Crack Propagation on Pipeline

Polyethylene (PE) is the primary material used for gas pipe applications. Because of its flexibility, ease of joining and long-term durability, along with lower installed cost and lack of corrosion, gas companies want to install PE pipe instead of steel pipe in larger diameters and higher pressures. As a result, rapid crack propagation (RCP) is becoming a more important property of PE materials.

This article reviews the two key ISO test methods that are used to determine RCP performance (full-scale test and small-scale steady state test), and compare the values obtained with various PE materials on a generic basis. It also reviews the status of RCP requirements in industry standards; such as ISO 4437, ASTM D 2513 and CSA B137.4. In addition, it reviews progress within CSA Z662 Clause 12 and the AGA Plastic Materials Committee to develop industry guidelines based on the values obtained in the RCP tests to design against an RCP incident.

Background

Although the phenomenon of RCP has been known and researched for several years 1, the number of RCP incidents has been very low. A few have occurred in the gas industry in North America, such as a 12-inch SDR 13.5 in the U.S. and a 6-inch SDR 11 in Canada, and a few more in Europe.

With gas engineers desiring to use PE pipe at higher operating pressures (up to 12 bar or 180 psig) and larger diameters (up to 30 inches), a key component of a PE piping material - resistance to rapid crack propagation (RCP) - becomes more important.

Most of the original research work conducted on RCP was for metal pipe. As plastic pipe became more prominent, researchers applied similar methodologies used for metal pipe on the newer plastic pipe materials, and particularly polyethylene (PE) pipe 2. Most of this research was done in Europe and through the ISO community.

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

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

1. Pipe size.
2. Internal pressure.
3. Temperature.
4. PE material properties/resistance to RCP.
5. Pipe processing.

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

Test Methods

The RCP test method that is considered to be the most reliable is the full-scale (FS) test method, as described in ISO 13478. This method requires at least 50 feet of plastic pipe for each test and another 50 feet of steel pipe for the reservoir. It is very expensive and time consuming. The cost to obtain the desired RCP information can be in the hundreds of thousands of dollars.

Due to the high cost for the FS RCP test, Dr. Pat Levers of Imperial College developed the small-scale steady state (S4) test method to correlate with the full-scale test3. This accelerated RCP test uses much smaller pipe samples (a few feet) and a series of baffles, and is described in ISO 13477. The cost of conducting this S4 testing is still expensive, but less than FS testing. Several laboratories now have S4 equipment. A photograph with this article shows the S4 apparatus used by Jana Laboratories.

Whether conducting FS or S4 RCP testing, there are two key results used by the piping industry; one is the critical pressure and the other is the critical temperature.

The critical pressure is obtained by conducting a series of FS or S4 tests at a constant temperature (generally 0C) and varying the internal pressure. At low pressures, where there is insufficient energy to drive the crack, the crack initiates and immediately arrests (stops). At higher pressures, the crack propagates (goes) to the end of the pipe. The critical pressure is shown by the red line in Figure 1 as the transition between arrest at low pressures and propagation at high pressures. In this case, the critical pressure is 10 bar (145 psig).

Figure 1: Critical Pressure (Plot of crack length vs. pressure)
Data obtained at 0° C (32°F).

Due to the baffles in the S4 test, the critical pressure obtained must be corrected to correlate with the FS critical pressure. There has been considerable research within the ISO community conducted in this area. Dr. Philippe Vanspeybroeck of Becetel chaired a working group - ISO/TC 138/SC 5/WG RCP - that conducted S4 and FS testing on several PE pipes 4. Based on their extensive research effort, the WG arrived at the following correlation formula 5 to convert the S4 critical pressure (Pc,S4) to the FS critical pressure (Pc,FS):

Pc,FS = 3.6 Pc,S4 + 2.6 bar (1)

It is important to note that this S4/FS correlation formula may not be applicable to other piping materials, such as PVC or polyamide (PA). For example, Arkema has conducted S4 and FS testing on PA-11 pipe and found a different correlation formula for PA-11 pipe 6.

