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Offshore Design & Installation | An Overview of Design, Analysis, Construction and Installation of Offshore Petroleum Platforms Suitable for Cyprus Oil/Gas Fields
Summary of Offshore Construction Project stages
Similar to the other fields of activities, the offshore platform construction services can be provided on a turn-key basis, i.e. covering investment feasibility studies, basic and detailed design, and procurement, installation of steel structures and equipment, and commissioning. All or any of the above listed work stages can be performed under the supervision of an independent certifying authority followed by the issue of a certificate of class.
Basically an offshore platform construction project includes the following phases:
Investment feasibility studies
Construction site survey including diving inspections of installation locations
Conceptual, basic and detailed design
Platform element strength calculations
Design approval by the regulating authorities
Procurement
Fabrication of steel structures
Preparation of platform elements transportation and offshore installation procedures
Loadout, transportation and installation operations
Commissioning |
Offshore Design & Installation | Environmental parameters
The design and analysis of fixed offshore platforms may be conducted in accordance with the APIs Recommended Practice for Planning, Designing, and Constructing Fixed Offshore Platforms Working Stress Design (API-RP-2AWSD). The latest revision of API-RP-2A-WSD is the 21st edition dated December 2000. The API specifies minimum design criteria for a 100-year design storm.
Helicopter landing pads/decks on offshore platforms must conform to API RP-2L (latest edition being the 4th edition, dated May 1996) |
Offshore Design & Installation | Design of offshore fixed platforms
The most commonly used offshore platforms in the Gulf of Mexico, Nigeria,
California shorelines and the Persian Gulf are template type platforms made of steel, and used for oil/gas exploration and production (Sadeghi 1989, 2001).
The design and analyses of these offshore structures must be made in accordance with recommendations published by the American Petroleum Institute (API).
The design and analysis of offshore platforms must be done taking into consideration many factors, including the following important parameters:
Environmental (initial transportation, and in-place 100-year storm conditions)
Soil characteristics
Code requirements (e.g. American Institute of Steel Construction AISC codes)
Intensity level of consequences of failure
The entire design, installation, and operation must be approved by the client. |
Offshore Design & Installation | Different analyses needed for template platforms
Different main analyses required for design of a template (jacket) type platform are as follows (Sadeghi 2001):
In-place analysis
Earthquake analysis
Fatigue analysis
Temporary analysis
Load out analysis
Transportation analysis
Appurtenances analysis
Lift/Launch analysis
Upending analysis
Up righting analysis
Unpiled stability analysis
Pile and conductor pipe drivability analysis
Cathodic protection analysis
Transportation analysis
Installation analysis.
To perform a structural analysis of platforms, the following software may be used (Sadeghi 2001):
SACS, FASTRUDL, MARCS, OSCAR, StruCAD or SESAM for structural analysis.
Maxsurf, Hydromax, Seamoor for hydrodynamics calculations.
GRLWEAP, PDA, CAPWAP for pile analyses. |
Offshore Design & Installation | Structural analysis
To perform a structural analysis of a platform, a structural model of the structure is developed normally using one of the following common software packages developed for the offshore engineering: SACS, FASTRUDL, MARCS, SESEM, OSCAR or StruCAD (Sadeghi 2001).
A model of the structure should include all principal members of the structure, appurtenances and major equipment.
A typical offshore structure supported by piles normally has a deck structure containing a Main Deck, a Cellar Deck, Sub-Cellar Deck and a Helideck. The deck structure is supported by deck legs connected to the top of the piles. The piles extend from above the Mean Low Water through the mudline and into the soil.
Underwater, the piles are contained inside the legs of a jacket structure which serves as bracing for the piles against lateral loads. The jacket may also serve as a template for the initial driving of the through leg piles (The piles may be driven through the inside of the legs of the jacket structure). In the case of using skirt piles the piles may be driven from outside of the legs of the jacket structure. The structural model file consists of:
The type of analysis, the mudline elevation and water depth.
Member sizes
Joints definition.
Soil data (i.e. mudmat bearing capacity, pile groups, T-Z, P-Y, Q-Z curve points).
Plate groups.
Joint coordinates.
Marine growth input.
Inertia and mass coefficients (CD and CM) input.
Distributed load surface areas.
Wind areas.
Anode weights and locations
Appurtenances weights and locations
Conductors and piles weight and location
Grouting weight and locations
Load cases include dead, live and environmental loading, crane loads, etc. |
Offshore Design & Installation | Any analysis of offshore platforms must also include the equipment weights and a maximum deck live loading (distributed area loading), dead loads in addition to the environmental loads mentioned above, and wind loads. Underwater, the analysis must also include marine growth as a natural means of enlargement of underwater projected areas subject to wave and current forces.
The structural analysis will be a static linear analysis of the structure above the mudline combined with a static non-linear analysis of the soil with the piles.
Additionally, checks will be made for all tubular joint connections to analyze the strength of tubular joints against punching. The punching shear analysis is colloquially referred to as joint can analysis. The Unity Checks must not exceed 1.0. All structural members will be chosen based on the results of the computer-aided in-place and the other above-mentioned analyses. The offshore platform designs normally use pipe or wide flange beams for all primary structural members.
Concurrently with the structural analysis the design team will start the development of construction drawings, which will incorporate all the dimensions and sizes optimized by the analyses and will also add construction details for the field erection, transportation, and installation of the structure. |
Offshore Design & Installation | The platforms must be capable of withstanding the most severe design loads and also of surviving a design lifetime of fatigue loading. The fatigue analysis is developed with input from a wave scatter diagram and from the natural dynamic response of the platform, and the stiffness of the pile caps at the mudline by applying Palmgeren-Miner formula (Sadeghi 2001). A detailed fatigue analysis should be performed to assess cumulative fatigue damage. The analysis required is a spectral fatigue analysis or simplified fatigue analysis according to API.
API allows a simplified fatigue analysis if the platform (API 1996):
Is in less than 122 m (400 ft) water depth.
Is constructed of ductile steel.
