Cogeneration and district energy, which formed the basis of the world’s very first power plant in New York, can be a prominent solution to energy security and environmental issues. And, as Manfred Klein writes, environmental policies for gas turbine CHP systems are evolving to advance sustainable energy objectives.
There are huge opportunities for industrial and commercial CHP systems. Previous articles in this magazine have discussed solutions to barriers, focusing on the business cases that often do not quantify the many benefits of CHP, and policy drivers that may discourage grid interconnection and local generation. One of these solutions is environmental regulatory policy, which is evolving but often not yet there to provide a balanced health benefit and the required incentives for expansion of ‘clean’ energy in on-site systems for various sectors.
So, what do we mean by ‘clean energy’ – is it just about carbon emissions, or health impacts? See Figure 1. Maybe both – there is more to this, as low air pollution and condenser water impacts have always been important to local regions. Air toxins and CFCs from these same energy systems must also be reduced, and back-end pollution controls have collateral impacts that often affect greenhouse gas (GHG) profiles. Pollution prevention and energy conservation, integrated with system efficiency, are key elements in arriving at balanced and cost-effective long-term solutions that address economic opportunities, energy security and environmental sustainability.
Gas turbine cogeneration systems fuelled by natural gas or synthetic gases have many attributes required by clean energy systems for thermal, electrical and mechanical energy with low air emissions. Smaller machines that can have most of the heat recovered often have the better CHP efficiency and GHG profiles. Best available technology (BAT) considerations will differ greatly, depending on the objectives and environmental issues to be mitigated, and the extent to which prevention and conservation is encouraged rather than controls and NOx emissions dilution. GHG issues may require a completely different environmental assessment (EA) approach than traditional air and water pollution control evaluations.
National guidelines and standards with comprehensive and consistent objectives applied in EAs or BAT determinations can give the best overall approaches. Until recently, GHG emissions and energy efficiency, as a balanced environmental issue, have rarely been studied in permitting and EA processes. Assessments may wish to consider the whole facility as a total energy system, rather than individual components, and may also include the various emissions and efficiency trade-offs in the surrounding region (for example to look for waste heat utilization potential, and water impacts).
|Figure 1. Clean energy balancing act|
A large fraction of the world’s energy production has been installed using various types of small and large gas turbine systems. Like other nations, Canada has many types of designs, in about 80 active gas turbine CHP plants and over 20 large gas turbine combined-cycle plants.
EMISSION STANDARDS FOR INDUSTRIAL GAS TURBINES
Gas turbines are thermodynamic engines which use a steady inflow of a gas (mostly air), compressed and fired with gaseous or liquid fuel. This high-pressure hot air mixture is expanded through a turbine to generate output power for thrust in an aircraft engine and for marine propulsion, or as shaft power for applications such as pipeline compression, electrical power and CHP heat production. Note that ‘gas turbine’ is a general term regardless of fuel used, as it is the large amount of clean air that produces the turbine power.
Most air pollution NOx measurements are done on a volumetric concentration basis, in parts per million by volume (ppmv) or in some cases in a weight/volume fraction such as mg/m3. Uncontrolled gas turbine NOx emissions are in the 150–300 ppmv range (about 300–600 mg/m3). Sometimes rules are based on a pollutant mass per unit heat input, such as lbs/MMBTU or grams/GJ.
There is little environmental stimulus to conserve energy, and plant output and system efficiency is not directly considered. To some degree they give an incentive to dilute the emission using airflow or stack height, although excess air can be limited by defining a standard oxygen content, such as 15% O2. Back-end controls also tend to encourage parasitic power losses, and plant efficiency objectives are not considered in the analysis. Traditional emission standards and assessment methods do not consider CO2 emissions, a necessary product of heat release.
Energy conservation is clearly pollution prevention, and therefore waste heat recovery and CHP should be specifically recognized as an emission prevention technology. An alternative output-based standard such as kg per MWh allows the plant designer and operator to take advantage of all available system efficiencies to reduce fuel consumption, and parasitic losses, or to increase output to offset other emissions. Output-based criteria allow simple and clear comparisons with other technologies, and can readily be used in emissions trading scenarios.
Emission standards should also deal effectively in a balanced fashion with collateral emissions, such as CO, unburned hydrocarbons, particulate matter (PM) and air toxics, as well as GHG emissions of methane and nitrous oxide.