The critical temperature is obtained by conducting a series of FS or S4 tests at a constant pressure (generally 5 bar or 75 psig) and varying the temperature 7. At high temperatures the crack initiates and immediately arrests. At low temperatures, the crack propagates to the end of the pipe. The critical temperature is shown by the red line in Figure 2 as the transition between arrest at high temperatures and propagation at low temperatures. In this case, the critical temperature is 35°F (2°C).

Figure 2: Critical Temperature (Plot of crack length vs. temperature)
Data obtained at 5 bar (75 psig).

RCP In ISO

The International Standards Organization (ISO) product standard for PE gas pipe, ISO 4437, has included an RCP requirement for many years 8. This is because there were some RCP failures in early generation European PE gas pipes, and the Europeans had conducted considerable research on RCP in PE pipes. Also, European gas companies were using large-diameter pipes and higher operating pressures for PE pipes, both of which make the pipe more susceptible to RCP failures. Below is the current requirement for RCP taken from ISO 4437:

Pc > 1.5 x MOP (2)

Where: Pc = full scale critical pressure, psig
MOP = maximum operating pressure, psig

Most manufacturers use the S4 test to meet this ISO 4437 RCP requirement. If the requirement is not met, then the manufacturer may use the FS test. Therefore, the ISO 4437 product standard requires that RCP testing be done, and also provides values for the RCP requirement.

RCP In ASTM

Until recently, ASTM D 2513 did not address RCP at all 9. The AGA Plastic Materials Committee (PMC) requested that an RCP requirement be added to ASTM D 2513, similar to the RCP requirement in the ISO PE gas pipe standard ISO 4437. The manufacturers agreed to include a requirement in ASTM D 2513 that RCP testing (FS or S4) must be performed. The ASTM product standard D 2513 does not include any required values.

PMC has agreed with this approach and will develop its own industry requirement in the form of a “white paper.” 10 The first draft was just issued within PMC with the following proposed requirement:

1. PC,FS > leak test pressure.
3. Leak test pressure = 1.5 X MOP.

RCP In CSA

CSA followed the direction of ASTM. The product standard CSA B137.4 11 requires that the RCP testing must be done. The values of the RCP test will be stipulated in CSA Z662 Clause 12, which is the Code of Practice for gas distribution in Canada. Clause 12 recently approved the requirement as shown nearby.

12.4.3.6 Rapid Crack Propagation (RCP) Requirements

When tested in accordance with B137.4 requirements for PE pipe and compounds, the standard PE pipe RCP Full-Scale critical pressure shall be at least 1.5 times the maximum operating pressure. If the RCP Small-Scale Steady State method is used, the RCP Full-Scale critical pressure shall be determined using the correlation formula in B137.4.
(end of box)

RCP Test Data

The critical pressure is the pressure - below which - RCP will not occur. The higher the critical pressure, the less likely the gas company will have an RCP event. In most cases, as the pipe diameter or wall thickness increases, the critical pressure decreases. Therefore, RCP is more of a concern with large-diameter or thick-walled pipe. Following are some typical critical pressure values for various generic PE materials. For most cases, the pipe size tested is 12-inch SDR 11 pipe.

PE Material S4 Critical Pressure (PC,S4) at 32°F (0°C)/Full Scale Critical Pressure (PC,FS) @ 0°C

Unimodal MDPE 1 bar (15 psig)/6.2 bar (90 psig)
Bimodal MDPE 10 bar (145 psig) /38.6 bar (560 psig)

Unimodal HDPE 2 bar (30 psig)/9.8 bar (140 psig)
Bimodal HDPE (PE 100+) 12 bar (180 psig)/45.8 bar (665 psig)

In general, the RCP resistance is greater for HDPE (high-density PE) than MDPE (medium-density PE). However, there is a significant difference when comparing a unimodal PE to a bimodal PE material, about a ten-fold difference.

