Year 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 Unit … · 2006. 12. 27. · PEMELIHARAAN...

The Study on the Improvement Measures for Electric Power Generation Facilities in Java-Bali Region in the Republic of Indonesia

Planning of Periodical Inspection Period Year 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015

Unit 1 AI AI GI AI AI MO AI AI AI GI Unit 2 MO AI AI AI GI AI AI MO AI AI Unit 3 AI MO AI AI AI AI GI AI AI AI

AI; Annual Inspection Source; PJB data GI; General Inspection MO; Major Overhaul

Regarding AI, the unit operation hours between AI and previous AI were 4,431 hours as mentioned in the unit 3 AI report in 2004. And the MO interval was 7 years as mentioned in the unit 1 MO report in 2004.

3) Required Days for Periodical Inspection

Required days were 6 days for AI as mentioned in the unit 3 reports in 2004 and 40 days for MO as mentioned in the unit 1 report in 2004 respectively.

Regarding the inspection hours for AI, required hours is much reduced in 2005 by the big effort of Brantas Office. This effort is useful to improve the unit operation availability

3.2.2.9. Organization of Operation and Maintenance Management

The organization of operation and maintenance is basically same for all power stations. The organization is as follows: Operation team; The power station is controlled and supervised in full time by three(3)

shifted four(4) groups. The operation staff is stationed in the control room and the powerhouse.

The staff in the control room controls the unit start and stop, output, voltage, and supervises the unit’s condition. And the staff in the power house supervises the whole equipment in the power station.

Maintenance team; The maintenance team basically consists of three (3) groups such as

“Mechanical”, “Electrical” and “Control and Instrument” and weekly inspection, monthly inspection, periodical inspection are planned and inspected by the staff. Also repairing work is carried out by the staff.

The periodical job rotation between operation staff and maintenance staff is generally rare.

Periodical job rotation between operation staff and maintenance staff is considered useful method for skill up the all party. It is recommended periodical rotation of staff.

Final Report 3 - 128


(1) Saguling

Saguling power station is one of the largest scale hydro power station in Indonesia with the maximum output 700 MW and belongs to the “UNIT BUSINESS GENERATION SAGULING” (“UNIT BISNIS PEMBANGKITAN SAGULING”) of INDONESIA POWER which manages eight (8) hydro power stations with the total number of staffs of 495 in 2004. The number of staff involved in the operation and maintenance for Saguling is as follows:

Engineering staff; 17 Operation staff; 56 Maintenance staff; 56

The organization of “UNIT BUSINESS GENERATION SAGULING” (“UNIT BISNIS PEMBANGKITAN SAGULING”) is shown in Appendix HY-13.

(2) Cirata

Cirata power station is the largest hydro power station in Indonesia with the maximum output 1,000 MW and belongs to the “UNIT MAINTENANCE CIRATA” (“UNIT PEMELIHARAAN CIRATA”) of PJB. The number of staff related to operation and maintenance for Cirata is 192 staff as follows: Engineering staff; 4 Operation staff; 57 Maintenance staff; 51 The organization of “UNIT MAINTENANCE CIRATA” (“UNIT PEMELIHARAAN CIRATA”) is shown in Appendix HY-14.

(3) Soedirman

Soedirman power station has the maximum output 180 MW and belongs to the “UNIT BUSINESS GENERATION MRICA” (“UNIT BISNIS PEMBANGKITAN MRICA”) of INDONESIA POWER which manages 12 hydropower stations with the total of staff of 472. Regarding the operation and maintenance staff related to Soedirman, age composition covers from twenty (20) years old to fifty (50) years old and two (2) years experience is the shortest among them. Concerning the engineering section, ages composition covers from forty nine (49) to fifty four (54) years old and all of them belong to a senior engineer. Considering the above age composition, staff distribution seems to be appropriate for operation and maintenance of the power station. Number of staff, age grouping, experience years, qualification and duties of each section related to Soedirman are shown in the following table.

3 - 129 Final Report


Main Data for Engineering, Maintenance and Operation 1 Engineering 5

Experience year min. 20 Age Varied from 49-55 Qualification Expert in O/M design, machinery, electrical Duties Adviser in O/M design, quality, supervisor

2 Operation 29 Experience year min. 2 Age Varied from 20-50 Qualification Expert in operation Duties Operation PLTAPB. Soedirman and power trading

3 Maintenance 25 Experience year min. 2 Age Varied from 20-50 Qualification Expert in maintenance electrical, mechanical, control instrument Duties Maintenance electrical, mechanical, control instrument equipment

4 Planning & Monitoring 16 Experience year min. 2 Age Varied from 28-53 Qualification Expert in planning & monitoring operation and maintenance Duties Planning & monitoring operation and maintenance

Source INDONESIA POWER data The organization of “UNIT BUSINESS GENERATION MRICA” (“UNIT BISNIS PEMBANGKITAN MRICA”) is shown in Appendix HY-15.

(4) Sutami

Sutami power station has the maximum output 105 MW and belongs to the" UNIT MAINTENANCE BRANTAS” (“UNIT PEMELIHARAAN BRANTAS”) of INDONESIA POWER which manages 12 hydro power stations with the total staff of 348 including outsourcing staff of 37. For maintenance work, there are four (4) outsourcing staff. Age grouping and experience grouping of each section related to Sutami is shown in the following tables and figures.

Age Grouping

Age 50 ~ 59 40 ~ 49 30 ~ 39 20 ~ 29

Number of staff 13 4 4 0

Source; PJB data

Experience Grouping Experience year >30 20 ~ 29 10 ~ 19 <9

Number of staff 1 8 12 0

Source; PJB data



0

5

10

15

50～59 40～49 30～39 20～29Age

Num

ber o

f the

Sta

ff

0

5

10

15

>30year 20~29 10~19 <9yearExperience

Num

ber o

f the

Sta

ff

Sutami Age Grouping of Staff Sutami Experience Grouping of the Staff

Regarding the staff profile, the average age is relatively high. Therefore new assignment and training of younger age group seems to be necessary from the view point of technology transfer from older generation to younger generation. Concerning the experience, present condition is ideal. However considering the future, it is important for new assignment of younger age group staff step by step to avoid the discontinuity of generation.

The organization of “UNIT MAINTENANCE BRANTAS” (“UNIT PEMELIHARAAN BRANTAS”) is shown in Appendix HY-16.

3.2.2.10. Integrated Reservoir Operation on Citarum River For integrated reservoir operation, rule curves for reservoir operation have been made every year of the existing three (3) reservoirs: Saguling, Cirata and Jatilhur on the Citarum River. These three reservoirs have been operated following the rule curves to efficiently use water resources of the Citarum River without any conflicts among stakeholders. The rule curves are made by a coordination committee headed by SPK-TPA: Sekretariat Pelaksana Koordinasi Tasa Pengatura Air (Secretariat of Water Management Coordination). Members of the committee are Dinas Pengoriou Jawa Barat, Pusat Penelition & Peugemerongon Air, Badan Meteorology dan Geophisika (Meteorology and Geophysics Agency), PT. PLN (Persero) P3B, PT. Indonesia Power Saguling, PT. PJB Cirata, and Perusahaan Umum Jasa Tirta II (PJT II). Monthly coordination meeting is held gathering the members. In the first meeting of the year in January, three rule curves to be applied in normal, wet and dry year are announced. In the monthly meeting, members will discuss and decide which rule curve must be employed in the next month.



