Sunday, January 25, 2015

The Practical Differences in Material Properties of Flexible Pipe Products


By Darrell Sanders, P.E., and Andrew Jenkins, E.I.

Learning Objectives

After reading this article you should understand:
  • Understand the intrinsic behavior of buried flexible pipe structures.
  • Distinguish between design strength and serviceability parameters as defined by national specifications.
  • Understand the nuances between laboratory-based quality control procedures and experience-based installation quality assurance best practices.
  • Understand the practical considerations of the concepts pipe stiffness and flexibility factor.

Overview

Buried flexible structures used for culverts, drainage, and sewers are fabricated from a variety of materials to form soil-interaction pipe systems. The physical properties of each material or combination of materials used to fabricate pipe are characterized by either linear or non-linear elastic behavior that is strongly influenced by strain rate. This paper discusses the basic material properties that affect strength, the technical differences between the terms flexibility factor and pipe stiffness, the practical implementation of flexibility and stiffness values that are associated with various pipe products, and how these affect handling, installation, and short-term and long-term performance.

Material properties of flexible pipe

When the AASHTO LRFD Bridge Design Specifications Section 12 were written, all buried structures were grouped together in a common document. This is convenient for the designer who is charged with evaluating and specifying buried pipe and conduit that is used for culverts, drainage, and sewers. This article focuses on flexible pipe structures.
Practicle Differences in Material Properties of Pipe
Ninety-six-inch steel-reinforced polyethylene pipe installation in New Mexico
Considering engineering mechanics of solids, there are two general classes of material used to fabricate flexible pipe. Materials that are classified as linear elastic include steel (AASHTO M36, M245) and aluminum (AASHTO M196) pipe of various corrugation depths and steelreinforced thermoplastic pipe (AASHTO MP20-10). Materials that are classified as non-linear include corrugated, solidwall and profile-wall high-density polyethylene or HDPE (AASHTO M294, and ASTM F714-08, respectively), profilewall and solid-wall polyvinyl chloride or PVC (AASHTO M304 and AASHTO M278) and glass-reinforced polymer mortar (ASTM D3262 and D3754). Table 1 lists these flexible pipe types and compares properties.
As a linear elastic material, metals behave predictably within typical service temperatures and maintain their mechanical properties under constant load (Figures 1 and 2). Thermoplastic materials exhibit non-linear elastic behavior and are sensitive to rate of strain, temperature, and creep. Creep is a visco-elastic phenomenon where the strain in a material continues to increase with time when subjected to a constant load (Figure 3). Although glass fibers show linear elastic behavior in a small displacement field (small strain), they do, along with most polymers used to fabricate plastic pipe, behave with visco-elastic characteristics and exhibit creep under long-term loads.

Figure 1: Constant load applied to a material
Figure 1: Constant load applied to a material


Figure 2: Constant strain response under constant loadFigure 2: Constant strain response under constant load


Figure 3: Increasing strain response under constant load. Example shows slight recovery after load is removed.Figure 3: Increasing strain response under constant load


The industry recognizes the difference between short-term and longterm plastic pipe properties and sets elastic modulus properties accordingly. Depending on the chemistry of the thermoplastic material, the ratio of short-term to long-term elastic modulus ranges between 3 and 5.
Strain gage placement per steel-reinforced polyethylene pipe full-scale load testing
Strain gage placement per steel-reinforced polyethylene pipe full-scale load testing

