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Chapter
2 Project Description
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Volume 5 Chapter 2 Project Description 2.1
OVERVIEW As discussed at the beginning of Chapter 1 the LNG/OET site has been cleared of approximately 185 ha of vegetation. Trees have been removed, however the stumps have been left in the ground. These works were conducted under the Infrastructure Upgrade Program (IUP), see Volume 6. Therefore part of the site clearance activities mentioned in this Chapter has already taken place. This section of the report describes the facilities and construction activities associated with the LNG plant and Oil Export Terminal (OET). These components essentially comprise: Onshore components;
• •
LNG plant, including all necessary utilities and common facilities; and Oil Export Terminal.
Offshore Components;
• • • • 2.1.1
Materials Off-loading facility; LNG Jetty; Tanker Loading unit (TLU); and Offshore pipeline connecting the OET and the TLU.
Role within Sakhalin II Project The Sakhalin II project will develop oil and natural gas from the Piltun-Astokhskoye (P-A) and Lunskoye offshore fields located off the north eastern coast of Sakhalin Island. Oil and gas will be extracted from two offshore platforms in the PA field and one platform in the Lunskoye field. Gas from the P-A and Lunskoye fields will be treated in an Onshore Processing Facility (OPF). In the OPF, gas will be dried and adjusted for dew point to meet the pipeline specification. The gas from the OPF will be routed via a single pipeline with compressor stations to the LNG Facility. LNG exported via the LNG Jetty is anticipated to be supplied to customers in the Asia-Pacific Region. An oil pipeline will run in parallel to the proposed natural gas pipeline. Oil will be stored in the OET, prior to transportation to an oil tanker via the TLU. These facilities are all located in Aniva Bay on the southern end of Sakhalin Island (Figure 2.1). Figure 2.2 shows a diagrammatic representation of the onshore and offshore facilities. The following sections provide descriptions of each of the above project components and provides details of construction/installation, commissioning and operating methods for each. Details of the proposed abandonment/decommissioning strategy are also discussed.
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Volume 5 Chapter 2 Project Description Figure 2.1
Overall Location Plan
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Volume 5 Chapter 2 Project Description Figure 2.2
Diagrammatic Representation of Onshore and Offshore Facilities Note: Only 3 oil storage tanks will be built at the OET.
Two Train LNG Plant
Oil Export Terminal Four Oil Storage Tanks
Tanker Loading Unit
Oil Tanker
Two LNG Tanks
2.2
LNG PLANT
2.2.1
Overview
Jetty and LNG Tanker
It is the intention of the project to fully integrate the operational, and partly integrate the utility requirements of the OET with those of the LNG facility. This will effectively treat the two facilities as one, with single management, integrated control room and one fence. 2.2.2
Footprint The preliminary land allocation for the facility is 478 hectares. The final footprint of the LNG plant will be approximately 159 hectares, while the OET will cover approximately 46 hectares.
2.2.3
Construction Overview Construction of the LNG plant will be undertaken over approximately four years. The LNG plant will have two separate LNG trains, and will begin operation once the first train is completed. Completion of the second LNG train will take an additional seven months. Construction of the LNG plant will therefore take a total of five years. Following clearing, site preparation activities such as excavation, filling, compacting etc will be undertaken. The whole construction area will be fenced and a temporary drainage system will be installed to prevent erosion and uncontrolled run-off.
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Volume 5 Chapter 2 Project Description LNG Facility The following earth works will be required to prepare the LNG Plant construction site:
• • •
excavation of 1 050 000 m3 for grading of the construction site; excavation of 87 000 m3 for water drainage channels; and construction of road beds requiring 68 000 m3.
Excess soil will be deposited in a former gully of the Tikhaja stream, located to the north of the site. This will enable the construction of the temporary camp and the detour road in this area. Approximately 210 000 m3 of the excavated soil is considered suitably fertile for temporary storage prior to use as landscaping material. The LNG plant will be built using a ‘stick built (1)’ process. The main stick built parts include;
• • • • •
both LNG trains; Utilities plant; LNG storage tank; main/major foundations; and underground and interconnecting systems between the process units.
The following elements will be pre-fabricated;
• • • • •
buildings in the administration area and possibly some process plant buildings; flare structures; LNG loading jetty; Material Offloading Facility (MOF); and minor foundations/supports/sleepers etc.
Further development of the stick built design will be required during Detailed Design Phase. Construction Workforce and Site Compound The same workforce will be used to build the LNG and the OET. The maximum workforce required for construction of the LNG/OET facility will be 4500 people. The construction camp is to be located to the north of the proposed site. The construction camp will utilise separate temporary facilities for electricity generation, waste disposal and other utilities. Upon commissioning of the first LNG train, a workforce of 2000 will remain for a further seven months to build the second train. Temporary Infrastructure Temporary facilities to be installed during the construction phase will include a concrete batching plant, materials offloading facility (MOF) and a temporary electrical grid. Electricity generation for the construction site and construction camp will be provided by diesel engines.
(1)
1 Stick built process refer’s to construction on-site from the ground up.
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Volume 5 Chapter 2 Project Description A temporary drainage system will be installed to prevent erosion and uncontrolled run-off. Material Offloading Facility During the construction period a materials offloading facility (MOF) will be built to enable vessels in Aniva Bay to offload equipment at the southern end of the site (Figure 2.3). This temporary facility will reduce the effect of transport through Korsakov. The MOF will be approximately 340 m long and 50 m wide occupying approximately 17 000 m2. It will be designed to offload equipment of approximately 400 t. Vessels up to 100 m long will be able to dock and unload at the MOF. The turning basin for vessels using the MOF will be dredged to a depth of 8 m. The dredging associated with the MOF will be undertaken between April and December 2003. The facility will be constructed using rock/sand fill with a steel piling/sheeting method. Its surface will include an asphalt road base to enable easy vehicular access. The design life of the MOF is approximately 6 years. It will be decommissioned in 2009. An exclusion zone of 200 m will be established around the MOF during construction (Figure 2.5). During operation, activities within the vicinity of the MOF and other offshore project components will be regulated by the presence of a safety zone to be established during construction and to remain in place during operation. The presence of the safety zone will restrict vessels access and prohibit anchoring and fishing activity completely. Engineering Considerations of Natural Hazards The key natural hazards existing at the site are seismic activity and coastal erosion. The seismic design of the LNG/OET complex is based on a distinction between the Operating Base Earthquake (OBE) and the Safe Shutdown Earthquake (SSE). The seismic design of the OET shall be based on the OBE only. OBE is the condition for which the complex will be designed; i.e. to withstand an earthquake without major damage such that the complex can be put back into operation after normal commissioning checks and/or minor repairs. The complex may suffer from trips and minor damage as a consequence of an OBE. The OBE is defined as an earthquake with an average return period of 475 years. The SSE is the condition for which the design of specified units of the complex will be verified to avoid catastrophic failure of the complex. For design purposes the SSE is defined as an earthquake with an average return period of 10 000 years. The following items will be designed for OBE and verified for SSE.
