Hydrotest Pressure Determination

By Ramesh Singh, MS, I Eng, MWeld I, Gulf Interstate Engineering, Houston | October 2009 Vol. 236 No. 10

Hydrostatic testing has long been used to determine and verify pipeline integrity. Several types of information can be obtained through this verification process. However, it is essential to identify the limits of the test process and obtainable results. There are several types of flaws that can be detected by hydrostatic testing, such as:

• Existing flaws in the material,
• Stress Corrosion Cracking (SCC) and actual mechanical properties of the pipe,
• Active corrosion cells, and
• Localized hard spots that may cause failure in the presence of hydrogen.

There are some other flaws that cannot be detected by hydrostatic testing. For example, the sub-critical material flaws cannot be detected by hydro testing, but the test has profound impact on the post test behavior of these flaws. Given that the test will play a significant role in the nondestructive evaluation of pipeline, it is important to determine the correct test pressure and then utilize that test pressure judiciously, to get the desired results.

When a pipeline is designed to operate at a certain maximum operating pressure (MOP), it must be tested to ensure that it is structurally sound and can withstand the internal pressure before being put into service. Generally, gas pipelines are hydrotested by filling the test section of pipe with water and pumping the pressure up to a value that is higher than maximum allowable operating pressure (MAOP) and holding the pressure for a period of four to eight hours.

ASME B 31.8 specifies the test pressure factors for pipelines operating at hoop stress of ≥ 30% of SMYS. This code also limits the maximum hoop stress permitted during tests for various class locations if the test medium is air or gas. There are different factors associated with different pipeline class and division locations. For example, the hydrotest pressure for a class 3 or 4 location is 1.4 times the MOP. The magnitude of test pressure for class 1 division 1 gas pipeline transportation is usually limited to 125% of the design pressure, if the design pressure is known. The allowed stress in the pipe material is limited to 72% of SMYS. In some cases it is extended to 80% of SMYS. The position of Pipeline and Hazardous Material Safety Administration (PHMSA) is similar. Thus, a pipeline designed to operate continuously at 1,000 psig will be hydrostatically tested to a minimum pressure of 1,250 psig.

Based on the above information, let us consider API 5L X70 pipeline of 32-inch NPS, that has a 0.500-inch wall thickness. Using a temperature de-rating factor of 1.00, we calculate the MOP of this pipeline from following:

P= {2x t x SMYS x1x factor (class1) x 1} / D (ASME B 31.8 Section, 841.11)

Substituting the values:

P= 2x 0.5 x 70,000 x1 x0.72 x1/32 = 1,575 psig

For the same pipeline, if designed to a factor of 0.8, the MOP will be computed to be 1750 psig.

• If the fittings were the limiting factors of the test pressure, then the following situation would arise.
• If the fittings used in the system are of ANSI 600 then the maximum test pressure will be (1.25 x 1,440) 1,800 psig. This test pressure will support the requirements of both factor 0.72 and 0.8.
• If, however, ANSI 900 fittings were chosen for the same pipeline system, the test pressure (1.25 x 2,220) 2,775 psig would test the pipeline but would not test the fittings to their full potential.

Let us first discuss the design factor of 0.72 (class1). In this case the test would result in the hoop reaching to 72% of the SMYS of the pipe material. Testing at 125% of MOP will result in the stress in the pipe reaching a value of 1.25 x 0.72 = 0.90 or 90% of SMYS. Thus, by hydrotesting the pipe at 1.25 times the operating pressure, we are stressing the pipe material to 90% of its yield strength that is 50,400 psi (factor 0.72).

However, if we use a design factor of 0.8 – as is now often used – testing at 125% of MOP will result in the stress in the pipe to 1.25 x 0.8 =1. The stress would reach 100% of the yield strength (SMYS). So, at the test pressure of 1800 psig the stress will be 56,000 psi (for factor 0.8). This will be acceptable in case of class 600 fittings. But, if class 900 fittings were taken into account, the maximum test pressure would be (1.25 x 2,220) 2,775 psig and the resulting stress would be 88,800 psi which will be very near the maximum yield stress (90,000 psi) of API 5L X 70 PSL-2 material.

Source:

http://pipelineandgasjournal.com/pipeline-hydro-test-pressure-determination January 2015

How Does Offshore Pipeline Installation Work?

Laying pipe on the seafloor can pose a number of challenges, especially if the water is deep. There are three main ways that subsea pipe is laid -- S-lay, J-lay and tow-in -- and the pipelay vessel is integral to the success of the installation.

Buoyancy affects the pipelay process, both in positive and negative ways. In the water, the pipe weighs less if it is filled with air, which puts less stress on the pipelay barge. But once in place on the sea bed, the pipe requires a downward force to remain in place. This can be provided by the weight of the oil passing through the pipeline, but gas does not weigh enough to keep the pipe from drifting across the seafloor. In shallow-water scenarios, concrete is poured over the pipe to keep it in place, while in deepwater situations, the amount of insulation and the thickness required to ward of hydrostatic pressure is usually enough to keep the line in place.

