Design Depth Surge Backlog Subsidence Warming Required Height Requirement (m) (m) (m) (m) (m) (m) (m) Summer highest 3.0 3.1 N/A 0.5 0.6 7.2 8.0 water level Spring ice 3.0 N/A 2.5 0.5 0.6 6.6 8.0 breakup
7-34 Shell Canada Limited August 2004 NDPA-P1 Section 7.6 PRODUCTION FACILITIES
APPLICATION FOR APPROVAL OF THE DEVELOPMENT PLAN FOR NIGLINTGAK FIELD PROJECT DESCRIPTION FACILITIES SAFETY DESIGN
7.6.1 DESIGN CONSIDERATIONS
The conceptual design of the facilities has been developed with personnel safety at the forefront of the design process. Occupational health and safety principles have been and will continue to be applied to the design process to ensure that the control rooms, living quarters and work areas will have the lowest exposure to hazards, such as: • fires • explosions • chemicals • noise
Currently, the gas conditioning facilities are designed with gas and fire detection systems and automated shutdown sequences to protect personnel from exposure to high-risk situations. However, protecting personnel safety is the first priority and, if a serious fire occurs, the facilities will be evacuated to ensure that personnel are protected.
A detailed review of the safety systems required will be completed as part of early Project Definition Phase engineering design activities.
7.6.2 GAS CONDITIONING FACILITIES
7.6.2.1 Fire and Gas Protection
A fire and gas detection system will be designed to provide early and reliable fire and hydrocarbon gas detection. The fire and gas system will: • automatically start the active fire protection systems • initiate shutdowns, if required • audibly and visually alert personnel throughout the facilities
Components of the fire and gas system equipment might include: • smoke detectors • gas detectors • flame detectors • heat detectors • manual alarm pull boxes
August 2004 Shell Canada Limited 7-35 NDPA-P1 Section 7.6 PRODUCTION FACILITIES FACILITIES SAFETY DESIGN
7.6.2.2 Active Fire Protection
An active fire protection system will be provided to:
• control fire and prevent escalation of a fire • extinguish fires, when possible • reduce the effects of smoke and radiation • cool the surrounding equipment and structures
7.6.2.3 Passive Fire Protection
Passive fire protection will provide fire barriers and structural stability if active fire protection fails. Fire and blast-rated boundaries will be established, vertically and horizontally, to prevent a fire or explosion from escalating between one area of a facility and another. Boundaries will also protect personnel, safe areas and critical equipment from the effects of a fire or explosion.
7.6.2.4 Additional Safety Systems
The gas conditioning facility will be equipped with portable fire-fighting and rescue equipment, and portable safety and life-saving equipment appropriate to the number of personnel on site, as specified in the Canadian Oil and Gas Installations Regulations.
Escape, evacuation and rescue systems for the gas conditioning facility barge will be developed for:
• controlled and emergency evacuation • personnel injury and medical evacuations
The primary method of evacuation from the gas conditioning facility will be over the connecting bridges to land. Secondary evacuation methods, such as lifeboats and ladder systems, and a temporary refuge will be evaluated further as engineering progresses.
7.6.3 WELL PAD FACILITIES AND FLOW LINES
The well pad facilities and flow line will use some of the safety systems used in the gas conditioning facilities. These might include:
• automated remote shutdown and depressurizing systems • evacuation temporary refuge • audible and visible alarms • building gas detection
Well pad safety system requirements will be developed as part of detailed engineering.
7-36 Shell Canada Limited August 2004 NDPA-P1 Section 7.7 PRODUCTION FACILITIES
APPLICATION FOR APPROVAL OF THE DEVELOPMENT PLAN FOR NIGLINTGAK FIELD PROJECT DESCRIPTION DEVELOPMENT ALTERNATIVES
7.7.1 ALTERNATIVES CONSIDERED
A number of different design concepts for production facilities were considered in the evaluation of development options. This evaluation process and its results are described in Section 4.3, Alternatives Considered.
The main alternative to the proposed concept included a similar reservoir development with a land-based gas conditioning facility. These two development options were both assessed in the conceptual design work as parallel options to enable a more accurate comparison.
As a result of these evaluations, both the proposed processing development and the land-based alternatives were technically and environmentally assessed in the conceptual design process.
7.7.2 LAND-BASED GAS CONDITIONING FACILITY
The land-based gas conditioning facility option shares many common development features with the proposed development option, including:
• six production wells (P-3, P-4, P-4L, P-11, D-1 and P-2) initially
• up to six additional future development wells
• one water disposal well
• three well pads:
• north pad (H-30), where wells P-3, P-4, P-4L, and P-11 will be located • central pad (B-19), where well D-1 will be located • south pad (E-58), where well P-2 will be located
• three above-ground flow lines to connect the well pads with the gas conditioning facility, including an HDD river crossing under Kumak Channel. The power cable, fuel gas and chemical lines will be installed along with the flow lines connecting the well pads and the gas conditioning facility.
August 2004 Shell Canada Limited 7-37 NDPA-P1 Section 7.7 PRODUCTION FACILITIES DEVELOPMENT ALTERNATIVES
7.7.2 LAND-BASED GAS CONDITIONING FACILITY (cont’d)
With the land-based gas conditioning facility, the processing facility would be on the east bank of Kumak Channel and would be built on a piled foundation. The size and number of processing modules required to be transported to site result in the following key differences in the facility design and construction:
• the larger modules would be shipped by barge directly to Niglintgak
• a dredged barge landing site would be required on the east side of Kumak Channel, with a 1 km all-weather access road from the landing site to the gas conditioning facility
• a thick gravel base would be required below the piled foundation to enable the large modules to be transferred directly onto the piled foundation after being transported by barge to the site
7-38 Shell Canada Limited August 2004 NDPA-P1 Section 8.1 PIPELINE TRANSPORT SYSTEMS
APPLICATION FOR APPROVAL OF THE DEVELOPMENT PLAN FOR NIGLINTGAK FIELD PROJECT DESCRIPTION GATHERING SYSTEM
8.1.1 SCOPE
The gathering system proposed by the proponents of the Mackenzie Gas Project will be designed, at a minimum, to accommodate the quantity of raw gas from the three anchor fields in the Mackenzie Delta.
The gathering system for the Mackenzie Gas Project will comprise:
• gathering pipelines (see Figure 8-1) to collect and transport natural gas and associated NGLs to a processing facility located near Inuvik (the Inuvik area facility)
• gas processing and NGL recovery facilities at the Inuvik area facility
• an NGL pipeline to transport NGLs south from the Inuvik area facility to Norman Wells, where it will tie into the existing Enbridge Pipelines (NW) Inc. pipeline
Niglintgak Lateral Taglu Niglintgak
Taglu Lateral
Parsons Lake
Storm Hills Pigging Facility
Parsons Lake Lateral
Storm Hills Lateral
Inuvik Area Facility Not to scale
Figure 8-1: Gathering Pipelines
August 2004 Shell Canada Limited 8-1 NDPA-P1 Section 8.1 PIPELINE TRANSPORT SYSTEMS GATHERING SYSTEM
8.1.2 GATHERING SYSTEM COMPONENTS
8.1.2.1 Gathering Pipelines
The gathering pipelines will consist of about 176 km of buried NPS 16, 18, 26 and 30 pipelines. These include:
• a 15.7 km NPS 16 lateral, which will extend east from the Niglintgak field to the outlet of the Taglu field
• an 81.4 km NPS 26 lateral, which will extend south from the Taglu field to the Storm Hills junction
• a 26.5 km NPS 18 lateral, which will extend south from the Parsons Lake field to the Storm Hills junction, where it will connect with the Taglu lateral
• a 52.5 km NPS 30 lateral, which will extend south from the Storm Hills junction to the Inuvik area facility
Receipt meter stations for the gathering pipelines will be located at the production field facilities. Gas and NGLs will be metered separately, using allocation meters designed to the same standards as custody transfer meters.
8.1.2.2 Inuvik Area Facility
The Inuvik area facility, which will be located east of Inuvik, will separate NGLs from the incoming gas stream and process the liquids into a saleable NGL mix that meets the inlet specifications of the NGL pipeline. The natural gas is compressed and chilled to the required inlet conditions of the Mackenzie Valley pipeline.
The Inuvik facility will connect to the NGL pipeline via the Inuvik NGL meter station. Accounting meter stations will be located at the Inuvik area facility.
8.1.2.3 NGL Pipeline
The 475 km NGL pipeline from the Inuvik area facility to Norman Wells will use the same right-of-way on the east side of the Mackenzie River as the Mackenzie Valley pipeline.
At Norman Wells, the NGL pipeline will connect with the existing Enbridge pipeline to Alberta markets. The NGL pipeline will provide flexibility for future industry development, as it enables easier expansion of the natural gas pipeline and will provide capacity for significant NGL volumes if higher liquid content gas is developed in the Mackenzie Delta or Mackenzie Valley regions.
Joint studies with Enbridge are planned to define the interconnection requirements, including those required for metering, potential batching and facility ownership.
8-2 Shell Canada Limited August 2004 NDPA-P1 Section 8.1 PIPELINE TRANSPORT SYSTEMS GATHERING SYSTEM
8.1.3 EXPANSION CAPABILITY
The gathering system can be expanded, if necessary, by installing additional compressors and pump stations, and by adding laterals and pigging facilities. Separate regulatory applications would be filed for expansions to the gathering system.
August 2004 Shell Canada Limited 8-3 NDPA-P1 Section 8.2 PIPELINE TRANSPORT SYSTEMS
APPLICATION FOR APPROVAL OF THE DEVELOPMENT PLAN FOR NIGLINTGAK FIELD PROJECT DESCRIPTION MACKENZIE VALLEY PIPELINE
8.2.1 SCOPE
The Mackenzie Valley pipeline component of the Mackenzie Gas Project will deliver about 34 Mm3/d (1.2 Bcf/d) of sales gas to Alberta from the outlet of the Inuvik area facility. Gas is expected to be delivered to Alberta before 2010.
8.2.2 PROPOSED PIPELINE ROUTE
The gas pipeline will follow portions of several potential routes from Inuvik to Norman Wells that were previously proposed by developers in the 1970s and 1980s. These potential routes all pass through the Gwich’in Settlement Area and the northern part of the Sahtu Settlement Area.
The proposed route for the gas pipeline from Norman Wells to Alberta is expected to run parallel to the Enbridge pipeline, as much as possible. The route will pass through the southern part of the Sahtu Settlement Area and the Deh Cho Region of the southern Northwest Territories.
The final route will be selected after additional technical work and consultation with:
• Aboriginal and other northern residents along the proposed pipeline route • regulators • other interested parties
8.2.3 GAS PIPELINE COMPONENTS
The gas pipeline will likely consist of:
• about 1,220 km of NPS 30 pipe, with a maximum operating pressure of 18 MPa
• four intermediate compressor stations
• a heater station
• a meter station at the Inuvik area facility
August 2004 Shell Canada Limited 8-5 NDPA-P1 Section 8.2 PIPELINE TRANSPORT SYSTEMS MACKENZIE VALLEY PIPELINE
8.2.3 GAS PIPELINE COMPONENTS (cont’d)
• a meter station at the NGTL interconnect facility near the Northwest Territories–Alberta boundary
The Mackenzie Valley pipeline will interconnect with the NOVA Gas Transmission Ltd. (NGTL) system in Alberta near the boundary with the Northwest Territories. NGTL’s existing Alberta system will be extended to the terminus of the Mackenzie Valley pipeline. NGTL will be responsible for designing and constructing the extension of the existing Alberta system.
8.2.4 COMPRESSOR STATIONS
The sales quality natural gas will be compressed at the Inuvik area facility before it enters the Mackenzie Valley pipeline system.
Four compressor stations will be located at about 225 km intervals along the pipeline near:
• Little Chicago • Norman Wells • Blackwater River • Trail River
8.2.5 OTHER FACILITIES
Other facilities might include a heater station, to be located near the Trout Lake winter road, about 100 km north of the Northwest Territories–Alberta boundary.
An interconnect facility with measurement equipment and system isolation facilities will be located near the Northwest Territories–Alberta boundary. NGTL will seek approval for this under a separate regulatory application.
8-6 Shell Canada Limited August 2004 NDPA-P1 Section 9.1 CONSTRUCTION AND INSTALLATION
APPLICATION FOR APPROVAL OF THE DEVELOPMENT PLAN FOR NIGLINTGAK FIELD PROJECT DESCRIPTION CONSTRUCTION APPROACH
9.1.1 SCOPE
This section describes the conceptual strategies and plans for construction and installation of the Niglintgak production facilities. The scope includes infrastructure, logistics, transportation and services for the construction and start- up phases of the Niglintgak development. Physical production assets include well pad facilities, flow lines and gas conditioning facilities. These strategies and plans will become more detailed as the project progresses and will be integrated with the overall Mackenzie Gas Project.
The execution plans include integrating facilities construction with drilling operations activities, wherever feasible (see Section 6, Drilling and Completions, for drilling operations activities). In the current schedule, drilling activities start before completion of all well pad facilities. Well pad design and project execution plans will ensure that these well pad facilities can be constructed while drilling operations are ongoing.
The execution plan highlights the significant differences in construction logistics and infrastructure requirements for different components of the Niglintgak development. For example, the modularized well pad facilities and flow line materials will be shipped via Hay River and assembled on site, whereas the gas conditioning facility will be preassembled off site and towed to Niglintgak via the Beaufort Sea. These logistical differences will be managed within the construction execution plan to ensure that all construction activities are coordinated.
9.1.2 CONSTRUCTION MANAGEMENT PHILOSOPHY
The Niglintgak construction activities will be conducted according to Shell’s corporate business principles and policies, including the following:
• Commitment to Sustainable Development • Health, Safety and Environment Policy • General Business Principles and Code of Ethics
All contractors will be required to manage their activities according to these principles.
The Niglintgak construction management objectives include the following:
August 2004 Shell Canada Limited 9-1 NDPA-P1 Section 9.1 CONSTRUCTION AND INSTALLATION CONSTRUCTION APPROACH
9.1.2 CONSTRUCTION MANAGEMENT PHILOSOPHY (cont’d)
• Pursue the goal of no harm to people.
• Ensure compliance with the law and stipulations stated within regulatory approvals and continually look for ways to reduce the environmental impact of our construction activities.
• Look for appropriate ways to contribute to the general well being of the community.
• Deliver facilities that meet or exceed the requirements of design drawings, codes, specifications and regulatory commitments.
• Develop detailed plans, including contingency plans, to ensure that weather window opportunities are not missed and milestones are achieved.
• Where possible, incorporate industry best practices and Shell global experiences into project design, construction and operations activities.
• Control costs to maintain successful project financial performance.
A systematic approach will be used to ensure that these objectives are met, and to achieve continuous performance improvement.
9.1.3 QUALITY ASSURANCE
The remote location and severe working conditions for the Niglintgak construction activities require additional focus on effective quality assurance in all project activities and project execution phases. The project’s Quality Assurance Plan will document the targets, measurement tools, reporting mechanisms and procedures to be used on the Niglintgak development to ensure that critical project success factors are met.
The Niglintgak Quality Assurance Plan will require engineering contractors and suppliers of goods and services to follow recognized industry quality management standards, e.g., ISO 9000. The objective of this Quality Assurance Plan is to ensure that all activities affecting quality are consistently organized and controlled, and effectively managed, implemented and documented. The plan will ensure that:
• all contractors and subcontractors have quality systems to fulfil their contractual obligations and that these systems are integrated with the Quality Assurance Plan
• environmental, safety, and health considerations are adequately incorporated into the design during all project phases
9-2 Shell Canada Limited August 2004 NDPA-P1 Section 9.1 CONSTRUCTION AND INSTALLATION CONSTRUCTION APPROACH
• design of equipment, material and services complies with specified contract requirements, project specifications and all applicable codes, standards and regulations
• deficiencies are promptly identified and evaluated, and corrective action is taken
• quality control procedures and test plans are established, documented and implemented
9.1.4 CONTRACTING STRATEGY
Various types of contracts, such as lump sum, reimbursable and unit rate, will be used on the Niglintgak project.
The contract type and work breakdown structure will be selected to best support the construction objectives and to:
• make the best use of contractor expertise • place risk where it is best managed • capitalize on available resources
The current contracting plan is for well designs and drilling activities to be managed within Shell, with specialist contractors providing support in key areas. For the field facilities, an experienced engineering contractor will be selected to perform the engineering design, material procurement and construction planning under the guidance of Shell’s Niglintgak project team.
Requests for information packages and prequalification processes will be used for major scopes of work identified in engineering and construction work packages. Bid lists will include qualified Aboriginal and other northern businesses, and will be expanded to include other prequalified northern and Canadian contractors, as determined by Shell.
All contracts awarded will meet the intent and specific requirements of the Canada Benefits Plan and any commitments identified in the specific benefits and land access agreements.
The Niglintgak development will use Inuvialuit, other northern and other Canadian businesses that are able to:
• meet or exceed specified safety, quality and technical standards, as well as the development’s timing requirements
• be internationally cost competitive at the point where the goods and services are required
August 2004 Shell Canada Limited 9-3 NDPA-P1 Section 9.1 CONSTRUCTION AND INSTALLATION CONSTRUCTION APPROACH
9.1.4 CONTRACTING STRATEGY (cont’d)
• contribute to the development of business and human capacity for the Inuvialuit and other Northern businesses to provide long-term, sustainable benefits to Shell
Where possible, construction and logistics requirements for Niglintgak will be integrated with the Mackenzie Gas Project to take advantage of synergies.
9-4 Shell Canada Limited August 2004 NDPA-P1 Section 9.2 CONSTRUCTION AND INSTALLATION
APPLICATION FOR APPROVAL OF THE DEVELOPMENT PLAN FOR NIGLINTGAK FIELD PROJECT DESCRIPTION CONSTRUCTION EXECUTION PLAN
9.2.1 PURPOSE
A Construction Execution Plan will be developed for Niglintgak, to provide the basic management strategy and plans for executing and managing the construction of the field facilities.
The Construction Execution Plan will describe the:
• construction organization • construction execution schedule • construction resources • materials and services • construction stages • drilling and completions plan • transportation and logistics plan • water and waste management plan
9.2.2 CONSTRUCTION ORGANIZATION
The Niglintgak development will be managed by a Shell project management team to ensure that Shell’s requirements are met in all phases of construction. The team will report to the Niglintgak project manager, who will be responsible for all drilling, facilities construction and construction logistics activities for Niglintgak.
The project manager will integrate all aspects of project execution by using a team consisting of:
• project management, drilling and well engineering specialists • construction, logistics and operations coordinators • Shell and contract specialists • safety and environmental coordinators
Construction of the Niglintgak field facilities and associated drilling activities will require significant labour and equipment resources during the 2006 to 2009 construction period (see Section 13.3, Socio-Economic Impacts).
August 2004 Shell Canada Limited 9-5 NDPA-P1 Section 9.2 CONSTRUCTION AND INSTALLATION CONSTRUCTION EXECUTION PLAN
9.2.3 CONSTRUCTION EXECUTION SCHEDULE
The Niglintgak development schedule is based on the Mackenzie Gas Project milestone of delivering first gas to the Mackenzie Valley pipeline by December 2009. To meet this milestone, regulatory approvals must be received in mid-2006 to allow for the three winter construction and drilling seasons required to complete the Niglintgak development.
Niglintgak drilling, well pad facilities and flow line construction will occur primarily in the winter. The current schedule is based on drilling and construction preparation activities starting in the summer of 2006, immediately following regulatory approvals. Niglintgak field construction and drilling activities will start in the first quarter of 2007 and be completed with pre-commissioning in early 2009 and start-up in December 2009 (see the field development schedule in Section 1.4).
Facilities construction and drilling at Niglintgak will occur primarily in the winter. The current schedule is based on drilling and construction preparation activities starting in the winter of 2006–2007. Construction activities will peak during the winters of 2007–2008 and 2008–2009. Commissioning and start-up is scheduled to occur in the second half of 2009, to meet the first gas target of December 2009.
9.2.4 EXISTING FACILITIES
Where feasible, the development will use Shell’s existing facility at Camp Farewell, which includes:
• full camp facilities for 35 people • a sewage treatment system • storage capabilities for 2 million litres of fuel • a barge landing site • a 140 x 200 m storage area • a 650 m airstrip
Camp Farewell will require some upgrading to prepare it for use to support the Niglintgak drilling and facilities construction activities.
9.2.5 MATERIALS AND SERVICES
9.2.5.1 Materials and Equipment
The major materials and equipment required for Niglintgak construction activities include:
• about 50,000 m3 of granular material
• about 10 prefabricated modules for well pad facilities
9-6 Shell Canada Limited August 2004 NDPA-P1 Section 9.2 CONSTRUCTION AND INSTALLATION CONSTRUCTION EXECUTION PLAN
• well casing and completion tubulars
• about 10 km of NPS 8 to NPS 12 pipe
• up to 1,500 t of piling and structural steel (for elevated well pad foundations and elevated flow lines)
• temporary construction camps and associated camp support facilities
• construction equipment, including:
• bulldozers, graders, compactors, gravel trucks and loaders • trucks, BobCats and forklifts • piling rigs • heavy-lift cranes • welding equipment
• a gas conditioning facility, including:
• a steel substructure • gas conditioning process modules
Material and service requirements will be defined as engineering progresses, and will be integrated with the overall Mackenzie Gas Project requirements wherever feasible.
Where possible, spares, warehouse space and staging sites will be shared with the other two anchor fields (Parsons Lake and Taglu) and the gathering system construction activities.
9.2.5.2 Construction Services
Specific services required during the construction of the Niglintgak development include:
• granular goods hauling and site placement • camp management, maintenance and operation for up to 100 personnel • engineering, procurement and construction management • development drilling • marine transportation and potentially dredging • construction waste management • materials and personnel transportation • environmental monitoring • emergency response • equipment maintenance • re-supply of fuel
August 2004 Shell Canada Limited 9-7 NDPA-P1 Section 9.2 CONSTRUCTION AND INSTALLATION CONSTRUCTION EXECUTION PLAN
9.2.6 CONSTRUCTION ACTIVITIES
Construction of the Niglintgak production facilities will occur in stages. The main construction stages and associated activities include:
• gas conditioning facility and well pad module fabrication
• infrastructure and logistics
• site preparation
• pile installation
• gas conditioning facility and well pad module transportation, including site installation
• commissioning
9.2.6.1 Module Fabrication
Well Pad Modules
The well pad modules are planned to be fabricated off site in a module fabrication shop, most likely in Alberta. The modules will be designed so they can be safely transported by truck, rail and barge to the Niglintgak site without exceeding specified size and weight restrictions. About 10 modules will be required to complete the three well pad facilities.
Gas Conditioning Facility
The gas conditioning facility will be fully fabricated and pretested at an off-site fabrication facility. The fabrication facility location will be further evaluated during detailed design for both Canadian and international locations. Construction will begin in 2006, once regulatory approval, equipment layout and process design have been finalized.
Two construction options are being considered for assembling the gas conditioning facility process equipment. These options are to:
• construct the gas processing facilities directly on the steel substructure after the substructure has been completed
• construct the gas processing facility in modules and assemble the modules on the substructure before transportation
Once constructed, the gas conditioning facility will be towed to site around Alaska and through the Beaufort Sea during the summer of 2008.
9.2.6.2 Infrastructure and Logistics
Construction infrastructure requirements for the Niglintgak development include:
9-8 Shell Canada Limited August 2004 NDPA-P1 Section 9.2 CONSTRUCTION AND INSTALLATION CONSTRUCTION EXECUTION PLAN
• upgrading Camp Farewell for use as a construction supply base and staging area
• constructing required ice roads and ice pads to support winter activities
• constructing camps for the workforce
• shipping required fuel, materials and modules for drilling and construction activities
9.2.6.3 Site Preparation
Site preparation at Niglintgak includes:
• conducting site surveys to identify lease boundaries and layout • placing gravel, where required • levelling the gas conditioning facility river location
Niglintgak production facilities require minimal gravel for construction because most of the land-based work involves elevated work platforms and winter construction using ice pads. Currently, the use of gravel is only planned for:
• the well pad flares for permafrost protection during flaring • the HDD crossing site, if a year-round site is required • the land site where the gas conditioning facility access bridges connect • the temporary storage area adjacent to the gas conditioning facility
9.2.6.4 Pile Installation
Most of the production facilities will be elevated on steel piles to provide both flood and permafrost protection. The conceptual design requires piles for several parts of the facilities, including:
• the well pad drilling platform – required for the first quarter of 2007 • the well pad production facilities – required for the first quarter of 2008 • the elevated flow lines – required for the first quarter of 2008 • the gas conditioning facility – required for the third quarter of 2008
Early pile installation is required to support the planned drilling program starting in the first quarter of 2007. If possible, all well pad and flow line piling will be completed in that winter. If necessary, because of logistical efficiency, this program might extend into the 2008 winter season.
Pile material will be shipped by barge during the summer and stockpiled at Camp Farewell until needed the following winter. Piles will be drilled and frozen in place. The piles for the gas conditioning facility will be completed when the gas conditioning facility is in place.
August 2004 Shell Canada Limited 9-9 NDPA-P1 Section 9.2 CONSTRUCTION AND INSTALLATION CONSTRUCTION EXECUTION PLAN
9.2.6.5 Transportation and Site Installation
Well Pad Module Installation
Well pad modules will be shipped from the module fabrication site by rail or truck to Hay River, transported by barge to Camp Farewell in the summer of 2008, and transported by truck over an ice road to the site during the first quarter of 2009. An alternative being considered is to transport the modules directly from the fabrication shop to Niglintgak by truck in the winter via an ice road.
The well pad modules will be set on previously installed steel piles. Field construction activities will include installation of interconnection piping, electrical and control cabling, heat tracing, insulation, and decking between modules.
Flow Line Installation
The elevated field flow line design will require field installation of both the insulated steel flow lines and the associated fuel, power and communication cables required in the design. Flow line materials will be shipped via barge to Camp Farewell during the summers of 2007 and 2008, for winter installation in 2008 or 2009.
The Kumak Channel HDD river crossing will be bored during the winter of either 2008 or 2009, using temporary ice pads for most of the required work space. HDD activities will be coordinated to the extent possible with the gathering system river crossing activities.
Gas Conditioning Facility Installation
Construction of the gas conditioning facility will be complete in early 2008, to be ready for towing from the construction yard through the Beaufort Sea to the Niglintgak site during the summer of 2008.
Any dredging required for either gas conditioning facility transportation or the setdown site will be done during the summers of 2007 and 2008. Bottom dredging will likely be required at the Niglintgak gas conditioning facility location to ensure a uniform river bottom profile before final setdown. The dredging plan will be finalized during ongoing engineering work, using additional bathymetric data to further understand the quantity and duration of any dredging required.
Following grounding of the gas conditioning facility, final site work will be completed, including:
• foundation piling • installing access bridges from the gas conditioning facility to the land • connecting flow lines to the well pads and gas conditioning facility
Much of the construction activity will occur in winter and will require the use of temporary workplace lighting equipment.
9-10 Shell Canada Limited August 2004 NDPA-P1 Section 9.2 CONSTRUCTION AND INSTALLATION CONSTRUCTION EXECUTION PLAN
9.2.6.6 Commissioning
The gas conditioning facility will be precommissioned before being towed to the site. Commissioning activities for the production facilities will begin in late 2008 and will include:
• checking out equipment after it has been towed to the site • loading required consumable supplies for process and utility equipment • inspecting and checking equipment and control systems
Following commissioning, the facilities will be handed over to operations for start-up.
9.2.7 DRILLING AND COMPLETIONS
Construction of the required drilling pads is included in the well pad construction execution plan. Drilling and completions operations will be fully integrated with the ongoing construction activities.
The drilling pads will be constructed during the first winter season following development approval. The steel decking and piles for the pads, and critical equipment required for ice road construction and early pad construction operations, will be transported by barge and staged at Camp Farewell during the preceding barge season (summer 2006).
A supplemental ice pad area will be constructed adjacent to each drilling site to accommodate the drilling camp and a small area for equipment storage. A temporary airstrip will also be constructed on the river channel adjacent to the drilling site to support drilling operations. The drilling rig, equipment and camp will be transported by truck to the well pad as soon as ice road conditions permit. At the end of each winter drilling season, the drilling equipment and camp will be demobilized to Camp Farewell or other areas.
Camp Farewell will be used as a support base and camp for summer well completion operations. Supplies and completion equipment will be stockpiled on the steel well pad decking before spring breakup of the ice roads. Transportation for summer completion operations will be provided by barge to the Niglintgak area, and by helicopter from the barge to the well pad deck.
For further information on drilling and completions operations, see Section 6, Drilling and Completions.
