Formatted DBM Feb 27.pdf

WHITESANDS EXPERIMENTAL PILOT PROJECT DESIGN BASIS MEMORANDUM

Submitted to: ORION OIL CANADA LTD. February 27, 2004 Norwest Corporation Suite 400, 205 – 9th Ave SE Calgary, Alberta T2G 0R3 Tel: (403) 237-7763 Fax: (403) 263-4086 Email [email protected] www.norwestcorp.com

PROPRIETARY AND CONFIDENTIAL ORION OIL 03-2303


TOC 1

TABLE OF CONTENTS 1 EXECUTIVE SUMMARY ............................................................................................................................................. 1-1 2 INTRODUCTION............................................................................................................................................................. 2-1

2.1 PURPOSE OF THE DESIGN BASIS MEMORANDUM..................................................................................................2-1 2.2 PROJECT OVERVIEW..................................................................................................................................................2-2 2.3 PROJECT OBJECTIVES................................................................................................................................................2-3 2.4 GUIDING PRINCIPLES AND KEY ASSUMPTIONS.....................................................................................................2-4 2.5 RISK MANAGEMENT..................................................................................................................................................2-4 2.6 PROJECT EXECUTION................................................................................................................................................2-4

3 THAI™ RECOVERY PROCESS................................................................................................................................. 3-1 3.1 PROCESS OVERVIEW.................................................................................................................................................3-1 3.2 RECOVERY STRATEGY..............................................................................................................................................3-2 3.3 PLANNED AND EMERGENCY SHUTDOWN AND RESTART .....................................................................................3-4 3.4 3-D CELL TEST RESULTS..........................................................................................................................................3-5 3.5 NUMERICAL SIMULATION PREDICTIONS................................................................................................................3-5 3.6 WATER DISPOSAL......................................................................................................................................................3-8 3.7 PRODUCED GAS .........................................................................................................................................................3-8 3.8 RESERVOIR CONTROL PARAMETERS....................................................................................................................3-10 3.9 PRODUCTION CONTROL METHOD AND WELL PROTECTION.............................................................................3-10 3.10 RESERVOIR RECOVERY CONFORMANCE METHOD.............................................................................................3-11 3.11 PRODUCED AIR/GAS CONTROL..............................................................................................................................3-11 3.12 DATA COLLECTION REQUIREMENTS- RESERVOIR..............................................................................................3-11 3.13 DATA COLLECTION REQUIREMENTS – SURFACE ................................................................................................3-12 3.14 CORROSION...............................................................................................................................................................3-12

4 WELL DESIGN AND COMPLETIONS .................................................................................................................... 4-1 4.1 WELL PATTERN AND LOCATIONS...........................................................................................................................4-1 4.2 VERTICAL INJECTION WELLS..................................................................................................................................4-1 4.3 HORIZONTAL PRODUCTION WELLS........................................................................................................................4-2 4.4 OBSERVATION WELLS..............................................................................................................................................4-2 4.5 WATER DISPOSAL WELLS........................................................................................................................................4-3 4.6 WATER SOURCE WELLS...........................................................................................................................................4-4 4.7 SURFACE REQUIREMENTS (DRILL PADS, ROADS, MUD DISPOSAL) ..................................................................4-4 4.8 LIFT SYSTEM ..............................................................................................................................................................4-4

5 SURFACE FACILITIES DESIGN............................................................................................................................... 5-1 5.1 FACILITIES OVERVIEW..............................................................................................................................................5-1 5.2 RAW WATER SUPPLY................................................................................................................................................5-2 5.3 STEAM GENERATION AND WATER SOFTENING.....................................................................................................5-2 5.4 AIR COMPRESSION.....................................................................................................................................................5-3 5.5 PIPING, INSULATION, SUPPORTS AND CONTROLS.................................................................................................5-3 5.6 PRODUCTION WELLHEAD CONTROLS.....................................................................................................................5-3 5.7 INJECTION WELLHEAD CONTROLS.........................................................................................................................5-3 5.8 PRODUCTION TREATMENT AND SEPARATION (EMULSIONS)...............................................................................5-3 5.9 PRODUCTION GAS VENT...........................................................................................................................................5-4 5.10 PRODUCED WATER TREATMENT AND DISPOSAL..................................................................................................5-4 5.11 TANKS AND PRODUCT SHIPPING/TRUCKING FACILITIES.....................................................................................5-4



TOC 2

5.12 PROCESS UTILITIES ...................................................................................................................................................5-4 5.13 CONTROL ROOM AND OFFICE..................................................................................................................................5-4 5.14 CHEMICAL ADDITION SYSTEM................................................................................................................................5-4 5.15 SPACE HEATING & LINE TRACING..........................................................................................................................5-4 5.16 HEAT RECOVERY.......................................................................................................................................................5-5 5.17 DILUENT SYSTEM ......................................................................................................................................................5-5

6 SITE DEVELOPMENT, UTILITIES AND OFF-SITES ....................................................................................... 6-1 6.1 POWER.........................................................................................................................................................................6-1 6.2 NATURAL GAS ...........................................................................................................................................................6-1 6.3 COMMUNICATIONS....................................................................................................................................................6-1 6.4 CAMP FACILITIES.......................................................................................................................................................6-2 6.5 CONSTRUCTION FACILITIES.....................................................................................................................................6-2

7 OPERATING DESIGN.................................................................................................................................................... 7-1 7.1 START -UP, SHUTDOWN PROCESS ............................................................................................................................7-1 7.2 DATA ACQUISITION AND REPORTING.....................................................................................................................7-2 7.3 WELL INTEGRITY.......................................................................................................................................................7-3 7.4 SAFETY AND ENVIRONMENTAL PROTECTION.......................................................................................................7-4

8 REGULATORY COMPLIANCE................................................................................................................................. 8-1 8.1 ALBERTA ENERGY AND UTILITIES BOARD............................................................................................................8-1 8.2 ALBERTA ENVIRONMENT AND ALBERTA SUSTAINABLE RESOURCE DEVELOPMENT .....................................8-1 8.3 REGIONAL MUNICIPALITY OF WOOD BUFFALO....................................................................................................8-2 8.4 OTHER.........................................................................................................................................................................8-2

9 PRELIMINARY RISK ASSESSMENT...................................................................................................................... 9-1

Appendix A Geology Appendix B Preliminary Project Schedule

List of Tables Table 3-1 Reservoir Design Parameters ............................................................................ 3-2 Table 3-2 Laboratory Physical Model Results with Wolf Lake Bitumen ............................ 3-5 Table 3.3 Orion Numerical Model Input ............................................................................. 3-7 Table 3-4 Produced Gas Composition ............................................................................... 3-9 Table 3-5 Preliminary Flare and Vent Stack Parameters and Emissions........................ 3-10 Table 7-1 Waste Streams................................................................................................... 7-5 Table 9-1 Preliminary Design and Operations Risk Summary.......................................... 9-1



TOC 3

List of Figures

Figure 2-1 Project Location Figure 2-2 Infrastructure in Project Vicinity Figure 2-3 THAI™ Schematic Figure 2-4 Preliminary Project Schedule Figure 3-1 THAI™ Process Schematic Figure 4-1 Well Spacing Figure 4-2 Spacing Detail Figure 4-3 Vertical Injection Well Figure 4-4 Wellhead Design – Vertical Injector Well Figure 4-5 Horizontal Production Well Figure 4-6 Wellhead Design – Horizontal Production Well Figure 4-7 Observation Well Completed for Temperature Measurement Figure 4-8 Temperature Observation Well Figure 4-9 Pressure Observation Well Figure 4-10 Water Disposal Well Figure 5-1 Production Facilities and Access Figure 5-2 Project Site Plan Figure 5-3 Plant Layout Figure 5-4 Process Flow Diagram Figure 5-5 P&ID Block Diagram Figure 5-6 Water Treatment P&ID Figure 5-7 Steam Generator P&ID Figure 5-8 Air Compressor P&ID Figure 5-9 Wellhead, Inlet Separator and Cooler P&ID Figure 5-10 Secondary Separator P&ID Figure 5-11 Aerial Cooler, Treater and Vent Stack P&ID Figure 5-12 Storage Tank and Pump P&ID Figure 5-13 Process Utilities P&ID Figure 6-1 Development Area Terrain Figure A-1 McMurray Seismic Character Correlation Figure A-2 Generalized Stratigraphic Section Figure A-3 Project Site Structural Cross-section Figure A-4 Devonian Unconformity Structure Figure A-5 Clearwater Marker Base to Devonian Isopach Figure A-6 McMurray Structure Figure A-7 Base of Clearwater Marker Structure Figure A-8 Wabiskaw Gas Pay Meters of Crossover Figure A-9 Caprock to McMurray Isopach Figure A-10 Clearwater Sandstone Isopach Figure A-11 Clearwater Sandstone Gas Pay Figure A-12 Preserved Colorado Isopach Figure A-13 McMurray Incised Valley Sandstone Isopach Figure A-14 McMurray Bitumen Pay Isopach



TOC 1

Abbreviations

AENV ..........................................................................................Alberta Environment AOSTRA.................................... Alberta Oil Sands Technology and Research Authority ASRD .........................................................Alberta Sustainable Resource Development AXYS................................................................. AXYS Environmental Consulting Ltd. CCME.............................................. Canadian Council of Ministers of the Environment CMG ..................................................................................Computer Modelling Group CO.................................................................................................... Carbon monoxide CO2 ...................................................................................................... Carbon dioxide COFCAW.......................................Combination Forward Combustion and Water Flood EDTA.....................................................................Ethylene Diamine TetraAcetic Acid EUB ........................................................................ Alberta Energy and Utilities Board GJ/hr ............................................................................................... Gigajoule per hour H2S..................................................................................................Hydrogen sulphide IHS........................................................................... Inclined Heterolithic Stratification km................................................................................................................Kilometre kPa.............................................................................................................. Kilopascal m........................................................................................................................Metre m3/d...............................................................................................Cubic metre per day MJ/m3 .................................................................................. Megajoule per cubic metre mKB........................................................................................ Metres below Kelly Bar MW..............................................................................................................Megawatt NO2 ........................................................................................... Nitrogen dioxide (gas) NOx ..................................................................... Oxides of Nitrogen (NO, NO2) (gas) Orion ......................................................................................... Orion Oil Canada Ltd. POB .....................................................................................Pressure Observation Well ppm .................................................................................................... Parts per million S.....................................................................................................................Standard SAGD.........................................................................Steam Assisted Gravity Drainage SARA..........................................................Saturates, aromatics, resins and asphaltenes SO2...................................................................................................... Sulphur dioxide STARS.............................Steam, Thermal and Advanced Processes Reservoir Simulator THAI™ ................................................................................. Toe-to-Heel Air Injection TOB .............................................................................. Temperature Observation Well TRS...........................................................................................Total Reduced Sulphur VAPEX ............................................................................... Vapour Extraction Process °C......................................................................................................... Degree Celsius



1-1

1 EXECUTIVE SUMMARY

Orion Oil Canada Ltd. (Orion), a wholly owned subsidiary of Petrobank Energy and Resources Ltd., plans to construct and operate the WHITESANDS Experimental Pilot Project (the Project). The Project will be located on Orion’s oil sands lease (Agreement 7400010012) approximately 13 km west of Conklin, Alberta. The Project will be designed to evaluate the THAI™ (Toe-to-Heel-Air-Injection) in-situ combustion process under actual field conditions. It will produce up to 300 m3/d of partially upgraded oil, referred to as THAI™ OIL. Orion has the right to use the patented THAI™ process. This document provides the design basis for the WHITESANDS Experimental Pilot Project. THAI™ is a revolutionary combustion technology for the in-situ recovery of bitumen and heavy oil by using a vertical air injection well at the “toe” of a horizontal production well. During this process a combustion front is created where approximately 10% of the bitumen in the reservoir is combusted. This generates heat, which reduces the viscosity of the bitumen and enables it to flow by gravity drainage to horizontal production wells. The combustion front sweeps the oil from the toe to the heel of the horizontal producing well efficiently recovering an estimated 80% of oil in place while upgrading the crude oil in-situ. The process has been extensively tested in laboratory physical models and its potential at a field scale confirmed through numerical simulations. The major advantages and benefits of the THAI process include:

• lower capital and operating costs, • significantly higher recovery potential than current in-situ processes, • minimal use of natural gas and fresh water, • lower greenhouse gas emissions, • production of partially upgraded crude oil (THAI™OIL), • potential to operate in thinner and deeper reservoirs than steam-based processes, and • potential application as a steam follow-up process.

The design provides for a wide range of flexibility in the operation appropriate for the world’s first field pilot of the THAI™ process. The pilot is aimed at demonstrating the commercial viability of the technology in a safe manner with a “robust” approach to the design. The pilot will have three vertical/horizontal well pairs plus several temperature and pressure observation wells. Data collection is a major objective of the pilot with an array of observation wells and facility instrumentation to obtain production and analytical compositional measurements. The pilot will have a small foot print and will be designed and operated to meet or exceed all environmental regulations. The pilot facilities will be designed for an anticipated five-year operating life, with start-up planned for late 2004 or early 2005.