(1) Reservoir Simulation

A reservoir simulation study of the three reservoirs is actually carried out by Pusat Penelition & Peugemerongon Air under the ministry of Public Works so as to establish rule curve every year. The simulation software is programmed to meet water demand at the most down stream reservoir: Jatilhur, which should release the water for irrigation and industrial/residential water supply in the downstream area as well as power generation with the priority below;

1st: Municipal water supply 2nd: Irrigation requirement 3rd: Water requirement for industry 4th: Flushing for cleaning of channels in the cities 5th: Power generation at the three reservoirs

Basic equation of the simulation software is presented below; AS = AM – (AK + E) or AK = AM –AS – E Where, AS : storage volume of reservoir (storage: +, release: -) AM : inflow water AK : outflow water E : water loss/evaporation

In the simulation the initial reservoir water level in January is set up at the same water level of the actual water level in the previous month: December and the water level in the final month: December is assumed to be equal or higher than that in the initial month: January. Inflow patterns for the simulation are made on the alternatives assuming climate conditions: normal, wet and dry years. Inflow of the normal, wet and dry year is assumed by calculation with frequency analysis of log Normal Type III on the basis of monthly discharge record in the Citarum River from 1988 to the previous year.

(2) Discussion on Present Operation

At the power oriented reservoir, concepts of efficient reservoir operation are to keep higher water level in a reservoir as much as possible and to minimize spilled water through a spillway. Based on the concepts, the reservoir is basically operated to be full just before dry season and to rise the water level after the beginning of the next wet season for efficient use of the reservoir water.

Regarding spilled water, very small volume of the reservoir water has been spilled out in Saguling according to the daily operation record from 1993 to 2003 as shown in Figure 3.2-3. The water volume of 160, 91, 7 and 27 million m3 was spilled out through the spillway non-gate section in 1993, 1994, 2001, and 2002 respectively, which are equivalent to 4.5, 2.9, 0.2 and 1.1 % of each annual inflow volume. In case of Cirata, although no



daily record was available, the spilled water might be small or none because we heard from the operators at site that no spillway gate operation has been made in these years.

There is a reason why so small volume of spilled water in Saguling and Cirata and the reason can be seen in the following reservoir operation record. Namely, it was rare that the reservoir water level reaches high water level since commencement of operation.

600

610

620

630

640

650

1985 1990 1995 2000 2005

Res

ervo

ir W

L (E

l.m)

0

100

200

300

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500

600

700

Mon

thly

Dis

char

ge (m

3/s)

Reservoir Water Level (El.m) HWL LWL Inflow (m3/s) Outflow (m3/s) Reservoir Operation at Saguling

180

190

200

210

220

230

1985 1990 1995 2000 2005

Res

ervo

ir W

L (E

l.m)

-

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1,000

Mon

thly

Dis

char

ge (m

3/s)

Reservoir Water Level (El.m) HWL LWL Inflow (m3/s) Outflow (m3/s)

Reservoir Operation at Cirata

There may be several reasons why the reservoir water level does not reach high water level. The followings might be ones of them.

Reason 1 : Decrease of inflow

The following figures show annual inflow volume and its moving average for 5 years of Saguling and Cirata from the commencement of the operation. As shown in the figures, inflow at Saguling and Cirata is tending downward from around 1995 or 1996. In case of Saguling, annual mean inflow in 2003 is 60 m3/s, which is almost half of 136 m3/s in 1992.



Saguling

-

1,000

2,000

3,000

4,000

5,000

6,000

7,000

1986

1988

1990

1992

1994

1996

1998

2000

2002

2004

Ann

ual I

nflo

w V

olum

e (m

illio

n m

3)

A nnual Inflow Volum e 5 year Average

Cirata

-

1,000

2,000

3,000

4,000

5,000

6,000

7,000

1988

1990

1992

1994

1996

1998

2000

2002

2004

Ann

ual I

nflo

w V

olum

e (m

illio

n m

3)

Annual Inflow Volum e 5 year Average

Reason 2 : Increase of water requirement in the downstream area

Because of increase of population and development of industries and agriculture in the downstream area, required water volume might be larger than that just after completion of Saguling and Cirata. This may be one of reasons although no data of the water requirement in the downstream area is available except the data of 2005. More data is necessary to make sure this reason.

Figure 3.2-4 shows rule curves with predicted inflow and simulated outflow in normal year and actual reservoir water levels with actual inflow and outflow from 2001 to 2005. In this figure, the following can be pointed out.

1) Effort of water storage in the beginning of wet season

As previously mentioned, the water level should keep as high as possible after coming into wet season. For example, in November 2001, water level in Saguling and Cirata reservoir rose by plentiful inflow. This water level should have kept high with less volume of outflow in the next month: December.

2) Excessive water use than required by simulation

Larger volume of water use (actual outflow) than water volume required by simulation is seen, for example dry season in 2001 and 2002 in Cirata. If the water should have not been used so much, the reservoir water level could remain higher water level for longer period although the reservoir water might have been operated based on instruction of P3B. *1)

*1): According to P3B, each dam must release their water from their reservoir to meet downstream water requirement in case water shortage is expected in the downstream area. The volume of water to be released from each reservoir is counted in proportion to the effective capacity of each reservoir. On the contrary, in the case plentiful inflow is expected, each dam can reserve the some amount of inflow in proportion to the effective reservoir capacity after fulfillment of the downstream water requirement. P3B called this principal “Equal Sharing”. The above mentioned “excessive water use than required by simulation” might be caused by this Equal Sharing in case of water shortage.



3) Rule curves set up at lower water level

It can be seen in Figure 3.2-4 that the both power stations have made good effort to follow the rule curves. Therefore, if the rule curves are set up at higher water level than ones presented in Figure 3.2-4, more energy could have been generated by the same volume of inflow and out flow with higher hydraulic head and higher efficiency of generator and turbine.

(3) Recommendation

Simulation and review of the rule curves at intervals of 10 or 15 days are recommendable to fit the rule curves to the actual situation timely and keep high reservoir water level as much as possible.

YearTotalInflow

(x106 m3) (x106 m3) (%)1993 3,538 160 4.5% 3,075.2

1994 3,137 91 2.9% 2,729.8

1995 2,817 0 0% 2,254.9

1996 3,030 0 0% 2,504.0

1997 1,737 0 0% 1,325.9

1998 3,601 0 0% 3,131.8

1999 2,645 0 0% 2,319.1

2000 2,463 0 0% 2,272.5

2001 3,454 7 0.2% 2,959.3

2002 2,450 27 1.1% 2,313.3

2003 1,901 0 0% 1,780.2

2004 2,182 1,990.5

Total 32,954 284 0.86%

Spilled Water through Spillway AnnualGeneration

(GWh)

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

1993

1994

1995

1996

1997

1998

1999

2000

2001

2002

2003

2004

Dis

charg

e V

olu

me (

millio

n m

3)

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

Anual Energ

y (

GW

h)

Total Inflow Outflow through Spillway Annual Energy

no record

Figure 3.2-3 Inflow and Spilled Water at Saguling Reservoir



2004

Sag

ulin

g

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urve

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ctua

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Inflo

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Fig

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3.2-

4

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ata

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3.3. Confirmation of Current Status and Recommendation on Improvement Relating to the Existing Power Facilities 3.3.1. System Stability

The length of Java Island from the east end to the west is about 1,000 km. The power system is mainly configured by long-distance Northern 500 kV transmission line (2 circuits) which is connected from Suralaya P/S in the western edge of Java to Paiton P/S in the eastern edge, as of November 2005. A large scale demand area is concentrated in the western region in Java, such as Jakarta. On the other hand, in the eastern region, there are many generators with large capacity like Paiton and Gresik. That is why a power flow in the Northern 500 kV transmission line is heavy toward the west and the capacity of the transmission line is restricted by the system stability. Therefore, generators in the east can not generate electric power at full capacity. Two sections of 500 kV transmission line are restricted, from Ungaran S/S to Mandirancan S/S and from Mandirancan S/S to Bandung Selatan S/S. The allowable limit of the transmission capacity is estimated as 1,800 MW and the average power flow in 2005 was 1,135 MW. 500 kV power flow in the peak load of Java in 2004 is shown in Figure 3.3-1.

