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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.
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3
Figure 3-7: Layout of LNG Terminal with one 60,000 m 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.
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Figure 3-8: Layout of LNG Terminal with two 30,000 m³ LNG Storage Tanks
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Nevertheless sample drilling which is a very extensive and costly measure and will not be executed before a more advanced stage of regarding the potential realization of such an LNG terminal.
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 populated 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 capacity of 43 m3.
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3
Figure 3-9: Typical LNG Truck Trailer with a Capacity of 43 m
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:
x
x
LNG Spills;
x
Thermal Radiation;
x
Ship Grounding and LNG Release;
x
Acts of Nature (storm, earthquake etc);
x
Vapour Dispersion;
x
Environmental Impacts;
x
Terrorism or sabotage;
x
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”.
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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
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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
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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:
x
x
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
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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:
x
x
x
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 requirements.
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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.
Investment Costs
in T EUR
#
Item
1
Direct Cost (Labor, Materials & Subcontracts)
2
Construction Equipment
851
3
Overhead and Indirects
2,174
4
Home Office Services (EPC Contractor)
2,941
5
Owner's Engineering Services
3,431
6
Specialty Contractors
47,219
45,458
Total:
102,101
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
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o
o
o
o
o
Process Equipment;
Underground and Aboveground Pipelines;
Underground and Aboveground Electric Equipment;
Concrete, Instrumentation and Insulation;
Over less cost intensive items.
(ii) The Specialty Contractors Cost which includes:
o
o
o
o
LNG Tank Costs;
Jetty Upgrades Costs;
Dredging Costs;
Over less cost intensive items.
45%
Direct Cost (Labor, Materials & Subcontracts)
Construction Equipment
3%
Overhead and Indirects
3%
Home Office Services (EPC Contractor)
2%
1%
Owner's Engineering Services
Specialty Contractors
46%
Figure 3-10: Investment Cost Break Down of the LNG Scheme for Case (I) and (II)
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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:
x The sourcing structure (e.g. Point of sale, ex-ship, FOB);
x The selected partner;
x Desire of Buyer to move upstream;
x Ability to invest and carry risk.
The identified options can be summarised in three categories as follows:
x Ex-ship LNG supply to a Re-gas terminal in Malta;
x FOB LNG supply from a terminal in a gas producing country (e.g. Algeria);
x 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.
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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 following table.
#
Item
1
Technical Assistance
2
Inspection
3
Maintenance
4
Nitrogen
5
Management and Operation
960
6
Tugboat Operation Fees
160
7
Telecommunication
20
8
Permits & other Fees
30
9
Insurance
Costs in T EUR/a
220
50
820
20
200
Total Annual Fixed OPEX:
2,480
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.
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#
1
Item
Fuel Gas for LNG Vaporisation
2
Electricity for HP Pumpsand Blowers
3
Caustic Soda for Vaporisation
Costs in T EUR/a
184
1,550
5
Total Annual Variable OPEX:
1,739
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 scenario 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 provided. 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.
LNG Scheme
high (Case I)
LNG Scheme
base (Case II)
Pipe Scheme
high (Case I)
Pipe Scheme
base (Case II)
T EUR /a
116,320
116,320
139,090
139,090
T EUR /a
55,095
55,095
13,553
13,553
23.8
24.4
25.9
26.8
Item
Unit
PV Capital
PV OPEX
Dynamic Unit Cost EUR/t
Table 3-8: Dynamic Unit Cost of LNG and Pipeline Schemes
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T EUR /a
T EUR /a
t/a
Fixed OPEX
Variable OPEX
Fuel Gas Supplied
Fuel Gas Supplied
DUC - Gas Supply
EUR /t
EUR /1000m³
t/a
OPEX
4 Dynamic Unit Cost
T EUR /a
T EUR /a
Capital
3 Present Value
T EUR /a
Year >>
102,101
6.5%
30
3
2011
Investment Cost
Item
2 Cash Flow
Total Investment in T EUR
Discount Rate
Lifetime in a
Construction Period in a
Start of Operation
Case:
1 General Information
n-3
23.8
17.7
7,216,329
55,095
116,320
0
0
0
35,735
n-2
0
0
0
35,735
n-1
0
0
0
30,630
490,709
1,739
2,480
0
1
517,539
1,739
2,480
0
5
0
10
546,681
1,739
2,480
Gas Demand Scenario High
580,292
1,739
2,480
0
15
613,903
1,739
2,480
0
20
648,647
1,739
2,480
0
25
685,357
1,739
2,480
0
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Table 3-9: Dynamic Unit Cost of the LNG Scheme - Case (I)
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T EUR /a
T EUR /a
t/a
Fixed OPEX
Variable OPEX
Fuel Gas Supplied
Fuel Gas Supplied
DUC - Gas Supply
EUR /t
EUR /1000m³
t/a
OPEX
4 Dynamic Unit Cost
T EUR /a
T EUR /a
Capital
3 Present Value
T EUR /a
Year >>
102,101
6.5%
30
3
2011
Investment Cost
Item
2 Cash Flow
Total Investment in T EUR
Discount Rate
Lifetime in a
Construction Period in a
Start of Operation
Case:
1 General Information
n-3
24.4
18.3
7,012,935
55,095
116,320
0
0
0
35,735
n-2
0
0
0
35,735
n-1
0
0
0
30,630
382,042
1,739
2,480
0
1
488,785
1,739
2,480
0
5
0
10
543,302
1,739
2,480
Gas Demand Scenario Base
576,300
1,739
2,480
0
15
609,370
1,739
2,480
0
20
643,857
1,739
2,480
0
25
680,296
1,739
2,480
0
30
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Table 3-10: Dynamic Unit Cost of the LNG Scheme - Case (II)
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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. Although 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
35,000
10,000 m³ Ship
30,629
25,513
24,672
24,041
25,000
25,000 m³ Ship
29,788
29,158
30,000
LNG Storage Required (m³)
20,000 m³ Ship
20,000
15,000
15,279
14,438
13,807
10,000
5,000
0
0.170
0.200
0.240
Natural Gas Send Out (bcm/a)
Figure 3-11: Required LNG onshore Storage vs. LNG vessel size
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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 Station.
General Data
LNG Storage Vessel Size
LNG Storage Vessel Size (Net)
Number of days to provide reserve storage due to inclement
weather/ship delays/plant operations/etc.
Daily Send Out - Maximum (% over Nominal)
Fuel Gas (% of Send Out)
Low Gas Demand Scenario
Gas Send Out Flow Rate
Gas Send Out Flow Rate
Gas Send Out Flow Rate
Fuel Gas Flow Rate
Gas Send Out (Gross)
Reserve storage due to inclement weather/ship delays
Sub-Total - Required Storage
LNG Tank Heel
Storage Required
Ship Frequency
Low Gas Demand Scenario
Gas Send Out Flow Rate
Gas Send Out Flow Rate
Gas Send Out Flow Rate
Fuel Gas Flow Rate
Gas Send Out (Gross)
Reserve storage due to inclement weather/ship delays
Sub-Total - Required Storage
LNG Tank Heel
Storage Required
Ship Frequency
Low Gas Demand Scenario
Gas Send Out Flow Rate
Gas Send Out Flow Rate
Gas Send Out Flow Rate
Fuel Gas Flow Rate
Gas Send Out (Gross)
Reserve storage due to inclement weather/ship delays
Sub-Total - Required Storage
LNG Tank Heel
Storage Required
Ship Frequency
5.5%
5.5%
5.5%
10,000
9,700
25,000 m³
24,250 m³
20,000
19,400
4
10%
2.0%
days
0.17
512,329
830
17
847
3,388
13,088
720
13,807
11.5
0.17
512,329
830
17
847
3,388
22,788
1,253
24,041
22.9
0.17
512,329
830
17
847
3,388
27,638
1,520
29,158
28.6
bcm/year
m³/day (Gas)
m³/day (LNG)
m³/day (LNG)
m³/day (LNG)
m³
m³
m³
m³
days
0.2
602,740
976
20
996
3,985
13,685
753
14,438
9.7
0.2
602,740
976
20
996
3,985
23,385
1,286
24,672
19.5
0.2
602,740
976
20
996
3,985
28,235
1,553
29,788
24.3
bcm/year
m³/day (Gas)
m³/day (LNG)
m³/day (LNG)
m³/day (LNG)
m³
m³
m³
m³
days
0.24
723,288
1,172
24
1,196
4,783
14,483
797
15,279
8.1
0.24
723,288
1,172
24
1,196
4,783
24,183
1,330
25,513
16.2
0.24
723,288
1,172
24
1,196
4,783
29,033
1,597
30,629
20.3
bcm/year
m³/day (Gas)
m³/day (LNG)
m³/day (LNG)
m³/day (LNG)
m³
m³
m³
m³
days
Table 3-11: Calculation for required LNG Storage Volume – Case (III)
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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).
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3.4
Economic Description of the Proposed Scheme for Case (III)
3.4.1
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 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.
Investment Costs
in T EUR
#
Item
1
Direct Cost (Labor, Materials & Subcontracts)
2
Construction Equipment
876
3
Overhead and Indirects
2,237
4
Home Office Services (EPC Contractor)
2,730
5
Owner's Engineering Services
3,299
6
Specialty Contractors
22,944
Total:
75,705
43,619
Table 3-12: Investment Cost of LNG Scheme Case (III)
Year
n-3
n-2
n-1
n
Disbursement in %
35%
35%
30%
Start Year
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:
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Site Preparation and Improvement;
o
Process Equipment;
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o
o
o
o
Underground and Aboveground Pipelines;
Underground and Aboveground Electric Equipment;
Concrete, Instrumentation and Insulation;
Over less cost intensive items.
Nearly a third of the total investment is caused by the specialty contractors cost which includes:
o
o
o
LNG Tank Costs;
Jetty Upgrades Costs;
Over less cost intensive items.
Direct Cost (Labor, Materials & Subcontracts)
4%
30%
4%
3%
Construction Equipment
1%
Overhead and Indirects
Home Office Services (EPC Contractor)
Owner's Engineering Services
Specialty Contractors
58%
Figure 3-12: Investment Cost Break Down of the LNG Scheme for Case (III)
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3.4.2
Operational and Maintenance Costs
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 following table.
#
Item
1
Technical Assistance
2
Inspection
3
Maintenance
4
Nitrogen
5
Management and Operation
6
Tugboat Operation Fees
80
7
Telecommunication
20
8
Permits & other Fees
30
9
Insurance
Costs in T EUR/a
200
40
690
20
960
150
Total Annual Fixed OPEX:
2,190
Table 3-14: 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 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.
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#
1
Item
Fuel Gas for LNG Vaporisation
2
Electricity for HP Pumpsand Blowers
3
Caustic Soda for Vaporisation
Total Annual Variable OPEX:
Costs in T EUR/a
37
520
2
559
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).
