MALTA RESOURCES AUTHORITY - REWSdownloads.rews.org.mt/files/75da700c-1944-4c6b-a162-9e5091527fca... · MALTA RESOURCES AUTHORITY Energy Interconnection Europe - Malta March 2008 Final

MALTA RESOURCES AUTHORITY

Energy Interconnection Europe - Malta March 2008

Final Report – Work Package IIA

LI 260442 Page 3-12

Figure 3-6: Diesel Unloading Arm at Delimara Power Station

Figure 3-7 is a satellite picture with a proposed lay-out superimposed. This lay-out shows one

60,000 m3 LNG storage tank at the reclaimed area next to the three diesel storage tanks right

below the cooling water inlet structure. Above the cooling water intake structure is the 500 meter

long berth. A new LNG loading arm and a vapour return arm have been placed in the middle of

the existing berth. A LNG pipe corridor leads from the unloading arm to the LNG storage tank.

The main LNG process area with (BOG blowers; De-Superheater vessel; HP Pumps and

Submerged Combustion Vaporizers) is placed in the empty space between unloading arm and

the existing cooling water inlet structure.




LI 260442 Page 3-13

Figure 3-7: Layout of LNG Terminal with one 60,000 m3 LNG Storage Tanks

The alternative layout option with two 30,000 m3 LNG storage tanks at the reclaimed area next

to the diesel tanks is shown in the following figure. Due to difficult soil condition it may not be

possible to build one large tank with a volume of 60,000 m3 and two smaller tanks have to be

built instead. In case of LNG being a solution considered in line with the expansion plan,

thorough assessment of geological conditions by sample drilling will have to be considered in

this regard.




LI 260442 Page 3-14

Figure 3-8: Layout of LNG Terminal with two 30,000 m³ LNG Storage Tanks




LI 260442 Page 3-15

Nevertheless sample drilling which is a very extensive and costly measure and will not be exe-

cuted before a more advanced stage of regarding the potential realization of such an LNG ter-

minal.

Modification on the existing Installations

From a first visual inspection during a site visit the entire berth appears to be in good condition

and does not require major modifications or refurbishments. Only the existing mooring hooks

and mooring dolphins need to be checked if they are suitable for LNG vessels. It is anticipated

that only minor upgrading is required.

On the existing berth is an unloading arm for diesel fuel and a narrow pipe corridor to bring the

diesel to the storage tanks. These installations do not necessarily need to be removed if

Enemalta would like to retain a duel fuel capacity. Usage of diesel unloading equipment could

be continued during periods were no LNG unloading operation is ongoing.

Connection from LNG plant to the Marsa Power Station Site

The existing gas turbine at the Marsa Power plant is currently running on diesel fuel. A fuel

switch to natural gas is in principle possible; however natural gas has to be transported from the

Delimara power station to Marsa. The Marsa power generation units will continue to run on

diesel for the Base Demand Case Scenario. A fuel switch to natural gas is in principle possible;

however natural gas has to be transported from the Delimara power station to Marsa.

In order to avoid a costly 11.5 km long connection pipeline from Delimara to Marsa through po-

pulated areas the low quantity of gas required could be trucked from the pipeline landfall

terminal station in Delimara using specialised LNG trucks to the Marsa power station.

The turbines would have a daily consumption of about 180,000 m3 of natural gas which is the

equivalent of 300 m3 LNG, This would require a min. storage tank for LNG of about 600 m3 to

have a one day reserve.

A LNG truck trailer has a cargo capacity of roughly 43 m3 which would require an average of

7 trips. Each roundtrip would take about 3 hours i.e. one hour driving the distance of 30 km

(roundtrip) and one hour for loading and unloading. In total one complete cargo trip would take

no longer than 3 hours. This means that in theory 7 trips could be done within one day.

The picture below shows a typical LNG truck trailer. This particular trailer has a LNG cargo ca-

pacity of 43 m3.




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Figure 3-9: Typical LNG Truck Trailer with a Capacity of 43 m3

A simple cost calculation in Table 3-3 shows the cost involved.

Description Cost in Euro

LNG Truck Filling Station at the terminal 400,000,--

LNG Trailer with capacity of 43 m³ 220,000,--

LNG Storage Tank at Marsa Power Station (600m³) 420,000,--

Vaporizer and HP LNG Pump, piping etc. at Marsa Power Station 180,000,--

Civil Works at Marsa Power Station 110,000,--

Total Estimate 1,350,000,--

Table 3-3: Cost Calculation for LNG Supply at Marsa by Truck Trailer




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However, it should be considered that the gas turbine at Marsa is not for base load power

generation and is only utilized during peak demand; therefore it is questionable if an additional

investment of 1.35 Mio EUR is justified for a fuel switch of a power generation unit that is used

to cover peak demand only.

3.1.3 Potential Hazards

Hazard identification for LNG terminal is conducted and the following hazards are identified:

LNG Spills;

Vapour Dispersion;

Thermal Radiation;

Environmental Impacts;

Ship Grounding and LNG Release;

Terrorism or sabotage;

Acts of Nature (storm, earthquake etc);

External Fire;

LNG Release due to Equipment or System Failure.

LNG Spill is one of the hazards discussed for LNG. The primary hazard of the flammable LNG is

the possibility of a fire. The two limiting conditions are an LNG release with and without

immediate ignition. If the ignition is immediate or relatively soon after the start of the release, the

fire size is determined by the LNG release rate which fuels the fire. If the ignition is delayed, an

LNG vapour cloud will develop and disperse as it expands and/or moves downwind. For ignition

to occur, the concentration of vapour in the atmosphere must be at less than 15% which is the

Upper Flammable Limit (UFL). At concentrations above the UFL, there is not enough air to

sustain combustion. As the cloud expands, eventually the concentration drops below 5% vapour

in the atmosphere. This concentration of 5% is the Lower Flammable Limit (LFL). At

concentrations below 5% vapour in the atmosphere there is not enough fuel to sustain

combustion. If ignition occurs, the area with concentrations at or above the lower flammable limit

(5%) will be at risk. The vapour cloud will burn back to the source of vapour. This source can be

either the release itself or a pool of LNG accumulated prior to ignition. From these scenarios

emerge two explicit requirements for the protection of the public beyond the boundaries of the

facility. These are the two “exclusion zones” which are required for facility siting. Specifically,

there are the “vapour dispersion exclusion zone” and the “thermal radiation exclusion zone”.




LI 260442 Page 3-18

Vapour Dispersion Hazards: When a release occurs, the LNG will vaporize as it comes into

contact with the relatively warm surfaces and atmosphere. The initial hazard following a release

comes from the LNG spreading over the surface and vaporizing as it absorbs heat. The vapour

generated will mix with air which begins the vapour dispersion process. It is possible to calculate

the theoretical distance the flammable concentration of a vapour cloud will travel and this

distance is called the Lower Flammable Limit (LFL) vapour dispersion isopleths. LFL distance

can be represented on a site plan as a ring of equal concentration. The isopleths for a LFL

vapour cloud must not go beyond the LNG facility boundaries or property that cannot or will not

have occupancies and thus result in a distinct hazard to the public. The hazard is not the vapour

itself, but the possibility that it could be ignited. If ignited, the vapour cloud will not expand any

further, but instead, will burn back to the vapour source. The LNG fire will continue to burn until

the fuel is consumed or the fire extinguished. An LNG vapour cloud, mixed with air will not

explode unless confined in an enclosure.

The vapour dispersion calculations for the LNG facility shall be performed in order to define the

vapour excursion from a design spill at each impoundment area.

Thermal Radiation Hazards: If a fire occurs, there will be radiant heat from the flame which

could cause personal injury, property damage and potentially secondary fires. The potential

personal injury of the public is the primary concern. The severity of the injury depends on the

intensity of the radiant heat, the exposure time and any protective factors such as clothing. The

intensity or thermal flux level is measured in kilowatts per square meter (kW/m2). This unit is

generally unfamiliar but if related to sunlight with a clear sky, direct sunlight radiant heat is about

1 to 1.5 kW/m2.

The limiting radiant heat restriction on general public exposure is 5 kW/m2 or, say, 5 times as

strong as sunlight. This is not instantly injurious but becomes quite uncomfortable fairly quickly.

Ultimately these flux levels can cause injury. Recent “real live person” experiments have shown

that 60 seconds at 5 kW/m2 is not injurious and does not cause continued discomfort after the

radiant heat exposure is discontinued. The duration of exposure factor allows time for an

exposed person to find protective shelter from the direct exposure and/or move away from the

fire. In summary, the 5 kW/m2 exposure limit provides a high level of safety.

The thermal radiation calculations for the LNG facility shall be performed for a full dike fire for

the storage tanks or a fire over the full extent of each impoundment area.

Environmental Impacts: Negative long-term environmental impact from an LNG release is

virtually non-existent. LNG is colourless, odourless, and non-toxic and leaves no residue after




LI 260442 Page 3-19

evaporation. LNG (liquid) has a specific gravity in the range of 0.45; therefore it will float on

water. LNG and LNG vapour are not soluble in water which precludes water contamination. The

specific gravity of LNG vapour is 0.55. LNG vapours become buoyant at temperatures above a

value of -107 ºC. The buoyancy of the vapour enhances the dispersion in the atmosphere with

no long-term hazardous effects. One of the attractive features of natural gas is that, unlike an oil

spill, an LNG release does not require any environmental clean-up effort. Methane is considered

to be a greenhouse gas but there are no vapours released in normal operations as all systems

are vapour tight.

Potential damage to environmental and socio-economic components is limited to short-term

hazards to flora, fauna and humans in the immediate vicinity of the release. There are no LNG

or vapour releases as a result of normal operations. Any short term releases would be the result

of an accidental spill or component failure. The affected area would probably be in the cleared

area around the tanks and process, but certainly within the facility boundaries. For example, any

fish in the immediate vicinity (a few hundred meters) of an LNG ship release would unlikely be

frozen or otherwise harmed as any freezing of the water would be at the surface of the water.

The surface of the water will be at the melting temperature of the ice. The ice will soon melt and

the environment will return to normal with no residual trace of the incident. Likewise, any

animals or birds within the vapour dispersion or thermal radiation isopleths caused by a release

could be immediately harmed or killed. An animal may not recognize a visible fog (vapour cloud)

as a fire hazard and thus suffer if they are in the flammable cloud if it is ignited. If they were not

within the vapour cloud if ignited, they could escape. If an LNG pool on water is ignited (“pool

fire”), marine mammals will likely stay away. It should be noted that persons can and have run

faster than a flame front. Immediately after an LNG release, the area would be suitable for

animals and humans to use again. Local population (animals or people) and property should

sustain no long-term effects from an LNG release. The LNG facility is designed to contain any

incident on site or within the controlled property.

An environmental emergency plan is required. Comprehensive safety and environmental

procedures shall be prepared using the safety studies for code regulation compliance, analysis

of emergency scenarios and the final facility design.

Ship Grounding and LNG Spill: When evaluating the possibility of ship grounding at or near the

terminal, two factors must be considered: the physical features of the navigable area adjacent to

the waterfront and berth, and the speed and control of the LNG ship. The navigable waters

surrounding the LNG facility shall be sufficiently deep that grounding would require a loss of

ship’s propulsion or steerage that would cause the ship to leave the berth area. While grounding

is always possible, as the ship approaches the facility it shall be under control of a licensed pilot.

The manoeuvring for berthing and turning of the ship shall be assisted by tugs. The tugs shall




LI 260442 Page 3-20

be able to control the movement of the ship and prevent grounding. The potential for damage in

the event of grounding shall be further mitigated by the ship’s reduced speed as it approached

the berth and its double hull.

Terrorism or sabotage: The possible scenarios of terrorism attack or sabotage shall be studied

in detail to define the necessary mitigation measures. However the chances of this type of threat

are remote for several reasons, including:

Terminal and shipping personnel are always screened before hiring.

Ship crews tend to be very stable as the jobs are considered to be very attractive. There

is very little turnover in terminal staffing.

Terrorists are more interested in “high profile” targets with strong symbolic value, or targets that

can cause mass casualties or severe economic damage. In general, LNG terminals are not

attractive targets due to their “low political profile”, difficulty of attack, and high level of security.

Acts of Nature: The possibility of a significant LNG release resulting from an act of nature, such

as a severe storm, ice storm, or earthquake is remote because the design requirements shall

take seismic, wind, and weather factors into account. The tanks shall be designed for the

seismic rating of the region, and the tank profile shall take into account the wind loads (both

typical and maximum) for the region. Equipment and structures shall be designed to withstand

the harshest recorded environment for the region. A lightening strike shall not affect the system,

unless it strikes a vent mast or other component that has a natural gas leak, creating a

methane-rich environment. Significant leaks should be detected by mandated safety systems

before they become a source of ignition. Such vent fires would be small and are easily

extinguished.

Should an act of nature cause a release, the result will be the same or less than other causes

previously cited. An LNG release would be impounded and the resulting vapour dispersion or

thermal radiation would be limited to the terminal site and not cause injury or damage to

adjacent property.

Acts of nature involving an LNG ship should be divided into two categories, predicted conditions,

and unpredicted events. A predicted condition would be high winds, hurricane, ice storm, etc.

Unpredicted acts would be those events that occur suddenly, such as earthquakes. The LNG

ship will not dock and, if docked, will undock and depart should the weather exceed the design

criteria. If extreme weather were predicted, the LNG ship’s officers would monitor the weather to

avoid being caught in restricted waters during the storm.

Unpredicted events of nature, such as earthquakes, present a different scenario. The worst

case would be the LNG ship breaking its moorings during a cargo discharge. Breaking moorings




LI 260442 Page 3-21

occurred once in the past when a sudden 100-mph wind, called a “Sumatra,” blew the LNG

Aries off the dock while loading cargo in Bontang, Indonesia. In such a case, the unloading arms

would exceed their operational range and the automatic disconnection (PERC) system would

activate. A small amount of LNG would be released; probably not enough to even reach the

water. If the LNG ship broke all its moorings and propulsion was not available, the ship could

drift and either allied with the dock or with the ground. Allision at low speed would possibly be

sufficient to penetrate the outer hull but not sufficient to breach the cargo tanks. (Allision is a

relatively new term adopted by the marine regulators to indicate the impact of a moving ship

with a fixed “obstacle” that is not moving.) Other damage to the ship caused by events of nature

is not plausible due to the ship being designed to be seaworthy in all types of weather.

External Fire: The possibility of an LNG release caused by external events, such as a forest fire

or adjacent oil storage fire, is extremely remote because the facility is built from non-combustible

materials, mostly steel and concrete. Further, the facility shall be designed to contain vapour

dispersion and thermal radiation within the boundaries of the facility, as explained in detail

above. The critical components of the import terminal for both operation and safety are not

susceptible to even large fires at the distances provided by the exclusion zones and plant

boundaries. These components are predominantly fire resistant. All components containing LNG

are alloy steel externally insulated. The safety zones also work to isolate the facility and prevent

an external fire from threatening the facility. Storage tanks would be protected by the

impoundment dike, which would serve as a firebreak around the tank and process area.

Furthermore, the facility shall be equipped with an extensive fire fighting system, which can be

used to protect the facility from an external fire.

An escalating LNG release as the result of a fire within the plant is unlikely for the same reason.

Due to the flammable nature of LNG, terminal personnel are extremely safety conscious. While

accidents have occurred, they do not typically result in fires large enough to initiate a

subsequent release or emergency escalation. However, in the event of a fire initiating a release,

vapour dispersion would not be an issue because an ignition source would be immediately

present. A major release would be contained within the dike or sump and thermal radiation is

predictable and part of the risk assessment process. A vapour release that ignited would burn

until the fuel was consumed or the fire extinguished. In either case, the fire and thermal radiation

would be contained within the facility boundaries, minimizing the danger to the surrounding

area. The fire fighting systems should prevent the fire from spreading to storage tanks and

process equipment not directly involved in the initial incident. All storage tanks and systems are

sealed such that no fugitive vapours are present to be ignited.




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LNG Release Due to Equipment or System Failure: The most credible type of release is the

result of equipment or system leakage, such as a leaking valve seal or flange gasket. This type

of release is typically small and non-threatening. The probability of such a failure is greatest at

flanges or joints where components, pipes, and valves are connected and undergo temperature

changes. These small leaks are visible and easily repaired by facility personnel. The next level

of failure would be a leak associated with a piece of equipment. In this case, the equipment is

typically replaced in service by a “spare” component and secured for repairs.

