THE FUTURE OF THE CANADIAN OIL SANDS: ENGINEERINGAND PROJECT MANAGEMENT ADVANCES

Peter B. Madden* and Jacek D. Morawski†

This paper discusses production technology and project managementdevelopments in the Canadian oil sands industry, in the context ofAMEC’s experience as a consultant and EPCM service provider to leaseholders, developers and operators. Mineable and in situ oil sandsdevelopments are described, along with methods for and challenges ofvarious production types of in situ, including Cold Flow, Cyclic SteamStimulation (CSS), Steam Assisted Gravity Drainage (SAGD), Toe toHeel Air Injection (THAI), and VAPEX. Effective project managementand supporting systems are critical to achieve cost and schedule targetson large, complex projects performed by AMEC. Workfront planning isessential to achieve optimum construction execution and a best valueproject. Construction Work Packages (CWPs) divide the work intodiscrete pieces and the Construction Work Execution Plan influencesscheduling of engineering and procurement deliverables. Integration ofthe schedules and linking to the required on site (ROS) dates of the CWPscopes minimizes workfront duration requirements, allowing progressivecompletion of systems. AMEC’s Engineering Data Warehouse (EDW)works with centrally-hosted, intelligent engineering design tools to assistin achieving tight cost and schedule targets. The EDW ensures allinformation related to a given piece of equipment is consistent across allsystems, supporting quality assurance of engineering data betweenAMEC, its sub-contractors and supervised contractors. Once verified andconsolidated, the information becomes part of a Master Tag Register(MTR), improving AMEC’s ability to meet contractual turnoverrequirements for data quality, completeness and accuracy. Health, safety,security and environmental (HSSE) systems are proactively developedand AMEC’s progressive improvement in safety performance over theyears is demonstrated. The improvement is due in part to the company’sBeyond Zero program, designed to achieve sustainable, world-classHSSE performance.

INTRODUCTIONThis paper addresses developments in the Canadian oil sands industry including

production technology and project management advances, in the context of AMEC’sexperience as a consultant and EPCM service provider to lease holders, developers and

* President Oil Sands, AMEC, 900 AMEC Place 801-6th Avenue SW, Calgary, AB, Canada, T2P 3W3.† Engineering Director, AMEC, 900 AMEC Place 801-6th Avenue SW, Calgary, AB, Canada, T2P 3W3.

AMEC Oil Sands 2010-001

operators of the oil sands. Additionally, the paper addresses the specific areas whereAMEC is working with the clients on Oil Sands mega-projects to provide solutions totechnological, environmental and commercial challenges. Enhanced project managementinitiatives and systems that support data management are also addressed. Theimplementation of these initiatives and systems is accomplished through an integratedcompletions and commissioning plan with improved accessibility for operations.

OIL SANDS BACKGROUND AND FACTSThe oil sands accounts for more than 170 billion barrels of the 175 billion barrels of

proven oil reserves in Canada that are recoverable with today’s technology. Canada issecond only to Saudi Arabia in terms of total volume.1 The reserves are contained in threemajor areas of northeastern Alberta beneath about 140,000 square kilometers. As ofMarch 2009, approximately 600 square kilometers of land were disturbed by oilsands surface mining activity.2 Approximately 80 per cent of recoverable oil sands can berecovered through in situ production, which has significantly less land disturbance, withthe 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 millioncubic meters) from the mineable area, totaling 75.9 million cubic meters (477 millionbarrels), for a total of 1.31 million barrels (207.4 thousand cubic meters) per day. Whilethe bitumen produced from mining was upgraded, bitumen crude produced from in situoperations was mainly marketed as non-upgraded crude bitumen.3

One in 13 jobs in Alberta is directly related to energy and every dollar invested in theoil sands creates about $9 worth of economic activity, with one-third of that economicvalue generated outside Alberta – in Canada, the U.S. and around the world. Oil sandsmake up about five per cent of Canada’s overall greenhouse gas emissions and less thanone-tenth of one per cent of the world’s emissions.4

