C-FER. Technologies. Advancing Engineering Frontiers. Production Operations

Transcription

1 C-FER Advancing Engineering Frontiers Production Operations

2 C-FER Printed September 2015

3 Corporate Profile For over 30 years, C-FER has created innovative technologies and developed new solutions for oil and gas, pipeline and other industries that have reduced costs, increased revenues, extended the life of systems and ensured regulatory compliance. C-FER offers state-of-the-art expertise in the following areas: Project Management Experimental Design Investigative Engineering Computer Modeling Prototype Design and Manufacture Full-Scale/Structural Testing Production Engineering Limit States Design Software Development Solid Mechanics Field Services Risk and Reliability Engineering C-FER holds patents and intellectual property rights to numerous energy industry products and processes including revolutionary Downhole Oil/ Water Separation technology, PC-PUMP software, CalTranTM software, PIRAMID software and more. The C-FER Advantage When there is a lot at risk, operators and suppliers alike rely on C-FER s third party, independent verification methodology. Whether you are pushing the boundaries of technology, optimizing design, or quantifying reliability, C-FER s expertise and one-of-a-kind facility can meet your performance qualification requirements. For energy producers who use technology for strategic advantage, C-FER s innovation expertise is a powerful resource for improving profitability and safety. Our know-how extends beyond applied research to include collaboration with manufacturers and service companies to ensure the viable commercialization of new energy industry products and services. C-FER Real World Solutions One of the keys to successfully bringing new technologies to market lies in the ability to perform tests at full scale, simulated within a controlled environment. C-FER s world class laboratory services offer a powerful combination of testing and analysis tools designed to accommodate a vast range of applied research to meet energy industry requirements. C-FER has the know-how to make solutions work in the real world. For more information on our products and services visit

4 y = x R 2 = Ambient Temperature ( o C) f(t) M ode 9.4 M edian 11.7 Mean Temperature Rise, t (degc) f(t) data Weibull Distribution Production Operations...finding innovative solutions to production engineering problems. Artificial Lift Assessment & Testing Progressing Cavity Pumps Electric Submersible Pumps Hydraulic Jet Pumps Gas Lifts Gear Pumps Dewatering Systems T em p eratu r e Rise ( o C) Downhole Processing Technology Oil/Water Separation (DHOWS) Gas/Liquid Separation Production Operations Analysis Thermal Enhanced Oil Recovery (CSS & SAGD) Cold Heavy Oil Production (CHOPS) Offshore and Subsea Mature Fields C-FER

5 Production Operations Engineering Consulting Production Enhancement Studies Analysis of Field Data Technical and Economic Assessment of Novel and Alternative Practices Analysis of Thermal Recovery Alternatives Risk & Reliability Assessments Quantitative Risk Analysis (QRA) related to Production Operations, Completions and Workovers Technical Training Gas Well Deliquification Options Downhole Oil/Water Separation Cold Heavy Oil Production Operations Applied Research & Development Surface & Downhole Tool Development Concept Development Prototype Design Performance Verification Full Scale Testing Artificial Lift System Performance High/Low Temperature Multiphase Heavy Oil Deliquification System Performance Novel Systems Controlled Gas Liquid Ratios (GLR), Pressures Production Equipment Tubing Wear/Coatings Sucker Rod Performance CT Testing Hostile Environments Sour/Explosive Gases High/Low Temperature C-FER

6 Cyclic Steam Well Pad Flow Assurance Heavy Oil The future of oil production is heavy. The World s heavy oil resources are unparalleled in magnitude but they present unique challenges to ensure recovery is done in an environmentally and economically efficient manner. C-FER is ideally positioned and experienced in the following recovery methods to assist operators and equipment manufacturers in tackling these challenges: Thermal Recovery Thermal extraction of heavy oil, using techniques such as cyclic steam, SAGD and air injection require special approaches for the well casing and artificial lift systems. Issues that have been investigated by C-FER include: Low intake-pressure pumping in SAGD wells Technical and life-cycle economic assessment of normal wellbore and completion concepts Casing connection evaluation and qualification for thermal wells Design and structural modeling of casing, slotted liners and various forms of sand screens Beam pump optimization in horizontal wells Steam injection and production inflow control in SAGD wells Drilling and completion best practices Managing Produced Sand Managing Produced Sand Cold Production Cold Heavy Oil Production with Sand (CHOPS) is a process developed in Canada where sand production is encouraged to increase inflow in nonthermal heavy oil operations. Issues that have been investigated by SAGD Pump Testing System C-FER include: Technical and economic feasibility of CHOPS in other areas around the world SAGD Pump Testing System Progressing cavity pumping system selection, optimization and run-life tracking Elastomer compatibility testing Gathering line operation with complex water-assisted flow regimes Handling and disposal of sand

