FéeFilleFée: February 2016

Subsea systems should be monitored or inspected regularly, internally and externally. The inspection can provide such information as: geometry variation (dent, wrinkle, buckle, etc.), wall thickness variation (metal loss), corrosion, crack, leak, etc.

The advantages and disadvantages of internal and external inspections are as follows:

Internal inspection: Applicable for inaccessible (buried or concrete/insulation coated) pipes. May have to shut-down the system to send pigs. Pigs may be stopped or lost due to pipe buckle or pressure loss due to large hole on the pipe.
External inspection: Applicable for un-piggable line. No need to shut-down the system. Good for partial suspicious area inspection, such as manifold, jumper connection, riser, etc.

Self-crawling intelligent pigs have been developed to perform the In-line inspection (ILI) without interrupting the production. The external inspections or integrity monitoring systems are performed by ROV or tools mounted on the pipeline.

Magnetic and ultrasonic tools are commonly used to detect corrosion, crack, geometry and wall thickness variations. Detecting a leak as early as possible will reduce the environmental damage. The current leak detection systems available for subsea pipelines are:

Ultrasonic - transmit ultrasonic waves and receive/record reflected waves
Acoustics - monitor/detect noise or pressure change being created by a rupture or sudden leak
Dye detectors - detect optical fluorescent leak visually by a laser beam
Fiber optics - detect leaks by hydrophones, accelerometers, temperature monitoring sensors installed on a distributed fiber optic cable along the pipeline
Flow balance - detect leak by monitoring volumetric flow rate, pressure, and temperature

The effective integrity monitoring and management planning allows the operator to reduce uncertainties and risks associated with riser fatigue, corrosion build-up, hydrate plug or wax formation conditions, etc.

The subsea integrity monitoring service providers include:

Genesis SIG (Subsea Integrity Group)
Come Monday, Inc.
IICORR (Integrity Inspection Corrosion)
Fugro Structural Monitoring (FSM)
2H Offshore
MCS
DeepSea Monitoring Solutions (DMS), etc.

Source:

Lee, Jaeyoung. Introduction to Offshore Pipelines and Risers. 2007.

Crude oil is a complex mixture of hydrocarbons which consists of aromatics, paraffins, naphthenics, resins, asphaltenes, diamondoids, mercaptans, etc. When the temperature of crude oil is reduced, the heavy components of oil, like paraffin/wax (C18–C60), will precipitate and deposit on the pipe wall. The pipe internal diameter will be reduced with wax deposition, resulting in higher pressure drop.Wax deposition problems can become so severe that the whole pipeline can be completely blocked. It would cost millions of dollars to remediate an offshore pipeline that is blocked by wax.

Wax varies in consistency from that of petroleum jelly to hard wax with melting points from near room temperature to over 100°C. Wax has a density of around 0.8 g/cm^ and a heat capacity of around 0.140 W/(mK).

In subsea system, following issues caused by waxes should be addressed by flow assurance analysis:

Deposition in flowlines, gradual with time but can block pipelines;
Gelation of crude oil during shut-in;
High start up pressures and high pumping pressures due to higher viscosity;
Insulation for pipeline increases capital expense;
Wax inhibitors increases operational expense;
Pigging operation in offshore environment,
Wax handling in surface facilities - needs higher separator temperature.

Several methods of wax control and management are practiced by production operations, but the transportation of crude oil over a long distance in subsea system demands significant planning and forethought. The wax management strategy generally is based on one or more of the following methods,

Flowline pigging,
Thermal insulation and pipeline heating,
Inhibitor injection,
Coiled-tubing technology.

The most common method of wax control is flowline pigging if the wax has formed. The solid deposit is removed with regularly removing the wax layer by the scouring action of the pig. Chemical inhibitors can also help control the wax deposition, although these chemicals are not always effective and tend to be expensive. In case that the flowline pigging option for the production lines is not practical, particularly for subsea completions, wax deposition is controlled by maintaining fluid temperatures above the cloud point for the whole flowline.