Has redundant framing.
Has natural periods less than 3 seconds. |
Offshore Design & Installation | Client permits and approval process
All offshore platform designs (whether structural or facilities) must be approved by the Client. The analysis results must demonstrate that the platforms have been designed using standard accepted methods and that the structures will be able to perform adequately in accordance within the design parameters as prescribed by the API RP-2A and the American Institute of Steel Construction (AISC) codes or other codes.
The permit application package must contain an analysis summary (and explanation of the modifications, if applicable) and show the maximum foundation design loads, and unity checks. It must have attached copies of the soil report, and the certified structural construction drawings. The drawings and analyses and the complete package must be signed by the Consultant Lead Engineer, and the Project
Manager and be submitted to the Client. |
Offshore Design & Installation | Fabrication (Construction)
The API RP-2A lists the recommended material properties for structural steel plates, steel shapes and structural steel pipes. As a minimum, steel plates and structural shapes must conform to the American Society for Testing and Materials (ASTM) grade A36 (yield strength, 250 MPa) (AISC). For higher strength applications, the pipe must conform to API 5L, grade X52.
All materials, welds and welders should be tested carefully. For cutting, fitting, welding and assembling, shop drawings are necessary. A suitable fabrication yard on shorelines should be selected. This fabrication yard must be well equipped and be large enough for fabrication and loadout of platforms |
Offshore Design & Installation | Load out and transportation
The offshore structures are generally built onshore in fabrication yards for cost savings and to facilitate construction. Upon completion, these structures have to be loaded out and be transported offshore to the final assembly site, on board a vessel.
Therefore an offshore design and analysis of a structure must include a loadout and transportation analysis as well.
All stages of the loadout of the structure should be considered and the stresses checked. Before transportation of the platform, a seafastening analysis is performed and the platform parts (jacket, decks, and appurtenances) are fastened to the barge.
In the transportation analysis, the motions of roll, pitch, heave and yaw should be considered.
To perform a transportation analysis, the engineer must have an environmental report showing the worst seastate conditions during that time of the year throughout the course of the intended route. Generally, based on Noble Denton criteria for transportation, it may assume a 20 degree angle of roll with a 10 second roll period, and a 12.5 degree angle of pitch with a 10 second period, plus a heave acceleration of 0.2 g (Sadeghi 2001). |
Offshore Design & Installation | Installation
All the structural sections of an offshore platform must also be designed to withstand the lifting/launching, upending, uprighting and other installation stresses.
The jackets must be designed to be self-supporting during the pile driving and installation period. Mudmats are used at the bottom horizontal brace level which will be transferred to the temporary loads to the seabed surface and soil before completion of the pile driving operation. The mudmats are made of stiffened steel plates and are generally located adjacent to the jacket leg connections for obvious structural reasons.
The piles must be designed to withstand the stresses during pile driving operation.
The piles are installed in sections. The first section must be long enough to go from a few meters above the top of the jacket leg to the mudline (in this regard setup and self weight penetration of pile should be taken into account). The other sections (add-ons) must be field welded to the first section at an elevation slightly higher than the top of the jacket legs When all the piles have been driven to the required design target penetrations, they will be trimmed at the design top of pile elevation. Te jacket will then be welded to the piles about 1.0 meters or less below the top of the piles around scheme plate. |
Oil & Gas Projects Australia | Construction of the Darwin Liquefied Natural Gas (LNG) plant began in June 2003 and the plant was commissioned in the first quarter 2006 when LNG sales commenced. The Darwin LNG facility has a single tank for LNG storage and is one of the largest above-ground LNG tanks constructed to date with a working capacity of 188,000 cubic meters.
Approximate value: $1.75 billion
Construction started: June 2003
First production: Q1 2006
ICN Involvement included:
Advise the project on engineering standards such that they represent Australian. standards and do not inadvertently preclude Australia and New Zealand participation.
Facilitate maximum Northern Territory business content.
Assist the project in advising Australian industry of project opportunities in a timely manner.
Assist the project in pre-qualification of Australian and New Zealand suppliers.
Identify with the project NT regional and indigenous business capabilities. |
Oil & Gas Projects Australia | The Field, which is 100% owned and operated by Eni, will deliver gas to the Northern Territorys Power Water Corporation (PWC) for over a period of 25 years, with supply rising to 18,000 boe/day over the life of the contract.
Approximate value: $500 million
Construction started: 2006
First production: 2009
ICN Involvement included:
Identification of first, second and third tier, capable and competitive Australian suppliers of plant, equipment and services.
Assist in the briefing and project requirement information dissemination to Australian industry.
Feedback Australian industry expertise into the design and engineering activities.
Identify opportunities for Australian industry involvement in overseas supply chains. |
Oil & Gas Projects Australia | Discovered in 1995, the Bayu-Undan field plays a vital role in ConocoPhillips Australian operations. Bayu-Undan is a gas-condensate field located offshore in the Timor Sea within the Joint Petroleum Development Area (JPDA). The field is 250 kilometres south west of Suai in Timor-Leste and 500 kilometres north west of the Northern Territory in Australia. ConocoPhillips operates the field on behalf of co-venturers Santos, Inpex, ENI, Tokyo Electric and Tokyo Gas.
We are proud of our contribution to the Timor-Leste economy and community. The Bayu-Undan project has contributed more than US$18 billion in taxes and other payments to the Timor-Leste Petroleum Fund since 2004. We have also invested a further $77 million through local content activity including employment and training, procurement and community investment. Click here for more information on our activities in Timor-Leste.
The Field
The Bayu-Undan field includes a central production and processing complex (CPP) comprised of two platforms Drilling, Production and Processing (DPP); and Compression, Utilities and Quarters (CUQ). The field also comprises a Floating, Storage and Offloading facility (FSO) two kilometres from the CPP and an un-manned wellhead platform (WP1) seven kilometres east of the CPP.
