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AMEC 2010-001

THE FUTURE OF THE CANADIAN : AND PROJECT MANAGEMENT ADVANCES

Peter B. Madden* and Jacek D. Morawski†

This paper discusses production technology and project management developments in the Canadian oil sands , in the context of AMEC’s experience as a consultant and EPCM service provider to lease holders, developers and operators. Mineable and oil sands developments are described, along with methods for and challenges of various production types of in situ, including Cold Flow, Cyclic Steam Stimulation (CSS), Steam Assisted Gravity Drainage (SAGD), Toe to Heel Air Injection (THAI), and VAPEX. Effective project management and supporting systems are critical to achieve cost and schedule targets on large, complex projects performed by AMEC. Workfront planning is essential to achieve optimum construction execution and a best value project. Construction Packages (CWPs) divide the work into discrete pieces and the Construction Work Execution Plan influences scheduling of engineering and procurement deliverables. Integration of the schedules and linking to the required on site (ROS) dates of the CWP scopes minimizes workfront duration requirements, allowing progressive completion of systems. AMEC’s Engineering Data Warehouse (EDW) works with centrally-hosted, intelligent engineering design tools to assist in achieving tight cost and schedule targets. The EDW ensures all information related to a given piece of equipment is consistent across all systems, supporting quality assurance of engineering data between AMEC, its sub-contractors and supervised contractors. Once verified and consolidated, the information becomes part of a Master Tag Register (MTR), improving AMEC’s ability to meet contractual turnover requirements for data quality, completeness and accuracy. Health, safety, security and environmental (HSSE) systems are proactively developed and AMEC’s progressive improvement in safety performance over the years is demonstrated. The improvement is due in part to the company’s Beyond Zero program, designed to achieve sustainable, world-class HSSE performance. INTRODUCTION This paper addresses developments in the Canadian oil sands industry including production technology and project management advances, in the context of AMEC’s experience as a consultant and EPCM service provider to lease holders, developers and

* President Oil Sands, AMEC, 900 AMEC Place 801-6th Avenue SW, , AB, , T2P 3W3. † Engineering Director, AMEC, 900 AMEC Place 801-6th Avenue SW, Calgary, AB, Canada, T2P 3W3. operators of the oil sands. Additionally, the paper addresses the specific areas where AMEC is working with the clients on Oil Sands mega-projects to provide to technological, environmental and commercial challenges. Enhanced project management initiatives and systems that support data management are also addressed. The implementation of these initiatives and systems is accomplished through an integrated completions and commissioning plan with improved accessibility for operations. OIL SANDS BACKGROUND AND FACTS The oil sands accounts for more than 170 billion of the 175 billion barrels of proven in Canada that are recoverable with today’s technology. Canada is second only to in terms of total volume.1 The reserves are contained in three major areas of northeastern beneath about 140,000 square kilometers. As of March 2009, approximately 600 square kilometers of land were disturbed by oil sands surface activity.2 Approximately 80 per cent of recoverable oil sands can be recovered through in situ production, which has significantly less land disturbance, with the remainder recoverable by mining. In 2008, Alberta produced 213 million barrels (33.9 million cubic meters) from the in situ area and 264 million barrels (42.0 million cubic meters) from the mineable area, totaling 75.9 million cubic meters (477 million barrels), for a total of 1.31 million barrels (207.4 thousand cubic meters) per day. While the bitumen produced from mining was upgraded, bitumen crude produced from in situ operations was mainly marketed as non-upgraded crude bitumen.3 One in 13 jobs in Alberta is directly related to and every dollar invested in the oil sands creates about $9 worth of economic activity, with one-third of that economic value generated outside Alberta – in Canada, the U.S. and around the world. Oil sands make up about five per cent of Canada’s overall greenhouse emissions and less than one-tenth of one per cent of the world’s emissions.4 The Canadian Association of Producers (CAPP) conducted a survey of oil sands producers in early 2010 to determine their plans for production of both bitumen and upgraded crude oil from 2010-2025.5

