Introduction to Combined Heat and Power · Introduction to Combined Heat and Power Newark, N.J.,...

Introduction to Combined

Heat and Power

Newark, N.J., August 24, 2016

Matt Lensink, P. Eng.Chief Operating Officer

CEM Engineering

What Is Cogeneration?

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• Simultaneous production of electricity and useful heat and/or cooling

from a single fuel source

• Utilizes proven technologies, such as:

– Combustion Gas Turbine Generators (GTG)

– Boilers or heat exchangers

– Steam Turbine Generators (STG)

– Internal Combustion Engine generators (ICE)

• Electricity produced by a cogeneration system on-site displaces electricity

purchased from the utility (thus, Behind-the-Meter [BTM])

What Is Cogeneration?

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• Combined efficiency of cogeneration (75% to 85%) is higher than the

separate production of electricity and thermal energy.

• Cogeneration (when properly designed and installed), can reduce

annual operating costs significantly.

• Cogenerated heat displaces heat from existing burners, boilers or

heaters.

Energy Efficiency Before CHP

*

* Assumes nuclear

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Energy Efficiency After CHP

19%

Conclusion: 20% improvement in macro efficiency

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Cogeneration Tutorial

Fuel 100% Trigeneration

17%

2%

30%

Heat losses

Line losses

Electricity

CoolingHeat 51%

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Who Should Consider CHP?

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• High, year-round demand for steam, hot water, or hot air (or chilled water in summer months) (or 800,000 Btu/hr of heat)

• Focused on reducing GHG emissions

• Energy cost is significant % of operating cost (> 5%)

• About to install new boiler or new genset

• “Energy champion” on staff (who is empowered to do the right thing)

Who Should Consider CHP? (cont’d)

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• Use at least 30 m3/hr of natural gas to produce thermal energy (heat) weekdays from 7 a.m. to 11 p.m.

• Use at least 250 kWe of electricity during these same hours.

• Steady demand for process chilled water (60 tons) is great, too.

• Struggles with electricity supply reliability

Prime Mover Options

• Microturbines Low demand for both hot water and electricity

• Organic Rankine Convert high-grade waste heat to electricityCycle (ORC)

• Steam Turbine Boilers designed for > 250 psigGenerators (STG)

• Combustion Gas > 10,000 lbs/hr of steam (> 40 psig)Turbine Generators (GTG)

• Internal Combustion Lots of demand for hot water <100 °CEngines (ICE)

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Technically Feasible?

• Size prime mover by matching:– Baseload thermal demand to

– Recoverable heat from prime mover

ICE GTG

< 10 mmBtu/hr (or 3,000 kWt) > 12 mmBtu/hr (or 3,600 kWt)

Stop at 3 MWe or 4 MWe Start at 1.8 MWe

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Internal Combustion

Engine (ICE)

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Internal Combustion Engine (ICE)(available from 30 kW to 4 MW)

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Internal Combustion Engine (ICE)(available from 30 kW to 4 MW)

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Internal Combustion Engine (ICE)(available from 30 kW to 4 MW)

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Typical Flow Diagram of an ICE

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Formet, St. Thomas, Ontario (Canada)

800 kWe ICE-based CHP system

• Acoustic weather-proof enclosure

• Complete with SCR and hot water

heat recovery

• CEM completed detailed design

and contract administration

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• Exhaust gas and heat recovery

• CEM completed detailed engineering and contract admin

3M Canada, Brockville, Ontario (Canada)

2 MWe ICE-based CHP system

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• Steam production from exhaust gas circuit

• Hot water production from jacket water circuit

• CEM completed engineering and contract administration services, including 86 drawings

Polycon Industries, Guelph, Ontario (Canada)

8 MWe ICE based CHP system (3 x 2.67 MWe)

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Gas Turbine

Generator (GTG)

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• One (1) Taurus 70 CED gas turbine with

SoLoNOx

• 4,160 V generator with an epicyclic

gearbox

• Power generation system ISO rated at

7.5 MWe (total), with islanding

• 800 kW spark-ignited CAT engine

generator set for peak clipping

Sonoco, Trenton, Ontario (Canada)

