HDPE Pipe

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. 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.

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.

High density polyethylene plastic pipe (HDPE) delivers exceptional value, unwavering reliability and remarkable advantages over conventional types of piping. It's today's right choice for water, drainage, fuel gas, conduit and plumbing & heating. Other reasons HDPE is a superior choice:

• Long-term service life
• Highly-resistant to corrosion, abrasion and chemicals
• Strong, durable, flexible and lightweight
• Longer-length pipe with leak-proof joints
• Lower labor requirements for installations
• Significant overall cost savings

Sources : https://en.wikipedia.org/wiki/High-density_polyethylene

http://www.jayaterusmultiniaga.com/product/high_density_polyethylene_hdpe_pipes__fittings.html

Pipeline Thermal Insulation

Assets such as offshore pipelines, risers, spools and subsea structures which transport liquid products may be required to maintain a minimum temperature while the product is being transported within the asset, particularly offshore. Some liquids such as oil and gas can leave wax or hydrate deposits if a minimum temperature is not maintained. These deposits can, over time, build up and block the asset/pipeline either reducing or completely stopping flow/production. External wet insulation can be designed and applied to ensure the reduction in product temperature is kept within a range so the risk of deposits during production is acceptable. Insulation can also reduce the frequency of pigging operations during the life of the asset.

During other operational events, such as pipeline shutdowns, the product is contained in a stationary state within the asset/pipeline while the process facility has other operations performed. Similarly, to avoid deposits during these shutdown periods external insulation can be designed and applied to ensure the reduction in product temperature is kept within a range so the risk of deposits during shutdowns is acceptable.

Injected Molded Polyurethane Applications provide thermal insulation and are commonly used offshore on flowline and riser field joints, spools and subsea structures. It is used less often onshore to thermally insulate pipelines and spools. The asset will require to have been pre-coated with an anti-corrosion layer prior to the thermal insulation application.

The preparation for IMPU requires that the anti-corrosion layer is in good condition and the bevel faces of the parent coating (usually PP) are cleaned, abraded and then pre-heated to build bond strength between the PP and IMPU. Once this preparation is completed a mold is placed over the area to be treated and Solid Polyurethane is injected into the annulus and often overlapping the parent coating bevel faces and onto the OD surface of the PP. Once the material cures the mold is removed and inspected.

OJS can apply all Solid Polyurethanes available on the market however we recommend our own formulated solid polyurethane material calledDensiflex for IMPU coatings. Densiflex is mercury free and fast curing – which is suitable for the offshore market.

Injected Molded Polypropylene Applications provide thermal insulation on pipeline and riser field joints and spools. The asset will require to have been pre-coated with an anti-corrosion layer prior to this thermal insulation application.

The preparation for IMPP requires that the anti-corrosion layer is in good condition and the bevel faces of the parent coating (usually PP) are cleaned, abraded and then pre-heated to build bond strength between the PP and IMPP. Once this preparation is completed a mold is placed over the area to be treated and Solid Polypropylene is injected into the annulus. Once the material cures the mold is removed and inspected.

Contoh Pipeline Thermal Insulation

Sumber : http://www.f-e-t.com/our_products_technologies/subsea-solutions/pipeline-field-joint-coatings/thermal-insulation-for-pipelines-risers-spools-and-subsea-structures/

Spiral Pipe for Offshore Application

Spiral welded line pipe has been used extensively for onshore applications, however there has been some reluctance to specify spiral welded line pipe for offshore applications. A joint industry project is beeing carried out together with coil manufacturers, pipe manufacturers, installation contractors and operators to review the status regarding offshore applications for spiral welded pipes and identify the most critical technology gaps using a technology qualification process. Detailed suggestions as to how the gaps can be met have been made. An update on efforts to close these gaps is ongoing.

The challenges for spiral welded line pipe include design, metallurgical and quality control issues. The design issues include fracture arrest, collapse and displacement controlled loading conditions which are all highlighted in DNV standard for submarine pipelines (DNV OS F101). The design issues regarding load controlled displacement are mainly due to limited experience with spiral welded line pipe subjected to large strains. For running fracture the limited experience with spiral welded pipe for offshore applications is an issue.

There are 5 new spiral welded pipe mills in United States so availability has improved. The review includes an assessment of typical pipe material test results and whether properties required for offshore applications can reasonably be expected.