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T EUR /a
T EUR /a
t/a
Fixed OPEX
Variable OPEX
Fuel Gas Supplied
t/a
Fuel Gas Supplied
DUC - Gas Supply
EUR /t
EUR /1000m³
T EUR /a
OPEX
4 Dynamic Unit Cost
T EUR /a
Capital
3 Present Value
T EUR /a
Year >>
75,705
6.5%
30
3
2011
Investment Cost
Item
2 Cash Flow
Total Investment in T EUR
Discount Rate
Lifetime in a
Construction Period in a
Start of Operation
Case:
1 General Information
78.3
58.5
1,559,363
35,898
86,248
0
0
0
26,497
n-3
0.7414717
n-2
0
0
0
26,497
n-1
0
0
0
22,712
120,890
559
2,190
0
1
122,258
559
2,190
0
5
0
10
122,258
559
2,190
Gas Demand Scenario Low
116,145
559
2,190
0
15
116,145
559
2,190
0
20
116,145
559
2,190
0
25
116,145
559
2,190
0
30
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Table 3-16: Dynamic Unit Cost of the LNG Scheme - Case (III)
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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 regasification 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 regas fleet:
x Capacity in Off-shore Mode is 14,150,000 m3/d using sea-water
(Unloading ~5.6 days);
x Capacity in Dock-side Mode is 12,750,000 m3/d without sea-water
(Unloading ~6.2 days);
x 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.
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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 terminal) 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.
High Pressure Pumps
And Vaporisers
Reinforced
LNG
Storage Tanks
Oversized
Boiler
Traction
Winch
Buoy
Compartment
Energy Bridge™
Regasification Vessel
Figure 4-1: Schematic Overview of a Regas-Vessel
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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 delivery method in areas where conventional LNG Regas terminal can not be built due to environmental 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.
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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 sections. Under consideration of all gas demand scenario below Table 5-1 provides the total fuel
LNG Scheme
Base Gas Demand
Pipeline Scheme
Base Gas Demand
EUR/t
180.0
202.6
Dynamic Unit Cost
of Fuel Supply
EUR/t
24.4
26.8
Total
EUR/t
204.4
229.4
Item
Unit
LNG Scheme
High Gas Demand
Pipeline Scheme
High Gas Demand
Projected Market
Fuel Price (2011)
EUR/t
180.0
202.6
Dynamic Unit Cost
of Fuel Supply
EUR/t
23.8
25.9
Total
EUR/t
203.7
228.5
Item
Unit
LNG Scheme
Low Gas Demand
Pipeline Scheme
Low Gas Demand
Projected Market
Fuel Price (2011)
EUR/t
180.0
202.6
Dynamic Unit Cost
of Fuel Supply
EUR/t
78.3
96.4
Total
EUR/t
258.3
299.0
Item
Unit
Projected Market
Fuel Price (2011)
Table 5-1: Comparison of Fuel Supply Cost – Gas Supply Alternatives
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270.0
Gas via LNG Conversion EUR/t
250.0
230.0
210.0
190.0
170.0
150.0
130.0
Year
110.0
2010
2015
2020
2025
2030
270.0
Natural Gas via Pipeline EUR/t
250.0
230.0
210.0
190.0
170.0
150.0
130.0
Year
110.0
2010
2015
2020
2025
2030
Figure 5-1: Comparison of Fuel Gas Prices of Supply Alternatives investigated
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costs in EUR per tonne including the costs of the supply and the market price (for the first possible 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 options.
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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:
x
x
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 introduced 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
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
Description
Identification
Table 6-1: General Data – New Gas-Based Generation Options
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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
Plant Type
Set Size (nominal)
Value
CCGT 2+1
MW
Partial Load
128.0
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
%
1.9%
2.2%
2.9%
2.5%
3.8%
1.2%
2GT+1ST
2GT+1ST
2GT+1ST
1GT+1ST
1GT+1ST
1GT
Partial Load
100%
85%
70%
50%
30%
20%
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%
Self Consumption
Turbines in Operation
Net Heat Rate
Table 6-2: Technical Data – Gas-Based Generation Option 1
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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 design 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:
x
x
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 operation) to 3.8% (1 GT + 1 ST operation) and decreases then to some 1.2% (1 GT operation);
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:
x
x
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 6-3
LI 260442
0
2,000
4,000
6,000
8,000
10,000
12,000
14,000
16,000
18,000
0
20,000
40,000
80,000
Load (kW)
60,000
100,000
120,000
2+1 gross HR
2+1 net HR
1+1 gross HR
1+1 net HR
1+0 gross HR
1+0 net HR
Heat Rates (kJ/kWh) of Supply Option 1 - 2+1 CCGT NG fired
140,000
MALTA RESOURCES AUTHORITY
Energy Interconnection Europe - Malta
March 2008
Final Report – Work Package IIA
Figure 6-1: Gross and Net Heat Rates – Gas-Based Generation Option 1
Page 6-4
Heat Rate (kJ/kWh)
160
2.323 p
116 T
150.3 M
LTE
2.323 p
125 T
2.609 M
152.9 M
160
IPB
3.08 M
20 T
190
237
9.159 p 9.159 p
171 T
176 T
152.9 M 23.9 M
IPE2
LNG 8.771 m
LHV= 117294 kWth
11.28 p
376 T
HPE2
10.83 p
1132 T
267
73.79 p
230 T
125.7 M
237
1X GE 6581B
HPE3
270
301
HPB1
HPS0
1.50 M
67.73 p
529 T
127.5 M
1.04 p
567 T
960.7 M
2 X GT
302
477
488
8.844 p 72.49 p 71.82 p
260 T 288 T
309 T
21.3 M 124.4 M 124.4 M
IPS2
35742 kW
480.3 m
8.993 p 72.49 p
228 T 282 T
21.3 M 125.7 M
IPS1
CCGT 2+1 configuration NG fired
100% load at summer conditions
488
21.3 M
488
Figure 6-2: Heat and Mass Balance – Gas-Based Generation Option 1 (Summer Conditions)
565
70.09 p
545 T
126 M
HPS3
FW
2.384 m^3/kg
636.2 m^3/s
565 T
960.7 M
1.58 M
46 T
0.0385 M
0.1032 p
46 T
148.8 M
42645 kW
72.73 %N2
13.37 %O2
3.314 %CO2
9.705 %H2O
0.8758 %Ar
Net Power 111711 kW
LHV Heat Rate 7560 kJ/kWh
p[bar], T[C], M[t/h], Steam Properties: IAPWS-IF97
316 08-20-2007 10:42:23 file=T:\26\0400\260442_malta\06_project_results\GTPro\Case 1 (2+1) neu\NG-fired\CCGT 2+1 NG fired 100% load summer conditions.gtm
1.136 m^3/kg
303.2 m^3/s
118 T
960.7 M
116 T
46 T
150.3 M
1p
36 T
471.6 m
GT MASTER 17.0.1 LI - W. Eisenhart
1.01 p
36 T
70 %RH
471.6 m
70.09 p 545 T
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Final Report – Work Package IIA
Energy Interconnection Europe - Malta
Colours:
Abbreviation:
- high pressure steam
red
light blue - intermediate pressure steam
p - pressure in bar
MALTA RESOURCES AUTHORITY
- gas, air and exhaust gas flow
violet
dark blue - feed water and water injection
to gas turbine
M - mass flow in kg / s
T - temperature in °C
8.325 p 258 T
Page 6-5
March 2008
163
2.323 p
125 T
1p
13 T
523 m
3.303 M
158.8 M
163
IPB
20 T
193
242
9.565 p 9.565 p
174 T
178 T
158.8 M 26.92 M
IPE2
LNG 9.789 m
LHV= 130906 kWth
12.44 p
358 T
HPE2
11.94 p
1136 T
271
75.5 p
233 T
131.6 M
242
1X GE 6581B
HPE3
274
303
HPB1
2 X GT
HPS0
69.15 p
528 T
130.3 M
1.04 p
551 T
1065.5 M
305
471
482
9.198 p 74.08 p 73.36 p
261 T 290 T
309 T
23.61 M130.3 M 130.3 M
IPS2
41563 kW
532.8 m
9.372 p 74.08 p
229 T 285 T
23.61 M 131.6 M
IPS1
CCGT 2+1 configuration NG fired
100% load at winter conditions
482
482
Figure 6-3: Heat and Mass Balance – Gas-Based Generation Option 1 (Winter Conditions)
549
FW
2.299 m^3/kg
680.4 m^3/s
549 T
1065.5 M
34 T
0.0399 M
71.57 p
530 T
130.3 M
HPS3
23.61 M
0.0544 p
34 T
153.9 M
46507 kW
75.3 %N2
13.95 %O2
3.378 %CO2
6.469 %H2O
0.9067 %Ar
Net Power 127120 kW
LHV Heat Rate 7414 kJ/kWh
p[bar], T[C], M[t/h], Steam Properties: IAPWS-IF97
316 08-20-2007 10:43:22 file=T:\26\0400\260442_malta\06_project_results\GTPro\Case 1 (2+1) neu\NG-fired\CCGT 2+1 NG fired 100% load winter conditions.gtm
1.12 m^3/kg
331.6 m^3/s
2.323 p
114 T
155.5 M
117 T
1065.5 M
LTE
114 T
34 T
155.5 M
1.01 p
13 T
45 %RH
523 m
GT MASTER 17.0.1 LI - W. Eisenhart
71.57 p 530 T
LI 260442
Final Report – Work Package IIA
Energy Interconnection Europe - Malta
Colours:
Abbreviation:
- high pressure steam
red
light blue - intermediate pressure steam
p - pressure in bar
MALTA RESOURCES AUTHORITY
- gas, air and exhaust gas flow
violet
dark blue - feed water and water injection
to gas turbine
M - mass flow in kg / s
T - temperature in °C
8.612 p 259 T
Page 6-6
March 2008
MALTA RESOURCES AUTHORITY
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March 2008
Final Report – Work Package IIA
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 comparable 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.
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March 2008
Final Report – Work Package IIA
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 shown 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 environmental 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
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MALTA RESOURCES AUTHORITY
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March 2008
Final Report – Work Package IIA
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 programme 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):
x
x
x
x
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
of 57 t/PJ (assuming a removal efficiency of 80%);
2020: Unabated EF for NOx emissions of 500 t/PJ; Abated EF for NOx emissions
of 155 t/PJ (assuming a removal efficiency of 69%);
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:
x
x
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:
x
A maximum of 630 g/kWh regarding the emissions of Greenhouse Gases.
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MALTA RESOURCES AUTHORITY
Energy Interconnection Europe - Malta
March 2008
Final Report – Work Package IIA
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
10000
5000
kJ / kWh
#
0
-
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 O
Case1
20%
30%
40%
50%
60%
70%
80%
90%
100%
10700
[comb. temp.]