Bayu-Undan field development is undergoing three phases. Phase one commenced in 2004, with the construction of offshore facilities to produce and process condensate, propane and butane (LPGs). This phase also saw a total of 13 wells drilled for production, gas injection and water disposal.
Phase two, approved in the 2003 amended Bayu-Undan Development Plan, completed in 2006 saw the installation of a subsea pipeline and the LNG production facility. The 500 kilometre 26 pipeline supplies gas from Bayu-Undan for processing into a 3.7 MTPA design capacity LNG facility Darwin LNG, located in the Northern Territory of Australia . LNG is loaded onto specialised tankers for transport to international markets. The LNG facility is operated by ConocoPhillips on behalf of the same co-ventures as Bayu-Undan.
Phase three development will be completed in stages, with the first part commencing in 2014. Consisting of drilling and tying-back to the Bayu-Undan facility, with two subsea production wells providing production assurance for the field. Ongoing stages include the evaluation of drilling additional production wells beyond 2015.
We are proud of the diverse workforce that supports the Bayu-Undan operation, which includes people from a range of nationalities and backgrounds including Australia and Timor-Leste |
Oil & Gas Projects Australia | Karratha gas plant.
In 2008, the facility capacity was increased to 16.3 million tonnes per year with the commissioning of a fifth, 4.4 million tonnes per year LNG production train. As well as processing gas for export, the facility supplies domestic supplies to consumers and businesses in Western Australia. The facility also processes condensate which is extracted from the gaseous hydrocarbons during processing
Karratha LNG Plant, Australia
The Karratha LNG plant in Western Australia, 1,260km north of Perth, is one of the largest in the country, producing around 12 million tons of LNG a year for the Japanese and South Korean markets and also supplying 65% of the gas required by the Western Australian domestic market.
The plant, which is operated by Woodside Energy Ltd for the North West Shelf Venture (NWSV), has four trains which were opened between 1989 and 2004 (1989 LNG trains one and two, 1992 LNG train three, 2004 LNG train four) although the plant was first commissioned for processing domestic gas in 1984. There are two 130km trunk lines to carry the gas to the shore, five 125,000 bpd condensate stabilisation units and two LPG fractionation units.
"The Karratha LNG plant is one of the largest in Australia."
The plant receives gas from several well known fields including Goodwyn, Waneae, Rankin, North Lambert, Hermes and Cossack and also tiebacks from Echo-Yodel and Perseus. The facility has 430 staff including 240 permanent staff and 190 contractors.
The NWSV includes: Woodside Energy Ltd. (16.67%) (Operator), BHP Billiton (North West Shelf) Pty Ltd (16.67%), BP Developments Australia Pty Ltd (16.67%), ChevronTexaco Australia Pty Ltd (16.67%), Japan Australia LNG (MIMI) Pty Ltd (16.67%) and Shell Development (Australia) Proprietary Limited (16.67%).
LNG loading
The LNG from the terminal is exported from an 850m jetty which has a loading rate of 10,000m³ an hour. On average the loading of an LNG ship takes about 22 hours.
The LPG and condensate produced from the site are exported from an alternative 450m jetty. Propane and butane products are loaded at about 1,500m³ an hour and condensate at 1,000m³ an hour. |
Oil & Gas Projects Australia | Karratha expansion
In April 2007 Woodside Energy announced their phase V expansion at the Karratha gas plant, which included the addition of a fifth liquefaction train (4.4 million tons per annum) and also other infrastructure including: acid gas recovery unit, the third fractionation unit for the site, train five jetty extension spur and loading facility, two new gas turbine power generation units, fuel gas area extension, a third boil-off gas compressor for the site, a control system upgrade and tie-ins to existing facilities.
The A$2.6bn project was carried out by a joint venture between Foster Wheeler Energy and Worley Parsons. ABB have supplied 15 Venturi flowmetres for the project for gas flow measurement. The new LNG train was open and in operation delivering loads of LNG for export on 30 September 2008 following the commissioning process currently underway.
Modular design
The LNG phase V expansion entered the EPC (Engineering, Procurement and Construction) phase in March 2005. During the final detailed design stages it was decided to adopt a modular approach to the construction of the new train and also to follow the design of the fourth train quite closely (phase IV expansion project). In the end the construction resulted in about 60% modular methods.
One of the major problems was the modularisation of the complex pipe work at the plant, which required 75 different large structures and more importantly how best to fit the pipe work together from the different modules.
"The Karratha LNG plant provides 65% of the gas required by the Western Australian domestic market."
This design work was carried out by Foster Wheeler Energy at their Reading offices and involved specialised computer-generated modelling.
By July 2005 construction of the modules had started at the Batam Yard in Indonesia and by the end of the first half of 2006 the module construction was almost completed with deliveries occurring in the third quarter of 2006.
The site at Karratha had already been prepared and was ready to accept the modules by October 2006.
Modules were transported by self-propelled motorised trailers from the jetty (after delivery by roll-on roll-off ship) over a few kilometres to the site where they were offloaded directly onto the prepared foundations (five modules weighed in excess of 1,000t but most weighed around 300t, module weight range was from 35t1,800t).
The tolerances of the engineering and the site civil engineering allowed the modules to fit together millimetre perfect. There have been 17 module shipments, the heaviest being 2,400t (total module weight was 18,000t).
The installation has four jetty loading arms, eight main compressors, one gas turbine generator and a 33kV substation. |
Oil & Gas Projects Australia |
Ichthys Offshore Integrated Project Management Support Services (IPMS)
Client
Ichthys Joint Venture
Location
Offshore Darwin, Northern Territory
JV
Clough Doris
Scope of Work
Integrated Project Management Services overseeing the detailed design, procurement, fabrication, commissioning, tow to site, and offshore hook-up of the Central Processing Facility and FPSO. |
Oil Gas Commissioing & Startup Challenges | The Pluto gas field was discovered in early 2005 in the North West Shelf area, approximately 180 km from the Burrup Peninsula and 100 km from the northern coast of Western Australia. Pluto LNG comprises an onshore processing plant on the Burrup Peninsula and associated LNG and condensate storage and export facilities. The onshore plant is linked to a series of offshore subsea wells and offshore riser platform via a 180km trunkline. Woodside Energy Ltd as Operator of the North West Shelf Joint Venture has successfully commissioned, started up and operated five LNG trains, however Pluto LNG is the first green-field LNG plant that Woodside Energy Ltd has started up in over 20 years. This paper discusses the challenges faced by the Commissioning and Startup Team and the solutions used to overcome them. |
Oil Gas Commissioing & Startup Challenges | Pluto LNG processes gas from the Pluto gas field, located in the Carnarvon Basin about 190 km north-west of Karratha, in north-west Western Australia. It is 90% owned and operated by Woodside with the remaining 10% owned in equal share by Tokyo Gas and Kansai Electric.
