HOW TO BECOME AN UNDERWATER DIVER?

While a career as a commercial diver and underwater welder can be rewarding, it is not for everyone. The industry demands total commitment, long hours, extensive travel, a great attitude and superior work ethic. If you're interested in becoming a commercial diver and underwater welder then it's important that you be ready for a physically and mentally challenging career.

What you will need

If you believe becoming an underwater welder is right for you, these are the minimum requirements you will need to possess:

High school Diploma or GED
Ability to swim
Mechanical aptitude
Commercial Diving Certification
AWS Certified Welding Training

Finding a School

View a class photo at Commercial Diving Academy

A commercial diver certification requires significantly more training than a standard recreational SCUBA certification. As a certified commercial diver, you are trained to work in industrial environments that frequently involve heavy construction and dangerous working conditions including electrocution and pressure related injuries.

Commercial divers receive the specialized training that allows them to work in a wide variety of environments from inland dams and bridges to offshore pipes and oil rigs.

In order to become a certified underwater welder, you will need formal training from an accredited diving school and pass their program in accordance with the American Welding Society D3.6 standard. **Click the image to the right to see what type of training exercises you will participate in as a commercial diver student!

Choosing the right school is an important first step to getting certified. You can learn more about all that CDA Technical Institute has to offer its students here.

Costs and Financial Aid

There are many costs associated with obtaining the required certifications to become a commercial diver. Financial aid - in the form of grants and loans - can assist you with the required costs of becoming an underwater welder. Here are some of the typical costs associated with the certification:

Tuition
Registration Fees
Room & Board
Books / Equipment
Dive Physical

To view CDA's tuition and fees for the Air/Mixed Gas Commercial Diver Program (Underwater Welder) click here. And for more information on financial aid available at CDA Technical Institute, click here.

Get a dive physical

Prior to gaining formal acceptance into a commercial diving program, you will be required to take a "dive physical". This needs to be completed by an approved hyperbaric physician. If you're planning on attending CDA, this can be done on the first day of school ($399) by a local Divers Certification Board of Canada (DCBC) approved physician.

After graduation

If you've just graduated, you may want to try contacting a company that hires underwater welders as apprentices. This type of position is referred to as a "diver-tender". As a graduate from Commercial Diving Academy you are entitled to career assistance from our placement department. Personnel from both offshore and inland dive companies are in contact with CDA regularly to recruit our graduates. Consequently, CDA's job-placement rates are among the highest in the country.

Source : https://www.commercialdivingacademy.com/underwater-welder.cms

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.

Source : http://www.offshore-technology.com/uploads/newsarticle/688566/images/140996/large/riser%20hydro.jpg

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.

Test Pressure And Materials SMYS
Though codes and regulatory directives are specific about setting test pressure to below 72% or in some cases up to 80% of the SMYS of the material, there is a strong argument on testing a constructed pipeline to “above 100% of SMYS,” and as high as 120% of SMYS is also mentioned. Such views are often driven by the desire to reduce the number of hydrotest sections, which translates in reduction in cost of construction. In this context, it is often noted that there is some confusion even among experienced engineers on the use of term SMYS and MOP/MAOP in reference to the hydrotest pressure.

It may be pointed out that the stress in material (test pressure) is limited by the SMYS. This is the law of physics, and is not to be broken for monetary gains at the peril of pipeline failure either immediate or in the future.

In this regard, section 32 of directive No. 66 of the Alberta Energy and Utilities Board in 2005 is of importance. The guidance is specific about the situation. It directs that if the test pressure causes hoop stress in the material exceeding 100% of the material SMYS, then the calculation and the entire hydro test procedure needs to be submitted to the board for review and approval.

Stress Relieving And Strength
Often there is argument presented that higher test pressures exceeding 100% of the SMYS will increase the “strength” of the material and will “stress relieve” the material. Both arguments have no technical basis to the point they are made. We will briefly discuss both these arguments here:

1. Higher test pressure will “increase the strength.” As the material is stressed beyond its yield point, the material is in plastic deformation stage, which is a ductile stage, and hence it is in the constant process of losing its ability to withstand any further stress. So, it is not increasing in strength but progressively losing its strength.

2. The second argument of “stress reliving” is linked with the “increase the strength” argument. The stress relief of material is carried out to reduce the locked-in stresses. The process reorients the grains disturbed often by cold working or welding. The stress relief process effectively reduces the yield strength. Thus, it does not “strengthen” the material. Note: It may be pointed out that a limited relaxation of stresses does occur by hydro testing, but the test pressure should be less than the material’s yield point.