The LNG facility shall be equipped with an extensive array of gas detection and flame detection

equipment. Small leaks shall be detected either visually, by trained personnel working in the

facility, or by the detection equipment. Small leaks and/or fires should be easily handled by

facility personnel, with assistance from the local fire department if necessary.

A system failure that generates a major release will have the same net effect as the other major

incidents evaluated above. A release will be contained and directed to a sump, thus mitigating

the extent of vapour dispersion. Should the vapour ignite, the thermal radiation will be mitigated

by the release’s containment in the sump. The fire will continue until the fuel is consumed or the

fire is extinguished. Damage will be confined to the terminal boundaries, including any controlled

areas outside the property lines.

The extensive Risk Assessment including HAZID, HAZOP, QRA and EIA shall be performed in

order to analyse in detail and in specific the effects of these defined possible hazards and the

related mitigation measures based on the following methodology:

Establishing the resulting LNG release from credible events;

Calculation of the area extent of the hazards (pool fire and vapour cloud);

Determining the potential exposures, primarily exposure of the public.

Determining the surrounding distances to which these significant hazards extend, the zone of

influence or “exclusion zone.” The purpose of the exclusion zone requirements is the protection

of the public (population and property) surrounding the facility. Protection and safety of the

facility itself is also covered, but the public safety requirements are so strict that the facility

protection is a secondary benefit.

Confirming that these zones of influence to not exceed the project codes and standards require-

ments.




LI 260442 Page 3-23

3.2 Economic Description of the Proposed Scheme for Case (I) and (II)

3.2.1 Investment Costs of Major Components

The below table provides the scheme’s investment cost in total and for each major component.

In total, the projects investment cost amounts to 102.1 Mio Euro (10% contingencies and 12%

contractors total profit, mark-up are included). The project duration regarding the recommended

two LNG tanks scheme (total storage capacity of 60,000 m³) is estimated at three years. The

disbursement schedule of the investment is shown in Table 3-5.

# Item

1

2

3

4

5

6

Construction Equipment

Total: 102,101

Overhead and Indirects

Home Office Services (EPC Contractor)

Investment Costs

in T EUR

Owner's Engineering Services 3,431

Specialty Contractors 45,458

851

2,174

2,941

Direct Cost (Labor, Materials & Subcontracts) 47,219

Table 3-4: Investment Cost of LNG Scheme Case (I) and (II)

Year n-3 n-2 n-1 n

Disbursement in % 35% 35% 30% Start Year

Table 3-5: Disbursement of the Investment Cost of LNG Scheme Case (I) and (II)

As illustrated in Figure 3-10 the two major proportions of the investment cost are:

(i) The Direct Cost which includes:

o Site Preparation and Improvement;




LI 260442 Page 3-24

o Process Equipment; o Underground and Aboveground Pipelines;

o Underground and Aboveground Electric Equipment;

o Concrete, Instrumentation and Insulation;

o Over less cost intensive items.

(ii) The Specialty Contractors Cost which includes:

o LNG Tank Costs;

o Jetty Upgrades Costs;

o Dredging Costs;


46%

1%

2%

3%

3%

45%Direct Cost (Labor, Materials & Subcontracts)




Owner's Engineering Services

Specialty Contractors

Figure 3-10: Investment Cost Break Down of the LNG Scheme for Case (I) and (II)




LI 260442 Page 3-25

Ownership and Operating Structure.

Since the only customer of the LNG terminal appears to be Enemalta it would make sense that

the Owner and Operator of the LNG Terminal would be a subsidiary of Enemalta.

Regulatory Structure.

There are a number of options available for the Buyer on how to structure the supply of LNG

and on how to participate along the LNG value chain. The structure is mainly dependent on:

The sourcing structure (e.g. Point of sale, ex-ship, FOB);

The selected partner;

Desire of Buyer to move upstream;

Ability to invest and carry risk.

The identified options can be summarised in three categories as follows:

Ex-ship LNG supply to a Re-gas terminal in Malta;

FOB LNG supply from a terminal in a gas producing country (e.g. Algeria);

Participation along the entire value chain.

3.2.2 Operational and Maintenance Costs

LNG Price Estimation

LNG imports into Europe are generally linked to crude oil prices (i.e. Brent) but prices are a bit

more diverse in Europe as compared to Asia as LNG is competing with pipeline imports and to

some extent also with indigenous supply in many countries. LNG supply contracts are not a

public domain and the exact pricing formula for LNG is negotiated on a case by case basis.

Traditionally LNG supply contracts were all long term i.e. over a period of 20 years and are

usually indexed to a basket of competing fuels (i.e. crude oil; diesel etc). Recent changes in the

LNG market have trended towards increased flexibility. Contracts have loosened terms on both

price and volume, and can be negotiated for shorter periods of time. Additionally, flexibility in

LNG shipping has led to an increase in short-term contacts.

Traditionally the LNG price is expressed in USD/mBtu. The average LNG price in spring 2007

for LNG delivered to Spain was 6.3 USD/mBtu (Source: Argus Global LNG Services) which is

equivalent to a natural gas price of some 167 EUR/1000m³ or 223.3 EUR/t.




LI 260442 Page 3-26

Regarding the development of the LNG price an indexation of the crude oil price forecast of the

Energy Information Agency (EIA) was applied (for more details see chapter 6.2 within the Work

Package I Report).

Fixed O&M Costs

For the LNG terminal the fixed operation expenditures have been estimated as stated in the fol-

lowing table.

# Item

1

2

3

4

5

6

7

8

9 200 Insurance

Costs in T EUR/a

Management and Operation 960

Tugboat Operation Fees 160

50

820

20

Technical Assistance 220

Inspection

Total Annual Fixed OPEX: 2,480

Maintenance

Nitrogen

Telecommunication 20

Permits & other Fees 30

Table 3-6: Estimate of Annual Fixed OPEX

Variable O&M Costs

Variable OPEX are the throughput dependent cost of operating the LNG terminal. The biggest

expense is the cost for electricity. For the electricity consumption of the pumps and blowers a

price of 0.05 Euro/kWh was assumed.

Another cost item is related to the gas consumption of the regasification process. Assumption is

that heat will be recovered during the operation of DPS. Assuming a typical plant availability of

91%, during the remaining time period gas itself will be utilised to regasify the LNG. A quantum

of 0.14% of the sent-out is used as fuel gas using the price of 223.3 EUR/t.




LI 260442 Page 3-27

# Item

1

2

3

Costs in T EUR/a

Fuel Gas for LNG Vaporisation 184

Electricity for HP Pumpsand Blowers 1,550

Total Annual Variable OPEX: 1,739

Caustic Soda for Vaporisation 5

Table 3-7: Estimate of Annual Variable OPEX

3.2.3 Dynamic Unit Cost Assessment for Case (I) and (II)

The approach applied for the economic analysis of fuel supply options was explained in section

3.1.3. The calculation of the DUC is provided in the following charts.

Fuel supply figures are applied in accordance to the individual demand scenarios. Regarding

the high gas demand scenario (Case I) the DUC of the proposed LNG supply scheme amount to

23.8 EUR per tonne of fuel. The DUC are marginally higher (3%) for the base gas demand sce-

nario resulting in 24.4 EUR per tonne of fuel.

Finally a comparison of the DUC for both gas supply options investigated in this study is provi-

ded. The lowest cost occurs for the LNG scheme regarding the high gas demand scenario. Its

DUC are 9% lower compared with the DUC of the related pipeline scheme based on the same

demand projection.

Nearly the same result was evaluated for the base gas demand scenario. The DUC of the

pipeline scheme are 10% lower compared with the DUC of the related LNG scheme based on

the same demand projection.

Item Unit

LNG Scheme

high (Case I)

LNG Scheme

base (Case II)

Pipe Scheme

high (Case I)

Pipe Scheme

base (Case II)

PV Capital T EUR /a 116,320 116,320 139,090 139,090

PV OPEX T EUR /a 55,095 55,095 13,553 13,553

Dynamic Unit Cost EUR/t 23.8 24.4 25.9 26.8

Table 3-8: Dynamic Unit Cost of LNG and Pipeline Schemes




LI 260442 Page 3-28

Table 3-9: Dynamic Unit Cost of the LNG Scheme - Case (I)

1

Ge

ne

ral

Info

rmati

on

Case:

Gas D

em

and

Sce

na

rio H

igh

To

tal In

ve

stm

en

t in

T E

UR

10

2,1

01

Dis

co

un

t R

ate

6.5

%

Lifetim

e in a

30

Co

nstr

uctio

n P

erio

d in a

3

Sta

rt o

f O

pe

ratio

n2

011

2

Ca

sh

Flo

w

Item

Year

>>

n-3

n-2

n-1

15

10

15

20

25

30

Investm

ent

Cost

T E

UR

/a

35,7

35

35,7

35

30

,630

00

00

00

0

Fix

ed

OP

EX

T E

UR

/a

00

02

,480

2,4

80

2,4

80

2,4

80

2,4

80

2,4

80

2,4

80

Va

ria

ble

OP

EX

T E

UR

/a

00

01

,739

1,7

39

1,7

39

1,7

39

1,7

39

1,7

39

1,7

39

Fu

el G

as S

up

plie

dt/

a0

00

49

0,7

09

51

7,5

39

54

6,6

81

58

0,2

92

613

,903

64

8,6

47

68

5,3

57

3

Pre

sen

t V

alu

e

Capital

T E

UR

/a

116,3

20

OP

EX

T E

UR

/a

55,0

95

Fu

el G

as S

up

plie

dt/

a7,2

16,3

29

4

Dyn

am

ic U

nit

Co

st

DU

C -

Gas S

up

ply

EU

R /

t23

.8

EU

R /

100

0m

³17

.7




LI 260442 Page 3-29

Table 3-10: Dynamic Unit Cost of the LNG Scheme - Case (II)

1

Gen

era

l In

form

ati

on

Ca

se:

Ga

s D

em

an

d S

cen

ario B

ase

To

tal In

ve

stm

ent

in T

EU

R10

2,1

01

Dis

cou

nt

Rate

6.5

%

Lifetim

e in

a30

Co

nstr

uctio

n P

erio

d in a

3

Sta

rt o

f O

pera

tion

20

11

2

Ca

sh

Flo

w

Ite

mY

ear

>>

n-3

n-2

n-1

15

10

15

20

25

30

Inve

stm

ent

Co

st

T E

UR

/a

35

,735

35

,735

30,6

30

00

00

00

0

Fix

ed O

PE

XT

EU

R /

a0

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LI 260442 Page 3-30

3.3 Technical Description of the Proposed Scheme for Case (III)

As it can be seen in Figure 2-1 (Section 2.1.1) the projected gas demand figures for the Low

Gas Demand Scenario is almost stagnant and actually declines slightly after the year 2020. Al-

though it is a very small gas demand we have calculated the CAPEX and OPEX figures for this

case.

The main difference in the design of the LNG terminal for Low Gas Demand Scenario is the size

of the LNG Storage tank. For this low gas demand we have taken the design sent-out of some

0.170 bcm/a and slightly higher volumes such as 0.200 bcm/a and 0.240 bcm/a to show the

sensitivities of the low gas demand scenario.

The vessel size was adopted for this low gas demand and vessels with a cargo volume of

5,000 m³; 10,000 m³ and 20,000m³ were selected. LNG vessels with a cargo volume of some

LNG Storage Required

13,80714,438

15,279

24,04124,672

25,513

29,158 29,78830,629

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

0.170 0.200 0.240Natural Gas Send Out (bcm/a)

LN

G S

tora

ge

Re

qu

ire

d (

m³)

10,000 m³ Ship 20,000 m³ Ship 25,000 m³ Ship

Figure 3-11: Required LNG onshore Storage vs. LNG vessel size




LI 260442 Page 3-31

20,000 m³ and below have a maximum length of 150 meters and a maximum draft of

7.6 meters. Therefore no dredging is required at the existing berth and the Delimara Power Sta-

tion.

General Data

LNG Storage Vessel Size 10,000 20,000 25,000 m³

LNG Storage Vessel Size (Net) 9,700 19,400 24,250 m³

4 days

Daily Send Out - Maximum (% over Nominal) 10%

Fuel Gas (% of Send Out) 2.0%

Low Gas Demand Scenario

Gas Send Out Flow Rate 0.17 0.17 0.17 bcm/year

Gas Send Out Flow Rate 512,329 512,329 512,329 m³/day (Gas)

Gas Send Out Flow Rate 830 830 830 m³/day (LNG)

Fuel Gas Flow Rate 17 17 17 m³/day (LNG)

Gas Send Out (Gross) 847 847 847 m³/day (LNG)

Reserve storage due to inclement weather/ship delays 3,388 3,388 3,388 m³

Sub-Total - Required Storage 13,088 22,788 27,638 m³

LNG Tank Heel 5.5% 720 1,253 1,520 m³

Storage Required 13,807 24,041 29,158 m³

Ship Frequency 11.5 22.9 28.6 days




Gas Send Out Flow Rate 976 976 976 m³/day (LNG)


Gas Send Out (Gross) 996 996 996 m³/day (LNG)



LNG Tank Heel 5.5% 753 1,286 1,553 m³






Gas Send Out Flow Rate 1,172 1,172 1,172 m³/day (LNG)


Gas Send Out (Gross) 1,196 1,196 1,196 m³/day (LNG)



LNG Tank Heel 5.5% 797 1,330 1,597 m³



Number of days to provide reserve storage due to inclement

weather/ship delays/plant operations/etc.

Table 3-11: Calculation for required LNG Storage Volume – Case (III)




LI 260442 Page 3-32

Looking at the graph in the figure above it is evident that the biggest factor in determining the

onshore storage requirements is the size of the vessel that supplies the LNG. It appears that a

LNG storage tank with 15,000 m³ is the optimum solution for the low gas demand scenario

based on a LNG supply vessel with a cargo volume of 10,000 m³. However, in reality it will be

difficult to secure a charter for a LNG vessel with 10,000 m³ cargo volume in the Mediterranean.

It is more likely to secure a charter of a 25,000 m³ LNG vessel. It is therefore recommended to

install a 30,000 m³ onshore storage tank for the low gas demand scenario.

Please note that partial unloading of LNG i.e. unloading of 25,000 m³ from a 60,000 m³ LNG

vessel is usually not allowed. LNG cargo vessels that are only partially filled are subject to the

so called sloshing effect that make a vessel instable during bad weather and also lead to higher

BOG rates during the journey.

Table 3-11 shows the general assumptions for the LNG storage tank calculations.

3.3.1 Basic Design

The basic design for Case (III) is the same as for Case (I) and (II)

3.3.2 Location

The location for Case (III) is the same as for Case (I) and (II).

3.3.3 Potential Hazards

The hazards and risk for Case (III) is the same as for Case (I) and (II).




LI 260442 Page 3-33

3.4 Economic Description of the Proposed Scheme for Case (III)


The below table provides the scheme’s investment cost in total and for each major component.

In total, the projects investment cost amounts to 75.7 Mio Euro (10% contingencies and 12%

contractors total profit, mark-up are included). The project duration regarding is estimated at

three years. The related disbursement schedule of the investment is shown in Table 3-13.

# Item

1

2

3

4

5

6

Investment Costs

in T EUR

Owner's Engineering Services 3,299

Specialty Contractors 22,944

876

2,237

2,730

Direct Cost (Labor, Materials & Subcontracts) 43,619


Total: 75,705



Table 3-12: Investment Cost of LNG Scheme Case (III)

Year n-3 n-2 n-1 n


Table 3-13: Disbursement of the Investment Cost of LNG Scheme Case (III)

As illustrated in Figure 3-12 the dominating investment cost proportion are the direct cost which

includes:

o Site Preparation and Improvement;

o Process Equipment;




LI 260442 Page 3-34

o Underground and Aboveground Pipelines;

o Underground and Aboveground Electric Equipment;

o Concrete, Instrumentation and Insulation;


Nearly a third of the total investment is caused by the specialty contractors cost which includes:

o LNG Tank Costs;

o Jetty Upgrades Costs;


58%

1%

3%

4%4%

30%Direct Cost (Labor, Materials & Subcontracts)




Owner's Engineering Services

Specialty Contractors

Figure 3-12: Investment Cost Break Down of the LNG Scheme for Case (III)




LI 260442 Page 3-35


LNG Price Estimation:

The price estimation and the approach regarding the price projection is described in the Section

3.2.1 of this report.

Fixed O&M Costs;

For the LNG terminal the fixed operation expenditures have been estimated as stated in the fol-

lowing table.

