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GENERATION OF ELECTRIC POWER FROM WASTE HEAT IN THE WESTERN CANADIAN OIL AND GAS INDUSTRY

PHASE 1 REPORT—SCOPING EVALUATIONS

REV A

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SUITE 400 CHEVRON PLAZA 500 – 5TH AVENUE S.W.

CALGARY, ALBERTA T2P 3L5

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CALGARY, AB T2P 3N4 Telephone: (403) 571-0852

Fax: (403) 571-0853

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October 2007 File: 20819/1

DISCLAIMER: PTAC does not warrant or make any representations or claims as to the validity, accuracy, currency, timeliness, completeness or otherwise of the information contained in this report , nor shall it be liable or responsible for any claim or damage, direct, indirect, special, consequential or otherwise arising out of the interpretation, use or reliance upon, authorized or unauthorized, of such information.

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Generation of Electric Power from Waste Heat In The Western Canadian Oil and Gas Industry

Petroleum Technology Alliance Canada PHASE 1—SCOPING EVALUATIONS

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ABSTRACT Capturing waste heat to generate power in the Western Canadian oil and gas industry could provide significant incremental electricity generation capacity from conventional waste heat sources, such as compression driver exhausts, as well as from waste heat streams less commonly put to a useful purpose, such as warm produced water. The potential advantages of waste heat power generation in the oil and gas industry are numerous, including:

• Electricity could be generated with no incremental emissions • Power production would require no additional fuel consumption, and minimal

variable operating costs • Generated electricity would provide cost savings or additional revenue • Electricity offers the potential to generate a useful product from otherwise wasted

energy, even when an adequate thermal load for the waste heat is unavailable This report summarizes an assessment of the available opportunities to generate electricity from waste heat in the upstream oil and gas industry. The main areas covered include:

• Common waste heat sources and their characteristics • Identification and description of the primary available power generation technologies

that utilize waste heat • Issues regarding grid interconnection and utilization of produced power • Scoping-level technical and economic assessments

Keywords: Waste Heat Recovery, Power Generation, Organic Rankine Cycle, Kalina Cycle



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ACKNOWLEDGEMENTS Petroleum Technology Alliance Canada (PTAC) would like to gratefully acknowledge EnCana, Natural Resources Canada, Alberta Energy Research Institute, Petro-Canada, Epcor, Alberta Electric System Operator, Kereco Energy and Western Economic Diversification for funding this project, and for their continued efforts in supporting emission reduction and energy efficiency initiatives in the oil and gas sector. Special thanks are also given to the individuals from the sponsoring organizations who participated on the project working group, and who provided their guidance, insight and/or review.

• Alberta Energy Research Institute

Richard Nelson

• Alberta Environment Jerry Keller

• Alberta Electric System Operator (AESO) Nicole LeBlanc

• EnCana

Russell Wickes

• EPCOR Denise Chang-Yen

• Kereco Energy

Kelly Edwards

• Natural Resources Canada Phil Jago and Catriona Armstrong

• Petro-Canada

Phil Croteau

• Petroleum Technology Alliance Canada (PTAC) Ralf Aggarwal



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DISCLAIMER This document is intended as an initial assessment of technology needs and potential processes. Any technologies discussed or referred to are intended as examples of potential solutions and have not been assessed in detail or endorsed as to their full technical or economic viability. This document was prepared for and under the direction of a PTAC-facilitated project working group. PTAC and the project consultant, Neill and Gunter, disclaim any warranty, express or implied, that the information in this report is accurate and complete, or will be useful or reliable for any purposes. The user assumes the entire risk of inaccuracy or incompleteness or that the information will be useful or reliable, regardless of any fault or any negligence on the part of PTAC, or Neill and Gunter.



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ABSTRACT …………………………………………………………………………………….. i ACKNOWLEDGEMENTS………………………………...………………………………….. ii DISCLAIMER …………………………………………………………….……………………iii TABLE OF CONTENTS……………………………………………………………………….iv LIST OF TABLES……………………………………………………………………………..viii LIST OF FIGURES……………………………………………………………………………..ix

1. EXECUTIVE SUMMARY.............................................................................................. 1

2. INTRODUCTION ........................................................................................................... 6

2.1 Background .......................................................................................................... 6 2.2 Study Objectives .................................................................................................. 7 2.3 Report Organization............................................................................................. 7 2.4 Study Limitations................................................................................................. 8

3. WASTE HEAT OPPORTUNITIES IN UPSTREAM O&G OPERATIONS................. 9

3.1 General ................................................................................................................. 9 3.2 Why Power Generation? .................................................................................... 10 3.3 Summary of Waste Heat Sources....................................................................... 10

3.3.1 Natural Gas Facilities....................................................................... 11 3.3.2 Oil Facilities..................................................................................... 13 3.3.3 Steam Assisted Gravity Drainage Operations.................................. 13 3.3.4 Other Opportunities.......................................................................... 15

4. WASTE HEAT POWER GENERATION TECHNOLOGIES..................................... 16

4.1 Introduction........................................................................................................ 16 4.2 Steam Rankine Cycle ......................................................................................... 17

4.2.1 Description and Applications........................................................... 17 4.2.2 Performance Characteristics ............................................................ 18 4.2.3 Technical Issues ............................................................................... 20 4.2.4 Costs................................................................................................. 20 4.2.5 Suppliers........................................................................................... 21

4.3 Organic Rankine Cycle ...................................................................................... 21 4.3.1 Description and Applications........................................................... 21 4.3.2 Performance Characteristics ............................................................ 22 4.3.3 Technical Issues ............................................................................... 23 4.3.4 Costs................................................................................................. 26



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4.3.5 Suppliers........................................................................................... 26 4.4 Kalina Cycle....................................................................................................... 27

4.4.1 Description and Applications........................................................... 27 4.4.2 Performance Characteristics ............................................................ 28 4.4.3 Technical Issues ............................................................................... 29 4.4.4 Costs................................................................................................. 30 4.4.5 Suppliers........................................................................................... 30

4.5 Stirling Engines.................................................................................................. 30 4.5.1 Description and Applications........................................................... 30 4.5.2 Performance Characteristics ............................................................ 31 4.5.3 Technical Issues ............................................................................... 31 4.5.4 Costs................................................................................................. 31 4.5.5 Suppliers........................................................................................... 31

4.6 Thermal / Hydraulic Systems............................................................................. 32 4.6.1 Description and Applications........................................................... 32 4.6.2 Performance Characteristics ............................................................ 32 4.6.3 Technical Issues ............................................................................... 32 4.6.4 Costs................................................................................................. 33 4.6.5 Suppliers........................................................................................... 33

4.7 Other Technical Considerations......................................................................... 33 4.7.1 Cooling Medium .............................................................................. 33 4.7.2 Condensing Heat Exchangers .......................................................... 36

5. ELECTRICITY PRODUCTION & GRID INTERCONNECTION ............................. 38

5.1 Electricity Industry Background ........................................................................ 38 5.1.1 Alberta.............................................................................................. 38 5.1.2 Saskatchewan ................................................................................... 40 5.1.3 British Columbia .............................................................................. 41

5.2 Options for Produced Power .............................................................................. 41 5.3 GHG Implications .............................................................................................. 42

5.3.1 General ............................................................................................. 42 5.3.2 Policy Background........................................................................... 42 5.3.3 Potential Impact on Project Economics ........................................... 43

5.4 Grid Interconnection Requirements ................................................................... 44

6. EVALUATION METHODOLOGY.............................................................................. 45

6.1 Performance Modeling....................................................................................... 45 6.2 Economic Modeling........................................................................................... 46

6.2.1 Approach and Key Assumptions...................................................... 46 6.2.2 Revenue / Cost Savings Estimates ................................................... 47 6.2.3 Capital Cost Estimates ..................................................................... 47 6.2.4 Operating Cost Estimates................................................................. 50 6.2.5 A Note on Return on Investment Expectations................................ 50



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7. WASTE HEAT SOURCE SCOPING EVALUATIONS .............................................. 52

7.1 Reciprocating Engines ....................................................................................... 52 7.1.1 Sources ............................................................................................. 52 7.1.2 Typical Waste Heat Characteristics ................................................. 53 7.1.3 Technical Issues ............................................................................... 53 7.1.4 Summary of Potential....................................................................... 54

7.2 Gas Turbines ...................................................................................................... 55 7.2.1 Sources ............................................................................................. 55 7.2.2 Typical Waste Heat Characteristics ................................................. 56 7.2.3 Technical Issues ............................................................................... 56 7.2.4 Summary of Potential....................................................................... 56

7.3 Fired Heaters ...................................................................................................... 58 7.3.1 Sources ............................................................................................. 58 7.3.2 Typical Waste Heat Characteristics ................................................. 59 7.3.3 Technical Issues ............................................................................... 59 7.3.4 Summary of Potential....................................................................... 60

7.4 Steam Generators ............................................................................................... 61 7.4.1 Sources ............................................................................................. 61 7.4.2 Typical Waste Heat Characteristics ................................................. 61 7.4.3 Technical Issues ............................................................................... 61 7.4.4 Summary of Potential....................................................................... 62

7.5 Warm Produced Water....................................................................................... 65 7.5.1 Sources ............................................................................................. 65 7.5.2 Typical Waste Heat Characteristics ................................................. 65 7.5.3 Technical Issues ............................................................................... 65 7.5.4 Summary of Potential....................................................................... 66

7.6 Surplus Steam .................................................................................................... 69 7.6.1 Sources ............................................................................................. 69 7.6.2 Typical Waste Heat Characteristics ................................................. 69 7.6.3 Technical Issues ............................................................................... 69 7.6.4 Summary of Potential....................................................................... 69

7.7 Amine Sweetening ............................................................................................. 71 7.7.1 Sources ............................................................................................. 71 7.7.2 Typical Waste Heat Characteristics ................................................. 71 7.7.3 Technical Issues ............................................................................... 72 7.7.4 Summary of Potential....................................................................... 72

7.8 Incineration ........................................................................................................ 74 7.8.1 Sources ............................................................................................. 74 7.8.2 Typical Waste Heat Characteristics ................................................. 74 7.8.3 Technical Issues ............................................................................... 74 7.8.4 Summary of Potential....................................................................... 75

7.9 Glycol Cooling Circuits ..................................................................................... 75 7.9.1 Sources ............................................................................................. 75 7.9.2 Typical Waste Heat Characteristics ................................................. 76



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7.9.3 Technical Issues ............................................................................... 76 7.9.4 Summary of Potential....................................................................... 76

7.10 Blowdown and Disposal Streams ...................................................................... 77 7.10.1 Sources ............................................................................................. 77 7.10.2 Typical Waste Heat Characteristics ................................................. 78 7.10.3 Technical Issues ............................................................................... 79 7.10.4 Summary of Potential....................................................................... 79

7.11 Condensers ......................................................................................................... 80 7.11.1 Sources ............................................................................................. 80 7.11.2 Technical Issues ............................................................................... 81 7.11.3 Summary of Potential....................................................................... 81

7.12 Sensitivity Analysis............................................................................................ 82

8. CONCLUSIONS AND RECOMMENDATIONS ........................................................ 84

9. REFERENCES............................................................................................................... 87

APPENDICES APPENDIX A GRID INTERCONNECTION REPORT APPENDIX B INFORMATION SHEETS



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LIST OF TABLES Table 1.1 Summary of Economics for Power Generation from Various Waste Heat Sources....... 2 Table 3.1 Fossil Fuel Industry Emissions ....................................................................................... 9 Table 4.1 Organic Working Fluid Properties................................................................................ 24 Table 4.2 Reference Kalina Cycle Projects................................................................................... 27 Table 5.1 Historical Alberta Wholesale Pool Prices..................................................................... 39 Table 5.2 Potential Effect of GHG Price on Electricity Value ..................................................... 43 Table 7.1 Typical Reciprocating Engine Energy Balance ............................................................ 52 Table 7.2 Alberta Oil Pools with Potential for Electricity Generation ......................................... 67 Table 7.3 Amine Unit Equipment Duties...................................................................................... 72 Table 7.4 Base Case Variables for Sensitivity Analysis ............................................................... 82



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LIST OF FIGURES Figure 3.1 Simplified Block Flow Diagram—Natural Gas Processing ........................................ 12 Figure 3.2 Simplified Block Flow Diagram—Conventional Oil Production ............................... 13 Figure 3.3 Simplified Block Flow Diagram—SAGD Operations ................................................ 14 Figure 4.1 Available Waste Heat Power Generation Technologies.............................................. 16 Figure 4.2 Simplified Steam Rankine Cycle Schematic (Typical) ............................................... 17 Figure 4.3 Typical Layout of Gas Turbine HRSG........................................................................ 18 Figure 4.4 Impact of Steam Conditions on Rankine Cycle Efficiency......................................... 19 Figure 4.5 Impact of Turbine Backpressure on Rankine Cycle Efficiency .................................. 19 Figure 4.6 Simplified Organic Rankine Cycle Schematic (Typical) ............................................ 22 Figure 4.7 6.5MW ORC at a Natural Gas Compression Station .................................................. 22 Figure 4.8 Effect of Waste Heat Temperature on ORC Cycle Efficiency .................................... 23 Figure 4.9 a) Wet expansion in a Steam Turbine b) Dry expansion in an ORC turbine............... 24 Figure 4.10 Ormat Energy Converter Schematic.......................................................................... 25 Figure 4.11 Cascading Closed Loop Cycle................................................................................... 26 Figure 4.12 Simplified Kalina Cycle Schematic (Typical)........................................................... 28 Figure 4.13 Effect of Temperature on Kalina Cycle Efficiency ................................................... 28 Figure 4.14 Kalina Cycle’s Variable Temperature Boiling Process ............................................. 29 Figure 4.15 Stirling Cycle ............................................................................................................. 30 Figure 4.16 Effect of Cooling Medium Temperature on Carnot Efficiency................................. 34 Figure 4.17 Effect of Chosen Approach on Tower Size ............................................................... 35 Figure 4.18 Increased Heat Recovery using a Condensing Heat Exchanger................................ 36 Figure 5.1 Historical Alberta Spot Market Prices for Electricity.................................................. 39 Figure 6.1 Correlation for ORC Efficiency (<150°C) .................................................................. 45 Figure 6.2 Correlation for ORC Efficiency (>150°C) .................................................................. 46 Figure 6.3 Effect of Plant Size on Total Capital Cost (Flue Gas Waste Heat Source) ................. 49 Figure 6.4 Effect of Plant Size on Total Capital Cost (Liquid Waste Heat Source)..................... 49 Figure 6.5 Capital Cost Temperature Correction (Liquid Waste Heat Source)............................ 50 Figure 7.1 Simplified Recip Heat Recovery Schematic (Example).............................................. 53 Figure 7.2 Power Output from Recip Engine Heat Recovery....................................................... 54 Figure 7.3 Recip Engine Financial Performance .......................................................................... 55 Figure 7.4 Power Output Ambient Temperature Correction Factors (Example).......................... 56 Figure 7.5 Power Output from Gas Turbine Exhaust Heat Recovery........................................... 57 Figure 7.6 Gas Turbine Financial Performance ............................................................................ 57 Figure 7.7 Impact of Load Factor on Gas Turbine Financial Performance .................................. 58 Figure 7.8 Typical Immersion Fire-Tube Heater .......................................................................... 59 Figure 7.9 Power Output from Fired Heater Exhaust Heat Recovery .......................................... 60 Figure 7.10 Impact of Load Factor on Fired Heater Financial Performance ................................ 61 Figure 7.11 Power Output from OTSG Exhaust Heat Recovery .................................................. 62 Figure 7.12 OTSG Financial Performance.................................................................................... 63 Figure 7.13 Impact of Flue Gas Exit Temp on Power Output from OTSG Heat Recovery ......... 64 Figure 7.14 Impact of Flue Gas Exit Temperature on OTSG Financial Performance.................. 64 Figure 7.15 Power Output from Warm Produced Water Heat Recovery ..................................... 66



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Figure 7.16 Warm Produced Water Financial Performance ......................................................... 68 Figure 7.17 Warm Produced Water Financial Performance ......................................................... 68 Figure 7.18 Impact of Surplus Steam Flow on Power Output ...................................................... 70 Figure 7.19 Surplus Steam Financial Performance....................................................................... 70 Figure 7.20 Simplified Amine Sweetening Schematic (Typical) ................................................. 71 Figure 7.21 Impact of Amine Unit Size on Power Output............................................................ 73 Figure 7.22 Amine Unit Heat Recovery Financial Performance .................................................. 73 Figure 7.23 Simplified Incineration Block Flow Diagram ........................................................... 74 Figure 7.24 Simplified SAGD Glycol Circuit Schematic (Typical) ............................................. 75 Figure 7.25 Impact of Glycol Flow Rate on Power Output .......................................................... 76 Figure 7.26 Glycol Circuit Heat Recovery Financial Performance .............................................. 77 Figure 7.27 Simplified Blowdown Heat Recovery Schematic (Typical) ..................................... 78 Figure 7.28 Power Output from Blowdown Heat Recovery......................................................... 79 Figure 7.29 Simplified SAGD Produced Gas Cooling Arrangement (Example) ......................... 80 Figure 7.30 Power Output from Condenser Heat Recovery ......................................................... 81 Figure 7.31 Summary of Sensitivity Analysis .............................................................................. 82



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1. EXECUTIVE SUMMARY

The overall purpose of Phase 1 of this study is to complete a preliminary examination of the technical and economic feasibility of generating power from recovered waste heat in the Western Canadian upstream oil and gas industry. Specific objectives include:

• Identify the technologies available for conversion of waste heat to electricity and produce a summary of relevant information for each technology

• Characterize the most common waste heat sources available to gauge their potential for heat recovery and power generation

• Complete scoping evaluations for the various waste heat sources to define the economics of projects, and to explore the sensitivity to various technical and financial variables

• Identify the potential for economic and repeatable application of waste heat power generation technology, and recommend a route forward for Phase 2 of the work

The fossil fuel industry is an enormous consumer of energy. Vast quantities of waste heat are produced as fuel is used internally during production, processing, refining and other operations. While representing a huge potential resource, the quality of waste heat is typically low and its further utilization is often impractical. This challenge—the practical and economic utilization of a low quality but high quantity energy source—is the primary goal of waste heat power generation technologies. These technologies have a number of potential advantages:

• Significant additional electricity generation capacity could be added • Electricity could be generated with no additional fuel consumption or incremental

emissions of pollutants or greenhouse gases • Power generation offers the potential to produce a useful energy form from

otherwise wasted energy, when an adequate thermal load for the waste heat is unavailable

Several potential waste heat sources in upstream natural gas, oil and SAGD facilities were considered, and typical operating conditions were summarized. The main opportunities identified include:

• Reciprocating engine and gas turbine exhausts • Flue gases from fired heaters, steam generators and incinerators • Warm liquid streams, such as warm produced water and boiler blowdown • Miscellaneous applications where heat is most commonly rejected in aerial

coolers, such as amine trim coolers, regenerator reflux condensers, produced gas coolers, column overhead condensers, and glycol system trim coolers

Three fully commercial technologies were identified as options to convert recovered waste heat to power. The efficiency of each technology is directly correlated with waste



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heat temperature, and range from below 5% for waste heat streams less than 80°C, to greater than 15% for hot streams like gas turbine exhausts. The technologies considered are as follows:

• Steam-based Rankine cycle, where a heat recovery steam generator is used to produce steam from hot exhaust gases, which in turn powers a steam turbine generator unit

• Organic Rankine cycle, where recovered waste energy is transferred to an organic working fluid, such as propone or pentane, which then drives a turbine expander

• Kalina cycle, another Rankine cycle variation where the unique properties of an ammonia-water working fluid provide some marked advantages in terms of efficiency and allowable waste heat temperatures

In order to complete the preliminary scoping evaluations for the various waste heat streams, performance and capital cost correlations were developed for waste heat power generation projects over a range of temperatures and unit capacities. A general summary of the results of the scoping evaluations is presented below. Note that there is considerable variation in financial results depending on a number of factors, such as plant load factor, project size and waste heat temperature—the intent of Table 1.1 is to provide an indication of where potentially successful projects may be found, and to frame expectations for project financial returns. A complete discussion of the scoping evaluation results are provided in Section 7 of this report.

Table 1.1 Summary of Economics for Power Generation from Various Waste Heat Sources

IRR Pricing Case

< 10% 10 – 15% > 15%

$85/MWh + $15/tonne CO2e

• Individual Reciprocating Engines

• Fire-tube Immersion Heaters

• Steam Generator Blowdown

• Steam Generator exhaust without condensing HX’s

• <20,000hp Gas Turbines

• Steam generator exhaust with condensing HX’s

• Surplus Steam >5,000kg/hr

• Trim coolers / reflux condensers in large sweetening plants (>100m3/hr amine circulation)

• >20,000hp Gas Turbines

• >5000m3/day warm produced water in upper temp range

• Surplus Steam >10,000kg/hr

• Large SAGD glycol cooling systems

• Overhead coolers etc. with duty >15MWth in upper temp range



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Each potential waste heat stream has advantages, disadvantages and particular characteristics that have a major influence on its viability for power generation.

• Reciprocating Engines—as the largest consumer of fuel gas in the upstream industry, reciprocating engines as a whole are a large source of waste heat that is recoverable from the exhaust gases and jacket cooling water. Individually, however, recips provide only small (<300kWe) power generation opportunities with the associated high capital cost per installed kW. There is potential to reduce capital costs considerably by pairing “off-the-shelf” power generation units with common engine models.

• Gas Turbines—exhaust gas heat recovery from gas turbines is one of the most

common applications for waste heat power generation, and has good potential for economic viability. While larger midstream units (>20,000hp) will have the most attractive economics, smaller units with high annual capacity utilization should be assessed for viability.

• Fired Heaters—despite being one of the largest consumers of fuel gas in the

upstream industry, fired immersion heaters have poor potential for economically viable waste heat power generation. A combination of factors, including intermittent burner firing, small project sizes and low capacity utilization result in unattractive projects. Large fired heaters (>10MWth duty) with elevated exhaust gas temperatures, high annual load factors, and modulating burner control, may provide opportunities in select cases.

• Steam Generators—flue gases are already at a relatively low temperature, so

limited incremental gains are available unless condensing heat exchangers are used to capture additional sensible and latent heat. For SAGD facilities, there is potential for attractive power generation projects by using condensing heat exchangers, and by marshalling several OTSG flue gas streams together to improve the economy of scale.

• Warm Produced Water—the most prospective opportunities will be those where

water flow and temperature are high enough to support generation in excess of 1MWe. Within the relatively low temperature range characteristic of this stream (80 to 115°C) small changes in temperature can have a large impact on plant output and specific capital cost. Focus on operations where flow and temperature are greater than 2,500 m3/day and 100°C, respectively.

• Surplus Steam— While reduction or elimination of LP steam venting should be

the first priority, large steam volume applications (greater than 5,000 kg/hr vented) with high load factors should be strongly considered for more detailed analysis of power generation economic viability.



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• Amine Sweetening—large amine sweetening plants (>100m3/hr amine circulation) may have decent potential for power generation by combining the reflux condenser and lean amine trim cooler waste heat streams, despite relatively low available temperatures. Project economics would benefit from avoided fan horsepower requirements from the aerial coolers during operation of the power generation unit, which would offset the low net efficiency of the power generation island.

• Glycol—while at the extreme low end of the feasible waste heat temperature

range, large SAGD glycol systems appear to have decent potential for power generation despite very low net efficiency. This is due in part to the avoided fan horsepower requirements from the aerial trim coolers while the power generation unit is in operation, and the potential to lower the capital costs of power generation if incorporated into the original design of new SAGD facilities.

• Blowdown—SAGD facilities have historically used OTSG’s for steam generation

which have high blowdown rates. Blowdown heat recovery is already incorporated into the plant heat integration scheme, and additional heat recovery for power generation has poor potential due to very small power output (and thus high specific capital costs per kW) and low available waste heat temperature.

• Condensers—column overhead condensers, produced gas coolers and other

similar heat rejection applications have decent potential for waste heat power generation in cases where projects in the MW size range can be supported. Generally, condensers operating above 85°C with duties greater than 15MWth will provide the most prospective opportunities for viable projects.

