THE NOVELEDGE IGCC REFERENCE PLANT: COST AND EMISSIONS REDUCTION POTENTIAL

Gasification Technologies 2004,

Washington, DC, October 6, 2004

Dave Heaven, Fluor; William S. Rollins, NovelEdge Technologies, LLC

ABSTRACT

NovelEdge Technologies has developed and patented a combined cycle power block concept that utilizes duct firing in the HRSG to increase the power output from the steam turbine relative to power from the gas turbine(s). The net effect of this approach is power output and heat rates almost matching those of conventional natural gas fired combined cycle designs while achieving reduced capital investment and maintenance. The purpose of this paper is inquiry into the integration of this NovelEdge technology with a reference gasification plant. Overall performance and cost are estimated and compared with a reference IGCC plant. Results indicate this is a practical alternative to the conventional IGCC configuration.

INTRODUCTION Production of electric power from gasification-derived syngas has conventionally been accomplished in Integrated Gasification Combined Cycle (IGCC) plants. This technology has been successfully deployed in 12 operating plants today. These IGCC plants have typically fired the available syngas in the gas turbines with little or no supplemental syngas duct firing in the heat recovery steam generators (HRSG), which recover heat from the gas turbine exhaust. NovelEdge Technologies has developed and patented a combined cycle power block for natural gas-fired plants, which relies upon considerable duct firing in the HRSG to substantially increase power production from the steam turbine relative to power production from the gas turbine. For this study, the duct firing is limited to temperatures that do not require water-cooled walls in the HRSG for simplicity. The benefits of this approach are reduced capital investment and reduced maintenance expense for a given net plant power output. The first purpose of this paper is inquiry into the integration of this NovelEdge technology with a reference gasification plant. The first step in the general approach was to start with a nominal 1000 MW IGCC plant based around four General Electric 7FA+e gas turbines, then reduce the gas turbine count to three and duct fire the remaining syngas in the three HRSGs. Plant feed rate and the gasification system were held fixed between the two cases. All interfaces between the gasification block and the power block were examined carefully to confirm a workable fit between the two sections. This provided a base comparison where the impact was focused only on the power island.

The second purpose of this paper was presentation of a plant design and performance based on conditions deemed more favorable to NovelEdge without forcing comparability to a reference conventional IGCC plant as was done initially.

BASIC NOVELEDGE CONCEPT NovelEdge Technology is a new process for combined cycle power plants. This new process has been awarded 4 patents by the US Patent and Trademark Office, while numerous other patent applications are still pending. Essentially, NovelEdge Technology is a combined cycle process that allows for a substantial increase in power through supplemental firing in the HRSG, only without the large degradation in heat rate that is associated with duct firing. The net effect is a high power-density combined cycle plant that has a lower specific capital cost (lower $/kW), but retains an excellent heat rate. To understand how NovelEdge Technology works, it is beneficial to first examine a basic natural gas-fired combined cycle, as illustrated in Figure 1. This cycle is arbitrarily based upon an “F” class gas turbine (GT) with a single pressure level HRSG and a reheat steam cycle. Note that although the steam cycle may be efficient, the combined cycle is not optimally efficient as a result of the high stack temperature (400° F). This basic steam cycle simply cannot recover all of the exhaust gas energy that is available when utilizing a clean fuel such as natural gas or syngas.

Figure 1

2

As a result of the lower efficiency of the basic combined cycle, the industry has gravitated to the multi-pressure level HRSG combined cycle arrangement as illustrated in Figure 2. By taking advantage of the latent heat required to boil water, and the fact that lower pressure steam boils at lower temperatures, the multi-pressure system can attain higher combined cycle efficiencies by recovering more exhaust gas energy than the basic combined cycle of Figure 1. This multi-pressure process reduces the stack temperature to a nominal 200° F.

Figure 2

With NovelEdge Technology a different approach is taken to recover exhaust gas energy (see Figure 3). Rather than utilize a multi-pressure level HRSG, a single pressure level is employed in conjunction with a large economizer section and duct firing. As duct firing increases, steam production in the HRSG increases. Higher steam flows equate to higher feedwater flows into the low temperature end of the HRSG. Essentially, when the correct amount of duct firing is used, the cold feedwater flow into the back end of the HRSG cools the stack gases down to a nominal 200° F. Thus the NovelEdge design retains the higher steam cycle efficiency yet still recovers all of the exhaust gas energy that is available.

3

Figure 3

Let’s examine mathematically how NovelEdge Technology works. An “F” class gas turbine (GT) has a simple cycle efficiency of approximately 36%. After losses, approximately 58% of the energy consumed by the GT is available in the HRSG. A conventional combined cycle, with a 3-pressure level HRSG and its mix of HP, IP, and LP steam, has a steam cycle efficiency of about 35.3%. Therefore, the combined cycle efficiency, η, is expressed as follows: η = 0.36 + (0.58)(0.353) η = .565 or 6040 Btu/kwh This heat rate is similar to published numbers from the OEM’s for their 2-on-1 “F” class power plants. For the NovelEdge combined cycle, the GT efficiency is unchanged at 36%. Also, there is 58% of the GT input energy available to the HRSG. However, to achieve a low stack temperature similar to the conventional plant (nominally 200° F), duct firing must be employed, and 30% more energy must be input to the HRSG. However, by now utilizing all high-pressure (HP) steam and increasing the main steam pressure, the steam cycle efficiency is increased to 42%. The efficiency for the NovelEdge cycle is calculated as follows: η = [0.36 + (0.58 + 0.30)(0.42)] / (1.0 + 0.30) η = .561 or 6085 Btu/kwh As can be seen by these calculations, the NovelEdge combined cycle efficiency is within 1% of the conventional multi-pressure level arrangement for natural gas fired plants.