Figure 1 – Growth Case – Oil Sands & Conventional Production The Growth Case illustrated in Figure 1 is based on the assumption that oil sands projects will be developed and brought into service gradually.6 Typically, oil sands leases are in undeveloped locations near the which, along with underground aquifers, provides a source of . The remote locations and limited labour capacity from the Fort McMurray area have necessitated large camps to be built at the mine site as well as airstrips to labour from all over Canada without increasing local labour demand. MINEABLE OIL SANDS The depth of the reserves determines whether mining or an in situ process will be used for recovery. Overburden removal is economically practical up to a depth of 75 meters for mining; beyond that depth, in situ techniques are preferred.7 Table 1 – Evolution of Oil Sands Mining Technology Function Old Current Next

Cutter Wheel At Face & Oil Sands Extraction Conveyor Shovel & Trucks Conveyor with Dragline Hydrotransport

Power Power from the Grid Nuclear Generation CT (composite tailings) Tailings Ponds Ponds & Thickeners MFT (mature fine tailings) Management Polymers

Prior to excavation, muskeg and overburden are removed to expose the oil sands and stockpiled for use in reclamation. The evolution of oil sands technology is listed in Table 1 and, since the first oil sands started production in 1967, has been at the forefront of the industry.8 Initially, draglines excavated the face of the formation and bucketwheels along with long conveyor belts moved the raw bitumen to on-site processing facilities that used hot water and tumblers to separate the oil and the .9 By the 1980s, trucks and power shovels began to replace the bucketwheels and draglines and, today, all bitumen mining employs the truck and shovel method.10 Power shovels dig out the oil sands and load it into trucks which transport the oil sands to crushers that break up lumps and remove rocks. In a process called hydrotransport, the oil sand is mixed with water at either 35°C or 50°C, depending upon the mine, and is piped to the processing plant. During hydrotransport, the bitumen begins to separate from the sand, water and minerals. The introduction of the hydrotransport system greatly increased both yields and reliability.11 Separation continues at the plant where the bitumen forms a thick froth at the top of the separation vessel and the sand settles out to the bottom. Material, including water, from the middle part of the vessel is further processed to remove more bitumen, the water is recycled and the sand is used in mine site reclamation.12 The next step is froth treatment, in which froth from the top of the separation vessel is treated to eliminate aqueous and solid contaminants to produce a clean bitumen product. The froth is first diluted with a to reduce the and density of the oil, which accelerates the settling of the impurities.13 Conventional froth treatment uses inclined plate settlers or to remove water and solids.14