Another point to note here is that there is a stage in the stressing of the material where strain hardening occurs and the material certainly gains some (relative) hardness, and thereby, strength. This happens as necking begins but, at that point, unit area stress is so low that the strength of the material is lost and it remains of no practical use, especially in context with the pipe material we are discussing.

Returning to the subject of pressure testing and its objectives. One of the key objectives of the testing is to find the possible flaws in the constructed pipeline. The test develops a certain amount of stress for a given time to allow these possible flaws to open out as leakages. In the following section we shall discuss the relation of these flaws to the test pressure and duration.

Critical Flaw Size
The maximum test pressure should be so designed that it provides a sufficient gap between itself and the operating pressure. In other worlds, the maximum test pressure should be > MOP.

This also presupposes that after the test the surviving flaws in the pipeline shall not grow when the line is placed in service at the maintained operating pressure. For setting the maximum test pressure, it is important to know the effect of pressure on defect growth during the testing on the one hand and on the other flaws whose growth will be affected by pressure over the time.

The defects that would not fail during a one-time, high test pressure are often referred as sub-critical defects. However these sub-critical defects would fail at lower pressure if held for longer time. But the size of discontinuity that would be in the sub-critical group would fail-independent of time-at about 105% of the “hold” pressure. This implies that maximum test pressure would have to be set at 5-10% above the maximum operating pressure (MOP) in order to find such defects during the test and also to avoid growth of sub-critical discontinuities after the hydro test pressure is released and during the operation life of pipeline. This is should be the main objective of the hydro test.

If test pressure reaching 100% (design factor of 0.80) of the SMYS is considered, then one must also consider some important pre conditions attached to the procurement of the steel and pipe. Especially important to consider is the level of flaw size that was accepted in the plate/coil used to manufacture the pipe. The test pressure of such magnitude would require that the acceptable defect size be re-assessed. This is because all else being equal, a higher design factor, resulting in a thinner wall, will lead to a reduction in the critical dimensions of both surface and through-wall defects.

Where such conditions are likely it may be prudent to reconsider the level of accepted flaws in the material. The current recommendations in API 5L 44th edition for acceptance level B2 as per ISO 12094 (for SAW pipes) may not be acceptable because it has limited coverage of body and edges and the acceptance criteria is far too liberal, in terms of acceptable size and area of flaws. More stringent criteria must be specified more in line with EN 10160 where level S2 for body and level E2 for edges may be more appropriate to meet the demands of the higher test pressures.

Sub-critical surface flaw sizes at design factors of 0.80 and 0.72 are susceptible to growth at low stress and are time dependent. These flaws are also dependent on the acceptable limits of impact absorbing energy of the material and weld (not part of the discussion in this article).

This increase in depth-to-thickness (d/t) ratio in effect reduces the ligament of the adjoining defects that reduce the required stress to propagate the discontinuity. Critical through-wall flaw lengths are also factors to be assessed. While there is a modest reduction in critical flaw length, it still indicates very acceptable flaw tolerance for any practical depth and the reduction will have negligible influence in the context of integrity management. Note that flaws deeper than about 70% of wall thickness will fail as stable leaks in both cases. This statement implies that mere radiography of the pipe welds (both field and mill welds) may not suffice. Automatic ultrasonic testing (AUT) of the welds will be better suited to properly determine the size of the planer defects in the welds. Similarly the use of AUT for assessing the flaws in the pipe body will be more stringent than usual.

Pressure Reversal
The phenomenon of pressure reversal occurs when a defect survives a higher hydrostatic test pressure but fails at a lower pressure in a subsequent repressurization. One of the several factors that work to bring on this phenomenon is the creep-like growth of sub-critical discontinuities over time and at lower pressure. The reduction in the wall thickness, caused by corrosion, external damages, is also responsible for a reduction in puncture resistance in the pipe. The reduction in the wall thickness, in effect reduces the discontinuity depth to the material thickness.

This increase in d/t ratio reduces the ligament between the adjoining defects. This effectively reduces the stress required to propagate the discontinuity. The other factor affecting the pressure reversal is the damage to the Crack Tip Opening (CTO). The CTO is subject to some compressive force leading the crack tip to force-close during the initial test. On subsequent pressurization to significantly lower pressure this “force-close” tip starts to open-up and facilitates the growth of the crack. Hence, if such a pressure cycle is part of the design, then the point of pressure reversal should be considered.