• • • • • •
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the operations centre; the LNG tanks; propane and ethane storage spheres/bullets; sectional ESD valves; fire station; and fire water pump house.
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Volume 5 Chapter 2 Project Description Figure 2.3
Layout of MOF and LNG Jetty
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Volume 5 Chapter 2 Project Description Remaining equipment and structures will be designed for OBE in accordance with Russian Federation and internationally recognised codes (UBC, British Standards or other approved). The coast is being eroded at the site. The 1986 FEMRI report suggests that coast has receded 1 m in the last 30 years. The landfall of the jetty will be designed with the stability and erosion of the coastal slopes in mind. Siting of the LNG/OET facility has considered erosion and has been situated approximately 80 m from the coast 2.2.4
Commissioning Commissioning of the LNG plant is required to produce ethane and methane for the LNG train process. It is anticipated that ten days of operation will be required to produce the appropriate volumes at a throughput of 40% of one train operation. During this time the gas stream will be flared continuously in the cold flare and the cold liquid burners. Approximately 65 000 t of natural or liquid natural gas will be flared during commissioning. This same process will be conducted during commissioning of the second LNG train, approximately seven months later. Demineralised water will be used to hydrotest the LNG storage tanks. The waste water will be directed to the effluent treatment plant, prior to disposal to Aniva Bay.
2.2.5
Operation Overview The LNG/OET facilities will have shared administration, operation and maintenance buildings. The effluent water and sewage treatment plant will be located at the OET and will service both facilities. The LNG process facilities and utilities will be designed for a 20 year lifetime. The OET and all LNG/OET civil structures and foundations will be designed for a 30 year lifetime. The LNG Jetty will have a design life of 30 years, with the exception of the foundations and other concrete items, which will be designed with a 40 year lifetime. LNG is essentially produced by cooling natural gas below its condensing temperature of minus 162°C at atmospheric pressure. Once liquefied, the gas volume is one six hundredth of its volume in its gaseous form, making it easier to transport and store. It is converted back to gas by raising the temperature (Figure 2.4). The gas treatment process comprises four stages as follows:
• • • •
gas pre-treatment (acid gas, water and mercury removal); liquefaction; Shell DMR (Double Mixed Refrigerant); fractionation; and storage.
Gas will be treated, processed and liquefied in two parallel process trains. The second LNG process train will be built following commissioning of the first line. The LNG plant will operate continuously 332 days a year, the shutdown period will be used to perform maintenance.
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Volume 5 Chapter 2 Project Description
Condensate (to OET)
SE- LNG Train 2
SE-LNG Train 1
Fractionation
Liquefaction
Feedgas Ex OPF
Gas Metering
Acid Gas Removal
DDehydration
Mercury Removal
Fuel Gas
LNG Storage and Loading
LNG Plant Process Flow
CO2
Figure 2.4
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Volume 5 Chapter 2 Project Description Acid Gas Removal The feed gas from the metering station will be split into the two LNG trains and fed to the acid gas removal unit. The acid gas removal unit will employ the Sulfinol-D process. This process will utilise a circulating amine solution to remove virtually all of the CO2 and H2S. These compounds would otherwise freeze when the gas is liquefied. Current indications are that no H2S is present in the feed gas. As a standard precautionary measure, the plant has been designed for a maximum of 20 ppm H2S present in the gas stream. The amine-rich solvent will be preflashed and subsequently stripped in a low pressure regenerator column. Acid gas, (mostly CO2) containing some hydrocarbons co-absorbed by the Sulfinol solvent, will be routed to the acid gas incinerator. Dehydration Prior to liquefaction, all moisture needs to be removed from the sweetened gas stream to prevent hydrate formation and blockages in the downstream liquefaction process. Treated gas from the Acid Gas Removal Unit will be cooled using precool mixed refrigerant (PMR) to condense the bulk of the water. The water will be removed in a separate vessel and returned to the Acid Gas Removal Unit. The gas will then be passed over molecular sieve beds to absorb the remaining water to below 1 ppmv in the gas. A slipstream of dry effluent gas will be used to regenerate the molecular sieve beds. Heat for the process will be provided from the waste heat of the gas turbine driving the PMR compressor. After cooling and water removal, the regeneration gas will be compressed back to the main feed stream, upstream of the PMR chiller. Mercury Removal The concentration of mercury in the feed gas is unknown at this stage. A mercury removal unit has been designed to treat mercury in the feed gas up to a maximum concentration 1000 ng Sm-3. The unit will comprise of a single bed of sulphur impregnated activated carbon in which mercury will be removed from the gas to a level of 10 ng Sm-3. Activated carbon will be changed every four years. Liquefaction Treated gas from the mercury removal unit will be cooled against PMR and fed to the scrub columns. The function of the scrub columns will be to remove heavy hydrocarbons (>C5), that could freeze out in the Main Cryogenic Heat Exchanger (MCHE). The bottom product of the scrub columns will then be fed to the fractionation unit. The scrubbed gas will then be recombined with excess natural gas liquids from the Fractionation Unit and fed to the MCHE for further cooling and liquefaction. In the MCHE, the natural gas will be liquefied and subcooled to a temperature of minus 153°C. The LNG will then be reduced in pressure and flashed in an endflash vessel. LNG will be pumped to LNG storage. Endflash gas will be routed via an endflash exchanger and recompressed to HP fuel gas pressure Fractionation The Fractionation Unit will consist of four columns. The feed will be first routed to the Demethaniser column, for light components to be removed as an overhead gas stream. Overhead gas from the Demethaniser Column will be routed to the MCHE to be cooled and liquefied into methane. The Deethaniser and Depropaniser Column
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Volume 5 Chapter 2 Project Description produce refrigerant grade ethane and propane. The cooling cycles will comprise closed loops so a small amount of the ethane and propane can be used to make up refrigerants (PMR and MR) for the Liquefaction process; most of the ethane and propane will be reinjected in the LNG. Stabilised condensate produced at the bottom product of the Debutaniser Column will be metered before being piped to the Oil Export Terminal. Storage LNG from the two trains will be piped to the LNG storage facilities, consisting of two tanks, of 100 000 m3 net capacity each. The LNG Facility’s two process trains will receive 13.8 billion cubic meters of gas annually (at 0°C and 101.325 kilopascals). The average capacity of one process train will be approximately 14 700 t of liquefied natural gas daily. LNG will be transferred to LNG tankers via the LNG Jetty. Condensate from the LNG plant will be transferred to the OET via above ground piping. Utilities The LNG plant will generate electricity for its own operations as well as for the OET. Four Frame 7 gas turbines will be required to drive the LNG train refrigerant MR and PMR compressors (2 gas turbines per train), while four Frame 6 gas turbines will be used to generate electricity for the rest of the LNG and OET site. It is anticipated that two of the Frame 6 gas turbines will be in operation during normal conditions, with a third required during high temperatures in the summer. The third and fourth Frame 6 gas turbines will be on standby (spinning reserve) for quick start-up if/when required. All cooling will be by closed circuit with limited top-up water requirements. Emergency power generation will be provided by;
• • • •
two diesel engines for emergency power generation; two diesel engines for fire water pumps; one diesel engine for emergency instrument air compression; and one gas fired boiler for plant start-up.