Design for strength

All flexible pipes are designed for strength using the same general approach. For a given material, wall section, and pipe diameter: the applied loads are determined, soil-interaction with the flexible pipe is modeled, stress in the wall area is computed, then local effects such as buckling or seam strength are checked.
Linear elastic materials are addressed in AASHTO LRFD Section 12.7 and non-linear plastic materials are addressed in AASHTO LRFD Section 12.12. Readers will notice that while the two specification sections use the same general approach to overall design, the physical differences in the character of the materials are treated with appropriate elastic or thermoplastic consideration. The engineer must use judgment to select appropriate short or long term modulus values. These values are necessary for limit state computations.
Inconsistencies between descriptive language and the equations within the AASHTO specification can be difficult for the engineer to interpret.
Table 1 – Comparison of round flexible pipe systems
Primary Structural MaterialElastic BehaviorCreep BehaviorTemperature-Dependent BehaviorShort-Term Elastic Modulus (ksi)Long-Term Elastic Modulus (ksi)
Corrugated Steel-
¼ inch & ½ inch deep
LinearNoNo29,00029,000
Corrugated Steel-1 inch deepLinearNoNo29,00029,000
Spiral Ribbed SteelLinearNoNo29,00029,000
Steel Structural PlateLinearNoNo29,00029,000
Steel-Reinforced PolyethyleneLinearNoNo29,00029,000
Corrugated Aluminum-
¼ inch & ½ inch deep
LinearNoNo10,00010,000
Corrugated Aluminum-1 inch deepLinearNoNo10,00010,000
Spiral Ribbed AluminumLinearNoNo10,00010,000
Aluminum Structural PlateLinearNoNo10,00010,000
Glass-Reinforced Polymer Mortar*Non-LinearYesYes2,6001,500
Profile Wall PVCNon-LinearYesYes440140-158.4
Solid Wall PVCNon-LinearYesYes440140-158.4
Solid Wall HDPENon-LinearYesYes11022
Corrugated HDPENon-LinearYesYes11022
* GRPM pipe elastic modulus are apparent values based on hoop testing.

Serviceability

Serviceability is considered for all flexible pipe materials. The overall idea is that a flexible, round pipe should stay (essentially) round during fabrication, handling, delivery, installation, backfilling operations, and initial soil consolidation. All of the soil-interaction models are based on the assurance that a round pipe maintains the desired shape. Also, all joint types, including soil-tight, silt-tight, leak-resistant, and special designs (designed to resist shear, bending, pull apart, pressure, or water-tight), are dependent on the anticipated roundness of the pipe (AASHTO PP63-09). Because construction is not a perfect science, some allowances are made recognizing that flexible round shapes won't be perfect in geometry, but will still function as desired while being structurally sound.
The approach to checking the handling and installation stiffness (or how well the pipe is expected to maintain a round shape) for most flexible pipe systems is based on the concept of the flexibility factor or FF which is computed by the equation:
Equation 1
FF = D
2/EI (inches/kip)
where:
D = Diameter in inches (in.);
E = Est = Short Term Modulus (ksi);
and
I = Moment of Inertia of the Pipe Wall (in.4/in.)
The computed flexibility factor should not exceed the limits prescribed by AASHTO Section 12. Note that the short-term modulus for plastic pipe does not account for any temperature effects during stockpiling or storage immediately prior to installation.

Pipe stiffness as a quality control procedure

ASTM D2412 is known as the parallel plate test and is used to measure the load at which a predetermined deflection is observed in a particular sample of plastic pipe. The parallel plate test is governed by ASTM sub-committee 17.11, which has responsibility for developing and maintaining standards for plastic pipe. In the test method, the term pipe stiffness is used to quantify laboratory behavior that is somewhat unique to thermoplastic pipe and reinforced polymer mortar pipe.
The test method recognizes possible variability in measured data because of the intrinsic properties of thermoplastic pipe materials. As a result, the rate of deflection and testing temperatures are specified in exact terms. One purpose of carefully controlled test conditions is to establish a precision statement for the test method. Precision statements are mandatory for all ASTM Test Methods per the ASTM manual on "Form and Style for ASTM Standards (March 2010)."
The Form and Style manual states: "Precision is the closeness of agreement between test results obtained under prescribed conditions. A statement on precision allows potential users of the test method to assess in general terms its usefulness in proposed applications. A statement on precision is not intended to contain values that can be duplicated in every user's laboratory. Instead, the statement provides guidelines as to the kind of variability that can be expected between test results when the test method is used in one or more reasonably competent laboratories."
The results from the practical application of the test method help a manufacturer with quality control for a product as various day-to-day production variables must be addressed. Certificates ensuring the purchaser that a quality control program is utilized should accompany the materials during delivery. As part of an overall quality control plan, a manufacturer can use the test method to:
  • Establish a baseline for product acceptance
  • Compare various plastics in pipe form
  • Study the interrelations of dimensions and deflection properties of plastic pipe and conduit
  • Measure the deflection and load resistance at any of several significant events (liner cracking or crazing, rupture, wall cracking, or wall delamination) if they occur during the test (visible to the unaided eye)