The Canadian Association of Petroleum Producers (CAPP) conducted a survey of oilsands producers in early 2010 to determine their plans for production of both bitumen andupgraded crude oil from 2010-2025.5

Figure 1 – Growth Case – Western Canada Oil Sands & Conventional Production

The Growth Case illustrated in Figure 1 is based on the assumption that oil sandsprojects will be developed and brought into service gradually.6

Typically, oil sands leases are in undeveloped locations near the Athabasca Riverwhich, along with underground aquifers, provides a source of water. The remotelocations and limited labour capacity from the Fort McMurray area have necessitatedlarge camps to be built at the mine site as well as airstrips to transport labour from allover Canada without increasing local labour demand.

MINEABLE OIL SANDSThe 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 75meters for mining; beyond that depth, in situ techniques are preferred.7

Table 1 – Evolution of Oil Sands Mining Technology

Function Old Current Next

Oil Sands ExtractionCutter WheelConveyorDragline

Shovel & TrucksAt Face &Conveyor withHydrotransport

PowerGeneration Power from the Grid Cogeneration Nuclear

TailingsManagement Ponds Ponds & Thickeners

CT (composite tailings)MFT (mature fine tailings)Polymers

Prior to excavation, muskeg and overburden are removed to expose the oil sands andstockpiled for use in reclamation. The evolution of oil sands technology is listed in Table1 and, since the first oil sands plant started production in 1967, innovation has been at theforefront of the industry.8

Initially, draglines excavated the face of the formation and bucketwheels along withlong conveyor belts moved the raw bitumen to on-site processing facilities that used hotwater and tumblers to separate the oil and the sand.9

By the 1980s, trucks and power shovels began to replace the bucketwheels anddraglines 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 oilsands to crushers that break up lumps and remove rocks. In a process calledhydrotransport, the oil sand is mixed with water at either 35°C or 50°C, depending uponthe mine, and is piped to the processing plant. During hydrotransport, the bitumen beginsto separate from the sand, water and minerals. The introduction of the hydrotransportsystem greatly increased both yields and reliability.11

Separation continues at the plant where the bitumen forms a thick froth at the top ofthe 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 wateris 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 istreated to eliminate aqueous and solid contaminants to produce a clean bitumen product.The froth is first diluted with a hydrocarbon solvent to reduce the viscosity and density ofthe oil, which accelerates the settling of the impurities.13 Conventional froth treatmentuses inclined plate settlers or centrifuges to remove water and solids.14

Figure 2 – Mineable Bitumen Extraction Plant FlowchartA typical mining oil sands facility today, as illustrated in Figure 2, consists of:

Open pit mine

Shovel and truck (100 tonnes 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 diluent)

Diluted bitumen tank

The future of oil sands mining includes mobile “at face” crushing and slurification toreduce both cost and environmental impact. As the name implies, the principles of “atface” crushing involve a mobile crusher, located next to the power shovel at the mineface, so that the ore can be dumped in directly, crushed, and fed to a connected slurrypipeline. 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 emissionswould be greatly reduced.15

Technical ChallengesIn a mineable bitumen extraction facility, the froth treatment area has seen many

technological improvements. Most notable is the move away from the naphthenic processto a paraffinic process. The naphthenic process is mechanical, requiring centrifuges andinclined plate separators. The paraffinic process is chemical and utilizes gravityseparation, with the resulting product having lower levels of contaminants such as waterand mineral solids.16

Environmental ChallengesTailings Management. It requires two tonnes of oil sand to produce one barrel of

synthetic crude oil. As a by-product of the production, oil sands tailings are produced andcontained in large earthen tailings ponds. Tailings are a mixture of clay, sand, water, silt,residual bitumen and other hydrocarbons, salts and trace metals. Over time, theparticulates 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 ofwater required for process cooling

improve consolidated tailings, thus reducing tailings ponds

create dry tailings, reducing the use of water, eliminating ponds and aiding thereclamation process.18

