EFFICIENCY AND ECONOMY OF AUTOMATING DISPLACEMENTS FOR FPSO PIPE STRESS ANALYSIS

Because Floating Production, Storage, and Offloading (FPSO) modules experience significant deflections from wave motion as well as hog/ sag, on board piping must be analyzed to assure that it is suitably designed for high cycle fatigue. This is done by keeping accumulated damage to a value less than 1.0 using the Palmgren-Miner rule. In order to simplify the acceptance criteria, a method must be developed to convert allowable accumulated damage into an allowable stress range that pipe stress engineers are accustomed to evaluating. This is done by combining methods from PD5500, DVN publications and the Fatigue Handbook: Offshore Steel Structures Probabilistic Fracture Mechanics; Tapir 1985.

To consider the effects of deck bending and module sway, displacements must be calculated from the naval architects hull data for every restraint in the pipe stress analysis model. Multiple loading cases require this process to be repeated for each loading case being considered.

Most engineering companies have developed a technique for automating the computation of module and/or deck displacements. These values once computed must be entered into the pipe stress analysis software. This task normally requires 8 to 24 hours per calculation depending on size and complexity of the piping system being analyzed. Since the data has been manually entered it must also be checked, which requires another 4 to 12 hours.

If a method can be found to calculate displacements and then automatically load them into the pipe stress analysis software, significant cost savings can be realized through reduced engineering work hours. On a project requiring 100 calculations, the potential savings using a reduction of 25 hours percalculation will be 2500 hours. This will result in a cost savings of $225,000 using $90/ hour as the cost basis. Savings could range as high as $700,000 on large FPSO's. By using the Caesar II neutral file writer to import/ export input data, it is possible to automate this process. An engineer, after entering the piping geometry into Caesar II and assigning restraints at the applicable nodes, can export a neutral file which can be read into displacement generating software (this is a company proprietary tool) where the displacements and rotations are applied to each restraint node. This enhanced neutral file can be re-imported into Caesar II ready for analysis complete with displacements and rotations. The most complex calculations can be processed in less than 30 minutes. By automating this process it may be possible to reduce FPSO pipe stress analysis time by as much as 40%.

References: https://www.onepetro.org/conference-paper/OTC-20868-MS, 

Flexible Pipe

What is flexible pipe?

A flexible pipe is made up of several different layers. The main components are leakproof thermoplastic barriers and corrosion-resistant steel wires. The helically wound steel wires give the structure its high-pressure resistance and excellent bending characteristics, thus providing flexibility and superior dynamic behaviour. This modular construction, where the layers are independent but designed to interact with one another, means that each layer can be made fit-for-purpose and independently adjusted to best meet a specific field development requirement.

Main characteristics

1. Flexibility

Flexibility is the distinctive property of a flexible pipe. A typical 8” internal diameter (ID) flexible pipe can safely be bent to a radius of 2m or less. This is the reason why flexible dynamic risers have been the enabling technology for floating production systems. This flexibility is also important for

flowlines laid on uneven seabed conditions. Flexibility makes it possible to spool the pipe on a reel or in a carousel for efficient and quick transportation and installation.

2. Installability

Because the flexible pipe comes in a continuous length, laying speed commonly averages 500m per hour. Separate sections are connected on deck during installation, eliminating the need for any intermediate riser base structure or subsea connections. This elimination of interfaces reduces risk in operation.

3. Modularity

The independent layers of a flexible structure enable it to be tailored to the precise needs of a specific development. Simple flexible pipes for medium pressure water transport comprise only four layers. The most complex flexible pipes may have up to 19 layers.

Beyond the basic fluid barriers and stress-resistant wires, additional layers can be included to prevent wear between steel layers (in dynamic applications) or to provide improved thermal insulation (“standard” flexible pipe already has a much better insulation coefficient than that of steel pipe).