A 1000 m3 above ground diesel storage tank will also be located on site for emergency electricity generation. This tank has earthen bunding for 110% of its volume with a HDPE underlay and leak detection system. Table 2.1
Approximate LNG/OET Workforce1 Facility Stage
Estimated Workforce
Commissioning and Start-up First years of first cycle operation Mature Organisation
270 - 300 235 - 265 < 180
1
The LNG plant and OET will share administration activities and workforce.
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Volume 5 Chapter 2 Project Description 2.3
LNG JETTY
2.3.1
Overview The proposed LNG Jetty is located in Aniva Bay and will comprise an 800 m long open trestle jetty structure with associated berthing and LNG loading facilities (Figure 2.3). The terrestrial component of this will include a rock filled causeway. The vessel berths have been designed such that the largest vessels anticipated (up to 145 000 m3 capacity) can moor without tidal or ice restrictions. The trestle and loading site is designed to withstand the ice conditions expected at the jetty location.
2.3.2
Description of Facilities Trestle Structure The trestle structure will be supported by conical shaped gravity supports (25 m by 25 m) spaced approximately 80 m apart. The resulting seabed footprint is 6250 m2. Rock fill will be used to protect the base of each gravity structure. The trestle will comprise an abutment, bridging for pipes, paved road, cable troughs, combined field auxiliary room and substation platform. The paved road, product pipeline, power sources, cables and support for the last section of the flyover bridge will pass over the abutment which will also act as protection of the near-shore area from coastal erosion. Flood protection measures will be taken to ensure that adequate protection of the abutment is provided. The pipe bridging will accommodate the loading/circulation LNG pipes as well as the vapour return ducts and service pipelines. The paved road on the flyover will be 4 m wide with a minimum vertical clearance of 4.5 m. The road will be capable of withstanding the movement of a lifting crane with a 30 t lifting capacity in non-operating position. The paved road/pipeline gradient will be sufficient to protect them form the impact of wave loads or the loads resulting from the effect of drifting ices. Potable water for the platform cell and sanitary cabin will be stored in 1 m3 thermally insulated containers. Chemical toilets will be located on the jetty. LNG Loading Facilities The platform will be equipped with a deck to accommodate all the pipeline equipment and the loading hose. Provision will be made for safe emergency exits from a vessel and from the loading site to the flyover. A drying system with drainage pits (1 m3 in volume) will be incorporated into the deck to soak up any spilled LNG in an emergency event. Measures will be adopted to prevent ice build up on the deck during winter months. Vessel Berths The LNG Jetty has been designed to accommodate vessels with a carrying capacity of between 20 000 and 145 000 m3. Typical vessel dimensions will be as follows:
•
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between 270 and 300 m in length;
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Volume 5 Chapter 2 Project Description • •
between 41 and 48 m in width; and between 10.8 and 11.5 m draught.
The vessel berths will be positioned stern to the shore. A minimum under-keel clearance of 1.5 m will be retained during the lowest astronomic tide (LAT). Four LNG berths and two guard vessel berths will be provided for mooring and anchoring the LNG vessels. Monitoring equipment will be installed in the mooring area to monitor mooring speeds, waves and flows. 2.3.3
Construction Overview Approximately 30 000 m3 of unsorted gravel will be used to fill the causeway core (located on the land). The causeway slope to shore will be strengthened by approximately 70 000 m3 rock. Approximately 5 000 t of steel and approximately 7 000 m3 of reinforced concrete will be used to construct the rest of the jetty. Approximately 25 000 m3 sand will be used to fill the caissons. Two 1500 t lifting barges will be required during the construction of the LNG Jetty. Dredging It is estimated that an initial volume of approximately 1 238 000 m3 spoil will be associated with the construction of LNG Jetty and MOF. Dredging will be undertaken by a suction dredger which can dredge up to 6000 m3 per day. It is estimated, however that only 4000m3 dredged spoil will require disposal each day. Once the type and quality of excavated spoil has been established, SEIC will investigate options for re-use. There is the potential for good quality sand or gravel to be used on-shore, however this would also be subject to timing of excavation in relation to on-shore activities. As a worst case, all dredged spoil will be disposed of at a licenced dredge disposal site located approximately 22 km offshore in 63 m water in the southern part of Aniva Bay (Figure 2.1). The proposed areas in which dredging will take place are shown in Figure 2.3. These areas are estimated to be 476 100 m2 for the LNG Jetty and approximately 90 000 m2 for the MOF respectively. Exclusion Zone The Jetty will have a 200 m exclusion zone within which no non project related vessels or people will be permitted to enter. A wider safety zone will be permanently established during construction and operation which will restrict access and prohibit anchoring and fishing activity in the immediate vicinity of the offshore project components (SEIC Exclusion Zones Position Paper) (Figure 2.5).
2.3.4
Operation The LNG plant will receive its first cargo in November 2006. During periods of maximum LNG production, it is planned to load one vessel every two days. Loading is anticipated to take up to 16 hours (for 145 000 t tankers). LNG will be stored in insulated tanks at -158°C located within the hull of the LNG tankers.
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Volume 5 Chapter 2 Project Description Figure 2.5
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Exclusion Zones
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Volume 5 Chapter 2 Project Description A turning circle with a radius of 600 m and under keel clearance of 1.5 m will be marked in the vicinity of the LNG jetty. Mooring spaces for LNG carriers will also be provided. During LNG tanker manoeuvring onto and off the LNG Jetty, the tanker will be assisted by 3 tug vessels. Support vessel crews will be transported via the port of Korsakov rather than the LNG Jetty. No maintenance dredging is required. Fire water will be supplied from the main fire water system. A safety zone will be established around all of the marine project components in Aniva bay as described in the previous section.
2.4
OIL EXPORT TERMINAL
2.4.1
Construction The OET is anticipated to take approximately three years to construct, and is scheduled to be completed two years prior to the completion of the LNG facility. The OET will be built using a similar stick built process as that used for the LNG plant, this will be further developed at the Project Specification phase.
2.4.2
Commissioning Commissioning of the Oil Export Terminal will principally comprise integrity testing of the storage tanks. De-mineralised water will be used to hydrotest, and will be subsequently discharged to the firewater ponds where, together with rainwater, it will be discharged into Aniva Bay.