Figure 2 – Mineable Bitumen Extraction Plant Flowchart A typical mining oil sands facility today, as illustrated in Figure 2, consists of:  Open pit mine  Shovel and truck (100 and 400 tonnes payload)  Double roll crushers  Conveyors (8,000 tonnes/hr)  Slurry plant (mix box)  Pumping and hydrotransport pipeline  Primary separation vessel (PSV)  Secondary separation (flotation)  Tailings, pipeline and pond  Froth treatment (solvent recovery, removal of fines and addition of )  Diluted bitumen tank The future of oil sands mining includes mobile “at face” crushing and slurification to reduce both cost and environmental impact. As the name implies, the principles of “at face” crushing involve a mobile crusher, located next to the power shovel at the mine face, so that the ore can be dumped in directly, crushed, and fed to a connected slurry pipeline. With this system, trucks would still be needed to carry overburden and to reach less accessible parts of the mines, but trucking requirements and related air emissions would be greatly reduced.15 Technical Challenges In a mineable bitumen extraction facility, the froth treatment area has seen many technological improvements. Most notable is the move away from the naphthenic process to a paraffinic process. The naphthenic process is mechanical, requiring centrifuges and inclined plate separators. The paraffinic process is chemical and utilizes gravity separation, with the resulting product having lower levels of contaminants such as water and mineral solids.16 Environmental Challenges Tailings Management. It requires two tonnes of oil sand to produce one of oil. As a by-product of the production, oil sands tailings are produced and contained in large earthen tailings ponds. Tailings are a mixture of , sand, water, , residual bitumen and other , salts and trace . Over time, the settle out and much of the water is treated and reused.17 New techniques are being implemented to:  promote the settling of fine solids in tailings ponds, reducing the volume of water required for process cooling  improve consolidated tailings, thus reducing tailings ponds  create dry tailings, reducing the use of water, eliminating ponds and aiding the reclamation process.18 Water Use. Many mining projects are located near the Athabasca River, which is currently the source of fresh water for the projects. Strict limits are placed on industry water use through Alberta’s Water Management Framework for the Lower Athabasca River. This framework puts a weekly cap on how much water oil sands companies can remove, which is tied to the fluctuating flow of the river. All existing and approved oil sands projects will withdraw less than three per cent of the average annual flow of the Athabasca River. Up to 90 per cent of the water used can be recycled depending on the maturity of the facility and type of extraction.19,20 As discussed above, advancing technology in tailings management is reducing the volume of water required and the speed at which it can be reused. Land Use. Companies must remediate and reclaim Alberta’s land so it can be productive again. Alberta Environmental legislation requires that all reclaimed land be able to support a range of activities similar to its previous use. A conservation and reclamation plan for the life of the project must be submitted prior to project approval and is modified as mine planning advances to ensure the desired end land use is achieved. Additionally, the government requires financial guarantees to ensure that reclamation is completed as planned. During construction, topsoil and overburden are removed and stockpiled so they can be replaced once mining is complete and the land can be replanted with appropriate vegetation. As a greater proportion of proposed projects are in situ, the impact upon the land will be far less.21 Air Quality. Operators are constantly researching new technologies and processes to reduce emissions of greenhouse (GHG). capture and sequestration (CCS) technology has been identified as an option to significantly reduce GHG emissions in the future. A key opportunity for CO2 reduction relies on the reduced heating demand that the new processes require. To ensure air quality remains high in the areas where oil sands development is taking place, the Wood Buffalo Environmental Association constantly monitors the air quality in the region. Wildlife. Operators invest substantial in monitoring and protecting wildlife. There are stringent rules about the reporting of wildlife population and Environmental Impact Assessments control and limit the effect that oil sands developments have on the . Some reclaimed land is already being used by a thriving herd of bison. Commercial Challenges Environmental awareness and high energy have encouraged operators to use more efficiently.22 Furthermore, the use of alternative including small- scale nuclear is being studied. Energy used in oil sands mining and extraction has been reduced by about 45% per barrel since 1990, and further reductions are expected.23 IN SITU OIL SANDS The in situ recovery method is so named because it uses wells that are drilled and cased in the oil formation to extract bitumen, leaving the sand in place. Production rates depend on the ability of the oil to flow through the formation and on the presence of a driver such as water or gas pressure. Processes currently in use are: Cold Flow, Cyclic Steam Stimulation (CSS), Steam Assisted Gravity Drainage (SAGD), Toe to Heel Air Injection (THAI), and VAPEX. The most commonly used are SAGD and CSS, but all are described in more detail below. Cold Flow Cold production refers to heavy oil that will flow naturally and can, therefore, be recovered using conventional pumping techniques. The oil is generally found in deeper formations and has a viscosity that allows the oil to flow at temperatures with a strong dependency on the permeability of the formation being drained. Capital investment for cold production is relatively low, as conventional surface treating facilities are used. In many cases, this type of production is associated with an active water drive, in which large volumes of water are produced along with the oil. Pumping is the main operating cost as energy is required to the emulsion to surface and to pump the back into the same formation in order to maintain reservoir pressure. All fluids go to tankage associated with the facility and regulations require that tanks have vapour recovery to control gas release and odour as part of the facility permit. If the production is from a sand type formation, an additional de-sand operation is required and this sand is taken to a licensed disposal facility. The water cut, or ratio of water compared to the total volume of produced, rises rapidly in this type of production, with wells producing 90 to 99% water. A properly designed facility can be run profitably at these levels, but is sensitive to the energy cost of the producing and disposal . This method has a recovery factor of 5 to 10% of the oil in place. CSS – Cyclic Steam Stimulation Cyclic Steam Stimulation is an early form of enhanced . Generally, injection of steam and production are done in the same well. The heat required to make the oil flow can be pumped down the well and allowed to soak into the reservoir. After a period of time, the well is opened and the emulsion flows out using injection pressure or is pumped out. As production slows, the well is shut in and the cycle is repeated.24 The facilities for CSS production are substantially the same as those for conventional production. One advantage is that typically there is little or no reservoir water with this type, so the emulsion is from the water used in the steam cycle. However, capital cost is increased due to the requirement of water treating and the boiling required to produce the steam. Alberta requires reuse of the produced water, so the dissolved minerals, salinity and hardness must be treated in a for reuse. The industry developed a simple heater consisting of a series of single path tubes to heat the water. It is known as a once-through steam generator and it is capable of handling poor quality water, hence reducing the water treating costs. The generator produces a mixed outflow of up to 80% steam and 20% water and this mixture can be piped to the wells for the heat soak cycle. An additional benefit is the ability to operate at high pressure to overcome reservoir pressure and pumping losses inherent in the distribution system. The recovery factor for CSS is in the range of 20 to 25%. Typical consumption is in the range of 7.5 gigajoules per cubic meter of air at a 3:1 steam to oil ratio (SOR). Experience does show that initial production will have quite a low SOR, starting at 0.5:1, but rising over time, to the point where economic limits are reached (4:1). SAGD - Steam Assisted Gravity Drainage SAGD is a production technique that has developed as a result of the improvements and capabilities of . Horizontal wells drilled into a formation allow a large surface of the well to be exposed to the formation. By drilling the producing well below the steam , continuous production can be achieved. Similar to cyclic production, the oil treating facilities are comparable to those for conventional production. Additional heat exchangers are required to control the temperatures of the incoming production, as well as to recover the heat as much as possible to generate new steam. Produced water must be treated and reused to generate the steam. A typical facility is licensed with a design to reuse 95% of the produced water. The design anticipates that 5% of the water used as steam will be lost to the reservoir, so, in total, up to 10% of the circulated volume is required for makeup water. Water treatment and steam production comprise a significant portion of the capital expenditure for the facility, but the high recycle volume enables the facility to be operated using deep well water and not draw from surface or fresh water supplies. The parallel well design uses steam only, which condenses in the reservoir heating the bitumen to flowing temperature. Typical emulsion temperatures are 150C to 200C at the wellhead. A major operating cost is the energy required to generate the steam. A typical facility runs on a 3:1 SOR but, unlike CSS, will not vary as much over the life of a well. Due to the large surface area expressed by the horizontal wells, individual well production can range from 500 to 1000 barrels of oil per day. Fuel consumption is similar to CCS at about 7.5 gigajoules per cubic meter of oil. The recovery factor for SAGD production is up to 60%. THAITM – Toe to Heel Air Injection Toe to Heel Air Injection (THAI™) uses horizontal production wells paired with vertical air injection wells to recover heavy oil or bitumen. Horizontal production wells are drilled to the base of the reservoir. Air injection wells are drilled vertically at the ‘toe’ of the horizontal wells. Steam is injected through the vertical and horizontal wells for two to three months to heat the reservoir near the wellbore. Once the bitumen reaches the required temperature and mobility, air is injected into the formation through the vertical air injection well. As air is injected into the formation, it starts a reaction, the vertical combustion front moves along the horizontal well (from the toe to the heel of the production well) sweeping the reservoir. The combustion front develops and the bitumen is heated to a high temperature where partial upgrading occurs. The heat causes a portion of the content of the oil to be left behind as that is the fuel for the continued combustion. The partially upgraded oil, along with vapourized water from the reservoir and combustion gases, flows into the horizontal well. Once at the surface, the oil flows through the plant facilities where it is treated. 25 Benefits of this process are being proven in the field, and include higher recovery rates than traditional in situ methods (with 60 to 80% recovery being predicted), minimal net usage of groundwater and natural gas, and the ability to produce partially upgraded oil. With relatively low capital investment and operating costs and a shorter construction time, THAI™ is a very promising developing technology.26 The challenge that arises in combustion processes is the difficulty in controlling the flame front and the production of corrosive and toxic gases. VAPEX VAPEX is a vapour extraction process that is similar to SAGD, but injects a vapourized hydrocarbon solvent rather than steam into the upper well to thin the oil. Pilot projects for VAPEX and similar processes have been producing very promising results. One of the benefits of the process is the reduction of fresh water use by more than 90% compared to SAGD, eliminating the water ponds required in other operations. It also has significantly higher extraction rates and lower operating costs and will greatly reduce emissions because it is a non-thermal process. Additionally, some partial upgrading occurs while still in the ground. A challenge faced is the high cost of the used, making solvent recovery a key step in the VAPEX process. Field testing is ongoing by a number of companies and, while the concept has proven quite successful to date, there is still much work to be done to implement full-scale production.27 The use of VAPEX is anticipated to increase for new in situ projects over the next five to ten years. Technical Challenges Bitumen production from the oil sands is still in its infancy. Most of today’s production is from the best and richest areas that are accessible. The type of production that is contemplated is not possible without improvements in drilling that allow closely spaced horizontal wells. Surface facilities have progressed by utilizing existing processes in new ways. Oil treating, water treating and clean up, and steam generation are all mature industries, but SAGD is attempting to use their capabilities in new ways. The biggest technical challenge is to deliver heat to the reservoir in a way that is both economical and sustainable. Presently, natural gas is considered to be the best and cleanest energy source. If a portion of the produced barrel could be used for energy, it would appear to be the ideal , but even this implies a cost to the producer. Environmental Challenges Unlike surface mining, in situ production has a relatively small surface impact and does not require large tailings ponds. Multiple wells are drilled from a single pad. However, the resources are in remote inaccessible areas. In many cases, permanent are required to be built to allow year round access and above ground lines are required to connect the well pads to the control facility. Air quality must be a consideration, with exhaust being released from the generating the steam. Using natural gas as the fuel and low NOx boilers to generate the steam decreases , but as production volumes grow, so will boiler exhaust increase. To mitigate these impacts, the government requires a detailed environmental impact assessment be performed prior to approving any in situ development. Commercial Challenges The bitumen produced in the oil sands sells at a discount to the prices such as West Intermediate. Production economics are sensitive not only to the of oil, but also to the cost of natural gas and , as all are in high demand. Most resources are in remote areas requiring large investments in infrastructure before even beginning to develop an area. As a result, projects can cost between $30,000 and $60,000 per barrel daily production rate to develop. PROJECT MANAGEMENT The significance of professional project management personnel and supporting systems cannot be over emphasized in its influence on the predictability of the outturn cost and schedule achievement of the project. Experience is now being drawn into the oil sands from the execution of other mega projects around the world. These projects are no longer the domain of a construction manager directing crews to work, rather the need for program management of multiple silo contracts to be managed with common resources, such as concrete plants, cranage, transport, and camps. Given the interdependency of the overall plant systems being delivered in silos, it is critical that the overall status of design delivery, cost management, planning, construction planning and handover to commissioning or operations is managed by sound principals and processes in an integrated system. Construction Work Packages Workfront planning starts at the design and procurement stage, and is followed by the execution phase for fabrication, delivery and construction.