It is recommended that the study proceed to Phase 2—Feasibility Evaluations. The two primary objectives of Phase 2 of the work would be to:

• Further characterize the possible impact of waste heat power generation on the Western Canadian upstream oil and gas industry. High level estimates of the waste heat resource would be carried out to gauge the total potential for electricity capacity additions.

• Further demonstrate the viability of these power projects by completing detailed feasibility assessments for selected common, representative scenarios that have a reasonable likelihood of current or future economic viability.

The project steering committee would have to determine, depending on the mandate of the project, which scenarios should be selected for more detailed assessment in Phase 2.



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Options include:

• Proven scenarios with a higher likelihood of further study indicating economic viability under today’s circumstances. An example would be a large gas turbine with high annual capacity utilization.

• Less conventional applications for waste heat power generation, that have potential to significantly impact the industry’s energy intensity. Candidates include SAGD glycol or steam generation systems, small reciprocating engines and warm produced water.

While the less conventional applications may have known economic or technical issues, as discussed in this report, it is felt they warrant additional investigation in Phase 2. The advantage of this approach is that the challenges associated with these applications can be assessed while benefiting from the collaborative nature of PTAC-facilitated projects. It is also recommended that technology supplier involvement in Phase 2 be pursued. As capital costs are the major factor in determining project economic viability, it is imperative that vendors evaluate supply costs for their equipment on an application-specific basis.



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2. INTRODUCTION 2.1 Background

This project was spurred by the potential to use waste heat recovery in the upstream oil and gas industry to improve the efficiency of operations. Utilizing waste heat to produce power could provide significant incremental electricity generation capacity from conventional waste heat sources, such as compression driver exhausts, as well as from waste heat streams less commonly put to a useful purpose, such as warm produced water. The potential advantages of waste heat power generation are numerous, including:

• Electricity could be generated with no incremental emissions of pollutants or greenhouse gases

• Power production would require no additional fuel consumption, and minimal variable operating costs

• Generated electricity could represent a significant source of cost savings or additional revenue

• Electricity offers the potential to generate a useful product from otherwise wasted energy, even when an adequate thermal load for the waste heat is unavailable

With these and other benefits in mind, PTAC and the Technology for Emission Reduction and Eco-Efficiency (TEREE) Steering Committee issued Request for Proposal EETR-0603—Generation of Electric Power from Waste Heat in the Western Canadian Oil and Gas Industry. A phased approach was proposed to meet the objectives of the study. Phase 1—Scoping Evaluations, focuses on identifying available power production technologies and characterizing the most prevalent waste heat recovery opportunities in upstream operations. Phase 2—Feasibility Evaluations, would only be undertaken if justified by the results of Phase 1, and would focus on completing a number of detailed case studies for representative waste heat recovery scenarios. This report presents the results of Phase 1 of the work.



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2.2 Study Objectives The overall purpose of the study is to examine the technical and economic feasibility of waste heat-to-power generation, and the potential for regular utilization in the upstream oil and gas industry. Specific objectives of Phase 1 of the study include:

• Identify the technologies available for conversion of waste heat to electricity, and produce a summary of relevant information for each technology

• Characterize the most common waste heat sources available to gauge their potential for heat recovery and power generation

• Complete scoping evaluations for the various waste heat sources to define the economics of projects, and to explore the sensitivity to various technical and financial variables

• Investigate the technical issues relating to grid interconnection of distributed electricity generation

• Identify the potential for economic and repeatable application of waste heat power generation technology in the upstream oil and gas industry, and recommend the best route forward for Phase 2 of the work

2.3 Report Organization

The report is organized as follows:

• Section 1 provides an Executive Summary of the study results • Section 2 provides background on the project and its motivation • Section 3 is a general introduction to the waste heat opportunities available, and

introduces some of the primary advantages, disadvantages and alternatives to electricity production

• Section 4 is a description of the technologies for power production from waste heat considered in the study, and includes a discussion of performance characteristics, costs and suppliers for each technology

• Section 5 describes the technical considerations around grid interconnection, and various applicable policy initiatives and economic issues that could impact waste heat power projects

• Section 6 describes the methodology used to complete the scoping evaluations of various waste heat recovery scenarios

• Section 7 characterizes the common waste heat streams considered in the study in terms of magnitude, temperature and potential for waste heat power generation and provides estimates of economic performance and sensitivity to technical and financial variables

• Section 8 summarizes the report conclusions and recommendations



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2.4 Study Limitations This study is a high-level examination of waste heat recovery opportunities and applicable power conversion technologies. Due to the broad scope of the project and the inevitable variations in site-specific factors, generalizations are required in order to assess “typical” waste heat sources and characteristics. The purpose of the scoping evaluations is to narrow the focus such that future detailed analysis is reserved for opportunities with a reasonable chance of becoming an economically feasible project. As such, no site-specific assessments have been completed, and performance, cost and economic feasibility estimates in this report are indicative only. Should the scoping evaluations identify that a particular application has potential, a detailed and site-specific investigation should be conducted, in consultation with technology providers, to determine expected performance and cost. The purpose of Phase 2 of this work, should it proceed, is to undertake this more detailed investigation for selected scenarios. Also note that suppliers lists provided in this report are not comprehensive and do not include all potential equipment vendors.



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3. WASTE HEAT OPPORTUNITIES IN UPSTREAM O&G OPERATIONS

3.1 General The fossil fuel industry is an enormous consumer of energy. A portion of the industry’s gross output is used internally to fuel production, processing, refining and other aspects of operations. The table below provides an order of magnitude indication of this internal energy consumption, based on Canada’s 2004 national greenhouse gas (GHG) inventory.

Table 3.1 Fossil Fuel Industry Emissions

Sector GHG Emissions from

Internal Fuel Combustion (Mt CO2e)1

Energy Consumption (GJ)2

Upstream Fossil Fuel Industry - Crude Oil Production 25.4 508 million - Natural Gas Industry 10.6 212 million - Other (Oilsands, Coal) 26.6 532 million - Natural Gas Transmission 8.5 170 million Downstream Fossil Fuel Industry 17.0 340 million TOTAL 88.1 1762 million

1 From National Inventory Report (Environment Canada, 2006) 2 Based on average 50 kg CO2 per GJ energy intensity, as natural gas is dominant fuel used in operations

Where fuel is combusted, waste heat is inevitably generated due to efficiency losses in the process. Between 10% and 70% of the energy contained in a fuel is lost as waste heat in typical industrial processes. From the above figures, it is evident that the magnitude of waste heat resulting from oil and gas operations is on the order of tens of gigawatts of thermal energy. While representing a huge potential resource, it is important to note that the quality of waste heat is typically low and its further utilization is often impractical due to its low temperature. This challenge—the practical and economic utilization of a low quality but high quantity energy source—is the primary goal of waste heat power generation technologies.



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3.2 Why Power Generation? Producing electricity from recovered thermal energy is another conversion step with its own associated efficiency losses. Electricity generation from waste heat typically has only between 5% and 25% thermal efficiency, and relatively high capital costs. In addition, investment is power generation is often characterized by moderate financial returns over a long time horizon. In many cases, focus should be placed on other options that could prove more thermally efficient and cost-effective than power generation. Generally, the alternatives include:

• Improving the efficiency of the process resulting in the waste heat stream, in order to reduce the waste heat generated in the first place. This approach often yields significant savings and is the least cost alternative, consisting of simple equipment upgrades or operational changes.

• Utilizing recovered waste heat directly as a source of thermal energy, rather than taking the additional electricity conversion step. Process heat integration in this manner can directly offset fuel consumption elsewhere in the process.

Throughout this report, some alternatives to waste heat power generation for specific applications are discussed, where appropriate. The main advantage of power generation, compared to the alternatives, is that a demand for recovered thermal energy is not required, and potentially complex process heat integration schemes can be avoided. Instead, the waste heat is converted to electricity—a high value energy form that can be universally used and easily transported to where it is needed. Note that on an equivalent basis, the value of electricity exceeds $20/GJ, with natural gas valued at around $6/GJ. In addition, there is no incremental fuel consumption or emission of pollutants or greenhouse gases from waste heat power generation. An heat source that would have otherwise been lost to the environment is the only energy input to the system.

3.3 Summary of Waste Heat Sources

The figures in the following sections illustrate the principle stages of processing for natural gas, oil, and steam-assisted gravity drainage (SAGD) facilities, and identify some key waste heat sources present in each stage of the process. Many variations in approach and process design are employed in industry—the intent of the simplified block diagrams is to indicate the main elements of each process and to establish some common waste heat recovery opportunities. The main sources of waste heat are dealt with in more detail in Section 7, where typical



October 2007 File: 20819/1 11

characteristics are outlined and each source is evaluated. 3.3.1 Natural Gas Facilities Natural gas processing involves the removal of liquids and impurities from the raw gas, and the separation of various product streams. Refer to Figure 3.1 for an overview. The largest source of waste heat in natural gas processing is the exhaust from gas compression drivers—reciprocating engines and gas turbines. The size and temperature of these waste heat streams are higher, providing economies of scale and better efficiencies, thus improving their potential for waste heat power generation. Fired heaters, used for line heating, reboilers and other applications, may produce higher temperature waste heat streams, but are generally smaller in scale. Numerous other waste heat sources of varying temperature and magnitude are found within the acid gas removal and sulphur recovery processes.



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GASWELLS

CONDENSATE & WATERREMOVAL / FIELD

PROCESSING

Produced Gas / LiquidsFired Heaters

FIELD PROCESSING &GATHERING

Raw Gas

Water

Condensate

COMPRESSION

Driver ExhaustJacket WaterInter / After Cooling

ACID GAS REMOVAL

Lean Amine Trim CoolingAmine ReboilerRegenerator O/H Cooler

SULPHUR PLANT /TAIL GAS TREATING /

INCINERATION

IncineratorClaus Plant Surplus

DEHYDRATION

Glycol Reboiler

Raw Gas Pipelines

Sulphur

Flue Gases

NGL RECOVERY

Condensate Stabilizer O/HCoolerColumn O/H Cooling

Sales Gas

COMPRESSION

Driver ExhaustJacket WaterInter / After Cooling

NGL FRACTIONATION

Column O/H CoolingFired Heaters

NGL SalesProducts

GAS PROCESSINGFACILITY

Liquids

Figure 3.1 Simplified Block Flow Diagram—Natural Gas Processing



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3.3.2 Oil Facilities Upstream oil processing primarily involves the removal of water and other impurities prior to transportation for further downstream refining.

DEGASSING /SEPARATION FREE WATER

KNOCKOUT

TREATING

Fired Heaters

Production Wells

Gas to Processing orDisposal

Sales Oil

STORAGE /EXPORT

Tank HeatersLine HeatersPump Drivers

PRODUCED WATERHANDLING

Warm Produced Water

Produced Water Reuse or Disposal

Figure 3.2 Simplified Block Flow Diagram—Conventional Oil Production Fired heaters, warm produced water and pump driver exhausts are the main waste heat recovery opportunities in upstream oil operations. Warm produced water represents a large source of geothermal energy, but can be a challenging application for waste heat power generation due to moderate temperatures.

3.3.3 Steam Assisted Gravity Drainage Operations Steam Assisted Gravity Drainage (SAGD) facilities utilize steam injection to recover bitumen. Produced fluids are separated into bitumen, gas and water, and produced water is recycled to the steam generation equipment following treatment. Designs include extensive heat integration schemes to optimize the thermal efficiency of the operations. Refer to Figure 3.3 for an overview. The steam generator exhaust, glycol system trim cooling, boiler blowdown and produced fluids cooling are the typically the largest available sources of waste heat. SAGD facilities are very unique and site-specific, and considerable variations in approach are used which have a significant impact on waste heat availability and characteristics.



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PRODUCTION PADS

Produced Fluids Cooling

SEPARATION & TREATING

Produced Fluids CoolingColumn O/HFired Heaters

SULPHUR RECOVERY

Regen HeaterRegen Aerial Cooler

ProducedLiquids

ProducedVapors

Producer Wells

Injection Wells

SLOP & OFF-SPECHANDLING

STORAGESales ProductBitumen

PRODUCED WATERDEOILING & TREATMENT

Produced WaterProduced Gas

COGENERATION &STEAM GENERATION

Steam Generator Flue GasBoiler Blowdown

FUEL BLENDING &DISTRIBUTION Blowdown Disposal

Sulphur

Natural Gas

Feedwater

Steam

GLYCOL SYSTEM

Glycol Trim CoolerGlycol Trim Heater

SAGD PROCESSINGFACILITY

WELL PADS

Figure 3.3 Simplified Block Flow Diagram—SAGD Operations



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3.3.4 Other Opportunities The focus of this study is on selected aspects of the upstream industry, however, opportunities also exist for waste heat recovery in downstream operations, including refineries and upgraders. While some specific waste heat streams common to downstream operations are not addressed by this study, considerable overlap does exist in terms of technology and waste heat source characteristics. The information in this report is still relevant to the applications potentially found in downstream facilities. Due to the high level of centralization inherent in downstream facilities, it is expected that waste heat power generation opportunities will often be larger in capacity, thus resulting in improved project economics.



October 2007

4. WASTE HEAT POWER GENERATION TECHNOLOGIES 4.1 Introduction

A number of technical options are available for producing electricity from waste heat. The following sections describe the general principles and characteristics of the rankine cycle variations and developing technologies outlined in the figure below.

Waste Heat PowerGeneration

Technologies

Rankine Cycles

Thermal /Hydraulic

StirlingEngines

DevelopingTechnologies

Kalina Cycle

MixturesSingle Fluid

Steam RankineCycle

Organic RankineCycle

Figure 4.1 Available Waste Heat Power Generation Technologies In general terms, all of the technologies are power cycles with a common principle—waste energy is transferred to a working fluid which is raised to an elevated temperature and pressure. A portion of the energy is converted to useful work in the cycle’s prime mover, and the remaining energy is rejected to the environment at a lower temperature than the original waste energy. All of the options are subject to a maximum thermal efficiency imposed by the temperature differential between the hot waste heat stream and the environment, referred to as Carnot or Second Law efficiency.

H

c

TT

−= 1maxη

where: ηmax is maximum thermal efficiency Tc is the average temperature of the cooling medium TH is the average temperature of the heat source

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In practice, actual power cycles typically approach only 25 to 60% of the theoretical maximum efficiency, and it is important to note that small increases in heat source temperature or decreases in cooling medium temperature can have a significant positive impact on overall cycle performance.

4.2 Steam Rankine Cycle 4.2.1 Description and Applications The steam-based Rankine Cycle is the workhorse of the thermal power generation industry and is widely employed. Steam at high temperature and pressure is generated in a boiler or heat recovery steam generator (HRSG) and expanded through a steam turbine-generator unit. Exhaust steam from the turbine is condensed, and pumped back to the steam generator to close the cycle. A simplified schematic of the process is provided below:

Feed Pumps

Condenser

Steam Turbine / GeneratorWORK OUT

HEAT ABSORPTION

Heat Recovery Steam Generator

Deaerator

Extraction Pumps

Cooling Tower

HEAT REJECTION

Figure 4.2 Simplified Steam Rankine Cycle Schematic (Typical) In some cases, backpressure (non-condensing) steam turbines can be used rather than condensing turbines. While power output is reduced for a given steam flow, the exhaust steam can be utilized for process heating. The overall thermal efficiency of a backpressure cycle is much higher as the exhaust

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steam is put to a useful purpose, but the disadvantage is that it is a “heat first” configuration where a heat sink must be present in order to generate power. The figure below shows a typical arrangement for an HRSG matched with a small gas turbine. A bypass stack is usually provided for temperature control and to allow the HRSG to be bypassed when the steam demand is not present.

Figure 4.3 Typical Layout of Gas Turbine HRSG (Source: Henderson, 2006)

Standard HRSG packages are often designed to produce 120 to 150 psig steam, commonly used team pressures, however customized units complete with superheaters are available for power generation applications. A variety of designs are available with different tube configurations or circulation methods, and will depend on the individual application. 4.2.2 Performance Characteristics The performance of a steam-based Rankine cycle generally improves with rising turbine throttle steam temperature and pressure. The following graph provides an estimate of Rankine cycle performance within the range of parameters that would most commonly be encountered for waste heat applications. The estimate assumes a turbine backpressure of 3 in Hg, a 10% auxiliary electrical load, and turbine isentropic efficiency of 80%.

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Steam Rankine Cycle Performance

10.0%

15.0%

20.0%

25.0%

30.0%

0 100 200 300 400 500 600

Inlet Steam Temperature (C)

Net E

ffici

ency

(%)

10.3 bar (150 psi)20.7 bar (300 psi)41.4 bar (600 psi)86.2 bar (1250 psi)

Figure 4.4 Impact of Steam Conditions on Rankine Cycle Efficiency Turbine backpressure is another key variable affecting Rankine cycle efficiency, and is directly related to the temperature of the cooling medium. Steam turbine condensers are traditionally water cooled via an evaporative cooling tower, which can allow low condensing pressures of around 2 in Hg. If air cooling is required, capital costs can increase significantly and cycle performance deteriorates. Figure 4.5 illustrates the impact of turbine backpressure for 41.4 bar (600 psi) / 316°C (600F) inlet steam conditions.


20.0%

25.0%

30.0%

0 2 4 6 8 10 12

Turbine Exhaust Pressure (in Hg)

Net

Effi

cien

cy (%

)

Figure 4.5 Impact of Turbine Backpressure on Rankine Cycle Efficiency

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Large utility scale applications, with supercritical steam conditions, double reheat configurations and regenerative feedwater heating, are exceeding 40% thermal efficiency, but in the range of conditions most commonly encountered in waste heat applications, cycle efficiency will usually be less than 30%. 4.2.3 Technical Issues Due to the boiling characteristics of water, steam cycles will typically only be applicable to high temperature flue gas waste heat sources, such as gas turbine exhausts. Steam cycles are not truly closed loops and require makeup water to replace system losses such as HRSG blowdown and deaerator venting. Blowdown is required to maintain the concentration of dissolved solids within acceptable limits and deaerator venting removes non-condensable gases from the system. In order to protect the HRSG and turbine blades from fouling, water treatment facilities are necessary for the conditioning of makeup water. Water treatment facilities add cost, complexity and operator requirements to the overall system, especially for high temperature and pressure designs where water quality requirements are stringent. Due to limitations in steam temperature (typically less than 600°C,) the Rankine cycle efficiency cannot closely approach the ideal maximum efficiency. The back-end stages of the steam turbine must be designed considering potential erosion due to the presence of moisture. As the steam expands through the turbine, steam conditions approach (or reach) saturation and water droplets are formed that can result in blade erosion. Most jurisdictions require licensed operators for steam systems, and staffing requirements will be subject to the local Power Engineers act and regulations. This can impact the owner’s ability to design for remote and unattended operation, and in some cases can severely affect the financial viability of a project. 4.2.4 Costs The main components of the system capital cost are the HRSG and steam turbine / condenser package. While costs vary widely with plant size, total investment between $3000 and $5000 per kWe should be expected for the smaller scale (<5MWe) projects typical of the waste heat recovery opportunities in the oil and gas industry. Larger utility scale projects can be installed for less than $2000/kW in some cases. Equipment costs for the steam turbine generator package are generally around $400/kW to $600/kW, including a water-cooled condenser and associated auxilliaries. Gas turbine HRSG packages typically run between $50 and $100 per kg/hr of steaming capacity, but ductwork and the bypass stack can add significant costs.



October 2007 File: 20819/1 21

Refer to Section 6 for additional information on costs.

4.2.5 Suppliers

Steam-based Rankine cycles are well-established technology, and numerous North American suppliers are available for the major system components. Some steam turbine manufacturers in with products in the size range appropriate for upstream waste heat projects include:

• Dresser-Rand • General Electric • Siemens • Turbosteam

Some HRSG manufacturers with products in the size range appropriate for upstream waste heat projects include:

• Rentech • TIW Western • IST

4.3 Organic Rankine Cycle

4.3.1 Description and Applications The Organic Rankine Cycle (ORC) has been utilized extensively to generate electricity from low grade heat sources, with 1000’s of MW of existing installed capacity. Commonly used in geothermal binary cycle power plants, the ORC has also been applied in waste heat recovery projects in the cement, steel making, oil and gas and other heavy industries. Modularized packages are offered by a number of vendors, with standardized models available in the range of 200kW – 7MW of electrical power output. The ORC resembles the steam Rankine cycle, but uses alternative working fluids. Organic fluids, including pentane, propane or various refrigerants, have thermodynamic properties that allow power generation from low temperature sources. Figure 4.6 provides an overview of the process and identifies the main components of the system.



October 2007

Feed Pumps

Condenser

RecuperatorEvaporator

Expander / Generator

Waste Heat Source

WORK OUT

HEAT REJECTION

HEAT ABSORPTION

Figure 4.6 Simplified Organic Rankine Cycle Schematic (Typical) In some cases, an intermediate thermal oil loop is used to transfer heat from a flue gas waste heat source to the evaporator. Other variations may include the use of a working fluid preheater, elimination of the recuperator, or water-cooled condensers.

Figure 4.7 6.5MW ORC at a Natural Gas Compression Station (Source: Ormat)

4.3.2 Performance Characteristics The waste heat source temperature, and thus the working fluid conditions at the expander inlet, has a significant effect on the cycle efficiency. Figure 4.8 shows the effect of

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temperature on net efficiency (which includes the impact of parasitic electrical loads) for a number of reference plants.

Organic Rankine Cycle - Reference Performance DataNET THERMAL EFFICIENCY

0.0%

5.0%

10.0%

15.0%

20.0%

25.0%

30.0%

0 100 200 300 400 500 600

Waste Heat Temp (C)

Net

Eff

icie

ncy

(%)

Figure 4.8 Effect of Waste Heat Temperature on ORC Cycle Efficiency

Considerable scatter is present in the reference data due to the numerous variations in design parameters and cycle configurations. Aside from the temperature of the waste heat source, other key factors impacting the overall cycle efficiency include the method of heat rejection and cooling medium temperature, and the design approach temperature between the waste heat source and working fluid. ORC systems generally will achieve between 25% and 35% of Carnot efficiency. 4.3.3 Technical Issues When capturing heat from flue gas, an intermediate hot oil loop is used in some designs because of the safety implications of a potential leak in the evaporator heat exchanger. In addition to increasing capital cost, the intermediate loop reduces overall performance by adding another temperature approach between the working fluid and the waste heat stream. Some ORC vendors believe that the risk of direct heating is very low and utilize evaporators directly heated by the flue gas waste heat stream. 4.3.3.1 Working Fluids The motive fluids used in ORC cycles do not freeze at normal ambient temperatures. This eliminates the requirement for controls and procedures to prevent freezing in the

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condenser and piping. The nature of some of the commonly used organic fluids causes vapor superheating during isentropic expansion in the turbine. This is unlike steam where expansion leads to condensation in the turbine, as shown in Figure 4.9. Dry expansion results in reduced blade erosion concerns and helps accommodate part load operation and transients.

Figure 4.9 a) Wet expansion in a Steam Turbine b) Dry expansion in an ORC turbine

(Source: Stine, 2001)

The characteristics of the waste heat stream are considered during working fluid selection. Critical properties are generally dependent on the molecular mass of the fluid. Heavier working fluids are generally used as waste heat temperature increases. Some properties of commonly used working fluids are shown below.

Table 4.1 Organic Working Fluid Properties

Working Fluid Critical Temperature

Molecular Weight

Propane 97oC 44 Isobutane 135oC 58 n-Pentane 197oC 72

Water (reference) 374oC 18 (Source: Goldsherry, 1982)

Working fluid selection should be matched with the specific design conditions of the application for optimization of the cycle.

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4.3.3.2 Cycle Configuration A recuperator is often included in the design of the power cycle, as shown in Figure 4.10, a schematic of Ormat’s Energy Converter system. This is a heat exchanger that captures energy that would otherwise be lost to the condenser to preheat the working fluid entering the evaporator. A recuperator can be considered when the working fluid is still superheated at the expander outlet.

