Cogeneration — Makes Sense

Cogeneration is the simultaneous production of electricity and useful heat from a single fuel consuming process. Single-purpose thermal electric power plants reject between 50% and 65% of the fuel heat to rivers, lakes, the ocean or the atmosphere. Cogeneration systems use this rejected heat for purposes such as paper drying, chemical processing, food processing, space heating or cooling using absorption chillers.

Cogeneration produces electricity and process heat with much less fuel than when they are produced separately. Significantly lower emissions are ensured and carbon dioxide emissions are reduced, thus helping Canada’s efforts to meet the Kyoto criteria.

But while policy makers talk about wind, solar energy and other “renewable” technologies, few appear to understand and appreciate the potential of cogeneration, otherwise known as combined heat and power (CHP). Indeed, Environment Canada says that while cogeneration installations could provide 20% of Canada’s current electricity needs, they represent only about 6% of national electricity production.1

In an endeavour to promote cogeneration, COGENCanada has recently been formed. Based in Ottawa, the organization’s overall objective is to promote cogeneration, energy cascading, heat recycling, and cogeneration-based eco-industrial networks. We are pursuing this goal through advocacy, training and communication. We hope to influence governments to strengthen incentives to promote combined cycle, biomass, fuel cell and other forms of cogeneration. The importance of financial incentives and emissions trading credits will be stressed and we’ll advocate the elimination of barriers to cogeneration. We will also work in cooperation with organizations such as the Canadian Chemical Producers Association, Canadian Electricity Association and Canadian Gas Association.

Aside from the environmental advantages of reduced fuel consumption, cogeneration presents other logistical advantages. One is that cogeneration is distributed generation i.e. the power is produced close to where it is used, rather than from a distant central source. Because steam cannot be transmitted more than four or five kilometres, the cogeneration plant is located near the steam load, which is usually also the electrical load. With such proximity, fewer transmission lines are required, transmission losses are reduced, and the more stable the transmission system is to operate.

Cogeneration also improves the competitiveness of industry by reducing costs. With a local power source, selected loads can be kept running during grid failures and blackouts, avoiding costly, unplanned plant shutdowns. Many cogeneration systems owned and operated by industrial plants such as pulp and paper mills are connected to the plant loads as well as to the grid to provide frequency, stabilization and back-up. Surpluses can be sold to the grid.

Many gas turbine cogeneration systems have been added to chemical plants and oil sands facilities in Alberta since the restructuring of the electricity industry began in the late 1990s. Ontario has also eliminated the vertically integrated monopoly of Ontario Hydro, allowing plants such as TransAlta Sarnia to be built. The Ontario government has recently asked for ideas to increase cogeneration in Ontario, resulting in the organization of the Ontario Coalition for Industrial Cogeneration with which COGENCanada will cooperate. As well, Hydro Qubec, BC Hydro and Saskatchewan Power are buying power from cogenerators.

While more independent power operators have begun building and operating cogeneration systems, unfortunately, their systems tend to be shut down during grid failures. These shutdowns can present a major disadvantage to industries. In August 2003, for example, there was a massive grid failure in the northeastern U.S. and Ontario. According to a study reported by the U.S. Electricity Consumers Resources Council, 30 chemical, petrochemical and oil refining facilities near Sarnia suffered outages costing an estimated $10-20 million per hour.

Barriers to cogeneration

Despite the obvious advantages, there are many barriers to overcome in implementing cogeneration. Transmission access and interconnects can be an issue. A suitable steam host must be found. Some companies erroneously believe that a steam host unduly hampers their flexibility to generate electricity to meet demand. With proper design, this objection is not valid.

The biggest barrier to cogeneration is a lack of political will. In countries such as Denmark, the Netherlands and Finland, cogeneration has been encouraged by government incentives and it makes up to 40% of their total electricity generation — the highest proportion in the world. It is therefore encouraging to read that the Canadian government is considering giving better tax breaks to promote cogeneration.

Siting considerations are also important. Local citizen groups must be consulted and their concerns alleviated. The selling price of electricity and the cost of fuel are also major considerations in deciding whether building a cogeneration plant is financially feasible

Combined Gas Cycle Plants and Biomass

Over the past century there have been many cogeneration systems using noncondensing (backpressure) steam turbines in pulp and paper mills and other process industries. Boiler pressures and temperatures have increased over the years, increasing the amount of electricity produced as a given amount of steam flows to process. With boilers, heat must be transferred through metal tubes so steam temperatures are limited to about 540C (1004F). Gas turbine inlet temperatures are double that. The gas turbine exhaust gas temperature is perhaps 500C.

With combined cycle systems using both gas turbines and steam turbines, the kWH of electricity per unit of process heat can be about tripled. A key objective of COGENCanada is to “promote policies which ensure that developers building combined cycle power plants take advantage of available cogeneration potential.”

A typical combined cycle configuration consists of a gas turbine burning natural gas and exhausting into a heat recovery steam generator (HRSG). The exhaust gas from the gas turbine contains about 15% oxygen and so is suitable as combustion air. The gas turbine is connected to an electrical generator. The steam generated in the HRSG goes to a steam turbine, to which another electrical generator is connected. The steam turbine can exhaust to a condenser (condensing turbine) or to a process (back pressure turbine). Steam to process can be extracted from the steam turbine at several points as required by the process steam conditions. A duct burner between the gas turbine and the HRSG can double the output of the HRSG. The electricity generated by the steam turbine can be more than doubled, giving great flexibility in supplying the electrical load. The use of a condenser also results in more electrical output from the steam turbine and more flexibility.

