coal fired unit versus natural gas combined - ipgsrl.com fired unit versus natural gas...

The economic development of one coun-try is dependent upon the ability of theauthorities to set up a highly suitable,

competitive and reliable electricity sector.It is well known that Italy,where in 2010 morethan 56% of electricity will be produced bynatural gas, is the European country havingthe most expensive and unbalanced fuel mixin the electricity production sector.The main disadvantages for Italy from thisunbalanced fuel mix are:• higher electricity cost in respect to other

western countries; this high Italian kWhcost reduces the competitiveness of manyenergy intensive industry productions;

• potential risk of electricity shortage in caseof interruptions of natural gas supply fromone of the three main Italians suppliers(Algeria, Libya and Russia).

The main reasons of this fuel natural gasoriented policy in Italy have been:• strong opposition to the conventional coalfired units from the green associations andfrom the local authorities, asserting that coalis more polluting in respect to natural gas;

• higher capital cost required for the con-struction of coal fired units;

• halt in 1988, after a referendum, of all nucle-ar construction, shut of the existing reac-tors and their decommission from 1990(the only country in the world).

Recent reduction of natural gas supply withinthe 2005 and 2006 winters and political crisisamong Russia and its nearby countries con-cerning the gas prices, pushed Enel to increa-se its investments in new or retrofitted coalfired units, but also Italian IPPs started to takein due consideration the coal alternative.Within this framework IPG finalized a feasibi-lity study on behalf of a new Italian IPP intere-sted to compare for its brown field site anatural gas combined cycle plant with a coalfired unit preparing also technical documentsfor the debate with local and governmentauthorities and with green associations so toobtain the permits required by the Italianlaws.The main addressed objectives of this paper are:• underline advantages and disadvantages of

the above mentioned alternatives that is

Impiantistica Italiana • Anno XX N. 6 novembre-dicembre 2007 1

Giorgio Dodero

IPG Industrial Project Group Srl

Coal Fired Unit versusNatural Gas CombinedCycle

Coal Fired Units Emissions are today approaching in Europethe Emissions of Natural Gas Fired Combined Cycles.

The main addressed objectives of this paper are: underline advantages and disadvantages of the techincal

alternatives of coal and natural gas plant; evaluate the capital costs and revenues of these two alternatives;

emphasize that by now coal fired units emissions are approaching the emissions of the combined cycle, but

in the near future with the coming of the zero emission technology any difference could be removed.

Finally, this paper will discuss what could be the position of an investor today in respect to the development

and opportunities of the CCS (Carbon Capture Sequestration) technologies.

Confronto tra impianti alimentati a carbone e a gas naturale in ciclo combinato

I principali scopi di questo articolo sono: illustrare i vantaggi e gli svantaggi di due tipologie di impianti alimenta-

ti con carbone e con gas naturale; valutare i costi di investimento delle due alternative; mettere in rilevo il fatto

che le emissioni delle nuove unità alimentate a carbone sono molto simili alle emissioni delle unità a gas a ciclo

combinato e che in un prossimo futuro, con l’entrata in servizio delle unità a carbone“zero emission”, non vi saran-

no differenze.

Infine, questo articolo illustra quale potrebbe essere la posizione di un investitore di oggi di fronte agli sviluppi e

alle opportunità offerte dalle tecnologie CCS (Carbon Capture Sequestration).

“

”

coal and natural gas;• evaluate the capital costs and revenues of

these two alternatives;• emphasize that by now coal fired units emis-

sions are approaching the emissions of thecombined cycle, but in the near future withthe coming of the zero emission technologyany difference could be removed.

Finally this paper will discuss what could bethe position of an investor today in respect tothe development and opportunities of theCCS (Carbon Capture Sequestration)technologies.

1. Comparing Coal and Natural GasTechnology AlternativesElectricity is generated, in accordance withdemand, in peaking or base-load plants andtransported over long distances to reach theconsumer at the required voltages.Today the fossil fuel options are natural gas andcoal and the technology options are coal firedconventional plants, coal fired IGCC and natu-ral gas fired combined cycles.Heavy fuel oils areless used in the conventional plants, due to thehigh purification cost of their exhaust gas anddue also to their higher cost in respect to coal.Distillate oil is used in the combined cyclesusually only during start up or as secondaryfuel, due to its higher cost in respect to naturalgas and due to the consequent increase of gasturbines maintenance costs.