Tow-In Pipeline Installation

While jumpers are typically short enough to be installed in sections by ROVs, flowlines and pipelines are usually long enough to require a different type of installation, whether that is tow-in, S-lay or J-lay.

Tow-in installation is just what it sounds like; here, the pipe is suspended in the water via buoyancy modules, and one or two tug boats tow the pipe into place. Once on location, the buoyancy modules are removed or flooded with water, and the pipe floats to the seafloor.

Figure 1: pipeline towing installation [www.pipeline.no].

There are four main forms of tow-in pipeline installation. The first, thesurface tow involves towing the pipeline on top of the water. In this method, a tug tows the pipe on top of the water, and buoyancy modules help to keep it on the water's surface.

Using less buoyancy modules than the surface tow, the mid-depth tow uses the forward speed of the tug boat to keep the pipeline at a submerged level. Once the forward motion has stopped, the pipeline settles to the seafloor.

Off-bottom tow uses buoyancy modules and chains for added weight, working against each other to keep the pipe just above the sea bed. When on location, the buoyancy modules are removed, and the pipe settles to the seafloor.

Lastly, the bottom tow drags the pipe along the sea bed, using no buoyancy modules. Only performed in shallow-water installations, the sea floor must be soft and flat for this type of installation.

S-Lay Pipeline Installation

When performing S-lay pipeline installation, pipe is eased off the stern of the vessel as the boat moves forward. The pipe curves downward from the stern through the water until it reaches the "touchdown point," or its final destination on the seafloor. As more pipe is welded in the line and eased off the boat, the pipe forms the shape of an "S" in the water.

Figure 2: S-Lay pipeline installation [www.pbjv,com.my].

Stingers, measuring up to 300 feet (91 meters) long, extend from the stern to support the pipe as it is moved into the water, as well as control the curvature of the installation. Some pipelay barges have adjustable stingers, which can be shortened or lengthened according to the water depth.

Figure 3: Pipe being lowered into the water via a stinger for S-lay installation.

Proper tension is integral during the S-lay process, which is maintained via tensioning rollers and a controlled forward thrust, keeping the pipe from buckling. S-lay can be performed in waters up to 6,500 feet (1,981 meters) deep, and as many as 4 miles (6 kilometers) a day of pipe can be installed in this manner.

J-Lay Pipeline Installation

Overcoming some of the obstacles of S-lay installation, J-lay pipeline installation puts less stress on the pipeline by inserting the pipeline in an almost vertical position. Here, pipe is lifted via a tall tower on the boat, and inserted into the sea. Unlike the double curvature obtained in S-lay, the pipe only curves once in J-lay installation, taking on the shape of a "J" under the water.

Figure 4. J-Lay pipeline installation [www.technip.com].

The reduced stress on the pipe allows J-lay to work in deeper water depths. Additionally, the J-lay pipeline can withstand more motion and underwater currents than pipe being installed in the S-lay fashion.

Figure 5. J-Lay Pipelay Vessel S7000

Types Of Pipelay Vessels

There are three main types of pipelay vessels. There are J-lay and S-lay barges that include a welding station and lifting crane on board. The 40- or 80-foot (12- or 24-meter) pipe sections are welded away from wind and water, in an enclosed environment. On these types of vessels, the pipe is laid one section at a time, in an assembly-line method.

On the other hand, reel barges contain a vertical or horizontal reel that the pipe is wrapped around. Reel barges are able to install both smaller diameter pipe and flexible pipe. Horizontal reel barges perform S-lay installation, while vertical reel barges can perform both S-lay and J-lay pipeline installation.

Figure 6. Vertical reel barge [www.jee.co.uk].

When using reel barges, the welding together of pipe sections is done onshore, reducing installation costs. Reeled pipe is lifted from the dock to the vessel, and the pipe is simply rolled out as installation is performed. Once all of the pipe on the reel has been installed, the vessel either returns to shore for another, or some reel barges are outfitted with cranes that can lift a new reel from a transport vessel and return the spent reel, which saves time and money.

Source:

http://www.rigzone.com/training/insight.asp?insight_id=311&c_id=19 January 2015

Pipeline Manufacturing: Seamless or Welded?

Pipes and tubings are vital elements in upstream oil and gas. From control lines to electrical lines, tubings can be used in diverse applications. In deepwater environments, coiled tubings could run up more than 70,000 feet to produce hydrocarbon.

Here, seamless and welded tube and pipe provider RathGibson, discusses the points to consider when choosing welded, welded and drawn, or seamless tubing or pipe in various applications. The US-based firm recently invited regional players to a forum in Dubai to give an overview of its business, its product lines and its best advice on seamless versus welded. Following the forum, David Manuel talks to experts at the company.