ASTM D2412 defines pipe stiffness (PS) as:

Equation 2
PS = F/?
y (lbf/in./in.)
where:
F = Force per inch of Pipe Length (lbf/in.)
?y = Deflection at F (in.)
The test method warns, "although PS units are dimensionally the same as those for pressure and stress, they are different quantities and should not be confused one with the other."
As a result, pipe stiffness as determined by ASTM D2412 is not the same as the pipe stiffness value used in AASHTO Section 12.12. Simply stated, this is not a direct comparison. The prescribed deflection rate and temperature of the ASTM parallel plate test are not relevant to actual in situ loads and exposure temperatures of a buried pipe.
For a composite pipe system such as steel-reinforced polyethylene, the use of pipe stiffness per ASTM D2412 is intended to provide a basis for manufacturing quality control not structural design. AASHTO MP20-10 states, "The pipe shall have minimum pipe stiffness at 5 percent deflection as listed [in the tables]… 5 percent deflection criteria was selected for testing convenience and should not be considered as a limitation with respect to in-use deflection."

Tested pipe stiffness versus structural design capacity

Equations in AASHTO Section 12.12 contain terms that appear to be similar to pipe stiffness. These computed terms are different than the numbers that result from tested pipe stiffness. For example, strain is computed for thermoplastic pipe per AASHTO Section 12.12.3.5.4 using a series of equations that consider pipe stiffness. Throughout the computations, the long-term modulus value is used. In this procedure, the equation for pipe stiffness is:
Equation 3
PS = F/? = E
ltI/(0.149 R(sup)3) (kip/in.-in.)
where:
F = Load per inch of Pipe (kip/in.)
? = Vertical Deflection of Pipe (in.)
Elt = Long Term Modulus (ksi)
I = Moment of Inertia of the Pipe Wall (in.4/in.)
R = Radius of Pipe to Centroid of Wall Section (in.)
Unlike Equation 3, it is important to emphasize that in the procedure described by ASTM D2412, the magnitude of pipe stiffness is determined by a carefully controlled laboratory test. Traditionally, pipe stiffness is not used for corrugated metal pipe; however, it does have usefulness with steel-reinforced polyethylene pipe. Although dimensionally the same as stress, pipe stiffness does not compute a magnitude of stress in the pipe wall.

Pipe stiffness and flexibility factor for quality assurance

Where quality control is procedural and testing protocol establishes a basis for acceptance, quality assurance is practice based and related to documenting or providing a pledge of performance. In a manufacturing setting, quality assurance takes the form of providing a certificate or some other tangible means that the product was manufactured, tested, and supplied in accordance with a predetermined specification. The pipe stiffness values, as measured by the parallel plate test in ASTM D2412, provide data relevant to acceptance of a finished product compared with an established baseline in strictly controlled laboratory testing conditions.
At the jobsite, installation assurance should follow industry standards such as AASHTO LRFD Bridge Construction Specifications. Corrugated metal pipe is addressed in Section 26 and thermoplastic pipe is addressed in Section 30. Both specification sections state that the overall performance of the flexible pipe is highly dependent on installation handling, backfill material, and methods used to place and compact the backfill. Final visual inspection and acceptance of the installation by the owner's technical representative is made significantly easier when appropriate consideration is given to pipe flexibility and pipe stiffness principles. At the time of this article, the principles of either Section 26 or 30 can be used for the installation of steel-reinforced polyethylene pipe.

