Deepwater Pipelines – Taking the Challenge to New Depths

To ensure continuity of supply, E&P companies have to consider opportunities in ever increasing water depths. Assisting this are new technological advances, including pipeline manufacture and design that increase the technical feasibility of deepwater developments.

Deepwater pipeline challenges

Conventional pipeline design, although concerned with many factors, is dominated generally by the need to withstand an internal pressure. The higher the pressure that products can be passed down the line, the higher the flow rate and greater the revenue potential. However, factors critical for deepwater pipelines become dominated by the need to resist external pressure, particularly during installation.

Local infield lines, such as subsea umbilicals, risers, and flowlines (SURF) usually are modest challenges as they are small in diameter and inherently resistant to hydrostatic collapse. In smaller sizes, these lines generally are produced as seamless pipe which is readily available and generally economical.

However, deepwater trunklines and long-distance tiebacks present a greater challenge. To increase subsea production these lines tend to be larger in diameter with a thicker pipe wall to withstand the hydrostatic pressure and bending as it is laid to the seabed.

Typically these lines are often 16 in. to 20 in. (40 cm to 50 cm) in diameter, which presents a further complication as the pipe sizes lie at the top end of economical production for seamless (Pilger) pipes. The Pilger process can produce the thick walled pipe required for these developments but often the manufacturing process is slow, the cost of material high, and the pipe lengths short. As a result, the most economical method to manufacture these lines is the UOE process. The increasingly stringent industry demands have driven this design toward its practical limits of manufacture and installation.

Corus Tubes has responded by manufacturing UOE double submerged arc welded (DSAW) linepipe to the deepest pipelines in the world. This pipe overcomes significant challenges associated with deepwater developments and facilitated a number of pioneering projects such as Bluestream and Perdido.

In the UOE process, steel plate is pressed into a “U” and then into an “O” shape and then is expanded circumferentially. Wall thickness and diameter requirements for deepwater trunkline pipe continue to be challenging for manufacturing economics and installation capabilities.

Distribution curve depicting ovality of Perdido pipe (457 mm x 20.62 mm thick).

Stress Analysis for Buried Pipeline/Underground Pipeline

Underground or buried piping are all piping which runs below grade. In every process industry there will be few lines (Sewer or drainage system, Sanitary and Storm Water lines, Fire water or drinking water lines etc), part of which normally runs underground. However the term buried piping or underground piping, in true sense, appears for pipeline industry as miles of long pipe run carrying fluids will be there.

Analyzing an underground pipe line is quite different from analyzing plant piping. Special problems are involved because of the unique characteristics of a pipeline, code requirements and techniques required in analysis. Elements of analysis include pipe movements, anchorage force, soil friction, lateral soil force and soil pipe interaction.

To appreciate pipe code requirements and visualize problems involved in pipe line stress analysis, it is necessary to first distinguish a pipe line from plant piping. Unique characteristics of a pipe line include:

Pipeline Elbow/ Pipeline Bend

Piping Elbows and Bends are very important pipe fitting which are used very frequently for changing direction in piping system. Piping Elbow and Piping bend are not the same, even though sometimes these two terms are interchangeably used.

A Bend is simply a generic term in piping for an “offset” – a change in direction of the piping. It signifies that there is a “bend” i.e,  a change in direction of the piping (usually for some specific reason) – but it lacks specific, engineering definition as to direction and degree. Bends are usually made by using a bending machine (hot bending and cold bending) on site and suited for a specific need. Use of bends are economic as it reduces number of expensive fittings.

Bend.

Source: http://www.marineinsight.com/marine/marine-news/headline/pipes-and-bends-an-essential-guide-for-second-engineers-part-2/

An Elbow, on the other hand, is a specific, standard, engineered bend pre-fabricated as a spool piece  (based on ASME B 16.9) and designed to either be screwed, flanged, or welded to the piping it is associated with. An elbow can be 45 degree or 90 degree. There can also be custom-designed elbows, although most are catagorized as either “short radius” or long radius”.

