Micro Gas Turbine Operation with Biomass Producer Gas and

Mar 6, 2008 - At reduced power, the lower limit for stable operation is a net heating value of about 8 MJ/(N m3). The gross efficiency of the micro ga...
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1944

Energy & Fuels 2008, 22, 1944–1948

Micro Gas Turbine Operation with Biomass Producer Gas and Mixtures of Biomass Producer Gas and Natural Gas Luc P. L. M. Rabou* ECN Biomass, Coal and EnVironmental Research, P.O. Box 1, 1755 ZG Petten, The Netherlands

Jan M. Grift Cogen Projects, P.O. Box 197, 3970 AD Driebergen, The Netherlands

Ritze E. Conradie HoSt, P.O. Box 920, 7550 AX Hengelo, The Netherlands

Sven Fransen Pon Power, P.O. Box 61, 3350 AB Papendrecht, The Netherlands ReceiVed October 24, 2007. ReVised Manuscript ReceiVed January 23, 2008

We report the performance of a commercial recuperated micro gas turbine on biomass producer gas and mixtures of biomass producer gas with natural gas. The biomass producer gas, obtained by gasification at 850 °C with air at atmospheric pressure, contains about 7% H2, 17% CO, 15% CO2, 4% CH4, 2% other hydrocarbons, 2% H2O, and a balance of N2 and Ar from air. It has a net heating value of about 6 MJ/(N m3). The micro gas turbine delivers full power (30 kWe) on gas mixtures with a net heating value of at least 15 MJ/(N m3). For gas of lower heating value, the maximum fuel gas flow allowed by the fuel control unit limits the attainable power. At reduced power, the lower limit for stable operation is a net heating value of about 8 MJ/(N m3). The gross efficiency of the micro gas turbine depends on the output power but not on the gas heating value, within our estimated measurement accuracy of about 2%. Above 70% of full power, NO emission is 5 times lower than that allowed by Dutch or German legislation, and CO emission is 40 times lower. Emissions of CO, unburned hydrocarbons, and NO are over 200 times, 15 times, and 3 times lower than those of a gas engine of similar size, operating on the same biomass producer gas. At partial load below 70% of full power, the micro gas turbine burner switches to a different operating mode that produces higher CO and NO levels. The CO emission remains far below that of the gas engine but exceeds the German limit during operation on the producer gas mixtures. The NO emission becomes similar to the emission of the gas engine and close to the legal limits.

Introduction In response to growing concerns about the climate effects of burning fossil fuels, biomass is receiving a lot of attention and political support as an alternative fuel. Much effort is spent on increasing the use of locally available biomass in small-scale installations for the cogeneration of heat and power (CHP). Most of these installations rely on gas engines and operate on biogas produced by digestion of wet biomass. Some installations use biomass producer gas produced by gasification of dry biomass. A disadvantage of gas engines is the emission of NOx and unburned or partly burned fuel. The emission of NOx can be and has been reduced by primary measures that reduce the combustion temperature. However, the amount of unburned fuel, typically 0.5-1%, tends to be increased by these NOx reduction measures. Catalytic exhaust gas treatment, common with natural gas fired engines, is hampered, in the case of biomass derived gas, by the presence of trace compounds, which poison the catalyst. Instead of gas engines, micro or mini gas turbines may be used. These realize complete combustion of fuel with significantly lower * To whom correspondence should be addressed. E-mail: [email protected].

NOx emissions. Unfortunately, that advantage is offset by lower electrical efficiency. To an operator, the lower electrical output causes a loss of income, which usually cannot be compensated by higher income from heat delivery or lower operating costs. Market opportunities may arise if strict emission limits have to be obeyed or if cleaner exhaust gas has an economical value. The latter would be the case if exhaust gas could be used for CO2 addition to greenhouses to enhance productivity. The high dilution by excess air increases safety but also increases the total gas volume to be distributed. Waste heat in the exhaust gas would be useful for greenhouse heating in the winter but would increase the need for ventilation in the summer. ECN, Cogen Projects, HoSt, and Pon Power have performed a study on the technical performance of a micro gas turbine operating on biomass producer gas and on the economical prospects of that concept for the CHP. Here, we present results from experiments with a standard Capstone 30 kWe recuperated micro gas turbine operating on biomass producer gas and mixtures of biomass producer gas with natural gas. Some of these results were presented in May 2007 at the 15th European Biomass Conference and Exhibition