Figure 3 – Schedule Overview The work is divided up into discrete pieces of work called Construction Work Packages (CWPs). Figure 3 illustrates the potential for time and cost savings in the field when synergies between the work packages and the different project phases are realized and Figure 4 illustrates the development process. The Construction Work Execution Plan does influence the makeup and timing of the engineering and procurement deliverables. The engineering, procurement and construction schedules are fully integrated and logic linked to the required on site (ROS) dates of the CWP scopes. Setting engineering delivery dates to the construction plan avoids delay to the start of workfronts, reduces their duration, and allows the progressive completion of systems. The project CWP definitions require interaction and acceptance by the general works construction contractors prior to the implementation phase. Figure 4 – CWP Development Process CWPs are subsequently divided further into discrete activities (known as Level 3 and Level 4 planning, or Craft Estimates), and incorporated into a fully integrated resource- loaded execution schedule. This concept is adopted in the design office to capture construction input to design at an early stage and is developed in line with engineering deliverable maturity until IFC (Issued for Construction) issue and prior to implementation. The construction/completion management team this activity with input from the applicable general contractor staff (imbedded into the design/procurement team). Site construction planning adds to existing workfront plans to develop the Level 4 to Level 5 schedule (i.e. job cards and activity sheets), and follows a look-ahead scheduling system that allows for a short look-ahead for the foremen and a three- to four-month look-ahead for the project and construction managers.

