feasibility study of integrated gasification combined cycle (igcc) in terms of the following...

8/18/2019 Feasibility study of Integrated Gasification combined cycle (IGCC) in terms of the following parameters: Technolog…

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Thermal Power Engineering

Project Report

ON

FEASIBILITY STUDY OF IGCC FOR

HIGH ASH CONTENT INDIAN COAL

Submitted By: Group-23

Prithvi Jawahar Rahul Jhingonia Nagendra Bandi

Vinod Kumar


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PROJECT TOPIC Feasibility study of Integrated Gasification combined cycle (IGCC) in terms of the following

parameters: Technology, Reliability and Economy for high high – ash content Indian Coal. (Project

no. : 3)

ABSTRACT In India, coal plays a very important role for power generation. Essentially, all the power generated

from coal is based on the PC (pulverized coal) plant. As both the economy and power demand in Indiahave grown rapidly in recent years, the Government of India is looking for alternatives to the PC plant touse coal more efficiently and cleanly. The Integrated Gasification Combined Cycle (IGCC) plant has beenidentified as one of these alternatives.

Due to the advantages such as high efficiency of electricity generation and high degree ofcleanness, Integrated Gasification Combined Cycle (IGCC) power plant represents the direction ofdevelopment for all fired power plants in India.

India faces a problem in adopting the IGCC technology due to high ash content present in coalavailable in the country. There are a very few demonstration plants in India of low capacity andapplicability and reliability of high capacity systems are not yet demonstrated. Attempts of imitatingforeign technology have failed due to the high ash content in Indian coal. There is a need for eitherdevelopment of indigenous technologies or implement processes such that the developed technologycan be adopted to suit Indian needs. This report analyzes the technical and economic attributes in termsof risk, reliability and feasibility of the IGCC power generation plan.

It is both necessary and possible for India to develop IGCC power plant, but not with the current

technology available. The biggest obstacle facing the development of IGCC is the lack of proventechnology for utilization of high ash coal and huge amount of investment needed.

COAL GASIFICATION & IGCC Coal gasification is a process that converts coal from a solid to a gaseous fuel through partial

oxidation. Once the fuel is in the gaseous state, undesirable substances, such as sulfur compoundsand coal ash, may be removed from the gas by established techniques. The net result is a clean,transportable gaseous energy source.

In contrast to combustion process which works with excess air, gasification process works onpartial combustion of coal with the oxygen supply controlled (generally 20 to 70% of the amountof O2 theoretically required for complete combustion) such that both heat and a new gaseousfuel are produced as the coal is consumed.

C + ½ O2 (gasification) → CO

C + H2O (gasification) → CO + H2


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The integrated gasification combined cycle is a process in which the fuel is gasified in anoxygen or air-blown gasifier operating at high pressure. The raw gas thus produced is cleaned ofmost pollutants (almost 99 % of its sulphur and 90 % of nitrogen pollutants). It is then burned inthe combustion chamber of the gas turbine generator for power generation. The heat from theraw gas and hot exhaust gas from the turbine is used to generate steam which is fed into thesteam turbine for power generation.

The process is called a combined cycle as high temperature power plant is superimposed astopping unit to the steam plant. Combined plants may be of many types of which gas turbine-steam turbine plant is most popular system.

PROCESSES INVOLOVED IN IGCC The main subsystems of a power plant with integrated gasification are:

Gasification plant

Raw gas heat recovery systems Gas purification with sulphur recovery Air separation plant (only for oxygen blown gasification) Gas turbine with heat recovery steam generator Steam turbine generator

Fig. 1 Schematic of IGCC Process – Source: www.mhi-global.com


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The feedstock which is fed into the gasifier is more or less completely gasified to synthesis gas(syngas) with the addition of steam and enriched oxygen or air. The gasifier can be fixed bed,entrained or fluidised bed. The selection of the gasifier to achieve best cost efficiency andemission levels depends upon the type of fuel. In the gas purification system, initial dust isremoved from the cooled raw gas. Chemical pollutants such as hydrogen sulphide, hydrogenchloride and others are also removed. Downstream of the gas purification system, the purifiedgas is reheated, saturated with water if necessary (for reduction of the oxides of nitrogen) andsupplied to the gas turbine combustion chamber. The IGCC technology scores over others as it isnot sensitive with regard to fuel quality. Depending on the type of gasifier, liquid residues,slurries or a mixture of petcoke and coal can be used. In fact, the IGCC technology wasdeveloped to take advantage of combined cycle efficiency of such low-grade fuels.

SECTIONS OF IGCC SYSTEM:In order to study the feasibility of implementing IGCC on a large scale in India, it is important toanalyses all the aspects and properties involved in these systems. The figure below (Fig. 2)shows a typical configuration of an IGCC plant.

1. Preparation section:Slurry is formed by grinding the coal with water in the feed preparation section whichis mixed with 62-68 wt% dry solids for feed to the slurry-fed GE or E-Gas plant. Slurry isstored in storage tanks before pumping into gasifiers.

2. Gasification section:Slurry feed is pumped to the refractory-lined gasifier where coal is gasified with oxygenfrom the air separation unit (ASU) to generate a raw syngas {majorly H 2+ CO}. The rawsyngas is sent to the downstream High Temperature Gas Cooling (HTGC) section for heatrecovery whereas, the heat in gasifier liquefies the coal ashes which are quenched andcrushed at the bottom of gasifier.