Elbow.

Source: http://www.whatispiping.com/piping-elbows-and-bends

Hydrate/Wax/Asphalt in Subsea Pipeline

Gas hydrates are solid crystalline compounds which have a structure wherein guest molecules are entrapped in a cage-like framework of host molecules without forming a chemical bond. It is water’s hydrogen bond that allows formation of hydrates. The hydrogen bond causes the water molecules to align in regular orientations. The presence of certain compounds causes the aligned molecules to stabilize and a solid mixture precipitates. The water molecules are referred to as the host molecules and the other compounds, which stabilize the crystal, are called the guest molecules. The hydrate crystals have complex, three dimensional structures in which the water molecules form a cage and the guest molecules are entrapped in the cages. 

The stabilization resulting from the guest molecule is postulated to be caused by Van der Waal’s forces, which is the attraction between molecules that is not a result of electrostatic attraction. The hydrogen bond is different from the Van der Waal’s force because it is due to strong electrostatic attraction, although some classify the hydrogen bond as a Van der Waals force. The formation of a hydrate requires the following three conditions:

1.      Low temperature and high pressure

2.      Presence of hydrate formers such as CH4, C2H4, CO2 and H2S

3.      Sufficient amount of water.

Pipeline Gooseneck

A gooseneck (or goose neck) is a 180° pipe fitting at the top of a vertical pipe that prevents entry of water. Common implementations of goosenecks are ventilator piping or ducting for bathroom and kitchen exhaust fans, ship holds, landfill methane vent pipes, or any other piping implementation exposed to the weather where water ingress would be undesired. It is so named because the word comes from the similarity of the pipe fitting to the bend in a goose’s neck.

Gooseneck may also refer to a style of kitchen or bathroom faucet with a long vertical pipe terminating in a 180° bend.

To avoid hydrocarbon accumulation, a thermosiphon should be installed at the low point of the gooseneck.

material is taken from http://en.wikipedia.org/wiki/Gooseneck_%28piping%29

Source : http://italkaboutpipe.tumblr.com/post/75357951079/gooseneck-piping

Thermal Expansion on Pipeline/ Expansion Loop Design

J. C. Suman, Sandor A. Karpathy

John Brown E&C

Houston

Managing thermal stresses in subsea pipelines carrying heated petroleum requires extensive thermal-stress analysis to predict trouble spots and to ensure a design flexible enough to anticipate stresses and expansions. Explored here are various methods for resolving predicaments posed by thermal loads and resulting deformations by keeping the stresses and deformations in the pipeline system within allowable limits.

The problems posed by thermal stresses are not unique; the solutions proposed here are. These methods are based on recent work performed for a major Asian subsea pipeline project currently under construction.

MAINTAINING VISCOSITY

For crude oil to flow through any pipeline under design pressure, it must maintain an optimum viscosity that depends on temperature and decreases proportionally as the fluid loses heat. Transporting crude oil of high viscosity through subsea pipelines can be particularly difficult. To ensure an efficient flow, pipelines are often insulated to reduce heat loss and to maintain optimum viscosity. But insulated marine pipelines pose numerous problems. The insulation must be protected from the hostile marine environment during its entire operational life. Provisions to protect the insulation from damage during pipeline installation are especially important. Moreover, the line must be engineered for and employ certain mechanisms to handle thermal expansion of the line that results from the temperature differential between the ambient water temperature and the design temperature of the fluid in the pipeline.

Fabrication and installation scenarios consider cost-effective installation of the pipeline from conventional marine lay vessels. Depending upon the size, length, and layout of the pipeline and the terrain of the ocean floor, restricting the expansion of the pipeline can lead to excessive loads on the line. These loads generally act on pipeline connections adjacent to platforms and pipeline end manifolds (PLEMs) or at subsea tie-ins. Design must consider both thermal growth and the resulting forces to ensure that the stresses in the pipeline components are within allowable limits.