Choosing between different types of tubing or pipe is complex. How are they different from each other? Where do each best fit?

Welded” can mean longitudinal seam welded tubing manufactured by an autogenous (without filler metal) fusion welding process, as opposed to tubing manufactured by other welding processes, such as solid-state processes.
Welded tubing is made by forming flat products (strip, sheet or plate) into the desired shape, in this case, normally round. Once the desired shape has been achieved, a high energy source is used to melt the metal locally at the weld joint. It is squeezed together and allowed to solidify, forming a weld bead. The high energy source may be an electric arc, a plasma arc, a laser beam, or even an electron beam.  The as-welded weld bead is typically somewhat thicker than the adjacent base metal and needs to be modified to match the base metal thickness, and to correct the undesirable physical, chemical and corrosion resistance attributes of the weld.
Some manufacturers will simply remove the excess material of the weld bead by scarfing the inside portion and either grinding or scarfing the outside portion.  This method of weld bead modification only changes the physical dimension and leaves the undesirable as-welded physical, chemical and corrosion resistance properties as they were.
To properly modify this condition the weld bead is cold worked locally and is given a solution anneal heat treatment.  This results in a microstructure that exhibits the same physical, chemical, mechanical, and corrosion resistance properties as the base metal.
Meanwhile, seamless tubing, sometimes referred to as “drawn tubing”, starts with a solid block or bar of steel that is pierced by extrusion, drilling, oxygen lance, or some other means to create a bore through the length of the starting stock.  This is then called a “hollow”. The hollow is then extruded through a die and mandrel combination to simultaneously reduce the outside diameter and to expand the diameter of the bore. The net result is a reduction in the wall thickness. Before the hollow can be drawn through the die, however, it must be “pointed” – which means one end of the hollow must be tapered to facilitate entry into the die. This tapered section is then cut off and discarded.
Depending on the ductility and malleability of the alloy and the starting and finished sizes this process may need to be repeated several times. Alloys that harden rapidly, like the Hastelloy and Incoloy types, require more cycles than standard austenitic stainless steels like 304 or 316. Because of extreme forces applied in the drawing operations, a very thick high pressure lubricant must be used to preserve both the inside and outside surface integrity.
These lubricants must be removed by cleaning before heat treatment can be performed. The cleaning cycle must use aggressive solvents, and is not always effective on small diameter tubing. The residual lubricants can result corrosion issues in service.
The net result is that all of this handling and additional scrap often results in a more expensive process that has its own unique set of potential defects.
One of the most common problems with seamless tubing is variation of wall thickness around the circumference of the tube at a single point along the length. Because the inside tooling cannot be held in a fixed position and is allowed to float in response to variations in hardness or strength along the hollow, the concentricity of the inside surface relative to the outside surface can become unacceptable.  It is not uncommon for the actual wall thickness of a seamless tube of 2.11 mm minimum, to vary from 2.11 mm to 2.31 mm at a single point. This is one of the reasons that seamless tube is normally ordered as a minimum nominal wall thickness where the tolerance is X.XX mm +20% / -0.  Welded tubing, on the other hand, being made from flat rolled strip material exhibits extremely consistent wall thickness. A 2.11mm nominal wall tube typically shows actual variation of 0.07 mm or less at a point. The variation from production lot to production lot is typically 0.1 mm or less.
The dimensional flaw of welded tubing may be its ovality, or roundness. Seamless tubing has a very round and very consistent diameter as a result of being extruded through a die, with typical measured variations in diameter of +/- 0.025mm for a 25 mm OD size. Roll formed welded tubing on the other hand, typically varies about +/- 0.050 mm to +/- 0.075 mm for the same nominal OD. However, for most applications, good concentricity is more valuable than good ovality. Ovality can be corrected or compensated for during fabrication or installation. A non-concentric (or eccentric) condition cannot.
Welded and drawn tubing is a compromise or combination of the two processes. It combines the positive attributes of each process. It is basically the same as the seamless process, except that the starting hollow is a welded product that has the usual excellent consistency of wall thickness. When the starting wall thickness is consistent, the final wall thickness is consistent.  It also cold works the full cross-section of the metal normally resulting in a very desirable microstructure and its associated properties. Dimensional control is excellent; it is a little bit less expensive than seamless and a bit more expensive than welded.  It can be produced as either finite length sticks or as coil forms in lengths that are only limited by handling and transportation capacities, up to 25,000 meters.

What are the criteria that should be considered?