10.1021/ef700630z CCC: $40.75  2008 American Chemical Society Published on Web 03/06/2008

Micro Gas Turbine Operation

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Table 1. Composition of the Producer Gas during Micro Gas Turbine Tests component

average (vol %)

minimum (vol %)

maximum (vol %)

H2 CO CO2 CH4 C2H2 C2H4 C2H6 C6H6 C7H8 N2 Ar H2O NH3 tar

6.9 16.9 15.3 4.2 0.23 1.7 0.09 0.23 0.017 52.0 0.62 1.8a 0.005

6.1 14.9 14.3 3.7 0.17 1.4 0.05 0.21 0.013 50.4 0.61

7.3 19.3 15.8 4.5 0.34 1.9 0.13 0.26 0.022 64.6 0.64 0.002

a

Corresponds to the saturated water vapor at the producer gas temperature at gas cleaning.

in Berlin.1 A full report (in Dutch) on the experiments and economical analysis can be obtained from the ECN website.2 Experimental Layout and Procedures The installation used for the production of clean biomass producer gas consists of a 500 kWth circulating fluidized bed (CFB) gasifier, a gas cooler, and a gas cleaning comprising dust, tar, water, and NH3 removal. The air-blown CFB gasifier operates near atmospheric pressure at about 850 °C. The gas is cooled to 400 °C before dust is removed by a cyclone. Tar and the remaining dust are removed by the OLGA oil scrubber system developed by ECN3 and marketed by Dahlman.4 A water scrubber removes NH3 and reduces the water content to the water vapor pressure near the temperature of the surroundings (about 15 °C). During the present experiments, clean wood pellets were used as fuel. Part of the clean producer gas is used in a gas engine or micro gas turbine. The remainder is burned in a modified natural gas boiler. For measurements on the micro gas turbine, the gas engine is switched to natural gas or switched off, except for some of the stability measurements, when the gas engine was operating in parallel with the micro gas turbine and the boiler. Results presented here for the micro gas turbine were obtained in the course of a 700 h performance test of the gasifier, the gas cleaning, and the gas engine. A more extensive description of the installation and results of the endurance test can be found in another contribution to the 15th European Biomass Conference and Exhibition.5 Table 1 shows the average composition of the clean producer gas, during the micro gas turbine tests. The gas has a net calorific value (LHV) of about 6 MJ/(N m3). Over periods of hours or days, variations around the average composition of 0.5-1 vol % are observed for CH4, H2, and CO2 and ones up to 2 vol % are observed for CO and N2. These variations are caused by differences in the moisture content of fuel batches, the filling degree of the fuel bunker, and the gradual changes in the operating temperature. Shortterm fluctuations of 0.1-0.2 vol % reflect the sensitivity of the CFB gasification process to irregularities in the fuel feed rate. The producer gas moisture content is estimated at 1.8%, correspond(1) Rabou, L. P. L. M.; Grift, J. M.; Conradie, R. E.; Fransen, S.; Verhoeff, F. Proceedings of the 15th European Biomass Conference and Exhibition, Berlin, Germany; 2007; Report No. ECN-M--07-073, contribution V2.1.I.6. (2) Rabou, L. P. L. M.; Grift, J. M.; Conradie, R. E.; Fransen, S. Report No. ECN-E--06-026,available at www.ecn.nl/publicaties. (i.e. select Dutch version of website). (3) Bergman, P. C. A.; van Paasen, S. V. B.; Boerrigter, H. In Pyrolysis and Gasification of Biomass and Waste; Bridgewater A. V., Ed.; CPL Press: Newbury, U.K., 2003; pp 347–356. (4) See the page “products” at www.dahlman.nl. (5) Verhoeff, F.; Rabou, L. P. L. M.; van Paasen, S. V. B.; Emmen, F.; Buwalda, R. A.; Klein Teeselink, H. Proceedings of the 15th European Biomass Conference and Exhibition, Berlin, Germany; 2007; Contribution OA7.5.