In 1992, Canadian emission guidelines for stationary combustion turbines were published through a national consultation to promote reasonable pollution prevention technology to achieve a sizeable reduction in NOx emissions. Energy efficiency to minimize CO2 emissions was also deemed to be important, as well as considerations of operational reliability and cost-effectiveness. We developed an energy output basis for the guideline, with NOx levels directly tied to the demonstrated overall system efficiency. This spring marks the 20th anniversary of the development of that Canadian guideline.
This was the first regulatory standard for the gas turbine sector that used output energy, and helped to establish pollution prevention, combustion modifications and overall system CHP efficiency as ‘Best Available Technology’. The guideline uses an energy output basis for power and heat, in grams of NOx per GJ of energy output. It allows higher efficiency systems to have a higher exhaust ppm NOx concentration. The emission targets in Figure 2 were established at a certain efficiency range in each chosen size category, for gaseous and liquid fuels.
For large units greater than 20 MWe, the power output allowance at 140 g/GJ relates the mass of NOx emitted to the number of GJ or MW of power output (0.5 kg/MWh). This allowance results in large units, fired on natural gas, having to meet a full load NOx emission target of about 27–33 ppmv in simple cycle applications and 37–42 ppmv in a combined-cycle plant. A higher emission level is available through the 40 g/GJ heat recovery allowance to encourage cogeneration applications. Units of 3 to 20 MW have targets set about 70% higher (240 g/GJ, or 0.86 kg/MWh). Revisions are being developed this year to also deal with large gas turbine units in the 70 MWe and greater sizes.
The US Environmental Protection Agency (EPA) has usually used concentration-based ppmv standards, coupled with some state daily, monthly or annual tonnage caps and emission offset rules. Best available control technology (BACT) practices included steam/water injection, dry low NOx combustion technology and add-on selective catalytic reduction (SCR) back-end emission controls. When the lowest achievable NOx emission rate became dominant, these ultra-low NOx control solutions with dry low NOx (DLN) plus SCR were often required, with regional levels set as low as 2 ppmv.
After some years of consultation, the US EPA released in July 2006 a new national NSPS regulation for gas turbines used for pipeline compressors, utility combined-cycle plants and industrial cogeneration plants. Instead of requiring ultra-low NOx stack concentration, the new rules would give a choice for using ppmv criteria, or a new output-based method in kg/MWh, at somewhat higher NOx levels to encourage more energy system efficiency (15–42 ppm, or 0.19 to 1.04 kg/MWh). Local state implementation may be held up by legal challenges due to perceived pitfalls in the loosening up of local NOx permit levels.
European countries have since 2005 revised the Large Combustion Plant Directive (LCPD), including ‘BAT Reference’ documents (BREFs). However, there is still much debate by industry and government on the various regulatory strategies in EU countries, and to what extent GHGs, system efficiency and other solutions are employed.
Europe has traditionally used concentration-based standards (mg/m3) or fuel input based levels (g/GJ fuel). The Large Combustion Plant Directive from 2005 has required limits for any fuel based plants with more than 50 MW thermal input capacity (between 15–20 MW output). For any gas-fired plants, this was set at a 50 mg/m3 level, but a 25 mg/m3 cogeneration efficiency allowance is a progressive incentive that allows this increased level. The European Commission in 2007 adopted new legislation on industrial emissions to strengthen these provisions, and a new Industrial Emissions Directive of 2011 may combine several impacts into an integrated policy.
AIR POLLUTION AND GHG EMISSIONS
Figure 3 compares approximate air pollution and CO2 emissions from various fuel-based systems. The multiple pollution prevention benefits of gas turbine and biomass CHP are evident, along with gasification and carbon capture.
Some energy solutions have both low air pollution and low CO2, including energy conservation, renewables, nuclear, hydro, as well as various industrial gas turbine systems. When GHG emissions are prevented in a system, one finds that all air pollution subsequently falls dramatically as well. There are many synergies and trade-offs in how air pollution and GHG emissions can be prevented and controlled. Some specific examples of balancing various issues are summarized below.
|Figure 2. Canadian CCME gas turbine guideline, 1992|
Water and steam injection for NOx reduction
One method of NOx reduction is the addition of clean water, at a water/fuel mass ratio about 1:1, into the combustion zone to lower the flame temperatures, achieving a 70% NOx reduction. Clean water treatment facilities and combustor maintenance can have high operating costs. Steam injection is often an option on combined cycles and cogeneration plants, where high-pressure steam at a ratio of 1.5:1 is readily available from the heat recovery steam generator (HRSG). Injection into the combustor while producing more power can, however, rob the high-pressure steam cycle of energy, thereby reducing plant efficiency in some cases.