Figure 5 – CWP Acceptance Hierarchy The acceptance hierarchy for CWP contents and activities is illustrated in Figure 5. The hierarchy illustrates how the CWP scope of work moves from an individual design module or area, forming part or all of a completed system. This ensures all the necessary inspection and test plans, check-sheets and deficiency lists are completed. Well-managed, highly efficient projects require intense planning. Accurate, realistic and detailed planning results in the removal of uncertainty, smarter working and high predictability, which, in turn, results in a highly efficient, effective and successful project. Engineering Data Warehouse Over time, oil sands client programs as well as individual projects have become increasingly complex. Client standards and expectations are higher - including the requirement to execute to compressed engineering schedules. Going forward, AMEC is now required to deliver engineering on multiple, overlapping projects concurrently, including addressing re-usable component design across multiple plants and plant expansion phases. Engineering delivery on a given project is now global in scope with engineering sub-contractors and workshares located around the globe. The move to modularization, with modules produced by globally- located fabricators, also places challenges on AMEC as the supervising engineering firm. There is increasing client focus on data and document turnover, and these turnovers are required at multiple points within the detailed engineering phase. Traditional practise has applied separate tools for process, instrumentation, electrical, and 3D model designs. Each tool used a separate database and an individual major equipment item resided in multiple tools as the design progressed. Equipment attributes were then reconciled and updated for an equipment item across the various tools to create a single master source of major equipment data. This data is used for consolidated engineering registers and for loading to other systems utilized during project execution, such as Completions and maintenance systems. It is also required for loading into owner/operator Operations and Maintenance (O&M) systems. Historically, this consolidation and reconciliation effort has been a highly manual process. Re-entry and synchronization (update) of data between tools within the suite has also been a primarily manual process. To address these challenges, AMEC has implemented an Engineering Data Warehouse (EDW) automation capability, coupled with the use of centrally-hosted, intelligent engineering design tools on its large oil sands projects. The AMEC EDW supports our Engineering Data Quality Assurance initiative by providing integration within the components of the engineering design tools suite. As a result, the information related to a given piece of equipment will be consistent across all tools that carry that major equipment item. Basic workflow capabilities within the EDW assist in ensuring that the responsible engineers address these differences in a timely manner. Engineering data integration within the AMEC SmartPlant engineering suite is shown in Figure 6. Figure 6 – Engineering data integration in SmartPlant engineering suite The EDW also acts as an information repository for major tagged equipment. Information is loaded into the EDW from the AMEC-hosted major engineering design tools (P&ID, Electrical, Instrumentation, 3D) in use by AMEC, AMEC sub-contractors and major supervised contractors on the project. Once loaded, the information is validated across all tools and differences are identified for resolution. Validated tag data is retained in the EDW and provides a consolidated source of major equipment tag information – an Engineering Master Tag Register (MTR). Additionally, the EDW includes the ability to load vendor information, to perform automated basic validation checks on this information, and to summarize changes from submission to submission. This optimizes the package engineer’s time to concentrate on major equipment specifications and changes to those specifications. Vendor data can be entered to complete additional attribute information in the MTR not provided from the engineering tools. Integration with the AMEC procurement system (Convero) will allow cross-checks with the engineering technical specifications in use to procure equipment against the specifications for each major equipment item in the EDW MTR. The AMEC EDW also provides the ability to navigate the equipment information using multiple views, including displaying the selected equipment item within the engineering design tool. The AMEC data warehouse application architecture utilizes two data warehouse components. The first is the EDW discussed in this paper. The EDW is based on the engineering tool suite’s integration tool, SmartPlant Foundation, for the SmartPlant suite utilized on the oil sands projects. The balance of the architecture utilizes the Bentley LifeCycle Server application to implement the final MTR, including vendor information. The AMEC data warehouse architecture is shown in Figure 7.