1-2

In addition to the WHITESANDS regulatory application, information on Petrobank and Orion is provided on Petrobank’s website at www.petrobank.com.



2-1

2 INTRODUCTION 2.1 PURPOSE OF THE DESIGN BASIS MEMORANDUM

The purpose of the Design Basis Memorandum (DBM) is to assemble in one document the objectives, guiding principles, risks/uncertainties, preliminary design, and operations plan for the WHITESANDS Experimental Pilot Project (the Project). The DBM provides:

• the basis to support the cost estimate and preliminary schedule , • the basis for the final design and execution planning of the Project, and • a summary for potential partners and financial institutions.

Norwest Corporation provided the engineering design and support team. This included:

• J. Aiello, P.Eng., Project Advisor (Norwest Corporation) • R. Luhning, Ph.D., P. Eng., Project Manager (Arkril Enterprises) • L. McKeary, RET, Surface Facilities (McKeary Technical Services Ltd.) • J. Donnelly, Ph.D., P.Eng., Surface and Subsurface Interface (Marengo Energy Research

Limited) • W. Boddy, P.Eng, Drilling and Completions (Marlex Engineering Ltd.) • S. Crevolin, P.Eng, Surface Facilities (Petrotherm) • Z. Lukacs, P.Eng, Schedule Coordination (Norwest Corporation) • B. Noble, M.A., Regulatory Management (L.B. Noble Resource Management Limited)

AXYS Environmental Consulting Ltd. coordinated the environmental design team for the Project. This included:

• K. Venner, Ph.D., Technical Leader, AXYS • H. McGrath, M.Sc., P.Ag., Terrain and Soils, AXYS • M. Davies, M.Sc., Air Quality, RWDI West Inc. • C. Serdula, M.Sc., Air Quality, RWDI West Inc. • G. McClymont, M.Sc., P. Geol., Groundwater, Westwater Environmental Ltd. • J. Saldana, Groundwater, Westwater Environmental Ltd.

Orion Oil Canada Ltd. staff provided input on objectives, guiding principles, reservoir simulation, project execution, geology, geophysics and site selection. This included:

• C. Bloomer, P. Geol., Project Executive • T. Pantalone, P. Geol., Geology • R. Baird, P. Geoph., Geophysics • C. Ayasse, Ph.D., Director, Technology, Reservoir Numerical Simulation.



2-2

2.2 PROJECT OVERVIEW

Orion Oil Canada Ltd. (Orion) , a wholly-owned subsidiary of Petrobank Energy and Resources Ltd., plans to conduct a field pilot of the THAI (Toe-to-Heel-Air-Injection) in-situ combustion oil sands technology. The Project will be located on Orion’s oil sands leases approximately 13 km west of Conklin, Alberta (see Figure 2-1). The surface facilities and access roads for the Project will be located in Sections 12 and 13, Township 77, Range 9, west of the 4th Meridian (see Figure 2-2). The reservoir target is wholly contained within Section 12. The Project is in an area that has been extensively explored and developed for natural gas and oil sands. The Leismer Gas Plant (BP Energy Canada) is located approximately 3 km north of the development area. Delineation drilling on the site in November, 2003 confirmed the presence of a high quality oil sands reservoir in which to conduct the Project. A summary of the geology and oil sands resource in the development area is provided in Appendix A. A separate report (Resource Assessment – WHITESANDS Project Area, January, 2004, Fekete Associates) on the results of the 2003 drilling program is also available. Three pairs of vertical air injector and horizontal producer wells will each have a peak productive capacity of 100m3/d of partially upgraded bitumen, hereinafter referred to as THAI™OIL. Production will be treated onsite and produced water will be disposed of via deep wells. Additional information on the production process is found in Section 3. THAI™OIL will be stored on site in tankage and trucked to a market outlet. THAI is an innovative new combustion process for the in-situ recovery of bitumen, which combines a vertical air injection well with a horizontal production well as shown in Figure 2-3. During this process a combustion front is created where a portion of the bitumen in the reservoir is combusted. This generates heat, which reduces the viscosity and partly upgrades the bitumen enabling it to flow, by a combination of induced pressure gradient and gravity drainage, to the horizontal production well. The combustion front sweeps the oil from the toe to the heel of the horizontal producing well efficiently recovering an estimated 80% of bitumen in place. The process has been extensively tested in laboratory physical models and its potential at a field scale confirmed through numerical simulations. Orion has the right to use the patented THAI™ process. The potential advantages/benefits of the THAI process include:

• lower capital and operating costs, • significantly higher recovery potential than current in-situ processes, • minimal use of natural gas and fresh water, • lower greenhouse gas emissions, • production of partially upgraded crude oil,



2-3

• potential to operate in thinner and deeper reservoirs than steam-based processes, and • potential application as a steam follow-up process.

The preliminary project schedule is illustrated in Figure 2-4. A preliminary detailed schedule is provided in Appendix B. Pending regulatory approval, site preparation and delineation drilling is expected to begin in early 2004 with start-up scheduled for late 2004. The initial phase of the Project is anticipated to last five years with the potential for a second phase if operating results warrant.

FIGURE 2-4 PRELIMINARY PROJECT SCHEDULE

2003 2004 2005 - 2010

Design Basis Engineering

Public Consultation

AEUB/AENV Application

AEUB/AENV Approval

Construction Permitting

Detailed Engineering

Site Preparation

Production Drilling

Plant Construction

Commissioning

Start-up

Operation: 5 Years

2003 2004 2005 - 2010

Design Basis Engineering

Public Consultation

AEUB/AENV Application

AEUB/AENV Approval

Construction Permitting

Detailed Engineering

Site Preparation

Production Drilling

Plant Construction

Commissioning

Start-up

Operation: 5 Years

2.3 PROJECT OBJECTIVES

The purpose of the Project is to evaluate the THAI™ process under actual reservoir conditions, in commercial length horizontal wells, in order to advance the technology to commercial application. The pilot will generate an array of technical, environmental and economic information on which to plan and evaluate a commercia l scale operation. The principle objectives of the pilot are to:

• Understand the dynamics and operating characteristics of the process, • Obtain information on the THAI™OIL, water and gas production rates, • Enhance the numerical simulation model using field data, • Obtain information on the characteristics of the produced THAI™OIL to evaluate its

commercial value, • Obtain information on produced water to evaluate its corrosion characteristics and

recycle potential,



2-4

• Obtain information on produced gases to evaluate their corrosion characteristics and emission management requirements,

• Obtain information in support of a commercial scale project design, and • Obtain additional information on capital and operating costs for a commercial scale

project.

2.4 GUIDING PRINCIPLES AND KEY ASSUMPTIONS

The Project has been developed based on the following guiding principles: • operational safety is number one priority, • development and operation have minimal environmental impact, • proven technology and conventional equipment utilized in areas of limited operational

risk, • robust design applied in critical areas relating to process success, • capital and operating costs minimized through innovation, • design is consistent with anticipated five-year operating life, • rental or leased equipment used where appropriate, and • all regulatory requirements met or exceeded.

2.5 RISK MANAGEMENT

All experimental projects have a number of technical, operational, execution and business risks and uncertainties. The challenge is to accurately identify and rank these at each stage in the project development to determine the significance and undertake appropriate design mitigation or management actions. Several of these will be resolved during the detailed engineering design stage. Others will have to be managed during the operational phase of the Project. A preliminary assessment of the design and operational risks is provided in Section 9.

2.6 PROJECT EXECUTION

The preliminary detailed schedule shown in Appendix B lists the major project execution activities required to take the Project through to start-up. During detailed engineering a Project Execution Plan (PEP) will be prepared to address these activities in more detail and develop plans for:

• contracting and procurement, • QA/QC, • modularization, • staffing, • change management, • safety systems, • environmental protection systems,



2-5

• regulatory compliance, • start-up and commissioning, and • operation.



3-1

3 THAI™ RECOVERY PROCESS 3.1 PROCESS OVERVIEW

The THAI recovery process for the pilot will be a “dry” combustion process operated at a high temperature in the reservoir to promote in-situ upgrading of the bitumen and avoid the need to inject fresh water with the air. In the event that production rates are too low or there is a need to lower the combustion front temperature, water can be injected with the air. Steam may be injected to control oxygen levels if necessary. The THAI™ process operates with an array of parallel horizontal production wells (producers) placed near the base of the oil sands zone. Vertical air injector wells (injectors) are drilled with an offset from the toe of the producers and are opened at the top of the pay zone as shown in Figure 3-1. A near-well steam preheat is then conducted to establish communication between the injector and the producer. When air is injected, ignition occurs and a combustion front develops. The front is quasi-vertical and remains vertical for the entire duration of the reservoir exploitation. This ensures that a high-oxygen flux is maintained and only high-temperature oxidation occurs.

FIGURE 3-1 THAI™ PROCESS SCHEMATIC

0Cold Heavy

Oil

Mob

ile O

il Zo

ne

Com

bust

ion

Zone

Pro

duct

ion

Wel

l

Ver

tica

l In

ject

ion

Wel

l

Coke

Zon

e

“Heel”

Air

“Toe”

0Cold Heavy

Oil

Mob

ile O

il Zo

ne

Com

bust

ion

Zone

Pro

duct

ion

Wel

l

Ver

tica

l In

ject

ion

Wel

l

Coke

Zon

e

“Heel”

Air

“Toe”

Hot combustion gases contact the bitumen ahead of the coke-burning (combustion) zone and heat the bitumen to over 400°C. The high temperatures, in the presence of reservoir clays , cause thermal cracking and upgrading of the bitumen by 7 to 10° API gravity to form THAI™OIL. The



3-2

hot, lighter cracked oil, reservoir water and combustion gases drain downward into the horizontal well for transmission directly to the surface by gas lift. Some bitumen warmed by conductive heating ahead of and behind the combustion front also drains into the horizontal well. Up to ten percent of the bitumen, the heavier, higher boiling point fraction, is left behind on the sand matrix and becomes the combustion fuel as the burning front advances. In addition to bitumen, the only other raw materials consumed by the THAI™ process are the associated gases and interstitial water in the oil sands formation. The reservoir design parameters are provided in Table 3-1.

TABLE 3-1 RESERVOIR DESIGN PARAMETERS

Steam Preheat Period

(months)

Water Rate

(m3/d/well)

Frontal Advance

Rate (m/d)

Peak Temperature

(°C)

Temperature in Swept Zone

(°C)

Wellbore Temperature

(°C)

Gas/oil Ratio

(m3/m3)

3 20 0.28 >600 215–260 after

5 years 200–300 944

Injection Forecast During the start-up period, steam requirements will be 500 m3/d/well pair. Each well pair will be treated separately for approximately a three-month period. Computer simulation studies indicated an optimum air injection rate of 85,000 Sm3/d per injector, with a well spacing of 100 m and a pay thickness of 20 m. Production Forecast Total gas production is expected to be very close to the air injection rate of 85,000 Sm³/d, because the combined volume of the generated N2, CO and CO2 and hydrocarbon gas will be approximately equal to the volume of oxygen consumed. The anticipated steady state production temperature is expected to average 250°C. THAI™OIL production is forecast to commence at 20 m3/d/well and increase to 90 to 100 m3/d/well over a five-year period. The water cut is expected to be 23 percent.

3.2 RECOVERY STRATEGY

The THAI™ recovery process strategy consists of three stages: • steam preheat, • combustion ignition, and • steady-state combustion



3-3

Steam Preheat The purpose of the steam preheat is to ensure that there is a heated communication channel between the vertical injection and horizontal production well. The steam preheat also ensures that the production well is heated through its entire length so that mobilized bitumen does not cool and plug the well. The steam preheat occurs in three steps:

1. Steam injection, accompanied by circulation into the horizontal production well at below fracture pressure, will begin with injection of steam into the long tubing landed near the toe of the horizontal production well. The condensed steam and mobilized bitumen will be produced via short tubing landed a short distance above the liner in the horizontal well. The steam circulation will continue with pressure/rate cycles to promote bitumen production.

2. The total section of reservoir around the vertical injection well must be heated to a high enough temperature (100°C) for spontaneous ignition to occur upon subsequent injection of air. Following the development of heat communication between the toe of the horizontal well and the vertical injection well, steam injection from the heel of the horizontal well will end and continuous injection of steam via the vertical well into the toe of the horizontal well will be conducted for a period of time until the horizontal well temperature rises to steam temperature less 50°C. Bitumen, liquid water and steam will be produced at the heel end of the horizontal well.

3. In preparation for ignition, steam will be injected into the upper part of the reservoir to create a heated volume, approximately 10 m in radius around the well at the top of the reservoir, which will become linked to the lower steam heated area and the horizontal well.