7 (P H,T H ) Heat Transfer (P T,T T ) SAGD Dual-String Injection Well (P H,T H ) Heat Transfer (P T,T T ) SAGD Dual-String Production Well Thermal Well Design Bitumen recovery operations using thermal methods such as SAGD, CSS or steam drive often require complex well designs that must resist extreme loading conditions on the well casing and liners yet provide efficient means to inject and distribute steam through long horizontal sections. C-FER has developed an advanced thermal well design approach that addresses all of these structural and thermo-hydraulic issues. Structural Design Considerations Since the casing and liner loads in a thermal well may exceed the yield strength of the pipe material, conventional tubular design approaches are inadequate. Consequently, a strain-based design approach has been developed which considers the following factors: Loads in excess of yield strength Cyclic loading due to rotating pipe during installation in deviated wells Cyclic loading due to thermal cycles 5600 Strain localization due to complex liner and Short String (ST) Long String (LT) connection geometries 5400 Pressure and structural integrity of connections 35% flow down LT Material degradation due to stress-corrosion synergies 5200 Thermo Hydraulic Design Considerations The design process for selecting appropriate injection and production string sizes and configurations (i.e., parallel vs concentric strings) must consider how these choices affect the following for both the circulation and production phases of the wells: Steam quality reaching the sand face Steam injection distribution along the horizontal section Inflow distribution and flow induced pressure losses in the wellbore and tubulars Pressure (kpa,abs) Heat transfer from inner LT to outer ST 65% flow down ST Measured Depth (mkb)

8 LP SAGD: Lab Testing of Artificial Lift Systems JIP In large regions of the Athabasca oil sands, where SAGD recovery techniques are currently being used or considered, the presence of a depleted or naturally low pressured formation directly above the reservoir makes it necessary to operate the producing wells at relatively low pressures. It is still uncertain if current artificial lift systems can operate efficiently and reliably at these low pressures, especially at low degrees of sub-cooling (i.e. close to steam saturation conditions). It is the objective of this JIP to test a number of downhole and surface driven pumping systems at low intake pressures and low degrees of sub cooling in a laboratory environment to prioritize and select candidates for further field trials. Anticipated downhole operating conditions will be replicated to the extent possible by installing the pumping systems in a section of mm (9 5/8 ) casing at approximately 87 inclination (close to horizontal). For each pumping system, a baseline performance curve will be established, and then additional performance curves will be determined for different temperatures and degrees of sub-cooling. The main goal of this study is to determine the minimum intake pressure (or degree of sub-cooling) at which each downhole or surface driven pumping system can operate without suffering significant deterioration in performance, over a range of operating temperatures. The experimental flow loop consists of a mm, 60 kg/m (9 5/8, 40 lb/ft) casing with 88.9 mm (3.5 ) tubing that has the following capabilities: Physical Setup Accommodates downhole and surface driven pump systems up to 24.4 m (80 ft) in length, up to 12 m (40 ft) per section; Allows for downhole gas (steam and air) separation at the pump intake with a simulated submergence of approximately 2 m (6.6 ft); Fully instrumented to allow real time pressure, temperature, flow measurements and pump torque and speed. Fully automated to allow for continuous 24 hour long term reliability testing The flow loop can be operated as either an open loop or a modified closed loop (i.e. inert atmosphere) system, meaning that a large range of field representative test fluids can be tested. Pressure and Temperature Limits Pump intake pressure from 0.1 MPag to MPag ( psig); Pump discharge pressure to MPag (1800 psig); Pump intake temperature from 60 C to 260 C ( F). Volumetric Capability Liquid flow rate up to 1500 m3/d (9400 bpd) Water, oil or oil/water mixture Air injection up to 120 std-m3/h (70 scfm) at MPag (600 psig) at the downhole pump intake.. Project Status Pump testing for the JIP began in June Five systems have been tested to date. The flow loop is now available for other pump or downhole equipment tests. Participants ChevronTexaco ConocoPhillips Devon Canada EnCana Oil and Gas Esso-Imperial Oil Husky Energy Innovation & Science (AERI) Nexen NAOSC (Statoil) Paramount Resources Petro-Canada Suncor Energy Total E&P Canada Petrobras

