HDPE (High Density Polyethilene)

High-density polyethylene (HDPE) or polyethylene high-density (PEHD) is a polyethylene thermoplastic made from petroleum. It is sometimes called "alkathene" or "polythene" when used for pipes.[1] With a high strength-to-density ratio, HDPE is used in the production of plastic bottles, corrosion-resistant piping, geomembranes, and plastic lumber. HDPE is commonly recycled, and has the number "2" as its resin identification code (formerly known as recycling symbol).
In 2007, the global HDPE market reached a volume of more than 30 million tons.
Properties
HDPE is known for its large strength-to-density ratio. The density of HDPE can range from 0.93 to 0.97 g/cm3 or 970 kg/m3.Although the density of HDPE is only marginally higher than that of low-density polyethylene, HDPE has little branching, giving it stronger intermolecular forces and tensile strength than LDPE. The difference in strength exceeds the difference in density, giving HDPE a higher specific strength. It is also harder and more opaque and can withstand somewhat higher temperatures (120 °C/ 248 °F for short periods, 110 °C /230 °F continuously). High-density polyethylene, unlike polypropylene, cannot withstand normally required autoclaving conditions. The lack of branching is ensured by an appropriate choice of catalyst (e.g., Ziegler-Natta catalysts) and reaction conditions.
Applications

HDPE pipe installation in storm drain project in Mexico
HDPE is resistant to many different solvents and has a wide variety of applications:
Swimming pool installation
3-D printer filament
Arena Board (puck board)
Backpacking frames
Ballistic plates
Banners
Bottle caps
Chemical-resistant piping
Coax cable inner insulator
Food storage containers
Fuel tanks for vehicles
Corrosion protection for steel pipelines
Personal Hovercraft; albeit too heavy for good performance
Electrical and plumbing boxes
Far-IR lenses
Folding chairs and tables
Geomembrane for hydraulic applications (such as canals and bank reinforcements) and chemical containment
Geothermal heat transfer piping systems
Heat-resistant firework mortars
* Last for shoes
Natural gas distribution pipe systems
Fireworks
Plastic bags
Plastic bottles suitable both for recycling (such as milk jugs) or re-use
Plastic lumber
Plastic surgery (skeletal and facial reconstruction)
Root barrier
Snowboard rails and boxes
Stone paper
Storage sheds
Telecom ducts
Tyvek
Water pipes for domestic water supply and agricultural processes
Wood plastic composites (utilizing recycled polymers)
HDPE is also used for cell liners in subtitle D sanitary landfills, wherein large sheets of HDPE are either extrusion or wedge welded to form a homogeneous chemical-resistant barrier, with the intention of preventing the pollution of soil and groundwater by the liquid constituents of solid waste.
HDPE is preferred by the pyrotechnics trade for mortars over steel or PVC tubes, being more durable and safer. HDPE tends to rip or tear in a malfunction instead of shattering and becoming shrapnel like the other materials.
Milk jugs and other hollow goods manufactured through blow molding are the most important application area for HDPE, accounting for one-third of worldwide production, or more than 8 million tons. In addition to being recycled using conventional processes, HDPE can also be processed by recyclebots into filament for 3-D printers via distributed recycling. There is some evidence that this form of recycling is less energy intensive than conventional recycling, which can involve a large embodied energy for transportation.
Above all, China, where beverage bottles made from HDPE were first imported in 2005, is a growing market for rigid HDPE packaging, as a result of its improving standard of living. In India and other highly populated, emerging nations, infrastructure expansion includes the deployment of pipes and cable insulation made from HDPE. The material has benefited from discussions about possible health and environmental problems caused by PVC and Polycarbonate associated Bisphenol A, as well as its advantages over glass, metal, and cardboard.

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Drivers influencing the evolution of horizontal and vertical trees

The capability and flexibility offered by modern subsea christmas trees and production systems is, by any measure, truly impressive. The industry has moved from simple production systems to more expansive ones incorporating complex controls and sensors and a range of monitoring and diagnostic systems.

This equipment operates in very challenging environments and stands as a testament to the skill and ingenuity of the teams that design, build, and install it.

The demands for the production of hydrocarbons from deep water at higher pressures and temperatures, coupled with a range of additional design constraints, ensure that subsea tree systems will continue to evolve to meet these challenges both now and in the future.

In the subsea industry much debate is generated comparing the relative merits of horizontal and vertical sub-sea tree systems. This article considers some of the primary drivers of this discussion and how they may influence both system design and future operations.

Horizontal and vertical trees

Subsea production trees can be segmented into two main types: horizontal trees and vertical trees. Horizontal trees are so called because the primary valves are arranged in a horizontal configuration, and likewise vertical trees have the primary valves arranged in a vertical configuration.