Conclusion

Many flexible pipe systems are commercially available in a variety of materials, sizes, and wall configurations. In order to understand the overall behavior, design, and installation of flexible pipe, it is important to know how to navigate various industry specifications. Practitioners should be aware that the key difference between the behavior of metal and steel-reinforced polyethylene pipe and the behavior of thermoplastic pipe is how the time-dependent modulus is applied. Appropriate use of flexibility factor and pipe stiffness concepts for serviceability is emphasized.
Pipe stiffness is not necessarily related to the buried pipe's ability to handle loads. Pipe stiffness, as determined by ASTM D2412, is a tested value and it is not used in strength checks in the AASHTO specification. Appreciation of the differences related to types of pipe materials being considered for applications is critical. Misconceptions and misuse of standards should be avoided. With careful consideration and understanding of design principles, the practitioner can evaluate short-term installation considerations along with long-term structural reliability.

Darrell Sanders, P.E., is chief engineer for CONTECH Construction Products Inc. He holds a B.S. degree in Civil Engineering from the University of Cincinnati and an MBA from the University of Dayton. He has been a registered Professional Engineer in Ohio since 1996. Sanders is a member of several industry committees, including NCSPA, AASTHO, ASTM, and Uni-Bell.
Andrew Jenkins, E.I., is the national plastic products manager for CONTECH Construction Products Inc. He holds a B.S. degree in Engineering from Missouri University of Science and Technology (Rolla). Jenkins' experience comes from 13 years in the petroleum, mining, and civil engineering industries.

REFERENCES

  • AASHTO LRFD Bridge Design Specifications, 5th Edition, 2010.
  • AASHTO M36, Standard Specification for Corrugated Steel Pipe, Metallic- Coated, for Sewers and Drains.
  • AASHTO M245, Standard Specification for Corrugated Steel Pipe, Polymer-Precoated, for Sewers and Drains.
  • AASHTO M196, Standard Specification for Corrugated Aluminum Pipe for Sewers and Drains.
  • AASHTO MP20-10, Standard Specification for Steel-Reinforced Polyethylene (PE) Ribbed Pipe, 300- to 900-mm (12- to 36-in.) Diameter.
  • AASHTO M294, Standard Specification for Corrugated Polyethylene Pipe, 300- to 1500-mm (12- to 60-in.) Diameter.
  • ASTM F714-08 Standard Specification for Polyethylene (PE) Plastic Pipe (SDR-PR) Based on Outside Diameter.
  • AASHTO M304, Standard Specification for Poly (Vinyl Chloride)(PVC)Profile Wall Drain Pipe and Fittings Based on Controlled Inside Diameter.
  • AASHTO M278, Standard Specification for Class PS46 Poly (Vinyl Chloride) (PVC) Pipe.
  • ASTM D3262, Standard Specification for "Fiberglass" (Glass-Fiber-Reinforced Thermosetting-Resin) Sewer Pipe.
  • ASTM D3754, Standard Specification for "Fiberglass" (Glass-Fiber-Reinforced Thermosetting-Resin) Sewer and Industrial Pressure Pipe.
  • AASHTO PP63-09, Standard Practice for Pipe Joint Selection for Highway Culvert and Storm Drains.
  • ASTM D2412, Standard Test Method for Determination of External Loading Characteristics of Plastic Pipe by Parallel-Plate Loading.
  • ASTM Form and Style for ASTM Standards, March 2010.
  • AASHTO LRFD Bridge Construction Specifications, 3rd Edition, 2010.

How Does Decommissioning Work?

