2.1
Need for the Project
As stated in EPD’s Progress Report on Improving the Air Quality in Hong Kong released
in November 2005 ([1]) , the HKSARG and the Guangdong
Provincial Government have reached a consensus to reduce, on a best endeavour
basis, the emission of four major air pollutants, namely sulphur dioxide (SO2), nitrogen oxides (NOx), respirable suspended
particulates (RSP) and volatile organic compounds (VOC).
The Project is proposed by CAPCO in response to the
HKSARG’s emissions reduction initiative with regard to SO2 and NOx
emissions. Some further reduction in particulate emissions is
also anticipated as a result of SO2 emission control in addition to existing high
efficiency ESP.
2.2
Scenario With or Without Project
The Project is
proposed and accepted in the 2005 Financial Plan as an additional measure to
ongoing efforts in improving the environmental performance of CAPCO generation
plant. The Project is expected to
deliver significant emissions reduction thus contributing to emissions
reduction initiative undertaken by the HKSARG and the Pearl River Delta region. Without the Project, CAPCO’s efforts in
contributing to emissions reduction initiatives will undoubtedly be undermined.
2.3
Consideration of Different Technologies
and Emission Control Options
2.3.1
Introduction
There are many
different technologies available for the control of NOx and SO2. The choice of control technologies and
their associated equipment would result in different installation, process
material supply and the management of any wastes and/or saleable
by-products.
The following
sub-sections provide a review of available emission control technology options
for the Project, discuss their technological maturity and environmental
performance in order to explain the rationale for the base technology
selection, LS-FGD and SCR.
2.3.2
Review
of the available NOx emission control technologies
Overview of NOx Emission Control
Technologies
The control of
NOx emissions from large new thermal power stations has become an
important consideration in the design and operation of such plant. A number of control technologies
have been developed to meet the emerging emission control requirements. Retrofit NOx control for
operating plant varies from combustion control technologies to post-combustion
flue gas denitrification (de-NOx).
CPB has
already implemented combustion control technologies to control its NOx emissions
by retrofitting with low NOx burners (LNBs). This has helped reduce the NOx
production from the boilers. The
enhancement technology options available for consideration include:
·
Advanced
Low NOx Burners (ALNBs)
·
Low
NOx Burners (LNBs) or ALNBs with Over Fire Air
·
Gas
Reburn or Amine Enhanced Fuel Lean Gas Reburn (AEFLGR)
·
Selective
Non-catalytic Reduction (SNCR)
·
Selective
Catalytic Reduction (SCR)
Advanced
Low NOx Burners (ALNBs)
CPB is equipped
with LNBs of an early design, an incremental improvements could be made by
installing ALNBs either as part of the normal routine maintenance regime of the
station or as part of a specific NOx reduction strategy. This technology can be used in combination
with any of the other available NOx reduction technologies.
LNBs
/ ALNBs with Over Fire Air
NOx
emissions could be further reduced by adding either an Over Fire Air (OFA) or
“reburning” technology to the existing LNBs or ALNBs. Over fire air and boosted over fire air
are in-furnace NOx control techniques that stage combustion in the
entire furnace. Typically a portion
of the total combustion air is diverted from the main wind box and is injected
into the furnace at a level above the top burner row. The intent is to operate
the burner zone at a lower stoichiometry than the upper furnace. Staging combustion in the furnace
reduces NOx in two ways.
Firstly, a reducing zone is formed which is not conducive to fuel NOx
conversion. Secondly, furnace staging
delays combustion which results in a longer flame and causes heat absorption to
occur over a large area of the furnace.
The temperature of the air/fuel/combustion gas mixture is thus reduced,
lowering thermal NOx production. OFA systems provide up to 30% NOx
reduction at slightly increased auxiliary power consumption and increased
carbon content in ash. Higher
carbon in ash content can be managed.
Gas
Reburn or Amine Enhanced Fuel Lean Gas Reburn (AEFLGR)
Reburning is sometimes considered a potentially
effective method of reducing NOx emissions levels using secondary
natural gas through the inherent staging effect of the reducing and over fire
air zones. The reburning process
divides the furnace into three combustion zones. The main supply of the fuel is burnt
under stoichiometry conditions in the lower furnace. Above the main burners a second fuel
such as natural gas is injected often using high pressure recirculated flue gas
as a carrier to ensure adequate mixing.
