Study of Gasification/Pyrolysis of MSW Residuals

Final Report

Study of Gasification/Pyrolysis of MSW Residuals

Prepared for:

City of Edmonton, 2nd Floor, Century Place, 9803-102A Avenue, N.W. Edmonton, AB T5J 3A3

EPCOR Power Development Corp. 10088 102nd Avenue N.W. Edmonton, AB T5J 2Z1

Prepared by: Earth Tech (Canada) Inc. 6th Floor, 1901 Rosser Avenue, Burnaby, BC V5C 6S3

January, 2004

Project No. 55692 (03)

Final Report January 2004 Page i

Table of Contents

SECTION TITLE PAGE NO.

EXECUTIVE SUMMARY...............................................................................................ES1

1.0 BACKGROUND AND HISTORY .......................................................................... 1

1.1 History and Context .......................................................................................... 1 1.2 Approach........................................................................................................... 2

2.0 WASTE GENERATION RATES AND SIZING................................................... 4

2.1 General .............................................................................................................. 4 2.2 Feedstock from City of Edmonton Facilities .................................................... 4 2.3 Summary of Potential Energy Available........................................................... 12 2.4 Equipment Sizing .............................................................................................. 13

3.0 ADVANCED THERMAL TREATMENT OPTIONS .......................................... 14

3.1 Pyrolysis and Gasification Theory and Practical Applications ......................... 14 3.2 Technology Selection Criteria........................................................................... 20 3.3 Initial Technology Short-listing, Classification and Status............................... 22 3.4 Technology Description (Pyrolysis and Gasification) ...................................... 26 3.5 Other Relevant Technologies ............................................................................ 32 3.6 Commercial Technology Description (Fluidized Bed Combustion)................. 35

4.0 FEED PREPARATION REQUIREMENTS.......................................................... 38

5.0 RESIDUES AND RESIDUE DISPOSAL ............................................................... 39

6.0 REVIEW OF HEAT RECOVERY/COGENERATION OPTIONS.................... 40

6.1 Process Routes and Syngas Utilization Options................................................ 40 6.2 Markets for Clean Syngas ................................................................................. 43 6.3 Markets for Dirty Syngas .................................................................................. 43 6.4 Markets for Power............................................................................................. 43 6.5 Markets for Heat/Steam, Cogeneration............................................................. 44

7.0 GREEN POWER AND GREENHOUSE GAS ...................................................... 45

7.1 Green Power and Gasification........................................................................... 45 7.2 Factors Influencing the Value of Green Power ................................................. 46 7.3 Factors Influencing the Value of Greenhouse Gas Credits ............................... 47 7.4 GHG Emissions from Selected Processes ......................................................... 49

Final Report January 2004 Page ii

8.0 AIR EMISSIONS AND CONTROL OPTIONS .................................................... 50

8.1 General .............................................................................................................. 50 8.2 Syngas Cleaning Process................................................................................... 50 8.3 Fluegas Cleaning Process.................................................................................. 53 8.4 Comparison of Current Canadian, USEPA and

EU-WID Emissions Standards .......................................................................... 58

9.0 EVALUATION OF BUDGETRY PROPOSALS .................................................. 59

9.1 Introduction ....................................................................................................... 59 9.2 Analysis of data................................................................................................. 59 9.3 Comparison Tables............................................................................................ 61 9.4 Capital and Operating Costs Discussion ........................................................... 62 9.5 Sensitivity of Costs ........................................................................................... 63 9.6 Conclusion on Costs.......................................................................................... 63

10.0 TECHNOLOGY VERIFICATION......................................................................... 64

10.1 Facility Site Visits ............................................................................................. 64

11.0 REGULATORY ISSUES ......................................................................................... 66

11.1 General .............................................................................................................. 66 11.2 Regulatory Process, Permitting......................................................................... 66 11.3 Public Process ................................................................................................... 68 11.4 Ranking the Potential for Community Support................................................. 73

12.0 IMPLEMENTATION SCHEDULE ....................................................................... 74

12.1 Prior to Award of Contract................................................................................ 74 12.2 After Award of Contract ................................................................................... 74

13.0 CONCLUSIONS AND RECOMMENDATIONS.................................................. 77

13.1 Conclusions ....................................................................................................... 77 13.2 Recommendations ............................................................................................. 79

APPENDICES

Appendix A – Evaluation of Budgetary Proposals Appendix B – Technical Process Specification Appendix C – Reference Facility Site Visits

Final Report January 2004 Page iii

List of Tables

Table 2.1 Composter Primary Residuals - Summary of Composition Table 2.2 Composter Secondary Residuals - Summary of Composition Table 2.3 Residuals MRF Rigid Line – Summary of Composition Table 2.4 Residuals MRF Fibre Line – Summary of Composition Table 2.5 Summary of MSW Generated in Local Counties Table 2.6 Summary of Wood Waste Generated in Capital Region Table 2.7 Summary of Plastic Waste Generated in Capital Region Table 2.8 Summary of Potential Energy Available Table 3.1 Summary of Pyrolysis Processes Table 3.2 Essential Criteria Table 3.3 Desirable Criteria Table 3.4 Commercial Status Criteria Table 3.5 Classification and Status of Technologies Table 3.6 Status of Proposals Table 3.7 Reasons for Declining to Quote Table 3.8 Fluidized Bed Combustion Technologies for Edmonton’s Application Table 3.9 General Comparisons between Pyrolysis and Gasification and Fluidized Bed

Combustion Processes Table 4.1 Feed Preparation Table 5.1 Residue Handling Table 6.1 Advantages and Disadvantages of the Process Routes for Syngas Utilization Table 8.1 Contaminants in Syngas Table 8.2 Syngas Cleaning Compared to Fluegas Cleaning Table 8.3 Emissions Standards Table 9.1 Capital Costs Table 9.2 Operating Costs Table 9.3 Final Cost Summary Table 12.1 Public Consultation and Permitting Schedule

Final Report January 2004 Page iv

List of Figures Figure 2.1 Summary of Energy Available for Residuals Figure 3.1 Schematic Representation of Gasification and Syngas Utilization Options Figure 3.2 Schematic Representation of Pyrolysis Figure 3. 3 Mechanism for Waste Pyrolysis Figure 3.4 Applications for Syngas from Gasification Processes Figure 3.5 Applications for Pyrolysis Products Figure 3.6 Short-listed Pyrolysis and Gasification Technologies Figure 3.7 Schematic of the Brightstar SWERF process Figure 3.8 Schematic of Enerkem’s BIOSYN Process Figure 3.9 Schematic of the Techtrade/WasteGen Process Figure 3.10 Schematic for the Thermoselect Process Figure 3.11 Schematic for the Thide EDDITh Thermolysis Process Figure 3.12 Schematic of the Ebara ICFB Process Figure 3.13 Schematic for the Energy Products of Idaho, BFBC Process Figure 6.1 Syngas Utilization & Energy Recovery Routes Figure 8.1 Syngas Cleaning Unit Operations Figure 8.2 Schematic of Semi-Dry Fluegas Scrubber Figure 8.3 Schematic of a Dry Scrubbing System Figure 8.4 Schematic of Conditioned Dry Scrubbing Process Figure 12.1 Project Implementation Schedule

Final Report January 2004 Page v

LIST OF ACRONYMS

AENV Alberta Environment

AESO Alberta Electric System Operator

APC Air Pollution Control

APRA Alberta Plastics Recycling Association

ASR Auto-Shredder Residues

BATNEEC Best Available Technology Not Entailing Excessive Costs

BFBC Bubbling Fluidized Bed Combustion

BOO Build, Own Operate

CCME Canadian Council of Ministers of the Environment

CEM Continuous Emission Monitors

CFBC Circulating Fluidized Bed Combustors

CV Calorific Value

DFO Department of Fisheries and Oceans

ECF Edmonton Compost Facility

ECP Environmental Choice Program

EPCOR Edmonton Power Corporation

ESP Electrostatic Precipitator

EIA Environmental Impact Assessment

EESR Electrical and Electronic Scrap Residues

EU European Union

EUB Energy Utilities Board

EWMC Edmonton Waste Management Centre

FBC Fluidized Bed Combustion

FCM Federation of Canadian Municipalities

GHG Greenhouse Gas

HDPE High Density Polyethylene

HHV Higher Heating Value

ICFBB Internally Circulating Fluidized Bed Boiler

ICI Industrial, Commercial and Institutional

IDC Interest During Construction

IPCC International Panel on Climate Change

LDC Local Distribution Company

MRF Material Recovery Facility

Final Report January 2004 Page vi

LIST OF ACRONYMS

MDF Medium Density Fibreboard

MPW Mixed Plastic Waste

MSW Municipal Solid Waste

NIMBY Not In My Backyard

OTF Over the Fence

PERT Pilot Emission Reduction and Trading

PET Polyethylene Terephthalate

RPS Renewable Portfolio Standards

RDF Refuse Derived Fuels

SWERF Solid Waste and Energy Recycling Facility

TIF Twin Interchanging Fluidized Bed

UK United Kingdom

US-EPA United States Environmental Protection Agency

WID European Emissions Standards

Final Report January 2004 Page vii

LIST OF SYMBOLS AND UNITS

% v/v percent by volume

% w/w percent by weight

MWel Mega Watts - electrical

MWth Mega Watts - thermal

PJ Pica Joule (1012)

Final Report January 2004 Page viii

GLOSSARY

Autothermic a reaction that is self-sustaining due to an energy producing component

MWel/KWel electrical output of a facility

MWel gros/KWel gros total electrical output of a facility

MWel net/KWel net power available to the grid after deduction of internal power requirements

MWth Thermal output of a facility

CO2e Tonnes of carbon dioxide equivalent

Hygroscopic The property of drawing moisture from the atmosphere

Higher heating value The maximum potential energy in dry fuel

Final Report January 2004 Page ES1

EXECUTIVE SUMMARY

The City of Edmonton (the City) owns and operates North America’s largest composting plant, which

plays an essential role in the City’s Waste Management Strategy and is an integral component of the

Edmonton Waste Management Centre. Operated in conjunction with the composting plant is a materials

recovery facility (MRF). The facility accepts the City’s recyclable materials from the City’s Blue Bag and

Blue Bin programs, and from recycling depots (approximately 40,000 tonnes per year). The compost

plant is designed to accept 190,000 tonnes of residential waste per year, and helps the City to achieve a

residential waste diversion rate of over 60 percent.

The non-compostable residue from the composting plant and MRF comprises over 73,000 tonnes per

year and has two outstanding features: it has a high calorific value, and it takes up a disproportionate

volume of scarce landfill space due to its low density. These materials are also not otherwise

recoverable. The City’s extensive recycling and composting programs capture practically all recoverable

organics and recyclables, leaving only this residue.

The primary purpose of this project is to identify innovative thermal technologies that will recover the

energy from Edmonton Compost Facility (ECF) and MRF residuals, reduce their volume and preserve

landfill space. The study is being led by the City, in partnership with EPCOR Power Development

Corporation (EPCOR), an Edmonton-based power and utility company. It is being executed by Earth

Tech (Canada) Inc., with support from Juniper, UK, and with funding assistance from the Green Municipal

Enabling Fund, administered by the Federation of Canadian Municipalities (FCM). The Alberta Plastics

Recycling Association (APRA) has also assisted with in-kind contribution of technical expertise.

The City and EPCOR have chosen to examine gasification and pyrolysis as innovative thermal treatment

technologies because:

• They are perceived as environmentally superior to conventional waste to energy

technologies;

• They could significantly increase the life of the Clover Bar landfill and defer the

investment of siting and building a new landfill;

• They would likely be accepted by the public;

• They offer the potential to generate green power and offset fossil fuel usage, resulting in

potential greenhouse gas credits, and

• An innovative thermal project would complement the existing array of world-class

technologies at the Waste Management Centre, and provide the fourth “R” of waste

management, namely the recovery of energy.


Over 150 gasification and pyrolysis technologies available worldwide were screened on the basis of

essential and desirable criteria. Companies that passed the initial screening were then classified as

meeting Tier 1 or Tier 2 criteria. Tier 1 criteria involved having multiple full-scale plants with extensive

operating history. Tier 2 proponents had to demonstrate a full-scale commercial plant recently started up,

or a semi-commercial installation, with a reasonable amount of operating history. Ten companies

satisfied the initial screening criteria and were contacted for budget proposals. In addition, several firms

were contacted for proposals on fluidized bed combustion systems as a benchmark by which to measure

the gasification and pyrolysis technologies.

Budget proposals for advanced thermal systems were received from Brightstar, Enerkem, Thermoselect,

Thide, and WasteGen. Fluidized bed combustion (FBC) proposals were received from Ebara and EPI.

All proposals included order-of-magnitude (+50%, -30%) cost estimates. However, significant data gaps

of varying degrees were identified. These gaps were overcome by an evaluation team comprised of

representatives from the City, EPCOR and Earth Tech, which developed a comprehensive evaluation

model that added in the local factors and missing components. The financial ranking of each submission

is shown in Table ES 1 below, which identifies the tipping or gate fee that would need to be charged to

enable these systems to break even.

Table ES 1 Comparison of Break-Even Tipping Fees ($/tonne of waste residues processed)

Technology/Scenario WasteGen Enerkem Ebara EPI Thide Thermo-

select

Technology type Pyrolysis Gasification FBC FBC Pyrolysis Gasification $/tonne $/tonne $/tonne $/tonne $/tonne $/tonne

1. No green power, no capital grants (base case)

$107 $78 $132 $75 $132 $157

The lowest cost advanced thermal technology was submitted by Enerkem, a Canadian company offering

a gasification process. This is followed by WasteGen, a UK based company offering a German pyrolysis

technology. Enerkem has a full-scale facility that has been operating in Spain since early 2003.

WasteGen has been pyrolysing municipal solid waste in southern Germany since 1987.

The highest price technology is from Thermoselect. This is a Swiss company with a combined pyrolysis

and gasification technology that offers a high degree of sophistication and reprocesses virtually all of the

residuals. Thermoselect has an operating facility in Karlsruhe Germany, which was built in 1999 and

began commercial operation in 2003.

Generally, the range of capital and operation costs for gasification and pyrolysis technologies is higher,

but not significantly different from the range for fluidized bed combustion systems reviewed. This

confirms that the pricing model and the quotations received are in-line with expectations.


In addition to financial evaluations, the advanced thermal recovery systems were rated based on their

ease of permitting and potential acceptance by the community. Thermoselect ranked the highest, due to

its use of gas engines for power production as well as the complete management of residuals. Enerkem

rated second highest, also because of the use of gas engines. However, Enerkem has more residuals to

dispose of than Thermoselect. WasteGen ranked lower because the pyrolysis process is directly coupled

to steam generation, and therefore could be confused with conventional combustion. While technically

the process is distinct and different from combustion, this may not be obvious to the technically

uninformed and could thus make permitting of such a facility more difficult.

An integral part of the selection process was the on-site verification of the leading advanced thermal

recovery technologies. The facilities were Enerkem in Castellon Spain, WasteGen in Burgau Germany,

and Thermoselect in Karlsruhe Germany.

Each of the facilities that was visited was chosen for a different reason. The Enerkem process most

closely meets the vision of a facility for Edmonton, and estimated costs were lowest of all the budgetary

proposals received. WasteGen was selected primarily because the facility has been operating

successfully since 1987, and Thermoselect was considered because it is reported to be the cleanest and

most advanced of all technologies. Review of these facilities does not exclude other technologies from

further consideration in the future.

The Enerkem facility in Spain was observed to be working well under normal operation conditions. The

facility was clean and neat and a good environmental neighbour to surrounding areas. The major

concerns with this technology are related to the feedstock preparation. An extensive process was

required for a waste stream that was already fairly uniform as delivered. By comparison, compost

residuals in Edmonton are much more diverse and will require significant additional processing and

handling. The Enerkem process has only been operating on this scale for about 6 months and therefore

long-term data is not available.

The WasteGen facility in Germany has been operational since 1987. The technology is simple and only

minimal proven pretreatment is required. There are no significant technical concerns with implementation

of this technology. Its disadvantage is that the plant looks like a conventional combustion system, even

though there is a very clear technical difference. If this technology were to be considered for Edmonton,

a thorough education program would be required to enlighten the general public and politicians to the true

nature of this advanced technology.

The Thermoselect process is the most complex of all submittals and is not likely to be confused with

conventional incineration. The process was designed as a high-end waste processing facility to recover,

to the greatest extent possible, energy and recyclable materials. The process is essentially a complex


and diverse chemical plant, which is reflected in high capital and operating costs. The technology’s

features are very low emissions and minimal residues.

All of the referenced facilities were reported to be meeting required environmental standards and there is

no reason to believe that any of the proposed technologies would not meet Canadian and Albertan air

emission standards.

Steps and timeframe for implementation of the considered gasification and pyrolysis technologies would

be similar to those for conventional thermal power plants. All of the considered technologies would

require an estimated 28 to 38 months for engineering, fabrication, construction and commissioning.

Additional time may be required for public consultation and permitting.

Conclusions

There is adequate feedstock in the form of composter and MRF residuals to justify the implementation of

a thermal recovery system. The relatively high heating value of this material compared to mixed

municipal waste makes energy recovery technically viable, and enhances its financial feasibility.

The recovery of energy from residual waste originating at the ECF is the logical final step of a fully

integrated waste management process. The composting and thermal processes complement each other,

resulting in the best utilization of resources, and the least amount of waste going to landfill. Application of

an energy recovery system would confirm and enhance the world leadership position of the Edmonton

Waste Management Centre.

Gasification and pyrolysis are technically viable methods of extracting energy from municipal solid waste.

They are technically distinct from incineration/combustion of waste in mass burn energy from waste

facilities, or fluidized bed systems. Key differences between gasification and combustion are:

Gasification

• Converts feedstock to CO and H2, which is a syngas that can be burned off-site in a

variety of applications, such as reciprocating engines, gas turbines, and steam boilers;

• Syngas can also be used as a feedstock for chemical processes;

• Gasification takes place in a reducing environment, suppressing the creation of

contaminants, such as dioxins, furans, SO2, NOx;

• Syngas clean-up is simplified because of low gas volumes;

• Char can often be re-used in the process;

• Post combustion cleaning of flue gases is often not required, and


• Gasification generates the smallest amount of greenhouse gases of the thermal

processes reviewed.

Combustion

• Converts feedstock to CO2 and H2O directly to heat in an excess air environment;

• Excess air combustion allows contaminants to form, which must be removed with an air

pollution control system;

• Released heat needs to be used immediately and locally;

• Large amount of excess air requires extensive flue gas clean-up system, and

• Ash needs disposal, and may require special handling.

The gasification technologies considered in this study contain some degree of technical and economic

risk, due to their short operating history with MSW on a large scale. The pyrolysis technology under

consideration is well proven, but expensive.

Gasification and pyrolysis technologies can meet all Canadian emission standards and are likely to be

more easily sited and permitted then more conventional combustion systems. However, they are also

more complex than mass burn energy from waste systems.

Economically, and at current power rates, the lowest cost advanced thermal system would require a

tipping fee of about $78 to break even. Electrical energy produced from ECF residuals needs to be

classified as green power, in order to enhance the revenues and overall economics. With additional

capital grants, low cost financing, and favourable green power rates, the tipping fee can be reduced to

below $50 per tonne, which could be competitive with a new, state of the art landfill.