It appears that the industry has a general understanding that the performance of spiral welded (SAWH) pipes is different to Submerge Arc Welded (SAWL)/ High Frequency Welded (HFI)/ Electric Resistance Welded ERW linepipe when exposed to the same loading conditions, and that currently existing design standards for offshore applications may not be applicable. An important issue is to establish how the spiral wound linepipe can be produced consistently to a high level of quality, and what is required by the design standard for spiral welded pipe to be fit for purpose for offshore use. Some of the main areas of concern regarding the quality of spiral wound linepipe will be discussed. The aim is to assess whether SAWH linepipe can be considered equivalent to SAWL and HFI/ERW linepipe.

The use of spiral welded linepipe (SAWH) for pipelines has generally been themost popular manufacturing choice of linepipe for onshore low pressure pipelines, pipelines transporting water, ship borne piping, or very shallow water, low pressure pipelines (≤ 500 ft).

Recently there has been more interest in the use of spiral wound linepipe, dueto the following reasons:
• There are five new SAWH pipe mills in America with “state-of-the-art” technology.
•  SAWH linepipe is a cost-effective solution compared to the other manufacturing processes.
•  Generally, the chemical compositions, mechanical properties anddimensional tolerances are assumed to be comparable to SAWL pipe.
•  SAWH linepipe can be manufactured in 80 ft lengths with diameters from 20 to more than 100-inch OD and wall thicknesses ranging from approximately 9to 25 mm.
•  Some SAWH pipe mills have coating capabilities for 80 ft pipe lengths(FBE and 3-layer coating systems). 80 ft pipe lengths could mean less fabrication costs for the installation contractors.

Source : http://www.petrotraining.org/spiral-wound-line-pipe-for-offshore-applications-8118-32

Pipeline Stress Analysis

WHAT IS STRESS ANALYSIS?

Piping stress analysis is a term applied to calculations, which address the static and dynamic loading resulting from the effects of gravity, temperature changes, internal and external pressures, changes in fluid flow rate and seismic activity. Codes and standards establish the minimum requirements of stress analysis.

PURPOSE OF PIPING STRESS ANALYSIS

Purpose of piping stress analysis is to ensure:

·         Safety of piping and piping components.

·         Safety of connected equipment and supporting structure.

·         Piping deflections are within the limits.

HOW PIPING AND COMPONENTS FAIL (MODES OF FAILURES)

There are various failure modes, which could affect a piping system. The piping engineers can provide protection against some of these failure modes by performing stress analysis according to piping codes.

1.  FAILURE BY GENERAL YIELDING : Failure is due to excessive plastic deformation.

·         Yielding at Sub Elevated temperature: Body undergoes plastic deformation under slip action of grains.

·         Yielding at Elevated temperature : After slippage, material re-crystallizes and hence yielding continues without increasing load. This phenomenon is known as creep.

2. FAILURE BY FRACTURE : Body fails without undergoing yielding.

·         Brittle fracture : Occurs in brittle materials.

·         Fatigue: Due to cyclic loading initially a small crack is developed which grows after each cycle and results in sudden failure

WHEN PIPING AND COMPONENTS FAIL (THEORIES OF FAILURE)

Various theories of failure have been proposed, their purpose being to establish the point at which failure will occur under any type of combined loading. The failure theories most commonly used in describing the strength of piping systems are

·         Maximum principal stress theory

This theory states that yielding in a piping component occurs when the magnitude of any of the three mutually perpendicular principle stresses exceeds the yield point strength of the material.

·         Maximum shear stress theory

This theory states that failure of a piping component occurs when the maximum shear stress exceeds the shear stress at the yield point in a tensile test.

In the tensile test, at yield, S1 =Sy (yield stress), S2=S3=0.So yielding in the components occurs when

Maximum Shear stress =τmax=S1-S2/ 2=Sy / 2

The maximum principal stress theory forms the basis for piping systems governed by ASME B31.3.

Note: maximum or minimum normal stress is called principal stress.

Source : http://www.pipingdesign.com/stressanalysis.pdf

Pipeline Ending Manifold (PLEM)

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 

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

Source : http://www.piping-engineering.com/pipe-flanges-types-systems.html

Pipeline Upheaval Buckling

When production starts through a pipeline, internal temperature and pressure will rise. The temperature increase will lead to thermal expansion of the steel. A pipeline will be restrained variously along the routing due to soil friction, and the temperature rise will result in axial compressive forces in the pipe. As a response to the longitudinal compressive force interacting with local curvature of the pipe, global buckling may occur.