Hydrotest on Offshore Pipeline

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:

Pipeline Decommisioning

In Canada, there are more than half a million kilometres of oil and gas pipelines that are in operation and more than 50 per cent of those pipelines are located in Alberta. With the amount of pipelines running throughout Canada it is important for all stakeholders, including oil and gas companies and affected landowners, to understand that pipelines have a lifecycle and how each lifecycle phase may affect them. Throughout a pipeline’s lifecycle the owner/operator of the pipeline will make decisions about the pipeline’s level of use. When a company decides to stop using a pipeline, replace a pipeline, or re-route a pipeline, questions can surface about what happens to the old pipeline and the effects this would have on landowners.

Each province has its own regulatory agency with a set of specific requirements for pipelines but if a pipeline crosses provincial borders then it falls under the jurisdiction of the National Energy Board (NEB). Under the NEB there are three different options that a company can choose from when they decide to stop using a pipeline: deactivation, abandonment or decommissioning, all of which require NEB approval.

The NEB refers to deactivation as “to remove temporarily from service”. More specifically, the NEB goes on to state that in practice it is acceptable that portions of pipeline that are in a deactivated state:

• Never return to service,

• Can remain in a deactivated state for an unspecified amount of time, or

• Can eventually be abandoned.

Flexible Riser

Conduits to transfer materials from the seafloor to production and drilling facilities atop the water's surface, as well as from the facility to the seafloor, subsea risers are a type of pipeline developed for this type of vertical transportation. Whether serving as production or import/export vehicles, risers are the connection between the subsea field developments and production and drilling facilities.

Multiple Riser ConfigurationsSource: www.atlantia.com

Similar to pipelines or flowlines, risers transport produced hydrocarbons, as well as production materials, such as injection fluids, control fluids and gas lift. Usually insulated to withstand seafloor temperatures, risers can be either rigid or flexible.

Flow Assurance for Offshore and Subsea acilities

Flow assurance, by definition, focuses on the whole engineering and production life cycle from the reservoir through refining, to ensure with high confidence that the reservoir fluids can be moved from the reservoir to the refinery smoothly and without interruption.

Overview

The full scope of flow assurance is shown in Fig. 1. Flow assurance matters specific to subsea tieback systems are shown in Fig. 2. Flow assurance is sometimes referred to as “cash assurance” because breakdown in flow assurance anywhere in the entire cycle would be expected to lead to monetary losses. A few specific flow assurance issues are discussed next.

Fig. 1—Full scope of flow assurance (courtesy of MSL Engineering).

Fig. 2—Flow assurance matters for subsea tieback systems (courtesy of BP).

Pipeline Integrity Management

Pipeline Integrity Management is a process for evaluating and reducing pipeline risks. The Pipeline Safety Improvement Act of 2002 required the federal Pipeline and Hazardous Materials Administration (PHMSA) to develop and issue regulations that address risk analysis and integrity management programs (IMP) for pipeline operators. In 2003, PHMSA finalized the IMP regulations which pipeline operators were required to implement the following year. As a result of these regulations, natural gas transmission companies must conduct baseline evaluations of pipe segments within high consequence areas (HCAs) by the end of 2012. HCAs are defined as areas where a gas pipeline failure would have a significant impact on public safety or the environment.

Integrity Management Program:

CenterPoint Energy has implemented a robust IMP to achieve or exceed the requirements mandated by PHMSA. This program builds on an existing foundation of pipeline safety regulations covering design, construction, testing, operation and maintenance – a foundation that was laid many years ago. CenterPoint Energy’s IMP is required for approximately 180 miles of HCA pipeline segments, but we plan to do more. By the end of 2012, the company expects to have evaluated over 2,500 miles of pipelines – over 10 times the amount required by PHMSA.