12 Heat Rate* Coeff C (2+1)
10%
8700
6700
4700
2700
700
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
1.0 - 1.09
Table 6-3: Specifications of D_CC1NGo (1/3)
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Final Report – Work Package IIA
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
Fuel Nox Coeff. C
NA
19
Fuel NOx Emissions over load (RAW)
20 Thermal NOx Emissions over load (RAW)
mg/m³
mg/m³
1,200
1,000
800
600
400
200
0
1,200
1,000
800
600
400
200
1
0
10% 20% 30% 40% 50% 60% 70% 80% 90% 100%
21 Specific NOx Emissions in g/kWh
Absolute NOx Emissions in tons
[g/kWh]
2.5
1.20
2.0
1.00
0.80
1.5
kg Nox
RAW
300
255
211
200
0.60
1.0
0.40
0.5
0.20
0.0
0.00
10%
20%
30%
40%
50%
60%
70%
80%
100.0
158
150
80.0
60.0
107
100
50
140.0
120.0
250
63
76
40.0
64
42
7
22
20.0
0
0.0
13
26
38
51
64
77
90
102
115
128
90%
Fuel Specifications
22 Initial Primary Fuel
23 Net Calorific Value
Rich gas
% of Carbon
Natural Gas
kJ/kg
48,156
24 Required Fuel at 100% load
kg
19,795
25 Required Combustion Air
m³
9.89
Fuel Composition
% of Nitrogen
(Emission Relevant)
75.00%
0.00%
% of Sulphur
0.00%
% of Nox Reduc.
50.00%
% of SO2 Reduc.
0.00%
Potential Emission Reduction
26 Resulting Exhaust Gas
m³
10.34
Table 6-3: Specifications of D_CC1NGo (2/3)
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MALTA RESOURCES AUTHORITY
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March 2008
Final Report – Work Package IIA
CO2 and SOx Emissions
#
Item
1
27
Fuel needed at 100% load
t
19.79
28
Density of Fuel
29
CO2 emission at 100% load
30
Specific CO2 Emissions in g/kWh
kg / m³ 0.77
t
53.38
Absolute CO2 Emissions in t
[t CO2]
[g/kWh]
60
800
50
594
600
525
474
35.4
40
439
422
462
446
433
423
417
30
400
20
10
200
13.4
18.2
22.5
39.9
44.3
48.7
53.4
27.0
7.6
0
13
0
10%
31
20%
30%
40%
50%
60%
70%
80%
90%
26
38
51
100%
Specific SOx Emissions in g/kWh
64
77
[MW]
90
102
115
128
Absolute SOx Emissions in tons
n/a
n/a
Exhaust Gas development in m³ due to Gross Performance
m³ Exhaust Gas
32
250,000
200,000
135,795
150,000
152,889
169,723
186,792
204,592
103,402
100,000
69,655
86,115
51,499
50,000
29,123
0
1
Table 6-3: Specifications of D_CC1NGo (3/3)
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March 2008
Final Report – Work Package IIA
The air pollution emissions of the investigated supply option:
x
do not exceed the limit value for NOx emissions;
x
do not exceed the limit value for SO2 emissions. Natural gas does not cause such
emissions at all;
x
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.
Specific Emissions g CO2/kWh .
1,000
900
800
921
871
700
600
500
400
420
300
200
100
Business as Usual
(all STs)
Business as Usual
(DPS ST)
Supply Option
Figure 6-5: Comparison of Greenhouse Gas Emissions - Gas-Based Generation Option 1
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MALTA RESOURCES AUTHORITY
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March 2008
Final Report – Work Package IIA
6.2
Economic Description of Gas-Based Generation Option 1 (CCGT 2+1)
6.2.1 Investment Costs of Major Components
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:
x
x
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;
LI 260442
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.
Page 6-14
MALTA RESOURCES AUTHORITY
Energy Interconnection Europe - Malta
March 2008
Final Report – Work Package IIA
Investment Costs
in T EUR
#
Item
1
Gas Turbine Package incl. Generator
24,700
2
Steam Turbine Package incl. Generator
10,342
3
Heat Recovery Boiler
14,125
4
Cooling Facility/Cooling System
5
Balance of Plant
6,095
6
Electrical Equipment
7,189
7
I&C Equipment
1,354
8
Civil/Buildings incl. On-Site Transportation
8,905
9
Engineering
3,470
10 Plant Startup
750
644
11 Contractor's Soft Costs
Total:
12,177
89,775
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 component. In total, the projects investment cost amounts to 89.8 Mio Euro (10% contingencies included). 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.
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MALTA RESOURCES AUTHORITY
Energy Interconnection Europe - Malta
March 2008
Final Report – Work Package IIA
Year
n-3
n-2
n-1
n
Disbursement in %
50%
30%
20%
Start Year
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).
2%
8%
10%
Gas Turbine Package incl. Generator and Air
inlet cooling/heating if applicable
Steam Turbine Package incl. Generator
4%
1%
Heat Recovery Boiler
7%
14%
1%
Cooling Facility/Cooling System
Balance of Plant
Electrical Equipment
I&C Equipment
16%
Civil/Buildings incl. On-Site Transportation
Engineering
28%
12%
Plant Startup
Contractor's Soft Costs
Figure 6-6: Investment Cost Break Down of Gas-Based Generation Option 1
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MALTA RESOURCES AUTHORITY
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March 2008
Final Report – Work Package IIA
6.2.2 Operational and Maintenance Costs
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
Fuel Supply Costs
(via LNG conversion)
Item
Fuel Supply Costs
(via LNG conversion)
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
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
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
Personnel Costs
2
Insurance, Fees and Others
2,244
Total Annual Fixed OPEX:
2,994
Costs in T EUR/a
750
Table 6-7: Estimate of Annual Fixed OPEX
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MALTA RESOURCES AUTHORITY
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Final Report – Work Package IIA
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).
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EUR/t
T EUR/a
t/a
GWh/a
Fuel Supply Costs (specific)
Fuel Supply Costs (absolute)
Fuel Input
Net Generation
DUC - Power Generation
4 Dynamic Unit Cost
Capital
OPEX
Net Generation
EUR/MWh
Partial Load
T EUR
T EUR
GWh
T EUR/a
Variable OPEX
3 Present Value
T EUR/a
Fixed OPEX
Year >>
70%
89.6
87.0
2.6
2.9%
50%
63.6
62.0
1.6
2.5%
106 7
46.1
85%
44.4
125 5
0
0
0
0
0
0
26,933
n-2
70%
7,963
50.1
87 9
70%
0
0
0
0
0
0
17,955
n-1
50%
7,528
2GT+1ST 1GT+1ST
100%
103,891
457,810
12,173
0
0
0
0
0
0
44,888
n-3
85%
7,647
100%
7,441
20
3%
91.5%
T EUR/a
kJ/kWh
d/a
%/a
%/a
2GT+1ST
2GT+1ST
Investment Cost
Item
2 Cash Flow
Net Heat Rate
Planned Outage
Forced Outage
Max Availability
85%
109.3
106.9
2.4
2.2%
30%
38.4
36.9
1.4
3.8%
20%
25.1
24.8
0.3
1.2%
53.9
62 8
50%
204
30,256
148,045
932
31,748
2,994
0
1
30%
8,478
1GT+1ST
71.8
37 7
30%
198
29,270
148,045
932
30,761
2,994
0
2
20%
13,974
1GT
3
110.9
25 1
20%
191
28,283
148,045
932
29,774
2,994
0
191
28,283
148,045
932
29,774
2,994
0
4
201
29,763
148,045
932
31,254
2,994
0
10
89,775
6.5%
30
3
221
32,723
148,045
932
34,215
2,994
0
20
238
35,296
148,045
932
36,787
2,994
0
30
Operation at 85% Load
T EUR/a 2,994
EUR/MWh 1.6
-- Regas LNG
kJ/kg 48,150
T EUR
%
a
a
Local Generation Option 1 (CCGT 2+1)
191
28,283
148,045
932
29,774
2,994
0
5
* other than Fuel Costs
Fixed OPEX
Variable OPEX*
Fuel Type
Net Calorific Value
Total Investment
Discount Rate
Lifetime
Construction Period
MW
MW
MW
%
--
CCGT 2+1
128.0
100%
128.0
125.5
2.5
1.9%
Plant Type
Set Size (nominal)
Partial Load
Set Capacity (gross)
Set Capacity (net)
Auxiliary Power
Self Consumption
Turbines in Operation
-MW
1.2 Economics
p
1.1 Technical
1 General Information
MALTA RESOURCES AUTHORITY
Energy Interconnection Europe - Malta
March 2008
Final Report – Work Package IIA
Table 6-8: Dynamic Unit Cost of the Gas-based Option 1
Page 6-19
MALTA RESOURCES AUTHORITY
Energy Interconnection Europe - Malta
March 2008
Final Report – Work Package IIA
Dynamic Unit Cost EUR/MWh
140
120
100
80
60
40
20
0
20.0
40.0
60.0
80.0
100.0
120.0
Plant's Operation - Load (Net) in MW
140
1,400
120
1,200
100
1,000
80
800
60
600
40
400
20
200
0
10%
Plant's Net Generation in GWh/a
Dynamic Unit Cost EUR/MWh
-
20%
30%
40%
50%
60%
70%
80%
90% 100%
Plant's Operation as Percentage of Load
Figure 6-7: Dynamic Unit Cost over Plant’s Load - Gas-Based Option 1
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Final Report – Work Package IIA
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 Systems; (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 Characteristics
Unit
Plant Type
Set Size (nominal)
Value
CCGT 1+1
MW
Partial Load
114.6
100%
85%
70%
50%
40%
25%
Set Capacity (gross)
MW
114.6
96.8
78.3
58.3
46.0
30.8
Set Capacity (net)
MW
112.3
94.6
76.2
56.3
45.4
30.3
Auxiliary Power
MW
2.4
2.2
2.1
1.9
0.6
0.5
%
2.1%
2.3%
2.7%
3.3%
1.3%
1.6%
1GT+1ST
1GT+1ST
1GT+1ST
1GT+1ST
1GT
1GT
Partial Load
100%
85%
70%
50%
40%
25%
kJ/kWh
6,930
7,141
7,471
8,122
12,564
15,101
Planned Outage
d/a
18
Forced Outage
%/a
3%
Max Availability
%/a
92.1%
Self Consumption
Turbines in Operation
Net Heat Rate
Table 6-9: Technical Data – Gas-Based Generation Option 2
LI 260442
Page 6-21
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Final Report – Work Package IIA
Maltese local conditions and provided fuel specifications have been considered for the evaluation 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
operational characteristics, which can be summarized as follows:
x
x
The plant’s self consumption (auxiliary power) drops from 2.4 MW to 0.5 MW in absolute
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.
Assuming outage characteristics of an average of 18 days a year for the units’ maintenance and
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
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:
x
x
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.
The plants’ net heat rate decreases from 7,113 kJ/kWh during summer to 6,903 kJ/kWh
during winter. This is equal to a net efficiency increase from 50.6% (summer) to 52.2%
(winter).