ing to the water vapor pressure at the temperature of the gas cleaning. The NH3 and tar contents have not actually been measured during the micro gas turbine tests but are results of the 700 h performance test, during which micro gas turbine tests have been performed. The main tar component is naphthalene, responsible for 40% of the total tar content of 90 mg/(N m3). The producer gas contains 5-10 mg/(N m3) of dust, mainly minute carbon particles. Capstone recuperated micro gas turbines are available in 30 and 65 kWe sizes in versions for natural gas and for landfill gas or biogas. We used a standard 30 kWe natural gas version, without technical modifications. We only changed the fuel index, a software parameter which allows the turbine operating system to cope with the burning properties of a range of gases, but observed little difference in behavior with the standard setting. The Capstone operating system selects the turbine speed and turbine exit temperature to match the required power output and regulates the fuel gas valve accordingly. Above about 20 kWe, the operating system switches to a low-NO combustion mode to reduce the thermal NO formation. In both modes, the exhaust gas contains about 18% O2; that is, there is no difference in the air excess used. At the test site, Dutch natural gas of 31.7 MJ/(N m3) (i.e., Dutch Groningen gas quality) is available at 100 mbar and the producer gas at 70 mbar above atmospheric pressure. Both gas lines are connected to a mixture gas line through regulating and safety valves. The safety valves close when CO or H2 is detected in the room where the micro gas turbine is situated. The producer gas line also contains a back-pressure valve to prevent the higher pressure natural gas from flowing in the wrong direction. The mixture gas line is connected to the gas compressor, which is needed to obtain the required micro gas turbine entrance pressure of about 4 bar. For ease of operation, we start the micro gas turbine with natural gas. When operating conditions are stable, we gradually replace natural gas with the producer gas. To that end, we reduce the opening of the regulating valve in the natural gas line. Thus, we reduce the pressure in the natural gas line downstream of the valve until the back-pressure valve in the producer gas line opens. From that point, the gas compressor receives a mixture of natural gas and the producer gas. Further reduction of the valve opening in the natural gas line increases the producer gas content in the gas mixture. In response to the lower calorific value of the gas mixture, the micro gas turbine operating system increases the opening of the fuel gas valve to allow a larger fuel gas flow to the burner. The operating system also decreases the air flow by a slight reduction of the turbine speed. The maximum allowable producer gas content in the fuel gas mixture is reached when the fuel gas valve is fully opened or when combustion becomes unstable. For measurements requiring prolonged operation, we add slightly more natural gas than the minimum needed, in order to retain a control margin for the operating system. The concentrations of CO, H2, CO2, and CH4 in the producer gas and the composition of exhaust gas are monitored continuously by the use of gas monitors. Average values are recorded automatically each minute. Concentrations of other hydrocarbons, N2, and Ar in the producer gas are determined by a micro gas chromatograph at 3 min intervals. The natural gas flow is measured by a standard rotary meter and the producer gas flow by a turbine gas meter. Typically, these devices are accurate within 0.5%. However, as they are used at the lower limit of their operating range, larger deviations may occur. The recorded values are corrected to the normal volume at standard pressure and temperature. Power output delivered to the grid, engine speed, turbine temperature, and fuel gas valve position are read from the micro gas turbine operating console and recorded manually. The micro gas turbine efficiency is calculated from the power output, divided by the natural gas and producer gas flows, and multiplied by their respective net heating values. In the case of the producer gas, the net heating value is calculated by using the measured producer gas composition, averaged over the measurement period. Although our efficiency results have not been obtained in standard conditions or with calibrated equipment, we estimate them to be reliable within a relative error margin of 2% for a comparison between natural

1946 Energy & Fuels, Vol. 22, No. 3, 2008

Figure 1. Gas flow for micro gas turbine operation on natural gas (b) or a gas mixture with the maximum producer gas content (9) as a function of the output power. Open symbols show contributions of natural gas (O) and the producer gas (4) to the gas mixture.

Figure 2. Maximum contribution of the producer gas, by volume (b) and energy (9), to the micro gas turbine fuel gas input as a function of the output power.

gas and mixtures of natural gas and the producer gas. The relevant error sources are the actual producer gas composition and flow. A possible systematic error in the natural gas flow cancels partly, except when 100% producer gas is used.