The balance of the combustion air is introduced above both combustion
zones in order to complete the combustion process within the furnace. This remaining air is introduced through
openings in the upper furnace wall to the manner typical of over fire air. NOx reduction typically is
35-45% from an uncontrolled base.
The Gas Reburn system requires additional usage of a supplementary fuel
such as natural gas.
AEFLGR is a
combination of natural gas reburn and SNCR with urea as the reagent. The method
features minimal use of natural gas at approximately 7% of the heat input. The effectiveness may approach 50%, but
the technology may not be sufficiently tested in large coal-fired plants.
Selective
Non-Catalytic Reduction (SNCR)
NOx
emissions in the flue gas are converted into elemental nitrogen and water by
injecting a nitrogen-based chemical reagent, most commonly urea (NH2CONH2)
or ammonia (NH3; either anhydrous or aqueous). The chemical reactions, in a simplified
form, are as follows.
|
2NO + NH2CONH2
+ 1/2 O2 à |
2N2 + CO2 +
2H2O |
|
NOx + NH3 +
O2 + H2O + (H2) à |
N2 + H2O |
Because the
highest NOx reduction is achieved at temperatures between 870 and
1,200°C, the reagent is introduced at the top and back-pass of the boiler. Multiple
injection locations may be required, especially in case of cycling units;
different injection locations are used as the unit operates at a reduced load.
SNCR is a
proven technology applied in some installations worldwide. This technology has generally been
applied to units of around 350MW and less, however application has extended to
larger generating units of the size similar to CPB. The typical removal efficiency is
30-40%. In the case of SNCR the
ammonia slip may be a more important issue than for SCR but can be managed.
Selective
Catalytic Reduction (SCR)
SCR is similar to SNCR in that it uses
ammonia injection in the flue gas to convert NOx emissions to
elemental nitrogen and water. The key
difference between SCR and SNCR is the presence in SCR systems of a catalyst,
which accelerates the chemical reactions.
The catalyst is needed because SCR systems operate at much lower
temperatures when compared with SNCR system. Typical temperatures for SCR are 340 to
380°C, compared with 870 to 1,200°C for SNCR. Different types of SCR catalyst are
available in the market. The
catalyst active surface is typically metal, ceramic or fibre reinforced. The catalysts are usually made of heavy
metal oxides, consisting of the base material TiO2 and active
components vanadium, tungsten, molybdenum, copper and chromium. In most cases, V2O5
is used with a small amount of WO3 and SiO2. As these catalysts are not chemically
modified in the process, their service life is generally very long. Rejuvenation of catalysts is only
required after 4 to 6 years of use.
The rejuvenation process usually involves the removal of solid particles
on the catalysts by vacuum cleaner, washing of the catalysts in acid baths and
drying of the washed catalysts. The
solid particles removed generally consist of ash particles and therefore can be
disposed of in a similar manner.
The wash water generated will be separately treated to the required
standards by neutralisation before discharge and is not expected to affect the
existing wastewater effluents of CPB.
Relevant requirements under the Water
Pollution Control Ordinance (WPCO)
and Waste Disposal Ordinance (WDO) should be met for the treatment and
disposal of waste and wastewater arising from the catalyst rejuvenation
process.
The SCR process is a post-combustion NOx
control technology that removes the NOx from the flue gas exiting
the boiler. When the flue gas
passes upstream of the SCR catalyst reactor, the NOx in the flue gas
reacts with the ammonia gas (a reagent) and is reduced to N2 and
water vapour. No solid or liquid
by-products will be generated from this process.
The ammonia
gas will be generated from an urea to ammonia conversion system to be installed
at the CPB, thus avoid bulk anhydrous ammonia storage on site. Up to 40,000 tonnes of urea will be used
per year. When urea reacts with
water under a heated environment, it hydrolyses to ammonia, carbon dioxide and
water. There are also other urea to
ammonia conversion technologies available, e.g. thermal decomposition. No solid or liquid wastes will be
generated from the conversion process.
A limited
amount of solid waste, in the form of spent catalyst, will be generated from
the SCR process. Common industry
practice is to recycle spent catalysts with original supplier(s) or to
rejuvenate them on-site. If the spent catalyst cannot
be recycled by the overseas suppliers or has reached a depleted stage, it can
be disposed of at the Chemical Waste Treatment Centre (CWTC) or at the SENT
Landfill after stabilisation
if required. With proper recycling and disposal
management of spent catalysts, potential environmental impacts of spent catalysts on the
existing and future waste management facilities in
The typical NOx
removal efficiency of SCR is 80%.
