Lyntas/mining_domain_knowledge_reference_dataset huggingface dataset:
Area: Marine Facilities
Progression of Marine Facilities Design
Although the marine facilities design has been advanced to a level sufficient for the purposes of planning and permitting, the design will be subject to change prior to the finalization of the design details. The current design details which have been submitted as part of the EA are only preliminary, and considerable engineering effort is still required to complete the designs to a level that is ready for construction. The designs will be received as they currently stand by the EPC contractor and will be modified to suit that contractors particular construction methodology as it fits into the framework of the EA and the projects overall Construction Management Plan. Factors which will influence the evolution of the design include:
 Changes resulting from further geotechnical and geophysical investigations;
 Changes resulting from further site and metocean investigations;
 Changes to suit EPC contractors equipment, construction preferences, and schedules; and
 Changes to suit regulated environmental restrictions and mandated mitigations.
Area: Marine Facilities
Construction Schedule and Equipment Profile
A summary of the estimated construction schedules and equipment profiles discussed above for each marine construction site is given in Figure 7-1. For the sake of conservatism, marine based construction methods have been assumed for all applicable construction sites, since this represents the largest floating equipment profile that may have an effect on marine traffic.
The minimum required equipment is identified for each construction site as well as the estimated frequency of floating equipment transits. Considering the estimated overall construction durations for each marine work site, a temporal profile is given for each piece of marine-based equipment. This allows a quick determination of the estimated construction fleet in operation at any given time.
As can be seen by Figure 7-1 at its peak, the construction fleet may consist of up to 4 to 7 marine derricks and 4 to 7 flat deck scows operating simultaneously over 3 different sites.
Also if the MOF dredging program lags, a jack-up barge working beside a marine backhoe dredger, and split hopper barge in the MOF cove may also be an ongoing operation during the peak time. The total construction fleet mobilized may include anywhere from 14 to 18 working barges and perhaps a dozen or so supply barges transiting from the various construction sites to staging and anchoring areas. This fleet will be supported by several crew boats, utility tugs and other small craft vessels.
The fleet will be distributed over a wide area of several kilometres from Lelu Island Slough to the LNG Berth locations out in open water. Much of the construction activities will occur in relatively confined or contained work sites. With a few exceptions, these work sites will be mainly located in coves and inlets away from regular marine traffic channels or in areas along the perimeter of Flora bank which are naturally probative to marine through-traffic.
Area: Marine Facilities
Daily transits are expected for much of the working vessels as they are deployed and recalled to accommodate tidal restrictions, weather conditions, material resupply, and work shift requirements. Staging areas and anchorages can be located to minimize disruptions to marine traffic. During construction activities much of the fleet will remain stationary while construction operations are being conducted and will only transit for the reasons discussed above.
In general the construction of the marine facilities should not be an impediment to marine traffic. Mitigations include enforcing a safety zone around each work site and promulgating work site restrictions through a variety of channels, such as Notices to Mariners, in accordance with the Marine Communication Plan. As a participant in the Port of Prince Ruperts Construction Coordination Committee for de-confliction with other users, PNW LNGs Marine Communications Plan will be used to alert mariners to project activities, hazards and safety measures such as enforced safety zones and marine route closures.
Area: Mining Concentrator Plants
The 40 ft (12.2 m) diameter 20 MW Cadia gearless SAG mill, was commissioned. This was a leap of over 40% above the largest operating SAG mill. A significant saving in capital cost gave the incentive necessary for a single mill line at Cadia, resulting in the selection of the 40 ft (12.2 m) diameter mill. Now, after 18 months of operation,
The grinding ball mills are important in the ore comminution circuits. Depending on numerous factors, such as, for example, inappropriate design, manufacturing, overloads, poor maintenance and inadequate operating procedures, flaws are developed in the structural components of this equipment. The structural components of a mill, basically, shell, heads and trunnions, besides high costs, have lead times that might reach three years.
Area: Offshore Design & Installation
A typical subsea oil and gas field consists mainly of Xmas trees, manifolds, termination units and pipelines. The central in a subsea field is the manifold. It is the link between the subsea field and the production facility. The manifold consists of a network of pipes and valves for gathering and distribution of the production flow. By using a manifold, the number of pipelines required in a subsea field is reduces, and it allows for a single pipeline for transportation to the production facility.
The Xmas trees are (normally) placed on the seabed, acting like satellites around the manifold. The trees are connected to the manifold with a pipeline called jumper or spool.
A termination unit can be called a PLEM or a PLET. These units are connection points between two or several pipelines. The Pipeline End Termination (PLET) comprises a single pipeline connection only, while the Pipeline End Manifold (PLEM) is supporting two or more pipeline connections.
In the subsea industry, the pipeline is a collective term for flowlines (pipelines transporting fluids and/or gas), spools, jumpers and risers
Area: Offshore Design & Installation
Platform solution
Per definition, in this context (thesis), a platform is all kinds of offshore surface units, like fixed platforms, floaters, FPSOs, etc. used in conjunction with offshore oil and gas production. If a subsea field is connected to a platform in such way that the produced oil and gas is transported to the platform for processing, it is called a platform solution. A common feature for this subsea solution is the riser which connects the subsea field to the platform.
Area: Offshore Design & Installation
Subsea-to-shore solution
For this type of subsea solution, all produced oil and gas is transported (tie-back) to an onshore facility for processing. The transportation is in a long export flowline. The subsea fields Snøhvit and Ormen Lange, which are well known in Norway, comprise the subsea-to-shore solution.
Area: Offshore Design & Installation
SUBSEA PIPELINE CONNECTIONS
Subsea pipeline connections can be differentiated between
 pipe-to-pipe connections 
   Pipe-to-pipe connection is the definition when to pipelines are connected to operate as one pipeline