Results When the producer gas is added to natural gas, the fuel gas valve opens wider in response to the lower heating value of the fuel gas mixture. The maximum opening of the fuel gas valve is reached when the operating console indicates a value of 80%. At that point, the maximum fuel gas flow is limited to about 25 (N m3)/hr for the producer gas and slightly more for the somewhat lighter mixtures with natural gas (see Figure 1). The data scatter because of variations in the producer gas quality and the operating margin. At full power and full opening of the fuel gas valve, the fuel gas mixture contains 65% producer gas by volume. At that point, the producer gas contributes only 26% to the net heating value of the mixture (15 MJ/(N m3)). According to our measurements, the gross electrical efficiency of the micro gas turbine at full power remains approximately 26% when the producer gas is added to natural gas. However, more energy is needed to compress the larger volume of fuel gas. The loss of net efficiency depends on the efficiency of the fuel gas compressor. When compared to compression of natural gas, it should be possible to limit the fuel gas compressor loss to an additional 1% for fuel gas with a 15 MJ/(N m3) net heating value. At partial load, the maximum contribution of the producer gas can be increased, as shown in Figure 2. Again, the data scatter because of variations in the producer gas quality and the operating margin.

Rabou et al.

Figure 3. O2 and CO2 concentrations in the dry exhaust gas of the micro gas turbine operating on natural gas (O, 4) or a gas mixture with the maximum producer gas content (b, 2) as a function of the output power.

At a given power setting, the micro gas turbine operating system tries to reach a certain combination of turbine speed and gas temperature. The system compensates the higher heat capacity of the larger fuel gas flow by a smaller air flow. To that end, it slightly reduces the turbine speed. As a result, full power output with a mixture of natural gas and the producer gas is a few percent below the 30 kWe output with pure natural gas. The smaller air flow also leads to a decrease of the O2 content in the exhaust gas (see Figure 3). The CO2 content increases more markedly, as the producer gas is richer in carbon than natural gas for the same heat input. This adds to the effect of less dilution by excess air. If a producer gas were available of higher calorific value, a larger producer gas contribution could be realized. An indirect gasifier, using, for example, the SilvaGas process developed at Battelle (USA), the FICFB process developed by the Technical University Vienna and applied in Güssing (Austria), or the Milena process in development at ECN, would allow the micro gas turbine to reach full power with 100% producer gas. The CO2 concentration in the exhaust gas would be lower, as indirect gasification yields producer gas leaner in carbon. With the producer gas actually available at ECN from the direct air-blown CFB gasifier, a larger contribution from the producer gas at full power would require hardware modifications of the micro gas turbine to increase the fuel gas flow. Instead, we investigated the performance with larger producer gas contributions at partial load. This is not an economical proposition but serves to show that the operating range can be extended to fuel gas of much lower heating value than indicated by the technical specifications of the micro gas turbine. Moreover, it allows us to evaluate emissions for operation on the producer gas. Figures 4 and 5 show results of operation with 100% producer gas at 5 kWe. Although the net heating value of 6 MJ/(N m3) allows operation for short periods, peaks in the exhaust gas CO concentration show that the combustion is unstable. During all our measurements, the concentration of unburned hydrocarbons remained about 5 ppmv. Taking into account the about 15-fold dilution in the exhaust gas, this corresponds to 0.08 vol % of the fuel gas slipping through the micro gas turbine combustion system. As the CO content in the producer gas is about twice the total amount of hydrocarbons, fuel gas slip would explain only 10 ppm of CO in the dry exhaust gas. The additional CO is probably due to incomplete combustion of hydrocarbons. Changes in the fuel gas valve position correlate to changes in the producer gas heating value or H2 content but are comparatively large. Peaks in the CO emission, near the end of each of the two periods shown, are accompanied by clearly

Micro Gas Turbine Operation

Figure 4. CO (9) and CO2 (2) concentrations in the dry exhaust gas from the micro gas turbine during operation at 5 kWe with 100% producer gas. Data of the second test are shifted in time to match the axis. Data as measured, at about 18% O2 in the dry exhaust gas.