Bimodal PE technology was developed in Asia and Europe in the 1980s. This technology is known to provide superior performance for both slow crack growth and RCP, as evidenced by the table. For the bimodal PE 100+ materials used in Europe and Asia, the S4 critical pressure minimum requirement is 10 bar (145 psig), which converts to 560 psig operating pressure. This means that with these bimodal PE 100+ materials, RCP will not be a concern. Today, there are several HDPE resin manufacturers that use this bimodal technology. Recently, a new bimodal MDPE material was introduced for the gas industry 12,13 with a significantly higher S4 critical pressure compared to unimodal MDPE - 10 bar compared to 1 bar.

Another measure of RCP resistance is the critical temperature. This is defined as the temperature above which RCP will not occur. Therefore, a gas engineer wants to use a PE material with a critical temperature as low as possible. Although critical temperature is not used as a requirement in the product standards, it is an important parameter, and perhaps should be given more consideration. Following is a table with some typical critical temperature values for various generic PE materials. For most cases, the pipe size tested is 12-inch SDR 11 pipe.

PE Material/Critical Temperature (TC) at 5 bar (75 psig)

Unimodal MDPE 15°C (60°F)
Bimodal MDPE -2°C (28°F)

Unimodal HDPE 9°C (48°F)
Bimodal HDPE -17°C (1°F)

Again, we see that RCP performance for HDPE is slightly better than MDPE, but there is a significant difference between bimodal PE and unimodal PE. The bimodal MDPE and HDPE materials have the lowest critical temperatures, which means the greatest resistance to RCP.

Conclusion

As gas companies use PE pipe in more demanding applications, such as larger pipe diameters and higher operating pressures, the resistance of the PE pipe to rapid crack propagation (RCP) becomes more important. In this article we have discussed the phenomenon of RCP and the two primary test methods used to determine RCP resistance - the S4 test and the Full Scale test. We reviewed the correlation formula between the FS test and S4 test for critical pressure. We have also discussed the two primary results of RCP testing - the critical pressure and the critical temperature.

ISO standards were the first to recognize the importance of RCP, especially in larger diameter pipe sizes, and incorporated RCP requirements in product standards, such as ISO 4437. The Canadian standards soon followed, and an RCP test requirement has been added to CSA B137.4. The required values for RCP testing are being added to the CSA Code of Practice in CSA Z662 Clause 12 for gas piping. ASTM just added an RCP requirement to its gas pipe standard ASTM D 2513. The corresponding AGA PMC project to develop RCP recommendations for required values from RCP testing is in progress.

In this article, we also discussed some results of RCP testing. In general, the HDPE materials have slightly greater RCP resistance than MDPE materials used in the gas industry. A more significant difference is observed when comparing unimodal PE materials to bimodal PE materials. Existing data indicate that bimodal HDPE materials show a significant increase in critical pressure compared to unimodal HDPE materials and also have considerably lower critical temperature values.

In addition, this bimodal technology has now just been introduced for MDPE. This bimodal MDPE material also has a significantly higher S4 critical pressure (10 bar vs. 1 bar) and a lower critical temperature than unimodal MDPE materials. With several PE resin manufacturers being able to produce bimodal PE materials, it is likely that in the near future, all PE materials used for the gas industry will be bimodal materials because of their superior RCP resistance.

Source : http://pipelineandgasjournal.com/rapid-crack-propagation-increasingly-important-gas-applications-status-report?page=show

Pipeline Inspection

External scanning of pipelines traditionally is undertaken by divers who require support vessels. AGR Group’s Neptune system, however, provides inspection without diver intervention and associated availability issues and depth limitations.