Besides including new thermoplastic or steel layers, it is also possible to assemble plastic hoses, electrical cables or optical fibers around a flexible pipe to produce an Integrated Service Umbilical (ISU®), or include active heating for flow assurance in deepwater to produce an Integrated Production Bundle* (IPB).

4. Corrosion resistance

Since the steel wires are not in direct contact with the conveyed fluid, they do not require the same corrosion resistance as steel pipe. This means that gas diffusion through thermoplastic materials enable use carbon steel where the equivalent rigid pipe application would require much more expensive corrosion-resistant alloys.

5. High pressure resistance

Flexible pipes resist all fluid pressures currently encountered in the most severe subsea applications. Again, the modularity of the flexible pipe manufacturing process enables us to adjust thickness, shape and number of steel wire layers to meet the specific requirements.

Modularity enables flexible technology to cover very different applications:

• production flexible products already installed in waters down to 2,140m
• kill & choke line for drilling (up to 20,000 psi)
• drain pipes and foam lines for onshore refinery applications

Even more important, it means that the flexible pipe structure is constantly evolving to meet stringent field specifications:

• higher pressures (up to 10,000 psi for a 7.5″ ID, up to 7,350 psi for a 9″ ID and up

to 6,700 psi for a 10″ ID) on dynamic riser applications

• higher temperatures (up to 170°C)
• enhanced insulation through thick foam fillers laid on SZ machine

enhanced flow assurance: active heating, gas lift and temperature monitoring

• ultra deepwater and up to 3,000 mwd

6. Versatility and re-usability

Moreover, flexible pipe is the only product, environmentally friendly, which can be recovered and reinstalled several times to be used successively for several marginal or evolutive fields as regularly done for years in Brazilian waters.

Source :

http://www.technip.com/sites/default/files/technip/fields/publications/attachments/flexible_pipe_march_2014_web_0.pdf

Hydrotest on Offshore Pipeline

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

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

There are some other flaws that cannot be detected by hydrostatic testing. For example, the sub-critical material flaws cannot be detected by hydro testing, but the test has profound impact on the post test behavior of these flaws.

Given that the test will play a significant role in the nondestructive evaluation of pipeline, it is important to determine the correct test pressure and then utilize that test pressure judiciously, to get the desired results.

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

Reference Code, Standards and Specification

These are few reference code, standards and specification of hydrostatic testing on submarine pipeline:

• ANSI B 31.8 : Gas Transmission and Distribution Piping Systems
• ANSI B 31.4 :  Liquid  Petroleum  Transportation  Piping System.
• API RP 1110 :  Pressure Testing of Liquid Petroleum Pipelines.
• ASME Sec VIII :  Boilers and Pressure Vessels Code Div.1
• DNV 81 :  Rules for Submarine Pipelines
• IP Part :  Institute of Petroleum Model Code of Safe Practice

Equipment and Instrumentation

These are all necessary materials, equipment, instruments and consumables for performing the work. Materials and equipment shall be in good working conditions and include, but not be limited to the following:

1. Pigs for filling, cleaning and gauging . The Contractor shall provide sufficient number of pigs, including spares. Unless otherwise specified, all pigs shall be capable of negotiating a minimum bend radius of 5 times pipe diameter. In case any full port check valves are installed in the pipeline. Contractor shall ensure that the distance between the driving cups of the pigs are of sufficient length to prevent bypassing while passing through the full port check valve.
2. Fill pumps : Filling pumps shall be capable of filling the pipeline at the volume rate required to maintain pig speeds as specified in section here in after.
3. Variable speed positive displacement pumps equipped with a stroke counter to pressurize the line with a known stroke and capable of exceeding the maximum test pressure by at least 20 bar.
4. Two positive displacement meters to measure the volume of water used for filling the line. These meters shall be provided with a calibration certificate not older than one month.
5. Portable tanks of sufficient size to provide a continuous supply of water to the pump during pressurizing.
6. Bourdon pressure gauges of suitable pressure range and accuracy.
7. Dead weight testers with an accuracy of 0.01 bar measuring in increments of 0.05 bar provided with a calibration certificate not older than one month.
8. Two 48 hours recording pressure gauges having an accuracy of + 0.1% of the full scale value, with charts and ink gauges tested with dead weight tester prior to use.
9. Two temperature recorders for the continuous recording of water temperature with a sensitivity of 0.1ºC and a range of 0-40ºC.
10. Thermocouples having an accuracy of + 0.2ºC for measuring the temperature of the pipe wall.
11. Injection facilities to inject hydrotest chemicals into the test water in the required dosages.
12. Voice radio communication set-up to monitor and control the operations continuously between the beginning and the end of the test section.
13. Temporary scraper traps/test heads along with piping and valve arrangements to allow launching and receiving of pigs. Pinger transmitter for mounting on pigs alongwith pig detecting/tracking equipment.
14. Portable submersible in-situ pipeline leak detectors (flourimeters) to detect the leakage of fluorescent dye (Rhodamine B or equivalent) along with light source, detector electronics and power supplies.

Hydrostatic test procedure

The procedure manual shall include the details of all materials, equipment and procedures etc. as given below:

1. A diagram indicating all equipment, instruments, fitting, vents, valves, thermocouples, temporary connections, relevant elevations and ratings. The diagram shall also indicate injection locations and test water intake and discharge lines.
2. Laboratory test results of the test water, estimated amount of test water including required dosages of oxygen scavenger, bactericide corrosion inhibitor and fluorescent dye; procedure for chemicals and dye injection and control of dosages.
3. Filling and flushing procedures, including a complete description of all proposed equipment and instruments (including spares) their location and set-up.
4. Direction of pigging for the filling, cleaning and gauging operation.
5. The type and sequence of pigs and the pig tracking system for cleaning and removal of air pockets. Pig inspection procedures, including procedure to be followed in case the gauging pig indicates damage.
6. Procedure for thermal stabilization after filling.
7. Pressure testing procedure including a complete description of all proposed equipments and instruments (including spares), their location and set-up and proposed system for observation and recording of data during the pressure test.
8. Theoretical calculations for temperature corrections and entrapped air volume calculations.
9. Procedure for hydrotest acceptance
10. Procedure for detection/location and rectification of leaks.
11. Formats for logging/recording the test data
12. Safety precautions proposed during the test.

Source :

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

http://www.lntenc.com/9wpp/Bidding%20Doc_RSPPM/Vol.II/2022.pdf

Pipeline Integrity Management

What is pipeline integrity management?

In the oil and gas industry, management of the integrity of pipeline has grown to become a serious business because of the overall consequence of pipeline failure: economic, social, environmental, and possibly legal. There are many different definitions of pipeline integrity management (PIM), including those listed within API 1160 and ASME B31.8S. As a simple and understood-by-all definition, the following is proposed: “a system to ensure that a pipeline network is safe, reliable, sustainable and optimised.”

A pipeline integrity management program is needed to increase their reliability and availability, and to effectively manage and minimize maintenance, repair, and replacement costs over the long run. Pipeline Integrity Management System is an innovative approach to generate a suite of activities required to properly manage pipeline assets so as to deliver greater safety by minimizing risk of failures, higher productivity, longer asset life, increased asset availability from improved reliability, lower integrity related operating costs, and ensure compliance with the regulations.

Pipeline Integrity Management Systems are developed to serve unique operational needs peculiar to particular pipeline system. For new pipelines systems, the functional requirements for integrity management shall be incorporated into the planning, design, material selection, and construction of the system. However, for pipelines which are already in operation, the integrity management plan is drawn after baseline assessments and data integration.

Integrity Management Process

The integrity management process could be summarized in the flow chart below:

What are the key benefits of a PIM System?