# Item

1

2

3

4

5

6

7

8

9

Inspection


Maintenance

Nitrogen

Telecommunication 20

Permits & other Fees 30

Costs in T EUR/a

Management and Operation 960

Tugboat Operation Fees 80

40

690

20

Technical Assistance 200

150 Insurance


Variable O&M Costs

Variable OPEX are the throughput dependent cost of operating the LNG terminal. The biggest

expense is the fuel cost for the regasification process the LNG.

Assumption is that 1.5% of the sent-out is used as fuel gas using the price of 223.3 EUR/t. For

the electricity consumption of the pumps and blowers a price of 0.05 Euro/kWh was assumed.




LI 260442 Page 3-36

# Item

1

2

3

Costs in T EUR/a

Fuel Gas for LNG Vaporisation 37

Electricity for HP Pumpsand Blowers 520

Total Annual Variable OPEX: 559

Caustic Soda for Vaporisation 2

Table 3-15: Estimate of Annual Variable OPEX

3.4.3 Dynamic Unit Cost Assessment for Case (III)

Similar to the results of the assessment of the low gas demand scenario pipeline scheme the

DUC calculation brings out that the dynamic unit cost of the LNG scheme are extremely high.

While the Case (III) gas demand figures are substantially lower compared to the base scenario,

the CAPEX and OPEX of the scheme do not decrease in the same range. Finally the dynamic

unit costs are nearly three times higher (78.3 EUR/t compared to 24.4 EUR/t).




LI 260442 Page 3-37

Table 3-16: Dynamic Unit Cost of the LNG Scheme - Case (III)

1

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LI 260442 Page 4-1

4 Techno-economic Specification of CNG Infrastructure

Compressed Natural Gas (CNG) is not yet publicly traded in any sizeable from or shape, this is

due to the lack of available infrastructure for CNG. Some countries have introduced miniature

CNG pilot projects for CNG powered vehicles such as busses or trucks. However, CNG has still

no sizeable market penetration that would allow the development of a commercial model for a

large scale CNG supply to Malta. There are no CNG vessels that are currently operating to

supply demand centres. Therefore CNG will not be considered in the further analysis. However,

typical future applications for CNG would be the supply of small Islands or small remote areas

that have no indigenous gas production or gas pipeline connection to supply gas.

However instead a CNG supply scheme a LNG regasification vessel could be an alternative to

the onshore LNG terminal or the sub sea gas pipeline from Sicily.

4.1 Technical Description of a LNG Regas Vessel

The only feasibly alternative to a LNG import using a conventional LNG Import and rega-

sification terminal is ship based re-gasification vessels developed by Exmar i.e. Energy Bridge.

A regasification vessel is capable of three different modes of cargo transfer (i) off-shore transfer

of gas via the STL Buoy; (ii) dock-side transfer via the high pressure gas manifold or (iii) LNG

transfer dockside into tanks or across dock ship to ship .

A typical re-gas vessel carries about 138 000 m3 LNG which converts to approximately 2.8 bcf

Gas or ~80 Mio m3 natural gas

Discharge pressure is up to 100 bars at a temperature of 4-5 deg. °C. Capacities of existing re-

gas fleet:

Capacity in Off-shore Mode is 14,150,000 m3/d using sea-water

(Unloading ~5.6 days);

Capacity in Dock-side Mode is 12,750,000 m3/d without sea-water

(Unloading ~6.2 days);

The turn-down ratio for Regas vessels is quite high and can be as low

as 2,830,000 m3/d.

The requirements for the Base Gas Demand Scenario are:

Average daily send-out is about 114,500 m3/h or 2,750,000 m3/d this means that the Regas

vessel will take about 30 days to empty its cargo volume of 80;000,000 m3 natural gas. In total

Malta would require 10 Regas shipments per year.




LI 260442 Page 4-2

The maximum hourly sent-out is about 165,000 m3/h which is well within the range of the Regas

vessel. The installation cost for the off-shore solution is about 32 Mio EUR not including the

onshore interconnection pipeline. Please note that for continuous supply (i.e. base load termi-

nal) a second STL Buoy has to be installed.

The dock-side solution requires the use of a jetty. This technology is only about 2 years old and

only about 15 LNG cargos have been delivered using Regas vessels. So far no technical

problems have been encountered but it is premature to declare Regasification vessel a proven

technology without risk!

Below is a schematic drawing showing a typical Regas-vessel.

Figure 4-1: Schematic Overview of a Regas-Vessel

High Pressure Pumps

And Vaporisers

Reinforced

LNG

Storage Tanks

Energy Bridge™

Regasification Vessel

Traction

Winch

Buoy

Compartment

Oversized

Boiler




LI 260442 Page 4-3

It should be noted that there is no prevailing business Model to charter LNG Regas vessels. So

far a “Fee for Service” approach has been used, but there is little to commercial history. The

“Fee for Service” Schedule Rates are not published and most likely require extensive case by

case negotiations.

The LNG Regasification vessels were primarily developed (i) to have an alternative LNG deli-

very method in areas where conventional LNG Regas terminal can not be built due to environ-

mental and general permitting concerns for a regasification terminal and (ii) where the gas

demand is either very small (< 2 bcm/a) or only spot delivery of LNG is required.

However, since Malta has the possibility to build a LNG terminal onshore it is not recommended

to further pursue the Regas vessel as an alternative delivery method.




LI 260442 Page 5-4

5 Dynamic Unit Cost Analysis for Gas Supply Alternatives

In order to provide a transparent and methodologically sound indicator to compare the different

gas supply options, the dynamic unit cost (DUC) calculation was carried out for each technically

feasible option. The dynamic unit cost approach allows to consider the full supply costs taking

into consideration its specific cost structure in terms of investment breakdown and expenditure

schedule, and to condense this case-specific and therefore heterogeneous information into one

homogeneous and meaningful cost information.

This chapter provides the comparison of the DUC calculations presented in the previous sec-

tions. Under consideration of all gas demand scenario below Table 5-1 provides the total fuel

Item Unit

EUR/t

EUR/t

Total EUR/t

Item Unit

EUR/t

EUR/t

Total EUR/t

Item Unit

EUR/t

EUR/t

Total EUR/t

Dynamic Unit Cost

of Fuel Supply78.3 96.4

258.3 299.0

Projected Market

Fuel Price (2011)180.0 202.6

203.7 228.5

LNG Scheme

Low Gas Demand

Pipeline Scheme

Low Gas Demand

Projected Market

Fuel Price (2011)180.0 202.6

Dynamic Unit Cost

of Fuel Supply23.8 25.9

LNG Scheme

High Gas Demand

Pipeline Scheme

High Gas Demand

202.6

26.8

LNG Scheme

Base Gas Demand

Pipeline Scheme

Base Gas Demand

180.0

204.4 229.4

Dynamic Unit Cost

of Fuel Supply

Projected Market

Fuel Price (2011)

24.4

Table 5-1: Comparison of Fuel Supply Cost – Gas Supply Alternatives




LI 260442 Page 5-5

110.0

130.0

150.0

170.0

190.0

210.0

230.0

250.0

270.0

2010 2015 2020 2025 2030

Year

Gas v

ia L

NG

Co

nvers

ion

EU

R/t

110.0

130.0

150.0

170.0

190.0

210.0

230.0

250.0

270.0

2010 2015 2020 2025 2030

Year

Natu

ral

Gas v

ia P

ipeli

ne E

UR

/t

Figure 5-1: Comparison of Fuel Gas Prices of Supply Alternatives investigated




LI 260442 Page 5-6

costs in EUR per tonne including the costs of the supply and the market price (for the first pos-

sible year of supply scheme’s operation). The approach for the price projection is described

already in the Section 3.2.1 of this report.

Exemplarily the results within the frame of the base gas demand are discussed here. The LNG

scheme is the gas supply alternative which contributes the lowest fuel cost. The costs of some

204.4 EUR/t are 11% lower than the cost of the pipeline scheme. An overview of the costs’

development up to the year 2030 is provided in the above charts. The LNG alternative leads to

221.0 EUR/t in 2030 whereas the pipeline alternative reaches 248.2 EUR/t.

In all comparative assessments, the LNG scheme is that one with the lowest costs. Therefore it

is recommended as the least cost gas supply option and the related cost are used as input

figures within the techno-economic assessment of the gas-based local power generation op-

tions.




LI 260442 Page 6-1

6 Techno-economic Specification of Gas-Based Generation Options

This chapter of the report is devoted to technical and economic aspects of gas-based

generation options identified and considered as potential candidates for the expansion of the

Maltese power generation system. Within the frame of the identification process LI’s experts

considered two basic types of projects.

These are:

the construction of new generation units; and

the refurbishment of existing units.

The investigated supply options are summarised in the following Table 6-1. In the manner intro-

duced for the existing power generation units (see Chapter 1 of this report) each supply option is

labelled by an identification code which will be used in the following sections and later be

applied within the computer-aided system simulation (Work Package III).

Item

Capacity

Range Description

Identi-

fication

Option 1 ~ 100 MW New Gas-fired combined cycle gas turbines

in 2 GT and 1 ST configuration CCGT 2+1

Option 2 ~ 100 MW New Gas-fired combined cycle gas turbines

in 1 GT and 1 ST configuration CCGT 1+1

Option 3 + 120 MW Repowering of an (existing) condensing steam turbine to

combined cycle in 2 GT + 1 ST configuration 2+1 ST R

Option 4 + 40 MW Repowering of (existing) gas turbines to combined cycle

in 2 GT + 1 ST configuration 2+1 GT R

Table 6-1: General Data – New Gas-Based Generation Options




LI 260442 Page 6-2

6.1 Technical Description of Gas-Based Generation Option 1 (CCGT 2+1)

6.1.1 Basic Design

Due to their high efficiency combined cycle gas turbine (CCGT) stations are the dominant power

generation technology in recent years in Europe (see also WP I Report). The plants can be

operated on natural gas or oil (Gasoil, Light Crude Oil). The heat of the exhaust gas from the

gas turbine is used to make steam to generate additional electricity via a steam turbine; this last

step thus enhances the efficiency of electricity generation.

For the first supply option a combined cycle power plant consisting of two gas turbines, two heat

recovery steam generators (HRSG) and one condensing steam turbine was defined. At an

international level three important manufacturers offer such power plants (i) General Electrics

(GE) Power Systems; (ii) Alstom; and (iii) Siemens. In the following the major technical and

operational characteristics of this supply option are presented. Maltese local conditions and

provided fuel specifications have been considered. The performance data of this supply option

as presented in the following is based on the gas turbine (GT) of type GE 6581B and dual

pressure HRSG without duct burner firing.

Plant Characteristics Unit Value

Plant Type CCGT 2+1

Set Size (nominal) MW 128.0

Partial Load 100% 85% 70% 50% 30% 20%

Set Capacity (gross) MW 128.0 109.3 89.6 63.6 38.4 25.1

Set Capacity (net) MW 125.5 106.9 87.0 62.0 36.9 24.8

Auxiliary Power MW 2.5 2.4 2.6 1.6 1.4 0.3

Self Consumption % 1.9% 2.2% 2.9% 2.5% 3.8% 1.2%

Turbines in Operation 2GT+1ST 2GT+1ST 2GT+1ST 1GT+1ST 1GT+1ST 1GT

Partial Load 100% 85% 70% 50% 30% 20%

Net Heat Rate kJ/kWh 7,441 7,647 7,963 7,528 8,478 13,974

Planned Outage d/a 20

Forced Outage %/a 3%

Max Availability %/a 91.5%

Table 6-2: Technical Data – Gas-Based Generation Option 1




LI 260442 Page 6-3

Another possible gas turbine types of similar size are for example the Siemens SGT-800F.

The gas turbines are designed with a dual fuel combustion system using LNG (gaseous) as

primary fuel. The design capacity of the gas turbines amounts to 41.1 MW (Net) each. The de-

sign capacity of the steam turbine is 43.2 MW (Net). For the cooling system an open loop water

cooling with a seawater inlet temperature of 20 °C and an allowable cooling water temperature

rise of 8 K is assumed.

The heat recovery steam generators (HRSG) are equipped with a bypass stack for simple cycle

operation of the gas turbines in order to increase the operational flexibility of the plant. Most

important for the steam cycle efficiency is the HRSG configuration and design. Both HRSG

produce in total 35.4 kg/s high pressure steam with 67.7 bar and 529 °C and an intermediate

pressure steam of 5.92 kg/s with 8.3 bar and 258 °C.

Table 6-2 provides the general technical parameters of the supply option (design conditions). A

partial load range between 100% (full load) and 20% is selected regarding the provision of the

operational characteristics, which can be summarized as follows:

The plant’s self consumption (auxiliary power) drops from 2.5 MW to 0.3 MW in absolute

terms. Related to the plants output the value increases from 1.9% (2 GT + 1 ST opera-

tion) to 3.8% (1 GT + 1 ST operation) and decreases then to some 1.2% (1 GT opera-

tion);

The plant’s net heat rate increases from 7,441 kJ/kWh to nearly 14,000 kJ/kWh over the

entire range of partial load. This is equal to a net efficiency decrease from 48.4% to

25.8% only.

Assuming outage characteristics of an average of 20 days a year for the units’ maintenance and

a 3% forced outage, the maximum availability of the plant is expected to amount 91.5% over a

year. The net and gross heat rates of the gas based supply option 1 are shown in the following

figure over the entire load range (calculated on fuel’s NCV). The results of GT Pro calculations

are summarized within the heat and mass balance diagrams in the Figures 6-2 and 6-3. The

calculations are based on the maximum load of the plant during summer and winter conditions.

The comparison of the summer and winter parameters brings out the following results:

The plant’s net capacity during summer amounts to only 88% (111.7 MW) compared to

the net capacity during the winter period by some 127.1 MW. Our analysis of the existing

system already brought out similar capacity levels in relation to the temperature

fluctuations in Malta (see work package I);

The plants’ net heat rate decreases from 7,560 kJ/kWh during summer to 7,414 kJ/kWh

during winter. This is equal to a net efficiency increase from 47.6% (summer) to 48.6%

(winter).




LI 260442 Page 6-4

Figure 6-1: Gross and Net Heat Rates – Gas-Based Generation Option 1

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565

T 9

60

.7 M

2.3

84 m

^3/k

g6

36.2

m^3

/s

565

4

88

4

88

488

4

77

3

02

30

1

270

2

67

23

7

237

1

90

1

60

16

0

118

T 9

60

.7 M

1.1

36 m

^3/k

g3

03

.2 m

^3/s

426

45

kW

0.0

385

M

FW

0.1

03

2 p

46 T

148

.8 M

46 T

2.3

23

p

11

6 T

15

0.3

M

LT

E

46

T 1

50.3

M

116 T

2.3

23 p

12

5 T

152.9 M

9.1

59

p

17

1 T

15

2.9

M

IPE

2

9.1

59 p

176 T

23.9

M

IPB

8.9

93 p

22

8 T

21

.3 M

IPS

1

8.8

44 p

260

T

21.3

M

IPS

2

2.609 M

73.7

9 p

230 T

125.7

M

HP

E2

72

.49

p

28

2 T

12

5.7

M

HP

E3

72.4

9 p

288

T

124

.4 M

HP

B1

71.8

2 p

309

T

124

.4 M

HP

S0

70

.09

p

54

5 T

12

6 M

HP

S3

1.5

0 M

67

.73

p 5

29 T

12

7.5

M

70.09 p 545 T

1.5

8 M

3.0

8 M

21.3

M

8.325 p 258 T

Abbreviation:

p -pressure in bar

M -mass flow in kg / s

T -temperature in °C

Colours:

red -gas, air and exhaust gas flow

violet-high pressure steam

light blue-intermediate pressure steam

dark blue-feed water and water injection to gas turbine

Fig

ure

6-2

: H

eat

an

d M

ass B

ala

nce –

Gas-B

ased

Ge

ne

rati

on

Op

tio

n 1

(S

um

me

r C

on

dit

ion

s)

MA

LT

A R

ES

OU

RC

ES

AU

TH

OR

ITY

Energ

y I

nte

rco

nnection E

uro

pe -

Malta

Marc

h 2

008

Fin

al

Rep

ort

– W

ork

Packag

e I

IA

LI

2604

42

Page 6

-6

GT

MA

ST

ER

17.0

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. E

isenhart

316 0

8-2

0-2

007 1

0:4

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=T

:\26\0

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result

s\G

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lo

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ditio

ns.g

tm

CC

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2+1 c

onfigura

tion N

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100%

load a

t w

inte

r conditio

ns

Net

Pow

er 127120 k

WLH

V H

eat R

ate

741

4 k

J/k

Wh

p[b

ar],

T[C

], M

[t/h

], S

team

Pro

pertie

s: IA

PW

S-IF97

1X

GE

6581B

2 X

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41563 k

W

1.0

1 p

13 T

45 %

RH

523 m

1 p

13 T

523 m

LN

G 9

.789 m

20 T

LH

V= 1

30906 k

Wth

12.4

4 p

358 T

11.9

4 p

1136 T

532.8

m

1.0

4 p

551 T

1065.5

M

75.3

%N

2 1

3.9

5 %

O2

3.3

78 %

CO

2 6

.469 %

H2O

0.9

067 %

Ar

549 T

1065.5

M

2.2

99 m

^3/k

g680.4

m^3

/s

549

482

482

482

471

305

303

274

271

242

242

193

163

163

117 T

1065.5

M

1.1

2 m

^3/k

g331.6

m^3

/s

46507 k

W

0.0

399 M

FW

0.0

544 p

34 T

153.9

M

34 T

2.3

23 p

114 T

155.5

M

LT

E

34 T

155.5

M

114 T

2.3

23 p

125 T

158.8 M

9.5

65 p

174 T

158.8

M

IPE

2

9.5

65 p

178 T

26.9

2 M

IPB

9.3

72 p

229 T

23.6

1 M

IPS

1

9.1

98 p

261 T

23.6

1 M

IPS

2

3.303 M

75.5

p

233 T

131.6

M

HP

E2

74.0

8 p

285 T

131.6

M

HP

E3

74.0

8 p

290 T

130.3

M

HP

B1

73.3

6 p

309 T

130.3

M

HP

S0

71.5

7 p

530 T

130.3

M

HP

S3

69.1

5 p

528 T

130.3

M

71.57 p 530 T

23.6

1 M

8.612 p 259 T

Abbreviation:

p -pressure in bar



Colours:





Fig

ure

6-3

: H

eat

an

d M

ass B

ala

nce –

Gas-B

as

ed

Gen

era

tio

n O

pti

on

1 (

Win

ter

Co

nd

itio

ns)




LI 260442 Page 6-7

6.1.2 Location

Regarding the possible erection of new power generation units, in general it was set focus to the

Delimara Power Station site.