1.1 Coal versus Natural GasCoal-based technologies offer a significantfuel price advantage over its natural gas basedcompetitors to virtually any power plant loca-tion. On the other hand, natural gas basedtechnologies have a capital cost advantageover coal technologies.Given these differences, the market areas forthe generating technology and fuel choicedecisions become quite clear. One simple wayfor defining these market areas is defining howlarge must be the coal fuel price advantageover gas to justify coal’s plant higher capitalcost. Looking in details, the market choice bet-ween coal and gas is sensitive to the type ofpower that is required.“Peaking” power capa-city is required to meet high air conditioningloads in the summer and high heating loads inthe winter, but this not in Italy where usuallyheating is made using natural gas.This peakingcapacity is usually used only a limited portionof time and its choice is dominated by capitalcost considerations. So, natural gas turbine’slarge capital cost advantage will continue tomake it the dominant choice for utilities tomeet expanding peaking load requirements.On the other hand,“base load” power capaci-ty is required on-line for long time to meetthe bulk of the electrical system demands.Fuel cost dominates the selection of the baseload technology, because fixed capital costsbecome less significant when spread over alarger generation baseline.Price differentials between coal and naturalgas are projected to grow larger in the nextfuture.While coal prices are expected to remain sta-ble (depending also upon region and coal qua-lity) natural gas prices are expected to increa-se as higher cost natural gas reserves need tobe developed to meet growing demand andoffset losses from depleting gas wells. Highernatural gas prices will be needed to supportdevelopment of new gas reserves.Another fac-tor increasing the cost of the natural gas is itshigh transportation cost both through pipelineline or through the liquefied natural gas chain.

Coal Fired Unit versus Natural Gas Combined Cycle

Impiantistica Italiana • Anno XX N. 6 novembre-dicembre 20072

Note: this value could be reduced in case of atoo quick increase of natural gas consumption

Note: US gas turbines have DLN systems capable of operating at less than 5 to 8 ppm NOx and catalyst must be used in addition to attain limits.All triple-pressure US HRSGs are equipped with SCR and CO catalyst beds.

Fuel

Investment

Emissions control

Emissions level

ZEP (ZeroEmission Projects):the new frontier

Coal-Fired Plant

Low cost fuel

More costly initialplant

More investment

Emissions of coal fireunits are becoming dayby day near to theemissions ofGas-Fired Plants

Emissions will becomeequivalent to the GasFired plants emissionsand new technologiesare expected

Gas-Fired Plant

More expensive fuel

Less costly initial plant

Lower investment andemits very low SO2

Permits for new US gasfired plants typicallyrequire lower emissionsin respect to similarplants in Europe (3 ppmNOx and single-digit CO) (note)

Gas Fired Plants couldremain competitive inrespect to Coal FiredPlants, if their efficiencywill increase

Fuel Type

Oil

Natural Gas

Coal

Estimated ConventionalGuaranteed supply (years)

41

64 (note)

234

Table 1 - Differences between coal and natural gas alternatives for new electricgeneration capacity decisions

Table 2 - Overview of the coal market in Italy


In Italy green associations and local authori-ties are opposing the coal choice, basing onthe fact that coal is dirty and its environmen-tal impact is more dangerous in respect tonatural gas. For this reason in Italy combinedcycles provide also base load power and in2010 more than 56% of electricity will be pro-duced by natural gas.A chapter of this paper will be dedicated tocompare the emissions of the natural gascombined cycle with the emissions of the coalfired conventional units and IGCC plants.Due to the improvements of the exhaust gaspurification technologies coal fired conventio-nal plants emissions start today to approach inEurope the combined cycle emissions, on thecontrary the emissions of the coal fired IGCCcan be today also lower of the cc emissions.Unlike natural gas, coal is not suitable fordispersed on-site use. Coal can be used mosteffectively where it permits the user to enjoythe economics of scale of large units and coaldelivery by ship, barge, unit train or conveyor(for a mine mouth plant).The differences between coal and natural gasalternatives for new electric generation capa-city decisions are reported in table 1.An overview of the coal market in Italy indi-cates that coal supply is safer in respect to theother fuels for the following reasons (table 2):• coal reserves are abundant and distributedin more than 100 countries, while oil and gasreserves are concentrated within few coun-tries and many of these countries are politi-cally instable;• high availability of coal extraction, transpor-tation, storage and handling systems on wor-ldwide basis.Abundant coal reserves in many countries canbe mined well into the next century at costs(in constant $’s) very close to today’s produc-tion costs. The best evidence for this is thatnew coal mines are and will continue to beadded at a very full production cost veryclose to the production costs of the existing

mines they are replacing.Figures 1 and 2 indicate, rispectevely, the natu-ral gas and coal price trends from 1995 to2005 (Cif = cost + insurance + freight).Thesefigures show that the gas prices rise morequickly in respect to coal prices.

1.2 Fuel TransportationFuel transportation costs are also an impor-tant factor in the utility fuel selection. Thesecosts can vary significantly by plant location,utility ability to promote inter-carrier compe-tition and distance between fuel source andplant. The cost to transport coal is rangingfrom $ 0.60 to 0.85/million BTU for longdistances. But due to the dispersion of coalreserves, coal transport costs are usually lessthan these amounts and are ranging between$ 0.10 to 0.30/million BTU. Gas pipeline tran-sport costs also vary widely depending upondistance and location.They can range from $1.50/million BTU to $ 2,5/million BTU orhigher and have an impact ranging from 30%up to 50% on the total gas price.