Combustion Ignition At the conclusion of steam preheat, air will be injected at up to 85,000 m3 /day, at below formation fracture pressure, through the upper screens of the vertical well to ignite the reservoir and initiate the THAI™ recovery process. The objective is to ignite the reservoir without damaging the vertical injection well while avoiding fracturing the reservoir. Any flow-back of gas or fluid into the injection well is to be avoided as this has a high probability of drawing combustion fuel into the well and damaging or destroying the well. Data from a large number of combustion tube tests indicates that spontaneous ignition of Athabasca bitumen will readily occur at temperatures exceeding 100°C. Ignition will be confirmed from the analysis of the produced gas. Once ignition is confirmed, the air injection rate will be gradually brought up to the design rate. Once at design rate, it is expected that the combustion front will move progressive ly from the toe toward the heel of the horizontal production well. If high temperatures in the production well occur or if there are difficulties in distributing heat along the well, hot water or steam may be injected along with the air.



3-4

The steam stimulation and ignition process will be conducted in sequence for the three THAI™ well pairs in order to learn from each preceding well pair how to improve the start-up and production methods for the next pair. Steady state combustion Steady state combustion will be maintained throughout the projected five-year life of the wells. It is anticipated that the air injection rate will be constant in order to obtain steady-state data for computer model history-matching.

3.3 PLANNED AND EMERGENCY SHUTDOWN AND RESTART

Through the pilot life the production operations will be shutdown in a planned manner for such things as yearly maintenance of facilities and special tests. The operations may also need to be shutdown due to emergency situations such as detection of high levels of oxygen in the produced gas. The main concern is the manner in which the wells are shutdown and restarted so as not to damage the wells or impede restarting of the THAI process. The THAI™ process is driven by air injection. When air injection is stopped, the advancement of the combustion front will slow and flow will continue until the bottom hole pressure is not sufficient to lift the fluids to surface. For the air injection wells, the main concern is to eliminate the possibility of back flowing of combustion material into the well. A constant pressure will be kept on the well to prevent influx of hot reservoir material that could damage the well or by influx of sand that could plug the well. This will be accomplished by injecting steam or hot water (to avoid thermal shock) to prevent the flow back and then filling the well with water to prevent inflow. The horizontal production wells should be shut down under pressure to eliminate the possibility of oxygen entering the well and causing damage by combustion in the wellbore. The horizontal well design has the capability to allow the well to be circulated to flush out material that may have settled in the well or to reheat the well as necessary if shut down for an extended period.

The main risk, which is unique to an in-situ combustion project, is the possibility of high oxygen content in the produced gas. This could lead to risk of fire or explosion in the surface facilities. For this reason the produced gases will be monitored continuously for oxygen content. In the event that oxygen content becomes excessive, the rate of air injection will be reduced or stopped and the well may be shut in. High temperature in the horizontal production wells could lead to production problems. The temperature distribution in the production wells will be monitored continuously using thermocouples placed strategically along the wells. If excessive temperature is observed, hot



3-5

water or steam will be injected to cool the wells. In addition, the air injection rate may be reduced.

3.4 3-D CELL TEST RESULTS

In June 2003, a THAI™ test in the University of Bath 3-D Cell was commissioned by Orion. The Cell contained 60% saturation of Wolf Lake bitumen. The results are summarized in Table 3-2. The THAI™ process operated effectively even at low oil saturation, producing substantially upgraded oil with high reservoir sweep.

TABLE 3-2 LABORATORY PHYSICAL MODEL RESULTS WITH WOLF LAKE BITUMEN

Process Oil Recovery

Air:Oil Ratio Peak Temperatures

Frontal Advance Rate

Dry in-situ combustion 74% 1650 Sm3/m3 500–600°C 1.2 m/d 3.5 NUMERICAL SIMULATION PREDICTIONS

The in-situ combustion version of the Computer Modelling Group (CMG) numerical simulation model “STARS” was used for simulation modeling to generate the forecast for the Project. The simulation had the following dimensions:

• thickness = 20 m, • spacing = 100 m, • length = 500 m , and • grid sizes were 1.0 m, 2.5 m 2.5 m respectively.

Geological parameters from the nearby Kirby Lake Project (see Figure 2-1) reservoir , which represent typical conditions in the area, were used. These parameters were consistent with the results of the November 2003 drilling program on the Project site. Simulations were conducted to assess the sensitivity of the process to:

• start-up heating procedures, • air rate, • air injector location, • well length, • well spacing, • well diameter, • well perforations, • grid size, and • bottom hole pressure.



3-6

Field Scale Numerical Simulations The commercialization of the THAI™ process will be similar to that followed in the development of SAGD and VAPEX. These processes began with laboratory-scale physical model tests followed by computer simulation modeling of these results, and then by field-scale reservoir simulation computer modeling, field piloting and finally commercial application. It is important to note that many commercial-scale SAGD projects begin with a field pilot to test the process performance in specific reservoirs. The purpose of Orion’s numerical simulation work is to scale -up the process to reservoir conditions and to develop a ‘DESIGN’ model for the Project engineering team. In 2001, Petrobank conducted the first field-level numerical simulation of the THAI™ process using the CMG STARS thermal simulator. Studies have been completed to determine the sensitivity of THAI™ to reservoir pay zone thickness, horizontal well spacing, horizontal well length, horizontal well diameter, the frequency of sand screens in the horizontal well, reservoir temperature, draw-down pressure, air injection rate, reservoir permeability, grid block size, start-up procedures and a number of other key variables required for design of the field pilot. The studies led to the Design Case, the basis for the THAI™ Project wells and facilities design. Numerical Simulation Input Data The reservoir parameters of the nearby Kirby Lake Project were used in the initial model runs (Table 3-3). The model will be re-run in February 2004 using reservoir data from the Orion November 2003 drilling program.



3-7

TABLE 3-3 ORION NUMERICAL MODEL INPUT

Simulator STARS 2003.1 Components (8) water, bitumen, upgrade, methane, CO2, CO/N2, oxygen,

coke Grid size, m 2.5 x 2.5 x 1.0 Number of grids 40,000 in element of symmetry (design model) Wells 1 vertical steam injector for communication pre-heating, 1

vertical air injector, 1 discretized horizontal well with tubing for well pre-heating.

Heterogeneity Homogeneous Permeability 6.4 D (horizontal), 3.4 D (vertical) (Kirby Lake) Porosity 33 % (Kirby Lake) Oil viscosity, cP (bitumen)

340,900 @ 10°C (Kirby Lake)

Temperature, ºC 20 (WHITESANDS)

Reservoir pressure, kPa

2600 (Kirby Lake)

Numerical Simulation Sensitivity Studies Sensitivity studies were conducted with 100 m horizontal wells and a well spacing of 50 m, looking at:

• start-up procedures (steaming for inter-well communication), • pay thickness (20 m, 25 m), • permeability(vertical) (3.4 D, 1.0 D), • drawdown pressure (500 kPa, 1250 kPa, 4000 kPa), • grid block size (1 m x 1 m x 1 m), and • air injection rate (50,000 m3/d, 75,000 m3/d, 85,000 m3/d, 100,000 m3/d).

Sensitivity studies were conducted for 500 m horizontal wells using the following parameters:

• well spacing (50 m and 100 m), • well diameter (152.4 mm, 177.8 mm), and • well completion (fully perforated, 50 % perforated).

Sensitivity to well length was tested at 50 m, 100 m, 250 m, 500 m and 750 m lengths. In summary, the computer modelling confirmed on a field scale basis the observations in the laboratory 3-D cell tests: the THAI™ process operated with a stable quasi-vertical combustion front, generated high temperatures at the front, indicating high-temperature combustion and showed complete utilization of the oxygen. Unique features were high oil rates and acceptable wellbore temperatures.



3-8

3.6 WATER DISPOSAL

The produced water generated by the Project will be separated from the THAI™OIL at the plant site and then disposed of into the Clearwater Sandstone via deep well injection. The amount of produced water will depend on whether the continuous co-injection of steam (“wet combustion”) is required for process control purposes. With normal “dry” combustion, the produced water will consist of condensed start-up steam (first year only) and interstitial water from the reservoir. With the wet combustion method, the produced water will consist of condensed start-up steam (first year only), interstitial reservoir water and the optional injected steam as noted above. The estimated disposal volumes for Year 1, Year 2 and Years 3 to 5 are 244,550 m3, 229,950 m3 and 251,850 m3, respectively, with approximate disposal rates of 670 m3/d, 630 m3/d and 690 m3/d, respectively. The recycle of produced water is not required because the Project will use less than 500,000 m3/y of fresh water. The pilot will collect data on produced water quality to allow the design of treatment facilities for reuse in future commercial operations or for export off-site to other potential water users.

3.7 PRODUCED GAS

The anticipated produced gas composition is provided in Table 3-4. Produced gas will be cooled to 80°C and vented. The vent stack will be 75 m in height and will be equipped with a chemical sweetener to remove H2S. The vent stack will discharge in-situ combustion gases that are entrained within, and removed from, the produced THAI™OIL stream. While these combustion product gases will be comprised primarily of N2, CO2, and CO, they are also expected to contain trace amounts of hydrocarbons and other compounds. Because of the high N2, CO2, and CO content (~97 to 98% on a dry basis), the heating value of the vent gas is low. The maximum H2S content is expected to be 150 ppm (on a dry basis). Following sweetening, the maximum H2S content will be less than 10 ppm. Representative carbon disulphide (CS2), benzene (C6H6), and ethylene (C2H4) emission values are also provided in the table to account for the other TRS (Total Reduced Sulphur) compounds and other hydrocarbon species that are of potential interest. Table 3-5 provides the preliminary parameters for the vent and flare stack design.



3-9

TABLE 3-4 PRODUCED GAS COMPOSITION

Compound Dry Basis Wet Basis

(mole %) (mole %) CH4 C2H4 (Ethylene) C2H6 C3 H6

C3H8 C4H10 C5H12 N2 CO2 CO O2 H2 SO2

H2O

0.96 0.01 0.04 0.03 0.08 0.07 -

82.05 12.12 3.04 1.45 0.12 0.01 0.00

0.88 0.01 0.04 0.03 0.07 0.06 -

74.99 11.08 2.78 1.33 0.11 0.01 8.60

(ppm) (ppm) H2S C6H6 (Benzene) CS2

150 11 13

137 10 12

Heating value (MJ/m3) 0.91 0.83

Note: A dash (-) indicates that the parameter is not applicable.



3-10

TABLE 3-5 PRELIMINARY FLARE AND VENT STACK PARAMETERS AND EMISSIONS

Flare Stack Vent Stack (Wet Basis)

Stack Location (UTM m N) Stack Location (UTM m E) Stack Height (m) Stack Diameter (m) Gas Flow Rate (m3/d)

6168879 484286

13.0 0.152 425

6168851 484315

75.0 0.203

277,000 Effective Stack Height (m) Pseudo Stack Diameter (m) Fraction Heat Radiated (%) Stack Exit Temperature (°C) (K) Stack Exit Velocity (m/s)

13.72 1.445

25 1000 1273 0.27

- - -

80 353

121.2 SO2 Emission Rate (kg/d) (g/s)

5.6 × 10-3

6.5 × 10-5 75.1 0.869

CO Emission Rate (kg/d) (g/s)

- -

9124 105.6

NOX Emission Rate (kg/d) (g/s)

0.41

0.0048 - -

H2S Emission Rate (kg/d) (based on 10 ppm – dry basis) (g/s)

- -

>4 >.05

CS2 Emission Rate (kg/d) (g/s)

- -

10.7 0.124

Ethylene Emission Rate (kg/d) (g/s)

- -

32.8 0.380

Benzene Emission Rate (kg/d) (g/s)

- -

9.2 0.106

Note: A dash (-) indicates that the parameter is not applicable.

3.8 RESERVOIR CONTROL PARAMETERS

There are two basic control parameters for the THAI process: the rate and pressure of air injection and the back pressure maintained on the production well.

3.9 PRODUCTION CONTROL METHOD AND WELL PROTECTION

The production control methods relate to the manner in which the injection and production wells are operated to prevent the wells from being overheated or burned, clogged by deposited bitumen or having “live” oxygen in the wells. The control methods are as follows:

• Adjust the air injection and production rates so that the horizontal production well is covered by a “pool” of liquid oil that prevents oxygen from entering.

• Coke will be deposited in the well immediately behind the burn front to provide a gas tight seal to keep air out of the well.



3-11

• The coke plug will be continuously removed by burning as the front advances and new coke will be deposited. Oxygen must not be allowed to enter the wellbore ahead of the burning front as this will overheat the wellbore and also reduce production rates.

• Should the “pool” of oil or coke plug not adequately restrict the entry of oxygen, water and/or steam can be injected at the lower perforations of the vertical injection well to restrict oxygen from entering the horizontal production well.

• Should temperatures in the horizontal well become excessive, steam and/or water can be circulated through the well using the long tubing to reduce the temperature. In this regard, it is important that the long tubing be regularly pulled back to a point near the combustion front so that the tubing will not become stuck in the wellbore because of coke deposits. Wellbore temperatures measured by the thermocouples will be used to locate the position of the combustion front. The long tubing will also be available to plug-off a section of the wellbore in case of screen failure or to isolate a tail section for any reason.