LI 260442
Page 6-22
LI 260442
0
2,000
4,000
6,000
8,000
10,000
12,000
14,000
16,000
0
20,000
40,000
Load (kW)
60,000
80,000
100,000
1+0 net HR
1+0 gross HR
1+1 net HR
1+1 gross HR
Heat Rates (kJ/kWh) of Supply Option 2 - 1+1 CCGT NG fired
120,000
MALTA RESOURCES AUTHORITY
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March 2008
Final Report – Work Package IIA
Figure 6-8: Gross and Net Heat Rates – Gas-Based Generation Option 2
Page 6-23
Heat Rate (kJ/kWh)
157
2.323 p
115 T
119.6 M
LTE
2.323 p
125 T
1p
36 T
666.8 m
2.225 M
121.8 M
157
IPB
3.12 M
31 T
189
227
9.077 p 9.077 p
171 T
176 T
121.8 M 13.63 M
IPE2
LNG 14.45 m
LHV= 193176 kWth
20 T
14.02 p
397 T
HPE2
13.32 p
1318 T
263
73.45 p
229 T
104.9 M
227
1X GE 6111FA
HPE3
265
301
HPB1
HPS0
1.73 M
67.49 p
585 T
107 M
1.04 p
629 T
681.2 M
302
506
520
8.783 p 72.22 p 71.71 p
260 T 288 T
309 T
11.41 M 103.9 M 103.9 M
IPS2
62965 kW
681.2 m
8.952 p 72.22 p
228 T 282 T
11.41 M 104.9 M
IPS1
CCGT 1+1 configuration NG fired
100% load at summer conditions
520
Figure 6-9: Heat and Mass Balance – Gas-Based Generation Option 2 (Summer Conditions)
520
627
FW
2.568 m^3/kg
485.9 m^3/s
627 T
681.2 M
1.38 M
46 T
0.0344 M
69.84 p
607 T
105.3 M
HPS3
11.41 M
0.1032 p
46 T
118.4 M
37072 kW
72.39 %N2
12.3 %O2
3.837 %CO2
10.6 %H2O
0.8716 %Ar
Net Power 97771 kW
LHV Heat Rate 7113 kJ/kWh
p[bar], T[C], M[t/h], Steam Properties: IAPWS-IF97
316 08-20-2007 11:27:33 file=T:\26\0400\260442_malta\06_project_results\GTPro\Case 2 (1+1) neu\CCGT 1+1 NG FIRED 100% load summer conditions.gtm
1.114 m^3/kg
210.8 m^3/s
109 T
681.2 M
115 T
46 T
119.6 M
1.01 p
36 T
70 %RH
666.8 m
GT MASTER 17.0.1 LI - W. Eisenhart
69.84 p 607 T
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Final Report – Work Package IIA
Energy Interconnection Europe - Malta
MALTA RESOURCES AUTHORITY
Colours:
Abbreviation:
- high pressure steam
red
light blue - intermediate pressure steam
p - pressure in bar
- gas, air and exhaust gas flow
violet
dark blue - feed water and water injection
to gas turbine
M - mass flow in kg / s
T - temperature in °C
8.302 p 258 T
Page 6-24
March 2008
160
2.323 p
114 T
124.1 M
LTE
2.323 p
125 T
1p
13 T
746.8 m
2.619 M
126.7 M
160
IPB
0.001 M
31 T
193
232
9.536 p 9.536 p
174 T
178 T
126.7 M 15.75 M
IPE2
LNG 16.29 m
LHV= 217815 kWth
20 T
15.65 p
380 T
HPE2
14.87 p
1328 T
267
75.38 p
233 T
110.8 M
232
1X GE 6111FA
HPE3
269
304
HPB1
HPS0
69.1 p
584 T
109.7 M
1.04 p
606 T
763.1 M
305
499
511
9.173 p 74.01 p 73.47 p
260 T 290 T
309 T
13.12 M109.7 M 109.7 M
IPS2
75611 kW
763.1 m
9.382 p 74.01 p
229 T 285 T
13.12 M110.8 M
IPS1
CCGT 1+1 configuration NG fired
100% load at winter conditions
511
Figure 6-10: Heat and Mass Balance – Gas-Based Generation Option 2 (Winter Conditions)
511
604
FW
2.46 m^3/kg
521.5 m^3/s
604 T
763.1 M
34 T
0.036 M
71.52 p
586 T
109.7 M
HPS3
13.12 M
0.0542 p
34 T
122.7 M
40367 kW
74.94 %N2
12.85 %O2
3.912 %CO2
7.395 %H2O
0.9023 %Ar
Net Power 113597 kW
LHV Heat Rate 6903 kJ/kWh
p[bar], T[C], M[t/h], Steam Properties: IAPWS-IF97
316 08-20-2007 11:27:57 file=T:\26\0400\260442_malta\06_project_results\GTPro\Case 2 (1+1) neu\CCGT 1+1 NG FIRED 100% load winter conditions.gtm
1.098 m^3/kg
232.8 m^3/s
109 T
763.1 M
114 T
34 T
124.1 M
1.01 p
13 T
45 %RH
746.8 m
GT MASTER 17.0.1 LI - W. Eisenhart
71.52 p 586 T
LI 260442
Final Report – Work Package IIA
Energy Interconnection Europe - Malta
MALTA RESOURCES AUTHORITY
Colours:
Abbreviation:
- high pressure steam
red
light blue - intermediate pressure steam
p - pressure in bar
- gas, air and exhaust gas flow
violet
dark blue - feed water and water injection
to gas turbine
M - mass flow in kg / s
T - temperature in °C
8.601 p 258 T
Page 6-25
March 2008
MALTA RESOURCES AUTHORITY
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March 2008
Final Report – Work Package IIA
6.3.2 Location
Regarding the potential location of supply option 2, the same site was selected as already depicted for supply option 1 in Figure 6-4.
6.3.3 Air Pollution Emissions
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 directives and with all the relevant aspects of the Maltese Legislation.
In the following tables the environmental impact due to potential air pollution emissions is
presented. The air pollution emissions of the investigated supply option:
x
x
x
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 56% below the current Green House Gas emissions (typical unit operation assumed)
and do not exceed the limit value for CO2 emissions.
Specific Emissions g CO2/kWh .
1,000
900
800
921
871
700
600
500
400
401
300
200
100
Business as Usual
(all STs)
Business as Usual
(DPS ST)
Supply Option
Figure 6-11: Comparison of Greenhouse Gas Emissions - Gas-Based Generation Option 2
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Final Report – Work Package IIA
General Information
#
Item
2
1 Plant Name
Natural Gas Based Supply Option 2
2 Plant Type
Combined Cycle Gas Turbine
3 Unit
CCGT 1+1 NG fired
4 State
Option
5 Unit_Ident
6 Comments
No Comments
Technical & Operational Data for Emissions (continued)
#
Item
Dim
2
7 Nominal Capacity
MW
114.6
8 Max Capacity Sent-Out (Operation)
MW
112.3
9 Min Capacity Sent-Out (Operation)
MW
30.8
10 Heat Rate* Coeff A (1+1)
-
5,619
11 Heat Rate* Coeff B (1+1)
-
-10,966
12 Heat Rate* Coeff C (1+1)
-
12,336
10000
20000
5000
10000
kJ / kWh
15000
5000
0
46,433
11a Heat Rate* Coeff B (1+0)
-50,173
12a Heat Rate* Coeff C (1+0)
25,219
13 Combustion Temp Coeff A
-
-742
14 Combustion Temp Coeff B
-
1,579
15 Combustion Temp Coeff C
-
485
16 Air Rate Lambda O
Case1
20%
30%
40%
50%
60%
70%
80%
90%
100%
1400
1300
[comb. temp.]
10a Heat Rate* Coeff A (1+0)
10%
1200
1100
1000
900
800
700
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
1.0 - 1.09
Table 6-10: Specifications of D_CC2NGo (1/3)
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Final Report – Work Package IIA
NOx Emissions
#
Item
2
17
Thermal Nox Coeff. A
1E-21
Fuel Nox Coeff. A
NA
18
Thermal Nox Coeff. B
7.72
Fuel Nox Coeff. B
NA
Fuel Nox Coeff. C
NA
19
Fuel NOx Emissions over load (RAW)
20 Thermal NOx Emissions over load (RAW)
mg/m³
mg/m³
mg/m³
1,200
1,200
1,200
1,000
1,000
1,000
800
800
800
600
600
400
400
600
400
200
2000
200
0
0.1
21 Specific NOx Emissions in g/kWh
[g/kWh]
1.20
kg Nox
RAW
2.0
1.00
250
300
0.80
250
200
1.5
0.20
200
150
150
100
100
50
50
0.00
0
0.60
1.0
0.40
0.5
0.0
20%
30%
40%
50%
60%
0.2
0.3
0.4
0.5
0.6
0.7
0.8
0.9
1
Absolute NOx Emissions in tons
2.5
10%
0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1
0
10% 20% 30% 40% 50% 60% 70% 80% 90% 100%
70%
80%
90%
214
255
175
211
131
158
90
65
13
7
11
13
63
36
22
42
23
26
34
38
46
51
75
76
57
64
54
64
80
90
92
102
120.0
100.0
100.0
80.0
80.0
60.0
60.0
40.0
40.0
20.0
20.0
89
107
69
77
120.0
140.0
103
115
115
128
0.0
Fuel Specifications
22 Initial Primary Fuel
Rich gas
23 Net Calorific Value
kJ/kg
48,156
24 Required Fuel at 100% load
kg
16,633
25 Required Combustion Air
m³
9.89
% of Carbon
Natural Gas
Fuel Composition
% of Nitrogen
(Emission Relevant)
75.00%
0.00%
% of Sulphur
0.00%
% of Nox Reduc.
50.00%
% of SO2 Reduc.
0.00%
Potential Emission Reduction
26 Resulting Exhaust Gas
m³
10.34
Table 6-10: Specifications of D_CC2NGo (2/3)
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Final Report – Work Package IIA
CO2 and SOx Emissions
#
Item
2
27
Fuel needed at 100% load
t
16.63
28
Density of Fuel
29
CO2 emission at 100% load
30
Specific CO2 Emissions in g/kWh
kg / m³ 0.77
t
44.85
Absolute CO2 Emissions in t
[t CO2]
[g/kWh]
50
1,400
800
1157
1,200 594
600
1,000
40
954
525
800
400
600
474
803 439
704 422
462
462
436
446
415
433
423
401
393
32.3
27.6
30
417
26.5
30.0
33.3
36.8
21.9
20 13.3
391
400
200
200
10
0
00
11
10% 20%
20% 30%
30% 40%
40% 50%
50% 60%
60%
10%
31
44.9
40.5
70%
70%
80%
80%
90%
90%
23
34
46
100%
Specific SOx Emissions in g/kWh
57
69
[MW]
80
92
103
115
Absolute SOx Emissions in tons
n/a
n/a
Exhaust Gas development in m³ due to Gross Performance
m³ Exhaust Gas
32
200,000
250,000
200,000
150,000
123,762
105,860
150,000
100,000
100,000
50,832
50,000
50,000
29,123
101,558
103,402
83,834
51,499
69,655
114,808
135,795
127,639
152,889
140,880
169,723
155,361
186,792
171,912
204,592
86,115
0
0.1
10%
0.2
20%
0.3
30%
0.4
40%
0.5
50%
0.6
60%
0.7
70%
0.8
80%
0.9
90%
1
100%
Table 6-10: Specifications of D_CC2NGo (3/3)
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Page 6-29
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Final Report – Work Package IIA
6.4
Economic Description of Gas-Based Generation Option 2 (CCGT 1+1)
6.4.1 Investment Costs of Major Components
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 implementation 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).