2.4.3
Operation The OET facility will provide oil storage to ensure continuous pipeline operations and ready volumes for tanker loading year round. It will be supplied with crude oil and commingled condensate from the Piltun-Astokhskoye and Lunskoye fields, and with condensate from the LNG plant. Condensate from the LNG plant will be transferred to the OET via above ground piping and blended with the oil. The main facilities of the OET will comprise three crude oil storage tanks, four crude oil loading pumps and an inlet and custody transfer metering station. The OET facility will also include effluent treatment facilities for both the OET and LNG facilities. Storage Tanks The three steel crude oil storage tanks will each have a minimum normal working capacity of 95 392 m3 (600 000 bbl). Each storage tank will have an earth dike that is designed to contain in excess of 110% of the tank storage volume. The tanks will be geodesic dome internal floating roof tanks with single seals on the single Glass Reinforced Epoxy (GRE) deck roof. Piping to and between the tanks will allow filling and withdrawal of oil, as well as transfer between two tanks. Tank insulation or heating is not required.
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Volume 5 Chapter 2 Project Description Tank overfill protection will be provided by a high-level alarm system and the manual remote switching of flow to another tank if tank volumes rise to a preset level. Final overfill shutdown of filling operations will automatically occur at a preset maximum fill point. Loading Pumps Four electric motor centrifugal loading pumps will load the tankers at a maximum rate of 7 949 m3hr-1 (50 000 b/h). Up to three pumps will be required to meet the anticipated tanker loading rates, however, piping and power supplies will be provided to accommodate the fourth pump, if required. The pumps will transfer crude to the offshore TLU via an offshore loading pipeline. Meters Custody transfer metering will take place as the oil is pumped from the storage tanks to the tankers. Utilities The LNG facility will provide primary and emergency electrical power, potable water, service water, firewater and instrument air to the OET. The LNG will transfer oily water and domestic sewage to the OET via underground piping to the OET effluent treatment plant. The OET effluent treatment plant will include sewage collection/ treatment and storm water and oily water collection treatment facilities. The treated water will be discharged via a marine outfall approximately 800 m from the shore, at a minimum 10 m water depth in Aniva Bay. The effluent treatment plant will include facilities for primary and secondary wastewater treatment, including settling tanks, biotreaters, degreaser skimming tanks, sand filter and sludge dewatering facility. The effluent treatment plant will be designed so that any discharges into Aniva bay meet the SEIC proposed standards for aqueous effluents from the LNG/OET facility. Aniva Bay is designated a zero discharge site, details of effluent permitting are currently under discussion with the relevant authorities.
2.5
OIL EXPORT PIPELINE TO TLU
2.5.1
Overview The subsea pipeline will be 76 cm (30 inches) in diameter and approximately 5.5 km long and will carry oil from the OET to the TLU (Figure 2.1). A 7 cm diameter composite cable will be ‘piggy backed’ onto the pipeline to feed electrical power to the TLU platform, together with an auxiliary fibre-optic line and copper signal cores which will allow for control and communication with the TLU. The marine outfall (approximately 800 m long) will be laid in the same trench. The pipeline landfall will be located within the OET site boundary. A pig receiver will be installed on land at the onshore OET during the first 5 years of operation. Figure 2.6 shows the basic design of the subsea pipeline.
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Volume 5 Chapter 2 Project Description Figure 2.6
Layout of the Subsea Pipeline
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Volume 5 Chapter 2 Project Description The pipeline has a design life of at least 30 years and is intended for continuous all year round operation. It will be designed in accordance with the international codes and standards for pipelines design including ANSI, ASME, APL, and Russian Federation regulatory documents. 2.5.2
Installation Overview The composite cable will be clipped onto the pipeline with metal straps (TEO-C Vol 6A, book 3, part 3, E-T3) allowing, both components to be installed together as outlined in the following sections. Schedule Pipeline and cable installation will take place during the summer months ie between April and September most likely between June and July 2004 or 2005. Approximately 6 months of preparatory work will also be involved prior to this period (TEO-C 6a, Book 7 - part 2). Construction Materials and Transportation to Site Basic construction materials required for construction will include:
• • • •
metal pipes (various diameters); sand and gravel mixtures and rock from quarries; lubricants and fuels; and various other products.
Spoil and rock excavated during dredging activities will be re-used as much as possible during construction. Some equipment and materials will need to be transported to site by vessels (carrying capacity of between 5000 and 8000 t). Other construction materials will be transported by road from the ice free sea-port of Korsakov. Construction Workforce and Site Compound The construction workforce associated with the installation of the subsea pipeline is anticipated to comprise approximately 400 employees. It is anticipated that employees will work on shifts and will be accommodated at the site camp associated with the onshore LNG/OET facilities. Personnel will be transported by either motor vehicle or support vessel to the work site. The power supply generators, potable water units, sewage water treatment and waste disposal plants, storage area, accommodation and office facilities will be available at the LNG/OET site compound. Machinery Requirements Both construction vessels and onshore construction machinery will be required to install the subsea pipeline and landfall crossing respectively. An indication of the machinery required is presented in Table 2.2.
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Volume 5 Chapter 2 Project Description Table 2.2
Machinery and Vessels Associated with the Installation of the Subsea pipeline. Activity
Timing
Vessels
Dredging Pipeline Laying Rock Backfilling
2250 April 2005 - May 2005 - June
6 11 3
These numbers do not include crew traffic vessels, fuel bunker vessels, water bunkering vessels and wastewater bunkering vessels.
Construction vessel refuelling will either be undertaken by a refuelling vessel and water tanker or in the port of Korsakov. Installation Sequence Installation activities will comprise the following:
• •
physical survey of pipeline corridor;
• •
trenches will be excavated with a cutter suction dredger (CSD); and
laying of underwater pipelines into the trench (assembling pipeline onboard the pipe-lay barge and pulling towards the shore with the onshore winch, followed by movement of pipe-lay barge towards the TLU); pipeline hydrostatic testing;
Trench backfilling may involve imported and indigenous backfill methods as follows:
•
trench backfilling with excavated material by means of shutes or tubes to direct the spoil onto the trench; and
•
trench backfilling with riprap protection by means of floating crane. In nearshore waters (up to the 6.5 m isobath) the trench will be protected with a layer of riprap (large pieces of crushed rock) laid on top of the backfilling material (crushed stone).
All activities for construction of pipelines to the TLU will be escorted and serviced by a floating diver’s station, two guard towboats and a passenger boat. Trench Excavation and Backfilling Trenches will be excavated with a cutter suction dredger (CSD). A trailing hopper suction dredger (THSD) equipped with jetting nozzles may be used in deeper water (LGL 2002). It is proposed that approximately 25 600 m3 spoil will be extracted during trench excavation. Dredged spoil will be reused for backfilling the trench. According to the engineering and geological surveys undertaken to date, marl and sandstone may occur in the vicinity of the proposed pipeline. No blasting will be undertaken. Trench backfilling will be undertaken by directing excavated soil back into the trench, this will be a continuous process of excavation, pipe laying and then backfilling. Following backfilling with indigenous material a layer of rock armour will be laid to protect the installation. In addition, rock and aggregate will be delivered from two quarries, Listvinichnyi and Chapaevskiy (or other authorised sites) which are located in southeast of YuzhnoSakhalinsk. The rock from these quarries is typically shale. It is anticipated that the total volume of rock required for backfilling will be approximately 3500 m3.