Enerkem gasification is the favoured technology for this project. The system produces a cleaned gas

product (syngas) than can be combusted in reciprocating engines for the production of electricity, while

maintaining low overall costs. Feedstock preparation requirements are not yet well defined and require

further study and additional input from Enerkem. The City and Enerkem are already pursuing pilot testing

of feedstock preparation systems, which will include the opportunity to also do test “burns” of the

produced feedstock.

Permitting of an advanced thermal system is not expected to present major hurdles, however the public

process will have to be well managed.


Recommendations

It is recommended to proceed with planning for an advanced thermal energy recovery project on the basis

of the following steps:

• Verify Enerkem’s position as the preferred technology vendor.

• Obtain design details of feedstock preparation and confirm price.

• Evaluate suitability of waste preparation system for ECF residuals. If necessary, view

similar existing system operating with composter residuals. Conduct testing in Edmonton

at a sufficient scale to be confident of replicability at a commercial scale.

• Consider the construction of a pilot facility for composter residuals only, which would later

be expanded based on the economics, operating experience, and long-term availability of

additional feedstocks. Work through pricing and operations assumptions with technology

vendor to advance from an order-of-magnitude to pre-design level cost estimate.

Compare final costs with published costs for mass burn energy from waste technology.

• Develop a funding model and partnership opportunities for the City of Edmonton and

EPCOR. Consider the option of a public-private partnership.

• Pursue federal and provincial funding opportunities to support innovative technologies for

waste diversion and alternative energy production.

• Determine likely market value of green power and greenhouse gas emission credits, with

implications on the economics of the project.

• Continue to look for opportunities to process other high energy value wastes and thus

increase the scale and economy of the project.

• Integrate the advanced thermal system into the City’s Waste Management Strategic Plan.

Take advantage of synergies with other Edmonton Waste Management Facilities:

− Design the ECF tipping floor as a single clearinghouse and processor for residential

waste (premium organics to the composter, residuals to the gasifier).

− Assess the savings and returns of burning landfill gas along with syngas from the

gasifier for the generation of power.

− Determine feasibility of utilizing low grade heat for winter heating of Edmonton

Compost Facility areas, such as the tipping floor.

• Consider a guided tour for the City/ EPCOR review team of the Burnaby mass burn

facility in BC, which is a state of the art facility that has been in operation for over 10

years.

Final Report January 2004 Page 1

1.0 BACKGROUND AND HISTORY

1.1 History and Context

The City of Edmonton (the City) owns and operates North America’s largest composting plant, which

plays an essential role in the City’s Waste Management Strategy and is an integral component of the

Edmonton Waste Management Centre. Operated in conjunction with the composting plant is a materials

recovery facility (MRF). The facility accepts recyclable materials from the City’s Blue Bag and Blue Bin

programs, and from recycling depots (approximately 40,000 tonnes per year). The compost plant is

designed to accept 190,000 tonnes of residential waste per year, and helps the City achieve a residential

waste diversion rate of over 60 percent.

The Edmonton Composting Facility (ECF) accepts mixed residential waste, and through a series of

process steps, removes the non-compostable fraction from the putrecible organics. This residue from the

composter comprises about 70,000 tonnes per year and has two outstanding features:

• It has a high calorific value, and

• It takes up a disproportionate volume of scarce landfill space due to its low density.

Therefore, the City, in partnership with the EPCOR Power Development Corporation (EPCOR), a City

owned utility company and power retailer, decided to explore innovative ways to:

• Capture and utilize the energy content of the waste, and

• Reduce the volume of residuals going to the landfill to the extent possible.

While conventional energy from waste technology utilizing mass burn combustion can achieve these

goals, it creates residuals and emissions that are perceived to be undesirable. Thus, the City and

EPCOR are looking for new and innovative ways to achieve their goals. For this study, gasification and

pyrolysis are being explored as innovative alternatives.

Innovative thermal treatment systems offer additional incentives:

• They offer the potential to offset fossil fuel usage, resulting in potential greenhouse gas

credits;

• An innovative project would complement the existing array of world-class technologies at

the Waste Management Centre, and provide the fourth “R” of waste management,

namely the recovery of energy, and

• One component of syngas is hydrogen, which has a possible application in the

developing fuel cell industry.


1.2 Approach

This report was prepared by Earth Tech in collaboration with the City of Edmonton and EPCOR.

Technology review and assessments were provided by Juniper, a United Kingdom based firm,

internationally recognized for its publications on gasification and pyrolysis technologies. Funding

assistance came through the Green Municipal Enabling Fund, administered by the Federation of

Canadian Municipalities (FCM). The Alberta Plastics Recycling Association (APRA) has also assisted

with in-kind contribution of technical expertise.

All parties worked closely together in defining the parameters for technology selection. The intent was to

be able to identify and recommend leading edge technologies without exposing the City and EPCOR to

undue technical and financial risks. A two-tiered evaluation system was jointly developed and applied to

all known gasification and pyrolysis technologies by Juniper. This resulted in a short-list of technologies

that could be considered for Edmonton. Short-listed firms were contacted by Juniper and requested to

provide budget proposals. The results of this exercise were summarized by Juniper and presented to

Earth Tech for further consideration.

Based on the information from Juniper, a financial summary sheet was developed to achieve comparable

numbers. In it, allowances were added for local factors and items not provided by the individual vendors.

The summary sheet was used to select the three technologies with the most favourable ratings and which

would be visited by engineers from the City, EPCOR, and Earth Tech.

Subsequent to the on-site verification of the three favoured technologies, Earth Tech summarized all data

and finalized the report. Information from Juniper was received in stand-alone sections, which are

included in the appropriate locations. Juniper’s input has been incorporated as supplied and consists of

the following sections and subsections:

• Pyrolysis and Gasification Theory and Practical Applications (3.1)

• Technology Selection Criteria (3.2)

• Technology Initial Short-listing, Classification and Status (3.3)

• Technology Description (Pyrolysis and Gasification) (3.4)

• Other Relevant Technologies (3.5)

• General Technology Description (Fluidized Bed Combustion) (3.5.1)

• Feed Preparation Requirements (4.0)

• Residues and Residue Disposal (5.0)

• Review of Heat Recovery/Cogeneration Options (6.0)

• Syngas Cleaning Process (8.2)


• Fluegas Cleaning Process (8.3)

• Comparison of Current Canadian, USEPA and EU-WID Emissions Standards (8.4)

• Evaluation of Budgetary Proposals (Appendix A)

• Technical Process Specification (Appendix B)


2.0 WASTE GENERATION RATES AND SIZING

2.1 General

In order to determine the size and capacity of an energy recovery facility it is necessary to obtain a

consistent and dependable supply of fuel or feedstock. Ideally, it would have a high calorific content, not

contain any contaminants, and not produce any hazardous by-products. The feedstock must also be

readily and economically available in order to make the project feasible. This project is based on the

need to manage the large volume of waste residuals produced at the City of Edmonton Compost Facility

(ECF), and a smaller amount from the City of Edmonton Materials Recovery Facility (MRF). Additional

fuels/feedstock considered are solid wastes generated by local surrounding communities and waste

generated by local industrial/construction activities (i.e. wood waste, plastics).

2.2 Feedstock from City of Edmonton Facilities

Municipal solid waste (MSW) generated in the City of Edmonton is collected in two separate streams

(recyclables and mixed wastes) and taken to the Waste Management Center, where it is processed either

at the MRF or at the ECF. In total, the ECF generates approximately 67,000 tonnes per year of finished

compost. The City of Edmonton has estimated that the residual waste stream produced from the two

facilities represents 30 percent to 40 percent of the total MSW processed. The residuals that are

produced at these facilities are generally not suitable for further recycling or composting, however the

residuals have a large calorific content, potentially suitable for recovery. Currently the waste residuals

are being landfilled.

2.2.1 Compost Facility

The design and operation of the ECF generates residuals at three locations: the pre-sort, the primary

screen and the secondary screen. The pre-sort removes the oversized and hazardous materials, for

proper disposal. The pre-sort residuals are not a suitable fuel source and were excluded from further

consideration. The primary screen, located immediately after the digesters, removes items larger than 75

mm in size. The secondary screening process removes items greater than 25 mm and then 10 mm in

size, after the material is composted in the Aeration Building. The following tables present a breakdown

of the composition of the residuals produced at both screen locations.


Table 2.1 Composter Primary Residuals - Summary of Composition*

Primary Residuals Average Fraction

(percent by weight)

Weight (tonnes per

year)

Textiles 22 7,280 Film plastic 25 8,367 Rigid plastic 19 6,385 Ferrous metal 16 5,328 Compost 5.9 1,968 Wood 5.7 1,917 Rubber 2.2 736 Paper 1.9 623 Non-ferrous metal 1.4 466 Foam 0.40 141 Rock/concrete 0.50 175

Glass 0.04 12

TOTAL 33,398

Table 2.2 Composter Secondary Residuals - Summary of Composition*

Secondary Residuals

Average Fraction (percent by weight)

Weight (tonnes per

year)

Textiles 7.5 2,741 Film plastic 12 4,293 Rigid plastic 14 5,109 Ferrous metal 2.5 897 Compost 26 9,450 Wood 6.5 2,368 Rubber 0.3 117 Paper 13 4,776 Non-ferrous metal 2.4 871 Foam 0.40 128 Rock/concrete 2.3 834 Glass 8.8 3,206 Bone 1.1 417 Batteries 0.80 285

Ceramic 3.0 1,109

TOTAL 36,604

*Note: Composition data, based on waste sort completed by the City of Edmonton, August 2002.

In summary, approximately 33,400 tonnes per year of primary residuals and 36,600 tonnes per year of

secondary residuals are generated for a total tonnage of 70,000 tonnes. From the composition tables it

can be seen that the residuals contain high percentages of plastic, paper and compost. The tonnage of

these residuals is based on the current amount of MSW that is being processed at this facility. Future


increases are possible if the composting process is further optimized, and additional volumes of MSW are

accepted (from surrounding communities and a growing City population).

2.2.2 Materials Recovery Facility

All residents of the City of Edmonton are encouraged to recycle their waste through either a curb side

pick up program, multi-family/apartment recycling bins or by using the recycle depots that are located

throughout the city. These materials are processed at the MRF, located at the Waste Management

Centre. The availability of the program and local participation rate has been expanding over the last

number of years and approximately 40,000 tonnes of material are processed at the MRF annually. The

facility sorts the recyclable material into categories such as paper, cardboard, plastics, metals, and glass.

During the sorting process, non-recyclable materials are removed and discarded.

Approximately 45 percent of the MRF residuals originate from the rigid container line and 55 percent of

the residuals are generated by the presort, film and fibre lines. The following tables present a summary

of the waste residuals from the MRF. Since this waste is processed and consistent, it is expected that it

could be a suitable source of feedstock to augment the residuals from the ECF. The current quantity of

discards from the MRF is 3,250 tonnes per year. Tonnage is expected to increase proportionally with

population growth.

Table 2.3 Residuals MRF Rigid Line – Summary of Composition*

Rigid Line Average Fraction (percent by weight)

Paper 49

Food 0.50

Yard Wastes 0.40

Metal 2.0

Aluminum 0.5

Glass 14

Plastic 31

Textiles 0.80

Other Organic 0.90

Other Waste 0.50

Household Hazardous 0.10

Total Generated 1,460 tonnes


Table 2.4 Residuals MRF Fibre Line – Summary of Composition*

Fibre Line Average Fraction (percent by weight)

Paper 51

Food 1.2

Yard Wastes 0.00

Metal 7.0

Aluminum 0.80

Glass 1.6

Plastic 34

Textiles 1.3

Other Organic 3.1

Other Waste 0.20

Household Hazardous 0.00

Total Generated 1,790 tonnes

*Note: Composition data based on waste sort completed by the City of Edmonton, August 2002.

2.2.3 Municipal Solid Waste Generated by Surrounding Communities

MSW generated by local communities is also a potential source of raw materials. Ideally, this MSW

would first be processed by the composter to remove the wet organics, which do not have a high heating

value. This potential feedstock would be a dependable source (annual tonnage generated increases as

population increases) and be consistent in composition.

Table 2.5 summarizes the MSW landfilled (domestic and commercial) at the following regional waste

disposal sites located in the area surrounding the City of Edmonton. Since this waste stream would be

expected to be consistent, this waste would be a suitable source of material to augment the existing

feedstock produced from the residential wastes collected within the City of Edmonton.

Table 2.5 Summary of MSW Generated in Local Counties

Location MSW

(tonnes/year)

County of Leduc Landfill 34,480

Sturgeon County Landfill 14,985

Strathcona County 15,000

Parkland County 10,000

Total Generated 74,465


For the purpose of calculating the amount of energy available from the MSW originating in surrounding

communities, it is assumed that the MSW would be processed through the compost facility or a similar

process and 35 percent of this waste would become residuals. Therefore, there is the potential to

augment the feedstock with 26,000 tonnes per year of residuals from the surrounding communities.

2.2.4 Other Potential Fuel Sources

Edmonton’s commercial and industrial waste stream has numerous sources of materials that could be

suitable for an innovative energy recovery process. Due to high variability in these streams, plus the fact

that the City does not control the material flow, the decision was made to examine only elements of these

streams that could be particularly beneficial to the project. A review of previously completed reports and

conversations with local contractors has determined that other potentially dependable feedstocks include

wood waste and plastics. Hydrocarbon (petroleum based) wastes are also available in the local market,

however, a decision was made early in the project to not consider this material as a potential feedstock at

this time, though other parallel initiatives are examining this opportunity closely.

2.2.4.1 Wood Waste

A considerable volume of wood waste is generated in the City of Edmonton on an annual basis. A recent

study completed for the City of Edmonton indicated that up to 380,000 tonnes of wood waste (all types) is

generated in the Capital Region annually. This study indicated that approximately 60 percent of this

tonnage (230,000 tonnes) may be slightly contaminated with other materials while the remaining 40

percent (150,000 tonnes) may be significantly contaminated (primarily construction and demolition

waste). A large percentage (90 percent) of the slightly contaminated wood waste is diverted from landfills

and is available at market price ($20 to $25 per tonne). Approximately 95 percent of the significantly

contaminated wood waste is currently being landfilled since it contains large amounts of building

materials (drywall, metals, concrete). Some of the hurdles for diverting this waste from a landfill and

using it in an advanced energy recovery process include:

• Some categories of wood waste are co-mingled in other wastes streams such as

Industrial, Commercial, and Institutional (ICI) waste, and therefore recovery of the wood

portion may be difficult and costly;

• Wood waste included in commercial-demolition waste is seen as a revenue stream for

Class 3 landfill operators and therefore will be less available for thermal treatment;

• Moisture content varies;

• Some wood wastes may contain preservatives, which may generate unwanted

emissions, and

• Most wood waste needs to be purchased, which negatively affects the economics of the

energy recovery system.

Table 2.6 presents a summary of the wood wastes available in the Capital Region.


Table 2.6 Summary of Wood Waste Generated in Capital Region

Quantity Available Current

Disposition Item

Description (tonnes per year) (percent)

Category 1 Clean chip, shavings, medium density fibreboard dust 100,000-120,000 95 % reused

Category 2 End cuts, broken dimension lumber 35,000-45,000 90 % reused Category 3 Whole pallets and crates 50,000-65,000 Unknown Category 4 Green wood (chipped) 45,000-70,000 75 % reused Category 5 Construction, renovation, demolition 40,000 95 % landfilled Category 6 Miscellaneous wood waste (ICI) 31,000 95 % landfilled Category 7 Residential wood waste 8,100 50 % landfilled

Totals 309,000-379,000

Source: City of Edmonton and Capital Region Select Waste Materials Supply Study, Randall Conrad & Associates Ltd., 2001.

Interviews with local wood waste contractors have indicated that 50,000 tonnes of chipped wood waste

(of various categories) would be available in the Edmonton area in a long-term contract (i.e. 5 to 10

years) at approximately $15 to $25 per tonne.

The interviewed contractors indicated there is currently one stockpile of wood waste in the Edmonton

area, which contains approximately 100,000 tonnes. A number of other small stockpiles containing 1,000

to 2,000 tonnes each also exist in the Edmonton area. These stockpiles contain various types of wood

waste and may contain suitable feedstock. Local contractors have indicated that due to the high tipping

fees, generators of waste wood have been looking for alternative disposal options such as at the AB Tech

facility located near Highways 16 and 60.

2.2.4.2 Plastic Waste

A waste material supply study completed by Randall Conrad & Associates in 2001, determined that there

were approximately 57,000 tonnes of plastic waste generated annually in the Edmonton area. Plastic

wastes are a desired feedstock since they have a high calorific content. The plastic waste is divided into

categories depending on the composition of the plastic (e.g. high density polyethylene (HDPE),

polystyrene, polyethylene terephthalate (PET)). Table 2.7 summarizes the plastic wastes generated in

the area.


Table 2.7 Summary of Plastic Waste Generated in Capital Region

Amount Current Disposition Type (tonnes per

year) Percent

Recycled Percent

Landfilled

PET 1,428 60% 40%

HDPE natural 2,571 50% 50%

HDPE colored 3,553 25% 75%

Polypropylene containers 1,975 20% 80%

Recyclable plastic film 10,853 10% 90%

Non-recyclable plastic film 14,424 0% 100%

Polystyrene rigid 4,073 0% 100%

Polystyrene foam 1,022 0% 100%

Composite Containers 1,714 0% 100%

Other plastics 6,241 0% 100%

Miscellaneous 3,154 0% 100%

Flexible Polyurethane Foam (carpet backing and car seats)

6,100 30% 70%

Total 57,000

Source: City of Edmonton and Capital Region Select Waste Materials Supply Study, Randall Conrad & Associates Ltd., 2001.

The above table shows that approximately 60 percent of the plastic waste stream is not recycled, and

provides an additional potential source of feedstock for an energy recovery facility.

An interview with a local Edmonton contractor who shreds wrecked automobiles for resmelting indicates

that there is a large supply of auto-shredder residue (ASR) which contains a high percentage of rigid and

foam plastics, and that there is only a small local market. This contractor indicated that they are currently

landfilling 9,000-12,000 tonnes of ASR per year and would be willing to pay for a portion of the hauling

fee to remove the material offsite. This material has potential as feedstock due to its high energy content

and homogeneous nature.

Other sources of plastic waste material in the Edmonton that are available but costly to segregate and/or

collect, are:

• Approximately 1,500 tonnes of plastic waste annually from the disposal of computers,

TVs, and electronic equipment. Recovery might be enhanced if the province proceeds

with plans to implement a deposit funded take back system. The Government of Alberta


is looking at the possibility of establishing an electronic waste program, which may be

similar to the existing tire recycling program (arrangements would be made to collect old

electronic products from communities, so they do not end up in landfill).

• 3,500 tonnes of scrap polypropylene bailer twine annually.

2.2.4.3 Agriculture Crop Waste/Biomass

A brief literature review was conducted into the feasibility of using biomass or agriculture crop residual as

feedstock.

In 1994, Cochrane-SNC-Lavalin completed a study titled “Assessment of the Potential Use of Biomass

Resources as a Sustainable Energy Source in Saskatchewan” on behalf of the Saskatchewan Energy

Conservation and Development Authority.