Investment Costs
in T EUR
#
Item
1
Gas Turbine incl. Generator
2
Steam Turbine Package incl. Generator
9,698
3
Heat Recovery Boiler
9,954
4
Cooling Facility/Cooling System
5
Balance of Plant
5,163
6
Electrical Equipment
5,737
7
I&C Equipment
8
Civil/Buildings incl. On-Site Transportation
7,812
9
Engineering
3,292
10
Plant Startup
11
Contractor's Soft Costs
20,853
672
853
603
Total:
9,894
74,550
Table 6-11: Investment Costs of Gas-Based Generation Option 2
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March 2008
Final Report – Work Package IIA
Year
n-3
n-2
n-1
n
Disbursement in %
50%
30%
20%
Start Year
Table 6-12: Disbursement Schedule of Gas-Based Generation Option 2
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.
Gas Turbine incl. Generator
1%
8%
10%
4%
Steam Turbine Package incl. Generator
1%
Heat Recovery Boiler
7%
13%
1%
Cooling Facility/Cooling System
Balance of Plant
Electrical Equipment
13%
I&C Equipment
Civil/Buildings incl. On-Site Transportation
Engineering
13%
28%
Plant Startup
Contractor's Soft Costs
Figure 6-12: Investment Cost Break Down of Gas-Based Generation Option 2
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March 2008
Final Report – Work Package IIA
6.4.2 Operational and Maintenance Costs
Gas Supply Costs Estimation
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
Fuel Supply Costs
(via LNG conversion)
Item
Fuel Supply Costs
(via LNG conversion)
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
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
Table 6-13: 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.
In total the annual fixed OPEX amount to 2.6 Mio EUR/a.
.
#
Item
1
Personnel Costs
2
Insurance, Fees and Others
1,864
Total Annual Fixed OPEX:
2,614
Costs in T EUR/a
750
Table 6-14: Estimate of Annual Fixed OPEX
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Final Report – Work Package IIA
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 2.0 EUR/MWh.
6.4.3 Dynamic Unit Cost Assessment for Option 2
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 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. 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.
In the selected 85% load case the DUC of the gas-based local generation option 2 amounts to
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 6-33
LI 260442
50%
58.3
56.3
1.9
3.3%
40%
46.0
45.4
0.6
1.3%
25%
30.8
30.3
0.5
1.6%
EUR/t
T EUR/a
t/a
GWh/a
Fuel Supply Costs (specific)
Fuel Supply Costs (absolute)
Fuel Input
Net Generation
DUC - Power Generation
4 Dynamic Unit Cost
Capital
OPEX
Net Generation
EUR/MWh
Partial Load
T EUR
T EUR
GWh
T EUR/a
Variable OPEX
3 Present Value
T EUR/a
Fixed OPEX
Year >>
T EUR/a
kJ/kWh
d/a
%/a
%/a
95 4
43.7
85%
41.9
112 3
0
0
0
0
0
0
22,365
n-2
70%
7,471
47.5
78 6
70%
0
0
0
0
0
0
14,910
n-1
50%
8,122
1GT+1ST 1GT+1ST
100%
86,272
389,482
10,891
0
0
0
0
0
0
37,275
n-3
85%
7,141
100%
6,930
18
3%
92.1%
Investment Cost
Item
2 Cash Flow
Net Heat Rate
Planned Outage
Forced Outage
Max Availability
1GT+1ST
1GT+1ST
55.8
56 1
50%
204
25,279
123,693
834
26,947
2,614
0
1
40%
12,564
1GT
79.1
44 9
40%
198
24,455
123,693
834
26,123
2,614
0
2
25%
15,101
1GT
3
113.7
28 1
25%
191
23,630
123,693
834
25,298
2,614
0
191
23,630
123,693
834
25,298
2,614
0
4
191
23,630
123,693
834
25,298
2,614
0
5
* other than Fuel Costs
10
201
24,867
123,693
834
26,535
2,614
0
2,614
2.0
Regas LNG
48,150
74,550
6.5%
30
3
221
27,341
123,693
834
29,009
2,614
0
20
238
29,490
123,693
834
31,158
2,614
0
30
Operation at 85% Load
kJ/kg
--
T EUR/a
EUR/MWh
70%
78.3
76.2
2.1
2.7%
Fixed OPEX
Variable OPEX*
Fuel Type
Net Calorific Value
85%
96.8
94.6
2.2
2.3%
T EUR
%
a
a
MW
MW
MW
%
--
CCGT 1+1
114.6
100%
114.6
112.3
2.4
2.1%
Total Investment
Discount Rate
Lifetime
Construction Period
-MW
Local Generation Option 2
Plant Type
Set Size (nominal)
Partial Load
Set Capacity (gross)
Set Capacity (net)
Auxiliary Power
Self Consumption
Turbines in Operation
p
1.2 Economics
General Information
1.1 Technical
1
MALTA RESOURCES AUTHORITY
Energy Interconnection Europe - Malta
March 2008
Final Report – Work Package IIA
Table 6-15: Dynamic Unit Cost of the Gas-Based Option 2
Page 6-34
MALTA RESOURCES AUTHORITY
Energy Interconnection Europe - Malta
March 2008
Final Report – Work Package IIA
Dynamic Unit Cost EUR/MWh
140
120
100
80
60
40
20
0
20.0
40.0
60.0
80.0
100.0
120.0
Plant's Operation - Load (Net) in MW
140
1,400
120
1,200
100
1,000
80
800
60
600
40
400
20
200
0
10%
Plant's Net Generation in GWh/a
Dynamic Unit Cost EUR/MWh
-
20%
30%
40%
50%
60%
70%
80%
90% 100%
Plant's Operation as Percentage of Load
Figure 6-13: Dynamic Unit Cost over Plant’s Load –Gas-Based Option 2
LI 260442
Page 6-35
MALTA RESOURCES AUTHORITY
Energy Interconnection Europe - Malta
March 2008
Final Report – Work Package IIA
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 feedwater 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:
x
x
x
General Electrics (GE) Power Systems,
Alstom
Siemens.
The gas turbines are 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 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).
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. Both
HRSG produce in total 41.2 kg/s high pressure steam with 87.1 bar and 493 °C and an intermediate 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 6-36
MALTA RESOURCES AUTHORITY
Energy Interconnection Europe - Malta
March 2008
Final Report – Work Package IIA
Plant Characteristics
Unit
Plant Type
Set Size (nominal)
Value
CCGT 2+1
MW
Partial Load
162.9
100%
85%
70%
50%
30%
20%
Set Capacity (gross)
MW
162.9
139.1
111.5
81.3
47.7
33.8
Set Capacity (net)
MW
159.6
136.0
108.7
79.2
45.9
33.4
Auxiliary Power
MW
3.2
3.1
2.9
2.1
1.8
0.4
%
2.0%
2.2%
2.6%
2.5%
3.8%
1.2%
2GT+1ST
2GT+1ST
2GT+1ST
1GT+1ST
1GT+1ST
1GT
Partial Load
100%
85%
70%
50%
30%
20%
kJ/kWh
7,377
7,537
7,897
7,436
8,422
12,874
Planned Outage
d/a
30
Forced Outage
%/a
3%
Max Availability
%/a
88.8%
Self Consumption
Turbines in Operation
Net Heat Rate
Table 6-16: Technical Data – Gas-Based Generation Option 3
Maltese local conditions and provided fuel specifications have been considered for the evaluation 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:
x
x
The plant’s self consumption (auxiliary power) drops from 3.2 MW to 0.4 MW in absolute
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 availability of the plant of some 88.8%.
LI 260442
Page 6-37
MALTA RESOURCES AUTHORITY
Energy Interconnection Europe - Malta
March 2008
Final Report – Work Package IIA
The net and gross heat rates of the gas based supply option 3 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 6-15 and 6-16. 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:
x
x
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.
The plants’ net heat rate decreases from 7,522 kJ/kWh during summer to 7,357 kJ/kWh
during winter. This is equal to a net efficiency increase from 47.9% (summer) to 48.9%
(winter).