Figure 4.10 Ormat Energy Converter Schematic (Source: Ormat)

The benefits of a recuperator include lower duty on both the condenser and evaporator, and improved cycle efficiency. However, by increasing the temperature of the working fluid at the evaporator inlet, a recuperator reduces the temperature to which the waste heat stream can be cooled, which can be especially be detrimental at low waste heat temperatures. A case-specific analysis is conducted to determine whether a recuperator should be included in the design of the system. A variation on the ORC is the Cascading Closed Loop Cycle, which employs a double-pressure configuration with two expanders and offers potential for improved efficiency.

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WOW Energies is the main proponent of this approach, and is currently pursuing a number of opportunities to demonstrate the technology on a large scale.

Figure 4.11 Cascading Closed Loop Cycle (Source: WOW Energies)

4.3.4 Costs

Costs are dependent primarily on project size and waste heat temperature. Recent projects in the 5MWe range implemented in gas turbine exhaust applications have cost around $3000 per kW. Smaller projects using lower temperature waste heat sources can exceed $5000 per kW. Continuing development of standardized packages and modularized designs offer further potential to reduce capital costs. Refer to Section 6 for additional information on costs. 4.3.5 Suppliers Some North American vendors of ORC technology include:

• Ormat • Barber Nichols • UTC Power-Pure Cycle • WOW Energy

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4.4 Kalina Cycle 4.4.1 Description and Applications

The Kalina cycle is a variation of the Rankine cycle which uses an ammonia/water mixture as the working fluid. The thermodynamic properties of the mixture make it a suitable working fluid for low grade waste heat applications. Developed in the 1980’s, the Kalina cycle has not been as widely demonstrated as the ORC, however, operating experience is quickly increasing. Some projects include:

Table 4.2 Reference Kalina Cycle Projects

Project Year Application

Canoga Park Demonstration 1991 6.5MW Bottoming Cycle

Sumitomo Metals 1999 3.4MW Oxygen converter gas heat recovery at steel mill

Husavik 2000 2.0MW geothermal

Fuji Oil Refinery 2005 3.9MW fractionation tower overheads heat recovery

Various projects under construction 2006-2008 Geothermal facilities

up to 45MW The ammonia/water mixture increases cycle efficiency by improving heat transfer in the evaporator and condenser. A separator supplies a strong mixture at high pressure to the turbine, and the separated lean liquid mixture is flashed to the turbine outlet, as illustrated in the figure below.



October 2007

Figure 4.12 Simplified Kalina Cycle Schematic (Typical)

(Source: Iiyoshi, 2000)

4.4.2 Performance Characteristics As with the other rankine cycle variations, net thermal efficiency is dependent on working fluid conditions at the turbine inlet. Figure 4.13 shows the impact of temperature on efficiency for some reference Kalina cycle cases.

Kalina Cycle - Reference Performance DataNET THERMAL EFFICIENCY

0.0%

5.0%

10.0%

15.0%

20.0%

25.0%

30.0%

0 100 200 300 400 500

Waste Heat Temp (C)

Net

Effi

cien

cy (%

)

Figure 4.13 Effect of Temperature on Kalina Cycle Efficiency

The improved heat transfer characteristics of the ammonia-water mixture provide an efficiency advantage over the ORC, with second-law efficiencies greater than 40% achievable.

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4.4.3 Technical Issues The distinctive characteristic of the Kalina cycle is that the working fluid does not boil at constant temperature—it follows the waste heat temperature in the evaporator more closely, as shown in Figure 4.14. With working fluids that boil at constant temperature, the saturation temperature creates a pinch point which limits the temperature to which the waste heat stream can be cooled. The “glide” of the ammonia-water mixture’s saturation conditions allows the working fluid to cool the hot stream to a lower temperature, increasing the total amount of waste heat recovered.

Figure 4.14 Kalina Cycle’s Variable Temperature Boiling Process (Source: Micack, 1996)

The cycle can be optimized by controlling the mixture composition at various stages of the cycle. For example, a lean mixture’s vapour pressure is much lower than a rich mixture. A lean mixture may be injected into the condenser to cause lower condenser vapour pressures, which allows extra turbine expansion and thus higher work output. Ammonia-water mixtures have a much lower freezing point than water. For example, even a lean 25/75 ammonia-water mixture has a freezing point of -51oC. This permits the working fluid to be cooled to sub-zero temperatures in cold winter climates, allowing lower turbine exit pressures and higher work output. This can only be attained when using an air cooled condenser (because of freezing of water in cooling towers,) reducing negative performance issues of ACC during the warmer months. Ammonia has a similar molar mass to water so conventional axial flow steam turbine components can be used. Condensing pressure is above atmospheric eliminating the need for expensive and maintenance intensive vacuum systems. Lower specific volume at the turbine exit requires a lower flow area, reducing the capital cost of the turbine.

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4.4.4 Costs

Costs are dependent primarily on project size and waste heat temperature. Generally, costs are similar to the alternatives, with installed capital costs between $3000/kW and $5000/kW typical for plants less than 5MW. The efficiency advantage of the Kalina cycle has the potential to lower specific per kW capital costs compared to the ORC. Refer to Section 6 for additional information on costs. 4.4.5 Suppliers Recurrent Engineering is the North American technology licensee and process designer for the Kalina Cycle. They have worked with various EPC firms to develop projects.

4.5 Stirling Engines 4.5.1 Description and Applications Stirling engines have had a long history of development. High specific costs per kW have limited their use to only a few specialized applications, including military, aerospace, and some solar power projects. Currently available Stirling engines range in size from 1kW to 55kW, and larger scale models continue to be developed. In the context of waste heat power generation in the oil and gas industry, Stirling engines of the size range required are not commercially available. The Stirling Cycle involves isothermal compression of the working fluid, followed by constant volume heating, isothermal expansion at the elevated temperature, and constant volume cooling, as illustrated in the p-V and T-s diagrams below.

Figure 4.15 Stirling Cycle

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Unlike reciprocating engines and gas turbines, in the Stirling engine the heat source is isolated from the working fluid. This presents advantages in providing fuel flexibility in the case of externally fired engines.

4.5.2 Performance Characteristics Stirling engines have a very high theoretical efficiency—a major driver in their continued development is that they theoretically match the efficiency of the Carnot cycle. In practice, the engine’s efficiency is limited by many factors such as the economically achievable temperature approach between the working fluid and the cold and hot reservoirs, friction and piston leakage. Current models are able to realize efficiencies up to 35%, which is comparable to the internal combustion engine (Potter, 2004). 4.5.3 Technical Issues Most commonly used working fluids include air, nitrogen, helium and hydrogen. Hydrogen is the most efficient thermodynamically, but its use has been known to cause metal embrittlement at high operating temperatures. Also, the high diffusion rate associated with this low molecular weight gas, allows it to leak through the engine’s various joints and seals, making it difficult to maintain a high working pressure inside the engine for any length of time. Auxiliary systems are typically required to maintain the proper internal pressure, resulting in additional capital costs. While small kW-scale units have proven extremely reliable and suitable for military and aerospace applications, the reliability of large power generation modules is unproven. Field trials of scaled up Stirling engines will be required before they could be considered for remote, unmanned applications. 4.5.4 Costs Stirling engines suffer from high manufacturing costs due to the low production volumes and relatively small output ratings. This has led to a high cost per kW compared to competing technologies. Total installed costs for industrial scale Stirling engines have been targeted around $1000/kW, but until full commercialization is achieved, actual costs for large models are unknown.

4.5.5 Suppliers Kockums, a subsidiary of ThyssenKrupp Marine Systems, has developed a 25kW Stirling engine for use in the Swedish submarine fleet. This engine has been modified to be used with a solar dish collector by Stirling Energy Systems.



October 2007 File: 20819/1 32

Regen Power Systems are currently testing bench models and are planning to have scaled up prototypes by late 2008. The anticipated product line is to include 500kW and 1MW models for condensing steam applications, and 250kW, 500kW, 1MW and 2MW models for 250oC exhaust gas.

4.6 Thermal / Hydraulic Systems

4.6.1 Description and Applications An example of a thermal-hydraulic system under development is Deluge Inc.’s Natural Energy Engine. Heat is applied to expand a hydraulic working fluid in a piston to create linear motion. Cooling water is then used to cool the fluid and retract the piston. The working fluid is typically carbon dioxide due to its high coefficient of expansion. These systems can operate on low waste heat temperatures (down to 80oC). Deluge is targeting oil pumping applications where warm produced water would provide the energy required to operate the engine. Economics of marginal wells could be significantly improved by reducing pumping costs. Another hydraulic design under development is the Encore Energy “Heatseeker,” which uses heat to boil a working fluid inside a vessel to produce a high pressure vapor. The elevated pressure is used to expel a hydraulic fluid from the vessel, which is then used to drive a hydraulic motor for electricity production. These technologies are in the early stages of commercialization. 4.6.2 Performance Characteristics Due to the stage of development, no industrial performance data is available. Developers estimate the systems to be between 20 to 40% efficient, depending on operating conditions. 4.6.3 Technical Issues Little operational experience is available, however, some testing has been completed to validate the concept. Natural Energy Engine prototypes have been validated in a number of tests. The US Department of Energy completed successful testing at its Rocky Mountain Oil Testing Center, using the NE Engine to pump oil while powered by only 80oC water. The US Department of the Interior conducted successful tests using the engine to pressurize salt water processed through a reverse osmosis membrane to produce drinking water.



October 2007

4.6.4 Costs No commercial models are available, but the future projected installed cost is around $1500/kW to $2000/kW. 4.6.5 Suppliers The companies developing these technologies are:

• Deluge Inc.—Natural Energy Engine • Encore Clean Energy—Heat Seeker

4.7 Other Technical Considerations

4.7.1 Cooling Medium As previously established, cycle efficiency is dependent on the waste heat source temperature. Another factor affecting system efficiency is the temperature of the cooling medium. Carnot theory states that the theoretical maximum efficiency depends on both the hot reservoir and cold reservoir temperatures.

H

c

TT

−= 1maxη

where: ηmax is maximum thermal efficiency Tc is the average temperature of the cooling medium TH is the average temperature of the heat source As shown below, the relative impact of cooling medium temperature becomes increasingly significant as the heat source temperature decreases. In this example, the relative change in Carnot efficiency is shown if the cooling medium temperature is decreased from 20 oC to 5 oC.

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0%

10%

20%

30%

40%

50%

60%

0 50 100 150 200 250 300T Hot

Car

not E

ffici

ency

0%

5%

10%

15%

20%

25%

30%

% E

ffici

ency

Incr

ease

T Cold = 5C T Cold = 20C Efficiency Increase

Figure 4.16 Effect of Cooling Medium Temperature on Carnot Efficiency In practice, low coolant temperature effectively reduces the backpressure on the turbine. This improves power output and thus cycle efficiency by permitting additional expansion in the turbine. Another benefit of low coolant temperatures is that the working fluid may be cooled to a lower temperature, which in turn can recover additional energy from the waste heat source, resulting in greater waste heat utilization. Cooling equipment can be classified as either wet or dry. Wet technologies take advantage of the evaporative cooling effect, and include wet cooling towers, evaporative fluid coolers and evaporative condensers. Evaporative fluid coolers and evaporative condensers involve spraying water and blowing air over the external surface of a tube bundle, while the internal fluid being cooled is kept isolated. In open cooling towers, air contacts the water being cooled directly. Wet cooling can achieve lower temperatures than dry cooling because the fluid temperature may approach the ambient wet bulb temperature instead of the higher dry bulb temperature. The approach temperature (the difference between the cold fluid exit temperature and the ambient wet bulb temperature) is typically between 5oC and 10 oC. The air in Alberta and Saskatchewan is quite dry, so wet bulb temperatures are low, and wet cooler performances benefit. In power generation, a small approach is desirable to improve the cycle efficiency and maximize power output. The trade-off, as illustrated in Figure 4.17, is the additional capital cost of the cooling tower to achieve the lower cooling medium temperature.

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Figure 4.17 Effect of Chosen Approach on Tower Size (Source: SPX Cooling Technologies, 2006)

Evaporative cooling consumes water and is therefore only an option when makeup water is available at the site. Regulatory and permitting issues must be considered. Other disadvantages of wet cooling include the need for chemical treatment facilities and the disposal of cooling tower blowdown. When water is not available on site for economic or environmental reasons, dry air cooling must be employed for the power cycle condenser. Options include air cooled fluid coolers, where an intermediate fluid is then run to the condenser, or air cooled condensers, where the working fluid is condensed directly. The condensing temperature achievable with air cooled technologies is limited by the higher dry bulb ambient temperature, and performance is hindered further by the lower convective heat transfer properties of air. The cold side approach to ambient dry bulb temperature is typically 10 to 15oC. Air cooled condensers do have a potential operating advantage in winter in certain instances. Some working fluids have very low freezing temperatures, so the condenser may be operated below 0oC during extreme winter temperatures. This would allow lower condenser pressure and greater work output, and could offset the negative impact of air cooling during the warmer months.

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4.7.2 Condensing Heat Exchangers Standard design practice when recovering heat from exhaust gas is to maintain temperatures in the gas path above the acid and moisture dew points to avoid corrosion from condensation of the products of combustion. The acid dew point varies depending on the fuel sulfur content, flue gas moisture content, excess combustion air, and other factors, and is usually between 100oC and 200oC for many fuels. The moisture dew point is a function of the water concentration in the flue gas, and is typically between 50 oC and 60oC for gas-fired applications. By cooling flue gas below the water dew point, it is possible to capture a portion of the latent heat from the exhaust. As water vapor condenses, heat is released at a rate of 2.3 MJ per kg of water. Boiler efficiency can be increased to above 90% by capturing extra sensible and latent heat, as wet and dry flue gas losses are reduced. The figure below provides and example of the additional potential latent and sensible heat recovery from a gas-fired, 150,000 kg/hour steam generator. Heat exchanger inlet conditions are assumed to be 200oC with a water dew point of 56oC. Cooling flue gas to 50oC is easily achievable using an ORC cycle with an air cooled condenser. Lower temperatures would be possible at low seasonal temperatures or by using alternate cooling equipment.

OTSG Heat Recovery using a Condensing Heat Exchanger

0

2000

4000

6000

8000

10000

12000

40 60 80 100 120 140 160

Flue Gas Exit Temperature (C)

Hea

t Rec

over

ed (k

W)

Sensible Heat Absorbed kW Total Heat kW

Acid and Water Condensation

No Acid or Water Condensation

Acid Condensation only

Figure 4.18 Increased Heat Recovery using a Condensing Heat Exchanger (Natural Gas with 15% excess air, 150,000 kg/hr Steam Generator, Cooling from 200 oC)

Condensing heat exchangers are available that are designed to withstand the corrosive effects through material selection. Some materials used include:

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October 2007 File: 20819/1 37

• Teflon coatings • FRP • Some stainless steel alloys • Aluminum

Other latent heat recovery designs have involved direct contact between the flue gas stream and the cooling medium using a spray tower configuration. The advantage of this design is lower costs, however, fouling of the heated water with the products of combustion may make this approach unfeasible.

Some potential drawbacks / design considerations of using condensing heat exchangers include:

• Expensive materials of construction increase the cost of a condensing heat exchanger to approximately three times that of a conventional exhaust heat exchanger of a similar size. Specific costs for equipment supply are typically between 35 and 110 $/kWth duty depending on exhaust conditions, approach temperatures and size of the installation.

• Low inlet temperatures are required for the heat recovery stream in order to maximize latent heat recovery, considering the water dewpoint will be in the 60

oC area. This could create pinch issues in some applications. The condensing temperatures in ORC and Kalina cycles can be well below this threshold, so recovery of latent heat is possible.

• Exhaust temperatures are significantly lower than is typical for flue gases. This will have a significant impact on dispersion and will influence stack height requirements.

• The condensed water from the flue gas is potentially acidic, and requires handling through disposal or recycle.

• Due to material limitations, some equipment has a maximum exhaust inlet temperature of only 260oC.



October 2007 File: 20819/1 38

5. ELECTRICITY PRODUCTION & GRID INTERCONNECTION

Most waste heat projects applicable to the oil and gas industry will be less than 5 MWe of capacity. Projects on this scale would normally be used to supplement internal electrical consumption, thus offsetting purchased electricity costs, or could produce surplus electricity for sale directly to the distribution system. This section deals with the requirements for distributed generation installations and issues around electricity purchase and supply.

5.1 Electricity Industry Background

5.1.1 Alberta The electricity industry in Alberta has three main components: generation, transmission and distribution, and retail. Electrical generation and retail in Alberta is deregulated, while transmission and distribution remains regulated. The Alberta Electric System Operator (AESO) is the province’s independent system operator, responsible for running the interconnected electric system and facilitation of the wholesale electricity market. The AESO is a non-profit organization that contracts with the owners of transmission and distribution infrastructure for transmission services. Access to transmission and distribution is open and electricity can be sold to the spot market through the power pool. Waste heat power generation projects in Alberta would be required to undergo the following general steps (AESO, 2005):

1. An application must be submitted to the Alberta Energy and Utilities Board (AEUB) for installation of an electric generator. Generators with a capacity less than one megawatt can submit a short application, GB-2000-03, “Application for a Small Generator.”

2. The appropriate Wires Owner application process must be completed. The

design of the proposed facility will have to comply with the Wires Owner’s detailed interconnection requirements. Technical requirements for interconnection are dealt with in more detail in Appendix A. Wire Owners in Alberta include:

• ENMAX, which serves Calgary, Red Deer, Lethbridge, Cardston, Fort

MacLeod and Crowsnest Pass • EPCOR, which serves Edmonton and Ponoka • ATCO, which serves primarily northern and east central Alberta • Fortis, which serves the remainder of Alberta



October 2007

3. If the power is to be exported to the grid for sale through the wholesale market, registration with the AESO as a market participant is required. All sold generation in Alberta clears through the AESO. Information on becoming a market participant is available at www.aeso.ca

The spot price for electricity has been relatively volatile in Alberta, especially directly following deregulation. There is considerable variability in the price from year to year, month to month and hour to hour. The following figures provide some historical data on spot pricing over the past several years.

Table 5.1 Historical Alberta Wholesale Pool Prices

$/MWh 2002 2003 2004 2005 2006 Avg.

2003 to 2006

1st Half 2007

Average 43.93 62.99 54.59 70.36 80.79 62.53 56.80 On Peak 56.04 75.54 64.54 86.86 104.99 77.59 72.1 Off Peak 28.47 46.98 41.88 49.28 49.67 43.26 36.76

(Source: AESO Annual Report, 2006)

Note the variation between on-peak and off-peak prices. On-peak hours are from 8AM to 11PM on Monday through Saturday. In addition, significant variation is typical from month to month due to factors such as weather and timing of planned generation outages.

Average Pool Prices

0.00

50.00

100.00

150.00

200.00

250.00

300.00

350.00

400.00

2000 2001 2002 2003 2004 2005 2006

$/M

Wh

Figure 5.1 Historical Alberta Spot Market Prices for Electricity (Source: AESO Annual Report, 2006)

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http://www.aeso.ca/



October 2007 File: 20819/1 40

For generators selling surplus electricity into the market, the actual amount received for electricity will be based on the powerpool pricing during the time period. In addition, adjustments stemming from transmission loss factors will likely be passed on to the generator if surplus electricity is supplied to the distribution system. The loss factor depends on the generator’s location, and is intended to account for losses of power during the transmission and distribution. Note that loss factors can be negative or positive—distributed generation, by placing the generation near the load, can actually reduce transmission losses. Purchasers of electricity must also bear the costs associated with the transmission system. Additional costs charged to electrical loads average around $11/MWh and are applied over and above the powerpool price. Therefore, distributed generation that offsets purchased electricity reduces the costs associated with transmission in addition to the bare electricity charge. Options to avoid the volatility of the spot market are available for both generators and purchasers of electricity. A wide variety of short and long-term products are available for purchasers.

5.1.2 Saskatchewan SaskPower is the crown utility in Saskatchewan and is responsible for electrical generation, transmission and distribution in the province. In 2001, SaskPower opened Saskatchewan’s limited wholesale electricity market to competition through the posting of an Open Access Transmission Tariff (OATT). The OATT provides access, for a fee, to the transmission system to wheel power through Saskatchewan or to sell to SaskPower’s two wholesale customers—the City of Swift Current and the City of Saskatoon. SaskPower has no obligation to purchase independently generated electricity, but indicates that all viable options are evaluated in terms of need and economic opportunity. As part of its Environmentally Preferred Power (EPP) program, SaskPower recently entered into agreements to purchase electricity from four 5MW waste heat projects installed at Alliance Pipeline compressor stations in the province. Current electricity prices (to purchase from SaskPower) depend on the applicable rate code. For the “Oilfields—Standard” rate, which applies to field processing facilities, the cost consists of an energy charge (5.062 ¢/kWh) plus a demand charge of $11.32 per kVA of billing demand each month. This would equate to approximately 7.3 ¢/kWh for facility with a maximum demand of 100kW and an average load of 70kW over a one month period. The current purchase price offered by SaskPower for electricity generated with no



October 2007 File: 20819/1 41

incremental greenhouse gas emissions is unknown, as projects are reviewed on a case by case basis. The establishment of the EPP and SaskPower’s support of recent waste heat power generation projects is encouraging for the deployment of waste heat technologies in the province.

5.1.3 British Columbia

BC Hydro and BC Transmission Corporation are the crown utilities in BC responsible for electrical generation, transmission and distribution in the province. There is no obligation to purchase independently generated power, however, BC Hydro is currently in the process of developing a Standing Offer Program for clean electricity projects up to 10 MW. This initiative was directed by the provincial government in the “BC Energy Plan: A Vision for Clean Energy Leadership.” In addition, BC Hydro has held a number of “Calls for Power” over the past several years, in which proposals from independent power producers are considered and winning bidders are offered Power Purchase Agreements. Waste heat power generation facilities have been proposed for mainline compressor stations on a major pipeline in the province, each with an approximate capacity of 5MW. Current electricity prices (to purchase from BC Hydro) depend on the applicable rate code and location within the province. Medium industrial customers pay both an energy charge and a demand charge per kW of billing demand each month. As an example, this would equate to approximately 4.8 ¢/kWh for facility with a maximum demand of 100kW and an average load of 70kW over a one month period.

5.2 Options for Produced Power

Produced electricity can be used internally by the operation to reduce purchased electricity costs. If surplus is available, over and above that required to meet internal demand, electricity can be sold into the market. Electricity billing is normally composed of both an energy charge and a demand charge. The energy charge is for the amount of electricity consumed, and the demand charge is the cost of servicing the peak demand of the operation. The demand component is typically set by either the contract capacity or the actual peak, if greater than 90% of the contract value. To provide back-up to on-site generation, most loads would likely maintain their electricity supply contracts and would continue to pay the demand component of their contract. The sale of surplus electricity would be to the provincial utility in Saskatchewan and BC, most likely via long-term power purchase agreements, which would alleviate exposure to volatility in the electricity markets.



October 2007 File: 20819/1 42

In Alberta, electricity can be sold into the spot market, in which pricing is variable. If the generator wishes to stabilize the cost benefits of a generation project, options are available to hedge against downside in the spot market. Contracts for Differences (CFD) can be entered in which a fixed price is established between buyer and seller—if the average pool price for the period is higher than the agreed CFD price, the seller would issue payment to the buyer for the difference. Likewise, if the average pool price for the period was lower than the CFD price, the buyer would pay the difference to the seller. For the purposes of this study, an “all-in” average electricity value between $75/MWh and $85/MWh has typically been used in the economic assessments, based on the foregoing review of Western Canadian electricity pricing.