A pipeline can buckle downwards in a free span, sideways on the seabed or upwards for buried pipelines. Vertical buckling of a pipeline is called upheaval buckling, and the direction of the buckle is upwards because this is the way of least resistance. If a vertical buckle leads the pipe into exposure on the seabed, this is a severe problem. An expensive and time consuming operation is needed to re cover the pipe at this location. If the buckle damages the pipeline, this part must be replaced before re covering takes place.

Figure describes upheaval buckling on buried pipe.

For upheaval buckling to occur, the pipeline must first have an initial imperfection. Imperfections are typically due to the pipeline being laid over a boulder or due to irregularities in the seabed profile.
Figure below illustrates a sequence of events which initiates buckling in a buried pipeline:



The pipeline is laid across an uneven seabed (a) and later trenched and buried (b). The trenching and burial operations modify the profile of the foundation on which the pipe is resting, so that it is not precisely the same as the original profile. Trenching may smooth the profile overbends, but may also introduce additional imperfections, if, for instance, a lump of bottom soil falls under the pipe.

Source : http://brage.bibsys.no/uis/bitstream/URN:NBN:no-bibsys_brage_25027/1/Ommundsen,%20Marius%20Loen.pdf

http://www.engr.mun.ca/~spkenny/Courses/Undergraduate/ENGI8673/Reading_List/1990_Palmer_Upheaval_Buckling.pdf

Pipe in Pipe

Pipe in pipe systems allow a range of advanced and highly efficient insulation materials to be used to achieve Overall Heat Transfer Coefficients less than 1 W/m2 K. These systems are important components of subsea developments where untreated well fluids may have to be transported large distances and wax and hydrate problems have to be managed. However, as a result of this efficient insulation, thermal expansion challenges are increased and techniques such as probabilistic analysis, upheaval buckling design, snake lay or cooling spools employed to mitigate high expansion loads. 
CHALLENGES 

• High Temperature Well Fluids 

High temperature well fluids increase the overall levels of energy in the system increasing the risk of uncontrolled buckling of the flowlines and increasing project costs through the use of pipeline anchors, rockdump or trenching, more exotic materials and the concern that the predicted design temperature is outside the range of applicability of existing design codes. 

• Wax/Asphaltene/Hydrate formation within product stream 

In heavy oils or multiphase pipelines excessive cooling of the product during transportation can result in drop out of high molecular weight waxes and asphaltenes. Increasing the operation increasing the operational pigging requirement of the system, increasing OPEX. In wet gas systems hydrate formation during startup or blow-down conditions can block pipelines. 

• Long distance tie-backs 

Long tie back from a subsea facility to the host platform increases the length of time that the production fluid is subjected to heat loss through the pipeline wall, increasing the risk of flow assurance issues, particularly in the event of shutdown condition and extended residence time of thefluid in the pipeline. 

• Low OHTC value requirement (<1 W/m2K) 

For long tie backs or production fluids with high critical temperatures the Overall heat transfer Coefficient requirements of the system can be onerous. Requiring conventional wet insulation thickness in excess of practical thicknesses for application or installation. 
SOLUTIONS 

• Use of Cooling Spools 

There can be significant cost benefit from cooling the product stream from very high temperature wells to minimise the thermal expansion forces and then maintaining this lower temperature for through efficient pipeline insulation reducing the volume of post lay rock dump or trenching required or enabling more conventional materials and analysis techniques to be employed. 

• Pipe In Pipe 

Installing a second pipeline around the product pipeline isolates the carrier pipeline from the seawater surrounding it and creates a dry chamber around the pipeline that can be engineered to accommodate a range of advanced insulation techniques. 

• Materials 

Typically pipeline insulation must be able to withstand the stresses imposed as a result of the installation methods and also be strong enough to withstand constant external pressure and function effectively when submerged and saturated. The dry, load-free environment within the annulus of the pipe allows non-typical insulation materials with much lower thermal conductivities to be applied subsea than has historically been possible e.g. rock-wool systems etc. 

Source : http://www.jpkenny.com/SiteCollectionDocuments/PIPE%20IN%20PIPE%20REV%2001.pdf