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Volume 5 Chapter 2 Project Description Pipe Laying The pipeline will be laid on the seabed by the pipe laybarge. In water deeper than 15 m, the pipe will be laid directly onto the seabed. Pipes laid in this way will be welded on board the pipe laying barge and laid in 12 m sections. All operations concerning preparation of pipe ends, alignment, welding, control, scraping and insulation coating will be performed simultaneously at different workplaces located approximately every 12 m (the estimated length of one pipe section). After completion of all operations the barge moves another 12 m and the process will be repeated. The pipeline will be welded to a bolted flanged connection at the TLU. The pipelines will be subjected to hydrostatic testing in accordance with technical specifications and standard requirements (Section 2.5.3). Exclusion Zone A temporary 750 m exclusion zone on all sides of the pipeline will be established during construction activity (SEIC Exclusions Zones Position Paper). 2.5.3
Commissioning Pipeline Hydrotesting Approximately 2756 m3 treated seawater and 5513 m3 of clean seawater will be passed through the subsea pipe under high pressure in order to test its integrity. The hydrotest water will contain small quantities of biocide and corrosion inhibitor to prevent internal corrosion, biofouling or bacterial corrosion of the pipe. Hydrotest water will be discharged to sea in the vicinity of the TLU. A small amount of detoxifier for biocide (sodium bisulphate) may be injected to neutralise the biocide prior to discharging the hydrotest water. The discharge will meet Russian standards.
2.5.4
Pipeline Operation Overview The underwater pipeline will have a diameter of 76 cm (30 inches) and a throughput of up to 8000 m3 per hour. The pipeline will be designed to operate continuously all year round. The steel pipes will be manufactured in accordance with the requirements of specifications 5L of API (American Petroleum Institute). Pipe wall thickness will be determined with corrosion allowance. For the purpose of buoyancy suppression and pipeline protection, concrete coating will be required to an approximate thickness of 90 mm. Corrosion Protection External and internal surfaces of the pipelines will have a corrosion-resistant coating. The pipeline will have cathodic protection system. Insulating joints will be installed where required. A cathodic protection plan will be developed
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Volume 5 Chapter 2 Project Description Exclusion Zone On completion of the pipeline, a permanent 500 m exclusion zone will be established to prevent fishing activity and the anchorage of vessels in its vicinity. This will be marked onto maps and included in shipping broadcasts as appropriate. The exclusion zone will be marked by buoys, reflectors and white lights. Emergency Prevention System In order to provide the serviceability of the pipeline and prevent any emergency situation, the Supervisory Control and Data Acquisition System (SCADA) will be installed at the shore-based Main Control Center. This system will monitor aspects of system performance. Maintenance and Repair Routine pipeline inspection will be carried out at least once a year during the summer months. A detailed schedule for maintenance will be specified once the pipelines have been commissioned.
2.6
TANKER LOADING UNIT
2.6.1
Overview Location The proposed Tanker Loading Unit (TLU) will be located in approximately 28 m water (Lowest Astronomical Tide) in Aniva Bay. It will be 4.3 km offshore, and approximately 4.8 km south from the OET. The nearest port is at Korsakov, located approximately 18 km to the west. The TLU will be connected to the subsea oil pipeline system from the OET (Section 2.4). It will be designed for continuous operation all year round and it is estimated that approximately 9.87 million t of exported crude and condensate per year (200 000 BPD) will be exported from the TLU. The TLU is suitable for the mooring and loading of 80 000 to 150 000 t vessels. Support vessels will assist the tankers to moor to the TLU and the operation of the flexible oil loading hoses. The TLU will be controlled from the shore or support vessels and will not normally be manned. Layout The TLU is a tower-type structure with gravity base and integrated rotating modulartype deck. The rotation of the platform through 360° will allow tankers to moor downwind at all times. Figure 2.7 shows the layout of the TLU.
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Volume 5 Chapter 2 Project Description Figure 2.7
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Layout of the TLU
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Volume 5 Chapter 2 Project Description Subsea Structures The base of the gravity-type TLU will be an octagonal structure with different crosssections at different heights. The steel bedplate of the substructure is divided into 17 ballast sections which will be filled with ballast to make the structure stable. During installation, seawater ballast will be used which will later be replaced with solid ballast (hematite - red iron ore). The solid ballast will comprise approximately 9300 t of dense flowable slurry material that can be placed into the GBS base compartments through hatches provided in the top of the base. (SEIC 2002 specification for TLU Ballast). The material will not have a hazardous or otherwise undesirable reaction with any element of the system it comes into contact with. The material will not degrade or harden whilst in place, it will be pumped out during decommissioning. The power supply will be provided by the onshore Oil Export Terminal (OET) facilities via a subsea power cable laid with the oil supply pipeline. The TLU navigation equipment will incorporate a self-contained power supply which will be triggered automatically in an emergency. Topside Structures The TLU topside will be a modular-type integrated deck rotating 360° around the substructure. The topside will house all primary equipment for tanker mooring and loading activities. The majority of the equipment will be located on the main deck as follows:
• • • • •
primary and secondary winches; stiff boom crane; crude oil riser valve and pressure gauges; hydraulic power pack; and electric equipment room (transformers, distribution boards and batteries).
Temporary shelter will also be available on the main deck. This is only intended for use during emergency situations, when it is not possible to leave the TLU. Anti-corrosion Protection The steel structures associated with the TLU will have corrosion protection as follows.
• •
cathodic protection of part of the external surfaces will be applied underwater;
•
within the splash/ice zone, a corrosion allowance and an ice erosion margin will be incorporated;
• •
above the maximum ice level, a protective coating will be provided; and
protective coating will not be applied to internal surfaces below the water line as corrosion inhibitors will be added to sea water ballast;
the application of a protective coating to internal surfaces above the sea water ballast level will be considered as part of detailed design.
All types of equipment will be supplied with standard surface treatment and coating as follows:
• • •
Sa 2.5 Class sand-blasting; zink and epoxy priming, 75 microns; aluminium-bearing epoxy mastic, 125 microns; and S A K H A L I N E N E R G Y I N V E S T M E N T C O M PA N Y • E N V I R O N M E N TA L I M PA C T A S S E S S M E N T
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Volume 5 Chapter 2 Project Description •
polyurethane-based upper layer of coating 75 microns.
Steel substructures will incorporate a dual protection system incorporating a protective polymeric coating (polyurethane, epoxy or polyester resin) and cathodic protection. 2.6.2
Installation Construction Schedule The TLU construction schedule is outlined in Table 2.3.
Table 2.3
Construction Schedule Work types Jan
Feb Mar
Apr
Month May Jun Jul
Aug
Sep
Oct
Nov
Dec
Work in 2005 TLU towing to the place of installation Erection and setting up Work in 2006 - 2030 Tanker Loading Abandonment (2030)
It is proposed that the TLU will be transported to the proposed TLU site during July/August 2005 and will be installed during August/September 2005. Preparatory Activities Preparation of approximately 2500 m2 of seabed will be required prior to installation of the TLU. Preparatory activities will include the following:
• • • •
site investigation; placing of a 0.5 m thick gravel mattress; floating of TLU into position; and flooding and ballasting.