5.3 GHG Implications 5.3.1 General Implementation of waste heat power generation projects indirectly results in greenhouse gas (GHG) reductions. While the process producing the waste heat may continue to operate as usual and emit GHG’s, the installation of waste heat recovery and power generation produces additional electricity that results in no incremental GHG emissions. In turn, an equivalent amount of electricity that would have otherwise been supplied via the grid is no longer required. Depending on the electricity generation profile in the region, the result is GHG emissions reductions, assuming that it is fossil fuel-fired generation that is being offset. While future regulations and economic impacts are currently uncertain in Canada, it is likely (as in Alberta) that GHG emissions will soon have a concrete economic impact on industrial operations. The purpose of this section is to discuss likely economic impacts of GHG policy on waste heat power generation projects. 5.3.2 Policy Background Canada is a signatory to the Kyoto Protocol and has committed to substantial greenhouse gas reductions in principle, however, the applicable regulatory requirements and implementation mechanisms are currently uncertain. In 2007, the Federal government released the Regulatory Framework for Air Emissions, which outlined a plan for achieving GHG reductions over the short and long term. In general, incentives for reduction will be provided by using economic instruments which attach a price to each unit of GHG emission. The compliance options available to emitters will likely include in-house reductions, emissions trading and contributions to a



October 2007 File: 20819/1 43

technology fund based on excess emissions. The specifics of the plan and the timeline for ultimately implementing mandatory programs and requirements remain unclear. In Alberta, the Climate Change and Emissions Management Act (and the associated Specified Gas Emitters Regulation) was brought into effect in 2007. The regulations apply to facilities with direct emissions of 100 kT or more, and require continuous improvement in GHG emissions intensity per unit of production. Compliance can be accomplished through the following options:

• In-house emissions reductions • Purchase of credits through contribution to the Climate Change and Emissions

Management Fund, at a price of $15/tonne CO2e • Purchase of Emission Performance Credits, which are held by facilities which

reduced their emission intensity beyond the mandatory requirements • Purchase of Emission Offsets, which are verifiable emission reductions achieved

by facilities not subject to the mandatory intensity limits Details on the required quantity of emissions reductions and other details of the Alberta program are available at www3.gov.ab.ca/env/climate. 5.3.3 Potential Impact on Project Economics Waste heat power projects could potentially benefit from GHG initiatives, considering that they result in additional electricity generation with no incremental GHG emissions. Waste heat power projects could produce Emissions Offsets by offsetting electricity that would have otherwise been produced with fossil fuels. The actual emissions reductions are dependent on regional factors, such as the dominant generation technology and the type of fuel used to meet marginal demand. Table 5.2 illustrates the potential economic impact based on average grid intensity and a price of $15 per tonne CO2e.

Table 5.2 Potential Effect of GHG Price on Electricity Value

Province Average Grid Intensity1 Impact on Price at $15/tonne CO2e

Alberta 0.861 tonne / MWh $12.92 / MWh Saskatchewan 0.840 tonne / MWh $12.60 / MWh

British Columbia 0.024 tonne / MWh $0.36 / MWh 1 Average Intensity from National Inventory Report, Greenhouse Gas Sources and Sinks in Canada, Environment Canada, 2006 It should be noted that actual GHG offsets from waste heat projects would depend on the

http://www.gov.ab.ca/env/climate



October 2007 File: 20819/1 44

actual type of generation offset by the project. For example, while the average intensity in British Columbia is very low due to the abundance of hydroelectric generation, marginal generation could in fact be provided by fossil-fuel fired capacity. Waste heat projects could therefore result in GHG emissions reductions in excess of that indicated by assuming the average grid intensity. Likewise, in Saskatchewan and Alberta, where the marginal generation is typically gas-fired, waste heat projects may result in GHG emissions reduction less than that indicated by assuming the average grid intensity. When the impact of GHG permits is considered in this study’s evaluations, it is generally assumed that CO2 is valued at $15/tonne, and that emissions are offset at a rate of 0.85 tonne per MWh, unless otherwise noted.

5.4 Grid Interconnection Requirements Refer to Appendix A—Grid Interconnection, which discusses the technical requirements for distributed generation installations, and the associated capital costs for electrical equipment outside the scope of the power generation island.



October 2007

6. EVALUATION METHODOLOGY

This section outlines the assumptions and methodology used for the scoping evaluations of power generation from various oil and gas industry waste heat streams. The results of the scoping evaluations are summarized in Section 7.

6.1 Performance Modeling Unless otherwise noted, base-case plant thermal efficiency for this study is based on reference data for organic rankine cycle plants. ORC has been chosen as the base-case technology for the following reasons:

• Applicable across the entire range of temperatures encountered • High degree of commercialization • Uptake in the oil and gas industry already exists • Several available vendors

The thermal efficiency correlations developed provide indicative estimates, as performance will ultimately depend on cycle configuration and operating conditions. During detailed assessment of specific projects, technology comparisons, heat and mass balances and system optimization study would be required to more accurately establish the expected system output.

Organic Rankine Cycle - Reference Performance DataNET THERMAL EFFICIENCY (<150C)

y = 0.1181Ln(x) - 0.4714

0%

5%

10%

15%

20%

25%

30%

80 90 100 110 120 130 140 150

Waste Heat Temp (C)

Net

Eff

icie

ncy

(%)

Figure 6.1 Correlation for ORC Efficiency (<150°C)

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Organic Rankine Cycle - Reference Performance DataNET THERMAL EFFICIENCY (>150C)

y = 0.0315Ln(x) - 0.0344

0%

5%

10%

15%

20%

25%

30%

100 200 300 400 500 600

Waste Heat Temp (C)

Net

Eff

icie

ncy

(%)

Figure 6.2 Correlation for ORC Efficiency (>150°C)

Note that “net efficiency” accounts for the internal parasitic electrical load of the power cycle’s auxiliary equipment, and is defined as the ratio of net electrical output, in kW, and the energy absorbed from the waste heat stream, in kW. It does not consider the portion of the available energy in the waste heat stream that is recovered.

6.2 Economic Modeling 6.2.1 Approach and Key Assumptions For assessing economic viability, a discounted cash flow analysis is conducted for each scenario being analyzed. The primary indicator provided for financial performance and comparison against other options is pre-tax Internal Rate of Return (IRR). The following key assumptions have been used:

• Cash flows are assumed to occur at the end of each year • Construction costs are incurred on an “overnight” basis • Project life is 20 years • The project costs are covered by 100% equity—no debt financing or equipment

leasing is considered • Escalation of annual revenues (or cost savings) and operating costs is assumed to

be 2% per year • No cost associated with lost production during construction is considered—it is

assumed that construction of any new waste heat projects would be coordinated with planned outages as required to avoid unnecessary disruption to existing facilities

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October 2007

6.2.2 Revenue / Cost Savings Estimates Revenue or cost savings of the project are estimated based on the predicted plant net electrical output and the annual average load factor. The load factor will be impacted by the availability and capacity utilization of the process generating the waste heat, as well as the availability of the power generation equipment itself. Annual average load factors vary considerably (50 to 80% is typical for the various processes generating the waste heat) and this is a variable that has been examined for its impact on overall project economics. Availability of the power generation unit is typically in excess of 95%. Value of electricity (either sales price or cost of offset electricity) and value of greenhouse gas emissions offsets are the other primary variables impacting revenue / cost savings. Two pricing scenarios are most commonly used in the evaluations:

• Low Case: $75/MWh + $0/tonne CO2 equivalent • High Case: $85/MWh + $15/tonne CO2 equivalent

6.2.3 Capital Cost Estimates Capital cost correlations have been developed for waste heat projects in order to assess the economics over a range of project sizes and scenarios. Cost estimates are based on a combination of reference prices in the literature, vendor budgetary quotations, and other cost data, and pricing has been adjusted, if necessary, to reflect typical balance of plant costs not included in the costs of the main power generation package. Cost estimates are for total “all-in” installed capital costs, including equipment supply and erection, commissioning, engineering and administration costs. An exchange rate of 1.1 CAD per USD and an escalation rate of 2% per year have been used to bring reference costs to 2007 CAD. The impact of plant capacity on installed capital cost per kW has been estimated using the ratio method of scaling.

n

k

xkx E

ECC )(= Where: Cx = cost of plant/equipment of size Ex

Ck = known cost of plant/equipment of size Ek n = cost capacity exponent

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October 2007 File: 20819/1 48

Cost estimates are indicative only. Numerous project and site-specific factors can significantly impact installed capital costs. These include, but are not limited to:

• Variations in waste heat stream characteristics • Complexity of retrofit requirements • Site conditions • Site integration issues, including the use and capacity of existing utilities etc. • Volatility in raw material costs • Distance to distribution system, if applicable • Labor rates and labor productivity

Regarding labor rates and productivity, the current cost pressures in Western Canada (and Northern Alberta in particular) can have a major impact on capital cost. Many of the reference costs used to develop the cost correlations are from elsewhere in North America, so an “Alberta Premium” has been applied. The correction factor is based on the following assumptions:

• Construction labor typically represents 20% of total, installed capital costs (Mines, 2006) and is the portion of the reference costs subject to the premium. This relatively low ratio for construction labor is due to the high degree of modularization typical of waste heat power generation plants.

• Average hourly labor rates for skilled trades, including overhead, profit, small tools, consumables, construction equipment and temporary site facilities is 20% higher than the US average. This premium can be substantially higher in cases where high travel and construction camp costs are incurred at northern mega-project sites.

• Average productivity ratios in Alberta, versus a Gulf Coast basis, range between 1.2 and 3.0 depending on the location, trade, time of year and other factors. An average productivity of 1.6 has been assumed.

Separate cost curves are provided for projects with flue gas and liquid or condensing waste heat streams. Recovering waste heat from flue gas streams is typically more expensive due to lower heat transfer coefficients and the relatively large heat exchangers required. Cost correlations used in the scoping evaluations are provided in Figures 6.3, 6.4 and 6.5.



October 2007

TOTAL CAPITAL COSTSFlue Gas Waste Heat Source

-1,0002,0003,0004,0005,0006,0007,0008,0009,000

0 1000 2000 3000 4000 5000 6000

Plant Output (KW)

Plan

t Cos

t ($/

KW

)

Including Alberta Premium

Reference Costs

Figure 6.3 Effect of Plant Size on Total Capital Cost (Flue Gas Waste Heat Source)

TOTAL CAPITAL COSTSLiquid or Condensing Waste Heat Source

-1,0002,0003,0004,0005,0006,0007,0008,000

0 1000 2000 3000 4000 5000 6000

Plant Output (KW)

Plan

t Cos

t ($/

KW

)

Reference Costs

Including Alberta Premium

Figure 6.4 Effect of Plant Size on Total Capital Cost (Liquid Waste Heat Source)

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October 2007

Capital Cost Temperature Correction Factor(Liquid Waste Heat Source)

0.6

0.8

1

1.2

80 100 120 140 160 180 200

Temperature (C)

Cap

ital C

ost F

acto

r

Figure 6.5 Capital Cost Temperature Correction (Liquid Waste Heat Source) The above temperature correction factor is to account for the improved efficiency and output for higher temperature waste heat streams, which typically results in lower specific per kW installed costs. 6.2.4 Operating Cost Estimates Operating and maintenance costs are typically between 0.5 and 1.5 ¢ per kWh for packaged waste heat power generation systems. For the purposes of this study, limited incremental O&M labour requirements are assumed and an average variable O&M cost of 1.0 ¢ per kWh has been taken in base-case analyses, unless otherwise noted. Fixed general and administrative operating costs (taxes, insurance etc.) are taken as 0.5% of the plant total capital cost.

6.2.5 A Note on Return on Investment Expectations The power generation industry is characterized by high capital costs and long-life projects. Similar to energy efficiency initiatives, even economically feasible waste heat power generation projects may not appear overly attractive when compared to competing alternatives to capital investment in the oil and gas industry.

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In order to frame expectations, consider a simplified analysis of an optimistic waste heat power generation case:

• Installed capital cost: $2,800/kW • Average load factor: 90% • Power price: $0.10/kWh • Operating Costs: $50/kW-yr

Annual revenue per installed kW is approximately:

(0.9)(8,760 hr/yr)(1kW/kW)($0.10/kWh) – ($50/kW-yr) = $740/kW-yr

This yields a payback of approximately 3.8 years, or a simple IRR of about 26%. Certainly it is a feasible investment on economic terms, but how will it stack up against other projects competing for capital funding? It is likely that other drivers, such as a requirement for significant reduction in greenhouse gas intensity, will be necessary to truly spur widespread utilization of waste heat to power technology in the oil and gas industry.



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7. WASTE HEAT SOURCE SCOPING EVALUATIONS

The following sections describe some of the major sources of waste heat in the upstream oil and gas industry. Typical ranges for temperature and magnitude are provided for each waste heat source in order to characterize its potential for power production, and some of the key issues around each application are discussed.

7.1 Reciprocating Engines 7.1.1 Sources

Reciprocating engines are widely used in the upstream oil and gas industry, primarily for gas compression. Reciprocating engine driven applications are estimated to be one of the largest consumers of fuel gas in the upstream industry, indicating a very large potential source of waste heat. The most commonly used models range up to around 3000hp. Gas-fired engines are typically 30 to 40% efficient on an LHV basis. While dependent on engine type, manufacturer and operating conditions, typical ranges for the engine energy balance are provided below:

Table 7.1 Typical Reciprocating Engine Energy Balance

Mechanical Power 30 – 40% Heat Rejected to Cylinder Cooling 25 – 40% Heat Rejected to Oil Cooling 3 – 5% Heat Rejected to Turbo Cooling 4 – 9% Heat Rejected to Exhaust 25 – 30% Surface Heat Loss 3 – 6%

(Source: GPSA Data Book and manufacturer literature) Exhaust gases and jacket water represent the largest heat sources available for recovery. Heat recovery configurations, whether for thermal energy or power production, must consider the temperature differences of the waste heat sources – jacket water and lube oil temperatures are at considerably lower temperatures than the exhaust gases. An example of a heat recovery arrangement is illustrated below:



October 2007

Lube Oil Cooler

Heat Utilization (Process Heating,

Power Production etc.)

Exhaust

Engine

Thermal Oil Pump

WASTE HEAT

WASTE HEAT

Jacket Water Cooler

Figure 7.1 Simplified Recip Heat Recovery Schematic (Example) 7.1.2 Typical Waste Heat Characteristics A wide range of engine sizes are deployed in the industry, with engines up to around 3000hp common. Exhaust gases are typically in the range of 400°C to 600°C. The relatively high temperature makes exhaust gas the most important source of heat recovery for power generation applications in order to improve the efficiency of the power cycle. Depending on the air to fuel ratio for the particular engine model, exhaust gas flows are usually between 3 and 6 kg/hr per bhp at full load. Jacket water is the other main source of waste heat, but with outlet temperatures of 80°C to 90°C, it typically would be used as a preheating medium in waste heat power generation applications. 7.1.3 Technical Issues Depending on the characteristics of the engine, the most cost-effective configuration of the power cycle could vary—an optimal balance between maximizing jacket water heat recovery and working fluid temperature must be determined. This should be assessed on a model by model basis. In order to maintain reliability, the system would be designed so that an outage of the power generation unit would not impact the availability of the engine. Heat exchange between the jacket water loop and power generation cycle would be in parallel with the engine radiator, and exhaust heat recovery could incorporate bypass arrangements if warranted.

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October 2007

Acid dewpoint issues must be considered for exhaust heat recovery equipment for engines using fuel gas containing sulphur. The future utilization of compression due to possible production declines must be considered against the investment in power generation equipment. Reductions in compression loading will result in decreased power output, impacting the economics of waste heat power generation. 7.1.4 Summary of Potential Reciprocating engines are the largest fuel gas consumer in the upstream oil and gas industry, with recent estimates suggesting that over 270 million GJ per year is consumed. (Clearstone, 2005). Combined with relatively high exhaust gas temperature, this indicates that reciprocating engines could be a high-impact source of waste heat. The biggest challenge is the fact that reciprocating engines are widely dispersed throughout the NG gathering and processing infrastructure, and are small scale opportunities when considered individually. Figure 7.2 provides an estimate of electrical output from waste heat power generation against engine horsepower. The graph is based on an exhaust gas flow of 4.8 kg/hr per bhp cooled from 420°C to 115°C, with a portion of the jacket water heat also recovered.

RECIP ENGINESPower Output from Heat Recovery

0

100

200

300

400

500

0 500 1000 1500 2000 2500 3000

Engine Horsepower

Net

Pow

er O

utpu

t (kW

e)

Figure 7.2 Power Output from Recip Engine Heat Recovery Figure 7.3 provides estimates of financial performance against engine horsepower for a range of capital costs, assuming an annual average loading of 70%, electricity value of

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October 2007

$85/MWh and GHG value of $15/tonne CO2e. The relatively small scale of the power generation units result in a high installed cost per kW and poor predicted returns.

RECIP ENGINES

0

5

10

0 500 1000 1500 2000 2500 3000

Engine Horsepower

IRR

(%)

-20% capital cost

+20% capital cost

Figure 7.3 Recip Engine Financial Performance (Load Factor 70%, $85/MWh + GHG value of $15/tonne CO2e)

It is worth noting that there is good potential for lowering capital costs for an application like reciprocating engines. There are a number of very commonly used engine models in the industry, and by pairing “cookie-cutter” power generation units with specific engine models, substantial cost savings could be achieved. This would obviously require uptake by the oil and gas industry for these cost savings to develop. Another area where economics could improve is in scenarios where several reciprocating engines are operating at a single site. Waste heat from individual jacket water and exhaust systems could be marshaled together to improve the economy of scale of project.

7.2 Gas Turbines

7.2.1 Sources Gas turbines are used extensively in the gas industry for compression. Models less than 10,000 hp are most common in upstream applications. One of the most widely deployed applications for waste heat power generation to date is on gas turbine exhausts in the midstream gas industry, where mainline compressors are often greater than 25,000 hp. Gas turbines operating at rated output are normally between 25% and 40% efficient. The efficiency generally improves with increasing rated capacity. Given that gas turbines are widely used and have a relatively high temperature exhaust stream, waste heat recovery

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October 2007

has good potential for financial viability. 7.2.2 Typical Waste Heat Characteristics Exhaust gas temperatures are typically in the range of 400°C to 550°C. Due to blade material limitations, large quantities of excess air are used to moderate temperatures in the gas path. Exhaust gas flows generally fall between 8 and 15 kg/hr per hp.

7.2.3 Technical Issues Considerable variation in power output occurs with ambient temperature, as turbine output increases with declining inlet air temperature. Figure 7.4 provides an example of temperature correction for Ormat’s Energy Converter for gas turbine applications.

Figure 7.4 Power Output Ambient Temperature Correction Factors (Example) (Source: Ormat)

In order to maintain reliability, the system would be designed so that an outage of the power generation unit would not impact the availability of the turbine. Exhaust heat recovery could incorporate a bypass stack. Some designs utilize an intermediate hot oil loop to transfer heat from the exhaust gas stream to the working fluid evaporator.

7.2.4 Summary of Potential The following graph provides an estimate of electrical output from gas turbine exhaust heat recovery, for exhaust temperatures between 400°C and 500°C. The results assume that flue gases are cooled to 115°C. For reference, 20 kg/s of exhaust flow would be typical for around a 5000 hp turbine, and a 30,000 hp turbine would have an exhaust flow of around 70 kg/s.

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October 2007

GAS TURBINESPower Output from Exhaust Heat Recovery

0

1500

3000

4500

6000

0 25 50 75

Exhaust Flow (kg/s)

Net

Pow

er O

utpu

t (kW

e)

400C 500C 450C

Figure 7.5 Power Output from Gas Turbine Exhaust Heat Recovery

Figure 7.6 provides an estimate of financial performance versus turbine exhaust flow for a range of capital costs. Larger units have decent potential with returns of greater than 15% readily achievable.

GAS TURBINES

0

5

10

15

20

25

0 25 50 7

Exhaust Flow (kg/s)

Pret

ax IR

R (%

)

5

-20% capital cost

+20% capital cost

Figure 7.6 Gas Turbine Financial Performance ($85/MWh + $15/Tonne CO2e and 70% Load Factor)

Figure 7.7 illustrates the significance of high average loading on the turbines on project economics. This is for a relatively small turbine (20 kg/s exhaust flow, roughly equivalent

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October 2007

to a Solar Centaur) and it is evident that in this size range highly utilized turbines must be targeted.

GAS TURBINES

0

5

10

15

20

25

50 75 100

Annual Load Factor (%)

Pret

ax IR

R (%

) $100/MWh + $20/T CO2

$75/MWh + $0/T CO2

Figure 7.7 Impact of Load Factor on Gas Turbine Financial Performance (Based on exhaust gas flow of 20kg/s)

7.3 Fired Heaters

7.3.1 Sources Fired Heaters are commonly used in the oil and gas industry for heating a fluid medium. It has been estimated that they consume 25% of fuel gas used in upstream processes of the Canadian oil and gas industry (Jachniak, 2005). Some applications include:

• Line Heaters • Reboilers • Oil Treaters • Tank Heaters • Propane, Butane or LPG Evaporators

Immersion heaters generally consist of a horizontal fire-tube immersed in a fluid bath. Heaters are usually operated intermittently, and the bath acts as a heat storage medium which is released between firings.

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October 2007

Figure 7.8 Typical Immersion Fire-Tube Heater (Source: Jachniak, 2005)

7.3.2 Typical Waste Heat Characteristics Exhaust gases from fired heaters are typically in the range of 425 to 600°C, depending on the bath temperature and design approach. Rated duties of 150,000 BTU/hr to 12 mmBTU/hr (44 kWth to 3.5 MWth) are common. Most fired heaters have efficiencies between 65-80%. Depending on the heater efficiency and excess air, exhaust gas flows are on the order of 0.5 to 1.3 kg/s per MWth of duty. 7.3.3 Technical Issues The waste heat available for power generation in the heater exhaust is depends on the efficiency of the unit. Improving fired heater efficiency (and reducing the waste heat available in the first place) should be the first priority. In addition to combustion optimization, options include heat transfer surface modification, or fuel or combustion air preheating. The PTAC-facilitated “Improved Immersion Fire-Tube Heater Efficiency Project” is a detailed assessment of efficiency opportunities. Many fired heaters are operated with an intermittent duty cycle such that the exhaust waste heat stream is not available continuously. Units operating with ON-OFF control are unsuitable for power generation. Some large fired heaters have multiple firetubes and stacks, which would result in additional capital costs to install exhaust heat exchange equipment.

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October 2007

7.3.4 Summary of Potential The following graph provides an estimate of electrical output from waste heat power generation for various fired heater duties and flue gas temperatures. The results assume that flue gases are cooled to 115°C, and that natural gas is combusted with excess air of 20%.

FIRED HEATERSPower Output from Heat Recovery

0

100

200

300

400

500

0 2000 4000 6000 8000 10000

Heater Duty (kWth)

Net

Pow

er O

utpu

t (kW

e)

150C 300C 450C

Figure 7.9 Power Output from Fired Heater Exhaust Heat Recovery

The potential for power generation from fired heater exhaust heat recovery is limited. A combination of factors, including frequent use of ON-OFF burner control, low project sizes (and thus high per kW capital costs) and low capacity utilization make the projects relatively unattractive. Figure 7.10 illustrates the economics are poor for even a relatively optimistic range of scenarios—a large fired heater (10MWth) with modulating control, with elevated stack temperatures and high capacity utilization.

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October 2007

FIRED HEATERS

-

5.0

10.0

15.0

20.0

50 60 70 80 90 100

Load Factor (%)

Pret

ax IR

R (%

)

300C 450C

Figure 7.10 Impact of Load Factor on Fired Heater Financial Performance (Based on 10MWth Heater Duty, $85/MWh + $15/Tonne CO2e)

Efforts to improve fired heater efficiency should focus on reduction of fuel consumption. Economic power generation opportunities will likely be limited to situations where waste heat from several units can be marshaled together to achieve improved economy of scale, or where power pricing is unusually high.

7.4 Steam Generators 7.4.1 Sources Steam generators are widely used in the upstream industry, with large scale installations required for in-situ bitumen production processes. SAGD facilities require large amounts of high pressure steam and typically use packaged, natural gas fired once-through steam generators (OTSG). The main source of waste heat is the steam generator flue gases. 7.4.2 Typical Waste Heat Characteristics Steam generators typical have efficiencies greater than 80% on an HHV basis, and stack temperature in the area of 200oC, depending on fuel characteristics and backend heat exchange configuration.