Our Integrity Management Program consists of seven main steps:

1. HCA Identification: CenterPoint Energy evaluates population densities each year to determine the HCAs along the pipeline system.
2. Data Integration: The company gathers and integrates information from historical construction documents, pipeline operating history, and pipeline evaluations.
3. Risk Analysis: The company then analyzes individual pipeline segments for exposure to threats as well as the public safety and environmental consequences of a pipeline failure.
4. Evaluation: Using state of the art tools, CenterPoint Energy evaluates the pipeline segments for corrosion, damage or other issues detrimental to the safe operation of the pipeline segment.
5. Repair: The company then investigates and repairs any issues found during the evaluation step to ensure the pipeline continues to operate safely.
6. Minimize Risks: The company utilizes data integration, risk analysis, evaluations and repairs to develop actions that can be taken to minimize or eliminate future damage and/or consequences.
7.  Improve: Finally, the company evaluates the IMP for areas of success and looks for other areas on our pipeline system where improvements can be made. We incorporate these improvements into our ongoing safety initiatives and the cycle starts again.

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. 

Pipeline Material and Grade Selection - A Rational Approach to Pipeline Material Selection

“If everything seems to be going well, you have obviously overlooked something,” says Murphy’s Law.

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).

Flexible Pipe - GE Oil & Gas Develops New Flexible Pipe Technology to Withstand Harsh Subsea Environments

As Brazil works to extract its vast offshore oil and gas reserves found in pre-salt formations, one of the most challenging locations is the Santos Basin, where operators face a number of complex production and transportation conditions. GE Oil & Gas has introduced innovative flexible pipes to help customers overcome these challenges by developing new materials for the pipes required to bring hydrocarbons to the surface.

Advanced flexible pipes

During the past three years, the GE Oil & Gas team in Niterói has developed new flexible pipe technologies to meet the specific conditions of the Santos Basin oil. As a result, the company now is one of only two accredited providers of advanced flexible pipes to be used in this location.

GE’s new flexible pipes feature important advances as each pipe layer is made with a specific material to ensure the safe and reliable transportation of oil and natural gas in the Santos Basin. Traditional flexible pipes are already highly engineered technologies that must be able to handle extreme pressures, temperatures and currents. The new pipes developed for the Santos Basin build on these characteristics by adding new materials specifically engineered to withstand the more acidic environment. Altogether, about 70 professionals worked on the flexible pipe technology project, which the GE team is continuing to enhance through more research and development.

Flexible pipe innovation

GE’s latest flexible pipe innovations build on the company’s 2011 acquisition of Wellstream Holdings, which enabled GE Oil & Gas to further grow in the floating production, storage and offloading offshore segment that underpins deepwater oil and gas production activities in Brazil and around the world. The business specialises in the engineering and manufacturing of high-quality flexible risers and flowline products for oil and gas transportation in the subsea production industry.

Pipeline Construction

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.

Surface Tow Pipeline Installation

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

Source: www.pbjv.com.my

Pipeline Pigging

HOW DOES PIGLINE PIGGING WORK?

Standard

While buildup in a pipeline can cause transmittal slows or even plugging of the pipeline, cracks or flaws in the line can be disastrous. A form of flow assurance for oil and gas pipelines and flowlines, pipeline pigging ensures the line is running smoothly.

The maintenance tool, pipeline pigs are introduced into the line via a pig trap, which includes a launcher and receiver. Without interrupting flow, the pig is then forced through it by product flow, or it can be towed by another device or cable. Usually cylindrical or spherical, pigs sweep the line by scraping the sides of the pipeline and pushing debris ahead. As the travel along the pipeline, there are a number functions the pig can perform, from clearing the line to inspecting the interior.

Foam pig

There are two main hypotheses for why the process is called “pipeline pigging,” although neither have been proved. One theory is that “pig” stands for Pipeline Intervention Gadget. The other states that a leather-bound pig was being sent through the pipeline, and while it passed, the leather squeaked against the sides of the pipe, sounding like a squealing pig.