LI 260442
Page 6-38
LI 260442
0
2,000
4,000
6,000
8,000
10,000
12,000
14,000
16,000
18,000
0
20,000
40,000
60,000
100,000
120,000
140,000
160,000
180,000
Energy Interconnection Europe - Malta
Load (kW)
80,000
2+1 gross HR
2+1 net HR
1+1 gross HR
1+1 net HR
1+0 gross HR
1+0 net HR
Heat Rates (kJ/kWh) of Supply Option 3 - 2+1 ST R NG fired
MALTA RESOURCES AUTHORITY
March 2008
Final Report – Work Package IIA
Figure 6-14:Gross and Net Heat Rates – Gas-Based Generation Option 3
Page 6-39
Heat Rate (kJ/kWh)
165
2.323 p
116 T
187.4 M
LTE
2.323 p
125 T
1p
36 T
632.2 m
3.215 M
190.6 M
165
IPB
2.06 M
20 T
197
256
10.77 p 10.77 p
178 T
183 T
190.6 M 40.41 M
IPE2
LNG 11.06 m
LHV= 147890 kWth
16.21 p
430 T
HPE2
15.48 p
1171 T
256
279
95.26 p
229 T
147.7 M
1X ALS GT8C2
HPE3
282
318
10.58 p 93.28 p
229 T 299 T
37.18 M 147.7 M
IPS1
320
1.04 p
531 T
1286.5 M
2 X GT
HPB1
2.06 M
87.1 p
493 T
148.3 M
462
10.4 p 93.28 p
261 T 306 T
37.18 M 146.3 M
IPS2
47392 kW
643.3 m
CCGT 2+1 configuration (refurbishment steam power plant), NG fired
100% load at summer conditions
462
529
FW
2.279 m^3/kg
814.3 m^3/s
529 T
1286.5 M
47 T
0.05 M
90.14 p
510 T
146.3 M
HPS3
37.18 M
0.1042 p
47 T
185.4 M
49897 kW
72.86 %N2
13.76 %O2
3.124 %CO2
9.381 %H2O
0.8773 %Ar
Net Power 141552 kW
LHV Heat Rate 7522 kJ/kWh
Figure 6-15: Heat and Mass Balance – Gas-Based Generation Option 3 (Summer Conditions)
p[bar], T[C], M[t/h], Steam Properties: IAPWS-IF97
316 08-21-2007 13:50:28 file=T:\26\0400\260442_malta\06_project_results\GTPro\Case 3 (2+1) refurbishment 60MW ST\CCGT 2+1 REFURBISHMENT ST NG FIRED 100% load at summer con
1.159 m^3/kg
414.1 m^3/s
126 T
1286.5 M
116 T
47 T
187.4 M
1.01 p
36 T
70 %RH
632.2 m
GT MASTER 17.0.1 LI - W. Eisenhart
90.14 p 510 T
LI 260442
Final Report – Work Package IIA
Energy Interconnection Europe - Malta
MALTA RESOURCES AUTHORITY
Colours:
Abbreviation:
- high pressure steam
red
light blue - intermediate pressure steam
p - pressure in bar
- gas, air and exhaust gas flow
violet
dark blue - feed water and water injection
to gas turbine
M - mass flow in kg / s
T - temperature in °C
9.8 p 259 T
Page 6-40
March 2008
168
2.323 p
125 T
4.075 M
195.1 M
168
IPB
20 T
200
260
11.1 p 11.1 p
181 T
184 T
195.1 M 45.02 M
IPE2
LNG 12.32 m
LHV= 164714 kWth
17.75 p
411 T
HPE2
16.95 p
1178 T
260
282
95.24 p
233 T
149.6 M
1X ALS GT8C2
HPE3
285
319
10.88 p 93.2 p
229 T 301 T
40.97 M149.6 M
IPS1
HPB1
321
2 X GT
1.04 p
514 T
1414.4 M
87 p
492 T
148.2 M
453
10.67 p 93.2 p
260 T 306 T
40.97 M148.2 M
IPS2
55470 kW
707.2 m
CCGT 2+1 configuration (refurbishment steam power plant), NG fired
100% load at winter conditions
453
512
FW
2.196 m^3/kg
862.8 m^3/s
512 T
1414.4 M
34 T
0.0511 M
90.05 p
495 T
148.2 M
HPS3
40.97 M
0.0543 p
34 T
189.1 M
53513 kW
75.42 %N2
14.3 %O2
3.205 %CO2
6.17 %H2O
0.9081 %Ar
Net Power 161209 kW
LHV Heat Rate 7357 kJ/kWh
Figure 6-16: Heat and Mass Balance – Gas-Based Generation Option 3 (Winter Conditions)
p[bar], T[C], M[t/h], Steam Properties: IAPWS-IF97
316 08-21-2007 13:51:14 file=T:\26\0400\260442_malta\06_project_results\GTPro\Case 3 (2+1) refurbishment 60MW ST\CCGT 2+1 REFURBISHMENT ST NG FIRED 100% load at winter condi
1.144 m^3/kg
449.3 m^3/s
LTE
2.323 p
114 T
191.1 M
125 T
1414.4 M
114 T
34 T
191.1 M
1p
13 T
694.9 m
GT MASTER 17.0.1 LI - W. Eisenhart
1.01 p
13 T
45 %RH
694.9 m
90.05 p 495 T
LI 260442
Final Report – Work Package IIA
Energy Interconnection Europe - Malta
MALTA RESOURCES AUTHORITY
Colours:
Abbreviation:
- high pressure steam
red
light blue - intermediate pressure steam
p - pressure in bar
- gas, air and exhaust gas flow
violet
dark blue - feed water and water injection
to gas turbine
M - mass flow in kg / s
T - temperature in °C
9.979 p 258 T
Page 6-41
March 2008
MALTA RESOURCES AUTHORITY
Energy Interconnection Europe - Malta
March 2008
Final Report – Work Package IIA
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 6-42
MALTA RESOURCES AUTHORITY
Energy Interconnection Europe - Malta
March 2008
Final Report – Work Package IIA
Figure 6-17: Potential Location of Gas-Based Generation Option 3
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.
HRSG
GT
GT
approx. 27 m
HRSG
approx. 27 m
Figure 6-18: Suggestion regarding the Formation of HRSGs and GTs
LI 260442
Page 6-43
MALTA RESOURCES AUTHORITY
Energy Interconnection Europe - Malta
March 2008
Final Report – Work Package IIA
1
2
FOR QUALITATIVE INDICATION ONLY
3
4
5
6
7
8
A
A
E
B
B
C
C
A
D
D
B
C
D
E
E
Thermoflow, Inc.
Company: Lahmeyer International GmbH
User: LI - W. Eisenhart
SHAPE, DIMENSIONS & SCALE ARE APPROXIMATE
GAS TURBINE PACKAGE
ELEVATION
A
B
C
D
E
F
G
H
I
J
Date: 11.12.07
F
GE 6561B 133
F
Drawing No:
11.4 m
3.4 m
6.5 m
1
4.4 m
11.6 m
2
-
-
3
-
-
-
4
C:\TFLOW17\MYFILES\GTMAS.GTM
5
6
7
8
PEACE/GT MASTER 17.0.2
1
2
FOR QUALITATIVE INDICATION ONLY
3
4
5
6
7
8
A
A
B
B
A
C
C
D
C
B
D
D
E
E
Thermoflow, Inc.
Company: Lahmeyer International GmbH
User: LI - W. Eisenhart
SHAPE, DIMENSIONS & SCALE ARE APPROXIMATE
GAS TURBINE PACKAGE
PLAN
A
B
C
D
E
F
G
H
I
J
Date: 11.12.07
F
GE 6561B 133
F
Drawing No:
3.4 m
21.9 m
1
2.5 m
2.6 m
2
-
3
-
4
-
5
C:\TFLOW17\MYFILES\GTMAS.GTM
6
7
8
Figure 6-19: Dimensions of one GT Package
LI 260442
Page 6-44
MALTA RESOURCES AUTHORITY
Energy Interconnection Europe - Malta
March 2008
Final Report – Work Package IIA
1
2
FOR QUALITATIVE INDICATION ONLY
3
4
5
6
7
8
A
A
B
B
C
C
F
G
D
D
H
E
E
A
C
D
E
Thermoflow, Inc.
Company: Lahmeyer International GmbH
User: LI - W. Eisenhart
HEAT RECOVERY STEAM GENERATOR
ELEVATION
A
B
C
D
E
F
G
H
I
J
Date: 11.12.07
F
F
Drawing No:
5m
-
7.1 m
1
10.9 m
2.1 m
2
22.2 m
12.1 m
3
2.7 m
-
4
-
C:\TFLOW17\MYFILES\GTMAS.GTM
5
6
7
8
PEACE/GT MASTER 17.0.2
1
2
FOR QUALITATIVE INDICATION ONLY
3
4
5
6
7
8
A
A
B
B
G
F
C
C
A
C
D
E
D
D
E
E
Thermoflow, Inc.
Company: Lahmeyer International GmbH
User: LI - W. Eisenhart
HEAT RECOVERY STEAM GENERATOR
PLAN
A
B
C
D
E
F
G
H
I
J
Date: 11.12.07
F
F
Drawing No:
5m
1
7.1 m
10.9 m
2
2.1 m
3.7 m
3
3.1 m
4
-
5
C:\TFLOW17\MYFILES\GTMAS.GTM
6
7
8
PEACE/GT MASTER 17.0.2
Figure 6-20: Dimensions of one HRSG
LI 260442
Page 6-45
MALTA RESOURCES AUTHORITY
Energy Interconnection Europe - Malta
March 2008
Final Report – Work Package IIA
6.5.3 Air Pollution Emissions
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:
x
x
x
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 56% below the current Green House Gas emissions (typical unit operation assumed)
and do not exceed the limit value for CO2 emissions.
Specific Emissions g CO2/kWh .
1,000
900
800
921
871
700
600
500
400
420
300
200
100
Business as Usual
(all STs)
Business as Usual
(DPS ST)
Supply Option
Figure 6-21: Comparison of Greenhouse Gas Emissions - Gas-Based Generation Option 3
LI 260442
Page 6-46
MALTA RESOURCES AUTHORITY
Energy Interconnection Europe - Malta
March 2008
Final Report – Work Package IIA
General Information
#
Item
3
1 Plant Name
Natural Gas Based Supply Option 3 (Refurbishment)
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
3
7 Nominal Capacity
MW
162.9
8 Max Capacity Sent-Out (Operation)
MW
159.6
9 Min Capacity Sent-Out (Operation)
MW
38.6
10 Heat Rate* Coeff A (2+1)
-
3,764
11 Heat Rate* Coeff B (2+1)
-
-7,944
12 Heat Rate* Coeff C (2+1)
-
11,566
5000
kJ / kWh
10000
0
18,027
11a Heat Rate* Coeff B (1+1)
-18,884
12a Heat Rate* Coeff C (1+1)
12,381
13 Combustion Temp Coeff A
-
-742
14 Combustion Temp Coeff B
-
1,579
15 Combustion Temp Coeff C
-
485
16 Air Rate Lambda O
Case1
20%
30%
40%
50%
60%
70%
80%
90%
100%
1400
1300
[comb. temp.]
10a Heat Rate* Coeff A (1+1)
10%
1200
1100
1000
900
800
700
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
1.0 - 1.09
Table 6-17: Specifications of D_CC3NGo (1/3)
LI 260442
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Energy Interconnection Europe - Malta
March 2008
Final Report – Work Package IIA
NOx Emissions
#
Item
3
17
Thermal Nox Coeff. A
1E-21
Fuel Nox Coeff. A
NA
18
Thermal Nox Coeff. B
7.72
Fuel Nox Coeff. B
NA
Fuel Nox Coeff. C
NA
19
Fuel NOx Emissions over load (RAW)
20 Thermal NOx Emissions over load (RAW)
mg/m³
mg/m³
mg/m³
1,200
1,200
1,200
1,000
1,000
1,000
800
800
800
600
600
600
400
400
200
2000
400
200
0
0
10% 20% 30% 40% 50% 60% 70% 80% 90% 100%
0
21 Specific NOx Emissions in g/kWh
[g/kWh]
1.20
kg Nox
RAW
2.0
1.00
350
300
0.80
1.5
0.60
1.0
0.40
0.5
0.0
20%
30%
40%
50%
60%
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Absolute NOx Emissions in tons
2.5
10%
0
70%
80%
0.20
50
0.00
0
90%
322
255
300
250
250
200
200
150
150
100
100
199
158
80.0
100.0
60.0
134
107
9
7
16
13
28
22
33
26
53
42
49
38
78
63
65
51
96
76
81
64
80
64
98
77
114
90
130
102
200.0
140.0
120.0
150.0
100.0
265
211
147
115
163
128
40.0
50.0
20.0
0.0
Fuel Specifications
22 Initial Primary Fuel
Rich gas
23 Net Calorific Value
kJ/kg
48,156
24 Required Fuel at 100% load
kg
24,985
25 Required Combustion Air
m³
9.89
% of Carbon
Natural Gas
Fuel Composition
% of Nitrogen
(Emission Relevant)
75.00%
0.00%
% of Sulphur
0.00%
% of Nox Reduc.
50.00%
% of SO2 Reduc.