Source:

Lee, Jaeyoung. Introduction to Offshore Pipelines and Risers. 2007.

Guo, Boyun, Shanhong Song, Jacob Chacko, Ali Ghalambor. USA. 2005.

Bai, Yong and Bai, Qiang. Subsea Pipelines And Risers. USA: Elsevier Inc. 2005.

Flow assurance is required to determine the optimum flowline pipe size based on reservoir well fluid test results for the required flowrate and pressure. As the pipe size increases, the arrival pressure and temperature decrease. Then, the fluid may not reach the destination and hydrate, wax, and asphaltene may be formed in the flowline. If the pipe size is too small, the arrival pressure and temperature may be too high and resultantly a thick wall pipe may be required and a large thermal expansion is expected.

It is important to determine the optimum pipe size to avoid erosional velocity and hydrate/ wax/asphaltene deposition. Based on the hydrate/wax/asphaltene appearance temperature, the required OHTC is determined to choose a desired insulation system (type, material, and thickness.) If the flowline is to transport a sour fluid containing H2S, CO2, etc., the line should be chemically treated or a special corrosion resistant alloy (CRA) pipe material should be used. Alternatively, a corrosion allowance can be added to the required pipe wall thickness. capital expense (Capex) and operational expense (opex) using CRA, chemical injection, corrosion allowance, or combination of the above should be exercised to determine the pipe material and wall thickness.

The picture above illustrates one example of how to select pipe size from flow assurance results. The blue solid line represents inlet pressure at wellhead and the red dotted line represents outlet fluid temperature. The 8” ID pipe may require a heavy (thick) wall and the 12” ID pipe may require a thick insulation coating depending on hydrate (wax or asphaltene) formation temperature.

Fluid Sampling

One of the most critical steps in identifying and quantifying flow assurance risks is fluid sampling. Fluid samples can be obtained from downhole and/or from surface separator. It is a good practice to collect at least two downhole samples with one serving as a back-up and collect at least three one-gallon samples from the separator. A certain amount of stock tank oil samples are needed for other crude oil analyses (geochemical and crude assay).

PVT Measurements

Once the fluid samples are in the lab, numerous tests will be performed to measure the fluid properties. Compositional analysis of the downhole sample would be performed through at least C36þ, including density and molecular weight of the Heptanes plus. Pressure-Volume Relations are determined at reservoir temperature by constant mass expansion. This measurement provides oil compressibility, saturation pressure, single phase oil density, and phase volumes. The compositions and gas formation volume factors for the equilibrium reservoir gas during primary depletion can be obtained by performing differential vaporization at reservoir temperature. Gas viscosities are then calculated from the composition. Undersaturated and depleted oil viscosity at reservoir temperature can be measured by using capillary tube viscometry.

Source:

Lee, Jaeyoung. Introduction to Offshore Pipelines and Risers. 2007.

Guo, Boyun, Shanhong Song, Jacob Chacko, Ali Ghalambor. USA. 2005.

Rapid crack propagation, as its name implies, is a very fast fracture. Crack speeds up to 600 ft/sec have been measured. These fast cracks can also travel long distances, even hundreds of feet. The DuPont Company had two RCP incidents with its high-density PE pipe, one that traveled about 300 feet and the other that traveled about 800 feet.

RCP cracks usually initiate at internal defects during an impact or impulse event. They generally occur in pressurized systems with enough stored energy to drive the crack faster than the energy is released. Based on several years of RCP research, whether an RCP failure occurs in pipe depends on several factors:

Pipe size.
Internal pressure.
Temperature.
Material properties/resistance to RCP.
Pipe processing.

Typical features of an RCP crack are a sinusoidal (wavy) crack path along the pipe, and “hackle” marks along the pipe crack surface that indicate the direction of the crack. At times, the crack will bifurcate (split) into two directions as it travels along the pipe.