The Pluto field was discovered in 2005. The Greater Pluto region is currently estimated to contain 5 trillion cubic feet (Tcf) of dry gas reserves.
Project approval was granted in 2007 for the development of a single greenfields LNG train with associated storage, offloading, utilities and offshore infrastructure. The LNG train is propane / mixed refrigerant design with a capacity of 4.3 million tonnes per annum.
Commissioning of the first equipment began in 2010. The offshore facilities commenced production in late 2011, with the first LNG cargo shipped in May 2012.
Initial production has been extremely successful, with a facility utilisation of over 90% achieved in the second half of 2012.
The challenges associated with the Pluto LNG facility start-up included:
Integration of simultaneous onshore and offshore start-ups,
Early introduction of gas and management of simultaneous commissioning and construction activities
Import of first fill propane and generation of mixed refrigerant within the LNG train
Early cool-down of the storage and loading facilities
Managing a number of equipment items which were new to Woodside as operator. |
Oil Gas Commissioing & Startup Challenges | This paper describes the innovative methods used to tackle these challenges and describes the processes taken to ensure the start-up was a success.
This paper describes a number of the technical challenges associated with the Pluto LNG start-up and the solution methods adopted by Woodside to overcome or deal with these challenges. A brief description of the facilities and an overview of the start-up logic and organisation is provided as background. A number of the technical challenges are then described in detail followed by a discussion on the success of the initial Pluto LNG production phase. |
Oil Gas Commissioing & Startup Challenges | Facilities Description
The initial phase of Pluto LNG comprises an offshore platform in 85m of water, connected to five subsea wells on the Pluto gas field in 800m of water. Offshore MEG (mono-ethylene glycol) injection is used to prevent subsea hydrate formation. Gas, condensate and MEG flow from the subsea wells to a not-normally-manned offshore platform through dual 20-inch 27km long flowlines. The offshore platform contains hydraulic equipment (for subsea well control), pig-launching facilities and high-integrity pressure protective equipment for the downstream trunkline.
The production fluids are then piped through a 180km trunkline to the onshore facility, located on the Burrup Peninsula near Dampier in Western Australia. The fluids are separated into their three phases (gas, MEG and condensate) in an onshore slugcatcher.
Gas from the slugcatcher is routed to the LNG train which consists of an acid gas removal unit, molecular sieves, mercury removal vessel, liquefaction unit and associated fractionation train. The liquefaction train uses C3 / MR technology and contains two fixed speed refrigerant compressors (propane and mixed refrigerant) which are driven by Frame 7 gas turbines
LNG from the train is pumped to two LNG tanks with a combined capacity of 240,000 m³.
Condensate from the slugcatcher is routed to 2 x 100% condensate stabilizers and stabilized condensate sent to one of 3 condensate tanks.
MEG from the slugcatcher is routed to a MEG regeneration facility where the produced water is removed before the MEG is pumped back offshore via a MEG injection line. The water is treated to very high purity in an effluent treatment plant before being discharged into the ocean.
A nitrogen rejection unit is provided to remove nitrogen from the LNG train end-flash gas. This nitrogen is used to provide the facility nitrogen requirements, while the reduced-nitrogen end-flash is used to supply fuel gas to the facility.
Power generation is supplied by 4 Frame 6 gas turbines, two of which are supplied with waste heat recovery units to supply heat to the plant utility systems via a hot water circuit. |
Oil Gas Commissioing & Startup Challenges | Start-Up Organisation
Construction and commissioning of the onshore facilities to the point of hydrocarbon introduction was managed by the onshore managing contractor, a Foster-Wheeler Worley Parsons Joint Venture. The start-up of the facility was carried out on an area basis. At the time of hydrocarbon introduction control of each area was transferred to Woodside, and start-up took place using Woodside personnel, processes and systems.
The Woodside start-up team consisted largely of operational personnel with start-up and operational experience from other recent Woodside operated projects (North West Shelf Project LNG Phases IV and V and the Otway Gas Plant). Lessons learnt from the start-up and operation of these facilities were identified and embedded into the start-up procedures and methodologies for Pluto LNG.
In addition to leveraging Woodsides own start-up experience, lessons learnt were gathered from other sites. This was done either through visits to other operational sites or through lessons-learned discussions with vendors and other operating companies. Woodside assessed these lessons and incorporated into the Pluto start-up methodologies where they were considered to represent best practice. |
Oil Gas Commissioing & Startup Challenges | Start-Up Logic
The high level Pluto LNG start-up logic is shown in figure 3. Initial commissioning was restricted to the diesel generation equipment and essential utilities (instrument air, flare system, nitrogen, and fire water) with the aim of preparing the plant for introduction of domestic gas.
The introduction of domestic gas allowed start-up of the main power generation facilities which broadened the scope of commissioning activities which could be carried out. As described later in this paper domestic gas was also used to allow early commissioning and start-up of the offshore facilities.
Also of note in the start-up logic is the importance of early start-up of the ETP and MEG systems, as these systems were required to complete early start-up of the offshore system. |
Oil Gas Commissioing & Startup Challenges | Use of Domestic Gas for Commissioning Purposes
The Pluto LNG Park is located adjacent to a domestic gas pipeline. A tie-in to this pipeline was made during the construction of the facility which allowed the use of domestic gas for initial commissioning of the flare and fuel gas systems, power generation facilities, refrigerant compressors and the offshore system.
