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.

http://www.wermac.org/specials/hottap.html

Hydrotest

A hydrostatic test is a way in which pressure vessels such as pipelines, plumbing, gas cylinders, boilers and fuel tanks can be tested for strength and leaks. The test involves filling the vessel or pipe system with a liquid, usually water, which may be dyed to aid in visual leak detection, and pressurization of the vessel to the specified test pressure. Pressure tightness can be tested by shutting off the supply valve and observing whether there is a pressure loss. The location of a leak can be visually identified more easily if the water contains a colorant. 

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.

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.

sumber gambar  : http://en.wikipedia.org/wiki/File:Water_jacket_test_diagram.jpg

Hydrotesting of pipes, pipelines and vessels is performed to expose defective materials that have missed prior detection, ensure that any remaining defects are insignificant enough to allow operation at design pressures, expose possible leaks and serve as a final validation of the integrity of the constructed system. ASME B31.3 requires this testing to ensure tightness and strength.

Buried high pressure oil and gas pipelines are tested for strength by pressurizing them to at least 125% of their maximum operating pressure (MAOP) at any point along their length. Since many long distance transmission pipelines are designed to have a steel hoop stress of 80% of specified minimum yield (SMYS) at MAOP, this means that the steel is stressed to SMYS and above during the testing, and test sections must be selected to ensure that excessive plastic deformation does not occur. Test pressures need not exceed a value that would produce a stress higher than yield stress at test temperature. ASME B31.3 section 345.4.2 (c)Other codes require a more onerous approach. BS PD 8010-2 requires testing to 150% of the design pressure - which should not be less than the MAOP plus surge and other incidental effects that will occur during normal operation.

Leak testing is performed by balancing changes in the measured pressure in the test section against the theoretical pressure changes calculated from changes in the measured temperature of the test section. Australian standard AS2885.5 "Pipelines—Gas and liquid petroleum: Part 5: Field pressure testing" gives an excellent explanation of the factors involved.

http://pipelineandgasjournal.com/pipeline-hydro-test-pressure-determination?page=show

DNV Promoting Improved Integrity Management of Pipelines

A joint industry project led by DNV Energy is formulating guidelines for submarine pipeline system integrity monitoring. The resultant document of recommended practice, DNV RP-F116, will provide the oil and gas industry with a useful tool in an area where no such formal guidance currently exists, according to project manager Bente Helen Leinum.

Bente Helen Leinum, DNV’s project manager for the joint industry project on subsea pipeline integrity management.

The need to keep pipelines operating safely and efficiently is paramount in times of high oil prices, when financial losses resulting from downtime can mount rapidly. However, taking action can be a challenge. Many pipelines are aging but may be required to remain in operation, often beyond their design lifetime. Increased use of optimized design also implies the need for close monitoring.

Additionally, there is increasing pressure at the regulatory level. Authorities around the world are adopting a more proactive approach as they seek to minimize the risk of environmental harm resulting from pipeline leaks. This leads to stricter regulation and standards of integrity monitoring, and operators must be able to document compliance.

For companies operating internationally, the situation is not made easier by the fact that the regulatory situation can differ widely. In many countries there are few or no requirements, while in others the regulations can vary from prescriptive to functionally based, or combinations of the two.

Pipeline Integrity Management Process

However, while the need for integrity management is becoming stronger, there are often implementation difficulties. Many pipelines, especially older ones, were not designed to facilitate today’s proper monitoring and inspection. Moreover, many pipelines are unpiggable, making them impossible to inspect with an intelligent pig.

In practice, operators have had to come up with their own solutions for pipeline integrity monitoring. Many companies use API and/or ASME codes developed for onshore pipelines, combined with their own, often project-specific, pipeline integrity management systems.

DNV RP-F116 will therefore provide a reliable point of reference for both industry and authorities, helping to raise the standard of subsea pipeline integrity management. Companies also will be able to use their adherence to it when documenting their compliance with regulations. For authorities the document will hopefully provide a useful tool when they review their regulatory regimes.

The project grew out of the updated code for pipeline design, DNV OS-F101, which DNV issued last year, Leinum says. As part of this work, a small joint industry project (JIP) examined issues of pipeline integrity management and formulated minimum requirements for the safe and reliable operation of subsea pipelines. In the process, the participants became aware of the need for more detailed guidance.

When the current JIP was proposed, the number of interested participants soon made it a viable proposition. The sponsors include oil companies CNOOC, DONG Energy, Eni, Gaz de France, StatoilHydro, Norwegian pipeline operator Gassco, Norwegian research institute Sintef, to which some of the project tasks have been assigned, and DNV itself. The budget is NOK 2.8 million ($545,000).

In parallel, DNV’s Houston office is managing another JIP covering submarine pipeline integrity management in the Gulf of Mexico. The results from this work, for which the project manager is Dan Powell, also will be used as input to the development of DNV-RP-F116.