Specifying a manufacturing process rather than specifying measurable results in any product is always a slippery slope.  The type of results and the value of measureable results need to be performance-based and to consider application critical attributes. If working pressure is of concern, then a minimum tensile or yield strength or burst pressure value should be considered, along with dimensional attributes like wall thickness and concentricity.
Wall thickness and concentricity should also be of concern when heat transfer rates are an issue. Tubes that exhibit a non-concentric or eccentric geometry may develop hot spots or weak spots at thin or thick sections around the circumference, as well as along the length. This could significantly affect process parameters in a heat exchanger.
If working temperature, either elevated or cryogenic, is of concern, test methods and data representative of the field conditions should be considered.  Basically, if material selection is properly executed, the product form should be insignificant.

What is the advantage of seamless over welded?

When welded tubing is properly manufactured by a reputable supplier, seamless does not have any advantage over welded.

Which is more cost-effective? Why?

From a tube manufacturing standpoint, typically welded is more cost-effective as a result of the minimised labour input and reduced manufacturing scrap.
From a fabrication standpoint, welded is more cost effective because of the reduced number of field orbital welds needed to join individual lengths of tube together to create the umbilical.
Seamless tubes are typically available in fixed finite lengths such as 6 or 12 metres. Welded tube on the other hand is available in continuous lengths up to 25,000 metres. A single continuous tube from a coil of strip material is typically about 500 metres long. A splice weld is made on the strip material at these 500 metre intervals and is cold worked before roll forming the tube. It is then solution anneal heat treated and X-ray examined. The net result is that strip material is infinitely long and the final length of the tube is then limited only by the size of the spool on which it can be coiled and the associated material shipping and handling capabilities.
Because these splice (orbital) welds are made and processed at the factory in a controlled environment the potential for corrosion is significantly reduced as compared to the field orbital welds which cannot be cold worked and are typically not heat treated.  The microstructure and the physical, chemical and corrosion resistance properties of the factory welds are virtually identical to those of the base metal.

In an oil and gas application, such as control lines, downhole and umbilical applications, what is more advisable between the two product types?

When purchased from a reputable reliable supplier, welded tubing can offer advantages of economy without sacrifice of performance. The economy is realised in both initial purchase costs and in time and labour in fabrication / installation. Coiled welded tubing can be supplied with a splice (orbital) weld that has been cold worked and solution annealed at intervals of about 500 metres. The maximum distance between splice welds in coiled seamless tubes is typically about 30 metres.  The wall thickness dimension control of welded tubing is superior to that of seamless tubing. Both products must meet the same minimum tensile strength and burst strength requirements. Both must meet the same corrosion testing requirements. Both must meet the same chemical composition requirements. The differences lie in the efficiencies of the manufacturing method.

According to industry players, the region’s specifications are inclined towards seamless pipes and tubes. Why is there a preference/bias over its welded counterparts? Is it a manufacturing issue?One of the biggest roadblocks to the implementation of welded tubing is the perception that the weld itself is a defect and ergo, welded tubing contains one continuous defect along its entire length. It is perceived as a weak spot in an otherwise continuous material. For many years, the industry was not able to provide a suitable quality welded product.  However, since the 1950’s, the industry has advanced significantly and modern day seam welded tubulars, from reputable conscientious manufacturers, perform equally as well as seamless products in field service.  If the seam weld can be identified by the naked eye, some consider it a defect.  This is the attitude that has prevailed in the industry for so long. One needs only to look at the microstructure and physical and corrosion test data to see that this is not necessarily so. A properly processed fusion weld is nearly indistinguishable from the base metal in a metallographic laboratory examination.  A properly processed weld exhibits the same physical and corrosion resistance properties as the base metal.

Do you think seamless are more marketable than welded tubes and pipes?

Seamless is marketed on an outdated myth that it does not have flaws but that welded has an inherent flaw throughout the length of each tube, as stated above. Intuitively this concept is easily accepted by purchasers and designers with limited experience with the various products.  Each product form and manufacturing method has its own inherent problems and potential defects.
Consumers must become familiar with what those problems and defects are, and how they might affect particular applications. Then they can make an informed decision based on facts, rather than myth. It is easy to market a manufacturing process and to have it specified in consumer documents rather than market on an ‘in service performance’ basis. Once a process is written into a specification it is normally very difficult to change that perception and requirement.  It is easy to keep the status quo as long as it appears to be working. There is often not sufficient motivation to evaluate alternative materials and manufacturing methods. It is usually a matter of economy that leads to change.
Welded tubing is acceptable as per most pressure vessel codes, and with additional non-destructive examination it can be used in place of seamless for lethal service applications. Why not for energy applications?

Are there specific industrial standards the region has to follow?

The industrial standards required are related to the specific industry.  The American Petroleum Institute standards are the primary standards followed in the Middle East. However, tubing specifications used most widely are the ASTM and ASME standards.  The National Association of Corrosion Engineers (NACE) standards and guidelines are also commonly used.

Answered by:

Carl Kettermann, Technical Director, RathGibson Inc.
Rick Lore, President of Mid-South Control Line – a division of RathGibson Inc
Alfredo D’Souza, Director of Business Development, Middle East, Africa & India, RathGibson Inc.