1.3 The Technology Choices and Their Costs (excluding CCS)Plant capital costs are significantly differentbetween the coal and the natural gas firedpower generation options.Natural gas based technologies have lowercapital costs than coal based technologies andthis difference is also depending from thetechnology selected for coal generation option.This capital cost advantage of the NG plants isranging between $ 500 to $ 1000/kW depen-ding upon the assumptions used that is fuelsource, required by authorities environmentallimitations, selected technology for the coalfired plant, major equipment redundancy, plantsite location and labor cost on the plant site.The main technologies that are competingtoday on the market are the following.


Fig. 1 – Cost trends of natural gas from 1995 to 2005 Fig. 2 – Costtrends of coal from 1995 to 2005

US

Do

llars

per

mill

ion

US

Do

llars

per

to

nne



1.3.1 Natural Gas Combined CycleThe combined cycle is the basic gas-firedtechnology that consists of gas turbinesdischarging hot exhaust gases into recoveryboilers producing high pressure steam whichoperates a steam turbine. Both the gas turbi-ne and the steam turbine move one or twoelectrical generators which generate electricity.For example a large 800 MWe plant of thistechnology costs around 600 $/kW.The gas fired combined cycle is the most effi-cient commercial technology with heat rates(LHV) of only 5880 BTU/kWh (58% efficien-cy), but further improvements are expectedin the near future. However, the natural gasheat rate is sensitive to unit operations andcan decline to a lower energy efficiency ifoperated at loads of 50% of the rated capaci-ty.At low loads emissions also increase, becau-se the dry low NOx combustion systems is notin operation.

1.3.2 Conventional Pulverized CoalFired PlantThe key components of a conventional coalfired plant are the steam generator and thesteam turbine that are interconnected by thethermal cycle, where the water coming fromthe condenser is heated in dedicated feedwa-ter heaters supplied by steam extracted fromthe steam turbine.The two main options arethe subcritical and the supercritical cycles.Today supercritical components reached verygood availability so these cycles are the mostadopted by the utilities also due to their higherefficiency in respect to subcritical cycles.These new conventional coal-fired steamelectric generating plants employ advancedpollution controls to meet very strict envi-ronmental requirements for particulates, sul-fur dioxide, mercury and NOx. The capitalcost of new conventional coal-based techno-logy was in 2003 approximately $1200/kW.Aswell known the boiler market situation resul-ted mainly in Europe in the nineties in thebankruptcy of important manufacturers. Thisbig crisis loomed over this sector up 2004,forcing the surviving boiler makers to reducetheir manpower and costs in order to get outfrom this downturn. Due to the very highdemand in 2006 coal fired boiler pricesmoved up and a shortage of critical materialscontributed also to this increase of boiler pri-ces and to the extension of their deliverytimes. For example prefabricated P92 pipesdelivery moved during 2006 from 12 to 22months.Today the capital cost of a new conven-tional is in Europe around $1400 - 1600/kW.Compared to the conventional subcritical

plant’s 36-38% efficiency, a sea water cooledsupercritical plant can readily achieve 45% onan LHV basis.Recently EON announced they will build theworld’s most innovative coal-fired powerplant by 2014 with an efficiency of more than50% and with superheater temperatures upto 700 °C, using nickel-based alloys, instead ofconventional steel for the key components ofboiler and steam turbine. Increasing efficiencyis one of the best strategies to reduce coalconsumption, but it is also the way for zeroemission plants.

1.3.3 Integrated Gasification CombinedCycle Plants (IGCC)Coal gasification is a process that convertssolid coal into a synthetic gas composed main-ly of carbon monoxide and hydrogen.Coal canbe gasified in various ways by properly con-trolling the mix of coal, oxygen or air, andsteam within the gasifier. Manufacturers offerseveral technology options for controlling theflow of coal in the gasification section (e.g.fixed bed, fluidized bed, and entrained-flowsystems). Most gasification processes being incommercial operation use oxygen as the oxi-dizing medium.IGCC combines a fossil fuel gasification systemwith a combined cycle. Depending on the levelof integration of the various processes, IGCCwas achieving 40 to 42% efficiency.Most of the IGCC plants use entrained gasi-fiers (e.g. Texaco-GE, Krupp Uhde and Shelltechnologies).Many companies including IPG [1, 2] presen-ted interesting improvements of the existingIGCC processes, but these improvements hadnot success up to now, because the efficiencyincrease to around 46%-47% do not justifythe higher cost of this technology.IGCC cost projections range from US$1800to $2100/kW; 20 to 30% higher than for thepulverized coal plants equipped with wetscrubbers and DeNOx. It is also important tonote that about 50% of IGCC is chemicalplant, on which the electric utilities operationstaff do not have experience and that finallyIGCC has higher O & M costs in respect tothe pulverized coal plants.IGCC was indicated within the nineties thetechnology of choice due to the opportunityof high removal of SO2 (e.g. 99% or higher)and of all other coal pollutants.Today the removal efficiency of the De-SOxand De-NOx systems improved and the emis-sions of new pulverized coal plants are lowe-ring day by day.An interesting opportunity could be offered