4

Another interesting facet of the NovelEdge combined cycle is its power production split between the gas turbines and the steam turbine. In a conventional unfired combined cycle, the GTs produce a nominal 65% of the plant load, while the ST produces the remaining 35%. For the NovelEdge cycle, however, the steam turbine typically produces the majority of the plant’s power output. Therefore, in essence the NovelEdge combined cycle shifts the power production emphasis in the combined cycle from a gas turbine based cycle to a one that is predominantly a steam cycle. Bearing this concept in mind, it can be understood that a conventional natural gas-fired plant at 750 MW might utilize a 3-on-1 arrangement, or 3 GTs and 1 ST, where the NovelEdge facility would utilize a 2-on-1 arrangement for the same power output. With this reduction in GTs and thus a reduction in the number of stacks, and utilizing an SCR to achieve equal NOx concentrations from all stacks, it is seen that the NovelEdge facility can have lower emissions than the conventional plant as well. By replacing more expensive gas turbine capacity with lower cost steam turbine capacity, producing a larger percentage of the plant’s power with the lower maintenance steam turbine, and utilizing fewer stacks for the same power production, the net result of utilizing NovelEdge Technology is a combined cycle plant with lower capital costs, lower maintenance costs, and in many instances, lower emissions.

COMPARISON OF CONVENTIONAL AND NOVELEDGE IGCC APPLICATIONS

Since NovelEdge Technology can save significant capital and maintenance expenses on natural gas-fired combined cycle power plants, it is of interest to examine what effect it may have on an IGCC application. For comparison purposes, it was decided to examine two plants of the same nominal output, a conventional IGCC and a NovelEdge IGCC. Both these plants have identical gasification equipment, with some minor changes in the syngas clean-up/heat recovery systems. Conventional Plant The conventional plant has an ISO rating of 1086 MW. It will consist of two (2) blocks of a 2-on-1 arrangement. Therefore, the major pieces of equipment include: 4 – Gasifiers 2 – Syngas clean-up trains 4 - ASU’s, nominal 2000 stpd of pure O2 and 3045 stpd N2 diluent each 4 - GE Frame 7FA+e gas turbines 4 – HRSGs, with 3 pressure level design 2 – Steam turbines, nominal 275 MW each 2 – Condensers

5

The conventional plant is based upon a single stage, slurry-fed gasification system with high-pressure steam production from the hot syngas. The plant utilizes a selective MDEA acid gas removal process for sulfur removal down to 40 ppm, and a zero liquid discharge system. Gas turbine NOx is controlled to 15 ppm primarily with nitrogen diluent that is moisturized with a small amount of steam. The “Block Flow Diagram” for this case is included as Figure 4, while the “Steam, Condensate, and BFW Diagram” for this facility is shown in Figure 5. This conventional 1086 MW plant consumes 8844 stpd of Pittsburgh #8 coal on an as-received basis. The higher heating value for this fuel input is 9654 MMBtu per hour HHV, for a heat rate of 8890 Btu/kwh or 38.4% efficient. NovelEdge Plant The NovelEdge plant has an ISO rating of 1073 MW. It will consist of one 3-on-1 arrangement. Therefore, the major pieces of equipment include: 4 – Gasifiers 2 – Syngas clean-up trains 4 - ASU’s, nominal 2000 stpd of pure O2 and 2285 stpd N2 diluent each 3 - GE Frame 7FA+e gas turbines 3 – HRSGs, with single pressure level design 1 – Steam turbine, nominal 700 MW 1 – Condenser The NovelEdge plant is based upon the same gasification system as the preceding conventional IGCC Case, including the selective MDEA module for sulfur removal down to 40 ppm and a zero liquid discharge system. Gas turbine NOx is controlled to 15 ppm primarily with nitrogen diluent that is moisturized with a small amount of steam. . The “Block Flow Diagram” for this case is Figure 6 and the “Steam, Condensate, and BFW Diagram” for this facility is shown in Figure 7.

6

MAKEUPWATER

BLA

CK

WA

TER

GR

EY

WA

TER

GREY WATER

1,280 STPDCOARSE SLAG

50 WT%SOLIDS

AMMONIA/ACID GAS

320STPD

FINE SLAG50 WT%SOLIDS

ACID

GAS

CLE

ANFU

EL G

AS

756 STPD93 WT%

SULFURIC ACID

PREHEATEDFUEL GAS

CTG

EX

HA

US

T G

AS

CONDENSATE

LP S

TEAM

IP STEAMFROM SRU

BFW

BFW

BFW

46 STPD50 WT% SOLIDS

FILTER CAKETO DISPOSAL

UNIT 0200

4 X 25% TRAINS

AIRSEPARATION

UNIT

UNIT 0100

4 X 25% TRAINS

GASIFICATION(RADIANT ONLY)

UNIT 0300

4 X 25% TRAINS

GASSCRUBBING

UNIT 0300

2 X 50% TRAINS

LOW TEMPGAS COOLING

&COS

HYDROLYSIS

UNIT 0800

4 X 25% TRAINS

COARSESLAG

HANDLING

UNIT 0400

4 X 25% TRAINS

BLACKWATERFLASH

&FINE SLAGHANDLING

VENT

2 X 50% TRAINS

MERCURYREMOVAL

UNIT 1000

4 X 25% TRAINS

COMBUSTIONTURBINE

GENERATOR(GE 7FA+e)

UNIT 1300

HEATRECOVERY

STEAMGENERATOR

(HRSG)