Source:

http://www.pipelineme.com/features/features/2010/06/seamless-vs-welded/ January 2015

Pipeline Inspection

In the United States, millions of miles of pipeline carrying everything from water to crude oil. The pipe is vulnerable to attack by internal and external corrosion, cracking, third party damage and manufacturing flaws. If a pipeline carrying water springs a leak bursts, it can be a problem but it usually doesn't harm the environment. However, if a petroleum or chemical pipeline leaks, it can be a environmental disaster. More information on recent US pipeline accidents can be found at the, National Transportation Safety Board's Internet site. In an attempt to keep pipelines operating safely, periodic inspections are performed to find flaws and damage before they become cause for concern.
When a pipeline is built, inspection personnel may use visual, X-ray, magnetic particle, ultrasonic and other inspection methods to evaluate the welds and ensure that they are of high quality. The image to the left show two NDT technicians setting up equipment to perform an X-ray inspection of a pipe weld. These inspections are performed as the pipeline is being constructed so gaining access the inspection area is not problem. In some areas like Alaska, sections of pipeline are left above ground like shown above, but in most areas they get buried. Once the pipe is buried, it is undesirable to dig it up for any reason.

So, how do you inspect a buried pipeline?

Have you ever felt the ground move under your feet? If you're standing in New York City, it may be the subway train passing by. However, if you're standing in the middle of a field in Kansas it may be a pig passing under your feet. Huh??? Engineers have developed devices, called pigs, that are sent through the buried pipe to perform inspections and clean the pipe. If you're standing near a pipeline, vibrations can be felt as these pigs move through the pipeline. The pigs are about the same diameter of the pipe so they range in size from small to huge. The pigs are carried through the pipe by the flow of the liquid or gas and can travel and perform inspections over very large distances. They may be put into the pipe line on one end and taken out at the other. The pigs carry a small computer to collect, store and transmit the data for analysis. In 1997, a pig set a world record when it completed a continuous inspection of the Trans Alaska crude oil pipeline, covering a distance of 1,055 km in one run.
Pigs use several nondestructive testing methods to perform the inspections. Most pigs use a magnetic flux leakage method but some also use ultrasound to perform the inspections. The pig shown to the left and below uses magnetic flux leakage. A strong magnetic field is established in the pipe wall using either magnets or by injecting electrical current into the steel. Damaged areas of the pipe can not support as much magnetic flux as undamaged areas so magnetic flux leaks out of the pipe wall at the damaged areas. An array of sensor around the circumference of the pig detects the magnetic flux leakage and notes the area of damage. Pigs that use ultrasound, have an array of transducers that emits a high frequency sound pulse perpendicular to the pipe wall and receives echo signals from the inner surface and the outer surface of the pipe. The tool measures the time interval between the arrival of a reflected echos from inner surface and outer surface to calculate the wall thickness.

Figure 1. Pig and the diagram.

On some pipelines it is easier to use remote visual inspection equipment to assess the condition of the pipe. Robotic crawlers of all shapes and sizes have been developed to navigate the pipe. The video signal is typically fed to a truck where an operator reviews the images and controls the robot.

Figure 2. Pipe crawler.

Source:

http://www.ndt-ed.org/AboutNDT/SelectedApplications/PipelineInspection/PipelineInspection.htm January 2015

Pipeline Routing

Oil and gas pipeline routes are pivotal pieces of information upon which pipeline engineering depends. The route will define the pipeline size, terrain, soils, and engineering analysis requirements. Engineering assessment based upon agreed alignment selection criteria is an important part of a linear project. To be able to reach the best construction line and optimise its components, the phases – namely corridor, route, alignment, and construction line selection — should be studied in the given order.

Selecting the optimum route does not end with geotechnical challenges, as it also requires interactive coordination between the owner, the engineer, the regulator, the landowners, the construction contractor and a multitude of other project stakeholders and interested parties. 
In North America, pipeline route selection is driven by regulatory requirements at the federal, state and local levels and involves finding a route that minimizes the impact on the environment and archaeological artefacts and recognises the concerns of the landowners while considering the geotechnical challenges which affect the construction of the pipeline. 
In arctic regions like Siberia, the soil conditions are an important consideration where areas of permafrost are interspersed with normal soils. In the permafrost areas, the pipeline will be installed above ground on supports and the depth of the permafrost determines the design of the supports, while in normal soil areas the pipeline is buried in a trench in the conventional manner. 
In mountainous terrain, such as in Turkey, geotechnical considerations are a significant aspect of pipeline route selection, as well as environmental and landowner concerns. The pipeline design must address geohazard mitigation for seismic areas and sections of the route which could be subject to landslides. 
Geo-political factors can also affect the route selection. Bringing Caspian Sea gas to Europe requires, among other pipelines, a new pipeline in Europe. A northern route requires a longer pipeline routed through environmentally sensitive areas, but this route supports future expansion of the pipeline system’s capacity. A southern route is shorter and reduces environmental concerns, but as this route also involves a marine crossing, the future expansion of the pipeline system is curtailed. 