When compared with SNCR, there would be a slight increase in auxiliary
power consumption while ammonia slip can be more easily controlled within
acceptable limit because of the presence of catalysts.
Summary of the Option Evaluation for NOx
Emission Control Technologies
Several NOx
emission control technologies have been reviewed and some of the NOx
reduction technology integrating the existing combustion technologies with
added modifications. The elements of such reduction technologies are combined,
taking into account characteristics of the particular power plant and its
fuel. ALNBs and LNBs/ALNBs with OFA
can reduce the NOx emissions by 30%, they can also be used in
combination with SNCR and SCR.
Combining technologies together may result in the use of less ammonia
reagent and less catalyst. Table 2.1 summarises the main features
of the control technologies discussed above, final NOx control
facility will be subject to design optimisation.
Table
2.1 Summary
of Considered NOx Control Technology Options
|
Control Technology |
Typical NOx Reduction
Efficiency |
Environmental Considerations |
Other Comments |
|
Advanced
Low NOx Burners (ALNBs) |
20% |
|
|
|
Low NOx
Burners (LNBs) or ALNBs with Over Fire Air (OFA) |
30-50%
reduction in addition to present LNBs |
Increased
auxiliary power consumption and increased carbon content in ash (thus reduce
the re-use potential of ash) but can be managed |
|
|
Gas Reburn or Amine
Enhanced Fuel Lean Gas Reburn (AEFLGR) |
Up to 50% |
|
AEFLGR may
not been sufficiently tested in large coal-fired plants |
|
Selective
Non-Catalytic Reduction (SNCR) |
30-40% |
Ammonia
slip that can be managed to avoid adverse effects on the quality of ash and
hence its re-use potential |
More
experience in 350MW, application now extended to larger generating units |
|
Selective
Catalytic Reduction (SCR) |
80% |
Ammonia
slip that can be managed to avoid adverse effects on the quality of ash and
hence its re-use potential Proper
management of spent catalyst required |
A smaller
SCR with OFA may also achieve up to 80% NOx reduction efficiency. |
The
summary in Table 2.1 indicates that none
of the NOx control measures considered would present environmental
considerations that prohibit their implementation for CPB. Each of the
technologies would be capable of providing air quality improvement in terms of
NOx emissions, either individually or in combination.
For the purpose of this EIA Study, the
environmental considerations of different NOx control options were
considered and the most conservative process is selected for detailed
assessment with respect to environmental impacts. Advanced Low-NOx burners do
not present any new issues. Low-NOx
burners are currently installed at the CPB units. With respect to overfire air, this is a
process that involves adding an additional source of air available for
combustion into the furnace, again no new environmental considerations are
involved. Both SNCR and SCR will
involve a reagent which will produce an ammonia slip of a few parts per million
(ppm), the SNCR will have a slightly higher slip. However these low levels of ammonia slip
are not environmentally significant.
The SCR brings with it an additional environmental consideration of
catalyst which the SNCR process does not involve. The Gas Reburn option does not bring any
new consideration. All of the above does not affect the flue gas dispersion
parameters used in the air quality modelling. As a result of the above consideration,
SCR has been selected as the most conservative process with respect to
environmental impact.
2.3.3
Review
of the Available SO2 Emission Control Technologies
Overview
of SO2 Emission Control Technologies
Flue gas
desulphurisation (FGD) represents the most extensively used method for limiting
SO2 emissions from large-scale fossil fuel combustion. These methods remove SO2 from the flue gases in the furnace or, most frequently,
in a processing unit downstream from the boiler. Many widely used FGD systems can achieve
a high level of SO2 removal efficiencies. Typical SO2 control
technologies considered for CPB Emission Control Project include:
·
Dry Type Flue Gas Desulphurisation
·
Limestone Forced Oxidation Flue Gas
Desulphurisation
·
Seawater Flue Gas Desulphurisation
Dry
Type
Flue Gas Desulphurisation
There are
three major types of dry sulphur dioxide removal technologies: Dry Circulating Scrubber
(DCS), Spray Dryer Absorber (SDA) and dry sorbent injection.
In dry scrubbers, a calcium hydroxide
slurry (quicklime mixed with water) is introduced into a spray dryer
tower. The slurry is atomized and
injected (close to saturation) into the flue gases, where droplets react with
SO2 as they evaporate in the vessel. The resulting dry by-product is
collected in the bottom of the spray dryer and in the particulate removal
equipment (ESP or bagfilter).