3. High Temperature Gas Cooling (HTGC)Raw syngas from the gasifier i s cooled t o about 650-700°C in HTGC section by generatinghigh pressure saturated steam in a radiant syngas. The cooled syngas is then sent toparticulate removal section.

4. Particulate RemovalSyngas from HTGC is quenched and scrubbed with water to remove particulates, hydrogenchloride, and ammonia.

http://www.netl.doe.gov/research/coal/energy-systems/gasification/gasifipedia/syngashttp://www.netl.doe.gov/research/coal/energy-systems/gasification/gasifipedia/syngas


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5. COS HydrolysisSyngas exiting from the Particulate Removal section is reheated to about 205°C beforeentering a COS hydrolysis reactor where about 90% of the carbonyl sulfide (COS) reactswith water to form hydrogen sulfide and carbon di oxide.

Fig. 2 Typical IGCC configuration – Source: http://www.joban-power.co.jp/

6. Low Temperature Gas Cooling (LTGC) and Mercury RemovalGas from the COS Hydrolysis section is cooled to about 38°C through a in the LTGC sectionseries of heat exchangers and knockout drums, where about 90% of the mercury isremoved due to adsorption on to carbon beds.

7. Acid Gas Removal (AGR)Lean solvent absorbs H 2S and small amount of the CO 2 from the cooled particulate freesyngas. H 2S free syngas exiting the absorber is stripped with nitrogen to remove excessCO2 and other non-sulfur bearing gases such as H 2 and CO. The flashed rich solvent is sentto the regenerator where the H 2S and CO2 are removed with reboiler steam. Acid gasfrom regenerator is sent to Sulfur Recovery Unit.

http://www.joban-power.co.jp/http://www.joban-power.co.jp/http://www.joban-power.co.jp/http://www.joban-power.co.jp/


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8. Sulfur Recovery Unit (SRU) & Tail Gas Treating Unit (TGTU)One-third of the H 2S is burned with oxygen from the air separating unit (ASU) (used ingasification section) to form SO 2. The SO2 is combined with the remaining two-thirds ofthe H 2S before being catalytically converted into sulfur via the Claus reaction(SO2+2H2S→3S+2H 2O). Tail gas from the SRU is normally hydrogenated to convertunreacted SO 2 and entrained sulfur into H 2S before being compressed for recycle to theAGR.

9. Clean Gas Humidification and ReheatClean syngas from AGR is humidified by washing against hot circulating water to addsteam and to recover some of the low level waste heat. The humidified syngas is reheatedthrough heat exchange against raw syngas before being sent to be burned in the gasturbine.

10. Gas turbineClean syngas is burned with compressed air in the gas turbine to generate power. Syngaswith up to approximately 60% hydrogen and the balance being nitrogen or/and water asthe diluent can be burnt in currently available commercial turbines. The gas turbine canalso provide a portion of the compressed air to the air separation unit (ASU). Thisincreases the overall IGCC plant efficiency and reduces the capital cost and powerconsumption of the ASU .

11. Heat Recovery Steam Generator (HRSG) and Steam Turbine Generator (STG)

Super-heated high pressure steam is generated by the hot exhaust from the gas turbinethrough the heat recovery steam generator (HRGS) which can also reheat intermediatepressure steam to without any firing. The HP and IP superheated steam are routed to thesteam turbine generator to generate additional electric power . Thus the whole systemwould form a gas turbine – steam turbine combined cycle.

ADVANTAGES OF IGCC • Flexibiliy in fuels:

It is an advanced technology that represents the cleanest of currently available coaltechnologies. Higher fuel flexibility IGCC plants can use any high hydrocarbon fuel, such as lowand high-sulfur coal, anthracite, and biomass. Thus IGCC plants may find application fromsmall scale fertilizer units to large scale power generation plants.


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• Higher efficiencies: The electricity generation efficiency of the IGCC process can be higher than 45% (HHV) withoutCO2 capture. With the development of gas turbines, future net efficiency developments

should take efficiencies beyond 50%.• Lower emission:

The plant is inherently lower emission of SOx, NOx and particulate matter (PM) thanconventional coal based power plants.

• Marketable by-products: During the gasification and gas clean-up process, mineral material (ashes and other inertspecies) is transformed into slag as a kind of by-product, which may commercial value innearby industries. The slag can be used in construction and building applications. Thegasification process in IGCC enables the production of not only electricity, but a range ofchemicals, by-products for industrial use, and transport fuels. In addition to electricitygeneration, hydrogen produced from the process can potentially be used as a transport fuel,in fuel cells.

IGCC TECHNOLOGY SCENARIO OF THE WORLD

Coal contributes about 61% of total fossil fuel proved reserve in whole world. The US holdsthe largest individual coal reserves, followed by Russia and China. The bad impact of burning ofcoal can be reduced by the clean-coal-technology which is a collection of technologies being

developed to mitigate the environmental impact of coal energy generation. Clean coaltechnologies are being developed to remove or reduce pollutant emissions to the atmosphereand IGCC technology is considered as one of them.