A key requirement of a subsea tree is that access is enabled to the “A” annulus between the production tubing and casing. This is required for a number of reasons, including pressure monitoring and gas lift. As an example, any pressure buildup in the A annulus can be bled to the production flowline via a crossover loop on the tree.

The original designs of subsea vertical trees and tubing hangers were of a dual-bore configuration. Prior to removal of the BOP, it is necessary to set plugs in both the production and annulus bores. Access to both bores requires the use of a dual-bore riser or landing string. The handling and operation of dual-bore systems compared to monobore systems is more complex, and time-consuming and, therefore, more costly.

On a horizontal tree, access to the A annulus is incorporated into the tree design and controlled by gate valves rather than plugs. This enables operations with a mono-bore, less-complex riser or landing string, which can deliver significant advantages, particularly in deep water. It is exactly this logic that led to the introduction of tubing-head spools for use with vertical trees, thereby offering many of the advantages of a horizontal tree.

Hangoff location

Another key functional difference relates to the hangoff location of the completion. In a vertical tree system the tubing hanger is landed either within the subsea wellhead or within a tubing-head spool. The subsea tree is then installed on top of the wellhead or tubing-head spool. In the case of the horizontal tree, the tree is installed on top of the subsea wellhead, and the tubing hanger is landed within the tree body.

This key difference means that, in the case of the horizontal tree, recovery of the completion can be achieved without removal of the tree. In the case of the vertical tree, access to recover the completion first requires removal of the tree itself. This functional variation is another input into the choice between horizontal and vertical trees.

If the probability of a failure in the completion (requiring its recovery) is higher than a failure in the tree (requiring recovery of the tree), then there may be a strong case for favoring a horizontal tree. The converse also is true; if a failure in the tree is considered the highest risk, then application of vertical tree technology incorporating the most efficient opportunity for its recovery may be favored over horizontal tree technology, where recovery of the tree first requires recovery of the completion.

The relative ease of recovery of tree or completion is then the key functional difference. The overall system choice is, in many ways, application-specific and dependent upon a large number of factors. However, there are additional primary factors that are important inputs to the selection process.

Influence of installation and intervention

Both horizontal and vertical tree systems use a landing string to run the completion through the BOP. In the case of the horizontal tree, the completion is normally run on a subsea test tree within the marine riser, and the tubing hanger is landed within the horizontal tree. The subsea test tree is an assembly of connectors and valves and is designed to carry out a number of critical functions.

Once the hanger is landed in the tree, correct orientation of the tubing hanger is critical to ensure communication of all hydraulic and electrical downhole functions. In the case of the horizontal tree, the tubing hanger is normally oriented passively using an orientation sleeve attached to the tree. This passive orientation does not rely on external input.

It is common practice that once a well is completed it will be flowed to the drilling rig to clean up the well or to carry out a well test. This test or cleanup is carried out with horizontal trees via the subsea test tree and a high-pressure riser within the marine riser. The primary function of the subsea test tree ensures that, should it be necessary to disconnect the rig from the BOP during the well test or cleanup, the valves within the test tree can be closed and an emergency disconnect carried out safely.

In the case of vertical trees, the completion is run on a landing string incorporating a tool that runs, locks, and orients the tubing hanger. This orientation function normally requires the tool to interface with a known reference, which commonly comprises a pin installed within the BOP. Once the tubing hanger is oriented correctly it can be landed in the wellhead, with the understanding that when the tree is landed and oriented, communication for all hydraulic and electrical downhole functions will be achieved.

Well cleanup or well testing on a vertical tree is typically only carried out after the well has been suspended and the BOP replaced by a dedicated test package and open-water riser. This test system comprises two main assemblies: the lower riser package (LRP) and the emergency disconnect package (EDP). In a similar fashion to the subsea test tree, this system enables the rig or vessel to safely disconnect in the event of an emergency.

Such LRP/EDP packages and open-water riser systems represent considerable capital investments, typically in the order of tens of millions of dollars. In comparison, subsea test trees can be rented on the open market on a per-day or per-well basis. As a result, they can have a much lower capital impact. This variance in the capital impact of installation and intervention equipment is often a key input into the choice of vertical or horizontal tree technology, particularly when the installed well count is relatively small.

Previously it was noted that an additional tubing-head spool can be run on top of the subsea wellhead. The tubing-head spool is simply an additional spool that is not unlike the body of a horizontal tree but without a production outlet. It broadly carries the same functionality as a horizontal tree body, including passive tubing hanger orientation and A annulus isolation. Using a tubing hanger spool in conjunction with a vertical tree can, in addition to enabling monobore landing string or riser operations, also allow the use of a subsea test tree with a vertical tree.