9.2.8 TRANSPORTATION AND LOGISTICS
Transportation requirements for the project will be highest during the peak construction and drilling years between project approval in 2006 and start-up in late 2009. Transportation and logistics management will be integrated with the rest of the Mackenzie Gas Project activities to reduce potential problems with transportation shortages and logistical constraints.
August 2004 Shell Canada Limited 9-11 NDPA-P1 Section 9.2 CONSTRUCTION AND INSTALLATION CONSTRUCTION EXECUTION PLAN
9.2.8 TRANSPORTATION AND LOGISTICS (cont’d)
The Niglintgak development will use several transportation options during drilling and construction activities, including:
• barges • helicopter and fixed-wing aircraft • trains • trucks and other road vehicles
The current construction and drilling plan will use a combination of these transportation options for transporting material, equipment and personnel for:
• the well pad, flow line and drilling materials and equipment • drilling and construction • the gas conditioning facility
9.2.8.1 Material and Equipment Transportation
Well Pad, Flow Lines and Drilling
The proximity of Niglintgak and Camp Farewell to navigable channels makes the use of barges for transporting material and equipment a cost-effective option to supplement transportation by ice roads. Major drilling, well site and flow line material and equipment for Niglintgak will be transported either to Shell’s existing Camp Farewell for staging or storage, or directly to Niglintgak. Most material and equipment, excluding the gas conditioning facility, will be transported:
• by barge from Hay River in summer • by truck via the Dempster Highway and via ice roads in winter
Consumable supplies, including contingency supplies and some drilling equipment, will be transported by barge to Camp Farewell each summer to supply construction and operations activities planned for the following winter season. A barge landing site is already in place at Camp Farewell. Some small items might be transported to Camp Farewell year-round by helicopter or small fixed-wing aircraft.
Ice roads from Inuvik to Camp Farewell and to specific Niglintgak well pad locations will be built during each of the winter construction or drilling seasons. Where possible, the construction and use of these ice roads will be integrated with the requirements of the Mackenzie Gas Project and other area activities. Equipment not shipped by barge will be moved to Niglintgak via the ice roads in the winter or, for smaller items, by helicopter in the summer.
Gas Conditioning Facility
Ocean-going tugs will be used to bring the gas conditioning facility from its fabrication location along the northern Alaska coastline to the Mackenzie Delta
9-12 Shell Canada Limited August 2004 NDPA-P1 Section 9.2 CONSTRUCTION AND INSTALLATION CONSTRUCTION EXECUTION PLAN
area. Because of the seasonal ice conditions in the Beaufort Sea, the gas conditioning facility will likely be moved in the late summer of 2008.
Two areas of complexity associated with the transportation of the gas conditioning facility to Niglintgak are:
• the short ice-free period through the Beaufort Sea, in particular, the area surrounding Point Barrow
• the selection of the optimum route through the relatively shallow and narrow Mackenzie Delta channels, to eliminate or reduce dredging requirements
The transportation route around Point Barrow, along the North Slope of Alaska, and then into the Canadian Beaufort Sea is well known for the ice-related challenges that it can pose. By mid to late August, a band of open water from 50 km to 100 km wide, which might contain some areas of low to moderate ice concentration conditions, normally stretches from the Alaskan coastline to the southern edge of the polar pack. However, the timing, duration and reliability of the access route is variable because of the presence of shifting ice cover. As a result, transportation around Point Barrow will be well planned to accommodate the range of ice conditions that can be encountered in any given year. Despite the difficulties, a large number of vessel transit, structure mobilization and sealift operations involving ocean tows have been successfully accomplished across this region over the past few decades.
The development plan calls for the Niglintgak gas conditioning facility to be waiting for ice breakup off Alaska by late July in the year of transport. The gas conditioning facility will then be towed around Point Barrow and into the Beaufort Sea, most likely arriving at the mouth of the Mackenzie River in early August. The ocean tow itself should take only one week, although waiting on the right weather and ice conditions for transport could take several weeks.
The current plan is to transport the gas conditioning facility from the fabrication yard to the Niglintgak site as a wet tow. A dry tow, with the gas conditioning facility carried on another vessel for the ocean tow, is also being considered. The exact Beaufort tow route and tow method will be finalized as engineering design progresses.
The gas conditioning facility will likely arrive at the mouth of the Mackenzie River by early August. River tugs will then tow it to the Niglintgak site sometime during August or September. The exact timing will depend on water levels and weather at the time of the tow. If dredging is required on the chosen route, it will be carried out in the weeks before the barge reaches the river mouth.
Desktop studies have been done on the following three identified access routes from the Beaufort Sea to the Niglintgak site (see Figure 9-1), using data from navigational charts, surveys and water-level monitors:
• Kittigazuit • Garry Island • Shallow Bay
August 2004 Shell Canada Limited 9-13 NDPA-P1 Section 9.2 CONSTRUCTION AND INSTALLATION CONSTRUCTION EXECUTION PLAN
Gas Conditioning Facility (cont’d)
Additional bathymetric information on two of these routes was obtained in the summer of 2004 to help evaluate the routes further. This information will be used to finalize the route, and identify any dredging or additional buoyancy requirements.
Currently, Kittigazuit is the preferred route, because it is the existing shipping route and, if dredging was required, it would widen or lengthen the existing channel to the advantage of all shipping in the area. However, the Garry Island route is more direct, shorter and is outside the Beluga Management Zone 1A, which must be crossed in the Kittigazuit route. Community consultation has identified concerns about transportation through the Beluga Management Zone 1A, particularly if dredging is required.
The Shallow Bay option was not pursued because it had no advantages over the other routes. Further information on the remaining routes was gathered in a multi-beam swath bathymetry survey carried out in summer 2004. The final route will be selected based on a number of criteria, including:
• the quantity (depth, width and length) of any dredging required • the directness of the route • the potential dredging time • the location of the dredging • the proximity to the Beluga Management Zone 1A • community input
Preparation of the final river location for the gas conditioning facility will likely involve a small amount of dredging at the set-down site, to create a suitable surface profile. The extent of this will also be confirmed with data from the summer 2004 multi-beam swath bathymetry survey. The gas conditioning facility will be grounded at the set-down site, using water ballast, and secured in place using a permanent steel pile foundation. The gas conditioning facility is planned to be in place to allow commissioning to take place in the autumn of 2008.
9.2.8.2 Drilling and Construction Personnel Transportation
Drilling and construction personnel from outside the Inuvik area will be transported to Inuvik by commercial airline or charter aircraft. Personnel will then be transported from Inuvik to Camp Farewell and the construction and drilling camps by:
• fixed-wing aircraft to both Camp Farewell and the Niglintgak ice strip • helicopter • ground transportation via ice roads from Inuvik
Drilling and construction personnel based in Camp Farewell during the winter construction period will be transported daily to Niglintgak.
9-14 Shell Canada Limited August 2004 NDPA-P1 Section 9.2 CONSTRUCTION AND INSTALLATION CONSTRUCTION EXECUTION PLAN
137°0'0"W 136°0'0"W 135°0'0"W 134°0'0"W 133°0'0"W
CAUTION FOR PLANNING PURPOSES ONLY NOT TO BE USED FOR NAVIGATION ³ 10 m Isobath (Depth Contour) 69°30'0"N Kittigazuit 69°30'0"N
Kendall-Garry Option ! Island Option Tuktoyaktuk
Taglu
Niglintgak
Camp 5 m Isobath (Depth Contour) Farewell
Shallow Bay Option (Revised) Parsons Lake 69°0'0"N 69°0'0"N
137°0'0"W 136°0'0"W 135°0'0"W 134°0'0"W 133°0'0"W 1501530 LEGEND SCALE 1:800,000 KILOMETRES Barge Route Significant Discovery Licence Area PROJECT Designated Route (Track Usually Followed) Beluga Management Zone 1A As Shown On Charts Kendall Island Bird Sanctuary Isobath Not to scale DEPTHS IN METRES TITLE NIGLINTGAK DEVELOPMENT PROJECTGOLD-1020
Figure 9-1: Barge Transportation Routes
August 2004 Shell Canada Limited 9-15 NDPA-P1 Section 9.2 CONSTRUCTION AND INSTALLATION CONSTRUCTION EXECUTION PLAN
9.2.9 WATER AND WASTE MANAGEMENT
9.2.9.1 Construction Water Management
Water sources for construction work will vary, based on each construction activity’s quality and quantity needs, and will be finalized during ongoing engineering design activities. Water sources being considered include:
• the Mackenzie River • local lakes • local municipalities
Potable water will be treated for domestic use, except for drinking water, which will be transported to site. Water supply for the facilities construction and drilling activities will be managed though the project’s Water Management Plan.
9.2.9.2 Construction Waste Management
The primary wastes expected to be generated are:
• shipping crate, wooden pallet and packaging debris • piping and structural steel cuttings, and welding consumables debris • sewage • lubricating oils and grease from routine equipment maintenance
All waste generated during construction and installation will be treated on site, if possible, or stored on site, then transported to suitable waste handling sites. Camp wastes will be incinerated on site as much as possible. The Niglintgak Waste Management Plan will address all waste sources from construction activities and outline how each will be managed to meet regulatory requirements.
9-16 Shell Canada Limited August 2004 NDPA-P1 Section 9.3 CONSTRUCTION AND INSTALLATION
APPLICATION FOR APPROVAL OF THE DEVELOPMENT PLAN FOR NIGLINTGAK FIELD PROJECT DESCRIPTION CONSTRUCTION INFRASTRUCTURE
9.3.1 CONSTRUCTION AND DRILLING CAMPS
Construction and drilling camp facilities will be required at Niglintgak to support drilling and construction activities occurring between 2006 and 2009. These camp requirements include using:
• portable drilling camps for each winter drilling season
• Camp Farewell for early facilities construction activities and additional camp space, if required
• a barge-based or land-based camp for facilities construction activities
Each camp will include:
• sleeping units • lavatory and shower facilities • kitchens • dining areas • recreational facilities • first-aid stations
Each camp will also require:
• water treatment facilities • sewage and waste handling facilities • offices • storage facilities • generator sets • communication systems
Camp requirements will be further defined as construction planning progresses.
9.3.1.1 Drilling Camps
A portable drilling camp will be established each winter on an ice pad adjacent to each drilling site at Niglintgak. The location, schedule and type of work will likely require separate drilling camps from those supporting other field construction activities. The camp will accommodate about 70 people for one-rig
August 2004 Shell Canada Limited 9-17 NDPA-P1 Section 9.3 CONSTRUCTION AND INSTALLATION CONSTRUCTION INFRASTRUCTURE
9.3.1.1 Drilling Camps (cont’d)
operations or 100 people for two-rig operations. These land-based portable drilling camp modules will be removed each spring before breakup.
Shell’s Camp Farewell will be used as a support base for drilling and well pad construction operations and provide additional camp facilities, if required.
9.3.1.2 Camp Farewell
Camp Farewell currently has capacity for 35 workers and will be expanded if additional space is required. The facility includes a 650-m-long airstrip that will be used for aircraft transporting both materials and construction personnel. Workers will be transported daily by ice road from Camp Farewell to the Niglintgak construction site.
Camp Farewell will provide additional camp capacity for drilling and facilities construction activities. This facility will also be the prime support base for both summer and early facilities construction activities, which might include:
• well pad site preparation • summer well completions • well pad and flow line piling • flow line HDD activities • gas conditioning facility transportation and dredging activities
Camp Farewell would require upgrading to prepare it for use to support the Niglintgak drilling and facilities construction activities. Integration of Niglintgak camp requirements with the overall Mackenzie Gas Project will be evaluated as execution plans are finalized.
9.3.1.3 Facilities Construction Camp
The facilities construction camp will accommodate an estimated peak construction workforce of about 100 people in early 2008 and 2009, including:
• construction supervisors • camp support staff • inspectors • tradespeople and general construction workers • owner representatives
Options being considered for the location of the camp include:
• adding camp facilities at Camp Farewell
• using a barge-based or land-based camp near the Niglintgak gas conditioning facility
9-18 Shell Canada Limited August 2004 NDPA-P1 Section 9.3 CONSTRUCTION AND INSTALLATION CONSTRUCTION INFRASTRUCTURE
The facilities construction camp location will be finalized as construction planning progresses.
9.3.2 STAGING AND STOCKPILE SITES
The primary staging and stockpile location for Niglintgak will likely be at Camp Farewell. Additional storage required for drilling and construction activities at Niglintgak include:
• a 100 x 100 m area at each well pad • a 150 x 100 m storage site at the gas conditioning facility
These storage sites will be used primarily for short-term storage. At the end of each construction season, most stored items will be relocated to Camp Farewell. The well pad steel deck and gas conditioning facility storage site will be used to stockpile any equipment remaining at the Niglintgak site over the summer period.
Fuel for the Niglintgak construction and drilling activities will be stored primarily at Camp Farewell and transported to the site by truck, as required. Camp Farewell has permanent bermed tank facilities for 2 million litres of fuel storage. Additional temporary onsite fuel storage at the Niglintgak site will be required for drilling and construction support.
9.3.3 GRANULAR RESOURCES
Niglintgak is expected to require minor amounts of borrow materials (estimated at 50,000 m3) for well pad flare, temporary storage sites and access bridge construction. All material is expected to be sourced from the Ya Ya borrow site near Niglintgak during the first quarter of 2007. Borrow site management and transportation will be fully integrated with the Mackenzie Gas Project.
August 2004 Shell Canada Limited 9-19 NDPA-P1 Section 10.1 OPERATIONS AND MAINTENANCE
APPLICATION FOR APPROVAL OF THE DEVELOPMENT PLAN FOR NIGLINTGAK FIELD PROJECT DESCRIPTION ORGANIZATION AND STAFFING
10.1.1 OPERATIONS AND MAINTENANCE ORGANIZATION
Niglintgak’s operations will be based in the Inuvik area. Operations staff for Niglintgak will report to Shell’s existing operations organization (see Figure 10-1).
Niglintgak Area Corporate Level Supervisor Support Business Unit As Required Level Support • Technical Administrative Support • Financial Accounting • Production Accounting • Safety Senior Operator Operator • Legal Operator • Health Operator Trainee Instrument Craft • Environmental • Human Resources Electrical Craft Mechanic Craft • Information and Technology Mechanic Craft Trainee • Procurement (Total number might change)
Operators (8-10) Instrumentation (2-4) Supplemental Staff Electricians (2-4) for Commissioning, Mechanics (2-4) Start-Up and Initial Vendor Specialists – TBD Operation Engineering – TBD Central Specialist – TBD Contractors – TBD TBD – To be determined
Figure 10-1: Niglintgak Operations and Maintenance Organization
An area supervisor will lead Niglintgak operations staff, which will consist of:
• operators • maintenance personnel • administrative support staff
Niglintgak operations will also be supported by Shell staff located off site. Business and corporate support services will be provided in the following areas:
August 2004 Shell Canada Limited 10-1 NDPA-P1 Section 10.1 OPERATIONS AND MAINTENANCE ORGANIZATION AND STAFFING
10.1.1 OPERATIONS AND MAINTENANCE ORGANIZATION (cont’d)
• technical • health, safety and environment • financial • legal • human resources
As required, the off-site staff will travel to Inuvik.
10.1.2 STAFFING
The Niglintgak facilities will be designed for normally unattended operation. The facilities will be designed to be controlled either remotely from the Inuvik area control centre or from the Niglintgak gas conditioning facility.
Staffing levels for Niglintgak will vary as operational stability and operating experience is achieved. The operations staffing plan for Niglintgak will cover the following operational activities:
• commissioning and start-up • initial operations • steady-state operations
10.1.2.1 Commissioning and Start-Up
The Niglintgak start-up organization will consist of the Niglintgak operations staff required for steady-state operations, supplemented with other experienced staff from operations, maintenance and engineering.
Before commissioning, supplemental staff will be integrated into the Niglintgak operations team to help develop:
• training materials • operating, maintenance and safety procedures and practices • commissioning and start-up plans • training plans
As part of their training, the Niglintgak staff will assist with in-shop and on-site inspections of facilities and equipment.
During commissioning, the Niglintgak start-up organization will be supplemented by various additional resources, including:
• equipment and process specialists from the original equipment vendors • engineering contractors’ support staff • Shell technical staff
10-2 Shell Canada Limited August 2004 NDPA-P1 Section 10.1 OPERATIONS AND MAINTENANCE ORGANIZATION AND STAFFING
During commissioning and start-up, work activities will change from scheduled days only to having the facilities staffed 24 hours a day, seven days a week in preparation for:
• starting up the facilities • starting up the wells • introducing well effluent for processing
10.1.2.2 Initial Operation
For initial operation, the Niglintgak operations staff, including supplemental staff, will be assigned to one of four operating teams or a day-support team. During start-up and initial operations, the work schedules for the teams will likely be:
• four operating teams on scheduled rotation to provide operations coverage 24 hours a day, seven days a week
• one day-support operations team on scheduled day shift to provide primarily maintenance and technical support
As operational stability and experience increase, supplemental staffing requirements will be reduced. Initially, the day-support team supplemental staff will be reduced. Then, over a period of up to 24 months, the operating teams will change from providing coverage 24 hours a day, seven days a week, to providing scheduled day coverage.
As these changes take place, the supplemental staff from the operating teams will be reduced until the team consists exclusively of Niglintgak operations staff.
10.1.2.3 Steady-State Operation
In steady-state operation, the Niglintgak facilities will normally be operated and controlled remotely from the Inuvik area control centre. The operating team will consist exclusively of Niglintgak operations staff. The Niglintgak facilities will be staffed for:
• scheduled operating and maintenance activities
• unscheduled operational issues that cannot be resolved remotely
• major maintenance interventions, such as scheduled maintenance shutdowns and facility modifications
August 2004 Shell Canada Limited 10-3 NDPA-P1 Section 10.2 OPERATIONS AND MAINTENANCE
APPLICATION FOR APPROVAL OF THE DEVELOPMENT PLAN FOR NIGLINTGAK FIELD PROJECT DESCRIPTION PROCEDURE DEVELOPMENT
10.2.1 SOTIS SYSTEM
10.2.1.1 Purpose
The operating and maintenance procedures for Niglintgak operations will be developed, validated and documented using Shell’s Operations Training and Information System (SOTIS). This is a competency-based training system that:
• establishes the knowledge and skill requirements for an activity or task • provides a learning method for that skill or knowledge • provides an evaluation method and a method for making up any deficiencies
The SOTIS system is computer-based and the information, procedures and practices stored in SOTIS will be available to all Niglintgak staff electronically or in printed form.
10.2.1.2 Scope
The SOTIS system provides a systematic standard approach to employee training and development for:
• safety skills for operations personnel • site-specific operating skills • site-specific maintenance skills • integrating business, relational and other skills to support business needs
This program provides training and information to:
• ensure compliance with legal, regulatory and corporate requirements
• protect employees, contractors and the community
• protect the environment
• develop employees to meet business needs and help employees reach their potential through continuous learning
• enhance operational facility reliability
August 2004 Shell Canada Limited 10-5 NDPA-P1 Section 10.2 OPERATIONS AND MAINTENANCE PROCEDURE DEVELOPMENT
10.2.1.2 Scope (cont’d)
• protect Shell’s operating assets
• optimize revenue and reduce operating costs
The SOTIS program has established requirements for developing all information that is contained in SOTIS. In the case of procedures, this ensures:
• clarity in format and instructions • clarity in training requirements and the timing of requalification • review and approval by subject specialists • review and approval by appropriate levels of management • current documentation
10.2.2 SITE-SPECIFIC PROCEDURES
The Niglintgak site-specific procedures and practices will be developed from Shell’s existing policies, procedures and practices. The Niglintgak-specific procedures and practices will be developed and implemented before commissioning, start-up and operations. All the Niglintgak staff will be trained in the required material before commissioning. Some site-specific and task-specific procedures and practices will be developed by Niglintgak operations, while others will be developed by subject-matter specialists within Shell.
These procedures and practices will:
• ensure that all operating activities meet or exceed all applicable regulatory, code, licence or permit-to-operate conditions
• comply with Shell’s existing policies, procedures and practices
• cover
• engineering • contracting and procurement • health, safety and environment • legal and finance • human resources • information and technology • operations
Niglintgak-specific procedures and practices will include:
• safety and health:
• general and task-specific safety rules and training • general and task-specific rules about health • emergency response and mutual aid response
10-6 Shell Canada Limited August 2004 NDPA-P1 Section 10.2 OPERATIONS AND MAINTENANCE PROCEDURE DEVELOPMENT
• regulatory and environmental:
• responsibilities, operational limits and reporting requirements • spill and leak response and mutual aid response
• operations and maintenance:
• equipment, process and system design basis and operating limits • routine equipment, process, system start-up, operation and shutdown • nonroutine equipment, process, system start-up, operation and shutdown • emergency equipment, process and system shutdown • critical task-specific maintenance instructions • critical task-specific operating instructions • routine and critical alarm response • maintenance practices for identified equipment • corrosion mitigation and inspection plans for identified process systems
10.2.3 TRAINING
10.2.3.1 Purpose
Training for Niglintgak staff will consist of pre-start-up and ongoing training for the life of the field. All training will follow Shell’s operator training system. Each Niglintgak employee will have a training plan outlining the training and level of competency required before the Niglintgak facilities start-up, as well as the ongoing training requirements to maintain competency.
10.2.3.2 Pre-Start-Up Training
During design and construction of the Niglintgak project, Shell and contract staff will develop training materials for operating and maintaining Niglintgak facilities. Niglintgak staff will also participate in developing some of these training materials under the direction of experienced staff. The training will consist of:
• participating in formal in-house classroom and hands-on training • participating in walk-through or dry-run training • demonstrating skill and knowledge by leading dry-run training • participating in specialty training from equipment vendors and training schools
When Niglintgak facilities are completed, hands-on training will take place. During commissioning and start-up, improvements will be incorporated into training materials through the Operations Training System (OTS) update and improvement process.
10.2.3.3 Ongoing Training
Niglintgak staff will maintain or increase their level of competency by:
August 2004 Shell Canada Limited 10-7 NDPA-P1 Section 10.2 OPERATIONS AND MAINTENANCE PROCEDURE DEVELOPMENT
10.2.3.3 Ongoing Training (cont’d)
• using OTS materials for planning operations and maintenance tasks • reviewing mandatory rules and procedures • completing time-based requalification of specific tasks • reviewing training materials when the materials’ content changes • completing assigned OTS training modules
10-8 Shell Canada Limited August 2004 NDPA-P1 Section 10.3 OPERATIONS AND MAINTENANCE
APPLICATION FOR APPROVAL OF THE DEVELOPMENT PLAN FOR NIGLINTGAK FIELD PROJECT DESCRIPTION DOWNTIME AND WELL INTERVENTIONS
10.3.1 PRODUCTION DOWNTIME
10.3.1.1 Target Availability
To maximize throughput and minimize costs, the Niglintgak development will be designed to have high operational availability, to reduce production downtime. The target is to have at least 95% operational availability.
10.3.1.2 Design Factors
To achieve this goal, the engineering and design process group will consider such factors as:
• number of wells and well location for reservoir drainage • well subsurface design for water and sand control • well pad design for subsurface well maintenance • well pad layout for concurrent operations and well maintenance or drilling • surface facilities design and layout for operations and maintenance • operations response time • 100% redundant equipment in critical applications • warehouse spares for critical equipment
The engineering and design process group will also consider the remote capabilities for start-up, control, monitoring and shutdown.
10.3.1.3 Maintenance
The facilities will be designed to enable much of the routine operation, maintenance and in-service inspection functions to be safely performed without process shutdown. Routine maintenance that requires process shutdown will be scheduled to minimize production interruptions. Power generation equipment will be designed and sized to provide excess capacity.
At initial start-up, the maximum combined capacity of the Niglintgak wells will exceed the processing capacity of the gas conditioning facility, so shutting down any single well will not affect total production. The well pads will be designed for concurrent operation, including production operations and well workovers or production operations and drilling.
August 2004 Shell Canada Limited 10-9 NDPA-P1 Section 10.3 OPERATIONS AND MAINTENANCE DOWNTIME AND WELL INTERVENTIONS
10.3.1.3 Maintenance (cont’d)
Major maintenance shutdowns will be scheduled over the life of the field, based on regulatory requirements and equipment status, as determined by routine maintenance and inspection. To minimize the loss of production, these shutdowns will be coordinated with the other anchor field operators and the pipeline operator.
10.3.1.4 Operations
A process and equipment surveillance system will be incorporated into the Niglintgak facility as part of Shell’s Operations Integrity Assurance (OIA) process. The surveillance system will continuously monitor well, facility and equipment parameters and automatically report any deviations from established performance criteria. This continuous monitoring helps to maximize operational availability by providing:
• real-time monitoring and feedback to the operations team to allow continuous process optimization
• operations and technical specialists access to trended and historical data of equipment and process operating parameters to aid in optimizing and scheduling maintenance
• data for determining the cause of production downtime
With this information, corrective action can be taken to minimize or avoid production downtime or to prevent reoccurrence.
Shell’s OIA process will further help to minimize production downtime through a structured approach, which ensures that:
• critical information and data is identified and available • key performance indicators and associated targets are identified • work roles and responsibilities are clear • compliance audits are scheduled regularly • flare events are reduced
10.3.2 WELL INTERVENTIONS AND WORKOVERS
10.3.2.1 Purpose
Well interventions and workovers will be required periodically to maintain production reliability and to monitor and optimize the performance of the producing reservoir zones.
Well intervention and workover programs will be developed and the work will be done under the direction of Shell’s production engineering or well completions group.
10-10 Shell Canada Limited August 2004 NDPA-P1 Section 10.3 OPERATIONS AND MAINTENANCE DOWNTIME AND WELL INTERVENTIONS
Well interventions are classified as either minor or major.
10.3.2.2 Minor Workovers
Minor workovers do not require removing the production wellhead or using a service rig. They include such operations as:
• production logging and testing to monitor reservoir flow performance • cleaning sand or other material from the wellbore • testing the SSSVs • testing mechanical wellbore integrity • running tools to isolate or open selected reservoir intervals or zones to optimize gas recovery
Equipment required to do minor workovers includes:
• wireline and logging units • coiled tubing units • nitrogen pumping units • fluid pumping units • well test equipment
Drilling and production pads will be large enough to accommodate minor well service operations during any season. If production reliability and other considerations require that well interventions and workovers be done during spring, summer or fall, the equipment required for minor workovers could be transported to the site by helicopter.
10.3.2.3 Major Workovers
Major workovers require removing the production wellhead and usually require using a service rig. They include such operations as:
• repairing or replacing the production tubing or other downhole equipment • recompleting the well in alternative reservoir intervals or zones
Where possible, major workovers that require transporting heavy equipment, including service rigs, to the site will be done in winter when vehicles can travel over winter roads to access the site.
Major well interventions are not expected to be routinely required during ongoing operations. However, if a major intervention is necessary, it can be done without interrupting the production from the other wells.
August 2004 Shell Canada Limited 10-11 NDPA-P1 Section 10.4 OPERATIONS AND MAINTENANCE
APPLICATION FOR APPROVAL OF THE DEVELOPMENT PLAN FOR NIGLINTGAK FIELD PROJECT DESCRIPTION LOGISTICS AND COMMUNICATION
10.4.1 LOGISTICS
10.4.1.1 Scope
Logistical support plans for the operations phase of the Niglintgak project will be finalized during detailed engineering. These plans will include:
• transportation of personnel • transportation of equipment and materials • critical spare and routine consumables requirements • warehousing requirements • infrastructure
Other logistical support will include supporting major maintenance activities, well work and drilling activities concurrent with operations. Details of this logistical support will continue to be developed throughout ongoing engineering design activities.
10.4.1.2 Transportation
Normally, people will be transported into the Inuvik area by commercially available air transportation. The methods used to transport people from the Inuvik area to the Niglintgak gas conditioning facility will vary, depending on the season and level of activity. Staff will be transported to the Niglintgak gas conditioning facility by helicopter or ice road in winter. In summer, they will be transported by helicopter or barge. Transportation to the well pads will primarily be by helicopter. Transportation alternatives will be further evaluated throughout the Project Definition Phase.
Ice roads to Niglintgak will be required during the first few winters of the field’s life, when transportation will be key to supporting initial operations. Ice road access will also be considered in later years, when major winter maintenance activities, well drilling or major well work activities are planned.
Major supplies for the Niglintgak operations at the Inuvik area control centre and the Niglintgak gas conditioning facility will be transported during the summer by supply barge. Commercially available ground transportation will also be used to deliver freight to the Inuvik area.
August 2004 Shell Canada Limited 10-13 NDPA-P1 Section 10.4 OPERATIONS AND MAINTENANCE LOGISTICS AND COMMUNICATION
10.4.1.3 Warehousing
Warehouse storage for the Niglintgak operations will be provided at a warehousing centre in the Inuvik area. Storage will be required for:
• routine consumables • critical spare parts • long-lead-time items
The Niglintgak gas conditioning facility will also have storage for some parts and materials.