Table 1 shows specifications of six prime coal based IGCC power plants of the world observedthat efficiencies of 41% - 44% can obtained using IGCC which is very difficult to achieve with thehelp of plants which use pulverized coal (PC). It is important to note that these plants employhigh quality coal which has relatively low ash content.

Table 1 Operating conditions of BHEL plants – Source: December 2005 report, Office of PSA

The gasification database (April 2014) of National Energy Technology Laboratory (NETL), USA,shows that total 98 gasification projects worldwide having commercial potential where, 35 areIGCC(Integrated Gasification Combined Cycle).

Small number of new projects have been initiated worldwide, each at some stage of planning orconstruction. According to NETL, already 35 projects have proposed in worldwide to generate


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20,730MW electricity by IGCC plant where the US proposed the maximum individual IGCC plant(11,775MW by 20 projects), followed by UK (2,540MW by 4 projects), Saudi Arabia (2,400MW by1 project) and China (1,0505MW by 2 projects). China plans to build 50 coal gasification plants inless populated north-western parts of the country, using the gas produced to generate electricityin the more populated areas, where smog is prevalent. Future concepts that incorporate a fuelcell or a fuel cell-gas turbine hybrid could achieve efficiencies nearly twice today's typical coalcombustion plants. If any of the remaining heat can be channeled into process steam or heat,perhaps for nearby factories or district heating plants, the overall fuel use efficiency of futuregasification plants could reach 70 to 80 percent.

Table 1 Operating conditions of plants across the world – Source: December 2005 report, Office of PSA

There are many research agencies and institute worldwide, developing coal gasificationtechnologies to minimize the environmental impact and improve the process efficiency for maximumenergy utilization. Some of them are, National Energy Technology Laboratory (NETL) USA,Commonwealth Scientific and Industrial Research Organization (CSIRO) –Australia, World CoalAssociation (WCA)-UK, International Energy Agency- IEA Clean Coal Centre (CCC)-UK, Institute of CleanCoal Technology (ICCT)-China, Canadian Centre for Clean Coal/Carbon and Mineral processingTechnologies (C5MPT)-Canada.

Compared to pulverized coal power plants, IGCC power plants have significantly higherefficiency. According to World Coal Association (WCA) London, the average global efficiency oftraditional coal-fired plants is currently 33% compared to 45% for the most efficient plants likeIGCC, due to the coupling of the gas and steam turbine process to the generation can be achieved.From the practical experience, average net efficiency of six existing IGCC plant is 41.8% with themaximum efficiency in 430MW Vresova IGCC plant by 44% and the minimum efficiency found in262MW Wabash River IGCC plant, Indiana USA by 39%. In IGCC power plant, efficiencies of over

Coal basedIGCC plant

WillemAlexander(Netherland)

WabashRiver(USA)

Tampa(USA)

Puertollano(Spain)

Vresova(Chinarepublic)

Nakoso(Japan)

Capacity(MW) 253 262 250 300 430 250Fuel feed Black coal +

BiomassBlackcoal+Petroleumcoke

Blackcoal

Black coal +Petroleumcoke

Lignite Blackcoal

Gasifier type O2 -blownDry-feedPrenflo

O2 -blownDry-feedE-Gas

O2 -blownSlurryfeedGE

O2 -blownSlurry-feedShell

O2 -blownDry-feedGSP

AirblownDry-feedHMI

Coalconsumption

2000 TPD 2500 TPD 2600 TPD 2500 TPD 2000TPD

1700TPD

Net efficiency 43% 39% 41% 42% 44% 42%


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55% can be achieved in the future. Compare to other advanced power plant processes, IGCCtechnology exhibits the highest efficiency and thus the lowest specific CO2 accrual.

In future, work on clean electricity generation by coal gasification technology will focus onimproving the reliability & performance of the gasifier and finding the best process for Syngas

cooling, Water gas shift reaction (WGSR), Acid gas removal (AGR) mechanism, etc. Technicaltrends, which help gasification, include improving gas turbines and poly-generation. Each increasein combined-cycle efficiency directly reduces the size and cost of the gasification facility requiredto fire that combined cycle. Advanced intercooled, recuperated, reheat gas turbines have thepotential of power-to-cogeneration heat ratio that is an order of magnitude higher than thatpossible with steam turbines. Poly-generation is unique to gasification and, with deregulation, thisconcept will develop.

IGCC TECHNOLOGY SCENARIO OF INDIA The involvement of IGCC technology for power generation in India is negligible when

compared to the total installed capacity. India lies among the top coal reserves holding countriesof the world. Essentially, all the power generated from coal is based on PC (pulverized coal) plant.Despite having adequate supply of coal, difficulties are faced in implementing IGCC technologiesfor power generation. The prime reason which hinders the implementation is the high ash contentpresence in Indian coal. The ash content typically ranges from 40% - 50% whereas all typical IGCCplants across the globe work on coal which has an ash content ranging from 1% to 16%.

The technical challenges of the electricity sector in India include low efficiencies of thermalpower plants, continued reliance on coal plants, and inadequate transmission and distributionnetworks. Due to the high ash content of Indian coal, oxy‐fueling and post‐combustion CO2capture would appear to be suitable options for India.

