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Combined heat and power

Topic last reviewed: 10 April 2013

Sectors: Downstream, Upstream

Combined heat and power (CHP) involves the use of a heat engine or power system to simultaneously generate electricity and useful heat. CHP is not a single technology, but an integrated energy system that can be modified depending on the energy end use. By recovering waste heat, the cogeneration of heat and power typically achieves effective electrical efficiencies of 70% to 80% — a dramatic improvement over the average 33% efficiency of conventional fossil-fuelled power plants.

The two most common system configurations are shown below.

Figure 1: Gas turbine or engine with heat recovery unit (ref 1)

 

Figure 2: Boiler with steam turbine (ref 1)

 

Figures 1 and 2 can be referenced at the ‘Combined Heat and Power Partnership’ website of the US EPA (Reference 1)

Gas turbines or reciprocating engines with heat recovery unit

Reciprocating engine and gas turbine CHP systems combust fuel to generate electricity and then use a heat recovery unit to capture waste heat from the combustion system’s exhaust stream. This heat is converted into useful thermal energy, usually in the form of steam or hot water. Gas turbines/engines are ideally suited for large CHP applications requiring significant amounts of electricity and heat simultaneously.

CHP captures some of the waste heat for heating purposes instead of releasing the heat with the flue gas from the power generation system. The waste heat from the exhaust gas from conventional gas turbines can be utilized for heating or generation of electrical power by using steam turbines. (See the template for Combined Cycle Power Plants for more information for utilizing the heat for generation of electrical power.) For all facilities, both onshore and offshore, it is important to analyse the need for power together with the need for heat throughout the process (see the template for PINCH analysis).

In most installations/plants (both onshore and offshore), there is often a large demand for thermal energy. Normally, the gas turbine exhaust is utilized as heat—a solution which is both energy-efficient and economical if the required heat demand matches well with the recovered waste heat. If the required heat demand is low, it may be difficult to utilize all the heat that it is possible to recover, and there will be surplus heat that cannot be utilized. In such situations, it may be more energy efficient to utilize the exhaust gas to produce extra power (e.g. combined cycle). Normally, it is more costly to use the exhaust gas for new power production than to use it for providing heat. Combining heat and power (heat integration) can provide up to 90% (or more) of the heat requirements for offshore installations when energy is recovered from the gas turbine exhaust and other hot process streams (Norwegian Petroleum Directorate, report published March 2011). The need for heating will vary for different installations and plants over time. On new plants, the waste heat from power generation is normally utilized, resulting in lower overall energy requirements, and thus, generally lower emissions. A gas turbine with an electric equivalent capacity of 30 MW (offshore example) equipped with a waste heat recovery unit (WHRU) can supply a heating capacity of 35 MW. Further, WHRUs can also be installed at existing turbines to recover waste heat, potentially reducing or eliminating the need for electric, gas-fired, or oil-fired heaters and boilers, and thus significantly reducing the energy used overall for heating.

Boiler with steam turbine

Unlike gas turbine and reciprocating engine CHP systems where heat is a by-product of power generation, steam turbines normally generate electricity as a by-product of heat (steam). In the oil and gas industry, steam turbines are less common than gas turbines or reciprocating engines with heat recovery units. Steam turbine plants typically exist in heavy industries where high-temperature furnaces are used. A waste heat recovery boiler recaptures waste heat from a manufacturing heating process, and the waste heat is used to produce steam that drives a steam turbine to produce electricity. Since fuel is burned first in the production process, no extra fuel is required to produce electricity. Alternatively, if no waste heat is available in the facility, a fuel-fired boiler can be used to produce the high-pressure steam required to drive a steam turbine for electricity generation, with associated waste heat recovery. It is important to analyse the need for power, the coincident need for heat, and the heat flow through the industrial process. (See the template for PINCH analysis)

Technology maturity

Commercially available? Yes
Offshore viability:  Yes
Brownfield retrofit?: 
Yes
Years experience in the industry:
21+

Key metrics

Range of application:  Process units with power and heating demand
Efficiency:  70–80%
Guideline capital costs: $5–20+ MM USD, depending on size of plant
Guideline operational costs: 
Less fuel and energy is used, saving operational costs
Typical scope of work description: 
For new plants, both onshore and offshore, it is important to analyse the need for power, the need for heat and the heat flow through the industrial process. Based on these analyses, an optimal solution for minimizing energy costs can be chosen.

For existing plants with electric, oil-fired, or gas-fired heaters, the energy consumption from these heaters must be analysed. Process, mechanical, and electrical engineers can then make plans to replace or retrofit the older direct-fired heaters with waste heat recovery units on the existing turbine or engine exhaust. Such modifications may be costly in some plants, and the capital cost for modification, operational cost savings from using less energy / fuel, and reduced greenhouse gas (GHG) emissions must then be evaluated before the decision to replace old heaters can be taken.

Decision drivers

Technical:   Footprint: Size, weight, area required Brownfield integration: Waste heat transport, piping, tie-ins, shut down, structural 
Operational:   Training of operators 
Commercial:   Saving energy and fuel cost 
Environmental:   Improved energy efficiency. Cogeneration’s higher efficiencies reduce air emissions of nitrogen oxides, sulphur dioxide, mercury, particulate matter and GHGs. 