This study looked at three main biomass materials, agricultural and croplands, forested lands, and

municipal wastes in order to identify and quantify sustainable energy sources. The following is a brief

summary of the agricultural and forestry portions of the report.

Cropland – Agriculture

Areas with black and grey Chernozemic soils (typical to the Edmonton area) have a higher potential to be

developed as a bio-energy source since they typically have higher yield crops with higher amounts of

crop residues per acre compared to other soil types. Agronomic studies have shown that it is possible to

move a portion of the crop residue off black soil fields and still leave a substantial amount of crop residue,

required for nutrient recycling and for soil protection. However if too much residue is removed, there is the

possibility that the soils would be more prone to wind and water erosion, and yields would decline due to

the reduction of soil organic matter.

This study indicated that between 1 million tonnes and 2 million tonnes of crop residuals would be

available annually in the black soil zone region of Saskatchewan (The large range is a result of two

variables: the type of crop (e.g. oil seed, wheat, rye) and the yield in a given year. The lower end of the

range was based on the worst year yield in the past ten years and the higher value was based on yields

on an average year). The amount of energy available from this material was estimated between 16 PJ

and 32 PJ.

The cost of the raw material was estimated between $40 per tonne for straw or chaff and $46 per tonne

for poor quality hay provided that the hauling distance was less than 50 km. Although these numbers are

for Saskatchewan, it has been assumed that they would also apply to central Alberta, which has similar

soil conditions.


Forested Land

This study looked at using wood waste generated from logging operations was well as growing biomass

on a plantation. This study indicated that energy plantations are a relatively new idea in Canada and

there is a lack of information to indicate the feasibility of this method since there currently are no large-

scale operations in Canada. This study determined that approximately 1 million tonnes of wood material

could be grown annually in Saskatchewan on marginal farmland however the cost for the production of

the fuel could be as much as $60 to $75 per tonne.

Based on the current level of research completed on dedicated energy plantations, it appears that

growing energy feedstocks is currently very expensive and not attractive for an energy recovery facility

where the economics would be based on charging a tipping fee to accept feedstock.

2.3 Summary of Potential Energy Available

Table 2.8 presents a summary of the potential energy, based on the higher heating value (HHV) and

annual production of all the above-described feedstocks. A graphical representation is shown in Figure

2.1. The following assumptions were made in the calculation of the amount of energy that may be

available:

• Residential MSW accepted from local communities is first processed in the composter to

generate additional residuals;

• Amount of wood waste assumed available is 50,000 tonnes since this is the amount that

the contractors indicted would be easily available on a long-term contract;

• Local auto recyclers have indicated that approximately 9,000 tonnes per year of plastic

feedstock is readily available in the Edmonton area. This waste material would be in the

form of ASR. This is a conservative estimate of the amount of plastic waste available.

Other non-recycled plastic material could be available, however, it may potentially be

mixed and contaminated with other wastes and therefore the quality of the feedstock may

be inconsistent and unsuitable for use in an advanced thermal recovery technology

without additional processing. The additional plastic waste materials have not been

included in the calculation at this time, and

• The energy available from the finished compost produced by the ECF is presented in the

table for information purposes, however this material is not foreseen as a feedstock.


Table 2.8 Summary of Potential Energy Available

HHV Production Energy Sample

(kJ/kg) (tonnes/yr) (GJ/yr)

Composter residuals 17,022 70,004 1,217,842 MRF fibre line residuals 33,555 1790 91,900 MRF rigid residuals 25,015 1460 22,800 Wood waste (various types) 16,920 50,000 846,000 Local Municipalities 17,171 26,061 498,916

ASR 18,840 9,000 169,560

TOTAL 158,315 2,847,018

Finished Compost (for information only) 7,425 66,700 495,000

Figure 2.1 Summary of Energy Available for Residuals

2.4 Equipment Sizing

At a project review meeting, it was decided by all participants (City of Edmonton, EPCOR, Earth Tech,

and Juniper) that potential energy recovery systems would be sized only for the amount of residue

material that is secure, plus not more than 50 percent of additional known waste, such as wood and ASR.

It was agreed that technology selection would focus on 50,000 tonne per year modules for a total plant

capacity not exceeding 100,000 tonnes per year. Single modules between 50,000 and 80,000 tonnes per

year would also be considered.

Composter Residuals42%

MRF Residuals4%

Wood waste (various types)30%

Local Municipalities18%ASR

6%

Wood waste (various types) Local Municipalities ASR Composter Residuals MRF Residuals


3.0 ADVANCED THERMAL TREATMENT OPTIONS

3.1 Pyrolysis and Gasification Theory and Practical Applications

3.1.1 Gasification Background

Major development of gasification processes occurred in the 1970’s and 1980’s in response to the two

major oil crises when supplies to the West from Middle Eastern sources were severely curtailed. The

developments were therefore mainly aimed at using coal as a fuel, to provide a strategic alternative

energy source to crude oil.

The impetus to apply gasification technology to MSW grew out of concern about the mounting problems

associated with MSW disposal, including diminishing landfill volumes, groundwater contamination from

landfill leachates and the technical problems associated with the early combustion technologies applied to

the incineration of MSW. The production of energy from MSW gathered pace in the mid-1980’s as it was

believed that the days of cheap and abundant energy were over.

3.1.2 Gasification Theory

Gasification is a thermal upgrading process (see Figure 3.1), in which the majority of the carbon in the

waste is converted into the gaseous form (syngas), leaving an inert residue (char). The upgrading

process involves the partial combustion of a portion of the fuel in the reactor with air, pure oxygen, and

oxygen enriched air or by reaction with steam. The energy content of the waste is therefore transferred

into the gas phase as chemical energy, which can be utilized to generate power. The components in

syngas also make it potentially suitable for use as chemical feedstock.

Relatively high temperatures are employed: 900 to 1100oC with air and 1000 to 1400oC with oxygen. Air

gasification is the cheaper of the two options, but results in relatively low energy gas, containing up to 60

percent nitrogen, with a heating value of 4 to 6 MJ/Nm3. Oxygen gasification gives a better quality gas of

10 to 18 MJ/Nm3 1 but, of course, requires an oxygen supply. The advantages and disadvantages of

using oxygen from an economic and technical perspective are complex and have to be considered on a

project-by-project basis.

1 cf. Natural gas has a heating value of 37 MJ/Nm3


The gasification process involves a number of reversible reactions. Some of these reactions have been

well characterized and reviewed, and determined to be key steps in the gasification process. These

reactions are listed below:

Solid-Gas Reactions COOC 22

1 ↔+ Partial Combustion Endothermic

22 COOC ↔+ Combustion Exothermic

42 CHH2C ↔+ Hydrogasification Exothermic

22 HCOOHC +↔+ Water-gas Endothermic CO2COC 2 ↔+ Boudouard Endothermic

Gas-Gas Reactions 222 HCOOHCO +↔+ Shift Exothermic OHCHH3CO 242 +↔+ Reforming Exothermic

Syngas essentially comprises all of the reaction products and some of the unconverted reactants such as

carbon (ash), oxygen and nitrogen (when air gasification is used). In addition to these products, traces of

other organic and inorganic compounds are produced or released in the waste gasification process, and

these also appear in the syngas. Figure 3.1 is a representation of the gasification process. Syngas

utilization options are discussed in Section 6.

Source: Juniper

Figure 3.1: Schematic Representation of Gasification and Syngas Utilization Options

Gasif icat ion Reac t or

Gas Engine or

Gas Turbine

Syngas Cleaning

Waste

Ash or SlagAir, O2, Steam

SyngasCO, H2, (N2)Dust , Tars,

S, Cl Compounds

Pow er & Heat

Residue

Exhaust Gases

Chemicals

CH3OH, H2, NH3

Boi le r + St eam Turb ine


In waste gasification the aim usually is to maximize the levels of CO and H2 in the syngas, which

increases the flexibility in utilizing the syngas as a source of energy and as chemical feedstock. To this

end operating conditions such as temperature and pressure are manipulated to optimize the yield and

composition of the syngas for its end use. For example, by increasing the gasification temperature the

rate of the reaction increases as well as the rate of production of CO and H2. However, a higher operating

temperature comes at a cost of greater energy input to the gasification process and higher reactor

materials costs. Thus, there is a delicate balance, unique to each process, to maximize certain

parameters while minimizing costs.

3.1.3 Pyrolysis Background

Pyrolysis is different from gasification and combustion, which are usually autothermic reactions. It is

endothermic requiring an input of energy, typically applied indirectly through the walls of the reactor.

Pyrolysis offers more flexibility than gasification in terms of possible products, since the technology yields

char, oils and syngas. These products could be utilized in various markets, providing added value. In

practice this flexibility is not commonly utilized. Originally, the main focus was on deriving bio-fuels (i.e.

liquid fuels from biomass) but the economics of this approach are uncertain. Many process companies

have now changed their emphasis to power production because of the more certain and favourable

economics for electricity. To this end, syngas and oil, and sometimes char derived from the pyrolysis

processes are combusted to raise steam for electricity generation.

3.1.4 Pyrolysis Theory

Pyrolysis is the thermal degradation of carbonaceous materials usually at temperatures between 400oC

and 600oC either in the complete absence of oxygen, or with such a limited supply, that gasification does

not occur to any appreciable extent. Such processes de-volatilize and decompose solid organic materials

by heat; consequently, no combustion is possible. The products of pyrolysis always include gas, liquid

and solid char with the relative proportions of each depending on the method of pyrolysis and the reaction

parameters, such as temperature, heating rate, pressure and residence time. In general, lower

temperatures produce more liquid product and high temperatures produce more syngas. A schematic

diagram for pyrolysis is presented in Figure 3.2.

Some pyrolysis processes are operated at 800oC or greater, and in such processes the main product is

syngas. In Juniper’s classification such processes are referred to as Thermal Gasification. These

processes also produce char and tar droplets. Figure 3.3, Mechanism for Waste Pyrolysis, is a

representation of waste pyrolysis.


Heavy tar

Cracking

Cracking

Thermal degradation

Thermal degradation

Recombination

Cracking

Cracking

Evaporation

Evaporation

Repolymerization

Primary reactions Secondary reactions

Waste/Fuel

Light Oil

Syngas

Light Oil

Char

Heavy Tar

Pyro lys is Reac t or

Boi ler , Engine or Turb ine

Energy Rec overy

Wast e

Char

Oi lH2O, C6 +

Pow er & Heat

Residue

Exhaust Gases

Chem ic a ls

CH3OH, H2, NH3

Indirect Heat

SyngasCO, H2, CxHy (C1-C6)

Gas Cleaning

Source: Juniper

Figure 3.2: Schematic Representation of Pyrolysis

Figure 3.3: Mechanism for Waste Pyrolysis


3.1.5 Some Effects of Temperature and Pressure in Pyrolysis

An increase in pyrolysis temperature usually decreases the char yields because of the greater conversion

of the solid hydrocarbon and oil fractions to gases. The specific quantity of char produced is dependent

upon the heating rate used, the time the solids are held at the final pyrolysis temperature and

characteristics such as the size, shape and orientation of the solids in the pyrolysis reactor. Pyrolysis

carried out under vacuum causes a reduction in the vapour residence time in the pyrolysis reactor and

therefore decreases the likelihood of secondary gas-phase reactions, which would normally reduce the

levels of heavy organics (oils) in the pyrolysis products. Table 3.1 summarizes the various pyrolysis

processes and the influence of parameters such as temperature, pressure, residence time and heating

rate on the nature of the pyrolysis products.

Table 3.1 Summary of Pyrolysis Processes

Technology Residence Time Heating Rate Temperature (oC)

Major products

Carbonization Hours-days Very Low 300-500 Charcoal

Pressure Carbonization

15min -2hr Medium 450 Charcoal

Hours Low 400-600 Char, liquids, syngas

Conventional Pyrolysis

5-30min Medium 700-900 Char, syngas

Vacuum pyrolysis 2-30 sec Medium 350-450 Liquids

0.1-2 sec High 400-650 Liquids

< 1sec High 650-900 Liquids, syngas

Flash Pyrolysis

< 1sec Very High 1000-3000 Syngas

Source: Juniper (modified from Klass)

3.1.6 Practical Applications of Gasification and Pyrolysis

Gasification and pyrolysis technologies have been developed for treating a number of waste streams.

The waste streams treated include MSW, Refuse Derived Fuels (RDF), ASR, sewage sludge, biomass,

scrap tires, Mixed Plastic Waste (MPW), and Electrical and Electronic Scrap Residues (EESR).

As shown previously in Figure 3.1, gasification produces a syngas and ash or slag. The quality of the

syngas differs between processes, which is a result of the initial waste calorific value (CV) and the

gasifying agent (air, steam or O2) used. The syngas can be utilized for energy generation or as a

chemical feedstock (see Figure 3.4). The former is normally preferred on commercial grounds.

Extraction of hydrogen from the syngas for fuel cells is one of the newer applications for syngas currently


being researched and developed. Some gasification processes produce a slag that may be reused as a

civil engineering raw material, but the ash produced in many gasification processes is landfilled.

Final Products Processing Technology

Synthesis

Turbine

Synthesis

Engine

Boiler

Primary Products

Conversion Technology

Gasification

Medium CV syngas

Low CV syngas

Methanol

Hydrogen

Fuel alcohol

Ammonia

Electricity

Electricity

Source: Juniper (modified from Bridgwater)

Figure 3.4: Applications for Syngas from Gasification Processes

Pyrolysis processes (see Figure 3.2) produce char, oil and syngas. The syngas can be used in a similar

way as describe above. Pyrolysis oils are high in heavy organics and could be used as fuel oil or distilled

to lighter fuels or chemical products (see Figures 3.3 and 3.5). The char from some pyrolysis reactors

has a high CV and could be combusted to recuperate some of its energy value.


Source: Juniper (modified from Bridgwater)

Figure 3.5: Applications for Pyrolysis Products

3.2 Technology Selection Criteria

3.2.1 Objective

The objective of this initial review, which has been undertaken by Juniper, was to conduct a screening of

the technologies known to Juniper and produce a short-list for further more detailed consideration. The

options for energy recovery and utilization from the syngas produced by the gasification process, or via

close-coupled combustion and the steam cycle, were also reviewed. The aim was for the City of

Edmonton to provide direction as to which energy utilization route was preferred to facilitate the selection

of the final three or four gasification processes to which reference plant visits would be made. A fluidized

bed combustion technology/supplier would also be selected.

3.2.2 Review Process

Juniper’s database of gasification and pyrolysis processes currently contains more than 150 companies

with processes that are at various stages of development from concept to fully commercial. Juniper staff

assess these technologies on an ongoing basis. For the City of Edmonton’s project, they considered

which of these many processes could potentially be utilized for the City’s application and then applied the

agreed screening criteria (see below) to develop a short-list of the most suitable processes.

A meeting was held at the offices of the Asset Management and Public Works Department in Edmonton

on 4 July 2002 and a list of criteria was developed that the short-listed technologies must meet. These

criteria were categorized as “essential” or “desirable”.

Pyrolysis

Oil Upgrading

Slurry

Engine

Turbine

Refining

Charcoal

Syngas

Extraction

Mixing

H’carbons

Conversion Technology

Primary Products

ProcessingTechnology

Intermediate Products

ProcessingTechnology

Final Products

Water

Electricity

Transport fuels

Chemicals

Boiler


3.2.2.1 Essential Criteria

Six essential criteria were identified (see Table 3.2) and these were used to determine the primary

shortlist of technologies. See Table 3.4 for Juniper’s criteria for assessing commercial status.

Table 3.2 Essential Criteria

Parameter Measure

Waste type/suitability Technology must be capable of handling and processing compost rejects and RDF

Process must be fully commercial based on Juniper’s current classification method (Tier 1), or

Status

Process must be currently operating as a demonstration facility at a scale of 50,000 tonnes per year or at a scale which would require a maximum scale-up of 3 times (Tier 2)

Process must be a net producer of energy Energy recovery/utilization

Combustion of dirty syngas is acceptable if it is part of an integrated process

Process must be able to meet the most stringent European emission requirements (WID), if applicable

Environmental impact

Process must not produce a hazardous residue which is difficult to handle and dispose of

Supplier credibility Potential suppliers must be credible organizations with the necessary engineering and financial resources to design, construct, commission and warrant such a process

Process must not be a combustion process or be perceived as combustion

Exclusions

Use of the syngas to generate steam as the final product for sale to potential over-the-fence customers

3.2.2.2 Desirable Criteria

Some desirable criteria (see Table 3.3), specifically those relating to flexibility and reference plants, were

also used to determine the primary shortlist of technologies included in the interim report.


Table 3.3 Desirable Criteria

Parameter Measure

Flexibility of feedstock acceptability Flexibility Amount of further pre-processing required (front-end simplicity) Environmental impacts

Amounts and types, if any, of emissions to air, liquid effluents and solid residues Capital costs Economics Operating costs

Reference plants Availability of reference facilities to visit and assess

3.2.2.3 Commercial Status

Juniper’s criteria for assessing the commercial status of processes are given in Table 3.4 below:

Table 3.4 Commercial Status Criteria

Criterion Description

Tier 1 Fully commercial Multiple full-scale plants have been built for more than one

customer, and have been operating satisfactorily for more than 2 years on a relevant feedstock and at appropriate scale

Tier 2 Semi-commercial A full-scale commercial plant for a similar application has been

handed over to a customer, or is operating satisfactorily under a build, own, operate (BOO) contract, and further opportunities are being pursued

Demonstration A semi-commercial installation has been completed at a scale beyond a pilot plant. This plant is being commissioned or is already being operated as a first reference installation, often by the developer themselves

3.3 Initial Technology Short-listing, Classification and Status

The analysis identified 10 companies with proprietary processes that are considered technically suitable

for this application and which meet the screening criteria outlined above. This does not imply that all

would either be willing to quote or would be considered satisfactory in commercial terms. The search was

global in scope but the process resulted in a list that emphasizes two countries: Japan (4 suppliers), and

Germany (3 suppliers). The list also contains 1 Norwegian, 1 Canadian and 1 Australian company.

Figure 3.6 lists the technologies that Juniper has passed through the short-listing process classified

according to the type of process option for which they are potentially suitable. See Section 6.0 for a

review of the process options. Note that two companies (PKA and Nippon Steel) appear twice.


Source: Juniper

Figure 3.6: Short-listed Pyrolysis and Gasification Technologies

Gasification/Pyrolysis

On-site Gas Engines On-site Close-CoupledCombustion

Off-site Clover BarPower Station

Slag Ash/Char Slag Ash/Char Slag Ash/Char

CleanedSyngas

Dirty Syngas

LurgiThermoselect

BrightstarEnerkemPKA(Toshiba)

EbaraMitsuiNippon Steel

EnergosThide

Nippon Steel WasteGenThidePKA(Toshiba)


The classification and status of technologies is detailed in Table 3.5.