Source; EVALUASI OPERASI SISTEM TENAGA LISTRIK JAWA-BALI TAHUN 2004

Figure 3.3-1 500kV Power Flow in the Maximum Load of Java 2004 (September 28th, 18:30)

Southern 500 kV transmission line with two circuits is under construction (Refer to Section 2.1.2) as a measure for the system stability. The early completion is expected 6.

6 The construction of southern 500kV transmission line was completed in June 2006.



3.3.2. Existing Transmission, Substation Facilities and Availability

(1) Outline of facilities

1) Transmission line

The outline of the transmission line facilities is shown in the following table. The number in the table is the total of overhead wires, underground cables, and submarine cables.

Outline of Transmission Line Facilities

Length of transmission line (km)

Number of line

Year 500kV 150kV 70kV Year 500kV 150kV 70kV 2001 2,849 10,475 3,935 2001 51 626 226 2002 3,128 10,581 3,935

2002 34 633 226 2003 3,532 11,209 3,861 2003 38 639 206 2004 3,578 11,195 3,765 2004 38 664 224

Source; PLN P3B STATISTIK 2004

2) Substation facilities

The outline of the substation facilities is shown in the following table.

Outline of Substation and Transformer Number and capacity of transformer at each voltage

500/150kV 150/70kV Year Number Capacity

(MVA) Number Capacity (MVA)

Number of substation at each voltage Year 500kV 150kV 70kV

2001 18 264 85

2002 2001 30 14,500 68 3,966

19 273 86

2003 2002 30 14,500 69 3,966

2003 32 15,500 59 3,462

2004

20 287 87

2004 32 15,500 60 3,522

Source; PLN P3B STATISTIK 2004 20 290 115

As a result of the site investigation of 500 kV substation by the study team, the latest 500 kV facilities such as Gas Insulated Busbar (GIB) and Gas Insulated Switchgear (GIS) are installed in Paiton substation. On the other hand, in the substation of the suburbs of Jakarta, the old type air blast circuit breakers which have been already discontinued by manufactures are installed. In September 2002, there was a large scale blackout because the old type air blast circuit breaker which should have been operated in the accident of 500 kV transmission line was not able to be worked. Spare parts of this type circuit breaker are few and it is recommended that the old type circuit breakers are replaced with new type gas circuit breakers.



(2) Availability

The following tables show the number of transmission lines which are not satisfied with N-1 criteria and the number of transformers which are categorized in each availability.

In 500 kV transmission line, only the section which is restricted by system stability (described in Section 3.3.1) is not satisfied with N-1 criteria. As for 500/150kV transformers, the ratio of transformers whose availability is over 60% is 90% or more, therefore, almost all transformers do not meet N-1 criteria.

In addition to these conditions, considering increase of demand in the future, transmission lines and transformers have to be newly installed in the place where they are not satisfied with N-1 criteria as soon as possible.

Load of Transformer

500/150kV 150/70kV Availability (× %) Number Capacity

(MVA) Number Capacity (MVA)

<20 －－－－ 20 < = × <40 1 250 3 170 40 < = × <60 2 750 10 760

Transmission Line not Satisfied with N-1 Criteria

Voltage (kV)

Number of line

Distance(km)

500 2

60 < = × <80 8 4,000 21 1,253

567

150 35

80 < = × <100 21 10,500 19 984 × > = 100 －－

977

70 14

0 0

Total 32 15,500 54 3,274

327 Source; EVALUASI OPERASI SISTEM

TENAGA LISTRIK JAWA-BALI TAHUN 2004

Source; EVALUASI OPERASI SISTEM TENAGA LISTRIK JAWA-BALI TAHUN 2004, etc.

3.3.3. Number of Service Interruptions

In 2004, there are 247 times of service interruptions (except for distribution) and total energy which were not supplied are 7,718 MWh. In addition, service interruptions with load shedding over 150MW occurred 11 times.

Number of Service Interruptions and Energy not Supplied (MWh) Year Number of service interruption Energy not supplied (MWh)

2003 285 7,530

2004 247 7,718

Source; EVALUASI OPERASI SISTEM TENAGA LISTRIK JAWA-BALI TAHUN 2004

The following figure shows the number of service interruptions by source of faults. Regardless of year, number of equipment accidents is large by far, (account for 46%) compared with the number of other causes. The accident caused by human error is not so many.



0

20

40

60

80

100

120

140

160

Nature

/Weather

Equipment Animal Human

error

Kite Over load Tree Relay

Malfunction

Others

2001 2002 2003 2004

Source; PLN P3B STATISTIK 2004

Figure 3.3-2 Service Interruptions by Source of Faults (times)

The number of service interruptions due to transmission line and transformer faults is investigated. The following figures show the number of service interruptions of transmission lines per 100 km circuit. and the number of service interruptions of transformers per unit.

0

0.5

1

1.5

2

2.5

3

Times/100kmc

2001 2002 2003 2004

500kV 150kV 70kV

0

0.05

0.1

0.15

0.2

0.25

0.3

0.35

0.4

Times/Unit

2001 2002 2003 2004

500kV 150kV 70kV

Source; PLN P3B STATISTIK 2004 Source; PLN P3B STATISTIK 2004 Figure 3.3-3 Number of Service Interruptions Figure 3.2-4 Number of Service Interruption of Transmission Line per 100 km Circuit of Transformer per Unit

According to the above figures, in 500 kV facilities, the number of service interruptions due to transmission line faults is small, but the one due to transformer faults is increasing year by year. If service interruption caused by a fault in 500 kV facilities occurred, it is likely to cause a large scale blackout. As mentioned in Section 3.3.2, the number of 500 kV transformers whose availability is over 80% are twenty one out of thirty two. Therefore, 500 kV transformer accidents have a significant impact on the society. In fact, the amount of energy not supplied in 2004 increased by 2.5% from the previous year 2003, although the



number of service interruptions in 2004 is 13% smaller that in 2003. Considering these situations as well as the availability described in Section 3.3.2, 500 kV transformers have to be expanded.