• If the oxygen content of the production gas exceeds a level (for example 1-3%) that may pose a possibility of explosion or combustion in production lines, the air injection will be reduced or stopped.

3.10 RESERVOIR RECOVERY CONFORMANCE METHOD

Part of the objective is to have a regular conformance of the recovery zone so that as full a volume of the reservoir as possible will be swept by the THAI process for high ultimate recovery. In addition to the parameters described above, it may be necessary to occasionally inject water or convert to wet combustion (co-injection of air and steam) to achieve the desired oil rates and recovery of the original oil in place. The array of observation wells described earlier will provide ongoing data to monitor the conformance of the recovery process. This conformance data will be essential for designing the placement of follow-up horizontal wells.

3.11 PRODUCED AIR/GAS CONTROL

The air/produced oil ratio is a critical factor in the THAI process economics. The design ratio is 85,000 m3/day/well of air for 100 m3/day/well oil at full production. Oxygen by-passing the combustion front or indications of starved combustion by high CO concentration will indicate that the injection/production operations need to be adjusted.

3.12 DATA COLLECTION REQUIREMENTS- RESERVOIR

The data collection for the reservoir is aimed at monitoring and controlling reservoir conditions mainly pressure and temperature. The observation well data collection will be focused on the conformance and spread of the combustion recovery through the reservoir. The spread of the



3-12

recovery between the horizontal production wells and outside of the unconfined THAI pilot pattern will be key to the design of the well spacing to be used for commercial operations.

3.13 DATA COLLECTION REQUIREMENTS – SURFACE

The surface data collection is aimed mainly at measurements of the volume and composition of injected and produced material (e.g. injected air, produced THAI™OIL, produced water, and produced gas). The surface measurements will provide the basic data for calculating the economics of the THAI process, controlling the THAI process and for the design of commercial facilities. Environmental monitoring, such as vent stack analyses, is mandated. These will also be used to monitor the efficiency of the process.

3.14 CORROSION

The THAI process will produce CO2 and SO2 in a wet environment, so corrosion can be expected. The minimum production temperature in the horizontal well is expected to be 250°C. At temperatures over 190°C all water will be in the vapour phase. The water in the production well is expected to be as steam at the production temperature, but corrosion will still be a concern as the production cools as it passes through the horizontal production well. Turbulent flow in the horizontal well is expected to coat the wellbore with bitumen (the metal is oleophilic), which may reduce the corrosive effect of the acids. In the surface facilities, the steam will condense upon cooling and the combination of liquid water, CO2 and SO2 can be expected to cause corrosion. The timely separation of produced THAI™OIL from produced gas and neutralization of the fluids may reduce the opportunity for corrosion. The coating of the insides of wells and vessels by the produced THAI™OIL will help to provide corrosion protection. Orion has commissioned a corrosion study by Dr. Bill Shaw at the University of Calgary. The program is to evaluate the performance of a variety of material compositions under a range of temperature, pressure and fluid conditions that may be experienced in the THAI™ process. It is expected that the study conditions will represent the worst case scenario by exposing bare metal to the potentially corrosive fluids. The program will define the potential severity of corrosion and identify design or operating solutions. The results of this study will be available for consideration during the detailed design stage of the Project.



4-1

4 WELL DESIGN AND COMPLETIONS

4.1 WELL PATTERN AND LOCATIONS

The pilot will have three horizontal production wells , three vertical air injection wells (one at the toe of each horizontal well) and 19 observation wells. The locations are shown in Figure 4-1.

4.2 VERTICAL INJECTION WELLS

The vertical well at the toe end of each horizontal production well has two purposes: 1) to inject steam to pre-heat the reservoir as part of the THAI™ start-up process, 2) to inject air for the combustion process. In the preheat operation 500 m3/d of 80% quality steam will be available at a wellhead pressure of 8,000 kPa at 295°C. For the combustion operation, air injection will be injected at up to 85,000 m3/d well at a maximum wellhead pressure of 8,000 kPa and a temperature of 175°C. The vertical injection wells are placed 15 m past the end of the last screen liner joint (approximately 17 m from the end of the horizontal liner) and 3 m off the “line” of the horizontal well as shown in Figure 4-2. This exact location (15 m) was chosen by numerical simulation as optimal for the start-up of the combustion process. The placement of the well 3 m off line was to avoid unintentionally intersecting the horizontal well when drilling the vertical well. The three vertical injection wells will be drilled and completed as shown in Figure 4-3. The material list for each injection well is as follows:

Surface Casing: 244.5 mm, 48.1 kg/m, H-40, Round Thread Conn., length 150 m Production Casing: 177.8 mm, 34.3 kg/m, L-80, VAM-SW Conn., length 420 m Screen Section: 177.8 mm x 3 m length, 316LSS Rib with 0.006” open, 2 required Tubing: 114.3 mm, 18.8 kg/m, J-55, Premium Conn., length 400 m Tubing: 60.3 mm, 6.85 kg/m, J-55, Premium Conn. , length 410 m Packer: 177.8 mm x 120.6 mm retrievable, thermal element Packer: 177.8 mm x 101.6 mm retrievable, thermal element Wellhead: working pressure 14,800 kPa @ 345°C The completion is designed to inject air at the top of the McMurray zone and provide for the option of injecting steam or hot water at the bottom of the zone if required for temperature control in the horizontal well and or prevention of air breakthrough to the horizontal well. The design pressure rating for the injection wellhead is 14,800 kPa at 345°C. A wellhead drawing is provided in Figure 4-4.



4-2

4.3 HORIZONTAL PRODUCTION WELLS

Each horizontal production well is expected to produce up to 100 m3/d THAI™OIL with 30 m3/d water and 85,000 m3/d combustion gas at a temperature of 250°C. The wells will be drilled and completed as shown on Figure 4-5. The 500 m horizontal sections will have a 177.8 mm liner with wire-wrapped screens. A 73.0 mm endless tubing string will be landed at the toe end for circulation and production capability. An 88.9 mm endless tubing landed at the heel end will be the primary production string. A 38.1 mm endless tubing string landed near the toe will contain up to eighteen thermocouples for temperature monitoring. The material list for each production well is as follows: Surface Casing: 339.7 mm, 71.4 kg/mm, H-40, Round Thread Conn., length 150 m Intermediate Casing: 244.5 mm, 59.5 kg/m, L-80, VAM-SW Conn., length 550 m Horizontal Casing: 177.8 mm, 38.7 kg/m, L-80, VAM-SW Conn., length 535 m Screen Section: 177.8 mm, 316LSS Rib with 0.008” open Tubing-Heel: 73.0 mm, 4.77 mm, WT, QT700, length 1050 m Tubing-Toe: 88.9 mm, 4.77 mm, WT, QT700, length 500 m Tubing Thermocouple : 38.1 mm, 2.77 mm, WT, QT700, length 1020 m Thermocouples: Underground Type K, 18 measuring points, cable length 1020 m Wellhead: working pressure 14,800 kPa @ 345°C The intermediate and horizontal casings require premium connections such as the VAM-SW shown above. Another equivalent premium connection may be used depending on the determination of the casing supplier. Produced fluids are expected to flow to the surface. If lift assist is required during start-up, then steam can be injected at the toe end through the 73.0 mm tubing, or gas lift can be implemented by injecting natural gas down the intermediate casing for return up the 88.9 mm production tubing. The wellhead is designed for top access to the 88.9 mm tubing for swabbing or pumping. Figure 4-6 shows the horizontal wellhead design. Pressure rating is 14,800 kPa at 345°C. Provision has been made for top entry into the 73.0 mm and the 88.9 mm tubing strings and the ability to pull the 73.0 mm tubing back as the combustion front advance from toe to heel.

4.4 OBSERVATION WELLS

Seventeen temperature observation wells and two pressure observation wells are planned. Their locations relative to the horizontal production wells and the vertical air injectors are shown on Figure 4-1. The observation wells numbered one through nine will be drilled first and used to position the horizontal sections and vertical air injectors. They will then be completed as temperature



4-3

measurement wells as shown on Figure 4-7. Eleven thermocouples will be placed through the production zone at 2 m spacing and five thermocouples will be placed above the production zone at 10 m spacing. The material list for each observation well is as follows: Surface Casing: 177.8 mm, 25.3 kg/m, H-40, Round Thread Conn., length 150 m Production Casing: 114.3 mm, 14.1 kg/m, J-55, Round Thread Conn., length 430 m Tubing: 60.3 mm, 6.99 kg/m, J-55, EUE, 8R, length 420 m Thermocouples: Underground Type K, 16 measurement points, cable length 420 m The temperature observation wells (TOBs) numbered one through five will be completed as shown in Figure 4-8. They will have the same arrangement of thermocouples as the temperature measurement wells. The temperature observation wells numbered six through eight are planned for the future. The material list for each TOB well is as follows: Surface Casing: 114.3 mm, 14.1 kg/m, J-55, Round Thread Conn., length 150 m Tubing: 60.3 mm, 6.99 kg/m, J-55, EUE, 8R, length 430 m Thermocouples: Underground Type K, 16 measurement points, cable length 420 m Two pressure observation wells are planned. One will be drilled and completed at the start of the Project (POB1), and the other (POB2) will be added in the future. They will be completed as shown on Figure 4-9. Pressure will be measured at the top of the Wabiskaw Formation and at the top of the lower Clearwater Shale. The placement of perforations will be determined during detailed engineering, giving due consideration to the relative location of the water disposal wells. The material list for each POB well is as follows: Surface Casing: 177.8 mm, 25.3 kg/m, H-40, Round Thread Conn., length 150 m Production Casing: 114.3 mm, 14.1 kg/m, J-55, Round Thread Conn., length 350 m Tubing: 60.3 mm, 6.99 kg/m, J-55, EUE, 8R, length 320 m

4.5 WATER DISPOSAL WELLS

The produced water generated by the Project will be separated from the THAI™OIL at the plant site and then disposed of into the Clearwater Sandstone at a depth of approximately 325 m. The amount of produced water for disposal will depend on whether the dry combustion or wet combustion method is used as outlined in Section 3.6. Water for disposal into the disposal wells will come from condensed steam during the start-up procedure, produced water during the oil production procedure and domestic requirements.

• 670 m3/d water during start-up total for three wells , and • 690 m3/d water during the oil production operations total for three wells based on the wet

combustion method.



4-4

Water disposal wells will be completed as shown on Figure 4-10. Surface casing will be set 25 m into the Clearwater Sandstone with thermal cement to surface. Production casing will be set through the Clearwater Sandstone with thermal cement to surface. Two or more disposal wells may be required depending on injectivity test results. The material list for each disposal well is as follows: Surface Casing: 244.5 mm, 48.1 kg/m, H-40, Round Thread Conn., length 320 m Production Casing: 177.8 mm, 29.8 kg/m, J-55, Round Thread Conn., length 335 m Tubing: 73.0 mm, Fibreglass, length 325 m Packer: 177.8 mm x 73 mm

4.6 WATER SOURCE WELLS

There are plans for two water source wells as necessary to meet process water needs. The expected water source zone is the Empress at an estimated depth of 145 m to 155 m.

4.7 SURFACE REQUIREMENTS (DRILL PADS, ROADS, MUD DISPOSAL)

The drilling pads and roads will be integrated into the Project surface facility plan. Mud disposal and borrow pits are available in the area.

4.8 LIFT SYSTEM

The production lift will be provided by the combustion gas flow with the THAI™OIL/water production. The minimum gas/liquid ratio will be 650. The down hole pressure will be maintained at a minimum of 4000 kPa to ensure sufficient lift pressure. Provision for a gas lift system should be incorporated into the detailed design.

TOP OF McMURRAY ZONE

BASE OF McMURRAY

11 TEMP POINTS OVER 20m

400mKB

420mKB

( 2m INTERVALS )


( 10m INTERVALS )

114.3mm CASINGSet at 425mKB. Thermal Cement to Surface

60.3mm TUBINGThermal Cement To SurfaceInside and Out

THERMOCOUPLE CABLE

177.8mm SURFACE CASINGSet at 150mKB. Thermal Cement to Surface


BASE OF McMURRAY

( 10m INTERVALS )

400mKB

420mKB

( 2m INTERVALS )



60.3mm TUBINGSet at 425mKB. Thermal Cement To SurfaceInside and Out

THERMOCOUPLE CABLE



TOP OF CLEARWATER SAND

400mKB

TOP OF WABISKAW ZONE

114.3mm CASINGThermal Cement to Surface

60.3mm TUBING

PERFORATIONS

PACKER

PERFORATIONS




5-1

5 SURFACE FACILITIES DESIGN

5.1 FACILITIES OVERVIEW

Site access will be via an all-weather road, which will intersect the BP well access road to the gas plant about 2 km northwest of the Project site (Figure 5-1).The surface facility will consist of connections to the three injection wells and three production wells, a steam generation plant, an air compression plant and a production treating facility. Plot plans of the facilities are shown in Figures 5-2 and 5-3. As shown in the Process Flow Diagram (PFD) (Figure 5-4), the production consisting of THAI™OIL, water and gas will flow directly from the wellheads to the production treatment facility. The facilities are designed on the basis of the predictions provided in Section 3.4. The block Process and Instrument Diagram (P&ID) corresponding to the PFD is shown in Figure 5-5. The first element in the production facility is a wellhead separator. This provides damping for production slugs and separates the produced gas from the liquids. The produced liquids are cooled to an operating temperature (to approximately 90°C) acceptable for separating partially upgraded bitumen and water. The liquid production (total fluid and water cut) of each production well will be metered. The metered data from each well will be reconciled with THAI™OIL sales volumes and the metered produced water volumes. The produced gas will be cooled to approximately 80°C, passed through a liquid knockout vessel and then vented to the atmosphere through a stack. The vented gas from each production well will be metered and analyzed for composition. A gas sweetening unit will be installed and operating at all times. Water and hydrocarbons condensed from the produced gas will be combined with the other produced liquids. The water will flow to the produced water tanks and ultimately be sent to deep well disposal. As the production wells will have a screened liner, the amount of produced solids is expected to be small; it will be periodically removed from the treater and tankage and disposed of in an environmentally acceptable manner. THAI™OIL will flow to production tanks from where it will be trucked to sales. Tank gauging will be used to meter the produced THAI™OIL volume. The injection steam is to be used to preheat the injection and production wells. It is expected that the preheating of the three THAI™ well pairs will be completed in less than a year, after which time the steam generation facilities will be retained for stand-by.