The study of mechanism of crack propagation under pressure fluctuations has been done by Mengshan Yu, Weixing Chen, Richard Kania, Greg Van Boven, and Jenny Been. From this study, they conclude:

Even the minor cycles whose crack propagation driving force is below CA threshold can still cause crack growth in the presence of underloads in C2 solution.
Acceleration factor can be up to 3.2 and 5.1 for tests in air and in C2 solution, respectively.
The contribution of corrosive solution to crack growth is the most at low mechanical driving force and reduces with increasing mechanical driving force.
Operating strategies for pipelines to minimize crack growth: reducing the underload occurrence, and static hold after underload.

Where Variable amplitude (VA) cyclic loadings, which are close to the actual pressure fluctuations, are studied in current investigation, since the growth rate may be very different from that under. Constant amplitude (CA): even the cycles whose crack propagation driving force is below the determined CA threshold could still cause significant crack growth. However, such minor cycles are usually ignored in the study of nearneutral pH stress corrosion cracking (NNpHSCC) of pipeline steel ever since NNpHSCC was identified, although they are the major part of actual pressure fluctuations.

Source:

http://pgjonline.com/2009/03/20/rapid-crack-propagation-increasingly-important-in-gas-applications-a-status-report/

http://www.cme.engineering.ualberta.ca/en/NewsEvents/CMENews/2014/February/~/media/cme/NewsEvents/Documents/Poster-Mengshan.pdf

To keep the conveyed fluid warm, the pipeline should be heated by active or passive methods. The active heating methods include, electric heat tracing wires wrapped around the pipeline, circulating hot water through the annulus of pipe-in-pipe, etc. The passive heating method is insulation coating, burial, covering, etc.

Oilfield pipelines are insulated mainly to conserve heat. The need to keep the product in the pipeline at a temperature higher than the ambient could exist for the following reasons including:

Preventing formation of gas hydrates
Preventing formation of wax or asphaltenes
Enhancing product flow properties
Increasing cool-down time after shutting down
Meeting other operational/process equipment requirements

In liquefied gas pipelines, such as LNG, insulation is required to maintain the cold temperature of the gas to keep it in a liquid state. This chapter describes commonly used insulation materials, insulation finish on pipes, and general requirements for insulation of offshore and deepwater pipeline.

Insulation Material

Polypropylene, polyethylene, and polyurethane are three base materials widely used in the industry for pipeline insulation. Their thermal conductivities are given in table below:

Depending on applications, these base materials are used in different forms resulting in different overall conductivities. A 3-layer polypropylene applied to pipe surface has a conductivity of 0.13 BTU/hr-ft-8F, while a 4-layer polypropylene has a conductivity of 0.10 BTU/hr-ft-8F. Solid polypropylene has higher conductivity than polypropylene foam. Polymer syntactic polyurethane has a conductivity of 0.07 BTU/hr-ft-8F, while glass syntactic polyurethane has a conductivity of 0.09 BTU/hr-ft-8F. These materials have lower conductivities in dry conditions such as that in pipe-in-pipe applications.

Because of its low thermal conductivity, more and more polyurethane foams are used in deepwater applications. Physical properties of polyurethane foams include density, compressive strength, thermal conductivity, closed cell content, leachable halides, flammability, tensile strength, tensile modulus, and water absorption. The values of these properties vary depending on density of the foam.

Source:

Lee, Jaeyoung. Introduction to Offshore Pipelines and Risers. 2007.

Guo, Boyun, Shanhong Song, Jacob Chacko, Ali Ghalambor. USA. 2005.

Subsea tie-in is typically made by diver-assisted flange connectors for shallow water pipelines and diverless remotely operated vehicle (ROV) connectors for deepwater pipelines.

There are three types of connectors available: flange, clamp (Graylok type), and collet connectors. Clamp or collet connector is more favorable over the flange connector due to ROV operability, offshore connection time, and available tie-in tools from contractors.