10.4.1.4 Infrastructure
The Niglintgak gas conditioning facility and each of the well pads will be designed for access by helicopter. Detailed design of the helicopter facilities will take into account the weather and seasonal conditions for the area.
The Niglintgak gas conditioning facility will be equipped with:
• living quarters • kitchen and recreation facilities • limited office space • a control room • supply barge docking and unloading facilities • a temporary refuge
Each of the well pads will be equipped with emergency shelters.
The Inuvik area control centre will contain office space, warehousing and a maintenance area. The office area will be used for maintenance and operations planning, safety meetings, employee training and business meetings. The maintenance area will be used for:
• repairing individual components
• calibrating and testing components
• staging tools and equipment before they are transported to the gas conditioning facility or well pads
Shell’s existing Camp Farewell facilities are expected to be used as a support base for certain drilling, well work and major maintenance activities. The camp will typically be used for storage and additional accommodation.
10-14 Shell Canada Limited August 2004 NDPA-P1 Section 10.4 OPERATIONS AND MAINTENANCE LOGISTICS AND COMMUNICATION
10.4.2 COMMUNICATION
10.4.2.1 Voice and Data Communication
A voice communication system among the Niglintgak gas conditioning facility, Inuvik and Calgary offices, as well as outside communication, will be installed. A voice radio system will be considered for communications among the well pads, the gas conditioning facility and, possibly, the Inuvik area control centre.
A data communication system will link the well pads, gas conditioning facility, Inuvik area control centre and Shell’s head office. The data system will provide these sites with:
• e-mail • production accounting data • financial accounting data • business data • production and operations monitoring data
August 2004 Shell Canada Limited 10-15 NDPA-P1 Section 10.5 OPERATIONS AND MAINTENANCE
APPLICATION FOR APPROVAL OF THE DEVELOPMENT PLAN FOR NIGLINTGAK FIELD PROJECT DESCRIPTION CONTROL AND MONITORING SYSTEMS
10.5.1 SYSTEM DESIGN
The control and monitoring system for the Niglintgak facilities will provide fully automated control, alarm, surveillance and emergency shutdown capability. The system design will:
• allow control from either the Inuvik area control centre or the Niglintgak gas conditioning facility
• support normally unattended operation of the Niglintgak gas conditioning facility
• provide remote, real-time equipment condition monitoring and process data
• use proven technology with known high reliability
• be capable of remote support for programming and diagnostics
10.5.2 REMOTE OPERATING AND MONITORING
The Niglintgak facilities will be designed to be operated and monitored remotely from the Inuvik area control centre when the facilities are unattended.
The control and monitoring system will be fail-safe. Communication loss between well pads, or the gas conditioning facility and Inuvik area control centre, will not result in an automatic shutdown of the operation. If communications are lost, all shutdown and safety systems will remain active and function, if required, without input from the control or monitoring system.
The control and monitoring system will include operator terminals at the gas conditioning facility and the Inuvik area control centre. These terminals can be used by operators to monitor and control the operation.
The control and monitoring system will automatically:
• monitor process and equipment parameters from the wells, well pad facilities, flow lines and gas conditioning facility
• monitor the status and condition of safety systems
August 2004 Shell Canada Limited 10-17 NDPA-P1 Section 10.5 OPERATIONS AND MAINTENANCE CONTROL AND MONITORING SYSTEMS
10.5.2 REMOTE OPERATING AND MONITORING (cont’d)
• electronically store the data for regulatory reporting and for equipment and process performance analysis
• initiate an alarm to alert the operations staff of a condition or event that requires attention, or if the required changes in operating parameters are outside allowable limits
• initiate an alarm if the control and monitoring system is not operating correctly
• initiate process and equipment shutdown
The control and monitoring system will also adjust specific operating parameters within established allowable limits. Operating parameters typically controlled by the control and monitoring system include:
• pressure • flow rate • temperature • level • operating speed • starting and stopping equipment • opening and closing valves
10.5.3 FLOW LINE CONTROL
The flow line system used to gather wet gas from the Niglintgak well sites consists of above-ground pipelines. A corrosion mitigation and inspection program will be developed and implemented for this system. Operating conditions of the flow lines will be monitored and controlled within allowable design limits. If required, chemicals for hydrate control and corrosion inhibition will be added and monitored.
Flow line operation and control will be one of the training topics for the Niglintgak operations staff.
10.5.4 LEAK MONITORING AND DETECTION
During detailed engineering, a leak detection plan for the Niglintgak facilities will be developed. For flow line leak detection, the plan will include monitoring by:
• pressure and flow monitoring systems and alarms • scheduled external visual inspection of the flow lines • scheduled external on-line inspection • condition-based scheduled internal inspection
10-18 Shell Canada Limited August 2004 NDPA-P1 Section 10.5 OPERATIONS AND MAINTENANCE CONTROL AND MONITORING SYSTEMS
The well pad facilities and the gas conditioning facility will be equipped with strategically placed hydrocarbon gas detection equipment. This equipment continuously monitors the area for hydrocarbon vapours and will alarm at concentrations well below hazardous levels.
Operations staff will be trained on and equipped with portable hydrocarbon gas detection equipment for use during maintenance and operations tasks.
Liquid leak detection systems and containment systems will be included in the well pad and gas conditioning facilities designs.
August 2004 Shell Canada Limited 10-19 NDPA-P1 Section 10.6 OPERATIONS AND MAINTENANCE
APPLICATION FOR APPROVAL OF THE DEVELOPMENT PLAN FOR NIGLINTGAK FIELD PROJECT DESCRIPTION ABANDONMENT AND RECLAMATION
10.6.1 SCOPE
The Niglintgak development will operate for about 25 years. When the area reserves are depleted, the development lands will be decommissioned and restored to a capability similar to the surrounding lands. The success of land remediation at the end of operations will depend on the success of reducing or remediating land disturbance that occurred during drilling, construction and operations.
Reclamation will be coordinated with construction activities to allow soils and disturbed materials to be managed properly. Where possible, the need for reclamation will be reduced by avoiding disturbing land in the first place.
The plan to decommission and reclaim the disturbed lands from the Niglintgak development includes:
• well pads • flow lines • the remote disposal sump • the gas conditioning facility
Abandonment and reclamation impacts have been considered in the development plan, and mitigation plans will continue to be developed during detailed design.
10.6.2 REGULATORY GUIDELINES
The Niglintgak development will be on crown land. Approvals to abandon and reclaim the lands will be required from INAC. NEB regulations and industry guidelines in place during construction and reclamation will be used to design the reclamation process.
10.6.3 DRILLING AREAS AND FLOW LINES
10.6.3.1 Well Abandonment
NEB regulations and industry guidelines will be used for well abandonment. Typically, the following procedure is used to decommission production and disposal wells:
August 2004 Shell Canada Limited 10-21 NDPA-P1 Section 10.6 OPERATIONS AND MAINTENANCE ABANDONMENT AND RECLAMATION
10.6.3.1 Well Abandonment (cont’d)
1. Install bridge plugs or cement squeezes to isolate all reservoir formation contacts. This will prevent materials from reaching the surface via the well.
2. Remove the wellheads.
3. Cut off the casings and conductor below ground surface.
4. Cap the casing with a steel plate and cement plug.
10.6.3.2 Well Pads
The well pads will be decommissioned by removing the structural steel and processing equipment. This material will be recycled or reused to the extent possible at the time of decommissioning, to reduce the need for disposal. Materials that cannot be reused or recycled will be removed to a suitable site and disposed of.
Steel support piles will either be cut off below ground and capped with native materials or pulled out of the ground.
Any disturbed soils will be graded and contoured to match existing landforms. Where feasible, granular material will be recycled and reused. Much of the low- lying areas of the Niglintgak field are subject to flooding and natural sedimentation, which will assist in site reclamation.
10.6.3.3 Remote Disposal Sump
A new remote disposal sump will be built off site at the start of each of the three winter drilling programs. This sump will be used to dispose of drilling cuttings and fluids. At the end of each drilling season, the sump will be capped, decommissioned and reclaimed. During operations, the drilling sump will be monitored to confirm its integrity, and any necessary remediation activities will be implemented and monitored.
10.6.3.4 Flow Line Reclamation
The above-ground flow lines for Niglintgak will be supported by vertical steel supports set into the permafrost. During reclamation activities, the above-ground portions of the flow lines, except for the supports, will be removed and the materials will either be recycled or reused elsewhere. The steel supports will either be cut off below ground and capped with native materials or pulled out of the ground.
Any below-ground flow lines, such as the Kumak Channel crossing section, will be abandoned in place. Before abandonment, the lines will:
• be purged and flushed to remove all hydrocarbons • have steel caps welded to either end to secure them
10-22 Shell Canada Limited August 2004 NDPA-P1 Section 10.6 OPERATIONS AND MAINTENANCE ABANDONMENT AND RECLAMATION
10.6.4 GAS CONDITIONING FACILITY
When operations are complete, the gas conditioning facility will be decommissioned. The gas conditioning facility will be excavated from its location in the Kumak Channel, refloated and towed out of the Mackenzie Delta area for recycling or disposal. Associated piping and equipment, such as the emergency shelter, bridge structures and structural piles, will be removed and recycled or disposed of off site. Disturbed ground associated with the gas conditioning facility will be contoured and restored. Where feasible, granular material will be recycled and reused.
August 2004 Shell Canada Limited 10-23 NDPA-P1 Section 11.1 SAFETY PLAN
APPLICATION FOR APPROVAL OF THE DEVELOPMENT PLAN FOR NIGLINTGAK FIELD PROJECT DESCRIPTION INTRODUCTION
11.1.1 HSE MANAGEMENT SYSTEM
Shell’s Health, Safety and Environment (HSE) management system (see Figure 11-1) provides the framework for managing all aspects of the development.
Leadership and Commitment
Policies and Objectives
Organization, Responsibilities, Resources, Standards and Guidelines
Hazards and Effects Management
Targets, Plans, Procedures Corrective Action and Practices
Implementation Monitoring
Corrective Action Audit and Improvement
Corrective Action Management Review and Improvement
Figure 11-1: HSE Management System Framework
The management system is a systematic approach, which is designed to:
• ensure compliance with the law • demonstrate that all hazards are adequately managed • achieve continuous improvement in HSE performance
August 2004 Shell Canada Limited 11-1 NDPA-P1 Section 11.1 SAFETY PLAN INTRODUCTION
11.1.1 HSE MANAGEMENT SYSTEM (cont’d)
This framework facilitates the structured management of HSE hazards and effects associated with the business, and ensures that mitigative methods are in place for properly controlling the hazards.
11.1.2 ISO BASIS
The management system is structured around the ISO standard framework of:
• plan • do • check • provide feedback
11-2 Shell Canada Limited August 2004 NDPA-P1 Section 11.2 SAFETY PLAN
APPLICATION FOR APPROVAL OF THE DEVELOPMENT PLAN FOR NIGLINTGAK FIELD PROJECT DESCRIPTION HSE PLAN FOR NIGLINTGAK
11.2.1 SCOPE
An HSE plan for the life of the Niglintgak field will be developed as the development progresses. The plan will include all activities that are within the context of the HSE management system.
11.2.2 LEADERSHIP AND COMMITMENT
Shell believes that strong and visible management leadership is critical for promoting a culture conducive to reducing risks. Shell requires that senior management provide a leading role towards constant HSE improvement through:
• visible leadership
• communicating the importance of HSE considerations in all business decisions
• communications with stakeholders
Management is expected to foster the active involvement of employees and contractors in improving HSE performance by encouraging a positive HSE culture through the following key beliefs in safety:
• The health and safety of people has first priority in achieving Shell’s excellence goals.
• All injuries and occupational illnesses can be prevented.
• Top management must be committed to safety excellence through visible personal involvement.
• Safety is an integral part of every job and every employee has a responsibility for safety.
Shell conducts annual employee surveys, and requests feedback on the company’s ability to provide a safe and healthy workplace.
August 2004 Shell Canada Limited 11-3 NDPA-P1 Section 11.2 SAFETY PLAN HSE PLAN FOR NIGLINTGAK
11.2.2 LEADERSHIP AND COMMITMENT (cont’d)
A solidly implemented HSE management system is an essential foundation for HSE performance. Continuous improvement will only be achieved when management fosters a culture in which business is conducted safely.
11.2.3 POLICIES AND OBJECTIVES
11.2.3.1 Policies
Management uses policies to communicate its intentions and expectations to employees, contractors and stakeholders. Policies and commitments to the policies are mandatory for all Shell business. Examples of policies that will be used for the Niglintgak field include Shell’s:
• Business Principles and Code of Ethics • Commitment to Sustainable Development and HSE Policy • Drug and Alcohol Policy • Corporate Security Policy • Respectful Workplace Policy
Within Shell, these policies are reviewed annually as part of the formal HSE management review.
11.2.3.2 Objectives
Shell establishes and maintains documented HSE objectives to reflect the company’s short and long-term aspirations. These objectives provide direction for setting targets and are articulated each year in the annual sustainable development report. HSE objectives that will be used for the Niglintgak field include:
• obtaining ISO 14001 registration for all major operating facilities
• protecting soil and groundwater through programs to reduce the potential for spills or leaks
• demonstrating the capability of responding effectively to all emergencies
• avoiding adverse HSE impacts on communities through careful management
11.2.4 PLAN ADMINISTRATION
11.2.4.1 Organization and Resources
The organization and associated resources will be developed to align with the requirements for each stage of the development. Any change to resource levels will be managed as part of the required change control procedure.
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11.2.4.2 Responsibilities and Competency
Within the Niglintgak field organization, all HSE responsibilities will be clearly indicated and all personnel will have adequate training to fulfill their responsibilities. HSE will be a project and operations organizational responsibility, with corporate HSE professionals providing support and advice.
HSE competency for all workers will be developed through a structured process that covers a broad range of requirements. The project will use many of Shell’s existing management and assurance processes that have been developed for similar assets, and worker competencies will be periodically reviewed to identify gaps. Shell’s Operations Training System will be the foundation for training and managing competency during the Operations Phase.
11.2.4.3 Contractor Management
One key to Shell’s success in HSE management is the performance of contractors, suppliers and others who work on the development and support the operations. Shell uses a contractor HSE management system to ensure a high quality of HSE qualification, selection and management. The key steps of the process are:
• qualification • selection • pre-job activities • work management • post-job evaluation • systems review
As part of the qualification step, Shell reviews each contractor’s HSE- management system to ensure that it aligns with Shell’s HSE management system. Expectations for, and clarity on, roles and responsibilities are critical to achieving an incident-free workplace. Shell will work with local contractors to enhance their HSE management systems to enable them to meet Shell’s HSE performance requirements and expectations.
11.2.4.4 Standards
Shell’s HSE management system requires that a number of standards be followed in implementing the plans. For the Niglintgak field, these standards include:
• incident management • emergency preparedness • journey management • task analysis • risk management • HSE safeguarding • system integrity
August 2004 Shell Canada Limited 11-5 NDPA-P1 Section 11.2 SAFETY PLAN HSE PLAN FOR NIGLINTGAK
11.2.4.5 Document Control
Shell’s HSE management system requires that document management and control be followed in implementing the plans. The critical documents for the Niglintgak field will be the HSE cases and performance data. The HSE plan will address how to update the HSE cases’ hazards and effects information as a result of:
• specified review cycles • job hazard analysis • emergency drills • inspections • incident analysis • a change in control or procedure • proactive safety measures
11.2.5 HAZARD AND EFFECTS MANAGEMENT
The HSE management system centres on identifying and managing all HSE hazards. The risk assessment process requires:
• the systematic identification of hazards
• an assessment of the associated risks
• an explicit determination of the controls necessary to manage those hazards and reduce the risks
Shell’s hazard and effects management process (see Figure 11-2) is composed of the following steps:
1. Systematically identify hazards, threats and their effects.
2. Assess the risks against specified screening criteria and ensure that it is as low as reasonably practicable (ALARP).
3. Record the significant hazards and effects in a risk register.
4. Implement suitable measures to reduce and control risks.
5. Plan for recovery if control is lost.
For the Niglintgak field, some of hazards that will be encountered are:
• extreme temperatures • long periods of darkness • travel, including by helicopter, boat and road • high-pressure hydrocarbons
11-6 Shell Canada Limited August 2004 NDPA-P1 Section 11.2 SAFETY PLAN HSE PLAN FOR NIGLINTGAK
Are people, environment, assets or company Identify reputation exposed to potential harm?
What are the causes and consequences? Assess How likely is loss of control? What is the risk and is it ALARP?
Can the causes be eliminated? Control What controls are needed? How effective are the controls?
Can the potential consequences or effects Recover be mitigated? What recovery measures are needed? Are recovery capabilities suitable and sufficient?
Figure 11-2: Hazard and Effects Management Process
Assessing the risks associated with these hazards:
• is fundamental to the management system • will be addressed throughout the HSE plan • will continue throughout the life of the project
Shell uses different risk tools, depending on the phase of the project and the information available. The emphasis in applying these tools is on adopting, where practicable, an inherently safe and minimal environmental impact approach. Some typical assessment tools that Shell will apply to the Niglintgak field are:
• HSE&SD assessments • hazard identification (HAZID) • environmental impact assessment (EIA) • socio-economic impact assessment (SEIA) • safeguarding analysis and review • hazard and operability review (HAZOP) • HSE cases
For any hazards assessed as significant, a detailed analysis of the risk will be undertaken. This will include identifying and assessing the controls necessary to reduce the risk to a level that is tolerable and ALARP.
The final step of managing hazards and effects is identifying and implementing any recovery measures required if a control does not function as planned. Although the focus is to implement necessary controls to adequately reduce the
August 2004 Shell Canada Limited 11-7 NDPA-P1 Section 11.2 SAFETY PLAN HSE PLAN FOR NIGLINTGAK
11.2.5 HAZARD AND EFFECTS MANAGEMENT (cont’d)
risk, contingency planning for recovery measures is a critical step in the management system.
A key deliverable of the HSE plan is the HSE case. The HSE case demonstrates that:
• there is an effective HSE management system in place
• the hazards and effects have been fully identified and are properly managed
• the asset has been designed and is being operated to meet specific health, safety and environmental standards
• the methods used to control hazards and manage the risks have been systematically identified, and appropriate knowledge, experience, controls and verification processes have been applied
• the identified controls and recovery methods are continually assessed and improved by a systematic program of performance monitoring, auditing and reviewing
• there is documentary evidence of all previous points
Figure 11-3 provides an example framework for an HSE case.
The HSE Case
Management Summary
Part 1 Part 2 Part 3 Part 4 Part 5 Part 6 Part 7 Introduction Description Operations Hazard HSE – Identified Conclusions of HSSD MS Analysis Critical Deficiencies Operations Activities Hazards and Remedial Effects Action Plan Register
Figure 11-3: HSE Case Structure
For the Niglintgak field development, Shell is committed to providing HSE cases for the following key risk activity areas:
11-8 Shell Canada Limited August 2004 NDPA-P1 Section 11.2 SAFETY PLAN HSE PLAN FOR NIGLINTGAK
• drilling • construction • operations
Drilling and construction HSE cases will be completed before field execution activities, which are currently planned for 2006. The operations HSE case will be developed on an ongoing basis throughout the design and construction activities and completed before initial operations, currently planned for 2009.
11.2.6 PLANS AND PROCEDURES
11.2.6.1 Purpose
As a part of the controls and recovery measures identified during the hazards and effects management process, specific plans and procedures will be developed.
These plans and procedures include process-related and management-related activities to address such items as:
• organization, roles and responsibilities • communication requirements • competence and training • asset integrity • change management • engineering controls
They will also include task-related activities to address such items as:
• adequacy of personnel resources to do the work • adequacy of equipment, tools and services for the work • adequacy of time available to perform the work safely • specific procedures and methodologies for performing the work safely
Many task level control requirements will be identified during the hazard assessments. The controls will be developed using knowledge and experience that Shell has developed for similar applications, and the best practices of the proven procedures used for other assets.
11.2.6.2 Contingency and Emergency Planning
Emergency response plans and procedures will be developed as part of the recovery step. Shell has a fully functioning system in place, for all its assets, that uses the following guiding principles to ensure effective emergency management:
• Create awareness of emergency situations, including the following details, and how they could arise from operations:
• what hazards exist
August 2004 Shell Canada Limited 11-9 NDPA-P1 Section 11.2 SAFETY PLAN HSE PLAN FOR NIGLINTGAK
11.2.6.2 Contingency and Emergency Planning (cont’d)
• what consequences can be expected • what level of response might be required • how operations can be returned safely to normal as soon as possible
• Develop an organization of teams and individuals that have clearly defined responsibilities for implementing an emergency response.
• Develop and define procedures that will deliver an effective and appropriate level of response, including mobilization and contingency plans for specific response situations.
• Conduct training, practice and review activities.
The emergency response plan for Niglintgak will include the following:
• organization, responsibilities, authorities and procedures for emergency response and disaster control, including maintaining internal and external communications
• systems and procedures for preventing, reducing and monitoring environmental effects of emergency actions
• procedures for communicating with authorities, communities, relatives and other affected parties
• systems and procedures for mobilizing third-party resources for emergency support
• arrangements for training response teams and for testing emergency systems and procedures through developed scenarios and drills
The specific emergency response plans for Niglintgak will consider all emergency situations, including:
• fire and explosion • failure of key controls, such as loss of well control • structural failures • work-site injuries • aviation incidents • person overboard • spills and loss of containment • security breaches • floods
Incorporated in the Niglintgak design will be emergency response measures and equipment, such as:
• emergency shutdown systems
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• fire-fighting devices • spill clean-up systems and services • specialist medical treatment available for remote locations • emergency evacuation procedures • rescue craft • first aid equipment, and trained personnel available
11.2.6.3 Security Planning
For construction and operations, Niglintgak will implement a site security system that conforms to Shell’s corporate security policy and procedures. This system will include the security of people and physical and intellectual property, and will be part of the site construction and operations procedures.
Once the facilities are operational, they will be equipped with a security and surveillance system, and with appropriate remote monitoring and alarm capabilities.
11.2.7 MONITORING AND PERFORMANCE REPORTING
11.2.7.1 Monitoring
Shell will develop and maintain procedures for monitoring relevant aspects of HSE performance and for establishing and maintaining records of the performance results. Monitoring includes:
• active monitoring, which includes:
• information in the absence of any incident • progress against plans • reviewing the effectiveness of the HSE management system • proactive safety measures • job observation
• reactive monitoring, which provides information on incidents, including near miss incidents, and insights for future prevention
The monitoring aspects of the Niglintgak HSE plan include:
• regularly monitoring progress towards objectives and targets
• regularly inspecting, according to specific performance criteria, the facilities, plant and equipment
• regularly analyzing discharges, emissions and waste disposal
• systematically observing the work practices and behaviours of workers to assess compliance with procedures and instructions
August 2004 Shell Canada Limited 11-11 NDPA-P1 Section 11.2 SAFETY PLAN HSE PLAN FOR NIGLINTGAK
11.2.7.1 Monitoring (cont’d)
• monitoring the health and medical condition of workers
• monitoring HSE critical activities and processes in alignment with the HSE cases
11.2.7.2 Incident Reporting and Investigation
Niglintgak will maintain an incident database on HSE performance in alignment with Shell standards. The project will contribute to and use a database that will share relevant information from Shell and industry incidents to help avoid recurrences. All workers will be required to follow incident reporting standards and procedures. All HSE incidents and near misses with significant actual or potential consequences will be thoroughly investigated and reported. Any unsafe conditions or unsafe practices that are identified will be immediately stopped until corrected.
The immediate circumstances of the incident and the underlying management system’s failures that caused, or contributed to, the incident will be identified in the incident investigation. The procedures for incident investigation are well developed within Shell. All incidents and high-potential-consequence near misses require an appropriate investigation and report to:
• ensure that the full requirements for investigating and reporting are met
• establish the root cause, and identify the required actions to reduce the chance of recurrence
• enable the action plan to be monitored to ensure that it is completed promptly
• provide a factual record of the incident and the recommended actions
• ensure that key findings are shared to prevent recurrence
11.2.8 AUDIT, MANAGEMENT REVIEW AND CORRECTIVE ACTION
Corrective action and improvement are critical components in verifying that the management system is working and identifying areas for improvement. The HSE plan will schedule formal audits, regular monitoring and measurement, and structured management reviews to ensure the continuing suitability, adequacy and effectiveness of the management system. These reviews and audits will incorporate any HSE concerns of employees, contractors and external stakeholders.
Niglintgak will be scheduled in the regular internal HSE audit cycle for Shell, as these audits are valuable in providing input on key areas for improvement, leading to progressively better HSE management. A protocol exists within Shell for documenting audit results and remedial action plans that will be followed for Niglintgak.
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As with all Shell operations, Niglintgak will have the environmental management system component of the HSE management system registered under ISO 14001. External auditors will verify compliance with the ISO 14001 requirements for environmental management systems. In addition, external auditors will periodically verify HSE data.
August 2004 Shell Canada Limited 11-13 NDPA-P1 Section 12.1 PUBLIC CONSULTATION
APPLICATION FOR APPROVAL OF THE DEVELOPMENT PLAN FOR NIGLINTGAK FIELD PROJECT DESCRIPTION INTRODUCTION
12.1.1 BACKGROUND
Shell has had a long and positive relationship with the people of the Inuvialuit Settlement Region and Gwich’in Settlement Area. Shell first became active in the Mackenzie Delta with exploration activities in the 1960s. Over the past 40 years Shell has invested over $500 million (2003$) in exploration activities in northern Canada. Through this extended period of activity, Shell has consulted extensively with stakeholders. Shell will build on these existing relationships to understand and respond to any concerns raised about the proposed development at Niglintgak.
Development plans for Niglintgak have involved assessing several options to best fit the constraints at the field location. Most of the shallow (700 to 1,000 m), compartmentalized reservoir lies below the Middle Channel of the Mackenzie River. This presents drilling challenges to access all of the reservoir. Drilling and production will occur from three surface locations that have been chosen next to previously disturbed exploration drilling locations. The field production will be delivered by above-ground flow lines to a gas conditioning facility, which will dehydrate (dry), compress and cool the gas to gathering system specifications. Shell has evaluated both the proposed barge-based option and a land-based alternative option for siting the gas conditioning facility.
12.1.2 CONSULTATION POLICY AND PRINCIPLES
Shell believes that working with stakeholders is a key principle in its commitment to sustainable development (SD).
Shell’s commitment to sustainable development includes being guided by key sustainable development principles, several of which apply directly to how the company relates to its stakeholders:
• Respect and safeguard people – we aim to treat everyone with respect. We strive to protect people from harm from our products and operations.
• Benefit communities – wherever we work we are part of a local community. We will constantly look for appropriate ways to contribute to the general well being of the community and the broader societies who grant our licence to operate.
August 2004 Shell Canada Limited 12-1 NDPA-P1 Section 12.1 PUBLIC CONSULTATION INTRODUCTION
12.1.2 CONSULTATION POLICY AND PRINCIPLES (cont’d)
• Work with stakeholders – we affect, and are affected by, many different groups of people, our stakeholders. We aim to recognize their interest in our business and to listen and respond to them.
Shell’s HSE policy is also relevant to stakeholder relations, as it states in part that Shell will:
• publicly report on its performance and engage in stakeholder consultation
• manage health, safety and environment as any other critical business activity and promote a culture in which all Shell employees share this commitment
• set targets for improvement and measure, appraise and report performance
• strive to achieve a health, safety and environmental performance of which we are proud, to earn the confidence of our customers, shareholders and society at large, to be a good neighbour and to contribute to sustainable development
12.1.3 NIGLINTGAK CONSULTATION PLAN
In preparation for Niglintgak consultation activities, a plan was developed to organize and align Shell’s consultation needs for the Niglintgak development with other ongoing Shell activities within the Mackenzie Delta region. The intent was to coordinate consultation associated with ongoing exploration and reclamation work with the current project efforts, in order to improve the effectiveness of Shell’s communication with stakeholders. To achieve this integration, Shell developed a coordinated consultation plan for all of its activities in the Mackenzie Delta region.
The goals of the consultation plan are to:
• foster and maintain good relationships with stakeholders and respect the land, environment and cultures of Aboriginal and non-Aboriginal people of the North
• build good relationships with any new stakeholders identified
• gain knowledge and develop understanding of stakeholder activities and issues to enhance development of the project plans, to seek synergies and to find win-win solutions to resolve issues
• meet or exceed regulatory requirements and achieve timely approvals in a manner consistent with Shell’s health, safety and sustainable development (HSSD) principles
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• ensure continuity, where possible, and coordination with other industrial activity in the Mackenzie Delta region. This includes activities by Shell, other oil and gas operators, and other industries.