7.4.3 Technical Issues Air preheaters, which transfer heat from the flue gas downstream of the economizer to the combustion air, are not always used on packaged steam generators. Air preheaters improve the efficiency of the steam generator by reducing sensible heat losses from the

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October 2007

flue gas, typically by around 2% on an HHV basis. For steam generators using fuel containing sulphur, the acid gas dew point restricts the temperature to which the flue gas can be cooled to around 160oC, unless specialized heat exchangers which can resist the corrosive effects of condensing acid and moisture are used. 7.4.4 Summary of Potential Estimates for electrical output from flue gas heat recovery are provided below for varying steam generator duties. The results assume a steam generator efficiency of 84%, an organic rankine cycle, and that exhaust gas is cooled from 200oC to 160oC.

STEAM GENERATORPower Output from Heat Recovery

0

50

100

150

200

250

0 30000 60000 90000 120000 150000

OTSG Duty (kg/hr of Steam)

Plan

t Out

put (

kWe)

Figure 7.11 Power Output from OTSG Exhaust Heat Recovery (84% Efficiency, Flue gas cooled from 200oC to 160oC)

The figure below provides estimates of financial performance against steam generator capacity, assuming an annual average loading of 85%. The relatively small scale of the power generation units result in a high installed cost per kW and poor predicted returns.

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STEAM GENERATOR

0

5

10

0 30000 60000 90000 120000 150000


Pret

ax IR

R (%

)

$75/MWh $85/MWh + $15/tonne CO2e

Figure 7.12 OTSG Financial Performance (84% Efficiency, Flue gas cooled from 200oC to 160oC, Load Factor 85%)

Financial performance for this application can potentially be improved by the extent of flue gas cooling. With a condensing heat exchanger, the flue gas can be cooled to temperatures below the water dew point to capture additional sensible heat, and latent heat by condensing some of the water vapour. Another option to improve project economics is to combine waste heat streams to increase the size of the power generation module and reduce specific costs per installed kW. For example, and typical 40,000 BPD SAGD facility might have four 150,000 kg/hr steam generators. The following graphs illustrate the effect of flue gas exit temperature and combination of individual steam generator flue gas streams on output and financial performance.

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0

1000

2000

3000

4000

5000

6000

7000

40 60 80 100 120 140 160


Plan

t Out

put (

kWe)

Based on 4 x 150K kg/hr steam generators combined

Based on 1 x 150K kg/hr steam generators

Figure 7.13 Impact of Flue Gas Exit Temp on Power Output from OTSG Heat Recovery

STEAM GENERATOR

0

4

8

12

16

20

24

40 60 80 100 120 140 160


Pret

ax IR

R (%

)



Figure 7.14 Impact of Flue Gas Exit Temperature on OTSG Financial Performance (150000 kg/hr Steam Generator with a Condensing Heat Exchanger)

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7.5 Warm Produced Water 7.5.1 Sources The geothermal energy potential of the Western Canadian Sedimentary Basin (WCSB) has been the subject of considerable research, and the Geological Survey of Canada considers it to be the largest accessible warm water resource in the country. Due to existing oil and gas development, large quantities of warm water are currently being co-produced to surface with hydrocarbons and reinjected following processing. Taking advantage of existing infrastructure could potentially eliminate one of the major costs associated with geothermal power generation projects, where wells are drilled specifically to access and dispose of warm water resources. Produced water handling is an issue in all hydrocarbon production. In conventional oil operations in the WCSB the produced water-to-oil ratio is typically in the range of 1 to 10. (Peachey, 2004) As fields mature, produced water rates tend to increase, resulting in increased geothermal energy potential over time. Investigation into the energy potential of warm produced water was completed for the PTAC-facilitated Low Carbon Futures study, completed in March 2007. Much of the information in this section is taken from the data summaries provided in the Low Carbon Futures report. 7.5.2 Typical Waste Heat Characteristics Available warm produced water flows available for electricity production cover a wide range. Several fields in Alberta handle tens of thousands of m3 per day of produced water. The degree to which water handling is centralized is another important consideration in assessing the economics of power generation potential, as several smaller plants will likely be more costly than a single larger facility. On the other hand, temperature losses throughout the system will typically be reduced in cases where the water is separated and disposed of near the well. Produced water temperature also varies significantly. Temperature increases with depth, and generally the depth of the WCSB increases from east to west, resulting in higher available water temperatures. Formation temperatures for Alberta oil pools ranged from 21°C to 113°C, according to a recent review of publicly available oil pool data. 7.5.3 Technical Issues Technical options exist which reduce water co-production in the first place, including downhole separation and the use of blocking agents. In some cases, these options could prove more cost-effective than heat recovery, and they should be considered as

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October 2007

competing alternatives when assessing the best route forward. A characteristic of water production is that it tends to increase over time as a field matures. While incremental generation would have to be added to take advantage of the additional thermal energy available, the primary benefit is the safeguarding of the power generation investment—the owner can be reasonably assured that the waste heat available to the power generation unit will not decrease over time.

As with all low temperature waste heat sources, the relative significance of the available cooling medium temperature is higher and must receive additional consideration. 7.5.4 Summary of Potential Estimates for electrical output are provided below for varying warm produced water flows and temperatures. The results assume that an organic rankine cycle package is used, produced water is cooled to 40°C, and that brine density is 1,100 kg/m3.

WARM PRODUCED WATERPower Output from Heat Recovery

0

1000

2000

3000

4000

0 2000 4000 6000 8000 10000

Produced Water Flow (m3/day)

Net

Pow

er O

utpu

t (kW

e)

85C 100C 115C

Figure 7.15 Power Output from Warm Produced Water Heat Recovery (ORC, Cooled to 40°C)

The “Low Carbon Futures” report summarized the geothermal potential of several Albertan oil pools, in terms of produced water temperature and volumes. Table 7.2 provides an estimate of potential electrical power production from these pools, assuming a temperature loss of 5°C from the formation temperature, a brine outlet temperature of 40°C, and a predicted cycle efficiency based on the inlet temperature to the ORC package. Note that no site specific investigations were completed.

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Table 7.2 Alberta Oil Pools with Potential for Electricity Generation From Warm Produced Water1

Field / Pool Name Formation Temperature (°C)

Produced Water Rate (m3/day) Sept 2006

Electricity Potential (MWe)

Swan Hills / Beaverhill Lake A&B 104 54,039 13.1

Swan Hills South / Beaverhill Lake A&B 107 24,356 6.5

Judy Creek / Beaverhill Lake A 96 33,642 6.1

Virginia Hills / Beaverhill Lake 102 13,470 3.1

Kaybob / Beaverhill Lake A 113 7,025 2.2

Carson Creek / Beaverhill Lake A&B 88 14,519 1.9

Sturgeon Lake / D-3 88 13,631 1.8

Judy Creek / Beaverhill Lake B 97 7,679 1.5

Goose River / Beaverhill Lake A 110 4,104 1.2

Windfall / D-3 A 104 1,751 0.4

Simonette / Beaverhill Lake A 112 1,163 0.4

Snipe Lake / Beaverhill Lake 88 2,763 0.4

Meekwap / D-2 A 80 3,566 0.3

Innisfail / D-3 92 1,682 0.3

Kaybob South / Triassic A 86 1,770 0.2

Rainbow / Keg River B 85 1,701 0.2

Harmattan East / Rundle 85 1,511 0.2

Caroline / Rundle A 91 1,252 0.2

1 Modified from Table 13-Low Carbon Futures report



October 2007

The figures below provide an estimate of the economics of warm produced water power generation versus flow rate and power price. Increasing water temperature is a more important factor than flow rate, as it improves efficiency, available thermal energy and specific capital cost.

WARM PRODUCED WATER

0

5

10

15

20

25

30

0 2000 4000 6000 8000 10000


PreT

ax IR

R (%

)

85C 100C 115C

Figure 7.16 Warm Produced Water Financial Performance (ORC, Cooled to 40°C, Load Factor 80%, $85 per MWh + $15/Tonne CO2e)

WARM PRODUCED WATER

0

5

10

15

20

70 75 80 85 90 95 100 105 110 115

Electricity Price ($/MWh)

PreT

ax IR

R (%

)

$0/T CO2 $15/T CO2

Figure 7.17 Warm Produced Water Financial Performance (2,500 m3/day, 100°C Water Cooled to 40°C, Load Factor 80%)

Power generation from warm produced water has good potential for those larger opportunities, where flow rate and resource temperature can support projects greater than 1 to 2 MWe.

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October 2007 File: 20819/1 69

7.6 Surplus Steam

7.6.1 Sources In some instances excess low pressure steam is vented to atmosphere. Some scenarios where this may occur include:

• Unrecovered flash steam from condensate receiving vessels • Backpressure control of low pressure headers by venting • Mechanical drive steam turbines may exhaust into the low pressure header

system, and if turbine loads draw steam in excess of the low pressure header thermal demands, the surplus steam must be vented to balance

Generally, methods to reduce or eliminate the steam vented in the first place should be considered as alternatives to power generation. Straight vent condensers allow for recovery of the condensate and some of the sensible heat, and may present a low cost option. One Ormat reference project involved condensing of 13,000 kg/hr of low pressure steam at a pulp and paper mill to produce 930 kW of electricity with an ORC package. 7.6.2 Typical Waste Heat Characteristics Steam will typically be at saturated conditions at less than 100 kPag (15psig.) Variations in flow can be a major factor. Only steam vents that operate continuously (not only during upset or unusual operating conditions) should be considered for power generation. 7.6.3 Technical Issues In addition to the benefits of energy recovery, water is recovered and can be recycled for boiler feedwater, resulting in reduced makeup and water treatment requirements. 7.6.4 Summary of Potential The following graph illustrates the electricity generation potential from surplus steam, assuming an organic rankine cycle, 110°C saturated steam, and a condensate outlet temperature of 80°C. Figure 7.17 summarizes the predicted economics against available steam flow, for a range of capital costs.



October 2007

SURPLUS LP STEAMPower Output from Heat Recovery

0

250

500

750

1000

0 2000 4000 6000 8000 10000

Steam Flow (kg/hr)

Net

Pow

er O

utpu

t (kW

e)

Figure 7.18 Impact of Surplus Steam Flow on Power Output (110°C sat steam, condensate outlet temperature 80°C)

SURPLUS STEAM

0

5

10

15

20

0 2000 4000 6000 8000 10000

Steam Flow (kg/hr)

Pret

ax IR

R (%

) -20% capital cost

+20% capital cost

Figure 7.19 Surplus Steam Financial Performance (110°C sat steam, cooled to 80°C condensate, Load Factor 70%,

$85 per MWh + $15/Tonne CO2e)

Large steam volume applications (greater than 5,000 kg/hr vented) with high load factors should be strongly considered for more detailed analysis, to ascertain if potential efficiency gains or capital cost reductions can be realized.

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7.7 Amine Sweetening 7.7.1 Sources Amine sweetening packages generally have three possible sources of waste heat – the lean amine trim cooler, the regenerator overhead condenser, and, if a direct-fired type, the amine reboiler. The figure below provides a simplified flow diagram of the process.

Reboiler

Sweet Gas

Sour GasRegenerator

Reflux Condenser

AcidGas

Reflux Separator

Rich / LeanExchanger

Contactor

Lean Amine Trim

Cooler

WASTE HEAT

WASTE HEAT

Figure 7.20 Simplified Amine Sweetening Schematic (Typical)

The actual operating conditions are dependent on a number of factors, including sour gas constituents, design variations, and type of amine used in the process.

7.7.2 Typical Waste Heat Characteristics Inlet temperature to the reflux condenser is normally between 80 and 100°C, and the lean amine trim cooler inlet temperature is typically in the 80 to 90°C range. The duty of the heat rejection equipment and reboiler is dependent on acid gas concentration, amine circulation rate and other factors. The Gas Processors Suppliers Association (GPSA) Data Book provides the following correlations for rough estimates of equipment duties.

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October 2007 File: 20819/1 72

Table 7.3 Amine Unit Equipment Duties

kWth per m3/hr of amine circulation

Btu/hr per GPM of amine circulation

Reboiler 92.6 72,000 Amine Cooler 19.3 15,000

Reflux Condenser 38.6 30,000 (Source: GPSA Data Book)

Amine circulation rate varies widely. Large gas plants may have circulation rates of 2000 gpm or higher, and small standardized sweetening packages are available with amine circulation rates of less than 3 gpm. 7.7.3 Technical Issues

The power generation system would have to be integrated with the sweetening system such that reliability was not adversely impacted. The working fluid vaporizers would be placed in parallel with the amine and reflux aerial coolers so that an outage of the power generation unit would not shut down the amine system. During operation of the power generation unit, the electrical load associated with the amine and reflux aerial cooler fans would be eliminated and these savings would offset the parasitic load of the power generation heat rejection equipment. 7.7.4 Summary of Potential The figure below estimates electrical power output versus amine recirulation rate. It is evident that large scale sweetening plants are required to generate electricity over 250kW. The output shown assumes that heat is recovered from both the amine cooler and reflux condenser. The reboiler is neglected as reboilers in large amine plants are often steam heated. The waste heat temperature is assumed at 85°C and the duties are as outlined in Table 7.3.



October 2007

AMINE TREATINGPower Generation from Heat Recovery

0

250

500

750

1000

1250

0 50 100 150 200 250 300 350 400

Amine Recirculation (m3/hr)

Net

Pow

er O

utpu

t (kW

e)

Figure 7.21 Impact of Amine Unit Size on Power Output (Including reflux condenser and lean amine trim cooler, 85°C waste heat temp)

Figure 7.21 shows the associated financial performance at $85/MWh and $15/tonne CO2e, with a load factor of 70%. The offset aerial cooler electrical load is assumed at 1.2 kW per m3/hr (0.36hp per GPM) of amine circulation, per GPSA Data Book guidelines.

AMINE TREATINGFinancial Performance

0

5

10

15

20

0 50 100 150 200 250 300 350 400


Pret

ax IR

R (%

)

$75/MWh $85/MWh + $15/tonne CO2

Both curves Include avoided costs of aerial cooler electrical load

Figure 7.22 Amine Unit Heat Recovery Financial Performance (Including reflux condenser and lean amine trim cooler, 85°C waste heat temp)

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October 2007

7.8 Incineration 7.8.1 Sources Sulphur recovery unit (SRU) tail gas is typically treated in thermal incinerators to oxidize reduced sulphur compounds to SO2 before exiting the stack. By raising the temperature of the effluent, incineration also increases the buoyancy of the SRU flue gases which assists in dispersion and compliance with ground level SO2 concentration requirements.

Claus Plant

Incinerator

Sulphur

Tail Gas

Acid Gas from Sweetening

WASTE HEAT

Stack

Figure 7.23 Simplified Incineration Block Flow Diagram

7.8.2 Typical Waste Heat Characteristics PTAC-facilitated “SRU Incinerator Optimization Survey” (Sulphur Experts, 2005) reports that most incinerator/stacks in Alberta were originally designed such that a stack exit temperature of 538°C would provide adequate oxidation and plume dispersion to comply with operating licenses. Optimization efforts and adjustments to reflect changed operating conditions (sulphur loading etc.) since plant inception have resulted in many facilities now operating at reduced stack temperatures to conserve fuel. Typical actual operating stack temperatures are in the range of 400°C to 550°C. 7.8.3 Technical Issues Plant operating permits specify required stack exit temperatures in order to achieve required sulphur compound oxidation and adequate plume dispersion. The licensed temperature will be dependent on the operating characteristics of the plant, including sulphur concentrations and recovery efficiency, stack height, degree of tail gas cleanup etc. If lower stack temperatures can be permitted, fuel consumption should be reduced rather than considering waste heat power generation.

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7.8.4 Summary of Potential Heat recovery from incineration has limited potential given permitting and environmental requirements. As waste heat recovery would lower stack temperature, re-permitting would be required as plume dispersion would be impacted. If indeed lower stack temperatures were possible, fuel optimization would provide a superior alternative to waste heat power generation.

7.9 Glycol Cooling Circuits 7.9.1 Sources Glycol runaround circuits are used in SAGD heat integration schemes to move heat between various heating and cooling loads to improve energy efficiency. A general schematic below illustrates the concept. The circulating glycol picks up heat while servicing a number of cooling loads, and transfers heat to various heating loads. The overall heat balance of the plant typically requires that additional heat be rejected via trim air coolers.

VARIOUS HEATING LOADS

Glycol Circulation Pumps

Glycol Trim Air Cooler

VARIOUS COOLING

LOADS

Glycol Trim Heater

WASTE HEAT

Figure 7.24 Simplified SAGD Glycol Circuit Schematic (Typical)

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7.9.2 Typical Waste Heat Characteristics The waste heat source available for power generation is the glycol at the inlet to the trim cooler. Typical design inlet and outlet temperatures for systems in SAGD facilities are around 75°C and 45°C, respectively. The glycol circulation rate is site specific but flow rates between 10 and 20 kg/hr per BPD of bitumen production are typical. 7.9.3 Technical Issues The temperature typical of this waste heat stream is at the extreme low end of what is feasible for ORC and Kalina cycles. Predicted net thermal efficiency with air cooling is only around 2.5%. As previously discussed, the temperature of the available cooling medium has a significant impact on cycle efficiency at such a low waste heat source temperature. The low efficiency of the cycle is offset by the benefit of reducing the fan horsepower requirements of the aerial trim cooler during operation of the power generation unit. 7.9.4 Summary of Potential The graph below summarizes the expected net output of a waste heat power generation system recovering heat from the glycol circuit for various flow rates. It is based on a net cycle efficiency of 2.5%, and assumes the glycol is cooled to 45°C.

GLYCOL SYSTEMPower Generation from Heat Recovery

0

250

500

750

1000

0 50 100 150 200 250

Glycol Flow (kg/s)

Net

Pow

er O

utpu

t (kW

e)

Figure 7.25 Impact of Glycol Flow Rate on Power Output

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Note that the above net power output considers the parasitic electrical loads of the power generation unit, including the heat rejection system and working fluid feedpumps. However, it does not reflect the fact that when the power generation unit was in service, the electrical load associated with the aerial trim cooler would be avoided. The figure below illustrates the impact of avoided trim cooler electrical load on project economics, assuming that the trim cooler electrical load is 1.2 kW per kg/s of glycol flow. It is based on electricity pricing of $85/MWh and an annual load factor of 85%.

GLYCOL SYSTEMFinancial Performance

0

5

10

15

20

25

0.0 50.0 100.0 150.0 200.0 250.0

Glycol Flow (kg/s)

Pret

ax IR

R (%

)

Including avoided costs oftrim cooler electrical load

Not including avoided costs of trim cooler electrical load

Figure 7.26 Glycol Circuit Heat Recovery Financial Performance (Glycol cooled from 75°C to 45°C, Load Factor 85%, $85/MWh + $15/tonne CO2e)

There is also potential to improve the economics of this scenario in cases where waste heat power generation could be incorporated into the original design of the facility. Capital costs associated with the trim cooler could potentially be avoided by integrating the power generation unit heat rejection equipment into the design so that it could provide cooling duty even when the power cycle was not operating.

7.10 Blowdown and Disposal Streams

7.10.1 Sources Historically, steam-assisted oil recovery projects have utilized once through steam generators (OTSG) for steam production. While able to accommodate relatively low-quality feedwater with high dissolved solids concentrations, OTSG’s require vapor/liquid separators to produce 100% quality steam, and operate with high blowdown rates typically in the range of 10-20%. Heat is recovered from the blowdown stream in the overall plant heat integration scheme,

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typically through the use of flash vessels, blowdown recycle and heat exchange with plant glycol, feedwater and/or bitumen streams. The ultimate configuration will be specific to the plant, but a typical generic arrangement is illustrated in the figure below.

OTSG

Feedwater

HP Steam to Wells

Flash Vessel

Steam Separator

Heat Recovery

Blowdown to Disposal

Wells

Blowdown Recycle to Water

Treatment

WASTE HEAT

Figure 7.27 Simplified Blowdown Heat Recovery Schematic (Typical)

The brine stream has traditionally been disposed of by deep well injection. Some projects have also incorporated evaporators into the design to further concentrate the waste stream and reduce disposal requirements. 7.10.2 Typical Waste Heat Characteristics The brine disposal stream downstream of the heat recovery equipment and blowdown recycle stream is the waste heat source available for power generation. Due to the high level of heat recovery already included in designs for the blowdown system, the disposal stream represents a relatively low quality waste heat source. Temperatures of around 75°C are typical, which is on the extreme low end of what can practically be used in a waste heat power generation system. The temperature of the heat rejection sink becomes very important at these low temperatures. The mass flow of the disposal stream is site specific and depends on technology selection, the steam-to-oil ratio and water characteristics, among other considerations. Generally, however, a brine disposal stream between 3 and 10 m3/hr per 10,000 BPD of bitumen production could be expected. The low end would be characteristic of a project with a

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low SOR and evaporators for further brine concentration, and the high end would be typical of a project with a relatively high SOR and limited blowdown treatment. 7.10.3 Technical Issues The use of drum boilers for SAGD applications is an alternative to OTSG technology. While requiring considerably more complex water treatment to maintain the necessary feedwater quality, drum boilers typically operate with only 2 to 3% blowdown. In these cases, potential for additional heat recovery from blowdown is very limited. As with the glycol case, the temperature typical of this waste heat stream is at the extreme low end of what is feasible for ORC and Kalina cycles. Predicted net thermal efficiency with air cooling is only around 2.5%. As previously discussed, the temperature of the available cooling medium has a significant impact on cycle efficiency at such a low waste heat source temperature. 7.10.4 Summary of Potential The graph below estimates electrical output for varying blowdown flows, at a net efficiency of 2.5% and based on cooling the blowdown to 45°C.

BLOWDOWNPower Output from Heat Recovery

0

25

50

75

100

0.0 2.5 5.0 7.5 10.0 12.5 15.0

Blowdown Flow (kg/s)

Net

Pow

er O

utpu

t (kW

e)

Figure 7.28 Power Output from Blowdown Heat Recovery Given the low power output over the range of flowrates typical for this waste heat stream, the high specific capital cost per kW would be uneconomic. Blowdown, on its own, has poor potential for power generation.

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7.11 Condensers 7.11.1 Sources 7.11.1.1 Produced Gas Coolers

In SAGD operations, produced fluids from the production wells contain a mixture of bitumen, water, steam and non-condensable gases. The composition of the produced fluids is dependent on a number of characteristics specific to each operation, including operating pressure and steam to oil ratio, among others. In general, however, all SAGD operations have a produced fluids stream containing significant thermal energy which must be separated into bitumen, water and hydrocarbon vapour. Heat recovery from the produced fluids is included in the overall heat integration scheme of the plant in order to improve energy efficiency and to condense the steam component of the produced gases. In some cases, additional trim heat rejection is provided by aerial coolers to condense steam in the produced gas stream and aid in separation of the hydrocarbon vapours. A simplified schematic illustrating an example of a produced gas cooling arrangement is provided in Figure 7.28.

Produced Gas Trim Coolers

Produced Fluids from

Producer WellsSeparator

Produced Liquids

Produced Gas

Separator

WASTE HEAT

Figure 7.29 Simplified SAGD Produced Gas Cooling Arrangement (Example)

The trim heat rejection provided by the aerial coolers represents a waste heat stream with potential for additional heat recovery. Ideally the cooling duty would be provided via heat integration, but in some instances use of the thermal energy in a power cycle could have advantages. 7.11.1.2 Column Overhead Condensers Overhead condensers for equipment such as condensate stabilizers, fractionators, and distillation columns represent another potential source of waste heat. Operating

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October 2007

conditions vary widely depending on the applications and would require review on a case by case basis. Both ORC and Kalina cycle power generation units have been successfully applied on fractionation tower condenser applications. 7.11.2 Technical Issues The temperature typical of these waste heat streams is relatively low (<120°C) which results in moderate power generation efficiencies. This is offset by the benefit of reducing the fan horsepower requirements of the aerial condensers during operation of the power generation unit.

7.11.3 Summary of Potential A generic summary of potential power production based on temperature and condenser duty is provided below.