This potentially negates the significant capital cost of an LRP/EDP and open-water riser system. It is, however, noted that use of a tubing-head spool can require an additional BOP trip.

In the case of a horizontal tree, the tubing hanger and completion are installed within the tree. This requires that the drilling program is closely coupled with the tree delivery schedule. The same is true for a tubing-head spool. The decoupling of tree delivery and the drilling program offers a degree of operational flexibility and again is a factor in tree selection.

Tree system weights

Tree system weight is an important operational parameter. The weight can influence lifting, handling, and installation operations and can have an impact on the required vessel capability. Many end users specify maximum weights for subsea tree systems. As a broad generalization it can be said that the functionally comparable vertical trees are lighter than horizontal trees, primarily driven by the fact that the horizontal tree is designed to interface with a BOP rather than a lighter and less demanding LRP/EDP.

It also is true to say that the functional demands being placed on subsea trees are growing. Valve sizes are increasing; required bending capacities are increasing; and more sensors and instrumentation are required, such as flowmeters.

Key takeaways

Application-specific parameters influencing the choice between either tree include operational risk, water depth, sidetracking, and more.

There is no right or wrong choice – what delivers an advantage in one application may not in another. There are perhaps two key takeaways: First, the demands placed on subsea tree designs will continue to evolve, and application-specific parameters will influence the horizontal/vertical technology evaluation. Second, discussion on this subject will continue to exercise the minds of subsea engineers from around the world for some time to come.

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Horizontal Subsea Trees

Horizontal subsea wellheads have found application in the Liuhua oil field in the South China Sea. These trees allow installation and retrieval of downhole equipment through the tree without having to disturb the tree or its external connections to flow lines, service lines, or control umbilicals.

This access to the well is important because the Liuhua wells will be produced with electrical submersible pumps (ESPs), which may have relatively short intervals between maintenance, leading to frequent well work. The wells will be completed subsea in about 300 m of water.

The large bore, horizontal trees allow all downhole equipment to be pulled without removal of the subsea tree. This wellhead configuration also provides well control and vertical access to downhole equipment through a conventional marine drilling riser and subsea blowout preventer (BOP), eliminating the need for costly specialized completion risers.

Another benefit of the horizontal tree is its extremely compact profile with a low number of valves for well control. Valve size and spacing are decoupled from the size and bore spacing of the tubing hanger.

The tree's low profile geometry reduces costs of manufacturing the tree and framework and optimizes load transfer to the wellhead.

LIUHUA

Amoco Orient Petroleum Co., China Offshore Oil Nanhai East Corp., and Kerr McGee Liuhua Ltd. are jointly developing the Liuhua field, the largest offshore oil deposit in the South China Sea. The Liuhua 11-1 field is in 300 m of water about 200 km southeast of Hong Kong (map, p. 60). The field is in a severe weather environment, where typhoons occur frequently and can complicate operations.

The Liuhua field was discovered in 1987 and is estimated to contain more than 1 billion bbl of oil. Despite the significant size of the field, the complex reservoir characteristics and environmental conditions make economic development of Liuhua a major challenge. Well test and model data indicated the reservoir would produce heavy oil under active water drive with high initial production followed by a rapid decline as water production increases.

Because of the water depth and low-energy producing characteristics of the reservoir, a conventional multiplatform development was dismissed because of unattractive economics.

Furthermore, the harsh weather environment puts exceptional technical constraints on floating production systems.

The project design for Liuhua includes two permanently moored floating production vessels and a subsea production system.

The subsea production system consists of all necessary equipment to transfer the oil from the reservoir to the floating production, storage, and offloading (FPSO) vessel, a converted 141,000-dwt crude tanker.

The floating production system is scheduled for installation in 1995 with initial subsea work beginning in mid-1995. Drilling and completion activity will continue until 1997. The FPSO is scheduled for installation in early 1996. The subsea production manifold and 6 of the 21 ESP horizontal subsea trees were recently shipped to begin commercial development of the Liuhua III oil field (Fig. 1).

SURFACE EQUIPMENT

The floating production system is a converted semisubmersible drilling vessel. The vessel will retain its ability to drill, complete, and workover wells while providing support for the subsea production and well systems.

The floating production system will have sufficient electric power generation capacity for the ESPS. The vessel will be permanently moored, and all power and control cables will be tethered from the surface.

The FPSO will be located in 293 m of water approximately 3 km from the floating production system via an internal turret mooring system. The 10-leg inverted catenary mooring system is designed to withstand 100-year typhoon conditions.

Production will flow through the subsea system and pipeline to the FPSO, which will have the capacity to process 65,000 bo/d from a total maximum fluid capacity of 300,000 b/d. The FPSO will also be capable of storing 720,000 bbl of processed crude. The crude will be offloaded via a tandem mooring system to shuttle tankers.