by the Integrated Gasification SOFC (SolidOxide Fuel Cells) combined cycle that canoffer a net thermal efficiency of 54% HHV [3].On the contrary IGCC remains the most sui-table technology to produce clean fuels and/orelectricity from the refinery residues [4].The time for construction of IGCC is similarto PC plant including also DeSOx andDeNOx. However, phased construction (erec-tion of the gas turbine first, followed by thegasifier) can improve the economics of theIGCC plant by producing power as soon asthe gas turbine is constructed.

2. ZEP (Zero Emission Projects) andCCS (Carbon Capture Sequestration)Within energy sector the mankind musturgently trying to:• reduce the greenhouse gases emissions pro-

duced by the combustion of the fossil fuels;• increase the fossil fuel reserves, basing on

the fact that fossil fuels will be with us forlong time to come, probably for the next 50or 80 years at least.

The European Union sponsored ZEP (ZeroEmission Project) looks the right answer tosolve these problems. This ZEP is based onthe main idea to capture the CO2 producedby the fossil fuel combustion and subsequen-tly sequestrate this CO2 mainly within theexisting oil wells to enhance oil and gas pro-duction, but also within other undergroundstorage facilities as for example the aquifers.This is an ambitious goal, but an entirely feasi-ble one. After all, this CCS technology hasbeen practiced over decades – CO2 in fact hasbeen separated from gaseous streams forseveral years in many industries. It has alsobeen used and stored extensively in EnhancedOil Recovery (EOR).Obviously, substantial R&D is required, notonly to reduce the cost and increase the effi-ciency of CO2 capture technologies, but todemonstrate the safety and feasibility of large-scale CO2 geological storage.What are the competing carbon capturetechnologies? Here the list of the most pro-mising.

2.1 Oxy-fuel CombustionOne of the interesting economical solution tocapture CO2 is to switch to oxy-fuel combu-stion.The use of oxygen in place of air resultsin a much lower volume of flue gas, whichenhances thermal efficiency, lowering alsoCO2 emissions.Among the possible process opportunities wecan consider the following alternatives.

2.1.1 Use of Oxy-fuel in a ConventionalPower Plant Standard BoilerLiterature indicates that furnace absorptionincreases by some 10–12% due to an increa-se in radiating power of the hot flue gas andthat the furnace exit gas temperature also isreduced.Approximately one third of the boiler exitflue gas feeds the CO2 compression systemvia the gas cooler and the CO2 treatment.Theremaining two-thirds of this flue gas is retur-ned to the boiler unit by a Flue Gas Recycle(FGR) fan to moderate the combustion tem-peratures.

2.1.2 Integration of Oxygen TransportMembranes (OTM) into Oxy-firedBoilerThis project has been funded by US DOEcoupling the Praxair’s expertise in OTM deve-lopment and oxy-fuel combustion with theexperience of Alstom Power in boiler deve-lopment and manufacturing.Gasification plants which integrate this OTMtechnology will have higher efficiency, lowercost of electricity, and lower emissions of pol-lutants compared to using a conventionalcryogenic air separation system unit.

2.1.3 Gas Turbine Oxy-fuel CombustionThis process use pure oxygen as the oxidant.Burning natural gas the combustion productsconsist primarily of CO2 and H2O and also,with N2 removed from the cycle, there will beno generation of NOx.In this case it is important to note that re-cir-culated CO2 used as working fluid has a nega-tive impact on the performance of current gasturbines. In effect being the sound speed ofCO2 approximately 80% of air, choking is like-ly to be encountered for operation at currentsynchronous speeds (3000/600 rpm) usingcurrent GT compressors.

2.2 Post-combustion CapturePost-combustion capture is focusing on theamine scrubbing processes that are the mostinteresting technologies available to approachthe scale required for CO2 capture within fos-sil fired power generation plants.These alkanolamines are the most usualemployed as suitable solvents for H2S andCO2 removal. The amines can be divided asprimary, secondary and tertiary according tothe number of the hydroxil groups bound tothe amine nitrogen.The best known among the primary amines is



the monoethanolamine and among the tertia-ry the triethanolamine.The Fluor Econamine FGSM technology usesa monoethanolamine (MEA) formulation spe-cially designed to recover CO2, including aninhibitor which protects the equipmentagainst corrosion.This allows the use of carbon steel for thecomponent construction.Mitsubishi Heavy Industry proposes the KS1solvent having a sterically hindered amine for-mulation.This KS1 and the improved KS2 and3 looks having less problems with the degra-dation and corrosion issues and a much lowerspecific stripping heat requirement than MEA.

