GAS TURBINE COMBINED CYCLE WITH CO2-CAPTURE USING ...

Proceedings of ASME TURBO EXPO 2000: Land, Sea, and Air May 8-11, 2000, Munich, Germany

2000-GT-162 GAS TURBINE COMBINED CYCLE WITH CO2-CAPTURE USING AUTO-THERMAL REFORMING OF NATURAL GAS Thormod Andersen and Hanne M. Kvamsdal SINTEF Energy Research, N-7465 Trondheim, Norway

Olav Bolland The Norwegian University of Science and Technology N-7491 Trondheim, Norway

ABSTRACT

PRE ST WR

A concept for capturing and sequestering CO2 from a natural gas fired combined cycle power plant is presented. The present approach is to decarbonise the fuel prior to combustion by reforming natural gas, producing a hydrogen-rich fuel. The reforming process consists of an air-blown pressurised autothermal reformer that produces a gas containing H2, CO and a small fraction of CH4 as combustible components. The gas is then led through a water gas shift reactor, where the equilibrium of CO and H2O is shifted towards CO2 and H2. The CO2 is then captured from the resulting gas by chemical absorption. The gas turbine of this system is then fed with a fuel gas containing approximately 50% H2. In order to achieve acceptable level of fuel-to-electricity conversion efficiency, this kind of process is attractive because of the possibility of process integration between the combined cycle and the reforming process. A comparison is made between a “standard” combined cycle and the current process with CO2-removal. This study also comprise an investigation of using a lower pressure level in the reforming section than in the gas turbine combustor and the impact of reduced steam/carbon ratio in the main reformer. The impact on gas turbine operation because of massive air bleed and the use of a hydrogen rich fuel is discussed.

INTRODUCTION

In order to reduce the CO2 emission from natural gas based power generation plants, three different main types of concepts have emerged as the most promising. A) Separation of CO2 from exhaust gas coming from a standard gas turbine combined cycle (CC), using chemical absorption by amine solutions. It can either be performed with a direct contact between exhaust gas and absorbent (Meisen and Shuai, 1997; Mimura et al., 1999; Erga et al., 1995; Allam and Spilsbury, 1992), or with the use of liquid membranes (Chakma, 1995; Feron and Jansen, 1997; Falk-Pedersen and Dannström, 1997). B) Gas turbine CC with a close to stoichiometric combustion with oxygen (97%+ purity) from an air separation unit as oxidising agent, producing CO2 and water vapour as the combustion products. In order to keep combustion products temperature to a permissible level for the turbine, most of the combustion products are cooled and recycled, making the gas turbine a semi-closed cycle with mainly CO2 as working fluid (Hendriks and Blok, 1992; Bolland and Sæther, 1992; Bolland and Mathieu, 1998; Kimura et al., 1995; Okawa et al., 1997; Mathieu, 1999). C) “Decarbonisation”, in which the carbon of the fuel is removed prior to combustion, and the fuel heating value is transferred to hydrogen. This concept can be applied both for natural gas by combining reforming, a water gas shift reaction and CO2 removal process (Moru, 1992; Anon, 1992; Steinberg, 1995; Gaudernack and Lynum, 1997; IEA, 1998; Audus et al., 1999), and in a similar manner also for coal where gasification replaces the reforming process (Pruschek et al., 1995; Meratla, 1997; Chiesa, 1999).

NOMENCLATURE

ABS ATR CC COND FC HC HRSG LTS/HTS NG

Pre-reformer Steam Turbine Water Removal

Absorber Auto-thermal reformer Combined Cycle Condenser Fuel compressor Hydrocarbon Heat Recovery Steam Generator Low/High Temperature Shift reactor Natural Gas

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Copyright © 2000 by ASME

reforming (tubular fired reforming), 2) Partial oxidation of natural gas (NG) with oxygen or air, 3) Auto-thermal reforming (ATR) and 4) Variations of gas heated reforming. The main reactions taking place in a steam reformer are the following endothermic reactions (de Groote and Froment, 1995):