The first IGCC plant of India was commissioned in the year 1989. It was a 6.2MWdemonstration power plant which was developed by Bharat Heavy Electricals Limited (BHEL) inTiruchchirappalli, Tamil Nadu. This plant was Asia’s first and the world’s second coal based IGCCinstallation and is currently in successful operation. It was set up soon after the successfuloperation of the first commercial-scale IGCC demonstration plant in the world, the Cool Water

Plant in California (1984-88). The project then had a cost of Rs.15 crore. This installation runs onair-blown fluidized-bed gasifier which is capable of testing coal of about 40% ash content at

0.8MPa between 960o

C and 1050o

C.


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Fig. 3 Schematic of 6.2MW IGCC plant – Source: “Workshop on Clean Coal Technologies”, BHEL,February 2012

A 6.4 MW IGCC pilot unit has been operating by BHEL since 1989, based on Siemens and

Alstom technology. Construction of a 200 MW IGCC demonstration plant in Vijayawada in Andhrawas begun in summer 2010 by a consortium of BHEL, Andhra Pradesh Power GenerationCorporation Limited (APGENCO) and the Department of Science. The Indian high‐ash coal requiresthe use of fluidized‐bed gasifiers, which is a different type to the well‐established entrained‐flowgasifier used for low‐ash coals.

In June 1991, Council for Scientific and Industrial Research (CSIR) along with United StatesTrade and Development Program published a 34o page report on “Fea sibility Assessment of CoalIntegrated Gasification Combined Cycle (IGCC) Power Technology for India ”. The study gives a clearcomparison between Pulverized Coal plants (PC plants) and IGCC plants. It includes various studiesand evaluations on IGCC plants and analysis of various aspects of practical implementation of IGCCtechnology in India. Later, no great emphasis was laid on developing technology andimplementing scaled up systems of IGCC in India. There were a good number of discussionsbetween the government and private corporations for setting up plants which did not turn out tobe successful due to various issues.

The office of Principal Scientific Advisor (PSA) in 2001 tried to bring BHEL and the NTPCtogether to work on development of a 100 MW IGCC demonstration plant. There was a great needto develop indigenous technology which could function with high ash content coal. BHEL would


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play an important role in this. BHEL had already set-up three R&D plants based on PFB [200mmdiameter Advanced Pressurized Fluidized Bed Gasifier (APFBG) (coal feed:1.2T/day); a 450mmdiameter Performance Evaluation and Demonstration Unit(PEDU) (18T/day) and 1.1m diameterCombined Cycle Demonstration Plant (CCDP) (150 T/day, 6.2 MWe)]. The table below (Table 1)shows the operating conditions for existing BHEL plants. Also, partnering a corporation like theNTPC was important so that the plant could be operated as a regular power plant and power couldbe supplied to the grid.

Table 2 Operating conditions of BHEL plants – Source: December 2005 report, Office of PSA

In 2003 a committee was set up by the office of PSA for the feasibility study of setting up ofthis 100MW demonstration plant. In December 2005, the committee published a report“Development of the Integrated Gasification Combined Cycle (IGCC) Technology as suited toPower Generation using Indian Coals” .

Table 2. Gives the experimental and simulated data carried out by the committee on BHEL’sCCDP.

Ultimately, the report estimated a carbon conversion efficiency of 85%, cold gas efficiency of71%, gas calorific value of 1000-1100 kcal/cu. m and a gross efficiency of 39% for the 100MWplant to be set up.

NTPC opted out of the project as NTPC was not agreeable to the financial terms even though

it had originally agreed to invest Rs.4 crore per MW. The technology was yet to prove itsrelevance in the Indian context, hence NTPC was not very keen in investing in this technology.

There were also clashes on the Intellectual Property between BHEL and NTPC. As a whole theaimed project turned into a failure and was ultimately called off.


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Table 3. Analysis on exper imental data on BHEL’s CCDP – Source: December 2005 report, Office of PSA

In May 2008, the power generation company of Andhra Pradesh, APGENCO, signed up with BHELto put up a 125-MW IGCC plant. But again, the project was not successful. This was due toproblems in funding and allocation Rs300 crore promised by the government.

In 2011 there was proposal for setting up a 100MW IGCC technology demonstration plant byNTPC at National Capital Thermal Power Station at Dadri in Uttar Pradesh. There would be noadditional land required as the plant would be set in already existing plants in Dadri. The projectaims at demonstrating the use of gasifier and other technology and commercial viability, so thatit could be replicated at already existing powerplants in India. The cost estimate of the projectwas about Rs 600 crores.

Again in April 2013, BHEL and NTPC involved in talks to form a joint venture for establishing100MW power project based on new gasification technology. It was estimated that the projectwould cost around Rs700 crore and the efficiency of the plant would be around 40%.

Any further official statements with regard to this project are not yet out.


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FEASIBILITY OF IGCC IN INDIA Since the evolution of gasifiers and IGCC technology all developed countries which had

access to high quality coal concentrated on research and development of processes

corresponding to the readily accessible high quality coal. GE, E-Gas and Shell gasifiers play adominant role in all major IGCC plants.

The following table shows a few famous IGCC plants across the world. The first six plantsshown in the table employ a high temperature “ entrained flow gasification ” which is suitablefor low ash content coal and not for the category of Indian coal.