Water Use. Many mining projects are located near the Athabasca River, which iscurrently the source of fresh water for the projects. Strict limits are placed on industrywater use through Alberta’s Water Management Framework for the Lower AthabascaRiver. This framework puts a weekly cap on how much water oil sands companies canremove, which is tied to the fluctuating flow of the river. All existing and approved oilsands projects will withdraw less than three per cent of the average annual flow of theAthabasca River. Up to 90 per cent of the water used can be recycled depending on thematurity of the facility and type of extraction.19,20 As discussed above, advancingtechnology in tailings management is reducing the volume of water required and thespeed at which it can be reused.

Land Use. Companies must remediate and reclaim Alberta’s land so it can beproductive again. Alberta Environmental legislation requires that all reclaimed land beable to support a range of activities similar to its previous use. A conservation andreclamation plan for the life of the project must be submitted prior to project approvaland 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 iscompleted as planned. During construction, topsoil and overburden are removed andstockpiled so they can be replaced once mining is complete and the land can be replantedwith appropriate vegetation. As a greater proportion of proposed projects are in situ, theimpact upon the land will be far less.21

Air Quality. Operators are constantly researching new technologies and processes toreduce emissions of greenhouse gases (GHG). Carbon capture and sequestration (CCS)technology has been identified as an option to significantly reduce GHG emissions in thefuture. A key opportunity for CO2 reduction relies on the reduced heating demand thatthe new processes require. To ensure air quality remains high in the areas where oil sandsdevelopment is taking place, the Wood Buffalo Environmental Association constantlymonitors the air quality in the region.

Wildlife. Operators invest substantial resources in monitoring and protecting wildlife.There are stringent rules about the reporting of wildlife population and EnvironmentalImpact Assessments control and limit the effect that oil sands developments have on theecosystems. Some reclaimed land is already being used by a thriving herd of bison.

Commercial ChallengesEnvironmental awareness and high energy prices have encouraged operators to use

natural gas more efficiently.22 Furthermore, the use of alternative fuels including small-scale nuclear plants is being studied. Energy used in oil sands mining and extraction hasbeen reduced by about 45% per barrel since 1990, and further reductions are expected.23

IN SITU OIL SANDSThe 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 ratesdepend on the ability of the oil to flow through the formation and on the presence of adriver such as water or gas pressure.

Processes currently in use are: Cold Flow, Cyclic Steam Stimulation (CSS), SteamAssisted Gravity Drainage (SAGD), Toe to Heel Air Injection (THAI), and VAPEX. Themost commonly used are SAGD and CSS, but all are described in more detail below.

Cold FlowCold production refers to heavy oil that will flow naturally and can, therefore, be

recovered using conventional pumping techniques. The oil is generally found in deeperformations and has a viscosity that allows the oil to flow at reservoir temperatures with astrong dependency on the permeability of the formation being drained.

Capital investment for cold production is relatively low, as conventional surfacetreating facilities are used. In many cases, this type of production is associated with anactive 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 pump the emulsion to surfaceand to pump the produced water back into the same formation in order to maintainreservoir pressure. All fluids go to tankage associated with the facility and regulationsrequire that tanks have vapour recovery to control gas release and odour as part of thefacility permit.

If the production is from a sand type formation, an additional de-sand operation isrequired and this sand is taken to a licensed disposal facility.

The water cut, or ratio of water compared to the total volume of liquid produced, risesrapidly in this type of production, with wells producing 90 to 99% water. A properlydesigned facility can be run profitably at these levels, but is sensitive to the energy cost of

the producing and disposal pumps. This method has a recovery factor of 5 to 10% of theoil in place.

CSS – Cyclic Steam StimulationCyclic Steam Stimulation is an early form of enhanced heavy oil production.