E.g  If a long export flowline from shore is to be connected to a subsea facility, a spool is required between the flowline and the structure. The shape of the spool (L-shape or Zshape) makes the spool compensate for thermal expansion in the flowline to avoid application of heavy loading directly into the connection point on the structure. The connection between a flowline and a spool is a very common subsea pipe-to-pipe connection

pipe-to-structure connections. While pipe-to-structure connection is the definition when a pipeline is connected to a subsea facility such as a Xmas tree, a manifold or a PLEM.
Area: Offshore Design & Installation
PIPELINE END TERMINATION (PLET)
A pipe-to-pipe connection can take place when a riser is connected to a subsea installed pipeline, or when an export flowline is connected to a spool. These types of connections, compared to the pipe-to-structure connections, do not have a given substructure for support. For a pipe-tostructure connection, the Xmas tree, the manifold or the PLEM will provide the required support to the connection point, while a pipe-to-pipe connection requires a purpose-built substructure.
The PLET is the required substructure for a pipe-to-pipe connection. It provides the support for the connection point. Figure 1.10 is an example of a PLET. A detail description of PLET is given in section 2.3
Area: Offshore Design & Installation
Figure 1.11 (overleaf) illustrates a difference between a platform solution and a subsea to- shore solution with respect to the use of a PLET. For the subsea-to-shore solution, the PLET is positioned at the connection point between the export flowline and a spool as the flowline cannot be connected directly into the manifold. For the platform solution the PLET is positioned at the connection point between the riser and a spool as the riser cannot be connected directly into the manifold.
Area: Offshore Design & Installation
Generally, a PLET is positioned where a flowline is connected to a spool. Most of the flowlines in a subsea field are rigid pipelines (section 2.1), and spools are then required between the flowlines and the connection points on the subsea facilities to compensate the thermal expansions in the flowlines
Area: Offshore Design & Installation
SUBSEA PIPELINES
The most common way to fabricate a subsea pipeline is to weld a large number of pipe joints into each other on a special lay-vessel at the same time as the pipeline is lowered and installed on the seabed. Typical pipeline material is carbon steel or a type of alloy.
Pipelines are generally regarded as rigid or flexible. Rigid pipelines are made of steel and have limited bending capacity and flexibility. Export flowlines and spools are usually rigid pipelines. The rigid pipelines are generally less expensive than flexible pipelines.
Area: Offshore Design & Installation
Installation methods
S-lay
Pipe joints are welded to a pipeline on a lay-vessel. From the lay-vessel the pipeline appear as an S-curve to the seabed
J-lay
Pipe joints are welded to a pipeline on the lay-vessel. The welding is done with the pipe joints in vertical position


Installation of spools and jumpers to a subsea field is done by an installation vessel (notlay-vessel). The spool or jumper is fabricated onshore, and is then transported by the vessel to the offshore location. From the vessel, the spool or jumper is installed to seabed by vessel crane