9 SAGD Downhole Flow Control JIP (SAGD Steam Injection Control JIP) Operational experience in vertical and deviated thermal wellbores has shown that proper control of steam injection and production inflow can have a significant impact on the steam-oil ratio (SOR), oil recovery, the rate of recovery and overall economics of a thermal recovery project. Field evidence suggests that better downhole flow control methods are called for in order to improve steam injection and production conformance, and to improve the uniformity of the steam chamber in order to increase the oil rates, thermal efficiency and recovery in a number of SAGD projects currently in operation. However, SAGD operators recognized that the industry must first address a number of technical and economic questions and challenges in order to advance alternative steam injection and production inflow control methods to the point where it may be considered a viable alternative. The common need to address these uncertainties became the motivation for the industry and C-FER to initiate the SAGD Downhole Flow Control JIP, which for Phase I was named the SAGD Steam Injection Control JIP. Phase I: Steam Injection control The first phase of the JIP was completed in 2012 and was focused on: Examples: Defining the state-of-the art of SAGD steam injection control methods and in-well and reservoir monitoring technologies Reviewing the fundamental basis, status and field experience of the various devices and technologies that may be used for controlling steam injection in SAGD horizontal wells Completing model developments and analyses to gain a better understanding of the key factors which may affect the design and performance of these various devices in a range of SAGD applications (e.g. such as variations in well depth and horizontal length, device type and placement, injection rate and pressure. At the end of the phase, there were fourteen SAGD operating companies participating in the JIP. The JIP is still open to new participants. Phase II: While Phase I of the JIP focused on steam injection control, Phase II will include both steam injection and production inflow control. C-FER and the Phase I participants are looking to launch Phase II phase of this project in mid The areas of focus for the second phase include: Examining the potential to develop improved SAGD-specific inflow control devices (ICDs) for SAGD applications Developing software tools to assist operators in assessing the design and performance of selected steam injection control technologies Updating the state-of-the-art review of steam injection and production inflow control methods Holding interactive workshops to provide participants with the opportunity to share field experience related to downhole steam injection and production flow control in their SAGD applications. Tubing Deployed Steam Injection Control Device Liner-Deployed Production Inflow Control Device Slotted Liner Tubing Deployed Steam Injection Devices & Methods Non-perforated Liner Pipe Liner Deployed Production Inflow Control Devices & Methods

10 Risk Analysis of Thermal Operations Oil production using thermal stimulation, such as in SAGD, is becoming more prevalent. To aid in the identification and quantification of the risks associated with the operation of a thermally-stimulated well, C-FER offers a quantified risk assessment. In a Quantified Risk Assessment, the root causes of undesired events are identified, and the relative importance of such events are determined. The risk associated with any design scenario is quantified with: Risk = Probability x Consequence The risk can then be readily compared for the various scenarios, and key areas of concern can be highlighted. Risk Scenario Comparisons: Various scenarios are studied and compared according to the details of a specific project. In a typical analysis, these could include: events that occur during workovers or normal operations, events that occur at different times in a well s production life, leaks or blowouts through the injector or the producer, leaks or blowouts through the tubing, annulus, both, or outside the casing, failures of components of different completions (different wellheads, with and without a DHSV, packer, etc ). Such a comparison provides a foundation for the development of a project, including a preferred completion, operational practice, and safety response plan. It can also highlight areas of concern that may require special attention. Our studies are customised and flexible, with a focus that is directed according to the customer s needs. Determining Failure Probabilities The probability of a failure is generally estimated through the use of a fault tree analysis. The probability of a top event, such as a release at surface, can be assessed by considering the combined probability of failure of individual components that would allow a flow path to the surface. An example of a fault tree is provided. Base events combine to give the probability of the event at the top of the tree. Historical data is used where possible to define base event probabilities, and also to help fine-tune the fault tree so that higherlevel probabilities accurately reflect field knowledge. Testing and experimentation can also be used to determine the probabilities used in the analysis. Example of a fault tree Flow tee normal failure B20 Flow tee failure E27 Release through tubing only B51 E7 External event causes flow tee failure Fluid to flow tee E2 base event top of another tree OR gate AND gate