Potential sites for additional power generating facilities (such as CCGTs) are already reserved

for the Delimara Power Station site. The geometric properties of supply option 1 would be com-

parable to those of the already existing combined cycle plant. This one and the potential sites

for the new CCGT are illustrated in the modal and map provided in the following figure.




LI 260442 Page 6-8

Figure 6-4: Potential Location of Gas-Based Generation Option 1

6.1.3 Air Pollution Emissions

In the following tables the environmental impact due to potential air pollution emissions is

considered. Based on the unit’s capacity and thermodynamic parameters, like e.g. specific

energy input and combustion temperatures as well as fuel air ratio lambda, the unit’s behaviour

regarding all possible operation modes was simulated. As already known both from physical

theory and operational experience, the partial load behaviour in terms of efficiency and fuel

consumption cannot be compared with full load operation mode. According to CO2 and SO2

emissions, the specific values for considered generation technologies can be reviewed over

several plant’s load characteristics. Moreover NOx conditions and influence parameters are sho-

wn as well as the specific emissions. Generally speaking, the NOx emissions are declining while

the unit operates in partial load, because of being significantly addicted to the combustion

temperature which is also declining due to thermo-dynamic simulations.

Calculations were carried out to demonstrate that the supply option 1 complies with the EU envi-

ronmental directives and with all the relevant aspects of the Maltese Legislation Act YY of 2001

(“Environmental Protection Act) as well as with the associated legal notices. With regard to the

European Large Combustion Plant Directive (LCPD 2001/80/EC) EU Member States may

choose, by 1 January 2008, to either comply with the Emission Limit Values (ELV) set down in

the LCPD or to produce and implement a national emission reduction plan. National plans

should reduce the total annual emissions of SO2, NOx and particulate matter to the levels that

would have been achieved by applying the ELVs set out in the LCPD to existing plants in

operation in the year 2000, on the basis of each plant’s operational performance averaged over




LI 260442 Page 6-9

the last five years of operation up to and including 2000. Furthermore, national plans should

specify the measures that will be implemented to ensure that this is achieved.

Malta’s National Programme under the Emissions Ceilings Directive was prepared by the Malta

Environmental and Planning Authority (MEPA) and published in December 2006. The program-

me describes clearly the current state and provides detailed targets regarding the future

development of Nitrogen Oxides and Sulphur Dioxide emissions of the power generating sector

in Malta.

Impacts on the existing generation system were already described in the report of the work

package I (in particular the limited operation hours of the Marsa Power Station). Regarding to

the operation of new power plants the National Programme under the Emissions Ceilings

Directive provides the following emission factors (EF):

2010: Unabated EF for NOx emissions of 500 t/PJ; Abated EF for NOx emissions

of 155 t/PJ (assuming a removal efficiency of 69%);

2010: Unabated EF for SO2 emissions of 234 t/PJ; Abated EF for SO2 emissions


2020: Unabated EF for NOx emissions of 500 t/PJ; Abated EF for NOx emissions


2020: Unabated EF for SO2 emissions of 234 t/PJ; Abated EF for SO2 emissions

of 57 t/PJ (assuming a removal efficiency of 80%).

The above targets are related to the energy input before the conversion to the plant’s electricity

output (sent-out). Transforming the values to the plant’s sent-out related emission limits the

following ELV for new power generating facilities have to be considered:

A maximum of 1.2 g/kWh regarding the emissions of NOx;

A maximum of 2.2 g/kWh regarding the emissions of SO2.

The Greenhouse Gas Emission Trading Scheme (EU Directive 2003/87/EC) was transposed in

the L.N. 140/2005 of the Maltese Legislations and sets the limits on Greenhouse Gas Emissions

(mainly CO2). Regarding the plant’s sent-out the EF amounts to:

A maximum of 630 g/kWh regarding the emissions of Greenhouse Gases.




LI 260442 Page 6-10

General Information

# Item 1

1 Plant Name Natural Gas Based Supply Option 1

2 Plant Type Combined Cycle Gas Turbine

3 Unit CCGT 2+1 NG fired

4 State Option

5 Unit_Ident

6 Comments

No Comments

Technical & Operational Data for Emissions (continued)

# Item Dim 1

7 Nominal Capacity MW 127.9

8 Max Capacity Sent-Out (Operation) MW 125.5

9 Min Capacity Sent-Out (Operation) MW 31.1

10 Heat Rate* Coeff A (2+1) - 3,010

11 Heat Rate* Coeff B (2+1) - -6,795

12 Heat Rate* Coeff C (2+1) - 11,238

10a Heat Rate* Coeff A (1+1) 15,328

11a Heat Rate* Coeff B (1+1) -16,885

12a Heat Rate* Coeff C (1+1) 12,144

13 Combustion Temp Coeff A - -742

14 Combustion Temp Coeff B - 1,579

15 Combustion Temp Coeff C - 485

16 Air Rate Lambda Case1 1.0 - 1.09

0

5000

10000

10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

kJ /

kW

h

700

2700

4700

6700

8700

10700

10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

[co

mb

. te

mp

.]

Table 6-3: Specifications of D_CC1NGo (1/3)




LI 260442 Page 6-11

NOx Emissions

# Item 1

17 Thermal Nox Coeff. A 1E-21 Fuel Nox Coeff. A NA

18 Thermal Nox Coeff. B 7.72 Fuel Nox Coeff. B NA

19 Fuel Nox Coeff. C NA

20 Thermal NOx Emissions over load (RAW)

21 Specific NOx Emissions in g/kWh Absolute NOx Emissions in tons

Fuel Specifications

22 Initial Primary Fuel Rich gas Natural Gas % of Carbon 75.00%

23 Net Calorific Value kJ/kg 48,156 % of Nitrogen 0.00%

24 Required Fuel at 100% load kg 19,795 % of Sulphur 0.00%

25 Required Combustion Air m³ 9.89 % of Nox Reduc. 50.00%

26 Resulting Exhaust Gas m³ 10.34 % of SO2 Reduc. 0.00%

Fuel NOx Emissions over load (RAW)

Fuel Composition

(Emission Relevant)

Potential Emission Reduction

0.0

0.5

1.0

1.5

2.0

2.5

10% 20% 30% 40% 50% 60% 70% 80% 90%

[g/kWh]

0.00

0.20

0.40

0.60

0.80

1.00

1.20

0

200

400

600

800

1,000

1,200

10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

mg/m³

0

200

400

600

800

1,000

1,200

1

mg/m³

2242

6376

64

107

158

211

255

7

0

50

100

150

200

250

300

13 26 38 51 64 77 90 102 115 128

kg Nox

RAW

0.0

20.0

40.0

60.0

80.0

100.0

120.0

140.0





LI 260442 Page 6-12

CO2 and SOx Emissions

# Item 1

27 Fuel needed at 100% load t 19.79

28 Density of Fuel kg / m³ 0.77

29 CO2 emission at 100% load t 53.38

30 Specific CO2 Emissions in g/kWh Absolute CO2 Emissions in t

31 Specific SOx Emissions in g/kWh Absolute SOx Emissions in tons

Exhaust Gas development in m³ due to Gross Performance

32

29,12351,499

69,655

103,402

135,795152,889

169,723186,792

204,592

86,115

0

50,000

100,000

150,000

200,000

250,000

1

m³ Exhaust Gas

525474

439 422462 446 433 423 417

594

0

200

400

600

800

10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

[g/kWh]

7.613.4

18.222.5

27.0

35.439.9

44.348.7

53.4

0

10

20

30

40

50

60

13 26 38 51 64 77 90 102 115 128

[t CO2]

[MW]

n/a n/a





LI 260442 Page 6-13

The air pollution emissions of the investigated supply option:

do not exceed the limit value for NOx emissions;

do not exceed the limit value for SO2 emissions. Natural gas does not cause such

emissions at all;

are 54% below the current Green House Gas emissions (typical unit operation assumed)

and do not exceed the limit value for CO2 emissions.

Finally, Figure 6-5 provides a comparison of the calculated GHG emissions of the supply option

and the today dominating technology in the Maltese power generation system.

871

420

921

-

100

200

300

400

500

600

700

800

900

1,000

Business as Usual

(all STs)

Business as Usual

(DPS ST)

Supply Option

Sp

ec

ific

Em

iss

ion

s g

CO

2/k

Wh

.

Figure 6-5: Comparison of Greenhouse Gas Emissions - Gas-Based Generation Option 1




LI 260442 Page 6-14

6.2 Economic Description of Gas-Based Generation Option 1 (CCGT 2+1)


The payment plan for a power plant project such as for the investigated supply options is closely

linked to the foreseen implementation schedule, in the way that there is normally a:

down payment of 10 – 20% of the contract value, covered by a down payment security, after

the award of contract to the Contractor;

a final payment of about 5% at the end of the warranty period; and a series of intermediate

payments linked to major events of work progress, the so-called “Milestones”, as there are:

o Mobilisation and site preparation;

o Civil works design;

o Civil construction works, incl. administration building;

o Architectural and civil finishing works;

o Design, manufacturing and transport of mechanical, electrical and Instrumentation & Control (I&C) equipment;

o Design, manufacturing and transport of the gas turbine generator(s);

o Erection of the gas turbine with auxiliaries, incl. commissioning and testing;

o Erection of heat recovery steam generator;

o Erection and commissioning of steam turbine generator;

o Erection and piping and components of water steam;

o Erection of cooling water system, mechanical, electrical and I&C equipment;

o Erection and commissioning of mechanical auxiliary equipment;

o Erection of electrical equipment;

o Erection of distributed control system (DCS) and other I&C equipment;

o Commissioning of the combined cycle;

o Reliability test run;

o Taking over by Owner.




LI 260442 Page 6-15

# Item

1

2

3

4

5

6

7

8

9

10

11

Total: 89,775

Heat Recovery Boiler

Cooling Facility/Cooling System

10,342

14,125

750

Gas Turbine Package incl. Generator 24,700

Steam Turbine Package incl. Generator

Investment Costs

in T EUR

Balance of Plant 6,095

Electrical Equipment 7,189

I&C Equipment 1,354

Civil/Buildings incl. On-Site Transportation 8,905

Engineering 3,470

Plant Startup 644

Contractor's Soft Costs 12,177

Table 6-4: Investment Costs of Gas-Based Generation Option 1

The above table provides the supply option’s investment cost in total and for each major com-

ponent. In total, the projects investment cost amounts to 89.8 Mio Euro (10% contingencies in-

cluded). The specific investment cost is 715 EUR/kW.

Figure 6-6 illustrates the investment break down. The dominating cost proportions are (i) the gas

turbine package; (ii) the heat recovery boiler; (iii) soft costs of the contractor and (iv) the steam

turbine package.




LI 260442 Page 6-16

Year n-3 n-2 n-1 n


Table 6-5: Disbursement Schedule of Gas-Based Generation Option 1

The investment’s disbursement was derived under consideration of the major project steps

which were explained at the beginning of this section (see Table 6-5; n is equal to the first year

of plants’ operation).

28%12%

16%

1%

7%

8%

2% 10%4%

1%

14%

Gas Turbine Package incl. Generator and Air

inlet cooling/heating if applicable




Balance of Plant

Electrical Equipment

I&C Equipment

Civil/Buildings incl. On-Site Transportation

Engineering

Plant Startup

Contractor's Soft Costs

Figure 6-6: Investment Cost Break Down of Gas-Based Generation Option 1




LI 260442 Page 6-17


Gas Supply Costs Estimation

As the result of the assessments in the chapters 1 to 5 the development of the costs of the

supply of gas to the power plant is presented in the below Table. The year 2011 is selected as

the first possible year of the plant’s operation. This assumption takes into account the project’s

schedule given in the previous section.

Item Unit 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

EUR/t 204.4 197.7 191.0 191.0 191.0 191.0 194.4 197.7 201.0 201.0

Item Unit 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

EUR/t 204.4 207.7 211.0 214.4 216.0 217.7 217.7 219.4 219.4 221.0

Fuel Supply Costs

(via LNG conversion)

Fuel Supply Costs


Table 6-6: Gas Supply Costs

Fixed O&M Costs

Fixed costs of operation and maintenance include expenses for staff salaries; insurance, fees

and other cost which remain constant irrespective of the actual quantum of the plant’s electrical

energy sent-out.

The personnel costs are calculated by the estimated number of required staff (25 employees)

and the average annual salary (30 T EUR/a). Based on experiences in similar assignments the

proportion of the remaining fixed operation and maintenance costs is 2.5% of the capital costs.

.

# Item

1

2


Costs in T EUR/a

Personnel Costs 750

Insurance, Fees and Others 2,244





LI 260442 Page 6-18

Variable O&M Costs

Variable costs of operation and maintenance include the cost of fuel and costs for e.g.

lubricating oil and chemicals which are consumed in proportion to the actual amount of the

plant’s electrical energy sent-out. The dominating proportion of the variable OPEX is the cost of

fuel, which depends on the fuel supply cost and the amount of fuel utilized. The latter item again

depends on the plant’s efficiency and further on the plant’s operation mode (e.g. full load or

partial load; number of turbines in operation). In the first section of this chapter the plant’s

performance parameters are described in detail. The following economic analysis considers

individual operation modes and the related specific fuel input. Based on our experience in

similar assignment the value of the remaining variable OPEX is estimated at 1.6 EUR/MWh.

6.2.3 Dynamic Unit Cost Assessment for Option 1

The economic analysis involves the derivation of the dynamic unit cost (DUC) for the proposed

local generation option. The (economic) dynamic unit cost is derived by dividing the present

value of the project costs at economic prices, by the present value of the quantity of output (the

plant’s net generation). In this case the DUC represents the specific power generation cost over

the project’s life cycle. Costs in this context are in reference to the investment and the variable

and fixed operation & maintenance costs. Duties, taxes, etc. are not taken into consideration for

the derivation of the economic dynamic unit cost. A discount rate of 6.5% is applied. The period

under consideration is equal to the estimated project’s economic lifetime.

The following chart provides the calculation of the dynamic unit cost of the gas-based option 1.

As far as the actual future operation of the plant is not known (this depends mainly on the most

economic dispatch of the unit as one component of the entire power generation system; see

Work Package III) we provide cost figures over the entire load range. Exemplarily the calculation

in the chart is based on an 85% load assumption. Nevertheless, the results are shown for

different operation modes from full load to partial load. The DUC trends are shown in Figure 6-7.

Regarding the expected annual net generation the option’s maximum availability of 91.5% is

considered in the 100% full load case.