Also several variations of the main three concepts have been proposed. E.g. chemical looping or cycling (Anheden and Svedberg, 1998; Ishida and Jin, 1999), which might be regarded as a hybrid version of concept B as the chemically bound oxygen reacts stoichiometrically with natural gas in the gas turbine combustor. These concepts have been compared in (Bolland and Sæther, 1992; Bolland and Mathieu, 1998; Bolland and Undrum, 1999; Bolland and Sæther, 1993; Riemer and Ormerod, 1995; Audus and Saroff, 1995; Akai et al., 1995; Göttlicher and Pruschek, 1999). Concept A is regarded as the most mature of the three, though there seems to be some remaining development work with respect to the chemical absorption process. The technology of removing CO2 from combustion products is applied in a number of smaller plants where CO2 is the main product, but there is little or no experience from large-scale power generation. Concept B has been described through numerous studies in the last decade and opposed to concept A and C about all the CO2 gas produced by the combustion can be captured. However, it has been regarded as the least attractive of the three concepts from a commercial point of view (Bolland and Undrum, 1999). The reason is mainly that the combustion process, compressor and turbine are much different from the existing air-based equipment. This means that a completely new gas turbine technology needs to be developed. The concept C has been known for years mainly related to studies for CO2 removal in conjunction with coal gasification integrated with CC. However, the production of electricity from decarbonised hydrogen is unlikely to be competitive with concept A unless some synergy effect can be achieved by integration between the different process steps (IEA, 1998). In the present work, focus is put on concept C; decarbonisation prior to combustion.

Cn H 2n + 2 + nH 2O ⇔ nCO + ( 2n + 1) H 2

(1)

C n H 2n + 2 + 2nH 2 O ⇔ nCO2 + ( 2n + 2) H 2

(2)

combined with the slightly exothermic water gas shift reaction:

CO + H 2 O ⇔ CO2 + H 2

(3)

Partial oxidation of NG with oxygen or air:

C n H 2n + 2 +

n O2 ⇔ nCO + (n + 1) H 2 2

(4)

Feeding only O2 (or air) and NG (partial oxidation) leads to a synthesis gas with a low H2/CO product ratio and according to De Groote and Froment (1995), this method is not economically attractive compared to steam reforming. However, at high conversion of CH4 in conventional steam reformers, the net reaction is endothermic meaning that external heat supply is required. In combination with a NG fired CC plant the auto-thermal reforming (ATR) method might be even more attractive for three main reasons. Firstly as this method actually is a hybrid combination of method 1 and 2, the heat generated from the exothermic oxidation reaction (Eq. 4) is directly exploited in the endothermic steam reforming reactions (Eqs. 1 and 2). Secondly, preheated air is supplied from the air compressor of the gas turbine and steam is supplied correspondingly from the steam turbine or boiler in the CC plant. Another important aspect here is the fact that an airblown ATR, together with water gas shift reactors and CO2 removal process, produce a fuel with no more than about 50% hydrogen. Modern gas turbines with low-NOX combustors are restricted regarding the hydrogen concentration of the fuel. Traditional steam reforming processes would, in this application, produce a fuel to the gas turbine with significantly higher hydrogen content. Therefore, the ATR method was chosen as a case in the present work. There exists a number of gas turbine power plants where fuel containing a significant fraction of hydrogen is used (refinery gas, coal gas, coke oven gas and firedamp). In almost all of these cases, diffusion combustor burners are used. Low-NOX burners (lean premix) for large and modern gas turbines are until recently not applied for hydrogen-rich fuels. Such lowNOX burners in gas turbines are typically designed for a narrow range of fuel properties. With hydrogen in the fuel, the flame speed and flame temperature increase. Problems that can arise

REFORMING OF NATURAL GAS

Reforming in the gas industry means the changing by heat treatment of a hydrocarbon with high volumetric heating value into a gaseous mixture of lower heating value. The main reforming reactions involve the decomposition of the hydrocarbon by means of steam, oxygen/air or by a mixture of both. The product mixture, commonly known as synthesis gas, contains mainly H2, CO, CO2, H2O, N2 (if air is used) and nonreacted HC. The reactor operating conditions and thereby the product composition differs depending on downstream processing as the synthesis gas might be used for production of ammonia, methanol, phosgene, polycarbonates, formic acid, acetic acid and oxo-alcohols (de Groote and Froment, 1995). With increased focus on “zero-emission” power plants, the use of H2 from synthesis gas as fuel in these plants has emerged. However, this means that CO2 (and shifted CO) has to be removed upstream the combustion in the power plant (Bolland and Undrum, 1999). The technologies that are most relevant for the production of synthesis gas are: 1) Conventional steam