HOW IT WORKS

Decommissioning oil and gas installations can cost operators an average of $4-$10 million in the shallow water Gulf of Mexico. Thus when the US Department of the Interior Bureau of Ocean Energy Management, Regulation, and Enforcement (BOEMRE) Gulf of Mexico OCS Region issued a new decommissioning regulation in September 2010, operators knew they'd take a hit.
NTL 2010-G05 requires wells that have not been used for the last five years to be to be permanently abandoned, temporarily abandoned, or zonally isolated within 3 years after Oct. 15, 2010. If wells are zonally isolated, operators have 2 additional years to permanently or temporarily abandon the wellhead. Plus, platforms and supporting infrastructure that have been idle for five or more years must be removed within 5 years as of the Oct. 15, 2010 effective date.
This new NTL on top of the typical volume of decommissioning work in the GOM will increase demand for contractors and, in turn, their dayrates.
According to a BOEMRE statement, the MMS (former name of the BOEMRE) conducted an Alternative Internal Control Review (AICR) of idle structures and wells on active leases in the GOM OCS in 2008. The review identified a significant number of idle platforms that need to be permanently plugged and removed. Why? Idle structures and wells could be damaged in a hurricane and cause an environmental disaster. Plus, damaged platforms and wells cost more to decommission than non-damaged wells.
How Is An Offshore Rig Decommissioned?
There are 10 steps to the process: Project Management, Engineering and Planning; Permitting and Regulatory Compliance; Platform Preparation; Well Plugging and Abandonment; Conductor Removal; Mobilization and Demobilization of Derrick Barges; Platform Removal; Pipeline and Power Cable Decommissioning; Materials Disposal; and Site Clearance. Each step is discussed below.
Project Management
Project management, engineering and planning for decommissioning an offshore rig usually starts three years before the well runs dry. The process involves:
  • review of contractual obligations
  • engineering analysis
  • operational planning
  • contracting
Due to the limited number of derrick barges, many operators contract these vessels two to three years in advance. In addition, much of the decommissioning process requires contractors who specialize in a specific part of the process. Most operators will contract out project management, cutting, civil engineering, and diving services.
Permitting And Regulatory Compliance
Obtaining permits to decommission an offshore rig can take up to three years to complete. Often, operators will contract a local consulting firm to ensure that all permits are in order prior to decommissioning. Local consulting firms are familiar with the regulatory framework of their region.
An Execution Plan is one of the first steps in the process. Included in this plan is environmental information and field surveys of the project site. The plan describes a schedule of decommissioning activities and the equipment and labor required to carry out the operation. An execution plan is required to secure permits from Federal, State, and local regulatory agencies. The BOEMRE will also analyze the environmental impact of the project and recommend ways to eliminate or minimize those impacts.
Federal agencies often involved in decommissioning projects include BOEMRE, National Marine Fisheries Service, US Army Corps of Engineers, US Fish and Wildlife Service, National Oceanic and Atmospheric Administration, US Environmental Protection Agency, US Coast Guard, and the US Department of Transportation, Office of Pipeline Safety.
Platform Preparation
To prepare a platform for decommissioning, tanks, processing equipment and piping must be flushed and cleaned and residual hydrocarbons have to be disposed of; platform equipment has to be removed, which includes cutting pipe and cables between deck modules, separating the modules, installing padeyes to lift the modules; and reinforcing the structure. Underwater, workers prepare the jacket facilities for removal, which includes removing marine growth.
Well Plugging And Abandonment
Plugging and abandonment is one of the major costs of a decommissioning project and can be broken into two phases.
The planning phase of well plugging includes:
  • data collection
  • preliminary inspection
  • selection of abandonment methods
  • submittal of an application for BOEMRE approval
In the GOM, the rig-less method, which was developed in the 1980s, is primarily used for plugging and abandonment jobs. The rig-less method uses a load spreader on top of a conductor, which provides a base to launch tools, equipment and plugs downhole.