Primary selection factors

The detailed pipeline route selection is preceded by defining a broad area of search between the two fixed start and end points. That is, possible pipeline corridors. The route can then be filtered with consideration of public safety, pipeline integrity, environmental impact, consequences of escape of fluid, and based on social, economic, technical environmental grounds, constructability, land ownership, access, regulatory requirements and cost. 
Economic, technical, environmental and safety considerations should be the primary factors governing the choice of pipeline routes. The shortest route might not be the most suitable, and physical obstacles, environmental constraints and other factors, such as locations of intermediate offtake points to end users along the pipeline route should be considered. Offtake points may dictate mainline routing so as to minimise the need or impact of the offtake lines or spurs. 
Many route constraints will have technical solutions (e.g. routing through flood plains), and each will have an associated cost. 
  

Corridor selection in project key stages

Pipeline routing is an iterative process, which starts with a wide ‘corridor of interest’ and then narrows down to a more defined route at each design stage as more data is acquired, to a final ‘right of way’ (ROW). Initially, a number of alternative corridors with widths up to 10 km wide are reviewed. Each project will have its own specific corridor-narrowing process depending on project size and location. 
Pipeline corridors should initially be selected to avoid key constraints. The route can then be further refined through an iterative process, involving consultation with stakeholders and landowners and a review of the EIA criteria, to avoid additional identified constraints. The ultimate aim is to achieve an economically and environmentally-feasible route for construction. 

Terrain, subterranean conditions, geotechnical and hydrographical conditions

The geography of the terrain traversed can generally be divided into surface topography and subterranean geology. Both natural and man-made geographical features can be considered under these two headings. 
The principal geographical features which are likely to be encountered and should be taken into account include: 

• Surface:
• Crops, livestock, woodlands;     
• Natural beauty, archaeological, ornamental rivers, mountains;
• Water catchment areas, forestry;
• Population, communications, services;
• Contouring, soil or rock type, water, soil corrosivity;
• Designated areas, protected habitats, flora and fauna
• Subterranean:
• Earthquake zone;
• Geological features;
• Infill land and waste disposal sites, including those contaminated by disease, radioactivity or chemicals;
• The proximity of past, present and future mineral extractions, including uncharted workings, pipelines and underground services;
• Areas of geological instability, including faults, fissuring and earthquake zones;
• Existing or potential areas of land slippage, subsidence and differential settlement;
• Tunnels;
• Ground water hydrology, including flood plains.

  

Geo-hazards

Geo-hazards are widespread phenomena that are influenced by geological and environmental conditions and which involve both long-term and short-term processes. They range in size, magnitude and effect. Many geo-hazards are naturally occurring features and processes (e.g. landslides, debris flow, seismic activity, rock falls, etc.) but there are also many geo-hazards that are caused by anthropogenic processes (e.g. undermining, landfills, engineered fill, chemistry and contamination, etc.), and these too need to be taken into account during the pipeline routing exercise. 
Geo-hazards are identified as geological, hydro-geological or geomorphological events that pose an immediate or potential risk that may lead to damage or uncontrolled risk. The type, nature, magnitude, extent and rate of geological processes and hazards directly influence pipeline route selection. Therefore, the process of early-stage terrain evaluation and the identification and assessment of geo-hazards and ground conditions are important as they can lead to extensive cost and time savings in the design and construction of a pipeline. 
The process enables the routing of the pipeline through the most suitable terrain, problem areas are identified, serious geo-hazards are avoided, where possible, and risks are minimised and mitigated. In addition, terrain evaluation is undertaken so that the need for expensive remedial measures or site restoration works is limited or prevented and the operability of the pipeline is safeguarded through a proper appreciation of the terrain conditions. By minimizing the risk of damage to the pipeline the risk to human safety is reduced. 
  

Terrain evaluation

Terrain evaluation along the pipeline corridor can be achieved using a variety of low-cost techniques that include satellite imagery and aerial photography interpretation, surface mapping and various other remote sensing techniques. This data can be incorporated, together with historical data on seismic events, geological features, meteorological processes and hydrological data, within a geographic information system (GIS – see below) and detailed terrain and hazard models developed. 
Terrain evaluation supports the anticipation, identification and assessment of the physical hazards and constraints within and outside of the pipeline corridor. It is essential that features outside the corridor be evaluated, as hazardous events outside of the corridor may be triggered by construction activity within the corridor and the resultant event may impact upon the pipeline. 
The risks associated with geo-hazards or the likelihood of an event occurring and its consequences can be qualitatively and quantitatively assessed using a scoring system or by a quantitative risk assessment (QRA). 
Safety of the pipeline is paramount in the routing selection. The extreme effect of a geological hazard on the pipeline is a rupture and it is this event that terrain evaluation and risk analysis seeks to avoid by improving the decision-making progress used in selecting the most appropriate route for the pipeline. 
  