Table 4. A few IGCC power plants – Source: NETL, Office of Fossil Energy, U.S.A

To harness the potential of coal reserves through implementation of IGCC, there is a pressingneed to develop indigenous technology rapidly or adopt and alter the available internationaltechnology such that it is adaptable in the Indian scenario. The following information providesinsights of feasibility of coal based IGCC implementation in India.

RESOURCE DATA OF COAL:

All the data below is for coal from open mine of Dakra seam in North Karnpura field. This can be

considered as typical Indian coal as its properties match with the coal from various mines across thecountry.


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Proximate analysis:

As Received Basis,wt%

Dry Basis,wt%

Moisture 18.0 ---Ash 34.8 42.5

Crystal water 3.5 4.3CO 2 in

carbonates 0.5 0.6

Volatile matter 17.1 20.8Fixed carbon 26.1 31.8

Table 5. Proximate analysis of coal – Source: IGCC Power Technology for India, CSIR report

Calorific value:

As Received Basis(kcal/J)

Dry Basis(kcal/J)

HHV 3322 4058

LHV 3168 3857

Table 6. Calorific value – Source: IGCC Power Technology for India, CSIR report

Ultimate analysis:

As Received Basis,wt%

Dry Basis,wt%

Moisture 18.0 ---Ash 34.8 42.5

Crystal water 3.5 4.3CO 2 incarbonates

0.5 0.6

C 35.8 43.6H 2.1 2.5N 0.8 0.9S 0.3 0.4O 4.2 5.2Cl Trace Trace

Table 7. Ultimate analysis of coal – Source: IGCC Power Technology for India, CSIR report

Ash fusion temperature:

The ash fusion temperature of Indian coal is very high. The initial deformation temperature is about1400 oC, while the hemispherical and flow temperatures are around 1500 oC.


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TECHNOLOGY SELECTION CRITERIA:

APPROACH 1:

If the intention is to use Indian technology for gasification of coal, BHEL’s air blown fluidizedbed gasifier would be the only hope. Other technologies are currently still in nascent stages and need time and investment to

develop and become practically viable. Scaling up models of BHEL’s 6.2MW plant (as done for BHEL 125MW project) could be used

to analyze and implement IGCC plants of high capacity which could range from 100MW -300MW capacity. An intended scale up process of BHEL is shown in Fig 4.

Fig. 4 BHEL’s Scale up of gasifier – Source: “Workshop on Clean Coal Technologies”, BHEL, February 2012

The setting up of a plant could be done in two stages.

Phase 1: The first phase involves design, development, procurement, installation andstabilized operation of gasifier along with hot gas cleanup facility specific to Indian coal.

Phase 2: Phase two would involve development of a Combined Cycle Gas Turbine (CCGT) andintegrating it with the established gasifier and gas cleanup system.


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A set of extensive studies were carried out by NTPC and other related organizations to findout the gasifier suitability. Samples of Run-of-mine (ROM) coal and washed coal, conventionallybeing used for power generation at power plants in Dadri were sent to various test locations foranalyzing technology suitability. The proximate analysis of coal used and the details of testlocation are provided in Table 8 and Table 9 respectively.

Table 8. Proximate analysis of coal used – Source: Conference on Clean Coal Technology with focus on CoalGasification, February 2012

Table 9. Test location details – Source: Conference on Clean Coal Technology with focus on Coal Gasification,February 2012

A few important conclusions that were made from this coal characterization tests were:

i. Fluid bed and transport gasifiers can gasify Indian coals very well due to their high reactivity . Thiswas checked at test locations of GTI, BHEL and EERC.


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ii. No significant improvement was shown by Washed coal as compared to ROM coal in terms ofgasification.

iii. Fluidized bed gasifier demonstrated a carbon conversion of 85%-90%. This could be furtherimproved by parametric optimization.

iv. Tests at Sansol showed fixed bed gasifier as well was suitable for gasification of Indian coals.

BHEL gives a set of advantages of using a Pre ssurized Fluidized Bed Gasifier (PFBG) for gasifying Indiancoal in its “Workshop on Clean Coal Technologies”, (February 2012).

i. Higher unit capacity per unit area vi. Capability to accept wide range of fuelsii. In-bed sulfur removal option vii. Better reliability and controliii. Easy gas cleaning viii. Operates in non-slagging modeiv. No liquid effluent formation ix. Dry granular ash dischargev. Ability to accept finer coals x. Reliable large fluidized bed combustion

systems

There could be a few gap areas in implementing the IGCC in India by the use of above specifiedtechnologies. These are specified in Table 9 below.

Scale up processuncertainties

Process parameters- Composition- Carbon conversion- Coal fines properties

Low calorific value gas The suitability of gas turbines for low CV gases shouldbe taken into consideration

Component reliability - Lock hopper- Refractory- Air Separating Unit (ASU)- Acid gas recovery

Equipment integration - Process controls- Economics- Redundancies- Integration

Resource and Development - Equipment such as hot gas filter

- Materials- Process establishment

Table 10. Gap areas of implementing IGCC in India


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APPROACH 2:

Another option is to select systems based on technologies available across the world and tryto map them to the Indian requirement.

Design considerations and technology selection should be done for both process area andpower generation area.