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NG (1) mixed with the medium pressure steam (31) is preheated to 500 °C in the HRSG unit prior to the pre-reformer (PRE). The steam to carbon ratio is set to 2 at the pre-reformer inlet. The air extracted from the gas turbine compressor (3) and the pre-reformer products (7) are preheated to 600 °C upstream the ATR unit. Both the pre-reformer (PRE) and the main reformer (ATR) are assumed equilibrium reactors. In the prereformer (PRE) most of the heavier hydrocarbon components (mainly C2H6) are converted to H2 and CO while methane is converted according to Eqs. 1, 2 and 4 in the ATR unit. The ATR outlet temperature was set to 900 °C. The steam cycle takes advantage of the reforming process by utilising the cooling process of the reformer products downstream the ATR to generate additional saturated high-pressure steam (25, 26). The saturated steam (27) is further superheated in the HRSG unit, and fed into the High Pressure (HP) steam turbine (28). The produced CO is converted to CO2 in the high and low temperature shift reactors (HTS, LTS), according to Eq. 3. Most of the water is removed in the water removal unit (WR) by condensation at 25 °C. It is assumed that 90% of the CO2 content is removed (38) in the absorber unit (ABS). The removed CO2 is assumed compressed to 100 bar for storage (not shown in Figure 1). A fraction (7.6-10.3%, see Table 2) of the resulting fuel is used for supplementary firing (20) of the gas turbine exhaust at the hot end of the HRSG. The rest is compressed (FC) to about 20 bar (18), heated by the feed stream (12) to the low-temperature shift converter, and then fed to the gas turbine combustor (19). By extracting air (3) from the gas turbine, there will be a significant reduction in the gas volume going into the gas turbine expander, and thus a reduction in the gas turbine pressure ratio. However, the fuel volumetric flow is such that it more or less replaces the lost volume caused by the air extraction. It is therefore possible to maintain the gas turbine pressure ratio at the same level as for a natural gas fired gas turbine without any air extraction. It was assumed a pressure drop of 3% in the pre-reformer, heat exchangers and shift-reactors, while 6% was assumed for the ATR.

are increased NOX formation, increased combustor wall temperatures, reduced flame stability and combustion induced pulsations. Large modern gas turbines cannot without testing, and perhaps also some modifications, be used with this type of fuel, with approximately 50% hydrogen. However, there is no fundamental obstruction for using this type of fuel in modern gas turbines with lean premix combustion. PROCESS DESCRIPTION

Figure 1 shows the process configuration of case 2 described in the next section. Selected stream data is presented in Table 1. The hydrogen-rich reformed gas is combusted in a gas turbine (GT), which is integrated with the decarbonisation process (Moru, 1992; Anon, 1992; Steinberg, 1995; Gaudernack and Lynum, 1997; IEA, 1998; Audus et al., 1999). A model of the gas turbine type GE9351FA from General Electric was used in the simulations. This gas turbine represents modern technology of today, and it is used in a number of plants built in the last few years. The considered steam cycle; Heat Recovery Steam Generator (HRSG), steam turbine (ST) and sea-water cooled condenser (COND) is an advanced process with three pressure levels and steam reheat. The reforming process is supplied with high-pressure air (3) and medium pressure steam (31) from the gas turbine compressor and the HRSG, respectively. There is also integration between the power plant and the reforming process with respect to preheating of feed streams in the reformer. This requires supplementary firing of the gas turbine exhaust approximately 600 °C to 750 °C. The steam production based on exhaust gas heat, below 600 °C, is very much the same as without any supplementary firing of the exhaust gas. This means that the supplementary firing does not increase steam production, as all the heat from the supplementary firing is used for preheating of the reformer feed streams. The high-pressure air extracted from the gas turbine compressor exit is typically 25% lower than the required gas turbine fuel nozzle pressure. Thus an extra pressurisation either of the air to the ATR or the fuel back to the gas turbine is needed.