4 X 25% TRAINS

UNIT 1310

STEAMTURBINE

GENERATOR

2 X 50% TRAINS

UNIT 1320

1 x 100% TRAIN

SULFURICACID PLANT

UNIT 12002 X 50% TRAINS

LOWPRESSURE

CONDENSATE(AMMONIASTRIPPER)

UNIT 0700

1 X 100% TRAIN

UNIT 0900

VAC

. CO

ND

EN

SAT

E (H

OT)

HE

ATED

VA

CU

UM

CO

ND

ENSA

TE

AIR

MAKEUPWATER

TOFLARE

LP STEAM FROM LTGC

MP STEAM FROM LTGC

COALSLURRY

RAWSYNGASQUENCHWATER

66.6 MW

NET POWEROUTPUT

1085.8 MW

2 X 83.8 MW

4 x 197.0 MW

2 X 266.0 MW

WASTEWATERTO FACILITYZLD SYSTEM

SLAG

WA

TER

LOC

KHO

PPE

R R

EC

IRC

. WAT

ER

SLAG WATER

GREY WATER

IP N2TO CTGs

IP N2FROM ASU

STEAMTURBINEEXHAUST

BFW

CWR

CWS

DEMIN.MAKEUPWATER

FINES

STR

IPP

ED W

ATER

AMMONIA OFFGAS

PITTSBURGH#8 COAL

SH

HP

STE

AM

CR

H S

TEAM

HR

H S

TEAM

SH

LP

STE

AM

INTERNALUSERS

8,340 STPD,DRY BASIS

2 X 50% TRAINS

ACID GASREMOVAL

(MDEA)

UNIT 1100

CRUDE SYNGAS

SCRUBBEDSYNGASPROCESS

CONDENSATE

PRO

CE

SSC

ON

D.

SOUR GAS

IP STEAM

BLOWDOWN

FLASH GAS

AIR

NAT GAS (START-UP)

CONDENSATERETURN

IP S

TEA

M

MAKEUPWATER

AIR

SH IP

STE

AM

AIREXTRACTION

SH M

P ST

EAM

HP

O2

7,97

0 ST

PD,

PU

RE

BA

SIS

TO LAKE

FROM LAKE

No. 2 FUEL OIL(START-UP)

BFW

WATER TONEUTRALIZATION

SUMP

LPSTEAM

VACUUMCONDENSATE

& BOILERFEEDWATER

SYSTEMS

2 X 50% TRAINS

UNIT 1350

EXH

AU

ST

TO A

TM

FLU

E G

AS

TO A

TM

HP STEAM

GRINDING &SLURRY

PREPARATION

UNITS 0500/0600

FIGURE 4: CONVENTIONAL IGCC1100 MW NOMINAL

PROCESSWASTEWATERTREATMENT

HRSG HP ECONOMIZER

#1

DA65 psig312°F

DEAERATOR (INTEGRAL)LP STEAM DRUM

HRSG HP ECONOMIZER

#2

HRSG HP ECONOMIZER

#3

HRSG HP

SUPERHEATERS

HRSG HP EVAPORATOR

544°

F60

0°F

LPLPHP IP

590°

F

HRSG REHEATERS

640 PSIG, SATURATED

12-B-401SULF. ACID PLANT

IP STEAMGENERATOR

08-E-202COS HYDROLYSIS

HEATER

HRSGIP ECONOMIZER

HRSGIP EVAPORATOR

452°

F

460 PSIG, SATURATED

E-203LP STEAM BOILER

55 PSIG, SATURATED

07-F-204AMMONIA

CONDENSATESTRIPPER

09-E-904AMMONIASTRIPPER11-E-101

MDEAREBOILER

VENT

60°F72°F

HRSGLP EVAPORATOR

ASUAIR

PRETREATMENTREGENERATION

HRSGIP SUPERHEATERS

ZERO LIQUIDDISCHARGE (ZLD)

FACILITY

699°F439 psig

996°F385 psig

1000°F1387 psig

313°F

316°F

MPFLASHDRUM

452°

F

MISCGASIFICATION

USERS

BDFROMSTEAMDRUMS

CWRCWS

BDFLASHDRUM

303°F

CONDENSATE TOMP FLASH DRUM

484°

F

IPCONDENSATE 225°F

79°F

566°F457 psig

IPBFW

13-TG-101/201CTG STEAMINJECTION

IP BFW TOSYNGAS HEATER

303°F

303°F

BD

BD

165°F

195°F

462°

F

DEMINMAKEUPWATER

175°F

314°F

GASIFICATIONRADIANT SYNGAS

BOILER

BD

IPKO

DRUM

HRSG LPSUPERHEATER 579°F

52 psig

FIGURE 5: STEAM DIAGRAM,CONVENTIONAL IGCC

MAKEUPWATER

BLA

CK

WAT

ER

GR

EY

WA

TER

GREY WATER

1,280 STPDCOARSE SLAG

50 WT%SOLIDS

AMMONIA/ACID GAS

320STPD

FINE SLAG50 WT%SOLIDS

AC

ID G

AS

CLE

AN

FUEL

GA

S

756 STPD93 WT%

SULFURIC ACID

PREHEATEDFUEL GAS

CTG

EXH

AU

ST

GA

S

CONDENSATE

LP S

TEA

M

IP STEAMFROM SRU

BFW

BFW

BFW

46 STPD50 WT% SOLIDS

FILTER CAKETO DISPOSAL

UNIT 0200

4 X 25% TRAINS

AIRSEPARATION

UNIT

UNIT 0100

4 X 25% TRAINS

GASIFICATION(RADIANT ONLY)