Alternative technologies

The following are technologies that provide similar benefits and may be considered as alternatives to combined heat and power:

  • Organic Rankine Cycle (e.g. O-Regen™ Technology by General Electric)

Operational issues/risks

Issues and risks are few and known. Combined heat and power technology has been used for many years. If a steam turbine configuration is used, solids may carry over from the boiler and deposit on the steam turbine nozzles, causing power output to degrade. The oil lubrication system must be clean and at the correct operating temperature and level to maintain proper performance. Other operations and maintenance items include inspecting auxiliary systems such as lubricating-oil pumps, coolers and oil strainers, and safety check devices such as over-speed trips. If a reciprocating engine is used, periodic inspection and replacement of engine oil and coolant is required.

Opportunities/business case

I. Natural gas platform in Vietnam

An energy savings analysis was conducted for an existing offshore production platform in Vietnam, with an installation consisting of two (2) Solar Mars gas turbine generators. The project involved replacement of the gas turbine silencer with a waste heat recovery unit (WHRU) to recover heat from the turbine exhaust stream. The recovered heat avoided the use of natural gas in direct-fired heaters on the platform.

Baseline scenario: Two natural gas-fired gas turbine generators and direct-fired heaters.

Energy efficiency project activity: Install WHRU to recover heat from turbine exhaust; displace equivalent natural gas use for direct-fired heaters.

Solar turbine performance specifications:

  • Heat input = 29,624 kW
  • Power output = 9,450 kW
  • Mass flow = 40.2 kg/s
  • Exhaust gas exit temperature = 470 °C
  • WHRU exit temperature = 110 °C
  • 15.73 MW WHRU available energy (53.66 MMBTU/hr)

WHRU performance specifications:

Thermal duty:

  • 15.73 MW WHRU thermal duty without supplementary firing
  • 41.25 MW WHRU thermal duty with supplementary firing

Process flow:

  • 29,188 kg/hr (no firing)
  • 91,373 kg/hr (fired)

Figure 3: Concentric internal bypass and silencer heat recovery system

Estimated costs:

Estimated cost savings:
•  Natural gas saved: 570,000 MM BTU/yr or 560 MM scf/yr (assuming 8500 hrs/yr and 80% thermal efficiency of displaced natural gas in direct-fired heaters)
•  Fuel cost saved: $4.5 MM/yr (assuming natural gas price of $8/MMBTU)

Equipment costs:
•  Uninstalled equipment cost (equipment only): $1.5 MM USD
•  Installed capital expense (CAPEX) cost: $5 MM USD (including heat distribution infrastructure)

Energy savings and emission reductions:
•  CO2 abatement: 31,000 tonnes CO2 equivalent/yr
•  Carbon valuation: $776,000 USD/year (at carbon price of $25 USD/tonne)

II. Natural gas platform, North Sea

A new offshore production platform has a power demand of 50 MW, and a heat demand of 8 MW. Investigation into a WHRU determined that a combined heat and power installation would satisfy the target heat demand of 8 MW from waste heat recovery (with surplus capacity above the platform’s heat demand).

The base case scenario for the platform was heat integration to achieve 3 MW of the heat demand. The additional 5 MW would then need to be supplied by power (electrical heating). Therefore, the alternative of installing a WHRU avoided an equivalent of 5 MW of electrical power generation on the platform.

Baseline scenario: Additional electrical generation of 5 MW to meet heat demand, after heat integration in base design taken into consideration.

Energy efficiency project activity: Install WHRU to recover 5 MW of heat from turbine exhaust; displace 5 MW of additional electrical generation in baseline scenario.

Estimated costs:

Estimated cost savings:
•  Natural gas saved: 360,000 MM BTU/yr or 350 MM scf/yr
•  Fuel cost saved: $3 MM USD/yr (assuming natural gas price of $8 USD/MMBTU)

Equipment costs:
•  Installed CAPEX: $6 MM USD

Energy savings and emission reductions:
•  CO2 abatement: 23,000 tonnes CO2 equivalent/yr, representing an overall platform reduction of 10%
•  Carbon valuation: $575,000 USD/yr at a carbon price of $25/tonne)


References:

  1. CHP Partnership, U.S. Environmental Protection Agency website.
  2. Norwegian Petroleum Directorate (NPD) (2011). ‘Miljøteknologirapporten’ (Environmental technology report). Published March 2011, Norwegian and Russian versions only.
  3. IPIECA (2007). ‘Saving Energy in the Oil and Gas Industry.’ (PDF file)
  4. -REMOVED-
  5. ENER-G Commercial Case Studies
  6. Kloster, P. (ABB Miljø AS, Norway). ‘Energy Optimization on Offshore Installations with Emphasis on Offshore Combined Cycle Plants’. SPE Paper 56964.
  7. U.S. Office of Energy Efficiency and Renewable Energy (1999). ‘Review of Combined Heat and Power Technologies’. U.S. Department of Energy.