Source : www.pollypig.com

Underwater Welding by Diver

Underwater welding is a process whereby metals are melted together underwater to either repair a structure or create a new structure. Used on oil wells, ships, and other underwater structures, underwater welding is done by one of two methods. The first is hyperbaric welding, in which a structure is created around the weld and a pressurized environment created. The second is arc welding, in which the welding electrode contains a flux coating that releases gases to preserve the integrity of the weld. Because of the dangers of shock, explosion and poisoning, underwater welding is only performed by professionals with both diving and welding certifications.

Method 1 of 2: Hyperbaric welding

1.           Identify the site and material of the joint to be welded as most underwater welds involve steel, but metals may vary.
2.            Prepare a chamber to place around the joint (each joint should have a separate chamber).
3.   .     Introduce gas into the chamber. A typical gas mixture uses helium and oxygen, but requirements vary based on the specific joint to be welded. The pressure of the chamber should be slightly above that of the surrounding water.
4.        Run a power supply to the chamber and set up a port for your electrodes. Multiple electrodes will likely be required, and should be placed in advance in front of the area of the joint to be welded.
5.            Dive to the weld site.
6.            Turn on the power supply and weld the joint from outside the chamber
7.            Turn off the power supply as soon as the welding is done.

Method 2 of 2: Arc welding

1.  Investigate the joint to be welded and identify the types of metals involved.
2.  Prepare the adequate electrodes, plan out the order of welding and dive to the weld site.
3. Weld the joint, ensuring that the flux coating of the weld is coming off as expected, and that too much hydrogen is not approaching the joint.
4. Turn off the power supply as soon as the welding is done.
5. In addition to underwater hyperbaric welding and underwater arc welding, a common way of welding joints on surfaces underwater is to bring the surface onto dry land, create a pressurized chamber around the joint, and use a hyperbaric dry welding process. This eliminates the need for diving while still reaching normally underwater locations.

WARNINGS

•  Explosions can occur when pockets of hydrogen or oxygen build up and are exposed to a flame. Ensure that there is a method for venting built-up hydrogen and oxygen, and review all safety procedures beforehand.
•  Because underwater welding involves two dangerous activities–welding and diving–years of instruction are usually needed before attaining competence. When learning how to weld underwater, do not attempt it if you are only comfortable as a welder or as a diver.
•  Underwater welding is only done with special electrodes designed for prolonged contact with water. Check that all electrodes and power supplies are adequately insulated.
•  Poisoning from nitrogen or other gases can cause permanent injury or death while welding underwater. Divers should always have an external or back-up air supply and should use a depressurizing chamber when returning to the surface.

Source :

http://www.wikihow.com/Weld-Underwater

Pipeline Hot Tap

What is a Hot Tap and why it is made?

Hot Taps or Hot Tapping is the ability to safely tie into a pressurized system, by drilling or cutting, while it is on stream and under pressure.
Typical connections consist:

•  Tapping fittings like Weldolet, Reinforced Branch or Split Tee. Split Tees often to be used as     branch and main pipe has the same diameters.
•    Isolation Valve like gate or Ball Valve.
•    Hot tapping machine which includes the cutter, and housing. Mechanical fittings may be used  for making hot taps on pipelines and mains provided they are designed for the operating  pressure of the pipeline or main, and are suitable for the purpose.
•  Design: ANSI B31.1, B31.3, ANSI B31.4 & B31.8, ASME Sec. VIII Div.1 & 2
•   Fabrication: ASME Sec. VIII Div.1
•  Welding: ASME Sec. IX
• NDT: ASME Sec. V

     There are many reasons to made a Hot Tap. While is preferred to install nozzles during a turnaround, installing a nozzle with equipment in operation is sometimes advantageous, especially if it averts a costly shut down.