6.8 MWe GTG-based CHP system; 120,000 lbs/hr HRSG

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• “O”-type HRSG

• One Allison 501-KB5S gas turbine

• Power generation system ISO rated @ 3.9 MWe

• Excess electric power wheeled to another

Sonoco facility through the utility grid

• Proven electrical islanding system

Sonoco, Brantford, Ontario (Canada)

3.9 MWe GTG-based CHP system; 55,000 lbs/hr HRSG

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• Unfired, two-pass HRSG used for baseload

cogeneration; gas fuel

• One Allison 501-KB5 gas turbine with H2O

injection to produce 42 ppm NOx

• Ideal 4,160 V generator with an Allen epicyclic

gearbox

• Power generation system ISO rated at

3.8 MWe

• Data acquisition system

University of Windsor, Windsor, Ontario (Canada)

3.8 MWe GTG-based CHP system

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• Supplementary fired superheated steam HRSG

• One gas-only Allison 501-KB7 turbine

• 4,160 V generator with an Allen epicyclic

gearbox

• Power generation system ISO rated at 4.9 MWe

• Data acquisition system fuel gas booster

compressor

London Health Sciences Centre, London, Ontario (Canada)

4.9 MWe GTG-based CHP system; 75,000 lbs/hr HRSG

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• 80,000 lb/hr package boiler

• Designed new powerhouse

• CEM completed detailed design and contract administration

• Operational since 2013

London Health Sciences Centre, London, Ontario (Canada)

3.5 MWe GTG-based CHP system; 25,000 lbs/hr HRSG

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• Two (2) 50,000 lb/hr fired HRSGs (fresh-air-fired)

• Two (2) 2,000 TR steam turbine-driven centrifugal chillers

• $27 million CAPEX

• CEM completed detailed design and contract admin

Toyota Motor Manufacturing Co., Cambridge, Ontario (Canada)

9.2 MWe GTG-based CHP system (2 @ 4.6 MWe)

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Electrical Interconnect

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• Generators which offset load (whether operating in parallel or islanded) can:

– Indirectly cause reverse power flow (which affects transformers and transmission lines)

– Increase voltages beyond acceptable levels

– Cause large voltage fluctuations for other customers

• All generators connected to the grid contribute short circuit

“Hard” Challenges

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• Electrical interconnection

• Air and noise compliance

• Space available?

• Natural gas volume and pressure

• Buried services

• Soil conditions

“Soft” Challenges

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• No proponent at lower levels

• No support at higher levels

• Financial incentives time consuming

• “Cogen is too capital intensive” (perception)

• Unwillingness to consider third party financing

• Marginal credit rating (or private ownership)

Conclusions

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Schedule Considerations

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• Before “decision to proceed”:

– Allow 12–14 months

– Getting government funding takes time

– Permits and approvals

– Approval of capital

• After authorization to proceed:

– Allow 10–18 months

– Issue POs for major equipment immediately

– Engineering while equipment is manufactured

– Big allowance for commissioning

Conducting a Study

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• First, establish financial feasibility:– 10-, 15- and 20-year IRR, after-tax, before financing

– With and without grant funding

• If project might meet your company hurdle rate:a) Then establish if there is electrical capacity

b) If there is, then do Front-End Engineering and Design (FEED) to firm up capital cost and refine business case

Why Now?

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• Natural gas supply (~150 years):– Lower burner tip prices

– Stabile and predictable

• Power prices increasing significantly:– 30%–50% over next 5–10 years

• Business case/financial feasibility therefore MUCH better

• Climate change/protect manufacturing viability

Conclusions

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• On-site power generation can help a plant survive

• Technology is now highly reliable/available

• Economics are good and getting better

• Electrical interconnect is not easy (due to glut of solar and wind projects)

• Need internal champion (with support from on high and lots of stamina/persistence)

Questions?

DISCLAIMER

Although all statements and information contained herein are believed to be accurate and reliable, they are presented without guarantee or warranty of any kind, expressed or

implied. Information provided herein does not relieve the user from the responsibility of carrying out its own tests and experiments, and the user assumes all risks and liability for

use of the information and results obtained. Statements or suggestions concerning the use of materials and processes are made without representation or warranty that any such

use is free of patent infringement and are not recommendations to infringe on any patents. The user should not assume that all toxicity data and safety measures are indicated

herein or that other measures may not be required.

Thank You!