A PIM System can vastly improve the safety of your pipelines by:

• Taking into account results from previous years in order to compare, analyze and update data.
• Allowing operators to reflect on their best practices, remaining compliant with the latest regulations and adopting the most appropriate standards.
• Identifying and analyzing actual and potential threats, ensuring data integrity

Source :

http://www.bureauveritas.com/wps/wcm/connect/bv_com/group/services+sheet/pipeline-integrity-management_941

Survey data vital to selecting routes for subsea pipelines | Engineer Live

Source: Survey data vital to selecting routes for subsea pipelines | Engineer Live.

---

Long subsea pipelines need a safe and stable route to shore. Pat Fournier, Senior Geophysicist with Australia’s Neptune Marine Services, explains the need for good quality survey data from beneath the seabed.Australia’s North West Shelf (NWS) is an isolated offshore geographic province extending 2400km along the northwest margin of the continent and is Australia’s largest oil and gas region. Four major sedimentary basins occur along the shelf, namely the Carnarvon, Canning, Browse and Bonaparte, from south to north respectively. The southern margin of the NWS is approximately 1200km north northwest of Perth, the capital city of Western Australia and the administrative centre for most exploration activity and associated oil field services.

Since the discovery of oil in Australia in 1953 at the Rough Range-1 well, onshore Carnarvon Basin, interest in oil and gas exploration has increased. In 1964 oil was discovered on Barrow Island and the NWS continued to grow and eventually became Australia’s premier oil and gas province replacing Victoria’s Gippsland Basins.

In the 1960s and 1970s regional offshore geological and geophysical exploration of the NWS led to the discovery of natural gas and condensate deposits in the Carnarvon, Browse and Bonaparte Basins, commencing with the Rankin discovery in the early 1970s. With gas replacing fuel oil in Australian homes and factories, increasing global energy demands, and LNG exports becoming a more viable source of income for the Australia economy, oil and gas companies and their export partners are looking to further exploit the large natural gas reserves in the Australasian region and specifically along the NWS.

Australia currently has two LNG processing plants; the North West Shelf Venture (NWSV) in Karratha and the Darwin LNG Plant, that deliver gas to local and international markets. These two facilities are located approximately 1800km apart along one of the most natural gas rich and remote coastlines in the world. The remoteness of the NWS is becoming less of a deterrent to investors as infrastructure develops in the region (with the aid of increased government support), and the large size of new natural gas discoveries offsets the high financial commitment required by the oil and gas companies to develop their fields.

Pipeline Material Selection

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

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

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

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

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

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

Concept Stage

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

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

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

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

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

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

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

 

Detailed Engineering Stage

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

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

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

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

Failure Prevention (Lessons Learned)

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

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

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

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

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

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

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

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

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

 

Conclusion

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

References: “A Rational Approach To Pipeline Material Selection”.http://www.pipelineandgasjournal.com/rational-approach-pipeline-material-selection.

Pipeline Corrosion in GoM

Originally written by: J. S. Mandke, Southwest Research Institute, San Antonio.

Corrosion is the leading cause of failures of subsea pipelines in the U.S. Gulf of Mexico. Third-party incidents, storms, and mud slides are additional principal causes of offshore pipeline failures. These are among the major conclusions of an analysis of 20-year pipeline-failure data compiled by the U.S. Minerals Management Service. For small size lines, additionally, failures due to external corrosion were more frequent during the period studied than internal corrosion. In medium and large-size lines, failures due to internal corrosion were more frequent than those due to external corrosion. Also, the majority of corrosion failures occurred on or near the platform and among the small-size pipelines. The motivation for the study described here was to perform a more in-depth evaluation of the pipeline failure data for the Gulf of Mexico than reported earlier, using an extended data base for the period 1967-87, and to compare the results with those reported earlier. The study results presented here provide an improved basis for assessment of safety of pipelines and for further improvements to current pipeline design, inspection, maintenance, and construction procedures.