In the selected 85% load case the DUC of the gas-based local generation option 1 amounts to

46.1 EUR/MWh. Only slight fluctuations of the DUC are observed within the plant’s base load

operation. In full load operation the DUC are 4% lower than the reference value. At 70% load

level the DUC are 9% higher than the reference value. In intermediate and peak load operation

the cost figures increase highly. At 50%-load an increase of 17% and at 20%-load an increase

of 141% is registered in comparison to the reference value.

The plant’s maximum annual net generation amounts to 1,006 GWh/a (at maximum availability

and full load).




LI 260442 Page 6-19

Table 6-8: Dynamic Unit Cost of the Gas-based Option 1

1

G

en

era

l In

form

ati

on

Loca

l Gene

ratio

n O

ptio

n 1

(C

CG

T 2

+1)

p

1.1

Tech

nic

al

1.2

Eco

no

mic

s

Pla

nt

Typ

e -

-C

CG

T 2

+1

Set

Siz

e (

nom

inal)

MW

128.0

Part

ial L

oad

100%

85%

70%

50%

30%

20%

To

tal I

nve

stm

en

tT

EU

R89,7

75

Set

Capaci

ty (

gro

ss)

MW

128.0

109.3

89.6

63.6

38.4

25.1

Dis

count

Rate

%6.5

%

Set

Capaci

ty (

net)

MW

125.5

106.9

87.0

62.0

36.9

24.8

Life

time

a30

Auxi

liary

Pow

er

MW

2.5

2.4

2.6

1.6

1.4

0.3

Const

ruct

ion

Pe

riod

a3

Self

Consu

mptio

n%

1.9

%2.2

%2.9

%2.5

%3.8

%1.2

%

Turb

ines

in O

pera

tion

--

2G

T+

1S

T2G

T+

1S

T2G

T+

1S

T1G

T+

1S

T

1G

T+

1S

T1G

TF

ixed O

PE

X

T E

UR

/a2,9

94

100%

85%

70%

50%

30%

20%

Variable

OP

EX

*E

UR

/MW

h1.6

Net

Heat

Ra

te

kJ/k

Wh

7,4

41

7,6

47

7,9

63

7,5

28

8,4

78

13,9

74

Fu

el T

ype

--

Reg

as

LN

G

Pla

nned O

uta

ge

d/a

20

Net

Calo

rific

Valu

ekJ

/kg

48,1

50

Forc

ed O

uta

ge

%/a

3%

Max

Ava

ilabili

ty%

/a91.5

%*

oth

er

tha

n F

ue

l C

osts

2

Cash

Flo

wO

pe

ratio

n a

t 8

5%

Load

Item

Year

>>

n-3

n-2

n-1

12

34

510

20

30

Inve

stm

ent

Co

stT

EU

R/a

44

,888

26,9

33

17,9

55

00

00

00

00

Fix

ed O

PE

XT

EU

R/a

00

02,9

94

2,9

94

2,9

94

2,9

94

2,9

94

2,9

94

2,9

94

2,9

94

Variable

OP

EX

T E

UR

/a0

00

31

,748

30,7

61

29,7

74

29,7

74

29,7

74

31,2

54

34,2

15

36

,787

Fuel S

up

ply

Cost

s (s

peci

fic)

EU

R/t

00

0204

198

191

191

19

1201

221

238

Fuel S

up

ply

Cost

s (a

bso

lute

)T

EU

R/a

00

030

,256

29,2

70

28,2

83

28,2

83

28,2

83

29,7

63

32,7

23

35

,296

Fuel I

nput

t/a

00

0148,0

45

148,0

45

148,0

45

148

,045

148,0

45

148,0

45

148

,045

148,0

45

Net

Genera

tion

GW

h/a

00

0932

932

932

932

93

2932

932

932

3

Pre

sen

t V

alu

e

Capita

l T

EU

R1

03,8

91

OP

EX

T E

UR

457,8

10

Net

Genera

tion

GW

h12,1

73

4

Dyn

am

ic U

nit

Co

st

Part

ial Load

100%

85%

70%

50%

30%

20%

125

5106

787

962

837

725

1

DU

C -

Po

wer

Gen

era

tio

nE

UR

/MW

h4

4.4

46.1

50.1

53.9

71.8

110

.9




LI 260442 Page 6-20

0

20

40

60

80

100

120

140

- 20.0 40.0 60.0 80.0 100.0 120.0

Plant's Operation - Load (Net) in MW

Dyn

am

ic U

nit

Co

st

EU

R/M

Wh

0

20

40

60

80

100

120

140

10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

Plant's Operation as Percentage of Load

Dyn

am

ic U

nit

Co

st

EU

R/M

Wh

-

200

400

600

800

1,000

1,200

1,400

Pla

nt's N

et

Gen

era

tio

n i

n G

Wh

/a

Figure 6-7: Dynamic Unit Cost over Plant’s Load - Gas-Based Option 1




LI 260442 Page 6-21

6.3 Technical Description of Gas-Based Generation Option 2 (CCGT 1+1)

6.3.1 Basic Design

This power plant is a combined cycle power plant consisting of one gas turbine, one HRSG and

one condensing steam turbine as single shaft design. On an international level the following two

important manufacturers can deliver such power plants: (i) General Electrics (GE) Power Sys-

tems; (ii) Siemens.

The gas turbine is designed with a dual fuel combustion system using LNG (gaseous) as

primary fuel and diesel as secondary fuel. Water injection for NOx reduction when burning diesel

may be considered in order to meet the allowed NOx emission standard. Because of the single

shaft configuration there is a steam turbine clutch installation assumed. A single cycle operation

of the gas turbine is thereby possible and thus the operational flexibility of the plant is increased.

The heat recovery steam generator (HRSG) is equipped with a bypass stack. The design

capacity of the gas turbine amounts to 75.2 MW (Net). The design capacity of the steam turbine

is 37.1 MW (Net).


Plant Type CCGT 1+1


Partial Load 100% 85% 70% 50% 40% 25%





Turbines in Operation 1GT+1ST 1GT+1ST 1GT+1ST 1GT+1ST 1GT 1GT

Partial Load 100% 85% 70% 50% 40% 25%









LI 260442 Page 6-22

Maltese local conditions and provided fuel specifications have been considered for the evalu-

ation of the major operational parameters. The performance data of this supply option is based

on the gas turbine (GT) of type GE 6111FA and dual pressure HRSG without duct burner firing.

Another possible gas turbine type of similar size is for example the Siemens SGT-1000F but in

this case an upgraded GT (with higher turbine inlet temperature and exhaust gas mass flow) or

a HRSG with duct burner firing is needed.

The HRSG produces in this case 29.7 kg/s high pressure steam with 67.5 bar and 585 °C and

an intermediate pressure steam of 3.17 kg/s with 8.3 bar and 258 °C. The indoor located

condensing steam turbine has a capacity of 37 MW. For the cooling system an open loop water

cooling with a seawater inlet Temperature of 20 °C and a allowable cooling water temperature

rise of 8 K is assumed.

Table 6-9 provides the general technical parameters of the supply option (design conditions). A

partial load range between 100% (full load) and 25% is selected regarding the provision of the



terms. Related to the plants output the value increases from 2.1% to 3.3% (1 GT + 1 ST

operation) and decreases thereafter to for example 1.3% (1 GT operation);

The plant’s net heat rate increases from 6,930 kJ/kWh to more than 15,000 kJ/kWh over

the entire range of partial load. This is equal to a net efficiency decrease from 51.9% to

23.8% only.


a 3% forced outage, the maximum availability of the plant is expected to amount 92.1% over an

entire year.

The net and gross heat rates of the gas based supply option 2 are shown in the following figure

over the entire load range (calculated on fuel’s NCV). The results of GT Pro calculations are

summarized within the heat and mass balance diagrams in the Figures 6-9 and 6-10. The



The plant’s net capacity during summer amounts to 86.1% (97.8 MW) compared to the

net capacity during the winter period by some 113.6 MW.



(winter).




LI 260442 Page 6-23


Heat

Rate

s (

kJ/k

Wh

) o

f S

up

ply

Op

tio

n 2

- 1

+1 C

CG

T N

G f

ired

0

2,0

00

4,0

00

6,0

00

8,0

00

10,0

00

12,0

00

14,0

00

16,0

00

020,0

00

40,0

00

60,0

00

80,0

00

100,0

00

120,0

00

Lo

ad

(kW

)

Heat Rate (kJ/kWh)

1+

1 g

ross H

R

1+

1 n

et

HR

1+

0 g

ross H

R

1+

0 n

et

HR

MA

LT

A R

ES

OU

RC

ES

AU

TH

OR

ITY

Energ

y I

nte

rco

nnection E

uro

pe -

Malta

Marc

h 2

008

Fin

al

Rep

ort

– W

ork

Packag

e I

IA

LI

2604

42

Page 6

-24

GT

MA

ST

ER

17

.0.1

LI - W

. E

isenh

art

31

6 0

8-2

0-2

007

11:2

7:3

3

file

=T

:\2

6\0

40

0\2

60

442

_m

alt

a\0

6_

pro

ject_

res

ults

\GT

Pro

\Case

2 (1+

1) n

eu\C

CG

T 1

+1 N

G F

IRE

D 1

00%

loa

d s

um

me

r con

ditio

ns.g

tm

CC

GT

1+1

configura

tion N

G f

ired

100%

load

at su

mm

er c

ond

itio

ns

Net

Po

we

r 97

771

kW

LH

V H

eat R

ate

71

13

kJ

/kW

h

p[b

ar], T

[C],

M[t

/h],

Ste

am

Pro

pertie

s: IA

PW

S-IF

97

1X

GE

61

11F

A

629

65 k

W

1.0

1 p

36 T

70 %

RH

666

.8 m

1 p

36 T

666.8

m

LN

G 1

4.4

5 m

31

T 2

0 T

LH

V=

19

317

6 k

Wth

14

.02 p

39

7 T

13.3

2 p

131

8 T

68

1.2

m

1.0

4 p

629 T

681.2

M

72

.39 %

N2

12

.3 %

O2

3.8

37 %

CO

2 1

0.6

%H

2O

0.8

716 %

Ar

627

T 6

81

.2 M

2.5

68 m

^3/k

g48

5.9

m^3

/s

62

7

52

0

520

520

506

302

301

2

65

2

63

2

27

2

27

18

9

15

7

157

109

T 6

81

.2 M

1.1

14 m

^3/k

g21

0.8

m^3

/s

370

72 k

W

0.0

344 M

FW

0.1

03

2 p

46 T

118

.4 M

46 T

2.3

23

p

115

T

119

.6 M

LT

E

46 T

119

.6 M

115

T 2

.32

3 p

12

5 T

121.8 M

9.0

77 p

171 T

121.8

M

IPE

2

9.0

77 p

176 T

13.6

3 M

IPB

8.9

52 p

22

8 T

11

.41 M

IPS

1

8.7

83

p

260

T

11.4

1 M

IPS

2

2.225 M

73.4

5 p

229

T

104

.9 M

HP

E2

72.2

2 p

282

T

104

.9 M

HP

E3

72.2

2 p

288 T

103.9

M

HP

B1

71.7

1 p

309 T

103.9

M

HP

S0

69

.84 p

60

7 T

10

5.3

M

HP

S3

1.7

3 M

67.4

9 p

585 T

107 M

69.84 p 607 T

1.3

8 M

3.1

2 M

11.4

1 M

8.302 p 258 T

Abbreviation:

p -pressure in bar



Colours:





Fig

ure

6-9

: H

eat

an

d M

ass B

ala

nce –

Gas-B

ased

Ge

ne

rati

on

Op

tio

n 2

(S

um

me

r C

on

dit

ion

s)

MA

LT

A R

ES

OU

RC

ES

AU

TH

OR

ITY

Energ

y I

nte

rco

nnection E

uro

pe -

Malta

Marc

h 2

008

Fin

al

Rep

ort

– W

ork

Packag

e I

IA

LI

2604

42

Page 6

-25

GT

MA

ST

ER

17.0

.1 L

I - W

. E

isenhart

316 0

8-2

0-2

007 1

1:2

7:5

7 file

=T

:\26\0

400\2

60442_m

alta\0

6_p

roje

ct_

results\G

TP

ro\C

ase 2

(1+1) ne

u\C

CG

T 1

+1 N

G F

IRE

D 1

00%

loa

d w

inte

r condit

ions.g

tm

CC

GT

1+1 c

onfigura

tion N

G fired

100%

load a

t w

inte

r conditio

ns

Net P

ow

er 113597 k

WLH

V H

eat R

ate

6903 k

J/k

Wh

p[b

ar], T

[C], M

[t/h

], S

team

Pro

pertie

s: IA

PW

S-IF97

1X

GE

6111FA

75611 k

W

1.0

1 p

13 T

45 %

RH

746.8

m

1 p

13 T

746.8

m

LN

G 1

6.2

9 m

31 T

20 T

LH

V= 2

17

815 k

Wth

15.6

5 p

380 T

14.8

7 p

1328 T

763.1

m

1.0

4 p

606 T

763.1

M

74.9

4 %

N2

12.8

5 %

O2

3.9

12 %

CO

2 7

.395 %

H2O

0.9

023 %

Ar

604 T

763.1

M

2.4

6 m

^3/k

g521.5

m^3

/s

604

511

511

511

499

305

304

269

267

232

232

193

160

160

109 T

763.1

M

1.0

98 m

^3/k

g232.8

m^3

/s

40367 k

W

0.0

36 M

FW

0.0

542 p

34 T

122.7

M

34 T

2.3

23 p

114 T

124.1

M

LT

E

34 T

124.1

M

114 T

2.3

23 p

125 T

126.7 M

9.5

36 p

174 T

126.7

M

IPE

2

9.5

36 p

178 T

15.7

5 M

IPB

9.3

82 p

229 T

13.1

2 M

IPS

1

9.1

73 p

260 T

13.1

2 M

IPS

2

2.619 M

75.3

8 p

233 T

110.8

M

HP

E2

74.0

1 p

285 T

110.8

M

HP

E3

74.0

1 p

290 T

109.7

M

HP

B1

73.4

7 p

309 T

109.7

M

HP

S0

71.5

2 p

586 T

109.7

M

HP

S3

69.1

p 5

84 T

109.7

M

71.52 p 586 T

0.0

01 M

13.1

2 M

8.601 p 258 T

Abbreviation:

p -pressure in bar



Colours:





Fig

ure

6-1

0:

Heat

an

d M

ass B

ala

nce –

Ga

s-B

ased

Gen

era

tio

n O

pti

on

2 (

Win

ter

Co

nd

itio

ns)




LI 260442 Page 6-26

6.3.2 Location

Regarding the potential location of supply option 2, the same site was selected as already de-

picted for supply option 1 in Figure 6-4.


The legal frame and the National targets are explained in detail in section 6.1.3. Calculations

were carried out to demonstrate that the supply option 2 complies with the EU environmental di-

rectives and with all the relevant aspects of the Maltese Legislation.


presented. The air pollution emissions of the investigated supply option:



emissions at all;



871

401

921

-

100

200

300

400

500

600

700

800

900

1,000

Business as Usual

(all STs)

Business as Usual

(DPS ST)

Supply Option

Sp

ec

ific

Em

iss

ion

s g

CO

2/k

Wh

.





LI 260442 Page 6-27

General Information

# Item 2

1 Plant Name Natural Gas Based Supply Option 2



4 State Option

5 Unit_Ident

6 Comments

No Comments


# Item Dim 2





11 Heat Rate* Coeff B (1+1) - -10,966

12 Heat Rate* Coeff C (1+1) - 12,336








0

5000

10000

10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

kJ

/ k

Wh

700

800

900

1000

1100

1200

1300

1400

10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

[co

mb

. te

mp

.]