Subsea connections are the connections completed on the seabed. As the industry has become driverless, subsea connections by welding and flanges are more or less non-existing. Subsea connections are completed by remotely operated mechanical connectors, also called clamp connectors.
Area: Offshore Design & Installation
PLET example 1
Figure 2.4 shows the PLET (fixed end), the termination (movable end) and the configuration before and after the connection operation. The termination is landed on the PLET, close to the Porch. A ROV operated connection tool executes the pull-in operation by pulling the termination towards the Porch. A torque tool operated by the ROV closes the clamp connector.
Area: Offshore Design & Installation
Design challenges for flowline systems
As offshore oil and gas production is moving into deeper waters, the risk of hydrate plugging and wax formation in flowlines increases, as does the cost of remediating any such plugs [45].
Hydrate and wax formation in subsea flowlines will cause undesired fluid properties and even blocking of the wellstream, which implies shutdown and comprehensive reparations 
There are several solutions to prevent formation of hydrates and wax during production. In the North Sea, the most common method combines thermal insulation and chemical injection. The disadvantage with this is that large amounts of chemicals are injected continuously into the well stream, then have to be removed again at the topside.

Electric heating is developed as a method for removing hydrates, and is also applicable for solving plug situations [46]. Electric heating may also prove effective in preventing or remediating wax plugging. In this case it may be possible to reduce capital costs by replacing conventional pigging loops with single heated flowlines.
Two systems are considered:
 Direct electric heating (DEH), Figure2.4, with strap-on piggyback cable and current carrying pipeline
 Indirect electric heating of pipelines using a) cables as ohmic elements or b) induction heating of pipeline wall. In both cases the cables are embedded inside the thermal insulation.
In a DEH system, the pipe to be heated is an active conductor in the electric circuit formed by the dynamic DEH riser cable, the armored feeder cables, the piggyback cable, and the flowline. The heating effect results from the fact that an electric current flowing in a metallic conductor generates heat.
AC current comes from the topside power system through the DEH riser cable. For safety and reliability reasons, the heating system is electrically connected to surrounding seawater (i.e. it is an "open system") through several sacrificial anodes. These anodes must be rated for both corrosion protection and for sufficient grounding of the system during the expected lifetime of the flowline
Area: Offshore Design & Installation
Risers
A riser is a pipe or assembly of flexible or rigid pipes used to transfer produced fluids from the seabed to surface facilities, and transfer injection or control fluids from the surface facilities to the seabed [50]. Riser connects subsea to topside [12].
There are different types of risers [12]:
? Drilling Risers - Typically top tensioned risers
? Production risers
 Flexible risers
 Steel catenary risers
 Hybrid riser towers
 Single Hybrid Risers  SLOR
 Grouped SLOR
? Export risers
 Similar to production risers
? Water/Gas Injection risers
 Similar to production risers
Area: Offshore Design & Installation
Flexible risers
Flexible pipes have been successful solutions for deep and shallow water riser and flowline systems worldwide. In such applications the flexible pipe section may be used along the entire riser length or limited to short dynamic sections such as jumpers.
Area: Offshore Design & Installation
Steel catenary risers
A Steel Catenary Riser (SCR) is a prolongation of a sub-sea pipeline attached to a floating production structure in a catenary shape. SCR lines are commonly subjected to fatigue loads, particularly in the touchdown zone, due to platform movements, Vortex Induced Vibrations (VIV) and sea currents.
In order to avoid any excessive stress concentration, the oil and gas industry pays particular attention to the welding process of SCRs in order to minimize any possible misalignment between pipe ends
Area: Offshore Design & Installation
Primary Functions of Umbilicals
An umbilical is defined as an assembly of fluid conduits, electrical and fibre optic cables, either on their own or in combination with each other, cabled together for flexibility
Area: Offshore Design & Installation
Glycol dehydration (absorption) is the most commonly used method of natural gas dehydration. Glycol has the advantages of having a high affinity for water vapor, is non-corrosive and is fairly easy to regenerate with low chemical losses
Area: Offshore Design & Installation
Operation
Wet gas is injected into the bottom of an Absorber Column, also known as a Contactor, while lean or dry glycol is injected near the top. The glycol then cascades over a number of trays within the contactor, comingling the glycol with the gas stream; the lean glycol has an affinity for water vapor, which bonds with the glycol. The now dry gas passes out the top of the contactor, generally through a heat exchanger to lower the temperature of the lean glycol before it is injected into the absorber column. Glycol has more affinity for water at lower temperatures.
The wet or rich glycol, which now includes the water vapor removed from the gas stream passes out the bottom of the contactor through a flash tank where gas entrained with the glycol is collected. It then passes through a heat exchanger to further cool the incoming lean glycol.
The rich glycol then flows into a regenerator or stripper column, which is mounted on top of the reboiler. The stripper column is packed with a ceramic packing. The rich glycol flows down the stripper column into the reboiler, where it comes into contact with rising hot glycol which has been heated in the reboiler to a temperature where the entrained water will vaporize and travel up the still column through an atmospheric reflux condenser before being released to the atmosphere.
For TEG glycol systems, the glycol can be heated to a maximum of 400° Fahrenheit (F) or 204° Celsius (C), which ensures that virtually all of the water contained within the rich glycol is vaporized. (98.6% purity) The now lean glycol can be stored or recirculated through the system.