CONDENSERSPower Output from Heat Recovery

0

1000

2000

3000

4000

5000

0.0 10.0 20.0 30.0 40.0 50.0

Condenser Duty (MWth)

Net

Pow

er O

utpu

t (kW

e)

85C 100C 115C

Figure 7.30 Power Output from Condenser Heat Recovery

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October 2007

7.12 Sensitivity Analysis

A sensitivity analysis was completed to assess the impact of major variables on the financial performance of a waste heat power generation project. The base case conditions are summarized in the following Table.

Table 7.4 Base Case Variables for Sensitivity Analysis

Variable Base Case Value

Project Size 1000 kW Load Factor 70%

Electricity Price $75/MWh Project Life 20 years

GHG Credit Value $15/tonne Annual Escalation 2%

O&M Cost $0.01/kWh Capital Cost $4982/kW

Each of the variables was changed by +/- 20% to determine the relative impact on project IRR. For example, a change in IRR in absolute terms from 10% to 12%, would be shown as a 20% relative change in IRR in the figure below.

Sensitivity Analysis

-40%

-20%

0%

20%

40%

Rel

ativ

e Ch

ange

in IR

R (%

)

Load FactorElectricity PriceProject LifeGHG CreditEscalationOperating CostCapital Cost

-20% Change in Variable +20% Change in Variable

Figure 7.31 Summary of Sensitivity Analysis

File: 20819/1 82



October 2007 File: 20819/1 83

Load factor, electricity price, capital cost, and project life are the most influential variables on project viability, and these factors must be closely considered when searching for potentially successful projects: • Load Factor—plants or processes consistently operating near rated capacity, and

with minimal downtime, must be targeted. Oversized equipment operating with widely changing throughput will not present good opportunities for waste heat recovery.

• Electricity Price—in order to realize the most value for generated power,

applications that offset expensive power (ie. diesel generators, simple cycle gas turbines etc.) should be targeted. Also, in some cases, the environmentally benign attributes of waste heat power generation (no incremental air emissions) could command a premium price.

Another opportunity to maximize power price is to look for locations where

distributed generation will significantly reduce distribution losses. Also consider applications where aerial coolers can be shut down when recovering heat—the avoided fan power consumption helps offset the parasitic electrical load of the power generation unit.

• Capital Cost—opportunities where synergies could result in capital cost savings

should be targeted. Examples include cases where existing cooling systems or electrical infrastructure could be used, or where retrofit work is simplified. Integration of waste heat power generation into original designs could potentially eliminate equipment that would otherwise have been necessary (eg. Aerial coolers) and thus effectively reduce capital costs. Finally, capital cost is largely a function of project size—opportunities for MW scale power generation should be investigated.

• Project Life—even the most economically viable waste heat projects have

payback periods typically greater than 4 years, and as such, facilities with expected lives of greater than 15 years (at rated capacity) should be targeted. Operations where plant throughput could decline significantly over time will not be good candidates for waste heat power generation.

The impact of operating costs, greenhouse gas credit value and the escalation of annual revenue or costs have a relatively minor impact on project economics.



October 2007 File: 20819/1 84

8. CONCLUSIONS AND RECOMMENDATIONS All in all, economically viable opportunities for waste heat power generation are available in the upstream oil and gas industry, through the use of commercially proven technologies. A number of commercial technical options and vendors are available, and implemented projects would result in significant environmental benefits. New generation capacity from waste heat would create no incremental emissions of air pollutants or greenhouse gases, and thus the technology offers an approach to assist in reducing CO2 intensity. Each potential waste heat stream has advantages, disadvantages and particular characteristics that have a major influence on its viability for power generation.

• Reciprocating Engines—as the largest consumer of fuel gas in the upstream industry, reciprocating engines as a whole are a large source of waste heat that is recoverable from the exhaust gases and jacket cooling water. Individually, however, recips provide only small (<300 kWe) power generation opportunities with the associated high capital cost per installed kW. There is potential to reduce capital costs considerably by pairing “off-the-shelf” power generation units with common engine models.

• Gas Turbines—exhaust gas heat recovery from gas turbines is one of the most

common applications for waste heat power generation, and has good potential for economic viability. While larger midstream units (>20,000hp) will have the most attractive economics, smaller units with high annual capacity utilization should be assessed for viability.

• Fired Heaters—despite being one of the largest consumers of fuel gas in the

upstream industry, fired immersion heaters have poor potential for economically viable waste heat power generation. A combination of factors, including intermittent burner firing, small project sizes and low capacity utilization result in unattractive projects. Large fired heaters (>10MWth duty) with elevated exhaust gas temperatures, high annual load factors, and modulating burner control, may provide opportunities in select cases.

• Steam Generators—flue gases are already at a relatively low temperature, so

limited incremental gains are available unless condensing heat exchangers are used to capture additional sensible and latent heat. For SAGD facilities, there is potential for attractive power generation projects by using condensing heat exchangers, and by marshalling several OTSG flue gas streams together to improve the economy of scale.



October 2007 File: 20819/1 85

• Warm Produced Water—the most prospective opportunities will be those where water flow and temperature are high enough to support generation in excess of 1MWe. Within the relatively low temperature range characteristic of this stream (80 to 115°C) small changes in temperature can have a large impact on plant output and specific capital cost. Focus on operations where flow and temperature are greater than 2,500 m3/day and 100°C, respectively.

• Surplus Steam— While reduction or elimination of LP steam venting should be

the first priority, large steam volume applications (greater than 5,000 kg/hr vented) with high load factors should be strongly considered for more detailed analysis of power generation economic viability.

• Amine Sweetening—large amine sweetening plants (>100m3/hr amine

circulation) may have decent potential for power generation by combining the reflux condenser and lean amine trim cooler waste heat streams, despite relatively low available temperatures. Project economics would benefit from avoided fan horsepower requirements from the aerial coolers during operation of the power generation unit, which would offset the low net efficiency of the power generation island.

• Glycol—while at the extreme low end of the feasible waste heat temperature

range, large SAGD glycol systems appear to have decent potential for power generation despite very low net efficiency. This is due in part to the avoided fan horsepower requirements from the aerial trim coolers while the power generation unit is in operation, and the potential to lower the capital costs of power generation if incorporated into the original design of new SAGD facilities.

• Blowdown—SAGD facilities have historically used OTSG’s for steam generation

which have high blowdown rates. Blowdown heat recovery is already incorporated into the plant heat integration scheme, and additional heat recovery for power generation has poor potential due to very small power output (and thus high specific capital costs per kW) and low available waste heat temperature.

• Condensers—column overhead condensers, produced gas coolers and other

similar heat rejection applications have decent potential for waste heat power generation in cases where projects in the MW size range can be supported. Generally, condensers operating above 85°C with duties greater than 15MWth will provide the most prospective opportunities for viable projects.

Load factor, electricity price, capital cost, and project life are the most influential variables on project viability, and these factors must be closely considered when searching for prospective waste heat power generation opportunities.



October 2007 File: 20819/1 86

It is recommended that the study proceed to Phase 2—Feasibility Evaluations. The two primary objectives of Phase 2 of the work would be to:

• Further characterize the possible impact of waste heat power generation on the Western Canadian upstream oil and gas industry. High level estimates of the waste heat resource would be carried out to gauge the total potential for electricity capacity additions.

• Further demonstrate the viability of these power projects by completing detailed feasibility assessments for selected common, representative scenarios that have a reasonable likelihood of current or future economic viability.

The project steering committee would have to determine, depending on the mandate of the project, which scenarios should be selected for more detailed assessment in Phase 2. Options include:

• Proven scenarios with a higher likelihood of further study indicating economic viability under today’s circumstances. An example would be a large gas turbine with high annual capacity utilization.

• Less conventional applications for waste heat power generation, that have potential to significantly impact the industry’s energy intensity. Candidates include SAGD glycol or steam generation systems, small reciprocating engines and warm produced water.

While the less conventional applications may have known economic or technical issues, as discussed in this report, it is felt they warrant additional investigation in Phase 2. The advantage of this approach is that the challenges associated with these applications can be assessed while benefiting from the collaborative nature of PTAC-facilitated projects. It is also recommended that technology supplier involvement in Phase 2 be pursued. As capital costs are the major factor in determining project economic viability, it is imperative that vendors evaluate supply costs for their equipment on an application-specific basis.



October 2007 File: 20819/1 87

9. REFERENCES AESO, Annual Report, 2006 AESO, “Fast Facts: Alberta’s Electricity Market: A Guide for Distribution Connected Generators,” 2005 Alberta Distributed Generation Interconnection Guide, 2002 Borekar, M.; et al. “Study of Optimum Design-Parameters of a Condensing Heat Exchanger

(CHX) for Waste Heat Recovery.” Presented at the Advances in Energy Research Conference, 2006.

Butler, B., “Phase I Direct Testimony of Dr. Barry Butler on Behalf of Conservative Groups,”

Before the Public Utilities Commission of the State of California, Application 06-08-010, 2007.

Clearstone Engineering, “Summary of Emission Reduction Opportunity Areas in the Upstream Oil and Gas Industry,” 2005 Environment Canada , “National Inventory Report, 1990-2005 – Greenhouse Gas Sources and

Sinks in Canada,” 2007. Gas Producers Suppliers Association (GPSA) Engineering Data Book 12th Edition, 2004. Goldsherry, F., “The Variable Pressure Supercritical Rankine Cycle for Integrated Natural Gas

and Power Production from the Geopressurized Geothermal Resource,” Geopressure Projects Office for the U.S Department of Energy, 1982.

Hugo, L. “Energy Conservation Solutions in the Upstream Oil and Gas Industry: An Eco-

Efficiency Pilot 2002-2005,” CETAC-West, 2005. Iiyoshi, T. et. al., “Introduction of a Power Generating System by Low Temperature Waste Heat

Recovery (“Kalina Cycle” Power Generating System),” 2000. Jachniak, J., “Improved Immersion Fire-Tube Heater Efficiency Project,” Petroleum Technology

Alliance Canada, Project EETR 0401, 2005.

Klint, B., et. al., “Sulphur Plant Tail Gas Incinerators in Alberta: A Survey of Current Operating Practice and Opportunities to Reduce Fuel Gas Consumption” Petroleum Technical Alliance of Canada,, 2005.

Micak, H. A., “An Introduction to the Kalina Cycle,” Proceedings of the International Joint

Power Generation Conference, Book No. H01077-1996.



Mines, G., “Overview of Contributors to the Cost of Geothermal Power Production,” Idaho National Laboratory, 2006

Peachey, B., “New Water Management and Conservation Options,” Petroleum Technology

Alliance Canada, 2004. Peachey, B., et. al. “Low Carbon Futures – Carbonate Triangle and Conventional Heavy Oil –

Lowest GHG Production Scenario,” Petroleum Technology Alliance Canada, 2007. Peachey, B., “Expanding Heavy Oil and Bitumen Resources While Mitigating GHG Emissions

and Increasing Sustainability: A Technology Roadmap,” Petroleum Technology Alliance of Canada, 2006.

Peachey, B., “Thermal Heavy Oil—Vent / Efficiency Options,” Petroleum Technical Alliance of

Canada, 2002. Potter, I.; Reader, G., “Application of Stirling Engines in the Oil and Gas Industry,” American

Institute of Aeronautics and Astronautics, 2004. SPX Cooling Technologies, “Cooling Tower Fundamentals,” 2006 Stine, W., Greyer, M. Power From The Sun, [Online] Available from

http://www.powerfromthesun.net/chapter12/Chapter12new.htm on September 11, 2007

October 2007 File: 20819/1 88

http://www.powerfromthesun.net/chapter12/Chapter12new.htm

APPENDIX A GRID INTERCONNECTION REPORT

PETROLEUM TECHNOLOGY ALLIANCE CANADA SUITE 400 CHEVRON PLAZA

500 – 5TH AVENUE S.W. CALGARY, ALBERTA T2P 3L5

GENERATION OF ELECTRIC POWER FROM WASTE HEAT IN THE WESTERN CANADIAN OIL AND GAS INDUSTRY

APPENDIX A DISTRIBUTED GENERATION & GRID INTERCONNECTION

Project Number: 20819 Specification No: S-14135

Rev. A

Prepared By:

NEILL AND GUNTER 144 4TH AVENUE SW, SUITE 2600

CALGARY, AB. T2P 3N4 Telephone: (403) 571-0852

Fax: (403) 571-0853

TABLE OF CONTENTS

1. INTRODUCTION ............................................................................................................1

2. OBJECTIVES...................................................................................................................1

3. DEFINITION OF DISTRIBUTED GENERATION........................................................2

4. INTERCONNECTION PROCEDURE............................................................................2

5. GENERAL INTERCONNECTION AND PROTECTION REQUIREMENTS..............3

5.1 General..................................................................................................................3 5.2 Generating Facility ...............................................................................................3 5.3 Grid Interconnection .............................................................................................6 5.4 Metering................................................................................................................8

6. TYPICAL INTERCONNECTION DESCRIPTION........................................................9

6.1 Proposed Interconnection Design .........................................................................9 6.2 Generator & Generator Protection and Control Scheme ......................................9 6.3 Lockable Generator Switch or Breaker ................................................................9 6.4 Revenue Metering.................................................................................................9 6.5 Interconnection Transformer ..............................................................................10 6.6 Switchgear Modifications / Additions ................................................................10 6.7 Interconnection Protection and Control Scheme ................................................10 6.8 Communications System ....................................................................................11 6.9 Shunt Trip Recloser ............................................................................................11 6.10 VAR Compensation / Voltage Support ..............................................................11 6.11 Distribution Interconnection (Cable or Overhead Distribution Line) ................12

7. CAPITAL COST ESTIMATES .....................................................................................14

7.1 Plant Equipment – 2000 kVA DG ......................................................................15 7.2 Plant Equipment – 500 kVA DG ........................................................................16 7.3 Over Head Distribution Line – 5 kV ..................................................................17 7.4 Over Head Distribution Line – 25 kV ................................................................17 7.5 Underground Distribution – 5 kV.......................................................................18 7.6 Underground Distribution – 25 kV.....................................................................18 7.7 Cost Summary.....................................................................................................19

Appendix 1 – Single Line Diagrams Appendix 2 – Tables

Distributed Generation & Grid Interconnection Generation of Electric Power from Waste Heat

Petroleum Technology Alliance Canada APPENDIX A

Neill and Gunter 1 October 2007 File: 20819/7 Rev. A

1. INTRODUCTION

This report establishes criteria and requirements and a capital cost estimate for the interconnection of distributed generation within a typical distribution system in the province of Alberta. Specifically, this guideline defines the technical requirements for connecting generation that is not exclusively owned by the Wire Service Provider (WSP), but is connected to the WSP facilities, with an operating voltage of 25,000 volts (25 kV) or lower and a Distributed Generation of between 200 kW and 5,000 kW balanced three phase output. This document does not constitute a design handbook. Power Producers who are considering the development of a generation facility intended for connection to a distribution system should engage the services of a professional engineer or a registered consulting firm qualified to provide design and consulting services for electrical interconnection facilities.

2. OBJECTIVES

The objective of this report is to provide a general summary of interconnection technical requirements and a capital cost estimate for the interconnection of Distributed Generation (DG) systems associated with the generation of electrical power from waste heat. This report will include a rough capital cost estimate (+/- 20) for the following:

a. All costs associated with designing, procuring and installing substation equipment required to meet interconnection requirements of the local utility with respect to customer owned Distributed Generation.

b. All costs associated with designing, procuring and installing electrical equipment required to interconnect the client substation to the WSP distribution system (4.16 kV to 25 kV) point of common connection (PCC).

The cost estimate for the above items also includes project management, engineering design and electrical construction management for the following work scope:

a. Detailed substation electrical and associated civil design including drawings, bills of material and the specification of various components.

b. Detailed distribution line (or direct buried cables) electrical and civil design including drawings, bills of material and the specification of various components.

c. Procurement of equipment. d. Preparation of technical specification and scope of work document for the distribution line

(or buried cable) installation contractor. e. Preparation of technical specification and scope of work document for the electrical

installation contractor. f. Review bids, and assist with preparation of the final construction contracts. g. Liaison and coordination with Alberta Energy and Utilities Board (EUB), Alberta electric

System Operator (AESO) and Wire Service Provider as required. h. Electrical regulatory, code and utility interconnection compliance reviews of electrical

installation contractors works. i. Administration of electrical contractor’s installation contracts at site. j. Site inspections and approval of electrical works during installation. k. Witness testing and commissioning of the substation and site electrical infrastructure.




3. DEFINITION OF DISTRIBUTED GENERATION

Distributed Generation (or DG) generally refers to small-scale (typically 1 kW – 50 MW) electric power generators that produce electricity at a site close to customers or that are tied to an electric distribution system. Distributed generation can be provided by numerous technologies and fuel sources. The focus of this investigation is on DG from waste heat power generation at oil and gas facilities. This report is constrained to describing the technical requirements of Distributed Generation with an operating voltage of 25,000 volts (25 kV) or lower and a generation output of between 200 kW and 5,000 kW. (Three phase, DG with an output lower than 200 kW and single phase DG below 50 kW require slightly less onerous protection requirements, refer to Tables 1 and 2 in Appendix 2). This report does not address the technical requirements for Inverter Type Voltage- Following Generation.

4. INTERCONNECTION PROCEDURE The following excerpts are taken from the Alberta Electric System Operator (AESO) “Fast Facts” guide and is applicable for all regions in the province of Alberta:

“The Alberta Electric System Operator is an independent system operator, the AESO leads the safe, reliable and economic operation and planning of Alberta’s interconnected power system. The AESO also facilitates Alberta’s hourly wholesale electricity market and is accountable for the administration and regulation of load settlement function. Distribution-connected generators are connected to local distribution systems at 25 kilovolts or less. The generators export electrical energy onto distribution lines in distribution service areas. The AESO requires that these types of generators be registered in order to exchange energy. The following is a step-by-step guide to assist distribution-connected generators become participants in the electricity market. Step 1: All generators in Alberta must obtain a site permit from the Alberta Energy and Utilities Board (EUB). EUB approval is required as a prerequisite for registration with the AESO. Step 2: There are several distribution companies operating in Alberta. The generator must determine which distribution company (wire-service provider WSP) is operating in their area and then contact the WSP to determine how they connect to the electric grid. The WSP takes the necessary steps, including administering contracts, to connect the generator to the grid and facilitate the exchange of energy. Step 3: The generator contacts the AESO to register as a market participant if they wish to sell surplus generation to the pool. The wholesale electricity market is operated by the AESO, and all generation in Alberta clears through the AESO.




5. GENERAL INTERCONNECTION AND PROTECTION REQUIREMENTS

The physical interconnection, metering, protection and control requirements associated with Distributed Generation are specified by the applicable Wire Service Provider. In Alberta the technical requirements of the individual WSPs are very similar as they all closely follow the “Alberta Distributed Generation, Interconnection Guide” developed by the Alberta Distributed Generation Technical and Policy Committee. Due to the similarity of the technical requirements for interconnecting Distributed Generation capital cost estimates produced using any of the WSPs “Distributed Generation Interconnection Guidelines” will be almost identical. Therefore, for consistency the “Alberta Distributed Generation, Interconnection Guide” dated July 16, 2002 has been used as a basis for the technical requirements of the Distributed Generation interconnection and for the associated capital cost estimates.

5.1 General

The “Alberta Distributed Generation, Interconnection Guide” was developed to promote safe operation and minimize the impact on electrical equipment within the WSP distribution system including other customers. These requirements do not address the protection for the Power Producer’s generation equipment. It is the responsibility of the Power Producer to provide such protection. The Power Producer is responsible for protecting the Power Producer’s generating equipment in such a manner that, utility system outages, short circuits or other disturbances, including excessive zero sequence currents and ferroresonant overvoltages, do not damage the Power Producer’s generating equipment. The Power Producer’s protective equipment must also prevent excessive or unnecessary tripping that would affect the WSP’s reliability and power quality to other customers. The generator supplier will normally supply the equipment required to protect and control the generator. This report will outline the basic requirements to be met by the generator protection and control. The costs for the generator protection and control system are not included in this report as they are considered to be included in the cost of equipment supplied by the generator vendor. The following subsections constitute a summary of the principal technical requirements as described in the “Alberta Distributed Generation, Interconnection Guide”. (For a full list of all technical requirements the WSP interconnection guidelines should be referenced for the location where the DG is to be installed.).

5.2 Generating Facility

1) Mitigation of Adverse Effects If the generating facility is affecting customers adversely the WSP may disconnect it until the concern has been mitigated. Deviation from any of the technical requirements outlined in the Generating Facility or Grid Interconnection sections of this report while generating could initiate a disconnect from the grid.




2) Synchronism

Any generating facility that can create a voltage, while separate from the electric system, must have synchronization facilities to allow its connection to the electric system. Synchronization facilities are not required for induction generators that act as motors during startup, drawing power from the electric system before they themselves generate power. Synchronization equipment must prevent connection to Grid when the Power Producer’s synchronous generator and/or power system is operating outside the following limits:

Aggregate Ratings Of Generation

(kVA)

Frequency Difference

(Hz)

Voltage Difference

(%)

Phase Angle Difference (degrees)

0 – 500 0.3 10 20 501 – 1500 0.2 5 15

>1500 0.1 3 10 Distribution and transmission facilities typically allow for automatic reclosing of electrical circuits after a variable time delay. The Power Producer is responsible for protecting their facility from the effects of such reclosing.

3) Voltage Regulation and Power Factor

The Power Producer is responsible for ensuring that the voltage levels at the Point of Common Coupling (PCC) are maintained within the guidelines prescribed by the WSP. Voltage levels must be at least equal to the voltage levels at all feeder load conditions, prior to the interconnection. Synchronous generators connected to the distribution system must be equipped with excitation controllers capable of controlling voltage. The generator bus voltage set point shall be stable at, as well as adjustable to, any value between 95% and 105% so that the WSP can maintain CSA voltage limits on its system. Induction generators do not have voltage or reactive power control and consume reactive power (VAR). In this case, the generator must provide reactive compensation to correct the power factor to +/- 0.9 at the PCC.

4) Frequency Control

An interconnected generating facility must remain synchronously connected for frequency excursions. Islanded operations are not allowed for generators connected to the WSP’s distribution system. Generators with stand alone capability, that serve isolated systems, must be capable of controlling the frequency of the system to between 59.7 Hz to 60.2 Hz for normal operation.




Underfrequency and overfrequency relaying that automatically disconnects generators from the WSP must not operate for frequencies in the range of 59.5 to 60.5 Hz. generators connected to the grid that protect for off-nominal frequency operation should have relaying protection that accommodates, as a minimum, underfrequency and overfrequency operation for the following specified time frames:

Underfrequency Limit Overfrequency Limit Minimum Time 60.0 - 59.5 Hz 60.0 - 60.5 Hz N/A (continuous operating range) 59.4 - 58.5 Hz 60.6 - 61.5 Hz 3 minutes 58.4 - 57.9 Hz 61.6 - 61.7 Hz 30 seconds 57.8 - 57.4 Hz 7.5 seconds 57.3 - 56.9 Hz 45 cycles 56.8 - 56.5 Hz 7.2 cycles

Less than 56.4 Hz Greater than 61.7 Hz Instantaneous trip Note: Values in the ENMAX and Fortis Alberta tables are slightly different.

Generators that do not meet the above requirements and trip off the grid in a shorter time than indicated shall automatically trip load simultaneously to match the anticipated generation loss, at comparable frequency levels.

5) Voltage Imbalance

The phase-to-phase voltage unbalance must not exceed 1% for any three-phase generating facility, as measured both with no load and with balanced three-phase loading.

6) Grounding

A ground grid of sufficient size to handle the maximum available ground fault current shall be designed and installed in order to limit step and touch potentials to safe levels as set forth in ANSI/IEEE Std. 80, “IEEE Guide for Safety in AC Substation Grounding”. All electrical equipment must be grounded in accordance with Alberta Electrical and Communication Utility Code (AECUC) and Canadian Electrical Code’s electrical and safety codes.

7) Resonance and Self-Excitation of Induction Generators

Resonance can cause damage to existing electrical equipment, including the electrical equipment of the Power Producer. Engineering analysis by the Power Producer should be a part of the design process to evaluate the existence of and to eliminate the harmful effects of:

a) ferroresonance in the transformer b) sub-synchronous resonance due to the presence of series capacitor banks c) resonance with other customers' equipment due to the addition of capacitor

banks to the distribution system For Power Producers connecting induction generators, the adverse effects of self-excitation of the induction generator during island conditions should be assessed and mitigated.