 

Failure Data Analysis

The significant components of a typical offshore pipeline system transporting hydrocarbons are: Platform risers, expansion loops or thermal offsets, subsea valves and fittings, tie-in spools, and the main trunk line or the infield flow line. An understanding of the varying risks of damage and their consequences associated with these components can be developed from an evaluation of the historical data on the reported pipeline failures.

Failure data on offshore pipelines are not readily available for all regions of the world. Most of the reported information is on the pipelines in the Gulf of Mexico and the North Sea. In the U.S., the Department of Interior's MMS has kept a record of offshore pipeline failures since 1967. No other data source with comparable details is available in the public domain on failures of offshore pipelines. Failure data published by the MMS' for about 690 failures that occurred during 1967-87 was compiled into a personal-computer data base.

Although the MMS data on pipeline failures are the most comprehensive source of information available, the information for some of the failures reported is either insufficient or unclear. In those instances, some judgment and assumptions had to be exercised during compilation of these data. This did not affect the actual results, however, because the emphasis of this study has been on detecting the overall failure trends for offshore pipelines rather than the absolute numbers on failures.

Pipeline Failure Causes in GoM

• Material failures. Material failures include instances where the pipe material ruptured or the weld cracked and failed. Equipment failures were primarily due to leakages or malfunctioning of fittings such as flanges, clamps, valves, etc. Out of the 60 total failures that were grouped under this category, about 23% were attributed to material failure, and the remaining 77% were attributed to equipment failure.
• Operational problems. Only seven failures were attributed to operational problems. These were mostly the result of lines being overpressured either during the normal operation or the pigging operation.
• Corrosion failures. Three subcategories comprise corrosion failures. In the first two cases, the failure was clearly identified as the result of either internal or external corrosion. In the third case, the origin of the corrosion was not clearly identified. We will refer to this as general corrosion. Out of the 343 total cases of corrosion failures, 15% resulted from internal corrosion, 46% from external corrosion, and 39% from general corrosion. Further evaluation of these data showed that for the smaller-sized pipe, external corrosion failures were more common, whereas for medium and larger-sized pipe internal corrosion was more common. This latter observation is consistent with the observation made by Andersen and Misund. About 78% of the total corrosion failures occurred on the platform, in the riser section or its vicinity on the seabed, and 20% occurred on pipelines on the seabed away from the platform.
• Storms, mud slides.

The analysis of the failure data presented here has indicated significant trends in pipeline failures. It is customary to convert the failure data to probability of failure or the failure rate per km-year or mile-year of the pipeline. Because the appropriate actuarial details on these failures were not available, probabilistic analysis of the failure data could not be performed. Corrosion is the leading cause of pipeline failures. It is followed by third-party incidents and storms and mud slides as the other principal causes of offshore pipeline failures in the Gulf of Mexico.

References: “Corrosion Causes Most Pipeline Failures in Gulf of Mexico”.http://www.ogj.com/articles/print/volume-88/issue-44/in-this-issue/pipeline/corrosion-causes-most-pipeline-failures-in-gulf-of-mexico.html. 

The Benefits and Limitation on Hydrostatic Testing

The concept and value of high-pressure hydrostatic testing of cross-country pipelines were first demonstrated by Texas Eastern Transmission Corporation. Texas Eastern sought the advice of Battelle in the early 1950s as they began to rehabilitate the War Emergency Pipelines and to convert them to natural gas service. Prior to testing, these pipelines exhibited numerous failures in service due to original manufacturing defects in the pipe. 

The Battelle staff recommended hydrostatic testing to eliminate as many of these types of defects as possible. After being tested to levels of 100 to 109 percent of SMYS during which time "hundreds" of test breaks occurred, not one in-service failure caused by a manufacturing defect was observed. The news of this successful use of hydrostatic testing spread quickly to other pipeline operators, and by the late 1960s the ASA B31.8 Committee (forerunner of ASME B31.8) had established an enormous database of thousands of miles of pipelines that had exhibited no in-service ruptures from original manufacturing or construction defects after having been hydrostatically tested to levels at or above 90 percent of SMYS(1). These data were used to establish the standard practice and ASA B31.8 Code requirement that prior to service, each gas pipeline should be hydrostatically tested to 1.25 times its maximum allowable operating pressure. Later, a similar requirement for liquid pipelines was inserted into the ASME B31.4 Code. When federal regulations for pipelines came along, the precedent set by the industry of testing to 1.25 times the MOP was adopted as a legal requirement.