The methods of pipeline tie-in are explained below:

Spoolpiece

Divers measure and then assist the installation of a piece of pipe to fit in between the two ends of flowline to be tied together. Misalignment of the two pipes can be accommodated by installing bends into the spool, and inaccuracies in placing the pipelines down can be accommodated when the spool is made up (after diver measurements).

The connection method can either be by flanges or welding. The welding method requires a hyperbaric habitat. From a design viewpoint, should there be large flowline expansion, then this can also be accommodated by incorporating a dogleg in the spool. This will permit expansion of the pipe without transmitting high loads into the adjacent pipe.

Lateral Pull

Lateral deflection involves positioning the flowline end to one side of the target structure and then pulling it laterally into position. The flowline may be pulled towards the target by a single wire, or a series of wires may be developed through dead-man anchors to give greater control of alignment. A bell mouth or stab-in guides usually assist final alignment.

For large diameters such as export lines or bundles, it is necessary to make a length of pipeline neutrally buoyant. This gives greater flexibility and reduces the pull forces, but can expose the pipe to large current forces.

J-tube Pull-in

This method requires the flowline to have the capacity to easily move axially over a relatively large distance. This limits the option to pulling the flowline directly from the pipelay vessel. The method of J-tube pull-in is to connect the flowline to a wire and, by pulling the wire, to pull the flowline through a riser (J-tube) up to the topsides of the platform. This method requires the J-tube to be of a reasonably large diameter compared to the flowline.

Connect and Lay Away

This method is very similar to the J-tube pull-in method with the exception that the tie-in is performed subsea. This method is usually applied in diverless operations, where a mechanical connecting system will be utilized to perform the connection. This system is mainly used at subsea manifolds/wellheads, where the water depth prohibits the use of divers. This is the only system developed for performing diverless connection of pipelines.

Stalk-on

The stalk-on method is primarily used in shallow water applications (less than 40 m) and hence would only be applicable in the Southern North Sea. The method involves laying the flowline down adjacent to the jacket it shall be tied into. The vessel maneuvers over the flowline, lifts it up and welds on (or flanges on) the jacket riser. The pipeline and riser are then lowered onto the seabed/jacket. The jacket clamps are subsequently closed around the riser.

Source:

Lee, Jaeyoung. Introduction to Offshore Pipelines and Risers. 2007.

Bai, Yong and Bai, Qiang. Subsea Pipelines And Risers. USA: Elsevier Inc. 2005.

Before I tell you more about pipe-in-pipe, I’ll tell you one fact related with this topic which I just found last night during my research:

The first known pipe-in-pipe system was installed in 1973 by Pertamina Offshore Indonesia. This pipeline was 8 miles long extending from shore to a single point mooring facility. The outer and inner diameters of this pipeline were 40" and 36" respectively.

How cool is that? Ok, now back to the main purpose of this article: to explain about pipe-in-pipe ~~and to fullfill my task assignment~~.

Due to the increased number of components in a pipe-in-pipe system compared with conventional pipelines, the design process is therefore more iterative in nature as the interactions of the components may necessitate design alteration.

A pipe-in-pipe system is essentially made up of an insulated inner pipe and a protective outer pipe. The function of the inner pipe is to convey fluids and therefore is designed for internal pressure containment. The inner pipe is insulated with thermal insulation materials to achieve the required arrival temperature. The outer pipe protects the insulation material from external hydrostatic pressure and other mechanical damage. Concrete weight coating is not normally required due to high submerged weight and usually low ocean current speeds in deepwater areas.

For the exploitation of HP/HT reservoirs, pipe-in-pipe system can provide the necessary thermal insulation and integrity for transporting hydrocarbon at high temperature (above 120 ^C) and high pressure (in excess of 10000 psi). Pipe-in-pipe system comprises a rigid steel flowline inside a rigid sleeve pipe. The two pipes are kept apart by some form of spacer at the ends of each joint, and by bulkheads at the ends of the pipeline.