Puncture Resistance

It may also be noted that there is a modest reduction in puncture resistance with both increasing SMYS and increasing design factor. Note that the maximum design factor is, in some instances, constrained by practical limits on D/t.
In any event, it should be noted that only a small proportion of large excavators are capable of generating a puncture force exceeding 300 kN and that the reductions in puncture resistance noted would have to be assessed for the integrated approaches to the management of mechanical damage threats.

Author
Ramesh Singh is Senior Principal Engineer (Materials, Welding and Corrosion) for Gulf Interstate Engineering, 16010 Barkers Point Lane, Houston, Texas 77079-9000, 713-850-3687, Fax: 713-850-3554, E-mail: rsingh@gie.com.

Bibliography
49 CFR Part 192 Part-V, “Pipeline Safety: Standards for increasing the Maximum Allowable Operating Pressure for Gas Transmission Pipelines,” Final Rule issued Dec. 17, 2008.

Anonymous, 1996. National Energy Board Report on the Public Inquiry Concerning Stress Corrosion Cracking on Canadian Oil and Gas Pipelines.

Anonymous, 2005. 6th Report of the European Gas Pipeline Incident Data Group,” EGIG 05R.0002. See EGIG website: http://www.EGIG.nl.

ASME B 31.8 Gas transmission and Distribution Piping system.

Chen, Q., Fuglem, M., Stephens, M., and Zhou, J., 2001. “Reliability-Based Design for Mechanical Damage,” 13th Biennial PRCI/EPRG Joint Technical Meeting, Paper 1.

Driver, R.G. and Zimmerman, T.J.E., 1998. “A Limit States Approach to the Design of Pipelines for Mechanical Damage,” Proc. 17th OMAE Conference, Paper OMAE98-1017.

Duffy, A.R., McClure, G.M., Maxey, W.A. and Atterbury, T.J., 1968. “Feasibility of Basing Natural Gas Pipeline Operating Pressure on Hydrostatic Test Pressure,” PRC/AGA NG-18 Report L30050.

Eiber, R.J., Hopkins, P., McLamb, M., and Abes, J., 2004. “Operation of New Design and/or Conversion of Existing Gas Pipelines to 80% SMYS Operating Stress,” GRI Report GRI-04-0152.

EN 10160 - 1999, Ultrasonic testing of steel flat product of thickness equal or greater than 6 mm (reflection method).

ISO 12094 - 1994 Welded steel tubes for pressure purposes-Ultrasonic testing for the detection of laminar imperfections in strip/plate used in the manufacture of welded tubes.

Rothwell, Brian, Staff Engineer, TransCanada PipeLines, “History and Operating experience of design factors above 0.72 in Canadian gas transmission pipelines.”

Texas Eastern, Technological Review of Hydrostatic Testing. Dec. 04, 1985.

Source : http://www.pipelineandgasjournal.com/pipeline-hydro-test-pressure-determination?page=5

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.

Pipeline Integrity Mangement
Source : http://gs-press.com.au/images/news_articles/cache/PIM_continuously_improving_loop-600x0.jpg

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:

HCA Identification: CenterPoint Energy evaluates population densities each year to determine the HCAs along the pipeline system.
Data Integration: The company gathers and integrates information from historical construction documents, pipeline operating history, and pipeline evaluations.
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.
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.
Repair: The company then investigates and repairs any issues found during the evaluation step to ensure the pipeline continues to operate safely.
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.
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.

Public Safety:

The ultimate goal of CenterPoint Energy’s IMP is to protect people living, working and playing near our pipelines, as well as protecting the environment surrounding our pipelines. As a direct result of our IMP efforts, CenterPoint Energy has excavated and examined over 2,100 pipeline segments.

To combat internal corrosion, we ran over 220 cleaning pigs in 2011 to clean our pipelines, used corrosion inhibitors, and monitored internal corrosion using metal probes.
To reduce external corrosion, we use cathodic protection equipment and routinely take test point readings to evaluate the pipeline’s level of protection. We also perform pipeline coating surveys – so far we have covered 3,100 miles of our system and plan to complete the entire system by 2016.
To help prevent third party damage we employ pipeline markers, aerial patrols, foot patrols, and right-of-way clearing. In addition, CenterPoint Energy is fully committed to, and participates in, the 8-1-1 Call Before You Dig Program.