UNIT 0300

4 X 25% TRAINS

GASSCRUBBING

UNIT 0300

2 X 50% TRAINS

LOW TEMPGAS COOLING

&COS

HYDROLYSIS

UNIT 0800

4 X 25% TRAINS

COARSESLAG

HANDLING

UNIT 0400

4 X 25% TRAINS

BLACKWATERFLASH

&FINE SLAGHANDLING

VENT

2 X 50% TRAINS

MERCURYREMOVAL

UNIT 1000

COMBUSTIONTURBINE

GENERATOR(GE 7FA+e)

UNIT 1300

HEATRECOVERY

STEAMGENERATOR

(HRSG)

UNIT 1310

STEAMTURBINE

GENERATOR

UNIT 1320

1 x 100% TRAIN

SULFURICACID PLANT

UNIT 12002 X 50% TRAINS

LOWPRESSURE

CONDENSATE(AMMONIASTRIPPER)

UNIT 0700

1 X 100% TRAIN

UNIT 0900

VA

C. C

ON

DE

NS

ATE

(HO

T)

HE

ATE

D V

AC

UU

M C

ON

DE

NS

ATE

AIR

MAKEUPWATER

TOFLARE

LP STEAM FROM LTGC

MP STEAM FROM LTGC

COALSLURRY

RAWSYNGASQUENCHWATER

NE: 70.6 MW

NET POWEROUTPUT

NE: 1073.0 MW

NE: 2 X 77.3 MW

NE: 3 x 197.0 MW

NE: 1 X 707.2 MW

WASTEWATERTO FACILITYZLD SYSTEM

SLA

G W

ATE

R

LOC

KH

OP

PE

R R

EC

IRC

. WA

TER

SLAG WATER

GREY WATER

IP N2TO CTGs

IP N2FROM ASU

STEAMTURBINEEXHAUST

BFW

CWR

CWS

DEMIN.MAKEUPWATER

FINES

STR

IPP

ED

WA

TER

AMMONIA OFFGAS

PITTSBURGH#8 COAL

SH

HP

STE

AM

CR

H S

TEA

M

HR

H S

TEA

M

SH L

P S

TEA

M

INTERNALUSERS

8,340 STPD,DRY BASIS

2 X 50% TRAINS

ACID GASREMOVAL

(MDEA)

UNIT 1100

CRUDE SYNGAS

SCRUBBEDSYNGASPROCESS

CONDENSATE

PR

OC

ES

SC

ON

D.

SOUR GAS

IP STEAM

BLOWDOWN

FLASH GAS

AIR

NAT GAS (START-UP)

CONDENSATERETURN

IP S

TEA

M

MAKEUPWATER

AIR

SH

IP S

TEA

M

AIREXTRACTION

SH M

P S

TEA

M

HP

O2

7,97

0 ST

PD,

PU

RE

BA

SIS

TO LAKE

FROM LAKE

No. 2 FUEL OIL(START-UP)

BFW

WATER TONEUTRALIZATION

SUMP

LPSTEAM

VACUUMCONDENSATE

& BOILERFEEDWATER

SYSTEMS

2 X 50% TRAINS

UNIT 1350

EX

HA

US

T TO

ATM

FLU

E G

AS

TO

ATM

HP STEAM

GRINDING &SLURRY

PREPARATION

UNITS 0500/0600

PROCESSWASTEWATERTREATMENT

NE: 3 X 33% TRAINS

NE: 3 X 33% TRAINS

NE: 1 X 100% TRAIN

FIGURE 6: NOVELEDGE IGCC1100 MW NOMINAL

FUE

L G

AS

9

HRSG HP ECONOMIZER

#1

HRSG HP ECONOMIZER

#2

HRSG HP

SUPERHEATERS

HRSG HP EVAPORATOR

LPLPHP IPHRSG REHEATERS

12-B-401SULF. ACID PLANT

IP STEAMGENERATOR

08-E-202COS HYDROLYSIS

HEATER

E-203LP STEAM BOILER

07-F-204AMMONIA

CONDENSATESTRIPPER

09-E-904AMMONIASTRIPPER11-E-101

MDEAREBOILER

ASUAIR

PRETREATMENTREGENERATION

ZERO LIQUIDDISCHARGE (ZLD)