Neptune combines an external state-of- the-art ultrasound scanner with a small ROV. The system can be mobilized anywhere in the world to examine and predict the remaining life of subsea tubulars. The system delivers high-resolution ultrasonic data in real time, which is used to underpin the detailed finite element analysis (FEA) calculations used in industry-standard, fitness-for-service (FFS) determinations.

 

AGR’s Neptune pipe inspection tool undergoing deployment

The neutral buoyant Neptune system, weighing 150 kg (331 lb) in air but neutrally buoyant in water, is deployed via an inspection class ROV to the work site. The scanner comprises a hydraulically opening and closing twin collar, 600-mm (23.6-in) wide construction containing a fully automated X-Y scanner. This clamshell construction is self-aligning to allow rapid installation by the ROV.

Self-centering rams within the clamshell hold the scanner firmly on the pipe, creating a stable platform for the X-Y probe carriage. The probe carriage has an axial range of 500 mm (20 in.) and a circumferential movement of over 360º. It is configured to deploy Time of Flight Diffraction (TOFD) transducers for volumetric weld inspection, and compression wave transducers to perform color graphic material mapping.

The historic restriction of analogue data transmission has been removed by locating the AGR Technology Design ultrasonic digital flaw detector on the Neptune scanner. This allows the inspection data to be digitized and processed at the subsea worksite, then sent through the ROV umbilical to be viewed in real time on the surface.

Currently, the Neptune system is configured to operate in water depths of up to 1,000 m (3,280 ft), but this could be extended. The system’s ultimate working or depth range is equivalent to the ROV umbilical length: some ROVs today operate to a range of 6,000 m (19,685 ft).

The ROV pilot and Neptune operator sit together during operations to ensure optimum operational interface. The objective of any examination performed with the Neptune system is to obtain high quality graphical images of parent material, welds, and adjacent HAZ material.

As the probe carriage rasters around the pipe, the data is stored and viewed in real time for both mapping and weld inspection. In TOFD mode, the two transducers straddle the weld at a pre-set standoff to allow volumetric imaging of the weld in one pass.

There are a multitude of ROVs in service around the world, hence the importance of being able to interface mechanically and electronically with any type of inspection class ROV. The size and weight of the self-contained Neptune system allow deployment from, small supply vessels or fixed offshore installations to monitor risers and caissons.

The system also can check pipeline areas following subsea impact, anomaly verification and quantification following IP runs, and to assess potential hot-tap locations. In its current configuration the double-collar scanner is ideal to examine straight pipe and upstream and downstream of bends.

 

Close-up of Neptune system

The examination is performed on production pipelines from the external surface. The cleaner the surface, the higher quality the resulting images. Thanks to an existing range of cleaning, excavation, and dredging options, some residing within the AGR group, each proposed inspection site can be addressed individually to optimize the data quality.

Gaining direct access to the pipeline wall may be difficult if the line is concrete-coated, buried, or rock-dumped. In such cases, internal inspection techniques may offer a more cost-effective solution, which AGR again can address via its suite of inspection tools.

Neptune’s current inspection diameter range is 12-18-in. (30-46 cm), with plans to build both smaller and larger diameter collars deploying the same techniques. There are further plans to use the system’s scanner as a platform for other techniques such as ACFM, eddy current, and phased array.

AGR embarked on the development of this technology in the mid 1990s aiming to inspect pipelines not designed for pigging. There are a number of reasons why such services may be required. Many non-piggable lines have reached the limit of their design life, so their integrity needs to be demonstrated if they are to remain in operation.

Again, operators in general are giving greater priority to ensuring the integrity of their pipelines, of any age. Production downtime resulting from loss of a pipeline due to corrosion or a defective weld more than outweighs the cost of regular inspection. And operators also find themselves facing more stringent regulations as authorities seek to avoid environmental damage from pipeline leaks.

Crack detection

Demand has grown for internal and external inspection of pipelines and welds the past year. Last fall, AGR introduced Claycutter X, a technology to excavate the sea bottom and to remove soil from old pipelines. AGR plans to provide the Neptune Subsea Inspection system and Claycutter X as a package to combine excavation, examination, and recovering.