Dry low NOx (DLN) combustors
A more cost-effective pollution prevention method for thermal NOx is to modify the combustion process itself, by changing the airflow and fuel mixture inside the combustor to minimize the occurrence of high local peak flame temperatures, in ‘lean pre-mix’ DLN combustors. Developments since 1990 have successfully resulted in NOx reductions of 60–90%, to a range near 0.7 kg/MWh (15-30 ppm)for small to medium-sized units, and as low as 0.2 kg/MWh (10 ppm) for some very large machines that have more physical combustor design volume and space. The fuel/air ratio must be closely controlled during off-design conditions to prevent instability, combustor pressure oscillations and flameout.
Gas turbine engine vibrations and thermal cracking of hot parts have always been a maintenance challenge, especially for high pressure ratio aeroderivative engines, and now with large gas turbine combined-cycle plants that must be cycled under part load conditions. Transient low fuel/air ratios during low power settings can create the need to bleed away compressor discharge air, or close inlet guide vanes, thereby losing efficiency. Difficulties are faced in designing a reliable fuel control system that maintains good combustion and low CO emissions over a wide range of ambient temperature and loading conditions.
NOx and CO2 emissions from systems often increase in opposite ‘directions’, with high pressures and temperatures (for efficiency) creating more thermal NOx. Small high-pressure combustors may also have difficult challenges in lean pre-mix design. Smaller units, with smaller combustors, can be allowed a higher NOx level as they can often be more efficient in CHP applications, being able to use most of their exhaust heat output, with a high heat to power ratio.
|Figure 3. Air pollution and CO2 emissions from various fuel-based systems|
Large gas turbines have lower NOx emission rates in large DLN combustors for combined-cycle plants. However, the required large steam condensers are an environmental problem for several reasons: large energy losses, thermal pollution of local water bodies, vapour plumes and noise impacts. Large gas turbine systems can be built very quickly, and consume large amounts of fuel from the natural gas delivery infrastructure. The remote siting of a large number of combined cycles will lead to more power transmission lines, condenser energy losses, and gas fuel supply and pricing uncertainty.
Selective catalytic reduction (SCR)
SCR systems use ammonia with a catalyst structure in the waste heat boiler to convert NOx in the exhaust stream to mostly nitrogen and water. Despite the demonstrated 70–80% reduction of NOx, there are several negative collateral issues with SCR systems, including increased fine particulate and ammonia emissions, problems with cycling operation, and the safety and health risks of ammonia handling and transportation. Back-end controls have generally been shown to be less cost-effective than pollution prevention measures, as they often give rise to other collateral air, water or safety impacts, as well as efficiency losses and increased GHGs. When employed after DLN combustion, the resulting safety issues, air emissions plus efficiency loss (more GHGs) can outweigh the marginal benefits of SCR.
Fine particulate and CO emissions
Fine particulate emissions (PM 10 and PM 2.5) can be a serious health issue. There has been discussion on fine PM emissions from gas-fired gas turbines (as per the US EPA AP42 rates of about 0.03 kg/MWh). However, with gas turbine engines swallowing millions of tonnes per year of air for their power output, some of that air may not go through combustion, but as combustor cooling bypass flow. The incoming air might have very fine airborne dust and volatile organic compound (VOC) oils. Can that air which gets by the inlet filter, avoiding combustion, pass through the machine and show up in the exhaust?
It may be that the modern gas turbine system, with higher efficiency air filtration, is cleaning the air from PM by over 99%, and the emission factor could be negative (unless there is an ammonia-based SCR). New DLN combustors also expose more of the airflow to high temperature combustion, possibly incinerating most particles which have survived the air filters.
Combustor design is greatly influenced by how carbon monoxide (CO) emissions are handled, especially for off-design, transient and cold ambient conditions. How important are CO emissions? These emission levels are often set at the same ppm level as NOx emissions. That may not be necessary, as they are much less harmful to human health, rising from an elevated high temperature exhaust stack to oxidize into CO2 within a day or two.