Public Awareness:

CenterPoint Energy has a comprehensive Public Awareness program. We dedicate a great deal of time and resources to keeping in contact with both the public and the emergency responders located near our pipelines. Each year we mail hundreds of thousands of information packets to people living near our pipelines. We also have safety meetings with excavation contractors, law enforcement and fire prevention officials. In addition, we send age appropriate educational materials to the schools near our pipelines. It is our goal to partner with the officials dedicated to protecting the public.

Leading Edge:

CenterPoint Energy is a proud participant and supporter of industry efforts to continually improve pipeline safety and reliability. We are a member of Intrastate Natural Gas Association of America (INGAA) and actively participate in the INGAA Integrity Management Continuous Improvement (IMCI) initiative. IMCI has set a goal of zero incidents as one of its guiding principles. Another IMCI goal is to apply integrity management principles on a much larger scale than required by current regulations. CenterPoint Energy supports these INGAA initiatives and participates on IMCI planning teams.

In addition, the company participates in research projects hosted by Pipeline Research Council International, Inc (PRCI). PRCI is dedicated to researching issues and producing solutions that assure safe and reliable pipelines. CenterPoint is a PRCI member company and participates on many PRCI research teams.

CenterPoint Energy believes we are one of the companies leading the pipeline industry to a safer, more reliable future.

Commitment:

CenterPoint Energy is committed to protecting the public and environment. Our dedication to safety is a reflection of our company values: Integrity, Accountability, Initiative and Respect. If you need further information or have additional questions, please contact us at Midstream Pipeline Safety.

Source :

http://www.centerpointenergy.com/services/pipelines/naturalgassafety/pipelineintegritymanagement/

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, landfillmethane 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.^[1]

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

Source : http://en.wikipedia.org/wiki/Gooseneck_(piping)

Decommissioning oil and gas installations can cost operators an average of $4-$10 million in the shallow water Gulf of Mexico. Thus when the US Department of the Interior Bureau of Ocean Energy Management, Regulation, and Enforcement (BOEMRE) Gulf of Mexico OCS Region issued a new decommissioning regulation in September 2010, operators knew they’d take a hit.

Total Pipeline Decommissioning Scheme
Source : http://qlf-www.uk.total.com/images/photos/activities/mcp01_pipeline.gif

NTL 2010-G05 requires wells that have not been used for the last five years to be to be permanently abandoned, temporarily abandoned, or zonally isolated within 3 years after Oct. 15, 2010. If wells are zonally isolated, operators have 2 additional years to permanently or temporarily abandon the wellhead. Plus, platforms and supporting infrastructure that have been idle for five or more years must be removed within 5 years as of the Oct. 15, 2010 effective date.

This new NTL on top of the typical volume of decommissioning work in the GOM will increase demand for contractors and, in turn, their dayrates.

According to a BOEMRE statement, the MMS (former name of the BOEMRE) conducted an Alternative Internal Control Review (AICR) of idle structures and wells on active leases in the GOM OCS in 2008. The review identified a significant number of idle platforms that need to be permanently plugged and removed. Why? Idle structures and wells could be damaged in a hurricane and cause an environmental disaster. Plus, damaged platforms and wells cost more to decommission than non-damaged wells.

How Is An Offshore Rig Decommissioned?

There are 10 steps to the process: Project Management, Engineering and Planning; Permitting and Regulatory Compliance; Platform Preparation; Well Plugging and Abandonment; Conductor Removal; Mobilization and Demobilization of Derrick Barges; Platform Removal; Pipeline and Power Cable Decommissioning; Materials Disposal; and Site Clearance. Each step is discussed below.

Project Management

Project management, engineering and planning for decommissioning an offshore rig usually starts three years before the well runs dry. The process involves:

review of contractual obligations
engineering analysis
operational planning
contracting

Due to the limited number of derrick barges, many operators contract these vessels two to three years in advance. In addition, much of the decommissioning process requires contractors who specialize in a specific part of the process. Most operators will contract out project management, cutting, civil engineering, and diving services.

Permitting And Regulatory Compliance

Obtaining permits to decommission an offshore rig can take up to three years to complete. Often, operators will contract a local consulting firm to ensure that all permits are in order prior to decommissioning. Local consulting firms are familiar with the regulatory framework of their region.

An Execution Plan is one of the first steps in the process. Included in this plan is environmental information and field surveys of the project site. The plan describes a schedule of decommissioning activities and the equipment and labor required to carry out the operation. An execution plan is required to secure permits from Federal, State, and local regulatory agencies. The BOEMRE will also analyze the environmental impact of the project and recommend ways to eliminate or minimize those impacts.