12.1.4 CONSULTATION STRATEGY AND APPROACH
In addition to coordinating the Niglintgak development with other Shell activities, the Niglintgak consultation process was coordinated with the consultation activities of the Mackenzie Gas Project. This coordinated approach was used as many key aspects of the Niglintgak development are tied to the overall Mackenzie Gas Project, including the regulatory regime and the common Mackenzie Gas Project Environmental Impact Statement (EIS).
Two main series of consultation activities were initiated:
1. The first series of consultations was organized and implemented by the environmental consultants for the Mackenzie Gas Project, to fulfill the public participation requirements for the EIS, including:
• the biophysical and socio-economic baseline • mitigation and assessment information, including traditional knowledge
2. The second series of consultations was organized by the Mackenzie Gas Project staff to consult with stakeholders on developing project details and activities. For details of these consultations, including the main consultation documentation for Niglintgak, see the Mackenzie Gas Project Public Consultation Program, a copy of which has been filed with this application.
In addition to these consultation efforts, Niglintgak-specific field initiatives were organized to supplement the main Mackenzie Gas Project consultation activities. The Niglintgak-specific consultations conducted by Shell consisted of:
• several rounds of consultation with the public
• specific and informal meetings with Inuvialuit Settlement Region groups, regulatory agencies, non-government organizations (NGOs) and individuals
12.1.5 CONSULTATION ACTIVITIES
Table 12-1 summarizes the consultation activities that are either Niglintgak- specific or where Niglintgak personnel were included as part of the broader Mackenzie Gas Project consultations.
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Table 12-1: Niglintgak Project Definition Consultation Meetings
Date Meeting Type Topic Stakeholders June 19, 20, 21, 22, Community Various meetings in the communities (Fort Community members, 23, 24, 25, 2001 meetings and McPherson, Tsiigehtchic, Aklavik, Tuktoyaktuk Hunters and Trappers informal and Inuvik) to review Shell’s winter exploration Committee, community conversations plans. corporations and Elders Committee June 21, 2001 Meeting Discussed what would be needed to have the Vince Steen – Minister, government attempt to get ice roads up to GNWT specification earlier in the year. Gurdev Jagpal – Ministry of Transport Ron Anderson – Anderson Exploration Russel Newmark – E. Gruben’s Transport Ltd. Dick Hekkinen – PetroCanada June 22, 2001 Meeting Meeting at Inuvik Petroleum Show. Discussed Nellie Cournoyea helipad plans for the proposed new hospital. Lyle Neis June 22, 2001 Informal Meeting at Inuvik Petroleum Show. Discussed Clayton Gordon conversation contracting opportunities for future Shell work. June 22, 2001 Tour Flew from Inuvik to sumps in the delta at the Brian Hepple request of Environment Canada, to review Todd Paget some work that had been done by Steve Kokel Steve Kokel for Environment Canada. Dawn Ostrem – Drum reporter June 23, 2001 Informal Discussed with NGTL the capacity of its Rick Connors conversation system and the probable need for it to be upgraded. June 26, 2001 Meeting Met with Indian and Northern Affairs Canada Rudy Cockney personnel and reviewed winter 2001/2002 Rob Walker exploration plans. Conrad Baetz July 11, 2001 Telephone Called Tsiigehtchic Band office and spoke to James Cardinal conversation James Cardinal. July 25, 2001 Meeting Reviewed winter 2001/2002 exploration plans. Scott Gallupe Conrad Baetz July 26, 2001 Meeting Met with Chief and some council members at Abe Wilson Fort McPherson. Discussed winter exploration Robert Alexi Sr. and upcoming pipeline and field development Johnnie Charlie issues, including social issues. July 26, 2001 Meeting Met with Band Manager at Tsiigehtchic and Trefor Gates discussed industry operations. July 26, 2001 Meeting Met with chief financial officer for Inuvialuit Wilf Blonde Regional Corporation and discussed issues dealing with meetings in the Deh Cho next week, as well as consultation and the awarding of environmental contracts. July 27, 2001 Meeting Discussed APG involvement at negotiating Nellie Cournoyea table with Deh Cho. Wilf Blonde July 27, 2001 Meeting Met with Lyle Neis and discussed the hospital Lyle Neis helipad idea.
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Table 12-1: Niglintgak Project Definition Consultation Meetings (cont’d)
Date Meeting Type Topic Stakeholders July 27, 2001 Meeting Discussed contracting opportunities. Tom Zubko July 28, 2001 Tour Overflight of 2001/2002 winter exploration Richard Tardiff project. Jacob Archie July 28, 2001 Informal Discussed winter project application process. Conrad Baetz – Indian meeting and Northern Affairs Canada Felix Horne – Inuvialuit Land Administration July 31, 2001 Telephone Discussed emergency medical support for Rick Turner – National conversation winter projects. Energy Board September 17, 2001 Telephone Discussed contracting opportunities and joint Billie Archie – Aklavik conversation ventures. September 18, 2001 Telephone Discussed possible contracting opportunities. Wayne Gordon – conversation Aklavik September 20, 2001 Telephone Discussed possible contracting opportunities. Richard Storr – Aklavik conversation September 21, 2001 Telephone Discussed possible contracting opportunities. Dennis Arey – Aklavik conversation Hunters and Trappers Committee September 24, 2001 Telephone Discussed possible contracting opportunities. Albert Adams – Inuvik conversation September 25, 2001 Telephone Discussed possible synergies for winter Ed Fercho – Japex conversation projects. September 25, 2001 Telephone Job descriptions for wildlife monitors discussed Dennis Arey – Aklavik conversation – Inuvialuit Environmental and Geotechnical to Hunters and Trappers follow up. Committee September 25, 2001 Telephone Discussed drilling plans for upcoming winter Pete Cott – conversation project. Department of Fisheries and Oceans September 27, 2001 Telephone Discussed arctic operations, such as hours Rick Turner – National conversation and medics. Energy Board September 27, 2001 Telephone Discussed post job clearances. Felix Horne – Inuvialuit conversation Land Administration September 28, 2001 Telephone Discussed economic opportunities, tender and Tanya Skones – conversation bidding procedures. Tuktoyaktuk October 10, 2001 Telephone Discussed Canada Labour Code – Part II and Rick Turner – National conversation III. Energy Board October 10, 2001 Telephone Discussed possible contracting opportunities. Billie Archie – Aklavik conversation October 23, 2001 Meeting Discussed management plan for Kendall Industry members and Island Bird Sanctuary. Canadian Wildlife Service representatives January 14, 2002 Informal Discussed permitting processes with Russell Russell Newmark conversation Newmark from E. Gruben’s Transport Ltd., and the need to streamline them to allow quicker reaction times.
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Table 12-1: Niglintgak Project Definition Consultation Meetings (cont’d)
Date Meeting Type Topic Stakeholders February 18, 2002 Meeting Meetings with Inuvialuit Regional Corporation, Nellie Cournoyea, Gwich’in Tribal Council and a public meeting in Inuvialuit Regional Inuvik to discuss primarily the winter Corporation exploration projects, but some contracting Fred Carmichael, opportunities for future work were also Gwich’in Tribal Council discussed. Wilbert Firth, Gwich’in Tribal Council Barry Greenland, Nihtat Members of the public February 20, 2002 Public meeting Tsiigehtchic meeting to review winter Peter Ross – Chief exploration work and safety issues, as well as Mavis Clarke some concern over pipeline routing selection. Would like route to be discussed with the Members of public community in more detail. February 20, 2002 Band council Discussed winter work, as well as future Council members and meeting developments, and the issues that will almost support staff certainly be a part of them, such as drugs and alcohol and the lack of banking services. February 20, 2002 Hamlet council Discussed employment, training, traditional Rebecca Blake – meeting knowledge, and business opportunities with Mayor members of the hamlet council. Brian Alexi February 21, 2002 Public meeting Discussed winter work, as well as future Evelyn Storr – Mayor developments, and some of the confusion that Alex Ilisiak – Inuvialuit the competing pipeline proposals are causing Land Administration in the community. commissioner Member of public February 22, 2002 Meeting SHARE meeting in Inuvik. Discussed the need Northern Contractors for common safety standards and the Explorer group difficulties that different standards foster. companies March 27, 2002 Meeting Met with Inuvialuit Regional Corporation board Nellie Cournoyea members and staff. Discussed winter Roger Connelly exploration work as well as upcoming Niglintgak development plans. June 3, 2002 Meeting Commercial Discovery Declaration Application. National Energy Board, Terry Baker June 11, 2002 Public meeting Mackenzie Gas Project update and review in Community members Aklavik. and organizations June 12, 2002 Public meeting Mackenzie Gas Project update and review in Community members Inuvik. and organizations June 13, 2002 Public meeting Mackenzie Gas Project update and review in Community members Tsiigehtchic. and organizations June 13, 2002 Public meeting Mackenzie Gas Project update and review in Community members Sach’s Harbour. and organizations June 14, 2002 Public meeting Mackenzie Gas Project update and review in Community members Holman. and organizations June 14, 2002 Meeting Inuvialuit Game Council meeting – Mackenzie Inuvialuit Game Gas Project update and review. Council members and the chairs of some co- management boards
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Table 12-1: Niglintgak Project Definition Consultation Meetings (cont’d)
Date Meeting Type Topic Stakeholders June 14, 2002 Public meeting Mackenzie Gas Project update and review in Community members Holman. and organizations June 17, 2002 Meeting Tuktoyaktuk Hunters and Trappers Committee. Tuktoyaktuk Hunters and Trappers Committee members June 17, 2002 Public meeting Mackenzie Gas Project update and review in Community members, Tuktoyaktuk. Hunters and Trappers Committee and Elders Committee June 20, 2002 Conference Inuvik Petroleum Show. July 15, 2002 Public meeting Meeting in Tuktoyaktuk to review winter Public exploration plans, and some minor questions on production operations and timing, as well as routing. Reviewed some Niglintgak plans. July 24, 2002 Telephone Discussed possible contracting opportunities. Frank Hansen conversation July 24, 2002 Telephone Discussed possible contracting opportunities. Sean McCarthy conversation July 31, 2002 Telephone Discussed the requirement for piles and the James Firth – Chief conversation ability of the Gwich’in to supply wooden piles Nihtat Gwich’in Band – as they have done in the past. Inuvik September 30, 2002 Telephone Discussed probable winter work and update on Ian Butters – conversation future plans. Resources, Wildlife and Economic Development October 15, 2002 Telephone Discussed possible community investment in Peter Clarkson – conversation new family centre. Mayor – Inuvik October 18, 2002 Meeting Beaufort Sea integrated management plan Department of initiative. Fisheries and Oceans, Doug Chernisak, Kelly Cott October 22, 2002 Meeting Mackenzie Gas Project EIS applications and Northern Pipeline Cooperation Plan update. Regulators Committee October 23, 2002 Meeting Mackenzie Gas Project update, regulatory Northern Pipeline process, Deh Cho consultation. Regulators Committee October 30, 2002 Meeting Kendall Island Bird Sanctuary. Chevron, Imperial Oil Resources Limited, Anadarko November 4, 2002 Meeting Joint field development update and review. Teachers November 4, 2002 Meeting Joint field development update and review with Gwich’in Tribal Council and Development Corporation. November 4, 2002 Meeting Inuvik Native Band and Nihtat Gwich’in update and review of field developments. November 5, 2002 Meeting Meeting with Inuvik-based regulators to review Department of and update on field development proposals. Fisheries and Oceans, Inuvialuit Land Administration, Indian and Northern Affairs
August 2004 Shell Canada Limited 12-7 NDPA-P1 Section 12.1 PUBLIC CONSULTATION INTRODUCTION
Table 12-1: Niglintgak Project Definition Consultation Meetings (cont’d)
Date Meeting Type Topic Stakeholders November 5, 2002 Canada, Joint (cont’d) Secretariat, Gwich’in Renewable Resource Board, Resources, Wildlife and Economic Development, Fisheries Joint Management Committee November 5, 2002 Workshop with Meeting with Inuvik-based regulators to review Hunters and Trappers local regulators and update on field development proposals. Committee, community corporations, Elders Committee, Nihtat Renewable Resource Council, Gwich’in Tribal Council, Inuvik Band, Royal Canadian Mounted Police, Department of Fisheries and Oceans, Resources, Wildlife and Economic Development November 5, 2002 Public meeting Joint field development update and review. Inuvik public November 6, 2002 Workshop Review and update on field development Aklavik Hunters and proposals with community-based Trappers Committees, organizations. Elders, community corporations, Renewable Resource Council, Band representatives November 6, 2002 Public meeting Joint field development update and review. Aklavik community members and workshop attendees November 7, 2002 Meeting Joint field development update and review. Aklavik teachers and students November 7, 2002 Meeting Joint field development update and review. Inuvialuit Land Administration staff Tuktoyaktuk November 7, 2002 Meeting Presentation on joint field development Teachers and students proposals and tour of school. Tuktoyaktuk November 7, 2002 Luncheon Joint field development update and review and Tuktoyaktuk Hunters meeting lunch. and Trappers Committees, community corporations, Elders November 8, 2002 Workshop Joint field development update and review. Tuktoyaktuk Hunters and Trappers Committees, community corporations, ECs November 8, 2002 Public meeting Joint field development update and review. Tuktoyaktuk community members
12-8 Shell Canada Limited August 2004 NDPA-P1 Section 12.1 PUBLIC CONSULTATION INTRODUCTION
Table 12-1: Niglintgak Project Definition Consultation Meetings (cont’d)
Date Meeting Type Topic Stakeholders November 20, 2002 Meeting Deh Cho process update. Robin Aitken, DIAND December 10, 2002 Meeting DPA/CDD, COGOA requirements, level of National Energy Board, detail expected, DPA process. Terry Baker, John Korec January 7, 2003 Meeting Drilling waste management. DIAND Yellowknife January 8, 2003 Meeting Kendall Island Bird Sanctuary, Mackenzie Gas CWS, Kevin Project update, Taglu and Niglintgak update, McCormick, Jim Hines, footprint expectations. Lynn Hjorsten – Justice Canada, Paul LaTour – CWS January 9, 2003 Meeting Benefits plans, access. Jim Antoine, Minister Resources, Wildlife and Economic Development January 20, 2003 Informal Discussed APG funding and the spin-off Roger Connelly – conversation benefits of the pipeline. Inuvialuit Regional Corporation January 20, 2003 Informal Discussed developments. Roger Connelly conversation January 20, 2003 Informal Discussed donation strategy and Fort Victor Stewart conversation McPherson requirements with recreation coordinator. January 21, 2003 Informal Discussed a proposal that he would be Abe Wilson – Chief – conversation presenting at an upcoming meeting. Fort McPherson January 22, 2003 Informal Discussed challenges in the education system Effie McLeod – conversation and explored some options for Shell helping Beaufort Delta out with those challenges. Education Council January 22, 2003 Meeting Devolution in the Northwest Territories. Kellie Voutier, DIAND, Brian Dominique January 23, 2003 Informal Discussed winter activity in the Tsiigehtchic Peter Ross – Chief – conversation region and the business opportunities that it is Gwichya Gwich’in creating. January 24, 2003 Informal Discussed Travaillant Lake and the need to Trefor Gates – conversation consult in the community. Would like to have Tsiigehtchic Band information as far in advance of meetings as Office possible so that they can formulate questions. February 4, 2003 Meeting Cooperation Plan update, regulatory Northern Pipeline processes. Regulators Committee (Cooperation Plan Working Group) February 6, 2003 Meeting Review Niglintgak proposal with Aklavik band Charlie Furlong – Chief representatives. Knute Hansen – COO Robert Buckle – Mackenzie Gas Project representative, and community worker February 9, 2003 Public meeting Project update in Fort McPherson with all field Fort McPherson public development
August 2004 Shell Canada Limited 12-9 NDPA-P1 Section 12.1 PUBLIC CONSULTATION INTRODUCTION
Table 12-1: Niglintgak Project Definition Consultation Meetings (cont’d)
Date Meeting Type Topic Stakeholders February 10, 2003 Public meeting In Tsiigehtchic with anchor field developers Community members and Mackenzie Gas Project representatives. Tsiigehtchic February 11, 2003 Workshop Joint field development review and update and Tuktoyaktuk workshop in Tuktoyaktuk. community corporations, Elders Committee and Hunter and Trappers Committee members February 11, 2003 Public meeting Joint field development update and review. Tuktoyaktuk public February 12, 2003 Workshop Joint field development review and update and Inuvik community workshop in Inuvik. corporations, Elders Committee, and Hunter and Trappers Committee members, and representatives from Gwich’in Tribal Council, Nihtat Gwich’in, Department of Fisheries and Oceans, Resources, Wildlife and Economic Development, and Indian and Northern Affairs Canada February 12, 2003 Public meeting Joint field development update and review in Inuvik community Inuvik. members February 13, 2003 Meeting Discussed plans for a youth conference. Barry Greenland – Sub-chief Nihtat Gwich’in Band February 13, 2003 Meeting Review recent community visits with Inuvialuit Nellie Cournoyea Regional Corporation. Roger Connelly February 13, 2003 Meeting Niglintgak update. Nellie Cournyea Roger Connelly March 6, 2003 Meeting Kendall Island Bird Sanctuary. K. McCormick, CWS March 7, 2003 Meeting World Wildlife Fund and PAS interests. Peter Ewins – World Wildlife Fund March 19, 2003 Conference Career Quest – Beaufort Delta Education School children Council career fair. Public March 19, 2003 Meeting Met with Indian and Northern Affairs Canada Rudy Cockney over previous winter projects but discussed the Conrad Baetz application process for the Mackenzie Gas Dan Carmichael Project and the Niglintgak development. March 21, 2003 Meeting Met with Supervisor of Schools at Beaufort Effie McLeod Delta Education Council and discussed the Aboriginal resource kits that Shell is supplying to schools to assist in teaching about Aboriginal issues in Canada. April 8–9, 2003 Workshop EIS issues scoping. Inuvialuit Settlement Region, GSA invitees
12-10 Shell Canada Limited August 2004 NDPA-P1 Section 12.1 PUBLIC CONSULTATION INTRODUCTION
Table 12-1: Niglintgak Project Definition Consultation Meetings (cont’d)
Date Meeting Type Topic Stakeholders April 29, 2003 Informal Discussed, in general terms, the opportunities Nellie Cournoyea conversation that should be brought to the region by the development and the industry in general. May 7, 2003 Meeting Regulatory applications in Inuvialuit Settlement Inuvialuit Land Region. Administration – Calvin Pokiak June 18, 2003 Meeting Canada Benefits Plan. Indian and Northern Affairs Canada, Fortier, Greenall, Graw June 18, 2003 Meeting Project update, Inuvialuit Land Administration James Thorburne – perspectives, granular resources. Inuvialuit Land Administration June 18, 2003 Conference Inuvik Petroleum Show. June 20, 2003 Meeting Northern benefits. Inuvik – Inuvialuit Regional Corporation, Inuvialuit Land Administration, Roger Connelly, Gerry Roy, James Thorburne July 17, 2003 Meeting COGOA applications, EIS and permits. National Energy Board Mieke van der Valk, John Korec, Bonnie Grey, Calgary July 30, 2003 Telephone Discussed regional skills program with some Effie McLeod conversation kind of mobile set-up to bring hands-on experience to the accessible communities. August 19, 2003 Telephone Discussed upcoming visit and purpose. Roger Connelly conversation August 19, 2003 Telephone Discussed upcoming visit and purpose. Fred Carmichael conversation September 8, 2003 Meeting Project update, regulatory classification. National Energy Board, COGOA, Terry Baker September 11, 2003 Meeting Project update, Cooperation Plan. Cooperation Plan Working Group, Calgary September 15, 2003 Meeting Project update, Cooperation Plan. Cooperation Plan Working Group, Calgary September 23, 2003 Meeting Project update, barge option. Environmental Impact Screening Committee, Inuvik October 22, 2003 Meeting Project update, GNWT interests. Joe Handley – GNWT Minister of Finance, Celina Stroeder – ADM, Resources, Wildlife and Economic Development October 22, 2003 Meeting Project update, Kendall Island Bird Sanctuary Canadian Wildlife issues. Service – Kevin McCormick, Bruce MacDonald
August 2004 Shell Canada Limited 12-11 NDPA-P1 Section 12.1 PUBLIC CONSULTATION INTRODUCTION
Table 12-1: Niglintgak Project Definition Consultation Meetings (cont’d)
Date Meeting Type Topic Stakeholders October 22, 2003 Meeting Cooperation Plan coordination. Northern Gas Pipeline Secretariat – Brian Chambers October 22, 2003 Meeting Project update, Inuvialuit Regional Corporation Ross McDonald perspective. Inuvialuit Regional Corporation, John Steen, Gerry Roy, Dennis Lennie, Rob Duncan, Roger Connelly, Frank Hansen October 23, 2003 Meeting Project update, Town of Inuvik perspective. Peter Clarkson – Mayor of Inuvik October 23, 2003 Meeting Project update, Gwich’in Tribal Council Grant Sullivan, Mary perspective. Ann Ross, Joe Benoit, Brian McCarthy, Elinor Firth, Gwich’in Tribal Council members October 27, 2003 Workshop Joint field development review and update. Community Workshop. corporations, Elders Committee, and Hunter and Trappers Committee members, and representatives from the Nihtat Renewable Resource Council and council October 27, 2003 Public meeting Joint field development review and update. Inuvik public October 28, 2003 Meeting Met with folks at Moose Kerr School in Aklavik. Aklavik students and teachers October 28, 2003 Workshop Joint field development review and update. Aklavik Community Workshop. corporations, Elders Committee, and Hunter and Trappers Committee members, and representatives from the Ehdiitat Renewable Resource Council and council October 28, 2003 Public meeting Joint field development review and update. Aklavik public October 29, 2003 Workshop Joint field development review and update. Tuktoyaktuk Workshop. Community Corporations, Elders Committee and Hunter and Trappers Committee members October 29, 2003 Public meeting Joint field development review and update. Tuktoyaktuk public November 9, 2003 Meeting Update Inuvialuit Regional Corporation chair Nellie Cournoyea on community visits and workshops.
12-12 Shell Canada Limited August 2004 NDPA-P1 Section 12.1 PUBLIC CONSULTATION INTRODUCTION
Table 12-1: Niglintgak Project Definition Consultation Meetings (cont’d)
Date Meeting Type Topic Stakeholders January 9, 2004 Teleconference Beaufort Delta Education Council YELS Oil Effie McLeod and Gas Program Steering Committee Austin Abbott meeting. Ken Jacobsen Brian Plesuk Jacqueline McArthur January 9, 2004 Wayne Ross (cont’d) Brian McCosham Mike Walsh January 12, 2004 Telephone Discussed Shell’s donation strategy. Alestine Andre – conversation Tsiigehtchic resident January 17, 2004 Informal Discussed future developments in general Floyd Roland conversation terms. January 20, 2004 Informal Discussed development and political Nellie Cournoyea conversation developments in the Inuvialuit Settlement Region, as well as past exploration activities. February 2, 2004 Workshop Discussed barge option. Inuvialuit Game Council, Elders, Hunters and Trappers Committee, community corporations from all Inuvialuit Settlement Region communities February 9, 2004 Public meeting Joint meeting with all field developers and Inuvik public some Mackenzie Gas Project representatives. March 16, 2004 Informal Discussed bathymetry program and possibility Roger Connelly conversation of dredging in Beluga 1A zones and the likely reaction to that course of action. March 17, 2004 Conference Career Quest – Beaufort Delta Education Public Council career fair. Albert Elias – Inuvialuit Land Administration commissioner April 19, 2004 Workshop Review the barge option, as well as benefits, Aklavik – members of sumps and drilling. community corporations, Hunters and Trappers Committee, and Elders Committee April 19, 2004 Public meeting Review the barge option, as well as benefits, Aklavik public sumps and drilling. April 20, 2004 Workshop Review the barge option, as well as benefits, Tuktoyaktuk – sumps and drilling. members of community corporations, Hunters and Trappers Committee, and Elders Committee April 20, 2004 Public meeting Review the barge option, as well as benefits, Tuktoyaktuk public sumps and drilling
August 2004 Shell Canada Limited 12-13 NDPA-P1 Section 12.1 PUBLIC CONSULTATION INTRODUCTION
Table 12-1: Niglintgak Project Definition Consultation Meetings (cont’d)
Date Meeting Type Topic Stakeholders April 22, 2004 Workshop Workshop to review the barge option, as well Inuvik – members of as benefits, sumps and drilling. community corporations, Hunter and Trappers Committee, and Elders Committee April 22, 2004 Public meeting Review the barge option, benefits, sumps and Inuvik public drilling. April 23, 2004 Meeting Review community visits, presentations and Nellie Cournoyea input from stakeholders. Roger Connelly Gerry Roy June 22, 2004 Publicity Project update, winter work, summer work Paulatuk public programs. June 22, 2004 Workshop Winter work, summer work plans and project Paulatuk Hunters and update. Trappers Committee, Elders and community corporations June 24, 2004 Public meeting Project update, winter work, summer work Sachs Harbour public programs. June 24, 2004 Workshop Project update, winter work, summer work Sachs Harbour Hunters programs. and Trappers Committee, Elders and community corporations June 25, 2004 Public meeting Project update, winter work, summer work Tsiigehtchic public programs. June 25, 2004 Workshop Project update, winter work, summer work Tsiigehtchic Hunters programs. and Trappers Committee, Elders and community corporations July 5, 2004 Public meeting Project update, winter work, summer work Inuvik public programs. July 5, 2004 Workshop Project update, winter work, summer work Inuvik Hunters and programs. Trappers Committee, Elders and community corporations July 6, 2004 Public meeting Project update, winter work, summer work Tuktoyaktuk public programs. July 6, 2004 Workshop Project update, winter work, summer work Tuktoyaktuk Hunters programs. and Trappers Committee, Elders and community corporations July 7, 2004 Public meeting Project update, winter work, summer work Aklavik public programs. July 7, 2004 Workshop Project update, winter work, summer work Aklavik Hunters and programs. Trappers Committee, Elders and community corporations
12-14 Shell Canada Limited August 2004 NDPA-P1 Section 12.1 PUBLIC CONSULTATION INTRODUCTION
Table 12-1: Niglintgak Project Definition Consultation Meetings (cont’d)
Date Meeting Type Topic Stakeholders July 8, 2004 Public meeting Project update, winter work, summer work Fort McPherson public programs. July 8, 2004 Workshop Project update, winter work, summer work Fort McPherson programs. Hunters and Trappers Committee, Elders and community corporations
August 2004 Shell Canada Limited 12-15 NDPA-P1 Section 12.2 PUBLIC CONSULTATION
APPLICATION FOR APPROVAL OF THE DEVELOPMENT PLAN FOR NIGLINTGAK FIELD PROJECT DESCRIPTION CONCERNS AND RESPONSES
12.2.1 KEY CONCERNS AND RESPONSES
Most concerns with Shell’s Niglintgak development are similar to the community concerns common throughout the Northwest Territories. However, during consultation, specific Niglintgak concerns were raised, including:
• the size and nature of the development’s land footprint
• the biophysical and socio-economic effects of the proposed gas conditioning facility concept
• the drilling waste disposal method and the use of drilling sumps
12.2.1.1 Size and Nature of Footprint
The location of the development inside the Kendall Island Bird Sanctuary requires that the land footprint be reduced as much as possible. Concerns were expressed about:
• the amount of disturbed land that might affect wildlife habitat and their activities
• sensory disturbances, such as light and noise, that might interfere with wildlife use of habitat
In response to these concerns, Shell made reducing the development’s footprint a priority in its assessment criteria when evaluating development options. The conceptual development design reduced surface disturbance and sensory impacts by:
• locating drilling sites at predisturbed locations • preferentially scheduling drilling and construction activities in the winter • using above-ground flow lines to reduce surface disturbance • locating the gas conditioning facilities on a foundation in the river channel
12.2.1.2 Gas Conditioning Facility
Although the chosen gas conditioning facility concept helped reduce the land disturbance footprint, it raised several unique concerns, including the:
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12.2.1.2 Gas Conditioning Facility (cont’d)
• environmental impact of potential dredging required to transport the gas conditioning facility to the site
• potential loss of jobs and business opportunities during construction because the gas conditioning facilities would be constructed off site
• protection of the river system during construction and operations activities
These concerns were expressed in community meetings and in a letter from the Inuvialuit Game Council on April 15, 2004. Shell has responded to the Inuvialuit Game Council’s letter and has initiated a number of design evaluations and work activities to address them.
12.2.1.3 Dredging
The potential impact of dredging in the Mackenzie Delta was assessed in the EIS, and it was concluded that dredging could be managed with no significant adverse environmental impact. Additional studies are being done to further refine the scope for any dredging and potential design modifications needed to avoid or reduce dredging in the delta area. Shell will continue to share information with concerned and interested parties as design work continues and site-specific mitigation plans are refined.