Figure 5. H2 concentration (4) and net heating value (—, LHV) of the producer gas, and the fuel gas valve position (b) of the micro gas turbine during operation at 5 kWe with 100% producer gas. Data of the second test are shifted in time to match the axis.

audible booming noises. Both are probably caused by flame blow-off and reignition. The combustion instability may partly be blamed on insufficient dampening of the fuel gas valve regulation, which responds to observed changes in turbine gas temperature and turbine speed. Capstone has recognized that as a more general problem and replaced the fuel gas valve in recent products by a different type with more stable behavior. According to our measurements, the gross electrical efficiency at 5 kWe is 14%. It should be taken into account, however, that the micro gas turbine is operating at only 1/6th of its design power output. Figure 6 shows results of operation at 7.5 kWe with a mixture of 93% producer gas and 7% natural gas by volume (72% and 28% by energy). The fuel gas mixture has an average net heating value of 8 MJ/(N m3). The limited increase in heating value makes the combustion stable enough to prevent audible signs of flame blow-off and reignition, but fluctuations in the exhaust gas CO concentration indicate that the combustion is still at the edge of instability. Comparison with data for operation on natural gas shows the exhaust gas CO concentration to be 5 times higher with nearly 100% producer gas. The difference is significantly larger than can be explained by the somewhat higher dilution by excess air in the case of natural gas (cf. Figure 3). As mentioned before, some of the additional CO may be due to unburned fuel, but most of it is probably due to incomplete combustion of hydrocarbons. Within the accuracy of our measurements, the gross electrical efficiency at 7.5 kWe is 17% both with only natural gas and with nearly 100% producer gas.

Energy & Fuels, Vol. 22, No. 3, 2008 1947

Figure 6. CO (9) and CO2 (2) concentration in the dry exhaust gas from the micro gas turbine during operation at 7.5 kWe with a mixture of 93 vol % producer gas and 7 vol % natural gas. Data from 14:25 are for operation with 100% natural gas. Data as measured, at about 18% O2 in the dry exhaust gas.

Figure 7. CO (9) and CO2 (2) concentration in the dry exhaust gas from the micro gas turbine during operation at 15 kWe with a mixture of 80 vol % producer gas and 20 vol % natural gas. Data as measured, at about 18% O2 in the dry exhaust gas.

Figure 7 shows results of operation at 15 kWe with a mixture of 80% producer gas and 20% natural gas by volume (43% and 57% by energy). The fuel gas mixture has an average net heating value of 11 MJ/(N m3). Clearly, the exhaust gas CO concentration is more stable than that at 7.5 kWe with a lower calorific gas mixture. The average exhaust gas CO concentration is about 2 times lower than that at 7.5 kWe, but the same holds true for operation with 100% natural gas at these power outputs. The gross electrical efficiency at 15 kWe is about 22% and, again, not affected by the use of a mixture with the producer gas instead of only natural gas. As mentioned in the Experimental Layout and Procedures, above about 20 kWe, the micro gas turbine operating system switches to a low-NO combustion mode, which reduces thermal NO formation. Figure 8 shows the effect of the switch on NO emission to be smaller for mixtures of the producer gas and natural gas than for 100% natural gas. Below 20 kWe, the lower NO emissions for operation with the producer gas mixtures point to lower combustion temperatures than with natural gas. That would also explain the observed higher CO emissions that we ascribed to incomplete combustion of hydrocarbons. In low-NO combustion mode above 20 kWe, NO emissions for operation with the producer gas mixtures are slightly higher than those with 100% natural gas. That may indicate thermal NO suppression to be less efficient at high fuel flow but more likely is due to the combustion of some residual NH3 in the producer gas. The switch to a low-NO combustion mode reduces the CO concentration for operation with mixtures of the producer gas and natural gas to the level observed with 100% natural gas

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Dutch and German limits may be reached or exceeded just before the switch to the low-NO combustion mode. In the lowNO combustion mode, NO emissions are 5 times lower than the legal limits. In the Netherlands, there is no limit to the CO emission. According to the German TA Luft regulation, CO emission of gas turbines should be limited to 100 mg/(N m3) at 15% O2 in the dry exhaust gas. That translates into 38 ppm at 18% O2. That limit is exceeded below 15 kWe with the producer gas mixtures. In the low-NO combustion mode, however, the measured CO concentration is 40 times lower than the legal limit.