11 Risk Analysis of Thermal Operations Example of STARS output temperature contours in a SAGD reservoir (symmetric) Reservoir Release Modeling Fluid flow rates during a leak or blowout will vary for different reservoirs and release scenarios, affecting the severity of the consequences. To quantify these release rates, C-FER has made special use of the STARS reservoir simulator, combined with a wellbore simulator. This has allowed for an estimate of release rates for conditions where wellhead pressures are at, or near, atmospheric conditions. Independent critical flow checks are also completed. By modeling the flow through the wellbore in concert with the reservoir response during a release, the rates and composition of the fluids can be determined for each scenario. This information can then be used in the consequence models to determine the severity of various hazards. Consequence Modeling: Several possible consequences are generally associated with an undesired event during thermal production Schematic diagram of fire plume resulting operations. In a typical study, from a vertical jet of natural gas models of consequences may include: Thermal Radiation a gas jet or oil pool fire oil spills a release of hazardous gas a steam jet lost production Fire Plume Damage Receptor Radius of hazard area, vertical jet Each relevant consequence is modeled to assess the impact on life safety, environmental damage, and project economics. Contour plot of critical H2S concentrations along the ground near a release Consequences will differ Critical Threshold H2S Concentration depending on the scenario. 10 ppm 50 ppm For example, a fire that occurs 100 ppm 300 ppm during a workover will likely pose a much greater hazard than if it occurred during normal operations, because of the larger number of people located near to the hazard. The consequence models are therefore customised for each scenario considered. Downward Distance (m) 30 Bounds of Hazard Area (m) Study Benefits: A Quantified Risk Assessment offers strong value by collecting often looselydefined hazards and risks, and setting them in the context of a logical framework. Customers have noted that the assessment provides boundaries in the design of major projects by identifying areas of concern and confirming when issues have been adequately resolved. The study can provide a higher level of certainty when proceeding into new, uncertain territory. 1000

12 DHOWS Downhole Oil/Water Separation System Course Course Description C-FER has spearheaded downhole oil/water separation system (DHOWS) technology through its Joint Industry Project (JIP) since The knowledge gained in the JIP has been compiled into a comprehensive course on the implementation of hydrocyclone separator-based DHOWS systems. The course provides a complete overview of the technology, from field and candidate well screening based on economic and technical criteria to basic design and operation of the systems. In addition to the systems based on hydrocyclone separators, systems based on gravity separation and reverse coning applications are also discussed in the course. Who should Attend? The course has been developed for personnel who deal with the design, implementation and operation of DHOWS systems. This includes field operators, completion and production technologists and engineers, and the staff of equipment manufacturers and vendors. Introductory material is included to accommodate participants with a limited knowledge of various pumping systems. Topics Evaluating economics of DHOWS systems Guidelines for pool and well screening System design and implementation Review of the field experience from the initial prototypes and onwards Advanced topics such as Offshore Implementations, Dual Stage Separation and Desanding Systems Registration The course is open to all industry operators. Participants inc-fer s Downhole Oil/Water Separation (DHOWS) Joint Industry Project included... Alberta Department of Energy Amoco Exploration & Production Technology Group Anderson Exploration Ltd. Aramco Services Company ARCO Exploration and Production Technology BP Exploration Operating Company Limited Baker Hughes Inc. Canadian Natural Resources Canadian Petroleum International Resources Ltd. Chauvco Resources Ltd. Chevron Petroleum Technology Company Conoco Inc. CS Resources Ltd. Den norske stats oljeselskap a.s. ELAN Energy Inc. Gulf Canada Resources Ltd. Imperial Oil Resources Instituto Mexicano Del Petroleo Marathon Oil Company Maxus International Energy Company Morrison Petroleums Limited Norcen Energy Resources Limited Norsk Hydro a.s PanCanadian Petroleum Limited Penn West Petroleum Limited Petrobras Petro-Canada Saga Petroleum a.s. Poco Petroleums Limited REDA Renaissance Energy Limited Phillips Petroleum Company Norway Schlumberger Shell International Exploration & Production B. V. Talisman Energy Inc. Texaco Inc. Tri Link Resources Limited Wascana Energy Inc.