0

5000

10000

15000

20000

10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

kJ /

kW

h





LI 260442 Page 6-28

NOx Emissions

# Item 2






Fuel Specifications







Fuel Composition

(Emission Relevant)


0.0

0.5

1.0

1.5

2.0

2.5

10% 20% 30% 40% 50% 60% 70% 80% 90%

[g/kWh]

0.00

0.20

0.40

0.60

0.80

1.00

1.20

0

200

400

600

800

1,000

1,200

10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

mg/m³

0

200

400

600

800

1,000

1,200

0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1

mg/m³

2242

6376

64

107

158

211

255

7

0

50

100

150

200

250

300

13 26 38 51 64 77 90 102 115 128

kg Nox

RAW

0.0

20.0

40.0

60.0

80.0

100.0

120.0

140.0

0.0

0.5

1.0

1.5

2.0

2.5

10% 20% 30% 40% 50% 60% 70% 80% 90%

[g/kWh]

0.00

0.20

0.40

0.60

0.80

1.00

1.20

0

200

400

600

800

1,000

1,200

10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

mg/m³

0

200

400

600

800

1,000

1,200

0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1

mg/m³

36

65

9075

54

89

131

175

214

13

0

50

100

150

200

250

11 23 34 46 57 69 80 92 103 115

kg Nox

RAW

0.0

20.0

40.0

60.0

80.0

100.0

120.0





LI 260442 Page 6-29


# Item 2







32

29,12351,499

69,655

103,402

135,795152,889

169,723186,792

204,592

86,115

0

50,000

100,000

150,000

200,000

250,000

0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1

m³ Exhaust Gas

525474

439 422462 446 433 423 417

594

0

200

400

600

800

10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

[g/kWh]

13.3

21.9

27.632.3

26.530.0

33.336.8

40.544.9

0

10

20

30

40

50

11 23 34 46 57 69 80 92 103 115

[t CO2]

[MW]

50,832

83,834

105,860 101,558114,808

127,639140,880

155,361171,912

123,762

0

50,000

100,000

150,000

200,000

10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

m³ Exhaust Gas

n/a

954

803704

462 436 415 401 393 391

1157

0

200

400

600

800

1,000

1,200

1,400

10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

[g/kWh]

n/a





LI 260442 Page 6-30

6.4 Economic Description of Gas-Based Generation Option 2 (CCGT 1+1)


The projects implementation plan (already described in section 6.2.1) leads to the investment

cost’s disbursement schedule shown in Table 6-12. The total duration of the project’s implem-

entation is estimated at three years. A lifetime of 25 years is assumed for the supply option 2.

The investment cost in total and for each individual major component is provided in Table 6-11.

In total, the projects investment cost amounts to 74.6 Mio Euro (10% contingencies included).

# Item

1

2

3

4

5

6

7

8

9

10

11

3,292

Plant Startup 603


Engineering

Investment Costs

in T EUR

Balance of Plant 5,163


9,698

9,954

672

Gas Turbine incl. Generator 20,853


Total: 74,550



I&C Equipment 853






LI 260442 Page 6-31

Year n-3 n-2 n-1 n



The specific investment cost amounts to 664 EUR/kW, approximately 7% less compared to the

gas-based generation option 1.

Figure 6-12 illustrates the investment break down. The dominating cost proportions are (i) the

gas turbine package; (ii) the heat recovery boiler; (iii) soft costs of the contractor and (iv) the

steam turbine package.

28%13%

13%

1%

7%

8%

1% 10%4%

1%

13%

Gas Turbine incl. Generator




Balance of Plant


I&C Equipment


Engineering

Plant Startup






LI 260442 Page 6-32



The development of the costs of the supply of gas to the power plant is presented in the below

Table. The year 2011 is selected as the first possible year of the plant’s operation. This assump-

tion takes into account the project’s schedule given in the previous section.

Item Unit 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

EUR/t 204.4 197.7 191.0 191.0 191.0 191.0 194.4 197.7 201.0 201.0

Item Unit 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

EUR/t 204.4 207.7 211.0 214.4 216.0 217.7 217.7 219.4 219.4 221.0

Fuel Supply Costs


Fuel Supply Costs



Fixed O&M Costs



energy sent-out.

The personnel costs are calculated by the estimated number of required staff (25 employees)

and the average annual salary (30 T EUR/a). Based on experiences in similar assignments the

proportion of the remaining fixed operation and maintenance costs is 2.5% of the capital costs.

In total the annual fixed OPEX amount to 2.6 Mio EUR/a.

.

# Item

1

2


Costs in T EUR/a

Personnel Costs 750






LI 260442 Page 6-33

Variable O&M Costs



plant’s electrical energy sent-out.

The dominating proportion of the variable OPEX is the cost of fuel, which depends on the fuel

supply cost and the amount of fuel utilized. The latter item again depends on the plant’s ef-

ficiency and further on the plant’s operation mode (e.g. full load or partial load; number of

turbines in operation). In the first section of this chapter the plant’s performance parameters are

described in detail. The following economic analysis considers individual operation modes and

the related specific fuel input.

Based on our experience in similar assignment the value of the remaining variable OPEX is

estimated at 2.0 EUR/MWh.


The following chart provides the calculation of the dynamic unit cost of the gas-based local

generation option 2. As far as the actual future operation of the plant is not known (this depends

mainly on the most economic dispatch of the unit as one component of the entire power gene-

ration system; see Work Package III) we provide cost figures over the entire load range.

Exemplarily the calculation in the chart is based on an 85% load assumption. Nevertheless, the

results are shown for different operation modes from full load to partial load. Furthermore, the

DUC trends are illustrated in Figure 6-13. Regarding the expected annual net generation the

option’s maximum availability of 92.1% is taken into consideration in the 100% full load case.


43.7 EUR/MWh. Only slight fluctuations of the DUC are observed within the plant’s base load

operation. In full load operation the DUC are 4% lower than the reference value. At 70% load

level the DUC are 9% higher than the reference value.

In intermediate and peak load operation (1 GT + 1 ST mode, and 1 GT mode respectively) the

cost figures increase rapidly. At 50%-load an increase of 28% and at 25%-load an increase of

161% is registered in comparison to the reference value.

The plant’s maximum net generation amounts to 906 GWh/a (at maximum availability and full

load).




LI 260442 Page 6-34

Table 6-15: Dynamic Unit Cost of the Gas-Based Option 2

1

G

en

era

l In

form

ati

on

Loca

l Gen

era

tion O

ptio

n 2

p

1.1

Tec

hn

ical

1.2

Eco

no

mic

s

Pla

nt

Typ

e -

-C

CG

T 1

+1

Set

Siz

e (

nom

inal)

MW

11

4.6

Part

ial L

oa

d100

%85%

70%

50

%40%

25%

Tota

l Inve

stm

ent

T E

UR

74,5

50

Set

Capaci

ty (

gro

ss)

MW

11

4.6

96

.87

8.3

58.3

46.0

30.8

Dis

cou

nt

Ra

te%

6.5

%

Set

Capaci

ty (

net)

MW

11

2.3

94

.67

6.2

56.3

45.4

30.3

Life

time

a30

Auxi

liary

Po

wer

MW

2.4

2.2

2.1

1.9

0.6

0.5

Const

ruct

ion P

eri

od

a3

Self

Con

sum

ptio

n%

2.1

%2.3

%2.7

%3.3

%1.3

%1.6

%

Turb

ine

s in

Opera

tion

--

1G

T+

1S

T

1G

T+

1S

T

1G

T+

1S

T

1G

T+

1S

T

1G

T1G

TF

ixed O

PE

X

T E

UR

/a2,6

14

100

%85%

70%

50

%40%

25%

Variable

OP

EX

*E

UR

/MW

h2.0

Net

Heat

Rate

kJ/

kWh

6,9

30

7,1

41

7,4

71

8,1

22

12

,564

15,1

01

Fu

el T

ype

--

Reg

as

LN

G

Pla

nned O

uta

ge

d/a

18

Net

Calo

rific

Valu

ekJ

/kg

48,1

50

Forc

ed O

uta

ge

%/a

3%

Max

Ava

ilabili

ty%

/a92.1

%*

oth

er

tha

n F

ue

l C

osts

2

Ca

sh

Flo

wO

pera

tion a

t 85%

Load

Item

Ye

ar

>>

n-3

n-2

n-1

12

34

510

20

30

Inve

stm

ent

Cost

T E

UR

/a37,2

75

22,3

65

14,9

10

00

00

00

00

Fix

ed

OP

EX

T E

UR

/a0

00

2,6

14

2,6

14

2,6

14

2,6

14

2,6

14

2,6

14

2,6

14

2,6

14

Variab

le O

PE

XT

EU

R/a

00

026

,947

26,1

23

25,2

98

25,2

98

25,2

98

26,5

35

29,0

09

31,1

58

Fuel S

upply

Cost

s (s

peci

fic)

EU

R/t

00

0204

19

8191

191

191

201

221

238

Fuel S

upply

Cost

s (a

bso

lute

)T

EU

R/a

00

025

,279

24,4

55

23,6

30

23,6

30

23,6

30

24,8

67

27,3

41

29,4

90

Fuel I

nput

t/a

00

0123,6

93

12

3,6

93

123,6

93

123,6

93

123,6

93

123,6

93

123

,693

123,6

93

Net

Gene

ratio

nG

Wh/a

00

0834

83

4834

834

834

834

834

834

3

Pre

se

nt

Valu

e

Capita

l T

EU

R8

6,2

72

OP

EX

T E

UR

38

9,4

82

Net

Gene

ratio

nG

Wh

10,8

91

4

Dyn

am

ic U

nit

Co

st

Part

ial L

oad

100%

85%

70

%50%

40%

25

%112

395

478

656

144

928

1

DU

C -

Po

wer

Gen

era

tio

nE

UR

/MW

h41

.94

3.7

47.5

55.8

79.1

113.7




LI 260442 Page 6-35

0

20

40

60

80

100

120

140

- 20.0 40.0 60.0 80.0 100.0 120.0


Dyn

am

ic U

nit

Co

st

EU

R/M

Wh

0

20

40

60

80

100

120

140

10% 20% 30% 40% 50% 60% 70% 80% 90% 100%


Dyn

am

ic U

nit

Co

st

EU

R/M

Wh

-

200

400

600

800

1,000

1,200

1,400

Pla

nt's N

et

Gen

era

tio

n i

n G

Wh

/a

Figure 6-13: Dynamic Unit Cost over Plant’s Load –Gas-Based Option 2




LI 260442 Page 6-36

6.5 Technical Description of Gas-Based Generation Option 3 (2+1 ST R)

6.5.1 Basic Design

For this supply option one of the existing conventional thermal power units of DPS, with the

auxiliary boiler, the steam turbine and the generator, has been modelled in order to recalculate

the design performance of the plant. The model was developed so that the gross output and

heat rate was consistent with data obtained from the station at the conditions described in the

plant documentation. The present technical parameters of the Delimara 60 MW steam turbines

are provided already in Table 1-8 (Specifications of D_ST1e) and respectively in Table 1.10

(Specifications of D_ST2e). Then the auxiliary boiler in the model was replaced by two gas

turbines with two heat recovery steam generators. All steam turbine ports (formerly for feed-

water heater) were closed and a new combined cycle power plant is received.

This power plant is a combined cycle power plant consisting of two gas turbines, two HRSG and

one (existing) condensing steam turbine. The performance data is based on the GT type of

Alstom’s ALS GT8C2 and double pressure HRSG without duct burner firing. On international

level three important suppliers offer such power plant equipment:

General Electrics (GE) Power Systems,

Alstom

Siemens.


primary fuel and diesel as secondary fuel. Water injection for NOx reduction when burning diesel

may be considered in order to meet the allowed NOx emission standard. Because of the single

shaft configuration there is a steam turbine clutch installation assumed. A single cycle operation

of the gas turbine is thereby possible and thus the operational flexibility of the plant is increased.

The heat recovery steam generator (HRSG) is equipped with a bypass stack. The design

capacity of the two gas turbines amounts to 55.3 MW (Net) each. As the result of the plant’s

addition by two gas turbines the design capacity of the steam turbine is 49.1 MW (Net).


operation of the gas turbines in order to increase the operational flexibility of the plant. Both

HRSG produce in total 41.2 kg/s high pressure steam with 87.1 bar and 493 °C and an inter-

mediate pressure steam of 10.3 kg / s with 9.8 bar and 259 °C. For the cooling system an open

loop water cooling with a seawater inlet temperature of 20 °C and an allowable cooling water

temperature rise of 8 K is assumed.




LI 260442 Page 6-37


Plant Type CCGT 2+1


Partial Load 100% 85% 70% 50% 30% 20%






Partial Load 100% 85% 70% 50% 30% 20%






Maltese local conditions and provided fuel specifications have been considered for the evalu-

ation of the major operational parameters which are provided in Table 6-16. A partial load range

between 100% (full load) and 20% is selected regarding the provision of the operational

characteristics, which can be summarized as follows:


terms. Related to the plants output the value increases from 2.0% to 2.6% (2 GT + 1 ST

operation); from 2.5% to 3.8% (1 GT + 1 ST operation) and decreases thereafter to only

1.2% (1 GT operation);

The plant’s net heat rate increases from 7,377 kJ/kWh to 12,874 kJ/kWh over the range

of partial load investigated. This is equal to a net efficiency decrease from 48.8% to

28.0%.

Regarding the planned outage duration, the current figure (30 days a year) was applied. It is

assumed that maintenance works for the both GTs will carried out within this time frame. The

addition of a typical forced outage rate for the type of technology (3%) leads to a maximum avai-

lability of the plant of some 88.8%.




LI 260442 Page 6-38






The plant’s net capacity during summer amounts to nearly 20 MW less (141.6 MW)

compared to the net capacity during the winter period which is 161.2 MW.



(winter).




LI 260442 Page 6-39

Figure 6-14:Gross and Net Heat Rates – Gas-Based Generation Option 3

He

at

Ra

tes

(k

J/k

Wh

) o

f S

up

ply

Op

tio

n 3

- 2

+1 S

T R

NG

fir

ed

0

2,0

00

4,0

00

6,0

00

8,0

00

10,0

00

12,0

00

14,0

00

16,0

00

18,0

00

020

,000

40

,00

060

,000

80

,000

100

,00

012

0,0

00

140

,000

160

,00

0180

,000

Lo

ad

(kW

)

Heat Rate (kJ/kWh)

2+

1 g

ross

HR

2+

1 n

et

HR

1+

1 g

ross

HR

1+

1 n

et

HR

1+

0 g

ross

HR

1+

0 n

et

HR

MA

LT

A R

ES

OU

RC

ES

AU

TH

OR

ITY

Energ

y I

nte

rco

nnection E

uro

pe -

Malta

Marc

h 2

008

Fin

al

Rep

ort

– W

ork

Packag

e I

IA

LI

2604

42

Page 6

-40

GT

MA

ST

ER

17.0

.1 L

I - W

. E

isenhart

316 0

8-2

1-2

007 1

3:5

0:2

8 file

=T

:\26\0

400\2

60442_m

alta\0

6_p

roje

ct_

resu

lts\G

TP

ro\C

ase 3

(2+1) re

furb

ishm

en

t 60M

W S

T\C

CG

T 2

+1 R

EFU

RB

ISH

ME

NT

ST

NG

FIR

ED

100

% lo

ad a

t sum

mer con

CC

GT

2+1 c

onfigura

tion (re

furb

ishm

ent ste

am

pow

er pla

nt), N

G fired

100%

load a

t sum

me

r condit

ions

Net P

ow

er 141

552 k

WLH

V H

eat R

ate

752

2 k

J/k

Wh

p[b

ar], T

[C], M

[t/h

], S

team

Pro

pertie

s: IA

PW

S-IF97

1X

ALS

GT

8C

2 2

X G

T

47392 k

W

1.0

1 p

36 T

70 %

RH

632.2

m

1 p

36 T

632.2

m

LN

G 1

1.0

6 m

20 T

LH

V= 1

47

890 k

Wth

16.2

1 p

430 T

15.4

8 p

1171 T

643.3

m

1.0

4 p

531 T

1286.5

M

72.8

6 %

N2

13.7

6 %

O2

3.1

24 %

CO

2 9

.381 %

H2O

0.8

773 %

Ar

529 T

1286.5

M

2.2

79 m

^3/k

g814.3

m^3

/s

529

462

462

320

318

282

279

256

256

197

165

165

126 T

1286.5

M

1.1

59 m

^3/k

g414.1

m^3

/s

49897 k

W

0.0

5 M

FW

0.1

042 p

47 T

185.4

M

47 T

2.3

23 p

116 T

187.4

M

LT

E

47 T

187.4

M

116 T

2.3

23 p

125 T

190.6 M

10.7

7 p

178 T

190.6

M

IPE

2

10.7

7 p

183 T

40.4

1 M

IPB

10.5

8 p

229 T

37.1

8 M

IPS

1

10.4

p

261 T

37.1

8 M

IPS

2

3.215 M

95.2

6 p

229 T

147.7

M

HP

E2

93.2

8 p

299 T

147.7

M

HP

E3

93.2

8 p

306 T

146.3

M

HP

B1

90.1

4 p

510 T

146.3

M

HP

S3

2.0

6 M

87.1

p 4

93 T

148.3

M

90.14 p 510 T

2.0

6 M

37.1

8 M

9.8 p 259 T

Abbreviation:

p -pressure in bar



Colours:





Fig

ure

6-1

5:

Heat

an

d M

ass B

ala

nce –

Ga

s-B

ased

Gen

era

tio

n O

pti

on

3 (

Su

mm

er

Co

nd

itio

ns)

MA

LT

A R

ES

OU

RC

ES

AU

TH

OR

ITY

Energ

y I

nte

rco

nnection E

uro

pe -

Malta

Marc

h 2

008

Fin

al

Rep

ort

– W

ork

Packag

e I

IA

LI

2604

42

Page 6

-41

GT

MA

ST

ER

17.0

.1 L

I - W

. E

isenhart

316 0

8-2

1-2

007 1

3:5

1:1

4 file

=T

:\26\0

400\2

60442_m

alta\0

6_p

roje

ct_

results\G

TP

ro\C

ase 3

(2+1) re

furb

ishm

en

t 60M

W S

T\C

CG

T 2

+1 R

EFU

RB

ISH

ME

NT

ST

NG

FIR

ED

100%

lo

ad a

t w

inte

r co

ndi

CC

GT

2+1 c

onfigura

tion (re

furb

ishm

ent ste

am

pow

er p

lant), N

G fired

100%

load a

t w

inte

r conditio

ns

Net P

ow

er 161209 k

WLH

V H

eat R

ate

7357 k

J/k

Wh

p[b

ar], T

[C], M

[t/h

], S

team

Pro

pertie

s: IA

PW

S-IF97

1X

ALS

GT

8C

2 2

X G

T

55470 k

W

1.0

1 p

13 T

45 %

RH

694.9

m

1 p

13 T

694.9

m

LN

G 1

2.3

2 m

20 T

LH

V= 1

64

714 k

Wth

17.7

5 p

411 T

16.9

5 p

1178 T

707.2

m

1.0

4 p

514 T

1414.4

M

75.4

2 %

N2

14.3

%O

2 3

.205 %

CO

2 6

.17 %

H2O

0.9

081 %

Ar

512 T

1414.4

M

2.1

96 m

^3/k

g862.8

m^3

/s

512

453

453

321

319

285

282

260

260

200

168

168

125 T

1414.4

M

1.1

44 m

^3/k

g449.3

m^3

/s

53513 k

W

0.0

511 M

FW

0.0

543 p

34 T

189.1

M

34 T

2.3

23 p

114 T

191.1

M

LT

E

34 T

191.1

M

114 T

2.3

23 p

125 T

195.1 M

11.1

p

181 T

195.1

M

IPE

2

11.1

p

184 T

45.0

2 M

IPB

10.8

8 p

229 T

40.9

7 M

IPS

1

10.6

7 p

260 T

40.9

7 M

IPS

2

4.075 M

95.2

4 p

233 T

149.6

M

HP

E2

93.2

p

301 T

149.6

M

HP

E3

93.2

p

306 T

148.2

M

HP

B1

90.0

5 p

495 T

148.2

M

HP

S3

87 p

492 T

148.2

M

90.05 p 495 T

40.9

7 M

9.979 p 258 T

Abbreviation:

p -pressure in bar



Colours:





Fig

ure

6-1

6:

Heat

an

d M

ass B

ala

nce –

Ga

s-B

ased

Gen

era

tio

n O

pti

on

3 (

Win

ter

Co

nd

itio

ns)




LI 260442 Page 6-42

6.5.2 Location

Figure 6-17 shows the location of the existing steam turbines and boilers at the Delimara Power

Station site, which is also the location of the proposed refurbishment measure.




LI 260442 Page 6-43


In the following more details of the unit’s geometry are provided. The first two drawings depict

the gas turbine package (Figure 6-19). The total length of the package is calculated at approx.

22 meters. The width of one package is calculated at approx. 5 meters.

Figure 6-20 shows the geometry of the heat recovery steam generator. The total length amounts

to some 27 meters. The width of one HRSG amounts to 7 meters. Summarizing the dimension

of the plant’s components the below figure provides a suggestion regarding the arrangement of

the required two HRSGs and two GTs. As the result a square of 27 x 27 meters is calculated

and considered as realizable.

Figure 6-18: Suggestion regarding the Formation of HRSGs and GTs

GT

GT

HR

SG

HR

SG

ap

pro

x. 2

7 m

approx. 27 m

GT

GT

HR

SG

HR

SG

ap

pro

x. 2

7 m

approx. 27 m




LI 260442 Page 6-44

FOR QUALITATIVE INDICATION ONLY

Thermoflow, Inc.

PEACE/GT MASTER 17.0.2

Date: 11.12.07

Company: Lahmeyer International GmbH

User: LI - W. Eisenhart

C:\TFLOW17\MYFILES\GTMAS.GTM

Drawing No:

GAS TURBINE PACKAGE

ELEVATION

GE 6561B 133

A A

B B

C C

D D

E E

F F

1

1

2

2

3

3

4

4

5

5

6

6

7

7

8

8

A B C D E F G H I J

SHAPE, DIMENSIONS & SCALE ARE APPROXIMATE

11.4 m 3.4 m 6.5 m 4.4 m 11.6 m - - - - -

A

B

C D

E


Thermoflow, Inc.

Date: 11.12.07




Drawing No:

GAS TURBINE PACKAGE

PLAN

GE 6561B 133

A A

B B

C C

D D

E E

F F

1

1

2

2

3

3

4

4

5

5

6

6

7

7

8

8

A B C D E F G H I J

SHAPE, DIMENSIONS & SCALE ARE APPROXIMATE

3.4 m 21.9 m 2.5 m 2.6 m - - - - - -

A

B

C D

Figure 6-19: Dimensions of one GT Package




LI 260442 Page 6-45


Thermoflow, Inc.


Date: 11.12.07




Drawing No:

HEAT RECOVERY STEAM GENERATOR

ELEVATION

A A

B B

C C

D D

E E

F F

1

1

2

2

3

3

4

4

5

5

6

6

7

7

8

8

A B C D E F G H I J

A C D E

F

G

H

5 m - 7.1 m 10.9 m 2.1 m 22.2 m 12.1 m 2.7 m - -


Thermoflow, Inc.


Date: 11.12.07




Drawing No:

HEAT RECOVERY STEAM GENERATOR

PLAN

A A

B B

C C

D D

E E

F F

1

1

2

2

3

3

4

4

5

5

6

6

7

7

8

8

A B C D E F G H I J

A C D E

F

5 m - 7.1 m 10.9 m 2.1 m 3.7 m 3.1 m - - -

G

Figure 6-20: Dimensions of one HRSG




LI 260442 Page 6-46


The legal frame and the National targets for local generation options are explained in detail in

section 6.1.3. In the following tables the environmental impact due to potential air pollution

emissions is presented. The air pollution emissions of the investigated supply option:



emissions at all;



871

420

921

-

100

200

300

400

500

600

700

800

900

1,000

Business as Usual

(all STs)

Business as Usual

(DPS ST)

Supply Option

Sp

ec

ific

Em

iss

ion

s g

CO

2/k

Wh

.





LI 260442 Page 6-47

General Information

# Item 3

1 Plant Name Natural Gas Based Supply Option 3 (Refurbishment)



4 State Option

5 Unit_Ident

6 Comments

No Comments


# Item Dim 3





11 Heat Rate* Coeff B (2+1) - -7,944

12 Heat Rate* Coeff C (2+1) - 11,566








0

5000

10000

10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

kJ

/ k

Wh

700

800

900

1000

1100

1200

1300

1400

10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

[co

mb

. te

mp

.]

0

5000

10000

10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

kJ

/ k

Wh





LI 260442 Page 6-48

NOx Emissions

# Item 3






Fuel Specifications






Fuel Composition

(Emission Relevant)



0.0

0.5

1.0

1.5

2.0

2.5

10% 20% 30% 40% 50% 60% 70% 80% 90%

[g/kWh]

0.00

0.20

0.40

0.60

0.80

1.00

1.20

0

200

400

600

800

1,000

1,200

10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

mg/m³

0

200

400

600

800

1,000

1,200

0 0 0 0 0 0 0 0 0 0

mg/m³

2242

6376

64

107

158

211

255

7

0

50

100

150

200

250

300

13 26 38 51 64 77 90 102 115 128

kg Nox

RAW

0.0

20.0

40.0

60.0

80.0

100.0

120.0

140.0

0.0

0.5

1.0

1.5

2.0

2.5

10% 20% 30% 40% 50% 60% 70% 80% 90%

[g/kWh]

0.00

0.20

0.40

0.60

0.80

1.00

1.20

0

200

400

600

800

1,000

1,200

10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

mg/m³

0

200

400

600

800

1,000

1,200

0 0 0 0 0 0 0 0 0 0

mg/m³

28

53

7896

80

134

199

265

322

9

0

50

100

150

200

250

300

350

16 33 49 65 81 98 114 130 147 163

kg Nox

RAW

0.0

50.0

100.0

150.0

200.0





LI 260442 Page 6-49


# Item 3







32

29,12351,499

69,655

103,402

135,795152,889

169,723186,792

204,592

86,115

0

50,000

100,000

150,000

200,000

250,000

0 0 0 0 0 0 0 0 0 0

m³ Exhaust Gas

525474

439 422462 446 433 423 417

594

0

200

400

600

800

10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

[g/kWh]

9.717.0

22.828.1

34.0

44.650.1

55.661.3

67.4

0

10

20

30

40

50

60

70

80

16 33 49 65 81 98 114 130 147 163

[t CO2]

[MW]

37,316

65,20987,460

130,165

171,072192,117

213,135234,914

258,244

107,851

0

50,000

100,000

150,000

200,000

250,000

300,000

10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

m³ Exhaust Gas

n/a

522467

432 417457 440 427 418 414

598

0

200

400

600

800

10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

[g/kWh]

n/a





LI 260442 Page 6-50

6.6 Economic Description of Gas-Based Generation Option 3 (2+1 ST R)


Under consideration of the project’s implementation plan (already described in section 6.2.1)

and taking into account the already existing components, an implementation duration of two

years is estimated. The investment cost’s disbursement schedule is shown in Table 6-19. The

lifetime of the supply option 3 is related to the remaining lifetime of the existing steam turbine

which is estimated at 15 years (see Table 1-8 Specifications of D_ST1e).



# Item

1

2

3

4

5

6

7

8

9 10,926 Contractor's Soft Costs

Investment Costs

in T EUR

I&C Equipment 1,430


17,027

6,576

7,289

Gas Turbine Package incl. Generator 32,792


Total: 88,063

Balance of Plant


Engineering 2,933

Plant Startup 758





LI 260442 Page 6-51

Year n-2 n-1 n

Disbursement in % 60% 40% Start Year



gas-based generation option 1, respectively 17% less compared to the gas-based generation

option 2.


gas turbine package; (ii) the heat recovery boiler; (iii) soft costs of the contractor and (iv) the civil

works.

37%

19%

7%

8%2% 9%

3%

1%

12%

Gas Turbine Package incl. Generator and Air

inlet cooling/heating if applicable


Balance of Plant


I&C Equipment


Engineering

Plant Startup






LI 260442 Page 6-52



As the result of the assessments in the chapters 1 to 5 the development of the costs of the

supply of gas to the power plant is presented in the below Table. The year 2011 is selected as

the first possible year of the plant’s operation. This assumption takes into account the project’s

schedule given in the previous section.

Item Unit 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

EUR/t 204.4 197.7 191.0 191.0 191.0 191.0 194.4 197.7 201.0 201.0

Item Unit 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030

EUR/t 204.4 207.7 211.0 214.4 216.0 217.7 217.7 219.4 219.4 221.0

Fuel Supply Costs


Fuel Supply Costs



Fixed O&M Costs



energy sent-out.

The personnel costs are calculated by the estimated number of additionally required staff

(10 employees) and the average annual salary (30 T EUR/a). Based on experiences in similar

assignments the proportion of the remaining fixed operation and maintenance costs is 2.5% of

the capital costs.

.

# Item

1

2


Costs in T EUR/a

Personnel Costs 300






LI 260442 Page 6-53

Variable O&M Costs



plant’s electrical energy sent-out.

The dominating proportion of the variable OPEX is the cost of fuel, which depends on the fuel

supply cost and the amount of fuel utilized. The latter item again depends on the plant’s

efficiency and further on the plant’s operation mode (e.g. full load or partial load; number of

turbines in operation). In the first section of this chapter the plant’s performance parameters are

described in detail. The following economic analysis considers individual operation modes and

the related specific fuel input.

Based on our experience in similar assignment the value of the remaining variable OPEX is esti-

mated at 4.0 EUR/MWh.


The following chart provides the calculation of the dynamic unit cost of the gas-based local

generation option 3. As far as the actual future operation of the plant is not known (this depends

mainly on the most economic dispatch of the unit as one component of the entire power gene-

ration system; see Work Package III) we provide cost figures over the entire load range.

Exemplarily the calculation in the chart is based on an 85% load assumption. Nevertheless, the

results are shown for different operation modes from full load to partial load. Furthermore, the

DUC trends are illustrated in Figure 6-23. Regarding the expected annual net generation the

option’s maximum availability of 88.8% is taken into consideration in the 100% full load case.


52.2 EUR/MWh. Fluctuations of the DUC are observed within the plant’s base load operation. In

full load operation the DUC are 2% lower than the reference value. At 70% load level the DUC

are 11% higher than the reference value.

In intermediate and peak load operation (1 GT + 1 ST mode, and 1 GT mode respectively) the

cost figures increase rapidly. At 50%-load an increase by 24% and at 20%-load an increase by

150% is registered in comparison to the reference value.

The plant’s maximum annual net generation amounts to 794 GWh/a (at maximum availability

and full load). This quantum considers exclusively the additionality of the repowering measure.




LI 260442 Page 6-54

Table 6-22: Dynamic Unit Cost of the Gas-Based Option 3

1

G

en

era

l In

form

ati

on

Loca

l Ge

ne

ratio

n O

ptio

n 3

(C

CG

T 2

+1

ST

R)

p

1.1

Te

ch

nic

al

1.2

Ec

on

om

ics

Pla

nt

Typ

e -

-C

CG

T 2

+1

Se

t S

ize

(n

om

ina

l)M

W1

62.9

Pa

rtia

l Lo

ad

100

%8

5%

70

%5

0%

30%

20

%T

ota

l In

vest

me

nt

T E

UR

88

,06

3

Se

t C

ap

aci

ty (

gro

ss)

MW

16

2.9

139

.11

11.5

81

.34

7.7

33

.8D

isco

un

t R

ate

%6

.5%

Se

t C

ap

aci

ty (

ne

t)M

W1

59.6

136

.01

08.7

79

.24

5.9

33

.4L

ifetim

ea

15

Au

xilia

ry P

ow

er

MW

3.2

3.1

2.9

2.1

1.8

0.4

Co

nst

ruct

ion

Pe

rio

da

2

Se

lf C

on

sum

ptio

n%

2.0

%2

.2%

2.6

%2.5

%3

.8%

1.2

%

Tu

rbin

es

in O

pera

tion

--

2G

T+

1S

T2G

T+

1S

T2

GT

+1

ST

1G

T+

1S

T

1G

T+

1S

T1G

TF

ixed O

PE

X

T E

UR

/a2

,502

100

%8

5%

70

%5

0%

30%

20

%V

ari

able

OP

EX

*E

UR

/MW

h4.0

Net

He

at

Ra

te

kJ/k

Wh

7,3

77

7,5

37

7,8

97

7,4

36

8,4

22

12

,874

Fu

el T

ype

--

Reg

as

LN

G

Pla

nn

ed

Ou

tag

ed

/a3

0N

et

Ca

lori

fic V

alu

ekJ

/kg

48

,15

0

Fo

rce

d O

uta

ge

%/a

3%

Ma

x A

vaila

bili

ty%

/a8

8.8

%*

oth

er

tha

n F

ue

l C

osts

2

Ca

sh

Flo

wO

pe

ratio

n a

t 8

5%

Lo

ad

Ite

mY

ea

r >

>n

-3n

-2n

-11

23

45

10

12

15

Inve

stm

en

t C

ost

T E

UR

/a0

52

,838

35

,22

50

00

00

00

0

Fix

ed

OP

EX

T E

UR

/a0

00

2,5

02

2,5

02

2,5

02

2,5

02

2,5

02

2,5

02

2,5

02

2,5

02

Va

ria

ble

OP

EX

T E

UR

/a0

00

27

,23

926

,449

25

,66

025

,660

25

,66

02

6,8

44

27

,63

42

8,6

21

Fu

el S

up

ply

Co

sts

(spe

cific

)E

UR

/t0

00

20

419

81

91

19

11

91

201

20

82

16

Fu

el S

up

ply

Co

sts

(ab

solu

te)

T E

UR

/a0

00

24

,21

223

,422

22

,63

222

,632

22

,63

22

3,8

17

24

,60

62

5,5

93

Fu

el I

np

ut

t/a

00

011

8,4

67

11

8,4

67

11

8,4

67

11

8,4

67

11

8,4

67

11

8,4

67

11

8,4

67

11

8,4

67

Net

Ge

ne

ratio

n (

min

us

exi

sitn

g)

GW

h/a

00

07

57

75

77

57

75

77

57

757

75

77

57

3

Pre

sen

t V

alu

e

Cap

ital

T E

UR

97

,44

5

OP

EX

T E

UR

274,0

65

Net

Ge

ne

ratio

n (

min

us

exi

sitn

g)

GW

h7

,11

6

4

Dyn

am

ic U

nit

Co

st

Pa

rtia

l L

oa

d10

0%

85

%7

0%

50%

30

%2

0%

15

96

13

57

111

87

98

47

93

19

DU

C -

Po

we

r G

en

era

tio

nE

UR

/MW

h5

1.4

52

.25

8.2

64

.99

0.0

13

1.1




LI 260442 Page 6-55

0

20

40

60

80

100

120

140

- 20.0 40.0 60.0 80.0 100.0 120.0 140.0 160.0


Dyn

am

ic U

nit

Co

st

EU

R/M

Wh

0

20

40

60

80

100

120

140

10% 20% 30% 40% 50% 60% 70% 80% 90% 100%


Dyn

am

ic U

nit

Co

st

EU

R/M

Wh

-

200

400

600

800

1,000

1,200

1,400

Pla

nt's N

et

Gen

era

tio

n i

n G

Wh

/a

Figure 6-23: Dynamic Unit Cost over Plant’s Load – Gas-Based Option 3




LI 260442 Page 6-56

6.7 Technical Description of Gas-Based Generation Option 4 (2+1 GT R)

6.7.1 Basic Design

This supply option one deals with the re-powering of the two existing GTs at the Delimara Power

Station site. The specifications of these turbines are provided in Table 1.12 (Specifications of

D_GT1e) and respectively Table 1.13 (Specifications of D_GT2e).