No dredging is associated with site preparation for the Tanker Loading Unit. Positioning and Ballasting of TLU The TLU will be floated to the prepared site by tug boats. A large floating crane will be used to stabilise the TLU during ballasting. The preliminary vessel requirements for transporting the TLU to site are outlined in Table 2.4, and will be verified in detailed design.
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Volume 5 Chapter 2 Project Description Table 2.4
Preliminary Vessel Requirements for Transporting the TLU Type Vessel
Number
Period Use (during 2005)
Total Operating Time (Hours)
Fuel Consumption (t d-1)
Towboat Tug with Lifting Boom Ballast Tug Crew Boat
2 2
21 days in July 16 days in July
504 384
10.5 10.5
2 1
19 days in July 30 trips between July and September (one per day approx)
456 720
10.5 2
Once in the correct position, the TLU will be installed on the seabed by flooding the base sections with ballast water. Once the structure is on the seabed, solid ballast will be placed into the base sections displacing approximately 4500 m3 seawater to sea. Ballasting will be carried out by a ballasting vessel. The rotating head will be lifted using the floating crane and installed onto the tower. The central support section of the rotating head will be welded onto the tower structure. Installation and ballasting will take approximately 25 days. Installation of Seabed Protection Measures After installation of the TLU, a protective embankment will be installed around the foundations of the tower in order to prevent scour. The protective embankment will comprise an underlayer made of crushed stone or gravel and rockfill. The area of the seabed necessary for the TLU installation, including construction of the protective embankment is approximately 1970 m2 (radius 25 m). A vessel will be used to install the protective embankment. It is estimated that the protective embankment will take approximately 40 days to construct. Benthic and seabed surveys will be undertaken prior to the installation of the embankment and will act as a baseline for future monitoring. Construction Workforce Approximately 50 construction personnel will carry out site preparation activities associated with the construction of the TLU. Approximately 70 construction workforce will be required during shipment and installation activities, however this will ultimately be dependent on the chosen contractor. Approximately 12 workers (and associated vessel crews) will be employed during commissioning. The number of workforce employed during the operation of the TLU will depend on the number of support vessels required during associated activities. It is estimated that up to 50 personnel may be required at any one time. Exclusion Zones An exclusion zone with a radius of 1000 m will be established around the TLU between April and December 2005.
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Volume 5 Chapter 2 Project Description In addition a safety zone will be established in the wider area around all the Aniva Bay offshore project components. This will restrict access and prohibit anchoring or fishing within this zone. 2.6.3
Commissioning TLU commissioning is anticipated to commence during the third quarter of 2005. Commissioning will include the following activities;
• • • •
testing of all electrical components; actuation of all hydraulic functions; speed/pressure adjustments; and initial startup and tests of all equipment.
Commissioning is anticipated to take up to 60 days. Hydraulic tests of new loading hoses will be performed by the manufacturer prior to installation. Any subsequent repair and maintenance of the loading hoses will be carried out onshore. Leak testing of the hoses will be carried out offshore. 2.6.4
Operation Tanker loading will commence in 2006 and will continue for between 25 and 30 years. Project abandonment is anticipated to take place in 2030. Loading During oil handling operations, an empty tanker will be moored to the TLU. The loading hose will be supported on the boom of the crane from where it will be connected to the tanker loading system (normally positioned in the middle or to the bow of the vessel). The routine procedure for tanker mooring/unmooring will typically be proposed as follows.
•
The TLU will be approached by the bow of the empty tanker, stopping at an appropriate distance.
•
The end of the towing line will be passed to the tanker with the help of the line thrower or support vessel.
•
The support vessel will retrieve the loading hose end and pass it to the tanker for subsequent attachment to the midship manifold or to the bow connection.
•
The front end of the loading hose will be connected to the tanker midship collector or to the bow connection.
•
After the Berthing Master confirms that the tanker is ready to receive, the OET control room will be notified to start pumping, initially at a low rate as per the berthing and loading procedure.
The routine procedure for tanker unmooring will typically be as follows.
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•
The front end of the loading hose will be disconnected from the tanker midship manifold or from the bow connection and the end valves on the hose closed and blinded prior to lowering the hose end(s) into the sea.
•
The loading hose will be left floating in the water in summer periods, and will be hung under the boom in winter periods, in between loadings.
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The tanker chain stopper will be released and the mooring hawser will remain floating in the water in summer periods, and will be hung under the boom in winter periods.
A Berthing Master will be in charge of the TLU control system during tanker mooring and unmooring. Tanker Specification & Movements The TLU has been designed to accommodate tankers ranging between 80 000 and 150 000 t in size. Only tankers with segregated ballast tanks will be associated with the project in accordance with the project design code. The expected specifications of standard tankers include the capability of bow mooring. For such vessel types, oil loading through the midships manifold is a standard operating mode. During the winter months, the tankers capable of bow loading will be used. Depending on the currents, wind and wave conditions, the TLU has been designed so that the tanker can move around the TLU maintaining a its bows into winds during loading operations. In order to provide safe movement of the tanker during loading conditions, the tanker will be assisted as appropriate by a support tug. The average expected volume of tanker traffic is approximately one every four days with mooring and loading taking 24 hours. The maximum tanker loading rate will be approximately 8000 m3 per hour. Support Vessel Movements The use of support vessels is anticipated during the operation of the TLU. Vessels types are outlined in Table 2.5. Table 2.5
Support Vessels Boat Type
Number
Function
Icebreaker Multipurpose Ice class tugs Tug Boats
1 2 2
Tank Barge (2,000 m3) Crew Boat
1 1
Convoy of tankers in the Aniva Gulf during winter. Ice breaking near TLU and LNG Jetty, mooring operations and operations with filing hoses. Ice breaking near TLU and LNG Jetty, mooring operations and operations with filing hoses. Repair and preventative operations with oil-loading hoses. Personnel transportation to TLU, tankers and other boat works.
All support vessels will be provided with additional fire extinguishing and oil spill contingency equipment. All tankers will comply with MARPOL with regards to the ballast water. Exclusion Zones Figure 2.5. shows the construction and operational exclusion zones associated with the facilities in Aniva Bay (SEIC -Exclusion Zones Position Paper). A 900 m radius exclusion zone will be established around the TLU during operation which will restrict the area from passage and anchorage of vessels (including fishing vessels) except for tankers and support vessels.