FACILITY

MPFLASHDRUM

MISCGASIFICATION

USERS

BDFROMSTEAMDRUMS

CWRCWS

BDFLASHDRUM

CONDENSATE TOMP FLASH DRUM

IPCONDENSATE

13-TG-101/201CTG STEAMINJECTION

IP BFW TOSYNGAS HEATER

BD

BD

DEMINMAKEUPWATER

GASIFICATIONRADIANT SYNGAS

BOILER

BD

IPKO

DRUM

FIGURE 7: STEAM DIAGRAM,NOVELEDGE IGCC

TO LP STEAMBOILER LINE

TOCONDENSER

LT GAS COOLING

FROM HRSGECONOMIZER #2

10

Just like the conventional plant, the NovelEdge plant at 1073 MW consumes 8844 stpd of Pittsburgh #8 coal on an as-received basis. With a higher heating value for this fuel input of 9654 MMBtu per hour HHV, the NovelEdge heat rate is 8997 Btu/kwh or 37.9% efficient. Process Comparison An examination of the Block Flow Diagrams for both the conventional and NovelEdge IGCC facilities (Figure 4 and Figure 6 respectively) indicates the major differences in these two cycles. For services such as the MDEA reboiler, ammonia condensate stripper, ASU air pretreatment regeneration, zero liquid discharge, and COS hydrolysis heater, all steam flows to these operations should be identical between either plant. Also, steam production from the sulfuric acid plant and the LP steam boiler should be identical. Therefore, the gasification process is essentially unchanged. From another perspective, however, such as the power island integration, a great deal has changed. For the NovelEdge process, all IP and LP sections of the HRSG have been eliminated. In addition, the LP steam line to the steam turbine is no longer required. The 4 deaerators that are integral with the LP section of each conventional HRSG are no longer necessary and are replaced with a vacuum-deaerating condenser. IP steam from the sulfuric acid plant is no longer tied to the IP steam system, but is simply used to provide moisturizing steam to be added to the nitrogen diluent. Additions to the NovelEdge process include a duct burner system for each HRSG, a low temperature gas-cooling module to preheat feedwater, and a heat exchanger to preheat low-pressure feedwater for the LP steam boiler and other miscellaneous gasification users. A vacuum-deaerating condenser is utilized in lieu of a pressurized system. For the ASU, the power requirements are reduced. Although the oxygen required is the same for either plant, conventional or NovelEdge, the conventional plant has 4 GTs, and thus requires a nominal 550,000 lb/hr of nitrogen diluent for each GT. The NovelEdge facility utilizes only 3 GTs; therefore its total diluent requirements are 550,000 lb/hr less than the conventional facility. This reduces the power requirements of the ASU, as less nitrogen must be compressed for GT injection.

PERFORMANCE COMPARISON The two major performance comparisons that will be made are efficiency and emissions. Note that from the gasification perspective, these two facilities are identical, so fuel flow, slag flow, mercury removal, fine ash collection, and other such services associated with syngas treatment are the same for either option.

Efficiency From the power island perspective, both the conventional and NovelEdge plants will receive the same amount of treated syngas fuel. Each plant will use identical GTs with identical performance, including fuel flow and diluent flow. The conventional plant, however, will consume all of its fuel equally in 4 separate GTs, while the NovelEdge plant, will consume ¾ of the fuel in the 3 GTs, and the remaining ¼ will be consumed equally in each of the 3 duct burners. The conventional plant utilizes main steam conditions of 1400 psia/1000° F inlet and 996° F reheat. The NovelEdge facility has main steam conditions of 1815 psia/1050° F inlet and 1050° F reheat Also, with no IP or LP steam, it becomes obvious that the NovelEdge steam cycle is a more energetic and efficient cycle. There are also some parasitic load savings with the NovelEdge cycle. Since the steam cycle will use higher pressure and more steam flow, additional pumping power is required. This equates to a nominal 4 MW. However, since the ASU must only provide diluent for 3 GTs in lieu of 4, there is an approximate 13 MW reduction in ASU power requirements. Therefore, the net effect is a nominal 9 MW reduction in parasitic loads for the NovelEdge facility. Ultimately, for the same fuel flow, the conventional plant produces 1086 MW while the NovelEdge facility produces 1073 MW. This equates to an efficiency reduction for the NovelEdge plant of nominally 1.2 %. Emissions Both the conventional and NovelEdge facilities utilize the same gasification systems, the same fuel quantity, and the same MDEA sulfur removal systems. Sulfur emissions from either plant are anticipated to be the same in tons per year. With 40 ppm of sulfur in the fuel, the anticipated sulfur emission rate is a nominal 175 lb/hr for the facility at base load. All the GTs in this comparison are designed for 15 ppm of NOx. Therefore, for the conventional cycle, each stack shall have a stack emission rate of 15 ppm NOx @ 15% O2. However, for the NovelEdge cycle, there are duct burners that will contribute to the NOx. The rate of NOx formation for the duct burners is 0.08 lb/MMBtu HHV. Therefore, the stack outlet NOx for the NovelEdge design is 16.5 ppm NOx @ 15% O2. Although at first glance this may seem like a sizeable increase, further examination reveals that this increase is actually quite small. At 15 ppm NOx @ 15% O2, each GT in the conventional plant emits 139.9 lb/hr of NOx. For the entire plant with 4 GTs, this calculates to 559.6 lb/hr. For the NovelEdge facility, each stack emits 16.5 ppm NOx @ 15% O2. This equals 189.4 lb/hr of NOx per stack or 568.2 lb/hr of total NOx for the plant. Therefore, the NOx emissions for the NovelEdge facility are only 1.5% greater than those in the conventional arrangement.

12

Further, had we elected to install SCR in these HRSGs and controlled NOx to a consistent reference level such as 3 ppm (uncorrected for O2), then the overall NOx emissions would have been reduced by 33%. Summary The following data in Table 1 summarizes the performance comparison for the 1086 MW conventional and 1073 MW NovelEdge IGCC plants:

Table 1

Conventional IGCC NovelEdge IGCC Plant Output - MW 1086 1073 Plant Heat Rate – Btu/kwh 8890 8997 NOx – ppm @ 15% O2 15 16.5 NOx Potential – Tons/year 2451 2489 SOx Potential – Tons/year 768 768

Heat Rates shown are HHV

COST COMPARISON

Cost estimates were developed for the two plants on the basis defined above. Both plants were located at a generic Gulf Coast location and were fully self sufficient in all supplies other than the Pittsburg #8 coal feedstock. The plant included air separation facilities but no sparing of the gasifiers. These are AACE Class 5 estimates with costs stated on instantaneous 3rd quarter 2004 basis. Initial fill of catalysts and chemicals is included but no other startup costs. Contingency is included at 8% and accuracy is deemed to be –15/+40%.