Initial power generation for commissioning activities was provided using the emergency diesel generators (EDGs) which provide black start capability during normal plant operation. The EDGs have limited capacity so no large electric motors could be run prior to start-up of the main power generation facilities.
The use of domestic gas as fuel gas allowed early start-up of the Frame 6 gas turbines, thus reducing diesel consumption and expanding the range of commissioning activities which could be conducted early. The power generation facilities are also equipped with waste heat recovery units which provide hot water to the utilities areas of the plant, this allowed early testing of heated water users in the MEG system and effluent treatment plant.
The LNG train gas turbines and compressors were commissioned using domestic gas as fuel gas. During the coupled compressor runs the compressors were run with air in the compressor circuit, rather than nitrogen which has been used previously. The use of air in the compressor circuit resulted in a significant risk reduction to personnel during this activity. |
Oil Gas Commissioing & Startup Challenges | Impact of Flare Tower Replacement
It was identified during the project construction phase that the main Pluto LNG flare tower required replacement as it was not adequately designed for the high wind loading that occurs during cyclonic conditions at the Pluto LNG site.
This issue had the potential to cause significant disruption to the start-up activities as without a flare stack hydrocarbons could not be introduced to the facility.
To address this issue a small temporary flare stack was installed which was specifically designed to allow introduction of domestic gas to site for commissioning activities. Figure 4 shows an image of this flare stack. |
Oil Gas Commissioing & Startup Challenges | MEG & ETP Commissioning
The onshore MEG system and the effluent treatment plant (ETP) posed a significant start-up challenge as they are complex process units which are not widely used in the LNG industry. Start-up of both the MEG and ETP were carried out early to ensure the maximum reliability of the units during the LNG train start-up.
During the design phase Woodside personnel visited other sites where MEG and ETP systems were in use to gather lessons associated with their start-up and operation. A number of operators and engineers in the start-up team had previous experience with MEG systems and in the water treatment industry. Woodside also utilised personnel and experience from the startup and operation of the Otway gas project MEG regeneration system, which Woodside operated between 2007 and 2009.
The decision to test the units early was worthwhile as unexpected challenges occurred in both the MEG and ETP systems during commissioning. The early commencement of testing meant that these issues were successfully resolved and both units were operating reliably prior to introduction of gas from offshore. |
Oil Gas Commissioing & Startup Challenges | MEG start-up
A first fill of MEG was shipped to the onshore system approximately 12 months before the commencement of the LNG train start-up. The volume of MEG imported was 9,000 m3.
The MEG was imported via chemical tanker which berthed at the Pluto LNG offtake jetty. The MEG was discharged from the tanker and routed to the permanent onshore MEG storage tanks via a hard-piped line which had been installed specifically for the first fill.
Following first fill the MEG was diluted with water down to a MEG concentration of 90%, this was done to reduce the viscosity and freezing temperature of the MEG prior to injection into the offshore system. Once the required MEG concentration was achieved the offshore MEG pipelines were filled from onshore.
A further portion of the MEG was diluted further to enable start-up and testing of the MEG reconcentration facilities. These facilities remove water from the MEG via distillation. Problems with the reliability of radar level instruments in the unit were encountered during this activity which was resolved by changing the transmitters with a different transmitter type. Following the resolution of these issues the unit was successfully ramped up. |
Oil Gas Commissioing & Startup Challenges | Effluent treatment plant start-up
The Pluto LNG effluent treatment plant contains a biological treatment facility for removal of MEG from the produced water. This bioreactor has limited capacity to remove hydrocarbons and so the ETP also contains corrugated plate interceptors and a macro-porous polymer extraction (MPPE) unit for removal of both free and dissolved hydrocarbons.
Following initial commissioning of all units using water it was necessary to establish the biological mass in the bioreactor. The unit was seeded using feed from the local waste-water treatment plant. Following seeding the unit was dosed with MEG to acclimatise and increase the biomass concentration.
Acclimatisation of the biomass proved challenging. The MEG initially used for bioreactor dosing contained a small concentration of amine corrosion inhibitor which proved toxic to the biomass. A further setback occurred when power was lost to the unit meaning that the aeration blowers on the bioreactor could not be operated.
Overall it took approximately 3 months to establish a healthy biomass. Once this milestone was achieved it was possible to route water from the MEG reconcentration facilities into the ETP and discharge the water.
At all times during the commissioning and start-up of the unit the discharge water from the ETP remained on specification. There have been no instances of off specification product being sent to the environment. |
Oil Gas Commissioing & Startup Challenges | Storage and Loading Cool-Down
Cool-down of the Pluto LNG storage and loading facilities was performed in advance of the LNG train start-up using cold gas and LNG supplied from an externally sourced LNG cargo.
The procedures for the LNG import and tank cool-down were developed using best practice techniques gathered from reviews of cool-down experience on other projects. Woodside also worked with the Pluto LNG joint venture partners, Tokyo Gas and Kansai Electric, to gather learnings from their experience with LNG import terminal start-up and operation.
During the cool-down operation LNG vapour and liquid were routed via the LNG loading arms to the onshore facilities. The temperature and flowrates of the vapour and liquid streams required for the cool-down were specified by the onshore facility and controlled from the ship.
The cool-down activity was completed in a number of stages. The total duration for these activities was approximately 8 days.
1. Cool-down of the loading lines and tanks with cold vapour
2. Filling of LNG loading lines with LNG
3. Cool-down of LNG tanks
4. Bulk unloading of LNG into cold tanks
The activity was carried out very successfully and without incident.
Following filling of the LNG tanks the in-tank LNG pumps were tested and LNG circulated through the loading lines to maintain cryogenic temperatures. This mode of operation continued until start-up of the LNG train had occurred. |
Oil Gas Commissioing & Startup Challenges | Propane
A first fill of refrigerant grade liquid propane was supplied via trucks from Perth, a distance of approximately 1600 km by road. The volume of propane delivered was sufficient to fill both the propane circuit and meet the initial propane fill requirements of the mixed refrigerant circuit. The propane was supplied via 23 truck deliveries.