Well abandonment involves:
  • well entry preparations
  • use of a slick line unit
  • filling the well with fluid
  • removal of downhole equipment
  • cleaning out the wellbore
  • plugging open-hole and perforated intervals(s) at the bottom of the well
  • plugging casing stubs
  • plugging of annular space
  • placement of a surface plug
  • placement of fluid between plugs
Plugs must be tagged to ensure proper placement or pressure-tested to verify integrity.
Conductor Removal
According to BOEMRE, all platform components including conductor casings must be removed to at least 15 ft below the ocean floor or to a depth approved by the Regional Supervisor based upon the type of structure or ocean-bottom conditions.
To remove conductor casing, operators can chose one of three procedures:
  1. Severing, which requires the use of explosive, mechanical or abrasive cutting
  2. Pulling/sectioning, which uses the casing jacks to raise the conductors that are unscrewed or cut into 40 ft-long segments.
  3. Offloading, which utilizes a rental crane to lay down each conductor casing segment in a platform staging area, offloading sections to a boat, and offloading at a port. The conductors are then transported to an onshore disposal site.
Mobilization/Demobilization And Platform Removal
Mobilization and demobilization of derrick barges is a key component in platform removal. According to BOEMRE, platforms, templates and pilings must be removed to at least 15 ft below the mudlline.
First, the topsides are taken apart and lifted onto the derrick barge. Topsides can be removed all in one piece, in groups of modules, reverse order of installation, or in small pieces.
If removing topsides in one piece, the derrick barge must have sufficient lifting capacity. This option is best used for small platforms. Also keep in mind the size and the crane capacity at the offloading site. If the offloading site can't accommodate the platform in one piece, then a different removal option is required.
Removing combined modules requires fewer lifts, thus is a time-saving option. However, the modules must be in the right position and have a combined weight under the crane and derrick barge capacity. Dismantling the topsides in reverse order in which they were installed, whether installed as modules or as individual structural components, is another removal option and the most common.
Topside can also be cut into small pieces and removed with platform cranes, temporary deck mounted cranes, or other small (less expensive) cranes. However, this method takes the most time to complete the job, so any cost savings incurred using a smaller derrick barge will likely be offset by the dayrate.
Removing the jacket is the second step in the demolition process and the most costly. First, divers using explosives, mechanical means, torches or abrasive technology make the bottom cuts on the piles 15 ft below the mudline. Then the jacket is removed either in small pieces or as a single lift. A single lift is possible only for small structures in less than 200 ft of water. Heavy lifting equipment is required for the jacket removal as well, but a derrick barge is not necessary. Less expensive support equipment can do the job.
Pipeline And Power Cable Decommissioning
Pipelines or power cables may be decommissioned in place if they do not interfere with navigation or commercial fishing operations or pose an environmental hazard. However, if the BOEMRE rules that it is a hazard during the technical and environmental review during the permitting process, it must be removed.
The first step to pipeline decommissioning in place requires a flushing it with water followed by disconnecting it from the platform and filling it with seawater. The open end is plugged an buried 3 ft below the seafloor and covered with concrete.
Materials Disposal And Site Clearance
Platform materials can be refurbished and reused, scrapped and recycled or disposed of in specified landfills.
To ensure proper site clearance, operators need to follow a four-step site clearance procedure.
  1. Pre-decommissioning survey maps the location and quantity of debris, pipelines, power cables, and natural marine environments.
  2. Post decommissioning survey identifies debris left behind during the removal process and notes any environmental damage
  3. ROVs and divers target are deployed to further identify and remove any debris that could interfere with other uses of the area.
  4. Test trawling verifies that the area is free of any potential obstructions.
ROVs and divers target are deployed
Reference: http://www.rigzone.com/training/insight.asp?i_id=354