12.2.1.4 Potential Loss of Jobs and Business Opportunities
Shell is aware of the public concern that the current development plan results in fewer construction jobs and business opportunities than the other land-based options in the Inuvialuit Settlement Region. However, a review of the planned Mackenzie Gas Project activities in the region indicates that labour and business opportunities during the three years of scheduled Mackenzie Gas Project construction will exceed the Inuvialuit Settlement Region’s capacity to supply the required resources. Therefore, although the proposed gas conditioning facility would result in fewer employment opportunities than the land-based option during construction, there would still be more employment opportunities available than could be filled locally. In addition, long-term operations jobs and business opportunities will be unaffected by the construction plan chosen for the gas conditioning facility.
12.2.1.5 Protecting the River System
Protecting the river system is a key component of the Niglintgak design work and construction plans. The gas conditioning facility has been designed to reduce the use of, and increase the control of, chemicals and fuels that might be spilled from it. The environmental impact of locating the gas conditioning facility in the river channel has been assessed in the EIS and mitigation strategies have been identified to ensure that no significant environmental effects are likely to occur. Additional studies will be undertaken in ongoing engineering studies to optimize the site-specific mitigation plan details for Niglintgak.
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Shell will continue to consult with stakeholders and respond to concerns raised about the gas conditioning facility, as more information is obtained.
12.2.1.6 Drilling Waste Disposal
The use of drilling sumps as a method of disposing of drilling waste was raised as a concern for all of the anchor field developments. Exploration sumps are usually built adjacent to the wells. Historically, some have been built in less than ideal sites or in areas prone to flooding, and local stakeholders have raised concerns about their long-term aesthetics and integrity.
Shell assessed a number of options for disposing of drilling waste from the Niglintgak development, including:
• a Niglintgak-owned and operated drilling waste disposal well • a third-party-owned and operated drilling waste disposal well • transporting drilling waste to, and using, a remotely located engineered sump
Important in the consideration of these options was the volume and nature of the drilling wastes proposed for Niglintgak. Because of the shallow nature of the reservoir and low well count (6 to 12 wells), the volume of drilling waste is expected to be low. In addition, the drilling fluid will be water based, reducing the environmental concerns with longer term sump storage.
The characteristics of the Niglintgak drilling program favour the use of an engineered remote sump as the preferred method for containing and disposing of Niglintgak drilling cuttings and fluids. Downhole injection at Niglintgak was rejected because of the lack of a suitable injection formation and the prohibitive disposal costs given the small volume of Niglintgak drilling cuttings. Disposing of drilling cuttings and fluids into a third-party injection facility is a possible option, but is not currently feasible, as no facility has been identified with confirmed capacity for the Niglintgak cuttings volume.
Shell will continue to consult with interested parties within the Inuvialuit Settlement Region to try to address any remaining concerns with drilling cuttings disposal.
12.2.2 OTHER CONCERNS
Many of the other concerns identified during consultation were common to several development elements of the Mackenzie Gas Project, as well as Niglintgak. These concerns are discussed briefly here. For more information, see EIS Volume 5: Biophysical Impact Assessment.
12.2.2.1 Sensory Impacts on Wildlife
Concerns were raised about the response of wildlife to sensory impacts. Potential disturbances that might affect wildlife movements and result in consequences to migration and harvesting include:
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12.2.2.1 Sensory Impacts on Wildlife (cont’d)
• noise from compressors and flares • activities, such as transportation • light from field lighting or flaring • fugitive odours from hydrocarbon handling
Shell is committed to reducing these types of impacts and a number of mitigation measures have been identified to reduce them (see EIS Volume 7: Environmental Management). One of the most effective mitigation techniques is scheduling activities to avoid wildlife while it is in the area. At Niglintgak, this will be accomplished by scheduling most drilling and construction activities during the winter, when wildlife is less abundant in the area. During operations, which are year-round, the opportunity to use schedule management as a mitigation measure is available to a lesser degree. In this case, the following design elements and operational practices to decrease potential wildlife impacts will be considered:
• using insulation and sound-suppression equipment • reducing the use of flares • reducing the use of lighting • applying preventive maintenance techniques to minimize unplanned interventions
12.2.2.2 Local Benefits
Several concerns were raised about access to project benefits, and the distribution of project benefits to the local communities. Shell has had a long history of operating in the Inuvialuit Settlement Region and will continue to provide education, employment, training and business opportunities, which will result in realized benefits to the Inuvialuit and other northerners from its activities.
Table 12-2 summarizes the recent business opportunity benefits achieved as a result of Shell’s activities previously reported to the Inuvialuit Regional Corporation, on an annual basis.
Table 12-2: Inuvialuit Business Opportunity Benefits from Shell Work in the ISR Total Non-Inuvialuit Inuvialuit Inuvialuit Expenditures Contracts Contracts Subcontracts Year ($) ($) ($) ($) June 2000 to May 2001 9,571,257 5,090,418 4,480,839 Not reported June 2001 to May 2002 17,863,665 1,264,095 16,599,570 2,283,055 June 2002 to May 2003 4,802,000 2,164,000 2,638,000 59,654 June 2003 to May 2004 1,763,503 318,087 1,445,416 None reported Note: Direct contracts are as reported by Shell’s financial system. Contractors report subcontracts and, in many cases, contractors did not complete the requested subcontracting reports.
12-20 Shell Canada Limited August 2004 NDPA-P1 Section 13.1 ENVIRONMENTAL AND SOCIO-ECONOMIC IMPACTS
APPLICATION FOR APPROVAL OF THE DEVELOPMENT PLAN FOR NIGLINTGAK FIELD PROJECT DESCRIPTION INTRODUCTION
13.1.1 SCOPE
The environmental impact assessment process is a key element of planning, designing, constructing, operating, and eventual decommissioning and abandonment of the Niglintgak development. The environmental impact statement (EIS):
• describes the predicted effects of the Niglintgak development and the associated measures to mitigate these effects
• provides regulatory authorities with the biophysical and socio-economic information needed to make decisions about the Niglintgak development
13.1.2 KEY ISSUES
The EIS identifies key issues for northern communities that were identified through a public participation process that began in 2002 and will continue throughout the life of the development. These key issues are:
• environmental protection and effects mitigation • socio-economic effects and mitigation • northern community health and wellness
13.1.3 OBJECTIVES
The objectives of the EIS are to:
• contribute to the development of the Niglintgak field in a way that enhances benefits and mitigates adverse biophysical and social effects
• ensure that issues raised by communities are directly addressed in the assessment
• predict development-specific effects, including the effects of:
• the development on biophysical, social and economic conditions • biophysical, social and economic conditions on the development • incidents and malfunctions
August 2004 Shell Canada Limited 13-1 NDPA-P1 Section 13.1 ENVIRONMENTAL AND SOCIO-ECONOMIC INTRODUCTION IMPACTS
13.1.3 OBJECTIVES (cont’d)
• identify suitable management and mitigation measures for development- specific effects and determine the residual effects
• assess the significance of the predicted residual effects on the biophysical and socio-economic environments
• determine if the residual effects could interact cumulatively with the effects from other past, present or foreseeable future projects or activities
13.1.4 APPROACH
13.1.4.1 Methods
The assessment process was designed to meet the EIS objectives, and was based on five stages.
13.1.4.2 Stage 1
The goal of Stage 1 was to develop key questions that focused the assessment on addressing the communities’ main concerns about project effects. These questions examine the effects of the project on an issue, or group of related issues, specific to a particular subject area.
13.1.4.3 Stage 2
The goal of Stage 2 was to select valued components (VCs) and key indicators (KIs) that could be used to answer the key questions. These valued components included selected species of animals, plant communities, waterbodies, community wellness, land uses and cultural features related to the communities’ concerns. Key indicators that could be used to measure the status of a VC were identified because they could provide a measure of change caused by the project, and they directly relate to the condition of the VC.
13.1.4.4 Stage 3
The goal of Stage 3 was to analyze effect pathways that illustrate the expected cause-effect relationships between development components and the biophysical and socio-economic environments, including the influence of effects mitigation. This analysis includes mitigation measures that have been incorporated into the design of the Niglintgak field development.
13.1.4.5 Stage 4
The goal of Stage 4 was to describe the predicted effects in ways that are meaningful and are consistent throughout the EIS. This was achieved by answering four basic questions:
• Is the effect good or bad? (The direction of an effect.)
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• How intense is the effect? (The magnitude of an effect.) • How large an area will be affected? (The geographic extent of an effect.) • How long will the effect last? (The duration of an effect.)
These questions form the framework for describing the effects. The approach was tailored to suit specific topics for each subject area of the impact assessment.
13.1.4.6 Stage 5
The goal of Stage 5 was to evaluate the significance of potential residual effects.
The concept of environmental sustainability was used as the basis for determining significance. Sustainable development is development that meets the needs of the present without compromising the ability of future generations to meet their needs.
An adverse residual effect is considered significant if the effect is either:
• moderate or high in magnitude and extends into the far future, i.e., more than 30 years after project facilities have been decommissioned and abandoned
• high in magnitude, and occurs outside the local study area at any time
13.1.4.7 Public Participation
Effective stakeholder participation is integral to successfully developing and implementing the EIS. It demonstrates a sound appreciation of community-based knowledge and helps ensure that recommended mitigation measures are consistent with community capabilities and needs.
The objectives of the public participation program were to:
• ensure that community issues and concerns about the field development were understood by the proponents and the EIS assessment team
• ensure that concerns and issues were considered and addressed in the assessment process through management, mitigation or both
• provide project information in a timely and sincere manner to potentially affected and interested stakeholders to enable them to effectively engage with the proponents
• engage stakeholders in scoping field development-related issues, defining effects and contributing to developing mitigation measures to reduce effects
• educate stakeholders about the assessment process
The public participation program followed a community-based process. It provided stakeholders with opportunities to register their perceptions about the development. The opportunities reflected, as much as possible, the ways in which
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13.1.4.7 Public Participation (cont’d)
stakeholders meet to exchange information. The program was designed to take into account the needs, capabilities and schedules of the communities involved, and included:
• interviews • group meetings • community dinners • open houses • workshops • field visits
By acknowledging stakeholders and respecting the ways that they communicate, the public participation team tried to reinforce people’s comfort with registering their input.
The public participation program entailed two main rounds of activity:
• Round 1 – issue identification and scoping • Round 2 – effect assessment and mitigation
Follow-up meetings are planned with communities interested in meeting to review the EIS submission.
13-4 Shell Canada Limited August 2004 NDPA-P1 Section 13.2 ENVIRONMENTAL AND SOCIO-ECONOMIC IMPACTS
APPLICATION FOR APPROVAL OF THE DEVELOPMENT PLAN FOR NIGLINTGAK FIELD PROJECT DESCRIPTION BIOPHYSICAL IMPACTS
13.2.1 SCOPE
The biophysical resources evaluated for the Niglintgak field are:
• air quality • noise • groundwater (hydrogeology) • hydrology • water quality • fish • soils, landforms and permafrost • vegetation • wildlife
The cumulative effects on these resources were also assessed.
No significant effects are predicted on any of these resources as a result of the Niglintgak field development.
For a detailed assessment of the effects on biophysical resources, see EIS Volume 5: Biophysical Impact Assessment.
13.2.2 AIR QUALITY
Air quality effects during construction at Niglintgak are related to dust generated from disturbed areas and traffic, and emissions from vehicles and construction camps. Emissions during operations are related to well test flaring and power generation.
Mitigation strategies, such as dust control, are expected to effectively manage Construction Phase effects. Strategies to reduce emissions during operations include:
• ensuring that flare stack design and performance are consistent with appropriate industry regulations
• using equipment that complies with the Canadian Council of Ministers of the Environment (CCME) standards
August 2004 Shell Canada Limited 13-5 NDPA-P1 Section 13.2 ENVIRONMENTAL AND SOCIO-ECONOMIC BIOPHYSICAL IMPACTS IMPACTS
13.2.2 AIR QUALITY (cont’d)
Air emissions released during construction and decommissioning are not reported in the EIS because they will be minor.
No significant effects on air quality are predicted (see Table 13-1). Of the 12 key indicators, the predicted magnitude of effect is low, i.e., <1% of the guideline, for seven of them. Effects for the 1-hour and 24-hour NO2, 1-hour and 8-hour CO and 24-hour PM2.5 maximum concentrations are predicted to have a moderate magnitude because predicted maximum concentrations exceed 5% of relevant guidelines but are below applicable objectives and standards. Effects are classified as long-term because they will continue for the life of the field operations.
Table 13-1: Potential Effects of Niglintgak Activities on Air Quality
Effect Attribute Phase When Geographic Key Indicator Impact Occurs Direction Magnitude Extent Duration Significant? 1-hour sulphur Operations Adverse Low Local Long-term No dioxide (SO2)
24-hour SO2 Operations Adverse Low Local Long-term No
Annual SO2 Operations Adverse Low Local Long-term No 1-hour nitrogen Operations Adverse Moderate Local Long-term No dioxide (NO2)
24-hour NO2 Operations Adverse Moderate Local Long-term No
Annual NO2 Operations Adverse Low Local Long-term No 1-hour carbon Operations Adverse Moderate Local Long-term No monoxide (CO) 8-hour CO Operations Adverse Moderate Local Long-term No 24-hour fine Operations Adverse Moderate Local Long-term No particulate matter (PM2.5) 1-hour benzene Operations Adverse Low Local Long-term No 1-hour BTEX Operations Adverse Low Local Long-term No Area potential Operations Adverse Low Local Long-term No acid input Note: BTEX = Benzene, toluene, ethylbenzene and xylene.
13.2.3 NOISE
The potential effects of the field development on the local noise environment at Niglintgak are related primarily to facility operation, drilling activity and well test flaring.
No significant effects on noise levels are predicted from operations at Niglintgak (see Table 13-2).
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Table 13-2: Potential Effects of Niglintgak Activities on Noise
Effect Attribute Valued Phase When Geographic Component Impact Occurs Direction Magnitude Extent Duration Significant? Environmental Construction – Adverse Moderate Local Short-term No sound levels Drilling Construction – Adverse Low Local Short-term No Well test flaring Operations Adverse Low Local Long-term No
Mitigation strategies to limit noise emissions include:
• using design criteria to meet EUB Guide 38 noise guidelines for remote sites (i.e., 40 dBA at 1.5 km)
• implementing engineering noise controls, as necessary, such as silencers, insulation and upgraded building shells
• scheduling discretionary activities to avoid sensitive time periods, where practical, in sensitive areas
The guideline limit for assessing operational noise is 40 dBA at 1.5 km. No guideline applies to the assessment of noise from flaring or drilling. In the production area, within the 1.5 km radius:
• predicted maximum well drilling noise is 42 dBA • predicted maximum well-test flaring noise is 40 dBA • predicted maximum production facility operational noise is 40 dBA
13.2.4 GROUNDWATER
The potential effects of Niglintgak field development activities on groundwater can be related to changes in permafrost patterns, which can occur from such activities as vegetation removal.
Mitigation strategies to limit effects on groundwater include monitoring visual changes in location and extent of groundwater discharge areas, where present, and adopting hydrology and water quality mitigative measures.
No significant effects on groundwater are predicted. Effects are predicted to be low in magnitude, i.e., within the normal range of variation, and local in extent (see Table 13-3).
13.2.5 HYDROLOGY
The potential effects of Niglintgak activities on hydrology can be related to:
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13.2.5 HYDROLOGY (cont’d)
• site disturbance during construction • water withdrawal and disposal • land subsidence resulting from gas extraction
Table 13-3: Potential Effects of Niglintgak Activities on Groundwater
Effect Attribute Phase When Geographic Valued Component Impact Occurs Direction Magnitude Extent Duration Significant? Groundwater Construction Adverse Low Local Far future No quantity and flow Operations Adverse Low Local Long-term No patterns Decommissioning Neutral No effect N/A N/A No and abandonment Groundwater quality Construction Adverse Low Local Long-term No Operations Adverse Low Local Far future No Decommissioning Neutral No effect N/A N/A No and abandonment Note: N/A = Not applicable because no effect has been predicted.
Mitigation strategies to limit effects on hydrology include:
• grading and ditching to direct runoff through silt fences, sediment traps, vegetation, berms or isolation areas for controlled release to the watershed
• providing a setback from watercourses to reduce impacts on local drainage patterns and streamflow
• designing for thaw settlement, and using insulating materials
• conducting visual inspections to monitor drainage conditions and sediment control devices within the Niglintgak production area
• monitoring streambed conditions and bank stability at water crossings
• monitoring visually for the effects of production-related land subsidence
No significant effects on hydrology are predicted. Most effects will be low and local (see Table 13-4).
13.2.6 WATER QUALITY
Potential effects of Niglintgak activities on water quality can be related to:
• wastewater releases or withdrawals at facilities and camps • leaks and spills • suspended sediment inputs from land disturbance and watercourse crossings
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Table 13-4: Potential Effects of Niglintgak Activities on Hydrology
Effect Attribute Phase When Geographic Key Indicator Impact Occurs Direction Magnitude Extent Duration Significant? Runoff amounts Construction Adverse Low Local Medium-term No Operations Adverse Low Local Long-term No Decommissioning Neutral No effect N/A N/A No and abandonment Drainage patterns Construction Adverse Low Local Medium-term No Operations Adverse Low Local Long-term No Decommissioning Neutral No effect N/A N/A No and abandonment Water levels and Construction Adverse Low to Local Medium-term No velocities moderate1 Operations Adverse Low to Local Long-term No moderate1 Decommissioning Neutral No effect N/A N/A No and abandonment Sediment Construction Adverse Low to high2 Local Medium-term No concentration Operations Adverse Low to Local Long-term No moderate2 Decommissioning Neutral No effect to Local Short-term No and abandonment high2 Channel Construction Adverse Low Local Medium-term No morphology Operations Adverse Low Local Long-term No Decommissioning Neutral Low Local Medium-term No and abandonment Note: 1. Moderate effects are related to barge-based gas conditioning facility option. 2. Moderate to high effects are related to barge-based gas conditioning facility option. N/A = Not applicable because no effects have been predicted.
Mitigation strategies to limit effects on water quality include: • treating wastewater to meet appropriate water quality standards before discharge or deep well injection • controlling runoff and sediment during construction • revegetating disturbed areas • preventing leaks and containing spills • limiting water withdrawal to meet regulatory standards • monitoring waterbodies affected by test water releases
No significant effects on water quality are predicted. Effects on water and sediment quality will be low in magnitude and local in extent during all field development phases (see Table 13-5).
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Table 13-5: Potential Effects of Niglintgak Activity on Water Quality
Effect Attribute Valued Phase When Geographic Component Impact Occurs Direction Magnitude Extent Duration Significant? Water and Construction Adverse Low to Local Medium-term No sediment quality moderate1 Operations Adverse Low Local Long-term No Decommissioning Neutral Low to Local Long-term No and abandonment moderate1 Note: 1. Moderate effects are related to barge-based gas conditioning facility option.
13.2.7 FISH AND FISH HABITAT
The potential effects of Niglintgak activities on fish and fish habitat can be related to:
• changes in water levels and water flow related to such activities as water withdrawal
• sediment deposition caused by erosion from construction sites
• direct effects to fish habitat from such activities as constructing watercourse crossings
Mitigation strategies to reduce the effects on fish include:
• controlling erosion and sediment • constructing primarily during winter conditions • preventing spills and leaks, and preparing contingency plans • avoiding spawning, rearing and overwintering fish habitats • monitoring water quality and fish health at selected lakes and watercourses
No significant effects on fish are predicted (see Table 13-6).
13.2.8 SOILS, LANDFORMS AND PERMAFROST
The potential effects of Niglintgak activities on soils and landforms can be related to surface disturbance during construction that can damage soils, degrade permafrost, cause erosion, and remove uncommon landforms.
Mitigation strategies at Niglintgak to reduce effects on soils and landforms include:
• reducing surface disturbance
• controlling erosion
• stabilizing slopes
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• monitoring the effects of thaw settlement and frost heave, soil erosion, slope movement and drainage conditions at selected sites within the Niglintgak lease
Table 13-6: Potential Effects of Niglintgak Activities on Fish
Effect Attribute Phase When Geographic Key Indicators Impact Occurs Direction Magnitude Extent Duration Significant? Habitat Construction Adverse Low Local Long-term No Operations Adverse Low Local Long-term No Decommissioning Adverse Low Local Far future No and abandonment Health Construction Adverse Low Local Short-term No Operations Neutral No effect N/A N/A No Decommissioning Adverse Low Local Short-term No and abandonment Distribution and Construction Adverse Low Local Short-term No abundance Operations Neutral No effect N/A N/A No Decommissioning Adverse Low Local Short-term No and abandonment Note: N/A = Not applicable because no effects have been predicted.
No significant effects on soils and landforms are predicted. All project effects on these features are low in magnitude and local in extent (see Table 13-7).
Table 13-7: Potential Effects of Niglintgak Activities on Soils and Landforms
Effect Attribute Valued Phase When Geographic Component Impact Occurs Direction Magnitude Extent Duration Significant? Ground Construction Adverse Low Local Short-term No stability Operations Adverse Low Local Long-term No Decommissioning Neutral No effect N/A N/A No and abandonment Uncommon Construction Adverse Low Local Far future1 No landforms Operations Adverse Low Local Far future No Decommissioning Neutral No effect N/A N/A No and abandonment Soil quality Construction Adverse Low Local Short-term to No far future Operations Adverse Low Local Short-term to No far future1 Decommissioning Adverse Low Local Short-term No and abandonment Note: 1. Far future effects relate to changes to patterned ground. N/A = Not applicable because no effects have been predicted.
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13.2.9 VEGETATION
The potential effects of Niglintgak activities on vegetation can be related to:
• vegetation loss during construction • dust and air emissions • changes in landforms, soils and permafrost
Mitigation strategies to reduce effects to vegetation include:
• reducing the areal extent of the disturbance to the extent practical, considering safety, constructability and operability
• controlling weeds to prevent weedy species invasion
• reclaiming disturbed areas
• monitoring vegetation composition and cover, vegetation and vigour and presence of weeds at selected sites
No significant effects on vegetation are predicted (see Table 13-8). The effects on vegetation types are low in magnitude and local in extent. No effects on the abundance and distribution of vegetation communities of concern or rare plants are predicted.
Table 13-8: Potential Effects of Niglintgak Activities on Vegetation Abundance and Distribution
Effect Attribute Valued Phase When Geographic Component Impact Occurs Direction Magnitude Extent Duration Significant? Vegetation types Construction Adverse Low Local Far future No Operations Adverse Low Local Far future No Decommissioning Adverse Low Local Far future No and abandonment Vegetation Construction Neutral No effect N/A N/A No communities of Operations Neutral No effect N/A N/A No concern Decommissioning Neutral No effect N/A N/A No and abandonment Rare plants Construction Neutral No effect N/A N/A No Operations Neutral No effect N/A N/A No Decommissioning Neutral No effect N/A N/A No and abandonment Note: N/A = Not applicable because no effects are predicted.
No significant effects on vegetation health are predicted. Dust and air emissions are predicted to result in low magnitude, local effects to the health of some vegetation types and rare plants (see Table 13-9). These effects will not extend beyond the life of the Niglintgak field.
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Table 13-9: Potential Effects of Niglintgak Activities on Vegetation Health
Effect Attribute Valued Phase When Geographic Component Impact Occurs Direction Magnitude Extent Duration Significant? Vegetation types Construction Adverse Low Local Short-term No Operations Adverse Low Local Long-term No Decommissioning Adverse Moderate Local Medium- No and abandonment term Vegetation Construction Neutral No effect N/A N/A No communities of Operations Neutral No effect N/A N/A No concern Decommissioning Neutral No effect N/A N/A No and abandonment Rare plants Construction Neutral No effect N/A N/A No Operations Neutral No effect N/A N/A No Decommissioning Neutral No effect N/A N/A No and abandonment Note: N/A = Not applicable because no effects have been predicted.
13.2.10 WILDLIFE
The potential effects of Niglintgak activities on wildlife can be related to:
• reduced habitat resulting from the direct loss of habitat from construction, or sensory disturbance that causes wildlife to avoid areas
• barriers that the field facilities might present to wildlife movement, such as trenches or above-ground flow lines that inhibit wildlife movements
• increased mortality because hunters and predators can access wildlife more readily along roads or pipeline rights-of-way
Mitigation strategies to reduce effects on wildlife include:
• developing and implementing operating guidelines to:
• address potential effects on wildlife • reduce sensory disturbance on wildlife
• managing access in cooperation with communities and regulatory agencies
• reducing the development footprint and related vegetation clearing, where practical, while maintaining a safe construction and operating site
• scheduling work activities to avoid sensitive life-cycle stages, where practical
• implementing design and work practices to reduce the barrier effects of the development on wildlife movement
• establishing reclamation plans to re-establish wildlife habitat
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13.2.10 WILDLIFE (cont’d)
• managing waste effectively to prevent wildlife attraction
No significant effects on wildlife habitat availability are predicted. Effects on wildlife habitat availability will be local. Most effects will be low magnitude except for short-term moderate effects on beluga whales related to the barge- based gas conditioning facility option (see Table 13-10).
Table 13-10: Potential Effects of Niglintgak Activities on Wildlife Habitat Availability
Effect Attribute Valued Phase When Geographic Component Impact Occurs Direction Magnitude Extent Duration Significant? Barren- Construction Adverse Low Local Long-term No ground grizzly Operations Adverse Low Local Long-term No bear Decommissioning Adverse Low Local Long-term No and abandonment Birds1 Construction Adverse Low Local Long-term No Operations Adverse Low Local Long-term No Decommissioning Adverse Low Local Long-term No and abandonment Beluga whale Construction Adverse Moderate Local Short-term No Operations Adverse Low Local Long-term No Decommissioning Adverse Moderate Local Short-term No and abandonment Bowhead Construction Adverse Low Local Medium-term No whale Operations Neutral N/A N/A N/A No Decommissioning Adverse Low Local Medium-term No and abandonment Ringed seal Construction Adverse Low Local Short-term No Operations Adverse Low Local Long-term No Decommissioning Adverse Low Local Medium-term No and abandonment Polar bear Construction Adverse Low Local Long-term No Operations Adverse Low Local Long-term No Decommissioning Adverse Low Local Medium-term No and abandonment Note: 1. Bird species addressed in the effects assessment include greater white-fronted goose, snow goose, tundra swan, scaup, peregrine falcon, whimbrel and Arctic tern. N/A = Not applicable because no effects have been predicted.
No significant effects on wildlife movement are predicted. The effects on wildlife movement in the area will be low magnitude and confined to the local area (see Table 13-11).
No significant effects on wildlife mortality are predicted (see Table 13-12). Industry-caused mortality of barren-ground grizzly bear is assumed to be less
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than the sustainable harvest quota. As a result, a low-magnitude effect, regional in extent, is predicted for the barren-ground grizzly bear mortality.
Table 13-11: Potential Effects of Niglintgak Activity on Wildlife Movement Effect Attribute Valued Phase When Geographic Component Impact Occurs Direction Magnitude Extent Duration Significant? Grizzly bear Construction Adverse Low Local Medium-term No Operations Adverse Low Local Long-term No Decommissioning Adverse Low Local Short-term No and abandonment Beluga Construction Adverse Low Local Short-term No whale Operations Neutral No effect N/A N/A No Decommissioning Adverse Low Local Short-term No and abandonment Bowhead Construction Adverse Low Local Short-term No whale Operations Neutral No effect N/A N/A No Decommissioning Adverse Low Local Short-term No and abandonment Ringed seal Construction Adverse Low Local Short-term No Operations Neutral No effect N/A N/A No Decommissioning Adverse Low Local Short-term No and abandonment Polar bear Construction Neutral No effect N/A N/A No Operations Neutral No effect N/A N/A No Decommissioning Neutral No effect N/A N/A No and abandonment Note: N/A = Not applicable because no effect has been predicted.
13.2.11 CUMULATIVE EFFECTS
An assessment of cumulative effects concluded that:
• the Niglintgak field development will not contribute to significant cumulative effects
• no significant overall cumulative effects are predicted
The Niglintgak development, as part of the Mackenzie Gas Project, might lead to future gas exploration and development within the Northwest Territories. However, information to adequately assess potential cumulative effects from such developments is not currently available.
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Table 13-12: Potential Effects of Niglintgak Activity on Wildlife Mortality Effect Attribute Valued Phase When Geographic Component Impact Occurs Direction Magnitude Extent Duration Significant? Barren- Construction Adverse Low Regional Medium-term No ground grizzly bear Operations Adverse Low Regional Long-term No Decommissioning Neutral N/A N/A N/A No and abandonment Beluga Construction Adverse Low Local Medium-term No whale Operations Neutral N/A N/A N/A No Decommissioning Adverse Low Local Medium-term No and abandonment Bowhead Construction Adverse Low Local Medium-term No whale Operations Neutral N/A N/A N/A No Decommissioning Adverse Low Local Medium-term No and abandonment Ringed seal Construction Adverse Low Local Medium-term No Operations Neutral N/A N/A N/A No Decommissioning Adverse Low Local Medium-term No and abandonment Polar bear Construction Adverse Low Local Medium-term No Operations Adverse Low Local Medium-term No Decommissioning Adverse Low Local Medium-term No and abandonment Note: N/A = Not applicable because no effect has been predicted.