Conclusion

In onshore and pipeline projects alike, the potential for catastrophe is always lurking close at hand to catch the naïve or complacent investor and contractor off-guard. However, when these challenges are successfully addressed, leaving a pipeline system with solid integrity and performance as well as satisfied investors, contractors and communities, projects can be very rewarding, both in financial terms as well as in the esteem accorded to all those involved. 

Source:
http://www.oilandgastechnology.net/pipeline-news/pipeline-route-selection-%E2%80%93-route-success January 2015

Pipeline Material Selection

Originally written by Krupavaram Nalli, Tebodin & Partners LLC, Sultanate of Oman

With the recent spate of material failures in the oil and gas industry around the world, the role of a material and corrosion engineer in selecting suitable material has become more complex, controversial and difficult. Further, the task had become more diverse, since now modern engineering materials offer a wide spectrum of attractive properties and viable benefits.

From the earlier years or late ’70s, the process of materials selection that had been confined exclusively to a material engineer, a metallurgist or a corrosion specialist has widened today to encompass other disciplines like process, operations, integrity, etc. Material selection is no more under a single umbrella but has become an integrated team effort and a multidisciplinary approach. The material or corrosion specialist in today’s environment has to play the role of negotiator or mediator between the conflicting interests of other peer disciplines like process, operations, concept, finance, budgeting, etc.

With this as backdrop, this article presents various stages in the material selection process and offers a rational path for the selection process toward a distinctive, focused and structured holistic approach.

What is material selection in oil and gas industry? Material selection in the oil and gas industry - by and large - is the process of short listing technically suitable material options and materials for an intended application. Further to these options, it is the process of selecting the most cost- effective material option for the specified operating life of the asset, bearing in mind the health, safety and environmental aspects and sustainable development of the asset, technical integrity and any asset operational constraints envisaged in the operating life of the asset.

What stages are involved? The stages involved in the material selection process can be outlined as material selection 1) during the concept or basic engineering stage, 2) during the detailed engineering stage, and 3) for failure prevention (lessons learned).

Concept Stage

Material selection during the concept stage basically means the investigative approach for the various available material options for the intended function and application. In this stage, a key factor for the material selection is an up-front activity taking into consideration operational flexibility, cost, availability or sourcing and, finally, the performance of the material for the intended service and application.

The material and corrosion engineer’s specialized expertise or skills become more important as the application becomes critical, such as highly sour conditions, highly corrosive and aggressive fluids, high temperatures and highly stressed environments, etc.

It is imperative at this concept stage that the material selection process becomes an interdisciplinary team approach rather an individualistic material and corrosion engineer’s choice. However, some level of material selection must be made in order to proceed with the detailed design activities or engineering phase.

The number and availability of material options in today’s industry have grown tremendously and have made the selection process more intricate than a few decades back. The trend with research and development in the materials sciences will continue to grow and may make the selection even more complex and intriguing.

It should be understood that, at the concept design stage, the selection is broad and wide. This stage defines the options available for specific application with the available family of materials like metals, non metals, composites, plastics, etc. If an innovative and cost-effective material choice is to be made from an available family of options, it is normally done at this stage.

At times, material constraints from the client or operating company or the end user may dictate the material selections as part of a contractual obligation. Sourcing, financial and cost constraints at times may also limit and obstruct the material selections except for vey critical applications where the properties and technical acceptability of the material is more assertive and outweighs the cost of the material.

Materials availability is another important criterion on the material selection which impacts the demanding project schedules for the technically suitable material options. Also, different engineering disciplines may have different and specific requirements like constructability, maintainability, etc. However, a compromise shall be reached at this stage among all the disciplines concerned to arrive at a viable economic compromise on the candidate material.

 

Detailed Engineering Stage

Materials selection during the detailed design stage becomes more focused and specific. The material selection process narrows down to a small group or family of materials, say: carbon steels, stainless steels, duplex stainless steels, Inconels or Incoloys, etc. In the detail design stage, it narrows down to a single material and other conditions of supply like Austenitic stainless steels, Martensitic stainless steels, cast materials, forged materials, etc.

Depending on the criticality of the application at this stage the material properties, manufacturing processes and quality requirements will be addressed to more precise levels and details. This may sometimes involve extensive material-testing programs for corrosion, high temperature, and simulated heat treatment as well as proof testing.

From the concept to detailing stage is a progressive process ranging from larger broad possibilities to screening to a specific material and supply condition.