SO2
may also be removed by injecting a sorbent (lime, limestone, or dolomite) into
the combustion gases.
The sorbent decomposes into lime, which
reacts in suspension with SO2 to form calcium sulphate (CaSO4).
The calcium sulphate, unreacted sorbent, and fly ash are removed at the
particulate control device (either an electrostatic precipitator or bagfilter)
downstream from the boiler. Sorbent
injection, however, affects the properties of the particulates (higher resistivity
and different size and morphology than derived from pulverized coal without SO2
control), which in turn adversely affects the performance of the electrostatic
precipitator (ESP).
Dry FGD
systems have up to 70-90% SO2 removal efficiency, but their
disadvantages are the use of reagents that are less cost effective and the
large amounts of waste by-products which are of little or no commercial value
and have to be disposed in a landfill site.
Limestone
Forced Oxidation Flue Gas Desulphurisation (LSFO FGD)
LSFO FGD is by far the most commonly used
FGD technology for large power boilers ([2]).
In typical wet scrubbers the flue gas enters a large vessel (spray
tower, absorber, bubbler, etc), where it is sprayed or mixed with limestone
slurry. The calcium in the slurry
reacts with the SO2 to form calcium sulphite or calcium
sulphate. A portion of the slurry
from the reaction tank is pumped into the thickener, where the solids settle
before going to a filter for final dewatering to about 50 percent solids.
Limestone with
forced oxidation (LSFO) is a variation of the traditional wet scrubber in that
it utilizes limestone instead of lime.
In the LSFO process, the flue gas is passed through absorbers that
contain a slurry of ground limestone in water. The sulphur dioxide is removed by
reacting with the limestone (calcium carbonate) to form calcium sulphite. The slurry is then aerated to oxidise
the calcium sulphite initially formed and is nearly fully oxidized to form
gypsum (calcium sulphate). The
resulting gypsum slurry is then treated, resulting in dewatered gypsum and a
small quantity of liquid effluent.
The resulting effluent may have a small chemical oxygen demand and/or
reduced dissolved oxygen concentrations.
The treated
effluent from the Limestone FGD process is likely to have the following
characteristics:
·
Increased
concentrations of sulphate ions;
·
Small
amount of suspended ash particles, which are likely to contain some trace
amount of metals content; and
·
Chemical
oxygen demand (COD).
The effluent
will be treated to comply with the discharge standards stipulated in the Technical Memorandum on Standards for
Effluents Discharged Into Drainage And Sewerage Systems, Inland And Coastal
Waters issued under the Water
Pollution Control Ordinance. It
will then be added to the cooling water flows and discharged via the existing
sub-marine cooling water outfall of CPB, resulting in a small increase in the
total flows from the outfall. It
should be noted that there would be no effect on the temperature of the cooling
water or on the quantities of residual chlorine in the discharge.
By-products
(up to 240,000 tpa of commercial grade gypsum and 17,000 tpa of lower grade
gypsum) and sludge arising from FGD wastewater treatment (about 180 tpd at 30%
dry solids) will be generated from the operation of the Limestone FGD
system. Gypsum is a material that
can be used for a number of applications (such as plasterboard and cement
production). According to a market
survey commissioned by CLP Power (as CAPCO operator), there is a large demand
of gypsum in Pearl River Delta (PRD) and East-Asia region. Taking into account the anticipated
growth in population growth and GDP in the region, it is anticipated that all
the commercial and lower grade gypsum would be recycled through the regional
market (the total gypsum generation rate is only a few percentage of the
existing consumption of gypsum for plasterboard and cement production in the
PRD and East-Asia region). A number
of plasterboard and cement manufactures in the region have expressed interest
in engaging in a long term arrangement to take all the gypsum to be generated
by the FGD operations.
Typical SO2
removal efficiency of the LSFO FGD system is 90%. Approximately 1 to 2 percent of the
unit's generating capacity is consumed to meet the power requirements of the
scrubber. LSFO FGD may also help
reduce particulates emission to some extent.
Sea
Water Flue Gas Desulphurisation (SWFGD)
SWFGD system reduces SO2
emissions by reacting seawater with the flue gas. Seawater (reagent) contains natural
alkalinity due to dissolved calcium and magnesium bicarbonate will react with
the acidic components of the flue gas to form soluble compounds that become
part of the effluent.