Both field experience and full-scale laboratory tests have revealed much about the benefits and limitations of hydrostatic testing. Among the things learned were the following:

• Longitudinally oriented defects in pipe materials have unique failure pressure levels that are predictable on the basis of the axial lengths and maximum depths of the defects and the geometry of the pipe and its material properties(2)
• The higher the test pressure, the smaller will be the defects, if any, that survive the test.
• With increasing pressure, defects in a typical line-pipe material begin to grow by ductile tearing prior to failure. If the defect is close enough to failure, the ductile tearing that occurs prior to failure will continue even if pressurization is stopped and the pressure is held constant. The damage created by this tearing when the defect is about ready to fail can be severe enough that if pressurization is stopped and the pressure is released, the defect may fail upon a second or subsequent pressurization at a pressure level below the level reached on the first pressurization. This phenomenon is referred to as a pressure reversal(3, 4)
• Testing a pipeline to its actual yield strength can cause some pipe to expand plastically, but the number of pipes affected and the amount of expansion will be small if a pressure-volume plot is made during testing and the test is terminated with an acceptably small offset volume or reduction in the pressure-volume slope(5)

Reference: http://www.kiefner.com/downloads/apihydro.pdf 

Energy Sector To Drive Demand For Spiral Welded Pipes And Tubes, Acording To New Report By Global Industry Analysts, Inc.

GIA announces the release of a comprehensive global report on the Spiral Welded Pipes and Tubes markets. Global market for Spiral Welded Pipes and Tubes is projected to reach 24.6 million tons by 2018, driven by economic recovery, level of activity in the energy sector, and intensifying pipeline construction activity.

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

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

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

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

Replacement of aging infrastructure offers huge potential for pipe manufacturers. The need to replace old pipelines is particular high in the US and Russia, where pipeline networks were mostly installed during the 60s and 70s. With the average lifespan of oil and gas transportation pipes ranging between 25 and 30 years, opportunities in the replacement market are huge, particularly for HSAW pipes. In the US, replacement demand holds enormous potential as a result of the recent enactment of the legislation that necessitates more inspections to be carried out, which could increase the likelihood of pipeline replacements. The Act is likely to play a critical role in enabling manufacturers of large diameter line pipes to survive the tough economic and overcapacity conditions.

Major players profiled in the report include American SpiralWeld Pipe Company LLC, ArcelorMittal SA, Borusan Mannesmann Boru Sanayi ve Ticaret A.S., Europipe GmbH, EVRAZ North America, JFE Steel Corporation, Jindal SAW Ltd., Man Industries Ltd., National Pipe Company Ltd., Nippon Steel & Sumitomo Metal Corporation, PSL Limited, Shengli Oil & Gas Pipe Holdings Limited, Stupp Corporation, Volzhsky Pipe Plant, UMW Group, and Welspun Corp Ltd.

The research report titled “Spiral Welded Pipes and Tubes: A Global Strategic Business Report” announced by Global Industry Analysts Inc., provides a comprehensive review of market trends, issues, drivers, company profiles, mergers, acquisitions and other strategic industry activities. The report provides market estimates and projections for all major geographic markets including the US, Canada, Japan, Europe (France, Germany, Italy, UK, Spain, Russia and Rest of Europe), Asia-Pacific (China and Rest of Asia-Pacific), Middle East, and Latin America.