At present there are no regulatory requirements in the GoM. But in parallel with this industry initiative, the Minerals Management System (MMS) has declared its intention of introducing requirements, publishing draft proposals last fall.

The GoM JIP was prompted by one of DNV’s earlier studies for MMS in which it assessed the integrity practices of GoM operators. Among the findings was that only 5% of pipelines can accommodate inspection pigs, obliging operators to rely on informal risk-based approaches to integrity management, coupled with monitoring and preventive measures.

Oil companies should be involved in such projects, Leinum says – they are an important source of current practice, which will be reflected in the recommended practice (RP). DNV also has a wealth of experience to contribute from its own activities, much of it distilled in the many RP documents it has published with respect to pipelines.

Three main areas of integrity management have been identified:

• The establishment of integrity in the design-manufacturing-installation phase – there is growing awareness of this need within the industry, and it is becoming more common for oil companies to involve integrity personnel at the design phase
• The transfer of vital information from design to operation to ensure integrity of the pipeline during operation
• The maintenance of integrity in the operational phase – which is the main scope of the recommended practice.

Following the launch of the DNV RP-F116 project, a workshop staged in December 2007 resulted in an agreed framework for the RP. The first draft is due to be discussed at a workshop this month. Another workshop will follow in September, and a fourth this December to put its seal on the final draft.

This will be taken over as a formal DNV document, translated into the DNV template and sent out for external consultation. Depending on the number and complexity of comments which need to be accommodated, the final document should be published by May 2009.

http://www.offshore-mag.com/articles/print/volume-68/issue-4/norway/dnv-promoting-improved-integrity-management-of-pipelines.html

Bottom Roughness Analysis

Depending on the seabed profile, seabed type, loads (self weight and axial loads) and environmental conditions (wave and current induced forces) an on bottom roughness assessment and span analysis is possibly required to identify if any problem areas exist, where spans do not meet the allowable maximum free span criteria.

Maximum static and dynamic allowable free span lengths may be provided to GeoLine for the on-bottom roughness assessment or alternatively we can determine the maximum allowable free spans lengths.

The maximum allowable free span lengths are used as screening criteria to determine areas of critical spans. SAGE Profile finite element software is used to compute the pipeline profile, which is compared with the seabed elevation to determine the span height and span lengths. The computed span lengths are compared with allowable free span length criteria. Environmental loads are taken into account in the analysis.

Modelling Seabed Stiffness

Modeling the seabed stiffness (bearing capacity) is of great importance for results of on-bottom roughness analysis. Non-linear soil springs are used to model the vertical soil reactions. The soil springs are calculated according to recommended practices  BS 8010, DNV-RP-F105 “Free Spanning Pipelines”. A sensitivity analysis should be carried out to investigate the affect of varying seabed stiffness on the span lengths. 

http://www.geoline.dk/pipepg7.shtml

Upheaval Buckling of Offshore Pipeline

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

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

Figure describes upheaval buckling on buried pipe.

For upheaval buckling to occur, the pipeline must first have an initial imperfection. Imperfections are typically due to the pipeline being laid over a boulder or due to irregularities in the seabed profile.

Figure below illustrates a sequence of events which initiates buckling in a buried pipeline:

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

The occurrence of an upheaval buckle is highly depending on the smoothness of the seabed profile. According to the DNV-RP-F110 (Global Buckling of Submarine Pipelines), it gives criteria to avoid upheaval buckling from occurring by designing sufficient cover providing enough resistance for pipelines to remain in place. Therefore, upheaval buckling is considered as an ultimate limit state (ULS) in the RP.

http://brage.bibsys.no/uis/bitstream/URN:NBN:no-bibsys_brage_25027/1/Ommundsen,%20Marius%20Loen.pdf http://www.engr.mun.ca/~spkenny/Courses/Undergraduate/ENGI8673/Reading_List/1990_Palmer_Upheaval_Buckling.pdf

Pipeline Construction

A pipeline construction project looks much like a moving assembly line. A large project typically is broken into manageable lengths called “spreads,” and utilizes highly specialized and qualified workgroups. Each spread is composed of various crews, each with its own responsibilities. As one crew completes its work, the next crew moves into position to complete its piece of the construction process.

These tasks include:

1. Pre-construction survey

   Before construction begins, crews survey environmental features along proposed pipeline segments. Utility lines and agricultural drainages are located and marked to prevent accidental damage during pipeline construction. Next, the pipeline’s centerline and the exterior right of way boundaries are staked.

2. Clearing and grading

   The pipeline right of way is cleared of vegetation. Temporary erosion control measures are installed prior to any earth-moving activities.

3. Trenching

   Topsoil is removed from the work area and stockpiled separately in agricultural areas. Crews use backhoes or trenching machines to excavate a pipeline trench. The soil that is excavated during ditching operations is temporarily stockpiled on the non-working side of the trench.