For the
The final
effluent from the
·
Increased
temperature;
·
Increased
concentrations of sulphate ions;
·
Decreased
pH;
·
Suspended
ash particles, which are likely to be contaminated with trace amount of metals
content;
·
Chemical
oxygen demand (COD); and
·
Decreased
dissolved oxygen.
The final
effluent is then returned to the main cooling water stream and discharged via
the CPB outfall. It should be noted
that the
Typical SO2
removal efficiency of
Summary
of the Option Evaluation for SO2 Emission Control Technologies
LSFO FGD can achieve typically 90% reduction of SO2 emissions
and
The potential water quality impacts from
the LSFO FGD option were considered to be much less than those from the
On the other
hand, LSFO FGD's by-product gypsum can be commercially recycled as construction
materials. As there are large
demand for gypsum market in the PRD and
Table 2.2 summarises the main features of control
technologies discussed above.
Table
2.2 Summary
of Considered SO2 Control Options
|
Control Technology |
Typical Efficiency |
Environmental Considerations |
Other Comments |
|
Dry Flue Gas
Desulphurisation (FGD) Systems |
70-90% |
Solid waste
that cannot be reused |
|
|
Limestone
Forced Oxidation Flue Gas Desulphurisation (LSFO FGD) |
90% |
Solid
by-product (gypsum) can be recycled with commercial outlets. Sludge from
wastewater treatment can be disposed of locally. |
Preferred |
|
Sea Water Flue
Gas Desulphurisation ( |
80% |
Contaminated
effluent with elevated sulphate, chlorine and heavy metals discharged into
the sea throughout the operating life of the system and uncertainties with
regard to potential bioaccumulation Limited
operational experience for large coal-fired plants |
|
2.3.4
Selection
of Emissions Control Option
Following the
review of different control options and consideration of their environmental
impacts, the SCR and LSFO FGD were selected as the package of emission control
options for the purpose of the EIA Study.
The choice was based on the expected environmental benefits of each
option, potential adverse environmental impacts and technological feasibility.
The
environmental impacts of these options and the reasons for selecting these
measures have been discussed and summarised in Tables 2.1 and 2.2.
·
SCR
has been selected as the most conservative process with respect to
environmental impact. This is due to
the fact that the SCR system encompasses the facilities and elements associated
with the other available NOx reduction technologies
·
Limestone
FGD was selected due to its technological maturity, and the overall lower
environmental side effects when compared to other FGD technologies.
The preliminary general arrangements of the proposed
facilities are shown in Figure 2.1.
2.4
Consideration of Alternative Construction
Methods and Sequence of Work
The total
capacity of the four existing power generation units at CPB represents about
one-third of all electricity supplied by CAPCO and CLP Power for use in
The scheme
described in Section 2.5 takes into
account of many constructability issues associated with this complex
retrofitting project.
2.5
Description of the Selected Scheme
The currently
envisaged construction and operational activities associated with the Project
are presented below.
Demolition
and Relocation of Certain Existing Facilities
While the existing
generating units will remain in their current locations, some of their
auxiliary and common facilities to the south of the generating units at CPB may
be demolished or relocated to provide space for the FGD, SCR and related
facilities. It must be emphasized
that the extent of demolition / relocation works depends primarily on the
layout and design of the new emissions control facilities which will be
finalised during the design engineering phase. The following paragraphs aim to provide
a description of the current scheme of these demolition / relocation works.
Demolition of CPB Fuel Oil Day Tank
The Fuel Oil
Day Tank (FODT), which has a capacity of 4,680 t, with the associated stairs,
piping, instrumentation, junction boxes, heat tracing, cables, etc, located
southwest of the CPB generating units will be demolished. The works will involve cutting the fuel
oil piping, moving the fuel oil equipment, and demolishing the fuel oil tank
and retaining wall.
The existing 1
m thick reinforced concrete foundation under the tank will be left in
place. The eight existing 2 m
diameter caissons drilled into the bedrock will also remain in place. The portion of the concrete slab between
the tank support foundation and the retaining wall will be backfilled with compacted
granular. The oil interceptor
serving the FODT bund areas will also be removed.
Demolition of Dangerous Goods Store
The Dangerous
Goods (DG) Store to the south of the FOPH will be demolished. The ground floor slab and the existing
concrete pavement will remain in place.