Estimate assumes clear and level site, no site remediation or piling requirements. Exclusions from the estimate include owner’s costs, sales/use taxes, forward escalation, working capital, inventory, scope changes, interest during construction and any premium steel prices reflecting the current market.

Table 2

Conventional IGCC NovelEdge IGCC Plant Capital, MM$ 1225 1150 Plant Capital, $/kW 1128 1072

13

Operating costs of the two plants are similar in many categories. The table below focuses on the differences. Capital charges are based on 10 years depreciation and 80% availability factor. This is a simplified approach and does not correspond to the EPRI COE methodology.

Table 3

Option Plant Rating MW

Heat Rate

Btu/kwh

Electrical Fuel Cost

$/kwh

Capital Cost $/kW

Electrical Capital

Cost $/kwh

Electrical O&M Cost

$/kwh

Total Cost for

Electricity $/kwh

Conventional 1086 8890 .0116 1128 .0161 .0105 .0382 NovelEdge 1073 8997 .0117 1072 .0153 .0102 .0372

Note: Capital costs charged at 10 years recovery before taxes and 80% plant availability.

NOVELEDGE REFERENCE PLANT IN DEVELOPMENT

In the previous comparison, two nominal 1100 MW plants were compared, a conventional IGCC plant and a NovelEdge facility. With the exception of the power island, in this comparison the gasification island, the ASU, and the balance of plant equipment were all nearly identical. This was done for purposes of consistency in the comparison. Having now verified that the NovelEdge approach does indeed provide similar performance to the conventional plant, only at a lower cost, it is logical to proceed to the next step, which is to search for potential improvements to an entire IGCC plant that is based around the NovelEdge process. Cost Effective Design It has been shown that the use of NovelEdge can reduce the cost of the power island in an IGCC application, but since the power island represents only about 40% of the overall IGCC plant cost, it is desirable to find cost savings in other portions of the plant as well. One such place where savings may be realized is in the gasification island. In some instances, the same gasifiers can be operated at higher pressure to yield more throughput. This results in an “economy of scale” cost savings, as the incremental power output is greater than the incremental cost adder. This may also be the case when a larger gasifier is substituted for a smaller one. In either instance, the cost of the gasification plant can be reduced on a $/kW basis by extending gasifier output to its rated capacity. The NovelEdge Reference Plant, which is still in development, will utilize the same gasifier count as in the 543 MW conventional plant (one block of the 2-on-1 as described in the aforementioned comparison), only we will increase its throughput by 25% by utilizing a larger gasifier. In addition, this will require a nominal 25% larger ASU,

14

however, the economy of scale factor should provide an ASU facility that is again less costly on a $/kW basis. Cycle Design As discussed earlier, the NovelEdge cycle is predominantly a steam cycle. With steam used for heat recovery from the hot syngas, the need for process steam requirements, and the presence of a great deal of low temperature energy, there are more opportunities for the NovelEdge cycle to be efficient. Some of the factors for increased efficiency are as follows:

1) It has an efficient steam cycle 2) Duct firing provides high end energy for superheat/reheat of excess steam,

such as that from a convective boiler 3) Process steam can be extracted rather than just produced at user pressure 4) An additional expander can be used for the duct burner fuel 5) More plant MWs per GT equate to relatively less parasitic load for

compressing nitrogen In the conventional cycle, most of the 55 psig process steam is produced in the LP steam boiler and used for various plant services. Although this steam meets the requirements for which it is intended, it produces no power. With the NovelEdge design, more 55 psig steam can be extracted from the ST, thus producing power before it is utilized for the plant services. With a steam-based cycle such as NovelEdge, more steam is generated and as a result, more cold feedwater is available for heat recovery. This allows for heat recovery of low temperature energy from returning condensate or from the syngas itself that might otherwise just be cooled by a trim cooler. Reference Plant Arrangement For this NovelEdge reference plant, we focused on a 2-on-1 arrangement based upon the GE Frame 7FA+e gas turbine. The emphasis was to utilize equipment to its maximum capacity. Therefore, utilizing gasifiers near their maximum operating pressure was deemed less costly than the use of an additional gasifier. The complement of major equipment is as follows: 2 – Gasifiers (50% capacity each), with radiant and convective coolers 1 – Selexol sulfur removal system 2 – ASUs (50% capacity each), nominal 4700 total tpd pure O2 2 – GE Frame 7FA+e GTs 2 – HRSGs, Nooter/Eriksen single pressure level 1 – Steam turbine, nominal 440 MW 1 - Condenser

15

Since the concept of NovelEdge is to utilize a single pressure cycle, and recover heat with the feedwater, in lieu of producing IP and LP steam as in the conventional cycle, one of the first changes to the conventional cycle is the elimination of IP and LP steam evaporators to the greatest extent feasible. However, due to gasification practice, the LP steam boiler was utilized, only with a diminished output. In addition, to maximize efficiency, a convective heat recovery boiler was added to the outlet of the gasifier. The remaining energy contained in the syngas after exiting the convective boiler is utilized to preheat feedwater. See Figure 8 for the “Block Flow Diagram” of the NovelEdge Reference Plant process.