5-2

Compression is required to provide a maximum of 255,000 m3 of injection air at a maximum pressure of 8000 kPa. The current design basis includes three 0.79 MW air compressors and three 0.29 MW air compressors, however, other configurations could be considered provided a minimum of two air injection trains are included to ensure that continuous air injection can be maintained. Air injection will begin after the steam preheat phase is complete and the in-situ combustion phase is to be initiated. During the in-situ combustion phase, hot water injection (to prevent thermal shock of cold water) may be required to cool the production well or to redistribute the heat in the reservoir. This injection water will be metered. The water will be heated with the steam generator that was used in the pre-heat phase.

5.2 RAW WATER SUPPLY

Raw water will be from fresh water wells and will be used for the following: • softened for use in the conventional steam generator, • well cooling, • wet combustion (if required), and • domestic use.

The groundwater source will be a water supply well completed in the basal sand and gravel (Empress Formation aquifer) of the buried Christina Valley. A second well may be installed to serve as a backup, and for monitoring water levels and the chemical quality of the groundwater. The water supply well will be located within the plant site if a sufficient thickness of the Empress aquifer is present. Otherwise, the well will be located approximately 500 to 1000 m south of the plant site, closer to the aquifer thalweg. Based on current information, it is anticipated that the minimum depth of the top of the aquifer at the site of the well will be 145 m.

5.3 STEAM GENERATION AND WATER SOFTENING

A rented steam generator complete with a water softening module will be used for the well start up procedure. The horizontal/vertical will pairs will be started up one at a time over the first year of pilot operations. The 53 GJ/hr once-through steam generator, fired by natural gas, will be used to produce approximately 500 m3 per day of 80% quality steam. The steam will be metered as it flows to the steam injection wells. The water treatment and steam generator P&IDs are shown in Figures 5-6 and 5-7 respectively.



5-3

5.4 AIR COMPRESSION

The drivers are expected to run on natural gas (about 23,300 m3 per day of natural gas) but alternatively may be designed to run on electricity that could be made available by power line extension from a nearby existing line. The air compressor P&ID is provided in Figure 5-8. The P&ID indicates three trains of compressors, however, two larger trains could be incorporated as an alternate design approach.

5.5 PIPING, INSULATION, SUPPORTS AND CONTROLS

The pilot facilities will be split between the injection wells and the horizontal wells production end as shown in Figure 5-1. There will be three flow lines on racks to take air, water and steam from the main facilities to the injection well end. The three separate lines are required to allow full flexibility during start-up and production operations. The water and steam lines will be insulated and electrically heat traced. Alternatively, they may be insulated and designed for quick drainage in the event of an interruption in flow.

5.6 PRODUCTION WELLHEAD CONTROLS

The production wellhead will have controls on production from both the long and short tubing. Capability to inject into the long and short tubing will also be available. The inlet separators are to provide dampening for the production, which is expected to slug, and to separate the produced gas from the produced liquid. The P&ID covering the wellheads, inlet separators and produced gas coolers is provided in Figure 5-9. The separated gas will be cooled to 80°C to condense the THAI™OIL and water for secondary separation. The P&ID for the secondary separator is shown in Figure 5-10. The gas from each of the three secondary separators will be monitored continuously for oxygen and hydrogen sulphide content. The measurement of the oxygen content is a safety issue as described in Section 3.9. The stream will also be sampled at least once a day for full chromatographic analysis.

5.7 INJECTION WELLHEAD CONTROLS

The injection wells will be designed to inject water, air or steam alone or simultaneously into the upper and lower perforations of the injection well. This is an important feature of the pilot to provide the maximum flexibility to control the in-situ combustion operations.

5.8 PRODUCTION TREATMENT AND SEPARATION (EMULSIONS )

The produced liquid will be cooled to approximately 90°C before it proceeds to the treater where chemical and diluent will be added to separate the THAI™OIL and water. The gas from the treater will be combined with the gas from the secondary separators before proceeding to the vent stack. The P&ID for the produced liquid coolers, treater and vent gas stack is shown in Figure 5-10.



5-4

5.9 PRODUCTION GAS VENT

The produced gas will be vented through a 75 metre high vent stack. The H2S content of the gas will be monitored at the inlet to the vent stack. An in-line H2S “sweetener” will be used to reduce the H2S content. The aerial cooler, treater and vent stack P&ID is provided as Figure 5-11.

5.10 PRODUCED WATER TREATMENT AND DISPOSAL

Orion proposes to dispose of produced water into the Clearwater Sandstone as described in Section 3.6. Water is currently being disposed into the Clearwater Sandstone by Devon Canada Corporation at rates as high as 509 m3 per day. The petrophysical log studies suggest that the Clearwater Sandstone will be similar in the development area to that encountered at Devon Canada’s 3-7 disposal well. An application for disposal approval will be made separately to the EUB.

5.11 TANKS AND PRODUCT SHIPPING/TRUCKING FACILITIES

There will be tanks for water, THAI™OIL, diluent and slop. There will be oil storage capacity for three days of production. Truck loading facilities will be incorporated into the design. The tanks will be blanketed with natural gas. Gases evolving from the produced fluids in the tanks and excess blanket gas will be collected and sent to the flare stack. The P&ID for the tanks, pumps and flare is shown in Figure 5-12.

5.12 PROCESS UTILITIES

Process utilities will include a fuel gas scrubber and instrument air package as shown in the P&ID (Figure 5-13).

5.13 CONTROL ROOM AND OFFICE

A control room will be provided for operations at the main plant site and for control of the injection end site. Computerized data collection with direct link to the Orion Calgary office will be installed.

5.14 CHEMICAL ADDITION SYSTEM

Chemicals will be required in the separators for emulsion treatment, in the H2S “sweetener”, and in the steam generation water treatment.

5.15 SPACE HEATING & LINE TRACING

Gas fired space heaters and electricity will provide heating and line tracing.



5-5

5.16 HEAT RECOVERY

Heat recovery will not be incorporated into the pilot design, but data necessary to evaluate and design a heat recovery system for a commercial operation will be collected. Production stream volumes, temperatures and pressures will be measured to support an assessment of the commercial viability of a heat recovery system to reduce net process energy intensity.

5.17 DILUENT SYSTEM

Diluent will be available to blend with the THAI™OIL to reduce the gravity and promote separation.



6-1

6 SITE DEVELOPMENT, UTILITIES AND OFF-SITES

The Project development area (see Figure 6-1) is approximately 84 ha in size. Elevations range from 620 ASL in the SW sector to 580 in the NE sector. The central portion is well drained and provides a suitable location for the plant site. Based on the results of the November 2003 drilling program the facility footprint within the development area may be reoriented into a more E-W configuration to take advantage of the of the higher quality reservoir and to avoid low lying ground in the NE sector. Earthwork requirements have not yet been defined. During final engineering the development area will be surveyed and a site plan prepared including plant site, well pads, roads, pipeline corridor, drainage pond, berms, soil storage locations, fresh water well and other Project facilities. A 3.5 km all-weather access road will be constructed, connecting with the existing all-weather BP well access road and the all-weather municipal road near the Leismer gas plant.

6.1 POWER

An existing 3-phase electricity line is located approximately 2.5 km NE of the Project site. Discussions with Aquila Networks indicate that once an agreement is signed it takes up to 20 weeks to install the service. The electrical demand for the Project will depend on whether electrical drivers or gas drivers are specified for the compressors.

6.2 NATURAL GAS

Discussions with ATCO Gas indicate that a high-pressure natural gas pipeline is located north of the development area. Approximately eight months lead-time is required to install gas service once an agreement is signed.

6.3 COMMUNICATIONS

A computerized data collection with direct link to the Orion Calgary office will be installed with the capability to provide 24-hour continuous real-time access to the data generation, control measurements and data base material at the site from the Orion office. The objective is to provide the identical access to site information at the Calgary office as is available at the Project site. Direct control of the Project operations will be restricted to the control room on site. Discussions with Telus indicate that the area is covered by cell phone service and that both conventional copper wire and high speed fibre optic cable service is available from the Highway 881 corridor. The estimated time for telecom service installation is three to six months depending on the type of service required.



6-2

6.4 CAMP FACILITIES

Two large full-service open camps are located at the Conklin 4-corners intersection, approximately 13 km east of the site. It is planned that both construction and operating personnel will use these camps. Contractors may opt to provide on-site facilities.

6.5 CONSTRUCTION FACILITIES

Temporary construction facilities will include: • construction office, • warehouse, • lay-down yard, and • parking lot.



7-1

7 OPERATING DESIGN 7.1 START-UP, SHUTDOWN PROCESS

The objective is to ignite the reservoir without damaging the vertical injection well while avoiding fracturing the reservoir. Any flow-back of gas or fluid into the injection well is to be avoided as this has a high probability of drawing combustion into the well and damaging or destroying the well. The procedure is as follows:

• Inject steam low in the reservoir with the vertical well to heat the reservoir near the vertical well and to develop heated communications with the horizontal production well. The horizontal well will be preheated with steam along its entire length by injecting steam into the well and cycling the hot water out of the well. This will prevent plugging of the well by cold bitumen.

• After heated communication has been achieved from the lower injection point on the vertical well to the horizontal production well, steam will be injected continuously into the lower injection point to enter the horizontal well. The cycling/injection into the horizontal well will be discontinued to allow the steam entering from the vertical well to flow through the horizontal well to complete the heating of the horizontal well to a predetermined temperature (steam temperature less 50°C).

• At this point, steam injection at the base of the vertical well will be terminated and steam will be injected into the upper part of the reservoir to create a heated volume (10 m in radius) around the well at the top of the reservoir that is linked to the lower steam heated area and the horizontal well in preparation for ignition.

• After creation of heated communication between the horizontal and vertical well, air will be injected high in the reservoir via the vertical well to ignite the oil by spontaneous combustion and start the recovery process.

• The air injection, at rates of up to 85,000 m3 /day of air into each vertical injection well, will be below fracture pressure.

Through the pilot life, the production operations will be shut down in a planned manner for such things as yearly maintenance of facilities and special tests. The operations may also need to be shut down due to emergency situations such as detection of high levels of oxygen in the produced gas. The main concern is the manner in which the wells are shutdown and restarted so as not to damage the wells or impede resta rting of the THAI™ process. The shutdown will be conducted in a planned, safe manner.

• For the air injection wells, the main concern is to eliminate the possibility of back flowing combustion material into the well. A constant pressure should be kept on the well to prevent influx of hot reservoir material that could damage the well with combustion in the well or by influx of sand that could plug the well. This will be



7-2

accomplished by injecting steam or hot water (to avoid thermal shock) to prevent the flow back and then filling the well with water to prevent inflow.

• The horizontal production wells should be shut down under pressure to eliminate the possibility of oxygen entering the well and causing damage by combustion in the well in the manner described for vertical wells. The horizontal well design incorporates the capability of circulating the well to flush out material that may have settled in the well or to reheat the well as necessary if shut down for an extended period.