SUBSEA MANIFOLD

The subsea systems are among the most innovative components of the Liuhua development. The manifold system uses a modular concept, which is a unique design for the offshore industry. This system consists of several relatively small components that can be assembled on site by a conventional floating rig and crew, eliminating the need for a costly prebuilt template and its installation.

Moreover, the floating production system is equipped with five moon pools and allows simultaneous operations during the initial seafloor installations and well completion activities.

The concept includes hard pipe jumpers between the wells and a compact central manifold. All the subsea equipment can be installed or retrieved using the floating production system, which will improve the economics of the project. There will be two remotely operated subsea vehicles for all. underwater intervention activities. Safety and other control systems will be operated with hydraulic control systems on the floating production system.

Fig. 2 shows the hydraulic distribution base on the subsea manifold.

HORIZONTAL SUBSEA TREES

The Liuhua development will have about 20 wells, all of which will be produced through horizontal subsea trees with ESPS.

This project is the oil industry's first use of ESPs in a multiwell subsea environment.

The horizontal trees are designed to facilitate the many well operations anticipated during the life of the field. Each tree will have a state-of-the-art electrical connector to supply power to the ESPs. The downhole completions were designed to be simple, yet functional.

The horizontal subsea trees are a flexible, economical alternative to conventional completions. The horizontal subsea tree diverts the flow of well bore fluids horizontally through the tree body.

Unlike conventional subsea trees, the system provides well control and vertical access through a standard marine riser and subsea BOP. This feature eliminates the need for expensive completion and workover risers and allows retrieval of the downhole ESPs and the completion without having to retrieve the tree.

The key benefits of this horizontal subsea tree configuration include the following:

• Permits frequent tripping of the ESP and tubing workovers without removal of the tree or flow lines
• Eliminates the need for complex dual riser systems and associated tools
• Streamlines the workover control system and reduces workover umbilical size
• Reduces total number of valves required (valve size is independent of tubing string size)
• Greatly simplifies tooling package and installation procedures (reduces troubleshooting downtime).

Horizontal trees use the same field-proven components found in conventional subsea trees (tubing heads, subsea valves, tubing hangers, and wellhead connectors), but the components are modified and reconfigured to suit the special operating conditions for frequent full bore workover access through the tree.

In the early part of the installation sequence, the horizontal tree is similar to a conventional tree with a tubing head. Because the tubing hanger lands in the body of the tree, a horizontal tree has the advantages of a tubing head spool used in conventional subsea completions. A horizontal tree is generally insensitive to the position of casing hangers and packoffs in the wellhead below. It provides a known machined landing shoulder for precise interface between the tubing hanger and the tree.

The horizontal tree also) provides new seal profiles to land, lock, and seal the tubing hanger.

Fig. 3 is a schematic of a horizontal subsea tubing hanger system for ESP applications.

Because the horizontal tree is installed early in the installation operation, it can be accessed using the marine riser and subsea BOP to land the tubing hanger, thus eliminating the need for a completion riser (and its rig up time).

Both conventional and horizontal trees require approximately the same number of steps and running tool equipment for wire line operations. The horizontal tree, however, allows full-bore access for downhole tools.

The wellhead is installed first, followed by the tree, tubing hanger, and tree cap. The novel order of installation eliminates a significant amount of intervention steps and equipment during workovers and reduces some equipment and run times required for installation. Table I compares the installation sequences for conventional and horizontal trees. Tables 2 and 3compare the subsea hardware wire line and downhole workover procedures, respectively, for conventional and horizontal trees.

SEALS

Because the subsea trees will be used in an ESP application, they will be configured as an elastomeric sealing system with a separate sealing wear sleeve in the tree bore. Elastomeric seals are the primary seals on the tubing hanger, wire line plug, and internal tree cap.

The sleeve permits retrieval of the seal surfaces in the event of damage from frequent tripping of the pumps through the tree bore. This system also eliminates retrieval of the tree which would be necessary if no wear sleeve were present.

Without the replaceable sleeve, it would be necessary to retrieve the tree to repair the tubing hanger seal surface, if damaged.

The barrier philosophy used for the ESP completion is different from that for a natural lift completion. One of the barriers is considered to be switching the pumps off.

The master valves are bolted on, dual barriers are used upstream of the master valve, and a crown plug is installed through the tubing hanger running tool (THRT), prior to retrieval of the THRT and blowout preventer (BOP).

The second pressure barrier is an external tree cap (installed after retrieval of the subsea BOP), used also to establish the electrical connection to the ESP pump.