Figure 7 – Data Warehouse Architecture The AMEC EDW provides multiple benefits to AMEC and to our clients. It supports a proactive engineering data quality assurance program by providing early, ongoing insight into the completeness, consistency and accuracy of engineering data throughout the engineering phases of a project. Additionally, it contributes to progress tracking of engineering delivery, and reduces manual re-entry, re-work, validation and consolidation effort and time, while meeting compressed schedules on multi-contractor, multi-location complex oil sands projects. SAFETY Safety is a core value for AMEC. The large, complex projects undertaken require careful attention to every aspect of the design, engineering and construction, from a safety perspective. Pursuit of excellence in safety begins at a personal level and relies on leadership. Behavioural Based Safety training and tracking of leading indicators support a culture within AMEC of emphasis at a personal level involving risk awareness and intervention for the benefit of all workers. Stringent health, safety, security and environmental (HSSE) systems are in place to prevent incidents from occurring and to ensure those that do occur are documented and investigated. Findings are reviewed to determine if remedial actions must be taken, or process or policy changes implemented. Industry-standard HSSE lagging indicators are tracked for every project to ensure safety targets are met or exceeded. Lost Time Injury Frequency Rate (LTIFR) and Total Recordable Incident Frequency Rate (TRIFR) are tracked as key indicators of project performance. AMEC has been present on most of the extraction and production sites north of Fort McMurray and, in January 2010, achieved 22 million jobhours without an LTI on the site. The progressive improvement in safety performance for both the industry and AMEC over the years is demonstrated below. It should be noted that data for AMEC’s industry (upstream oil sands design and construction) is not publicly consolidated, thus we looked to similar industries for comparative data sets. Data from the Canadian Association of Petroleum Producers (CAPP) includes conventional as well as oil sands figures at all stages of development (for example, construction and operation). However, operations typically experience fewer injuries due to the controlled environment and established work procedures. Figure 8 shows that, despite working in the higher-risk construction industry, AMEC’s LTIFR is an order of magnitude lower than the CAPP figures. AMEC’s LTIFR was also compared to data from the Mine Safety and Health Administration (MSHA). This data set was chosen because, although geographically separate (MSHA data is gathered from across the USA), the industry is similar to that of Alberta’s Oil Sands.