5.3 Grid Interconnection

1) Point of Common Coupling The Point of Common Coupling (PCC) is the point where the WSP’s electrical facilities or conductors are connected to the Power Producer’s facilities or conductors, and where any transfer of electric power between the Power Producer and the WSP takes place. The PCC will be identified in the design and on the single line diagram. The WSP will coordinate design, construction, maintenance and operation of the facilities on the distribution side of the point of common coupling. The Power Producer is responsible for the design, construction, maintenance and operation of the facilities on the generation side of the point of common coupling. All voltage, frequency and harmonic parameters, as specified in the following sections, shall be met at the PCC unless otherwise stated.

2) Point of Disconnection To provide a means of electrically isolating the WSP System from the Power Producer generator, a manual and visible disconnect switch must be installed at the Point of Common Coupling (PCC). On a site that interconnects multiple generators, one disconnect switch must be capable of isolating all the generators simultaneously. A withdrawable circuit breaker is an acceptable disconnect device.

3) Voltage Flicker Any voltage flicker at the Point of Common Coupling that is caused by the generating facility should not exceed the limits defined by the "Maximum Borderline of Irritation Curve" identified in Fig. 10.3 of IEEE Std. 519-1992 IEEE Recommended Practices and Requirements for Harmonic Control in Electric Power Systems.

4) Harmonics Maximum harmonic current distortion limits for power generation equipment, measured at the Point of Common Coupling, are as specified in Table 10.3 of IEEE Std. 519-1992 IEEE Recommended Practices and Requirements for Harmonic Control in Electrical Power System.

5) Inadvertent Energization of WSP facilities When the WSP’s facilities are de-energized for any reason, the Power Producer’s generator must not energize the WSP’s facilities.




6) Network System Interconnection (EPCOR requirement) Distributed generation facilities that export power onto EDI’s distribution system, will not be allowed to connect to the downtown network system.

For non-exporting distributed generation facilities, EDI may allow parallel operation on the network system if:

• The Power Producer installs reverse power protection for the facility. • Reverse power protection settings prevent any cycling operation of network

protectors due to the output of the distributed generation. • The network equipment loading and fault interrupting capacities are not exceeded

by the addition of the distributed generation.

7) Interconnection Grounding Grounding configurations shall be designed to provide:

� Solidly grounded distribution facilities. � Suitable fault detection to isolate all sources of fault contribution, including the

generator, from a faulted line or distribution element. � A circuit to block the transmission of harmonic currents and voltages. � Protection of the low voltage side from high fault current damage.

The preferred winding configuration of the distribution or generator step-up transformer (i.e. delta, grounded wye, etc.) varies from WSP to WSP, which is a concern to be addressed during detailed design but has little significance with respect to providing a capital cost estimate for a typical installation as changing the winding configuration has little impact on cost.

8) Interrupting Device Ratings and Fault Levels

The design of the generating facility must consider the fault contributions from both the distribution facility and the generating facility to ensure that all circuit fault interrupters are adequately sized to accommodate the present and anticipated future fault contributions from the interconnected electric system, including fault level design limits.

9) Protection

All WSP require similar protection schemes that can be provided by modern multi-element relays. Required IEEE relaying elements are defined in Table 2 in Appendix 2 and Typical Protection Single Line Diagrams in Appendix 1.

10) Anti-Islanding In most cases, the generating facility will routinely operate as a part of the interconnected system. A problem on the WSP system could lead to the generator becoming islanded and inadvertently the sole producer of power to one or more of the WSP’s customers. This could result in damages to those customers and liability to the Power Producer because of




irregularities in power quality. The Power Producer’s generator must be equipped with protective hardware and software designed to prevent the generator from being connected to a de-energized WSP circuit. Details of Anti-Islanding requirements can be found in the WSP interconnection guides.

11) Transfer Trip

All synchronous generators that are rated 500 kW or larger with the ability to export power onto the WSP’s distribution system, must be equipped with transfer trip protection or an WSP approved anti-islanding relay that performs the equivalent function of a transfer trip.

12) Generators Paralleling for 30 cycles or Less (Closed Transition Switching)

Refer to Table 3 in Appendix 2 for the protective functions required by this guideline for generators 10 MW or less that parallel with the WSP distribution system for 30 cycles or less.

13) Mitigation of Protection System Failure

Relays with self-diagnostic check features provide information on the integrity of the protection system should be used whenever possible. The design of protection should be done by a qualified professional engineer, or a competent technical person, working with the WSP engineers to ensure that this self-checking feature is integrated into the overall protection system for the safe and reliable operation of the power system.

14) Surge Withstand Performance The interconnection system must have the capability to withstand voltage and current surges in accordance with the environments described in IEEE/ANSI C62.41 or C37.90.1.

5.4 Metering

Sales of electricity require an interval meter and purchase of metering services from a company called a "meter data manager" who reads your meter. If your DG system is more than 25 kW in generating capacity, or if you have several DG systems that together total more than 150 kW of generating capacity, you are required to install interval metering regardless of whether you sell the excess to the Pool. Details of Revenue Metering technical requirements are outlined in the WSP guidelines.




6. TYPICAL INTERCONNECTION DESCRIPTION 6.1 Proposed Interconnection Design

The basic components of the interconnection system are as follows:

• Generator & Generator Protection and Control Scheme • Lockable Generator Switch or Breaker • Revenue Metering • Interconnection Transformer • Switchgear Modifications / Additions • Interconnection Protection and Control Scheme • Communications System • Recloser (special case - if feeder load unbalance will overload the transformer) • Three Phase Medium Voltage Disconnect Switch and Fuse • VAR Compensation / Voltage Support • Distribution Interconnection (Cable or Overhead Distribution Line)

Refer to Single Line Diagrams in Appendix 1 for an overview of the typical configuration for a Distributed Generator interconnection.

6.2 Generator & Generator Protection and Control Scheme Costs for the generator, and the generator protection and control scheme are not included in the scope of estimates provided in this Appendix. This equipment is covered in the cost of the main power generation equipment package, as described in the main report. The generator and it’s associated protection and control scheme should meet all the requirements as described in the WSP Distributed Generation guidelines. (Typical Generator protection requirements are shown on the Single Lines in Appendix 1 and in the tables in Appendix 2).

6.3 Lockable Generator Switch or Breaker A Visible Lockable Switch is required within Five meters of the Point of Common Coupling. The switch must be adequately rated to break the connected generation/load and be lockable in the “Open” position. The switch must be capable of being closed without risk to the operator when there is a fault on the system. Costs for design, procurement, installation and commissioning of this item are included in Section 7 of this report.

6.4 Revenue Metering Revenue class meter(s), revenue class current transformers (CTs) and revenue class voltage transformers (PTs) must be installed as per the WSP specifications. Costs for design, procurement, installation and commissioning for one revenue class meter and associated PTs and CTs is included in Section 7 of this report.




6.5 Interconnection Transformer

In most cases the interconnection transformer will be the same transformer that presently supplies the Power Producers facilities. Some examples of exceptions to this rule would be when the generation exceeds the rating of the existing transformer or the winding configuration of the existing transformer does not meet the requirements of the WSP. The costs to design, procure, install and commission a separate / dedicated generator interconnection transformer have been included in the interconnection cost estimate in Section 7. Most waste heat power producers will be able to use the existing plant transformer and the separate / dedicated generator interconnection transformer cost can be deducted from the total interconnection cost in Section 7. Typical costs for interconnection transformers are summarized in the following table.

Voltage (HV / LV)

KVA Cost in Canadian Dollars (HST not in price)

25 kV / 575 V 2,000 44,600.00 25 kV / 575 V 500 17,800.00

4.16 kV / 575 V 2,000 43,600.00 4.16 kV / 575 V 500 17,800.00

6.6 Switchgear Modifications / Additions

In instances where the Power Producer is adding waste heat generation to an existing plant modifications and/or additions will have to be made to the existing switchgear to accommodate a new withdrawable breaker with which to connect the new generator. For cases where the Power Producer has only one load breaker at his point of interconnection an additional breaker will have to be added so that there are separate load, generator and main incoming breakers in the MCC / Switchgear. The costs to design, procure, install and commission the one (1), withdrawable breaker have been included in the interconnection cost estimate in Section 7.

6.7 Interconnection Protection and Control Scheme The costs to design, procure, install and commission the protection and control scheme as described in this document and the applicable WSP Distributed Generation Interconnection Guide has been included in Section 7. The technical requirements and therefore the costs of the protection and control scheme are identical for Distributed Generation ranging from 200 kVA to 5,000 kVA. For generating units between 50 kVA and 200 kVA there are some small savings in the protection and control scheme but these costs are not significant with respect to the overall project cost and are therefore not addressed in this report.




Costs for typical relays which will address the requirements of the WSP are summarized in the following table.

Relay Relay Elements

Cost US Dollars

Cost in Canadian Dollars (HST not in price)

Schweitzer SEL-547 Distributed Generator Interconnection Relay

25, 27, 32, 47, 59, 81 O/U

1,000.00

1,090.00

Schweitzer SEL-551 Overcurrent and Reclosing Relay

50, 50N, 51, 51N, 79

840.00

935.00

Schweitzer SEL-300G

Generator Relay

21, 24, 25, 27, 32, 40, 46, 49,

50, 50N, 51G,59, 59N, 60, 64G, 64F,

78, 81, 87

3,100.00

3,370.00 *

* The generator relay is only referenced in this report to emphasize the minimum WSP

requirements for the generator relay that is to be supplied by the generator vendor. A generator relay equivalent to the SEL-300G must be supplied by the generator vendor and included in the generator price. Therefore, the generator relay cost has not been included in Section 7.

6.8 Communications System

Typically the communications requirements for small Distributed Generators will require either a leased phone line or a radio system. In both cases the material costs will be approximately $5,000 and the engineering and labour costs $10,000 for telemetering. If an anti-islanding transfer trip scheme is required by the WSP then the Power Producer will have to install additional dedicated communications for the transfer trip signal. The costs for this additional transfer trip communications system will be approximately the same as for the telemeteing system, approximately $ 5,000 and the engineering and labour costs $10,000 for telemetering.

6.9 Shunt Trip Recloser The shunt trip recloser is only required if the feeder imbalance will overload the transformer. The majority of Distributed Generator installations will not require a shunt trip recloser and the shunt trip recloser cost can be deducted from the total interconnection cost in Section 7.

6.10 VAR Compensation / Voltage Support Synchronous generators voltage set point must be stable at, and adjustable to, any value between 95% and 105%. Induction generators must provide reactive compensation to correct the power factor to +/- 0.9 at the PCC.




The Power Producer must ensure that the generator purchased meets the above requirements for voltage support and VAR compensation. If the generator is not capable of meeting these requirements they will not be allowed to connect to the WSP. Cost to provide separate VAR compensation or voltage control equipment has not been included in this estimate as it should be supplied by the generator vendor.

6.11 Distribution Interconnection (Cable or Overhead Distribution Line) Both the overhead and underground distribution line options are based on per kilometer costs as the length of line will be site specific. In cases where the Power Producer is generating capacity is less than the WSP interconnection transformer the lines feeding the interconnection transformer will not have to be up-graded. In cases where the Power Producer is generating capacity is greater than the WSP interconnection transformer the lines feeding the interconnection transformer will have to be up-graded if possible (re-conductor) or a new line built. The distribution capital cost estimates in this report are for brand new distribution systems (overhead or underground) as rebuild costs, if required, are site specific. 25 kV, 5 MW, Three Phase, Overhead Line The capital estimate cost for a new 25 kV overhead distribution collection system with a 10 MVA capacity would include:

.1 Three (3), #1/0 AWG “Raven” ACSR phase conductors and one (1), #1/0 AWG ACSR neutral conductor.

.2 Single pole construction with two pin cross-arm. (One 25 kV pin insulator on the pole top, two on the cross-arm).

.3 Allowance for guy wires every second pole.

.4 Conductor span of 50 meters between poles.

.5 Pin Insulators 25 kV class, ANSI.

25 kV, 5 MW, Three Phase, Underground The capital estimate cost for a new 25 kV underground distribution collection system with a 7.6 MVA capacity would include:

.1 One (1), Three Phase, #1/0, 25 kV insulated, triplex cable with concentric neutral.

.2 Direct buried 1000 mm. in common earth with no sheeting or de-watering. No allowance made for excavation in rock.

.3 One 25kV termination per phase at the riser pole.

.4 One 25kV termination per phase at pad mount transformer




4.16 kV, 5 MW, Three Phase, Overhead Line The capital estimate cost for a new 4.16 kV overhead distribution collection system with a 5 MVA capacity would include:

.1 Three (3), 556.5 MCM “Dove”ACSR phase conductors and one (1), #4/0 AWG ACSR neutral conductor.

.2 Single pole construction with two pin cross-arm. (One 5 kV class pin insulator on the pole top, two on the cross-arm).

.3 Allowance for guy wires every second pole.

.4 Conductor span of 50 meters between poles.

.5 Pin Insulators 5 kV class, ANSI.

4.16 kV, 3.6 MW, Three Phase, Underground The capital estimate cost for a new 4.16 kV underground distribution collection system with a 3.6 MVA capacity would include:

.1 Three (3), 500 MCM, 5 kV insulated, single phase cables and one (1), #4/0 AWG Copper neutral conductor.

.2 Direct buried 1000 mm. in common earth with no sheeting or de-watering. No allowance made for excavation in rock.

.3 One 5kV termination per phase at the riser pole.

.4 One 5kV termination per phase at pad mount transformer.




7. CAPITAL COST ESTIMATES

The following +/- 20% accuracy estimates include all costs for design, procurement, installation, commissioning, project management, construction management and construction support for each item identified in the estimate table. Each of the following estimates is derived for a specific, distinct set of conditions and is not transferable or scalable to other DG projects as each Power Producers Distributed Generation will require a separate and unique cost estimate which must be developed by a qualified engineering firm specific to the proposed Power Producers DG installation.




7.1 Plant Equipment – 2000 kVA DG For the specific case of a 2000 kVA DG connected to an existing plant MCC that can accommodate a new 4160 A withdrawable breaker. Replacing the 25 kV / 4160 V step up transformer with a new transformer. New cables to the transformer from the MCC 30 meters away. Cables from Generator to MCC 30 meters away. Room is available in existing plant buildings for new equipment. 600 V / 4160V Generator step-up transformer supplied by generator vendor and not included in this estimate.

Construction Cost Estimate – 2000 kVA Distributed Generation Item Description Cost in Canadian Dollars 6.2 Generator & Generator Protection and Control Scheme 4 In Generator Vendor Scope 6.3 Lockable Generator Switch or Breaker 6,260 6.4 Revenue Metering 21,230 6.5 Interconnection Transformer 1 57,900 6.6 Switchgear Modifications / Additions 2 26,720 6.7 Interconnection Protection and Control Scheme 22,480 6.8 Communications System 5 30,170 6.9 Shunt Trip Recloser 3 42,240 6.10 VAR Compensation / Voltage Support 4 In Generator Vendor Scope 125 V DC UPS – 100 Ah Battery and 20 A Charger 23,560 Misc. Civil Works 9,900 Misc. Electrical Works 40,884 Commissioning 29,400 Engineering 93,480 Construction Management 20,211 Total 424,435

1. A separate / dedicated generator interconnection transformer will not normally be required for Power Producers who’s generation is less than their load and the cost of this item can be removed from the total. Or for a new Power Producer with no existing WSP interconnection transformer.

2. Cost included for one withdrawable load breaker.

3. Waste heat power producers may be able to use the existing plant transformer as the interconnection transformer and the cost of this item can be deducted from the total. Refer to Section 6.5 for details

4. Generator, Generator Protection and Control Scheme and VAR Compensation / Voltage Support are to be supplied by the generator vendor. Costs for these items are not included in the estimates presented in the Grid Interconnection Report.

5. The communications system includes costs for both telemetering and transfer trip communications systems. If the transfer trip is not required approximately $15,000 can be removed from the price.

6. HST not included in estimate.




7.2 Plant Equipment – 500 kVA DG For the specific case of a 500 kVA DG connected to an existing plant MCC that can accommodate a new 600 A withdrawable breaker. Replacing the 25 kV / 600 V step up transformer with a new transformer. New cables to the transformer from the MCC 30 meters away. Cables from Generator to MCC 30 meters away. Room is available in existing plant buildings for new equipment.

Construction Cost Estimate – 500 kVA Distributed Generation Item Description Cost in Canadian Dollars 6.2 Generator & Generator Protection and Control Scheme 4 In Generator Vendor Scope 6.3 Lockable Generator Switch or Breaker 6,260 6.4 Revenue Metering 21,230 6.5 Interconnection Transformer 1 28,120 6.6 Switchgear Modifications / Additions 2 16,680 6.7 Interconnection Protection and Control Scheme 22,480 6.8 Communications System 5 30,170 6.9 Shunt Trip Recloser 3 42,240 6.10 VAR Compensation / Voltage Support 4 In Generator Vendor Scope 125 V DC UPS – 100 Ah Battery and 20 A Charger 23,560 Misc. Civil Works 4,700 Misc. Electrical Works 31,684 Commissioning 27,400 Engineering 81,780 Construction Management 16,815 Total 353,119

1. A separate / dedicated generator interconnection transformer will not normally be required

for Power Producers who’s generation is less than then their load and the cost of this item can be removed from the total. Or for a new Power Producer with no existing WSP interconnection transformer.

2. Cost included for one withdrawable load breaker.

3. Waste heat power producers may be able to use the existing plant transformer as the interconnection transformer and the cost of this item can be deducted from the total. Refer to Section 6.5 for details

4. Generator, Generator Protection and Control Scheme and VAR Compensation / Voltage Support are to be supplied by the generator vendor. Costs for these items are not included in the estimates presented in the Grid Interconnection Report.

5. The communications system includes costs for both telemetering and transfer trip communications systems. If the transfer trip is not required approximately $15,000 can be removed from the price.





7.3 Over Head Distribution Line – 5 kV The following estimate is for 1 km of three phase, 5 kV class, single pole construction, 336.4 MCM ACSR overhead distribution line rated 4 MVA at 4.16 kV. The cost estimate is typical for an installation in good soil conditions. For lines less than 1 km the average cost per km will be higher then this estimate and for lines over 3 km the average cost will be lower.

Construction Cost Estimate – 5 kV Overhead Distributed Line Item Description Cost in Canadian Dollars

1 Civil Materials, Labour and Expenses 73,314 2 Electrical Materials, Labour and Expenses 41,172

3 Engineering 34,067 4 Construction Management 5,724

Total per kilometer 154,277


2. 50 M spans and 40 foot class 3 poles used.

3. 10 % contingency has been factored into the estimate.

7.4 Over Head Distribution Line – 25 kV

The following estimate is for 1 km of three phase, 25 kV class, single pole construction, 1/0 AWG, ACSR overhead distribution line rated 10 MVA at 25 kV. The cost estimate is typical for an installation in good soil conditions. For lines less than 1 km the average cost per km will be higher then this estimate and for lines over 3 km the average cost will be lower.

Construction Cost Estimate – 25 kV Overhead Distributed Line Item Description Cost in Canadian Dollars

1 Civil Materials, Labour and Expenses 73,314 2 Electrical Materials, Labour and Expenses 33,522 3 Engineering 34,067 4 Construction Management 5,342



2. 50 M spans and 40 foot class 3 poles used.





7.5 Underground Distribution – 5 kV The following estimate is for 1 km of three phase, 5 kV class, direct buried, 500 MCM copper, XLPE, 100% insulated, 505 Amps (direct buried), rated 3.6 MVA at 4.16 kV. The cost estimate is typical for a direct buried installation in good soil conditions. For circuit lengths less than 1 km the average cost per km will be higher then this estimate and for circuit lengths over 3 km the average cost will be lower.

Construction Cost Estimate – 5 kV Underground Distributed Item Description Cost in Canadian Dollars




2. No allowance made for concrete duct bank for trafficked areas.

3. No allowance has been made for excavating in bedrock.


7.6 Underground Distribution – 25 kV

The following estimate is for 1 km of three phase, 25 kV class, direct buried, 1/0 AWG copper, XLPE, 100% insulated, 210 Amps (direct buried), rated 9.1 MVA at 25 kV. The cost estimate is typical for a direct buried installation in good soil conditions. For circuit lengths less than 1 km the average cost per km will be higher then this estimate and for circuit lengths over 3 km the average cost will be lower.

Construction Cost Estimate – 25 kV Underground Distributed Item Description Cost in Canadian Dollars




2. No allowance made for concrete duct bank for trafficked areas.

3. No allowance has been made for excavating in bedrock.





7.7 Cost Summary

Construction Cost Summary

Item Description Cost in Canadian Dollars

7.1 Plant Equipment – 2000 kVA DG 424,435

7.2 Plant Equipment – 500 kVA DG 353,119

7.3 Over Head Distribution Line – 5 kV, 4 MVA per km 154,277

7.4 Over Head Distribution Line – 25 kV, 10 MVA per km 146,245

7.5 Underground Distribution – 5 kV, 3.6 MVA per km 514,627

7.6 Underground Distribution – 25 kV, 9.1 MVA per km 298,713

1. HST not included in estimate

Robert Forbrigger, P. Eng. Senior Electrical Engineer, Neill and Gunter




Appendix 1 – Single Line Diagrams

1. Single Line Diagram for Wye-Delta Interconnection 2. Single Line Diagram for Wye-Wye Interconnection




Appendix 2 – Tables Table 1 Interconnection Protective Function Requirements, Single-Phase Connected to

the Secondary or Primary System Table 2 Interconnection Protective Function Requirements, Three-Phase Connected to

the Secondary or Primary System Table 3 Interconnection Protective Function Requirements, Generators Connected to

Secondary or Primary System

APPENDIX B INFORMATION SHEETS

Generation of Electric Power from Waste Heat in the

Western Canadian O&G Industry

INDEX Of Information Sheets

SOURCES OF WASTE HEAT (Typical Source Temperatures)

Low (< 100oC)

Medium (100oC – 350oC)

High (>350oC)

• Warm Produced Water • Glycol Systems • Boiler Blowdown • Amine Sweetening

• Condensers • Surplus LP Steam • Steam Generator Exhaust

• Gas Turbine Exhaust • Recip Exhaust • Incinerators • Fired Heaters

WASTE HEAT TECHNOLOGIES

Developing Commercial

• Thermal Hydraulic • Stirling Engines

• Organic Rankine Cycle • Steam Rankine Cycle • Kalina Cycle • Condensing Heat Exchangers



Warm Produced Water

Information Sheet

Applications: • Primarily conventional oil production

Description:

• Produced fluids may have been warmed from geothermal activity

• Low available waste heat temperature

• Energy typically lost when produced water is separated and reinjected

Efficiency • N/A

Waste Heat Temperature:

• In Alberta, opportunities between 80°C and 115°C are available

• Temperature generally increases with well depth

Size Range / Flow Rates

• In WCSB, produced water-to-oil ratios of 1 to 10 are typical, increases over time

• Flow rates cover a wide range • Several fields handling tens of

thousands m3/day

Technical Issues

• Takes advantage of existing infrastructure to access geothermal resource

• At low temp, cooling source for power generation is important

• Maximize heat integration first • Consider alternatives for

produced water (i.e. downhole separation, blocking agents)

• Low temperatures make it a challenging application for power generation—temp and flow combinations that can support projects > 1MWe will have best chance for economic viability

WARM PRODUCED WATERPower Output from Heat Recovery

0

1000

2000

3000

4000

0 2000 4000 6000 8000 10000


Net

Pow

er O

utpu

t (kW

e)

85C 100C 115C

NOTE: Based on ORC technology, produced water cooled to 40°C

Alberta Oil Pools with Potential for Electricity Generation

Field / Pool Name Formation

Temperature (°C)

Produced Water Rate

(m3/day) Sept 2006

Electricity Potential (MWe)

Swan Hills / Beaverhill Lake

A&B 104 54,039 13.1

Judy Creek / Beaverhill Lake A 96 33,642 6.5

Swan Hills South / Beaverhill Lake

A&B 107 24,356 6.1

Virginia Hills / Beaverhill Lake 102 13,470 3.1

Kaybob / Beaverhill Lake A 113 7,025 2.2

Modified from Low Carbon Future Report (Peachey, 2007)

WH to Ele. Technology:

• Organic Rankine Cycle • Kalina Cycle Links:

• Generation of Electric Power from Waste Heat in the Western Canadian O&G Industry

• Information Sheet Index • Low Carbon Futures

http://www.ptac.org/cho/dl/chop0701s.pdf



Glycol Systems

Information Sheet

Applications: • SAGD Heat Integration • Sulphur Plant Heat Integration • Space Heating Systems

Description:

• In SAGD facilities, large glycol systems are used in the plant heat integration scheme

• Glycol loop picks up energy from a number of cooling loads, and transfers energy to heating loads

• The overall heat balance of the plant typically requires that excess heat be rejected via trim air coolers

• A waste heat exchanger would absorb heat in place of the glycol trim cooler.