Table 3.5 Classification and Status of Technologies

Technology/Supplier Country Status Reference plants/Comments

On-site power generation via gas engines or close-coupled combustion system Energos Norway Tier 1 A number of commercial plants operating in

Norway and Germany Nippon Steel Japan Tier 1 16 commercial operating plants in Japan. Normal

design employs close-coupled combustion and steam cycle power generation. Could be designed to produce dirty syngas for Clover Bar

PKA Germany Tier 1 2 commercial plants in Germany, both designed to clean the syngas, one uses gas engines the second uses the syngas in an aluminum melting furnace

Thermoselect Switzerland Tier 1 One plant operating in Germany and a second built by a licensee in Japan

Thide France Tier 1 2 reference plants operating in Japan on MSW and a 3rd plant being built in Japan by the licensee (Hitachi) and a 4th plant scheduled for completion in France in 2003.

Brightstar Australia Tier 2 One 50 kTpa demonstration plant in extended commissioning trials near Sydney (Wollongong)

Ebara Japan Tier 2 One commercial plant for ASR with 4 MSW plants under construction in Japan

Enerkem Canada Tier 2 One demonstration plant (25 kTpa) for plastic-rich waste almost operational in Spain. 50 kTpa MSW plant planned for Canada

Lurgi Germany Tier 2 One large 40 Tph plant in commissioning in Germany

Mitsui Japan Tier 2 One 66 kTpa MSW plant in operation in Fukuoka, Japan and a second plant of 120 kTpa for Aichi

WasteGen Germany Tier 2 Previously operated as Mannesmann and then acquired by Technip. TechTrade is now the owner of the technology and the company employs the main technical and engineering expertise. 32 kTpa plant in Germany has operated on MSW since 1987. A second 100 kTpa plant for MSW has been also been constructed in Germany

Off-site syngas utilization at Clover Bar Power Station Nippon Steel Japan Tier 1 See above Thermoselect Switzerland Tier 1 See above Thide France Tier 1 See above Enerkem Canada Tier 2 See above PKA Germany Tier 2 See above WasteGen Germany Tier 2 See above


Juniper sent out enquiries and project specifications as attached in Appendix B to those companies

listed in Table 3.5. The responses to these enquiries are listed in Table 3.6. Some companies have

submitted more than one budgetary proposal in line with Edmonton’s request to look at the potential for

different energy recovery options.

Table 3.6 Status of Proposals

Technology Vendor

Status Proposals Submitted

Advanced Thermal Processes (Pyrolysis and Gasification)

Brightstar Submitted 1. Syngas, onsite combustion

Ebara Not submitted

-

Energos Declined N/A

Enerkem Submitted 1. Syngas, onsite combustion

2. Syngas, OTF*

Lurgi Declined N/A

Nippon Steel Declined N/A

PKA Bankrupt N/A

Thermoselect Submitted 1. Syngas to engines

2. Syngas, OTF

Thide Submitted 1. Syngas, onsite combustion to recover steam 2. Syngas, onsite combustion to recover electricity 3. Syngas, OTF

Toshiba Declined N/A

WasteGen Submitted 1. Syngas to engines

2. Syngas, OTF

Fluidized Bed Combustors

Ebara Submitted 1. Fluegas, onsite power generation

2. Fluegas OTF

EPI Submitted 1. Fluegas, onsite power generation

Seghers Declined N/A

*OTF: Over–The–Fence

Table 3.7 provides summaries of why companies that appear in the shortlist in Table 3.6 declined to

submit budgetary proposals for this project. The reasons for not quoting, as given by the vendor, are

summarized below:


Table 3.7 Reasons for Declining to Quote

Process/Vendor Reasons for Declining to Quote

Energos Energos stated that “their technology would be construed as an incineration process” and declined to bid on this basis.

Lurgi Lurgi stated that "they do not offer their gasification technology for such waste streams" - this appears to us to be an odd reason and it is more likely that they are either very busy at this time or consider the project too small for their capabilities.

Nippon Steel Nippon Steel stated that "their process is for MSW and they have no experience with the Edmonton waste streams and could not therefore estimate the budget for such a plant".

PKA PKA have gone out of business. We have contacted their Japanese licensee, Toshiba, who have declined to submit a proposal (see below for reason).

Seghers Seghers stated that they preferred to offer their moving grate incineration system. The company had filed for bankruptcy but has been acquired by Keppel Engineering. However, they would not offer a fluidized bed.

Toshiba Toshiba have declined to submit a proposal because they are concentrating on their home market of Japan.

3.4 Technology Description (Pyrolysis and Gasification)

The following process descriptions relate to those processes that submitted a budgetary proposal.

3.4.1 Brightstar

The Brightstar process contains extensive materials sorting and recycling capabilities. The raw input

waste stream is autoclaved at temperatures of around 150oC using process steam under pressure and

then sorted using a series of trommels, conveyors, screens and magnets to recover metals, glass and

some plastics. The remaining solids (or pulp) are dewatered using mechanical presses and dried using

process steam. The dried solids are then fed to the first of a 2-stage gasification process, where it is

heated to about 900oC. The char leaving the first gasification stage is gasified further in the second stage

to release more energy and to produce an inert ash. The syngas from both stages are combined and

cleaned using a wet scrubbing technique and then used to power gas engines. The company has

operated a demonstration facility in Wollongong, New South Wales since the beginning of 2001. The

Brightstar SWERF (Solid Waste and Energy Recycling Facility) process is described in Figure 3.7.


Source: Juniper

Figure 3.7: Schematic of the Brightstar SWERF process

In Figure 3.7, the secondary gasifier is shown in broken lines. This is because the current mode of

operation at Brightstar’s Wollongong plant does not utilize a char gasifier (secondary gasifier). At present

the char from the primary stage gasifier is sent to landfill. The current mode of operation will also have

subsequent effects on the heating of the primary stage gasifier as is denoted by the broken arrows

showing syngas return from the secondary gasifier.

3.4.2 EBARA Corporation (Fluidized Bed Combustion)

Please see Fluidized Bed Combustion Technologies in Section 3.5 ‘Other Relevant Technologies’ below.

3.4.3 Enerkem

Enerkem Technologies is a Canadian company based in Quebec, Canada. Enerkem offers the BIOSYN

process for processing putrescible residues such as woody biomass materials, sorted MSW as well as

organic wastes including MPW. The Enerkem process for MSW takes pre-sorted wastes, from which the

metals, plastics, paper, cardboard and glass has already been recovered for recycling. Therefore, the

fuel processed is essentially an RDF.

Autoclave

MSW

Ferrous Metals

Waste Separation &

Washing

Glass + hard plastic

Organic Pulp Processing

Pulp Drying

Hot Exhaust Gases Waste Heat

Boiler

Pyrolysis Coils

Syngas Cleaning

Gas Engines

Dried Pulp

Syngas

Process Water

Secondary Gasifier

Sepa

rato

r

Water Treatment

Recycled Process Water + Additives

Process Water

Cleaned Syngas Recycled Process Water

Steam

Oil

Bio-Fertilizer

Condensate Scrubber Water

Char

Ash

Cleaned Syngas

Hot Fluegas

a


The fuel is shredded and pelletized before being injected into the waste gasifier. Figure 3.8 describes

the Enerkem waste gasification technology.

Source: Juniper

Figure 3.8: Schematic of Enerkem’s BIOSYN Process

3.4.4 EPI (Fluidized Bed Combustion)

Please see Fluidized Bed Combustion Technologies in Section 3.5 Other Relevant Technologies

below.

3.4.5 WasteGen (Techtrade)

WasteGen UK Limited is a recently formed consortium of UK and overseas partners that aims to develop

waste to energy projects in Europe. The company relies on consortium members to provide engineering

resources for its projects. The key member of the consortium is the German pyrolysis equipment

company Techtrade. (Techtrade was formerly part of Mannesmann, which acquired the rights to the

original technology, which was developed in the former East Germany by Pyropleq. Pyropleq was sold to

the French contracting company Technip as Technip Germany, and is now a small independent

company).

Process Residues

Char

Fluegas to Stack

Water

Steam

To waste water t reatment

Tars

Gasifier Cyclone

Cyclone Scrubbing

Tower Venturi Scrubber

Demister Shredder

Granulator-Pelletiser

Sorted Waste

Boiler Steam Turbine

Syngas Storage


Techtrade brings to the consortium the experience in building and developing the waste pyrolysis process

(Pyropleq) operating since 1987 in Burgau, Germany and recently in Hamm, Germany.

The incoming wastes (MSW or MPW) are held in storage pits prior to size reduction using shredders.

The waste material is then conveyed into an indirectly heated rotating pyrolysis kiln where it is pyrolysed

for periods ranging from 30 minutes to 2 hours. The syngas from the pyrolysis process passes through a

hot ceramic filter, which removes particulates. The syngas is then fired in a combustion chamber and the

thermal energy recovered from the resulting gases via a waste heat boiler and steam turbine. A portion

of the fluegas is recycled to provide heating for the pyrolysis reactors. The company offers an option of

utilizing partially cleaned syngas (particulates removed) over-the-fence in a nearby power plant. This

option is currently being used at one of the company’s reference facilities, which processes waste plastics

in Hamm, Germany. Figure 3.9 describes the WasteGen process in more detail.

Source: Juniper

Figure 3.9: Schematic of the Techtrade/WasteGen Process

3.4.6 Thermoselect

Thermoselect operates a 3 line, 225 kTpa MSW and industrial waste plant in Karlsruhe, Germany. A

similar process geared towards industrial waste is operated by their Japanese licensee, Kawasaki Steel in

Thermal Oxidation

Shredded Waste

Waste Heat Boiler

Air

Steam

MSW

Residues to

disposal

Pyrolysis Reactor

Flue gas

Char

Ceramic Filter

Exhaust gases to stack Fabric

Filter

Power Generation

Flue gas

Flyash

Flue gas

Gas Cleaning Residues

Syngas

Quench Ferrous Metals

NaHCO3 + Activated Carbon


Chiba, Japan. The input waste is compacted to remove surface water and trapped air before being

passed through a drying chamber. The waste leaving the drying chamber is passed to a high

temperature gasifier, which uses oxygen as the gasifying agent. The inorganics and unburned

carbonaceous matter are slagged at the high operating temperatures of the gasifier (greater than

1300oC). The syngas is quenched and cleaned using wet scrubbing methods. At Karlsruhe, the syngas

is combusted to raise steam. In Chiba, the syngas is utilized in gas engines. Figure 3.10 describes the

Thermoselect process.

Source: Juniper

Figure 3.10: Schematic for the Thermoselect Process

3.4.7 Thide

Thide Environnement is a French company offering a waste thermolysis system called the EDDITh

process. The company has two reference plants operating in Japan, through their licensee Hitachi. The

plant in Nakaminato, Japan has operated since 1999 on domestic refuse at a capacity of about 10 kTpa.

A second, 2-line Japanese reference plant, built by Hitachi at Itoigawa, has been in operation since May

2002 on domestic refuse at about 25.6 kTpa. The company is presently building two other plants to

handle domestic refuse in Izumo, Japan and in Arras, France. The Izumo plant, at a capacity of 72 kTpa,

is planned to start commercial operation in 2003, while the Arras plant (50 kTpa), which will also take

industrial waste and sewage sludge, is planned to start in 2004.

The incoming waste to the Thermolysis process proposed for Edmonton will be first crushed to sizes

between 80 to 250 mm. The waste is then dried using hot fluegas before being fed to the Thermolysis

reactor. The waste stays in the rotating reactor for periods ranging from 30 to 60 minutes, during which

Compression/ Degassing Quench Gasification/

Melting Gas

Cleaning Gas

Engineor other

Scrubberresidue Liquid

effluent

Exhaust gases 2

Recycled H2O

H2O

Wastewater

treatment

Fresh make-up

MSW

Metal alloy

Melted granulate

~

Heavy metal sludge + saltsAdditives

Hot flue gas

O2

Natural gas


time it is heated to between 450 to 650oC by the application of heat to the outside of the reactor. The

reactor is heated by recirculated hot fluegas from the syngas combustor. The solids from the thermolysis

reactor are washed and passed through a series of gravimetric, densimetric and magnetic separators to

recover metals, inerts and soluble salts. The inert materials are sent to landfill. Ferrous metals are

recovered for sale. Non-ferrous metal extraction is not planned in the basic solution offered by Thide.

Wastewaters from the washing process are directed to evaporation-crystallization units to remove salts,

which are sent to landfill after being immobilized with an organic binder or sent to a salt mine. The ‘cleaned’ solids or Carbor is rinsed, dried, pelletized and then stored for use as fuel either on or offsite.

Usually the syngas from the thermolysis reactor are combusted and the hot fluegas used to dry the

incoming waste stream as well as to heat the thermolysis reactor (see Figure 3.11). For Edmonton, Thide

has proposed 3 different configurations for recovering energy from the syngas. In the first, the gases from

the thermolysis reactor are combusted to produce either steam (option 1) or electricity via steam cycles

(option 2). Thide also offered the third option of utilizing the syngas offsite in a nearby power plant.

Figure 3.11, describes the Thide EDDITh Thermolysis process. When the gases are combusted onsite

the exhaust gases leaving the process will be cleaned by a dry scrubbing process.

Source: Juniper

Figure 3.11 Schematic for the Thide EDDITh Thermolysis Process

Shredded waste

Metals +Inerts

Combustion Chamber

Solid Fuel Carbor

Offsite PowerGeneration

~

Syngas + Tar

Air

Hot flue gases

Exhaust gases

Char

Heat (from syngas)

Wastewater

Separation/ Washing/Drying

Thermolysis reactor

Dryer

Dryer water


3.5 Other Relevant Technologies

A potentially viable solution to Edmonton waste treatment is the utilization of a fluidized bed combustor,

which is much more widely established worldwide than gasification and pyrolysis technologies. This

section looks at the advantages and disadvantages of using fluidized combustion technologies for

handling Edmonton’s waste streams.

Fluidized Bed Combustion (FBC) has some major advantages over pyrolysis and gasification processes:

• The technology is more proven than waste gasification and pyrolysis;

• It can handle a wider range of high and low heating value waste streams, and

• It is better suited to large scale applications as envisaged by Edmonton.

However, FBC also has some disadvantages in the context of Edmonton’s application:

• It is likely to be classified as waste incineration;

• Energy recovery options are limited to onsite energy recovery via steam cycles. Hot

fluegas could also be sent to nearby power plant’s heat recovery system, and

• Heat recovery boilers are prone to ash fouling and corrosion due to high particulate carry

over from FBC.

3.5.1 General Technology Description (Fluidized Bed Combustion)

Two basic types of Fluidized Bed Combustors have been used in the thermal treatment of wastes:

Bubbling Fluidized Bed Combustors (BFBC) and Circulating Fluidized Bed Combustors (CFBC). Table

3.8 lists fluidized bed combustion providers that Juniper has identified in the context of handling

Edmonton’s wastes. These processes are included along with the short-listed pyrolysis and gasification

technologies (see Table 3.6), in the list of suitable technologies for Edmonton’s application.

Table 3.8 Fluidized Bed Combustion Technologies for Edmonton’s Application

Company Country Technology

EPI USA BFBC

Ebara Corporation Japan ICFB (see Section 3.6.1).

Seghers Belgium BFBC

Source: Juniper

Bubbling Fluidized Bed Combustion is a mature technology that is firmly established in a number of

industrial markets. In terms of capacity BFBC plants vary from a few megawatts to the large (280 MWTh)

biomass/waste fired units, such as those supplied by Kvaerner to the pulp and paper industry. However,

the bulk of units are operating at medium scale today. The advantage of BFBC systems lies in the

presence of bubbles in the fluidized bed, which promotes intense circulation and mixing of the solids,


leading to isothermal conditions throughout the bed. This favours high burn-out efficiencies and low

emissions. Fuel pre-preparation is required and usually involves drying and size reduction.

Circulating Fluidized Bed Combustors or CFBC utilize smaller particles and higher velocities than BFBCs.

This improves heat transfer and hence greater unit throughput can be achieved and a wider range of

waste types can be handled. In CFBC’s the ash particles are carried out of the reactor into a second

reactor. Some of the fluidizing medium is also carried over, separated and returned to the first reactor.

The second reactor essentially increases the ‘reaction’ time of the particles increasing the overall waste

conversion efficiency. This type of system has some advantages such as higher heat transfer,

potentially higher waste conversion efficiencies and higher throughputs. However, higher cost associated

with a second reactor, solids circulating system and greater air requirements are some of its

disadvantages.

In both, the bubbling and circulating variants of fluidized bed technology, particle size is important. This is

because too large a particle size increases the air requirements for fluidization resulting in greater energy

usage and larger reactor sizes to accommodate the higher air volume and to reduce particle settling. If

the particle size is too small, entrainment of particles with the fluidization gas occurs resulting in high dust

loads carried downstream. Therefore, not unlike gasification and pyrolysis systems, fluidized bed

combustors would require some degree of feed preparation. Table 3.9 gives general comparisons

between Pyrolysis/Gasification and Fluidized Bed Combustors.


Table 3.9 General Comparisons between Pyrolysis/Gasification and Fluidized Bed Combustion Processes

Pyrolysis/Gasification Fluidized Bed Combustors

o Only a few proven installations o Scale up and operational risks o Better suited to small and medium scale

applications Technology

o Many proven installations, worldwide

o Minimal scale up and operation risks

o Reference plants at various scales

o Extensive feed drying and shredding

may be required

Fuel Preparation o Extensive feed shredding

may be required

o Reducing conditions minimizes emissions of NOx and dioxins/furans

o Small syngas volumes, so cheaper to clean up

o Some systems produce a slag which is safer to dispose of than ash or char

o Comparatively lower GHG emissions Emissions

o Abatement of dioxins and NOx likely to be required

o Combustion increases gas volumes and therefore capital costs, space requirements and gas cleanup costs

o Ash disposal required o Comparatively higher GHG

emissions o Boilers prone to ash fouling &

corrosion due to high particulate carry over from fluidized bed

o A number of energy recovery routes

possible. On site steam generation, higher efficiency gas engines & gas turbines and co-firing

o High efficiency energy recovery routes, such as gas engine not fully proven with waste derived syngas

Energy Recovery

o Higher energy efficiency routes such as gas engines & gas turbines cannot be used; capital cost saving co-firing options cannot be used

o Energy recovery methods, utilizing steam cycles are well proven and established processes

o Regarded as an alternative to combustion for waste to energy by politicians and regulators, so likely to get government grants

o Sometimes seen as unproven and risky so may not easily bankable by external sources of finance

o May need smaller chimney for same unit capacity

Perception & Legislative Issues

o May be regarded as an incinerator by regulators

o Potential NIMBY (Not In My Back Yard) issues

o A higher chimney and possibly taller building

Source: Juniper


3.6 Commercial Technology Description (Fluidized Bed Combustion)

3.6.1 EBARA Corporation

Ebara, based in Japan, is better known as a supplier of fluidized bed combustion technologies. This

company boasts many years of experience in developing a range of fluidized bed based technologies for

waste combustion. One of their FBC technologies, which could be relevant for Edmonton, is the Internally

Circulating Fluidized Bed Boiler (ICFB), for which the company has over 15 reference plants operating

mainly in Japan on a variety of waste streams. The ICFB adopts a unique ‘revolving’ type fluidized bed

technology, which is named Twin Interchanging Fluidized bed (TIF). In this system the motion is

achieved by special air injection compartments that cause the sand bed to revolve. The ‘bed’ of sand

stays in a single reactor and thus this system could be regarded as a variant of BFBC.