3.3.4. Frequency

According to ATURAN JARINGAN Jawa-Madura-Bali, which defines rules and procedures in order to assure a certain level of reliability and effective operation, the allowable range of normal frequency should be regulated within 50±0.2 Hz. If frequency falls under 49.5 Hz by the dropout of generators and etc., automatic load shedding is carried out along with quantity and velocity of dropped frequency. The generators which are supposed to carry out LFC operation are a large scale hydropower like Saguling, Cirata and large scale thermal power stations like Paiton, Suralaya, and Gresik. According to the information acquired in the site investigation, generators owned by IPPs and PLN (Muara Tawar 3.1, 3.2, 3.3, 4.1, 4.2, 4.3) are operated with governor free mode, but generators owned by IP and PJB do not carry out governor free operation. Therefore, it is IPP and some of Muara Tawar that control frequency in short period. ATURAN JARINGAN Java-Madura-Bali regulates that all power stations have to be operated with governor free mode. In addition, P3B UBOS instructed each power station to operate with governor free mode. In order to keep frequency stable, it is recommended that these generators of IP and PJB are operated with governor free. In 2004 Java-Bali system, the number of times which fell down under 49.5 Hz, for an example, caused by generator dropout were three hundred ten times. In twenty times out of them, load shedding was executed. In addition, there were twenty eight times that system frequency exceeded 50.5 Hz.

3.3.5. Voltage In Java-Bali system, the regulation of voltage depends on the control of reactive power from generators, on and off of facilities which control reactive power such as condensers and reactors, and on-load tap changing transformers. The acceptable fluctuation range of 500 kV voltage is within ±5% against the nominal voltage. According to EVALUASI OPERASI SISTEM TENAGA LISTRIK JAWA-BALI TAHUN 2004, which describes evaluation of system operating performance in Java-Bali 2004, the voltage in fifteen substations out of twenty all 500 kV substations dropped below the lower limit (475 kV) at maximum during one month. Especially in Mandirancan substation the voltage went down to 435 kV. On the other hand, the voltage had been kept



over 475 kV at five substations located in the eastern part of Java without falling below the lower limit. The reason is considered that large scale generations are concentrated in the east. Figure 3.3-5 shows a power flow drawing in peak load of 2007 when southerly 500 kV transmission will be operated. The voltage in all 500 kV substations is kept within permissible range. The reason is considered that loss of reactive power will decrease due to the completion of 2 routes (northerly and southerly) in 500 kV. On the contrary, it is concerned that voltage will rise at the time of light load after completion of southerly 500 kV transmission line. But at the site investigation on November 2005, the study team confirmed that reactors were installed at substations like Paiton, Kediri, Klaten, New Tasikmalaya, and so on in southerly 500 kV system.

Capacity [MW](Voltage [kV])

SubstationPower station

Source; Rencana Usaha Penyediaan Tenaga Listrik 2006-2015

Figure 3.3-5 Power Flow Drawing in 500 kV Java-Bali (2007)



4. REHABILITATION, MODIFICATION AND REPOWERING PLANS BASED ON EXISTING FACILITIES

4.1. Thermal Power Stations

This section covers the detailed further study on the final repowering plans proposed and decided at the 2nd Steering Committee. The final plans are listed again on the Table 4.1-1 hereunder.

Table 4.1-1 Final Plans for Further Study at 2nd Steering Committee Final Plans Proposed Concepts

T.Lorok PLTU Repowering Plan

One block of C/C conversion (PLTGU 1-1-2) of PLTU #1 & #2 Steam Turbines

Grati BLK-II PLTG Repowering Plan

One block of C/C conversion (PLTGU 3-3-1) of PLTG BLK-II Gas Turbines

Gilimanuk PLTG Repwoering Plan

One block of C/C conversion (PLTGU 1-1-1) of PLTGU Gas Turbine

UBP Semarang Oil Reduction Plan

One block of C/C Installation (PLTGU 1-1-1) consisting of one GT, one HRSG and one ST, instead of T.Lorok PLTU #1 & #2, Sunyaragi and Cilacap PLTGs stopping

UBP Grai/Perak Oil Reduction Plan

One block of C/C conversion (PLTGU 3-3-1) combining existing three (3) Grati GTs, new three (3) HRSGs and new one ST, instead of Perak #3&#4 stopping

UBP Bali Oil Reduction Plan

One block of C/C conversion (PLTGU 1-1-1) combining existing Gilimanuk GT, a new HRSG and a new ST, instead of Pesanggaran PLTG #1 & #2 and PLTD #1-#4

4.1.1. Technical Study 4.1.1.1 Original Three (3) Repowering Plans

(1) Tambak Lorok PLTU #1 & #2 Combined Cycle Conversion Plan

This repowering plan consists of the existing two (2) steam turbines of T.Lorok PLTU #1&#2, a newly installed F-type gas turbine and a newly installed HRSG (Heat Recovery Steam Generator). The gas turbine and the HRSG are supposed to be installed at the site after the demolition of PLTU #1 & #2 boilers. Tambak Lorok PLTU #3 is now under gasification and up-rating rehabilitation work based on the gas supply agreement, however, the forecast on possible gas supply expansion plan is unknown at this moment. The gas turbine shall be of gas/HSD dual firing just same as the current PLTGU Block I & Block II. The basic design figures of the main components of the plan are as follows:- ◊ GT& Generator ; F-Type Gas Turbine, 240 MW Capacity at 30°C

Gas/HSD Dual Firing, DLN ＊ 1 for Gas & Water Injection for HSD＊2

282 kVA Generator and Step-up Transformer

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◊ HRSG ; One Drum Type, Steam Condition 88 kg/cm2g × 510°C

◊ Existing STs & Generators ; Single-flow Condensing Type Steam Turbines, 50MW Capacity × 2 sets Rehabilitation of Turbine Rotor and Renewal of Governor

◊ Existing ST Generators & Step-up Transformers ;

Capacity 60 kVA × 2 sets, Rehabilitation of Stator Coil Rewinding

◊ Instrument & Control Systems ; C/C Operation System

◊ Major BOP; BFPs (Boiler feedwater Pumps), Steam & Water Piping and Valves

◊ Electrical Equipments & S/S ; Conventional Type (150kV Connection) *1) DLN: Dry Low NOx Combustion *2) HSD: High Speed Diesel Oil

A F-type gas turbine of 240 MW class at HSD firing emits larger volume of flue gas compared with the existing two (2) 50MW boilers with MFO (Marine Fuel Oil) firing, but by adopting DLN combustors for gas firing and water injection combustors for HSD firing, pollutants like NOx, SOx, particulates, etc. in the flue gas are predicted to be lower, compared with the existing MFO firing boilers. The cooling water system including the existing PLTU #1 & #2 condensers remains unchanged and can be used for the plan. Then, there will be no major influence on the environmental impact assessment (EIA).

The plan is capable of the following performance: ◊ Gas Firing Performance ・GT Output 236.9MW ・ST Output 50.7MW × 2 ・Plant Output 338.3MW ・Plant Thermal Efficiency 51.6% (LHV) ◊ HSD Firing Performance ・GT Output 206.4MW ・ST Output 40MW × 2 ・Plant Output 286.4MW ・Plant Thermal Efficiency 47% (LHV)

The repowering output of the plan for oil firing is calculated as 186.4 MW as follows; PLTGU Output = 206.4MW + 40MW × 2 = 286.4MW PLTU Output = 50MW × 2 = 100MW Repowering Output = 286.4MW－100MW = 186.4MW

The EPC cost of the above repowering plan is estimated as 159.3 Million US$. This cost includes the rehabilitation expenditure of PLTU #1& #2 steam turbines.