Generally, injection of steam and production are done in the same well. The heat requiredto 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 injectionpressure or is pumped out. As production slows, the well is shut in and the cycle isrepeated.24

The facilities for CSS production are substantially the same as those for conventionalproduction. One advantage is that typically there is little or no reservoir water with thistype, so the emulsion is from the water used in the steam cycle. However, capital cost isincreased due to the requirement of water treating and the boiling required to produce thesteam. Alberta requires reuse of the produced water, so the dissolved minerals, salinityand hardness must be treated in a boiler for reuse. The industry developed a simple heaterconsisting of a series of single path tubes to heat the water. It is known as a once-throughsteam generator and it is capable of handling poor quality water, hence reducing thewater treating costs. The generator produces a mixed outflow of up to 80% steam and20% water and this mixture can be piped to the wells for the heat soak cycle. Anadditional benefit is the ability to operate at high pressure to overcome reservoir pressureand pumping losses inherent in the distribution system. The recovery factor for CSS is inthe range of 20 to 25%.

Typical fuel consumption is in the range of 7.5 gigajoules per cubic meter of air at a3:1 steam to oil ratio (SOR). Experience does show that initial production will have quitea low SOR, starting at 0.5:1, but rising over time, to the point where economic limits arereached (4:1).

SAGD - Steam Assisted Gravity DrainageSAGD is a production technique that has developed as a result of the improvements

and capabilities of directional drilling. Horizontal wells drilled into a formation allow alarge surface of the well to be exposed to the formation. By drilling the producing wellbelow the steam injection well, continuous production can be achieved.

Similar to cyclic production, the oil treating facilities are comparable to those forconventional production. Additional heat exchangers are required to control thetemperatures of the incoming production, as well as to recover the heat as much aspossible to generate new steam.

Produced water must be treated and reused to generate the steam. A typical facility islicensed with a design to reuse 95% of the produced water. The design anticipates that5% of the water used as steam will be lost to the reservoir, so, in total, up to 10% of thecirculated volume is required for makeup water. Water treatment and steam productioncomprise a significant portion of the capital expenditure for the facility, but the highrecycle volume enables the facility to be operated using deep well water and not drawfrom surface or fresh water supplies.

The parallel well design uses steam only, which condenses in the reservoir heating thebitumen to flowing temperature. Typical emulsion temperatures are 150C to 200C atthe wellhead.

A major operating cost is the energy required to generate the steam. A typical facilityruns on a 3:1 SOR but, unlike CSS, will not vary as much over the life of a well. Due tothe large surface area expressed by the horizontal wells, individual well production canrange from 500 to 1000 barrels of oil per day. Fuel consumption is similar to CCS atabout 7.5 gigajoules per cubic meter of oil.

The recovery factor for SAGD production is up to 60%.

THAITM – Toe to Heel Air InjectionToe to Heel Air Injection (THAI™) uses horizontal production wells paired with

vertical air injection wells to recover heavy oil or bitumen. Horizontal production wellsare 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 fortwo to three months to heat the reservoir near the wellbore. Once the bitumen reaches therequired temperature and mobility, air is injected into the formation through the verticalair injection well. As air is injected into the formation, it starts a combustion reaction, thevertical combustion front moves along the horizontal well (from the toe to the heel of theproduction well) sweeping the reservoir. The combustion front develops and the bitumenis heated to a high temperature where partial upgrading occurs. The heat causes a portionof the asphaltene content of the oil to be left behind as coke that is the fuel for thecontinued combustion. The partially upgraded oil, along with vapourized water from thereservoir and combustion gases, flows into the horizontal well. Once at the surface, theoil flows through the plant facilities where it is treated. 25

Benefits of this process are being proven in the field, and include higher recoveryrates than traditional in situ methods (with 60 to 80% recovery being predicted), minimalnet usage of groundwater and natural gas, and the ability to produce partially upgradedoil. With relatively low capital investment and operating costs and a shorter constructiontime, THAI™ is a very promising developing technology.26 The challenge that arises incombustion processes is the difficulty in controlling the flame front and the production ofcorrosive and toxic gases.