Shredded waste is fed to the ICFB. The resulting fluegas is fed to a waste heat boiler where the heat is

recovered to raise steam and electricity via steam turbines in the usual configuration of this process. The

gas then passes through an economizer to heat up the boiler feed water and a gas air heater. Lime and

activated carbon are sprayed into the cooled fluegas before it is de-dusted using bag filters. The fluegas

is cleaned further by a wet scrubbing method using a scrubbing solution of NaOH and polished by

passing the fluegas through an activated carbon adsorber.

The non-combustibles discharged from the ICFB are separated and the fluidizing medium (sand) returned

via storage to the ICFB. The non-metallic part of the separated incombustible materials is stored before

being sent to landfill. Figure 3.12 describes the Ebara ICFB process in more detail.


Source: Juniper

Figure 3.12: Schematic of the Ebara ICFB Process

3.6.2 Energy Products of Idaho

Energy Products of Idaho (EPI), based in the USA, has a large number of reference fluidized bed

combustion plants worldwide handling a variety of materials. The input is fed to a BFBC for destruction.

The hot fluegas generated is cleaned by cyclone before being used to raise steam in a boiler. In the usual

plant configuration, power is generated using steam turbines. Gas cleaning is usually by dry scrubbing

methods with the only liquid effluents associated with boiler and cooling tower blowdown. A schematic of

the EPI combustion process is shown in Figure 3.13.

Air

Power

Heater

bed material to

Activated

pollution control

ICFB

Waste

Boiler

Ash

Condensate

Generation ~

Bottom ash +

separation

Fluegas

Economizer Hot water

Steam

Ash

Slaked Lime +

Carbon

Fabric Filter

Air Heater

Air Ash Ash + Air

residues

Scrubber

Activated Carbon Adsorber

Steam

To stack

Disposal

Air


Source: Juniper

Figure 3.13: Schematic for the Energy Products of Idaho, BFBC Process

Fluidised Bed

Combustor

Waste

Boiler

Air

Ash

Cleaned stackgases

Water

PowerGeneration ~

Bottom ash + Bed Material (recycled

online)

Fluegas

Evaporative Cooling Tower

Flyash + liquid blowdown

Economiser Hot water

Steam

Ash

Water spray

Dry Gas Scrubber

Sorbent Injection

Fabric Filter

NOx Abatement

Solids for disposal

NH3


4.0 FEED PREPARATION REQUIREMENTS

Table 4.1 summarizes the feed preparation associated with each process. The summary is based on

information supplied in the budgetary proposals. In some cases, for example Brightstar, the feed

preparation is based on receiving a feed of MSW, since this is the feed material currently handled at this

operator’s demonstration plant in Australia.

Table 4.1 Feed Preparation

Company Waste Preparation

Brightstar Waste is autoclaved using low pressure process steam, and then separated by a series of trommels, conveyors, sieves and magnets. Waste then dewatered and dried before gasification

Ebara Waste is shredded before combustion in fluidized bed

Enerkem Pre-sorted waste from which recyclables are already removed is shredded and then pelletized before thermal treatment

EPI Waste must be shredded before being fed to fluidized bed combustor

Thermoselect No pre-drying or waste shredding required. Wastes are compacted within the process to remove trapped air and surface water before being gasified.

Thide Not specified but assumed to be shredding and metal removal

WasteGen Waste must be shredded before being fed to the rotary pyrolysis kiln


5.0 RESIDUES AND RESIDUE DISPOSAL

Table 5.1 summarizes the ways in which the various residue streams are handled in specific processes.

The summary is based on information submitted by the process operator in the budgetary proposals.

Table 5.1 Residue Handling

Company Residues Residue Disposal

Brightstar Ash Wastewater

Ash: to landfill Wastewater: wastewater treatment facility

Ebara (ICFB) Bottom ash Granulated Slag + APC Residues Wastewater

Bottom ash: ash separated from the fluidizing sand is collected and stored for landfilling Flyash + APC residues: Collected and disposed to landfill Wastewater treatment: facilities for waste water treatment not included in the budgetary proposal

Enerkem Char, Cyclone dust, Sludge Spent Adsorbent Wastewater

Char from Gasifier, Ash from Cyclones, Dewatered Sludge from Wastewater treatment: collected in a container for final disposal or stabilization Spent Activated Carbon: To cement stabilization or return to gasifier Wastewater: wastewater treatment facility included and produces sewage quality effluent.

EPI Ash Residue collection and handling is not included in the EPI budgetary proposal. Disposal to landfill is expected.

Thermoselect Granulated Slag Wastewater Salt etc.

Granulate: stored in bunkers to be sold for reuse Wastewater: treatment system included and produces water to be reused within the process Sulphur, salt and heavy metals: stored in bags for ‘sale’

Thide Process produces a solid fuel Salts APC residues

Solid Fuel, Carbor: Can be utilized offsite Salts: Recovered salts from wastewaters sent to salt mines or bounded with an organic binder. APC Residues: No disposal plans reported in the proposal

WasteGen Char and Cyclone dust Flyash APC residues

Char + Cyclone dust: collected together for disposal. Flyash from Fluegas path: collected in bags for final disposal APC Residues: residues sent to a bunker for storage and final disposal


6.0 REVIEW OF HEAT RECOVERY/COGENERATION OPTIONS

6.1 Process Routes and Syngas Utilization Options

Figure 6.1 shows the possible process routes available to the City of Edmonton with respect to syngas

utilization and energy recovery options.

Source: Juniper

Figure 6.1: Syngas Utilization & Energy Recovery Routes

The options available to the City are:

1. The gasification process produces a dirty syngas product, which is cleaned. This clean syngas is

then used directly in on-site spark-ignition gas engines to produce electricity. Carbon monoxide

(CO) and oxides of nitrogen (NOx) may need to be removed from the exhaust gases prior to

discharge to atmosphere.

2. The gasification process produces a dirty syngas product, which is cleaned. The clean syngas is

transported by pipeline to the off-site Clover Bar natural gas fired power station where it is used

as an auxiliary to displace a portion of the natural gas (fossil fuel displacement). It is assumed at

this stage that the syngas can be transported by pipeline; however, this will have to be confirmed

in the feasibility study.

1

2

3

4

GA

SIF

ICA

TIO

N

CleanedSyngas

DirtySyngas

Off-siteClover Bar

Power Station

On-site Close-coupled

Combustion

On-siteGas Engines

Engine Exhaust Gas

Cleaning

Flue Gas Cleaning

To Atmosphere

To Atmosphere

To Atmosphere

Blended combustion products

~

Steam ~

1

2

3

4


3. The gasification process produces a dirty syngas product that, if the process can be sited close

enough to the off-site Clover Bar power station, could be used directly in the power station to

displace a portion of the natural gas (fossil fuel displacement).

4. The gasification process produces a dirty syngas product, which is combusted directly in an on-

site integral close-coupled stage of the process. The hot flue gas is used to raise steam in a

boiler and then produces electricity via a steam turbine/generator. The flue gas is cleaned prior to

discharge to atmosphere.

The advantages and disadvantages of each of these are shown in Table 6.1.


Table 6.1 Advantages and Disadvantages of the Process Routes for Syngas Utilization

Process Route Advantages Disadvantages

1. Onsite gas engines

o Highest thermal efficiency o More kWh/tonne of waste o Gas engines are well proven for

landfill gas and biogas applications o Syngas use and power generation

is close to gasifier o Greater reduction of greenhouse

gas emissions

o Syngas cleaning incurs increased capital and operating costs

o Exhaust gases require treatment to reduce CO and NOx to WID levels

o Several process companies have under-estimated the technical challenge associated with this route

2. Offsite combustion of cleaned syngas

o No requirement to invest in power production equipment (i.e. gas engines)

o No requirement to invest in a connection between the gasification plant and electrical transmission grid

o Syngas will displace natural gas o No additional gas cleaning

equipment will be needed as flue gas from syngas combustion will mix with natural gas combustion products

o Syngas requires transportation via pipeline or the gasification plant must be located close to the power station which would require transportation of the feed compost rejects

o Waste transport will produce greenhouse gas emissions

o Syngas cleaning incurs increased capital and operating costs

3. Offsite combustion of dirty syngas

o Only dust removal from the syngas is required

o No requirement to invest in energy recovery equipment

o Syngas will displace natural gas o No additional flue gas cleaning

equipment will be needed as flue gas from syngas combustion will mix with natural gas combustion products

o Potential issues of corrosion or boiler tube foul-up at Clover Bar would need careful evaluation

o Gasification plant must be located close to the power station which would require transportation of the feed compost rejects

o Waste transport will produce greenhouse gas emissions

o Tar contamination may require installation of different burners

4. Onsite Combustion

o Lower risk as this is the least challenging option in terms of technical development

o Integrated process therefore syngas does not need to be cleaned

o No tar handling issues o Inorganic constituents can be

melted within the process to form a vitrified slag

o Uses steam cycle (lower efficiency conversion to power)

o Larger volume of flue gas requires cleaning

o Could be perceived as incineration


6.2 Markets for Clean Syngas

As discussed above, the primary market for clean syngas is the generation of electricity through the use

of reciprocating gas engines. Thus, the market for power, preferably green power, is the economic driver.

This is discussed further in the section on green power (Section 7.0).

The second option of transporting the clean syngas to the Clover Bar generating station is attractive

because the capital costs of the generating equipment could be saved. However, this market for the

syngas is probably not long term, since the Clover Bar generating station may be decommissioned within

the next 5 to 10 years. The facility is 30 years old, and is currently only being used as a peaking station.

A third option exists, namely the sale of clean syngas to a nearby industry as fuel. The City has indicated

that an Eco Industrial Park may be built at or near the Edmonton Waste Management Centre in the

future. Should this occur, the syngas could be sold based on its energy content and the prevailing cost of

energy as a replacement or partial substitute for natural gas.

6.3 Markets for Dirty Syngas

The only real use for dirty gas is in heating processes as a supplemental fuel in large boilers. This could

be for a power utility, as indicated above for the Clover Bar generating station, or it could be for an

industry that requires a constant supply of heat for its process. In either case, the gasification facility

would have to be located within a very close distance from the user, since transportation of dirty syngas is

technically difficult over larger distances.

Using dirty syngas for reciprocating engines must be avoided for the reasons described earlier (potential

to destroy engines).

There were no users identified that have a constant guaranteed long term (greater than 15 years)

demand for dirty syngas within a transportable distance from the Waste Management Centre.

6.4 Markets for Power

Power from a gasification/pyrolysis facility could potentially be sold as green power through EPCOR (see

also the discussion on green power in Section 7.0). The City may wish to be one of the purchasers of

this power, and/or use some of the power directly for the operation of the composter. Power is seen as

the major market for the proposed facility, since it is constant, reliable, long term, and has the potential for

the best returns (as green power).

Financial evaluations in this study have estimated the value of power at $55 per MWh, and with premiums

for green power, ranging as high as $75 per MWh.


6.5 Markets for Heat/Steam, Cogeneration

Similar to the sale of clean syngas to a nearby user, such as in a future Eco Industrial park, the

gasification/pyrolysis could also sell heat directly to a user located nearby. This opens two possibilities:

• The facility produces heat (in the form of hot water/glycol or steam) only and sells it to a

local user for the value of the energy transmitted. This could be used as process heat

and for space heating, and

• The facility becomes a true cogeneration facility and produces both heat and steam.

Environmentally, this offers the best utilization of the energy in the feedstock, and

economically has the potential for generating the highest revenue. It also offers the

greatest operational flexibility, since a lower heat demand, for example in the summer,

allows the generation of more electricity.

In the short term, cogeneration does not seem feasible, because of a lack of potential users for process

heat. Transferring heat in pipelines over large distances is not economical, and ideally users should be

no more than 3 kilometers away. However, if an Eco Industrial park is built in the area, district heating

could be made mandatory, and process heat, if required, could also be supplied by the

gasification/pyrolysis facility.

On a seasonal basis, some of the waste heat from a gasification/pyrolysis system could be used for

space heating at the ECF, particularly in the tipping floor area. This would only use a small amount of the

available heat, and only for part of the year. A detailed cost/benefit analysis would be required to confirm

viability once the technology and final location of the facility have been determined.

Using waste heat for green houses is another seasonal use for the thermal energy available. The size of

the green houses could be calculated to maximize the use of available energy. Similar to space heating,

economic verification is required once the technology and final location of the facility have been

determined.


7.0 GREEN POWER AND GREENHOUSE GAS

Solid waste management has been identified as a major, non-transport sector, anthropogenic source of

greenhouse gas emissions. (GHG) It is therefore essential to consider various alternative waste

management activities, including energy derived from waste sources in and of themselves, as

fundamental components of a broad-based program in response to greenhouse gas emissions and global

climate change.

Disposal of wastes in a landfill site and the resultant landfill gas2 generation is widely recognized as one

of the primary waste management activities resulting in significant release of greenhouse gases to the

atmosphere. Therefore, activities that avoid or decrease the disposal of wastes in landfills can be

considered to reduce that portion of GHG emissions that would otherwise be attributable to landfill gas

emissions. Similarly, other activities that decrease the quantity of landfill gas emitted to the atmosphere,

such as landfill gas recovery, also reduce net emissions of GHG.

Due to the GHG intensity associated with conventional energy production, direct use of waste by-

products (i.e. landfill gas, gasification of wastes, anaerobic waste decomposition gas) to provide fuel for

energy production can also reduce net emissions of greenhouse gases through avoidance of

consumption of conventional fuels.

It is important to understand that the area of waste management offers two distinct streams to realize

GHG emission reductions. These are:

• Implementation of alternative waste management technologies that decrease the net

amount of waste landfilled and therefore reduces the amount of landfill gas released to

the atmosphere; and,

• Creation of “green” or renewable energy using fuels derived from waste by-products

thereby reducing GHG emissions associated with the consumption of conventional fuels

that would otherwise be required to generate an equivalent amount of energy.

7.1 Green Power and Gasification

Under its Environmental Choice Program (ECP), Environment Canada has recently developed standard

certification criteria for renewable low-impact electricity3 (“green power”). This standard recognizes

“biogas-fuelled electricity” and “biomass-fuelled electricity”, among others, as electricity from renewable

sources that impose low impacts on the environment.

2 Landfill gas is comprised primarily of equal parts of methane and carbon dioxide. Methane is a potent greenhouse gas with 21 times the global warming potential of carbon dioxide by weight.

3 “Environmental Choice Program, Certification Criteria Document, CCD-003, Electricity – Renewable Low-impact”


Biogas results from anaerobic decomposition of waste at landfill sites, sewage treatment plants and in

anaerobic waste processing facilities.

Biomass electricity is generated from the combustion of clean biomass, and can be derived from the

following sources:

• Untreated wood wastes and agricultural wastes;

• Dedicated energy crops;

• Liquid fuels derived from biomass: ethanol, biodiesel and methanol, and,

• Organic material separated from municipal solid waste that has been processed

(pelletization or gasification) to serve as a combustion fuel.

From this it may be interpreted that gasification of organic waste and subsequent generation of electricity

would be considered low-impact renewable electricity. It should be recognized that the ECP green power

criteria also includes numerous other specifications and requirements that would have to be met to

achieve ECP certification as green power.

One important element of the ECP certification process is the requirement to retire, or transfer to the

consumer, the rights to all environmental benefits (defined as including emission reductions) associated

with offsetting generation of null electricity from the grid. To qualify for ECP certification as renewable

low-impact electricity, a power generator must permanently retire or transfer ownership of the GHG

emission reductions resulting from avoidance of consumption of conventional fuels to the end user of the

electricity.

It is important to note that the GHG emission reductions that result from decreasing emissions of landfill

gas are typically far greater than those associated with avoidance of consumption of conventional fuels4.

This is largely due to the fact that the global warming potential of methane is 21 times that of carbon

dioxide, while the carbon dioxide component of gas derived from organic wastes is considered as null by

GHG inventory methods5.

7.2 Factors Influencing the Value of Green Power

While consumers in many areas have expressed strong interest in being able to choose between various

sources of electrical power based on environmental considerations, it should be recognized that the

renewable electricity market in Canada is in its infancy. Consumer demand is only one factor in the value

4 For example, the greenhouse gas emission reductions arising from direct capture and combustion of landfill gas are roughly ten times the reductions associated with generation of green power from the energy content of the equivalent quantity of landfill gas.

5 International Panel on Climate Change (IPCC).


of green power in Canada. Accessibility and availability are also key issues. In most Canadian

jurisdictions, consumers have little access to green power. Currently, supplies of green power are limited,

primarily due to the constrained state of the market for renewable electricity.

Governments have just begun to take initial steps towards encouraging development of a formal

renewable energy industry in Canada. As one method to attempt to lead consumer demand, the Federal

and some provincial governments have established programs to purchase some portion of the power

consumed by their operations from renewable sources. The Federal government has offered a partial

subsidy for purchase of wind power. Some governments are also offering tax advantages as a method to

attempt to encourage generation of renewable energy.

Some jurisdictions are also considering implementing requirements such as renewable portfolio

standards (RPSs). A RPS is a regulatory tool that requires that a certain minimum amount of electrical

power within a defined area must be generated by renewable methods. The renewable power is then

contributed into the grid and costs for the renewable power are then distributed incrementally to all

electricity consumers.

As the renewable energy industry in Canada develops, it is likely that green power in Canada will be

viewed as a premium product because of its inherent benefits over conventional power sources and the

generally higher costs associated with producing renewable electricity. This has been the case in many

other countries that have already achieved more advanced progress in the establishment of renewable

power markets.

The extent to which Canadian consumers are willing to pay extra for this premium product remains

uncertain. Typically, renewable energy costs between 10 to 50 percent more to generate than

conventional electricity, dependent upon the conventional power technologies being considered.

Implementation of measures such as RPSs would immediately create demand for renewable power,

while development of a grass-roots consumer appetite for this premium power requires extensive

education and marketing efforts. It is clear that renewable electricity from waste gasification or any other

technology must realize financial compensation for its inherent environmental benefits to be economically

viable. Trading of GHG emission reductions may provide one vehicle to assist in achieving this viability.

7.3 Factors Influencing the Value of Greenhouse Gas Credits

Under the terms of the Kyoto Accord, Canada has agreed to reduce its GHG emissions to 6 percent

below its 1990 limits, between 2008 and 2012. GHG emissions trading is one of the mechanisms for

helping individual countries to achieve the reductions committed to at Kyoto.


Emissions trading involves the process of one party reducing its emission levels and transferring

ownership of that reduction to another party who can use the purchased reductions to meet an emissions

target. By implementing this market-based approach, emissions trading can greatly reduce the costs

associated with achieving emission reductions. There are two basic types of trading systems, “cap and

trade” and “baseline and credit”. The point at which the emission target is set can identify these. The

“cap and trade” system sets an overall quantity of permissible emissions, and then involves trading

permits or allowances within this overall framework. The “baseline and credit” system, on the other hand,

sets a level of emissions for each party within the trading system, and any reductions made by a party

below the target level are credited to the party and are available for trading to other members of the

system6.

Emissions trading programs involving air contaminants such as sulphur dioxide have been in-place and

functioning in other jurisdictions for many years. Recently, several countries have taken steps to

establish formal GHG trading programs. Currently there is no formal GHG emission trading system in

Canada, however, trading of GHG emissions is on-going in Canada on an informal or ad-hoc basis.