2.3 Pre-combustion CaptureIGCC was considered within eighties thetechnology of choice for the production ofelectricity from coal, but this expectation wasreversed mainly due to the increase of theperformances of the conventional plants (effi-ciency increase to 45%, expected efficiencyincrease to 50% by 2014 and continuousreduction of their environmental impact).IGCC efficiency increases are expected, but

not in a short term.The advantages of this pre-combustion de-carbonization technology in respect to thepost-combustion are • IGCC provides the best environmental per-

formances with respect to organic and inor-ganic pollutants. In effect, IGCC is the clea-nest fossil fuel technology in the market.IGCC could be a real zero emission plant,selecting suitable raw gas purificationtechnologies that are in use in chemicalindustry. But obviously plant cost willincrease;

• pre-combustion de-carbonization of syngasoffers intrinsic advantages in respect topost-combustion de-carbonization, becausethe gas volume is limited and the carboncapture is performed at high pressure andhigh concentration. Figure 3, which indicatesa comparison as provided by the US DOE in2000, shows that IGCC offers a net COE,including O&M and capital costs, approxima-tely 20% lower than that of a conventionalcombustion plant.

On other hand quite half of the IGCC is achemical plant, where usually electric utilitieshave limited experience.

Fig. 3 - Pre-versus-postcombustion decarbonization (cost of electricity) [7]



Items

Fuel : natural gas

Gross thermal power capacity

Gross electric power capacity

Net electric power capacity

Net efficiency (LHV)

Exhaust gas flow rate

SO2

NOx

CO

Solid particulate

Working hours/year

Electricity Production

Fuel Consumption

Net Heat Rate (LHV)

Condenser Pressure

Units of measurement

kcal/Scum

MWt

MWe

MWe

%

Scum/h

mg/Scum

mg/Scum

mg/Scum

mg/Scum

hours

MWh/year

Scum/year

kcal/kWh

bara

Operating Data2 GT in service

8600

1452

822

806

56.62

3,700,000

-

25

20

-

7000

5,642,000

142,000

1519

0.12

Operating Data1 GT in service

8600

722.5

406.8

400

56.3

1,825,850

----

25

20

-

-

-

70,073

1527.5

0.12

Table 3: Operating data of a combined cycle equipped with dry air cooled condenser

Items

Fuel : imported coal

Gross thermal power capacity

Boiler efficiency

Gross electric power capacity

Net electric power capacity

Net efficiency (LHV)

Exhaust gas flow rate at air

heaters outlet ( temp °C 121 )

Main steam flow

Main steam temperature

Main steam pressure

Reheat steam flow

Reheat steam temperature

Reheat steam pressure

Feedwater temperature at boiler inlet

SO2

NOx

Solid particulate

Working hours/year

Electricity Production

Fuel Consumption

Net Heat Rate (LHV)

Condenser

Units of measurement

kcal/kg

MWt

%

MWe

MWe

%

tons/h

tons/h

°C

bar

tons/h

°C

bar

°C

mg/Scum

mg/Scum

mg/Scum

hours

MWh/year

tons/day

kcal/kWh

bara

Operating Data

6400

1600

94.33

680

636

42.5

2360

1944

600

262

1635

610

54.5

310

100

100

20

7000

4,452,000

4850

2018

0,084

Notes

Flow rate corrected

for air leakage

@ 3.5% O2 v/v, dry

@ 3.5% O2 v/v, dry

@ 3.5% O2 v/v, dry

Table 4: Operating data of a Supercritical unit equipped with dry air cooled condenser



In addition the IGCC commissioning period isquite longer of that of the conventional plantsand the IGCC availability is lower mainlyduring the first years of life of these plants.IGCC availability is low also due to poor plantstandardization that could be improved stan-dardizing an IGCC plant on EU basis.

3.An Italian Case: the IPG FeasibilityStudyThe site of this plant is located in the Northof Italy at about 20 km from the sea side.Thissite has been selected due to its local facili-ties, including an existing transportationsystem of coal from a nearby harbour and alarge area suitable for this plant and not usualin this Italian mounting region.This study has been split into the followingphases:• preliminary design on this site of a 800 MWe

natural gas combined cycle and of a 660 MWe

coal fired conventional supercritical unit;• definition of the capital and operating cost

of the cc versus the conventional unit;• comparison of the emissions of the cc ver-

sus the coal fired conventional unit;• comparison of the COE of the cc versus the

conventional unit.