Gasifier selection:

The following five processes represent state of art gasification technology available:

i. Shellii. Texacoiii. KRWiv. DOWv. BGL

Shell Texaco BGL KRWBed Entrained Entrained Moving FluidizedFeeding Dry Slurry Wet WetTemperature, °C 2000 1250 –

15502000 870 –

1040Pressure, Mpa 3 4.1 2.5 2.1Coal size, mm


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Design consideration for KRW gasifiers:The carbon conversion in KRW gasifiers is not very certain. Also there is a possibility that ash maynot agglomerate because of very high fusion temperature. The failure of agglomeration woulslead to elutriation and would be difficult to be retrieved.

Design consideration for moving bed gasifiers:Moving bed gasifier is commercially tested for high ash Indian coal with successful results. Butproblems are faced in economically using coal fines rejected and treatment of water effluent.

Sulfur recovery:

For Shell gasifier, acid gas produced will have sufficient sulfur concentration to use Claus unitfor recovery of sulfur.

For Texaco and moving bed gasifiers, the sulfur concentration is very low to recover sulfur

through the Claus unit. Sulfur combustion should be done catalytically at reducedtemperatures. KRW gasifier uses in-bed sulfur capture techniques and hence does not require acid gas

removal or sulfur recovery facilities.

Gas turbine (GT) selection:

The turbines to be used should be selected from the set of existing turbines. Gas turbine selectionis limited by 50 cycles electrical system in India .

Advanced gas turbines with higher firing temperature can be used to take advantage of turbineefficiency improvement and demonstrate full potential of the IGCC plant.

RELIABILITY, COST AND RISK FACTORS:

Though coal based IGCC technology is in general labeled as green energy conversion and highefficiency process, its compatibility in India is to be thoroughly understood. IGCC systems have a fewsetbacks in Indian scenario as far as implementation is concerned.

The total efficiency of a plant employing IGCC which uses Indian coal was theoreticallyestimated at about 42%-43% initially. It is now evident that such high efficiencies could not beobtained practically in any of the demonstration plants within the country. The maximum efficiencywas limited 38% - 40% whereas efficiencies of 40% - 44% could be demonstrated at various powerplants across the world.

IGCC technology has its own set of advantages as described in technology section above.Considering efficiencies, efficiency of IGCC plants is comparable to that of pulverized coal (PC) firedpower plants (34% - 38%) and conventional combined cycle (CC) power plants (40 %). But it isimportant to note that the cost of implementing IGCC could be 1.5 – 2 times that of PC plants, which


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is very high. Table 11 gives the relative cost of generation between IGCC and PC plants 1989 estimatedIndian cost for a 600MW plant.

If a plant aims at having a processes such as Carbon Capture and Storage (CCS), there wouldbe a further decrease in overall plant efficiency and the cost of plant would increase further. But

growing environmental concerns makes it important to follow such processes for sustainability. IGCC plant PC plant

Shell Texaco KRW Moving

bed Without

FGD With FGD

Net output, MW 564.4 496.2577.

2 585.7 558.0 549.0Total capital

require,( Rs Crores) 2,055 2,059

1,460 1,529 1,065 1,278

Unit capital,Rs/kW

net 36,41

8 41,50025,292 26,103 19,084 23,275

Relative unitcaptal 1.56 1.78 1.09 1.12 0.82 Base

Cost ofgeneration, Paise/kWh@5500 h/yoperation 146.0 170.2

103.8 115.5 86.7 102.2

@6000 h/yoperation 135.4 158.1 96.5 107.6 81.4 95.6

@7000 h/yoperation 118.8 139.2 85.0 95.3 73.0 85.4@8000 h/yoperation 113.4 133.0 81.3 91.3 70.3 82.1

Relative cost of generation 1.43 1.67 1.02 1.13 0.85 Base

Table 11. Cost comparison between IGCC and PC plants, Source: IGCC Power Technology for India, CSIR report

The plant life of coal based IGCC would be about 25 – 35 years. This could be clearly observedfrom the long established plants in other countries and as well from BHEL’s 6.2MW demonstration

plant set up way back long. Though costlier than other systems, the IGCC system in India, with properintegration of developed applicable technology, is very reliable in terms of longer applicability andoperation, lower water consumption, better sulfur separation, economical CCS and otherenvironmental aspects.


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There are a few risks involved with implementation of IGCC with respect to Indian context.HIGH ASH CONTENT: In Indian coal, mineral matter is intrinsically mixed with the carbonaceous matter. As result ash

produced during the process would be mostly fine particles. Most of the available gasifiertechnologies fail to agglomerate them into large particles and separate them from the gasifiersystem .

A porous filter designed in the USA can handle particulates at around 650 Celsius . US based IGCCunits use low ash coal, which doesn't require filtration (very less particulates) before being sentto the gas turbine unit.

These fine ash particles might get elutriated and might enter the turbine systems if not properlyretrieved posing threat to the gas turbine functioning.

Even if India is going to use this kind of filters before the IGCC gas turbine unit, it should bringdown the syngas temperature from around 1200 C to around 650 C before using the filter. Thiswould reduce the thermal efficiency of the IGCC.