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Figure 1: Process flow diagram, case 2

Table 1 Stream data for the flowsheet in Figure 1 (Case 2) STREAM 1 2 3 7 Natural Air Air Pre.ref. gas outlet 8.2 H2 (vol%) CO (vol%) 0.6 0.3 0.3 2.7 CO2 (vol%) 1.6 77.1 77.1 0.5 N2 (vol%) 20.7 20.7 O2 (vol%) 93.2 29.5 CH4 (vol%) 3.7 C2H6 (vol%) 0.4 C3H8 (vol%) 1 1 59.0 H2O (vol%) 0.9 0.9 Ar (vol%) 0.5 Other (vol%) 4 15 382 423.8 Temp (°C) 15 1.013 14 14 Pressure (bar) 18.1 629.6 82.8 57.4 Flow (kg/s) 17.3 28.9 28.9 16.9 MW (kg/kmol)

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9 ATR outlet 31.3 8.9 5.5 29.0

19 Fuel to GT 56.0 0.4 2.0 40.8

27 Sat. steam

28 Superh. steam

31 Reheat steam

38 CO2

0.1

0.2

24.9 0.3

0.2 0.5

100

100

100

3.2

900 12.8 140.3 18.3

250 20.8 68.2 13.8

324 119 96.3 18.0

560 115 119.4 18.0

382 15 39.3 18.0

25 1.013 42.7 44.0

96.8


CONCEPTUAL VARIATIONS

conventional modern combined cycle power plant is presented (Base).

In addition to a natural gas fired combined cycle used as a base case, three cases including fuel decarbonisation are investigated in the present work. The main difference between the case 1 and cases 2&3, is the location of the required pressurisation in the loop going from the gas turbine compressor extraction (3) to the fuel feed of the gas turbine (19). In case 1, the air stream (3) is cooled and compressed before the preheating in the HRSG. Around this compressor the streams are heat integrated, though the temperature upstream the HRSG preheating section is reduced compared to the temperature of the gas turbine compressor exit. The compression of the air is increasing the heat demand in the HRSG preheater. In cases 2&3 the fuel gas (17) is compressed (FC) downstream the absorber unit (ABS), giving a lower pressure through the reforming process. Steam is continuously supplied to the reforming process and used both in the reformers and the shift-reactors. In the first cases 1&2 all the steam flows through the entire reforming process. Since a large portion of this steam is used in the shiftreactors (LTS and HTS), a large flow of steam is flowing through the reformers as “inert” material, in excess of what is required to avoid coking of the ATR catalyst. The steam that does not take part in the reforming reactions is heated up to the ATR operating temperature and then cooled before the shiftreactors. This heating and cooling of the “inert” steam represents a thermodynamical loss. The influence of splitting the steam supplied to the process, so that 50% of the steam is fed upstream the pre-reformer and the rest is fed upstream the shift-reactors, is investigated, as case 3. The pressure level in the reforming process of case 3 is the same as in case 2.