Initial vapour purging of the sphere was carried out by routing liquid propane through a temporary vaporiser to the sphere. Loading of the propane sphere was then carried out using temporary unloading facilities.
Due to the hazardous nature of this activity a large exclusion area was applied to the propane storage facility and the activity was carried out late during the commissioning phase when site construction numbers had reduced. The activity was completed without incident and in sufficient time to allow a full propane inventory for the LNG train start-up. |
Oil Gas Commissioing & Startup Challenges | Ethane
Mixed refrigerant for the Pluto LNG start-up was generated using the Once through MR process. This process leverages from Woodsides operational experience of managing small internal leaks within the LNG train main cryogenic heat exchangers (MCHEs) and involves bleeding natural gas into the mixed refrigerant (MR) circuit whilst operating the MR compressors to circulate the gases through the refrigerant circuit.
This circulation of natural gas results in the formation of a temperature gradient in the main cryogenic heat exchangers, which is used to separate and remove the lighter components (methane and nitrogen). The continuous introduction of natural gas and removal of light components results in an increase in the composition of heavy components in the circuit and eventually the generation of significant quantities of ethane rich liquid refrigerant.
Using this method sufficient mixed refrigerant for a train start-up and ramp-up to 70% was made within two days, this represents a large improvement over traditional approaches for ethane generation which can take several weeks.
Further details of the once-through MR process are described in a separate paper being presented at LNG17. |
Oil Gas Commissioing & Startup Challenges | Commissioning and Start-Up of Offshore Facilities
Approximately 12 months prior to the LNG train start-up the offshore system was pressurised with natural gas taken from the domestic gas pipeline that runs close to the Pluto LNG facilities. Pressurisation of the trunkline and flowlines was required to provide sufficient backpressure to prevent low temperatures during initial flow from the Pluto LNG wells. The domgas was heated onshore with an electric heater to prevent low temperatures in the onshore and near-shore pipelines during the pressurisation.
Pressurisation of the offshore system also allowed early hydrocarbon commissioning of the offshore platform and subsea system with the offshore system being declared ready for start-up (RFSU) approximately 5 months prior to the LNG train start-up.
The Offshore RFSU milestone and the availability of supporting Onshore MEG export allowed the Pluto LNG wells to be started and well performance proven by packing and unpacking the Offshore system. This early offshore start-up resulted in a significant risk reduction during the LNG train start-up as the offshore system had already been successfully operated.
Careful monitoring of offshore pipeline condensate and MEG inventories was necessary during the initial operation of the wells. Any liquids from the wells accumulated in the flowlines and trunkline could not be removed by pigging until a flow path to the onshore plant was available, so it was important that the volume of liquids accumulated in the trunkline during this phase did not exceed the slugcatcher capacity. This monitoring was performed by a dedicated offshore engineering team who were located at the onshore facilities for the duration of the start-up. |
Oil Gas Commissioing & Startup Challenges | Flow assurance issues during first start-up
Wel stream gas was introduced to the onshore facilities once the onshore gas pre-treatment facilities were ready for start-up. The flow of gas to shore was initially at relatively low rates, as dictated by onshore fuel gas and commissioning requirements with offshore trunkline liquid inventories managed by periodic running of liquid management pigs.
Early running of pigs allowed start-up of the condensate stabilisation facilities to be carried out prior to LNG train start-up. Initial operation of the stabilisers was very successful with no significant issues found.
Estimates of trunkline liquid inventories and hence pigging trigger points during this period were made based on the cumulative production rates, building on the experience gained in the early Offshore commissioning. Although liquid volume estimates were found to be accurate, when pigging at low rates significant biasing was seen in liquid receipt between the two slugcatcher halves. This was manageable as pigging trigger points had been set early enough to allow for this type of uncertainty. The magnitude and direction of flow biasing changed with every pig run, however biasing has not been evident in subsequent pig runs at full production rates.
Based on experience from other sites there were concerns that significant volumes of solids (eg sand, corrosion products) would be bought to shore during initial pigging activities and additional temporary filtration capacity was installed in the MEG system to cater for this. Overall the number of filter change-outs in the Onshore liquid handling systems has been manageable which is attributed to successful management of the offshore system during hydro-testing and preservation which resulted in low formation of corrosion products, and good well completion management which resulted in relatively low levels of well solids. |
Oil Gas Commissioing & Startup Challenges | Ramp up of wells during LNG train start-up
Well ramp up rates were restricted during early operation to allow the wells to stabilise and minimise the risk of formation damage and sand production. During final cool-down and ramp-up of the LNG train there is a very rapid increase in natural gas flow which is faster than can be met by ramp-up of the wells. This discrepancy required the Offshore and Onshore start-up teams to work closely together to manage the competing flow, pressure and liquid management objectives. Ramp-up of the offshore system commenced several hours prior to LNG train ramp-up, with close monitoring of system flowrates and pressures required to ensure sufficient margin from high pressure limits on the trunkline and onshore facilities. Start-up plans had to ensure liquid inventory accumulation in the offshore system remained within a defined operating envelope to avoid flooding the Onshore facilities during the LNG ramp-up. |
Oil Gas Commissioing & Startup Challenges | Nitrogen Rejection Unit
The nitrogen rejection unit (NRU) is designed to remove nitrogen from the Pluto LNG end-flash gas. This is necessary to allow the end-flash gas to be burnt in the fuel gas system. The start-up of the NRU requires end-flash gas from the LNG train and thus cannot be commenced until after the LNG train has been started.
The NRU is a new equipment unit for Woodside and so vendor personnel (Linde) were present on site to assist with first start-up and operator training. |
Oil Gas Commissioing & Startup Challenges | Cool-down of the NRU is a lengthy process with a cool-down and ramp-up from ambient conditions taking several days. Process conditions change very slowly which means changes made to flows or pressures may not impact the cool-down until several hours later.