The Canadian government recently presented a proposed program for the establishment of a national

GHG trading regime entitled, “Offset System, Discussion Paper”. The government has undertaken

stakeholder consultation on this plan and is currently considering the feedback received. The discussion

paper describes proposed methods of establishing GHG emission targets and a framework for trading

GHG emission reductions. The government has indicated that the final design of a national GHG

emissions trading system will be presented to the Ministers involved for approval by the end of 2003 and

that development of detailed rules and protocols will take place in 2004.

The Federal government has committed to imposing a ceiling on the cost of acquiring carbon dioxide

equivalents (CO2e7) at $15/tonnne. In a market-based system, the actual value of the CO2e will

presumably be controlled by the forces of supply and demand. These forces are largely dependent upon:

• Caps that the large industrial emitters negotiate with the Federal government;

• Costs of process modifications that would be necessary for large industrial emitters to

implement to achieve direct reductions; and,

• Specific rules that are established regarding eligibility of various sectors to create valid

emission reductions to sell to the large industrial emitters.

6 Source: Initial Scoping of GHG emissions Trading Potential in Alberta, by CABREE, March 2002

7 CO2e refers to equivalent tonnes of CO2. Greenhouse gases all have different strengths, and a tonne of CO2 has been established as the base unit.


The value of emission reductions will also depend on the “vintage” and quality of the reductions. It is

expected that emission reductions to be achieved during the first commitment period under Kyoto (2008 –

2012) will be in the greatest demand and therefore will have the highest value. Emission reductions from

the period 2000 to 2007 would be expected to have slightly lesser value, but should still be in demand

based on the government’s indications regarding protection of value for those taking early actions. It is

unclear as to whether pre-2000 emission reductions will have any value.

In general terms the highest quality emission reductions are those that comply with the requirements of

the Intergovernmental Panel on Climate Change (IPCC) with the least ambiguity. The IPCC requirements

address such matters as the eligibility, quantification, verification, ownership, etc. associated with

greenhouse gas emission reductions. Under the Ontario Pilot Emission Reduction and Trading (PERT)

program, emission reduction protocols were submitted and evaluated against IPCC methodologies.

Protocols that were accepted included those associated with waste management activities such as landfill

gas collection and combustion, municipal solid waste incineration and landfill diversion of wood waste. In

general, measures that reduce emissions of landfill gas to the atmosphere have been taken as “the gold

standard” of emission reductions due to the extent that most of these actions can be very well defined

and documented.

In a recent study commissioned by the Federation of Canadian Municipalities (FCM) in support of

innovative project funding mechanisms, it was estimated that the value of greenhouse gas emission

reductions could fall in the range of $6 to $7 per tonne of carbon dioxide equivalent during the first Kyoto

commitment period.

7.4 GHG Emissions from Selected Processes

The GHG emissions from some of the selected processes have been provided by the vendors on the

basis of tonnes of CO2 released per MWh generated (gross power output).

Two gasification systems for which values were obtained are Enerkem and Thermoselect, which release

0.32 and 0.06 tonnes of CO2 per MWh respectively.

Pyrolysis systems release more CO2 than gasification systems. WasteGen releases 0.86 tonnes of CO2

per MWh and Brightstar releases 0.84 tonnes of CO2 per MWh of electricity produced.

By comparison, Ebara reported 1.5 tonnes of CO2 per MWh for its fluidized combustion process.

Coal fired power plants typically produce 1.0 tonnes of CO2 per MWh.

From the above figures, it can be seen that gasification technologies produce significantly lower CO2

emissions per unit of electricity produced than conventional combustion and coal power plant systems.


8.0 AIR EMISSIONS AND CONTROL OPTIONS

8.1 General

Potential air emissions depend on how the syngas is converted into energy. The following are the main

control options:

• Syngas cleaning before combustion, if syngas is combusted in a reciprocating engine or

gas turbine. Example technologies are Enerkem and Thermoselect;

• Conventional flue gas scrubbing, if dirty syngas is combusted directly after gasification or

pyrolysis in a steam boiler, and

• Both syngas cleaning and flue gas scrubbing, if the process only partly cleans the syngas

before combustion. Example technology is WasteGen.

The following subsections provide a description of syngas and flue gas cleaning, and how the two

processes differ. It also provides an overview of potential contaminants of concern in the syngas and

how they are dealt with by the process.

The section ends with an overview of regulatory air emission limits in Canada, the European Union (EU),

and the United States, and how they relate to the budgetary proposals received.

8.2 Syngas Cleaning Process

The type and amount of contaminants present in dirty syngas is different from those in dirty fluegas. This

is essentially due to the difference in the prevailing conditions within gasifiers and pyrolysers as

compared with combustion systems. In fact, small changes in the reactor conditions when operating in

gasification or pyrolysis modes could result in significant changes to the composition of the syngas

stream. Such changes will inevitably have consequential effects for the gas cleaning system, which

would have to be able to cope with the different contaminants thrown at it. Nevertheless, the

contaminants usually of concern in gasifiers and pyrolysers are summarized in Table 8.1 below:


Table 8.1 Contaminants in Syngas

Pollutant Observations

Dioxins and Furans The reducing conditions of pyrolysis and gasification will minimise the formation of dioxins. Syngas is converted directly in gas engines or used ‘over-the-fence’, both of which avoid the conditions for low temperature dioxin formation associated with conventional heat and energy recovery, which generate fluegas. Dioxin formation should be less of an issue.

Heavy metals Heavy metals in the syngas would be the result of vaporization of relatively low boiling point metal compounds remaining in the waste feed at the temperature prevalent in the pyrolysis and gasification reactors. Metals such as mercury and cadmium are known contaminants in syngas. Arsine, an extremely poisonous hydride of arsenic has also been detected in syngas. This arises because arsenic compounds present in the waste react with nascent hydrogen generated under pyrolysis and gasification conditions. Heavy metals still require careful management and some species formed in reducing conditions are different from those formed in classical combustion based processes.

Acidic gases Acidic gases in the syngas stream are likely to be mainly species formed in reducing conditions, such as H2S, HCN, COS and NH3. These species are different from those formed in classical combustion systems and would mean that different approaches to conventional scrubber technology may need to be employed.

Particulates This is a mixture of flyash from the gasifier or pyrolyser and high-boiling-point residual hydrocarbons (tars). The presence of tars involves particular challenges. Some process developers have not fully appreciated this requirement.

NOx NOx is unlikely to be a problem in the reducing part of the gasification/pyrolysis process, (i.e. up to the gas engines or co-fired system). However, when the syngas is combusted with excess air in gas engines, or in the pyrolyser burners (when syngas is used for process heating), NOx could become an issue. The impact in co-fired systems is likely to be small because of the relative energy loads. NOx must be abated when using gas engines to meet best practice limits.

Carbon monoxide (CO)

Usually CO is only a cause of concern after gas engines, when its conversion efficiency is low. Before the gas engine CO is an essential component of the syngas stream.

Source: Juniper


Syngas cleaning, unlike fluegas cleaning, is not geared only towards minimizing emissions to

atmosphere. For syngas to be of sufficient quality to be utilized in on-site gas engines, extra measures

have to be taken to reduce the levels of certain contaminants, especially the acidic gases (which would

cause engine corrosion), particulates (which would cause erosion of moving parts) and trace metals

(which condense, causing erosion and blockages). A typical syngas cleaning system for generating

engine quality syngas consists of most of the unit operations is shown below. It is clear from Figure 8.1

that syngas cleaning is more akin to a chemical process plant than is fluegas cleaning.

Source: Juniper

Figure 8.1: Syngas Cleaning Unit Operations

Instead of utilizing such comparatively extensive syngas cleaning processes as in Figure 8.1, many

process developers have opted for the combustion of the syngas within the process. Once this is done

traditional flue gas cleaning techniques described below can be used to perform gas cleaning. The

advantages of using flue gas cleaning processes compared with syngas cleaning systems are

summarized in Table 8.2 below.

Exhaust gases

Cleaned syngas

To neutralize SO2, HF and HCl, COS, NH3, HCN etc.

To dissolve HCl + HF and dissolve heavy metals as chloride or fluorides

Quench Acid Scrubber Particulate Removal

Alkaline Scrubber

H2S Removal

NaOH or Lime Water Water

Additive to convert H2S to

elemental sulphur

Elemental Sulphur

Water Treatment plant

Gas Engine

Water or Glycerine

Water recirculated

Electricity

NOx + CO Removal


Table 8.2: Syngas Cleaning Compared to Fluegas Cleaning

Syngas Item Fluegas

Gas cleaning methods usually involve wet chemistry more akin to chemical plants than power plants. Both wet gas cleaning and wastewater treatment is required. pH balancing, precipitation, oxidation neutralization and particulate removal often necessary. Catalytic removal of NOx and CO may also be required.

Cleaning Methods

Gas cleaning techniques well established. Dry gas cleaning using an alkaline sorbent and activated carbon, or similar adsorbent material is now normally the technology of choice.

Relatively small gas volumes because of the limitations on air/O2 usage and the equilibrium reactions that are dominant under such conditions. This reduces unit treatment costs, size of the plant, stack height and quantity of residues

Gas Volumes

Comparatively larger volumes of exhaust gases to be handled. Mostly unreacted N2 in the excess air used. Larger gas volumes mean bigger plants Potential concerns over dioxins

Wet gas cleaning and wastewater treatment uses a number of different and costly chemical additives. This translates to high operating costs Cost

Higher exhaust gas volumes will require larger ducting bigger gas cleaning equipment and more gas cleaning additives. Equipment footprint might also be greater. This is likely to translate to mainly high capital costs

High gas cleaning standards required for operational and reliability reasons within the plant

Cleaning Standards

High gas cleaning standards specified by legislation aimed at preventing environmental impact outside plant

8.3 Fluegas Cleaning Process

The emphasis in modern flue gas treatment is towards higher efficiency contaminant removal while

reducing the amount of residues generated that may have to be treated before disposal. Table 8.3,

identifies the contaminants present in the flue gases that have to be abated in order for the final

emissions to meet legislated emissions limits.

Fluegas can be cleaned using wet, semi-dry or dry methods. The distinction between these three gas

cleaning techniques is the level of water utilized in the gas cleaning process. Generally, dry and semi-dry

cleaning systems do not produce liquid effluents, while wet scrubbing systems generate wastewater that

will require additional treatment.

8.3.1 Wet Scrubbing

A wet scrubbing system usually consists of some form of gas quenching, once the sensible heat is

recovered from the fluegas. This is usually followed by a Venturi scrubber or Electrostatic Precipitator

(ESP), placed ahead of the wet scrubber to remove the entrained particulates. The wet scrubber is

usually a tray or packed tower with a circulating alkaline solution through which the fluegases pass.


The reduction in the gas temperature, usually by direct quenching with water, aims to minimize

dioxin/furan reformation by rapidly lowering the temperature of the fluegases below the optimum

temperature range for dioxin/furan formation.

The removal of particulates upstream of the wet scrubber is usually performed to prevent their deposition

and accumulation in the wet scrubber, which could lead to blockages in packed or tray columns. In the

wet scrubber itself, caustic soda (NaOH) or lime (CaO) is commonly used as the circulating alkaline

solution to bring about acid neutralization. Many studies have shown that the use of water based

scrubbing for fluegas cleaning is advantageous in the removal of HCl and HF but particularly

advantageous in the removal of SO2 when compared with dry and semi-dry scrubbing processes.

Despite the high acid gas scrubbing efficiencies often attributed to wet scrubbers, this type of system has

a number of disadvantages compared with dry and semi-dry flue gas scrubbing processes. One such

disadvantage is the practice of having the particulate removal device upstream of the acid neutralization

step. In ESP’s, for example, reactions between collected flyash and the fluegas, in some instances,

provide ideal conditions for dioxins and furans to be formed. This is supported by the results of numerous

studies that have shown that an ESP followed by a wet scrubbing system is the least efficient method,

compared with dry and semi-dry scrubbing, for reducing dioxin and furan emissions.

Another significant disadvantage of wet scrubbing processes is that they produce a liquid effluent, which

will require treatment. In most developed countries this technique is not BATNEEC (Best Available

Technology Not Entailing Excessive Costs) and therefore it is being phased out of the market for flue gas

cleaning.

8.3.2 Semi-Dry Scrubbing

Semi-dry systems do not produce liquid effluent. The neutralization agent is usually injected as slurry of

lime into the hot fluegas stream. The liquid content of the slurry is volatilized by the sensible heat of the

fluegas, which is simultaneously cooled. Tests on these types of systems have shown that they have

better acidic gas removal rates than dry scrubbers, which is believed to be the result of the higher

humidity that is known to favour acidic gas absorption within the solid lime particles.

Particulate removal is conducted after acid gas scrubbing to collect fly ash along with the scrubbing

residues. This is usually carried out with fabric filters. In some semi-dry systems, dioxin and heavy metal

removal is facilitated by injecting activated carbon adsorbents into the fluegas stream just before the

fabric filter. This allows sufficient contact time for the necessary adsorption processes to take place. A

schematic of a semi-dry system is shown in Figure 8.2.


The main disadvantage of this type of system is the materials handling problems associated with creating

slurry and pumping it with good reliability.

Source: Juniper

Figure 8.2: Schematic of Semi-Dry Fluegas Scrubber

8.3.3 Dry Scrubbing

Dry scrubbing processes do not produce liquid effluents. In these processes, the materials handling

associated with handling slurries are also circumvented by using mostly dry solid additives.

In a typical dry system, the fluegas after heat recovery is rapidly cooled to prevent dioxin and furan

reformation. The gases are then treated with an alkaline reagent to reduce the emissions of HCl, HF and

SO2. The alkaline reagent used is usually hydrated lime (Ca(OH)2) or sodium bi-carbonate (NaHCO3),

and is often dependent on the temperature of the fluegas among other considerations. Processes using

sodium bicarbonate are generally regarded as having a number of advantages over processes utilizing

hydrated lime, because NaHCO3 is more reactive than limestone, less hygroscopic and its reaction

products are less difficult to clean off a bag filter and easier to handle. Because of its higher reactivity,

less bicarbonate is required for a given application than hydrated lime. However, these advantages are

greatest when the fluegas temperature is about 160 to 180oC. At lower flue gas temperatures hydrated

lime is believed to be the superior scrubbing agent. Economic factors also play an important role in the

decision on which sorbent to use, and these factors are assessed on a project specific basis.

Carbon based adsorbents, usually activated carbon are simultaneously injected with the alkaline reagent

to abate heavy metal compounds containing mercury and cadmium, and also to reduce any traces of

dioxins and furans. The fluegas is then passed through a solids capture device, usually a fabric filter or

Water

Fresh Reagent Silo

Concentrated Slurry Tank

Air Fabric Filter

Slurry Tank

Spray Dryer Scrubber

Solids Discharge

Water Water

Valves

Hot Fluegas


ESP, to minimize particulate emissions. Of the two types of particulate capture devices, fabric filters are

believed to perform more efficiently in capturing particulates over a broader size distribution than ESP.

In some dry scrubbing systems, especially when NOx emissions are expected to be high, a catalytic or

non-catalytic process for minimizing such emissions is employed. Figure 8.2 shows a dry scrubbing

system without NOx abatement.

The main disadvantage with the type of system shown in Figure 8.3 is that SO2 capture is relatively

inefficient compared with wet and semi-dry scrubbers. To bolster this efficiency, some dry systems make

use of an evaporative cooler, which uses a water spray to cool and humidify the flue gas before it enters

the dry scrubbing reactor. This alternative approach is shown in Figure 8.4.

Source: Juniper

Figure 8.3: Schematic of a Dry Scrubbing System


Source: Juniper

Figure 8.4: Schematic of Conditioned Dry Scrubbing Process


8.4 Comparison of Current Canadian, USEPA and EU-WID Emissions Standards

Table 8.3 provides an overview of air emission standards in Canada, the EU and the USA. All values in

Table 8.3 below have been corrected to the same conditions, so that they are comparable. As can be

seen from the table, the EU limits are the most stringent, followed by the Ontario Regulation Guidelines

A7, Canadian Council of Ministers of the Environment (CCME) Emission Guidelines, and the US EPA

limits. All proponents’ proposals used in this study are based on meeting the stringent EU limits.

Table 8.3 Air Emissions Standards

POLLUTANT

CCME Emission

Guidelines measured at 11

percent O2 & 25oC

Ontario Regulations

Guideline A-7, Sept 2000,

measured at 11 percent O2 &

25oC

EU WID LIMTS measured at 11

percent O2, dry basis, &

corrected to 25oC

USEPA LIMITS corrected to 11 percent O2, dry

basis and & 25oC

Particulates 20 mg/Rm3 17 mg/Rm3 9.2 mg/Rm3 68.7 mg/Rm3

Carbon Monoxide (CO) 57 mg/Rm3 (50ppmdv)

NA 45.8 mg/Rm3 172.1 mg/Rm3

NOx 400 mg/Rm3 (210ppmdv)

110 ppmv 183.2 mg/Rm3 1050 mg/Rm3

VOCs NA NA 9.2 mg/Rm3 NA

Hydrogen Chloride (HCl)

75 mg/Rm3

(50ppmdv) 18 ppmv 9.2 mg/Rm3 115.5 mg/Rm3

Hydrogen Flouride NA NA 0.9 mg/Rm3 NA

Sulphur Dioxide 260 mg/Rm3 (100ppmdv)

NA 45.8 mg/Rm3 114.5 mg/Rm3

Mercury 200 ug/Rm3 20 ug/Rm3 46 ug/Rm3 464 ug/Rm3

Cadmium 100 ug/Rm3 14 ug/Rm3 46 ug/Rm3 3.9 ug/Rm3

Lead 50 ug/Rm3 142 ug/Rm3 NA 39 ug/Rm3

Heavy Metals NA 0.046 mg/Rm3 NA

Dioxins/Furans I-TEQ (ngNm-3)

0.5 ng/Rm3 0.14 ng/Rm3 0.09 ng/Rm3 0.4 ng/Rm3

Opacity NA NA NA 10 percent

Sulphur dioxide NA 21 ppmv NA NA

Organic matter NA 100 ppmv NA NA

Arsenic 1 ug/Rm3 NA NA NA

Chromium 10 ug/Rm3 NA NA NA

PAH 5 ug/Rm3 NA NA NA

PCB 1 ug/Rm3 NA NA NA

Chlorophenol 1 ug/Rm3 NA NA NA

Chorobenzene 1 ug/Rm3 NA NA NA


9.0 EVALUATION OF BUDGETRY PROPOSALS

9.1 Introduction

Budgetary proposals were received and initially reviewed by Juniper. The results were presented in a

tabular form and are presented in Appendix A. Tables A.1 and A.2 summarize the budgetary proposals

submitted to Juniper in response to the project specifications contained in Appendix B of this report. The

first of these two tables summarizes the proposals for onsite energy recovery. The second table

summarizes the budgetary proposals for offsite (over-the-fence) energy recovery.

Local factors, such as labour costs, construction costs, value of power, cost of utilities, and allowances for

components not quoted on by the proponents were added by the City of Edmonton/EPCOR/Earth Tech

team in the subsequent sections.

It should be noted that technology vendors were selected based on the criteria established for this study.