3.1 Preliminary Design on this Site of a800 MWe Natural Gas Combined CycleThe power island is equipped with two gasturbines, two heat recovery steam generatorsand one steam turbine.The operating performances of this plant areindicated in the table 3.This plant is rigged with a direct dry air coo-led condenser equipped with 20 modules.The maximum electrical power consumptionof this condenser is expected to range from2,5 to 3 MWe.The water consumption inclu-ding the auxiliary evaporation towers, the

Fig. 4 - Preliminary 660 MWe unit layout



thermal cycle makeup and minor additionalrequirements is ranging from 50 to 55 t/h.

3.2 Preliminary Design on this Site of a 660 MWe Coal Fired ConventionalSupercritical UnitThe unit rating and steam conditions have beenchosen according to Italian standardization.This unit will be equipped with:• two pass balanced boiler arranged for pulve-

rized coal firing;• advanced De NOx SCR systems with 85%

efficiency;• advanced fabric filters with a 99,9% efficiency;• advanced humid limestone/gypsum De SOx

with a 97% efficiency;• coal stock system equipped with two geo-

desic domes designed for a capacity ofabout 35,000 m3 each that means the ope-ration of this unit for about ten days. Thecoal shall be delivered to this dome througha fully closed belt conveyor system.

• direct dry air cooled condenser equippedwith 45 modules. The maximum electricalpower consumption of this condenser isexpected to range from 5 to 5,6 MWe.

The operating performances of this plant areindicated in the table 4.The water consumption including the auxilia-ry evaporation towers, the thermal cyclemakeup, gypsum washing, scrubber make upand minor additional requirements is rangingfrom 150 to 160 t/h.The preliminary layout of this supercriticalunit is indicated in figure 4. This layout hasbeen subsequently modified to obtain a bet-ter fitting with the site.

4. Combined Cycle Versus SupercriticalCoal Fired Unit Emissions: as TodayThe main pollutants of the electrical thermalpower plants are NOx, SO2, CO and particu-late.

4.1 Nitrogen Oxide EmissionsEuropean gas turbines manufacturers usuallyguarantee NOx emissions < 25 ppm using DLNcombustion systems in steady state conditionswith load ranging from 50% to 100%.It is interesting to note that US gas turbinesmanufacturers produce 9 ppm combustionsystems for the US market. But US Authoritiesimpose to reduce NOx emissions at 3 ppmusing SCR.The gas turbines NOx emissions are referred toa 15% O2 content in the flue gas on dry basis.With reference to coal fired power plants EU

standards request NOx emissions lower of200 mg/Nm3, but Enel agreed with Italian localauthorities to reduce NOx emissions under100 mg/Nm3. And the coal fired units emis-sions are referred to a 6% O2 content in theflue gas on dry basis.

4.2 Sulphur Dioxide EmissionsSO2 gas turbines emissions are not measuredin the gas turbine exhaust gas, but often natu-ral gas holds sulphur compounds.With reference to coal fired power plants EUstandards request SO2 emissions lower of 200mg/Nm3, but Enel agreed with Italian localauthorities to reduce SO2 emissions under100 mg/Nm3.

4.3 Carbon Monoxide and CarbonDioxide EmissionsCombined cycle CO emissions are rangingfrom 15 to 20 mg/Nm3, while the CO emis-sions of conventional units are negligible. ButUS Authorities impose to reduce CO emis-sions of large combined cycles at 1 ppm usingcatalyst.CO2 is not a pollutant, but has an impact onthe greenhouse gases.CO2 emissions are tied to the efficiency of thepower plant and are respectively about 0,38t/MWh for new combined cycles and about0,80 t/MWh for conventional advanced coalfired units.

4.4 Particulate EmissionsAlso particulate emissions are not usuallymeasured in gas turbine exhaust gases, butrecent investigations confirm that gas turbi-nes exhaust gases can hold PM10, PM5 andPM2,5 mainly during plant start up and lowload.When the gas turbine operates at high loadand in steady state conditions, the combu-stion process, specifically DLN, is highly effi-cient and therefore usually do not producePM emissions.In effect, gas turbines and combined cyclesexhaust gases may hold particulates comingfrom:• inert solids within fuel gas supply; usually, but

not always gas turbines manufacturersimpose to filter natural gas at plant batterylimits ;

• metallic rust and oxidation products (pre-sent also in the gas transportation piping, inthe cc inlet and exhaust equipment inclu-ding the heat recovery steam generator). Itis important to note that gas travel for



thousand kilo-meters inside not previouslycleaned steel piping ;

• formation of aromatic compounds or PM10,PM5 & PM2,5 during natural gas combustion,due to poor premixing during DLN combu-stion and/or oxygen scarcity at low loads insome combustor zone or due also to theheavier molecules existing in the gas [5].