This means the start-up operation spans several shifts and it is essential to have robust procedures and shift handovers to ensure the success of the cool-down. Woodside worked with Linde during the start-up operation to improve start-up methodology for the unit resulting in procedures which can be reliably carried out by operations personnel without on-site engineering or vendor assistance. |
Oil Gas Commissioing & Startup Challenges | Storage and loading flare
The flares at the Pluto LNG facility were designed to minimise dark smoke during plant production.
In order to meet this requirement the Pluto LNG storage and loading flare was provided with air-assist technology, which reduces smoke formation by using air blowers to force mixing of air and hydrocarbons close to the flare-tip.
During the first LNG offloading operation high backpressures were experienced in the storage and loading flare header which caused the LNG loading operations to be halted. Upon investigation it became apparent that ice formation was occurring at the storage and loading flare-tip, caused by the introduction of humid air into the cold flare gas. Turning off the air assist gas and switching to the offline flare stack eliminated this problem.
A significant contributor to the ice formation issues was the mechanical design of the flare tip, which restricted the area available for flow of gas and air flow. This design was intended to promote stable flame formation and minimise dark smoke to the maximum possible extent. This restricted area available for gas flow meant that a relatively small amount of ice build-up could cause a significant increase in backpressure.
The problem was eliminated and operations were able to be continued with the air assist turned off. Re-design of the flare tip is being progressed to remove the mechanical flow restrictions and move to a more open pipe design. This is expected to allow the use of assist air and minimise dark smoke without any increase in backpressure. |
Oil Gas Commissioing & Startup Challenges | Ramp-Up Performance
The culmination of the described start-up techniques was a safe, reliable and successful start-up of the Pluto LNG facilities.
Figure 6 shows the capacity and reliability performance of the Pluto LNG facilities over the first few months of operation. The train achieved production rates close to design capacity within 3 months of operation, with a system reliability greater than 90% in the second half of 2012.
This good start-up performance has resulted in 39 LNG cargoes being delivered from the facility in 2012. This better than expected production from Pluto resulted in Woodside upgrading its production forecast twice during 2012. |
Oil Gas Commissioing & Startup Challenges | The start-up of the Pluto LNG facilities is considered to be a great success, with a rapid ramp-up and high reliability over the initial operational period. This is considered testament to the level of planning and preparation, the high quality team and the innovative start-up methodologies which were employed.
The start-up presented a number of technical challenges which were overcome by leveraging off the experience from within the Woodside start-up team. Best practice techniques from previous Woodside start- experience.
Through the successful commissioning, start-up and initial operations, Pluto LNG has demonstrated Woodsides world-class capability as an LNG operator. We will continue to build on this capability for use on future LNG projects. |
Oil Tanker & Ship Building | Ships are large, complex vehicles which must be self-sustaining in their environment for long periods with a high degree of reliability.
The naval architect is concerned with the hull, its construction, form, habitability and ability to endure its environment. The navigating officer is responsible for safe navigation of the ship, and its cargo operations. The marine engineer is responsible for the various systems which propel and operate the ship.
More specifically, this means the machinery required for propulsion, steering, anchoring and ship securing, cargo handling, air conditioning, power generation and its distribution.
There are two main parts of a ship: the hull and the machinery. The hull is the actual shell of the ship including her superstructure,
The machinery includes not only the main engines required to drive her but also the auxiliary machinery (boilers, generators, etc.) used for manoeuvring purposes, steering, mooring, cargo handling and for various other services, e.g. the electrical installations, winches and refrigerating plant. |
Oil Tanker & Ship Building | Many modern cargo and passenger liners have a transverse propulsion unit or bow thruster in the bows. Its purpose is to give greater manoeuvrability in confined waters, e.g. ports, and so reduce or eliminate the need for tugs.
The modern tendency is to have large unobstructed holds with mechanically operated hatch covers, both for the speedy handling of cargo, and to reduce turn-round time to a minimum. |
Oil Tanker & Ship Building | A ship's actual design and number of decks depend on the trade in which the ship will ply. A tramp, carrying shipments of coal or ore, will be a single deck vessel with large unobstructed hatches to facilitate loading and discharge. A cargo liner carrying a variety of cargo in relatively small consignments would have 'tween decks to facilitate stowage. If such a vessel also conveyed wood and other commodities of high stowage factor, a shelter deck would be provided.
Additionally, container ships are equipped with specially designed holds with cells or slots to facilitate speedy container handling using shore-based lifting gear. |
Oil Tanker & Ship Building | Three principal types of machinery installation are to be found at sea today.
The three layouts involve the ships propulsion machinery using direct-coupled slow-speed diesel engines (the main engine), medium-speed diesels with a gearbox, and the steam turbine with a gearbox drive to the propeller.
The propeller shaft must rotate at about 80 to 100 rev/min. The slow-speed diesel engine rotates at this low speed and the crankshaft is thus directly coupled to the propeller shafting. The medium-speed diesel engine operates in the range 250750 rev/min and cannot therefore be directly coupled to the propeller shaft. A gearbox is used to provide a low-speed drive for the propeller shaft. The steam turbine rotates at a very high speed, in the order of 6000 rev/min. Again, a gearbox must be used to provide a low-speed drive for the propeller shaft.
On a crude oil carrier, the main line system changes name, depending on where it is placed.
From cargo tanks to the cargo pumps, the main lines are called bottom lines.
From the cargo pumps delivery side, the name changes to risers.