0.00%
Potential Emission Reduction
26 Resulting Exhaust Gas
m³
10.34
Table 6-15: Specifications of D_CC3NGo (2/3)
LI 260442
Page 6-48
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March 2008
Final Report – Work Package IIA
CO2 and SOx Emissions
#
Item
3
27
Fuel needed at 100% load
t
24.99
28
Density of Fuel
29
CO2 emission at 100% load
30
Specific CO2 Emissions in g/kWh
kg / m³ 0.77
t
67.38
Absolute CO2 Emissions in t
[t CO2]
[g/kWh]
80
70
60
50
40
30
20
10
0
800
598
594
600
525
522
474
467
439
432
422
417
462
457
446
440
433
427
423
418
417
414
400
200
0
17.0
20%
30%
40%
50%
60%
70%
80%
90%
22.8
28.1
50.1
61.3
67.4
34.0
9.7
16
10%
31
44.6
55.6
33
49
65
100%
81
98
114
130
147
163
[MW]
Specific SOx Emissions in g/kWh
Absolute SOx Emissions in tons
n/a
n/a
Exhaust Gas development in m³ due to Gross Performance
m³ Exhaust Gas
32
300,000
250,000
250,000
200,000
200,000
150,000
150,000
100,000
100,000
50,000
50,000
171,072
135,795
65,209
51,499
87,460
69,655
107,851
86,115
192,117
152,889
213,135
169,723
234,914
186,792
258,244
204,592
130,165
103,402
37,316
29,123
0
10%
0
20%
0
30%
0
40%
0
50%
0
60%
0
70%
0
80%
0
90%
0
100%
0
Table 6-15: Specifications of D_CC3NGo (3/3)
LI 260442
Page 6-49
MALTA RESOURCES AUTHORITY
Energy Interconnection Europe - Malta
March 2008
Final Report – Work Package IIA
6.6
Economic Description of Gas-Based Generation Option 3 (2+1 ST R)
6.6.1 Investment Costs of Major Components
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).
The investment cost in total and for each individual major component is provided in Table 6-18.
In total, the projects investment cost amounts to 88.1 Mio Euro (10% contingencies included).
Investment Costs
in T EUR
#
Item
1
Gas Turbine Package incl. Generator
32,792
2
Heat Recovery Boiler
17,027
3
Balance of Plant
6,576
4
Electrical Equipment
7,289
5
I&C Equipment
1,430
6
Civil/Buildings incl. On-Site Transportation
8,332
7
Engineering
2,933
8
Plant Startup
9
Contractor's Soft Costs
10,926
Total:
88,063
758
Table 6-18: Investment Costs of Gas-Based Generation Option 3
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March 2008
Final Report – Work Package IIA
Year
n-2
n-1
n
Disbursement in %
60%
40%
Start Year
Table 6-19: Disbursement Schedule of Gas-Based Generation Option 3
The specific investment cost amounts to 552 EUR/kW, approximately 23% less compared to the
gas-based generation option 1, respectively 17% less compared to the gas-based generation
option 2.
Figure 6-22 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 civil
works.
8%
2%
Gas Turbine Package incl. Generator and Air
inlet cooling/heating if applicable
9%
3%
Heat Recovery Boiler
1%
7%
Balance of Plant
12%
Electrical Equipment
I&C Equipment
19%
Civil/Buildings incl. On-Site Transportation
Engineering
Plant Startup
37%
Contractor's Soft Costs
Figure 6-22: Investment Cost Break Down of Gas-Based Generation Option 3
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Page 6-51
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March 2008
Final Report – Work Package IIA
6.6.2 Operational and Maintenance Costs
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
Fuel Supply Costs
(via LNG conversion)
Item
Fuel Supply Costs
(via LNG conversion)
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
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
Table 6-20: 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 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
Personnel Costs
2
Insurance, Fees and Others
2,202
Total Annual Fixed OPEX:
2,502
Costs in T EUR/a
300
Table 6-21: Estimate of Annual Fixed OPEX
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Final Report – Work Package IIA
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 4.0 EUR/MWh.
6.6.3 Dynamic Unit Cost Assessment for Option 3
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 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. 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.
In the selected 85% load case the DUC of the gas-based local generation option 3 amounts to
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 6-53
LI 260442
50%
81.3
79.2
2.1
2.5%
30%
47.7
45.9
1.8
3.8%
20%
33.8
33.4
0.4
1.2%
EUR/t
T EUR/a
t/a
GWh/a
Fuel Supply Costs (specific)
Fuel Supply Costs (absolute)
Fuel Input
Net Generation (minus exisitng)
DUC - Power Generation
4 Dynamic Unit Cost
Capital
OPEX
Net Generation (minus exisitng)
EUR/MWh
Partial Load
T EUR
T EUR
GWh
T EUR/a
Variable OPEX
3 Present Value
T EUR/a
Fixed OPEX
Year >>
T EUR/a
kJ/kWh
d/a
%/a
%/a
135 7
52.2
85%
51.4
159 6
0
0
0
0
0
0
52,838
n-2
70%
7,897
58.2
111 8
70%
0
0
0
0
0
0
35,225
n-1
50%
7,436
2GT+1ST 1GT+1ST
100%
97,445
274,065
7,116
0
0
0
0
0
0
0
n-3
85%
7,537
100%
7,377
30
3%
88.8%
Investment Cost
Item
2 Cash Flow
Net Heat Rate
Planned Outage
Forced Outage
Max Availability
2GT+1ST
2GT+1ST
64.9
79 8
50%
204
24,212
118,467
757
27,239
2,502
0
1
30%
8,422
1GT+1ST
90.0
47 9
30%
198
23,422
118,467
757
26,449
2,502
0
2
20%
12,874
1GT
3
131.1
31 9
20%
191
22,632
118,467
757
25,660
2,502
0
191
22,632
118,467
757
25,660
2,502
0
4
191
22,632
118,467
757
25,660
2,502
0
5
* other than Fuel Costs
201
23,817
118,467
757
26,844
2,502
0
10
2,502
4.0
Regas LNG
48,150
88,063
6.5%
15
2
208
24,606
118,467
757
27,634
2,502
0
12
216
25,593
118,467
757
28,621
2,502
0
15
Operation at 85% Load
kJ/kg
--
T EUR/a
EUR/MWh
70%
111.5
108.7
2.9
2.6%
Fixed OPEX
Variable OPEX*
Fuel Type
Net Calorific Value
85%
139.1
136.0
3.1
2.2%
T EUR
%
a
a
MW
MW
MW
%
--
CCGT 2+1
162.9
100%
162.9
159.6
3.2
2.0%
Total Investment
Discount Rate
Lifetime
Construction Period
-MW
Local Generation Option 3 (CCGT 2+1 ST R)
Plant Type
Set Size (nominal)
Partial Load
Set Capacity (gross)
Set Capacity (net)
Auxiliary Power
Self Consumption
Turbines in Operation
p
1.2 Economics
General Information
1.1 Technical
1
MALTA RESOURCES AUTHORITY
Energy Interconnection Europe - Malta
March 2008
Final Report – Work Package IIA
Table 6-22: Dynamic Unit Cost of the Gas-Based Option 3
Page 6-54
MALTA RESOURCES AUTHORITY
Energy Interconnection Europe - Malta
March 2008
Final Report – Work Package IIA
Dynamic Unit Cost EUR/MWh
140
120
100
80
60
40
20
0
20.0
40.0
60.0
80.0
100.0
120.0
140.0
160.0
Plant's Operation - Load (Net) in MW
140
1,400
120
1,200
100
1,000
80
800
60
600
40
400
20
200
0
10%
Plant's Net Generation in GWh/a
Dynamic Unit Cost EUR/MWh
-
20%
30%
40%
50%
60%
70%
80%
90% 100%
Plant's Operation as Percentage of Load
Figure 6-23: Dynamic Unit Cost over Plant’s Load – Gas-Based Option 3
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March 2008
Final Report – Work Package IIA
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)”.
The gas turbines are designed with a dual fuel combustion system using LNG (gaseous) as
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 Characteristics
Unit
Plant Type
Set Size (nominal)
Value
CCGT 2+1
MW
Partial Load
117.8
100%
85%
75%
50%
30%
20%
Set Capacity (gross)
MW
117.8
99.6
87.4
58.6
36.4
23.5
Set Capacity (net)
MW
115.3
97.2
85.1
56.9
34.9
23.2
Auxiliary Power
MW
2.5
2.4
2.3
1.7
1.5
0.3
%
2.1%
2.4%
2.6%
2.8%
4.1%
1.2%
2GT+1ST
2GT+1ST
2GT+1ST
1GT+1ST
1GT+1ST
1GT
Partial Load
100%
85%
75%
50%
30%
20%
kJ/kWh
7,513
7,599
7,847
7,606
8,551
12,911
Planned Outage
d/a
20
Forced Outage
%/a
3%
Max Availability
%/a
91.5%
Self Consumption
Turbines in Operation
Net Heat Rate
Table 6-23: Technical Data – Gas-Based Generation Option 4
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March 2008
Final Report – Work Package IIA
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 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
operational characteristics, which can be summarized as follows:
x
x
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 2.1% (2 GT + 1 ST operation) to 4.1% (1 GT + 1 ST operation) and decreases then to some 1.2% (1 GT operation);
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%.