Today, single-purpose combined cycle plants without cogeneration are being built and while these plants are considerably more efficient than coal-fired plants, high natural gas prices have become a problem. If a cogeneration component is added to combined cycle plants, they can become a major contribution to our electricity supply using much less fuel. Combined cycle cogeneration plants are also low in operating costs compared to large fossil-fired single purpose stations. They are cheaper to build and require fewer people to operate and maintain than fossil fuel-fired steam electric plants. They can be built relatively quickly, time from approval to completion being typically two to three years.

Biomass as a fuel represents an especially good opportunity to reduce the environmental impact of electrical generation. The emissions from burning the biomass are virtually the same as those from letting it decay naturally. Given the amount of biomass fuel available in forest industries, gasification of wood residue and pulp
ing liquor will allow the many Canadian biomass steam-turbine only cogeneration systems to be converted into combined cycles. This would more than double the electrical output. There is one gasification system currently operating in a corrugating medium paper mill at Trenton, Ontario. It uses a sodium carbonate semichemical pulping system.

Ottawa Hospital General Campus

One of the most interesting Non Utility Generators (NUGs) built a decade ago is a TransAlta combined cycle cogeneration system at the Ottawa Hospital General Campus on Smyth Road. The plant serves a complex of hospitals. There is one GE 40 MW LM6000 gas turbine generator with a heat recovery steam generator (HRSG) and one extraction condensing steam turbine. The steam turbine produces 30 MW with supplementary firing, or 12 MW without. The supplementary firing is provided by a duct burner between the gas turbine and the HRSG. There is some 15% oxygen in the gas turbine exhaust at a temperature of approximately 427C (800F). Because the burner uses such high temperature oxygen, the efficiency is 10% higher than that of a good conventional boiler.

The system provides heat in the form of steam and heat in the form of hot water to the hospitals. An absorption chiller uses steam heat from the cogeneration plant to provide cooling to the hospitals. One of the larger hospitals about a kilometre from the cogeneration plant is both heated and cooled by a single hot water loop. That hospital has absorption chillers using hot water to provide the cooling.

Noise is not a problem, even though the plant is close to a hospital and residential areas. Gas turbines do create a lot of noise, but with this type of installation the HRSG with its large heat transfer surface is an ideal muffler. The gas turbine is also in a sound proof enclosure.

River water is not available so a wet surface air-cooled condenser maintains a vacuum at the exhaust end of the steam. The steam not extracted from the steam turbines for use in the buildings flows to a vacuum condenser, so electrical generation will be maximized before the latent heat is rejected. The steam enters a bank of bare tubes where it condenses on the inner surface. Water is sprayed on the outer surface and large fans blow air over it to carry away the heat. The spray improves surface to air heat transfer and provides some evaporative cooling.

A plume of pure water vapour that emanates from the wet surface air-cooled condenser has caused local people to raise objections. There is no environmental problem but some have complained that the plume obstructs the view (others actually find the plume aesthetically appealing). While the water spray is not required in cold weather, shutting it off caused freezing of the condensate, so the cloud is a year around feature. A degree of mitigation was achieved by heating the vapour after it leaves the heat transfer surface.

Sarnia

In 1973, Dow Chemical converted a coal-fired high-pressure steam cogeneration system serving the Sarnia petrochemical complex into a 165 MW combined cycle system. It used aluminum finned tubes in the heat recovery steam generator to heat water and reduce the stack temperature to the 135 to 150F range — a demonstration of condensing heat recovery, that compares with 250F or more in almost all other such plants.

The Sarnia plant also demonstrated the ability of a cogeneration system to maintain electrical supply to a large industrial complex during grid failures. The cogeneration system was connected directly to the Dow complex to supply electricity. It was also connected to the grid to stabilize the frequency in the Dow complex. During grid failures, low frequency relays disconnected the plant from the grid. Selective load shedding allowed islanding and continued operation of the complex. All this was developed under the guidance of Joe Zanyk, P.Eng., a member of the COGENCanada board of advisors.

TransAlta recently took over the 1973 Dow Sarnia plant and added a new 400 MW combined cycle cogeneration system supplying millions of pounds per hour of steam to four nearby chemical petrochemical complexes: Dow, Nova, Bayer and Suncor. The plant — one of the largest in Canada — uses three gas Alstom 11N2 gas turbines each having a heat recovery steam generator and a steam turbine. The steam turbine is such that electrical output can be maintained despite changes in process steam demand. Duct burners between the gas turbines and the heat recovery steam generators vary the output of the steam turbines. The plant can supply firm power, peaking power and spinning reserve independently of process steam requirements. Delta Engineering (now Jacobs) of Calgary designed the plants.

Gordon A. Robb, P.Eng. is president of COGENCanada and president of Thermoshare. He is based in Ottawa. Bruce Brown, P. Eng. is vice-president of Thermoshare, based in Mississauga. See http.cogencanada.ca

1 EnviroZine, Issue 41, March 11, 2004 and report by Catherine Strickland and John Nyboer for Natural Resources Canada, April 2002.

***

ALHOLMENS KRAFT

Located in Pietarsaari, Finland this is the world’s largest biofuelled power plant and one of the largest circulating fluidized bed boilers. The wood fuel procurement system is also innovative and based on bundling the forest residues. Commercial operation started early in 2002.

The power plant sits beside a pulp and paper mill, which allows it to use wood-based fuels from the mill and to produce process steam for the mill. The design allows for operation in a pure condensing mode as well as in a cogeneration mode.

The annual fuel mix is 45% peat, 45% bark and wood residues, and 10% heavy fuel oil and coal. The plant supplies steam to a district heating system. It uses biomass, limestone injection and low NOx technologies to reduce the environmental impact. There are about 50 people working in operations and maintenance.

The maximum electrical output is 240 MWe and the thermal output is 100 MWt to process steam and 60 MWt to district heat.