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Volume 5 Chapter 2 Project Description The safety zone established around all the Aniva Bay facilities will remain as a permanent feature prohibiting anchoring and fisheries activities within this zone. Guard vessels will patrol the area for the safety of vessels not associated with the TLU facility. Navigation and Communication Systems Through the Main Control Centre (which will incorporate the communication centre of all onshore installations), the following means of communication will be available:
•
satellite communication for connection to Russian and international telecommunication links;
•
radio-relay communication link intended for providing communication with tank farm, oil metering station, as well as for control of mooring and loading operations with redundancy of equipment by emergency radio stations and channels;
•
separate radio communication system operating in the marine frequency band and providing the ‘ship-to-shore’-type communication between onshore installations, tankers and support vessels;
• •
navigation radio systems and beacons;
• •
computer networks, etc.;
telephone communication with the respective services of Korsakov and YuzhnoSakhalinsk; provision of safe working conditions.
Maintenance Maintenance will be carried out approximately once every month. There will be a three month period, however, during the winter months when the TLU may be difficult to access for maintenance visits. No maintenance dredging will be carried out.
2.7
DECOMMISSIONING AND ABANDONMENT
2.7.1
Overview Decommissioning refers to the process of dismantling the operating assets after completion of the operating life cycle. Due to long-term operation of the offshore project components (25 years) the proposals for decommissioning will be specified towards the end of the life of the project. When developing the decommissioning plan, the following factors will be considered:
2.7.2
•
the requirements of federal and regional legislation and standards in place at the time of decommissioning;
•
the social and economic status of Sakhalin and the demands of the local population; and
•
the condition of terrestrial and marine flora and fauna.
Generic Decommissioning Procedures Decommissioning procedures at this stage are generic and will generally include the following activities.
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Volume 5 Chapter 2 Project Description
2.7.3
• •
Operating processes will be systemically shut down in a safe manner.
•
The fate of the emptied and cleaned structures and equipment will then be decided by a feasibility study to determine the best environmental and economic solution consistent with international oil and gas industry practice.
Liquid and solid contents/wastes will be removed for treatment and disposal. For pipelines and tanks this will entail flushing and cleaning to remove oils and gases.
LNG Plant and Jetty. Removal of the LNG plant (if removal is required) will include the decommissioning of process lines, storage tanks, utilities area and the administration building. Much of the area will be concrete and a suitable alternative use for the area will be sought. Decommissioning of the LNG Jetty (if removal is required) will include equipment decommissioning. The jetty will be carefully dismantled. Components will be recycled as far as possible. Where this is not possible, waste materials will be disposed of according to the waste management procedures currently employed at that time. An environmental survey will be conducted in order to establish any environmental damage and appropriate mitigation measures.
2.7.4
OET & TLU Removal of the OET (if removal is required) will include the decommissioning of storage tanks, transfer lines and the wastewater treatment plant. Given the available infrastructure a suitable alternative use for the area will be sought. Decommissioning of the Tanker Loading Unit (if removal is required) will involve deballasting the legs and bases and refloating the TLU. Components will be recycled as far as possible. Where this is not possible, waste materials will be disposed of according to the waste management procedures currently employed at that time. An environmental survey will be conducted in order to establish any environmental damage and appropriate mitigation measures.
2.7.5
Oil Export Pipeline On completion of the project, the subsea pipelines will be depressurised, purged and cleaned. The pipelines will preferentially be left in place, however this may not be possible. Where removal is desired, an environmental survey will be carried out to determine the extent of the disruption to marine flora and fauna.
2.8
WASTE MANAGEMENT PLAN Sakhalin Energy Investment Company (SEIC) has established as a requirement of the Sakhalin II development, that all its operations comply with the Solid Waste Management Plan, (SWMP). The SWMP has been established as a means of managing waste generating and disposal activities and operations and covers a range of waste materials that SEIC assumes responsibility for. The SWMP has been developed in compliance with policies that together form the basis of the Health, Safety and Environmental Management System of the Company. The SWMP establishes, as a minimum standard, compliance with all applicable Russian Federation Laws and Federal and Local administration policies.
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Volume 5 Chapter 2 Project Description The SWMP will involve the development of an integrated approach comprising both new and upgraded facilities that best fit the requirements of the overall project construction and operational development schedule. Please refer to Volume 1, Section 6.2 for a detailed overview of the SWMP.
2.9
OIL SPILL RESPONSE PLANNING In support of the Corporate Oil Spill Response Plan (OSRP), each asset will have its own site plan which will meet the specific local requirements. OSRPs for the TLU and OET have been developed and address the following key points:
• • • • • • • • • • • • • • • • •
regulatory framework; environmental baseline and potential impacts of oil pollution; risk assessment; fate of modelling of spilled oil; spill response team organisation; initial response, notification and communication; response resources; response objectives and strategies; tracking, surveillance and forecasting; offshore response; coastal zone response; river response; response on land; wildlife management; waste management of spills; HSE Guidelines; and training.
In the event of an oil spill, the OSRP will be adopted to ensure that impacts to the environment are minimised and areas of special value are afforded priority protection. These plans will be updated at least six months prior to operation. It is proposed that they are updated prior to construction. Please refer to Volume 1, Section 6.6 for a detailed overview of the OSRP.
2.10
INVENTORY OF EMISSIONS, DISCHARGES AND WASTES
2.10.1
Emissions to Air Overview Emissions generated during construction and operation of the LNG plant, LNG Jetty, OET, OET pipeline and TLU are described in the following sections.
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Volume 5 Chapter 2 Project Description Construction Emissions to air will be associated with the following activities:
• • • •
combustion emissions from operation of construction machinery; particulate (dust) emissions from exposed areas; marine vessel emissions and generator operation; and pipe welding operations.
These activities will result in the following main emissions during construction:
• • • • •
sulphur dioxide (SO2); nitrogen dioxides (NOx); carbon monoxide (CO); hydrocarbons; and particulate matter.
Emissions during constructed will vary in magnitude, frequency, and duration for the various construction activities required. It is therefore difficult to accurately quantify emissions associated with construction of the project components in Aniva Bay. Operation During operation, emissions to air arise from the following activities.
• •
Process emissions from the LNG plant.
•
It is anticipated that approximately 144 LNG carrier vessels will dock at the LNG jetty per year (per LNG train). Ship loading time will be approximately 16 hours for a 145 000 m3 LNG carrier. Three tugboats will be required to assist with turning.
•
Tanker loading operations have been identified as a significant potential source of VOC emissions. VOC emissions are estimated at about 65 t with the loading of a typical cargo of 600 000 bbls.
•
One 150 kW diesel generator will provide an emergency power supply at the TLU.
It is estimated that approximately 95 crude oil tankers (peak production) will dock at the TLU per year. Ship loading time is anticipated to be approximately 22 hours requiring support from one tug boat. A small support craft will also be active for 4 hours during connecting and disconnecting to and from the TLU.
The following principles have been adopted in relation to control emissions from the LNG/OET facility:
•
A ‘no venting’ principle with respect to the disposal of gas from process units and other equipment will apply to the LNG plant. Some form of venting, however, may be required in special cases where routing to the flare is prohibited for safety or other reasons.
•
The acid gas from the regenerator column (containing hydrocarbons) will not be emitted directly to the atmosphere but will be routed to a thermal combustion unit.