7.2 DATA ACQUISITION AND REPORTING

Data collection for the reservoir is aimed at monitoring and controlling reservoir conditions, mainly pressure and temperature. Observation well data collection will be focused on the conformance and spread of the combustion recovery through the reservoir. The spread of recovery between the horizontal production wells and outside of the unconfined THAI™ pilot pattern will be key to the design of the well spacing to be used for commercial operations. Surface data collection is aimed primarily at measurements of the volume and composition of injected and produced material (e.g. injected air, THAI™OIL, produced water, and produced gas). Surface measurements will provide the basic data for calculating the economics of the THAI™ process, controlling the THAI™ process, designing commercial facilities and meeting mandated environmental regulations. The data acquisition, reporting and comparison will include the following:

• production and injection data, • observation wells data, • material balance for water and air usage, • composition of produced gas, disposal water and flare, • oxygen, hydrogen sulphide, carbon monoxide and carbon dioxide measurements, • pilot injection and production performance (daily and cumulative), • individual well performance (daily and cumulative), • pressure and temperature at well heads, • air/oil ratio (daily and cumulative for pilot and wells), • steam and/or water/air ratio (if wet combustion used), • water/oil and gas/oil ratios for production, • pressure and temperature within wells, • observation wells temperature and pressure, • reservoir pressure and temperature contours, • measurements of surface vent gas concentration in surrounding area, • produced fluid heat content measurements, and • water analyses (pH and ions).



7-3

The focus of the data collection program will be to address the uncertainties in the experimental parameters and to achieve regulatory compliance.

• THAI™OIL, water and gas production, and water and air injection are to be metered for each well and reconciled with total THAI™OIL sales, total water disposal and total gas production.

• Produced gas will be monitored continuously for O2, H2S and CO content. On a routine basis, gas chromatography will be used to obtain a full compositional analysis including CO2.

• On a routine basis, THAI™OIL samples will be analyzed for density, viscosity and SARA (saturates, aromatics, resins and asphaltenes) components.

• On a routine basis, produced water will be analyzed for pH, anions, cations, dissolved solids and entrained oil.

• A test program will be initiated to analyze potential corrosion problems with the downhole tubulars.

• Thermocouples will be installed in the injection wells, the production wells and a number of observation wells to monitor in-situ temperatures.

• A systematic program will be initiated to test various chemical additives in the breaking of the produced emulsions.

• A corrosion-monitoring program will be in place for the surface facilities. • A number of benchmarks will be placed strategically in and around the Project

site. Baseline elevations will be checked periodically to confirm that there is no ground movement.

• THAI™OIL samples will be collected on a routine basis and forwarded to an external lab for analysis.

The Project performance data will be used to develop a history match and improve the predictive capability of the numerical simulation.

7.3 WELL INTEGRITY

There are two main issues related to the well operations as follows: • The horizontal production wells have a risk of being damaged by combustion heat. The

main interventions are to inject cooling water or steam into the vertical injector and/or the horizontal well to cool the production. This can be done on a “slug’ basis or on a continuous basis. If the overheating cannot be remedied, then reducing or stopping air injection will be necessary.

• Excessive sand production may result if the sand control slots or wire wrap is eroded by high velocity gas carrying sand into the well. The effect is like sand blasting and the



7-4

“holes” will become larger. This is a common problem with conventional in-situ recovery operations between vertical wells. Repair of this problem would be difficult. However, as the combustion front with the THAI process moves along the horizontal well, the erosion is most likely at the combustion front where the bulk of the production and gas will enter. If the sand control is breached at the combustion front, the breached section will “disappear” behind the production front as the front moves forward.

7.4 SAFETY AND ENVIRONMENTAL PROTECTION

Personnel Safety There are two major safety risks at the surface facilities, both associated with the produced gas. The produced gas is expected to contain H2S and appropriate safety training and systems must be in place. The anticipated produced gas can be dispersed via the vent as specified to meet the ground level guidelines. The H2S content of the produced gas will be measured and reduced to an acceptable level using a “sweetening” system installed at the plant site. There will also be monitoring stations situated around the area to monitor compliance with environmental requirements. The sweetening system will be a commercially available and proven system (e.g. Canwell) that uses a liquid chemical solution to contact the produced gas to chemically capture the H2S. The units have been proven effective at much higher gas flow rates and H2S content well beyond the conditions anticipated for the pilot. The liquid chemical will be a proprietary blend of aldehyde/alkanolamine condensates that captures both H2S and mercaptans. The supplier of the chemical will collect and dispose of the spent liquid chemical at commercially licensed facilities. The oxygen content of the produced gas may get to the level that could cause an explosion. The oxygen content of the produced gas must be continuously measured and the production stopped if the oxygen content reaches a critical level. Waste Management During regular operation and maintenance of the facilities, a number of waste materials will be generated. These waste volumes will be small. Commercial approved services will be used to remove any wastes which are subject to special disposal requirements. Chemicals will be stored in accordance with EUB guidelines. All production related waste storage vessels will be sized to allow for a realistic waste removal schedule. Each vessel will have secondary containment and leak detection as defined under EUB guidelines. In addition, the entire site will be graded in a manner to contain any spills or releases. The THAI™ process will generate a number of waste streams as detailed in Table 7-1 below. Temporary steam generation will be required only during the THAI well start up and thus



7-5

wastes normally associated with conventional steam generation will only be produced during the start-up period.

TABLE 7-1 WASTE STREAMS

Waste Stream Flow Rate Storage/Disposal Characterization Produced solids Net solids: 1 m3/d Enclosed tank with

vapour recovery & trucked out

Sand with a hydrocarbon constituent residue

Water softener back wash

7 m3/d (during start up only)

Disposal well Highly mineralized water

Steam generator blowdown water

20 m3/d (during start up only)

Disposal well Highly mineralized water

Tank Blanket Gas 0.4 103 Sm3/d (day) Flared (incinerated) Methane, carbon dioxide with a H2S component

Combustion Gas 255 103 Sm3/d (dry) Vented Nitrogen, carbon dioxide with sulphur components

Produced Water 120 m3/d Disposal well Water created by the THAI process & water from the oil sands

Produced Solids The production wells are completed with sand exclusion liners to prevent sand and other solid materials from being carried into the production wells. It is expected that very fine solids will pass through the sand exclusion liners and be co-produced with the THAI™OIL. The solids will accumulate in the oil/water separation facilities and production tanks. Approximately once per year the solids (with residual hydrocarbon) will be removed for off-site disposal at a commercial approved facility. Lubricants Various rotating equipment and air compression facilities will require regular change out of lubricants. The used lubricants will be collected and disposed of by an approved used-oil handling third party contractor. Other Oily Wastes Oily rags, filter cartridges and any other contaminated solid wastes will be stored in a dedicated oily waste bin and disposed of by a third party contractor. Sewage and Grey Water All sewage and grey water will be collected in holding tanks that will be emptied as required by a third party contractor and disposed of at an approved facility.



7-6

Domestic and Dry Wastes Domestic and dry wastes will be collected in a dumpster and removed by a third party contractor and disposed of at an approved facility. Dry wastes will not be burned on site. Other Hazardous Wastes Other hazardous wastes frequently associated with oil and gas facilities, such as certain types of spent catalysts, will not be generated at the facility. The use of radioactive tracers or sources is not anticipated, other than those supplied by third party, properly licensed contractors.

Chemical Storage As described earlier, a variety of chemicals is used in the process primarily for maintenance (e.g. lubricants), water treatment chemicals for steam generation and oil/water demulsifiers. The chemicals used for steam generation water treatment consist of an oxygen scavenger, such as sodium sulfite , and a hardness-sequestering agent known as a chelant (EDTA) and salt. The softening unit requires the use of regeneration chemicals consisting of acid and caustic. All chemicals will be stored in their shipping containers or vessels specifically designed for that type of service within process buildings that will have containment floors.



8-1

8 REGULATORY COMPLIANCE

This section summarizes the regulatory compliance requirements that will impact the final design and construction of the Project. At the time of writing, February 2004, applications for approval have been submitted (October, 2003) to the Alberta Energy and Utilities Board (EUB), under the Oil Sands Conservation Act and to Alberta Environment (AENV) under the Environmental Protection and Enhancement Act. Approval of these applications is anticipated in the first quarter of 2004. Applications for several additional approvals will be submitted in 2004, after the decision to proceed. Regulatory approvals associated with the provision of natural gas and electrical services will be the responsibility of those providing the service.

8.1 ALBERTA ENERGY AND UTILITIES BOARD

The EUB application was based on the conceptual design outlined in this DBM. The EUB approval will be based on that design. Any subsequent significant changes to the approved Project design will require the approval of the EUB and may require the submission by Orion of an amendment application. As well the EUB approval may require Orion to implement specific conditions in the final design. Following the decision to proceed, applications to the EUB will be required for a deep well disposal approval and numerous well licences. The EUB has a number of Interim Directives and other regulatory guidelines covering issues such as noise control (http://www.eub.gov.ab.ca/BBS/requirements/ils/ids/id99-08.htm) and production measurement (http://www.eub.gov.ab.ca/BBS/requirements/ils/ids/id91-03.htm), which should be consulted during the final design phase to ensure compliance.

8.2 ALBERTA ENVIRONMENT AND ALBERTA SUSTAINABLE RESOURCE DEVELOPMENT

The same comments regarding design basis, conditions and changes apply to the AENV approval as are discussed in Section 8.1 above. In particular, emission standards for SO2, H2S, NOx, and particulates will be specified in the approval. For example final selection of the steam boiler will be required to meet the CCME National Emission Guidelines for Commercial/Industrial Boilers and Heaters. Following the decision to proceed, applications to AENV under the Water Act will be required for ground water use and surface drainage. Applications to Alberta Sustainable Resource Development (ASRD) for surface rights (MSL, LOC, MLL, etc.) will be required prior to construction. These approvals will contain numerous design and construction conditions.



8-2

AENV and ASRD administer a number of guidelines, standards and codes of practice dealing with air, water, land and waste management that will impact the Project. These should be evaluated during final design.

8.3 REGIONAL MUNICIPALITY OF WOOD BUFFALO

The Project will require a development permit from the Regional Municipality of Wood Buffalo. The application fee is $10 per $100 thousand of construction cost. The permit requires that developers comply with all the building, mechanical, electrical and safety codes of Alberta. PermitPro in Fort McMurray administers review of final plans and approvals.

8.4 OTHER

Depending on the final design of the Project, additional approvals and compliance requirements may arise. These include for example flare stack lighting and tower and radio frequency approvals from Transport Canada.



9-1

9 PRELIMINARY RISK ASSESSMENT

The WHITESANDS Project is the world’s first field pilot of the THAI™ process and as such there are a number of considerations that may or may not actually be areas of significant risk. In-situ combustion projects using combustion drive have generally encountered recovery conformance issues and well damage by combustion. The gravity drainage aspect of the THAI process and the design of the Project are aimed at preventing these historical difficulties. A summary of the potential design and operating risk areas identified to date are outlined in Table 9-1, along with preliminary design mitigation initiatives and remaining issues for the detailed engineering phase. It is recommended that a preliminary HAZOP assessment be undertaken at the commencement of detailed engineering and that a comprehensive HAZOP review be conducted on the Project when the detailed engineering is between 50% and 80% complete.

TABLE 9-1 PRELIMINARY DESIGN AND OPERATIONS RISK SUMMARY

Risk Description Preliminary Design Considerations

Issues for Detailed Engineering

Excess heat in the production well

The injection and production wells are completed with the facility to inject steam/water to control excess heat in the production well

Define instrumentation systems and operating procedures

Ignition of oil in the production well resulting in damage to the well

Thermocouples in the well to identify heating Continuous monitoring of O2 content in production gas stream System to inject steam/water to control excess heat in the production well

Provide instrumentation and monitoring system details

Failure of the coke plugging process in the formation – air entering the well or coke combustion in the well

Control of overheating through steam/water injection

Define air/water/steam injection rates and monitoring system



9-2



Excessive corrosion in production well related to produced fluids

Ongoing monitoring of well temperatures Control well temperatures to maintain any water in the gas phase

Review corrosion test results Confirm preliminary design approach or identify alternatives Review simulation results Metallurgical solutions

Excessive sand production in the horizontal well impairs production

Well designed includes very standard keystone slots (or wire wrap)

Confirm preliminary design approach or identify alternate or additional control systems Conduct sieve analysis on subject core

Excessive O2 entry into the production well

Continuous monitoring of O2 in the produced gas Operate the well to maintain a pool of oil or water above the production well as a “seal” to prevent oxygen entry by increasing bottom hole pressure

Confirm preliminary design approach or identify alternatives

Explosion due to high O2 content in produced gas stream

Continuous monitoring of O2 in the produced gas Adjust air injection to reduce O2 content Shutdown at specified level


No cap rock to contain THAI™ process, contamination of overlying natural gas and/or groundwater resources by produced gases and fluids

Drilling program in Project area confirmed existence of competent cap rock

Monitoring program

Gas cap above the target reservoir area which may be under lease to other rights holders is consumed in the combustion process

Drilling program in Project area confirmed there is no gas cap

None



9-3



Combustion is not symmetrical about the production well

The interventions available to control combustion conformance are air injection rates and individual well production rates and use of wet combustion

Verify final well locations in high quality reservoir

Emulsion formation Add diluent and optimize demulsifying chemicals as needed

None Include flexibility to resolve any issues following operational start-up

Excessive corrosion in facilities downstream of the wellhead due to high CO2 or SO2 content gas/water

Ongoing monitoring of well temperatures Sparing of key components and replacement as necessary

Review corrosion test results Confirm preliminary design approach or identify alternatives Develop corrosion monitoring program Identify metallurgical solutions

Inability to complete all horizontal wells to 500 m length

Applied conventional horizontal well drilling

Confirm preliminary design approach Resolve problems during drilling and completion process

Destruction or damage of the long production tube due to heat or combustion

The production tube is designed to be pulled back as the combustion front advances through the reservoir


Backflow of air and oil into the injection well

Steam/water can be injected into the injection well with sufficient pressure to prevent backflow

Define in start-up, operating and shutdown procedures

Calcium carbonate or calcium sulphate scale formed in or on the production well

Scale removal through acid treatment




9-4



Erosion of pipes and valves by sand in the production stream

Sparing of key components and replacement as necessary

Confirm preliminary design approach or identify alternatives Develop monitoring program for critical areas Design to minimize erosion

H2S in the production gas stream

Continuous monitoring of H2S content in the produced gas Gas sweetening capability incorporated Shutdown at defined level

Confirm preliminary design approach or identify alternatives Emergency Response Plan



APPENDIX A GEOLOGY

PROPR IETARY AND CONFIDENTIAL ORION OIL 03-2303


A-1

GEOLOGY

RESOURCE DESCRIPTION Orion currently holds 45 sections of land under oil sands lease agreements in the Conklin area of north-eastern Alberta. The site of the planned Project in Sections 12 and 13, Twp 77, R. 9, W4M is held under Oil Sands Agreement 7400010012 (Lease 012), which expires in 2015-01-13. The natural gas rights in the Clearwater Formation are held by BP Canada. The natural gas rights in the McMurray Formation in Sections 12 and 13 are undisposed Crown rights.