Figure 8 – Lost Time Injury Frequency Rate (LTIFR)* Comparison between AMEC Oil Sands**, CAPP***, and MSHA**** Data * Calculation based on 200,000 man-hours worked ** Includes data only where AMEC has EPCM responsibility *** CAPP data includes conventional as well as oil sands figures. AMEC solely works in the oil sands industry and engages in engineering design and construction management. **** MSHA data used reflects operator and contractor statistics as well as and mineral industries. The LTIFR cannot be calculated for 2005 as employee work hours are not available. This improvement in safety performance is due in part to AMEC’s Beyond Zero program. Beyond Zero is the vision of what is needed and where the company has to go to achieve sustainable, world-class HSSE performance throughout all our global operations. Techniques which have been deployed to protect the workforce from accidents include:  Constructability reviews during design  Workface planning and crew management  Job Safety Assessments  Tool box talks  Worker competency management  Worker inductions  Time-outs for Safety  Absolute rules for employment and a ‘just culture’  Drug and testing  Safety reward programs  Performance reporting  Behavioural Based Safety programs  Intervention training  Management prioritization of safety at all parts of the project CONCLUSION AMEC has seen many advances in production technology and project management during its long involvement as a provider of EPCM services for Alberta’s oil sands lease holders, developers and operators. The development of new mining and in situ extraction technology is only one aspect of our improved delivery mechanisms for Oil Sands projects. The pursuit of reduced energy and environmental impact are inbuilt to these developments, but the advance of integrated management and design systems, construction planning and proven safety culture improvements are also critical in supporting a step change in performance for the industry. The overall combination of these competencies within AMEC’s services will enable advances in cost, quality, schedule and safety within future Oil Sands projects. ACKNOWLEDGMENTS The authors wish to acknowledge contributions by the following people: Stuart Albion, P. Eng., AMEC BDR, subject matter expert for in situ oil sands production John Peters, Process Engineering Manager, AMEC Dan Canning, Oil Sands Construction Management, AMEC Brent Clarke, Manager Information Management, AMEC Krista Young, Marketing and Communications Coordinator, AMEC REFERENCES

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