Some of the selected companies chose not to quote for the Edmonton project despite being sent project

specifications. The reasons for not providing a budgetary quote are listed in Table 3.7 in Section 3.0 of

this report. These firms remain qualified and are not precluded from consideration in the future.

9.2 Analysis of data

The data, information and costs submitted by proponents and compiled by Juniper needed to be

complemented with local data and information to create a true comparative picture. Many of the

proponents only provided information and costs of the core technical components. Others provided some

of the infrastructure information with their budget quotation.

A model was developed that allowed inputs of cost data for all necessary categories of equipment and

components required to make a full functioning system. Costs were then assigned to these components

either from the Juniper/proponent information, or from project team experience on similar projects and

accepted factors for project expenses. Thus, core technical and operating data and costs were taken

from the proponents, and local costs and ancillary equipment costs were provided by the

City/EPCOR/Earth Tech team. In addition, contingencies were allocated based on the level of confidence

in proponents’ costs. It should be noted that the estimates are based on local Edmonton conditions, and

could differ significantly for other regions.

For capital costs, the model incorporated the following main categories:

• Capital budget of process equipment

• Spare parts

• Equipment erection

• Waste preparation equipment (shredder, pelletizer, drier)


• Ash handling (removal from system, treatment and disposal, if required)

• Water treatment (process water discharge, if any)

• Air pollution control (syngas cleaning, waste gas scrubbers)

• Emissions monitoring (waste gas quality, continuous emissions monitoring)

• Boiler and steam turbine generator (if used for power generation)

• Reciprocating engine and generator (if used instead of boiler for power generation)

• Condenser cooling

• Condenser cooling water supply pipe/pumps

• Substation and grid interconnect to local electrical system

• Civil works/buildings

• Fire protection system

• Engineering, project management, construction services

• Development costs (permitting, hearings, legal, staff start-up, miscellaneous)

Similarly, operating cost categories were established:

• Salaries and staff burden

• Routine maintenance, tools, vehicles, security, insurance, etc.

• Plant consumables/chemicals (activated carbon, ash stabilizers, sorbents)

• Make up water, waste water

• Purchased power (auxiliary power for plant start up and/or stabilization)

• Balance of plant

• Capital cost recovery (based on 8% interest and 25 years)

• Interest during construction (IDC)

Using the developed spreadsheets, it was possible to generate a comparative analysis with an estimated

accuracy of plus 50 percent, minus 30 percent. Operating cost final results are presented as $ per tonne

tipping fee for feedstock processed to achieve a break-even point, without profit or additional margins.

Scenarios were run for power generation on-site only. Upon receipt of proposals and further analysis, it

was determined that the over-the-fence option of generating syngas and exporting it to a power plant is

not feasible at this time. The Clover Bar generating station, which was being considered for this option

will likely only used be for peak power generation in the future, and is thus considered unsuitable as a

long term recipient of syngas.

Gasification technologies were modeled using gas engines burning cleaned syngas to produce electricity.

Pyrolysis systems and FBC were calculated using traditional steam boilers and steam turbine generators.

All facilities had allowances for gas clean up and continuous emission monitors (CEM). Costs for plant


consumables (water, oxygen, sorbent, activated carbon, etc) are based on proponent quoted volumes

and local supply costs. Labour is based on an average cost per employee of $75,000 per year.

9.3 Comparison Tables

Capital costs for key components are presented in Table 9.1 below:

Table 9.1 Capital Costs

TECHNOLOGY NAME WasteGen Enerkem Ebara EPI Thide Thermoselect

Technology type Pyrolysis Gasifier FBC FBC Pyrolysis Gasifier

Annual capacity (tonnes) 100,000 120,000 72,740 110,000 73,000 132,000

Power output. Mwnet 9.5 12 6.6 10 6.5 17.6

Energy conversion method

Boiler & Turbine

Gas Engines

Boiler & Turbine

Boiler & Turbine

Boiler & Turbine Gas Engines

Direct costs $94,404,612 $67,900,000 $76,711,181 $65,951,610 $76,216,239 $203,490,526

Indirect costs $6,753,000 $7,557,000 $6,603,000 $7,483,000 $6,871,000 $8,924,000

TOTAL CAPITAL ESTIMATE $101,157,612 $75,457,000 $83,314,181 $73,434,610 $83,087,239 $212,414,526

Capital Cost in $/kWnet Installed $11,640 $6,850 $13,790 $8,000 $13,960 $13,230

Capital cost in $ per tonne of installed capacity $1,012 $629 $1,145 $668 $1,138 $1,609

Major operating cost categories are shown in Table 9.2.

Table 9.2 Operating Costs

TECHNOLOGY NAME WasteGen Enerkem Ebara EPI Thide Thermoselect

Technology type Pyrolysis Gasifier FBC FBC Pyrolysis Gasifier

Annual capacity (tonnes) 100,000 120,000 72,740 110,000 73,000 132,000

Operating staff 23 25 20 30 24 36

Fixed operating costs $3,755,178 $3,685,592 $3,314,445 $4,226,346 $3,709,179 $5,936,430

Variable operating costs $1,378,390 $3,523,230 $1,360,200 $1,310,600 $805,410 $2,574,457

TOTAL OPERATING COSTS $5,133,568 $7,208,822 $4,674,645 $5,536,946 $4,514,589 $8,510,887

Operating costs per tonne $51.34 $60.07 $64.27 $50.34 $61.84 $64.48

A final summary of costs, which includes amortization of capital costs and revenue from the sale of

power, is shown in Table 9.3


Table 9.3 Final Cost Summary

TECHNOLOGY Waste Gen Enerkem Ebara EPI Thide Thermoselect Brightstar

Technology Type Pyrolysis Gasification Fluidized bed

combustor Fluidized bed

combustor Gasification Gasification Gasification Costs Note 1

Annual capital costs (amortized over 25 years at 8 percent) $9,476,445 $7,068,812 $7,804,873 $6,879,354 $7,783,613 $19,898,993

Annual operating costs $5,133,568 $7,208,822 $4,674,645 $5,536,946 $4,514,589 $8,510,887

Total annual capital and operating costs $14,610,014 $14,277,634 $12,479,517 $12,416,300 $12,298,202 $28,409,879

Revenues

Power sales, based on $55/MWh $3,918,750 $4,950,000 $2,904,000 $4,125,000 $2,681,250 $7,744,000

Total revenues $3,918,750 $4,950,000 $2,904,000 $4,125,000 $2,681,250 $7,744,000 Net annual operating costs $10,691,264 $9,327,634 $9,575,517 $8,291,300 $9,616,952 $20,665,879

Break-even tipping fee $/ tonne $107 $78 $132 $75 $132 $157 $75 to $80

Note 1: Brightstar submitted a proposal for a design, build, own and operate facility only. No cost breakdown is available. Estimate includes profit.

9.4 Capital and Operating Costs Discussion

From the above Tables 9.1 to 9.3, the following picture emerges:

• Budgetary quotations from proponents were not directly comparable because each

technology was sized for a different capacity. Therefore, capital cost per KWelnet

installed was chosen as a comparative indicator of plant capital cost. This is also

relevant because it reflects overall plant efficiency and the major generator of revenues

during operations is the sale of energy. Specific capital costs range from about $7,000 to

almost $14,000. This is a reflection of the efficiencies of some systems, and the

complexity of others. Enerkem, with its gasification proposal has the lowest capital costs

based on specific unit power output, followed by EPI, a fluidized combustion system. The

third spot goes to WasteGen, a pyrolysis system. The complexity of the Thermoselect

system, and its high internal power needs are reflected in its high capital costs.

• Operating costs, measured in $ per tonne of waste throughput, are fairly similar for most

technologies. The spread ranges from $50 to $65 per tonne, which appears low for this

type of technology. It is felt that the proponents offered low estimates of operating

personnel in order to make their technologies attractive. These low estimates have been

compensated for by adding contingencies into the calculations. Some cost uncertainty

remains, but overall final estimates are expected to be in the correct order of magnitude.


• The break-even tipping fee required to cover costs of capital and operation, after revenue

from the sale of power, shows Enerkem as the lowest advanced technology cost at $78

per tonne. EPI’s more conventional fluidized bed came in at $75 per tonne. This is

without any allowances for capital grants or premiums for the sale of green power. In a

similar range is Brightstar, which only provided a per tonne range of $75 to $80 based on

a proponent owned and operated facility. After allowances for profit, Brightstar break-

even costs might be very competitive with Enerkem’s. Considerable additional technical

and financial information would be required from Brightstar to verify this.

9.5 Sensitivity of Costs

The above (base case) cost figures are conservative, and do not reflect the reality of a marketplace

where green power is emerging as an attractive product, and capital grants and other inexpensive funding

sources are becoming available to support emerging technologies and Canada’s commitment to meeting

the objectives of the Kyoto Accord.

Neither the value of green power, nor the availability of grants and low cost capital can be quantified at

this time. Simple sensitivity calculations showed that, for example, if revenues from power sales increase

by $20 per MWh, then operating costs decrease by about $15 per tonne. In order to further enhance the

economics of applying advanced thermal technologies, the resulting electricity produced by the facility

would need to be sold as green power and at a significantly higher rate than conventionally generated

power. Green power could sell for as much as $75/MWh, which is similar to the market rate for wind

generated power.

9.6 Conclusion on Costs

Capital and operational costs for the reviewed technologies are in a range comparable to mass burn

incineration, with some of the more complex technologies at the higher end of the scale. This is as

expected and verifies the process used to obtain estimates and compare costs.

The City of Edmonton estimates that the current Clover Bar landfill will be at capacity in 2010, and that a

state-of-the-art landfill, newly sited and built, would require a significant escalation in tipping fees. These

might fall into the same range as some alternative thermal systems. Comparisons of waste gasification

versus landfill costs do not take into account the long term liability of storing waste in a landfill. Given the

uncertainty surrounding future landfill costs, it appears that some advanced thermal technologies may be

competitive and justifiable, especially if green power can be marketed and capital assistance becomes

available.

The two advanced thermal technologies that stand out as having the most potential from a financial

perspective are Enerkem (gasification) and WasteGen (pyrolysis). The price per tonne offered by

Brightstar is also attractive, but there was insufficient information available from Brightstar to compare

their technology with the other respondents.


10.0 TECHNOLOGY VERIFICATION

10.1 Facility Site Visits

All of the short-listed firms that submitted proposals provided information on reference facilities, as

requested. The project scope required the on-site verification of as many of these facilities as practical.

The facilities and the technologies that were chosen were:

1. Enerkem: Castellon, Spain

2. WasteGen: Burgau, Germany

3. Thermoselect: Karlsruhe, Germany

Enerkem was selected because the process most closely meets the vision of a facility for Edmonton, and

because estimated costs were lowest of all of the budgetary proposals received. The facility produces a

syngas, which is cleaned and burned in reciprocating engines to generate power.

WasteGen was selected primarily because the facility has been operating successfully since 1987.

In spite of its high cost, Thermoselect was considered because it is reported to be the cleanest and most

advanced (process-wise and environmentally) of all of the submissions.

Reference facilities that could not be included in the inspections were Thide, Ebara, and Brightstar. The

Thide facility in France was still under construction and not operational. The Ebara and Brightstar

facilities are located in Japan and Australia respectively, and travel to these locations in addition to

Europe was not within the project budget. It was felt, however, that the three selected reference facilities

provided a good cross section of advanced thermal technologies.

The process verification trip was organized by Earth Tech, and conducted from May 31st to June 7th,

2003. Participants included engineers from the City of Edmonton and Earth Tech, a representative from

EPCOR, and a voluntary participant from the Alberta Plastics Recycling Association.

In addition to visiting the chosen reference facilities, the team met with senior environmental

engineers/managers from the German consulting firm FICHTNER GmbH & Co KG. FICHTNER is

recognized as one of Europe’s leading environmental design firms and has extensive experience with all

forms of thermal recovery from waste, including gasification, pyrolysis, and mass burn technologies.

The following provides a brief summary of on-site observations and conclusions. For process and

technical information, please refer to earlier relevant sections in this report. Detailed accounts of the site

visits with pictures and figures can be found in Appendix C. Comments are based on personal

observations made by the review team, and may differ from claims made in the vendor submissions.


The Enerkem facility in Spain was observed to be working well under normal operation conditions. The

facility was clean and neat and a good environmental neighbour to surrounding areas. The major

concerns with this technology are in the feedstock preparation. An extensive process was required for a

waste stream that was already fairly uniform as delivered. By comparison, compost residuals in

Edmonton are much more diverse and will require significant additional processing and handling. Also,

the Enerkem process has only been operating on this scale for about 6 months. While it seems to be

operating well, long term data is not available.

The WasteGen facility in Germany has been operational since 1987. It is owned by the local county and

they reported being happy with performance and environmental results. The technology is simple and

only minimal proven pretreatment is required. There are no significant technical concerns with

implementation of this technology. Its disadvantage is that the plant looks like a combustion facility, even

though there is a very clear technical difference. If this technology were to be considered for Edmonton,

a significant education program would be required to enlighten the general public and politicians to the

true nature of this advanced technology. The other major disadvantage of the WasteGen pyrolysis

process is that it is thermally less efficient then gasification or conventional mass burn incineration.

The Thermoselect facility is very attractive architecturally and appeared clean and functional on the inside

as well. The process is the most complex of all submittals and is not likely to be confused with

conventional combustion. The process was designed as a high-end waste processing facility designed to

recover, to the greatest extent possible, energy and recyclable materials. The process is essentially a

complex and diverse chemical plant, which is reflected in high capital and operating costs. The

technology’s features are very low emissions, minimal residues, and an aesthetically pleasing

appearance. However, operating and capital costs are so high, that any further consideration of this

technology would be difficult to justify. In addition, there is ongoing controversy about the efficiency of the

technology and there does not appear to be any agreement within the international engineering

community whether the process is an over-engineered and over-priced waste processing facility or a

model technology for waste management.

All of the referenced facilities were reported to be meeting permit requirements and there is no reason to

believe that any of the proposed technologies would not meet Canadian environmental standards.


11.0 REGULATORY ISSUES

11.1 General

Permitting and siting consist of two key components, the regulatory process and the public process.

While these are related (i.e.: regulatory process requires public process input), they are described

separately. The regulatory process is well established and follows a known routine for this type of project.

The public process has well defined procedures, but the output of the public process and implications for

the project as a whole are much less predictable than the regulatory process. This poses a greater risk of

uncovering unforeseen obstacles.

For this project, it has been assumed that a thermal recovery facility using advanced technology would be

sited adjacent to the existing compost facility. Other options, such as siting the facility beside an existing

power plant will need to be addressed if such a configuration is considered in the future.

11.2 Regulatory Process, Permitting

In order to construct and operate a waste gasification or pyrolysis facility at the Edmonton Waste

Management Centre, there would be a requirement for the proponent to follow a formalized procedure

administered by the Government of Canada, the Province of Alberta and the City of Edmonton. The

following sections present a brief summary of each regulatory authority.

11.2.1.1 City of Edmonton

Currently the zoning at the EWMC is zoned DC2.395 (Direct Development Control). The purpose of this

zoning is to establish a site specific development control district to accommodate the development of an

integrated waste management facility and its constituent elements as defined and regulated by the

Environmental Protection and Enhancement Act and the Public Health Act.

The DC2.235.1 bylaw describes permitted uses for the EWMC (i.e. co-composting, dry waste disposal,

MRF, etc.) and it also allows a Development Officer to approve other uses under a category titled

“Ancillary Uses to Waste Management Operations”. Conversations with staff within the City of Edmonton

Planning and Development Department have indicated that it is quite possible that the proposed waste to

energy facility would fall into this category and therefore rezoning may not be required.

There is a City of Edmonton requirement to apply for and obtain a development permit for the facility. In

order to be granted a development permit the proposed site will need to be identified and facility plans will

need to be developed which shows that the development criteria listed in the DC2 regulation have been

followed. In addition, since the EWMC is located within the North Saskatchewan River Valley, the Waste

Management Department will also need to work closely with the Planning and Development and

Community Services Departments to ensure that the proposed plant does not have any adverse impact to


the river valley location and follows the City of Edmonton North Saskatchewan River Valley Area

Redevelopment Plan (Bylaw 7188).

11.2.1.2 Province of Alberta

Alberta Environment: According to the Alberta Environmental Protection and Enhancement Act,

Approvals and Registrations Procedures Regulation, there is a requirement to obtain an approval for the

construction of an industrial plant facility. This approval is required for all activities (such as waste to

energy facility) listed in the Province of Alberta Activities Designation Regulation. The approvals

application includes the following procedures.

• Submission of an Application;

• Determination if an Environmental Impact Assessment (EIA) is required;

• Completion of EIA if required;

• Public notification by applicant;

• Review of application by Technical Director;

• Address deficiencies, and

• Approval decision.

Due to the size of the proposed facility, an EIA may not be required. However, an Alberta Environment

Director will make the ultimate decision.

Energy Utilities Board: According to the Energy Utilities Board (EUB) Guide 28 (Application for Power

Plants, Substations, and Transmission Lines), anybody intending to construct, operate and/or alter

electric facilities needs to file an application with the EUB, pursuant to the Hydro and Electric Energy Act.

The EUB can exempt some projects from an application (i.e. if the electricity is solely for the use of the

generator). In order to determine if an application is required, additional discussions will need to take

place between the proponent and the EUB once more specific project details are known (i.e. mega watts

of electricity produced, users of electricity).

The EUB application process generally includes submission of the following information.

• Application;

• Description of public notification and involvement program;

• Land use;

• Technical operating information;

• Construction schedule, and

• Compliance with provincial environmental emission standards.


11.2.1.3 Government of Canada

There are two federal departments that would be interested in the construction and operation of a

gasification or pyrolysis facility at the EWMC.

Department of Fisheries and Oceans (DFO): DFO would want to review the proposed project in the event

that there was any discharge to the North Saskatchewan River or if there were to be any works

constructed along the banks of the river. If the design of the gasification or pyrolysis system does not

include these items, an approval from DFO will not be required.

Environment Canada: It is recommended that the proponent be proactive and inform Environment

Canada of the proposed facility to see if they have any concerns or any requirements which need to be

followed. It should be noted that if the Federal Government provided any funding for this project there

would be a mandatory requirement to complete an environmental impact assessment as per the

Canadian Environmental Assessment Act.

11.3 Public Process

Public consultation will need to be done to inform the general public of the City’s plans, and to get buy-in

and approval. This is a positive step for the City to take, and shows their commitment to obtaining

community approval. The public process deals with the identification and quantification of community

impacts. These impacts can be both positive and negative, and are considered by the regulators when

issuing permits for the proposed facility. The following discussion identifies some of the key potential

community impacts by category and to assess whether these impacts are positive, neutral or negative for

each of the short listed technologies.

11.3.1 Air Emissions

Any thermal process will raise public concerns about air emissions. The best example of this is mass

burn incineration of municipal waste. Many members of the public have visions of uncontrolled

combustion without pollution control equipment, resulting in visible smoke and odours being emitted from

incinerator smoke stacks. While incineration technology has advanced to become the cleanest form of

solid waste management available, the perception remains that it is environmentally undesirable and

hazardous to human and community health.

In light of this general public attitude toward waste combustion, it needs to be clarified for regulators and

the general public, that the advanced forms of combustion being considered by the City are technically

and environmentally significantly different from incineration.