13 Production Enhancement for Gas Wells Background Water production in gas wells may result in liquid loading, which in turn... reduces gas production rates reduces recoverable reserves increases operating costs. Downhole gas/water separation technology (as well as established techniques such as velocity string or plunger lift) may improve gas production rates. The applicability of each technique depends on specific field and well conditions. An engineering assessment of a number of wells in a field can determine the applicability of various commercially available production systems. Potential Benefits Increased gas flow rate (production acceleration) Reduced water handling (with downhole injection system) and other operating costs Increased recoverable reserves (capture) Reactivation of shut-in wells Capabilities Multidisciplinary engineering team with state-of-the-art knowledge of production technology Extensive experience in petroleum applications and new technology deployment, including gas/water separation specialized in-house computer models for performance prediction Engineering Services C-FER s approach to determining the suitability of different production systems consists of the following steps... Initial meeting with client to define ultimate objectives, based on client s development plans and current operating status of a property Pre-screening of candidate wells from field, based on overall reservoir and well characteristics and on location-specific requirements or constraints Detailed review of top well candidates/systems including... Well tests, logs, fluid analyses Wellbore configuration Workover history Production history Development of alternatives for enhancing production of candidate wells Detailed technical and economic analysis of selected alternatives... Build/use proprietary nodal & economic models Determine impacts on production volumes Determine impacts on operating & capital costs Selection of top alternatives based on results of analysis Deliverables In-house presentation of results of technical and economic analysis, including go-forward recommendations Formal report with format and level of detail determined by client Proposal for assistance in field implementation and performance monitoring (if warranted)

14 Laboratory Facilities LOAD FRAMES C-FER operates a variety of large-scale servo-hydraulic load frames to simulate complex loading scenarios representative of field conditions. Auxiliary Equipment Electric resistive or inductive heating systems Hydrotest equipment High pressure cooling system Leak detection equipment Bending systems Torsion systems Pass-through pressure vessels Example Tests ISO / Thermal well casing connections Biaxial Tension/Compression of line pipe Four-point bend of line pipe Wave loading on composite risers Makeup of subsea pipeline collets Drilling top drive assemblies Crack growth in aerospace structural panels Seismic building dampers System Universal Testing System Tubular Testing System Maximum Specimen Dimensions Maximum Load Length Base Compression Tension Dynamic 6 m 2 x 18 m 15 MN 15 MN 5 MN Length Diameter 15 m 1.5 m Compression 15 MN Tension 15 MN Connection Testing System Length Base 11.6 m 2 x 2 m Compression 15 MN Tension 15 MN Horizontal Testing System Length Diameter 5.5 m 1.2 m System can be reconfigured to accept larger specimens Tension 71 MN Frame Orientation Special Features Structurally capable of 22 MN with additional actuators Vertical Vertical Vertical Horizontal Maximum stroke rate 100 mm/sec Bending capacity 27 MNm Bending capacity 8 MNm Energy dissipation system for destructive testing Bending capacity of 27 MNm Sour service capability

15 Laboratory Facilities DEEP WELL SIMULATOR The Deep Well Simulator (DWS) is used by the oil industry to develop and test a wide range of systems and products under carefully simulated bottomhole service conditions. The well is actually a subsurface pressure vessel equipped with a wellhead to simulate a wide array of downhole temperatures, pressures and flow rates encountered in the field. C-FER Using appropriate fluids, this facility allows carefully controlled testing for drilling and production equipment. Full scale testing reduces the risk of costly downhole problems during field implementation. Operating temperatures from 20 C (68 F) to 200 C (392 F) Coupled to a flowloop Able to handle a variety of fluids Cased well bore 0.6 metres (2 feet) in diameter, providing 14 MPa (2,000 psi) containment capacity Control tests on pump systems with full pressure fluid mixing (single and two phase), flowmeters, and tankage Easy access to electric and hydraulic power, fluid handling and instrumentation Accommodates concentric and multiple tubing/casing strings Maximum tool string and specimen configuration 46 m (150 ft) in length and 560 mm (22 inches) in diameter SPECIAL ENVIRONMENTS LABORATORY C-FER s Special Environments Laboratory (SEL) is one of the world s largest and most comprehensive containment test facilities. The SEL is utilized for tests demanding the safe containment of toxic and flammable gases and potential explosions. Each of two independent systems consists of an in-ground primary containment chamber that houses the test specimen, and an above-ground secondary containment chamber that houses control equipment and provides expansion volume for any release from the primary containment chamber. The internal dimensions of this facility accommodate testing at full scale with a wide range of loads, pressures and fluid flow conditions, yielding results that are more representative of processes occurring under real field conditions. Twin in-ground test chambers provide secondary containment for toxic and flammable gases, with capacity to fully contain explosions Simulation of corrosive and flammable environments, including flow External remote control of test systems Sealable below-ground test vessel, 12 m deep x 2.5 m diameter