Federal agencies often involved in decommissioning projects include BOEMRE, National Marine Fisheries Service, US Army Corps of Engineers, US Fish and Wildlife Service, National Oceanic and Atmospheric Administration, US Environmental Protection Agency, US Coast Guard, and the US Department of Transportation, Office of Pipeline Safety.

Platform Preparation

To prepare a platform for decommissioning, tanks, processing equipment and piping must be flushed and cleaned and residual hydrocarbons have to be disposed of; platform equipment has to be removed, which includes cutting pipe and cables between deck modules, separating the modules, installing padeyes to lift the modules; and reinforcing the structure. Underwater, workers prepare the jacket facilities for removal, which includes removing marine growth.

Well Plugging And Abandonment

Plugging and abandonment is one of the major costs of a decommissioning project and can be broken into two phases.

The planning phase of well plugging includes:

data collection
preliminary inspection
selection of abandonment methods
submittal of an application for BOEMRE approval

In the GOM, the rig-less method, which was developed in the 1980s, is primarily used for plugging and abandonment jobs. The rig-less method uses a load spreader on top of a conductor, which provides a base to launch tools, equipment and plugs downhole.

Well abandonment involves:

well entry preparations
use of a slick line unit
filling the well with fluid
removal of downhole equipment
cleaning out the wellbore
plugging open-hole and perforated intervals(s) at the bottom of the well
plugging casing stubs
plugging of annular space
placement of a surface plug
placement of fluid between plugs

Plugs must be tagged to ensure proper placement or pressure-tested to verify integrity.

Conductor Removal

According to BOEMRE, all platform components including conductor casings must be removed to at least 15 ft below the ocean floor or to a depth approved by the Regional Supervisor based upon the type of structure or ocean-bottom conditions.

To remove conductor casing, operators can chose one of three procedures:

Severing, which requires the use of explosive, mechanical or abrasive cutting
Pulling/sectioning, which uses the casing jacks to raise the conductors that are unscrewed or cut into 40 ft-long segments.
Offloading, which utilizes a rental crane to lay down each conductor casing segment in a platform staging area, offloading sections to a boat, and offloading at a port. The conductors are then transported to an onshore disposal site.

Mobilization/Demobilization And Platform Removal

Mobilization and demobilization of derrick barges is a key component in platform removal. According to BOEMRE, platforms, templates and pilings must be removed to at least 15 ft below the mudlline.

First, the topsides are taken apart and lifted onto the derrick barge. Topsides can be removed all in one piece, in groups of modules, reverse order of installation, or in small pieces.

If removing topsides in one piece, the derrick barge must have sufficient lifting capacity. This option is best used for small platforms. Also keep in mind the size and the crane capacity at the offloading site. If the offloading site can’t accommodate the platform in one piece, then a different removal option is required.

Removing combined modules requires fewer lifts, thus is a time-saving option. However, the modules must be in the right position and have a combined weight under the crane and derrick barge capacity. Dismantling the topsides in reverse order in which they were installed, whether installed as modules or as individual structural components, is another removal option and the most common.

Topside can also be cut into small pieces and removed with platform cranes, temporary deck mounted cranes, or other small (less expensive) cranes. However, this method takes the most time to complete the job, so any cost savings incurred using a smaller derrick barge will likely be offset by the dayrate.

Removing the jacket is the second step in the demolition process and the most costly. First, divers using explosives, mechanical means, torches or abrasive technology make the bottom cuts on the piles 15 ft below the mudline. Then the jacket is removed either in small pieces or as a single lift. A single lift is possible only for small structures in less than 200 ft of water. Heavy lifting equipment is required for the jacket removal as well, but a derrick barge is not necessary. Less expensive support equipment can do the job.

Pipeline And Power Cable Decommissioning

Pipelines or power cables may be decommissioned in place if they do not interfere with navigation or commercial fishing operations or pose an environmental hazard. However, if the BOEMRE rules that it is a hazard during the technical and environmental review during the permitting process, it must be removed.

The first step to pipeline decommissioning in place requires a flushing it with water followed by disconnecting it from the platform and filling it with seawater. The open end is plugged an buried 3 ft below the seafloor and covered with concrete.

Materials Disposal And Site Clearance

Platform materials can be refurbished and reused, scrapped and recycled or disposed of in specified landfills.

To ensure proper site clearance, operators need to follow a four-step site clearance procedure.