The air gap between the inner and outer pipes provides the means of achieving the high thermal insulation. This air gap accommodates the insulation, which typically consists of either granular material poured into the inter-pipe annulus, or of a blanket form, which is wrapped around the inner pipe. In either case, the insulation material needs to be kept dry in order to maintain its insulation properties.

There are several conditions under which pipe-in-pipe systems (including bundles in this definition) may be considered for a particular flowline application over a conventional or flexible pipeline.

Insulation- HP/HT reservoir conditions
Multiplicity of flowlines
Trenching and Rock-dumping

Source:

Bai, Yong and Bai, Qiang. Subsea Pipelines And Risers. USA: Elsevier Inc. 2005.

http://www.itp-interpipe.com/products/index.php

Pig is a device used for cleaning a pipeline or separating fluids being moved down the pipeline. It is inserted in the pipeline and carried along by pressurized flow of water, oil, or gas. An intelligent pig is fitted with magnetic or ultrasonic sensors to detect corrosion or defects in the pipeline. Pigging is performed during installation and operation for such purposes as:

During Installation

Debris removing, cleaning, and gauging
Watering, dewatering, and drying
Commissioning
During Operation

Cleaning – wax/scale/condensate buildups removal

Inventory management – sweeping out batching products
Corrosion and scale control
Inspection – geometry (physical damage), corrosion, crack, leak detection

Miscellaneous

Decommissioning
Isolation
Recommissioning

Pigging Procedure

Pressure and Flow Rate

Operating pigging pressures and fluid flow rates should be carefully controlled. Velocity of driving fluid is usually between 3 feet per second and 5 feet per second during pigging. Recommended ranges of operating pressures and flow rates are presented in table below:

Pre-Run Inspection

If the pig has been run before, it should be inspected to assure that it will run again without stopping in the pipeline. Measure the outside diameter of the pig’s sealing surface. This diameter must be larger than the inside pipe diameter to maintain a good seal. Inspect the sealing surfaces to assure there are no cuts, tears, punctures, or other damage that will affect the pig’s ability to run in the pipeline. The unrestrained diameter of brush pigs should also be measured to assure that the brushes will maintain contact with the pipe wall during the complete run. When using brush-type mandrel cleaning pigs, the brushes should be inspected for corrosion or breakage. Every precaution should be taken to prevent these brushes from breaking in the pipeline. Loose bristles can damage valves, instrumentation, and other pipeline equipment. All components of brush-type mandrel pigs should be checked to be certain that they are tight and in good condition.

Freeing a Stuck Pig

Getting the pig stuck rarely happens in pipeline that is pigged routinely, but can happen when pigging a pipeline that has been neglected or never pigged before. If a pig becomes stuck, it is important to identify the cause. Retrieving the pig is the first priority. When bidirectional pigs are used, stuck pigs may be recovered with reverse flow.

Pig tracking is normally done on critical projects and when attempting to locate stuck pigs. A pig tracking system consists of a transmitter mounted on the pig, an antenna, and a receiver that records and stores each pig passage. In addition, the operator can see and hear the signal of the pig passing under the antenna. The antenna and receiver are simply laid on the ground above and in line with the pipe and the passage of the pig is heard, seen, and recorded.

Sometimes a pig without a transmitter fails to come into the receiver because it gets stuck somewhere in the line. When this happens, the pig cups usually flip forward and flow continues around the stuck pig. In order to find the stuck pig, another pig with a transmitter is launched and tracked closely at all points that are readily accessible. When the transmitter pig passes one tracking point but never reaches the next point, it is assumed the transmitter pig has reached the stuck pig and they are both stuck. The line is then walked, carrying the antenna and receiver until the transmitter pig is pinpointed. Both pigs and the debris ahead of the pigs is then removed by cutting the pipe behind and well ahead of the stuck pig.

In addition, to know more about how pipeline pigging work, you can watch the video below:

There’s one more thing we should know about pipeline pigging. It’s pig launcher/pig trap. I will explain about it in other article soon.

Source:

https://www.youtube.com/watch?v=XT1cOip53R4

Lee, Jaeyoung. Introduction to Offshore Pipelines and Risers. 2007.