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APPLICATION FOR APPROVAL OF THE DEVELOPMENT PLAN FOR NIGLINTGAK FIELD PROJECT DESCRIPTION SOCIO-ECONOMIC IMPACTS
13.3.1 SCOPE
The socio-economic key issues evaluated for the Niglintgak field were the effects on:
• the regional economy • infrastructure • individual, family and community wellness • traditional culture • non-traditional land and resource use • heritage resources
Most of the socio-economic issues are overall effects from the Mackenzie Gas Project, resulting from the combined influences of all project components and activities in the Beaufort Delta Region. The effects of the Niglintgak field development cannot be distinguished from those of all components acting together. The need for goods, services and employment, and their economic impact, will be further defined and assessed during the construction and operations phases of the field development.
The cumulative effects on these issues were also assessed.
No significant adverse effects are predicted on any of these issues as a result of the Niglintgak field development. Several significant positive effects on regional economies are predicted.
For a detailed assessment of the socio-economic effects, see EIS Volume 6: Socio-Economic Impact Assessment.
13.3.2 REGIONAL ECONOMIC EFFECTS
The Mackenzie Gas Project will generate a large demand for goods, services and labour at various locations in the Northwest Territories. Suppliers, contractors and northern residents are expected to respond to these demands to the extent possible. Where demand exceeds northern supply capacity, supply requirements will be filled from outside the Northwest Territories.
The project impacts on the economy were assessed by considering:
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13.3.2 REGIONAL ECONOMIC EFFECTS (cont’d)
• project capital and operating expenditures • regional capacity of workers and businesses • project employment and labour income • demography and population mobility
The assessment also considers mitigating measures planned or implemented by the proponents of the Mackenzie Gas Project to enhance northern and Aboriginal labour skills and business capacity. Some examples of mitigating measures taken or planned include: • providing qualified Aboriginal and other northern residents with the opportunity to work during construction
• participating in industry initiatives to educate and train potential trades and technical workers for pipeline and production operations • providing full and fair opportunity for Aboriginal and northern businesses to participate in business opportunities • providing lead time to Aboriginal businesses to develop the ability to qualify and compete for work • structuring work packages to better align with the capacity of northern businesses, where appropriate
• placing particular emphasis on local content plans when awarding work
13.3.2.1 Capital and Operating Expenditures
The total capital expenditure for all Mackenzie Gas Project components is $7,732 million, in constant 2003$ Cdn (see Table 13-13).
Table 13-13: Mackenzie Gas Project Capital Expenditures
Total Activity Expenditure Timing ($Million) Pre-construction January 1, 2002 to June 30, 2006 845 Construction July 1, 2006 to June 30, 2010 6,247 Ongoing capital July 1, 2010 to December 30, 2023 639 Total 7,732
Table 13-14 shows that, of the $6.2 billion construction expenditures:
• $1.9 billion (31%) will be made in the Inuvialuit Settlement Region (ISR) • $1.1 billion (17%) will be made in the Gwich’in Settlement Area (GSA)
The balance of the project investment will occur outside the regions.
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Table 13-14: Mackenzie Gas Project Capital Investment by Area
2006–2007 2007–2008 2008–2009 2009–2010 Total Location ($M) (%) ($M) (%) ($M) (%) ($M) (%) ($M) (%) Project total 1,409 100 2,261 100 1,907 100 671 100 6,247 100 Inuvialuit Settlement Region 301 21 580 26 672 35 362 54 1,915 31 Gwich’in Settlement Area 276 20 419 19 308 16 77 11 1,079 17 Other 831 59 1,262 56 927 48 232 35 3,253 52 Note: Numbers might not add up because of rounding.
Although the total capital investment for constructing all Mackenzie Gas Project components is $6.2 billion, and the components are physically located in the Northwest Territories, most of the capital spending on goods and services needed to construct the Mackenzie Gas Project components will go to businesses located outside of the Northwest Territories. This is because the regions in the Northwest Territories lack the capacity to undertake such a large project, given the small population base and workforce, and the limited number, size and scope of local businesses and contractors.
Of the $1.9 billion of capital expenditures to occur in the Inuvialuit Settlement Region during construction from 2006 to 2010, an estimated $328 million (17%) will be spent in the region. Similarly, of the $1.1 billion of capital expenditures to occur in the Gwich’in Settlement Area, $353 million (33%) will be spent in that area. Together, this constitutes $681 million over four years in the Beaufort Delta Region.
The estimated total capital expenditure for the Niglintgak field is $369 million between 2002 and 2009 (see Table 13-15).
The estimated annual average operating expenditure for the Niglintgak field is about $10 million between 2010 and 2035.
Table 13-15: Capital Expenditures for the Niglintgak Field, Barge Option
2002 2003 2004 2005 2006 2007 2008 2009 Total Expenditure Type ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M) ($M) Engineering and project management 1446181814772 Line pipe and piping materials 00000013013 Major equipment and modularization1 00001497280138 Logistics 000000303 Construction2 0000007916 Camp buildings set-up and catering 0000145515 Drilling site preparation and site construction 0000462214 Drilling and service wells 0111125413098 Total14473714911354369 Note: Numbers might not add up because of rounding. 1. Includes prefabricated modules, production equipment, and other equipment and material. 2. Includes labour travel, fuel, construction equipment rental, installation labour, granular delivery, facilities site preparation, facilities construction and borrow royalty.
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13.3.2.2 Employment
During Mackenzie Gas Project construction, an annual average of 261 people from the Inuvialuit Settlement Region and 407 from the Gwich’in Settlement Area would be available to seek project employment and related work (see Table 13-16).
A GNWT Labour Force Survey identified the total available labour pool and those who would be willing to accept direct employment rotation. Acceptance of work rotation was taken as an indicator of labour accepting direct project employment.
Table 13-16: Estimated Labour Pool Available in ISR and GSA for Project-Related Work
2006–2007 2007–2008 2008–2009 2009–2010 Average Indicator ISR GSA ISR GSA ISR GSA ISR GSA ISR GSA Total unemployed 313 574 315 603 318 629 320 608 317 603 Will do rotational work (%)82658276827582548267 Total unemployed adjusted 258 372 260 459 262 469 264 328 261 407 for rotational work
The willingness to do rotational work only applies to direct jobs, which make up about half of the total number of project-related jobs created.
An estimate of direct employment demand for the region was developed by comparing the job type and occupation requirements for each project component located in the region with the expected skills of the local labour force.
The Statistics Canada Inter-Regional Input-Output Model was used to estimate the total demand generated by the project for indirect and induced employment in the Northwest Territories. The territorial estimates were then broken down into regions using project expenditure data. Table 13-17 describes the project employment demand in the Inuvialuit Settlement Region and the Gwich’in Settlement Area. Taking into account capacity constraints of the available labour force in these regions, an estimated annual average of 568 workers are expected to be available to meet the demand for Mackenzie Gas Project jobs during construction, assuming that project-related training is made available in the Northwest Territories.
13.3.2.3 Labour Income
Project-related construction employment will lead to increased household income in the regions. Project construction is estimated to lead to an increase of about $120 million in labour income in the Inuvialuit Settlement Region and Gwich’in Settlement Area throughout the construction period. This comprises $67 million in direct project-related income and $53 million earned by those producing goods and services for the project and its employees (see Table 13-18).
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Table 13-17: Project Employment Demand in the ISR and GSA
Number of Jobs Type of Demand 2006–2007 2007–2008 2008–2009 2009–2010 Total Average Inuvialuit Settlement Region Modelled employment demand without labour supply constraints Direct 59 145 566 39 809 202 Indirect 216 527 784 663 2,189 547 Induced 99 209 272 199 780 195 Total 374 881 1,622 901 3,778 945 Estimated employment demand with labour supply adjustments Direct 59 145 201 39 445 111 Indirect 40 40 40 41 160 40 Induced 20 20 20 20 80 20 Total 118 205 262 100 685 171 Gwich’in Settlement Area Modelled employment demand without labour supply constraints Direct 499 1,986 1,277 60 3,822 956 Indirect 906 1,174 1,001 181 3,263 816 Induced 228 300 249 46 822 206 Total 1,633 3,459 2,528 287 7,907 1,977 Estimated employment demand with labour supply adjustments Direct 232 287 293 60 872 218 Indirect 93 115 117 181 506 127 Induced 46 57 59 46 208 52 Total 372 459 469 287 1,586 397 Note: Numbers might not add up because of rounding.
Table 13-18: Estimated Project-Related Labour Income in the ISR and GSA – 2006 to 2010
2006–2007 2007–2008 2008– 2009–2010 Total Average Type of Demand ($M) ($M) 2009 ($M) ($M) ($M) ($M) Inuvialuit Settlement Region Direct 2 9 12 3 26 6 Indirect 3 3 3 3 11 3 Induced 1 1 1 1 3 1 Total 5 13 16 7 40 10 Gwich’in Settlement Area Direct 12 13 14 3 41 10 Indirect 6 7 7 11 30 8 Induced 2 2 2 2 9 2 Total 19 22 23 16 80 20 Grand Total 24 35 39 23 120 30 Note: Numbers might not add up because of rounding.
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13.3.2.3 Labour Income (cont’d)
Between 2009 and 2030, total project-related employment in the Inuvialuit Settlement Region and Gwich’in Settlement Area is expected to fluctuate between 168 and 466 jobs and average 276 jobs (see Table 13-19). These jobs will result in average annual labour income estimates that range from $12 to $32 million or an annual average of about $19 million during this period (see Table 13-20).
Table 13-19: Estimated Project-Related Annual Average Employment (2009 to 2030)
Number of Jobs Type of Demand 2009–2015 2016–2020 2021–2025 2026–2030 2009–2030 Inuvialuit Settlement Region Direct 136 207 54 49 113 Indirect 8 19 5 5 9 Induced 4 10 3 2 5 Total 148 236 62 56 127 Gwich’in Settlement Area Direct 40 37 37 37 38 Indirect 68 129 52 50 74 Induced 34 64 26 25 37 Total 142 230 115 112 149 Grand Total 290 466 177 168 276 Note: Numbers might not add up because of rounding.
Table 13-20: Annual Average Labour Income in the ISR and GSA
2009–2015 2016–2020 2021–2025 2026–2030 2009–2030 Type of Demand ($M) ($M) ($M) ($M) ($M) Inuvialuit Settlement Region Direct 11.5 17.6 4.6 4.2 9.6 Indirect 0.4 1.0 0.3 0.2 0.5 Induced 0.2 0.4 0.1 0.1 0.2 Total 12.2 19.0 4.9 4.5 10.3 Gwich’in Settlement Area Direct 4.0 3.7 3.7 3.7 3.8 Indirect 3.5 6.6 2.7 2.6 3.8 Induced 1.4 2.7 1.1 1.0 1.6 Total 8.9 13.0 7.5 7.3 9.1 Grand Total 21.1 32.0 12.4 11.8 19.4 Note: Numbers might not add up because of rounding.
The Niglintgak field barge option will contribute about 170 people to the total project employment demand between 2006 and 2010 (see Table 13-21). The Niglintgak land-based option contributes about 250 people to total project employment demand.
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Table 13-21: Niglintgak Field, Barge Option – Peak Construction Employment
Staffing Classification 2006–2007 2007–2008 2008–2009 2009–2010 Total Supervisors 3 7 12 4 26 Welders 2 728138 Teamsters 02316 Operators 1 4 12 1 18 Labourers 2 8 24 3 37 Other 2 4 11 4 21 Inspectors 01416 Site-abandonment personnel 00000 Site-abandonment infrastructure 00000 personnel Site-abandonment logistics personnel 00000 Camp and catering personnel236213 Camp infrastructure personnel00101 Camp logistics personnel11114 Total 13 37 102 18 170
Drilling and completion activities at Niglintgak will generate 97 on-site jobs in 2007–2008 and 122 jobs during 2008–2009 and 2009–2010. A total of 341 jobs will be generated (see Table 13-22).
Table 13-22: Niglintgak On-Site Drilling, Completions and Related Employment
Drilling and Completions 2006–2007 2007–2008 2008–2009 Total Supervisors, technical, administrative 11 13 13 37 Surveyors, monitors, safety 12 13 13 38 Equipment operators 30 28 28 86 Construction labourers 6 4 4 14 Welders 1 1 1 3 Electrician 1 1 1 3 Mechanic 1 1 1 3 Camp staff – cooks 12 12 12 36 Drilling crew personnel 12 24 24 60 Specialty drilling services 11 25 25 61 Total 97 122 122 341
Once start-up is complete and the facilities are fully operational, the Niglintgak development will require 13 full-time equivalent (FTE) operations employees (see Table 13-23), including two trainees and two FTE contract maintenance personnel. These positions will be rotational.
The Inuvialuit Settlement Region and Gwich’in Settlement Area economies will respond to the overall project demand and the specific demand of the Niglintgak
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13.3.2.3 Labour Income (cont’d)
field development. The combined regional economic effects, including project procurement, employment and income, are expected to be significant, positive and high in magnitude during construction. During operations, regional economic effects in the Inuvialuit Settlement Region will be positive, low in magnitude, regional and beyond in extent, long-term and not significant (see Table 13-24). In the Gwich’in Settlement Area, economic effects during operations will be positive, moderate in magnitude, regional and beyond in extent and long-term and significant. The moderate magnitude is attributed to Inuvik, the primary business and service centre for the Beaufort Delta Region.
Table 13-23: Niglintgak Operations Labour Force Requirements
Position Number of Jobs Manager 1 Administrative support 1 Professional staff 0 Driver 0 Labourer 0 Millwright 2 Pipefitter 0 Electrician 2 Control room operator 1 Field operator 4 Subtotal 11 Maintenance contractor 2 Total 13
Table 13-24: Economic Effects of the Project and Niglintgak Field
Effect Attribute Geographic Location Phase Direction Magnitude Extent Duration Significant? Inuvialuit Construction Positive High Regional and Short-term Yes Settlement beyond regional Region Operations Positive Low Regional and Long-term No beyond regional Gwich’in Construction Positive High Regional and Short-term Yes Settlement beyond regional Area Operations Positive Moderate Regional and Long-term Yes beyond regional
13.3.2.4 Demography and Population Mobility
The possibility that increases in populations will overburden community infrastructure and services is a concern. All aspects of field development and project construction will create demands for labour, and thus tend to encourage
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migration to regional and other centres of project activity. Relevant mitigation measures include hiring southern workers for project and production-related positions in selected provincial cities, from contractor lists and via media advertising. Hiring in the North will be restricted to qualified Aboriginal and other northerners, and this restriction will be publicized.
Aboriginal and other northerners will be able to sign up for project work in their home communities, which will help discourage intra-territorial migration. However, these measures will only be partly effective because there will be many indirect and induced jobs during the Construction Phase, which might cause workers to migrate within and into the Northwest Territories.
The effects of the Niglintgak field development are not distinguishable from combined project effects. These effects will be expressed primarily in Inuvik, where the population is expected to increase by about 450 during construction. Table 13-25 shows the project-related effects on population mobility during construction.
During the Operations Phase, from 2009 to 2015, the initial transitional effect on Inuvik could be an increase of about 280 people. This effect will stabilize during early operations, and by 2021 to 2025 will reach about 200 people. Table 13-26 shows the project-related effects during operations.
Table 13-25: Potential Construction Effects on Population Mobility
Effect Attribute Region Direction Magnitude Geographic Extent Duration Significant? Beaufort Delta Adverse Low Regional Short-term No Inuvik Adverse and positive High Local Short-term No
Table 13-26: Potential Operations Effects on Population Mobility
Effect Attribute Region Direction Magnitude Geographic Extent Duration Significant? Inuvik Positive Low Local Long-term No
13.3.3 INFRASTRUCTURE
13.3.3.1 Transportation
The Mackenzie Gas Project will increase demand on all transportation modes, including highway, railroad, barge and air transportation, during the Construction Phase, in addition to increasing project-related travel.
Agreements between the project and the GNWT, and between the project and applicable municipalities, will be negotiated and will include provisions for the project’s use of permanent and seasonal roads. The agreements will consider:
• coordination of road maintenance activities
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13.3.3.1 Transportation (cont’d)
• coordination of road upgrading, where required
• options that could include making contributions in kind, such as constructing winter roads, maintaining and repairing highways or contributing to a portion of maintenance costs
Other general mitigation measures will include:
• continuing discussions with barge service and air transportation providers to provide them with ample lead time to ensure sufficient capacity to meet community requirements and project demands
• coordinating with the GNWT and other responsible authorities to provide construction air and barge traffic demand projections, including provisions for assessing the need for, and completing upgrading and other improvements to, regional and municipal airports, airstrips and barge landings
All project effects are expected to be low to moderate in magnitude, of short duration and not significant (see Table 13-27).
Extensive transportation will not be required during the Operations Phase. As a result, the effects of the Operations Phase on transportation infrastructure were not assessed.
Table 13-27: Potential Effects on Transportation Infrastructure
Effect Attribute Mode of Region Transportation Direction Magnitude Geographic Extent Duration Significant? Beaufort Delta Road Adverse Low Regional Short-term No Marine Adverse Moderate Regional Short-term No Air Adverse Moderate Regional Short-term No
13.3.3.2 Energy and Utilities
During the construction and operations phases, the project will have no effects on the energy and utilities systems of any community. Accordingly, there is no need to detail project effects on energy and utilities infrastructure during either of these phases.
All communities have sufficient capacity to accommodate any foreseeable demands created by the projected level of in-migrants or transients that the project might attract to the study area.
13.3.3.3 Housing
Project effects on housing and accommodations will include direct and indirect demands for short and long-term accommodation. Demands for short-term
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accommodation will be reduced by providing project construction camps. Programs to discourage speculative in-migration (see Section 13.3.2.4, Demography and Population Mobility) will help reduce pressures on accommodation.
Based on population projections, an estimated additional 160 dwellings will be needed in Inuvik from 2002 through 2011. Because of its proximity to the gathering system and other activity in the coastal area, Tuktoyaktuk might experience some degree of speculative in-migration.
The effects on housing are expected to be adverse, short-term and not significant in affected communities (see Table 13-28). Housing effects are expected to be high in magnitude and local in Inuvik, and moderate and local in Tuktoyaktuk. Low-magnitude local effects are expected in the other Beaufort Delta Region communities.
Table 13-28: Potential Effects of Mackenzie Gas Project on Housing
Effect Attribute Region Direction Magnitude Geographic Extent Duration Significant? Inuvik Adverse High Local Short-term No Tuktoyaktuk Adverse Moderate Local Short-term No Other Beaufort Adverse Low Local Short-term No Delta communities
13.3.3.4 Recreation Resources
Camp facilities will meet the recreation needs of the vast majority of project employees. The remaining employees will be based in Inuvik, most for relatively short periods. There will also be some speculative in-migration to Inuvik, in spite of planned mitigation measures (see Section 13.3.2.4, Demography and Population Mobility). Inuvik is well equipped with a large-capacity recreation complex and other facilities.
Some positive effects might be expected in Inuvik, where increased recreation demand and user fee revenues could lead to increases in the hours facilities are open for use.
No effects are expected on recreation facilities and use during the Operations Phase, other than a low-magnitude, localized, adverse and positive effect in Inuvik.
13.3.3.5 Governance
Governance encompasses both the authority to make decisions and the ability to access and manage the funds required to make some decisions consequential. Governance arrangements in the Northwest Territories are changing as a result of ongoing devolution discussions between regional representatives and the governments of the Northwest Territories and Canada.
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13.3.3.5 Governance (cont’d)
The project will provide a substantial source of revenue to the various levels of government from:
• benefits and access agreements • direct taxation • payment of royalties
During the Construction Phase, the project will generate $136 million in personal taxes from activity in the Northwest Territories. The GNWT share, after adjustment for the formula financing grant (FFG) is taken into account, is estimated to be $9.8 million. Estimates of corporate tax flows have not been included. During project operations, total taxes generated from activity in the Northwest Territories will amount to about $399 million annually, of which the GNWT share, after the FFG is taken into account, is estimated to be $22 million. The GNWT share will vary from 7% of the total during construction to 5% during operations.
The size of these various project payments should exceed the costs of sustaining adequate levels of infrastructure and services to meet project demands. However, before a final devolution agreement is implemented, the largest part of these revenues will accrue to the federal government, while the likely costs of the project for infrastructure and services will impinge on the local, regional and territorial governments. These authorities will not have the resources to pay for the project-induced needed infrastructure and public services expenditures under current programs and budgets.
There is an issue with the timing of expenditures for the physical infrastructure necessary before and during construction, and the substantial project royalty fee and tax revenues receivable during operations. Accordingly, Construction Phase effects on governance are seen as adverse, moderate in magnitude, regional and beyond regional in extent, but short-term and not significant. The Operations Phase effects will be positive, low in magnitude, regional and beyond regional in extent, long-term and not significant.
13.3.4 INDIVIDUAL, FAMILY AND COMMUNITY WELLNESS
The focus of individual, family and community wellness is on the effects of the project Construction Phase, when there will be elevated levels of employment and income that might positively or negatively affect individual, family and community wellness. When construction has been completed, the elevated levels of employment and income will decline. The smaller numbers employed for technical operations, anchor field and pipeline maintenance during the Operations Phase will be stationed primarily in Inuvik, with a few in Norman Wells, and perhaps some maintenance staff in Fort Simpson. Accordingly, during the Operations Phase, there will be no need for mitigation to reduce adverse effects on wellness, and no residual effects are expected.
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13.3.4.1 Community Well-Being and Delivery of Social Services
The most frequent and persistent problems that community wellness centres must address are substance abuse, primarily alcohol and derivative violence, often in families. The increased incomes from project employment could add substantially to substance abuse-related problems, and to the burdens of the social service workers who must try to deal with the problems.
Because of Inuvik’s location and central role as service centre for the Beaufort Delta Region, many of the wellness issues will express themselves there. As a result, effective mitigation will be a serious challenge, requiring a concentrated effort by all.
The single most important mitigation focuses on controlling substance abuse, and this will require initiatives by the project proponents, the GNWT and local communities. Measures initiated by the project proponents will include:
• providing money-management training programs in camps, and supporting community-based money-management training programs, to reduce the potential for negative lifestyle choices
• enforcing policies for alcohol and drug-free workplaces and camps
The GNWT should ensure that the resources of RCMP detachments are adequate to strictly enforce liquor ordinances, laying charges against those guilty of violent abuse and detaining inebriated people who might endanger themselves or others.
The proponents encourage local communities to enact ordinances restricting alcohol import amounts and mobilizing their resources to discourage substance abuse and associated violence.
Measures that reduce adverse effects on community wellness reduce the demands and the stresses on social services workers, who will then be better able to deal with wellness problems.
Table 13-29 shows that the project effects on well-being during the Construction Phase are expected to be adverse and high in magnitude in Inuvik, Tuktoyaktuk, Paulatuk and Aklavik, and moderately adverse in Fort McPherson and Tsiigehtchic. These effects are expected to be neutral and low-magnitude in Holman and Sachs Harbour. In each of these communities, the effects are expected to be local, short-term and not significant.
The effects on social service delivery are shown in Table 13-30. They generally parallel well-being conditions. All are expected to be short-term and not significant.
13.3.4.2 Health Conditions and Health Care Services
All project camps will have health care staff and facilities appropriate to camp size. Staffing and facility equipment will ensure that any accident victims and seriously ill patients can be stabilized for medical evacuation.
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13.3.4.2 Health Conditions and Health Care Services (cont’d)
The most serious threats to health in communities are posed by:
• substance abuse and the consequential elevated risks of accidental and violent injuries
• population movement and the potential that contagious diseases might be spread by transients or workers returning from camps
Table 13-29: Potential Project Effects on Well-Being Conditions
Effect Attribute Geographic Location Direction Magnitude Extent Duration Significant? Inuvik Adverse High Local Short-term No Tuktoyaktuk, Paulatuk and Adverse High Local Short-term No Aklavik Fort McPherson and Adverse Moderate Local Short-term No Tsiigehtchic Holman and Sachs Harbour Neutral Low Local Short-term No
Table 13-30: Potential Project Effects on Delivery of Social Services
Effect Attribute Location Direction Magnitude Geographic Extent Duration Significant? Inuvik Adverse High Local Short-term No Tuktoyaktuk, Adverse High Local Short-term No Paulatuk, Aklavik Fort McPherson, Adverse Moderate Local Short-term No Tsiigehtchic Holman, Sachs Neutral Low Local Short-term No Harbour
For measures to mitigate substance abuse, see Section 13.3.4.1, Community Well-Being and Delivery of Social Services.
The project proponents will work with GNWT Health and Social Services to design project health and work environment guidelines and procedures for:
• developing medical alert and quarantine protocols
• conducting fitness-for-work assessments
• assessing and caring for ill or injured workers
• enhancing communications and cooperation among medical personnel in the camps and regional and territorial health authorities
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The project effects on health conditions during construction are expected to be adverse and of moderate magnitude in all of the Beaufort Delta Region communities (see Table 13-31). These effects will be of short-term duration, and none are significant.
Table 13-31: Potential Project Effects on Health Conditions
Effect Attribute Geographic Location Direction Magnitude Extent Duration Significant? Inuvik Adverse Moderate Local Short-term No Other Beaufort Delta Adverse Moderate Local Short-term No communities
Effects on health care services are driven by changes in community and regional health conditions, speculative in-migration and problems associated with the recruitment and morale of nurses. The GNWT is engaged in seeking to solve these recruitment and morale issues.
Mitigation measures to discourage speculative in-migration will reduce the risk of overburdening health care facilities (see Section 13.3.2.4, Demography and Population Mobility).
The project effects on the Tuktoyaktuk health care centre and on Inuvik Hospital in-patient services are expected to be adverse and high in magnitude. Effects on health care services in the other Beaufort Delta Region communities are expected to be adverse and moderate in magnitude (see Table 13-32).
Table 13-32: Potential Project Effects on Health Care Services
Effect Attribute Geographic Location Direction Magnitude Extent Duration Significant? Tuktoyaktuk care centre Adverse High Local Short-term No Inuvik Hospital out-patient Adverse High Local Short-term No services Inuvik Hospital in-patient Adverse Moderate Regional Short-term No services Other Beaufort Delta Adverse Moderate Local Short-term No Region health care centres
13.3.4.3 Human Health Risks
During both construction and operations, the project will have no effects on air, water or soil quality that could induce adverse effects on the health of humans, plants or animals.
Concerns were expressed in some communities about emissions from diesel trucks parked with engines idling near communities. Relevant mitigation includes using vehicles that burn low-sulphur diesel fuel and avoiding idling engines in vehicles parked near communities. The effects of diesel exhaust on human health
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13.3.4.3 Human Health Risks (cont’d)
are expected to be adverse, low-magnitude, local and short-term, and not significant.
13.3.4.4 Public Safety and Protection Services
Many RCMP detachments in the Beaufort Delta Region report that they are overburdened. During the Construction Phase, police will be affected by having to address any increased problems in the communities they serve, and occasional problems in camps.
Controlling alcohol and drug abuse will be the most effective way to mitigate many policing problems (see Section 12.3.4.1, Community Well-Being and Delivery of Social Services). However, because substance abuse problems are difficult to resolve, these measures will only be moderately effective.
Given the increased likelihood of substance abuse and derivative problems that the increased community earnings from project construction might bring, Construction Phase effects on local policing are expected to be adverse, high in magnitude in Inuvik, and from low to moderate in magnitude in other Beaufort Delta Region communities. The geographic extent will be local and of short-term duration. Thus, these effects are considered not significant.
There will be no need for mitigation and no residual effects on policing services during the Operations Phase.
13.3.4.5 Education Attainment and Services
Education attainment and services in the study area will be somewhat affected by the project. Some adolescents will respond to employment opportunities by leaving school prematurely, and some former dropouts might return to qualify for more training. Children of in-migrants could increase enrollment pressures. Therefore, enrollment pressures and project-related changes in education and training programs might increase or decrease. Some effects might tend to carry on from construction into operations.
The schools, project personnel and community members will seek to discourage adolescents from leaving school early. Measures previously described in Section 13.3.2.4, Demography and Population Mobility, to discourage in-migration to regional centres, which might increase enrolment, will be relevant as well.
Project construction and operations effects on education attainment, as well as on education facilities and services, are expected to be positive and adverse in all communities, and of moderate magnitude and local extent in Inuvik. The effects in the remaining Beaufort Delta Region communities are expected to be low in magnitude and local in extent.