Several production mode barrier options were considered for the Liuhua project (Fig. 4). Option 2 was selected but was modified to have an external guide ring to transmit the bending load from the in-water power cable to the tree housing.

Because the electrical connector is a large-diameter, pin-type connector, the production bore of the tubing hanger must be moved off the centerline of the well, and the system effectively becomes a parallel bore system.

Thus, an hydraulically operated tubing hanger running and retrieval tool must be used in conjunction with an orientation system.

The external tree cap also provides the same transfer of workover to production controls provided on conventional completions. A universal running tool will be used to transfer the tree cap from the tree to a stump, allowing access to the well (Fig. 5).

This procedure eliminates the need for retrieving the in-water power cable during workovers.

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Rapid Crack Propagation

Although the PHMSA has noted pipeline safety has improved in recent years, corrosion continues to be a major contributor to pipeline failures, according to the administration. Corrosion could lead to dangerous explosions and fires.

When natural gas pipelines exhibit weaknesses, the pipes may be more prone to corrosion, according to the American Gas Association. Companies may want to be on the lookout for rapid crack propagation (RCP), or when a brittle crack in a material grows and results in fractures, as one of the red flags for pipeline failure, Pipeline and Gas Journal said.

Since the risk of RCP is high for metal pipes, pipeline and utility companies are increasingly choosing durable polyethylene (PE) pipes for upstream and midstream systems.

The risk of rapid crack propagation (RCP) is high for metal pipes. Durable polyethylene (PE) pipes may be a solution for upstream and midstream systems.

Why Pipeline Operators Are Choosing PE Pipe

According to Alliance for PE Pipe, PE pipe is not only durable, but it's also flexible. The properties of PE pipe allow this material to withstand corrosion and chemicals while underground.

Since plastic pipes can endure corrosion better than metal, PE is often used for natural gas pipelines because the process used to make PE pipe makes it less prone to leaks.

Utilities could choose PE piping systems when overhauling underground infrastructure, which may protect them from corroded pipes and joints that could lead to leaks, according to the Plastics Pipe Institute (PPI).

"PE pipes, as well as the heat fusion joints in PE piping, greatly resist the propagation of an initial small failure into a large crack—a major reason for the overwhelming preference for PE piping for gas distribution applications," the report by the PPI said. "And, PE piping retains its toughness even at lower temperatures. In addition, PE piping exhibits very high fatigue resistance. Potential damage by repetitive variations inoperating pressure (surges) is highly resisted."

Factors That Raise Risk of RCP

Pipeline and Gas Journal outlined numerous factors that may contribute to the risk for RCP cracks.

One risk is the size of the pipe; the pipe's diameter may influence cracking. The publication notes that as the diameter of the pipe grows, the risk for RCP also increases.

Another factor is the operating temperature of the pipe. Pipeline operators may want to make sure pipes are protected from lower temperatures because frigid conditions could cause RCP.

Pressure is also a significant factor because a pipeline pressure pulse may contribute to RCP. Companies may want to be aware that there is a higher chance of RCP when the stress in the pipe wall rises. In the event RCP occurs, the consequent pressure waves may result in fragmentation, causing pieces to travel at a high velocity and distance.

What to Look for in RCP

When replacing their existing pipeline and underground infrastructure, pipeline operators may want to look out for warning signs that indicate RCP cracks. Although PE pipelines are more durable against such cracks, they also can appear in this type of material.

According to Pipeline and Gas Journal, an RCP crack is usually presented by a sinusoidal crack within the pipe. Other signs of an RCP crack include the crack going into two directions and butt fusion joints, or when cracks are arrested by electrofusion couplers.

As companies determine what is the best pipeline material for their transmission and distribution operations, they should look into PE pipes for their strength and ability to withstand several factors that could lead to RCP.

Although PE is still vulnerable to RCP, there are a variety of ways pipeline operators can prevent these cracks in PE pipes. If operators choose PE pipeline, they should test the pipe for the amount of pressure it can endure to make sure they limit the chance of RCP.

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Bottom Roughness Analysis

Now, I’m starting to use english for words in my blog because I want to upgrade my english skill in writing.hehehehe ( I hope none of you will be confused with my word). Today,I want to share about on bottom roughness(OBR) analysis. What’s is bottom roughness?It’s an analysis to predict the location of span along subsea pipeline after installation or during operation. So, what’s the different between free span analysis?free span analysis is “only” determine the maximum allowable length of pipeline that unsupported when laid on seabed. The criteria of allowable span is divided into VIV(Vortex Induced Vibration) and ULS (Ultimate Limit State or Static Criteria). Why bottom roughness analysis is so important?Without bottom roughness analysis you don’t know how many support (sand bag, grout bag, etc) that you need to rectify of over span. However, it’s only prediction, so you need further inspection to ensure the location of over span.