Orion has conducted an extensive review of the regional geological database. Within the six township (Twp 76 to 77 Ranges 8 to 10 W4M) area surrounding the site, 187 wells have been drilled which includes 93 gas wells, 46 standing wells, 45 dry and abandoned wells and 3 water disposal wells. Of the 28 wells on Orion oil sands leases, 7 had log results indicating bitumen saturation in McMurray channel sandstones. Orion has also closely followed the recent review of geological data in the Leismer Field by the EUB in dealing with the ongoing gas-associated-with-bitumen issue. Based on this abundance of data and the resulting interpretation, Orion is very confident of its characterization of the regional geology as it directly relates to the proposed Project site.

In early 2003 Orion conducted a 3-D seismic program of an approximate 20 km2 area in Lease 012, which includes the Project site (see Figure A-1 McMurray Seismic Character Correlation Map). The objective was to obtain data that could be correlated to wells in close proximity to the area, which would enable Orion to identify a Project location with acceptable reservoir characteristics and which also was a suitable development site within reasonable proximity to existing infrastructure. REGIONAL GEOLOGY The bitumen resource target for the Project is found in the McMurray Formation, which is the basal unit of the Lower Cretaceous Mannville Group. The McMurray Formation contains the significant bitumen reserves that constitute the Athabasca oil sands deposit of Northeastern Alberta. The study area for this regional discussion encompasses Township 76 and 77 Ranges 8 to 10 W4M.

The Mannville Group is composed of very weakly consolidated clastic sedimentary rocks that rest unconformably on the carbonates of the Devonian Beaverhill Lake Group (Figure A-2 Generalized Stratigraphic Section). In Northeastern Alberta, the Mannville Group is divided into three formations. From oldest to youngest these formations are: the McMurray, the Clearwater, and the Grand Rapids. The Mannville Group is overlain by Cretaceous Colorado Shale that is truncated by Quaternary glacial deposits as shown in Figure A-3 (Project Site Cross-Section).

GEOLOGY OF THE MCMURRAY FORMATION – PRODUCTION ZONE

The regional McMurray Formation consists of a lower member of fining upward fluvial to estuarine sandstones and an upper member of coarsening upwards brackish bay fill deposits,



A-2

separated by a mappable flooding surface. Generally, the regional McMurray, especially the Upper McMurray exhibits a horizontally layered package. The thickness of the Lower McMurray, however, is controlled by topography on the pre-Cretaceous unconformity surface, as illustrated by the Devonian Structure map (Figure A-4) and the Clearwater Marker to Devonian Isopach (Figure A-5). Due to lowstand sea level events during the Upper McMurray time, at least two incised valley systems are interpreted to have eroded up to 30 m of the regional McMurray Formation. Stacked estuarine channel sandstones, which infilled these valleys, comprise the target reservoir for the Project. A large-scale sedimentary structure, known as inclined heterolithic stratification (IHS) is often observed within valley fill channel sandstones. Structure on the top of the McMurray Formation, as shown on the McMurray Structure map (Figure A-6), is influenced by both drape over the pre-Cretaceous unconformity surface as well as differential compaction over the incised valley sequences. These structural influences diminish up the stratigraphic section, as seen on the Base Clearwater Structure map (Figure A-7). Structurally, the McMurray Formation top dips approximately 1.7 m per km to the southwest (see McMurray Top Structure Map Figure A-6). Together with the surface topography, the resulting depth to the McMurray top varies from 300 m to 480 m in the regional study area. Based on an estimated fracture gradient of 20 kPa per metre of depth, the fracture pressure of the McMurray at 400 m would be 8,000 kPa. CLEARWATER FORMATION The Clearwater Formation is made up of two sand-shale sequences in the Project area, described below:

Wabiskaw Member The lowermost part of the Clearwater Formation is made up of the Wabiskaw Member, which directly and sharply overlies the McMurray Formation. This member, typically around 10 m thick, consists of upward cleaning, transgressive marine silty sands. Sufficient stratigraphic variability occurs in this member to develop numerous small traps for gas and some minor amounts of bitumen (Wabiskaw Gas Pay Map, Figure A-8). A regionally correlatable, initial transgressive shale at the base of the Wabiskaw Member separates it from the McMurray Formation.

Lower Clearwater Shale - Production Zone Caprock Abruptly overlying the Wabiskaw Member is a shale sequence that is about 22 m thick forming a major caprock between the Clearwater Sandstone Member above and the Wabiskaw–McMurray below (Figure A-9 Caprock to McMurray Isopach Map). It includes the five-metre thick Wabiskaw Marker, a regionally correlatable bentonite bed.



A-3

Over a five-metre interval, this shale sequence quickly grades into the overlying Clearwater Sandstone (Figure A-10 Clearwater Sandstone Isopach)

Clearwater Sandstone – Water Disposal Zone The Clearwater Sandstone is a very uniform, 35 m thick marine shoreface complex that hosts a significant, structurally-controlled gas accumulation, extending into the northeastern-most part of the Orion lease holdings (Figure A-11 Clearwater Sandstone Gas Pay Map). This Clearwater Sandstone is the proposed water disposal zone for the Project.

Upper Clearwater Shale The Clearwater Sandstone is sharply overlain by a series of interbedded shales and cleaning-upward sandy siltstone packages that total 22 to 36 m in thickness, which form the seal for the Clearwater Sandstone gas pool. The top of the Clearwater Formation has a short, transitional contact with the base of the Grand Rapids Formation.

GRAND RAPIDS FORMATION The Grand Rapids Formation can be divided into an upper and lower member: The Lower Grand Rapids Member is a 30 to 40 m thick upward-coarsening sandstone, which is water wet throughout the area. The Upper Grand Rapids member consists of 38 to 60 m of up to four stacked coarsening-upwards sand cycles separated by impermeable, thin marine shales. Gas is trapped in combined structural-stratigraphic traps in the upper cycles in the regional study area. COLORADO GROUP Tight marine shales of the Cretaceous Colorado Group overlie the Grand Rapids Formation. The Colorado Group is dramatically truncated at the unconformable contact with the unconsolidated Quaternary glacial drift. Preserved Colorado Group thickness varies from as little as 5 m to more than 80 m in the study area (Figure A-12 Preserved Colorado Isopach Map). In the vicinity of the proposed Project, 40 to 60 m of Colorado section is expected. The Colorado Group Shale forms an effective seal between the brackish water- and hydrocarbon-charged Cretaceous sediments below and the freshwater-bearing glacial sediments above. QUATERNARY – WATER SOURCE HORIZON The surficial glacial drift is made up of gravel, sand, silt and clay. The Empress Formation is the proposed fresh water source for the Project at an estimated depth of 145 m to 150 m below surface in the area of the Project site.



A-4

PROJECT SITE GEOLOGY The proposed Project site is in Sections 12 and 13 Twp 77 Rge 9W4M and within the 20 km2 3-D seismic survey that Petrobank Energy and Resources Ltd. shot and processed January 2003. Core test holes on the site were completed in November 2003 and are the basis of current interpretations. Core was cut to calibrate petrophysical log analyses and provide key engineering parameters. As previously discussed, the target reservoir is interpreted to be McMurray Formation comprising compound incised valley fill sandstones. In general, the incised valley orientation is interpreted to be northeast–southwest (see McMurray Incised Valley Sandstone Isopach Figure A-13). The location of the 3-D seismic was determined based on this interpretation. There is essentially no gas observed in this valley sandstone complex. Less than 1 m of log indicated gas in the 8-13-77-9W4 and 10-7-77-8W4 wells, which are at the highest structural area of the seismic survey. There is also no underlying water apparent from logs in the incised valley channel sandstones, although wet Lower McMurray sandstone is seen in the 10-7-77-8W4 well between 388 and 394 mKB.

Seismic Definition of the Project Site In the area covered by the Orion 3-D seismic program, both McMurray regional and channel sandstones have been encountered by the existing wells. Seismically, the distinction between the target channel sandstones and the regional sandstone sequence can be interpreted in part by differences in the bedding between the two. Within the McMurray time interval, the regional sequence usually exhibits flat lying reflectors, while portions of the channel packages show inclined reflectors as a result of IHS, thus allowing for channel or non-channel fairways to be mapped. This does not necessarily predict channel reservoir quality. The thickest, most continuous, and best channel sandstone reservoirs do not have any reflectors. The seismic amplitude characteristics of a thick, continuous channel sandstone at an existing well was extracted and compared to the other McMurray interval seismic amplitudes within the 3-D survey. Using a pattern recognition algorithm, the correlation coefficient between the extracted amplitude and the amplitude recorded and processed at each bin in the survey was calculated. The results were mapped as seen on the McMurray Seismic Character Correlation Map (Figure A-1), which shows areas of higher correlation in shades of blue and areas of lower correlation in red. It must be noted, however, that the amplitude characteristics of the desired reservoir can also be produced by other variables such as shale; consequently, the McMurray Seismic Character Correlation Map should be interpreted in conjunction with a review of the actual seismic cross-section in order to place the amplitude in context.



A-5

Reservoir Quality

Reservoir quality is considered to be good to excellent based on petrophysical log responses. The four wells with log indicated bitumen pay in the seismic survey area have a weighted average of 21.4 m of pay at 33 percent sandstone density porosity, using cut-offs of 20 ohm-m and 30 percent porosity as shown in the Net Bitumen Pay Map (Figure A-14). Core from the test holes in the pilot site area confirmed petrophysical responses. The sands are well sorted, upper fine to lower medium grained, with local matrix supported intraformational conglomerate. Pay in the pilot site area is 23 to 24 metres thick with a minimum bitumen saturation of 70 per cent and a minimum porosity of 30 percent. Porosity values are as high as 39 percent and bitumen saturation can exceed 90 percent of pore volume. Permeability is greater than one Darcy, with over 11 Darcies observed. Higher gamma ray values in the pay column corresponded to intraformational conglomerate.

WATER DISPOSAL ZONE Orion proposes to dispose of water produced from the Project into the Clearwater Sandstone. Water is currently being disposed into the Clearwater Sandstone by Devon Canada Corporation using a well at 3-7-77-7W4M, about 11 km from the proposed Project site. Since 1982, at the 3-7-77-7W4 well, 240,309 m3 of water have been disposed into the Clearwater Sandstone at rates as high as 509 m3 per day. Mapping and correlation based on petrophysical logs indicate that the geology for the Clearwater Sandstone disposal zone at the proposed Project site is the same as at the 3-7 disposal well. At the proposed Project site, more than 24 m of wet sandstone underlying 7 m of gas charged sandstone is anticipated. A nearby well at 10-18-77-8W4 cored Clearwater sandstone with permeabilities from 1.5 to 6 Darcies and porosities consistently above 30 percent. The Clearwater Sandstone underlies the entire study area and is as thick as 40 m elsewhere on the Orion lease. An application, under Section 26 of the Oil and Gas Conservation Act and Guide-51, for subsurface water disposal into the Clearwater Sandstone will be prepared and submitted under a separate cover in 2004.