VAPEXVAPEX 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. Pilotprojects 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 than90% compared to SAGD, eliminating the water ponds required in other operations. It alsohas significantly higher extraction rates and lower operating costs and will greatly reducegreenhouse gas emissions because it is a non-thermal process. Additionally, some partialupgrading occurs while still in the ground. A challenge faced is the high cost of thesolvents used, making solvent recovery a key step in the VAPEX process. Field testing isongoing by a number of companies and, while the concept has proven quite successful todate, 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 nextfive to ten years.

Technical ChallengesBitumen 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 productionthat is contemplated is not possible without improvements in drilling that allow closelyspaced horizontal wells. Surface facilities have progressed by utilizing existing processesin new ways. Oil treating, water treating and clean up, and steam generation are allmature 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 botheconomical and sustainable. Presently, natural gas is considered to be the best andcleanest energy source. If a portion of the produced barrel could be used for energy, itwould appear to be the ideal solution, but even this implies a cost to the producer.

Environmental ChallengesUnlike 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 roadsare required to be built to allow year round access and above ground lines are required toconnect the well pads to the control facility.

Air quality must be a consideration, with exhaust being released from the boilersgenerating the steam. Using natural gas as the fuel and low NOx boilers to generate thesteam decreases pollutants, but as production volumes grow, so will boiler exhaustincrease.

To mitigate these impacts, the government requires a detailed environmental impactassessment be performed prior to approving any in situ development.

Commercial ChallengesThe bitumen produced in the oil sands sells at a discount to the benchmark prices

such as West Texas Intermediate. Production economics are sensitive not only to theprice of oil, but also to the cost of natural gas and electricity, as all are in high demand.

Most resources are in remote areas requiring large investments in infrastructurebefore even beginning to develop an area. As a result, projects can cost between $30,000and $60,000 per barrel daily production rate to develop.

PROJECT MANAGEMENTThe significance of professional project management personnel and supporting

systems cannot be over emphasized in its influence on the predictability of the outturncost and schedule achievement of the project. Experience is now being drawn into the oilsands from the execution of other mega projects around the world. These projects are nolonger the domain of a construction manager directing crews to work, rather the need forprogram 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 iscritical that the overall status of design delivery, cost management, resource planning,construction planning and handover to commissioning or operations is managed by soundprincipals and processes in an integrated system.

Construction Work PackagesWorkfront planning starts at the design and procurement stage, and is followed by the

execution phase for fabrication, delivery and construction.

Figure 3 – Schedule OverviewThe 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 fieldwhen synergies between the work packages and the different project phases are realizedand Figure 4 illustrates the development process.

The Construction Work Execution Plan does influence the makeup and timing of theengineering and procurement deliverables. The engineering, procurement andconstruction 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 planavoids delay to the start of workfronts, reduces their duration, and allows the progressivecompletion of systems. The project CWP definitions require interaction and acceptanceby the general works construction contractors prior to the implementation phase.

Figure 4 – CWP Development ProcessCWPs 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 captureconstruction input to design at an early stage and is developed in line with engineeringdeliverable maturity until IFC (Issued for Construction) issue and prior toimplementation. The construction/completion management team leads this activity withinput from the applicable general contractor staff (imbedded into the design/procurementteam).

Site construction planning adds to existing workfront plans to develop the Level 4 toLevel 5 schedule (i.e. job cards and activity sheets), and follows a look-ahead schedulingsystem that allows for a short look-ahead for the foremen and a three- to four-monthlook-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 designmodule or area, forming part or all of a completed system. This ensures all the necessaryinspection and test plans, check-sheets and deficiency lists are completed.

Well-managed, highly efficient projects require intense planning. Accurate, realisticand detailed planning results in the removal of uncertainty, smarter working and highpredictability, which, in turn, results in a highly efficient, effective and successful project.