Pre-decommissioning survey maps the location and quantity of debris, pipelines, power cables, and natural marine environments.
Post decommissioning survey identifies debris left behind during the removal process and notes any environmental damage
ROVs and divers target are deployed to further identify and remove any debris that could interfere with other uses of the area.
Test trawling verifies that the area is free of any potential obstructions.

Source :

http://www.rigzone.com/training/insight.asp?i_id=354

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.

Hot Tap operation

The Hot Tap is made in one continuous process, the machine is started, and the cut continues, until the cutter passes through the pipe wall, resulting in the removal of a section of pipe, known as the “coupon”. The coupon is normally retained on one or more u-wires, which are attached to the pilot bit. Once the cutter has cut through the pipe, the hot tap machine is stopped, the cutter is retracted into the hot tap adapter, and the Valve is closed. Pressure is bled off from the inside of the Tapping Adapter, so that the hot tap machine can be removed from the line. The machine is removed from the line, and the new service is established.

Hot Tap Coupon

The Coupon, is the section of pipe that is removed, to establish service. It is very highly desirable to “retain” the coupon, and remove it from the pipe, and in the vast majority of hot taps, this is the case. Coupon retention is mostly the “job” of the u-wires. These are wires which run through the pilot bit, and are cut and bent, so that they can fold back against the bit, into a relief area milled into the bit, and then fold out, when the pilot bit has cut through the pipe. In almost all cases, multiple u-wires are used, to act as insurance against losing the coupon.

Line Stopping

Line Stops, sometimes called Stopples (Stopple® is a trademark of TD Williamson Company) start with a hot tap, but are intended to stop the flow in the pipe. Line Stops are of necessity, somewhat more complicated than normal hot taps, but they start out in much the same way. A fitting is attached to the pipe, a hot tap is performed as previously detailed. Once the hot tap has been completed, the Valve is closed, then another machine, known as a line stop actuator is installed on the pipe. The line stop actuator is used to insert a plugging head into the pipe, the most common type being a pivot head mechanism. Line stops are used to replace Valves, fittings and other equipment. Once the job is done, pressure is equalized, and the line stop head is removed. The Line Stop Fitting has a specially modified flange, which includes a special plug, that allows for removal of the Valve. There are several different designs for these flanges, but they all work pretty much the same, the plug is inserted into the flange through the Valve, it is securely locked in place, with the result that the pressure can be bled off of the housing and Valve, the Valve can then be removed, and the flange blinded off.

Line Stop setup

The Line Stop Setup includes the hot tap machine, plus an additional piece of equipment, a line stop actuator. The Line Stop Actuator can be either mechanical (screw type), or hydraulic, it is used, to place the line stop head into the line, therefore stopping the flow in the line. The Line Stop Actuator is bolted to a Line Stop Housing, which has to be long enough to include the line stop head (pivot head, or folding head), so that the Line Stop Actuator, and Housing, can be bolted to the line stop Valve. Line stops often utilize special Valves, called Sandwich Valves. Line Stops are normally performed through rental Valves, owned by the service company who performs the work, once the work is completed, the fitting will remain on the pipe, but the Valve and all other equipment is removed.

Line Stop operation

A Line Stop starts out the same way as does a Hot Tap, but a larger cutter is used,. The larger hole in the pipe, allows the line stop head to fit into the pipe. Once the cut is made, the Valve is closed the hot tap machine is removed from the line, and a line stop actuator is bolted into place. New gaskets are always to be used for every setup, but “used” studs and nuts are often used, because this operation is a temporary operation, the Valve, machine, and actuator are removed at the end of the job. New studs, nuts, and gaskets should be used on the final completion, when a blind flange is installed outside of the completion plug. The line stop actuator is operated, to push the plugging head (line stop head), down, into the pipe, the common pivot head, will pivot in the direction of the flow, and form a stop, thus stopping the flow in the pipe.

Completion Plug

In order to remove the Valve used for line stop operations, a completion plug is set into the line stop fitting flange (Completion Flange). There are several different types of completion flange/plug sets, but they all operate in basically the same manner, the completion plug and flange are manufactured, so as to allow the flange, to accept and lock into place, a completion plug. This completion plug is set below the Valve, once set, pressure above the plug can be bled off, and the Valve can then be removed. Once the plug has been properly positioned, it is locked into place with the lock ring segments, this prevents plug movement, with the o-ring becoming the primary seal. Several different types of completion plugs have been developed with metal to metal seals, in addition to the o-ring seal.

Line Stopping Procedure