Efficiency • N/A

VARIOUS HEATING LOADS

Glycol Circulation Pumps

Glycol Trim Air Cooler

VARIOUS COOLING

LOADS

Glycol Trim Heater

WASTE HEAT

Simplified SAGD Glycol System Schematic (Typical)


• 75°C is typical upstream of the trim cooler


• Glycol circulation of between 10 and 20 kg/hr per BPD of bitumen production is typical for SAGD

• 40,000 BPD plant ~ 200 kg/s glycol

Technical Issues

• Extreme low end of feasible waste heat temperature

• At low temperature, cooling source for power generation is important

• Maximize heat integration first • Improved economics from avoided

aerial cooler fan horsepower (offset low efficiency of power gen unit)

• Potential to lower capital cost of power gen if incorporated into original design

GLYCOL SYSTEMPower Generation from Heat Recovery

0

250

500

750

0 50 100 150 200 250

Glycol Flow (kg/s)

Net

Pow

er O

utpu

t (kW

e)

NOTE: Glycol cooled from 75 to 45oC, power generation at 2.5% net efficiency, benefit of reduced aerial cooler horsepower not shown




• Information Sheet Index



Blowdown and Disposal Streams

Information Sheet

Applications: • Steam Generators

Description:

• SAGD projects have historically used OTSG’s for steam production

• Can accommodate low quality water but high blowdown rates (10-20%) are required

• Traditionally disposed of by deep well injection

• Blowdown heat recovery already incorporated into the plant heat integration scheme

• Low available waste heat temperature

Efficiency • N/A

OTSG

Feedwater

HP Steam to Wells

Flash Vessel

Steam Separator

Heat Recovery

Blowdown to Disposal

Wells

Blowdown Recycle to Water

Treatment

WASTE HEAT

Simplified Blowdown Heat Recovery Schematic (Typical)


• 75°C typical downstream of existing heat recovery


• Site specific, dependent on steam-to-oil ratio and technology

• Approx 3 to 10 m3/hr blowdown per 10,000 BPD of bitumen typical

Technical Issues

• At extreme low temperature limit for power generation

• Blowdown losses are low if drum boilers are used

• By itself, blowdown has very limited potential for power generation due to small size (and high specific capital cost per kW) and poor conversion efficiency

BLOWDOWNPower Output from Heat Recovery

0

25

50

75

100

0.0 2.5 5.0 7.5 10.0 12.5 15.0

Blowdown Flow (kg/s)

Net

Pow

er O

utpu

t (kW

e)

NOTE: Cooled from 75 to 45oC, power generation at 2.5% net efficiency







Amine Sweetening

Information Sheet

Applications: • Sweetening Sour Gas in Gas Processing Plants

Description:

Waste heat sources include: • Lean Amine Trim Cooler • Reflux Condenser • Amine Reboiler Flue Gas (see Fired

Heaters)

Efficiency • N/A


• 80 to 90oC typical for both Lean Amine Trim Cooler and Reflux Condenser

Reboiler

Sweet Gas

Sour GasRegenerator

Reflux Condenser

AcidGas

Reflux Separator

Rich / LeanExchanger

Contactor

Lean Amine Trim

Cooler

WASTE HEAT

WASTE HEAT

Simplified Amine Sweetening Schematic (Typical)


From GPSA Databook: • Amine Trim Cooler =

19.3kWth/(m3/hr amine circulation) • Reflux Condenser =

38.6kWth/(m3/hr amine circulation)

Technical Issues

• Heat from amine cooler and reflux condenser could be marshaled together to increase output from waste heat power generation

• Parallel operation with existing aerial coolers to ensure reliability

• Improved economics from avoided aerial cooler fan horsepower (offset low efficiency of power gen unit)

• Large gas plants (>100m3/hr amine circulation) likely required for economically viable projects

AMINE TREATINGPower Generation from Heat Recovery

0

250

500

750

1000

0 50 100 150 200 250 300 350 400


Net

Pow

er O

utpu

t (kW

e)

NOTE: ORC power generation, waste heat temp 85C, benefit of reduced aerial

cooler horsepower not shown







Condensers Information Sheet

Applications: • SAGD Produced Gas Coolers • Column Overhead Condensers

Description:

• SAGD produced fluid thermal energy is typically recovered the in heat integration scheme of the plant. Some cases require additional trim heat rejection, which creates a waste heat stream with potential for heat recovery for power generation.

• Overhead condensers are required for equipment such as condensate stabilizers, fractionators, distillation columns and amine plants

Efficiency • N/A

Produced Gas Trim Coolers

Produced Fluids from

Producer WellsSeparator

Produced Liquids

Produced Gas

Separator

WASTE HEAT

Simplified SAGD Produced Gas Cooling Schematic (Example)

Waste Heat Temperature: • Varies with application


• Site specific, dependent on application

Technical Issues

• Heat integration should be considered before power generation.

• Produced gas coolers are not required at all SAGD facilities

• Improved economics from avoided aerial cooler fan horsepower (offset low efficiency of power gen unit)

• Proven application for waste heat power generation (refinery column overheads) for both Kalina and ORC technology

CONDENSERSPower Output from Heat Recovery

0

1000

2000

3000

4000

5000

0.0 10.0 20.0 30.0 40.0 50.0

Condenser Duty (MWth)

Net

Pow

er O

utpu

t (kW

e)

85C 100C 115C







Surplus Low Pressure Steam

Information Sheet

Applications:

• Unrecovered flash steam from condensate receiving vessels

• Backpressure control of low pressure headers by venting

• Mechanical drive steam turbines may exhaust into the low pressure header system, and if turbine loads draw steam in excess of the low pressure header thermal demands, the surplus steam must be vented to balance

Description: • Waste heat for power generation

may be captured by condensing these streams

Efficiency • N/A


• 100 to 120oC (Atmospheric to 100kPa(g) Sat steam)


• Site Specific • Often Intermittent

Technical Issues

• Reduction or elimination of steam venting should be considered prior to power generation (ie. vent condensers)

• Also will reduce make up water and water treatment requirements

• Proven application for ORC in pulp and paper plants

• Large steam volume applications (>5,000kg/hr) with high load factors should be considered for more detailed analysis

SURPLUS LP STEAMPower Output from Heat Recovery

0

250

500

750

0 2000 4000 6000 8000 10000

Steam Flow (kg/hr)

Net

Pow

er O

utpu

t (kW

e)

ORC with 110°C saturated steam, condensate outlet temperature of 80°C.







Steam Generator Exhaust

Information Sheet

Applications: • Steam Generation

Description:

• Used widely in the upstream O&G industry for steam production

• SAGD facilities require large amounts of high pressure steam and typically use packaged, gas fired once-through steam generators (OTSG)

• Waste heat could be captured from the flue gas stream

Efficiency • 80 to 85% typical


• 200oC typical • Depends on acid dewpoint and

whether an air preheater is used


• Flue gas - 0.4 to 0.5 kg/s per MWth Duty (typical)

Technical Issues

• Use of air preheaters should be considered before electricity production. Air heaters can improve the efficiency of the steam generator by around 2% on an HHV basis.

• Acid dewpoint may limit temperature to which exhaust can be cooled without use of corrosion resistant cold-end materials

• Consider marshalling several steam generator exhausts to improve economy of scale

• Low potential for further heat recovery from flue gases unless condensing HX’s are used to capture additional sensible and latent heat


0

50

100

150

200

250

0 30000 60000 90000 120000 150000


Plan

t Out

put (

kWe)

NOTE: Based on 12MPa Sat Steam OTSG, gas fired, 15% excess air, flue gas cooled from 200 to 160°C with ORC power generation


0

1000

2000

3000

4000

5000

6000

7000

40 60 80 100 120 140 160


Plan

t Out

put (

kWe)



NOTE: Based on OTSG flue gas and condensing heat exchangers to capture additional sensible and latent heat,

cooled from 200°C with ORC power generation


• Organic Rankine Cycle • Kalina Cycle • Condensing Heat Exchangers

Links: • Generation of Electric Power from Waste Heat in

the Western Canadian O&G Industry • Information Sheet Index



Gas Turbines

Information Sheet

Applications: • Compression Drivers • Electricity Generation /

Cogeneration

Aeroderivative Gas Turbine (Source: GE Power)

Description:

• Models <10,000 hp most common in upstream industry, with >25,000 hp common in midstream industry

• High exhaust gas temperatures • High excess air is used for

controlling turbine inlet temperatures, resulting in large exhaust gas flow rates

Efficiency • 25 – 40% typical, generally improves with larger turbines

Waste Heat Temperature: • 400 - 550oC exhaust typical


• 8 to 15 (kg/hr flue gas)/hp • 0.9 to 2.2 (kWth Available)/hp

Technical Issues

• Considerable variation in waste heat availability with ambient temperature, as output increases with declining inlet air temp

• To maintain reliability, bypass stack required to allow operation of turbine with power gen unit down

• Intermediate Hot Oil loop often required between exhaust gases and working fluid evaporator in power gen cycles

• Consider use of condensing heat exchangers

GAS TURBINESPower Output from Exhaust Heat Recovery

0

1500

3000

4500

6000

0 25 50Exhaust Flow (kg/s)

Net

Pow

er O

utpu

t (kW

e)

75

400C 450C 500C

NOTE: Based on ORC technology cooling exhaust to 115C


• Rankine Cycle • Organic Rankine Cycle • Kalina Cycle

Links: • Generation of Electric Power from Waste Heat in the

Western Canadian O&G Industry • Information Sheet Index



Reciprocating Engines

Information Sheet

Applications: • Compression Drivers • Backup Power Generation

(Source: http://www.waukeshaengine.com/)

Description:

• Reciprocating internal combustion engines are used as prime movers in a wide variety of applications

• These are the largest fuel gas consumer in the upstream oil and gas industry, recent estimates suggesting that over 270 million GJ per year is consumed

• Waste Heat can be captured from exhaust, jacket cooling water and lube oil cooling

Efficiency • 30 to 40% typical (LHV)


• 350 to 500oC (exhaust) typical • 80 to 90oC (jacket water) typical

Size Range / Flow Rates • Exhaust 3 to 6 kg/hr per bhp

Lube Oil Cooler

Heat Utilization (Process Heating,

Power Production etc.)

Exhaust

Engine

Thermal Oil Pump

WASTE HEAT

WASTE HEAT

Jacket Water Cooler

Simplified Recip Heat Recovery Schematic (Example)

Technical Issues

• Big potential industry wide, but individual engines provide small scale power generation opportunities and the associated high capital cost per installed kW

• Potential to reduce capital costs by pairing “off-the-shelf” power gen units with common engine models

• Marshalling heat from a bank of engines could improve economics

• Heat recovery equipment in parallel to radiator to ensure reliability

RECIP ENGINESPower Output from Heat Recovery

0

100

200

300

0 500 1000 1500 2000 2500 3000

Engine Horsepower

Net

Pow

er O

utpu

t (kW

e)

NOTE: Based on Exhaust gas flow of 4.8 kg/hr per hp cooled

from 420°C to 115°C and jacket water heat recovery


• Rankine Cycle • Organic Rankine Cycle • Kalina Cycle



http://www.waukeshaengine.com/



Incinerators

Information Sheet

Applications: • Sulphur Recovery Unit (SRU) tail gas treatment

Description:

• SRU tail gas is treated in thermal incinerators to oxidize reduced sulphur compounds to SO2 before exiting the stack

Efficiency • N/A


• 400°C to 550°C typical at stack exit

Technical Issues

• Optimize burner operation (fuel consumption and excess air) before considering power generation

• Minimum stack temperatures are required by operating permits to oxidize sulphur compounds and maintain plume buoyancy

• Limited potential for power generation given permitting and environmental requirements

• If lower stack temperatures can be permitted, fuel consumption should be reduced rather than considering waste heat power generation

Claus Plant

Incinerator

Sulphur

Tail Gas

Acid Gas from Sweetening

WASTE HEAT

Stack

Simplified Schematic (Typical)




• Information Sheet Index • SRU Incinerator Optimization Survey • PTAC Knowledge Center - Sour Gas Plants

http://www.ptac.org/eet/dl/C504%20PTAC%20Incinerator%20Optimization%20Study%20Step%201%20Report.pdf

http://www.ptac.org/links/EnergyEfficiencyKC/SourGas.pdf



Fired Heaters

Information Sheet

Applications:

• Line Heaters • TEG Reboilers • Amine Reboilers • Oil Treaters • Tank Heaters • Butane / Propane / LNG evaporators

Description:

• Used for heating a fluid medium • Generally consists of a horizontal

firetube immersed in a fluid bath • Very common (estimated they consume

25% of fuel gas used in upstream processes)

(Source: Jachniak, 2005)

Efficiency • 65-80% typical


• Optimized stack temperature is 200 to 350oC (approach temperature between bath and stack should be 100 to 150°C)


• Rated Duties 150,000 BTU/hr to 12 mmBTU/hr (44 kWth to 3.5 MWth) are common

• Flue Gas 0.5 to 1.3 (kg/s)/MWth Duty

Technical Issues

• First consider improving fired heater efficiency by:

− Combustion optimization − Heat transfer surface modification − Fuel or combustion air preheating

• Heaters with intermittent burner firing are unsuitable for power generation

• Potential for power generation from immersion heaters is poor due to a combination of factors—frequent ON-OFF burner control, small project sizes (and associated high per kW capital costs) and low capacity utilization

FIRED HEATERSPower Output from Heat Recovery

0

100

200

300

400

500

0 2000 4000 6000 8000 10000

Heater Duty (kWth)

Net

Pow

er O

utpu

t (kW

e)

150C 300C 450C

NOTE: Based on 20% excess air, flue gas flow Cooled to 115°C with ORC power generation




• Information Sheet Index • Improved Immersion Fire Tube Heater Efficiency • PTAC Knowledge Center - Fired Heaters


http://www.ptac.org/links/EnergyEfficiencyKC/FiredHeaters.pdf



Thermal Hydraulic Systems Information Sheet

Description:

• Heat is applied to expand the hydraulic working fluid to create linear motion

• Good potential for warm produced water for artificial lift—targeting marginal wells where reduced pumping costs could improve economics significantly

• One design uses heat to boil a working fluid inside a vessel to produce a high pressure vapor. The pressurized fluid is expelled from the vessel to drive a hydraulic motor for electricity production.

Advantages:

• Small footprint • Low noise • Low waste heat temperatures

required (60 – 80oC)

Disadvantages: • Early stages of development • Very low cycle rate

Efficiency: • 20-40% efficiency depending on operating conditions

Typical Capital Costs ($/kW)

• No commercial models are available • Projected cost is $1500 to 2000/kWe

Typical O&M Costs ($/kWh) • No industrial operational experience

Technical Issues:

• Typical working fluid is CO2 (high coefficient of expansion)

• High working pressures (1200 to 3000 psi or 8.2 to 20.7Mpa)

(Source: Deluge Inc)

Manufacturers / Suppliers:

• Deluge Inc. –Natural Energy Engine • Encore Energy – Heatseeker Links:





Stirling Engines Information Sheet

Description:

• Long history of development • High $/kW has limited use to only a

few specialized applications including military, aerospace, and some solar power projects

• Currently available Stirling engines range in size from 1kW to 55kW

• Primary driver for development is that they can theoretically reach Carnot efficiency

Advantages: • Potentially high efficiency • Low noise/vibrations

Disadvantages: • Early stages of commercialization • Reliability concerns

Efficiency: Up to 60% of Carnot targeted, best current models around 35%


Industrial scale engines are not fully commercialized but costs are targeted at $1000/kW

Typical O&M Costs ($/kWh) $0.002 to 0.008/kWh (projected)

Technical Issues:

• Most common working fluids—air, nitrogen, helium and hydrogen

• Hydrogen embrittlement at high temperatures

• Loss of working fluid • High working fluid pressures

(13.8MPa)

The Stirling Thermodynamic Cycle

(Source: http://engine.stirling.cz/)


• Kokums – 25kW engine developed for use in submarines. Is being applied with a dish collector for solar power generation.

• Regen Power Systems – Currently under development. Product line is to include 500kW and 1MW models for 100oC condensing steam and 250kW, 500kW, 1MW and 2MW models for 250oC exhaust gas.

Links: • Generation of Electric Power from Waste Heat

in the Western Canadian O&G Industry • Information Sheet Index



Organic Rankine Cycle (ORC) Information Sheet

Description:

• Rankine cycle with an alternative working fluid

• Available in skid mounted packages • Sizes range between 200kW – 7MW

Advantages:

• Well established technology • Able to utilize low grade heat • Condensing pressure is near

atmospheric

Disadvantages: • Constant temperature boiling creates a

pinch point which may restrict the waste heat utilization

Feed Pumps

Condenser

RecuperatorEvaporator

Expander / Generator

Waste Heat Source

WORK OUT

HEAT REJECTION

HEAT ABSORPTION

Simplified Schematic – Organic Rankine Cycle (Typical)

Efficiency: • Approx 25-35% of Carnot efficiency, see graph for reference data


• Approx $3000/kWe at 5MWe • Can exceed $5000/kWe small projects

Typical O&M Costs ($/kWh) • $0.005 to $0.015 / kWh

6.5MW ORC at Compressor Station (Source: Ormat)

Technical Issues:

• When capturing heat from flue gas, an intermediate hot oil loop is often used

• A recuperator may be used to increase cycle efficiency and lower evaporator and condenser duties. This may reduce waste heat utilization


• Barber Nichols • Ormat • WOW Energy • UTC Power • Various Others

Links:



Organic Rankine Cycle - Reference Performance DataNET THERMAL EFFICIENCY

0.0%

5.0%

10.0%

15.0%

20.0%

25.0%

30.0%

0 100 200 300 400 500 600

Waste Heat Temp (C)

Net

Eff

icie

ncy

(%)



Steam Rankine Cycle Information Sheet

Description:

• Heat is recovered to generate steam which is expanded in a steam turbine to generate power

• Turbine exhaust steam is condensed, and pumped back to the steam generator

• Cogen applications employ a backpressure turbine where turbine exhaust is used for process heating

Advantages: • Well developed commercial technology with many suppliers

Disadvantages: • Relatively high waste heat temperatures required

Efficiency: • 20 to 30%


• Approx $3000/kWe at 5MWe • Can exceed $5000/kWe for smaller

projects or complex retrofits • Steam turbine generator package

typically $400/kW to $600/kW including a water-cooled condenser and associated auxilliaries

• Gas turbine HRSG packages typically run between $50 and $100 per kg/hr

Typical O&M Costs ($/kWh)

• $0.005 to $0.015 / kWh if no additional licensed operator is required

Technical Issues:

• Relatively high efficiency; affected by turbine inlet steam temperature and turbine exhaust pressure (see graphs)

• Water treatment and makeup water are required

• Vacuum systems required • Steam operators required

Feed Pumps

Condenser

Steam Turbine / GeneratorWORK OUT

HEAT ABSORPTION

Heat Recovery Steam Generator

Deaerator

Extraction Pumps

Cooling Tower

HEAT REJECTION

Waste Heat Rankine Cycle Configuration (Typical)


10.0%

15.0%

20.0%

25.0%

30.0%

0 100 200 300 400 500 600

Inlet Steam Temperature (C)

Net

Effi

cien

cy (%

)

10.3 bar (150 psi)20.7 bar (300 psi)41.4 bar (600 psi)86.2 bar (1250 psi)

NOTE: Based on turbine backpressure of 3 in Hg, 10% aux electrical

load, and turbine isentropic efficiency of 80%


20.0%

25.0%

30.0%

0 2 4 6 8 10

Turbine Exhaust Pressure (in Hg)

Net

Eff

icie

ncy

(%)

12

NOTE: Based on 41.4 bar (600 psi), 316°C (600F) inlet steam conditions


HRSGs: • Rentech • TIW Western • IST

Turbines: • Dresser-Rand • General Electric • Siemens • Turbosteam

Links: • Generation of Electric Power from Waste

Heat in the Western Canadian O&G Industry • Information Sheet Index



Kalina Cycle Information Sheet

Description:

• Ammonia/water working fluid • Waste heat applications have been installed

up to 6.5MW. Geothermal plants, up to 45MW, are under construction.

Advantages:

• Ammonia/water mixture evaporates over a variable temperature range, increasing cycle efficiency and utilization of heat source

• Able to utilize low grade heat • Low cost working fluid • Condensing pressure near or above

atmospheric

Disadvantages: • Ammonia handling system required

Efficiency: • Efficiencies up to 40% of Carnot are possible—see graph for reference data


• Approx $3000/kWe at 5MWe • can exceed $5000/kWe for smaller projects

Typical O&M Costs ($/kWh) • $0.005 to $0.015 / kWh

Technical Issues:

• Cycle optimization by controlling mixture composition at various stages of the cycle

• Ammonia-water mixtures have better heat transfer properties than ORC working fluids, allowing for smaller and less costly heat exchangers.

• Potential for sub-zero condenser temperature in winter to improve cycle performance

Simplified Kalina Cycle Schematic

(Source: Iiyoshi, 2000)

Ammonia/Water boiling temperature profile

(Source: Micack, 1996)

Kalina Cycle - Reference Performance DataNET THERMAL EFFICIENCY

0.0%

5.0%

10.0%

15.0%

20.0%

25.0%

30.0%

0 100 200 300 400 500

Waste Heat Temp (C)

Net

Eff

icie

ncy

(%)


• Licensed by Recurrent Engineering in North America Links:





Condensing Heat Exchangers Information Sheet

Description:

• Heat Exchanger to cool flue gas below the acid and moisture dew points

• Specialized materials to prevent corrosion such as teflon coatings, FRP, stainless steel and aluminium

Advantages:

• Captures extra sensible heat and latent heat by cooling below the dew point and condensing moisture

• Condensed water washes the tube surface to reduce fouling

Disadvantages:

• Expensive materials to resist corrosion

• Lower exhaust temperatures may impair dispersion and influence stack height requirements

• Condensed water may be acidic and requires handling through disposal or recycle

Efficiency: • Increases boiler efficiency above

90% by reducing wet and dry flue gas losses


• Capital cost is approximately 3x that of conventional HX’s

• Typically $35 to 110/kWth duty

Typical O&M Costs ($/kWh)

• Periodic inspection and maintenance

OTSG Heat Recovery using a Condensing Heat Exchanger

0

2000

4000

6000

8000

10000

12000

40 60 80 100 120 140 160


Hea

t Rec

over

ed (k

W)

Sensible Heat Absorbed kW Total Heat kW

Acid and Water Condensation

No Acid or Water Condensation

Acid Condensation only

NOTE: Based on 150000kg/hr Steam OTSG, exchanger inlet conditions

assumed at 200oC, water dew point of 56oC


0

1000

2000

3000

4000

5000

6000

7000

40 60 80 100 120 140 160


Pla

nt O

utpu

t (kW

e)



NOTE: Increased Power Generation from Waste Heat Recovery

using ORC technology

Technical Issues:

• Low coolant temperatures are required to bring flue gas below the dew point

• Material limitations of some equipment restricts the maximum exhaust inlet temperature to 260°C


• Condensing Heat Exchanger Corp. • Combustion Energy Systems



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