Another development is the WeldScan tool, which the AGR PipeTech division says it aims to promote in the Gulf of Mexico and West Africa. To date the system has been applied only in the Norwegian sector of the North Sea.

 

A pipeline inspection train is readied, with AGR’s pipe Intruder, which supplies the motive force, at the front.

Like its predecessor PipeScan, WeldScan is equipped with ultrasonics to measure wall thickness and to detect weld defects. However, using TOFD takes accuracy to new levels, capable of detecting cracks in welds of less than a millimeter for both width and depth. In other words, cracks can be identified much earlier.

This meets the needs of increasing application of exotic and high-grade steels in pipelines and risers to cope with multiphase flows and corrosive wellstreams. These materials are often difficult to weld, so regular monitoring of welds is required.

The move into deeper waters also places a premium on reliable integrity monitoring techniques, i.e. for inspecting steel catenary risers which are exposed to severe loadings.

WeldScan has proved its worth in examining pipelines made of high-grade steel – in this case 13% chrome – in a number of assignments carried out for an operator in the Norwegian sector.

AGR also has developed a method to transport its inspection tools through the pipeline. This is self-propelled pig, known as PipeIntruder, incorporates a seal disc with an internal bypass. Water is pushed through the seal disc by a pump at the front, creating back-pressure to push the tool forward. Pumping can be reversed, sending the tool backwards.

An odometer wheel tracks PipeIntruder’s position in the pipeline. The tool also has axial and circumferential motors to position WeldScan alongside a weld with ±1mm (0.04 in.) axial accuracy. Video cameras monitor this operation. Data from WeldScan is transmitted to the surface via fiber-optic cable in real time.

The PipeIntruder is available for pipe diameters from 8-30 in. (20.3-76.2 cm). Above 30 in. (76 cm), electro-hydraulic tractors are available. The pig hauls all combinations of inspection tools, and can travel up to 10 km (6.2 mi), the maximum range of the umbilical winch.

The string made up of the PipeIntruder and inspection tools is inserted into the pipeline at the host platform. The tools can be used to inspect other tubular structures such as risers, J-tubes, and loading lines.

Source : http://www.offshore-mag.com/articles/2008/04/new-depth-independent-high-resolution-subsea-pipeline-inspection-tool-released.html

Pipeline Corrosion

The Oil and Gas Industry, like many is highly reliant on the continued and prolonged structural corrosion of pipelines both externally and internally has always been a problem that materials scientists, engineers and plant operators have had to battle with.

Not only do pipelines form an integral part of many process systems in the oil and gas industry but one only needs to think about the potential value of the contents flowing through those pipes to understand just how important structural integrity and mitigation of loss is to an oil and gas company.

 

Failure of spirally-welded pipeline from Stress Orientated Hydrogen Induced Cracking.(Courtesy M Hay Shell Canada – replicated with Permission from Exova)

For a plethora of reasons including strict regulatory requirements, oil and gas pipelines are subjected to a comprehensive test regime. However, pipeline corrosion really isn't a straight forward subject to study, test or rectify. There are a vast range of variables to consider:

·         The environment - external and internally

·         The pipe materials

·         The age of the pipework and how long it has been immersed in the environment

·         Coatings used

·         The product carried by the pipework

·         Conditions of use (thermal cycling etc)

With such a diverse range of corrosion factors it is not surprising that pipelines have been found to fail for a variety of reasons. In light of this, engineers need to carefully test both the materials used and pipeline fabrication methods to ensure the most efficient and reliable pipework is installed for each specific purpose.

To test the base materials and weld properties of pipelines, there are a number of materials

standards and test qualification programmes available. For most offshore oil and gas pipelines NACE MR0175/ISO 15156 is used. This materials recommendation standard provides the environmental limits for a range of typical pipeline materials; it also covers hardness limits, load levels and test limits etc. to help engineers understand the likely performance of their pipeline within certain situations.