Engineering Data WarehouseOver time, oil sands client programs as well as individual projects have become

increasingly complex. Client standards and expectations are higher - including therequirement 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 designacross multiple plants and plant expansion phases. Engineering delivery on a givenproject is now global in scope with engineering sub-contractors and workshares locatedaround 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 turnoversare 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 majorequipment item resided in multiple tools as the design progressed. Equipment attributeswere then reconciled and updated for an equipment item across the various tools to createa single master source of major equipment data. This data is used for consolidatedengineering registers and for loading to other systems utilized during project execution,such as Completions and maintenance systems. It is also required for loading intoowner/operator Operations and Maintenance (O&M) systems.

Historically, this consolidation and reconciliation effort has been a highly manualprocess. Re-entry and synchronization (update) of data between tools within the suite hasalso been a primarily manual process.

To address these challenges, AMEC has implemented an Engineering DataWarehouse (EDW) automation capability, coupled with the use of centrally-hosted,intelligent engineering design tools on its large oil sands projects. The AMEC EDWsupports our Engineering Data Quality Assurance initiative by providing integrationwithin the components of the engineering design tools suite. As a result, the informationrelated to a given piece of equipment will be consistent across all tools that carry thatmajor equipment item. Basic workflow capabilities within the EDW assist in ensuringthat the responsible engineers address these differences in a timely manner.

Engineering data integration within the AMEC SmartPlant engineering suite is shownin Figure 6.

Figure 6 – Engineering data integration in SmartPlant engineering suiteThe EDW also acts as an information repository for major tagged equipment.

Information is loaded into the EDW from the AMEC-hosted major engineering designtools (P&ID, Electrical, Instrumentation, 3D) in use by AMEC, AMEC sub-contractorsand major supervised contractors on the project. Once loaded, the information isvalidated across all tools and differences are identified for resolution. Validated tag datais retained in the EDW and provides a consolidated source of major equipment taginformation – an Engineering Master Tag Register (MTR).

Additionally, the EDW includes the ability to load vendor information, to performautomated basic validation checks on this information, and to summarize changes fromsubmission to submission. This optimizes the package engineer’s time to concentrate onmajor equipment specifications and changes to those specifications. Vendor data can beentered to complete additional attribute information in the MTR not provided from theengineering tools.

Integration with the AMEC procurement system (Convero) will allow cross-checkswith the engineering technical specifications in use to procure equipment against thespecifications for each major equipment item in the EDW MTR.

The AMEC EDW also provides the ability to navigate the equipment informationusing multiple views, including displaying the selected equipment item within theengineering design tool.

The AMEC data warehouse application architecture utilizes two data warehousecomponents. The first is the EDW discussed in this paper. The EDW is based on theengineering tool suite’s integration tool, SmartPlant Foundation, for the SmartPlant suiteutilized on the oil sands projects. The balance of the architecture utilizes the BentleyLifeCycle Server application to implement the final MTR, including vendor information.The AMEC data warehouse architecture is shown in Figure 7.

Figure 7 – Data Warehouse ArchitectureThe AMEC EDW provides multiple benefits to AMEC and to our clients. It supports

a proactive engineering data quality assurance program by providing early, ongoinginsight into the completeness, consistency and accuracy of engineering data throughoutthe engineering phases of a project. Additionally, it contributes to progress tracking ofengineering delivery, and reduces manual re-entry, re-work, validation and consolidationeffort and time, while meeting compressed schedules on multi-contractor, multi-locationcomplex oil sands projects.

