City of TorontoSolid Waste Management Services

8th Canadian Waste Resource Symposium

BIOGAS UTILIZATION:

Disco Road Organics Processing Facility

Carlyle Khan, Director

Infrastructure Development & Asset Management

December 1, 2015

Agenda City of Toronto Solid Waste Management Services

Climate Change Goals

Biogas and Landfill Gas Assets

Disco Road Organics Processing Facility

The Anaerobic Digestion Process

Biogas Overview

Biogas Utilization Options

Preferred Biogas Utilization Option

Electricity & Thermal Energy Overview

The Renewable Energy Approval Process and Reports

Financials and Payback

Biogas Consumption Amounts

Solid Waste Management

Mission Statement:

To be a leader in providing innovative management services to residents, businesses and visitors within the City of Toronto in a safe, efficient, effective and courteous manner, creating environmental sustainability, promoting diversion and maintaining a clean city.

The City of Toronto has committed to:

Reducing GHGs by 30% from 1990 levels by 2020.

Reducing GHGs by 80% from 1990 levels by 2050.

Climate Change & Solid Waste

Renewable Natural Gas (Fuel)

Renewable Electricity Renewable Natural Gas (Heat)

Biogas & Landfill Gas Assets

The Greenlane Landfill

The Disco Road Organics Processing Facility

The Dufferin Organics Processing Facility

The Keele Valley Landfill (closed)

Disco Road Organics Processing Facility

The Anaerobic Digestion Process

Tipping Floor

Residual Waste, such as plastic bags, sent to Green Lane Landfill

Water added to material

Clean Organic Pulp Suspension Buffer Tank

Water Removed

Effluent

Digester Solids

BiogasBiogas

Utilization Facility

Electricity generation for facility (reduce reliance on power grid)

Heat for buildings and the anaerobic digestion process (reduce reliance on NG)

Flare

Green Bin materials collected and sent to transfer stations.

Renewable Natural Gas production to use in NG vehicles (reduce reliance on diesel)

AD Facility

Biogas OverviewComponent Amount Unit

Temperature 33 °C

Water (H2O) 100 %RH

Pressure 29.06 In. Hg

Methane (CH4) 68.7 Vol.%

Carbon Dioxide (CO2) 30.6 Vol.%

Nitrogen (N2) ND Vol.%

Oxygen (O2) 0.68 Vol.%

Hydrogen Sulphide (H2S) 821 Vol.%

Total Non Methane Hydrocarbons 2247 mg/m3

Total Silicon 187 µ/m3

* ~ 97 m3/tonne SSO

Biogas Utilization Options

Power Purchase Agreement – Electricity Generation with Limited Heat Capture

Power Purchase Agreement – Combined Heat and Power

Load Displacement Electricity Generation with Limited Heat Capture

Load Displacement Combined Heat and Power

Renewable Natural Gas

Renewable Compressed Natural Gas as Vehicle Fuel

Renewable Liquefied Natural Gas as Vehicle Fuel

Biogas to Methanol

Electricity and Heat Generation

Electricity

A 2.0 MW Plant with two internal combustion engines.

Both generators to operate during on-peak hours

One generator (0.850 MW) to operate during off-peak hours

Thermal Energy

Limited heat capture with design flexibility to convert to full scale CHP.

Heat to be conveyed by 90°C hot water

Supply of full thermal demands at 120 Disco (DROPF and Transfer Station)

Supply of majority of thermal demands at 150 Disco (Partner Division)

Behind the Meter Conceptual Design

A

B

C

D

DROPF Transfer Station

Biogas Utilization Facility

Biogas,Electrical,Hot Water

Connections

Electrical and Hot Water Connections

Hot Water Connection

150 Disco Road

(Disco Yard) 120 Disco Road

(DRWMF)

Financial Estimates

• Estimated Capital Cost Approximately $5.0 million

• Estimated Annual Operating Cost $260,000 plus major overhaul every 10 years of $790,000

• Estimated Annual Energy Savings $1.4 million in Electricity

$77,000 in Natural Gas

Simple Payback of approximately 4.8 years

But Wait…….

Recommendations

Environmental

EconomicSocial

Triple-bottom Line Framework

RNG

Estimated that we can produce 4.5M diesel litre equivalents each year (1.2M diesel gallon equivalents)

RNG Option

Behind the Meter Theoretical Design

DISCO Transfer Station

Biogas Upgrading

Facility

Biogas Stream

Natural Gas Pipeline

Compressor

Financial Estimates

• Estimated Capital Cost Approximately $2.0 – 4.0 million (technology dependent)

• Estimated Annual Operating Cost $1.00 – 1.5M (technology dependent)

• Estimated Annual Diesel Cost Avoidance $4.0M (entirely dependent on price of diesel)

Simple Payback of approximately 2.5 years

Environmental Estimates

Social Estimates

Social Benefits

NG vehicles are far less noisy

Local health outcomes

Job creation potential through new technology adoption

Thank You