Covering most of the common issues associated with Wet Hydrogen Sulfide (Wet Sour) corrosion in oil and gas pipelines, this standard focuses largely on cracking as a result of the presence of Hydrogen Sulfide. In particular:

·         Sulfide stress Cracking (SSC)

·         Hydrogen Induced Cracking (HIC)

However, one particularly problematic failure mechanism; Stress Orientated Hydrogen Induced Cracking (SOHIC) does not have a dedicated test regime.

Dr. Chris Fowler a corrosion expert at Exova and his team have recently completed an extensive research and development project into 'Corrosion Testing of Pipework'. The culmination of which is a ground-breaking new approach to the way the offshore oil and gas industry will test corrosion of critical pipework. In particular, the testing of pipework with respect to Stress Orientated Hydrogen Induced Cracking (SOHIC).

A completely new test method has been developed to provide greater insight and a more robust test regime and associated set of results for the specific issues of SOHIC. This is not only of great interest to pipeline engineers but, the same issue has been found to affect pressure vessels as well - so the new test method could potentially offer a solution to all manner of industries.

SOHIC has the potential to cause catastrophic damage to a pipeline and Exova's research has found that at least 9 critical pipelines in the oil and gas industry have failed due to this type of crack mechanism over the past 20 years.

Dr Chris Fowler, the lead scientist in developing Exova's new test method explains the rationale behind the project:

 “As a business we look to continually innovate and develop new testing methods that will safeguard our customers operations. In this case we have developed the SOHIC testing system to help ensure pipeline integrity in the oil and gas industry, particularly as exploration is now entering harsher environments.

“This new testing method will give companies working in the oil & gas sector the reassurance they require in relation to pipeline management. It’s a significant step towards minimizing the environment’s impact on this important infrastructure and help safeguard the provision of energy.”

The initial objective of the project (which started in 2005) was to find a solution to the SOHIC problem, one that arises from a diverse range of conditions and prior to the completion of this project had been extremely difficult to accurately replicate within a controlled test environment.

The team at Exova, led by Dr Chris Fowler have successfully designed a new test method and rig which will enable test pipelines to be subjected to the bending and twisting forces associated with this type of residual stress adjacent to welds. Thus, offering engineers the ability to accurately control load levels to effectively replicate the 'live' environment.

 

The “new” test rig which can impart controlled bending and twist.

Now, for the first time, a dedicated test regime has been designed, we are at the point where engineers and scientists can work to accurately identify and quantify the specific variables responsible for the development / onset of SOHIC.

One key stage of development has been the ability to prove that materials which are known to be susceptible to SOHIC do crack under the conditions the Exova team have managed to replicate and, that a range of materials that are known to be resistant to SOHIC didn’t experience the same cracking issues. This effectively offers engineers a simple yes or no approach to materials to be used in these specific environments.

The next step is for researchers to delve deeper into the specific material properties that make a steel more susceptible to SOHIC than others:

·         Material microstructure

·         Alloying elements / Chemical Composition

·         Steel Chemistry

·         Hardness

·         Fabrication techniques etc.

However, it is clear that SOHIC is not just a material specification issue, the research team are now looking at other recent technological developments in pipeline fabrication that may also have an impact. For example new welding techniques such as Girth welding.

The team at Exova is working with both NACE and EFC to try and better understand a range of other variables that make pipeline more susceptible to SOHIC. Their findings are due to be published at the end of 2014.

Source : http://www.azom.com/article.aspx?ArticleID=9841

Deepwater Pipeline

Since 2004, a joint industry project (JIP) has been working to develop the capability to repair 10 to 24-in. ANSI 1500 pipelines in sea water depths from 1,000 to 10,000 ft. During the first phase of the JIP, participants identified and evaluated diverless pipeline repair methods and available repair tools (leak clamps and connectors). The second phase involved qualification testing of a novel low-cost method of using structural repair clamps as connectors to repair a spool piece.