4.5 ComparisonTable 5 is comparing the combined cycle emis-sions in respect to the coal fire unit emissions.Gas turbines manufacturers usually obtain theabove indicated guaranteed emissions at stea-dy state loads from 50% to 100% and if thecombustors are well adjusted.The reduction of NOx is obtained also to thedetriment of an increase of CO emissions.As indicated in this table 5 it is important tonote the NOx gas turbine emissions arereferred to a 15% O2 content, while the stan-dard emissions of a conventional power plantare referred to a 6% O2 content, but in effectthe O2 content is around 3.5%.In this table 5 both the cc and the conventio-nal units emissions are also referred at a 3.5%O2 content.In addition, basing on the fact that the flueexhaust gas temperatures at chimney outletare ranging from 95 °C to 100 °C for cc andfrom 120 °C to 125 °C for conventional units,the upward lift of the cc flue exhaust gas islower and so the pollutants emitted by the ccmay be discharged nearby the plant mainly incase of thermal inversion.This comparison between coal and naturalgas on environmental basis must take also indue consideration their emissions duringtheir extraction, mining, treatment and tran-sportation steps up to the power plant(upstream emissions) [8].A comparison between coal and gas upstreamemissions is not easy on quantitative basis,because it is dependent from the coal mining

and gas well locations and characteristics,from the type of used transportation systemand from the length of journey from the fuelsource to the power plant.

4.6 Main Emissions During theUpstream of the Natural Gas Life CycleIn the case of natural gas we must take in dueconsideration mainly:• gas flaring (gas combustion on the well area)

and venting (release of gas to atmospherealso on the well area), referred to the gasthat cannot be used locally or transported.During the World Bank-IMF Spring meetingsto tackle issues such as the impact of clima-te change and the efficient use of cleanenergy, the Global Gas Flaring Reductionpartnership issued a statement April 23,2006 estimating that over 150 bcm of natu-ral gas are being flared and vented annually.That is the equivalent of the combinedannual gas consumption of Germany andFrance. And the 40 bcm of gas flared inAfrica is equivalent to half of the continen-t's power consumption;

• gas purification near the extraction area toreduce CO2 (that can reach also from 20%up to 30% in volume) and H2S content.These CO2 and H2S are usually vented toatmosphere;

• gas leakages during its transportation andCO2 emitted by the gas turbines movingthe pipeline gas compressors and by theLNG ships motors.

4.7 Main Emissions During theUpstream of the Coal Life CycleIn the case of coal we must take in due con-sideration mainly:• natural gas (including in some cases up to 90%

of methane) leakages from the coal miningduring coal extraction: this gas, that must be

NOx

SOx

Particulates

CO

Combined cycles:

Pollutant contentmg/Scu-meter @ 15% O2 v/v dry,during premixing (from50% to 100% load)

25

perhaps negligible, butnot measured in Italy

not measured in Italy

20

Combined cycles:

Pollutant contentmg/Scu-meter related @ 3.5% O2 v/v dry,during premixing (from50% to 100% load)

73

perhaps negligible, butnot measured in Italy

not measured in Italy

58

Coal fired unit:

Pollutant contentmg/Scu-meter @ 3.5% O2 v/v dry,also at low loads

118 or lower

118 or lower

15

Negligible

Coal fired unit:

Pollutant contentmg/Scu-meter @ 6% O2 v/v dry,also at low loads

100 or lower

100 or lower

15

Negligible

Table 5 : Combinedcycle emissions in respect to the coal fire unit emissions in Europe



removed during coal extraction mainly forsafety reasons, is or flared or vented or con-veyed through pipelines to the natural gasusers (power generation, home heating etc).This gas coming from coal-bed formations isincluding a 2 micron coal dust (mean particlesize) that quickly coats gas filters, and it istough to remove when it builds up in dehy-dration, processing, and lubricating liquids;

• dust formation from coal during its tran-sportation and storage : but now are usedcovered geodesic domes for storing coaland coal is transported for example fromthe ships to the boiler coal bunkers througha fully closed belt conveyor system, so dustdispersion to the environment is approa-ching to zero;

• wastewater discharges: the cleaning of allcoal handling machinery is usually madeusing water that after its use is conveyed towater purification systems.

4.8 NoiseNoise control, in its broadest sense, is theprevention of noise before it is generated.Alternatively, noise reduction is the attenua-tion of noise after it has been produced. Anymoving machinery creates noise that can bereduced through the correct design of themachinery (mainly reducing the speed of themachinery components and of the insideinvolved fluids and solids). But the reductionof the noise produced by the machinery itself,increases its cost, so usually the project engi-neer is trying to finding a technical and eco-nomic compromise between the improve-ment of the design of the machine and theattenuation of excess sound through absor-bent surfaces (usually soft materials) [11].Basing on the fact that the number of machine-ry used within a coal plant is higher in respectto the machinery used in a combined cycleplant and that the land requirement of a coalplant is about 30 times the land requirement ofa combined cycle plant, the noises generatedby a coal plant exceed that of a cc plant.