16

MAKEUPWATER

BLAC

K W

ATER

GR

EY W

ATER

GREY WATER

1,600 STPDCOARSE SLAG

50 WT%SOLIDS

AMMONIA/ACID GAS

400STPD

FINE SLAG50 WT%SOLIDS

ACID

GAS

CLE

AN

FUE

L G

AS

945 STPD93 WT%

SULFURIC ACID

PREHEATEDFUEL GAS

CTG

EXH

AUST

GAS

CONDENSATE

LP S

TEAM

IP STEAMFROM SRU

BFW

BFW

BFW

57.5 STPD50 WT% SOLIDS

FILTER CAKETO DISPOSAL

UNIT 0200

2 X 50% TRAINS

AIRSEPARATION

UNIT

UNIT 0100

2 X 50% TRAINS

GASIFICATION(RADIANT ANDCONVECTIVE)

UNIT 0300

4 X 25% TRAINS

GASSCRUBBING

UNIT 0300

1 X 100% TRAIN

LOW TEMPGAS COOLING

&COS

HYDROLYSIS

UNIT 0800

2 X 50% TRAINS

COARSESLAG

HANDLING

UNIT 0400

2 X 50% TRAINS

BLACKWATERFLASH

&FINE SLAGHANDLING

VENT

1 X 100% TRAIN

MERCURYREMOVAL

UNIT 1000

2 X 50% TRAINS

COMBUSTIONTURBINE

GENERATOR(GE 7FA+e)

UNIT 1300

HEATRECOVERY

STEAMGENERATOR

(HRSG)

2 X 50% TRAINS

UNIT 1310

STEAMTURBINE

GENERATOR

1 X 100% TRAIN

UNIT 1320

1 x 100% TRAIN

SULFURICACID PLANT

UNIT 12001 X 100% TRAIN

LOWPRESSURE

CONDENSATE(AMMONIASTRIPPER)

UNIT 0700

1 X 100% TRAIN

UNIT 0900

VAC

. CO

ND

ENS

ATE

(HO

T)

HEA

TED

VAC

UU

M C

ON

DEN

SAT

E

AIR

MAKEUPWATER

TOFLARE

LP STEAM FROM LTGC

MP STEAM FROM LTGC

COALSLURRY

RAWSYNGASQUENCHWATER

31.9 MW

NET POWEROUTPUT

709.1 MW

1 X 105.5 MW

2 x 197.0 MW

1 X 433.4 MW

WASTEWATERTO FACILITYZLD SYSTEM

SLAG

WAT

ER

LOC

KHO

PPE

R R

ECIR

C. W

ATER

SLAG WATER

GREY WATER

IP N2TO CTGs

IP N2FROM ASU

STEAMTURBINEEXHAUST

BFW

CWR

CWS

DEMIN.MAKEUPWATER

FINES

STR

IPPE

D W

ATE

R

AMMONIA OFFGAS

PITTSBURGH#8 COAL

SH

HP

STEA

M

CR

H S

TEAM

HR

H S

TEAM

SH L

P ST

EAM

INTERNALUSERS

10,425 STPD,DRY BASIS

1 X 100% TRAIN

ACID GASREMOVAL

(MDEA)

UNIT 1100

CRUDE SYNGAS

SCRUBBEDSYNGASPROCESS

CONDENSATE

PRO

CES

SC

ON

D.

SOUR GAS

IP STEAM

BLOWDOWN

FLASH GAS

AIR

NAT GAS (START-UP)

CONDENSATERETURN

IP S

TEAM

MAKEUPWATER

AIR

SH IP

STE

AM

AIREXTRACTION

SH

MP

STE

AM

HP

O2

9,96

2 ST

PD,

PU

RE

BA

SIS

TO LAKE

FROM LAKE

No. 2 FUEL OIL(START-UP)

BFW

WATER TONEUTRALIZATION

SUMP

LPSTEAM

VACUUMCONDENSATE

& BOILERFEEDWATER

SYSTEMS

1 X 100% TRAIN

UNIT 1350

EXH

AU

ST T

O A

TM

FLU

E G

AS T

O A

TM

HP STEAM

GRINDING &SLURRY

PREPARATION

UNITS 0500/0600

FIGURE 8: NOVELEDGE REFERENCE PLANT

PROCESSWASTEWATERTREATMENT

EXP. 2

EXP. 1

FUEL

GAS

EXP. 1

EXP. 2

6.5 MW12.6 MW

Feedwater preheating is now provided by several means. First, low temperature water from the black water treatment facility provides low temperature heat. In addition, returning water from the fuel gas heaters provides some feedwater heating. And also, condensate from both the 55 psig header and the 640 psig header is utilized as well. Final preheating of the feedwater before entering the HRSG is accomplished through the use of a steam extraction feedwater heater, which utilizes low-pressure steam from the steam turbine. The majority of the process steam required by the 55 psig header is now extracted from the steam turbine, as the LP steam boiler produces only about 20% of the required flow. To minimize overall system changes, the Sulfuric Acid Plant (SAP) is unchanged, and excess steam generated in the SAP is sent to the cold reheat line. Also, to enhance efficiency and environmental performance, the standard MDEA sulfur removal system was replaced with a Selexol system to reduce sulfur to a nominal 8 ppm. With these low levels of sulfur, an SCR system in the HRSG can be effective. The HRSG for this application is built by Nooter/Eriksen. It includes the duct burner, SCR catalyst, and an ammonia oxidation catalyst. The SCR is designed to reduce the NOx to 3ppm @ 15% O2. Due to the sulfur content of the syngas fuel, the ammonia oxidation catalyst is designed to reduce the ammonia slip after the SCR to 0.5 ppm, its purpose being to negate the effects of ammonia salt formation in the downstream sections of the HRSG. As is typical of a NovelEdge HRSG, this unit includes only one evaporator for HP steam, and a large economizer section. Superheat and reheat sections are included downstream of the duct burners. Firing temperature at maximum output is less than 1400° F. Figure 9 is a general arrangement drawing for the HRSG for this application.