In 2005, though, hurricanes Katrina and Rita impacted the JIP participants' thinking on repair methods and tools, which ultimately led to the formation of DW RUPE–Pipelines, a co-ownership group consisting of four founding co-owners (Enterprise Partners, Enbridge, BP, and Eni), for purchasing and storing $12 million in repair system components for emergency call-out. Now, the tools are all ready for service, and the DW RUPE tools are ready for use when needed. (Note: The co-ownership group is open to any interested new members.)

RUPE is an acronym for "Response to Underwater Pipeline Emergencies" and is patterned after the shallow-water RUPE Repair Tools co-ownership group, which has been in operation for over 30 years, and now consists of more than 33 co-owners worldwide.

Progress to date

The co-ownership group called DW RUPE Repair Tools is in its fourth year of operation after originating in May 2007. Four companies – Enterprise, Enbridge, BP, and Eni – agreed to co-fund a suite of deepwater pipeline repair tools at an overall cost of $12 million. Preceding the formation of the co-ownership group were two JIPs starting in 2004 and running through hurricanes Katrina and Rita in 2006. Both focused on how to make repairs and on what tools would be required.

 

Pipe handing arrangement for system integration trials

In 2004, JIP participants assessed felt that the risk of damage was remote, but the consequences of failure in lost revenue and environmental damage were quite high. They recognized that the essential repair tools at that time were the traditional connectors to join pipe ends and clamps to seal a small leak in a pipe. With further study, though, the group realized that the leak clamp would require a pipe gripping means in addition to the traditional sealing means; thus, a structural clamp was required.

In an issued request for proposal to several companies, Quality Connector Systems responded with a proposal to make a structural clamp that would fill the dual purpose of being both a pipe joining clamp-type connector and a structural leak clamp. Hence, the co-owners could purchase two clamp/connectors for each pipe size rather than two connectors and one clamp – an approximate savings of 1/3 earlier cost estimates (since the price per tool is about the same), and a low-cost solution. A second JIP built and successfully tested the clamp/connector tool in the 12-in. size.

Then, in 2005 hurricanes Katrina and Rita hit, and four of the JIP participants decided to develop a pipeline deepwater repair system consisting of two connectors and one structural clamp for each pipe size from 10 to 24-in.

Following these storms, the co-owners evaluated the risk as higher; and as a result, they wanted the "best" solution rather than a low capex solution (although both solutions are workable). Consequently, DW RUPE–Pipelines was formed. (Also being organized, but not yet formed, is DW RUPE–Flowlines.) The group's objective is to have a complete tool inventory available for deepwater flowline repair emergencies.

Now the collaborative effort is complete and these key project milestones have been reached:

• DW RUPE began in 2004 and, after three years, two JIPs, and the collective forces of hurricanes Katrina and Rita, has become reality.
• DW RUPE has fully developed a process and the equipment necessary to use in making emergency repairs to deepwater pipelines while minimizing environmental impact. The project selected, and has in storage, connectors, clamps, FBE/weld seam removal and end preparation tools, lifting frames, and indexing bases as key components to use in affecting ROV-assisted repairs.
• Beginning in May 2007, the DW RUPE–Pipelines co-ownership group became the first cooperative to provide a high-pressure, deepwater depth pipeline repair system that is open to new co-owners both in the Gulf of Mexico and internationally. DW RUPE has procured $12 million of ANSI 1500 tools fitting pipe sizes from 10 to 24-in. and capable of water depths from 1000 to 10,000 ft.
• An Excel-based spreadsheet calculation tool has been created to assist in planning careful placement of lifting means (pipe lift frames and indexing cases) to achieve a viable repair project.