Remarks before made a Hot Tap

•   A hot tap shall not be considered a routine procedure, but shall be used only when there is no    practical alternative.
•  Hot Taps shall be installed by trained and experienced crews.
•    It should be noted that hot tapping of sour gas lines presents special health and metallurgical    concerns and shall be done only to written operating company approved plans.
•  For each hottap shall be ensured that the pipe that is drilled or sawed has sufficient wall thickness, which can be measured with ultrasonic thickness gauges. The existing pipe wall thickness (actual) needs to be at least equal to the required thickness for pressure plus a reasonable thickness allowance for welding. If the actual thickness is barely more than that required for pressure, then loss of containment at the weld pool is a risk.
• Welding on in-service pipelines requires weld procedure development and qualification, as well as a highly trained workforce to ensure integrity of welds when pipelines are operating at full pressure and under full flow conditions.

Hot Tap setup

For a hot tap, there are three key components necessary to safely drill into a pipe; the fitting, the Valve, and the hot tap machine. The fitting is attached to the pipe, mostly bywelding.In many cases, the fitting is a Weldolet® where a flange is welded, or a split tee with a flanged outlet (see image above). Onto this fitting, a Valve is attached, and the hot tap machine is attached to the Valve (see images on the right). For hot taps, new Stud Bolts, gaskets and a new Valve should always be used when that components will become part of the permanent facilities and equipment. The fitting/Valve combination, is attached to the pipe, and is normally pressure tested. The pressure test is very important, so as to make sure that there are no structural problems with the fitting, and so that there are no leaks in the welds. The hot tap cutter, is a specialized type of hole saw, with a pilot bit in the middle, mounted inside of a hot tap adapter housing. The hot tap cutter is attached to a cutter holder, with the pilot bit, and is attached to the working end of the hot tap machine, so that it fits into the inside of the tapping adapter. The tapping adapter will contain the pressure of the pipe system, while the pipe is being cut, it houses the cutter, and cutter holder, and bolts to the Valve.

Pipeline Welding Technology

When one looks on a huge oil and gas installation like a refinery spread across many acres and representing millions of dollars on equipment and infrastructure investment, one does not see the raw crude oil injected into the refinery for the refining process. This is because the crude oil is transported through an underground pipeline. The pump station which pumps oil into the pipeline is also located far away from the refinery.

But the underground pipeline and the aboveground refinery are there for one purpose. That is to provide refined oil and other products to the public. The pipeline is for transporting the crude oil and the refinery is for refining this crude oil.

It is interesting to know that the welding techniques for these complementary structures are entirely opposite to each other. Downhill welding techniques are used for welding pipeline whereas uphill welding is used for welding refinery piping systems. Even the welding codes and inspection methods are different. The pipeline welding is controlled by API 1104 whereas refinery piping work is controlled by ASME Sec IX.

In this article we are going to discuss one by one how and why the two welding methods differ from each other. Following are the main areas where we mostly find the difference: 1.) weld joint, 2.) use of clamps, 3.) welding technique, 4.) codes and standards, 5.) electrode coating, and 6.) welding speed.

Weld Joint

The pipe thickness used on pipeline is usually less than that used in refinery piping and the pipe ends of a pipeline are machine beveled whereas pipe ends of a refinery piping joint are manually cut and beveled. These two factors play a major role in determining the opposite welding techniques.

Since the pipe end of a pipeline pipe is factory machined and smooth, it is easy to use an internal clamp to adjust both ends of a pipeline joint keeping uniform root gap without tacks, thus downhill welding technique (Figure 1) is a better choice for speedy welding. In contrast, in the case of refinery piping, not only is the pipe thickness greater but also the handmade bevels are not so smooth. Tack welds are also used instead of clamps and the root gap is not as uniform as in the case of the pipeline joint. Therefore the uphill welding technique (Figure 2) is a better choice.