Construction Phase effects on education facilities and services are expected to be positive and adverse, moderate in magnitude and local in Tuktoyaktuk, positive
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and neutral, low in magnitude and regional in Inuvik, and generally neutral in the remaining study area communities.
During the Operations Phase, effects on education attainment are expected to be positive, moderate in magnitude, and local in Inuvik, and positive, low in magnitude and local in the other Beaufort Delta Region communities. Effects on education facilities and services in Inuvik and Tuktoyaktuk are expected to be positive, low in magnitude, local and regional in extent. In other Beaufort Delta Region communities, there would be no effect on education facilities and services during project operations.
None of the project effects on education attainment or education facilities and services are predicted to be significant for either the construction or the operations phases.
13.3.5 TRADITIONAL CULTURE
13.3.5.1 Traditional Harvesting and Land Use
Two issues relate to traditional harvesting at Niglintgak:
• the effects of the barge option on marine harvest • the project effects on harvesting activity generally
The Inuvialuit, and in particular the hunters and trappers’ committees, have identified the Niglintgak barge option as an option that could affect traditional harvesting. During the public participation process, specifically, the Inuvialuit Settlement Region–Gwich’in Settlement Area Regional Workshop held in Inuvik, individuals expressed concerns about marine habitats in the region, and the effects that barge traffic and potential dredging would have on beluga whales, herring and marine birds in the Mackenzie Delta. According to participants, potential disturbances of the river bottom would affect the herrings’ use of that area. This would, in turn, affect both the herring harvest by people and, potentially, the beluga’s use of the region, as the herring is a food source for the whale. Additionally, the vibration resulting from the potential dredging and barge traffic could affect beluga and marine bird use of the region.
Although the barge option for the Niglintgak field could affect subsistence harvesting in the area, further information obtained from the ongoing traditional knowledge and environmental studies will better inform this assessment. The EIS biophysical effects assessment concluded that beluga habitat availability, movement and mortality are not expected to be significantly affected. Further, although some localized and short-term physical displacement could occur, it is unlikely that there would be a loss of harvesting opportunity.
A detailed mitigation plan will be prepared when the traditional knowledge studies currently underway provide spatial and temporal information related to sensitive traditional land use or subsistence harvesting areas. The bathymetric and environmental studies conducted during the summer of 2004 will also
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13.3.5.1 Traditional Harvesting and Land Use (cont’d)
provide more detailed information related to potential dredging requirements and their subsequent effect on marine habitats.
Harvesting activities and seasonal wage employment are now symbiotic, because low incomes from trapping necessitate wage employment to pay for the expensive equipment now needed for efficient harvesting. The project will provide wage employment that might support harvesting equipment and expense requirements.
Project employment could jeopardize harvester lore and disciplines by pre- empting harvesting opportunities because of time needed for employment. Some Aboriginal workers might find the paid work more rewarding than harvesting, promoting interest in a southern lifestyle. However, Aboriginal workers could also react negatively and strengthen their appreciation of the more traditional relationships and the lifestyle they enjoy at home.
Elders are powerful influences for sustaining tradition. The project will aid their efforts and help meet the traditional food requirements of communities by providing Aboriginal workers with flexible work schedules to accommodate traditional pursuits, where feasible.
The project will also provide cultural-awareness training to workers and support community-based initiatives that promote traditional harvesting, lifestyles and positive community relationships, such as:
• traditional harvesting training camps for young people • traditional skills proficiency demonstrations or competitions
Low-magnitude adverse effects on harvesting activity are expected in Inuvik (see Table 13-33). The availability of project employment in the Beaufort Delta Region is expected to have moderate adverse effects on harvesting in the other communities in the region.
Most employment opportunities generated by the project will end once construction and associated restoration activities are complete. Accordingly, no project effects on traditional harvesting or culture are expected.
Table 13-33: Potential Mackenzie Gas Project Effects on Traditional Harvesting
Effect Attribute Location Direction Magnitude Geographic Extent Duration Significant? Beaufort Delta Adverse Moderate Regional Short-term No Region Inuvik Adverse Low Local Short-term No
13.3.5.2 Preserving Traditional Language and Culture
The effects of the project on cross-generation transference of traditional language skills, and knowledge of, and identification with, traditional culture are central to
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questions about language and culture retention. As in the case of resource harvesting, project influences might either strengthen or weaken language and culture.
Recent surveys have shown a decline in the use of Aboriginal languages in all regions. Fluency declined by 11% between 1989 and 1999 in the Northwest Territories as a whole. This erosion of fluency in Aboriginal languages is already strongly influenced by the use of English in the media, schools and most work situations. As a result, project employment will likely have little effect on language and cultural retention.
Nevertheless, to help counteract these influences, the project will support community-based initiatives that promote traditional culture, lifestyle and positive community relationships, such as:
• Aboriginal language-proficiency demonstrations or competitions
• cultural activities and events that are consistent with the proponents’ principles and practices for community involvement
Workers will have access in camps to Aboriginal language reading material, radio and television broadcasts, and tapes and CDs, where available.
Because previous exposure to English has been so great, only low-magnitude adverse effects on traditional language and culture retention are expected in most communities. No effects are expected in Inuvik, Norman Wells, Yellowknife and Hay River (see Table 13-34). Most employment opportunities generated by the project will end once construction and associated restoration activities are complete. Accordingly, no project effects on traditional harvesting or culture are expected.
Table 13-34: Potential Project Effects on Language and Culture Preservation
Effect Attribute Location Direction Magnitude Geographic Extent Duration Significant? Beaufort Delta Adverse Low Regional Short-term No Region Inuvik Adverse No effect Local Short-term No
13.3.6 NON-TRADITIONAL LAND AND RESOURCE USE
The Niglintgak field is located within federal crown lands. No impact on land ownership is expected because of this development.
There is little physical presence on the landscape affecting visual or aesthetic value. Oil and gas exploration activities have previously taken place in the Niglintgak field area, and it is unlikely that the lands will be developed for other than oil and gas production purposes. Activities taking place at Niglintgak throughout the life of the field could affect tourism activities, mostly through aesthetic impacts. No specific tourism activities have been identified as occurring
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13.3.6 NON-TRADITIONAL LAND AND RESOURCE USE (cont’d)
near Niglintgak. However, there could still be occasional recreational use of the area. The quality of recreational activities in the area could be affected by sensory disturbance from increased traffic, noise and emissions during construction, particularly for those activities that could be enjoyed by local community members, such as snowmobiling.
Table 13-35 shows the combined effects of the Mackenzie Gas Project on non- traditional land and resource use for the Beaufort Delta Region.
Table 13-35: Potential Project Effects on Non-Traditional Land and Resource Use
Effect Attribute Valued Geographic Component Impact Direction Magnitude Extent Duration Significant? Granular Decrease in available land base Neutral to No effect to Local Short-term to No resources for granular extraction adverse low long-term Change to existing granular Positive or Moderate Local to Short-term No operations adverse regional Positive Low Regional Long-term No Loss of granular resources Adverse Moderate Regional Short-term to No long-term Adverse Low Regional Long-term No Net effect on granular resources Adverse Low Regional Long-term No Oil and gas Decrease in available land base Adverse Low Local Short-term to No activities for other oil and gas activities long-term Changes in other oil and gas Positive to No effect to Local to Short-term to No activities adverse low regional long-term Non- Decrease in available land base Adverse Low Local Short-term to No traditional for resource harvesting activities long-term resource Change in non-traditional hunting Adverse Low to Regional Short-term No harvesting and fishing success moderate Neutral to No effect to Local Long-term No adverse low Change in resource harvesting Positive or Low Local Short-term to No opportunities adverse long-term Tourism and Decrease in available land base Neutral to No effect to Local to Short-term to No recreation for tourism and outdoor adverse low regional long-term recreation activities Change to tourism and recreation Neutral to No effect to Local to Short-term No activities adverse low regional Positive to No effect to Local to Long-term No adverse low regional Change in quality of tourism and Neutral to No effect to Local to Short-term No outdoor recreation adverse low regional Positive to No effect to Local to Long-term No adverse low regional Change to summer tourist and Neutral to No effect to Local to Short-term to No recreational boat traffic in the adverse low regional long-term Mackenzie River and Mackenzie Delta
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13.3.6.1 Protected Areas
Project effects on environmentally protected areas in the Inuvialuit Settlement Region are discussed on a regional basis, as the effects are geographically specific. The land and resource use that takes place in these protected areas is governed by the land-use categories identified in the Community Conservation Plans (CCPs) in the Inuvialuit Settlement Region. They range from Category A, lands with no known significant and sensitive cultural or renewable resources, to Category E, lands where cultural or renewable resources are of extreme significance and sensitivity.
Development of Niglintgak will result in a decrease in the total land base of the Kendall Island Bird Sanctuary for the life of the project. This could result in an adverse effect on the protected resources within this area, specifically the migratory birds. Activities that occur in the winter will not have a marked effect on the sanctuary, as no birds are present during this time. However, some spring and summer activities will be required, and these activities could affect the migratory bird population that uses the Kendall Island Bird Sanctuary.
Niglintgak is located within several areas designated as Inuvialuit Category C lands for:
• spring goose harvesting • fall goose harvesting • important migratory bird habitat
The Inuvialuit CCPs allow development within these areas, but recommend managing these areas to eliminate, to the greatest extent possible, potential damage and disruption. It is expected that this recommendation will be met following implementation of project mitigation measures.
The proposed route for bringing the barge-based processing facility to the Niglintgak site is around Alaska to the Tuktoyaktuk area, through Kittigazuit Bay, up the East Channel of the Mackenzie River and then down the Middle Channel of the Mackenzie River to the Niglintgak site. The Kittigazuit Bay area includes a Beluga Management Zone 1A and is classified as Category E by the Inuvialuit CCPs. All zones classified as Beluga Management Zone 1A are under consideration to become Marine Protected Areas.
The Beaufort Sea Beluga Management Plan states:
All shipping activities (including dredging) should be confined to designated routes and areas. Passage through or close to Zone 1 outside of designated routes, even if it is the shortest route, should be avoided from breakup to August 15.
This indicates that dredging and shipping are permitted within zones classified as Beluga Management Zone 1A at all times of the year, as long as the activity is taking place along a designated route. The plan also indicates that designated routes are “those marine transportation corridors established, following
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13.3.6.1 Protected Areas (cont’d)
consultation with the Department of Fisheries and Oceans, by Transport Canada.”
The EIS biophysical effects assessment has concluded that beluga habitat availability, movement and mortality are not expected to be significantly affected. Furthermore, although some localized and short-term physical displacement could occur, it is unlikely that there would be a loss of harvesting opportunity.
13.3.6.2 Visual and Aesthetic Resources
Terrain features limit the line-of-sight to areas on and around Niglintgak, but a new industrial presence in the area and associated lighting will be noticeable to land travellers and people in aircraft.
No significant effects are expected. Visual and aesthetic resources will be most noticeable on the ground at a local scale or from the air on a regional level.
13.3.7 HERITAGE RESOURCES
13.3.7.1 Archaeological Investigations
Heritage resources are non-renewable resources that might be located at or near the ground surface and, therefore, are highly susceptible to any activities disturbing the ground. They are defined and managed by GNWT legislation.
Based on community and regulatory input, the key issues relating to heritage resources include loss of, or damage to, historical, cultural, archaeological and palaeontological resources. The methods used for project-focused field reconnaissance and heritage resources impact assessment are considered standard for archaeological investigations of this type in the region. As the infrastructure and borrow sites are not specific to the anchor fields, they are included in this discussion.
For the anchor fields, including Niglintgak, two crews of three to four people completed investigations in the summer and fall of 2002 and 2003. Areas of investigation were selected based on aerial photographs, NTS map analysis and helicopter overflight. Field investigations involved qualitatively assessing the heritage resource potential of each proposed development area and photographing the locations investigated. Because of the large area encompassed by these anchor fields, only parts of each were subject to ground inspection.
Fifty-one heritage resource sites were recorded in the Inuvialuit Settlement Region. Only two are located within the Niglintgak study area. Heritage Resource Impact Assessments will be completed before development begins.
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13.3.7.2 Infrastructure Investigations
Twelve infrastructure locations were inspected in the Inuvialuit Settlement Region as part of the 2002 focused reconnaissance, and an additional nine locations were investigated in 2003. Some assessment-level investigations were possible in 2003 because of the more refined level of location information available. Two prehistoric sites and four historic sites have been recorded as being in potential conflict with production area infrastructure.
13.3.7.3 Borrow Site Investigations
Seventeen borrow sites were inspected in the Inuvialuit Settlement Region as part of the granular resource component of the 2002 reconnaissance. In 2003, 15 borrow sites were subject to reconnaissance and assessment-level investigations. For most of the locations, the level of investigation was typically concentrated on a limited area. Because of scheduling issues, definitive alignments were not available for the access roads associated with the borrow sites. Therefore, few access roads were inspected. Seven sites were inspected, including both prehistoric and historic sites. These were recorded as being in potential conflict with the borrow sites.
A list of all sites identified is contained in EIS Volume 6: Socio-Economic Impact Assessment.
The studies completed to date have focused on key resources and landforms within zones that might be developed for the project, with the intent of assisting in planning future research strategies and formulating recommendations for the final impact assessment. The heritage resources program designed for the project recognizes these uncertainties and has adopted a staged approach that will provide increasing levels of precision for assessment of the heritage resource effects of the project. When full information on present resources and expected effects is gathered, mitigation programs will be implemented to offset or reduce predicted negative effects. Without the information that will be forthcoming as the project unfolds and is approved, mitigation can only be discussed in general terms. Mitigation strategies are usually devised when full information on effects is known, and are made in consultation with the regulatory agency responsible for heritage resource management in the Northwest Territories – the Prince of Wales Northern Heritage Centre.
13.3.8 TRADITIONAL KNOWLEDGE
Traditional knowledge studies are being conducted with affected communities in relation to the project sites and activities in the Niglintgak area. Traditional knowledge is being collected to help in project planning and to provide information for the regulatory process. As the traditional knowledge studies are still underway, supplemental information will be provided to northern regulators and the Joint Review Panel on this subject. As an interim measure, existing traditional knowledge sources have been reviewed and considered in the EIS. For further information on the traditional knowledge study process, see EIS Volume 1: Overview and Impact Summary.
August 2004 Shell Canada Limited 13-39 NDPA-P1 Section 13.3 ENVIRONMENTAL AND SOCIO-ECONOMIC SOCIO-ECONOMIC IMPACTS IMPACTS
13.3.8 TRADITIONAL KNOWLEDGE (cont’d)
Traditional knowledge studies underway have been designed with community input and participation. Community or regional organizations have been engaged to undertake traditional knowledge studies relevant to the project.
The traditional knowledge program includes:
• reviewing existing information • collecting and validating new information • producing traditional knowledge baseline reports
Traditional knowledge working groups have been established in the Inuvialuit Settlement Region and the Gwich’in Settlement Area. The purpose of the working groups is to develop a framework, determine content, establish a schedule and provide guidance for the traditional knowledge study.
Once the research is undertaken, the studies are expected to document data related to such topics as:
• mammals • birds • fisheries • vegetation • surface and groundwater flows • historical, cultural and spiritual sites
The data collected during the traditional knowledge program will be integrated with the other components of the environmental and socio-economic studies being undertaken for the project. Available and relevant traditional knowledge will be given full consideration and incorporated into each of the studies associated with the project.
As the community and regional traditional knowledge studies are still underway, existing traditional knowledge sources have been reviewed as an interim measure to provide as much information as possible for the EIS, pending completion of the community studies. The information collected during this review has been provided to appropriate members of the project environmental team for use in the EIS, and will be distributed to traditional knowledge working groups that have not completed their studies. The working groups will be asked to review and validate the documented information and will be encouraged to incorporate any relevant information into the traditional knowledge studies being conducted.
13-40 Shell Canada Limited August 2004 NDPA-P1 Section 14.1 CAPITAL AND OPERATING COSTS
APPLICATION FOR APPROVAL OF THE DEVELOPMENT PLAN FOR NIGLINTGAK FIELD PROJECT DESCRIPTION COST ESTIMATE BASIS
14.1.1 SCOPE
This section provides cost information for developing the Niglintgak field, including:
• historical drilling, seismic and development capital expenditures • estimated future development capital costs over the development’s life • estimated future annual operating costs
Only those costs directly associated with the development of the Niglintgak gas field are included in these estimates. Costs associated with developing other components of the Mackenzie Gas Project are documented in separate regulatory applications.
14.1.2 HISTORICAL COSTS
Historical costs for the Niglintgak field include expenditures for:
• exploration and delineation drilling • well evaluations • seismic acquisition and processing • regulatory preparation • abandonment and reclamation
These historical costs have been categorized and adjusted to constant 2003$, based on annual average Consumer Price Index (CPI) information. Table 14-1 outlines Niglintgak expenditures from 1970 to 2003, including conceptual engineering costs associated with preparing the current development plan application.
August 2004 Shell Canada Limited 14-1 NDPA-P1 Section 14.1 CAPITAL AND OPERATING COSTS COST ESTIMATE BASIS
Table 14-1: Costs for Niglintgak Field – 1970 to 2003
As Spent ($Million) Total Regulatory CPI Index Costs Year Drilling Seismic Preparation Total Costs (millions) ($Million) 1969 0 0.1 0 0.1 5.2 0.7 1970 0 0.1 0 0.1 5.0 0.7 1971 0 0.2 0 0.2 4.9 0.8 1972 0 0.7 0 0.7 4.7 3.1 1973 4.9 0.4 0 5.3 4.4 23.1 1974 3.7 0.6 0 4.3 3.9 16.8 1975 9.3 0.1 0 9.4 3.5 33.3 1976 9.8 0.3 0 10.2 3.3 33.3 1977 0 0 0 0 3.0 0 1978 0 0 0 0 2.8 0 1979 0 0 0 0 2.6 0 1980 0 0 0 0 2.3 0 1981 0 0 0 0 2.1 0 1982 0 0 0 0 1.9 0 1983 0 0 0 0 1.8 0 1984 0 0 0 0 1.7 0 1985 0 0 0 0 1.6 0 1986 0 0 0 0 1.6 0 1987 0 0 0 0 1.5 0 1988 0 0 0 0 1.4 0 1989 0 3.2 0 3.2 1.4 4.3 1990 0 0 0 0 1.3 0 1991 0 0 0 0 1.2 0 1992 0 0.1 0 0.1 1.2 0.1 1993 0 0 0 0 1.2 0 1994 0 0 0 0 1.2 0 1995 0 0 0 0 1.2 0 1996 1.4 0 0 1.4 1.1 1.6 1997 0 0 0 0 1.1 0 1998 0 0 0 0 1.1 0 1999 0 0 0 0 1.1 0 2000 0 0 0.3 0.3 1.1 0.3 2001 0 0 0.9 0.9 1.0 0.9 2002 0 0 0.7 0.7 1.0 0.7 2003 0 0 4.2 4.2 1.0 4.2 Total 29.1 5.9 6.1 41.1 N/A 123.9 Note: Numbers might not add up because of rounding.
14-2 Shell Canada Limited August 2004 NDPA-P1 Section 14.2 CAPITAL AND OPERATING COSTS
APPLICATION FOR APPROVAL OF THE DEVELOPMENT PLAN FOR NIGLINTGAK FIELD PROJECT DESCRIPTION CAPITAL COST ESTIMATE
14.2.1 SCOPE
The current capital cost estimate for the Niglintgak development is based on the conceptual design described in this development plan application. Although the conceptual design will be further refined, this cost estimate is believed to be accurate for the scope defined. The capital cost estimate includes costs for:
• regulatory application preparation • well drilling and completions • project management • design, procurement and construction of production facilities and flow lines • procurement of materials and services • precommissioning
14.2.2 DRILLING AND COMPLETIONS
Drilling and completion cost estimates are based on:
• drilling six production wells and one disposal well. Incremental future wells to further optimize recovery have not been included.
• drilling operations conducted over three winters, using two drilling rigs
• drilling time estimates, based on the proposed well designs, considering Niglintgak’s drilling conditions and recent exploration well drilling performance for the Mackenzie Delta
• material and time estimates for well completion and testing, based on conceptual well designs, and considering arctic conditions
• materials and services costs that are based on vendor quotes and include transportation from the source to Niglintgak
The cost estimates also include:
• modification of existing drilling equipment for arctic conditions • transportation and standby costs for equipment and personnel • mobilization and demobilization of drilling equipment and camps
August 2004 Shell Canada Limited 14-3 NDPA-P1 Section 14.2 CAPITAL AND OPERATING COSTS CAPITAL COST ESTIMATE
14.2.3 FACILITIES
The Niglintgak capital cost estimates were factored from major equipment requirements to estimate the installed cost of production facility units. These estimates were based on:
• the conceptual process design (see Section 7, Production Facilities)
• using both Shell’s and contractors’ historical cost databases containing information on similar projects or similar locations
• budgetary quotes for specific major equipment acquired from vendors
• historically derived factors for major equipment bulks
• experience of labour productivity in different construction locations
• transportation, infrastructure and logistics costs estimated from combined vendor and historical cost information
• average gas conditioning facility fabrication costs associated with international construction
• 2003 estimates of construction equipment and labour rates
14.2.4 PRELIMINARY COST ESTIMATE
The preliminary capital cost estimate (see Table 14-2) is based on:
• an accuracy level of +25/-15% and an equal chance of overrun and underrun
• an assumption that adequate labour and construction resources are available to complete the development as planned
• contingencies of 15 to 20% for different elements of the development
• the exclusion of the goods and services tax (GST) and provincial sales tax for any materials, equipment or services
• constant 2003$ Cdn subject to the annual inflation rate when capital costs are incurred
• an assumption that goods and services will be acquired on an internationally competitive basis
14-4 Shell Canada Limited August 2004 NDPA-P1 Section 14.2 CAPITAL AND OPERATING COSTS CAPITAL COST ESTIMATE
Table 14-2: Preliminary Capital Cost Estimate ($Million 2003)
Regulatory Application Facilities Development Year Support1 Construction Drilling Total 2004 3.6 0.0 0.6 4.2 2005 6.4 0.0 0.7 7.1 2006 9.0 23.4 4.7 37.1 2007 0.0 119.0 30.8 149.8 2008 0.0 70.0 43.0 113.0 2009 0.0 21.0 32.0 53.0 Total 19.0 233.4 111.8 364.2 Note: 1. Includes Niglintgak predevelopment project management costs.
August 2004 Shell Canada Limited 14-5 NDPA-P1 Section 14.3 CAPITAL AND OPERATING COSTS
APPLICATION FOR APPROVAL OF THE DEVELOPMENT PLAN FOR NIGLINTGAK FIELD PROJECT DESCRIPTION ANNUAL OPERATING COST ESTIMATE
14.3.1 SCOPE
Annual cost estimates for the operation and maintenance of the Niglintgak field were prepared based on:
• six production wells and one disposal well • 10 km of flow lines • a gas conditioning facility that includes:
• separation • compression • dehydration • refrigeration
• gas conditioning utilities systems
14.3.2 OPERATING AND MAINTENANCE COSTS
The operating and maintenance cost estimate for Niglintgak is based on Shell’s experience in gas field operations throughout Canada. Alberta-based operating costs were adjusted to reflect operating remote arctic facilities. Periodic major maintenance activities and well interventions were included in developing an average annual cost estimate over the life of the facility.
The operating cost estimate includes costs for:
• well pad operations, including periodic well interventions and routine maintenance
• on-site and off-site operations and maintenance staff
• routine and major maintenance costs for production facilities
• all consumables, goods and materials for well pads, flow lines and the gas conditioning facility
• routine inspections
• accommodation and catering for on-site personnel
August 2004 Shell Canada Limited 14-7 NDPA-P1 Section 14.3 CAPITAL AND OPERATING COSTS ANNUAL OPERATING COST ESTIMATE
14.3.2 OPERATING AND MAINTENANCE COSTS (cont’d)
• logistics and transportation support
• property taxes, access fees and insurance
• management and administration (local and head office)
• abandonment and reclamation
Fuel gas will be supplied from the processed gas stream leaving the facility and is included as gas shrinkage, not as an operating cost.
Table 14-3 shows the preliminary operating cost estimate for the Niglintgak field in constant 2003$.
Table 14-3: Preliminary Annual Average Operating Cost Estimate ($Million 2003)
Activity Total Operations 1.2 Maintenance 2.7 Logistics 3.2 Well work 0.7 Modifications 0.2 Taxes and access 1.2 Management and administration 0.9 Total cost 10.1
14-8 Shell Canada Limited August 2004 NDPA-P1 Section 15.1 LIABILITY AND COMPENSATION
APPLICATION FOR APPROVAL OF THE DEVELOPMENT PLAN FOR NIGLINTGAK FIELD PROJECT DESCRIPTION LIABILITY
15.1.1 SCOPE
The construction, operation and abandonment of projects such as the Niglintgak field development expose a proponent to potential liability. Federal legislation and policy expressly impose liability on operators engaging in activities that could potentially harm the environment. For example, the Fisheries Act will impose liability on those responsible for an uncontrolled or unauthorized release of harmful substances into the environment in a way that threatens fish or fish habitat.
In addition to federal legislation and policies, several territorial statutes, such as the Territorial Waters Act, impose liability with respect to the operations and abandonment of oil and gas developments in the North. Liability might also arise as a result of agreements entered into between the proponent and private landowners, such as the Inuvialuit.
Even if the issue of liability is addressed within a statutory regime, civil liability could still arise as a result of project-related activities. Because legislation and government policy are subject to change, further liabilities could possibly arise over the expected life of Niglintgak.
15.1.2 CANADA OIL AND GAS OPERATIONS ACT
Under the Canada Oil and Gas Operations Act (COGOA), an operator can be held liable for failing to comply with the requirements outlined in COGOA or any orders made under that Act. As well as preserving civil liabilities and remedies, COGOA imposes liability for:
• loss or damage suffered by any person as a consequence of a spill or an authorized release of oil or gas
• costs reasonably incurred by the Government of Canada in taking any action in relation to a spill or authorized release of oil or gas
August 2004 Shell Canada Limited 15-1 NDPA-P1 Section 15.1 LIABILITY AND COMPENSATION LIABILITY
15.1.3 INUVIALUIT FINAL AGREEMENT
The Inuvialuit Final Agreement also outlines the potential liability issues associated with compensation to wildlife harvesters as a result of development activities.
15.1.3.1 Wildlife Harvester Provisions
Where it is established that a development has or will cause wildlife harvest loss or future wildlife harvest loss, a developer will be required to provide a remedy, which could include compensation, property replacement, or remediation and reclamation of damaged wildlife habitat. The Inuvialuit Final Agreement does not require any proof of fault or negligence, as the liability is considered absolute.
15.1.3.2 Worst Case Scenario Assessment
The Inuvialuit Final Agreement mandates the Inuvialuit Environmental Impact Review Board to assess the worst-case scenario associated with a proposed development in the Inuvialuit Settlement Region. As part of this assessment, the Board is to provide an estimate of the developer’s potential liability. The Joint Review Panel that has been established to perform the environmental review of the Mackenzie Gas Project, including Niglintgak, will assess the potential liability that might arise from the worst-case scenario.
15-2 Shell Canada Limited August 2004 NDPA-P1 Section 15.2 LIABILITY AND COMPENSATION
APPLICATION FOR APPROVAL OF THE DEVELOPMENT PLAN FOR NIGLINTGAK FIELD PROJECT DESCRIPTION COMPENSATION
15.2.1 SCOPE
The proponent of a project, such as Niglintgak, might be required to provide compensation for damages and losses caused by its development. The compensation requirements are set out in legislation, but might also be found in freely negotiated agreements or agreements arising from various dispute resolution mechanisms.
15.2.2 HARVESTERS’ COMPENSATION AGREEMENT
In accordance with the terms of the Inuvialuit Final Agreement, once the determination of the worst-case scenario for Niglintgak is made, Shell and the Inuvialuit Game Council will complete their negotiation of a Harvesters’ Compensation Agreement. This agreement will deal with wildlife harvest loss and might address compensation, property replacement, remediation and reclamation of damaged wildlife habitat.
15.2.3 ENVIRONMENTAL AGREEMENT
Shell is also engaged in negotiating an environmental agreement with the Government of the Northwest Territories. This agreement is intended, in part, to address the potential liabilities that could arise as a consequence of the development of Niglintgak.
15.2.4 PROOF OF FINANCIAL CAPABILITY
Under COGOA and the related Canada Oil and Gas Production and Conservation Regulations, Shell will be required to provide proof of financial capability to complete the work proposed under its Development Plan. The proof could take any form satisfactory to the NEB, including a line of credit, a guarantee or an indemnity bond. In addition, proof of financial capability might be required by territorial legislation or mandated in the agreements entered into with the Inuvialuit Game Council and the Government of the Northwest Territories.