16 Laboratory Facilities EXPERIMENTAL FLOW LOOP The Experimental Flow Loop is used to test the performance of downhole pumping systems over a range of operating temperatures, pressures, flowrates and gas/liquid ratios. The flow loop consists of an 85 ft long, mm OD (9 5/8, 40 lb/ft), casing section; separator; and heating and cooling equipment. Physical Setup Accommodates downhole- and surfacedriven pump systems up to 24.4 m (80 ft) in length, up to 12 m (40 ft) per section; Allows for downhole gas (steam and air) separation at the pump intake with a simulated submergence of approximately 2 m (6.6 ft); # API wellhead flange which allows for a variety of standard wellheads to be installed. Fully instrumented to allow real time pressure, temperature, flow measurements and pump torque and speed. Pressure and Temperature Limits Pump intake pressure from 100 kpag to 4140 kpag ( psig); Pump discharge pressure to 7580 kpag (1100 psig); Pump intake temperature from 60 C to 200 C ( F). Volumetric Capacity Liquid flow rate up to 800 m 3 /d (5050 bpd) Water, oil or oil/water mixture Air injection up to 120 std-m 3 /h (70 scfm) at 4140 kpag (600 psig) at the downhole pump intake. C-FER

17 Laboratory Facilities DEEPWATER EXPERIMENTAL CHAMBER C-FER s Deepwater Experimental Chamber (DEC) enables full-scale testing of deepwater pipeline and production equipment. The vessel is unique because of the size, pressure rating and ease of access. Equipped with quick release end caps, the vessel ensures rapid installation and removal of equipment, reducing both testing time and cost. Full-scale tests with comprehensive instrumentation, control and video monitoring minimizes the potential for costly equipment failures in deep water. Working pressures to 55 MPa (8,000 psi) 10.7 m (35 ft) long with a 1.22 m (4 ft) diameter Equipped with internal rams and reaction frames to apply tension, compression, torsion and bending loads to specimens while under pressure Full scale pipeline testing at working pressures, both internally and externally Rapid installation and removal of test specimens and assemblies Internal video monitoring Accommodates hydraulic, electrical, video and instrumentation leads C-FER STRONG FLOOR AND WALLS High capacity multi-use reaction floor (22 m x 12 m) Buttressed multi-directional reaction wall (15 m long x 6 m high) for application of multi-directional loading Accommodates large-scale structural assemblies and components with more than 1,300 tie-down locations Serviced by 15 tonne overhead travelling crane COMPONENT TESTING 1000 kn capacity servohydraulic MTS machine for coupon testing under a variety of load & temperature conditions 16,200 N-m torsion testing unit, with independently operated axial tensile load capacity to 1,300 kn Other self-contained computer-controlled load and pressure systems for serviceability and proof testing of hoisting equipment, couplings, valves, vessels, etc.

18 Contacts MANAGING DIRECTOR Francisco Alhanati x253 CHIEF ENGINEER & C-FER FELLOW Maher Nessim x207 C-FER FELLOW Cam Matthews x252 BUSINESS DEVELOPMENT & PLANNING Brian Wagg, Director x235 EXPLORATION & PRODUCTION Kelly Piers, Director x246 DRILLING & COMPLETIONS Kirk Hamilton, Manager PRODUCTION OPERATIONS Wayne Klaczek, Manager x x306 ENGINEERING SERVICES Paul Skoczylas, Manager x299 PIPELINES & STRUCTURES Qishi Chen, Director x215 DESIGN & CONSTRUCTION Chris Timms, Manager x259 INTEGRITY & OPERATIONS Jason Skow, Manager x308 C-FER

19 C-FER Printed September 2015

20 C-FER 200 Karl Clark Road Edmonton, Alberta Canada T6N 1H2