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The summary of the repowering plan; ① Repowering; 186.4MW ② EPC cost; 159.3 Million US$

(2) Grati Block II PLTGs Combined Cycle Conversion Plan

This repowering plan consists of the existing three (3) gas turbines of Grati Block II PLTG #1- #3, a newly installed steam turbine and newly installed three (3) HRSGs (Heat Recovery Steam Generators). The steam turbine and the HRSGs to be designed identically as those of Block-I are supposed to be installed at the site already prepared next to the current Block I units.

The basic design figures of the main components of the plan are basically same as Block I and are as follows:- ◊ Existing GT &

Generator ; 701D-Type × 3 sets, Gas/HSD Dual Firing Capacity 112.45MW for Gas, 100.75MW for HSD at 32°C Generator & Step-up Transformer 135 kVA × 3 sets

◊ HRSG; Two Drum Type × 3 sets, 75 kg/cm2g × 505°C & 5.2 cm2g ×176°C

◊ ST & Generator; HP/LP Tandem Compound Condensing Type × 1 set, Capacity 189.5 MW, Condenser Vacuum 0.085P Generator/Step-up Transformer 225 kVA

◊ Instrument & Control Systems;

C/C Control System

◊ Major BOP; Intake/Discharge Facilities, CWPs (Cooling Water Pumps) & CW, Piping, BFPs (Boiler Feedwater Pumps)

◊ Station Electrical Equipments & S/S;

Conventional Type (150kV Connection)

After converted into the C/C plant conversion, the existing three (3) gas turbines remain operating same as up to now with HSD (High Speed Diesel Oil) firing. Then, the total flue gas volume and their pollutants in the flue also remain same as up to now and only the stack gas temperature will go down after through the HRSG heat exchanging, but its temperature level will be just same as Block I. The cooling water system for the plan is newly required but the overall cooling system of Grati Power Station originally had been planned for Block II and even future Block III of the same capacity of 500MW class C/C plant. Then, there will be no difficulty for the installation of the cooling water system of the plan. Under the above situation, there will be no major influence on the environmental impact assessment (EIA) with the repowering plan.

The plan is capable of the identically same performance of the Block II as follows; ◊ Gas Firing Performance

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・GT Output 112.45MW × 3 ・ST Output 189.5MW ・Plant Output 526.85MW ・Plant Thermal Efficiency 49.8% (LHV) ◊ HSD Firing Performance ・GT Output 100.75MW × 3 ・ST Output 159.58MW ・Plant Output 461.83MW ・Plant Thermal Efficiency 47.1% (LHV)

The repowering output of the plan for oil firing is 159.58MW as ST output. The EPC cost of the above repowering plan is estimated as 159.3 Million US$.

(3) Gilimanuk PLTG Combined Cycle Conversion Plan

This repowering plan consists of the existing gas turbine of Gilimanuk PLTG, a newly installed steam turbine and a newly installed HRSG (Heat Recovery Steam Generator). The steam turbine and the HRSG are supposed to be installed at the site next to the existing PLTG house, but, the site area needs to be expanded for newly installed facilities by purchasing additional land space. It is reminded that the site is close to the National Park Area.

The current site map is shown as Figure 4-1-1 Gilimanuk PLTG Layout.

9 10

7 8

Figure 4.1-1 Gilimanuk Power Station Layout

As shown, the site is located next to the existing switchyard of 150 kV receiving power from the submarine transmission line from Java Island. Moreover, the site is located in the

Final Report 4 - 4


inland area about 1 km away from the nearest seashore and on the about 4m height from the seawater level. Then, it is thought to be very difficult to adopt sea water for condenser cooling. Then, a dry cooling system by air cooled condenser (ACC) type is proposed for the plan.

The basic design figures of the main components of the plan are as follows:- ◊ Existing GT & Generator ; 13E2-Type × 1 set, HSD Firing (Originally Gas/HSD

Dual Firing) Capacity 133.8 MW for HSD Generator & Step-up Transformer 170 kVA × 1 set

◊ HRSG; Two Drum Type × 1 set, 70 kg/cm2g × 510°C & 5.2kg/cm2g × 155°C

◊ ST & Generator; T/Compound Condensing Type × 1 set Capacity 67 MW, Condenser Vacuum 0.15 kg/cm2

Generator/Step-up Transformer 80 kVA

◊ Air Cooled Condenser*; L 52m × W 50m × H 34m, Fan/Motor 149kW × 16 sets

◊ Instrument & Control Systems; C/C Control System

◊ BOP; ST Exhaust Piping, CWPs & CW Piping, BFPs & FW Piping



The plan for HSD firing is capable of the following performance: ◊ GT Output 133.0MW (C/C operation) ◊ ST Output 67.0MW ◊ Plant Output 200.0MW ◊ Plant Thermal Efficiency 49.6% (LHV) ◊ GT Simple Cycle Efficiency 33.0% (LHV) ◊ Condenser Vacuum 0.15ata

The repowering output of the plan is 67.0MW as the steam turbine output. The EPC cost of the above repowering plan is estimated as 66.4 Million US$. This cost includes the installation expenditure of ACC (Air Cooled Condenser) system, but, does not include the purchasing expense of the land for the site extension.

As mentioned above, the existing site is located about 1 km away even from the nearest seashore. Then, without the feasibility study of usual sea water cooling system a dry ACC (Air Cooled Condenser) system is proposed here in this report. It seems necessary, however, whether the usage of sea water cooling system for the plan will be feasible or not by executing a further feasibility study. In this case the following items should be considered. i) Applicability of Sea Water Quality Standards, especially temperature rise limitation

(<2.0°C) and temperature effect to mangrove and coral ii) Location of the steam turbine and condenser, especially siphon limit, steam pressure

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drop from the HRSG supposed to be installed near to the existing gas turbine unit and relation with National Park area.

4.1.1.2. Oil Reduction Plans

(1) Concept of Oil Reduction Plans

The basic idea of oil reduction plans is based on the followings;

◊ Reduce Oil Consumption Totally per UBP*

◊ Stop the Operation of the Existing Less Heat Efficient Simple Cycle Gas Turbines (PLTGs) and/or Steam Plants (PLTUs) within the UBP’s management territory

◊ Instead of above Stopping Units (as the alternative plant), ① To convert the Existing GTs to a Higher Efficient Combined Cycle Plant, this means a

Conversion-type Repowering Plan, or, ② To install a newly Higher Efficient Combined Cycle Plant, this means a Scrap &

Build-type Repowering Plan

◊ For above ①, Oil Reduction will happen by the Oil Consumption of the Existing Stopping Steam Plants because oil consumption of the gas turbine remain constant between before and after the conversion.

◊ For above ②, Oil Reduction will happen by the difference of oil consumption of the Existing Stopping PLTGs/PLTUs and the newly Installed C/C plant.

◊ GHG (Greenhouse Gas) Reduction based on above Oil Reduction will be calculated

*UBP: Unit Bisnis Pembangkitan- Unit Business (Power) Generation. UBP manages and controls several power stations.

Oil reduction, mainly HSD (High Speed Diesel Oil) reduction calculated above is considered to be real and will contribute to the balance of payments per UBP unit and the global warming issue in spite of whether or not the plan will be approved as CDM (Clean Development Mechanism) project.

(2) UBP Semarang Oil Reduction Plan

UBP Semarang manages and controls the following thermal power stations and their power units.