GASEOUS EXTRACTION: Gasifier air extraction from gas turbine, in-bed sulfur capture and hot gas particulate removal are

technically difficult processes and there is a factor of risk involved with these. There are relatively lesser technological risks associated with moving bed gasifier because it is the

most commercially exploited process and its suitability for Indian high ash coals has been established. Sulphur release does not have much commercial use, unlike the case in USA that encourages the

use of IGCC there. Similarly, for the utilization of released hydrogen, plan for using it in fuel cells and related

transportation energy needs have to be put in place.

COST ANALYSIS CASEFollowing is a case study based on the estimated cost of a moving bed gasifier IGCC plant as per

the 1989 pricing based on report on “Feasibility Assessment of Coal Integrated Gasification Combined Cycle (IGCC) Power Technology for India ” published by Council for Scientific and Industrial Research (CSIR) along with United States Trade and Development Program in 1991.

Cost of the entire moving bed case were directly estimated under the Indian conditions. Costs ofthe off sites and supporting facilities such as coal transportation system, raw water supply and treatment,solid waste disposal system, and electrical system were factored from the PC plant. This is to establish aconsistent basis for comparison between the IGCC plant and PC plant.

The bases used for converting U.S. costs into India costs and other cost estimate bases are asfollows:

Exchange rate: An exchange rate of Rs 17 per US dollar is assumed.


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Direct field material: i. To convert from the U.S. direct field material cost to India, the bulk material for civil and

structural is taken out first because it can be procured in India.ii. For all plant units except the air separation, combined cycle, and fuel oil and LPG units, it is

assumed that 30% of the remaining direct field material will be imported and the other 70%

will be procured in India.iii. For the combined cycle unit, it is assumed that only the gas turbine will be imported and the

remaining equipment and material will be procured in India.iv. For the fuel oil and LPG unit, the entire unit will be procured in India.v. For equipment and material to be procured in India, it is assumed the India costs will be

25% higher than the U.S. costs (10% for ocean freight and marine insurance and 15% for overallhigher cost markup in India).

Direct field material: To adjust the labor cost, the labor productivity in India is assumed to be 40% oft h a t in US. The labor rate in India is assumed to be Rs 17/h.

Direct field subcontract: The major item under this category is the air separation plant. For this plantunit, it is assumed that 70% of its cost is equipment and 30% is labor. All the equipment is to beimported as a package unit and all the labor is to be indigenous supply. The subcontract costs in other plant units are assumed to be all indigenous supply and also have a70/30 split between equipment and labor. The labor adjustments are the same as those describedabove for the direct field labor

Indirect cost: This cost is broken down to 70% material and 30% labor, all assumed to be indigenoussupply. The labor adjustments are the same as those described above for the direct field labor.

Engineering services: It was assumed that the basic design package would be prepared by a foreignengineering company and the detailed engineering would be performed by an Indian engineeringcompany but checked by the former. The total engineering cost is estimated to be 5% of the total fieldcost and the split between the foreign and Indian engineering companies is 30 and 70%. The licenseand know how would be obtained from appropriate foreign process licensors. The total licensing feeis assumed to be $3.5 million.

Working capital: This cost was estimated based on the following provisions: 1. Coal: 15 days2. Limestone: 60 days3. Consumables: 60 days4. Salary and wages: 60 days

Spare parts: The cost to provide a three-year supply of both foreign and Indian spare parts is estimated to be 5% of the equipment cost.

Interest during construction: An equity/debt ratio of 1:1 is used to calculate this cost. It is alsoassumed that the equity portion would be spent first before the loan portion is used. The total project


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duration is 4 years. The interest rate is assumed to be 15% per year.

Contingency: This is calculated at 5% of the capital cost.

Duties and taxes: The duties and taxes rate assumed are as following:

1. Ocean freight and marine insurance: 10% of FOB cost2. Custom duty: 30% of CIF cost (cost include ocean freight)3. Sales tax: 4% of FOR cost (freight on rail)4. Excise duty: 15.75% of FOR and sales tax5. Inland transport: 4% of FOR6. Insurance: 1.5% of FOR7. Income tax on foreign license and engineering: 30%8. R&D on foreign license and engineering: 7%

Land: The total land requirement is 1505 acres. The land is assumed to be available at no cost.

Project lead time: The total project lead time from project award to commercial operation isestimated to be 4 years. This includes permitting, engineering, procurement, plant construction, andstart up. But it excludes plant licensing.

Cost of generation: These costs are shown for 5500, 6000, 7000, and 7400 hours per year of plant operation. The bases used to derive these costs are described below.

Labor and overheads: This cost is estimated based on a total plant staff of 1400. The average salaryand benefit is assumed to be Rs. 50,000 per year.

Maintenance Materials: Total annual maintenance materials estimated to be 2% of the total plantcost including contingency.

Depreciation: This cost is calculated based on 3.6% of the total capital excluding the working capital.