APPENDIX B

PRELIMINARY PROJECT SCHEDULE

ID Task Name Duration Start Finish

1 Public Consultation 324 days Mon 10/20/03 Wed 12/29/04

11

12 Business Plan 176 days Mon 3/15/04 Mon 11/1/04

13 Corporate Project Approval 1 day Mon 3/15/04 Mon 3/15/04

14 Marketing & Logistics 95 days Thu 7/1/04 Mon 11/1/04

15

16 Project Management 230 days Mon 3/1/04 Fri 12/31/04

17 DBM Complete 1 day Mon 3/1/04 Mon 3/1/04

18 Project Cost Estimate 1 day Mon 3/15/04 Mon 3/15/04

19 Select Engineering Team 1 day Mon 3/15/04 Mon 3/15/04

20 Orion Decision to Conduct Site Survey 1 day Mon 3/15/04 Mon 3/15/04

21 Project Execution Plan 1 day Mon 5/3/04 Mon 5/3/04

22 Staffing 228 days Wed 3/3/04 Fri 12/31/04

23 Assign Production Drill Program Management 1 day Mon 3/1/04 Mon 3/1/04

24

25 Regulatory Approvals 174 days Wed 2/18/04 Mon 10/4/04

26 EUB Project Approval Granted 1 day Fri 2/20/04 Fri 2/20/04

27 EUB & AEPEA Approvals Compliance Plan 10 days Wed 2/18/04 Tue 3/2/04

28 Conservation & Reclamation Plan Approval 45 days Thu 4/1/04 Tue 6/1/04

29 Surface Lease Rights 44 days Mon 3/1/04 Thu 4/29/04

30 RMWB Development Permit Application Submission 23 days Mon 3/15/04 Wed 4/14/04

31 Safety Codes Act - Submit Application to Permit Pro 77 days Tue 6/29/04 Mon 10/4/04

32

33 2003/04 Exploration Program - Stratigraphic Wells 47 days Wed 10/29/03 Wed 12/31/03

34 Well Licence Application 6 days Wed 10/29/03 Wed 11/5/03

35 Liason with Local Alta Sustainable Resources Development Officer re access road 5 days Mon 11/3/03 Fri 11/7/03

36 Access Contruction / Drill Pad Prep 3 days Thu 11/6/03 Sun 11/9/03

37 Drill Three (3) delineation Wells 6 days Mon 11/10/03 Mon 11/17/03

38

39 Core Analysis 23 days Mon 12/1/03 Wed 12/31/03

40 Core Analysis at Core Lab 11 days Mon 12/1/03 Mon 12/15/03

41 Detailed Core Description 11 days Mon 12/1/03 Mon 12/15/03

42 Integrate core analysis with petrphysics; Generate Bitumen Weight % Maps 23 days Mon 12/1/03 Wed 12/31/03

43

44 Confirm Observation Well Locations 1 day Mon 3/15/04 Mon 3/15/04

45

46 Pilot Production Drilling Operations 165 days Mon 3/1/04 Fri 10/1/04

47 Observation Well Drilling 53 days Mon 3/15/04 Tue 5/25/04

48 Select OB Well Drilling Contractors/ Reserve Drill Rigs 1 day Mon 3/15/04 Mon 3/15/04

49 OB Well Casing & Services Bid 13 days Tue 3/16/04 Thu 4/1/04

50 Award OB Well Casing & Services Contract 1 day Fri 4/2/04 Fri 4/2/04

51 Survey Locations of Observation Wells 11 days Fri 4/2/04 Fri 4/16/04

52 Application for OB Well Licences (9) 5 days Mon 4/19/04 Fri 4/23/04

53 Lease Construction / Site Prep 6 days Mon 4/26/04 Sat 5/1/04

54 Drilling Programs 24 days Tue 3/30/04 Fri 4/30/04

55 Drill OB wells 18 days Sat 5/1/04 Tue 5/25/04

56

57 Evaluate Results of OB Wells 9 days Wed 5/26/04 Sat 6/5/04

58 Confirm Locations for Horizontal Producers & Vertical Injector wells 1 day Sat 6/5/04 Sat 6/5/04

59

60 Horizontal Well (3) Drilling 82 days Thu 4/1/04 Tue 7/20/04

61 Horizontal Well Casing, Wellheads, Services bids 22 days Thu 4/1/04 Fri 4/30/04

62 Select Horizontal Well Drilling Contractor 22 days Thu 4/1/04 Fri 4/30/04

3/15

3/1

3/15

3/15

3/15

5/3

3/1

2/20

3/15

6/29

3/15

3/15

4/2

6/5

Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan FebQtr 4, 2003 Qtr 1, 2004 Qtr 2, 2004 Qtr 3, 2004 Qtr 4, 2004 Qtr 1, 2005 Qtr 2, 2005 Qtr 3, 2005 Qtr 4, 2005 Qtr 1, 2006

Orion Oil Canada Limited WHITESANDS Experimental ProjectPreliminary Project Schedule

Page 1


63 Survey Horizontal Well Locations 7 days Sun 6/6/04 Mon 6/14/04

64 Application for Horizontal Production Well Licences 7 days Tue 6/15/04 Wed 6/23/04

65 Drill Program for Horizontal Wells 12 days Wed 6/16/04 Thu 7/1/04

66 Lease Construction (Drilling pad & surface facilities) 12 days Tue 6/15/04 Wed 6/30/04

67 Drill Horizontal Production Wells 13 days Fri 7/2/04 Tue 7/20/04

68

69 Air Injection Wells 111 days Thu 4/1/04 Sun 8/22/04

70 Air Injection Well Casing, Wellheads, Services bids 22 days Thu 4/1/04 Fri 4/30/04

71 Select Air Injection Well Drilling Contractor 11 days Thu 4/1/04 Thu 4/15/04

72 Survey Air Injection Well Locations 11 days Sun 6/6/04 Fri 6/18/04

73 Well Licences for Air Injection Wells 7 days Mon 6/21/04 Tue 6/29/04

74 Lease Construction 6 days Wed 7/21/04 Tue 7/27/04

75 Air Injection Well Drill Program 13 days Thu 7/22/04 Wed 8/4/04

76 Drill Air Injection Wells 15 days Thu 8/5/04 Sun 8/22/04

77

78 Water Disposal Wells 142 days Thu 4/1/04 Fri 10/1/04

79 Water Disposal Well Casing, Wellheads, Services bids 21 days Thu 4/1/04 Thu 4/29/04

80 Select Water Disposal Well Drilling Contractor 11 days Thu 4/1/04 Thu 4/15/04

81 Survey 11 days Sun 6/6/04 Fri 6/18/04

82 Water Disposal Well Licence Application 7 days Mon 6/21/04 Tue 6/29/04

83 Disposal Well Drill Program 13 days Fri 7/16/04 Sat 7/31/04

84 Drill Two (2) Water Disposal Wells 4 days Mon 8/23/04 Thu 8/26/04

85 EUB Water Disposal Application 23 days Wed 9/1/04 Fri 10/1/04

86

87 Temperature OB wells (5) & Pressure OB Well (1) 95 days Mon 5/10/04 Mon 9/6/04

88 Select Drilling Contractor for add'l temp / pressure OB wells 11 days Mon 5/10/04 Mon 5/24/04

89 Confirm Locations based on Horizontal Well Drilling 1 day Fri 7/23/04 Fri 7/23/04

90 Survey Additional OB Wells 14 days Sat 7/24/04 Sat 8/7/04

91 Apply for well licences 5 days Sun 8/8/04 Thu 8/12/04

92 Drill Program for Extra Temp & Press OB wells 14 days Mon 8/2/04 Tue 8/17/04

93 Drilling Operations 8 days Fri 8/27/04 Mon 9/6/04

94

95 Two (2) Water Source Wells 79 days Thu 4/1/04 Thu 7/15/04

96 Water Source Well Casings and Services Bids 21 days Thu 4/1/04 Thu 4/29/04

97 Select Water Source Well Drilling Contractor 11 days Thu 4/1/04 Thu 4/15/04

98 Water Act Licence 77 days Mon 4/5/04 Thu 7/15/04

99 Water Well Licence 7 days Thu 4/1/04 Fri 4/9/04

100 Survey 11 days Mon 5/17/04 Mon 5/31/04

101 Water well Drill Program 14 days Wed 5/12/04 Mon 5/31/04

102 Drill Water Source Wells 6 days Tue 6/1/04 Sun 6/6/04

103

104 Completion Operations 161 days Mon 3/1/04 Mon 9/27/04

105 Confirm Tubular Metalurgy 11 days Mon 3/1/04 Mon 3/15/04

106 Order Wellheads for Production Wells 69 days Wed 5/5/04 Mon 8/2/04

107 Bids & Selection of Well Service Contractors 21 days Mon 5/3/04 Mon 5/31/04

108 Horizontal Well Completion Operations 8 days Thu 8/12/04 Sun 8/22/04

109 Air Injection Well Completion Operations 5 days Mon 8/23/04 Fri 8/27/04

110 Water Disposal Well Completion Operations 6 days Fri 8/27/04 Thu 9/2/04

111 Press OB Well Completion 2 days Tue 9/7/04 Wed 9/8/04

112 Recompletion of OB Wells 13 days Thu 9/9/04 Mon 9/27/04

113

114 Engineering; Procurement; Construction 197 days Mon 3/15/04 Tue 11/30/04

115 Detailed Facilities Engineering 93 days Mon 3/15/04 Fri 7/16/04

7/23

3/1

Assume Spring BreakupMarch 15



Page 2


116 Issue Contract for Engineering 1 day Mon 3/15/04 Mon 3/15/04

117 Site Topographic Survey 11 days Tue 3/16/04 Tue 3/30/04

118 Soils testing 11 days Wed 3/17/04 Wed 3/31/04

119 Detailed Engineering: Equipment Specification / Site Design 79 days Mon 3/15/04 Mon 6/28/04

120 Generate RFQ for Equipment 46 days Tue 5/18/04 Fri 7/16/04

121

122 Procurement 101 days Thu 5/27/04 Fri 10/1/04

123 Place order for Equipment 50 days Thu 5/27/04 Fri 7/30/04

124 Equipment Delivery 74 days Thu 7/1/04 Fri 10/1/04

125

126 Production Site Prep 103 days Fri 3/19/04 Mon 8/2/04

127 Brushing & Clearing 7 days Tue 6/1/04 Mon 6/7/04

128 Completed Site Prep Plan including road requirements & facility locations 10 days Tue 6/1/04 Thu 6/10/04

129 Secure Road Use Agreement with BP 1 day Mon 5/31/04 Mon 5/31/04

130 Upgrade WHITESANDS Access Road 9 days Thu 6/3/04 Fri 6/11/04

131 Upgrade BP Road 9 days Mon 6/14/04 Thu 6/24/04

132 Facilities Site Prep 15 days Tue 6/15/04 Mon 7/5/04

133 Construction Camp Facilities Move in 1 day Mon 8/2/04 Mon 8/2/04

134

135 Utility Contracts - Letters of Intent 9 days Fri 3/19/04 Wed 3/31/04

136 Power 1 day Fri 3/19/04 Fri 3/19/04

137 Natural Gas 1 day Fri 3/19/04 Fri 3/19/04

138 Telecommunications 9 days Fri 3/19/04 Wed 3/31/04

139 Site Utilities 190 days Mon 3/22/04 Fri 11/26/04

140 Gas 190 days Mon 3/22/04 Fri 11/26/04

141 Power 114 days Mon 3/22/04 Mon 8/16/04

142 Telecommunication 142 days Thu 4/1/04 Fri 10/1/04

143

144 Construction 91 days Mon 8/2/04 Tue 11/30/04

145 Production Facilities Construction 91 days Mon 8/2/04 Tue 11/30/04

146

147 Commisioning & Startup 350 days Wed 9/1/04 Sat 12/31/05

148 Inspection 65 days Wed 9/1/04 Tue 11/30/04

149 Commisioning 23 days Wed 12/1/04 Fri 12/31/04

150 Start up of Operations 261 days Mon 1/3/05 Sat 12/31/05

151 Develop Detailed Operating Procedure 186 days Mon 3/1/04 Mon 11/1/04

152 Start up Plan & Procedure 186 days Mon 3/1/04 Mon 11/1/04

153 Ignition Procedure 183 days Mon 3/1/04 Wed 10/27/04

154 Communication Procedure 183 days Mon 3/1/04 Wed 10/27/04

155 Ongoing Operational Procedure 183 days Mon 3/1/04 Wed 10/27/04

156 Risk Mitigation Procedure 183 days Mon 3/1/04 Wed 10/27/04

157

158 HS&E Management 182 days Thu 4/1/04 Fri 11/26/04

159 Environment Protection Plan 83 days Fri 6/11/04 Fri 9/24/04

160 Emergency Response Plan 182 days Thu 4/1/04 Fri 11/26/04

161 Well Head Emergency Shutoff Valve Write up 1 day Mon 11/1/04 Mon 11/1/04

162 Global Project Hazops & Risk Analysis 2 days Thu 4/1/04 Fri 4/2/04

163 Detail Operational Hazop 4 days Mon 11/15/04 Thu 11/18/04

164

165 Reservoir Engineering & Modeling 309 days Mon 11/10/03 Thu 12/30/04

166

167 Corrosion research Project 97 days Mon 10/20/03 Mon 3/1/04

3/15

5/31

8/2

3/19

3/19

3/19

1/3

6/11

11/1



Page 3

Documents

Formatted DBM Feb 27.pdf