SAFETYSafety is a core value for AMEC. The large, complex projects undertaken require

careful attention to every aspect of the design, engineering and construction, from asafety 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 aculture within AMEC of emphasis at a personal level involving risk awareness andintervention for the benefit of all workers. Stringent health, safety, security andenvironmental (HSSE) systems are in place to prevent incidents from occurring and toensure those that do occur are documented and investigated. Findings are reviewed todetermine if remedial actions must be taken, or process or policy changes implemented.Industry-standard HSSE lagging indicators are tracked for every project to ensure safetytargets are met or exceeded. Lost Time Injury Frequency Rate (LTIFR) and TotalRecordable Incident Frequency Rate (TRIFR) are tracked as key indicators of projectperformance.

AMEC has been present on most of the extraction and production sites north of FortMcMurray and, in January 2010, achieved 22 million jobhours without an LTI on theAlbian Sands site. The progressive improvement in safety performance for both theindustry and AMEC over the years is demonstrated below. It should be noted that data forAMEC’s industry (upstream oil sands design and construction) is not publiclyconsolidated, thus we looked to similar industries for comparative data sets.

Data from the Canadian Association of Petroleum Producers (CAPP) includesconventional as well as oil sands figures at all stages of development (for example,construction and operation). However, operations typically experience fewer injuries dueto 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 ofmagnitude lower than the CAPP figures.

AMEC’s LTIFR was also compared to data from the Mine Safety and HealthAdministration (MSHA). This data set was chosen because, although geographicallyseparate (MSHA data is gathered from across the USA), the industry is similar to that ofAlberta’s Oil Sands.

Figure 8 – Lost Time Injury Frequency Rate (LTIFR)* Comparison betweenAMEC 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 coal 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 Zeroprogram. Beyond Zero is the vision of what is needed and where the company has to goto achieve sustainable, world-class HSSE performance throughout all our globaloperations.

Techniques which have been deployed to protect the workforce from accidentsinclude:

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 Alcohol testing

Safety reward programs

Performance reporting

Behavioural Based Safety programs

Intervention training

Management prioritization of safety at all parts of the project

CONCLUSIONAMEC 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 leaseholders, developers and operators.

The development of new mining and in situ extraction technology is only one aspectof our improved delivery mechanisms for Oil Sands projects. The pursuit of reducedenergy and environmental impact are inbuilt to these developments, but the advance ofintegrated management and design systems, construction planning and proven safetyculture improvements are also critical in supporting a step change in performance for theindustry. The overall combination of these competencies within AMEC’s services willenable advances in cost, quality, schedule and safety within future Oil Sands projects.