For more details about this comprehensive market research report, please visit –
http://www.strategyr.com/Spiral_Welded_Pipes_and_Tubes_Market_Report.asp

Reference:

http://www.prweb.com/releases/spiral_welded_pipes_tubes/DSAW_HSAW_pipes/prweb10402550.htm

SOIL INTERACTION EFFECTS ON SIMPLE CATENARY RISER RESPONSE | 2H Offshore

Introduction

---

The use of steel simple catenary risers in deepwater developments is becoming more popular with a number of SCR’s already installed offshore Brazil and in the Gulf of Mexico. Upcoming deepwater field developments in the Gulf of Mexico, Brazil and West Africa have planned SCR configurations for large diameter export and subsea tie back production lines. A typical SCR configuration is shown in Figure 1.

The concept of the steel catenary is inherently simple and is often thought of as an extension of the flow line or pipeline. However, the dynamic movements experienced by the SCR from vessel motions and hydrodynamic loading result in a more complex behavior of the structure compared with flow lines and pipelines. This results in a requirement for sophisticated numerical tools to assist in the design process, in particular for the prediction of extreme storm stresses and long-term fatigue life due to vessel motions and vortex induced vibrations (VIV).

Current developments of steel catenary technology have focused on better understanding of these issues, one of which is the SCR touch down region and its interaction with the seabed. Studies carried out in the STRIDE JIP have shown that riser strength and fatigue response are influenced by the seabed soil and its local geometry in the touch down region. Their potential implications on SCR design have led the industry to investigate this area further. Recent initiatives include large and small scale testing programs carried out in the STRIDE JIP and CARISMA JIP [1] respectively.

This paper defines the mechanisms and uncertainties surrounding riser-seabed soil interaction, describes improved riser soil interaction models and their effects on SCR response, and outlines the STRIDE Phase III large scale testing initiative to better understand and model riser-soil interaction.

---

Conclusions

---

It is evident that current modeling of the seabed for SCR design using a flat rigid or elastic seabed is simplistic compared with the deep profiled trenches observed at the touch down zone of existing SCR’s in the Gulf of Mexico. Current modeling techniques do not account for the potential stress raising effects of soil suction and the passive soil resistance of the trench wall.

More rigorous modeling techniques using pipe-soil models to better account for seabed stiffness, soil suction and trench wall resistance can be used to improve prediction of riser fatigue life and strength, and also assess the significance of these mechanisms on overall SCR design. Critical load cases are found from parametric analyses, which show that seabed stiffness and soil suction can affect riser fatigue damage, and trench wall resistance and soil suction can cause a local increase in riser stress during a large vessel offset.

Uncertainties surrounding the mechanisms of riser-seabed interaction and validation of the  riser-soil models developed have been addressed in large scale testing within the STRIDE JIP Phase III program. Further investigation is required on the damping of vortex induced vibrations when the riser is trenched riser into the seabed.

Reference:

Thethi, Ricky. 2001. Soil Interaction Effects on Simple Catenary Riser Response. Texas: Deepwater Pipeline & Riser Technology Conference. www.2hoffshore.com

GE Oil & Gas Develops New Flexible Pipe Technology To Withstand Harsh Subsea Environtments

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

Advanced flexible pipes

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

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

Flexible pipe innovation

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

Brazil

To drive additional innovation, GE is establishing a new US$ 250 million Global Research Centre in Rio de Janeiro, which will host a subsea systems laboratory that will focus on developing more solutions for the pre-salt layer and ultra-deep water exploration.

Brazil is a key growth market for GE Oil & Gas, with the country expecting investments to reach about US$ 320 billion by 2021, according to Energy Research Company. In addition to the future subsea systems laboratory, the company also has announced a total of US$ 262 million in investments to expand its equipment production facilities in Niterói and Macaé, Rio de Janeiro, and Jandira in São Paulo.

Reference: http://www.energyglobal.com/news/pipelines/articles/GE_develops_new_flexible_pipe_technology_to_withstand_harsh_subsea_environments.aspx