2D OBR analysis is very simple, you can use any FEA softwere such as ABAQUS, ANSYS, etc..For this note, I used ABAQUS FEA as mny OBR simulator. The pipeline can be modelled using 1D element (PIPE31H) and the seabed can be modeled using anlaytical rigid of surface. The common step that used for Bottom Roughness is adopted from Subsea Pipelines & Riser book (2005,Yong Bai & Qiang Bai)

After ODB file is produced from your ABAQUS FEA machine, for the next step you need to extract COORD1 (coordinate of pipeline KP), COORD3 (water depth of your Bottom of Pipe [BOP]), and CPRESS (Contact pressure as indicator only to make sure each node of pipeline BOP is touching seabed or not). You can use python file or extract manually using Abaqus Viewer.

1. Open your ODB file (double click you ODB file or open using Abaqus Viewer). On the left side you will see the tree and 2 X click the step you want to extract.
2. Create Path. On the menu bar, please click Tools>Path>Create and you type your path name, click OK then you will face “Edit Node List Path” and please fill Node Labels you want to extract the value, for example 1:7399 (it means node 1 to node 7399).
3. Create XY Data. Click Tools>XY Data>Manager. Please see picture below for easy explanation. Each of your XY data shall be copied in Microsoft Excel. Please check any bug/error with your output result.

Before you try process further with your excel spreadsheet, you must interpolate your water depth of seabed (that has been inputed in abaqus) against your COORD1 data (coordinate of pipeline KP), then you will get new water depth of seabed with same KP with your COORD1 data. Divide your Excel spreadsheet into 2 Sheets.

In the sheet no.1 you need to set your sheet as a sample below. You will see any number span start & span end along the pipeline. Please make sure during pipeline embedded (negative value of span gap) there are any value of CPRESS and vice verse. The maximum gap value along pipeline must be inputted into allowable free span analysis (onset/screening/fatigue criteria as per DNV RP F105)

After that, you have to “sort & filter” each span start & span end, then copy this KP into sheet no.2 as a picture below. From each this formula you will get the overspan results. Please notice that this screening will used maximum gap value along KP start and KP end.  The minimum span gap value that influence VIV, is 30% OD (Ref: OTC No. 4455, 1983, The Influence of Boundary Layer Velocity Gradients and Bed Proximity On Vortex Shedding from Free Spanning Pipeline). Some people used 20% OD (Ref: Sumer and Fredsoe, 1989, Hydrodynamiccs around Cylindrical Structures) as conservatism result

The analysis has not over yet. First, you need to check with centre third of pipeline criteria. If the average center third of pipeline below allowable gap value, you can ignored this over span if it is caused by VIV only (not ULS/Static criteria). But if, you want get the conservatism result, you can consider this span is over span (But it will affect your span rectification cost). Second, you need to check the uplift possibility (or look like upheaval) in your ABAQUS FEA model. It should be not happened because the weight of pipeline and wave/current will forced this uplift section to drop on seabed as lateral buckling. So, if your over span is occur in this uplift section, please ignore it as a span, but you must check the integrity of this section (Using Load controlled Check & Displacement Control Check as per DNV F101). Third, you need to reassessed again each over span section with each gap value and recalculate again in allowable free span assessment, so you will get new allowable span that longer than before.

Your 2D Bottom Roughness Analysis is end from here. But if you want, you can do re-analysis (start form sheet-1) with interactivity phenomenon [during VIV, your span is will induced vibration with its neighbor span, so make this effective length is longer than isolated span]. As per DNV RP F105, you can determined each  span is a kind of isolated or interacting span as a diagram below.

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Step-by-step Approach to Pipeline Integrity Management

In the early 1990s asset integrity management was addressed by increasing inspection programmes. In the late 1990s, increasingly sophisticated IT tools were developed, and today a complex mix of strategies, IT solutions and inspections are often employed. This can potentially lead to client dissatisfaction, since from an operator’s point of view ‘it costs a lot, it’s complicated and we’re not sure we really need it’.

Bureau Veritas attended a conference where an operator presented on the issues involved in implementing a highly sophisticated integrity management system. In particular the issue of anticipating difficulties related to methodologies, data, management of change, etc. In response, Bureau Veritas explained the difficulties of taking on such a wide scope at once. The operator immediately replied: “Guys, you have the 360° view, we don’t. You should teach us all that and warn us!”

No revolution but simply common sense

There are many different definitions of pipeline integrity management (PIM), including those listed within API 1160 and ASME B31.8S.

As a simple and understood-by-all definition, the following is proposed: “a system to ensure that a pipeline network is safe, reliable, sustainable and optimised.”