UK pipeline decommissioning provides potential for innovation

26/01/2015

Need for new lifting, cutting, and trenching techniques
Mick Borwell
Oil & Gas UK
Since 1966, 45,000 km (27,962 mi) of pipeline has been installed in the North Sea to transport hydrocarbons from the UK continental shelf (UKCS) to shore. Of this pipeline, less than 2% has been decommissioned.
The UK government and industry continue to focus on maximizing recovery of around 15-24 Bboe from the UKCS, and 2013 brought record investment in new projects. Collaborative work has resulted in fiscal change and technological advances, but as the basin continues to mature, decommissioning is emerging as a parallel and growing business opportunity.
Decommissioning expertise is available within the UK supply chain, but without significant activity in this area, the sector has not been fully tested. To help contractors better understand the opportunities, Oil & Gas UK has produced several documents.
In its "Decommissioning Insight" published in 2013, the association forecasts that between 2013 and 2022 more than 2,300 km (1,429 mi) of pipeline, infrastructure from 74 fields, more than 70 subsea projects, and about 130 installations are scheduled for decommissioning at a total forecast expenditure of £10.4 billion ($17 billion).

Inventory of UKCS pipelines

The pipelines mentioned in the forecast represent a fraction of the extensive network of pipeline currently installed in the North Sea to transport oil and gas production to host platforms or to shore. Overall, the UKCS pipeline inventory covers a broad range of equipment designed to accommodate the transportation of many different fluids under diverse conditions, varying water depths, and different oceanographic environments.
In many cases, the existence of nearby pipeline infrastructure has led directly to the exploitation of marginal fields that would otherwise be uneconomic. Such opportunities remain a key factor in the timing of any pipeline decommissioning. A more detailed description of the different types of pipeline infrastructure can be found in Oil & Gas UK's 2013 report, "The Decommissioning of Pipelines in the North Sea Region."
Trunklines represent the major element of subsea infrastructure transporting large quantities of oil and gas from offshore to onshore receiving facilities and end users across Europe. They account for 18% of the total number of pipelines and 63% of the total pipeline length in the North Sea inventory.
Such pipelines include some of the longest in the North Sea, often with diameters of more than 30 in., and tend to be installed offshore using the S-lay pipelay method from a specialist lay vessel.
The pipeline inventory also includes rigid flowlines, flexible flowlines, umbilicals, and power cables, as well as associated equipment such as the concrete mattresses used extensively in the UKCS to provide protection and stability to subsea pipelines, cables, and umbilicals. These flexible mattresses are typically manufactured by joining different shapes of concrete blocks together with polypropylene or Kevlar rope. Oil & Gas UK estimates that 35,000-40,000 mattresses have been deployed since operations began in the North Sea.
While pipelines are integral to field life extension and future development opportunities, some fields in the UKCS have reached the end of their economic life. Specific parts of the pipeline system naturally become redundant, and with no potential future use, they are available to be decommissioned.
Seven Navica reeling vessel. (Image reproduced with permission from Subsea 7)

Decommissioning to date

Oil and gas pipeline decommissioning has been taking place in the North Sea since the early 1990s, when the Crawford field pipelines were decommissioned. Since then, pipeline decommissioning has continued at a modest rate and only when all potential reuse options for the infrastructure, including new field developments, have been carefully considered.
Less than 2% of the North Sea pipeline inventory has been decommissioned, and of the pipelines which have been decommissioned, 80% are less than 16-in. in diameter. Half of the larger diameter pipelines (16 in. or greater) decommissioned to date were removed; these were all infield pipelines less than 1 km (0.6 mi) long. The longest large diameter trunkline to be decommissioned so far is the 35-km (21.7-mi) Piper A to Claymore 30-in. export line, which was decommissioned in situ.
Under current regulations, decommissioning of oil and gas pipelines is considered on a case-by-case basis using the comparative assessment (CA) process to determine the best option for decommissioning. The CA process enables the particular diameter, length, and configuration of individual pipelines to be taken into account when considering decommissioning options against the criteria of safety, environmental impact, cost, and technical feasibility.
Health and safety is a dominant factor in any CA, with the focus aimed at minimizing the long-term risks to other users of the sea and the short-term risks to those carrying out decommissioning operations. An integral part of the process is the environmental impact assessment, which is prepared to support all pipeline decommissioning plans.
Each decommissioning solution needs to be considered on its individual merits, as pipeline installations vary widely according to model, location, environment, and maintenance status. It is at the CA stage, when a number of options are considered, that significant opportunities exist for supply chain companies to develop innovative technologies for decommissioning pipelines.