NovelEdge Reference Plant HRSG Design

Figure 9

The net result of optimizing the IGCC plant for the NovelEdge-based IGCC is a facility that can achieve efficiency levels of 40% HHV or greater. In this 2-on-1 arrangement with the GE Frame 7FA+e, the nominal ISO output is 709 MW. The emissions for the plant are reduced to less than 2 ppm for SO2 and less than 3 ppm for NOx. Capital costs are also low, with an estimated Gulf Coast installation cost of less than $1000 per kW. Now let’s compare the cost of electricity for the 543 and 1086 MW conventional plants from the initial comparison (one block of 2-on-1 and two blocks of 2-on-1) to the 709 MW NovelEdge Reference Plant. The three economic factors considered were fuel cost, capital cost, and maintenance cost. Plant capacity factor was assumed to be 80% in either case. Fuel costs were taken to be $1.30 per MMBtu. The annual capital and maintenance costs considered being 10% and a nominal 6.5% of the capital costs respectively. With this data, Table 4 compares the cost of electricity from the two plants.

Table 4

Option Plant Rating MW

Heat Rate

Btu/kwh

Electrical Fuel Cost

$/kwh

Capital Cost $/kW

Electrical Capital

Cost $/kwh

Electrical O&M Cost

$/kwh

Total Cost for

Electricity $/kwh

Conventional 543 8890 .0116 1190 .0170 .0110 .0396 Conventional 1086 8890 .0116 1128 .0161 .0105 .0381

NovelEdge 709 8510 .0111 980 .0140 .0091 .0341 As can be seen from this data, even with its larger economy of scale, the conventional 1086 MW plant still has a higher cost of electricity than the smaller NovelEdge facility. Thus the NovelEdge Reference Plant is an efficient, yet low cost and low emissions IGCC facility. Flexibility is Key The one key issue that makes the NovelEdge IGCC approach so attractive is its flexibility. The plant rating can be tailored to meet a variety of parameters including output or cost. If transmission is a limiting factor, the NovelEdge plant can be designed to meet a specified output. To reduce cost, the necessary amount of duct firing can be designed into the facility to get the most from a particular portion of the plant, such as maximizing the output of a given gasification island, staying within the design limits for a single ASU, or maybe maximizing the output of a manufacturer’s steam turbine model. The latter has significant importance in the repowering of existing facilities.

REPOWERING

Many natural gas-fired combined cycle plants are currently stranded, due to the high cost of fuel. This leaves the door open for repowering opportunities. If a natural gas fired combined cycle (NGCC) plant can be reasonably converted to IGCC, this might restore a plant’s profitability. From a historical perspective, approximately 75% of the NGCC plants built in the last several years included some amount of duct firing. This means a 2-on-1 NGCC plant with “F” class GTs will include a nominal 200 to 300 MW steam turbine. From the NovelEdge Reference Plant, it is noticed that the steam turbine utilized in this design is rated at a nominal 440 MW. Therefore, an integrated repowering could use a 1-on-1 arrangement (half size of Reference Plant presented herein with a nominal 220 MW steam turbine) and achieve a nominal 360 MW output. Therefore, all that would be needed would be the GT rework to utilize syngas, and a new HRSG. Some minor ST rework may be required, but typically these steam turbines were designed for 1800 psia/1050/1050° F steam conditions. For higher output, such as 720 MW, a second new HRSG and a new ST could be installed. This might provide an economical repowering that is mentioned here for reader interest, but is beyond the scope of this current paper. And of course, the repowering of main steam plants, be they coal, oil, or natural gas fired can be readily achieved with NovelEdge Technology, as it is a steam based combined cycle, utilizes a single pressure steam, and will be a better match to the existing steam turbine. And obviously the key element, flexibility, provides for matching the steam flow to the existing steam turbine. This can be easily accomplished by providing the correct amount of duct firing to the IGCC process. Repowering will provide many opportunities in the future, and the fact that NovelEdge is a steam based combined cycle, in conjunction with its flexibility, make it an ideal technology to accomplish this task.

21

CONCLUSIONS This paper has presented a consistent comparison of conventional IGCC with a NovelEdge IGCC. This comparison required a larger plant than would usually be built but was necessary to remain within the bounds of an integer number of gas turbines and the design range of HRSG duct firing for the NovelEdge process. The more usual size of 500 MW+ was discussed under the NovelEdge reference plant. The conclusions reached in the comparison of conventional IGCC with NovelEdge IGCC were:

• Power production from the power block is less for NovelEdge. Although the incremental duct-fired steam cycle is very efficient, it does not quite compete with combined cycle efficiency.

• Power production from NovelEdge improves because elimination of one gas turbine eliminates the need to compress NOx control nitrogen to that gas turbine. On an overall basis, power production is 1073 vs. 1086 MW or about 1.2 percent less than the conventional IGCC.

• Plant availability will be the same for both cases. The same basic components are included in both cases and the level of duct firing in the NovelEdge case falls well within commercial experience.

• Plant risk is comparable for both cases for the same reasons. • Capital investment for NovelEdge IGCC is 1150 MM$ or about 93.9% of the

conventional IGCC. Note that the investment costs are dropping faster than the power output.

• Maintenance costs are lower for the NovelEdge case. While long term gas turbine maintenance costs are roughly $.0025/kW-hr, steam turbine maintenance costs are about 20% of this figure.

• Non-maintenance operating costs are expected to be equivalent between the two cases.

• Overall costs of electricity are significantly less. • The benefits of this technology should be applicable to other gasification

processes. The plant components of the NovelEdge process are commonly used in power plants and are well proven. The economics of this process are attractive and the process is worth consideration in future IGCC plants.

22