4. Pipe stringing

   Individual joints of pipe are strung along the right of way adjacent to the excavated ditch and arranged so they are accessible to construction personnel. A mechanical pipe-bending machine bends individual joints of pipe to the desired angle at locations where there are significant changes in the natural ground contours or where the pipeline route changes direction.

5. Welding and coating pipe

   
   After the stringing and bending are complete, the pipe sections are aligned, welded together, and placed on temporary supports along the edge of the trench. All welds are then visually and radio graphically inspected. Line pipe, normally mill-coated or yard-coated prior to stringing, requires a coating at the welded joints. Prior to the final inspection, the entire pipeline coating is electronically inspected to locate and repair any coating faults or voids.

6. Lowering pipe in and backfilling

   The pipe assembly is lowered into the trench by side-boom tractors. The trench is backfilled using a backfilling or bladed equipment; no foreign materials are permitted in the trench.

7. Testing

   After backfilling, the pipeline is hydrostatically tested following federal regulations. Test water is obtained and disposed of in accordance with applicable federal, state and local regulations.

8. Restoration

   
   Our policy is to clean up and restore the work area as soon as possible. After the pipeline is backfilled and tested, disturbed areas are restored as close as possible to their original contours. Restoration measures are maintained until the area is restored, as closely as possible, to its original condition.

Special Land Considerations

Projects are designed to minimize the impact to residential areas, as well as agricultural lands. Land disturbed during the construction period will be returned to as close to original condition as possible. Agricultural lands will be properly restored using approved, modern mitigation techniques designed to ensure full productive reuse of the agricultural lands.

http://co.williams.com/pipeline-construction/

Underwater Welding Development and Risk

The fact that electric arc technology could operate underwater has been known for over a 100 years. The first ever underwater welding was carried out by British Admiralty Dockyard for sealing leaking ship rivets below the water line in the early 1900s and the specific waterproof electrodes and the methods to use underwater were developed in Holland by ‘Van der Willingen’ in 1946.

In recent years, the number of offshore structures, pipelines, and platforms being installed in deeper waters has increased. Some of these pipelines and structures will experience failures. Any repair for these on location will require the use of underwater welding.
When confronted with the issue of underwater welding, we often question: “Why should we consider underwater welding in the first place?” The immediate answer is “Why not?”

Risks and precautions
Welding underwater can be a dangerous profession if precautions aren't taken. The main risks are electric shock and the possibility of producing in the arc mixtures of hydrogen and oxygen in pockets, which might set off an explosion. The other common danger is breathing nitrogen in the air mix, which is absorbed into the blood but not metabolised by the body at depths under pressure. This could turn into bubbles on ascent and paralyse the diver. Curiously, the risk of drowning is not considered in commercial diving because that is the first hurdle to overcome in this profession.
The quantity of dives, dive repetitiveness, depth of the operations, time spent underwater and the exhausting nature of a specific task increase these risks significantly. Appropriate safety measures are provided to the diver via emergency air or gas supply, stand-by divers and decompression chambers. The diving-related health and safety procedures are managed by strict governing guidelines and work procedures.
When subsea welding is completed, both the welder and the structures being welded are at risk. The welder has to be very careful to avoid receiving an electric shock. For this, adequate precaution is taken by insulating the welder and limiting the voltage of welding sets. Continuous control of hydrogen and oxygen build-up is managed by removal and kept away from the arc to minimise any potential explosion.
Lastly, the welder’s time under water is controlled by using saturation diving chambers and regular rest periods in between. Inspection of an underwater weld is very difficult and complicated when compared to surface welding, but as it is the only controlling process of the quality of the weld, it is always done. The weld is inspected very carefully to confirm that no defects remain.
There are many underwater welding schools located in different parts of the world, including Australia, to train commercial divers. Historically, underwater welding was restricted to salvage operations and emergency repair work with limited depths of less than 9 m.

In underwater welding, the environment around the welder is wet. He or she wears a dive suit, and uses welding equipment which has been customized for wet environments. This equipment is designed to be as safe as possible for the welder, reducing the risk of electric shock and the development of dangerous situations. Someone who practices underwater welding must be both a skilled welder and a skilled diver, with the ability to safely and effectively prepare a scene for welding and to confirm that the welds are of high quality.

For some welding situations, a diver may create a dry chamber around the objects being welded. This type of welding is known as hyperbaric welding. Welders performing hyperbaric welding must still have diving skills and the specialized skills to weld at high pressure, but they are not working in an actively wet environment. Constructing a dry chamber can be time consuming, but there are a number of advantages to working in a dry environment which can make hyperbaric welding preferable for certain applications.

http://www.wisegeek.com/what-is-underwater-welding.htm http://pipeliner.com.au/news/application_of_underwater_welding_processes_for_subsea_pipelines/063794/