Table 2 Computational results for the different cases. Stream numbers (#) refer to Figure 1 Base 1 2 3 Natural gas LHV Input [MW] (1) [A] 684 874 864 843 Total air flow rate GT [kg/s] (2) 630 630 630 630 Air extraction to ATR [kg/s] (3) 83.1 82.5 78.1 ATR inlet pressure [bar] (4) 23.8 13.8 13.8 900 900 900 ATR outlet temperature [°C] (9) Flow rate PRE inlet [kg/s] (6) 55.0 57.4 36.9 Flow rate ATR inlet [kg/s] (4)+(8) 137 140 115 Fuel composition % H2 0 55.6 56.0 56.3 % N2 1.6 40.9 40.8 40.2 % CO 0 0.3 0.35 0.4 % CO2 0.6 2.0 2.0 2.0 % CH4 93.2 0.5 0.15 0.4 % C2H6 3.7 0 0 0 % H2O 0 0.2 0.2 0.2 % Ar 0 0.5 0.5 0.5 % other 0.9 0 0 0 Fuel flow GT [kg/s] (17) 14.3 67.8 68.2 66.3 Fuel flow duct firing [kg/s] (20) 0 7.6 7.0 5.5 Power output GT [MW] 257 255 256 257 Power output ST [MW] 148 179 190 180 Gross power output [MW] [B] 391 421 432 424 Air & fuel compression [MW] [C] 5.5 10.9 10.7 CO2-compression [MW] [D] 14.2 14.2 13.7 Net power output [MW] [B-C-D] 391 401 407 400 Net efficiency [%] [(B-C-D)/A] 57.2 45.9 47.1 47.4 CO2 emissions [g/kWh el.] 355 64.0 57.0 60.4 CO2 reduction [%] 0 82.0 83.9 83.0 Base case: Natural gas fired CC, ISO conditions, 15 °C cooling water. Case 1: Compressor on the air (3) supplied to the ATR. Case 2: No extra pressurisation of the air to ATR, but a compressor on the fuel stream (17) to the gas turbine. Case 3: As case 2, but the MP-steam (31) is split, and partly supplied both upstream the pre-reformer (31) and downstream the ATR (mixed with 10), giving a steam to carbon ratio in the ATR of 1 (compared to 2 otherwise).

RESULTS

Simulations are made with state-of-the-art computational tools (GTPRO and PRO/II). Table 2 presents a comparison of the three different concepts for the integration of the natural gas reforming and the power cycle. In addition, data from a

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Case 2

Corrected efficiency

Case 3

11

58

10 9

57

8 7

55

6

54

5 4

53

3 2 1 0 -1

(6)

52 51 50 49

47

-4 -5

46 45 Extraction of MPsteam (2)

HP-steam production (3)

Air/fuel compr. (4)

CO2 compr.

-5.1

9.6

-0.6

-1.6

Case 2

-4.5

10.2

-1.3

-1.6

-4.5

9.2

(5)

44 43

Case 1

Case 3

Net efficiency

48

-2 -3

-6

(1)

56

Efficiency [%]

Influence [%-points]

Case 1

-1.3

-1.6

42 Base

1

2

3

Case

Figure 2 Graphical presentation of computational results. The left figure shows the most important factors influencing the plant efficiency. The right figure shows a corrected efficiency (see text) and the resulting net system efficiency for the different cases. 6 = Net efficiency (%). This is the total system efficiency, calculated as: 6 = 1+2+3+4+5.

Explanation of the different columns in Figure 2: 1 = Corrected efficiency (%). This is the efficiency of a standard CC fired with decarbonised fuel supplied at 250°C and including the air extraction necessary for the reforming process (12-13% of the compressor inlet flow). A standard CC operated this way, gives a net efficiency very close to that of a natural gas fired CC (57.2% in this work). The corrected efficiency is, however, related to the flow of natural gas necessary for producing this hydrogen-rich fuel (1). Thus the gap between 57.2% and the corrected efficiency represents mainly the loss of heating value in the reforming process. This loss includes use of fuel for additional firing of the HRSG unit for the purpose of preheating the reforming feed streams. 2 = Efficiency change (%-points) due to extraction of MPsteam from the steam turbine. 3 = Efficiency change (%-points) due to HP-steam generation within the fuel reforming process. 4 = Efficiency change (%-points) due to the work required to compress either air or fuel in the reforming process. 5 = Efficiency change (%-points) due to the work required to compress CO2 from atmospheric pressure (it is assumed that the pressure out of the CO2-absorber is atmospheric) to the pressure required for storage (100 bar).