Natural gas containing four parts per million (4 ppm) or less is generally considered to be pipeline quality sweet natural gas by U.S. gas transmission and distribution companies. Some jurisdictions, such as the Texas Railroad Commission, allow concentrations as high as 100 ppm to be considered as sweet gas. Natural gas with higher concentrations of H?S is referred to as sour natural gas. When H?S is combined with CO?, as is often found in natural gas well streams, the combination creates what is termed acid gas. Acid gas, in addition to being deadly as described above is very corrosive to steel.

The most common methods of H?S and CO? removal from natural gas are as follows
 Amine Treatment Plant Processes
 Iron Sponge Processes
 Proprietary Processes
 Claus Process for Sulfur Recovery
Area: Offshore Design & Installation
Amine Treatment Plant Processes
The alkanolamine treatment process is the most commonly used process to sweeten natural gas. These are commonly referred to as amine treatment processes or plants. The most common alkanolamines used are
 Monethanolamine
 Diethanolamine
 Methyldiethanolamine (MDEA)
Other amines that are less often used include:
 Diisopropanolamine
 Aminoethoxyethanol (Diglycolamine)

Amines are used in an aqueous solution. The selection criteria and concentration level of the amine type is based on the ratio of H?S to CO? in the gas stream and the concentrations of each. Regardless of which amine is chosen for the gas stream conditions, the sweetening process is essentially the same
Area: Offshore Design & Installation
The sour natural gas normally runs through an inlet scrubber to remove any slugs of liquid, liquid HC, grit or sand from the gas stream. After the scrubber the gas is introduced into the bottom of an absorber or contactor tower. Lean amine (amine that has been stripped of H?S and CO?) is injected into the top of the tower. The tower includes a series of trays to increase the time for comingling the amine with the sour gas. Each tray has a liquid amine level of 2-3 inches (5-8 centimeters) maintained by a weir. The gas passes up from underneath the tray though openings in the trays causing it to bubble through the liquid forming froth. The H?S and CO? are absorbed by the lean amine in the trays. The gas flows out the top of the contactor tower as sweet gas.
Area: Offshore Design & Installation
The now rich amine (amine that has absorbed H?S and CO?) is run through a flash tank separator to remove any natural gas that may have carried over in the rich amine. Any liquid HCs are removed via conventional oil/water separation in this separator and the rich amine is drained from the bottom of the flash tank separator. Separation of the HCs also helps to prevent foaming due to HCs in the amine.
Area: Offshore Design & Installation
The rich amine is then preheated by a heat exchanger utilizing heat from the lean amine, which must be cooled before being reinjected to the contactor. The rich amine is injected into the top of a stripper column (regenerator) which is packed with trays. As the rich amine flows down through the regenerator column, it is met by a gas stream of steam, H?S and CO? that is generated in the reboiler. This lowers the partial pressure of the H?S and CO?, causing it to separate from the amine. Overhead gas is passed through a condenser to recover water and the small amount of amine that is vaporized by the regenerator. The condensed liquid and acid gas flow through a reflux drum from which it is pumped back into the regenerator column.
Area: Offshore Design & Installation
The acid gas containing the concentrated H?S and CO? are sent to a flare, incinerator, reinjection to a depleted well, sulfur recovery or other disposal method.
The lean amine is then sent through a filter followed by an activated charcoal filter to remove any particulate matter that may have been picked up during the process. Depending on which amine is used, the amine may also be sent though a reclaimer to further purify the amine. The lean amine is then cooled before being pumped back to the top of the contactor tower to begin the sweetening process again.
A typical layout of a 100 gallon per minute sweetening plant packaged by Zephyr Gas Services (currently constructed in Sheberghan, Afghanistan) is shown below in Figure 3-7 Typical Sweetening Plant Layout.
Area: 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
Area: Offshore Design & Installation
Environmental parameters
The design and analysis of fixed offshore platforms may be conducted in accordance with the APIs 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)
Area: 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.