227 Bunting Road,

St. Catharines, Ontario

L2M 3Y2 Canada

Matt Lensink, P. EngChief Operating Officer

Office: 905-935-5815

matt@cemeng.ca • www.cemeng.ca

Appendix Slides

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Typical Hurdles/Solutions

Hurdle Possible solution

Capital availability? Use “Other Peoples Money” (OPM)

Driver and executive sponsor Identify both early on

Electrical interconnect Apply to utility early on (first!)

Predictable payback?Predictable price of natural gas during payback period

(“strip”)

Capital cost accuracyComplete 25%–50% design first, then estimate

capital cost

On schedule? Get all permits and approvals first

IRR/NPV alone not good enough Is there another big problem that cogen solves?

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Sample Business Case

“Sparks Spread”

• Is the ratio of delivered cost of electricity (¢/kWh) to burner tip

cost of natural gas ($/mcf)?

• Need > 1.7 (preferably 2.0)

• Example: 10¢ (CAD)/kW.h ÷ $5.50 (CAD)/mmBtu = 1.8

• Example: 11¢ (CAD)/kW.h ÷ $6.0 (CAD)/mmBtu = 1.8

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Technical Assumptions

Nominal Generating Capacity 2,000 kWe

Average Gross Power Output 2,000 kWe

Parasitic Power Load 4%

Average Net Power Output 1,920 kWe

Operating Hours 8,300 hr/yr

Net Electricity Produced 15,936 MWh/yr

Gross Heat Rate (LHV) 8,000 Btu/kW.h

Thermal Energy Recovered (HHV) 4.0 mmBtu/hr

HHV to LHV Ratio 1.11

Thermal Efficiency of Existing System (HHV) 80%

Technical Assumptions

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Financial/Economic Assumptions ($ CAD)

Delivered Cost of Electricity (2014) 0.110 $/kW.h

Burner-tip Cost of Fuel (2014) 5.50 $/mmBtu

Maintenance Reserve (LTSA) (2014) 0.013 $/kW.h (regular maintenance)

Consumables (Urea) (2014) 38 $000's/yr

Maintenance Reserve (Minor Overhauls) (2014) 280 $000's (every 4 years)

Maintenance Reserve (Major Overhauls) (2014) 530 $000's (every 8 years)

Standby Power Cost (2014) 2.30 $/kW/mo

Capital Cost (Design, Supply, Install, Commission) 5,000 $'000's

Equivalent Unit Capital Cost 2,500 $/kWe

Discount Rate for NPV Analysis 10%

Corporate Income Tax Rate 26.5%

Capital Cost Allowance Rate 30%

2015 2016 2017 2018 2019 2020

Escalation Rate on Natural Gas (from previous year) 2% 2% 2% 2% 2% 2%

Escalation Rate on Electricity (from previous year) 6% 4% 4% 5% -3% 2%

Escalation Rate on Electricity (cumulative from 2014) 6% 10% 15% 21% 17% 20%

Escalation Rate on All Other Variables 3% 3% 3% 3% 3% 3%

Financial/Economic Assumptions

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Proforma Analysis ($000’s CAD/year)

Year - 1 2 3 4 5

Calendar 2015 2016 2017 2018 2019 2020

Electricity Saved - 1,934 2,015 2,116 2,055 2,095

Natural Gas Saved by Thermal Recovery - 190 194 198 202 206

Total Annual Gross Revenues 2,124 2,209 2,313 2,257 2,301

Fuel Cost - 843 860 878 895 913

Non-Fuel O&M (Regular Maintenance) - 229 236 243 250 258

Non-Fuel O&M (Major and Minor Overhauls 315

Standby Power Charge 59 60 62 64 66

Consumables 38 39 41 42 43

Total Annual O&M Expenses 1,169 1,196 1,223 1,566 1,280

Earnings Before Interest and Taxes 955 1,013 1,090 691 1,022

Capital Cost (Design, Supply, Install, Commission) 5,000

Capital Cost Allowance (Carry-over Unused) - 750 1,275 1,155 689 437

Corporate Income Tax - 54 - - 0 155

Net Earnings After Tax (Before Grant) (5,000) 901 1,013 1,090 690 867

Proforma Analysis - $000's per year (CAD)

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Financial Results

%

10-year IRR (after-tax, before financing) 12

15-year IRR (after-tax, before financing) 15

20-year IRR (after-tax, before financing) 16

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