•
To minimise emissions of hydrocarbons from sources such as pumps, seals, valves, the project will use closed draining, installation of dry seals on compressors and where applicable double seals for hydrocarbon pumps.
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A ‘no flaring’ principle for disposal of hydrocarbon streams applies to normal plant operations. During start-up and shut-down controlled flaring is part of the operational procedure. The operations philosophy shall cover all situations where gas flaring is needed as a consequence of operational upsets.
• •
Low-NOx burners will be used for all power generation facilities and furnaces. Low sulphur diesel fuel will be used, preferably of max 0.05% sulphur content, depending on availability on Sakhalin.
The anticipated emissions associated with the operation of the LNG plant are provided in Table 2.6 and Table 2.7. Table 2.6
LNG Plant Emissions with One LNG Train Pollutant
Emission volume, t/yr
Nitrogen oxide (as NO2) Sulphur dioxide Hydrogen sulfide Carbon oxide
119.441 513.551 0.726 3452.220
Source Final 5-9_1-App-E_1-E-P12 Table 51
Table 2.7
Total Emissions from LNG Facility with Two LNG Trains Pollutant
Emission volume, t/yr
Nitrogen oxide (as NO2) Sulphur dioxide Hydrogen sulfide Carbon oxide
180.046 923.306 3.030 6619.422
Source Final 5-9_1-App-E_1-E-P12 Table 52
The anticipated vessel emissions associated with the operation of the LNG plant are detailed in Table 2.8. Table 2.8
Vessel Emissions Associated with Operation of the TLU and LNG Jetty Construction Activity
SO2 t/yr
NOx t/yr
CO t/yr
VOCs t/yr
LNG Tanker Crude Tanker Support Ship Tugs (mooring) Tugs (turning) Tugs (idle) LNG Tanker Tugs TOTAL
164.2 83.9 0.03 0.69 0.17 0.54 249.53
319.1 163.1 0.85 19.06 4.71 14.65 56.68 578.15
1.73 10.9 0.06 1.27 0.32 1 3.8 19.08
0.29 59.61 0.02 0.41 0.1 0.33 1.24 62
Emissions during two LNG Train Operation
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Volume 5 Chapter 2 Project Description 2.10.2
Discharges Overview Liquid effluents generated during construction, commissioning and operation of the OET pipeline, TLU and LNG Jetty are described in the following sections. Construction The principal effluents discharged to the marine environment from vessels are predicted to comprise of:
• • •
greywater (2) from sanitary effluent eg sewage, wash water and laundry discharges; drainage water eg bilge water (3) and machinery spaces drainage; service water/cooling water.
In addition, there will also be the discharge of approximately 4,500 m3 ballast water from the TLU. All vessels will comply with the requirements of MARPOL (ie the installation of oil/water separators for bilge and machinery spaces, an oil record book and an International Pollution Prevention (IOPP) Certificate (4)). Discharges of bilge water or drainage from machinery spaces will be treated to the specification of 15 parts per million (ppm) oil content or lower prior to overboard discharge. The vessels will also be equipped with adequate grey and blackwater (5) treatment facilities. Untreated sanitary wastes will be dealt with according to MARPOL convention, ie waste will not be disposed of to sea within 12 nm of the coast. If the vessels are between 4 nm and 12 nm from the coast, the sewage will be treated to ensure that hydrocarbons and biological oxygen demand (BOD) do not exceed 15 and 60 mg l-1 respectively. Cooling water and surplus service water eg from the drinking water generation system may contain residual chlorine (typically less than 1 part per million for potable water generation systems). Other effluents discharged during survey operations eg deck drainage due to rainfall or spray run-off, and effluents from deck cleaning operations may contain trace amounts of oil. The offshore contractor will ensure that all discharges from construction vessels are in accordance with the standards set out in MARPOL and Russian Legislation. Commissioning Approximately 4 512 m3 filtered seawater with additives will be discharged to sea near the pipeline landfall in Aniva Bay.
(2)
Greywater is water from culinary activities, bathing and laundry facilities, deck drains and other non- oily waste water drains (excluding sewage).
(3)
Bilge water is water generated in the bilge of the ship’s machinery spaces and thereby contaminated with oil and other substances, some of which may be harmful.
(4)
References 36 and 37 of MARPOL 73/78 Annex 1, 1973 as amended by the 1978 Protocol.
(5)
Blackwater is sewage and other wastes from toilets and urinals together with drainage from medical premises eg dispensaries or medical facilities.
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Volume 5 Chapter 2 Project Description Operation The following above ground and underground drainage systems will be installed at the LNG plant and OET;
• • • •
entirely oil free (EOF); accidentally oil contaminated (AOC); continuously oil contaminated (COC); and domestic sewer system (COC).
Entirely oil free surface water will be collected in open concrete drains throughout the site and stored in the firewater ponds in the western portion of the site. The firewater ponds will have an outfall to Aniva Bay to remove excess water. The AOC drainage system will collect surface water effluents through surface drain channels. The effluents will flow into the controlled discharge facility located in the effluent treatment area, near the OET. The system is designed for a maximum flow rate of 70% fire water consumption, presuming loss by evaporation of the other 30%. The COC drainage system will use localised water catch basin to contain COC effluents. These will accumulate in collecting sumps and then transported by truck to the primary effluent treatment facility. The domestic sewer system will receive wastes generated by the administration area buildings and service (toilets, showers and canteen) buildings. Domestic sewage will be routed by gravity to the sewerage lift station, where it will be transferred by pipeline to the effluent treatment facility. The effluent treatment plant is designed for collection and primary treatment of COC and AOC effluent. AOC will flow to the controlled discharge facility for discharge to the firewater ponds or for further treatment depending on quality. The controlled discharge facility will include a ‘first flush’ compartment and oil skimming facilities. All COC effluents transported by vacuum trucks will be discharged into the buffer tank. The buffer tank will be located inside the effluent treatment building to ensure against freezing. Following buffering, treated effluent will be discharged to Aniva Bay from an outlet approximately 400 m from the coast. SEIC has proposed effluent standards for discharges of treated water from the LNG and OET facility to Aniva Bay, these are detailed in Table 2.9. During normal operation, discharges from vessels will comprise mainly vessel discharges as described for construction vessels. The offshore contractor will ensure that all discharges from support vessels during operation are in accordance with the standards set out in MARPOL and SEIC guidelines. Ballast water will be handled according to IMO. Mid ocean refreshment will be considered. Ballast water will be discharged into Aniva Bay during cargo loading. Routine LNG Jetty discharges will be limited to uncontaminated wastewater (rainwater, firewater, storm water and other water not contaminated with hydrocarbons). Uncontaminated wastewater will be drained to sea via drains and gutters.
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Volume 5 Chapter 2 Project Description Table 2.9
Aqueous Effluent standards for the LNG/OET Facility Limits (mg/l)
World Bank Standards1
Proposed Sakhalin LNG/OET Standards for Effluent
Temperature (°C) pH Oil & Grease Phenol Nitrogen (as total N) TSS BOD5