Guo, Boyun, Shanhong Song, Jacob Chacko, Ali Ghalambor. USA. 2005.

The hydrotests are conducted mainly to verify the mechanical strength of pipeline or pipeline sections. Hydrotesting is carried out by pressurizing the system to a specified internal pressure and holding it for a certain period of time to check whether or not there is a pressure drop. If the pressure drops within the hold period, it is assumed that a leak or leaks may exist somewhere in the system. After the holding period is over, the pressure is released and a complete visual inspection follows. Standard codes, such as ASME B31.4, ASME B31.8, and API RP 1111, provide guidance on how to perform pressure tests of gas and liquid pipelines.

Hydrotest use water as fluid with pressure larger than the design pressure. The test pressure is recommended to be set at no less than 1.25 times the internal design pressure for both hydrostatic testing and leak testing. The holding time is recommended to be at least 4 hours for hydrostatic testing and at least 1 hour for leak testing.

A complete description of the test equipment and instruments is very important for the success of the tests. The following is a partial list of the devices needed for the tests:

A high-volume pump that can fill the line at high enough velocity to remove debris and to push the pigs
A filter that would remove all particles larger than a certain size to ensure the test fluid is clean
A meter to measure the quantity of water filled
Injection pumps for chemical injections
A variable speed, positive displacement pump to pressurize the line. The pump should have a known volume per stroke and should have a stroke counter
A pressure recorder that would continuously record the test pressure for the whole test period. The pressure measuring equipment should have an accuracy and repeatability of +-0.1%
A temperature measurement device that is properly calibrated and should continuously measure the fluid temperature. The device should be able to read in increments of no less than 0.18F (0.058C)
A temperature device to measure the ambient temperature
Pressure relief valves
Pig transmitter device or remote pig signaling system

How the test results will be reported and what will be reported should be defined before performing the tests. The test records should include the details of the test operations and details of any failures. The failure report should include the exact location of each failure, the type of failure, the causes for the failure, and the recommended repair methods. When the tests are finished, all waste should be disposed of in the correct manner which should be defined in the company’s waste management and disposal policy.

Source:

Guo, Boyun, Shanhong Song, Jacob Chacko, Ali Ghalambor. USA. 2005.

Bai, Yong and Bai, Qiang. Subsea Pipelines And Risers. USA: Elsevier Inc. 2005.

In order to prevent corrosion defects, over the past ten years there have been several manufacturing methods developed for producing Corrosion Resistant Alloy (CRA) clad/lined pipes. API (1993) has developed a specification for the CRA clad and lined pipe. CRA clad or lined pipes may be classified into two basic categories (Urband, 2001):

Metallurgically Bonded Pipes: They are those in which there is a metallurgical bond between the structural outer pipe and the corrosion resistant inner pipe.
Mechanically Lined Pipes: The simplest and most economical method of producing clad pipe is to internally line carbon steel pipes.

CRA steel is often used to replace carbon steel for corrosive applications. But CRAs are normally more expensive than carbon steel. Thus, whether or not CRAs should be useddepends upon overall economics. But in subsea application, the very critical, high impact components, like trees, jumpers, and manifolds, are often made of CRAs. But pipelines, especially long pipelines, are often made of carbon steel and continuous corrosion inhibitor injection is utilized to protect the pipeline.

Depending on alloy contents, CRA pipe can be broken into follows:

Stainless steel: 316L, 625 (Inconel), 825, 904L, etc.
Chrome based alloy: 13 Cr, Duplex (22 Cr), Super Duplex (25 Cr), etc.
Nickel based alloy : 36 Ni (Invar) for cryogenic application such as LNG (liquefied natural gas) transportation (-160oC)
Titanium: Light weight (56% of steel), high strength (up to 200 ksi tensile), high corrosion resistance, low elastic modulus, and low thermal expansion, but high cost (~10 times of steel). Good for high fatigue areas such as riser touchdown region, stress joint, etc.
Aluminum: Light weight (1/3 of steel), low elastic modulus (1/3 of steel), high corrosion resistance, but low strength (only up to 90 ksi tensile). Applications can include casing, air can, and risers.