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 4 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 6-25 and 6-26. 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:
x
x
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);
The plants’ net heat rate decreases from 7,650 kJ/kWh during summer to 7,484 kJ/kWh
during winter. This is equal to a net efficiency increase from 47.1% (summer) to 48.1%
(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 6-57
LI 260442
0
2,000
4,000
6,000
8,000
10,000
12,000
14,000
16,000
0
20,000
40,000
80,000
Load (kW)
60,000
100,000
120,000
2+1 gross HR
2+1 net HR
1+1 gross HR
1+1 net HR
1+0 gross HR
1+0 net HR
Heat Rates (kJ/kWh) of Supply Option 4 - 2+1 GT R NG fired
140,000
MALTA RESOURCES AUTHORITY
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March 2008
Final Report – Work Package IIA
Figure 6-24: Gross and Net Heat Rates – Gas-Based Generation Option 4
Page 6-58
Heat Rate (kJ/kWh)
161
2.323 p
116 T
139.7 M
LTE
2.323 p
125 T
2.467 M
142.1 M
161
IPB
2.97 M
20 T
190
239
9.149 p 9.149 p
171 T
176 T
142.1 M 23.42 M
IPE2
LNG 8.102 m
LHV= 108352 kWth
10.76 p
368 T
HPE2
10.33 p
1099 T
268
74.04 p
230 T
115.5 M
239
1X GE 6541B
HPE3
271
301
8.981 p 72.73 p
228 T 282 T
20.96 M 115.5 M
IPS1
HPB1
HPS0
1.51 M
67.95 p
518 T
117.3 M
1.04 p
558 T
907.8 M
2 X GT
302
473
484
8.843 p 72.73 p 72.05 p
261 T 288 T
309 T
20.96 M 114.4 M 114.4 M
IPS2
32757 kW
453.9 m
CCGT 2+1 configuration (refurbishment of single-cycle plant), NG fired
100% load at summer conditions
484
484
556
FW
2.358 m^3/kg
594.5 m^3/s
556 T
907.8 M
1.46 M
46 T
0.0372 M
70.32 p
535 T
115.8 M
HPS3
20.96 M
0.1035 p
46 T
138.2 M
38875 kW
72.78 %N2
13.52 %O2
3.241 %CO2
9.581 %H2O
0.8764 %Ar
Net Power 101978 kW
LHV Heat Rate 7650 kJ/kWh
Figure 6-25: Heat and Mass Balance – Gas-Based Generation Option 4 (Summer Conditions)
p[bar], T[C], M[t/h], Steam Properties: IAPWS-IF97
316 08-29-2007 12:38:06 file=T:\26\0400\260442_malta\06_project_results\GTPro\Case 4 (2+1) refurbishment 2x37MW GT\NG fired\CCGT 2+1 REFURBISHMENT NG FIRED 100% load at summ
1.139 m^3/kg
287.3 m^3/s
119 T
907.8 M
116 T
46 T
139.7 M
1p
36 T
445.8 m
GT MASTER 17.0.1 LI - W. Eisenhart
1.01 p
36 T
70 %RH
445.8 m
70.32 p 535 T
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Colours:
Abbreviation:
- high pressure steam
red
light blue - intermediate pressure steam
p - pressure in bar
MALTA RESOURCES AUTHORITY
- gas, air and exhaust gas flow
violet
dark blue - feed water and water injection
to gas turbine
M - mass flow in kg / s
T - temperature in °C
8.331 p 259 T
Page 6-59
March 2008
164
2.323 p
114 T
144.3 M
LTE
2.323 p
125 T
1p
13 T
496.4 m
3.06 M
147.3 M
164
IPB
20 T
193
243
9.553 p 9.553 p
174 T
178 T
147.3 M 26.5 M
IPE2
LNG 9.077 m
LHV= 121387 kWth
11.93 p
354 T
HPE2
11.45 p
1105 T
272
75.4 p
233 T
120.6 M
243
1X GE 6541B
HPE3
275
303
9.355 p 73.98 p
229 T 285 T
23.43 M 120.6 M
IPS1
HPB1
2 X GT
HPS0
69.06 p
517 T
119.4 M
1.04 p
540 T
1010.9 M
305
466
476
9.192 p 73.98 p 73.26 p
261 T 290 T
309 T
23.43 M 119.4 M 119.4 M
IPS2
38504 kW
505.4 m
CCGT 2+1 configuration (refurbishment of single-cycle power plant), NG fired
100% load at winter conditions
476
476
538
FW
2.268 m^3/kg
636.8 m^3/s
538 T
1010.9 M
34 T
0.0384 M
71.48 p
519 T
119.4 M
HPS3
23.43 M
0.0543 p
34 T
142.7 M
42275 kW
75.35 %N2
14.1 %O2
3.303 %CO2
6.34 %H2O
0.9073 %Ar
Net Power 116781 kW
LHV Heat Rate 7484 kJ/kWh
Figure 6-26: Heat and Mass Balance – Gas-Based Generation Option 4 (Winter Conditions)
p[bar], T[C], M[t/h], Steam Properties: IAPWS-IF97
316 08-29-2007 12:38:53 file=T:\26\0400\260442_malta\06_project_results\GTPro\Case 4 (2+1) refurbishment 2x37MW GT\NG fired\CCGT 2+1 REFURBISHMENT NG FIRED 100% load at winte
1.124 m^3/kg
315.7 m^3/s
118 T
1010.9 M
114 T
34 T
144.3 M
1.01 p
13 T
45 %RH
496.4 m
GT MASTER 17.0.1 LI - W. Eisenhart
71.48 p 519 T
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Final Report – Work Package IIA
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Colours:
Abbreviation:
- high pressure steam
red
light blue - intermediate pressure steam
p - pressure in bar
MALTA RESOURCES AUTHORITY
- gas, air and exhaust gas flow
violet
dark blue - feed water and water injection
to gas turbine
M - mass flow in kg / s
T - temperature in °C
8.604 p 259 T
Page 6-60
March 2008
MALTA RESOURCES AUTHORITY
Energy Interconnection Europe - Malta
March 2008
Final Report – Work Package IIA
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.
Figure 6-27: Potential Location of Gas-Based Generation Option 4
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March 2008
Final Report – Work Package IIA
6.7.3 Air Pollution Emissions
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.
In the following tables the environmental impact due to potential air pollution emissions is
presented. The air pollution emissions of the investigated supply option:
x
x
x
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 53% below the current Green House Gas emissions (typical unit operation assumed)
and do not exceed the limit value for CO2 emissions.
Specific Emissions g CO2/kWh .
1,000
900
800
921
871
700
600
500
400
430
300
200
100
Business as Usual
(all STs)
Business as Usual
(DPS ST)
Supply Option
Figure 6-28: Comparison of Greenhouse Gas Emissions - Gas-Based Generation Option 4
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March 2008
Final Report – Work Package IIA
General Information
#
Item
4
1 Plant Name
Natural Gas Based Supply Option 4 (Refurbishment)
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
4
7 Nominal Capacity
MW
117.8
8 Max Capacity Sent-Out (Operation)
MW
115.3
9 Min Capacity Sent-Out (Operation)
MW
34.9
10 Heat Rate* Coeff A (2+1)
-
6,725
11 Heat Rate* Coeff B (2+1)
-
-12,970
12 Heat Rate* Coeff C (2+1)
-
13,748
5000
kJ / kWh
10000
0
28,344
11a Heat Rate* Coeff B (1+1)
-27,591
12a Heat Rate* Coeff C (1+1)
14,312
13 Combustion Temp Coeff A
-
-742
14 Combustion Temp Coeff B
-
1,579
15 Combustion Temp Coeff C
-
485
16 Air Rate Lambda O
Case1
20%
30%
40%
50%
60%
70%
80%
90%
100%
1400
1300
[comb. temp.]
10a Heat Rate* Coeff A (1+1)
10%
1200
1100
1000
900
800
700
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
1.0 - 1.09
Table 6-24: Specifications of D_CC4NGo (1/3)
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Final Report – Work Package IIA
NOx Emissions
#
Item
4
17
Thermal Nox Coeff. A
1E-21
Fuel Nox Coeff. A
NA
18
Thermal Nox Coeff. B
7.72
Fuel Nox Coeff. B
NA
Fuel Nox Coeff. C
NA
19
Fuel NOx Emissions over load (RAW)
20 Thermal NOx Emissions over load (RAW)
mg/m³
mg/m³
mg/m³
1,200
1,200
1,200
1,000
1,000
1,000
800
800
800
600
600
600
400
400
200
2000
400
200
0
0
0
10% 20% 30% 40% 50% 60% 70% 80% 90% 100%
0
21 Specific NOx Emissions in g/kWh
[g/kWh]
1.20
1.00
0.90
1.00
0.80
0.70
0.80
0.60
0.60
0.50
0.40
0.40
0.30
2.0
1.5
1.0
0.20
0.20
0.10
0.00
0.5
0.0
20%
30%
40%
50%
60%
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Absolute NOx Emissions in tons
2.5
10%
0
0
70%
80%
90%
kg Nox
RAW
237
250
300
255
193
211
250
200
200
150
150
100
100
50
50
0
80.0
99
107
8
7
12
13
22
22
24
26
40
42
35
38
47
51
71
76
59
64
60.0
60
64
71
77
120.0
100.0
145
158
57
63
140.0
40.0
20.0
82
90
94
102
106
115
118
128
0.0
Fuel Specifications
22 Initial Primary Fuel
Rich gas
23 Net Calorific Value
kJ/kg
48,156
24 Required Fuel at 100% load
kg
18,354
25 Required Combustion Air
m³
9.89
% of Carbon
Natural Gas
Fuel Composition
% of Nitrogen
(Emission Relevant)
75.00%
0.00%
% of Sulphur
0.00%
% of Nox Reduc.
50.00%
% of SO2 Reduc.
0.00%
Potential Emission Reduction
26 Resulting Exhaust Gas
m³
10.34
Table 6-20: Specifications of D_CC4NGo (2/3)
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Final Report – Work Package IIA
CO2 and SOx Emissions
#
Item
4
27
Fuel needed at 100% load
t
18.35
28
Density of Fuel
29
CO2 emission at 100% load
30
Specific CO2 Emissions in g/kWh
kg / m³ 0.77
t
49.50
Absolute CO2 Emissions in t
[t CO2]
[g/kWh]
60
800
663
594
600
49.5
50
556
525
481
474
437
439
426
422
470
462
40
446
430
433
421
423
420
417
33.2
30
400
20
200
10
17.0
20.6
44.7
25.1
7.8
0
0
12
10%
31
13.1
36.8
40.5
20%
30%
40%
50%
60%
70%
80%
90%
24
35
47
100%
59
71
82
94
106
118
[MW]
Specific SOx Emissions in g/kWh
Absolute SOx Emissions in tons
n/a
n/a
Exhaust Gas development in m³ due to Gross Performance
m³ Exhaust Gas
32
189,703
200,000
250,000
171,171
200,000
150,000
150,000
100,000
100,000
50,000
50,000
29,927
29,123
50,201
51,499
65,123
69,655
78,992
86,115
96,109
103,402
127,232
135,795
140,955
152,889
155,261
169,723
186,792
80%
0
90%
0
204,592
0
10%
0
20%
0
30%
0
40%
0
50%
0
60%
0
70%
0
100%
0
Table 6-20: Specifications of D_CC4NGo (3/3)
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March 2008
Final Report – Work Package IIA
6.8
Economic Description of Gas-Based Generation Option 4 (2+1 GT R)
6.8.1 Investment Costs of Major Components
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 respectively Table 1.13 Specifications of D_GT2e).
The investment cost in total and for each individual major component is provided in Table 6-25.
In total, the projects investment cost amounts to 54.4 Mio Euro (10% contingencies included).
Investment Costs
in T EUR
#
Item
1
Steam Turbine Package incl. Generator
2
Heat Recovery Boiler
3
Cooling Facility/Cooling System
4
Balance of Plant
5,893
5
Electrical Equipment
4,932
6
I&C Equipment
1,332
7
Civil/Buildings incl. On-Site Transportation
6,533
8
Engineering
2,510
9
Plant Startup
10
Contractor's Soft Costs
9,805
13,317
729
615
Total:
8,752
54,441
Table 6-25: Investment Costs of Gas-Based Generation Option 4
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March 2008
Final Report – Work Package IIA
Year
n-2
n-1
n
Disbursement in %
60%
40%
Start Year
Table 6-26: Disbursement Schedule of Gas-Based Generation Option 4
The specific investment cost amounts to 472 EUR/kW, approximately 34% less compared to the
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.
Figure 6-29 illustrates the investment break down. The dominating cost proportions are (i) the
heat recovery boiler; (ii) the steam turbine package; (iii) soft costs of the contractor and (iv) the
civil works.
12%
5%
Steam Turbine Package incl. Generator
1%
2%
Heat Recovery Boiler
Cooling Facility/Cooling System
9%
16%
Balance of Plant
Electrical Equipment
11%
I&C Equipment
Civil/Buildings incl. On-Site Transportation
1%
18%
Engineering
Plant Startup
24%
Contractor's Soft Costs
Figure 6-29: Investment Cost Break Down of Gas-Based Generation Option 4
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Page 6-68