When they appear on the main deck, the names are deck lines. |
Oil Tanker & Ship Building | COW Lines (Crude Oil Washing)
On the main deck you will find the cow main line with branches leading to the ships crude oil washing machines. This line comes from the cow cross over line on the delivery side in the pump room. |
Oil Tanker & Ship Building | Inert Lines
To control the atmosphere in the cargo tanks you will find inert lines on the main deck leading to each tank. These lines are for supplying inert gas during discharging or tank washing. Some inert gas systems are connected to a main riser, which are fitted with a press/vacuum valve for regulation of the pressure and vacuum in the cargo tanks. Other inert gas systems have these press/vacuum valves installed on each cargo tank with the same function as the riser. |
Oil Tanker & Ship Building | Cargo heating
In addition to the provision of cargo compartments, pipelines and pumps for handling the oil, the oil tanker must also provide adequate heating systems for some types of oil and cooling systems for others. Properly constructed ventilation systems are necessary in all oil tankers in order to avoid excessive loss of cargo from evaporation and to control the escape of dangerous gases.
Steam is used to heat the oil in a ship's tank. It is piped from the boilers along the length of the vessel's deck.
In ships carrying heavy lubricating oils which require heating, the coils are generally ordinary steel pipe, but vessels carrying crude oils which have to be heated, are now equipped with cast iron or alloy coils. |
Oil Tanker & Ship Building | Ventilation
Cargo pump rooms shall be mechanically ventilated and discharges from the exhaust fans shall be led to a safe place on the open deck. The ventilation of these rooms shall have sufficient capacity to minimize the possibility of accumulation of flammable vapours. |
Oil Tanker & Ship Building | Gas freeing
It is generally recognized that tank cleaning and gas freeing is the most hazardous period of tanker operations. This is true whether washing for clean ballast, gas freeing for entry, or gas freeing for hot work. |
Oil Tanker & Ship Building | Oil Tankers
Based on size, oil tankers have been categorised into the following types:
1.Small Range (Product) Tanker: 10,000 to 60,000 tons DWT.
2.Panamax Tanker: 60,000 to 78,000 tons DWT.
3.Aframax (Average Freight Rate Assessment) Tanker: 80,000 to 1,20,000 tons DWT.
4.Suezmax Tanker: 1,20,000 to 2,00,000 tons DWT.
5.VLCC (Very Large Crude Carrier): 2,00,000 to 3,20,000 DWT.
6.ULCC (Ultra Large Crude Carrier): 3,20,000 to 5,50,000 DWT. |
Oil Tanker & Ship Building | The most important design drawing that is to be studied in order to identify the design of a ship, is its General Arrangement Drawing. Figure 3 illustrates the profile view of an oil tankers general arrangement. It basically shows the arrangement of all the spaces within the ship, and gives a frame-by-frame location of every space, bulkheads, and other primary structures
The main deck of an oil tanker is usually mounted with a network of pipelines that are used to load and unload cargo oil to and from the ship. Flexible hoses are attached to the pipelines for completion of the process.
The engine room and superstructure, as usual, are located at the aft. But, one notable feature in oil tankers, that is not found in other types of ships is the pump room, that is usually located just forward of the engine room. The pump room houses all the pumps required for cargo oil loading and discharge. |
Oil Tanker & Ship Building | Bulbous Bow:
Today, all tankers are equipped with a bulbous bow, so as to increase the power efficiency of the ship. Though these are slow speed ships, a bulbous bow reduces the wave making resistance considerably. |
Oil Tanker & Ship Building | Structural Design:
The structural design of oil tankers vary according to the type and size of the tanker. To understand them, we will study their midship sections in detail. |
Oil Tanker & Ship Building | Double Hull Tankers:
All oil tankers of length above 120 m are required to be double hulled, as per MARPOL rules. Panamax, Aframax, Suezmax, VLCC and ULCC tankers are all double-hulled. The primary reason for providing two hulls is to prevent the contact of cargo oil with the external environment in case of any structural damage to the hull.
Today, irrespective of the classification society certifying the design of a tanker, the structural design of double hull tankers is done according to The Harmonised Common Structural Rules (CSR) for Tankers, by IACS. |
Oil Tanker & Ship Building | Power and Propulsion:
Since tankers are low speed vessels (average maximum cruising speed is 15.5 knots), and are not restricted by space constraints, they can afford to be run by large slow speed marine diesel engines. These engines occupy more space than high speed marine diesel engines, but provided more shaft efficiency, and gearbox losses are eradicated since the RPM of the engine is same as that of the propeller. Usually, large diameter and low RPM propellers are used for more propulsive efficiency. |
Oil Tanker & Ship Building | Systems On-board:
Oil tankers have a number of systems that are unique to its operation. We will discuss the most important ones in brief.
Cargo Oil Heating System: Ships carrying crude oil are equipped with this system, as crude oil is heavy and becomes very sluggish and thick in cold environments, which can block the pumps and pipelines during discharge. So, cargo oil heating system is used to maintain the suitable temperatures and viscosity of cargo oil in holds.
Cargo Tank Venting System: Did you know that cargo oil tanks are never pressed full so as to allow space for oil vapour? But, at the same time, these vapours, being highly inflammable, are not allowed to accumulate in the cargo tanks. Proper venting systems allow the vapours to escape from enclosed spaces.
Overflow Control System: This system uses a level and pressure cascade control to ensure that the level of oil in the tank does not exceed the design head. High level alarms and spill valves are connected to the system in order to take correct action in case of anomaly.
Inert Gas System: The space between the free surface of the cargo oil and the top plating of the tank is to be kept inert, in order to prevent access of oxygen, so that even in case of any accumulation of oil vapour, a situation of fire is avoided. This is done by continuous supply and regulation of inert gas in cargo oil tanks. The space above the oil surface is ensured to be completely occupied by inert gas. The most common gases used for this purpose are Argon and Carbon-dioxide.
Fire Fighting System: The fire-fighting systems on board an oil tanker is the most vital for the ships safety, and is designed as per the MARPOL rules. Fire hoses, extinguishers and sprinklers are distributed along the ships length and breadth for access to all points. CO2 bottle room just above the engine room to allow CO2 flooding in the engine room during engine room fire.
Most oil tankers are provided with at least one deck-crane so as to handle the cargo oil hoses during discharge and loading of cargo oil, when the hoses are to be removed from stowage points and connected to the discharge manifolds on the ships deck. |
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