Except the consideration of two already existing (former) open cycle gas turbines, the general

layout of the combined cycle plant is comparable to that one described in detail in the chapter

“Technical Description of the Gas-Based Generation Option 1 (CCGT 2+1)”.


primary fuel. As the result of the refurbishment, the design capacity of the gas turbines amounts

to 38 MW (Net) each. The design capacity of the steam turbine is 38.5 MW (Net). For the

cooling system an open loop water cooling with a seawater inlet temperature of 20 °C and an

allowable cooling water temperature rise of 8 K is assumed.


Plant Type CCGT 2+1


Partial Load 100% 85% 75% 50% 30% 20%






Partial Load 100% 85% 75% 50% 30% 20%









LI 260442 Page 6-57


operation of the gas turbines in order to increase the operational flexibility of the plant. Most

important for the steam cycle efficiency is the HRSG configuration and design. Both HRSG

produce in total 32.6 kg / s high pressure steam with 67.95 bar and 518 °C and an intermediate

pressure steam of 5.82 kg / s with 8.3 bar and 259 °C.

Table 6-23 provides the general technical parameters of the supply option 4 (design conditions).

A partial load range between 100% (full load) and 20% is selected regarding the provision of the



terms. Related to the plants output the value increases from 2.1% (2 GT + 1 ST operati-

on) to 4.1% (1 GT + 1 ST operation) and decreases then to some 1.2% (1 GT operati-

on);

The plant’s net heat rate increases from 7,513 kJ/kWh to nearly 13,000 kJ/kWh over the

entire range of partial load. This is equal to a net efficiency decrease from 47.9% to

27.9%.


a 3% forced outage, the maximum availability of the plant is expected to amount 91.5% over a

year.






The plant’s net capacity during summer amounts to only 87% (102.0 MW) compared to

the net capacity during the winter period by some 116.8 MW. Our analysis of the existing

system already brought out similar capacity levels in relation to the temperature

fluctuations in Malta (see work package I);



(winter).

As mentioned at the beginning of this section, the configuration of this gas-based generation

option number 4 is very similar to the configuration of the new CCGT evaluated as gas-based

generation option number 1. The comparison of the net efficiencies between both alternatives

provides only a slight derating of the efficiency by 0.5 %-points.




LI 260442 Page 6-58


Heat

Rate

s (

kJ/k

Wh

) o

f S

up

ply

Op

tio

n 4

- 2

+1 G

T R

NG

fir

ed

0

2,0

00

4,0

00

6,0

00

8,0

00

10,0

00

12,0

00

14,0

00

16,0

00

020,0

00

40,0

00

60,0

00

80,0

00

100,0

00

120,0

00

140,0

00

Lo

ad

(kW

)

Heat Rate (kJ/kWh)2+

1 g

ross H

R

2+

1 n

et

HR

1+

1 g

ross H

R

1+

1 n

et

HR

1+

0 g

ross H

R

1+

0 n

et

HR

MA

LT

A R

ES

OU

RC

ES

AU

TH

OR

ITY

Energ

y I

nte

rco

nnection E

uro

pe -

Malta

Marc

h 2

008

Fin

al

Rep

ort

– W

ork

Packag

e I

IA

LI

2604

42

Page 6

-59

GT

MA

ST

ER

17.0

.1 L

I - W

. E

isenha

rt

316 0

8-2

9-2

007 1

2:3

8:0

6 fi

le=

T:\2

6\0

400\2

60442_

malta\0

6_p

roje

ct_

res

ults\G

TP

ro\C

ase 4

(2+

1) re

furb

ish

me

nt 2x3

7M

W G

T\N

G fired

\CC

GT

2+

1 R

EF

UR

BIS

HM

EN

T N

G F

IRE

D 1

00%

loa

d a

t sum

m

CC

GT

2+1 c

onfigura

tion (re

furb

ishm

ent o

f sin

gle

-cyc

le p

lan

t),

NG

fir

ed

100

% load a

t sum

mer co

ndit

ions

Net P

ow

er 101

978 k

WLH

V H

eat R

ate

765

0

kJ

/kW

h

p[b

ar], T

[C], M

[t/h

], S

team

Pro

pertie

s: IA

PW

S-IF

97

1X

GE

654

1B

2 X

GT

3275

7 k

W

1.0

1 p

36 T

70 %

RH

445.8

m

1 p

36 T

445

.8 m

LN

G 8

.102

m

20 T

LH

V= 1

08

352

kW

th

10.7

6 p

368 T

10.3

3 p

109

9 T

453.9

m

1.0

4 p

558 T

907.8

M

72

.78

%N

2 1

3.5

2 %

O2

3.2

41

%C

O2

9.5

81

%H

2O

0.8

76

4 %

Ar

55

6 T

90

7.8

M

2.3

58 m

^3/k

g594.5

m^3

/s

556

4

84

484

484

47

3

302

3

01

2

71

268

239

239

19

0

161

1

61

119 T

907.8

M

1.1

39 m

^3/k

g287.3

m^3

/s

38875 k

W

0.0

372

M

FW

0.1

035 p

46 T

138.2

M

46 T

2.3

23 p

116

T

139

.7 M

LT

E

46 T

139.7

M

11

6 T

2.3

23 p

125 T

142.1 M

9.1

49 p

171 T

142.1

M

IPE

2

9.1

49 p

176

T

23.4

2 M

IPB

8.9

81 p

228 T

20.9

6 M

IPS

1

8.8

43 p

261 T

20.9

6 M

IPS

2

2.467 M

74

.04

p

23

0 T

11

5.5

M

HP

E2

72.7

3 p

282 T

115.5

M

HP

E3

72.7

3 p

288 T

114.4

M

HP

B1

72.0

5 p

309

T

114

.4 M

HP

S0

70.3

2 p

535 T

115.8

M

HP

S3

1.5

1 M

67.9

5 p

518

T 1

17

.3 M

70.32 p 535 T

1.4

6 M

2.9

7 M

20.9

6 M

8.331 p 259 T

Abbreviation:

p -pressure in bar



Colours:





Fig

ure

6-2

5:

Heat

an

d M

ass B

ala

nce –

Ga

s-B

ased

Gen

era

tio

n O

pti

on

4 (

Su

mm

er

Co

nd

itio

ns)

MA

LT

A R

ES

OU

RC

ES

AU

TH

OR

ITY

Energ

y I

nte

rco

nnection E

uro

pe -

Malta

Marc

h 2

008

Fin

al

Rep

ort

– W

ork

Packag

e I

IA

LI

2604

42

Page 6

-60

GT

MA

ST

ER

17.0

.1 L

I - W

. E

isenh

art

316 0

8-2

9-2

007 1

2:3

8:5

3 file

=T

:\26\0

400\2

60442_m

alta\0

6_p

roje

ct_

res

ults\G

TP

ro\C

ase 4

(2+1) re

furb

ishm

en

t 2

x37M

W G

T\N

G fired\C

CG

T 2

+1 R

EFU

RB

ISH

ME

NT

NG

FIR

ED

100%

load a

t w

inte

CC

GT

2+1 c

onfigura

tion (re

furb

ishm

ent of sin

gle

-cyc

le p

ow

er pla

nt)

, N

G fired

100%

load a

t w

inte

r cond

itio

ns

Net P

ow

er 116781 k

WLH

V H

eat R

ate

748

4

kJ

/kW

h

p[b

ar], T

[C], M

[t/h

], S

team

Pro

pertie

s: IA

PW

S-IF9

7

1X

GE

6541B

2 X

GT

38504 k

W

1.0

1 p

13

T

45

%R

H

49

6.4

m

1 p

13 T

496.4

m

LN

G 9

.077 m

20 T

LH

V= 1

21

387 k

Wth

11.9

3 p

354 T

11.4

5 p

1105 T

505.4

m

1.0

4 p

540 T

1010.9

M

75.3

5 %

N2

14.1

%O

2 3

.303 %

CO

2 6

.34 %

H2O

0.9

073 %

Ar

538 T

1010.9

M

2.2

68 m

^3/k

g636.8

m^3

/s

53

8

476

476

476

466

305

303

275

272

243

243

193

164

164

118 T

1010.9

M

1.1

24 m

^3/k

g315.7

m^3

/s

42275 k

W

0.0

38

4 M

FW

0.0

543 p

34 T

142.7

M

34 T

2.3

23 p

114 T

144.3

M

LT

E

34

T 1

44.3

M

114 T

2.3

23 p

12

5 T

147.3 M

9.5

53 p

174 T

147.3

M

IPE

2

9.5

53 p

178 T

26.5

M

IPB

9.3

55 p

229 T

23.4

3 M

IPS

1

9.1

92

p

261 T

23.4

3 M

IPS

2

3.06 M

75.4

p

233 T

120.6

M

HP

E2

73.9

8 p

285 T

120.6

M

HP

E3

73.9

8 p

290 T

119.4

M

HP

B1

73.2

6 p

309 T

119.4

M

HP

S0

71.4

8 p

519 T

119.4

M

HP

S3

69.0

6 p

517

T 1

19

.4 M

71.48 p 519 T

23.4

3 M

8.604 p 259 T

Abbreviation:

p -pressure in bar



Colours:





Fig

ure

6-2

6:

Heat

an

d M

ass B

ala

nce –

Ga

s-B

ased

Gen

era

tio

n O

pti

on

4 (

Win

ter

Co

nd

itio

ns)




LI 260442 Page 6-62

6.7.2 Location

Figure 6-27 shows the location of the existing gas turbines at the Delimara Power Station site,

which is also the location of the proposed re-powering measure.





LI 260442 Page 6-63


The legal frame and the National targets are explained in detail in section 6.1.3. Calculations

were carried out to demonstrate that the supply option 4 complies with the EU environmental

directives and with all the relevant aspects of the Maltese Legislation.


presented. The air pollution emissions of the investigated supply option:



emissions at all;



871

430

921

-

100

200

300

400

500

600

700

800

900

1,000

Business as Usual

(all STs)

Business as Usual

(DPS ST)

Supply Option

Sp

ec

ific

Em

iss

ion

s g

CO

2/k

Wh

.





LI 260442 Page 6-64

General Information

# Item 4

1 Plant Name Natural Gas Based Supply Option 4 (Refurbishment)



4 State Option

5 Unit_Ident

6 Comments

No Comments


# Item Dim 4





11 Heat Rate* Coeff B (2+1) - -12,970

12 Heat Rate* Coeff C (2+1) - 13,748








0

5000

10000

10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

kJ /

kW

h

700

800

900

1000

1100

1200

1300

1400

10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

[co

mb

. te

mp

.]

0

5000

10000

10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

kJ

/ k

Wh





LI 260442 Page 6-65

NOx Emissions

# Item 4






Fuel Specifications






Fuel Composition

(Emission Relevant)



0.0

0.5

1.0

1.5

2.0

2.5

10% 20% 30% 40% 50% 60% 70% 80% 90%

[g/kWh]

0.00

0.20

0.40

0.60

0.80

1.00

1.20

0

200

400

600

800

1,000

1,200

10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

mg/m³

0

200

400

600

800

1,000

1,200

0 0 0 0 0 0 0 0 0 0

mg/m³

2242

6376

64

107

158

211

255

7

0

50

100

150

200

250

300

13 26 38 51 64 77 90 102 115 128

kg Nox

RAW

0.0

20.0

40.0

60.0

80.0

100.0

120.0

140.0

0.0

0.5

1.0

1.5

2.0

2.5

10% 20% 30% 40% 50% 60% 70% 80% 90%

[g/kWh]

0.00

0.10

0.20

0.30

0.40

0.50

0.60

0.70

0.80

0.90

1.00

0

200

400

600

800

1,000

1,200

10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

mg/m³

0

200

400

600

800

1,000

1,200

0 0 0 0 0 0 0 0 0 0

mg/m³

22

4057

7160

99

145

193

237

8

0

50

100

150

200

250

12 24 35 47 59 71 82 94 106 118

kg Nox

RAW

0.0

20.0

40.0

60.0

80.0

100.0

120.0

140.0





LI 260442 Page 6-66


# Item 4







32

29,12351,499

69,655

103,402

135,795152,889

169,723186,792

204,592

86,115

0

50,000

100,000

150,000

200,000

250,000

0 0 0 0 0 0 0 0 0 0

m³ Exhaust Gas

525474

439 422462 446 433 423 417

594

0

200

400

600

800

10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

[g/kWh]

7.813.1

17.020.6

25.1

33.236.8

40.544.7

49.5

0

10

20

30

40

50

60

12 24 35 47 59 71 82 94 106 118

[t CO2]

[MW]

29,927

50,20165,123

96,109

127,232140,955

155,261171,171

189,703

78,992

0

50,000

100,000

150,000

200,000

10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

m³ Exhaust Gas

n/a

556

481437 426

470 446 430 421 420

663

0

200

400

600

800

10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

[g/kWh]

n/a





LI 260442 Page 6-67

6.8 Economic Description of Gas-Based Generation Option 4 (2+1 GT R)


Under consideration of the project’s implementation plan (already described in section 6.2.1)

and taking into account the already existing components, an implementation duration of two

years is estimated. The investment cost’s disbursement schedule is shown in Table 6-26.

The lifetime of the supply option 4 is related to the remaining lifetime of the existing gas turbines

which is estimated at approximately 15 years (see Table 1.12 Specifications of D_GT1e res-

pectively Table 1.13 Specifications of D_GT2e).



# Item

1

2

3

4

5

6

7

8

9

10


Total: 54,441


Balance of Plant


Engineering 2,510

Investment Costs

in T EUR


I&C Equipment 1,332

13,317

729

5,893

Steam Turbine Package incl. Generator 9,805

615


Plant Startup





LI 260442 Page 6-68

Year n-2 n-1 n

Disbursement in % 60% 40% Start Year



Gas-Based Generation option 1, 29% less compared to the gas-based generation option 2, and

respectively 14% less than the specific investment cost of supply option 3.


heat recovery boiler; (ii) the steam turbine package; (iii) soft costs of the contractor and (iv) the

civil works.

18%

24%

1%

11%

9%

2%

12% 5%

1%

16%




Balance of Plant


I&C Equipment


Engineering

Plant Startup



Documents

MALTA RESOURCES AUTHORITY - REWSdownloads.rews.org.mt/files/75da700c-1944-4c6b-a162-9e5091527fca... · MALTA RESOURCES AUTHORITY Energy Interconnection Europe - Malta March 2008 Final