Plant Name ForeignComponent(Rs. Lakhs)

Indiancomponent(Rs. Lakhs)

Total(Rs. Lakhs)

Coal Transportation System - 3030 3030

Coal Handling System - 2200 2200 Gasification, Gas Cooling, & GasLiquor

6977 25241 32191

Separation Acid Gas Removal 388 1808 2196 Sulphur Recovery 145 685 830 Tar and Oil fired Boiler - 2710 2710 Combined Cycle 14561 17833 32394


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Solid Waste Disposal - 4800 4800 Relief and Blowdown 49 190 239 Interconnecting Piping 359 1776 2135 Compressed Air System - 150 150 Fuel Oil and LPG System - 218 218

Electrical System - 5872 5872 Instrumentation and Controls 653 360 1013 Cooling water system - 3572 3572 Raw water supply and Treatment - 1690 1690 Fire Protection - 1960 1960 Waste Water Treating - 339 339

General Service & Mobileequipment - 1400 1400

Site Prep., Improvement &Buildings - 8880 8880 Total Field Cost 23132 84687 113210 Engineering Fee 1617 3774 5391 Total Plant Cost 24749 88461 113210 Contingency (5%) 1237 4423 5661 Initial Catalysts & Chemicals 600 209 809 Plant Facilities Investment 26568 93093 119680 Owner’s Cost 2388 14655 17043 Total Capital Requirements 28974 107748 136723

Duties & Taxes

-

16161

16161

Total Capital w/Duties & Taxes 28974 123909 152884

Table 12. Capital cost requirement for moving bed based IGCC plant, Source: IGCC Power Technology for India,CSIR report

Gross Power Produced, MW 640.1 Net Power Produced, MW 585.7 Aux. Power Consumption, % of Gross Power 8.5

Project Capital Requirement

Total Capital, Rs lakhs 152884 Rs/kw Gross Power Generated 23884

Annual (5500h/y) Coal Consumption, kg/kW gross 3855 Heat Rate (HHV basis), KcalkWh net power 2611 Specific Coal Consumption, kg/kWh net power 0.766


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Fixed Costs, Rs/y/kW gross power Labor and Overhead 109.36 Maintenance Material 424.43 Chemicals & Catalysts 289.49 Depreciation 853.25 Interest on Long Term Loan 1791.32 Return on Equity 1194.22 Interest on Working Capital Loan 93.22 Total Fixed Costs 4755.29

Variable Costs (5500 h/y), Rs/y/kw gross power Coal 1079.44 Limestone - Raw Water 14.59 Ammonium Sulfate Credit 9.85

Sulfur Credit 26.06Total Variable Costs 1058.12

Total Fixed and Variable Costs, Rs/y/kW 5813.41

Table 13. Cost of generation for moving bed based IGCC plant, Source: IGCC Power Technology for India, CSIR report

Electricity cost, Paise/kWh net power,

@5500 hr/y operation 115.5 @6000 hr/y operation 107.6 @7000 hr/y operation 95.3 @7400 hr/y operation 91.3

CONCLUSION India should look at establishing coal gasification, possibly including underground coal

gasification. However, the lack of positive policies and the use of ineffective state-run industriesin the past to try and implement some initiatives have prevented any significant activity beingestablished. There is evidence of the changing situation with a few coal-to-chemicals projectsbeing developed by private companies. However, the enormous potential in India is far frombeing realized.

IGCC is essentially a combined cycle of steam based and the natural-gas-based electricitygeneration, using coal and natural gas as fuels respectively. The gasification route offers variousadvantages over combustion route as mentioned below:


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Higher overall efficiency due to combined cycle

Cleaner power generation due to very low emissions Suitability for carbon capture (pre-combustion) Possibility of poly-generation i.e. producing various chemical products along with power

generation.

However, the technology is not yet commercialized and there are only a few demonstrationplants available worldwide. The technology also has some drawbacks which need to be cateredduring commercialization of the technology22.

High technological complexity Higher capital costs Technology not yet matured/commercialized and there are only few vendors Very less work done globally on fluidized bed gasifier based IGCC technology, which is

suitable to high ash Indian coals

Technology developed outside India is not directly applicable as observed, hence needsmodification to suit Indian needs. There is a huge scope for development of technologies basedon moving bed and pressurized fluid bet combustion systems, which are highly compatible withhigh-ash content coal. Every system which could be implemented has its own set of gaprequirements and risks which are to be addressed through proper estimated study of each processinvolved in whole IGCC power plant system.

REFERENCES

1. Feasibility Assessment of Coal Integrated Gasification Combined Cycle Power Technology for India,United States Trade and Development Program and Council of Scientific and Industrial Research(CSIR), June 1991

2. Development of Integrated Gasification Combined Cycle (IGCC) as suited to power generation usingIndian Coals, Office of PSA, Government of India , December 2005

3. IGCC Technology and Indian Energy Security, Arunn Narsimhan,

4. IGCC Technology Overview, Presentation to World Bank, Feb. 22, 2007, Dr. Tan-Ping Chen, Sr. VicePresident, Energy Technology, Nexant, Inc.

5. Technological options for promoting Energy efficiency in Power Plants, D. K Jain, Executive Director

(Engineering), NTPC Ltd.6. Energy Efficient Coal Gassification for IGCC Power Plant, Haarsh Rai, Abhinav Bharti, Rakesh Singh,

Neeraj Kr., International Journal of Innovative Technology and Exploring Engineering (IJITEE)

7. Challenges and Opportuities for Coal Gassification in Developing Countries, IEA Clean Coal Centre,December2013

8. Frontline, Vol 25, Issue 22, Oct 25

feasibility study of integrated gasification combined cycle (igcc) in terms of the following...

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