Figure 8. NO concentration in the dry exhaust gas of the micro gas turbine as a function of the output power for operation on the biomass producer gas mixed with varying amounts of natural gas (b) and on 100% natural gas (O). Data as measured, at about 18% O2 in the dry exhaust gas.

Figure 9. CO concentration in the dry exhaust gas of the micro gas turbine as a function of the output power for operation on the biomass producer gas mixed with varying amounts of natural gas (9) and on 100% natural gas (0).

(see Figure 9). Apparently, the high-power combustion mode effectively prevents cold zones where CO oxidation is slow. As partial load operation below 70% of maximum power would be avoided for economical reasons, it is fair to say that the use of the producer gas instead of natural gas does not increase the CO emission in practical operation conditions. The above data for emissions are given as measured in the dry exhaust gas. For comparison with data for a gas engine, the present results must be corrected in order to compensate for the higher dilution by excess air in the case of a micro gas turbine. Correction to 6% O2 in the dry exhaust gas increases the concentrations by a factor of 5. Above 20 kWe, the result would become less than 5 ppm of CO, 25 ppm of unburned hydrocarbons, and 30 ppm of NO. For comparison, our results for a 45 kWe gas engine operating on the same producer gas are more than 1000 ppm of CO, 350 ppm of unburned hydrocarbons, and 70-100 ppm of NO. According to Dutch legislation, NOx emission should be below 135 g/GJ of fuel. In the conversion from concentration to weight, the molar mass of NO2 should be used for NO. As NO represents about 90% of all NOx, the legal requirement translates into limits of 35 ppm of NO for natural gas and 25 ppm of NO for the producer gas, both at 18% O2 in the dry exhaust gas. The German TA Luft regulation sets the NOx limit for gas turbines at 75 mg/(N m3) in the case of natural gas and 150 mg/(N m3) in the case of the producer gas, both at 15% O2 in the dry exhaust gas. These values translate into 15 and 30 ppm of NO at 18% O2. From Figure 8, it can be seen that the

Conclusions The standard Capstone micro gas turbine operates remarkably well on mixtures of the biomass producer gas and natural gas. Even without modifications, it is able to deliver full power, provided the net heating value is at least 15 MJ/(N m3). Hence, the Capstone micro gas turbine should be able to deliver full output power on the producer gas from indirect gasifiers. The lower net heating value of the producer gas, as compared to natural gas, has a negligible effect on the gross electrical efficiency of the Capstone micro gas turbine. The net electrical efficiency will decrease by about 1% for the producer gas from an indirect gasifier because of the higher power demand for compression of the larger fuel gas volume. Our partial load results show that it might suffice to enable a larger fuel gas flow to allow full power operation with even lower calorific gas, down to a net heating value of 8 MJ/(N m3). However, the even larger fuel gas flow would lead to a further reduction of the net electrical efficiency. Above 70% of the design power output, emissions of CO, unburned hydrocarbons, and NO are very low, both for pure natural gas and mixtures with the biomass producer gas. When compared to a gas engine of similar size, the micro gas turbine produces over 200 times less CO, 15 times less unburned hydrocarbons, and 3 times less NO per volume of the dry exhaust gas at the same O2 content. The NO emission is 5 times lower than the current Dutch and German limits. The CO emission is 40 times lower than the German limit. At partial load below 70% of full power, the micro gas turbine burner switches to a different operating mode that produces more CO and NO. The NO emission then becomes similar to that of a gas engine and close to the legal limits. The CO emission remains far lower than that of a gas engine but at less than 50% load exceeds the German legal limit. If, instead of natural gas, the producer gas could be used, with the same composition as in our experiments, the CO2 concentration of the exhaust gases would increase by a factor 2.5. The higher CO2 concentration would be advantageous if the exhaust gases were used in a greenhouse to enhance production. If the producer gas from an indirect gasifier were used, in which the gasification process is separated from the combustion for process heat requirements, the CO2 concentration would increase only by a factor 1.7. However, operation on the producer gas from an indirect gasifier would be possible without modifications to the micro gas turbine and would require less energy for the fuel gas compression. Acknowledgment. Financial support from the Renewable Energy (DEN) program of the Dutch Energy Agency SenterNovem is gratefully acknowledged. EF700630Z