A comparison of the different cases shows that all the three cases with fuel decarbonisation, as expected, results in efficiencies well below that of a conventional combined cycle (Base case). The cases with removal of CO2 give efficiencies in the range 46-47%, compared to about 57% for the natural gas fired base case combined cycle. This is a reduction of 10-11%points (compression of CO2 is included). As seen from Figure 2, the “corrected efficiencies” for cases 2 and 3 are higher than for case 1. This indicates that it is more favourable with respect to efficiency to maintain the lowest pressure (approx. 14 bar) through the reforming process, and instead pressurise the reformed fuel before it enters the gas turbine. It is more efficient to operate the reforming process at 14 bar than at 24 bar. The reason for this is the following: In order to minimise the compressor work, the air stream (3) in case 1 is cooled before it is compressed to 24 bar. The consequence of this is a lower HRSG preheating inlet temperature and thus more supplementary firing is required. This leads to a lower ratio between the flow of fuel supplied to the gas turbine and

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Both these two technologies are mature, and one cannot expect significant changes in the future to the design principles or costs. It was found that these two technologies should be tightly integrated (air, steam) in order to achieve an acceptable fuel-toelectricity conversion efficiency. However, compared to a natural gas fired combined cycle power plant, the removal of CO2 implies a reduction of efficiency of about 10-11%-points, or increased natural gas consumption of about 21-25%. The fuel property is characterised by a hydrogen volumetric fraction of about 55% and nitrogen content of about 40%. For lean premixed low-NOX gas turbine combustors, this may be an obstacle. Burner modifications may be necessary. Otherwise, there is no need for technology development or design of new components compared to what is found in existing reforming plants or in combined cycle power plants. The technology is feasible today. The supplementary firing in the HRSG may produce NOX at a non-acceptable level compared to that of a low-NOX gas turbine. It was found advantageous, from a thermodynamic point of view, to keep the pressure low in the reforming process (below that of the gas turbine), and to use a compressor to increase the fuel pressure prior to the gas turbine. This conclusion may not be the same with respect to the economy as lower pressure indicates larger equipment costs. Compared to a standard combined cycle, this technology of removing CO2 from a power plant implies a rather complex plant. It would be possible to build such a plant with a dual fuel firing. The gas turbine can operate either on reformed fuel or natural gas.

the flow of natural gas required as input to the process, resulting in a lower corrected efficiency. Another reason for the better net efficiency of the cases 2 and 3 compared to case 1, is related to the pressure of the MP steam extracted from the steam turbine (leftmost column group in Figure 2). In cases 2 and 3, the pressure of the MP steam is 15 bar compared to 25 bar for case 1, resulting in better steam turbine performance and a lower efficiency penalty for this extraction. An apparent benefit of case 1 is that the compression of the air upstream the reforming process leads to a lower efficiency penalty than the fuel compression of the other two cases does, due to a lower mass flow. The difference is, however, not large enough to compensate for the drawbacks of case 1, mentioned above. The results for the cases 2 and 3 are not very different, though a slightly better efficiency for case 3 (0.3%-points difference). This indicates that the splitting of the steam supplied to the reforming process more or less is insignificant by means of energy efficiency. There are, however, other beneficial aspects as the volumetric flow through the pre-reformer and the ATR is considerably lower than in case 2. This implies both lower investment and operating costs for this section. The steam to carbon ratio in the ATR reformer feed is well below the recommended value (1.5-2) which means coking might be a consequence. However, this conceptual change was examined in order to check the potential of energy efficiency improvement. The reduced flow of inert steam through these reactors also reduces the duty required to heat inert components, and the effect of this can be seen from the slightly higher efficiency number of case 3. The degree of CO2-reduction for the three cases are very much dependent on the assumption of a 90% removal of CO2 in the absorber unit, and thus not much focused here. However, the numbers calculated in Table 2 gives an indication on what degree of total CO2 emissions that can be expected from such a plant compared to a conventional combined cycle plant, when the difference in net efficiency is compensated for. It is known, however, that it might be possible to remove up to 99% of the CO2 fed to an absorber unit, which for the present cases would mean a 90% reduction of CO2-emissions compared to a standard combined cycle power plant.

REFERENCES

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CONCLUSIONS

A concept for removing CO2 from a natural gas fired combined cycle power plant is presented. The removal of CO2 is achieved using natural gas reforming combined with a water gas shift reaction of the synthesis gas and a high-pressure absorption of CO2. This concept implies removal of the carbon from the fuel prior to combustion in the gas turbine. This removal technology for CO2 is a combination of the well-known auto-thermal reforming process (for example used in ammonia production) and the combined cycle technology.

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