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Table 4.1-2 UBP Semarang: Thermal Power Station and Power Units Installed Capacity Available Capacity PLTU Tambak Lorok Unit #1 50.0MW 45.0MW Unit #2 50.0MW 45.0MW Unit #3 200.0MW 200.0MW Sub Total 300.0MW 290.0MW PLTGU Tambak Lorok Block I GTG 1.1 109.65MW 105.0MW GTG 1.2 109.65MW 105.0MW GTG 1.3 109.65MW 105.0MW ST 1.0 188.0MW 170.0MW Block II GTG 2.1 109.65MW 105.0MW GTG 2.2 109.65MW 105.0MW GTG 2.3 109.65MW 105.0MW ST 2.0 188.0MW 170.0MW Sub Total 1,033.90MW 970.0MW Sunyaragi PLTG Unit #1 20.0MW 18.0MW Unit #2 20.0MW 18.0MW Unit #3 20.0MW 18.0MW Unit #4 20.0MW 18.0MW Sub Total 80.0MW 72.0MW Cilacap PLTG Unit #1 29.0MW 20.0MW Unit #2 26.0MW 20.0MW Sub Total 55.0MW 40.0MW

Tambak Lorok PLTU/PLTGU

Cilacap PLTG

Sunyaragi PLTG

Figure 4.1-2 UBP Semarang Three Power Stations

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Among the above table less efficient units are Tambak Lorok PLTU #1&#2, Sunyaragi PLTG #1- #4 and Cilacap PLTG #1& #2.

Then, the following oil reduction scheme will be born; ◊ Less Efficient Oil Firing Plants to be stopped T.Lorok PLTU #1& #2 (MFO Firing) 50MW × 2 units Sunyaragi PLTG #1- #4(HSD Firing) 20MW × 4 units Cilacap PLTG #1& #2(HSD Firing) 26MW + 29MW Total Capacity of above Stopping Plants 235MW ◊ An Alternative Combined Cycle Plant to be newly installed F-type GT+HRSG+ST/Generator PLTGU (1-1-1) C/C Output at HSD Firing 307.4MW ◊ Repowering & Oil Consumption Reduction to be obtained Repowering (307.4 – 235 = 72.4) 72.4MW Oil Reduction PLTGU Consumption < Stopping Plants Consumption

Instead of using the existing PLTU #1 & #2 steam turbines for the repowering plan proposed in Item (1) of Section 4.1.1.1, here is newly proposed even a ST/Generator installation of larger capacity for C/C better performance. Then, the cooling system for the larger capacity of condenser shall be newly installed, including water intake and discharge system. This means the increase of condenser warm water discharge and will possibly require a new EIA (Environmental Impact Assessment). As mentioned before, Tambak Lorok PLTU #3 is now under gasification and up-rating rehabilitation work based on the gas supply agreement, however, the forecast on possible gas supply expansion plan is unknown at this moment. The gas turbine shall be of gas/HSD dual firing just same as the current T.Lorok PLTGU Block I & Block II.

The basic specification data of the alternative C/C Plant (1-1-1) is as follows; ◊ GT& Generator ; F-Type, Capacity 240MW at 30℃

Gas/HSD Dual Firing with Low NOx Combustor Generator & Step-up Transformer 285 kVA

◊ HRSG; RH & Three Drums Type, Steam Condition 110kg/cm2g × 538/566°C

◊ ST& Generator; RH T/C Condensing Type, ST Capacity 133MW, Generator & step-up Transformer 160kVA


◊ BOP; Intake & Discharge Water Facilities, Steam & Feedwater Piping and Valves

◊ Electrical Equipments & S/S; Conventional Type (150kV Connection)

This combined cycle PLTGU (1-1-1) will be proposed to be installed at the open space area now being used as the football field next to the existing PLTU #3 unit.

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The performance data of the alternative C/C Plant will be as follows; Gas Firing GT Output 236.9MW ST Output 133.0MW Plant Output 369.9MW Plant Efficiency 56.4% (LHV) HSD Firing GT Output 206.4MW ST Output 101.0MW Plant Output 307.4MW Plant Efficiency 50.4％ (LHV）

Whereas, the performance data of the stopping units are supposed to be as follows; T.Lorok Output 50MW×2 (after rehabili.) PLTU #1& #2 Plant Efficiency 30% (Assumed) Sunyaragi Output 20MW × 4 PLTG #1-#4 Plant Efficiency 28% (Assumed) Cilacap Output 26MW + 29MW PLTG #1& #2 Plant Efficiency 28.0% (Assumed)

As to Tambak Lorok PLTU #1 & #2 these units shall be assumed to be rehabilitated and produce the rated load of 50MW each. Other plant efficiencies are also assumed. A F-type gas turbine of 240MW class at HSD firing emits larger volume of flue gas compared with the existing 50MW × 2 MFO (Marine Fuel Oil) firing boilers, but by adopting DLN combustors for gas firing and water injection combustors for HSD firing, pollutants like NOx, SOx, particulates, etc. in the flue gas are predicted to be lower, compared with the existing PLTUs. This situation remains same as mentioned on the repowering plan of Item (1) of Section 4.1.1.1.

Based on the above conditions yearly base oil consumption is calculated as follows per assumed CF (capacity factor);

◊ Oil (HSD) Consumption by the alternative C/C Plant CF=50% Oil Consumption = 307.4MW × 8760h × 50% × 860kcal/kWh ÷ 0.504÷10,500kcal/kg=218,800ton/y CF=30% Oil Consumption = 307.4MW × 8760h × 30% × 860kcal/kWh ÷ 0.504÷10,500kcal/kg=131,200ton/y ◊ Oil (MFO) Consumption by T.Lorok PLTU #1 & #2 CF=50% Oil Consumption = 50MW × 2 × 8760h × 50% × 860kcal/kWh ÷ 0.30÷10,500kcal/kg=119,500ton/y CF=30% Oil Consumption = 50MW × 2 × 8760h × 30% × 860kcal/kWh÷ 0.30÷10,500kcal/kg=71,700ton/y ◊ Oil (HSD) Consumption by Sunyaragi and Cilacap PLTGs CF=50% Oil Consumption = (20×4+26+29=) 135MW × 8760h x 50% ×

860kcal/kWh÷0.28÷10,500kcal/kg=173,000ton/y CF=30% Oil Consumption = (20×4+26+29=) 135MW × 8760h × 30% ×

860kcal/kWh÷0.28÷10,500kcal/kg=103,800ton/y

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Therefore, the performance gains such as repowering, oil and GHG reduction as the oil reduction plan are summarized as follow;

◊ Repowering = C/C Generation – Existing PLTUs/PLTGs Generation CF=50% Repowering = (307.4MW-235.0MW=) 72.4MW×8760h×50%= 317.1GWh/y CF=30% Repowering = (307.4MW-235.0MW=) 72.4MW×8760h×30%= 190.3GWh/y

◊ Oil Reduction = C/C Consumption – Existing PLTUs/PLTGs Consumption CF=50% Oil (HSD+MFO) Reduction = 218.8 – 119.5 – 173.0 = –73.7 k-ton/y CF=30% Oil (HSD+MFO) Reduction = 131.2 – 71.7 – 103.8 = –44.3 k-ton/y

◊ GHG Reduction = Oil Reduction x Carbon % in Oil (0.85) × CO2/C (=3.666) CF=50% GHG (CO2) Reduction = 73.7kton/y × 0.85 × 3.666 = 230,000 ton-CO2/y CF=30% GHG (CO2) Reduction = 44.3kton/y × 0.85 × 3.666 = 138,000 ton-CO2/y

The EPC cost of the above oil reduction plan of a newly installed F-type gas turbine C/C plant (1-1-1) is estimated as 212.4 Million US$. This cost includes the newly installed cooling water system (intake/discharge facilities, CW pump & piping) for the condenser.