 

Twelve-inch clamp in test configuration

Repair tools

The co-ownership group systematically selected repair tools for the initial inventory of DW RUPE. Whenever any tools are removed for emergency repairs by the co-owners, replacement tools may involve different component suppliers, depending on competitive bidding.

For the initial system, the co-owners carefully evaluated and selected their procurement options, which included:

• Double grip and seal connectors (two per pipe size)
• Structural leak clamps (one per pipe size)
• Pipe lift frames (two for all sizes)
• Indexing bases (two for all sizes)
• FBE & weld seam removal as well as pipe end preparation tools (all sizes).

Repair process

The co-owners agreed upon a methodology and process for performing repairs. Obviously, the first step involves locating the damaged deepwater pipeline and determining the magnitude of the damage and oil leakage condition. Depending on the findings from an ROV video survey of the damage location, the pipeline owner (and member of DW RUPE) will determine whether to use a structural clamp to repair a pinhole leak or remove a damaged segment of pipe and perform a spoolpiece repair. The top priority, though, is the need to evaluate and control any oil or gas leakage, thus minimizing environmental issues.

 

Spool piece with bolted connector

By the time a damaged gas pipeline has been located, its condition has been determined, and a repair crew has been mobilized, any gas loss (less detrimental than any oil loss) will have likely already occurred. For oil, one assumes that the pipeline is shut in by appropriate valves so that the pipeline is not purposely flowing oil. Consequently, the only oil release would be caused by movement of the damaged pipeline during repair (movement driven by gravity flow based on the density difference between oil and water).

Next, twin pipe lift frames would be lowered one at a time to specific points on either side of the leak location of the pipeline. The first pipe lift frame would be installed far enough from the leak area, a distance calculated to be a lift point where "humps" are created, as seen in the associated diagram. Also shown are the indexing bases that are deployed to stabilize the leak point above the seafloor for clamping or to control the pipe ends after cutting out the damaged section.

The "humps" formed with the lift frames create "high points" that are higher than the leak point by at least one pipe diameter in vertical distance. As long as the leak point is below the bottom of the pipe at the "hump" point, leakage cannot occur from gravity flow of the lifted sides. The pipe damage point is thus located in the "valley" between "humps."

The next step in the oil containment process is to either attach a structural leak clamp, if there is a pinhole leak, or cut out a section of damaged pipe if the damage is more severe or extensive. If cuts are necessary, the lift frames must be positioned far enough away from the cut location so that any occurring spring-back, which ultimately creates a gap, will not cause the pipe ends to slant upward (thus, potentially losing oil by gravity flow). DW RUPE has carefully constructed a finite difference computer model, verified with finite element methodology, to achieve the downward sloping pipe ends past the pipe cuts.

Further, considering pipe spring-back, one understands that deepwater routes have very large radius curves; hence, the presence of residual bending moment in the vertical plane will likely be mild. For design purposes, the maximum allowable strain (reference API RP 1111) is 0.15% so any residual spring-back is negligible. Thus, for the 100 ft of pipe adjacent to the cut, one would expect the spring-back to be fewer than a few inches per side.

Another potential problem in the pipe sagbend area (a location of compressive bending stresses on the top) is the pipe's "binding" the cutting device during the cutting process. Experience suggests that either diamond wire saws or milling heads deployed subsea would be more resistant to binding than a conventional bladed saw. The circular cross section of the wire or the milling head tends to bore a hole which can relieve lateral compression effects in the process.

Even if there were a binding problem, though, there would also be a delay in the cutting process until the diamond wire was replaced. In that case, the second cut would also take advantage of relief provided by the first cut, and the pipe would eventually be cut completely.

Once the pipe ends are downward sloping, the ROV can insert low pressure flexible sealing plugs (pigs) capable of maintaining a seal during subsequent pipeline spoolpiece placement activities that follow.

Source : http://www.offshore-mag.com/articles/print/volume-71/issue-7/flowlines-__pipelines/improving-deepwater-pipeline-repair-capability.html