ACKNOWLEDGMENTSThe 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

1 Radler, Marilyn. "Special Report: Oil, gas reserves rise as oil output declines." Oil & Gas Journal, vol. 107, issue 47,2009. [Online]. Available: http://www.ogj.com/index/current-issue/oil-gas-journal/volume-107/issue-47.html.[Accessed: Jan. 11, 2010].2 Government of Alberta, "Facts and Statistics." Alberta Energy, n.d. Available:http://www.energy.alberta.ca/OilSands/791.asp. [Accessed: Jan. 11, 2010].3 Energy Resources Conservation Board, “ST98-2009:Alberta’s Energy Reserves 2008 and Supply/Demand Outlook2009-2018,” Energy Resources Conservation Board, 2009. [Online]. Available:http://www.ercb.ca/docs/products/STs/st98_current.pdf. [Accessed: Jan. 14, 2010].4 "Alberta’s Oil Sands: Facts and Stats." Alberta’s Oil Sands. Government of Alberta, n.d. Web. 11 Jan. 2010.Retrieved from http://www.oilsands.alberta.ca/519.cfm.5 Canadian Association of Petroleum Producers, “2010 Crude Oil Forecast, Markets & Pipeline Expansions.” CanadianAssociation of Petroleum Producers, June 2010. [Online]. Available:http://www.capp.ca/aboutUs/mediaCentre/NewsReleases/Pages/2010-Oil-Forecast.aspx#IIL6P31WZ607 [Accessed:Jun. 28, 2010]6 ibid.7 Government of Alberta, "Facts and Statistics." Alberta Energy. Government of Alberta, n.d. Available:http://www.energy.alberta.ca/OilSands/791.asp. [Accessed: Jan. 11, 2010].8 Canadian Centre for Energy Information, "Oil Sands and Heavy Oil Overview." Oil and Natural Gas, n.d. [Online].Available: http://www.centreforenergy.com/AboutEnergy/ONG/OilsandsHeavyOil/Overview.asp?page=1. [Accessed:Jan. 11, 2010].9 ibid.10 ibid.11 ibid.12 ibid.13 Natural Resources Canada, "Froth Treatment." CanMetENERGY, Mar. 2, 2009. [Online]. Available:http://canmetenergy-canmetenergie.nrcan-rncan.gc.ca/eng/oil_sands/multiphase_systems/froth_treatment.html.[Accessed: Jan. 11, 2010].14 Canadian Centre for Energy Information, "Oil Sands and Heavy Oil Overview." Oil and Natural Gas, n.d. [Online].Available: http://www.centreforenergy.com/AboutEnergy/ONG/OilsandsHeavyOil/Overview.asp?page=1. [Accessed:Jan. 11, 2010].15 ibid.16 Natural Resources Canada, "Froth Treatment." CanMetENERGY, Mar. 2, 2009. [Online]. Available:http://canmetenergy-canmetenergie.nrcan-rncan.gc.ca/eng/oil_sands/multiphase_systems/froth_treatment.html.[Accessed: Jan. 11, 2010].17 Government of Alberta, “Facts about Tailings Management.” Alberta’s Oil Sands. [Online] Available:http://www.oilsands.alberta.ca/documents/Tailings_management.pdf . [Accessed: Jan. 12, 2010].18 Griffiths, M., Taylor, A., & Woynillowicz, D., “Troubled Waters, Troubling Trends – Technology and PolicyOptions to Reduce Water Use in Oil and Oil Sands Development in Alberta.” The Pembina Institute, May 2006.Available: http://www.oilsandswatch.org/pub/612. [Accessed: Jan. 12, 2010]19 Government of Alberta, “Facts about Alberta’s Oil Sands – An Overview” Alberta’s Oil Sands. [Online]. Available:http://www.oilsands.alberta.ca/documents/Overview.pdf. [Accessed: Jan. 11, 2010]20 Canadian Association of Petroleum Producers, “Environmental Aspects of Oil Sands Development.” CanadianAssociation of Petroleum Producers, n.d. [Online]. Available:http://membernet.capp.ca/raw.asp?x=1&dt=PDF&dn=105401. [Accessed: Jan. 12, 2010].21 Canadian Association of Petroleum Producers, “Land Use in Canada’s Oil Sands.” Canadian Association ofPetroleum Producers, Sept. 2009. [Online]. Available:

http://www.capp.ca/library/publications/crudeOilAndOilSands/pages/pubInfo.aspx?DocId=154988#RRM8Qw0eEICo[Accessed: Jan. 11, 2010].22 The Oil Sands Developers Group, “Extracting Oil Sands – In-situ and Mining Methods Fact Sheet,” The Oil SandsDevelopers Group. Oct. 2009. [Online]. Available: http://www.oilsandsdevelopers.ca/wp-content/uploads/2009/10/Extracting-Oil-Sands-In-situ-and-Mining-Fact-Sheet-October-2009.pdf. [Accessed: Feb. 2,2010].23 ibid.24 Speight, James G. “Recovery of Heavy Oil and Tar Sand Bitumen,” in The Chemistry and Technology of Petroleum.CRC Press. pp. 165–167.25 Petrobank Energy, “The THAI™ Process,” Petrobank Energy, Nov. 2009. [Online]. Available:http://www.petrobank.com/wp-content/uploads/2009/06/THAI-sheet-Nov-20091.pdf. [Accessed: Jan. 13, 2010].26 ibid.27 Collison, Melanie, “Solvents on track,” Oil Sands Review, pp 42-43, Jan. 2008.