The summary of the oil reduction plan; ① Repowering; 321.5 GWh/y Oil reduction; 72.3 k-ton/y GHG reduction; 225 k-ton/y at CF=50% ② EPC Cost; 212.4 Million US$

(3) UBP Perak/Grati Oil Reduction Plan

UBP Perak/Grati manages and controls both of Perak and Grati Power Stations and their Power Units. Table 4.1-3 shows the power units of both power stations/ PLTU #1 & #2 at Perak power station have retired with no operation since 1996.

Table 4.1-3 UBP Perak/Grati: Thermal Power Station and Power Units Installed Capacity Available Capacity

PLTU #3 50MW 30MW Perak PLTU #4 50MW 30MW GT 1-1 112.45MW 100.75MW GT 1-2 112.45MW 100.75MW GT 1-3 112.45MW 100.75MW ST 1-0 189.50MW 159.58MW PLTGU Block-I (526.85MW) (461.83MW) GT 2-1 113.84MW 101.90MW GT 2-2 113.84MW 101.90MW GT 2-3 113.84MW 101.90MW

Grati

PLTG Block-II (341.52MW) (305.70MW)

Final Report 4 - 10


Among the above table less efficient units are Perak PLTU #3 & #4 and Grati Block-II three (3) simple cycle operation gas turbines. Then, the following oil reduction scheme will be born;

◊ Less Efficient Oil Existing Plants to be stopped. Perak PLTU #3 & #4 (MFO Firing) 50MW × 2 units

◊ Grati BLK II PLTG #1-#3 101.90MW × 3 units to be converted into a higher efficient Alternative Combined Cycle Plant.

Newly Installed HRSG × 3 + ST/Generator × 1 PLTGU (3-3-1) C/C Output at HSD Firing 461.83MW

◊ Repowering & Oil Consumption Reduction to be obtained. Repowering: (461.83 – (50x2+100.75 × 3) = 59.58) 59.5 MW Oil Reduction: Oil Consumption by Stopping Perak PLTUs

As oil consumption for Grati Block II gas turbines remain just same as simple cycle operation, oil reduction will not be born before and after C/C conversion. Instead, Perak PLTU #3& #4 will be stopped and cause oil reduction by their yearly based supposed oil consumption volume. In this case MFO (Marine Fuel Oil) reduction will happen. As mentioned above, this plan consists of the existing three (3) gas turbines of Grati Block II PLTG #1- #3, a newly installed steam turbine and newly installed three (3) HRSGs (Heat Recovery Steam Generators). The steam turbine and the HRSGs to be designed identically as the Block I are supposed to be installed at the site already prepared next to the Block I.

Block-I Block-II

Figure 4.1-3 Grati Power Station Layout

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After converted into the C/C conversion, the existing three (3) gas turbines remain operating same as up to now with continuing HSD firing. Then, the total flue gas volume and their pollutants in the flue also remain same as up to now and only the stack gas temperature will go down after through the HRSG heat exchanging, but its temperature level will be same as Block I.

The cooling water system for the plan is newly required but the overall cooling system of Grati power station originally had been planned for Block II and even future Block III of the same capacity of 500MW class C/C plant. Then, there will be no difficulty for the installation of the cooling water system of the plan.

Under the above situation, there will be no major influence on the environmental impact assessment (EIA) for this repowering plan.

The Basic Specification of Grati BLK II PLTGU (3-3-1) is as follows; ◊ Existing GT& Generator ; 701D-Type × 3 sets, Gas/HSD Dual Firing

Capacity 112.45MW for Gas, 100.75MW for HSD at 32°C

◊ HRSG; Two Drum Type × 3 sets, 75 kg/cm2g × 505°C T & 5.2kg/cm2g × 176°C

◊ ST& Generator; HP/LP T/Compound Condensing Type × 1 set, Capacity 189.5MW, Condenser Vacuum 0.085ata

◊ Instrument & Control Systems; C/C control system

◊ BOP; Intake/Discharge Facilities, CWPs & CW Piping, BFPs& Piping



It is noted that Grati Block II PLTGU (3-3-1) Specification is just same as Block I (3-3-1).

Then, HSD firing performance of Grati Block II Alternative C/C is the same as Block I. ◊ GT/ST Output 100.75MW × 3/159.58MW ◊ Plant Output 461.83MW ◊ Plant Thermal Efficiency 47.1% (LHV)

The EPC cost of the above repowering plan is estimated as 159.3 Million US$.

As to stopping Perak PLTU #3& #4 these units shall be rehabilitated of the same burner system applied to Tanjung Priok #3& #4 and be supposed to recover 50MW each, because Perak PLTU #3& #4 boilers are of the same design as T.Priok #3& #4 boilers and have had to have almost same firing troubles causing the load limitation up to 30MW and have already gotten the rehabilitation works to recover 50 MW each generation during 2005. Then, stopping Perak #3& #4 units are supposed to have the following MFO Firing Performance;

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◊ ST Output after rehabilitation 50MW × 2 ◊ Plant Efficiency 30% (Assumed) Therefore, the performance gains such as repowering, oil and GHG reduction as the oil reduction plan are summarized as follow; ◊ Repowering = C/C Incremental Generation – Existing PLTUs Generation CF = 50% Repowering = (159.58MW - 50 × 2MW =) 59.58MW × 8760h × 50%

= 260.9GWh/y CF = 30% Repowering = (159.58MW - 50 × 2MW =) 59.58MW × 8760h × 30%

= 156.5GWh/y

◊ Oil Reduction = Existing PLTUs Consumption CF = 50% Oil (MFO) Reduction = 100MW × 8760h × 50% × 860kcal/kWh÷0.30÷

10,500kcal/kg = 119.5 k-ton/y CF = 30% Oil (MFO) Reduction = 100MW × 8760h × 30% × 860kcal/kWh÷0.30÷

10,500kcal/kg = 71.7 k-ton/y

◊ GHG Reduction = Oil Reduction × Carbon % in Oil (0.85) × CO2/C (=3.666) CF=50% GHG (CO2) Reduction = 119.5kton/y × 0.85 × 3.666 = 372,000 ton-CO2/y CF=30% GHG (CO2) Reduction = 71.7kton/y × 0.85 × 3.666 = 223,000 ton-CO2/y

The summary of the oil reduction plan; ① Repowering; 260.9GWh/y Oil reduction; 119.5 k-ton/y GHG reduction; 372 k-ton/y at CF=50% ② EPC Cost; 159.3 Million US$

(4) UBP Bali Oil Reduction Plan

UBP Bali manages and controls three thermal power stations and the grid power from Java Island the locations of which are shown in the Figure 4.1-4. The power units at three power stations are also listed in Table 4.1-4.