August 2004 Shell Canada Limited 15-3 NDPA-P1
APPLICATION FOR APPROVAL OF THE DEVELOPMENT PLAN FOR NIGLINTGAK FIELD GLOSSARY PROJECT DESCRIPTION
% The symbol for percent.
° The symbol for degrees.
°C The symbol for degrees Celsius.
°F The symbol for degrees Fahrenheit.
2-D The abbreviation for two-dimensional.
3-D The abbreviation for three-dimensional.
3-D dynamic reservoir A model built using Shell’s proprietary software (MULTISIM) which was model used to predict the field gas off-take rate with time, gas recovery and resources, under specific reservoir and operating conditions.
3-D static geological 7A 3-D static model of the subsurface created using Shell’s proprietary model modelling software (DEPSIM). a The metric symbol for year. abandoned well A well not in use because it was a dry hole originally, because it has ceased to produce or because it was not capable of economic production. abandonment The act of permanently stopping operations, discontinuing service, removing facilities and restoring land to a productive state.
Aboriginal person Any Indian, Inuit or Métis person who was born in the Northwest Territories or who is descended from an Aboriginal person born in the Northwest Territories. access road A temporary or permanent road that provides access to a pipeline right-of- way or to a facility, and that is not open to the general public. adfreezing The process by which one object adheres to another by the binding action of ice. aggradation The gradual buildup of land on a shore as a result of wave action, tides, currents, airborne material or alluvial deposits. Also known as accretion.
ALARP The abbreviation for as low as reasonably practicable. alkaline Having the nature of an alkali, i.e., having a pH above 7.
August 2004 GL-1 NDPA-P1 GLOSSARY
alluvial Relating to or consisting of alluvium, or deposited by running water. all-weather road A paved or unpaved, i.e., gravel, road that is open to traffic all year. amplitudes The shapes and heights of the peaks in a spontaneous potential curve. amsl The abbreviation for above mean sea level. anchor fields The three natural-gas fields, Taglu, Parsons Lake and Niglintgak, whose production will provide the initial volume of gas shipped in the Mackenzie Valley pipeline. annulus The space surrounding a pipe in the wellbore, or the space between tubing and the wellbore. Also known as annular space.
ANSI The abbreviation for American National Standards Institute. anticline Rock layers folded in the shape of an arch, in which the strata slope down from the crest. Anticlines sometimes trap oil and gas.
APG The abbreviation for Aboriginal Pipeline Group.
API The abbreviation for American Petroleum Institute. aquatic Growing, living in, or frequenting water. Also, occurring or situated in or on water. aquifer A water-saturated, permeable body of rock capable of transmitting significant or usable quantities of groundwater to wells and springs under ordinary hydraulic gradients. aquitard A bed of low permeability adjacent to an aquifer, which might serve as a storage unit for groundwater, although it does not yield water readily. argillaceous Rocks or sediments largely composed of clay-size particles or clay minerals.
ASME The abbreviation for American Society of Mechanical Engineers. asphaltene Any of the dark, solid constituents of crude oil or bitumen that are soluble in carbon disulphide but insoluble in paraffin naphthas. They hold most of the organic constituents of bitumen.
ASTM The abbreviation for American Society for Testing and Materials. authigenic Of constituents that came into existence with or after the formation of the rock of which they constitute a part. For example, the primary and secondary minerals of igneous rocks.
GL-2 August 2004 NDPA-P1 GLOSSARY
availability Unit of measure for the actual time a facility, pipeline, or other equipment is capable of providing service, if called upon. azimuth The direction of the wellbore in directional drilling, or the face of a deflection tool in degrees. baseline A surveyed condition that serves as a reference point to which later surveys are coordinated or correlated. bathymetric The science of measuring ocean depths in order to determine the sea floor topography. bbl/d The abbreviation for barrels per day.
BC The abbreviation for British Columbia.
Bcf The abbreviation for billion cubic feet.
Bcf/d The abbreviation for billion cubic feet per day. bedrock The solid rock underlying soil or any other unconsolidated surficial cover. benefits plan A plan to provide Aboriginal and other northerners and other Canadians with a fair opportunity to participate competitively in supplying the goods, services and personnel required by the project. bentonite A type of clay derived from the alteration of volcanic ash. berm A mound or wall of earth. bioturbation The disruption of marine sedimentary structures by the activities of benthic organisms. blowdown The act of emptying or depressurizing material in a vessel. blowout preventer Any one of several types of valves used on the wellhead to prevent the loss of pressure either in the annular space between drill pipe and casing or in the open hole during drilling completion operations.
BOP The abbreviation for blowout preventer. borehole The hole made by drilling or boring. borrow site An area that could be excavated to provide material, such as gravel or sand, to be used as fill elsewhere.
C1 The chemical formula for methane.
C2 The chemical formula for ethane.
August 2004 GL-3 NDPA-P1 GLOSSARY
C3 The chemical formula for propane.
C4 The chemical formula for normal butane.
C5 The chemical formula for pentane.
C6 The chemical formula for hexane or toluene.
C7+ The chemical formula for heptane plus.
C8 The chemical formula for normal octane. capillary pressure A pressure or adhesive force caused by the surface tension of water. This pressure causes the water to adhere more tightly to the surface of small pore spaces than to larger ones. Capillary pressure in a rock formation is comparable to the pressure of water that rises higher in a small glass capillary tube than it does in a larger tube. casing Steel pipe placed in an oil or gas well, as drilling progresses, to prevent the wall of the hole from caving in during drilling, to prevent seepage of fluids, and to provide a means of extracting petroleum if the well is productive.
CDD The abbreviation for Commercial Discovery Declaration.
CEAA The abbreviation for Canadian Environmental Assessment Act. Also, the abbreviation for the Canadian Environmental Assessment Agency. chert A rock of precipitated silica whose crystalline structure is not easily discernable and that fractures conchoidally (like glass). Flint, jasper and chat are forms of chert. clast A sedimentary rock consisting of fragments of pre-existing rocks. clay The fraction of an earthy material containing the smallest particles, i.e., particles finer than 3 µm. cm The metric symbol for centimetre.
CO2 The chemical formula for carbon dioxide.
COGOA The abbreviation for Canada Oil and Gas Operations Act. commissioning The act of charging a system and doing checkouts to ensure that equipment functions safely before start-up. completion, well The activities and methods of preparing a well for the production of oil and gas or for other purposes, such as injection. compression, gas The process of increasing the pressure on gas to reduce its volume or cause it to flow. Natural gas is usually compressed for pipeline transportation.
GL-4 August 2004 NDPA-P1 GLOSSARY
compressor station A facility containing equipment that is used to increase pressure to compress natural gas for transportation. conglomerate Cemented, rounded fragments of water-worn rock or pebbles, bound by a cement-like substance.
ConocoPhillips The abbreviation for ConocoPhillips Canada (North) Limited. continuous permafrost A category of permafrost where more than 90% of all ground is frozen. Permafrost distribution along the Mackenzie Valley varies from extensive and continuous in the north to discontinuous and sporadic in the south.
Cooperation Plan The abbreviation for the Cooperation Plan for the Environmental Impact Assessment and Regulatory Review of a Northern Gas Pipeline Project through the Northwest Territories.
CPCN The abbreviation for Certificate of Public Convenience and Necessity.
Cretaceous The geological period between about 144 and 65 million years before present. crown land Land whose mineral rights are owned by the federal or provincial governments in Canada.
CSA The abbreviation for Canadian Standards Association. decommissioning The act of taking a processing plant or facility out of service and isolating equipment, to prepare for routine maintenance work, suspending or abandoning. dehydration The process of removing water or water vapour from gas or oil. delineation well A well drilled to evaluate the quality, thickness and areal extent of a reservoir. delta An alluvial deposit, usually triangular in shape, at the mouth of a river, stream, or tidal inlet. deltaic Of or relating to a delta. demobilization The process of moving people, supplies and equipment from the work site to another location. development well A well that is drilled after data from an exploration well has confirmed the presence of oil or gas in a formation.
Devonian The geological period between about 408 to 360 to million years before present.
DFO The abbreviation for Department of Fisheries and Oceans.
August 2004 GL-5 NDPA-P1 GLOSSARY
diagenesis All the changes that take place in a sediment at low temperature and pressure after deposition. directional drilling A drilling method in which the wellbore intentionally deviates from the vertical. discontinuous A category of permafrost where some of the underlying ground is permafrost unfrozen. Permafrost distribution along the Mackenzie Valley varies from extensive and continuous in the north to discontinuous and sporadic in the south. dock A berth or wharf, or an artificially enclosed body of water for loading and unloading ships and barges. downhole Pertaining to the wellbore. downthrown The side of a fault whose relative movement appears to have been downward.
DPA The abbreviation for Development Plan Application. drawdown The difference between static and flowing bottomhole pressures. Also, the distance between the static level and the pumping level of the fluid in the annulus of a pumping well. drilling mud The fluid circulated through the wellbore during rotary drilling. dry gas Natural gas from the well that is free of liquid hydrocarbons, or gas that has been treated to remove all liquids.
DST The abbreviation for drill stem test. ecoregion An ecological area that has broad similarities in soil, relief and dominant vegetation. Also referred to as an ecoclimatic region.
ECP The abbreviation for external casing packer.
EEMUA The abbreviation for Engineering Equipment and Materials Users Association.
EIA The abbreviation for Environmental Impact Assessment.
EIS The abbreviation for Environmental Impact Statement.
Enbridge The abbreviation for Enbridge Pipelines (NW) Inc. environmental impact The process of evaluating the biophysical, social and economic effects of a assessment proposed project.
GL-6 August 2004 NDPA-P1 GLOSSARY
environmental impact A report containing the environmental impact assessment. statement
Eocene A geological epoch in the Tertiary Period, extending from about 55 to 38 million years ago.
ESD The abbreviation for emergency shutdown.
ESS The abbreviation for expandable sand screen. estuarine Of or pertaining to estuaries. exploration well A well that is drilled primarily to determine if oil or gas actually exists in a subsurface rock formation.
ExxonMobil The abbreviation for ExxonMobil Canada Properties. facies The total features of a sedimentary rock, including sedimentary structure, lithology and ichnofacies, that characterize a sediment as having been deposited in a given sedimentary environment. fault A fracture in rock along which the adjacent rock surfaces are differentially displaced.
FEED The abbreviation for front-end engineering and design. feldspar A group if silicate minerals that includes a wide variety of potassium, sodium and aluminum silicates. Feldspar makes up about 60% of the outer 15 km of the earth’s crust. flare system An arrangement of piping and burners used to dispose of surplus combustible vapours by igniting them in the atmosphere. flash drum A vessel in which volatile liquids are vaporized, by either heat or vacuum. flow line A pipe through which gas travels from a well to processing equipment or to storage. The pipe is either buried, or installed above-ground. fluvial deposits All sediments, past and present, deposited by flowing water. footprint The amount and shape of the area disturbed. ft The abbreviation for foot.
G The metric symbol for giga (billion or 109). gas, natural A compressible mixture of hydrocarbons with a low specific gravity that occurs naturally in a gaseous form.
August 2004 GL-7 NDPA-P1 GLOSSARY
gathering pipelines Four pipelines, also known as laterals, that transport natural gas and NGLs from the anchor fields to the Inuvik area facility. These include the Taglu lateral, Niglintgak lateral, Parsons Lake lateral and Storm Hills lateral. gathering system A system of pipelines and related facilities that include four gathering pipelines, the Inuvik area facility, the NGL pipeline and related facilities, such as valves, pig launchers and receivers. Also referred to as the Mackenzie gathering system. geology The study or science of the earth, its history, and its life as recorded in the rocks. Includes the study of geologic features of an area, such as the geometry of rock formations, weathering and erosion and sedimentation. geotechnical Related to the application of scientific methods and engineering principles to civil engineering problems, by acquiring, interpreting and using knowledge of materials of the crust of the earth.
GIIP The abbreviation for gas-initially-in-place. glacial till Unsorted sedimentary material deposited directly by, and underneath, a glacier, consisting of a mixture of clay, silt, sand, gravel and boulders. Also known as till. glycol A group of compounds, such as ethylene glycol and diethylene glycol, used to dehydrate gaseous or liquid hydrocarbons, to inhibit the formation of hydrates, or to cool fluids (liquid or gas), by acting as a heat transfer medium.
Gm3 The metric symbol for billion cubic metres.
GNWT The abbreviation for Government of the Northwest Territories. granular resources Material deposits that have a granulated surface or structure, such as gravel. groundwater The water within the earth that supplies water wells and springs.
H2S The chemical formula for hydrogen sulphide. habitat The part of the physical environment in which a plant or animal lives.
HDD The abbreviation for horizontal directional drilling. horizontal directional A river crossing technique used in pipeline construction in which the pipe drilling is buried under the riverbed at depths much greater than conventional crossings. An inverted arc-shaped hole is drilled beneath the river and the preassembled pipeline is pulled through it.
HSE The abbreviation for health, safety and environment.
GL-8 August 2004 NDPA-P1 GLOSSARY
hydrate A mixture of water and gas that forms a solid plug in a gas pipeline under certain conditions. Also known as gas hydrate plug. hydrocarbons Organic compounds of hydrogen and carbon whose densities, boiling points, and freezing points increase as their molecular weights increase. Petroleum is a mixture of many different hydrocarbons. hydrogeology The science dealing with the occurrence of ground water, its use and its functions in modifying the earth, primarily by erosion and deposition. hydrology The science that treats the occurrence, circulation, distribution and properties of the waters of the earth and their reaction with the environment.
IC4 The chemical formula for isobutane.
IC5 The chemical formula for isopentane. ice road A secondary road made of compact snow or ice, often plowed over a frozen lake or ground, and which is impassable in the summer. Also known as a winter road.
ID The abbreviation for inside diameter.
IEEE The abbreviation for Institute of Electrical and Electronic Engineers.
Imperial The abbreviation for Imperial Oil Resources Ventures Limited.
INAC The abbreviation for Indian and Northern Affairs Canada. incident A specific unplanned event or sequence of events that has an unwanted and unintended effect on people’s safety or health, on property or the environment, or on regulatory compliance. infrastructure Basic facilities, such as transportation, communications, power supplies and buildings, that enable an organization, project or community to function. inlet separator A vessel located at the entrance to a hydrocarbon facility that separates the incoming stream into different components, such as gas and liquids. ion An atom, group of atoms or compound that is electrically charged as a result of the loss of electrons (cation) or the gain of electrons (anion).
ISA The abbreviation for Instrument Society of America. kg/m The abbreviation for kilogram per metre. km The metric symbol for kilometre.
August 2004 GL-9 NDPA-P1 GLOSSARY
km2 The metric symbol for square kilometre. kPa The metric symbol for kilopascal. land use permit A permit issued by the designated managing body for a specific tract of land, allowing for an activity to be conducted on that land, as described in a land use application. laydown area An area for placing pipe or tubing in a horizontal position on a pipe rack, or for storing other construction materials temporarily. line heater Equipment used to increase the temperature of natural gas flowing in a pipeline. line of strike The direction taken by a structural surface, such as a fault plane, as it intersects the horizontal. Also known as a strike. litharenite A variety of sandstone containing abundant rock fragment grains. lithology The study of rocks, or the individual character of a rock’s mineral composition and structure. logistics The activities associated with procuring, maintaining and transporting materials, equipment and personnel. m The metric symbol for metre.
M The metric symbol for mega (million or 106). m3 The metric symbol for cubic metres. m3/d The metric symbol for cubic metres per day.
Mackenzie gathering A system of pipelines and related facilities that include four gathering system pipelines, the Inuvik area facility, the NGL pipeline and related facilities, such as valves, pig launchers and receivers. Also referred to as the gathering system. mD The abbreviation for millidarcy.
MD The abbreviation for measured depth. measured depth The total length of the wellbore, measured along its actual course through the earth. Measured depth can differ from true vertical depth, especially in directionally drilled wellbores. meltwater Water derived from melting ice or snow, especially glacier ice. mg/L The metric symbol for milligrams per litre.
GL-10 August 2004 NDPA-P1 GLOSSARY
millidarcy The measurement of permeability. mitigation The elimination, reduction or control of the adverse environmental effects of the project, including restitution for any damage to the environment caused by such effects through replacement, restoration, compensation or any other means. mKB The abbreviation for metres from kelly bushing. mm The metric symbol for millimetre. mm/a The metric symbol for millimetres per year.
Mm3 The metric symbol for million cubic metres.
Mm3/d The metric symbol for million cubic metres per day.
MMscf/d The abbreviation for million standard cubic feet per day. mobilization The movement of people or equipment to the work site. modularized Components that are assembled into larger constructed modules in areas remote from the construction site. mol% The abbreviation for mole percent.
Monte Carlo simulation A statistical method of using the random sampling of numbers to estimate the solution to a numerical problem.
MPa The metric symbol for megapascal. mSS The abbreviation for metres subsea.
MSS The abbreviation for Manufacturers Standardization Society. mud, drilling The fluid circulated through the wellbore during rotary drilling. mudstone A blocky or massive, fine-grained sedimentary rock in which the proportions of clay and silt are about equal.
MW The abbreviation for megawatt.
N2 The chemical formula for nitrogen.
N/A The abbreviation for not applicable. natural gas A compressible mixture of hydrocarbons with a low specific gravity that occurs naturally in a gaseous form.
August 2004 GL-11 NDPA-P1 GLOSSARY
natural gas liquids Hydrocarbons that are gaseous in the reservoir, but that will separate out in liquid form at the pressures and temperatures at which separators normally operate. The liquids consist of varying proportions of butane, propane, pentane and heavier fractions, with little or no methane or ethane.
NEB The abbreviation for the National Energy Board.
NEBA The abbreviation for the National Energy Board Act.
NEMA The abbreviation for National Electrical Manufacturers Association.
NFPA The abbreviation for National Fire Protection Association.
NGL The abbreviation for natural gas liquid.
NGO The abbreviation for non-government organization.
NGTL The abbreviation for NOVA Gas Transmission Ltd. nominal pipe size The outside diameter of a pipe, expressed in inches. non-government Any non-profit organization that is independent from government. Non- organization government organizations are typically value-based organizations that depend, in whole or in part, on charitable donations and voluntary service.
NORM The abbreviation for naturally occurring radioactive material.
North, the The Arctic, or the northern part of a province.
NPS The abbreviation for nominal pipe size.
NTCL The abbreviation for Northern Transportation Company Limited.
NWT The abbreviation for Northwest Territories.
Oligocene A geological epoch in the Tertiary Period, extending from about 38 to 25 million years ago.
P50 The abbreviation for Probabilistic 50. pad The surface parts of a multiwell drilling or production site, including wells, buildings, piping and electrical facilities.
Paleocene A major worldwide division, an epoch, of geological time of the Tertiary period, extending from the end of the Cretaceous period to the Eocene epoch. particulate matter Matter in the form of small liquid or solid particles.
GL-12 August 2004 NDPA-P1 GLOSSARY
permafrost Perennially frozen ground, occurring wherever the temperature remains below 0°C for several years. permeability The capacity of a porous rock, soil, or sediment for transmitting a fluid without damaging the structure of the medium. petrology The branch of geology concerned with origin, occurrence, structure, and history of rocks, principally igneous and metamorphic rock. petrophysics The study of the physical properties of reservoir rocks. pig An in-line scraper, i.e., brush, blade cutter or swab, that is forced through a pipeline by fluid pressure. The pig is used to remove scale, sand, water and other foreign matter from the interior surfaces of the pipe. pigging The act of pushing a device through a pipeline in order to physically clean deposits from the inner surface of the pipeline, or to remove liquids. pigging facilities Pipeline in-line inspection and cleaning tool receivers and launchers. pingo A low hill or mound forced up by hydrostatic pressure in an area underlain by permafrost. polycrystalline A material composed of aggregates of individual crystals. polygons Arrangements of rock, soil and vegetation formed on a level or gently sloping surface by frost action. pore spaces The pores in a rock or soil considered collectively. Also known as pore volume. porosity The presence of spaces (pores) between the grains of sand making up a rock formation. Porosity is measured by dividing pore volume by total rock volume. ppm The abbreviation for parts per million.
Preliminary Information The initial report submitted by the proponents of a proposed project, Package indicating their intentions and providing information relevant to the project. procurement Activities that must take place to obtain, on schedule and at optimum price, materials or services needed to construct a project. prodelta The part of a delta lying beyond the delta front, and sloping gently down to the basin floor of the delta. It is entirely below the water level. production The operation of bringing raw natural gas to the surface for processing.
August 2004 GL-13 NDPA-P1 GLOSSARY
progradation Seaward buildup of a beach, delta or fan by nearshore deposition of sediments transported by a river, by accumulation of material thrown up by waves or by material moved by longshore drifting. proponent The organization (Shell Canada Limited) that is undertaking the Niglintgak field development.
PT The abbreviation for production test. public consultation The process of involving all affected parties in the design, planning and operation of a project. The process requires that the proponents give the parties to be consulted notice of the matter in sufficient form and detail to allow them to prepare their views on the matter. They are also given a reasonable amount of time to prepare their views and an opportunity to present their views to the proponents, who consider the views presented, fully and impartially.
Q1 The abbreviation for the first quarter of the year (January 1 to March 31). radiant heat The heat that travels in all directions from a heat source.
RAM The abbreviation for reliability and maintenance. raw gas Unprocessed gas or the inlet gas to a plant.
RCMP The abbreviation for Royal Canadian Mounted Police. reclamation The process of re-establishing a disturbed site to a former or other productive use, not necessarily to the same condition that existed before disturbance. The land capability may be at a level different, i.e., lower or higher, than that which existed before the disturbance, depending on the goal of the process. Reclamation includes the management of a contaminated site and revegetation, where necessary. Reclamation is not considered complete until the goals for reclamation have been achieved. regulators The government departments or agencies that issue licences, permits or authorizations likely to be applied for in respect of a proposed project. regulatory review For the Mackenzie Gas Project, the processes related to a review of a certificate under the NEBA, applications under COGOA, land use permits and water licences under the NWT Waters Act, the Mackenzie Valley Resource Management Act and others. reservoir A subsurface, porous, permeable rock body containing a natural accumulation of oil or gas, or both. resources Those quantities of petroleum estimated on a given date to be potentially recoverable from known accumulations, but that are not currently considered to be commercially recoverable.
GL-14 August 2004 NDPA-P1 GLOSSARY
retrogradation Generally, a process of deterioration, a reversal or retrogression to a simpler physical form. risk assessment The process by which the results of a risk analysis are used to make decisions on the acceptability of the risk. right-of-way The right of passage or of crossing over someone else’s land. Also, an easement in lands belonging to others that is obtained by agreement or lawful appropriation for public or private use.
RWED The abbreviation for Resources, Wildlife and Economic Development. sandstone A consolidated rock composed of sand grains cemented together.
SCADA The abbreviation for supervisory control and data acquisition. scour Erosion within a stream bed caused by the flow of water or ice.
SDL The abbreviation for significant discovery licence. sedimentology The science concerned with the description, classification, origin, and interpretation of sediments and sedimentary rock.
SEIA The abbreviation for Socio-Economic Impact Assessment. seismic data Detailed information obtained from earth vibration produced naturally or artificially (as in geophysical prospecting). seismic map A contour map constructed from seismic data, the z coordinate of which could be either time or depth. seismic program A study to obtain detailed information from earth vibrations that are produced naturally or artificially (as in geophysical prospecting). service rig A hoist and engine, mounted on a wheel chassis with a self-erecting mast, that is used to service wells. settlement area The main area where an Aboriginal group traditionally lived and pursued their livelihood. Rights and benefits defined by the Final Agreement, such as rights to hunt and fish, or economic benefits, such as consultation on exploration and development, may extend to the whole settlement area. shale A fine-grained laminated or fissile sedimentary rock made up of silt or clay-size particles. It generally consists of about one-third quartz, one-third clay materials and one-third miscellaneous minerals, including carbonates, iron oxides, feldspars and organic matter.
Shell The abbreviation for Shell Canada Limited.
August 2004 GL-15 NDPA-P1 GLOSSARY
shutdown The act of stopping work temporarily or stopping a machine or piece of equipment in operation.
Significant Discovery A licence, issued under the provisions of the Canada Petroleum Resources Licence Act, that allows the licence holder to explore, drill and test for petroleum and to develop frontier lands to produce petroleum. silica A mineral that has the chemical formula SiO2 (silicon dioxide). It is relatively hard and insoluble. Quartz is a form of silica, but usually contains impurities that give it colour. silt A term used for detrital rocks that consist predominantly of particles ranging in size from 1/16 to 1/256 mm. smectite A variety of green clay mineral. socio-economics The study of social and economic factors. spawning habitat A particular type of area where a fish species chooses to reproduce. Preferred habitat (substrate, water flow and temperature) varies from species to species. spring break-up The time of year when the temperature rises sufficiently to thaw ice, causing it to break up in rivers, allowing them to become navigable. spud date The date on which drilling began on a well.
SSSV The abbreviation for subsurface safety valve. staging area An area used by migratory birds to prepare for, or rest during, migratory flights. staging site A location where equipment is stored, maintained or readied for work. stakeholders People or organizations with an interest or share in an undertaking, such as a commercial venture. start-up The act of starting up new machinery or equipment after commissioning, or re-starting up machinery or equipment after a temporary shutdown or decommissioning. steady-state conditions The normal functioning of a process or equipment, as opposed to start-up and shutdown conditions. stockpile A storage supply of something, such as line pipe or soil, to be used later. strata Distinct, usually parallel, and originally horizontal beds of rock. An individual bed is a stratum. stratigraphy A branch of geology that deals with the arrangement of rock layers.
GL-16 August 2004 NDPA-P1 GLOSSARY
strike The direction taken by a structural surface, such as a fault plane, as it intersects the horizontal. Also known as a line of strike. substrate An underlying surface or foundation of a structure or development. subsurface rights The rights to exploit oil, gas and mineral resources and to benefit from the development of resources and minerals found beneath the ground. sustainable Development that meets the needs of the present without compromising the development ability of future generations to meet their own needs. sweet gas A gas that has no more than the maximum sulphur content, as defined by the specifications for the sales gas from a plant or by a legal body. talik Permanently unfrozen ground in regions of permafrost. Usually applies to a layer which lies above the permafrost, but below the active layer, that is, when the permafrost table is deeper than the depth reached by winter freezing from the surface.
TBD The abbreviation for to be determined.
TDS The abbreviation for total dissolved solids.
Tertiary The geological period between about 65 to 2 million years before present. thaw settlement Settlement that occurs when a warm pipeline thaws the surrounding frozen soil. thermokarst lakes Lakes in an irregular land surface formed in a permafrost region by melting ground ice. throughput The amount of material put through a process or pipeline. throw, fault The amount of vertical displacement occasioned by a fault. till Unsorted sedimentary material deposited directly by, and underneath, a glacier, consisting of a mixture of clay, silt, sand, gravel and boulders. Also known as glacial till. topography The configuration of a surface, including its relief and natural and artificial features. traditional knowledge Cultural knowledge that is based on direct observation or information passed on orally from other community members, developed from centuries of experience of living off the land. tripping The act of pulling the drill string out of the hole or replacing it in the hole. A pipe trip is usually done because the bit has dulled or has otherwise ceased to drill efficiently and must be replaced.
August 2004 GL-17 NDPA-P1 GLOSSARY
tundra A vast treeless zone, lying between the ice cap and the timberline of North America and Eurasia, that has a permanently frozen subsoil. turbidite A characteristic sedimentary deposit of the continental rise, formed by a turbidity current and composed of clay, silt and gravel, with the clay on top.
TVD The abbreviation for true vertical depth. unconformity A lack of continuity in deposition between rock strata in contact with one another, corresponding to a gap in the stratigraphic record. Also, the surface of contact between rock beds in which there is a discontinuity in the ages of the rocks. utilities The supply of electricity, natural gas, water, sewer drains and other services. water crossing A location where a pipeline crosses a stream or a river. wellbore The hole drilled by the bit in a well. well completion The activities and methods of preparing a well for the production of oil and gas or for other purposes, such as injection. wellhead The equipment installed at the surface of the wellbore. wetlands A broad group of wet habitats where the water table is usually at or near the surface, or the land is covered by shallow water. wind rose A polar graph that indicates wind speed and relative duration according to its direction. Wind roses are useful for determining the most prevalent direction of winds of desired strength. winter road A secondary road made of compact snow or ice, often plowed over a frozen lake or ground, and which is impassable in the summer. Also known as an ice road. wireline A slender, small diameter, rod-like or thread-like piece of metal that is used for lowering special tools, such as perforating guns, into a well. workover One or more of a variety of remedial operations performed on a producing oil or gas well, to try to increase production. zonal isolation The practice of separating producing formations from one another by casing, cement and packers for pressure control and maintenance purposes, and to prevent mixing fluids from separate formations. Also known as zone isolation.
GL-18 August 2004 NDPA-P1