Source:

Lee, Jaeyoung. Introduction to Offshore Pipelines and Risers. 2007.

Guo, Boyun, Shanhong Song, Jacob Chacko, Ali Ghalambor. USA. 2005.

Bai, Yong and Bai, Qiang. Subsea Pipelines And Risers. USA: Elsevier Inc. 2005.

From the previous article in this blog, you may already know about pipeline material and grade selection. Now, in this post, I will write more about the difference and usage of high strength steel and low strength steel pipeline material.

Low Strength Steel Pipeline Material

Low carbon (carbon content less than 0.29%) steel is mild and has a relatively low tensile strength so it is used to make pipes. Medium or high carbon (carbon content greater than 0.3%) steel is strong and has a good wear resistance so they are used to make forging, automotive parts, springs, wires, etc. Carbon equivalent (CE) refers to method of measuring the maximum hardness and weldability of the steel based on chemical composition of the steel. Higher C (carbon) and other alloy elements such as Mn (manganese), Cr (chrome), Mo (molybdenum), V (vanadium), Ni (nickel), Cu (copper), etc. tend to increase the hardness (harder and stronger) but decrease the weldability (less ductile and difficult to weld).

Pipes are graded per their tensile properties. Grade X-65 means that SMYS (specified minimum yield strength) of the pipe is 65 ksi. The yield strength is defined as the tensile stress when 0.5% elongation occurs on the pipe, per API-5L . The DNV code defines the yield stress as the stress at which the total strain is 0.5%, corresponding to an elastic strain of approximately 0.2% and a plastic (or residual) strain of 0.3%

High Strength Steel Pipeline Material

The research and development of new steels are for both sour and non-sour service. The materials being developed for subsea pipelines and risers are grades X70 and X80 for nonsour service and grades X65 and X70 with a wall thickness of up to 40 mm for sour service.

For offshore pipelines, the current trend is towards linepipe in grade X70 with a wall thickness up to 40 mm. Fulfillment of the requirements for DWTT transition temperature will be progressively difficult as the wall thickness increases. For wall thickness in excess of 30 mm, low transition temperatures can only be achieved by means of highly expensive rolling processes. Until now, there has been only limited offshore use of X70 material. The main installation contractors have completed three projects with X70 and have two planned until 1997.

For high pressure transmission land lines. Grade X70 is now widely used for high pressure transmission lines in many countries.

Meanwhile, five onshore projects have been identified in which X80 pipe has been used.A period of seven years elapsed before Ruhrgas AG in Germany began in 1992 to place an order for linepipe for the construction of the world's first ever grade X80 pipeline.

Large diameter X80 pipe can be manufactured consistently for long pipelines. The approach to the X80 projects was significantly different when the welding procedure and consumables were selected. The field welding of the X80 pipe did not present any difficulty for the Ruhrgas and Mitzihwin projects. These projects demonstrated that conventional mechanized welding using the GMAW process could produce consistent, high quality welds for onshore pipelines.

Source:

Lee, Jaeyoung. Introduction to Offshore Pipelines and Risers. 2007.

Bai, Yong and Bai, Qiang. Subsea Pipelines And Risers. USA: Elsevier Inc. 2005.

Pages

Fluid Sampling

PVT Measurements

General Principle

Expansion Analysis

Hot Rolling

Cold Rolling

Hot Tube Piercing

Welded Pipe

Insulation Material

Spoolpiece

Lateral Pull

J-tube Pull-in

Connect and Lay Away

Stalk-on

Pig Launcher Procedure

Pig Receiver Procedure

During Installation

Cleaning – wax/scale/condensate buildups removal

Miscellaneous

Pigging Procedure

Low Strength Steel Pipeline Material

High Strength Steel Pipeline Material

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