Bureau Veritas’ PIM step-by-step approach is comprised of the following six stages:

• Policy and strategy: where are you now, where do you want to go and what should you put in place to reach your target?
• Methodology: do you want/need to use a risk-based, threat-based or consequence-based approach or something else?
• Data: start thinking about data collection and modelling only once the policy and strategy, and methodology have been identified.
• Systems and tools: once policy and strategy have been defined, methodology has been selected and data gathered, select the most appropriate tool to use (simple or sophisticated software).
• Study and analysis: the tools will enable an assessment of the pipeline network and definition of your inspection plans.
• Inspection and expertise: after implementing the inspection plans, specific expertise should be used to analyse the inspection results. The knowledge gained will then be used during the regular PIM review.

Company policy and methodology is key

As a first step, it is important to properly define the roots of the PIM approach chosen. Local constraints, in-house specific requirements, international guidelines and adequacy will help set up the basis of the methodology to be developed.

The most appropriate approach will be found by referencing the local regulatory body’s policy (safety/inspections-oriented or risk/threat mitigation-oriented) along with common practices and existing procedures, the assets’ typology and age, the existing international best practices, and the level of in-house expertise. Several approaches may be considered, such as qualitative versus quantitative, threat-based versus damage-based, and probabilistic versus deterministic.

The identification of expected results (primary target) should be properly specified: restricted impact on the environment, corrosion-related failure prevention, inspection strategy, and means of mitigation. This will ensure that the PIM is set up in-line with the project targets.

The PIM methodology can then be chosen and tailored to the specific case.

A PIM approach that may be suitable for one operator may not be acceptable for another operator.

Only once the methodology is developed and understood by all project stakeholders can the data and tool issues be properly addressed.

Data and tools: you don’t need a video game

Data management is a crucial task within the PIM process. It should provide a complete system capable of delivering the right data in the right shape, at the right place and for the right purpose. This requires very organised and step-wise work.

By defining the PIM strategy, key performance indicators can be identified and data requirements can be defined. This refers to the format, accuracy, and frequency requirements of the data. It is also beneficial to think mid-term about PIM requirements, for example, consider the tools that will be used and any modifications that might be planned to the asset.

Finally, it is advised that data quality control/quality assurance is performed to obtain the ‘green light’ before processing data into the PIM process.

The same applies to the tools to be used. While there is a temptation to use a very ‘high tech’ tool, the most important consideration is for an easy-to-use tool that will monitor the health of the pipeline network and point out pipeline segments which require mitigation or inspection due to their threat or risk levels.

Depending on the pipeline’s length, a Microsoft Excel macro could be sufficient. However, an automated and integrated tool is necessary for longer pipelines or complicated networks.

Study and analysis: from integrity assessment to inspection plans

Now with an operational and clear pipeline database along with a PIM tool, the chosen PIM methodology can be implemented. The PIM tool will enable the first integrity assessment to be carried out – ‘first’ because PIM is a continuous loop where previous results are used to improve the following assessments. Following this, a ‘pipeline prioritisation’ can be obtained, which will form the basis to analyse and understand the pipeline network’s condition. Frrom here, the PIM can be expanded to include a mitigation plan plus inspection plan.

Here an important question arises: what actions should be performed in order to reduce the threat/risk level on the pipeline? Should the inspection frequency be increased, a mitigation action applied, or both? The decision should rely on the inspection and mitigation policies defined in the first step of the PIM process.

Inspection and expertise: method qualification and trustworthy results

Undoubtedly, one of the most visible steps of the PIM process is the inspection itself. There are many inspection techniques for pipelines but the most widely used are magnetic-flux leakage and ultrasonic testing. The in-line inspection provider should be selected very carefully, evaluating their qualification by referring to the specific requirements of the project.

The most critical part of this process is the analysis of results and the expertise required to obtain crucial information on the actual condition of the pipeline.

An effective PIM should be comparable to a high-quality management system.

This article started by outlining that a PIM is a system allowing operators to ensure that their pipeline networks operate in a safe, reliable, sustainable and optimised way.

If neglected and unused, even the most expensive and ‘high tech’ PIM solution will fail to be beneficial. A PIM needs to be accepted and embedded into the company’s processes.

Therefore, as a conclusion, Bureau Veritas would advise operators to keep in mind that a PIM, like a quality management system, is a continuous process. Therefore it is important to break down the PIM plan into manageable steps.

Acknowledgements

The author and co-authors of this article would like to express their gratitude to their customers, in particular TOTAL (Worldwide), CuuLong Joint Operating Company (CLJOC – Vietnam) and KazTransOil (KTO – Kazakhstan) who have fed Bureau Veritas’s thoughts about PIM and asset integrity management (AIM) in general. Not only have those successful and friendly collaborations inspired Bureau Veritas to develop its AIM ‘step-by-step approach’ but have also allowed a deeper knowledge of AIM which, we trust, will be useful to other pipeline operators.