The 3 short-listed technologies that represent advanced forms of thermal recovery are briefly examined:

• Enerkem: The proposed Enerkem facility would use reciprocating gas engines for power

generation. Therefore, there would be no single stack indicating that emissions are being

released into the air. Instead each gas engine would have its own exhaust, similar to


stationary diesels, which are common in Alberta. There may be some interest in what the

exhaust does to the air shed as a whole, but the likelihood of this being perceived as

incineration with a negative connotation is low. The Enerkem facility will include a flare,

but this will only be used intermittently.

• WasteGen: From the outside, and for the uninformed, the WasteGen proposed facility

most closely resembles a traditional mass burn incinerator system. As described in

previous sections, the thermal process is significantly different from mass burn

incineration and results in very low air emission values. This technology has the highest

risk of being perceived as an incinerator by the general public, and a considerable public

education would be required if this technology needed to be permitted.

• Thermoselect: Similar to Enerkem, Thermoselect is proposing gas engines for the

generation of power. The Thermoselect design includes a by-pass stack which is only

used rarely (in the even of problems with syngas cleaning systems or generating

equipment). However, it does have the appearance of a normal discharge stack and

could lead to a public perception issue. At the Thermoselect Karlsruhe reference facility,

a necessary retrofit to clean up by-pass gases resulted in a two year delay in commercial

operation.

11.3.2 Visibility

The exact location of the advanced thermal process has not been determined. It is assumed that it will be

adjacent or close to the composter, so that residuals can be easily moved to the thermal process, ideally

by conveyor. The EWMC is essentially in an industrial area and visually, impacts would be as follows:

• Enerkem: The Enerkem facility essentially looks like a small chemical plant and would fit

well into the industrial environment of northeast Edmonton.

• WasteGen: The WasteGen facility also would fit well into the chemical plant category

from a visual perspective, and, apart from the clearly identified stack and air pollution

control equipment, would not set itself apart from other facilities at the waste

management centre.

• Thermoselect: The Thermoselect architecture is visually appealing and could become a

highlight of the waste management centre.

11.3.3 Noise

All energy generation facilities produce noise. At the waste management facility, there is already a

certain noise level from operating mobile equipment and stationary fans at the composter. The primary

concern would be cumulative noise levels and their potential impact on surrounding communities.

However, all three proponents indicated that their power generation equipment would be located indoors

and any exhausts would be muffled. Based on the information available it is not believed that any of the

processes would significantly contribute to additional noise pollution from the EWMC.


11.3.4 Traffic

Currently, compost residuals are hauled from the composter to the landfill, which is on the same general

site. If these compost residuals become feedstock for the thermal recovery plant, then there would be a

net reduction in truck traffic on the site and no change in traffic patterns.

If, however, the thermal recovery facility is built to accept additional materials from surrounding

communities (either at the composter or directly at the thermal facility) then there would be added truck

traffic to the EWMC.

11.3.5 Dust

Apart from some normal construction dust, it is not anticipated that the enclosed facilities will produce any

appreciable dust that could harm the environment or human health. There is potential for the residuals

leaving the Enerkem facility to generate dust when they are being landfilled, since the solid residuals will

be fairly dry. WasteGen’s residuals are more like a black slag and are fairly wet when removed from the

facility. Therefore, no dust is expected. Thermoselect will likely not landfill any residuals.

11.3.6 Disaster Potential

Disaster potential discussions address the increased risk of explosion, fire, or unexpected releases of

noxious gases or other pollutants.

• Enerkem: The Enerkem process is a well-controlled chemical and thermal process where

risks of fire or explosion are relatively low. Since the feedstock is processed extensively

there is basically no risk of undesirable materials entering the gasifier that could cause an

explosion, for example. The risk of fire is also low, since the high temperature process is

well-controlled and no heated, potentially combustible materials are removed from the

process.

• WasteGen: WasteGen uses a waste bunker and shear shredders where there is a risk of

fire or contamination if undesirable materials are inadvertently processed. However,

unless the facility would accept unsorted waste, this is not likely to happen. Residuals

coming from the Edmonton compost facility will have undergone rigorous preprocessing

and the likelihood of dangerous materials entering the WasteGen process is very low.

WasteGen residuals contain inorganic carbon, that have the ability to burn. However, the

ignition point would be very high, and no landfill fires have been reported from this

residue.

• Thermoselect: Thermoselect also uses a waste bunker, and a low likelihood of fire or

explosion exists because of the limited presorting of materials entering this bunker. As

well, the Thermoselect gasifier is designed to withstand small explosions, such as

bursting propane tanks without harm.


11.3.7 Social

Social benefits of implementing advanced technologies include items such as:

• The development of new technical skills and knowledge base.

• The potential for training, teaching and research opportunities for the University of

Alberta, the Northern Alberta Institute of Technology and the Alberta Research Council.

• Availability of such a facility could prompt corporate funding for research and

development on other applications for waste management in Alberta industries, such as

the oil and gas industry.

• All three of the short listed components offer some degree of social benefits. The

Enerkem process appears to be most suitable for industrial wastes, and could result in

significant spin-offs in that area. Enerkem is independently pursuing industrial waste

projects in Alberta and elsewhere.

• Thermoselect offers the highest degree of technical sophistication and would likely be

more appealing to technical and training institutions. The technology offered by

WasteGen is more conventional and highly focused on solid waste, thus it may have less

appeal for industry and the educational system.

11.3.8 Economics

Implementation of this project with any of the short listed technologies would result in 20 to 30 direct

permanent full time jobs. With capital budgets of over $60 million, a significant amount of construction

activity would take place in Edmonton. Much of the fabrication required for these facilities could be

carried out by Edmonton-based companies, since they are well equipped for this type of work. In addition

to the $2 to $3 million of civil work, there could easily be $20 million of fabrication contracts and over $2

million of engineering.

In addition to direct economic benefits to Edmonton-based companies from this project, the citizens would

benefit from the long-term deferral of new landfill development. There is also the potential for federal

grants for innovative technologies that could help support implementation of this project. As landfill space

becomes scarce in the built-up regions around Edmonton, the facility could offer services to surrounding

communities for additional revenue.

All of the short-listed technologies would contribute to the economic benefits described above.

Thermoselect, having by far the highest capital cost and degree of technical sophistication, would likely

contribute most to the indirect economic benefits.


11.3.9 Intangibles

A project of this nature could have intangible benefits, from which the City and the public would benefit,

and could ultimately result in public support if adequately conveyed. Some of these intangibles include:

• Leadership in waste management. The City has already established itself as a leader in

waste management and adding an advanced thermal recovery system would help to

strengthen and maintain that lead. Citizens are likely to be proud of a city recognized as

a champion in environmental stewardship. Edmonton would set itself aside from

followers in this field.

• Smart growth. By bringing in innovative technology to Edmonton, the City can attract

other businesses that are interested in either providing and expanding on the

implemented technologies, or in utilizing the advanced thermal system to responsibly

handle their own waste.

• Avoidance of panic situations. A well-planned integrated approach to solid waste

management can help avoid panic situations such as those being experienced by other

large cities in North America at this time. In the long run, the approach envisioned by the

City of Edmonton could result in reliable long-term waste disposal without incurring the

cost of multiple stream collection and the bringing on-stream of several different

technologies, as is currently the case in Toronto, for example.

• Because of their advanced approach to energy recovery and conversion into electricity,

both Enerkem and Thermoselect appear to provide the greatest degree of intangible

benefits. The WasteGen technology is not as efficient, or as attractive environmentally,

however, it does offer a proven and reliable system to the City, with a lower technical risk.

11.3.10 Environmental

The public perceives landfilling as undesirable from an environmental perspective because there is an

increasing reliance on ground water and an increasing need to protect ground water. Since all landfills

are expected to eventually leak, there is an environmental need to deal with wastes as they are

generated rather than leave the task for future generations. In Europe, a new law takes affect in 2005

that requires all waste to be treated and not contain any degradable organic substance before disposal.

This means it must either be composted or combusted. In Canada, this approach is being discussed by

some provinces, but has not been implemented. Any of the three short-listed technologies would provide

the missing link in Edmonton’s solid waste strategy.

Public support is expected to be positive, provided the public understands that these technologies are

necessary to minimize dependency on landfills, reduce long term environmental liability, and to maintain a

leadership position in waste management by recovering the energy from waste materials using

technologies that are much more advanced then mass burn incineration.


11.4 Ranking the Potential for Community Support

Actual community support, or lack thereof, will not be known until the public process has been

undertaken. Based on an understanding of the project, the technologies, the City, and general solid

waste management, the following picture emerges:

• Gasification is the technology that has the highest likelihood or public acceptance. It

carries a low risk of emitting pollutants and provides the potential to introduce a new

technology and new professional skills to Edmonton;

• Pyrolysis also has a low risk of emitting pollutants, and would introduce new professional

skills, but because the proposed technology looks very much like conventional

combustion, it may encounter more public opposition than gasification, and

• Mass burn combustion is environmentally also a low-risk technology, but offers no new

expertise development and has a negative public image.


12.0 IMPLEMENTATION SCHEDULE

12.1 Prior to Award of Contract

Prior to the award of contract, the City must conduct a detailed technical and financial feasibility study of

the preferred technology. This is anticipated to take 6 months. Following the study, the internal city

planning process could require up to 3 months. The equipment procurement process will include the

preparation of specifications, tendering and evaluation of submissions. This process will take at least 6

months. There are therefore at least 15 months of work required prior to the award of contract.

12.2 After Award of Contract

Estimates of implementation times were only received from three proponents. They do not differ

significantly, so that generally accepted schedules for power projects can be used as a guideline. The

general schedule is therefore as follows:

• Engineering. After award of contract, expect 6 to12 months for detail engineering.

• Fabrication and site preparation. This step involves the preparation of the site,

installation of all necessary foundations, utility infrastructure, and other components, as

well as the fabrication and shipment of all equipment to site. Expect 8 months duration.

• Construction and erection. Depending on the season, assume 8 to 12 months to install

all equipment and finish buildings and civil works, utility connections, landscaping, etc.

• Commissioning and trial operation. Assume 6 months, since this involves new

technology that could (and often does) require some modifications during the

commissioning stage.

In total, the time from award of contract to readiness for commercial operation could be 28 to 38 months

(2.3 to 3.2 years), based on the technical steps outlined above. In addition to the technical

implementation, public consultation and permitting are required. This work can begin shortly after

completion of feasibility analysis and continue in parallel with the subsequent processes. However, any

major issues identified by the public consultation and permitting processes will need to be clarified before

the beginning of fabrication and site work (step 2 above). The total time required for permitting and public

consultation could be as short as 8 months or as long as 36 months, depending on the level of interest

shown by the general public or organized interveners (such as environmental groups), and the degree of

process formality called for by regulations. The time required may be longer depending on the findings of

the hearing.

The steps outlined in Table 12.1 are considered necessary for the implementation of a complete

permitting and public consultation process. These steps are also illustrated in Figure 12.1.


Table 12.1 Public Consultation and Permitting Schedule

Task Name Task Description Duration

Prepare for consultation

Prepare questions and answers and project information for public consultation process. Identify stakeholders and special interest groups that should be consulted.

3-5 weeks

Environmental Impact Assessment

The detailed environmental impact assessment (EIA) must include air, soil and noise studies and a brief economic impact study. The EIA can be completed in 8 to 12 weeks, provided the seasonal background information is available; if it is not available, up to a full year of may will need to be collected. .

8 weeks – 1 year

Confirm interconnection requirements

The Alberta Electric System Operator (AESO) must confirm the interconnection requirements. This may be carried out through a local distribution company (LDC).

6-12 weeks

Conduct public consultation meetings

Invitations and information will be sent out 2 weeks prior to the meetings. Meetings will be scheduled for once or twice per week, for 2 weeks. 1 week will be required to document results of public consultation meetings.

5 weeks

Prepare and submit EUB/AENV application

The application must include: • Project overview and technical description • Environmental impact assessment results • Brief socio-economic impact study • Results of public consultation

A public notice of application will also be issued. Comments received as a result of the notice will form the basis of the EUB’s decision regarding the need for a public hearing.

8-16 weeks

Application approval (no hearing)

If no public hearing is required, the application will be approved with or without conditions.

2-4 weeks

Conduct public hearing

The length of the public hearing will depend on the number of interveners. The decision from the EUB will be delivered after the hearing.

14-32 weeks

If no hearing is required, the total time for public consultation and permitting will be 32 to 94 weeks (8 to

23.5 months) depending upon environmental data gathering requirements. If a hearing is required, an

additional 14 to 32 weeks (11.5 to 31.5 months) will be required.


Figure 12.1 Project Implementation Schedule

ID Task Nam e Dura tion 1 Faster P rogress 560 days 2 Prepare fo r pub lic consu ltation 3 wks 3 Public Consulta tion m eetings 5 wks 4 Environm enta l Assessm ent 8 wks 5 In te rconnection requirem ents 6 wks 6 EUB/AENV Applica tion 2 wks 7 EUB/AN EV pub lic no tice 6 wks 8 Application approval w /out hearing 2 wks 9 Engineering 6 m ons

10 F abrication and Site P repara tion 8 m ons 11 C onstruction and Erection 8 m ons 12 C om m issiong and Tria l Operation 6 m ons 13 14 15 Slow er Progress 860 days 16 Prepare fo r pub lic consu ltation 5 wks 17 Public Consulta tion m eetings 5 wks 18 Environm enta l Assessm ent 12 w ks 19 In te rconnection requirem ents 12 w ks 20 EUB/AENV Applica tion 8 wks 21 EUB/AN EV pub lic no tice 8 wks 22 Application approval w / hearing 8 wks 23 Estab lish hearing date 12 w ks 24 Public hearing 8 wks 25 EUB dec ision afte r hearing 12 w ks 26 Engineering 12 m ons 27 F abrication and Site P repara tion 8 m ons 28 C onstruction and Erection 12 m ons 29 C om m issiong and Tria l Operation 6 m ons

Qtr 4 Qtr 1 Q tr 2 Q tr 3 Q tr 4 Q tr 1 Q tr 2 Q tr 3 Q tr 4 Q tr 1 Q tr 2 Q tr 3 Q tr 4 Qtr 1 Q tr 2 Q tr 3 Q tr 4 Y-1 Y1 Y2 Y3 Y4


13.0 CONCLUSIONS AND RECOMMENDATIONS

13.1 Conclusions

There is adequate feedstock in the form of composter and MRF residuals to justify the

implementation of a thermal recovery system. The relatively high heating value of this material

compared to mixed municipal waste makes energy recovery technically viable, and enhances the

financial feasibility.

The recovery of energy from residual waste originating at the Edmonton Compost Facility is the

logical final step of a fully integrated waste management process. The composting and thermal

processes complement each other, resulting in the best utilization of resources, and the least

amount of waste going to landfill. Application of an energy recovery system would confirm and

enhance the world leadership position of the Edmonton Waste Management Centre.

Gasification and pyrolysis are technically viable methods of extracting energy from municipal solid

waste. They are technically distinct from incineration/combustion of waste in mass burn energy

from waste facilities, or fluidized bed systems. Key differences between gasification and

combustion are:

Gasification

• Converts feedstock to CO and H2, which is a syngas that can be burned off-site

in a variety of applications, such as reciprocating engines, gas turbines, and

steam boilers;

• Syngas can also be used as a feedstock for chemical processes;

• Gasification takes place in a reducing environment, suppressing the creation of

contaminants, such as dioxins, furans, SO2, NOx;

• Syngas clean-up is simplified because of low gas volumes;

• Char can often be re-used in the process;

• Post combustion cleaning of flue gases is often not required; and

• Gasification generates the smallest amount of greenhouse gases of the thermal

processes reviewed.

Combustion

• Converts feedstock to CO2 and H2O directly to heat in an excess air environment;

• Excess air combustion allows contaminants to form, which must be removed with

an air pollution control system;


• Released heat needs to be used immediately and locally;

• Large amount of excess air requires extensive flue gas clean-up system, and

• Ash needs disposal, and may require special handling.

The gasification technologies considered in this study contain some degree of technical and

economic risk, due to their short operating history with MSW on a large scale. The pyrolysis

technology under consideration is well proven, but expensive.

Gasification and pyrolysis technologies can meet all Canadian emission standards and are likely

to be more easily sited and permitted then more conventional combustion systems. However,

they are also more complex than mass burn energy from waste systems.

Economically, and at current power rates, the lowest cost advanced thermal system would

require a tipping fee of about $78 to break even. Electrical energy produced from Edmonton

Compost Facility residuals needs to be classified as green power, in order to enhance the

revenues and overall economics. With additional capital grants and low cost financing, the

tipping fee might be reduced to under $50 per tonne, which could be competitive with a new,

state of the art landfill.

Enerkem gasification is the favoured technology for this project. It offers a cleaned syngas that

can be combusted in reciprocating engines for the production of electricity, while maintaining low

overall cost. Feedstock preparation requirements are is not yet well defined and require further

study and additional input from Enerkem.

Permitting of an advanced thermal system is not expected to present major hurdles. The public

process will, however, have to be well managed, and can be expected to be lengthy.

Traditional mass burn or fluidized bed energy from waste facilities should not be ruled out for the

recovery of energy from compost residuals. In spite of technical advances in pyrolysis and

gasification, these technologies have not yet achieved a break-through in the marketplace, and

conventional combustion systems continue to predominate due to simple and reliable technology,

and proven emission control systems.


13.2 Recommendations

It is recommended to proceed with planning for an advanced thermal energy recovery project on

the basis of the following steps:

• Verify Enerkem’s position as the preferred technology vendor.

• Obtain design details of feedstock preparation and confirm price.

• Evaluate suitability of waste preparation system for ECF residuals. If necessary,

view similar existing system operating with composter residuals. Conduct testing

in Edmonton at a sufficient scale to be confident of replicability at a commercial

scale.

• Consider the construction of a pilot facility for composter residuals only, which

would later be expanded based on the economics, operating experience, and

long-term availability of additional feedstocks. Work through pricing and

operations assumptions with technology vendor to advance from an order-of-

magnitude to pre-design level cost estimate. Compare final costs with published

costs for mass burn energy from waste technology.

• Develop a funding model and partnership opportunities for the City of Edmonton

and EPCOR. Consider the option of a public-private partnership.

• Pursue federal and provincial funding opportunities to support innovative

technologies for waste diversion and alternative energy production.

• Determine likely market value of green power and greenhouse gas emission

credits, with implications on the economics of the project.

• Continue to look for opportunities to process other high energy value wastes and

thus increase the scale and economy of the project.

• Integrate the advanced thermal system into the City’s Waste Management

Strategic Plan. Take advantage of synergies with other Edmonton Waste

Management Facilities:

− Design the ECF tipping floor as a single clearinghouse and processor for

residential waste (premium organics to the composter, residuals to the

gasifier).

− Assess the savings and returns of burning landfill gas along with syngas from

the gasifier for the generation of power.

− Determine feasibility of utilizing low grade heat for winter heating of

Edmonton Compost Facility areas, such as the tipping floor.


• Consider a guided tour for the City/ EPCOR review team of the Burnaby mass

burn facility in BC, which is a state of the art facility that has been in operation for

over 10 years.

Documents

Study of Gasification/Pyrolysis of MSW Residuals