Lyntas/mining_domain_knowledge_reference_dataset huggingface dataset:
Area: 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.
Area: 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.
Area: 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.
Area: 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.
Area: 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.
Area: 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
Area: 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).
Area: 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.
Area: 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.
Area: Oil & Gas Projects Australia
The Field, which is 100% owned and operated by Eni, will deliver gas to the Northern Territorys 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.
Area: 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
Area: 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.
Area: 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 35t1,800t).
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.
Area: 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.
Area: 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.
Area: 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.
Area: 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.
Area: 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.