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Pipeline Ending Manifold (PLEM) /PLET

Subsea manifold is a flow-routing subsea hardware (subsea flow router) that connects between subsea trees and flowlines. It is used to optimize the subsea layout arrangement and reduce the quantity of risers connected to the platform. If connected to dual flowlines, the manifold can typically accommodate pigging and have the capability of routing production from a particular tree to a particular flowline.

Pipeline End Manifold (PLEM)

It a simpler version of a cluster manifold generally designed to direct fluids for only one or two subsea Christmas trees. A PLEM generally connects directly to a subsea flow line without the use of a pipeline end termination (PLET).

Manifold Compenents

Four well manifold P&ID.

A manifold is typically composed of the following major components:

• Pipework and valves – contains and controls the production and injection fluids.
• Structure framework – protects and supports the pipework and valves.
• Subsea connection equipment – allows subsea tie-in of multiple pieces of equipment. Types include vertical, horizontal and stab-and-hinge-over connections.
• Foundation – interface between the manifold structure and seabed.
• Controls Equipment – allows the remote control of any hydraulically actuated subsea manifold valves and the monitoring of production and injection fluids. Control pods may be either internal or external to the manifold.

Valves

Valves on the manifold are essential for directing and controlling the flows. They can be either manual or hydraulically actuated. Sometimes chemical injection valves are placed on the manifold as well.

• Branch valves are generally slab type gate valves (similar to tree valves). Their sizes are based on the production/injection tree size.
• Flowline header valves are also gate type, but ball valves have been used previously. Their sizes are based on the flowline size.
• Materials are chosen for compatibility with production and injection fluids. Most of time, it is CRA-clad.
• Double barrier philosophy generally used against production fluids.
  • Two valves in series
  • One valve and one pressure cap
  • Primary seal is generally a metal-to-metal seal

Pipework

A wide range of pipework configurations is possible. Each header connects to an individual flowline. the pipework sizing is based on the tree piping size and the flowline diameters. The main circuit is designed to accommodate pigging operations. The material of construction needs to be compatible with production and injection fluids.

• Test headers can be incorporated to test individual or groups of trees
  • Test headers can be a second or even third header isolated in the manifold
• Insulation may be required for unscheduled or emergency shutdowns

Control System

Control system for the manifolds is the same as the control system for the trees. Multiple options for the control system have been used in the manifold design

• No controls on the manifold. The manifold is controlled by tree subsea control modules (SCMs).
• SCMs on the manifold.
• Manifold with control system distribution units with flying leads going to trees.

Framework Structure

The framework is a welded structure to provide support for the pipework and valves and contain the foundation interface structure. The pipework is allowed to float inside the framework within limits and it is not rigidly attached to the frame. The frame can also be used for lifting and landing of the jumper tie-in tools.

Foundation

• Mud mats – a simple foundation resting directly on the seabed, generally with a short skirt around the perimeter to resist lateral loads.
• Piles – long cylindrical structures embedded into the soil intended to hold a subsea structure above the seabed. Foundations may utilize one or more individual piles.
• Intermediate Structures – an intermediate structure can be used to interface a subsea manifold with a pile foundation to reduce weight of the manifold structure or to ease retrieval of the manifold. Intermediate structures can be either retrievable or permanent structures.

Tie-ins to wells and flowlines

The tie-in hubs placed on the outer edge of the manifold, which are used to tie-in jumpers that bring in fluid from the production wells and export fluid into the flowlines (production manifold). The tie-in sizing is based on the tree piping size and the flowline diameters. and the loads applied from the flowlines

Insulations

Generally gas manifolds are not insulated and oil manifolds are insulated. For oil production, insulation is necessary to allow adequate cool-down time to treat or remove trapped production water. Gas production is generally treated continuously with chemicals to prevent hydrates.

Deployment method

The following vessels are typically used for manifold deployment:

• Drill Rig: through moon pool or keel-hauled on drill string
• Heavy Lift vessels (Derrick Barges): through moon pool or over side
• Work-class vessels: over side on crane or winch

The following equipments are typically required:

• Manifold hydraulic installation tool
• Sling sets, either wire rope or synthetic fiber

Applicable API Specs

• API Spec 17P – Templates and Manifolds
• API Spec 17D – Specifications for subsea wellhead and Christmas tree equipments
• API Spec 17A – Recommended practice for design and operation of subsea production systems
• API Spec 17H, ISO 13628-8 – ROV Interfaces

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