But the combustor designer is faced with great challenges in mechanical airflow and mixing strategies, with the added complication of transient, start-up and shutdown operating modes. The necessary features of low CO emissions over these conditions will compromise the reliable dry low NOx performance over a suitable operating range.
Gas turbine engines have varying amounts of shaft output per kg/sec of air mass flow. This seems to depend on engine size, number of compressor/turbine spools, pressure ratio and bleed air, combustor firing intensity, and the overall resulting efficiency. The value of air mass flow varies from about 200–400 kW per kg/sec air). Traditional gas turbine NOx emissions are measured and studied in term of concentration ppmv. In an efficient unit, at half the air mass flow for a certain power, the same concentration could have only half of the mass emissions.
HEAT RECOVERY STEAM GENERATORS (HRSGs)
HRSGs are critical to efficient gas turbine CHP systems. They can employ a duct burner at their intake from gas turbine exhaust that has a residual amount of oxygen (13–16%) needed for combustion. This ‘auxiliary firing’ can normally give a large boost to steam production by raising the gas temperature from about 450–500°C to around 900°C, especially for turbine units which have very efficient cycles and low exhaust temperatures. The available oxygen levels will decrease with firing in proportion to the fuel added. Because of the very high preheat from the gas turbine, duct burners are very effective in allowing the HRSG to act as a ~100% efficient ‘boiler’. Sometimes these burners are treated in permitting as a source of increased NOx emissions. There are however many benefits to having them:
- avoiding additional traditional boiler fuel used at a 75–85% heat efficiency;
- allowing smaller gas turbine engines for the CHP application;
- providing good CHP opportunities for aeroderivative gas turbines with low exhaust gas temperatures;
- for single-pressure drum units, the higher inlet temperature will increase heat transfer and lower the final stack temperature by 30–50°C, thereby improving overall thermal efficiency;
- providing intermittent cycling flexibility for triple the steam production of unfired HRSG systems;
- duct firing also allows for improved active control of steam conditions and process optimization.
To evaluate system efficiency and GHG emissions, ‘fuel chargeable to power’ (FCP) is an energy allocation method that can be used for cogeneration calculations. FCP is defined as the net heat rate credited to electricity (or mechanical power) after the thermal load has been served, in GJ/MWh.
|Figure 4. Quality of energy|
Other more detailed analyses for heat may use ‘exergy’ methods, where the ‘quality’ of energy is determined depending upon temperature and pressure levels, and system losses – see Figure 4. Exergy analysis would allocate more emissions than FCP to the higher quality power portion of a system. Whether FCP or exergy, such methods would allow for a meaningful allocation of various emissions for cogeneration systems.
For fair comparisons, the use of higher heating value (HHV), rather than LHV, could also be considered for all energy systems that can use condensing heat recovery. CHP markets would also be better served if the MWth thermal values were recognized and described at the same time as MWe electrical totals.
IGCC and polygeneration should be considered for large projects where natural gas is at a premium, where coal or petcoke is abundant, and where CO2 capture and storage can be linked to this technology. Because IGCCs are essentially coal plants, they will be unable to meet the very stringent NOx emission levels of natural gas-fuelled plants. Hydrogen-rich fuels must be reliably and safely burned to provide for effective carbon capture and system availability. They have significant flame speed, auto-ignition and flashback characteristics in high-pressure combustion, and are often used with nitrogen or steam dilution to minimize NOx emissions.
Identifying comprehensive environmental solutions for GHG and air pollution reductions, with energy reliability and security, make economic sense regardless of the degree of proof in anthropogenic climate change – what used to be termed ‘no regrets’ measures. Energy output, fuel combustion and emissions occur in real, physical facilities. Site visits, training and time spent in the field near actual equipment can be extremely valuable for all in understanding important linkages, collateral impacts and integrated systems.
Rational and clear energy output-based environmental standards can help encourage best practices for many efficient and clean energy opportunities. A balanced economic implementation will be a key consideration among the variety of energy choices that are needed for our long-term infrastructure and job creation needs.
Manfred Klein is a member of the Industrial Application of Gas Turbines Committee, Canada, a technical advisory group to Canadian industry and government. For further information, visit: www.iagtcommittee.com