If caissons or concrete piers are required in the area to support the
future emissions control equipment, portions of the pavement will be
demolished.
Re-routing
of Underground Pipeworks
Several
sections of the underground pipeworks of the following systems will be
re-routed aboveground:
·
sea
water flushing;
·
town
water domestic;
·
town
water maintenance; and
·
sea
water fire main.
The
underground trench will be backfilled with soil after re-routing of the
pipeworks.
Relocation of CO2 Storage Tank
The existing
2,626-litre CO2 storage tank, fill connection and vaporisers will be
relocated from their existing locations to the area north of the chemical waste
building in an area presently occupied as a scaffolding laydown area. The concrete slab supporting the
existing CO2 Tank will remain in place.
Relocation of the LPG Storage Tanks
The existing
two LPG tanks of 4,600 litres capacity each and the associated equipment will be
removed and relocated to the existing foundation and piers east of Eastern
Road. The adjacent vapour room and
switch room will be demolished but the concrete slab on grade will remain in
place.
Relocation of the Intermediate Pressure Reduction Station
The
Intermediate Pressure Reduction Station (IPRS) of the gas transmission system
will be relocated to provide space for the installation of the emissions
control equipment. The concrete
slab floor and objects protruding aboveground will be demolished and
backfilled.
Installation
of the New Emissions Control Equipment and Facilities
New facilities
to be installed for the Project will include the SCR and FGD equipment, reagent
and by-product handling and storage facilities associated with the SCR and FGD
operations. An additional berthing
facility for the loading and unloading of reagents and by-products will also be
required. These are described in
the following sections.
Installation of SCR and FGD Facilities
The SCR and
FGD facilities will be retrofitted to the CPB generating units. The exact footprint of these facilities
will be finalised upon design optimisation.
Provision
of Reagent and By-product Handling and Storage Facilities
The major
reagent and by-product handling facilities for FGD operations will include
limestone storage facilities, limestone slurry tanks, gypsum dewatering and
storage facilities, and handling and storage facilities for lower grade
gypsum. SCR systems will require
urea as the ammonia supply reagent, urea storage facilities, dissolvers, urea
solution storage tanks and urea-to-ammonia reactors will be required.
Provision of Additional Berthing Facility
The SCR
systems could require about 40,000 tonnes per annum (tpa) of urea, while the FGD
systems could consume about 150,000 tpa of limestone and generate about 257,000
tpa of gypsum as by-product. The
quantities of reagents required and by-product produced will be finalized
during the design engineering phase.
It is anticipated that additional berthing facility will be needed for
the loading and unloading of process reagents and by-product.
The provision
of additional berthing is by extending the existing Heavy Load Berth to form a
multi-purpose wharf, providing a straight quay with the potential to
accommodate ships with a wide range of loaded draft requirements. It is anticipated that the extension
work will require some small-scale dredging for the foundations
of the deck and for providing sufficient turning basin for the different marine
vessel loaded draft requirements.
The estimated quantity of the dredged sediment is 80,700 m3. Figure 2.2 shows the
existing hydrographical profile (i.e. seabed level) in the vicinity of the additional
berthing facility. Based on the
loaded draught requirement of the vessels to be accommodated, a minimum depth
of -8.2 mPD will be required. The
area expected to require dredging for the additional berthing facility has been
determined taking into account the loaded draught requirements, the existing
hydrographical profile and the safety requirements for the berthing manoeuvres
and the dredging area is shown in Figure 2.3.
The preliminary design of the
additional berthing facility, with the envisage pile design and layout, is
presented in Figure 2.4.
The schematics of the emissions control
systems have been presented in Figure 2.5. The FGD wastewater treatment system (or
known as the chloride purge treatment system) is used to treat effluent from LS
FGD processes. No effluent is
anticipated from the operation of the NOx control system.
2.5.3
Proposed
Project Programme
Subject to
timely agreement of a long-term environmental policy and the successor
regulatory regime with the HKSARG, the currently envisaged project milestones
are as follows:
|
Key Stage of the
Project |
Indicative Date |
|
Finalisation of other major permitting requirements |
2006 |
|
Completion of front-end engineering design |
1st half of 2007 |
|
Commencement of relocation of existing facilities |
1st half of 2007 |
|
Award of major contracts |
2007 |
|
Dredging works |
2nd Quarter of 2007 |
|
Commencement of retrofit site work |
End 2007 |
|
Start-up of the retrofitted units |
End 2009 to 2011 |