Pesanggaran PLTD/PLTG

Pemaron PLTG

Gilimanuk PLTG

Submarine Cables

Figure 4.1-4 UBP Bali Three Power Stations and Submarine Cables

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Table 4.1-4 UBP Bali Power Units List Installed Capacity Available Capacity

Unit #1 5.08MW 4.52MW Unit #2 5.08MW 4.52MW Unit #3 5.08MW 4.42MW Unit #4 5.08MW 4.42MW Unit #5 4.14MW 3.20MW Unit #6 6.77MW 5.34MW Unit #7 6.77MW 5.34MW Unit #8 6.52MW 4.48MW Unit #9 6.52MW 4.48MW Unit #10 12.39MW 9.60MW Unit #11 12.39MW 10.50MW

Pesanggaran PLTD

PLTD Total 75.82MW 60.82MW Unit #1 21.35MW 19.53MW Unit #2 20.10MW 18.00MW Unit #3 42.10MW 35.07MW Unit #4 42.10MW 35.07MW

Pesanggaran PLTG

PLTG Total 125.65MW 107.67MW Unit #1 48.8MW 45.0MW Unit #2 48.8MW 45.0MW

Pemaron PLTG

(ST-1) (48.4MW) (to be postponed) Gilimanuk PLTG #1 133.8MW 132.0MW

Among the above table less efficient units are eleven (11) Pesanggaran PLTD units, four (4) Pesanggaran PLTG units and Gilimanuk PLTG unit. The combined cycle conversion project of Pemaron PLTG units had been planned, but now is postponed. It is noted that an especially big unit of Gilimanuk PLTG of 133 MW now being operated as base load should be converted into a higher efficient combined cycle plant.

Then, the following oil reduction scheme will be born;

◊ Less Efficient Oil Fired Existing Plants to be stopped. Pesanggaran PLTG #1& #2 (HSD Firing) 21.4+20.1MW Pesanggaran PLTD #1- #4 (HSD Firing) 5.08MW × 4 ◊ Gilimanuk PLTG to be converted to a Higher Efficient Alternative Combined Cycle Plant. One Newly Installed HRSG + One ST/Generator PLTGU (1-1-1) C/C Output at HSD Firing 200MW ◊ Repowering & Oil Consumption Reduction to be obtained. Repowering 67.0 – (41.5+ 20.3) = 5.2 5.2MW Oil Reduction; Oil Consumption by Stopping Plants

As to Gilimanuk PLTG Combined Cycle Conversion Plan its design concept remains same as for the repowering plan proposed in Item (3) of Section 4.1.1.1. Then, this repowering plan as the oil reduction plan also consists of the existing gas turbine

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of Gilimanuk PLTG, a newly installed steam turbine and a newly installed HRSG (Heat Recovery Steam Generator). The steam turbine and the HRSG are supposed to be installed at the site next to the existing PLTG house, but, this extension site area seems to be newly purchased. It is reminded that the site is close to the National Park Area.

As oil consumption for Gilimanuk PLTG gas turbine remains just same as simple cycle operation, oil reduction will not be born before and after C/C conversion. Instead, Pesanggaran PLTD #1-#4 and Pesanggaran PLTG #1& #2 will be stopped and cause oil reduction by their yearly oil consumption volume. After converted into the C/C conversion, the existing PLTG gas turbine remain operating same as up to now with same HSD firing. Then, the total flue gas volume and its pollutants in the flue also remain same as up to now and only the stack gas temperature will go down after through the HRSG heat exchanging. At Pesanggaran Power Station, its PLTD #1- #4 and PLTG #1& #2 will be stopped, then, air pollutants should be totally reduced there. Oil reduction happened at Pesanggaran will contribute to environmental improvement around the center of Bali Island in terms of air pollutants. The Gilimanuk site is located in the inland area about 1 km away from the nearest seashore and at the about 4m height from the seawater level. Then, it is thought to be difficult to adopt sea water for condenser cooling. Then, a dry cooling system by air cooled condenser (ACC) type is proposed here again for the plan. Under the above situation, there will be no major influence on the environmental impact assessment (EIA) with the reduction plan.

The basic design figures of the main components of the plan are as follows:- ◊ Existing GT& Generator ; 13E2-Type × 1 set,

HSD Firing (Originally Gas/HSD Dual Firing) Capacity 133MW for HSD

◊ HRSG; Two Drum Type × 1 set, 70 kg/cm2g × 510°C &5.2 kg/cm2g × 155°C

◊ ST& Generator; T/Compound Condensing Type × 1 set, Capacity 67MW, Condenser Vacuum 0.15P

◊ Air Cooled Condenser* L 52m × W 50m × H 34m Structure and Cooling Surfaces, Fan/Motor 149kW × 16 sets


◊ BOP; ST Exhaust Piping, CWPs & CW Piping, BFPs & FW Piping

◊ Station Electrical Equipments & S/S; Conventional Type (150kV Connection) The Gilimanuk PLTGU for HSD firing is capable of the following performance: ◊ GT/ST Output 133.0MW + 67.0MW ◊ Plant Output 200.0MW

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◊ Plant Thermal Efficiency 49.6% (LHV)

Stopping Pesanggaran PLTG #1& #2 and PLTD #1 - #4 Performance; ◊ PLTG #1& #2 Output 21.4 + 20.1 = 401.5 41.5MW ◊ PLTD #1- #4 Output 5.08 × 4 = 20.3 20.3MW ◊ PLTG Plant Efficiency 28% (Assumed) ◊ PLTD Plant Efficiency 35% (Assumed)

Therefore, the performance gains such as repowering, oil and GHG reduction as the oil reduction plan are summarized as follow;

◊ Repowering = C/C Incremental Generation – Existing PLTGs/PLTDs Generation CF=50% Repowering = (67.0 – 41.5 – 20.3 =) 5.2MW × 8760h × 50% = 22.7GWh/y CF=30% Repowering = (67.0 – 41.5 – 20.3 =) 5.2MW × 8760h × 30% = 13.6GWh/y ◊ Oil Reduction = – Existing PLTGs/PLTDs Consumption CF=50% Oil Reduction = (41.5MW ÷0.28 + 20.3÷0.35) × 8760h × 50% ×

860kcal/kWh÷10,500kcal/kg = –73.9 k-ton/y CF=30% Oil Reduction = (41.5MW ÷0.28+20.3÷0.35) × 8760h × 30% ×

860kcal/kWh÷10,500kcal/kg= –44.3 k-ton/y ◊ GHG Reduction = Oil Reduction x Carbon % in Oil (0.85) × CO2/C (= 3.666) CF=50% GHG (CO2) Reduction = 73.9 kton/y × 0.85 × 3.666 =230,000 ton-CO2/y CF=30% GHG (CO2) Reduction = 44.3 kton/y × 0.85 × 3.666 =138,000 ton-CO2/y

The EPC cost of the above repowering plan is estimated as 66.4 Million US$. This cost includes the installation expenditure of ACC (Air Cooled Condenser) system, but, does not include the purchasing expense of the land for the site extension.

As mentioned above, the existing site is located about 1 km away even from the nearest seashore. Then, without the feasibility study of usual sea water cooling system a dry ACC (Air Cooled Condenser) system is proposed in this report. It seems necessary, however, whether the usage of sea water cooling system for the plan will be feasible or not by executing a further feasibility study. In this case the following items should be considered. i) Applicability of Sea Water Quality Standards, especially temperature rise limitation

(<2.0°C) and temperature effect to mangrove and coral. ii) Location of the steam turbine and condenser, especially siphon limit, steam pressure

drop from the HRSG supposed to be installed near to the existing gas turbine unit and relation with National Park area

The summary of the oil reduction plan; ① Repowering; 22.7 GWh/y Oil reduction; 73.9 k-ton/y GHG reduction; 230 k-ton/y at CF=50% ② EPC Cost; 66.4 Million US$

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