Opportunities for innovation

When evaluating a preferred option for decommissioning a pipeline and its associated equipment, the availability and track record of technology used in previous projects provides the context for the other key CA criteria of safety, environmental impact, and cost.
Supply chain companies specializing in particular services will have the opportunity to develop innovative techniques in the key technology areas for pipeline decommissioning, many of which are in their infancy. These are:
  • Pipeline cleaning
  • Trenching, burial, and de-burial
  • Subsea cutting
  • Lifting
  • Reverse installation methods
  • Mattress removal.
Pipeline cleaning is performed prior to decommissioning and involves the depressurization of a pipeline and the removal of any hydrocarbons in accordance with the Pipelines Safety Regulations. At this stage there are opportunities for companies skilled at minimizing the potential contamination of the marine environment.
The technology for trenching and burial of pipelines during installation is well established, and a number of contractors offer a range of trenching tools capable of trenching and burying pipelines of various diameters in all soil types. There is, however, limited experience of existing pipelines, laid on the seabed surface, being buried specifically for decommissioning in situ.
While there are different methods and types of equipment for cutting pipelines subsea using "cold cutting" tools such as abrasive water jets, diamond wire cutting, reciprocating cutting, and hydraulic shears, significant opportunities exist for contractors capable of developing new technologies to improve these techniques. These might include automated techniques to help reduce the use of divers in these activities. Lifting sections of infrastructure from the seabed is another area where innovative thinking is in demand. The "cut and lift" process of decommissioning requires cut sections of pipeline to be lifted from the seabed to a transportation vessel; supply chain companies providing innovative cutting techniques could help increase efficiency in this area by reducing the duration of lifting operations for long lengths of pipeline.
Reverse installation methods encompass both reverse reeling and reverse S-lay techniques. The process by which rigid or flexible pipelines can be recovered from the seabed by reeling them from the seabed using a specialist reel vessel is known as "reverse reeling."
For rigid pipe, there are a limited number of specialist reel vessels available from the leading installation contractors. These vessels are usually engaged in installation activities, but can be adapted to recover pipelines as part of a decommissioning project. Subsea 7's Seven Navica is one vessel capable of performing this work.
For larger diameter and concrete coated trunklines, the industry is considering a reversal of the S-lay installation process by which pipelines could be removed and recovered on to the deck of a specialist S-lay vessel. However, this has not been done in the North Sea, and more study is needed before the technique can be considered feasible for decommissioning long distance large diameter pipelines.
As yet, no established technique or technology has been universally adopted for mattress recovery. Solutions developed by contractors will need to take into account the age and condition of the mattresses being recovered.

Click to Enlarge

Regional variations

Oil & Gas UK's 2013 "Decommissioning Insight" highlights the contrast between different UKCS basins, noting that in the central and northern North Sea (CNS and NNS), decommissioning of pipelines and mattresses is estimated to cost more than £400 million ($655 million) from 2013 to 2022. Over this period, nearly 40 trunklines (130 km/81 mi), 115 rigid and flexible flowlines (420 km/261 mi), 87 umbilicals (250 km/155 mi), and almost 900 mattresses have been identified for decommissioning in these basins.
The forecast indicates significant expenditure will take place from 2019 to 2022, suggesting that pipeline decommissioning will occur toward the latter end of decommissioning programs. The peak in 2019 can be attributed to at least 10 pipeline decommissioning projects.
While containing a similar number of pipelines to the southern North Sea (SNS), the decommissioning of rigid and flexible flowlines in the CNS and NNS basins is more expensive, suggesting a greater degree of complexity in these regions.
Over the same period in the SNS and the Irish Sea, four trunklines (64 km), 116 other pipelines (1,300 km/808 mi), and 21 umbilicals (150 km/93 mi) will be decommissioned at a cost of around £100 million ($164 million). Additionally, 2,100 mattresses have been scheduled for decommissioning.
While these decommissioning activities represent a fraction of the overall market of oil and gas activities, they are part of a burgeoning sector. By making more information on decommissioning available, Oil & Gas UK aims to help the industry prepare for decommissioning projects, increase the efficiency of processes involved, and help ensure that future projects are enabled by an "at the ready" supply chain.
Reference: http://www.offshore-mag.com/articles/print/volume-74/issue-2/engineering-construction-installation/uk-pipeline-decommissioning-provides-potential-for-innovation.html

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