At times, the selection activity may involve a totally new project (greenfield) or to an extension of existing project (brownfield). In the case of an existing project, it could be necessary to check and evaluate the adequacy of the current materials; it may be necessary at times to select a material with enhanced properties. The candidate material shall normally be investigated for more details in terms of cost, performance, fabricability, availability and any requirements of additional testing in the detail engineering stage.

Failure Prevention (Lessons Learned)

Material selection and the sustainability of material to prevent any failure during the life of the component is the final selection criterion in the process.

Failure is defined as an event where the material or the component did not accomplish the intended function or application. In most cases, the material failure is attributed to the selection of the wrong material for the particular application. Hence, the review and analysis of the failure is a very important aspect in the material selection process to avert any similar failures of the material in future.

The failure analysis - or the lessons learned - may not always result in better material. The analysis may, at times, study and consider the steps to reduce the impact on the factors that caused the failure. A typical example would be to introduce a chemical inhibition system into the process to mitigate corrosion of the material or to carry out a post-weld heat treatment to minimize the residual stresses in the material which has led to stress corrosion cracking failure.

An exhaustive review and study of the existing material that failed, including inadequacy checks and a review of quality levels imposed on the failed materials, is required before an alternate and different material is selected for the application.

The importance of the failure analysis cannot be overstressed in view of the spate of failures in recent times in the oil and gas industry. The results of failure analysis and study will provide valuable information to guide the material selection process and can serve as input for the recommendation in the concept and design stages of the project. It strengthens and reinforces the material selection process with sound back-up information.

Let us take a general view of material recommendations for pipelines. Some of the materials most relevant for use in pipelines in the Middle East are indicated for information and guidance in Table 1. The recommendations are general in nature and each pipeline is to be studied in detail case by case as regards operating conditions, fluid compositions, etc. before any final selections.

Also, other considerations - like the total length of the pipeline, above or below ground installation, nature of the pipeline (export line or processing line, etc.) – that are to be taken into consideration during the detailed engineering phase.

Table 1: General Material Selection for Pipelines in Oil and Gas Industry.

Notes: CA: Corrosion Allowance, CS: Carbon Steel, CRA: Corrosion Resistant Alloy and GRP: Glass Reinforced Plastics. The recommendations in Table 1 are for guidance only. Each pipeline is to be analyzed on a case-by-case basis based on operating conditions and fluid compositions.

 

Conclusion

To maintain the integrity of the asset and provide a safe, healthful working environment it is always a welcome event to have the material selection process be executed as a holistic team approach rather than an individual metallurgist’s or corrosion specialist’s choice.

Source:

http://www.pipelineandgasjournal.com/rational-approach-pipeline-material-selection January 2015

Pipeline Construction

Pipeline construction is divided into three phases, each with its own activities: pre-construction, construction and post-construction.

 

Pre-Construction

Surveying and staking

Once the pipeline route is finalized crews survey and stake the right-of-way and temporary workspace. Not only will the right-of-way contain the pipeline, it is also where all construction activities occur.

Preparing the right-of-way

The clearly marked right of way is cleared of trees and brush and the top soil is removed and stockpiled for future reclamation. The right-of-way is then leveled and graded to provide access for construction equipment.

Digging the trench

Once the right-of-way is prepare, a trench is dug and the centre line of the trench is surveyed and re-staked. The equipment used to dig the trench varies depending on the type of soil.

Stringing the pipe

Individual lengths of pipe are brought in from stock pile sites and laid out end-to-end along the right-of-way.

 

Construction

Bending and joining the pipe

Individual joints of pipe are bent to fit the terrain using  a hydraulic bending machine. Welders join the pipes together using either manual or automated welding technologies. Welding shacks are placed over the joint to prevent the wind from affecting the weld. The welds are then inspected and certified by X-ray or ultrasonic methods.

Coating the pipeline

Coating both inside and outside the pipeline are necessary to prevent it from corroding either from ground water or the product carried in the pipeline. The composition of the internal coating varies with the nature of the product to be transported. The pipes arrive at the construction site pre-coated, however the welded joints must be coated at the site.

Positioning the pipeline

The welded pipeline is lowered into the trench using bulldozers with special cranes called sidebooms.

Installing valves and fittings

Valves and other fittings are installed after the pipeline is in the trench. The valves are used once the line is operational to shut off or isolate part of the pipeline.

Backfilling the trench

Once the pipeline is in place in the trench the topsoil is replaced in the sequence in which it was removed and the land is re-contoured and re-seeded for restoration.

 

Post Construction

Pressure Testing

The pipeline is pressure tested for a minimum of eight hours using nitrogen, air, water or a mixture of water and methanol.

Final clean-up

The final step is to reclaim the pipeline right-of-way and remove any temporary facilities.

Source:

http://www.cepa.com/about-pipelines/pipeline-design-construction/pipeline-construction January 2015