Spiral Pipe for Offshore Application

Spiral welded pipes market, though encountering overcapacity conditions particularly in North America, is expected to witness steady growth in the upcoming years driven by the implementation of new pipeline projects. Investments in oil and gas exploration and production, which are influenced by prevailing crude oil & gas prices, have a considerable impact on the demand for spiral welded pipes and tubes. Resurgent world economy and consequent increase in the demand for industrial natural gas is expected to drive up momentum of the spiral welded pipes market.

Global demand for spiral welded pipes, which are primarily used in the transportation of oil and gas and in water transportation projects, is closely linked to the investments in the energy sector. The energy sector makes use of spiral welded pipes with diameters of up to 60” and up to 80 feet in length. Another factor that is expected to fuel demand for spiral pipes and tubes is new pipeline construction activity due to the shift of population from traditional centers that would necessitate development of infrastructure for delivering oil and natural gas to the new locations. Demand for spiral welded pipes is also expected from the replacement market, as most of the existing pipeline infrastructure, particularly in developed regions, has reached their end of useful life. Structural applications of spiral welded pipes are also gaining momentum, specifically with additional activity occurring in port, offshore loading and infrastructure improvement sectors.

As stated by the new market research report on Spiral Welded Pipes and Tubes, Asia-Pacific represents the largest market worldwide, driven primarily by increased use in transporting natural gas. Besides Asia-Pacific, Latin America ranks among the fastest growing regional markets with compounded annual growth rate ranging between 7.5% and 9.0% over the review period. North American market, on the other hand, is encountering testing times owing to weak demand and overcapacity conditions. Oversupply is the major concern for spiral welded pipes market particularly with regard to large diameter double submerged arc welded or DSAW line pipes, which finds use in transmitting oil, natural gas liquids, and natural gas to consumers from drilling locations.

Despite the prevailing conditions, potential opportunities are expected primarily from the implementation of new pipeline projects in the upcoming years, resurgent growth of the US economy, and increased demand from natural gas exploration operations. Also, overcapacity conditions are expected to fade away in the coming years, as several megaprojects are set to be taken up across the world, particularly in regions such as Southeast Asia, Australia, Middle East, Africa, and West Asia.

Crack on Offshore Pipeline

Stress corrosion cracking can be a serious threat to the integrity of natural gas and petroleum pipelines. The pipeline industry responded to this threat by performing a comprehensive research program to determine the cause(s) of the failures and investigate various techniques for preventing future failures. A relatively concise list of discoveries has had a measurable impact on mitigation of the stress corrosion cracking threat.

Starting with the first recognized stress corrosion cracking failure in 1965, the intergranular form of cracking (also known as high-pH SCC) was investigated to identify the causative agent and the controlling metallurgical, environmental, and stress related factors. In the 1980s, a second, transgranular form of stress corrosion cracking (near neutral pH SCC) was discovered in Canada, resulting in a similar scope of research activities designed to develop mitigation methods for this form of cracking. The information developed in these research programs has been incorporated into pipeline integrity management programs.

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Offshore Pipeline Buckling and Collapse

With ultra deepwater pipelines being considered for water depths of nearly 3,000 m, pipe collapse, in many instances, will govern design. For example, bending loads imposed on the pipeline near the seabed (sagbend region) during installation will reduce the external pressure resistance of the pipeline, and this design case will influence (and generally govern) the final selection of an appropriate pipeline wall thickness.

To date, the deepest operating pipelines have been laid using the J-lay method, where the pipeline departs the lay vessel in a near-vertical orientation, and the only bending condition resulting from installation is near the touchdown point in the sagbend. More recently, however, the S-lay method is being considered for installation of pipelines to water depths of nearly 2,800 m. During deepwater S-lay, the pipeline originates in a horizontal orientation, bends around a stinger located at the stern or bow of the vessel, and then departs the lay vessel in a near-vertical orientation. During S-lay, the installed pipe experiences bending around the stinger (overbend region), followed by combined bending and external pressure in the sagbend region.