5. Combined Cycle versus SupercriticalCoal Fired Unit Emissions: in The NextFutureBeing important EU electric utilities andpetrochemical companies strongly interestedto develop the CCS technologies within theZEP in the next future the fossil fired powergeneration plant emissions will approach toalmost zero.Basing on the fact that the content of impuritieswithin CO2 delivered to sequestration facilities

must be reduced to very low values (prelimina-ry studies indicate also 0,01%), the future emis-sions in case of the adoption of CCS post com-bustion technologies both for CC and conven-tional plants could be as follows.

5.1 Nitrogen Oxide and CO EmissionsGas turbines would use also in Europe the 9ppm combustion technologies now requestedby the US Authorities and always referred toa 15% O2 content in the flue gas on dry basis.Additional reduction to about 3 ppm will beobtained through catalysts.The NOx emissions of the coal fired units willbe reduced to 20 ppm or lower as referred toa 6% O2 content in the flue gas on dry basis,combining at their best low NOx burners,BOFA (boosted overfire air), Selective auto-catalytic reduction (SACR), NOx SelectiveCatalytic Reduction (SCR) [6].

5.2 Sulphur Dioxide EmissionsSO2 gas turbines emissions must be measu-red also in the gas turbine exhaust gas and incase of need actions (for example scrubbers)must be included to minimize these SO2emissions.The SOx emissions of the coal fired unitsmust reduced in this case to 10 ppm as refer-red to a 6% O2 content in the flue gas on drybasis. Some manufacturers offer De-SOxsystems including a second scrubber dow-nstream of the first one.

5.3 Particulate EmissionsNatural gas supply station of the gas turbineswill be equipped with filtering and/or scrubbingsystems to minimize particulate emissions.The particulate emissions of the coal firedunits will be reduced also under 2 ppm orlower, with an additional scrubber or with awet electrostatic precipitator (wesp).As indicated at item 3, the oxy-fuel combu-stion technologies look presently foreseeableonly for conventional plants. In this case thelimits of the pollutants within the exhaustgases and the used technologies will be thesame as in case of the post combustion withthe following advantages:• NOx arises only from the nitrogen contai-

ned in the coal;• higher flame temperature decreases particu-

lates;• the reduction of the combustion gas flow

rate reduces the dimension of the De-NOx,De-SOx and De-dust systems.

In the case of adoption of pre-combustion de-



carbonization, the gas turbines combustorswill be supplied by hydrogen and air and theNOx will be limited during combustion toabout 10 ppm and further reduction looksnot required.

6. ConclusionsWe hope that the readers can find within thispaper sufficient information for a preliminarysurvey of this important topic both from thepoint of view of the involved technologies andfrom the point of view of their impact on theenvironment.With the existing technologies (item 5.0) theflue exhaust gas emissions of the conventionalcoal fired plants are approaching in Europethe emissions of the natural gas combinedcycles.On the contrary in US the emissions of com-bined cycles required by the local authoritiesare definitely lower in respect to the cc emis-sions required in Europe and so lower of theemissions of the US and EU conventionalplants.In the next future with the adoption of theCCS (carbon capture sequestration) techno-logies (item 6.0) in the framework of the ZEP(zero emission projects), the flue gas exhaustemissions of the conventional plants will beon the same level of the emissions of thecombined cycles on world wide basis.The author also wish to thank Mr. Robert G.Schwieger Editor and Publisher of the US“Combined Cycle Journal” magazine, who hasmade a significant contribution to this paperindicating detailed information on the gas turbi-nes and combined cycle emissions required bythe Regulatory Issues in the US market in theearly 1990s.The author wish to thank also Eng.Francesco Chiesa, who gave his support indica-ting updated prices of natural gas and coal. n

Paper presented at “Power Gen 2007”, Madrid(Spain), 27 June 2007

References

[1] Dodero G., Barra M.: Advanced gasification process -

Power Gen 2005, Milan

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[3] Ichiro K.: Research Activities for High Temperature

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[4] Dodero G., Englund Vattenfal C.: Gasifiers, Combined

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[7] Shilling N.Z.: IGCC Clean Power Generation Alternative For

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[10] Burns D.: Pipeline-quality Gas Can Knock Your Plant

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[11] Dodero G., Barra M.: Evaluating the Impact of New

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Mr. Dodero is Chairman ofthe Company IPG IndustrialProject Group Srl. In this rolehe is also responsible fordeveloping the powertechnology on behalf of IPG.Before this IPG assignment,until 1997 Mr. Dodero hasbeen a senior manager ofENEL (the Italian StateOwned Electric Company)

and responsible for planning and construction of largescale, multi-national, process plants for power generationand other applications. He has worked for more than 36years in ENEL.Mr. Dodero holds a degree in Electrical Engineering of thePolytechnic Institute of Milan and participated to a courseon Chemical Engineering. He has authored or coauthoredmore than 60 papers and publications on behalf of ENELand subsequently on behalf of IPG.

coal fired unit versus natural gas combined - ipgsrl.com fired unit versus natural gas...

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